In the article, All-time low for discovered resources in 2017, Rystad reports, it stated the following:
“We haven’t seen anything like this since the 1940s,” says Sonia Mladá Passos, senior analyst at Rystad Energy. “The discovered volumes averaged at ~550 MMboe per month. The most worrisome is the fact that the reserve replacement ratio in the current year reached only 11% (for oil and gas combined) - compared to over 50% in 2012.” According to Rystad’s analysis, 2006 was the last year when reserve replacement ratio reached 100%.
TAKEAWAY OPTIONS
Current pipeline takeaway capacity out of the Permian is roughly 3.1million b/d, which combined with local refinery demand for Permian crudeat just under 300,000 b/d falls short of production.
Current price discounts have made moving crude by rail economical,although there is limited rail capacity. There is roughly 315,000 b/d ofPermian Basin rail capacity, but much of that is now being used to moveother commodities like frac sands.
Murex, along with Cetane Energy, said it will expand Cetane'stransloading facility at Carlsbad, New Mexico, boosting its CBR capacityby 40,000 b/d, to 75,000 b/d, in the third quarter.
Current CBR volumes out of West Texas will likely be capped at about50,000 b/d as the bulk of the existing loading terminals have yet to beretrofitted to handle crude, according Jenna Delaney, senior oil analystwith Platts Analytics. But those volumes are anticipated to rise to100,000 b/d in the second half of 2018, she added.
Roughly 10,000 b/d of crude is currently moving by truck out of thePermian, and this will not grow beyond 40,000 b/d due to a shortage ofdrivers.
NEW PIPELINES
To meet the growing output, two waves of pipelines are being plannedacross Texas, offering a total of at least 4.1 million b/d of newtakeaway capacity by mid-2020 and beyond.
* Gray Oak (Q3 2019 completion): Phillips 66 (75%) owner and Andeavor(25%) said in April it has received shipper support to move ahead withthe 700,000 b/d pipeline, and also launched an open season that couldincrease throughput on the line to 1 million b/d. The pipeline willmove crude to Corpus Christi and to Sweeny/Freeport along the HoustonShip Channel and is targeted for startup in the third quarter of 2019.Part of Gray Oak's development will be a connection to a3.4-million-barrel marine terminal under development by BuckeyePartners at Corpus Christi for exports. Nearly 50% of throughput onGray Oak will be targeted for exports, while Phillips 66's Sweeneyrefinery near Freeport could utilize 60,000 b/d to 70,000 b/d asfeedstock, the company said.
* EPIC Midstream (Q3 2019): The San Antonio-based company is working tobring on more shippers on its Eagle Ford Permian Ingleside and CorpusChristi pipeline, for which it secured 75,000 b/d and 100,000 b/d offirm capacity, respectively, from Apache and Noble Energy. The pipelineis due for startup by the third quarter of 2019 and has increasedcapacity in the line to 675,000 b/d from 590,000 b/d. That figure mayincrease further to 825,000 b/d.
* Cactus II (Q3 2019): Plains All American is moving ahead with thepermitting, right of way and procurement process for the 650,000 b/dpipeline it plans to bring into service in Q3 2019. Cactus II will shipbarrels from the Delaware Basin to the Port of Corpus Christi, and theadjacent Ingleside Terminal on the Texas Gulf Coast, with Trafiguracoming on board as anchor shipper, committing to 300,000 b/d. Plains isadding storage tanks and augmenting its gathering system at Wink andMcCamey that will add 220,000 b/d of new capacity this summer from thebasin to its crude terminal in Southwest Texas.
* Midland to Nederland (2020): Energy Transfer Partners, which is intalks with shippers, said it will announce strategic partners for the600,000 b/d pipeline that will ship crude from Midland to Nederland onthe USGC. The facility will be built in 2020. Energy Transfer has yetto announce a partner for this planned pipeline, but fellow midstreamplayer Magellan said at an analyst event in mid-June it was consideringa joint venture with Energy Transfer for a long-haul Midland to USGCpipeline.
* Jupiter (2020): An open season will be launched in the third quarter byDallas-based Jupiter Midstream for the pipeline, which will have acapacity of up to 500,000 b/d and will move barrels from the Permian toBrownsville on the southernmost tip of the Texas Gulf Coast. Detailedengineering studies are underway for the line, which will define itsfinal capacity and cost. The pipeline will serve crude export plansthat Jupiter has at Brownsville, which includes two new docks to loadPanamax and an offshore facility to load VLCCs. The pipeline istargeted to be built by 2020 and Jupiter is seeking a JV partner.
* ExxonMobil/Plains (2020): ExxonMobil, which plans to increase itsPermian production to 600,000 b/d over the medium term from 200,000 b/dcurrently, unveiled in mid-June what will likely be the single-largestPermian crude pipeline. With a capacity of 1 million b/d, Exxon willpartner with Plains and has signed a letter of intent to set up a JV.The long-haul line will run from Wink and Midland to Baytown, Beaumontand Webster, Plains said. The companies did not indicate a specifictimeline for startup, but industry sources expect the line would bebuilt no sooner than the fourth quarter of 2020.
A mysterious surge in emissions of an illegal ozone-destroying chemical has been tracked down to plastic foam manufacturers in China, according to an on-the-ground investigation published on Monday.
The chemical, trichlorofluoromethane or CFC-11, has been banned around the world since 2010 and is a potent destroyer of ozone, which protects life on Earth from UV radiation, and strong greenhouse gas. A shock rise in the gas in recent years was revealed by atmospheric scientists in May, but they could only narrow the source to somewhere in East Asia.
The Environmental Investigation Agency, a non-governmental organisation, has now identified widespread use of CFC-11 factories in China that make insulating foams. The EIA’s investigators identified factories that sold the chemicals needed for foam-making, then contacted and visited them.
“We were dumbfounded when out of 21 companies, 18 of them across China confirmed use of CFC-11, while acknowledging the illegality and being very blase about its use,” said Avipsa Mahapatra at the EIA. Furthermore, the companies said the use of CFC-11 was rife in the sector. “It was very clear. These companies, again and again, told us everybody else does this,” she said.
China is a major producer of the rigid polyurethane foams involved and the EIA calculates that if the illegal use of CFC-11 is pervasive in the 3,500 small- and medium-sized companies that make up the sector, then this would explain the surge. Without action, the CFC-11 emissions would delay the recovery of the planet’s ozone hole by a decade, scientists estimate.
“We didn’t know what on Earth someone would be using CFC-11 for – well, here’s one answer and that’s a surprise,” said Steve Montzka at the US National Oceanic and Atmospheric Administration in Colorado, whose team revealed the surge. “Despite efforts to get rid of this activity, it continues.”
He praised the EIA work, but cautioned that CFC-11 might be also produced by other activities and that this should not be ruled out: “If this one issue is targeted within China, we want to be sure that will take care of the problem.” New atmospheric measurements in east Asia should narrow down the total amount of CFC-11 being leaked and any hotspot locations in the next nine months, he said.
The EIA’s evidence has been passed to the Chinese government, which has already inspected and taken samples from some sites, and to officials at the Montreal Protocol (MP), the treaty that phased out ozone-killing chemicals. An MP working group is meeting in Vienna on 11 July and will consider the next steps.
“This week will be a critical moment for dialogue, resolve and action to ensure any illegal activities are fully investigated and urgently halted,” said Erik Solheim, the head of UN Environment, which hosts the MP. He said the EIA evidence was part of a wider body of scientific investigation taking place.
PU foams are used mainly as insulation in buildings, either sprayed into cavities or applied as solid panels, and are in high demand due to China’s construction boom. CFC-11 is easy to produce and $150 (£113) a tonne cheaper than the ozone-friendly alternative, according to the companies to which the EIA investigators spoke. The penalty in China for its use is a fine.
“The profit margins were very high, the demand was high and the risks were very low,” said Mahapatra. “That enabled these companies to use it so blatantly and is why we think this is so pervasive.”
A representative of one company, Aoyang Chemical Co, in Dacheng, Hebei province, told the EIA that 99% of its foams used CFC-11, bought from “shady and hidden” factories in Inner Mongolia. Another, from the nearby Wan Fu Chemical Co, said it was easy to avoid inspections: “When the municipal environmental bureau runs a check, our local officers would call me and tell me to shut down my factory. Our workers just gather and hide together.”
The EIA’s findings are supported by official Chinese government documents, with a 2016 report from environmental officials in Shandong province, a key region for foam production, stating: “There is still a large volume of illegally produced CFC-11 being used in the foam industry” and that its production is “highly concealed”. Other documents from Shandong showed one factory alone to have been producing 1,100 tonnes of CFC-11 in a year.
The EIA report acknowledges significant uncertainties in its calculation but believes it has been conservative in estimating 10,000-12,000 tonnes a year of CFC-11 leaking into the atmosphere from foam-making in China from 2012-17. The scientific study that revealed the surge estimated emissions between 8,000 and 18,000 tonnes over the same period.
Iron ore is starting to buckle after a series of warnings that prices are set to drop as global supply rises, and as investors fret about the potential impact of escalating trade tensions between the U.S. and China.
Benchmark spot ore eased to $62.50/t on July 5, the lowest since November, according to Mysteel. In Singapore, SGX AsiaClear futures sank as much as 1.5% to $62.88/t, the cheapest since April 9, while the contract on the Dalian Commodity Exchange fell almost 4% last week.
Since retreating into a bear market in March, iron ore has held in a narrow range in the mid-$60s as investors weigh robust steel production in top user China against prospects for increased mine supply. Last week, Australia, the world's largest shipper, forecast that prices will fall back into the $50s as output expands while China begins to reduce purchases. Lower prices reduce income for top miners Rio Tinto Group, BHP Billiton and Vale.
The "macro environment has been providing a key drag on sentiment with the looming trade tariffs," said Hui Heng Tan, a research analyst at Marex Spectron. That, coupled with both a period of lower demand and supply increases, means there's "a perfect storm in the making," Tan said.
Others expecting prices to ease include China's Orient Futures Co., as well as National Australia Bank. "Slowing steel demand in China should flow through into weaker demand for iron ore over the next few years," NAB said in a note. Prices are expected to drop toward $60 by the end of 2018, it said.
There are potential drivers for iron ore, including moves in China to redouble efforts to curb pollution. Recently, the State Council issued a three-year plan to tackle smog, tightening constraints on industrial production. In the past, similar measures have supported prices of premium iron ore products even as they mandated steel output curbs.
And Goldman Sachs said commodities are forecast to rise over the next 12 months as trade war concerns are overblown, although a note from the bank did not give an explicit outlook for iron ore. "The trade war impact on commodity markets will be very small," it said.
US Tariff history. Note that whereas the Smoot-Hawley tariff was general, the Trump tariff is specific to China.
By the late 1920s the economy of the United States had made exceptional gains in productivity due to electrification, which was a critical factor in mass production. Horses and mules had been replaced by motorcars, trucks and tractors. One-sixth to one-quarter of farmland, previously devoted to feeding horses and mules, was freed up, contributing to a surplus in farm produce. Although nominal and real wages had increased, they did not keep up with the productivity gains. As a result, the ability to produce exceeded market demand, a condition that was variously termed overproduction and underconsumption. Senator Smoot contended that raising the tariff on imports would alleviate the overproduction problem; however, the US had actually been running a trade account surplus, and although manufactured goods imports were rising, manufactured exports were rising even faster. Food exports had been falling and were in trade account deficit; however the value of food imports were a little over half that of manufactured imports.[7]
Most economists and economic historians argue that tariffs have played only a minor role in the Great Depression:
Douglas A. Irwin writes: "most economists, both liberal and conservative, doubt that Smoot Hawley played much of a role in the subsequent contraction. Milton Friedman also held the opinion that the Smoot-Hawley tariff of 1930 did not cause the Great Depression."[17]
William Bernstein writes "most economic historians now believe that only a minuscule part of that huge loss of both world GDP and the United States’ GDP can be ascribed to the tariff wars "because trade was only nine percent of global output, not enough to account for the seventeen percent drop in GDP following the Crash. He thinks the damage done could not possibly have exceeded 2 percent of world GDP and tariff "didn't even significantly deepen the Great Depression."(A Splendid Exchange: How Trade Shaped the World)
According to Paul Krugman, "Protectionism was a result of the Depression, not a cause. Rising tariffs didn’t even play a large role in the initial trade contraction"; "Where protectionism really mattered was in preventing a recovery in trade when production recovered".[18][19]
Peter Temin, explains a tariff is an expansionary policy (favourable to economic growth), like a devaluation as it diverts demand from foreign to home producers. He notes that exports were 7 percent of GNP in 1929, they fell by 1.5 percent of 1929 GNP in the next two years and the fall was offset by the increase in domestic demand from tariff. He concludes that contrary the popular argument, contractionary effect of the tariff was small. (Temin, P. 1989. Lessons from the Great Depression, MIT Press, Cambridge, Mass)[20]
Nobel laureate Maurice Allais, thinks that tariff was rather helpful in the face of deregulation of competition in the global labor market and excessively loose credit prior to the Crash which, according to him, caused the crisis Financial and banking sectors.He notes higher trade barriers were partly a means to protect domestic demand from deflation and external disturbances. He observes domestic production in the major industrialized countries fell faster than international trade contracted; if contraction of foreign trade had been the cause of the Depression, he argues, the opposite should have occurred. So, the decline in trade between 1929 and 1933 was a consequence of the Depression, not a cause. Most of the trade contraction took place between January 1930 and July 1932, before the introduction of the majority of protectionist measures, excepting limited American measures applied in the summer of 1930. It was the collapse of international liquidity that caused of the contraction of trade.[21]
The US ten year bond yield flagged a condition similiar to the 1930's earlier this decade.
A spokesperson for China's Ministry of Commerce Wednesday expressed solemn protest against the United States' announcement of a list of tariffs on 200 billon U.S. dollars of Chinese goods.
"The United States has unveiled the list of tariffs in an escalating manner. This is totally unacceptable, and we express our solemn protest against this," the spokesperson said.
"By doing this, the United States is hurting China, hurting the whole world, and hurting itself. The irrational act goes against the will of the people.
"China is shocked by what the United States did. To defend the core interests of the nation and the fundamental interests of the people, the Chinese government will, as always, be forced to take necessary countermeasures. In the meantime, we appeal to the international community to jointly defend free trade rules and the multilateral trade regime and fight trade bullying.
"We will immediately lodge an additional complaint with the WTO over the unilateral acts of the United States."
Rio Tinto is planning to consolidate its sales and marketing teams from London and other European locations into Frankfurt starting this autumn, as the miner moves staff away from its global headquarters in the UK capital.
The London Stock Exchange-listed company underscored marketing and commercial synergies for the consolidation, rather than comment on how the UK's Brexit process may have influenced the decision.
It followed a consultation with employees, which was reported in February.
Commercial department staff in London will start to move to Frankfurt after the summer with more following next year, according to sources close to the situation.
"Rio Tinto is proposing to consolidate its sales and marketing operations in Europe into one existing Rio Tinto location in Frankfurt," a company spokesman said.
"Consolidating Commercial's sales and marketing presence in Europe into one location will ensure closer proximity to key customers, simplify Commercial's footprint and leverage the benefits of co-location."
The decision to move staff away from London followed a move to a single site in St James's Square, in central London.
Many international banks have decided to move more staff into European cities such as Amsterdam, Dublin and Frankfurt with the UK scheduled to exit the EU on March 29, 2019.
Other than Frankfurt, the other regional hubs for the company will be Singapore -- where Rio Tinto has a large sales and marketing operation -- and Chicago, sources said.
"It is about bringing our sales and marketing operations in Europe, which are currently spread across a number of locations in a number of European countries together, closer to our key customers," the spokesman said.
"It simplifies our footprint. It is part of our global plans to bring people doing similar activities together which provides many benefits from working more closely together."
The Anglo-Australian group's global headquarters will remain in London and Chairman Simon Thompson and CEO Jean-Sebastien Jacques will be based there.
Rio Tinto has iron ore, aluminum and base metals mining and refining operations mainly in Australia, Canada, Mongolia and South Africa.
The company has been looking to invest and develop minerals such as lithium, to power new energy and metals applications and reduce emphasis on bulk minerals as Asian emerging economies mature.
Rio Tinto exited thermal and coking coal mining and sales after concluding a series of divestments over the past few years.
In Europe, the company has agreed to sell its aluminum assets, to focus on production of the alloy in Canada.
Rio Tinto's office in Frankfurt is focused on sales of titanium, zircon, high purity iron, steel and metal powders, and is based in Eschborn.
Russian Prime Minister Dmitry Medvedev has signed a decision imposing extra duties of 25% to 40% on some imports from the US in response to Washington's tariff move, the Russian economy ministry said on Friday.
The extra duties will apply to imports of fiber optics, equipment for road construction, the oil and gas industry, metal processing and mining, according to an economy ministry statement.
Russia will impose duties on goods which have Russian-made substitutes, Economy Minister Maxim Oreshkin is quoted as saying in the statement.
One of the world’s biggest cargo shippers announced on Saturday it was pulling out of Iran for fear of becoming entangled in U.S. sanctions, and President Hassan Rouhani demanded that European countries to do more to offset the U.S. measures.
The announcement by France’s CMA CGM that it was quitting Iran deals a blow to Tehran’s efforts to persuade European countries to keep their companies operating in Iran despite the threat of new American sanctions.
Iran says it needs more help from Europe to keep alive an agreement with world powers to curb its nuclear program. U.S. President Donald Trump abandoned the agreement in May and has announced new sanctions on Tehran. Washington has ordered all countries to stop buying Iranian oil by November and foreign firms to stop doing business there or face U.S. blacklists.
European powers which still support the nuclear deal say they will do more to encourage their businesses to remain engaged with Iran. But the prospect of being banned in the United States appears to be enough to persuade European companies to keep out.
Foreign ministers from the five remaining signatory countries to the nuclear deal — Britain, France, Germany, China and Russia — offered a package of economic measures to Iran on Friday but Tehran said they did not go far enough.
“European countries have the political will to maintain economic ties with Iran based on the JCPOA (the nuclear deal), but they need to take practical measures within the time limit,” Rouhani said on Saturday on his official website.
CMA CGM, which according to the United Nations operates the world’s third largest container shipping fleet with more than 11 percent of global capacity, said it would halt service for Iran as it did not want to fall foul of the rules, given its large presence in the United States.
“Due to the Trump administration, we have decided to end our service for Iran,” CMA CGM chief Rodolphe Saade said during an economic conference in the southern French city of Aix-en-Provence.
“Our Chinese competitors are hesitating a little, so maybe they have a different relationship with Trump, but we apply the rules,” Saade said.
The shipping market leader, A.P. Moller-Maersk of Denmark, already announced in May it was pulling out of Iran.
In June, French carmaker PSA Group suspended its joint venture activities in Iran, and French oil major Total said it held little hope of receiving a U.S. waiver to continue with a multibillion-dollar gas project in the country.
Total’s CEO Patrick Pouyanne said on Saturday the company had been left with little choice.
“If we continued to work in Iran, Total would not be able to access the U.S. financial world,” he told RTL radio. “Our duty is to protect the company. So we have to leave Iran.”
Iranian Oil Minister Bijan Zanganeh called the tension between Tehran and Washington a “trade war”. He said it had not led to changes in Iranian oil production and exports.
He also echoed Rouhani’s remarks that the European package did not meet all economic demands of Iran.
“I have not seen the package personally, but our colleagues in the foreign ministry who have seen it were not happy with its details,” Zanganeh was quoted as saying by Tasnim news agency.
Some Iranian officials have threatened to block oil exports from the Gulf in retaliation for U.S. efforts to reduce Iranian oil sales to zero. Rouhani himself made a veiled threat along those lines in recent days, saying there could be no oil exports from the region if Iran’s were shut.
Cairn Energy said on Monday it would write down the value of its investment in Vedanta Ltd after Indian tax authorities sold $216 million worth of its shares in the Indian mining company in a dispute over retrospective tax dues.
Cairn said it still holds about 3 percent in Vedanta Ltd after the sale, while warning that it was possible that the Indian tax department might make further sales.
The write down will result in an impairment charge in the company’s half year results in September equal to the value of the total shares notified as having been sold by the tax department at that time, Cairn said.
Indian metals and mining group Vedanta Ltd last year completed its buyout of oil and gas explorer Cairn India Ltd, giving Cairn a shareholding of about 5 percent in Vedanta plus an interest in preference shares. The investment was valued at about $1.1 billion at the end of 2017.
The tax authorities seized the shares after issuing Cairn with a $1.3 billion bill in 2014 on capital gains it said it had made on a decade-old reorganisation of its Indian business.
Cairn said that it would continue to fight the Indian authorities in an arbitration case over the bill with final hearings due in two weeks.
Indian authorities had already seized dividends due to Cairn from its shareholding in Vedanta totalling about $155 million and had offset a tax rebate of $234 million due to Cairn as a result of overpayment of capital gains tax on a separate matter, the company said.
German companies signed a raft of agreements with Chinese partners at a meeting of Chinese Prime Minister Li Keqiang and German Chancellor Angela Merkel in Berlin on Monday, according to a document seen by Reuters.
Chemicals giant BASF agreed with the government of Guangdong province on a plan for a new site in China, and business software maker SAP struck a strategic cooperation agreement with Suning Holdings Group, the document showed.
Siemens agreed with China’s State Power Investment Co on joint development of a high-performance gas turbine, and with Alibaba Cloud Computing on a cooperation on an Internet of Things platform, it said.
Also, carmaker BMW struck a deal with China’s Brilliance Group to expand their joint venture, while Volkswagen and China’s Anhui Jianghuai Automobile Group signed a Memorandum of Understanding on a joint research and development centre and a car platform.
China has jailed hundreds of officials for failing to tackle environmental violations uncovered during inspections last year, the environment ministry said in the latest round of the “war on pollution” led by President Xi Jinping.
A total of 4,305 officials in 10 provinces and regions had been held to account for failing to rectify violations, with some of them facing fines and even jail time, the ministry said late on Monday.
Beginning at the end of May, central government inspectors started re-examining thousands of violations uncovered during the nationwide environmental audit, and found that many of the problems had not been properly resolved.
They have already accused local governments and state-owned enterprises across the country of conducting “perfunctory” or even “fraudulent” rectifications.
Total fines of 510 million yuan ($77.13 million) had already been issued in the 10 regions, which include the two biggest steel producing provinces of Hebei and Jiangsu, as well as Yunnan and Ningxia in the far west and Guangdong in the southeast, the Ministry of Ecology and Environment said.
This round of inspections involved a total of 28,076 violations. The ministry said 464 officials had been subject to administrative or criminal detention.
China is in the fifth year of its war on pollution and Xi vowed in May to use the full might of the ruling Communist Party to tackle longstanding environmental problems.
China's air quality has improved across the country, showed a report on the implementation of the Air Pollution Control Law on July 9.
The Air Pollution Control Law and the action plan on air pollution control have been well implemented across the country since the 18th Communist Party of China National Congress in 2012, said the report submitted for review at a session of the National People's Congress (NPC) Standing Committee, which runs from July 9-10.
The implementation of the law and the action plan on air pollution control has seen positive achievements, said the report.
The NPC Standing Committee sent four teams to the country's eight provincial-level regions, including Henan, Inner Mongolia and Shanxi, to check the implementation of the Air Pollution Control Law from May to June. They also entrusted local legislatures in 23 other provincial-level areas with law enforcement inspection.
The average density of PM10 in 338 Chinese cities at prefecture level and above in 2017 decreased by 22.7% compared to 2013 levels, while the average density of PM2.5 in major areas including the Beijing-Tianjin-Hebei region, the Yangtze River Delta and the Pearl River Delta, fell 39.6%, 34.3% and 27.7% respectively, said the report.
China cut steel production capacity by 170 million tonnes per annum (Mtpa), coal by 800 Mtpa, and cement by 230 Mtpa over the past five years, the report noted.
The proportion of coal consumption dropped 8.1 percentage points while the proportion of clean energy in total energy consumption increased by 6.3 percentage points over the past five years, it said.
China's top legislature called on July 9 for strengthened air pollution control measures in key sectors as it concluded inspections on the implementation of the Air Pollution Control Law and found the law is not adequately applied in some areas.
The legislature's inspections in eight provincial regions, including Henan, Shandong and Jiangsu provinces, found many local governments failed to implement measures as required by the law to control air pollutants from bulk coal consumption, straw burning, construction sites, mines and motor vehicles, top legislator Li Zhanshu told a session of the Standing Committee of the National People's Congress on July 9.
Bulk coal is a major contributor to smog in northern China during the winter. Li said more than 200 million tonnes of bulk coal is consumed in the region as a heating source each winter. Calculations by authorities showed that air pollutants from a tonne of bulk coal used for heating equals that of 10 to 15 tonnes of coal used in power generation.
The Air Pollution Control Law stipulates that governments of all levels should take measures to strengthen bulk coal management. Some local governments in Shanxi and Shaanxi provinces, however, were found to have made slow progress in replacing the polluting energy with clean ones, Li said.
More than 20 million tonnes of bulk coal is consumed every year in the Guanzhong region of Shaanxi, home to five cities including the province's capital Xi'an. Bulk coal is still widely used in old communities in urban areas, shantytowns and rural areas in the region. Local governments failed to carry out control measures "effectively", the legislator said.
Another major problem legislators found is that some local governments haven't made sufficient efforts in supervising fuel quality and controlling pollution from motor vehicles. Motor vehicles have taken a larger share as a source of pollution as many areas have shifted to cleaner fuels for energy and heating.
There are special clauses on pollution control with motor vehicles and fuel quality supervision, but it's common to see diesel trucks with substandard pollution control measures or even no such measures at all, Li told the session.
Some of the local authorities had inadequate capability in vehicle supervision and some failed to fulfill their duties in the supervision work. Vehicle testing institutes in some areas even falsified testing results, noted Li.
There are also gaps in the supervision of fuel manufacturing and circulation in some regions. While there were unlicensed enterprises manufacturing fuel illegally and no government departments in these regions were in charge of supervising the diesel in the market, Li said.
Some enterprises were also blamed for failure in implementing pollution control measures as required by the law.
The law stipulates that enterprises in steel, construction materials, petroleum and chemical industries should resort to clean technologies in production and install pollution control facilities.
Chinese President Xi Jinping on Tuesday pledged a package of $20 billion in loans, and about $106 million in financial aid, to Middle East nations, as part of what he called an “oil and gas plus” model to revive economic growth in the region.
Beijing has ramped up engagement in the Middle East in recent years as Arab nations play an important role in Xi’s signature Belt and Road foreign policy plan for strong trade routes linking China with central and southeast Asia.
Development was key to resolving many security problems in the Middle East, Xi told a gathering with representatives of 21 Arab nations in the Chinese capital.
“We should treat each other frankly, not fear differences, not avoid problems, and have ample discussion on each aspect of foreign policy and development strategy,” he said.
China would offer aid worth 100 million yuan ($15 million) to Palestine to support economic development, besides providing a further 600 million yuan ($91 million) to Jordan, Lebanon, Syria and Yemen, he added.
A consortium of banks from China and Arab nations, with a dedicated fund of $3 billion, will also be set up, he said.
It was unclear what the relationship between the bank consortium, financial aid and the overall loan package would be.
The loans will fund a plan of “economic reconstruction” and “industrial revival” that would include cooperation on oil and gas, nuclear and clean energy, Xi said.
He urged “relevant sides” to respect the international consensus in the Israel-Palestine dispute, and called for it to be handled in a just manner, so as to avoid regional disruption.
China, which traditionally played little role in the Middle East conflicts or diplomacy, despite its reliance on the region for energy supplies, has been trying to get more involved in resolving long-standing disputes.
China says it sticks to a policy of “non-interference” when offering financial aid and deals to developing countries, which, coupled with development, can help resolve political, religious and cultural tension.
It applies this pattern of economic support, as well as a strict security regime, to its restive western region of Xinjiang. But rights groups have criticized the approach, saying the clampdown has further stoked, not eased, tension between the Muslim Uighur minority and the ethnic Han majority.
All of China's major polluters will need to install real-time emissions monitoring systems before the end of the year, according to a report submitted to parliament on July 9, as the country tries to improve surveillance and bring lawbreaking firms into line.
China is now in the fifth year of its war on pollution, and President Xi Jinping said in May that the country would use the full might of the ruling Communist Party to fix the damage done by four decades of untrammeled economic growth.
According to the National People's Congress (NPC) report, published by state news agency Xinhua, China's central government has already spent 52.8 billion yuan ($7.98 billion) to improve air quality over the 2012 to 2017 period.
But some regions are still way behind when it comes to monitoring and cracking down on pollution, it said, and China will work to create a comprehensive nationwide monitoring system by the end of the decade, extending full coverage to smog-prone cities in the country's central and western regions.
Though China has tried to create a national surveillance system that would enable regulators to identify violations in real time, monitoring standards and compliance levels have so far been uneven.
During a nationwide inspection program completed last year, the central government uncovered thousands of violations throughout China's 31 provinces and regions, and according to recent reviews, many of the problems still have not been properly rectified.
The report to parliament also promised that all households in the Beijing-Tianjin-Hebei and Shanxi-Shaanxi regions would make the switch from coal to natural gas heating by 2020 as part of efforts to curb smog.
China already converted more than 4.7 million households and 62,000 enterprises from coal to gas over the 2012 to 2017 period, but the acceleration of the program last year led to severe fuel shortages across the northern regions during the winter.
China also installed ultra-low emissions technology on more than 700 gigawatts of coal-fired power capacity in the last five years, equal to 71% of the country's total coal-fired power capacity. It also eliminated more than 20 million substandard vehicles from its roads over the period, the report added.
A “reckoning” over China’s unfair trade policies can be put off no longer, but many of the most significant problems cannot be handled by the World Trade Organisation, U.S. ambassador Dennis Shea told a WTO meeting on Wednesday.
“Given China’s very large and growing role in international trade, and the serious harm that China’s state-led, mercantilist approach to trade and investment causes to China’s trading partners, this reckoning can no longer be put off,” Shea said at a two-yearly review of China’s trade policies, according to a copy of his remarks prepared for delivery at the meeting.
Glencore Plc said on Wednesday it would cooperate with U.S. authorities after they demanded documents about the mining firm’s business in Democratic Republic of Congo, Venezuela and Nigeria as part of a corruption investigation.
The company said it had set up a committee of board members, including Chairman Tony Hayward and independent non-executive directors Leonhard Fischer and Patrice Merrin, to oversee its response to the subpoena from the Department of Justice (DoJ).
“The company will cooperate with the DoJ, while continuing to focus on our business and seeking to maximize the value we create for our diverse stakeholders in a responsible and transparent manner,” Hayward said.
“Glencore takes ethics and compliance seriously throughout the group,” the chairman said.
Switzerland-based Glencore received a subpoena from the DoJ last week requesting documents and records on compliance with the U.S. Foreign Corrupt Practices Act and money-laundering statutes.
The U.S. Foreign Corrupt Practices Act makes it a crime for companies to bribe overseas officials to win business.
The DOJ has so far not commented on the request.
Glencore shares had fallen 4.2 percent to 313.29 pence by 0921 GMT, down 20 percent since the start of 2018 and close to one-year lows. The stock suffered its biggest one-day fall in more than two years after the subpoena announcement last week.
Responding to the share fall, Glencore announced a buy back worth $1 billion in an effort to soothe investors.
Some analysts say the U.S subpoena could be a result of Glencore settling a mining row in Congo with Israeli billionaire Dan Gertler, under U.S. sanctions since last year, by agreeing to pay royalties in euros.
Congo accounts for about 25 percent of Glencore’s net present value, analysts said, adding that Venezuela and Nigeria’s contribution was negligible. The firm mines cobalt in Congo, a key metal used to make batteries for electric vehicles.
The president of China’s CIC sovereign wealth fund said on Wednesday that a trade war appeared unavoidable, and that the dispute would have a negative impact on CIC’s investments.
“None of us is hoping for this trade war, (but) it seems to be unavoidable,” said China Investment Corp (CIC) President Tu Guangshao, who was speaking at a financial conference in Paris.
China has accused the United States of bullying and warned it would hit back after President Donald Trump’s administration raised the stakes in their trade dispute, threatening 10 percent tariffs on $200 billion of Chinese goods.
China’s commerce ministry said on Wednesday it was “shocked” and would complain to the World Trade Organisation, but did not immediately say how it would retaliate. In a statement, it called the U.S. actions “completely unacceptable”.
The U.S. Senate made a minor effort to push back against President Donald Trump’s trade policies on Wednesday by backing a non-binding motion to give Congress a role in his decisions to impose tariffs for national security reasons.
The vote was 88-11 in favor of the measure, part of an effort led by some of Trump’s fellow Republicans who support free trade to resist the president’s escalating effort to address what he sees as unfair foreign trade.
They worry that trade disputes with China, as well as with allies like western European nations and Canada, could damage the U.S. economy by harming U.S. employers and raising prices for consumers.
The vote came as China accused the United States of bullying and warned it would hit back after the Trump administration raised the stakes in a trade dispute by threatening 10 percent tariffs on $200 billion of Chinese goods.
However, the Senate’s Republican leaders have not yet allowed a binding vote on legislation introduced in June to require congressional approval of any tariffs imposed for national security reasons.
Republicans, who have majorities in both the Senate and House of Representatives, have backed almost all of Trump’s initiatives since he became president in January 2017.
Some lawmakers have spoken out against his policies on trade and in other areas but they have not used tactics such as withholding votes for his nominees as a way of influencing the White House.
The measure’s main sponsors - Republican Senators Bob Corker, Jeff Flake and Pat Toomey - said they considered Wednesday’s action a “test vote” on the issue.
Corker acknowledged in remarks in the Senate that the vote was a “baby step” but said he would continue to push for a binding vote and was “hopeful” that one would be scheduled in the near future.
The non-binding measure approved on Wednesday was a “motion to instruct” lawmakers finalizing a water and energy spending bill to ensure that Congress plays a role in implementing such tariffs.
China's identified mineral and energy reserves have grown significantly over the past five years, the Ministry of Natural Resources (MNR) said.
Many new deposits of major strategic minerals - including gold, natural gas, shale gas, flake graphite and tungsten - were discovered from 2012 to 2017, according to a report by the ministry.
Flake graphite, which has a wide range of applications, including fuel cells, coatings and thermal materials, saw the biggest increase in reserves - nearly doubling.
Gold reserves grew by 61% while those for tungsten rose 47.9% during the period.
Shale gas, a new energy source that China began to explore in 2005, has the greatest potential, according to Ju Jianhua, leader of the ministry's working group that handles the protection of mineral resources.
Last year, recoverable shale gas reserves hit 198 billion cubic meters, an increase of 62% over 2016, while last year's new total shale gas reserves were estimated to be as high as 377 billion cubic meters.
Four big shale gas fields were discovered in the Sichuan Basin in Southwest China, of which two, found last year, were estimated at more than 100 billion cubic meters each.
"China is now among the few countries in the world that are conducting large-scale commercial extraction of shale gas," Ju said.
He said mineral resources are fundamental to China's social and economic development. Currently, the country faces challenges including a lack of technological innovation and an increasing dependence on imports of some minerals from foreign countries, including chrome and cobalt, which are commonly used in gas turbines.
Last year, a total 77 billion yuan ($11.6 billion) was invested in mineral exploration, the ministry said.
Mexican president-elect outlines priorities but doesn't mention energy reforms
Mexican president-elect Andres Manuel Lopez Obrador did not mention Mexico's energy reform in his top 12 legislative priorities as he laid out a blueprint for fulfilling the promises made.
China’s aluminium exports exceeded half a million tonnes for only the second time ever in June as stronger international than domestic prices encouraged overseas shipments, while steel exports hit an 11-month high, defying U.S. tariffs.
China is the world’s biggest producer of both steel and aluminium, which have been subject to 25 percent and 10 percent import tariffs, respectively, in the United States, the world’s largest economy, since March 23.
Unwrought aluminium and aluminium product exports were 510,000 tonnes last month, China’s General Administration of Customs said on Friday..
That was up 10.9 percent from 460,000 tonnes a year ago. Exports also topped a revised 480,000 tonnes in May, which was previously the second-highest figure on record behind only the whopping 542,700 tonnes exported in December 2014.
Exports for the first half of the year were at 2.713 million tonnes, up 12.8 percent from 2.405 million tonnes a year earlier, customs said.
Meanwhile, steel product exports for June climbed 1.9 percent year on year to 6.94 million tonnes, hitting their highest since July 2017. Exports were up 0.9 percent from 6.88 million tonnes in May.
For the first half, steel exports were 35.43 million tonnes, down 13.2 percent year on year, customs said.
OPEC's largest oil producer is turning its taps on after 16 months of curbing output.
It comes with oil prices back on the brink of $80/b spurred by sharp supply outages from Venezuela and Libya and with the potential for the market to tightening further due to looming sanctions on Iran's oil sector. Saudi Arabia has changed its tone since May, reassuring some of the world's biggest crude oil consumers, especially the US and India, that it is willing to balance the market.
That has drawn fellow OPEC member Iran's ire, which has questioned whether changes to its production cut agreement in June to pump an extra 1 million b/d can come at the expense of other member's market share.
Saudi Arabia, meanwhile, continues to reiterate its readiness to use its spare oil production capacity to meet any future changes in oil supply and demand "when needed".
The kingdom has always maintained it can boost output by up to 2 million b/d and over the weekend it reassured the US it can deliver.
But S&P Global Platts Analytics believes the global crude market could be left short by that very same 2 million b/d by the end of the year.
The question whether the world's only swing producer has both the means and the motivation to pump to the maximum to meet global oil supply shortages at short notice and for the long-term therefore needs an answer.
PRODUCTION PROFILE
While Saudi Aramco CEO Amin Nasser told Platts recently that "maximum sustainable production" was 12 million b/d up from 10.03 million b/d in May, industry experts believe Saudi Arabia will struggle to pump more than 1 million b/d of additional output.
Platts Analytics says even if Saudi Arabia produces close to 11 million b/d it would be running its system at stress levels.
Saudi crude production averaged 9.96 million b/d from January to May this week, according to Platts OPEC survey data and is set to add at least 300,000 b/d in June according to preliminary survey data as it starts to empty some of its tanks.
Saudi crude output averaged 10.38 million b/d in 2016, before OPEC and non-OPEC started their production cuts.
SPARE CAPACITY
EIA defines spare capacity as the volume of production that can be brought on within 30 days and sustained for at least 90 days.
In the longer term Saudi Arabia could possibly reach the 12 million b/d but it would take significant time and investment and doesn't fit the spare capacity definition.
There is the possibility of an emergency surge in output towards 12 million b/d whereby oil fields are depleted beyond what would be considered a reasonable rate and could end up damaging its production abilities further out.
NEUTRAL ZONE
Saudi Arabia shares with Kuwait a partitioned neutral zone that can generate up to 500,000 b/d.
The closure of the key fields, Khafji and Wafra, has led to a political stand-off between the two OPEC producers.
The restarts of these fields will be crucial for the kingdom if it wants to reach its 12 million b/d target.
Earlier this week, Japan's Toyo Engineering said the Khafji oil field shared by Saudi Arabia and Kuwait is being prepared to restart production in 2019.
Khafji was shut in October 2014 for environmental reasons and Wafra has been shut since May 2015 due to operational difficulties.
Industry experts believe it will take time for production to return should the issue be resolved.
KEY TERMINALS
The country's largest oil export terminals are in the port of Ras Tanura.
The port can handle capacity of about 6.5 million b/d, according to the EIA.
All of Saudi's key crude oil grades load from here along with condensate and products.
The port comprises three terminals: Ras Tanura terminal, Ju'aymah crude terminal, and Ju'aymah LPG export terminal.
The Ras Tanura crude terminal has a 33 million barrels storage capacity.
Sea shipping capacity is crucial to Saudi Arabia given that it lacks international pipelines.
The other key crude export terminal is the King Fahd terminal in Yanbu on the Red Sea, which has a loading capacity of 6.6 million b/d.
Total crude oil storage capacity at the terminal is 12.5 million barrels.
Only Arab Light crude oil grade is loaded at the Yanbu terminal.
Saudi Arabia has other smaller ports, including Ras al-Khafji, Jubail, Jizan, and Jeddah.
KEY BUYERS
The main customers of the kingdom's oil are in Asia, with the region taking almost two-thirds of the country's oil exports.
Japan, China, India and South Korea are the largest buyers of Saudi crude. The main buyers in this region are China's Unipec, CNOOC and Sinochem; Japan's Nippon Oil Corporation, Cosmo Oil, Idemitsu Kosan; and India's IOC, BPCL and Reliance.
The US, a key ally of the kingdom, is also a sizeable buyer, taking around 15% of Saudi crude exports.
Saudi Aramco operates the 603,000 b/d Port Arthur refinery in Texas, which is a pivotal buyer.
Flows to Europe are around 10% of Saudi crude loadings with the bulk being exported from the Sidi Kerir terminal in Egypt.
CRUDE QUALITY, EXPORT GRADES
Saudi crude is generally a mix of heavy to medium sour oil, which is generally high in sulfur and yields a decent amount of residual fuel and vacuum gasoil.
The oil is particularly popular with complex refineries in Asia, US and Europe which can crack heavy sulfurous crudes, and still yield distillate products due to the refiners having complex secondary units.
The key export grades are Arab Heavy, Arab Medium, Arab Light and Arab Extra Light.
Some of Saudi's key oil fields are Ghawar, Khurais, Shaybah, Safaniyah, Qatif and Zuluf.
EXPORT EXPANSION
Saudi Aramco plans to begin exports from the Muajjiz oil terminal on the Red Sea sometime before the end of 2018.
This would raise Saudi Arabia's total loading and (crude and products) export capacity to about 15 million b/d from 11.5 million b/d.
CRUDE BURN
Liquid fuels continue to account for half of the current energy mix.
Saudi Arabia burned an average of 458,000 b/d of crude last year in its power plants, with a peak of 680,000 b/d in June, according to the Riyadh-based Joint Organizations Data Initiative.
The government hopes to increase the share of gas used to 70% over the next 10 years, nearly doubling its current gas production to 23 Bcf/d by 2026.
It processed an all-time high of 12 Bcf/d of raw gas in 2016, producing 8.3 Bcf/d of sales gas.
That was up from around 8 Bcf/d of sales gas in 2015, according to its annual review released in June last year.
Asian oil refiners are racing to secure crude supplies in anticipation of an escalating trade war between the United States and China, and as Washington plans tough sanctions against Iran aimed at shutting the country out of oil markets.
As part of a wave of retaliation for Friday’s U.S. tariffs, China has threatened a 25 percent duty on imports of U.S. crude. Meanwhile, Washington’s new sanctions against Tehran are due to kick in from November.
That double whammy is prompting Asian refiners to move swiftly, with South Korea leading the way. Under Washington’s gaze, Seoul pressure has halted all orders of Iranian oil, according to sources, even as it braces from spillover effects from the U.S.-China tit-for-tat on trade.
“As South Korea’s economy heavily relies on trade, it won’t be good for South Korea if the global economic slowdown happens because of a trade dispute between U.S and China,” said Lee Dal-seok, senior researcher at the Korea Energy Economic Institute.
In China, state media slammed U.S. President Donald Trump’s government as a “gang of hoodlums”, with officials vowing retaliation. Standing in the line of fire are U.S. crude supplies to China, which have surged from virtually zero before 2017 to 400,000 barrels per day (bpd) in July.
Although just 5 percent of China’s overall crude imports, these supplies are worth $1 billion a month at current prices - a figure that seems certain to fall.
“The Chinese have to do the tit-for-tat, they have to retaliate,” said John Driscoll, director of consultancy JTD Energy, adding that cutting U.S. crude imports was a means “of retaliating (against) the U.S. in a very substantial way”.
OPPORTUNITY KNOCKS ELSEWHERE?
In an early sign of future times, an executive from China’s Dongming Petrochemical Group, an independent refiner from Shandong province, said his refinery had already cancelled U.S. crude orders.
“We expect the Chinese government to impose tariffs on (U.S.) crude,” the executive said, declining to be named as he was not authorised to speak to media. “We will switch to either Middle East or West African supplies,” he said.
JTD Energy’s Driscoll said China may even replace American oil with crude from Iran. “They (Chinese importers) are not going to be intimidated, or swayed by U.S. sanctions,” he said.
In Japan, Asia’s third-biggest importer of crude, the oil industry has yet to react publicly to Friday’s news. The Petroleum Association of Japan previously warned refiners will have to stop loading Iranian crude oil from October if Tokyo doesn’t win an exemption on U.S.-Iran sanctions.
Amid the turmoil, some in the region spot opportunity.
“If China retaliates with tariffs on U.S. crude, that could improve South Korea’s terms of buying U.S. crude...because the U.S. would need a market to sell to,” said Lee Dal-seok at the Korea Energy Economic Institute.
Highlighting that issue, JTD Energy’s Driscoll said U.S. oil sellers were “already discounting” their crude.
Libya’s Tripoli-based National Oil Corporation (NOC) is asking for U.N. sanctions against 48 individuals and entities they accuse of trying to sell oil illicitly in a struggle over the country’s oil wealth.
In a letter circulated to foreign embassies and the United Nations, and seen by Reuters, NOC Chairman Mustafa Sanalla described a “surge” in attempts by eastern factions to market oil ahead of them taking control last month of key fields and export terminals.
Since 2014 Western powers and U.N. Security Council resolutions have backed the NOC in Tripoli, the capital, as the sole legitimate producer and seller of Libyan oil, warning that illicit exports could lead to further fragmentation of the divided country. That has deterred buyers and banks wary of dealing with an unrecognised entity.
But Sanalla’s letter and copies of contracts that NOC Tripoli says were passed on by people involved in oil trading allege that a parallel NOC in the eastern city of Benghazi has stepped up its campaign to market oil under Faraj Said, head of the firm since last August.
“This ‘NOC Benghazi’, headed by Faraj Said, is pursuing a complex and combined strategy, focussed on destabilising NOC, including via illicit exports, contracts and blockades, to ultimately gain control of Libyan oil,” Sanalla wrote.
The letter was sent mid-June, about 10 days before forces loyal to eastern-based commander Khalifa Haftar announced that they would hand east Libyan ports and fields to the Benghazi NOC, raising the stakes over the contest for the sparsely populated country’s oil.
Production has plummeted by about 850,000 barrels per day (bpd) from little more than one million bpd, as eastern officials have blocked tankers booked by NOC Tripoli from loading, effectively shutting Zueitina and Hariga ports. Haftar’s Libyan National Army (LNA) has also prevented NOC Tripoli from reopening Ras Lanuf and Es Sider, after fending off an armed attack against the ports last month.
The standoff is part of a wider conflict that developed after the Nato-backed uprising against Muammar Gaddafi seven years ago. Factions aligned with rival governments in the east and west have competed for power since disputed elections in 2014.
OIL INCOME STRUGGLE
About three-quarters of Libya’s oil production is based in the east, but oil sales and revenues have been processed through Tripoli, home to an internationally backed interim government.
Some in the east have long complained that they receive too few oil revenues, though officials in Tripoli dispute that. The LNA said this week that it was seeking the replacement of the central bank governor in Tripoli, who it also blames for funnelling money to its armed opponents — a charge that central bank officials in the capital deny.
Said and his office could not be reached for comment. He told Reuters last week that NOC east, which claims legitimacy through an eastern parliament and government, was not “rushing” oil sales. “The important thing is for the oil money to go to a safe place,” he said.
Sanalla’s letter says that even before eastern factions announced they would take over oil ports, they had tried in May to export 600,000 barrels from Hariga port on a tanker named Phaedra Bright 1, but the tanker was persuaded to turn back before it loaded.
According to NOC Tripoli, NOC Benghazi has been offering buyers substantial discounts that would lead to losses in revenue of at least $821 million. NOC Tripoli estimates that Libya is already losing more than $67 million daily because of the port stoppages.
Sanalla called for travel bans and asset freezes under a U.N. sanctions regime to be imposed on Said and other senior NOC Benghazi officials, as well as on traders and energy companies allocated contracts by the eastern NOC.
Failure to act could have “grave consequences for peace and security in Libya”, Sanalla wrote.
“In particular, I am concerned that these efforts may accelerate ahead of the elections planned for December, and that they may create conditions that interfere with the acceptance by certain segments of the Libyan population of election results.”
China: Operating rates at independent refineries, known as teapots, in eastern Shandong province fell to 61.08% of capacity in week to July 5, according to industry website Oilchem.net . Rate drop for 3rd straight week, falling to lowest level since Sept.
@staunovo
S&P Global Platts, the company that sets the key price of Brent crude, is contemplating the eventual incorporation of U.S. oil to help calculate one of its newest European benchmarks, a sign of just how much America’s booming exports are reshaping global energy trading.
The publisher of prices used to settle physical crude trades is deliberating whether it might one day include U.S. oil when assessing Brent crude delivered to the Dutch port of Rotterdam, the company said on Wednesday. The potential change doesn’t apply to its widely used Dated Brent benchmark that’s based on prices where oil is loaded.
U.S. crude exports have surged since the nation lifted all restrictions on overseas shipments in late 2015, reaching an unprecedented 3 million barrels a day at the end of June. Commodities giant Trafigura Group this week offered to sell a cargo of American oil for delivery to Rotterdam on a Platts-run trading window, at least the third time this year that a trader has sought to do so.
“A number of crude grades could one day be considered for inclusion” in Platts’ Rotterdam assessment, said Joel Hanley, senior director for European oil pricing at the company. “These should be grades currently being delivered into the region, which could start with current North Sea grades and be expanded into others, could include grades from West and North Africa, the Mediterranean, as well as the U.S.”
While the main benchmark has the name Brent, in practice it reflects the price of five different grades loaded in the North Sea since the original field with that name now pumps far too little to underpin a reliable benchmark.
But with the region’s production facing a structural decline, Platts started the new Rotterdam-delivered assessment in March 2016. When it did so, it said the pool of crudes could be widened if suitable grades could be found. Platts said at the time that the new Rotterdam marker would help the market if ever liquidity underpinning the Dated Brent benchmark dried up.
Historically, while European and U.S. oil prices have tracked one another, they’ve also traded based on their own supply-and-demand dynamics. The difference between Brent and West Texas Intermediate futures, currently around $6.50 a barrel, remains one of the most-traded energy spreads in the world today.
The main Dated Brent marker was started in 1987. As production declined, Platts added Forties and Oseberg crude in 2002, followed by Ekofisk in 2007 and Troll in December last year. While the additions helped the benchmark’s liquidity, they also add a layer of complexity. Platts uses “quality premiums” and “de-escalators” to adjust for the different properties found in various grades, particularly sulfur.
There’s no guarantee that U.S. crude will ever actually become part of any Brent price, and such alterations often take a long time to become reality. For example, talk over the past few years of using Russia’s Urals crude to help formulate North Sea oil prices has more recently quietened down.
https://www.energyvoice.com/oilandgas/176252/us-oil-could-soon-help-set-the-brent-crude-price/
Saudi Aramco will provide full-term crude contractual volumes to customers in Japan for barrels across available grades loading in August, sources with direct knowledge of the matter said Monday.
However, it was not immediately clear whether the state-owned oil giant will also restore normal operational tolerance to its customers in Japan from August, following the recent OPEC/non-OPEC agreement, industry sources said.
S&P Global Platts reported on July 5 that state-owned Abu Dhabi National Oil Co. was set to provide full-term crude contractual volumes and restore normal operational tolerance to customers in Asia next month, marking a clear shift after more than a year of supply cuts.
ADNOC has told its various Asian customers it will not cut its term crude contractual volumes and, in fact, allow up to an additional 5% above its term volumes, for cargoes loading in August, sources with direct knowledge of the matter said.
For the first time ever, U.S. crude oil exports have hit the 3 MMb/d mark — a once-unthinkable pace equivalent to sending out 10 fully loaded Very Large Crude Carriers a week. VLCCs, with their 2-MMbbl capacity and rock-bottom per-bbl delivery costs, are the most cost-effective way to transport crude to distant markets like China and India. But there’s still only one terminal on the Gulf Coast that can fill a VLCC to the brim — the Louisiana Offshore Oil Port — and pipeline connections from key Texas and Oklahoma plays to LOOP are limited. Elsewhere along the coast, VLCCs need to be loaded in offshore deep water by reverse lightering from smaller vessels — a slower and more costly loading process. Change is a-comin’, though. Companies are testing the docking and partial loading of VLCCs at terminals along the Texas coast, and plans for a number of greenfield facilities capable of partially — or even fully — loading the gargantuan vessels at the dock are being considered. Today, we review the latest efforts to streamline the loading of VLCCs and what they mean for crude-export economics.
As we said in our last look at VLCCs a few months ago (Rock the Boat), the use of the supertankers during the U.S.’s 40-year ban on most crude exports was largely limited to imports to LOOP, occasional shipments out of the Valdez Marine Terminal in Valdez, AK (the southern terminus of the Trans-Alaska Pipeline System) and into Andeavor’s Berth 121 in Long Beach, CA — the two other U.S. facilities designed to handle VLCCs. Since the export ban was lifted in December 2015, though, crude exports — and interest in using VLCCs for exports out of the Gulf Coast — have been on the upswing. Figure 1 shows that in 2015, the last year the ban was in place, exports (almost all of them to Canada) averaged 465 Mb/d, according to the Energy Information Administration (EIA). Exports rose 27% (to just about 590 Mb/d) in 2016, then almost doubled in 2017 (to more than 1.1 MMb/d).
Figure 1. U.S. Crude Exports by Week (in Mb/d). Source: EIA
Export volumes continued rising through the first half of 2018, averaging 1.8 MMb/d so far and hitting an all-time high — an even 3 MMb/d — in the week ended June 22.
VLCCs are the Airbus A380s of the crude-shipping world — highly efficient, long-distance conveyors of valuable cargo (crude and people, respectively). An A380 is a double-decker, wide-body jet airliner that can transport up to 850 (!) passengers in (God forbid) an all-economy configuration (or 525 in a typical first-class/business/economy layout) more than 8,000 miles at a cruising speed of about 560 miles per hour (mph). VLCCs may be much, much slower (traveling at about 14 knots, or 16 mph), but they can move about 2 MMbbl of crude oil, the equivalent of about five hours’ worth of U.S. production. The supertankers have an average length of about 1,100 feet, with an average beam (or width) of nearly 200 feet and an average fully loaded draft of 72 feet.
There are about 800 VLCCs operating in the world today, with an increasing number being filled with U.S. crude along the Gulf Coast and sent to faraway ports in Europe and Asia. The vast majority of the VLCCs being used to export crude from the U.S. are reverse-lightered in designated trans-shipment areas (TSAs) off the Texas and Louisiana coasts. Reverse lightering is a multi-day process that involves anchoring an empty VLCC in a TSA and using Aframax-class tanker (capacity ~750 Mbbl) or other smaller vessels to ferry crude from the terminal to the VLCC. According to our friends at Navigistics, transporting crude from a fully reverse-lightered VLCC from a TSA off Corpus Christi to various Asian destinations (Singapore and Ulsan, South Korea) would cost about $3/bbl less than shipping it the same distance on a smaller tanker. That’s half the transportation cost — quite a savings when you consider the VLCC’s 2-MMbbl capacity.
What would be even more cost-efficient, though, would be fully or at least partially loading a VLCC at a land-based marine terminal or an offshore terminal connected to land by pipeline — and, if only partial loading is possible due to physical constraints (most likely the water depth of the channel or alongside the terminal), topping off the vessel with partial reverse lightering out in a TSA. LOOP, which consists of three single-point mooring buoys (in 110-foot-deep water) and a pumping station connected by a 48-inch-diameter pipeline to the Clovelly, LA, storage facility, is still the only Gulf Coast option for fully loading a VLCC without at least some reverse lightering. To date, LOOP has sent out a total of three fully loaded VLCCs, the most recent being the Eagle Vancouver, which left LOOP on June 27 and is now bound for India. (The first and second loadings at LOOP occurred in February and March of this year.) There’s a catch with exporting through LOOP, however. As we said in Clovelly Calling?, the Clovelly hub is currently the only source of crude for exports out of the offshore terminal — the hub and LOOP are linked by what is the now-bidirectional LOOP Pipeline. While Clovelly has some 70 MMbbl of underground salt-cavern and aboveground tank storage (more than enough to line up the 2 MMbbl needed to fill a VLCC), its primary purpose in life (so far) has been to receive imported crude (from LOOP via the LOOP Pipeline) and crude from offshore Gulf of Mexico (GOM) production — primarily from the Shell-operated Mars pipeline system and BP’s Thunder Horse field (via the Endymion pipeline system) — and then distribute that imported and GOM crude to U.S. refineries. Also, since 2013, Clovelly has been a destination point for Shell’s Zydeco (formerly Ho-Ho) Pipeline, which can transport up to 350 Mb/d of crude east from storage terminals in Houston and Port Arthur/Beaumont, TX, and Lake Charles, LA.
Put another way, it is key ports along the Texas coast (Corpus Christi, Houston Ship Channel/Texas City, and Beaumont, to name three) — and not LOOP — that are most directly connected by pipeline to production areas like the Permian and SCOOP/STACK whose increased production growth is increasingly relieved through exports. Our understanding is that the pace of reverse-lightering activity in TSAs off the coast of Corpus Christi, Galveston and Beaumont/Port Arthur is still increasing — from only one VLCC being fully loaded via reverse lightering every other month in 2016 to six per month in 2017 to even more in the first half of 2018. Now, we’re seeing the beginnings of another trend, namely, docking VLCCs at marine terminals, filling the supertankers to the dock/channel draft limit (often about halfway), then moving them out to TSAs where their loading can be completed through partial reverse lightering.
Testing of this hybrid approach (partial dock loading and partial reverse lightering) has been going on for more than a year now. As we said in Take It to the Limit, Occidental Petroleum (Oxy) in May 2017 brought in an empty 2-MMbbl VLCC to its Ingleside marine terminal across the bay from Corpus Christi to test what improvements might be needed at its dock to allow the partial loading of VLCCs. Currently, Oxy is in the midst of a major expansion program at Ingleside that will add VLCC loading arms and allow partial VLCC loading (1.2 MMbbl to 1.4 MMbbl) there starting in the fourth quarter of 2018. By the second half of 2019, the Ingleside terminal’s export capacity will increase to 750 Mb/d from the current 300 Mb/d. Also at Ingleside, and within a stone’s throw of Oxy’s terminal, a joint venture of Buckeye Partners (50% stake), Phillips 66 Partners (25%) and Andeavor (25%) is developing the open-access South Texas Gateway Terminal, which by late 2019 will offer 3.4 MMbbl of crude storage capacity (expandable to 10 MMbbl-plus), connectivity to the Phillips 66 Partners and Andeavor’s planned 700-Mb/d Gray Oak Pipeline from the Permian (expandable to 1 MMb/d), and two deepwater docks each capable of partially loading VLCCs. Again, the VLCCs will receive the balance of their crude at a TSA off the coast. [Across the bay in Corpus Christi, Buckeye recently completed improvements at its Buckeye Texas Hub terminal that for the first time will allow Suezmax-class vessels (capacity ~1 MMbbl) to dock there.]
The FMPC C Melody at the Seaway Texas City Terminal. Source: Enterprise
The first (albeit only partial) loading of a VLCC at a Texas port occurred just a few days ago (in late June) at the Texas City marine terminal owned by Seaway Crude Pipeline Co., a joint venture of Enterprise Products Partners and Enbridge that is best known for its Cushing-to-Gulf-Coast crude pipeline system. Enterprise on June 22-24 loaded 1.1 MMbbl onto the FMPC C Melody (a 2-MMbbl VLCC) at the Seaway terminal, which has two docks offering a 45-foot draft; then, reverse lightering in a nearby TSA filled the VLCC to the brim. (Enterprise first brought in a VLCC to the terminal in April 2018 to determine what improvements would be needed to load the vessel; it then made those tweaks, which included adjustments to the terminal’s loading arms.)
So, partial loading of VLCCs at Texas marine docks has now happened at Texas City, and the same is likely to be occurring with some regularity at Oxy’s Ingleside terminal within a few months and at the Buckeye-led South Texas Gateway Terminal (also at Ingleside) within a year and a half. This approach to vessel loading should help to hold down shipping costs and, with that, make the U.S. even more competitive in overseas markets. Fully loading VLCCs at land-based terminals along the Texas coast will take longer, though, and will require channel-deepening projects (like the one planned for Corpus Christi, which will deepen the channel to 54 feet from the current 45 feet by 2022, if all goes to plan). There’s also been talk (by Magellan Midstream Partners, for one) about the possible development of a deepwater offshore terminal, a la LOOP. And privately held JupiterMLP has indicated it is seeking permits for the proposed Jupiter Offshore Loading Terminal six miles off the coast of Brownsville, TX. Yup, the plan is to fully load VLCCs there.
https://rbnenergy.com/working-on-a-dream-plans-afoot-to-load-crude-onto-vlccs-at-more-gulf-coast-ports
In line with its agreement with OPEC to reverse part of the cuts, Russia is boosting its crude oil production, pumping as much as 11.193 million bpd in the first four days of July, up from 11.06 million bpd in June, Reuters reported on Thursday, quoting a source familiar with the data.
Last month, Russia and OPEC’s largest producer and de facto leader Saudi Arabia managed to get OPEC and their Moscow-led non-OPEC allies to agree to boost production by unspecified quotas for individual countries part of the pact, to ‘ease market and consumer anxiety’ over the high oil prices. According to Russian Energy Minister Alexander Novak, Russia’s share of the 1-million-bpd total OPEC/non-OPEC increase could be around 200,000 bpd.
Before the decision to reverse some of the cuts—or as OPEC and allies put it, to stick to 100-percent compliance rates—Russia’s pledge in the pact was to cut 300,000 bpd of its oil production from the October 2016 level, which was the country’s highest monthly production in almost 30 years—11.247 million bpd.
Even before the OPEC and friends meeting, Russia had already started boosting its oil production, and had pumped as much as 11.09 million bpd in the first week of June—143,000 bpd above the country’s then-quota under the OPEC+ production cut deal.
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Just before the meeting, all signs were pointing to Russia gearing up for a jump in its oil production, with plans for exports and refinery runs in the coming months indicating that Moscow was preparing to increase its oil production as early as this month.
Earlier this week, Russia’s Novak and his Saudi counterpart Khalid al-Falih discussed the latest developments on the oil market and exchanged information about their countries’ plans for production to meet summer demand, Russia’s energy ministry said in a statement. The decision to ease the combined OPEC/non-OPEC compliance rate from 147 percent in May 2018 to 100 percent starting July 1 equates to adding around 1 million bpd on the market, the statement said.
https://oilprice.com/Energy/Crude-Oil/Russian-Oil-Production-Soars-To-11193-Million-Bpd.html
Gabon oil workers’ union ONEP began a 15-day strike at the facilities of French oil producer Total on Monday after demands for higher pay and other issues were not met, the union said in a statement.
ONEP threatened to strike last month, after Total Gabon failed to respond to demands made to the company in May. In addition to higher pay, the union requested new bonuses, increased opportunities for career advancement and a reduction in the number of foreign workers.
“The 15-day strike will affect all installations operated by Total Gabon’s employees as of Monday July 9th,” the ONEP statement said, including facilities in the capital Libreville and the oil hub of Port Gentil.
The decision to strike follows several failed discussions with Total representatives mediated by the Ministry of Employment, ONEP said.
A Total spokeswoman had no immediate comment.
Gabon produces about 200,000 barrels per day (bpd) of crude, according to the U.S. Energy Information Administration, but output from the OPEC member’s mature fields has plummeted from a 1997 peak of 370,000 bpd.
A steep fall in oil prices in 2014 and 2015 choked much needed revenue and forced companies to layoff thousands of oil workers.
Total produces about 54,000 barrels of oil equivalent per day in Gabon.
Libya’s oil output will keep dropping day by day if major ports remain closed after clashes last month led to a political deadlock, the head of the country’s state energy producer said.
“Today, production is 527,000 barrels a day, tomorrow it will be lower, and after tomorrow it will be even lower and everyday it will keep falling,” Mustafa Sanalla, chairman of the Tripoli-based National Oil Corp., said in a video statement posted on the company’s Facebook page. The nation was producing more than twice that amount before fighting in February forced an oil field in western Libya to shut down, he said.
Sanalla urged Khalifa Haftar, an army commander in the politically divided nation’s east, to transfer control of the closed oil ports to the NOC in Tripoli.
Haftar’s forces gave control of the ports to a separate oil authority in the eastern city of Benghazi, after recapturing them from a rival militia. The U.S., U.K., France and Italy expressed concern about this transfer to an entity other than the NOC. The surprise handover led to a halt in shipments from the ports of some 850,000 barrels a day. Libya’s instability in complicating OPEC’s effort to pump more crude as well as United Nations-backed efforts to hold elections this year.
‘Frustrated’ Libyans
Haftar’s forces said their army was not receiving payments for protecting oil facilities. Sanalla said in the video statement that crude revenue is sent to the central bank and that the NOC isn’t responsible for how it gets distributed.
“I understand Haftar’s feeling,” Sanalla said. “He must be frustrated like most Libyans, but do we express this disappointment by halting exports? I don’t think this is right. We all agree that the situation is not right, that national wealth is not utilized to its best.”
While Libya holds Africa’s largest oil reserves, years of conflict among armed groups competing for influence over its energy riches have hobbled production and exports since a 2011 revolt led to the ouster and death of former strongman Moammar Al Qaddafi. The economy’s decay economy has stoked anger in eastern Libya over a perceived misuse of funds and a view that that too much wealth is concentrated in the west.
“We hope that the army leadership will hand over the ports to keep oil production going, and any other discussion can be held with the government, the central bank, the house of representatives,” Sanalla said. “If you hand over the ports to us, this will be an act of courage and nobility because no one wins in this battle, we all lose.”
Libya was pumping about 1.3 million barrels of crude a day in February before militias closed the western 80,000-barrels-a-day Elephant, or El-Feel, field in February, Sanalla said. Output will continue to decline if the five ports recaptured by Haftar stay closed, he said. Oil facilities in the Gulf of Sirte along the central coast are old and in poor condition, and only four of 13 storage tanks at the port of Ras Lanuf are currently operational, he said.
“Let’s keep oil out of politics, especially at these difficult times,” Sanalla said. “We are appealing to everyone’s national spirit, keep oil facilities out of the conflict.”
Syncrude update: One coker, producing approximately 150,000bbls/d is expected to return to service during the second half of July. A second coker, producing approximately 100,000 bbls/d, is expected to return to service during the first half of August.
@staunovo
Preliminary investigation results indicate that the cause of the disruption was a transformer trip in Syncrude's power house resulting in a rapid site wide loss of power and steam generation. As a result, all process units were brought down. There were no injuries or safety incidents as a result of this outage.
Syncrude has developed a return to service plan. Power and steam systems have been fully restored, the assessment and repair for the transformer is underway, and the safe and staged return to operations has begun. One coker, producing approximately 150,000 barrels per day (bbls/d), is expected to return to service during the second half of July. A second coker, producing approximately 100,000 bbls/d, is expected to return to service during the first half of August.
However, coke removal is required on the remaining coker due to the nature of the shutdown. In order to mitigate the impact, Syncrude will investigate advancing some of the planned maintenance for this coker that had been originally scheduled for the fall of 2018 and spring of 2019.
Pipeline shipments of treated product are estimated to be approximately 60% to 70% of capacity for August. It is expected that Syncrude will ramp up to full production in early to mid-September.
https://www.nasdaq.com/press-release/suncor-provides-update-on-syncrude-recovery-plan-20180709-00202
Italian energy company Eni on Monday announced its second oil discovery in the Western Desert of Egypt.
A new oil discovery in the Western Desert of Egypt could unlock a new area for production gains in the country, Italian energy company Eni said Monday.
Eni said it made its second oil discovery in the B1-X exploration area in the Western Desert. It's located about 4 miles away from an earlier discovery dubbed A2-X and was already producing about 5,100 barrels of oil per day.
The company said the discovery established the region as one with a high production potential.
"Eni plans, in the near term, the drilling of other exploratory prospects located nearby the A2-X and B-1X discoveries to consolidate what can result as a new productive area for Eni in Egypt," the company's statement read.
Known more for offshore gas resources, Egyptian oil prospects are quickly catching up. Last month, regionally-focused SDX Energy said the results from a drilling operation in the Gulf of Suez could dictate the next steps for oil exploitation.
SDX in June started drilling an appraisal well, designated SRM-3, at the South Ramadan basin. That field is located between the Ramadan field, with an estimated 550 million barrels of oil, and the Morgan field, with an estimated 1.5 million barrels of oil.
Eni said it produces about 55,000 barrels of oil equivalent per day from the Western Desert. Any new production from the area would run through existing pipelines to a refinery once development plans are approved by the Egyptian government.
The Italian company is Egypt's main producer, with equity production of around 300,000 barrels of oil equivalent per day.
Oil prices rose on Tuesday on escalating concerns over potential supply shortages, with Brent crude leading the way as hundreds of oil workers in Norway were set to strike later in the day.
Brent crude LCOc1 had added 32 cents, or 0.4 percent, to $78.39 per barrel by around 0303 GMT, following a 1.2-percent climb on Monday.
Hundreds of workers on Norwegian oil and gas offshore rigs are due to strike on Tuesday after rejecting a proposed wage deal, a move which will likely affect the production of at least one field, Shell’s Knarr.
Happening in Norway today: 699 workers will go on strike on 9 platforms and mobile rigs after failed to reach an agreement with employers in mediation, SAFE union & Norwegian Shipowners Association said. Strike could escalate with additional 900 workers from July 15.
That potentially adds to disruptions in other oil producers amid tensions in the Middle East.
The United States says it wants to reduce oil exports from Iran, the world’s fifth-biggest producer, to zero by November, which would oblige other big producers to pump more.
Saudi Arabia, fellow members of the Organization of the Petroleum Exporting Countries (OPEC) and allies including Russia agreed last month to increase output to dampen price gains and offset global production losses in countries including Libya.
The market has grown concerned that if the Saudis offset the losses from Iran, that will use up global spare capacity and leave markets more vulnerable to further or unexpected production declines.
“The bottom line becomes the available spare capacity within OPEC ... and the markets have started to focus on that,” said Victor Shum, vice-president for energy at IHS markets in Singapore.
“It is likely that concern will support prices all through the summer, while demand continues to be strong during the summer peak,” he said.
Over the past 4 weeks, USA has exported 10.33 million barrels of crude oil to India. This is 344K barrels per day. In April, this number was 17Kbpd, but the previous record was 98Kbpd in September 2017.
@TankerTrackers
An independent Chinese refiner has suspended crude oil purchases from the United States and has now turned to Iran as one of its sources of crude, media reports, citing an official from the refiner, Dongming Petrochemical Group.
What’s more, the source said that Beijing is planning to slap tariffs on U.S. crude oil imports and replace them with West African and Middle Eastern crude, including crude from Iran. China has already said that it will not comply with U.S. sanctions against Iran and it seems to be the only country for now in a position to do this.
U.S. crude oil exports to China reached 400,000 bpd at the beginning of this month, but now Beijing is planning to impose a 25-percent tariff on these as part of its retaliation for Trump’s latest round of tariffs on US$34 billion worth of Chinese goods. The retaliation began with tariffs on 545 U.S. goods worth another US$34 billion, but, Reuters reports, the oil tariffs will be announced at a later date.
Energy analysts seem to believe that these oil tariffs are more or less a certainty, and now expect a reshuffle of crude oil imports to Asia. With China turning to Iran for its crude, U.S. oil could start flowing in greater amounts to another leading importer in the region, South Korea.Related: Big Oil’s Next Major Move
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“If China retaliates with tariffs on U.S. crude, that could improve South Korea’s terms of buying U.S. crude...because the U.S. would need a market to sell to,” on analyst, from the Korea Energy Economic Institute.
Meanwhile, South Korea’s embassy in Iran this weekend rejected media reports that the country had suspended oil purchases from Iran under pressure from the United States. The country is the third-biggest buyer of Iranian crude in Asia, buying Iranian crude at an average daily rate of almost 300,000 barrels since March this year.
China's independent refiner Qingyuan Petrochemical has accumulated a large sum of demurrage charges as it struggles to discharge three cargoes of crude oil since May, denting the company's credit and finances that could hamper future crude imports.
Three cargoes, a total of about 388,000 mt (2.84 million barrels), of crude oil have been floating near the ports in eastern China's Shandong province for more than 45 days. The entire volume was supplied to Qingyuan petrochemical's 7.04 million mt/year (141,000 b/d) refinery, mostly by BP, S&P Global Platts' data showed.
Of this, a tanker carrying 130,000 mt of Angolan Cabinda crude has failed to discharge since it arrived at Dongjiakou port on May 12.
Another 130,000 mt of Brazilian Lula crude shipped by Olympic Luck arrived on May 15, and was re-directed at around the end of June to find a new outlet in Japan or South Korea. The rest, 130,000 mt of Plutonio crude, has been shipped back to Rizhao, waiting to be discharged.
Typically, it took less than a month for Qingyuan to discharge crude cargoes.
However, Qingyuan could neither resell nor take the barrels into its own system this time due to a combination of factors -- low run rates at independent refineries and stricter tax regulations introduced in March, which essentially raised costs and weighed on the independent sector's overall refining margins.
"It's not a good time to sell crude as quite a lot of [Chinese] independent refineries are offline for maintenance until August," a Beijing-based analyst said.
In addition, market participants said that Qingyuan may have bit off more than it could chew as the company has been running at its minimum utilization rate in 2018.
The refiner has two plants in Shandong province -- Linzi with 60,000 b/d capacity and Qingyishan with 81,000 b/d. But it operates only the Linzi plant currently and at a run rate of about 60%.
Other than these cargoes that have not been discharged, Qingyuan also has around 130,000 mt of crude stocks at Qingdao port.
FINANCES, CREDIT IN JEOPARDY
The longer-than-usual demurrage could significantly hurt Qingyuan's finances and hamper its ability to open letters of credit to import crude oil in the future.
The stranded cargoes could incur a daily demurrage fee of around $35,000 per vessel, according to sources with knowledge of the matter.
Other than the demurrage costs, the refiner owed more than Yuan 10 million in logistics fees to the Qingdao Shihua Oil Terminal, which it has failed to pay on time, according to a port source.
Qingyuan's ability to open letters of credit could be in jeopardy unless it can revive its cash flow from the refining business or by selling the imported crude even at lower prices, market sources said.
In late 2014, Qingyuan was on the brink of bankruptcy until the local government injected cash into the company.
The independent refiner was back on track in 2016 when it gained permission to crack imported crude.
From 2017, the company started to import crude but only cracked a part of the crude it had bought from the international market, opting to resell most of the barrels to other independent refiners.
Qingyuan Petrochemical imported 1.59 million mt of crude oil in the first six month this year, but its throughput was only at 870,000 mt, data from Platts and Chinese information provider JLC showed.
Permian pinch spurs pipeline binge, and fears of overbuild
The pipeline crunch threatening the world’s hottest shale play won’t be solved until at least the back half of next year. But then, the floodgates will open.
Pipelines serving the Permian basin in Texas and New Mexico were able to carry 2.9 MMbopd in the second quarter, according to analysts at Bloomberg NEF, and pretty much every line from Midland to the Gulf Coast is full. That’ll change in late 2019 as three major projects are slated to open, potentially adding more than 2 MMbpd of capacity.
Fixing the pipeline conundrum is key for a shale play where researcher IHS Markit expects output to more than double by 2023 to 5.4 MMbpd, eclipsing every OPEC nation beyond Saudi Arabia. Pipeline builders are pouring billions of dollars into the basin, but delays are a concern as developers compete for everything from labor to steel.
“They want to move heaven and Earth to get these projects done,” said John Kilduff, a partner at New York-based hedge fund Again Capital LLC. “In a situation like this, the economics just make it so compelling that they rush resources into the area, and that’s what you’re seeing.”
The bottlenecks are reverberating through global energy markets. Combined with disruptions in Iran, Venezuela, Libya and Canada, stranded oil in the Permian has helped push up benchmark U.S. crude prices by roughly 20% this year. With gasoline also rising and congressional elections looming in November, President Donald Trump took to Twitter last week demanding OPEC lower prices.
In the meantime, producers are moving cautiously, with the number of wells left deliberately uncompleted on the rise. Permian wells that were drilled but not taken through the final stage of hydraulic fracturing surged to 3,203 in May, a 90% increase from a year earlier and the highest since the Energy Department began tracking in 2013.
Pipeline woes are moving some companies to rethink their strategy. ConocoPhillips CEO Ryan Lance told Bloomberg TV last month that the world’s biggest independent oil explorer will likely move some rigs from the Permian to the less crowded Eagle Ford shale in South Texas to avoid the constraints. “Why would I drill into that headwind if I can reallocate that capital somewhere else?" Lance said.
The shortage has forced some producers to sell locally at a steep discount to Gulf Coast prices, or to pay extra to ship barrels hundreds of miles by truck or rail. Crude sold in Midland, in the heart of the Permian, for $15.35/bbl less than in Houston on Monday, after starting the year at a $4 discount.
That makes the new proposals critical to the U.S. shale boom’s future.
The projects include Plains All American Pipeline LP’s Cactus II, running from Midland to Corpus Christi on the Gulf Coast and slated to carry as much as 670,000 bpd. Also expected in late 2019 are Phillips 66 Partners’ and Andeavor’s Gray Oak pipeline, proposed for 700,000 to 1 MMbbl, and the private equity-backed EPIC pipeline, which could carry as much as 675,000 bbl.
Substantial relief
They’ll offer “substantial relief” to producers eager to drill without fear of having nowhere to put their supply, Kilduff said.
Others are trying to make existing infrastructure go further: Plains, Energy Transfer Partners LP and Magellan Midstream Partners LP are all expanding existing crude pipes. That’s expected to add 400,000 bpd of capacity by the middle of next year.
Other projects are farther off, including plans for two giant pipelines that could take 1 MMbbl of oil each. Energy Transfer is proposing one from the Permian to Nederland, Texas, and ExxonMobil Corp. is teaming up with Plains for another to Corpus Christi. Those projects wouldn’t enter service until 2020 or 2021.
That’s already sparking talk of a potential overbuild, including from Magellan CEO Mike Mears. He’s advocated shippers extend contracts on existing lines -- like his Longhorn pipeline -- instead of signing onto new projects.
“You may have a nicely contracted pipeline for five years, but what does your sixth look like if your competitors build too many pipelines?" Mears said last month at an investor conference. “You always want to be cautious of not overbuilding.”
But complications could also arise. Plains last month bumped back the start date for Cactus II -- from the third quarter of 2019 to October -- citing unidentified “constraints.”
“If it’s delayed again, producers could be looking at a difficult 2019,” Guggenheim Securities analyst Matthew Phillips said.
Pipeline timelines
Plains may not be the only one facing pressure. The chances for setbacks are “increasing by the day,” said Robert W Baird & Co. analyst Ethan Bellamy.
“If you’re starting to build three or four of these pipelines out of the Permian at the same time, there’s a potential to max out the available construction capacity,” he said. “If there are delays, they’re probably due to construction capacity and labor and acquisition of pipeline in a timely and cost-efficient manner.”
Still, by early 2020, drillers may have more ability to move oil out of the Permian than they really need, said John Zanner, an RBN Energy analyst. While good for producers that benefit from cheaper shipping, that also could force companies to scrap some plans, he said.
Others say the play is up to the challenge.
“They’re finding more and more oil every day,” said Again Capital’s Kilduff. “The good old days are back, and you’re going to see all of these be put into action.”
http://www.worldoil.com/news/2018/7/9/permian-pinch-spurs-pipeline-binge-and-fears-of-overbuild
There's chatter that a break from the oil crescent conflict in Libya might be possible this week. Only time will tell if it's possible.
@Ben_Mussa
LIBYA'S NOC SAID TO RESUME CONTROL OF EASTERN OIL PORTS
OPERATIONS AT LIBYA'S EASTERN OIL PORTS SAID ORDERED TO RESUME
@warrenpatCMDTY
Oil prices have spiked more than 13 percent in the past ten days, with WTI touching $75 at one point, the highest since the 2014 price crash. The factors that have contributed are quite vivid. Trump’s request that Saudi Arabia increases its production by 2 million bpd and the ensuing fear regarding the spare capacity. Some issues at Libyan ports added to market fear as well, with production continuing to fall. Canada also played a role with the Syncrude facility closing down, taking down 250,000 bpd offline. Arguably the most influential factor is the increasingly hardline stance that the U.S. is taking in regard to Iranian oil exports. In this bullish environment, it is important to keep an eye on the downside risks to oil and not get carried away with investor sentiment.
With U.S. mid-term elections in November, Trump is set to face increasing pressure. The trade war is already hurting some farmers in the U.S. and the steel and aluminum tariffs are hurting industries of all sorts; from automobile to oil. Trump’s Tweets suggest that higher oil prices are a key concern for his administration. Gasoline prices have surged above $3 and with every increase the likelihood of Trump tapping into the Strategic Petroleum Reserves grows larger. This is one of the key factors that would add downward pressure to oil prices.
One key downside factor that analysts should be conscious of is the easing of sanctions on Iran. Iran sanctions were one of the major reasons for an oil price spike, and the hardline stance taken recently by the U.S. has just made it even more important. If Trump’s administration uses its “case-by-case” analysis of countries to ease the threat of Iran sanctions, then we will almost certainly see more downward pressure on oil prices.
With Trump’s reputation for changing his stance on key issues well documented, and his recent flip flopping on both his Iran policy and his demands on Saudi Arabia’s production, it is not unrealistic to assume he will do all he can to lower crude prices before November’s elections. As well as the November elections, the trade war with China and disagreements within NATO may force Trump’s hand when it comes to punishing Iran and making demands of Saudi Arabia and OPEC.
The most vital industry information will soon be right at your fingertipsJoin the world’s largest community dedicated entirely to energy professionals
Interesting times--- Oil markets are behaving in a very interesting manner these days. For example, an increase in production is usually considered a bearish factor and cause oil prices to fall. But with Venezuelan oil production collapsing, disruptions from Libya growing and the Iranian geopolitical scenario alongside rising tensions in the Middle-east (last week Iran issued a threat of blocking straits of Hormuz, a vital choke point), markets are clearly on edge over a supply deficit. This fear in markets may be causing sentiment to play a larger role than fundamentals, and when that sentiment changes, the downside may be far greater than many think. There is still no scarcity of oil, and there is certainly no certainty over what Donald Trump might do next.
https://oilprice.com/Energy/Energy-General/Downside-Risk-Remains-In-Oil-Markets.html
India’s oil imports from Iran declined by 15.9 percent in June, the first month after the United States said it would reimpose sanctions on the country, according to data from shipping and industry sources.
In June, India imported 592,800 barrels per day (bpd) of oil from Iran compared to 705,200 bpd in May, the data showed. The sources declined to be identified.
India, Iran’s top oil client after China, has asked refiners to look for alternative oil as the nation may have to drastically cut imports from Tehran to comply with the renewed U.S. sanctions.
The United States said it would reimpose the sanctions after withdrawing from a 2015 agreement with Iran, Russia, China and several Western European countries where Iran agreed to curtail its nuclear activities in return for the lifting of earlier sanctions.
U.S. crude oil production is expected to average more than 12 million barrels per day late next year for the first time ever, the U.S. Energy Information Administration said in a monthly report on Tuesday.
U.S. oil production has soared, boosted by improved technology for tapping shale formations. Output rose 5.6 percent last year and is expected to grow 15.4 percent this year. If the forecasts are realized, that will make the United States the world’s largest crude producer, surpassing Russia.
“Production growth in the United States, Brazil, Canada, and Russia will make up the majority of total global supply growth in 2019,” EIA Administrator Linda Capuano said in a statement after the report was released.
The agency increased its 2019 average forecast by 40,000 bpd to 11.80 million bpd, and increased its forecast for the fourth quarter of that year by 50,000 bpd to 12.02 million.
U.S. crude production this year is expected to be 10.79 million bpd, unchanged from last month’s forecast, according to the agency, which is the statistical arm of the U.S. Department of Energy.
The EIA expects production to average 10.91 million bpd this quarter and 11.29 million in the fourth quarter.
Total U.S. oil demand is expected to be 20.35 million bpd this year, 60,000 bpd less than previously forecast. At the same time, the agency increased its 2019 demand outlook by 10,000 bpd to 20.68 million bpd.
If EIA’s forecast is realized, 2019 gasoline consumption would be the highest annual average on record, surpassing the previous record set in 2017, Capuano said.
OPEC expects supplies from its rivals to increase by the most in five years in 2019, with extra oil from the U.S. alone sufficient to meet the growth in global demand.
In its first detailed outlook for 2019, the Organization of Petroleum Exporting Countries indicated that the North American oil boom means OPEC members are already producing enough crude to cover what will be needed from them. That could still change, however, as the group’s output is threatened by a spiraling economic crisis in Venezuela and renewed U.S. sanctions on Iran.
OPEC Cuts, Rivals Grow
Output curbs by the group have boosted prices -- and supply from its competitors
The report may fuel the debate that’s splitting the organization. Saudi Arabia, OPEC’s biggest producer, is resolved to increase oil output amid pressure from the U.S. to cool rallying prices. Iran, which is seeing customers flee as American sanctions kick in, argues that other members are betraying the group if they raise supply.
“If the world economy performs better than expected, leading to higher growth in crude demand, OPEC will continue to have sufficient supply to support oil-market stability,” the organization’s secretariat in Vienna said in the report.
On July 4, President Donald Trump renewed criticism of the group by tweeting that OPEC isn’t doing enough to tame prices, which at about $74 a barrel in New York are near their highest in more than three years.
Global oil demand will climb by 1.45 million barrels a day in 2019, slightly below this year’s growth rate, to average 100.3 million barrels a day, according to the report.
The growth in non-OPEC supply will be considerably stronger though, at 2.1 million barrels a day, the most since 2014. Though the shale-oil boom is slowing because of pipeline constraints, the U.S. will still contribute about three-quarters of the global supply expansion, enough to meet the growth in world consumption.
Rivals Ramp Up
That surge reflects how output curbs by OPEC over the past 18 months have emboldened the group’s rivals, giving shale drillers and other producers the higher prices they needed to resume operations.
As a result, OPEC’s 15 members will need to provide an average of just 32.2 million barrels a day next year, slightly below the 32.3 million they pumped in June.
Maintaining that level, however, will be a contentious process.
Venezuela’s output continues to sink to the lowest in decades as its economic meltdown takes a toll on oil infrastructure and workers. More crucially, Trump’s administration is trying to choke off exports from Iran after quitting a nuclear accord with OPEC’s third-largest producer.
Saudi Arabia, the United Arab Emirates and Kuwait are already boosting supplies, the report showed. The Saudis have raised output by 405,400 barrels a day to 10.42 million, the biggest jump in more than three years, according to OPEC.
But attempting to compensate for a halt in Iranian exports -- currently at about 2.5 million barrels a day -- would almost certainly strain the abilities of Saudi Arabia and its partners.
It could also stretch relations within the organization to breaking point. Iran insists that output limits assigned to each country in late 2016 still apply, and that any country producing above these quotas is violating the agreement.
“If OPEC survives as an organization, it will have to be without Iran,” said Olivier Jakob, managing director of consultants Petromatrix GmbH in Zug, Switzerland.
Russian oil producers may be capable of increasing production by as much as 600,000 b/d within the next nine to 18 months if the country's agreements with OPEC and its partners allow, according to analysts.
Following the decision in June by OPEC and its oil producing partners to boost output by 1 million b/d from levels in May, Russia has pledged to add an additional 200,000 b/d to the market. The return of Russian barrels is a key factor currently weighing on markets.
"I think it is realistic to boost output by up to 600,000 b/d within the first half of 2019 -- but Russian companies will need to drastically intensify drilling to do so," said Mikhail Sheybe, an analyst from Sberbank CIB.
The Energy Information Administration defines spare capacity as the volume of crude that can come on stream within 30 days and be sustained for at least 90 days.
"We estimate that Russia will retain [roughly] 360,000 b/d of swing capacity at the end of 2018, as oil output ramps up by the agreed 200,000 b/d," a recent report by BofA Merrill Lynch Global Research said. "We expect Russian oil producers to accumulate additional [roughly] 140,000 b/d spare capacity by the end of 2019, bringing the total figure to 500,000 b/d."
Russia's spare capacity has grown because oil producers continued to prepare major greenfield projects for full-scale development in anticipation of production caps being lifted at some point this year, analysts said. The country can produce more crude if required, Russian energy minister Alexander Novak said last month.
His comments came amid concerns that OPEC countries may not be able to cover potential gaps in supply in the fourth quarter, expected as a result of looming US sanctions on Iran, sliding output from Venezuela and the latest slump in Libyan exports. Saudi Arabia and Russia hold the bulk of the world's current spare capacity.
Because Russia has never deliberately reduced its output before, it's uncertain how quickly oil producers will be able to increase production. Key producers estimated they would need on average of between two to four months to restore barrels, while some sources said these forecasts were conservative.
In June, Russia boosted its output by 89,400 b/d to 11.063 million b/d, as oil producers carried out tests to assess how quickly output could be increased.
DRILLING IS KEY
Further production growth will depend on drilling rates, as most of the increase is likely to come from new, rather than closed, low-margin wells.
"Depending on oil prices, companies will be looking at what projects to develop and whether it is economically justified to increase production [further] within a short period of time," said Andrey Polischuk, a Moscow-based analyst from Raiffeisen Bank.
Oil producers may opt to increase production gradually to avoid any potential sharp drops from reservoirs in the future, as they will pursue their own business interests, said Polischuk.
Based on current plans, "greenfields" can add some 221,000-241,000 b/d in production in 2019, Daria Kozlova from Vygon Consulting estimated.
Intensive drilling in recent years has also helped to stabilize production at some major mature projects such as Rosneft's Yuganskneftegaz. The unit's output rose by 8.4% on the year to 1.4 million b/d in June, and it has potential to grow by another 100,000 b/d, said Ronald Smith, director for CEEMEA Oil and Gas at Citi Research.
FUTURE PRODUCTION
Russia's government is more conservative. If the OPEC coalition agreements are maintained, Russia's crude production is likely to average at around 11.045 million b/d this year and grow by nearly 1% to 11.146 million b/d in 2019, Russia's energy and economic development ministries estimated.
Production will peak at around 11.246 million b/d in 2020-2021, and then gradually fall by 100,000 b/d in 2024, according to the latest short-term economic outlook by the economy development ministry.
Official forecasts, however, tend to be too conservative, analysts said.
"Russia can produce 12 million b/d by the end of 2020, based on the huge pipeline of greenfield projects it has," Citi's Smith said.
"Nobody has stopped drilling. Rosneft was increasing drilling even though it visibly, purposely reduced production under the output cut deal, as it was preparing the fields for the full-scale development," he said.
Russian key greenfields to underpin output growth in 2019 and beyond include Rosneft's Yurubcheno-Tohomskoye and the Vankor cluster of fields, Gazprom Neft's Novoport and Prirazlomnoye as well as the Messoyakha and Kuyumba fields the two companies develop jointly.
The world’s oil supply cushion could be stretched to the limit due to prolonged outages, supporting prices and threatening demand growth, the International Energy Agency said on Thursday.
The expected drop in Iranian crude exports this year due to renewed U.S. sanctions, coupled with a decline in Venezuela’s production and outages in Libya, Canada and the North Sea have driven oil prices to their highest since 2014 in recent weeks.
OPEC and other key producers including Russia responded to the tightness by easing a supply-cut agreement, with Saudi Arabia vowing to support the market as U.S. President Donald Trump accused the group of pushing prices higher.
The Paris-based IEA said in its monthly Oil Markets Report that there were already “very welcome” signs that output from leading producers had been boosted and may reach a record.
The global energy watchdog however said the disruptions underscored the pressure on global supplies as the world’s spare production capacity cushion “might be stretched to the limit”.
Spare capacity refers to a producer’s ability to ramp up production in a relatively short time. Much of it is located in the Middle East.
The IEA said OPEC crude production in June reached a four-month high of 31.87 million barrels per day. Spare capacity in the Middle East in July was 1.6 million bpd, roughly 2 percent of global output.
As U.S. sanctions on Iran are expected to “hit hard” in the fourth quarter of the year, Saudi Arabia could further ramp up output, which would cut the kingdom’s spare capacity to an unprecedented level below 1 million bpd, the IEA said.
Non-OPEC production including from surging U.S. shale also continued to rise, but the IEA said that might not be enough to assuage concerns.
“This vulnerability currently underpins oil prices and seems likely to continue doing so. We see no sign of higher production from elsewhere that might ease fears of market tightness,” it said.
The IEA maintained its 2018 oil demand growth forecast at 1.4 million bpd, but warned that higher prices could dampen consumption.
“Higher prices are prolonging the fears of consumers everywhere that their economies will be damaged. In turn, this could have a marked impact on oil demand growth.”
The IEA said Iran’s crude exports could be reduced by significantly more than the 1.2 million bpd seen in the previous round of international sanctions. Iran exports roughly 2.5 million bpd, most of which goes to Asia.
China and India, the world’s second and third largest oil consumers, could face “major challenges” in finding alternative crude oil following the drop in Iranian and Venezuelan exports, the IEA said.
Iranian crude exports to Europe dropped by nearly 50 percent in June, the IEA said, as refiners gradually wind down purchases before U.S. sanctions take effect in November.
BRENT CRUDE OIL PROMPT TIMESPREAD FLIPS INTO CONTANGO
@staunovo
Libya’s Tripoli-based National Oil Corporation (NOC) has announced that four export terminals are being reopened after “eastern factions” handed over the ports according to Reuters.
Force majeure has been lifted on the ports of Ras Lanuf, Es Sider, Zueitina and Hariga, the NOC declared in a statement.
“Production and export operations will return to normal levels within the next few hours,” it said.
The ports were shut in June due to a struggle for control between rival groups. As a consequence, Libya’s national output was reduced by around 850,000 barrels per day (bpd).
Ras Lanuf and Es Sider were closed after armed opponents of eastern-based commander Khalifa Haftar launched attacks on them on June 14th.
The attack was defeated a week later, but eastern officials aligned with Haftar blocked operations at both terminals, in addition to Zueitina and Hariga, stating they would handle exports via a rival NOC based in the east.
However, yesterday, the NOC commended Haftar’s Libyan National Army for “putting the national interest first” by handing back the ports.
The head of the rival NOC, Faraj Said, confirmed the ports would be reopening, although he told the Reuters news agency that Ras Lanuf and Es Sider, needed maintenance work after being damaged in the fighting.
“The ports of Zueitina and Hariga are now open for any tankers carrying a contract. Ras Lanuf and Es Sider need some maintenance,” he said.
http://www.arabianoilandgas.com/article-19049-force-majeure-lifted-at-four-libyan-export-terminals/
Aker BP has entered a three-year cooperation agreement with Resoptima for the incorporation of Resoptima’s software solutions into Aker BP’s digitalization effort within reservoir management. In addition Aker BP will take a 15% equity position in Resoptima. Deploying the Resoptima solutions across the Aker BP producing assets is aligned with Aker BP’s ambitious digitalization agenda.
Both Aker BP and Resoptima see great potential for the E&P industry to increase recovery while reducing costs by leveraging the power of data-driven reservoir modeling and management. By facilitating a better collaboration between the subsurface disciplines, as well as rapidly updating reservoir models as new data becomes available, Aker BP will be able to better account for uncertainty, improve its decision-making processes and increase its operational efficiency.
Resoptima’s reservoir modeling and data conditioning software ResX allows E&P companies to rapidly create reliable reservoir models through consistent integration of all available reservoir data while accounting for uncertainty. The software can be used to run virtual experiments of future production scenarios and help operators making the right decisions to maximize recovery, while minimizing the financial risk.
The collaboration will also allow Resoptima to further develop the technologies through access to Aker BP’s subsurface competence and reservoir data.
“We are a leading company for digitizing E&P, and Resoptima’s technologies will help us maintain our technical leadership in reservoir monitoring and modeling to maximize value creation from our fields,” said Karl Johnny Hersvik, CEO of Aker BP. “Efficient operations require up-to-date digital models for reservoir simulation and optimization and our cooperation with Resoptima will bring forth significant value in this discipline”.
“Aker BP is committed to leveraging their impressive data platform in order to make faster and better business decisions,” said Atila Mellilo, CEO of Resoptima. “The cooperation will also enable us to improve our products based on the common view we share with Aker BP regarding the intelligent use of data for driving business decisions in the E&P sector”.
http://www.worldoil.com/news/2018/7/5/aker-bp-boosts-digitalization-agenda-with-resoptima
National Oil Corporation (NOC) and Eni announce that Mellitah Oil & Gas, Eni and NOC joint venture company (50/50), has started production from the first well of the offshore Bahr Essalam Phase 2 project. This comes just three years after the final investment decision. Two further wells will begin production within a week. An additional seven wells will come onstream by October 2018.
Phase 2 of the project completes the development of the largest offshore producing gas field in Libya, increasing production potential by 400 MMscfd. Phase 2 will be completed between September and October, bringing total field production to 1,100 MMscfd. Bahr Essalam, located about 120 km northwest of Tripoli, contains over 260 Bcm of gas. This is delivered through the Sabratha platform to the Mellitah onshore treatment plant before principally being used to supply the national network.
Chairman of the Presidential Council of Libya and Prime Minister of the Government of the National Accord, Fayez Al-Saraj, attended the opening ceremony and thanked the workers of NOC, Eni and Mellitah Oil & Gas for their efforts in developing the Libyan oil & gas sector.
China's omission of liquefied natural gas (LNG) from its vast list of U.S. products that face hefty import duties from July 6 has preserved a potential weapon should the trade war with Washington deepen.
It also underscores Beijing's desire to ensure supplies of gas as it pushes to switch millions of households and businesses away from using coal as a key part of its 'war on pollution'.
China will on July 6 impose tariffs on $34 billion of U.S. goods from pork to soybeans to cotton in retaliation for a similar move by Washington as trade relations sour between the world's top two economies.
"If the (trade) war escalates, (I expect) the government will not hesitate to add LNG," a state oil and gas company executive said.
Although U.S. LNG supplies to China have so far been tiny in volume and value compared with the around $12 billion per year of U.S. crude that arrives in the country, analysts say those levels could be set to shoot up as Beijing forges ahead with its battle to clear its skies.
Morgan Stanley has estimated annual Chinese imports of U.S. LNG could rise to as much as $9 billion within two or three years, from $1 billion in 2017. The amount could be even larger if the United States resolves a logistics bottleneck.
That would go a long way to helping balance China's trade surplus with the United States, a major bugbear of Washington's in the trade dispute. But the strategy also hands Beijing another weapon in its arsenal if the spat deteriorates further.
However, some industry sources said the country would feel the impact of any increased tariffs on U.S. LNG, as there are a limited number of major alternative suppliers.
"If we impose tariffs on U.S. LNG, we pay a much higher opportunity cost," Mei Xinyu, a researcher at a think tank affiliated with the Commerce Ministry told Reuters.
"It is easier for China to switch into other suppliers in the soybean market. Duties on soybeans hurt the U.S. more, but duties on energy products would hurt both sides."
At a meeting between the government and China's three oil and gas majors ahead of U.S. President's visit to the country last September, the companies underlined that China would have limited alternative sources for LNG imports, an official from one of the firms told Reuters.
"The conclusion at that time was that U.S. oil is not competitive," the official said. "In the gas market, we don't have much choice, mainly Qatar, Australia and the U.S."
And China is eager to avoid any repeat of last winter's gas crunch, when plunging temperatures drove people to crank up their heating amid the moves to turn away from coal.
Domestic natural gas demand rose 17.6% in the first five months of 2018, way above government forecasts of an annual growth rate of 7 or 8%, data from National Development and Reform Commission showed.
With domestic gas production restrained, China needs to expand imports to meet the target of having natural gas account for a 10% share of the energy consumption basket, said analysts.
Diamond Offshore Ocean Monarch conducting flow back operations at Sole-3 on July 5, 2018; Source: Cooper Energy
Cooper Energy has informed that Sole-3, the first of two production wells for the Sole Gas Project off Australia, is being shut-in for future connection after successful performance of clean-up and flow back operations.
The Sole Gas Project is located in VIC/L32, offshore Victoria, Australia where Cooper is the operator with a 100% interest.
The clean-up and flow back test was conducted on the near-horizontal 97 meter completed section of the Top Latrobe Group sandstone reservoir over a 26-hour period. Analysis of the test data has confirmed that well performance and reservoir deliverability are consistent with pre-drill expectations, Cooper said on Friday.
The flow rate was constrained by surface well test equipment to a maximum of approximately 48 MMscf/day, (million standard cubic feet per day) through a 104/64” choke. During a 9-hour flow period, through a 88/64” choke, the flow rate averaged approximately 38 MMscf/day.
According to Cooper, post-test analysis of the measured data has confirmed Sole-3 capability to produce above the maximum plant throughput rate of 68 TJ/day under production conditions.
The company added that the gas recovered is consistent with expectations and H2S concentrations are well within plant specifications. Sole-3 is currently being suspended prior to pipeline connection. It is expected the pipelay operation to connect the Sole gas field with the Orbost Gas Processing Plant will start in October 2018.
Cooper Energy Managing Director David Maxwell said that successful testing of Sole-3 marked the achievement of one of the key milestones for the Sole Gas Project.
“We now have a well in place, ready to go, with production capability exceeding project requirements. Reservoir quality, production performance and the gas composition are all in line with pre-drill expectations” he said.
“We now move on to resuming Sole-4 and completing the project’s drilling requirement,” Maxwell concluded.
https://www.offshoreenergytoday.com/coopers-sole-well-capability-exceeds-plant-requirements/
U.S. energy companies this week added oil rigs for the first time in three weeks but the rate of growth has slowed over the past month or so with a decline in crude prices from late May through late June.
U.S. crude prices, however, jumped to their highest since November 2014 earlier this week.Drillers added five oil rigs in the week to July 6, bringing the total count to 863, General Electric Co’s Baker Hughes energy services firm said in its closely followed report on Friday.
The U.S. rig count, an early indicator of future output, is much higher than a year ago when 763 rigs were active as energy companies have been ramping up production in tandem with OPEC’s past efforts to cut global output over the past year-and-a-half.So far this year, U.S. oil futures have averaged $65.71 per barrel. That compares with averages of $50.85 in 2017 and $43.47 in 2016.
Looking ahead, crude futures were trading at about $70 for the balance of 2018 and $65.51 for calendar 2019.In anticipation of higher prices in 2018 than 2017, U.S. financial services firm Cowen & Co this week said the exploration and production (E&P) companies they track have provided guidance indicating a 13 percent increase this year in planned capital spending.
Cowen said those E&Ps expect to spend a total of $81.2 billion in 2018, up from an estimated $72.1 billion in 2017.Analysts at Simmons & Co, energy specialists at U.S. investment bank Piper Jaffray, this week forecast average total oil and natural gas rig count would rise from 876 in 2017 to 1,033 in 2018, 1,092 in 2019 and 1,227 in 2020. Last week, Simmons forecast the count would rise to 1,037 in 2018, 1,097 in 2019 and 1,232 in 2020.
Since 1,052 oil and gas rigs were currently in service, drillers would only have to add a handful of rigs for the rest of the year to hit Simmons’ forecast for 2018.So far this year, the total number of oil and gas rigs active in the United States has averaged 1,005. That keeps the total count for 2018 on track to be the highest since 2014, which averaged 1,862 rigs. Most rigs produce both oil and gas.
The U.S. Energy Information Administration (EIA) last month projected average annual U.S. production will rise to a record high 10.8 million barrels per day (bpd) in 2018 and 11.8 million bpd in 2019 from 9.4 million bpd in 2017. [EIA/M] The current all-time U.S. annual output peak was in 1970 at 9.6 million bpd, according to federal energy data.
BP Plc is in the lead to acquire the U.S. onshore shale oil and gas assets of BHP Billiton Ltd after submitting an offer worth well in excess of $10 billion, people familiar with the matter said on Friday.
The move represents a big bet by BP on U.S. oil and gas production at a time when energy prices are rebounding. It would allow it to significantly rebalance its business with oil production, after focusing largely on natural gas assets.
BP is the front-runner in the auction for the assets run by BHP, and could reach a deal in coming weeks, the sources added, cautioning that an agreement is not certain and it is possible that negotiations could end unsuccessfully.
The exact terms and composition of BP’s offer could not be learned. The sources asked not to be identified because the matter is confidential. BP and BHP did not immediately respond to requests for comment.
BHP said in August it aimed to sell onshore shale assets in the Eagle Ford, Permian, Haynesville and Fayetteville basins, which it acquired at the height of the oil boom. It had come under pressure from activist hedge fund Elliott Management Corp to do so.
The acreage for sale includes holdings that BHP acquired in its $12-billion takeover of Petrohawk Energy in 2011, which have declined rapidly in value as the price of natural gas has fallen from $4.50 at the time of the deal to a low of $1.60 last year.
In 2015, BP began operating its onshore U.S. business as a separate entity to make it more competitive. Since then, BP has expanded the business to include acreage in the Haynesville and Bossier shale plays near the Texas–Louisiana border.
However, BP’s expansion in U.S. shale fell behind many of it peers. When others were building out their presence onshore, BP’s focus was on the aftermath of the Deepwater Horizon oil-spill disaster in the Gulf of Mexico, which has forced it to pay tens of billions of dollars in damages and restitution since 2010.
If completed, the acquisition of BHP’s acreage would be transformational for BP’s unit, adding oil-rich wells in the Permian and Eagle Ford basins of Texas.
Other oil majors that participated in the auction for the assets include Royal Dutch Shell Plc and Chevron Corp, sources have said.
China National Petroleum Corp (CNPC) is expected to sign a preliminary agreement with Abu Dhabi National Oil Co (ADNOC) later this month to invest in oil and gas exploration and refinery projects, four sources with knowledge of the matter said.
The agreement will be signed during a high-level Chinese state visit to the United Arab Emirates during which CNPC Chairman Wang Yilin will be on the business delegation.
“It will be a preliminary and broad cooperation deal that covers upstream and downstream investment,” said one of the sources, a Beijing-based oil executive briefed on Wang’s planned trip.
CNPC International, the state major’s overseas investment arm for oil and gas exploration and production, is taking the lead in talks with ADNOC, the executive added.
A CNPC spokesman declined to comment on the deal.
An ADNOC spokesman said the company has received “significant interest” from the market as well as from existing and new partners since it announced its plan to expand its strategic partnership model, but declined to comment on the specific deal.
China will host a high level China-Arab summit next Tuesday where President Xi Jinping will deliver the keynote speech.
“We see a trend of some Gulf countries such as Abu Dhabi, Qatar and Saudi Arabia moving to diversify away from their oil and gas reliant economy, by divesting some of those assets to free up capital for other sectors,” said a second source, a CNPC official.
ADNOC announced in April its first ever competitive exploration and production licensing round of six oil and gas blocks, with bids due by October. CNPC is set to join the bidding, said a separate CNPC source with knowledge of the matter.
ADNOC plans to double its refining capacity and triple petrochemicals output potential by 2025, as the state energy firm focuses more on downstream expansion to capture new growth markets.
CNPC, which runs its Middle East operation out of Dubai, last March won 10 percent stakes in two ADNOC offshore oilfield concessions under a 40-year deal that cost $1.2 billion.
That followed an 8 percent interest CNPC won in 2017 for $1.8 billion in Abu Dhabi’s giant onshore oilfield concession.
CNPC already operates refineries in Japan, Singapore, Sudan, Scotland and France, and is recently negotiating with Brazil for a partnership that could give China its first refining capacity in the Americas.
Norway: Drilling workers on fixed platforms and mobile rigs would go on strike from July 10 if a deal isn’t reached in state-backed mediation by a midnight deadline on July 9
Potential strike wouldn’t have immediate consequences on existing oil and gas production
@staunovo
Exports of LNG from Australia's east coast fell to a 15-month low in June with a sharp decline in shipments to Japan, data released by the Gladstone Ports Corporation on Friday showed.
A total of 1.6 million mt of LNG was shipped from Gladstone - where all three of eastern Australia's LNG terminals are based - down 7% year on year and 3% month on month, the data showed.
This is the lowest volume exported in a single month from the three terminals - the Origin-ConocoPhillips Australia Pacific LNG, the Santos-led Gladstone LNG, and Shell's Queensland Curtis LNG - since March last year when 1.59 million mt was shipped out, according to the data.
The last of the six trains at the port came online in October 2016 when APLNG's second train began operations, and the June export volume is the second lowest monthly total since then.
Exports could fall further as APLNG, the biggest of the three terminals, is scheduled to undergo maintenance from this month.
The two-train 9 million mt/year facility is due to see half-train outages over July 17-July 22, August 21-August 26 and September 11-September 17, according to a notice issued by the Australian Energy Market Operator earlier this year.
The National Australia Bank said in a report Thursday that Australia's total LNG exports were expected to have been flat for the April-June quarter after volumes surged over 8% quarter on quarter in January-March, but might pick up again in July-September.
Meanwhile, exports from Gladstone to Japan in June fell to a nine-month low of 66,031 mt, down 67% year on year and 49% month on month, GPC data showed.
Volumes to China where the highest since January at 1.15 million mt, up 12% year on year and 7% month on month.
Shipments to South Korea slumped to a six-month low of 242,309 mt in June, down 33% year on year and 19% month on month.
Exports to Malaysia were steady at 62,859 mt, the data showed.
Singapore got 72,033 mt of LNG in June from Gladstone port, which compares with none a year earlier and similar to the volumes imported in May, the data showed.
An Australian regulator said on Monday it had found some safety problems on the offshore gas platform for Japanese firm Inpex Corp’s Ichthys LNG project off northern Australia and was considering enforcement action.
The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) found “defiencies in the suitability of electrical equipment in hazardous areas” during a four-day inspection of the Ichthys Explorer platform in late June, a spokeswoman said in emailed comments.
Inpex had hoped to start producing gas from the long delayed $40 billion project in June, but the company’s new chief executive, Takayuki Ueda, told Reuters last week the company still had to address “various minor issues”.
“Inpex has informed NOPSEMA that it has delayed introducing hydrocarbons to the platform to address the identified deficiencies,” the NOPSEMA spokeswoman said.
An Inpex spokeswoman declined to comment on the specific technical issues. During final safety checks required before start-up some minor areas for improvement were identified, but they posed “no major challenges”, she said.
“We are firmly committed to the safety of our workers above all else and will only commence production from the wellhead when we are satisfied that final safety verifications are completed,” the spokeswoman said.
Ichthys will send gas from the offshore central processing facility through an 890-km (550-mile) pipeline to the mainland near the city of Darwin, where it will be chilled into liquefied natural gas (LNG) for export.
NOPSEMA said its inspection has yet to be formally concluded so it could not provide any further details.
Enforcement steps available to the regulator range from issuing improvement notices or prohibition notices regarding a specific activity up to civil and criminal prosecutions for major breaches, according to its web site
A ground-breaking new tax-break intended to revitalise the North Sea has moved closer to being implemented.
The UK Government published draft legislation for the introduction of transferable tax history (TTH) for the oil and gas industry.
Westminster said TTH would be available for all North Sea licence transfers approved by the Oil and Gas Authority on or after November 1, 2018.
Industry experts believe letting firms transfer tax credits would attract fresh investment to the basin and prolong production from mature fields.
Oil companies build up credits on the taxes they pay during the production life of a field. They can then use those credits to offset decommissioning costs once the well runs dry.
But under the current regime, those tax credits cannot be transferred from the asset owner to the prospective buyer.
The system has made it difficult for deals to be struck between oil majors looking to sell non-core assets and smaller, aspiring firms who are keen to beef up their portfolios, but do not want to be faced with a hefty decommissioning bill.
In the Budget in November 2017, the UK Government agreed to introduce TTH for oil and gas.
Mike Tholen, upstream policy director at Oil and Gas UK, said: “The publication of draft legislation for Transferable Tax History is greatly welcomed by the industry as it’s an additional tool in the deal toolkit, with the potential for bringing new investment to the basin.
“TTH will help increase recovery from existing fields and encourage fresh investment which will both help generate activity for our hard-pressed supply chain. It will also help extend the lives of many mature fields and postpone decommissioning.
“Adopting this measure makes it clear that the Treasury recognises the need for a predictable fiscal regime as the basin matures, which is critical in ensuring it remains competitive.
“We look forward to continuing our work with Government for these measures to be put in law and available for use to industry for deals from 1 November 2018. This in turn will ensure industry continues to provide security of energy supply for the longer term, contributing billions to the economy and supporting hundreds of thousands of high-value jobs.”
Nick Gardner, tax partner at law firm Ashurst, said: “The long awaited publication today of the draft legislation for the election to transfer tax history is to be welcomed.
“It is hoped that the introduction of the provisions with effect from this November will encourage new participants into the market, give them greater certainty that they will obtain tax relief for any decommissioning costs and assist in the UK Government’s drive to maximise economic recovery from the North Sea.
“The legislation is, however, highly complex and buyers and their financiers will need to consider carefully the extent to which there is any risk that an election may not deliver the promised tax history and incorporate appropriate contractual protections into sale documentation and loan agreements.”
Russian Novatek-led Yamal LNG project has sent two Arc7 ice-class LNG carriers destined to China via the Northern Sea Route in just nine days with no icebreaking support, marking the start of regular LNG shipments without an icebreaking escort, Novatek said Friday.
The Vladimir Rusanov tanker passed the NSR and arrived at the Bering Strait, while the Eduard Toll vessel entered open water in the Chukchi Sea, Novatek said.
Both tankers were dispatched from the port of Sabetta on the Kara Sea -- from the first 5.5 million mt/year train of the Yamal LNG project launched late 2017 -- and are now heading towards the Chinese port of Jiangsu Rudong, it said in a statement.
"The ice-covered part of the route was passed in only nine days with no icebreaking support, thus confirming the outstanding icebreaking capabilities of the Arc7 ice-class vessels," it said.
The Vladimir Rusanov left Sabetta port on June 25, S&P Global Platts reported previously.
"We are happy that the Arc7 ice-class tankers with LNG produced by our Yamal LNG project opened this year's summer navigational period on the Northern Sea Route," Novatek CEO Leonid Mikhelson said in the statement.
"These shipments were the first voyages with Russian LNG via the Northern Sea Route without escort of an icebreaker. Moreover, they mark the start of regular LNG shipments via the Northern Sea Route, which was only made possible due to the unique characteristics of ice-class LNG carriers developed for Novatek to serve the Arctic projects."
A total of five cargoes from the Yamal LNG project are expected to transit the NSR and arrive in Northeast Asia in July, according to a source close to the matter.
Of the five cargoes, three were allocated to Novatek, while single cargoes were allocated to other shareholders, namely China's CNPC and France's Total.
Since the start of the year, the project has been loading cargoes every four to eight days aboard its fleet of specialized icebreaker vessels for delivery into Northwest Europe.
A total of 33 cargoes have been shipped aboard the fleet of five specialized Arc7 LNG tankers since the start of operations.
Some cargoes have remained in Europe, while others were loaded via transshipment onto traditional LNG vessels for onward sailing to more premium markets, particularly in the Middle East and Asia.
The second 5.5 million mt/year train at Yamal LNG is currently being commissioned and is expected to come online in September or October. The third 5.5 million mt/year train will start up in early 2019.
Novatek plans to build a total of 15 Arc7 tankers by 2022, up from seven vessels in 2018.
Yamal LNG is a joint venture between Novatek (50.1%), Total (20%), CNPC (20%) and Silk Road Fund (9.9%).
Brazil’s state-run oil company Petróleo Brasileiro SA has lifted restrictions on doing business with certain units of the engineering firm Odebrecht SA [ODBES.UL], Petrobras said in a securities filing on Friday.
Petrobras’ board of directors approved the measure at a board meeting on Thursday, the filing said.
Odebrecht has been at the center of a major global corruption investigation, involving numerous other firms that paid billions of dollars in bribes to win contracts with Petrobras in the last two decades.
Under the terms of the agreement with Odebrecht SA, Petrobras will reassess the risk of doing business with its oil and gas unit Ocyan SA before allowing its participation in future Petrobras bids.
Petrobras said construction arm Odebrecht Engenharia e Construção SA will be re-evaluated after it confirms the implementation of specific points of its integrity program.
Petrobras said the agreement was possible after Odebrecht adopted measures to prevent, detect and remediate acts of corruption and fraud, policies Petrobras said it verified.
The oil company said it was keeping restrictions on another 14 companies that were put in place in 2014 in the midst of a sprawling bribery and corruption probe.
The investigation, known as “Car Wash,” has been looking into kickbacks in exchange for lucrative government contracts.
Eligibility to return as a Petrobras contractor followed Odebrecht’s leniency agreements with Brazilian and U.S. prosecutors in connection with that probe, the filing said.
China will raise gasoline price by 270 yuan per ton and diesel price by 260 yuan per ton, industry website http://Oilchem.net reports.
@staunovo
Construction of China's first self-supporting deepwater gas field has started in order to further tap oil and gas resources in the South China Sea and meet huge domestic gas demand, according to China National Offshore Oil Corporation (CNOOC), the nation's largest producer of offshore oil and gas.
This latest move by CNOOC to strengthen its presence in the area, came after it formed a partnership with Australia-based Roc Oil Co and British Virgin Islands-registered Smart Oil Investment to jointly develop oil blocks in the South China Sea.
The company also signed a similar agreement in May with Canada's Husky Energy, after putting 38 offshore blocks up for bidding to seek overseas partners for joint development, the most in recent years.
Construction of the ultradeep Lingshui 17-2 gas field in the South China Sea with certified proven reserves exceeding 100 billion cubic meters will further ensure China's energy security as the nation phases out coal and other fossil fuels and shifts toward clean energy, said Li Li, energy research director at ICIS China, a consultancy specializing in the energy market.
Li said oil companies in China had revived production this year as oil prices recovered following three years of decline. Crude prices climbed above $70 a barrel in 2018 after falling as low as $30 in early 2016. The company's deepwater drilling rig CNOOC 981 discovered Lingshui 17-2 in September 2014, which has an average operational depth of 1,500 meters below the sea surface, according to CNOOC.
While increasing US shale gas output might pose a threat to deepwater gas field exploration, which has relatively higher costs, gas production will help meet ever-increasing domestic gas demand, Li said.
According to CNOOC, China has mastered the design, construction and installation technology for semi-submersible production platforms to be used in volatile conditions in the South China Sea, it said.
The South China Sea has strong winds and cold temperatures, while constant moisture from storms and mist from the high winds make the region one of the most demanding of all offshore oil and gas exploration territories, along with the North Sea and the Gulf of Mexico, according to Li Yanjun, an engineer with CNOOC's Zhanjiang branch.
To further tap the gas resources in the South China Sea, CNOOC has also been eyeing more opportunities in the South China Sea in recent years, including the high-temperature and high-pressure gas fields in the region.
According to the Ministry of Land and Resources, nearly 15 trillion metric tons of natural gas lie in the high-temperature and high-pressure gas fields of the South China Sea, one-third of the total in the region.
However, Li from ICIS China said despite a potential supply of gas resources, a significant factor to cause gas shortage is the limited capacity of distributed gas storage infrastructure.
China's imports of gas currently account for more than 30 percent of domestic consumption, and the figure is expected to continue growing, she said.
"It's necessary that China develops massive gas storage facilities to avoid large-scale gas shortages," said Li.
ExxonMobil has, together with its partners in the Mozambique Rovuma Venture submitted the development plan to the government for the first phase of the Rovuma LNG project, which will produce, liquefy and market natural gas from the Mamba fields located in the Area 4 block offshore Mozambique.
The plan details the proposed design and construction of two liquefied natural gas trains which will each produce 7.6 million tons of LNG per year.
ExxonMobil will lead the construction and operation of natural gas liquefaction and related facilities on behalf of the joint venture, and Eni will lead the construction and operation of upstream facilities.
“As the Rovuma LNG project progresses, every effort will be made to actively build the local workforce and supplier capabilities in Mozambique,” ExxonMobil said on Monday.
Liam Mallon, president of ExxonMobil Development Company said:“We are excited to be progressing the Rovuma LNG project, working with the government and leveraging the expertise and capabilities of all of the partners,”
“The Rovuma LNG Project is moving forward swiftly,” said Stefano Maione, Eni’s executive vice-president for the Mozambique Program. “The size of the project makes it not only an important investment in the country, but also supports economic growth and opens new opportunities for Mozambicans.”
FID in 2019, start-up in 2024
A final investment decision by the Area 4 joint venture parties is scheduled in 2019, with LNG production expected to start in 2024. Marketing activities are progressing, with negotiations on sales and purchase agreements underway, targeting completion in parallel with the development plan approval process.
Rovuma LNG is operated by Mozambique Rovuma Venture S.p.A., an incorporated joint venture owned by ExxonMobil, Eni and CNPC, which holds a 70 percent interest in the Area 4 concession alongside its partners Galp, KOGAS and Empresa Nacional de Hidrocarbonetos E.P. (ENH), each of which hold a 10 percent interest.
ExxonMobil in June said it had made significant progress on marketing the Rovuma gas, and that it was in active negotiations on binding sales and purchase agreements for Rovuma LNG with some affiliated buyer entities of the Area 4 co-venturers.
France’s Total is set to sell a third of its stake in Laggan Tormore gas field along with other oil and gas assets in Britain’s North Sea that could fetch a total of $1.5 billion, four banking and industry sources said.
The divestment will include stakes in a number of smaller fields Total acquired as part of the 2017 $4.95 billion deal to buy the oil and gas division of A.P. Moller-Maersk, the sources said. The deal was completed in March.
Those fields include Golden Eagle, in which Total has a 32 percent stake, as well as Dumbarton (30 percent), Bruce (43 percent) and Keith (25 percent).
Bank of America Merrill Lynch will run the sale of the 20 percent stake in Laggan Tormore process, which leave Total with a 40 percent stake once complete. Investment bank Lambert Energy will lead the sale of the other stakes.
Total and Lambart Energy declined to comment. Bank of America Merrill Lynch did not respond to a request for comment.
The sale is part of a broad change of guard in the aging North Sea where veteran players are seeking to dispose of older fields with declining production while new, nimbler companies believe they can squeeze out more value.
Last week, Chevron said it was preparing to sell its fields in the central North Sea. Royal Dutch Shell and BP have also sold a large number of fields in recent years.
The Laggan Tormore gas field, in which Total now has 60 percent, started production in February 2016 and can produce up to 90,000 barrels of oil equivalent per day.
Any deal for the Bruce and Keith fields is likely to be complicated, however.
London-listed Serica Energy, which agreed to acquire stakes in Bruce, Keith and the adjacent Rhum field from BP last year, is seeking a waiver from the U.S. government to allow it to operate Rhum, which is 50 percent owned by Iran’s national oil company, as Washington prepares to re-impose sanctions on Tehran.
Without a waiver, the field will have to shut down, leaving Bruce and Keith holding little value, the sources said.
Saudi Aramco is more resilient to oil price slumps than its biggest listed rivals, its 2016 accounts indicate, giving a rare insight into the state energy giant’s finances ahead of a proposed flotation.
The full-year accounts, not publicly available but seen by Reuters, show Aramco’s net income fell by about 21 percent to $13.3 billion in 2016 - when oil prices collapsed to a 12-year low of $27.10 a barrel due to a global glut of crude.
By comparison, the net income of Exxon Mobil Corp, the world’s largest listed oil company, dropped 51 percent in 2016, while the earnings attributable to shareholders of Royal Dutch Shell, the No.2 listed oil firm, fell 37 percent, excluding items.
Saudi Aramco said in response to a request for comment: “Saudi Aramco does not comment on speculation regarding its financial performance and fiscal regime.”
Industry experts say Aramco’s ability to better weather price shocks is down to low production costs, the fact its major operations are concentrated in just one country and because it has fewer employees than its biggest rivals even though it is the world’s largest oil producer.
Analysts estimates the Saudi giant’s production costs at below $1 per barrel compared to $10 per barrel in places like Russia and as much as $20-30 per barrel in locations like the North Sea.
The accounts show 67,718 people worked for Aramco in 2016. That compares with 71,100 at Exxon and 89,000 at Shell.
Aramco produces around 10 million barrels per day (bpd) of oil compared with Exxon’s and Shell’s oil equivalent of 4 million bpd and 3.7 million bpd respectively.
In April, Bloomberg reported Aramco had net income of $33.8 billion in the first six months of 2017, up from $7.2 billion in the first of half of 2016, as oil prices spiked and as the Saudi government changed the tax rate.
Full-year results for 2016 and 2015 have never been disclosed before.
Aramco’s earnings and other key information about the company, which pumps about 10 percent of the world’s oil, have been a closely guarded secret for decades.
The accounts provide a window into its finances ahead of the proposed stock market listing, should it go ahead.
Even though Aramco may be bigger and more resilient than its peers, analysts have repeatedly expressed doubt that it can achieve Riyadh’s $2 trillion valuation, if and when it decides to list its stock. Its nearest rival Exxon is worth $350 billion.
A listing of up to 5 percent of Aramco has been the centerpiece of a government plan to diversify the kingdom’s economy. But some sources close to the process say the plans for a domestic and international listing may never happen.
“Domestic is more likely, but the whole thing is uncertain,” said a source familiar with Aramco’s IPO plans.
Saudi Arabia’s energy minister, Khalid al-Falih, said on June 21 it would be “nice” to see Aramco floated in 2019, adding the timing was not critical to the government.
$13 BILLION NET INCOME
The documents seen by Reuters show that Aramco made more money than any other oil company in 2016.
Its net income of $13.3 billion in 2016 outstripped Exxon’s $7.8 billion, while Shell reported 2016 earnings attributable to shareholders - the equivalent metric - of $3.5 billion.
BP, dealing with the financial aftermath of the Deepwater Horizon disaster, reported a loss of $999 million in 2016, better than a $5.162 billion loss in 2015.
Based on cash flow from operations, another important metric for investors, Aramco did well too.
The company’s net cash from operating activities rose about 21 percent to $29 billion in 2016, the accounts show.
The highest figure among the listed competitors was reported by Exxon, whose cash flow from operations was $22.1 billion, down 27 percent from 2015. Shell’s cash flow from operations fell 31 percent and BP’s declined 44 percent.
Aramco realized an average price of $40.68 on its crude oil exports in 2016, down from $49.46 in 2015, the accounts showed. Revenue was $135 billion, down from $146 billion in 2015.
The 2016 Aramco accounts reviewed by Reuters were prepared according to IFRS standards, and according to the 85 percent tax rate that applied at the time. The Saudi government cut the tax rate to 50 percent from 2017, making the firm more attractive to potential investors.
Indonesia’s state owned energy holding company, Pertamina, has decided not to go ahead with what would have been the country’s second land-based receiving terminal for liquefied natural gas (LNG), its chief executive said on Monday.
Indonesia has forecast sharp increases in gas demand after 2020, but increases in domestic consumption of the super-cooled fuel have been hampered by an abundance of cheap coal and sluggish development of gas infrastructure.
“Today we are not going ahead, because it is not yet feasible to continue,” Pertamina acting CEO Nicke Widyawati told reporters, referring to the project that would have been built in Bojonegara, not far from Jakarta.
The terminal, valued at up to $800 million, was to be developed in a joint venture between Kalla Group unit Bumi Sarana Migas and Pertamina, with financing from the Japan Bank for International Cooperation (JBIC).
The 4-million-tonne-per-year terminal was to be designed by the engineering unit of Tokyo Gas Co Ltd and was expected to come onstream in 2019.
“Gas demand has declined so it’s not feasible from a business standpoint,” Widyawati added, noting that if gas demand for power generation increased the decision to halt the project may be reviewed.
Norway’s BW LPG, the world’s largest liquid petroleum gas shipper, raised its offer to buy rival Dorian LPG on Monday after its first advance was rebuffed.
BW offered Dorian shareholders 2.12 BW LPG shares for each Dorian share, up from 2.05 BW LPG shares in an initial offer made on May 29.
BW LPG said the offer represents a value of $8.67 per Dorian share. The stock closed at $7.98 in New York on Friday.
The total equity value of the new transaction is about $479 million, with a total enterprise value of about $1.1 billion, including the assumption of net debt.
BW LPG said it had held conversations with “many shareholders of both companies” and that the sentiment had been “overwhelmingly positive with many shareholders expressing surprise at Dorian’s refusal to engage”.
“Although the company remains open to engaging in dialogue with Dorian, BW LPG intends to nominate independent, highly qualified directors to stand for election to Dorian’s board at its upcoming annual meeting,” BW LPG said in a statement.
The deal is backed by shipping conglomerate BW Group, owned by the Hong Kong-based Sohmen-Pao family, which owns 14.2 percent of Dorian and about 45 percent of BW LPG.
Shares in BW LPG were up 2.47 percent at 0754 GMT, outperforming an Oslo benchmark index up 1.06 percent.
Dorian LPG’s fleet consists of 22 very large gas carriers (VLGC).
The combined company would own 73 vessels, of which 68 would be very large gas carriers, 2 VLGCs currently under order and 3 large gas carriers.
A flurry of activity in a remote Canadian town is raising optimism that Royal Dutch Shell and its partners are ready to go ahead with the nation’s largest infrastructure project: a C$40 billion ($30 billion) liquefied natural gas terminal that could at last unlock energy exports to Asia.
The action is unmistakable in Kitimat, British Columbia, the Pacific coast city hugging a deep inlet that would be the closest launch point on the continent for LNG cargoes to Asia. The lights are on, shades open and SUVs parked outside a 49-unit apartment complex built to house Shell executives, which sat mostly darkened for the last two years. Local workers have left jobs at a Rio Tinto Plc smelter nearby to join contractors ramping up for the LNG project. Landlords are raising rents and houses are selling twice as fast as they used to in anticipation of a flood of workers coming to town.
“I would put money on it -- it’s going ahead," says Phil Germuth, mayor of Kitimat, who recently hosted a banker from Barclays Bank Plc visiting from the U.K. to examine the project. Germuth also met a group of officials reporting to the board of Mitsubishi Corp., one of the project’s five partners, who visited the site in May.
When Crystal Smith, head of the Haisla Nation whose indigenous lands surround the proposed terminal, was invited to the project site last week by another group from Mitsubishi, she couldn’t find a spot in the usually deserted parking lot.
Goose Bumps
“Who gets excited to see a full parking lot? I got goose bumps from seeing it full," she said. While she’s met officials in the past as the leader of a community whose consent is integral to the project, she recounts "this meeting was a little different." There was no agenda. "They just wanted to meet -- in the sense that they’re very optimistic we’re going to be together for the next 40, 50 years."
LNG Canada, as the project is called, is stunning in scale. It proposes to eventually ship as much as 28 million tons a year out of Kitimat, the equivalent of 10% of global LNG supply in 2017. It would carve out a new path -- the shortest by days -- between North America and Asia for super-chilled gas. For Canada, whose energy exports are sold almost exclusively to the U.S. at depressed prices for the lack of a coastal facility, it means unlocking the Montney, a massive formation holding about half the total reserves of Qatar. It would also mean an investment triple the size of Canada’s largest single infrastructure project to date, LNG Canada CEO Andy Calitz said in a LinkedIn post last month.
Decision Delayed
LNG Canada -- comprised of Shell, Mitsubishi, Malaysia’s Petroliam Nasional, PetroChina and Korea Gas Corp. -- expects to make a final investment decision by the end of the year. An exact date is up to the partners to make, Susannah Pierce, spokeswoman for LNG Canada, said in an email.
The project’s backers twice-postponed the decision in recent years amid a global supply glut. That outlook has turned. Energy producers from Shell to Total to Anadarko Petroleum are looking again at projects deemed too risky just a year ago as demand picks up faster than expected.
"Goodbye gas glut," Sanford C. Bernstein & Co. analysts said in a June 28 note. New supplies of LNG are "being easily mopped up by rampant market growth." While only one major LNG project gained approval last year, in the next 18 months some $150 billion worth of LNG ventures have a better-than-even chance of going ahead, according to Energy Aspects. Meanwhile, prices in Asia -- the biggest market for the fuel -- are rebounding.
Calgary-based Stream Asset Financial Management said this week it believes a positive final investment decision "is effectively a done deal" and will be announced earlier than expected, likely in the second or third week of September. National Bank of Canada analyst Greg Colman believes "the probability is weighted towards a positive decision." His team, using Google Earth, has spotted old storage tanks being cleared from the site, a barge installing piles to expand the pier, and preparatory work for the massive camps that would host thousands of workers.
Tidal Wave
Terrace Mayor Carol Leclerc, whose city 60 km to the north serves as the region’s hub, says she’s "99.9%" sure the project will move forward, citing the flurry of activity. "It’s going to be like a tidal wave coming into the northwest."
The clock is ticking. British Columbia has set a Nov. 30 deadline for a final decision if the project is to claim as much as C$6 billion in tax breaks and savings. Meanwhile, in recent weeks both LNG Canada and TransCanada Corp., which would build the 670-km pipeline to supply the terminal, have selected their main contractors to lock in prices for the project.
Graham Pitzel, a Re/Max real estate broker in Kitimat, says he’s getting calls nearly every day from people in Vancouver, Edmonton, Calgary and Toronto interested in purchasing properties in the town of 8,000 people, speculating prices will surge as the project takes off. Homes used to stay on the market for six months; now the average is half that. He says bungalows never fetched more than C$200,000 earlier, but he’s just sold one for C$260,000 and has an offer of C$290,000 on another.
“I’m building a house because if you try to do it after the project’s going, it’s going to be hard to find a contractor," Pitzel says. "It’s now or never."
Duties Exemption
Hurdles remain. The federal government has yet to clarify whether it’ll grant the project an exemption from duties on the complex steel modules needed to build a terminal. Each LNG model can be as tall as a 10-story building and weigh as much as 10 jumbo jets -- no Canadian assembly yard has the experience or space to build them along with the water access to ship them to site, according to David Keane, president of the BC LNG Alliance. The federal finance ministry didn’t respond to a request seeking comment.
“We are confident in our position that large, complex LNG modules cannot be made in Canada, and therefore should not be subject goods," LNG Canada’s Pierce said.
Canada can hardly afford to let another major energy investment flame out. Former British Columbia Premier Christy Clark once boasted that more than 20 LNG projects would be built in the province, yet none has gone ahead.
In May, Prime Minister Justin Trudeau’s administration had to buy Kinder Morgan’s Trans Mountain oil pipeline system for C$4.5 billion to ensure the controversial expansion gets built amid fierce local opposition. While LNG Canada has the support of the provincial government, the proposed TransCanada pipeline route runs near one group of indigenous opponents in northern BC pledging to block the project.
Local Support
Still, indigenous and municipal officials say Shell has painstakingly cultivated on-the-ground support and is unlikely to face local opposition. The plant will have the lowest carbon emissions in the world per ton of LNG produced, according to the provincial government. To address fears of pipeline leaks, it hired an energy consultant to lug a vat of chilled gas to local schools, pouring LNG onto the floor to demonstrate how quickly it evaporates into thin air. Amid a national outpouring of grief over a deadly April bus accident involving a junior hockey team from Saskatchewan, Shell donated a new bus with seat belts to a high school in Kitimat.
“If there were a blueprint of how to approach any kind of major industrial project, especially in oil and gas, LNG Canada is one to learn from," says the Haisla Nation’s Smith
Valero Energy Corp shut production on the small crude distillation unit (CDU) at its 180,000 barrel-per-day (bpd) Memphis, Tennessee, refinery on Monday for repairs, sources familiar with plant operations said.
A Valero spokeswoman did not reply to a request for comment.
Valero plans to keep the 80,000 bpd CDU shut until July 25 for unplanned repairs to clean out fouling from crude oil, the sources said.
Two recent asset acquisitions by small exploration-and-production companies in the Eagle Ford Shale of South Texas and press reports hinting at the potential for a much larger deal could signal a renewed interest in the play among producers.
In the first deal, announced July 2, privately owned producer Venado Oil and Gas, in partnership with investment firm KKR, will acquire 22 producing wells and approximately 23,000 net underdeveloped Eagle Ford acres from an undisclosed buyer.
In Q2 2018 the acquired assets, which are next to the partnership's existing operated assets in Atascosa and Frio counties, saw production of around 4,500 boe/d net, the partners said in a statement. Production was composed of 74% oil, 11% natural gas and 15% natural gas liquids. Venado and KKR did not disclose the financial terms of the transaction
In the second deal, announced July 5, Japanese trading and investment conglomerate Sumitomo Corporation said subsidiary Summit Discovery Resources II had reached a deal to acquire 624 acres in Karnes County, in the core of the Eagle Ford. As a result of the transaction, SDRII has become the 100% working interest owner and operator of the assets, which have an estimated peak production of 3,000 boe/d.
INTEREST IN EAGLE FORD RISING ALONG WITH CRUDE PRICES
Interest in the oil-rich Eagle Ford is growing as oil prices and demand for crude are on the rise. Gas production from the play is expected to increase, in association with the region's crude oil output. Drilling activity in the Eagle Ford Shale has been unimpeded by pipeline constraints that are now affecting the Permian Basin. On Friday, rig count in the South Texas play edged up to 81 and is now just shy of a recent 12-month high. In the Texas portion of the Permian, the number of drilling rigs slumped to 379 last week, down by 12 over the past month, data compiled by Baker Hughes shows. At nearly $76/b, spot market crude prices in the Eagle Ford are now outperforming benchmark WTI Midland crude by more than $15/b, according to S&P Global Platts data.
A widening spread between West Texas and Gulf Coast crude prices in recent months comes amid growing concerns over pipeline takeaway capacity from the Permian Basin.
Natural gas transport capacity isn't far behind either, with significant constraints expected to emerge by third-quarter 2018.
In addition to the two small transactions announced this month, a major deal, which would significantly change the ownership profile of the Eagle Ford, could be in the offing.
According to recent press reports, international oil and gas giant BP is the lead contender to acquire the onshore US oil and gas assets of Australia's BHP Billiton, having submitted a bid of $10 billion. Citing company policy, a BP spokesman declined to comment on the reported bid.
Last August BHP, which owns assets in the Haynesville Shale and Permian Basin plays as well as the Eagle Ford, under pressure from activist shareholder groups, announced plans to exit the US onshore sector and sell its existing US assets at auction.
At the time of the announcement BHP said its Eagle Ford assets had produced 10.9 million boe, which included 4.9 million barrels of oil and condensate, 2.7 million barrels of natural gas liquids and 19.4 Bcf of gas in the quarter that ended June 30, 2017.
The US ethane cracker margin fell to a record low Monday, a result of a continued surge in ethane pricing and a weak spot ethylene market.
The US ethane cracker margin was calculated Monday at 2.65 cents/lb, down 0.10 cent from Friday, falling to the lowest level since S&P Global Platts began assessing them in 2011.
July non-LST ethane, reflecting prices at the Enterprise NGL storage and fractionation facility in Mont Belvieu, Texas, rose 1.375 cents to 39.625 cents/gal on Monday. It topped 39 cents for the first time since 2014.
Ethane was last assessed higher on February 24, 2014, at 40.75 cent/gal.
Ethane cash costs have climbed on limited supply from strong export numbers and production capacities, as well as strong demand from upcoming cracker startups.
The US ethylene market has been weak on concerns of oversupply, awaiting news of on-spec production from ExxonMobil's new 1.5 million mt/yr Baytown, Texas, steam cracker -- expected by the end of the summer-- as well as the startup of Indorama's Lake Charles, Louisiana, 440,000 mt/yr cracker, by the end of the third quarter.
Spot prices hit one-month lows on June 18-19 of 12.25 cents/lb FD USG, only 0.25 cent above record lows reached in mid-May, according to Platts data. Spot prices have climbed 18.4% since June 18, rising on steep feedstock costs and extended maintenance at two Texas steam crackers --Eastman Chemical's No. 3A and Chevron Phillip Chemical's Port Arthur ethylene unit 1544.
US ethylene for prompt-month delivery was assessed Monday at 14.25-14.75 cents/lb FD USG, up 0.75 cent on the day.
Although, margins remain low for ethylene production, integrated producers are seeing favorable margins between ethane and downstream derivatives, most notably polyethylene due to stronger prices.
The world's largest shipping association, the Baltic and International Maritime Council, or BIMCO, has called upon the International Maritime Organization to adopt more accurate sulphur verification procedures and an effective implementation plan for compliance to the IMO 2020 rule.
This comes as an intersessional meeting of the IMO on sulphur implementation is being held over July 9-13.
The IMO rule on the 0.5% limit on sulphur in marine fuels, compared with 3.5% now, will take effect January 1, 2020. It applies outside designated emission control areas where the limit is already 0.1%.
The introduction of the 0.5% global sulphur cap is the most significant change since the introduction of liquid bunkers as some 60% of the bunkers will have to switch from high sulphur fuel oil to low sulphur grade overnight, according to some industry sources.
"The current IMO verification procedure contained in Appendix VI to MARPOL Annex VI is a mash-up of some elements from the ISO verification procedure, making the outcome random and difficult for ship operators and PSC authorities to understand," BIMCO said in a statement made available to S&P Global Platts late Monday.
"BIMCO and its partners firmly believe the current verification procedure fails to be statistically sound," it added.
In this context, it has submitted a paper to the IMO, proposing ways to secure a uniform and more accurate way of interpreting results when measuring the level of sulphur in fuel oil, BIMCO said.
The aim of the proposal is to secure easy-to-understand, easy-to-implement and uniform verification procedures of test results for both MARPOL samples and in-use fuel oil samples, it said.
One of the proposals in the document calls for the IMO to replace Appendix VI with an appropriate reference to the ISO 4259 standard, it said.
ISO 4259-1:2017, for example, specifies the methodology for the design of an inter-laboratory study and calculation of precision estimates of a test method specified by the study.
The document submitted by BIMCO also includes proposals to add a definition of sulphur content in regulation 2 of MARPOL Annex VI and to unify verification procedures for both MARPOL samples and in-use fuel oil samples, it said.
Separately in another statement, BIMCO said it had also, along with its partners, submitted a draft proposal to the IMO for an implementation plan for achieving compliance with the 0.5% global sulphur cap.
This is significant as widespread compliance to the IMO 2020 rule still remains of great concern because of the magnitude of the change this rule entails and its associated costs.
A marine industry survey conducted by ExxonMobil last year, for example, noted that the route to compliance with the IMO global sulfur cap was unclear for many vessel operators, with 70% of respondents saying that they do not believe the industry was ready for the deadline.
BIMCO said it wanted IMO member states to encourage the ships flying their flags to develop written implementation plans, to help member states adopt a practical and pragmatic approach when verifying compliance with the requirements of sulphur regulation.
The implementation plan could voluntarily be submitted to authorities, and ships carrying an implementation plan along with a detailed description of how it is being followed should be met with a practical and pragmatic approach during inspections, it said, adding that "this pragmatic implementation approach would be for a period of three months after January 1, 2020 for those ships which are in possession of an implementation plan."
"The priority of compliance inspections in ports should be on willful non-compliance with the regulations. Where ships experience technical or operational issues that may lead to accidental and unintended non-compliance, this should be considered differently than willful non-compliance, and such ships should not face severe measures or penalties," it said.
The draft implementation plan includes planning and preparation for structural modifications, if required, detailing the number of bunker tanks designated to store low sulphur fuel as well as the purchasing procedure to source compliant fuels, among other aspects, it said.
The average price Japanese buyers paid for spot LNG cargoes contracted in June rose to $9.30/MMBtu, up 13.4% from $8.20/MMBtu in May, the Ministry of Economy, Trade and Industry said Tuesday.
METI does not disclose delivery months for the spot deals contracted in any given month.
Demand for summer cargoes, coupled with supply issues at multiple projects including Sabine Pass in the US and Malaysia's Bintulu, lent some upward pressure for the spot market in June.
The Platts JKM averaged $10.39/MMBtu in June, reflecting deals for July and August deliveries.
The average price of spot cargoes delivered to Japan in June stood at $8.90/MMBtu, up 12.7% from $7.90/MMBtu in May, METI data showed.
Against this, the Platts JKM for June delivery cargoes averaged $7.971/MMBtu. The marker was assessed from April 16 to May 15, during which the price gradually rose on the back of firm demand from end-users and traders.
After treading near the 79-Bcf/d level this past spring, Lower 48 natural gas production surged about 1.5 Bcf/d higher in the last three weeks of June to record highs approaching 82 Bcf/d by month’s end. The supply gains suspended the market’s bullish view of the persistently large storage deficit compared with last year and the five-year average and reeled in the prompt CME/NYMEX Henry Hub futures contract from the $3/MMBtu mark — at least for now. Where did the gains occur and how much of that influx truly is new production versus volumes returning from seasonal maintenance? Today, we examine the drivers behind the recent production jump.
It’s no surprise that Lower 48 production has been on a tear lately. As we noted in Fill Me Up, Buttercup, the market this past winter was expected to add more than 4 Bcf/d of pipeline takeaway capacity in the Northeast. Much of that has come to fruition, with new capacity added as recently as June 1 on Rover Pipeline (Are You Ready, Part 2). Moreover, rig counts (black line in Figure 1) in recent weeks have been at the highest levels since March 2015, with the June 2018 average count coming to 1,056 rigs.
Figure 1. Sources: Baker Hughes, RBN Energy
What has taken the market by surprise, however, is the abruptness and sheer strength with which production has surged in just the past couple of weeks. Lower 48 dry gas production, per RBN’s NATGAS Billboard data (blue area in Figure 1), started 2018 at an average 76.3 Bcf/d in January, more than 1.0 Bcf/d below the December 2017 monthly average high of 77.5 Bcf/d. In February and March, domestic supply rallied to new highs, ending the first quarter of 2018 near 79 Bcf/d. But then growth all but stalled. As the red arrows indicate, between March and June (2018), the volumes mostly oscillated within 0.5-Bcf/d on either side of the 79-Bcf/d level. It wasn’t until the second half of June that output shifted into high gear. If we compare average volumes in the week ended June 7, versus the week ended June 28, we see that total Lower 48 dry gas production zoomed higher by about 1.5 Bcf/d in that time to 81.8 Bcf/d by June 30, with the bulk of those gains occurring in the last week of the month.
The production gains have continued into July, with yesterday’s Billboard data showing that volumes hit a new high of 82.2 Bcf/d just this past weekend. That’s a whopping 10 Bcf/d higher than this time last year. It’s no wonder that Henry Hub futures, which touched the $3/MMBtu mark in late June, have whimpered back 15 cents or so since then to the $2.80s.
So, where’s the production growth happening and what’s behind it? To know that, we dive into the regional breakdown in OPIS PointLogic’s modeled gas production data, which tells us that on the macro level, supply rose in every region to varying degrees. But, as Figure 2 below suggests, the gains certainly were more pronounced in some regions than others. The columns in the graph show the change in volumes by region from the first week of June (ended June 7) to the last week of June (ended June 28). As one would expect based on recent patterns, the Northeast and Texas regions led the charge, making up about 600 MMcf/d and 300 MMcf/d of the total gains, respectively. When combined, that’s about 60% of the total. The offshore Gulf of Mexico contributed another 200 MMcf/d or so, while the Rockies, Southeast and West brought online 100-150 MMcf/d each; only the Midcontinent region was relatively flat.
Figure 2. Source: OPIS PointLogic
A confluence of factors, from takeaway capacity and seasonal demand to operational events, led to the sudden groundswell of supply at the end of June. Next, we take each of the growth regions individually to understand what’s behind the surge, starting with the Northeast.
Northeast Production
If we break down the Northeast production data into producing areas, Appalachian volumes from West Virginia fell off, but gains from two Marcellus Shale subregions — the liquids-rich southwestern Pennsylvania (SWPA) and the dry northeastern Pennsylvania areas — as well as from the Utica (primarily in Ohio) more than made up for those declines. Volumes from these three regions combined jumped 660 MMcf/d between the week of June 7 and the week of June 28 — 260 MMcf/d and about 200 MMcf/d from the SWPA and northeastern Marcellus regions, respectively, and another ~200 MMcf/d from the Utica.
The uptick was all the more impressive given that takeaway capacity from the area experienced a major disruption starting on June 7 (2018), when a pipeline explosion prompted a force majeure on Columbia Gas Transmission’s (TCO) new Leach Xpress line (LXP). We discussed the effects of this event on production, prices and Gulf-bound flows last month in Here I Am. As we noted in that blog, TCO’s production receipts fell off dramatically as LXP’s capacity was cut down to zero; the line is not expected back online until mid-July, as of the latest update from the operator. However, as we also noted last time, the event had little impact on overall Appalachian production, and, what’s more, volumes are up from pre-explosion levels. This is because other pipelines picked up the slack, rerouting the gas to alternative markets in the Northeast and Midwest.
Pipeline flows show that while TCO production receipts from the SWPA dropped nearly 200 MMcf/d between the first and last week of June, other takeaway pipes from the area — including Dominion Transmission, Equitrans and Tennessee Gas Pipeline (TGP) — picked up 430 MMcf/d, for a net change of 265 MMcf/d.
TCO receipts from Ohio were also down nearly 500 MMcf/d. But flows through several of the other pipes, which had been lagging in May and early June, likely due to mild spring demand, climbed in the latter part of June as temperatures rose and air conditioning demand lifted deliveries to power generators. Ohio receipts on Texas Eastern Transmission Co. (TETCO), which had been flagging around the 800-MMcf/d level in early June, ramped up by 280 MMcf/d to nearly 1.1 Bcf/d in the last week of June. Westbound flows on the Rockies Express Pipeline (REX), which had diminished through May and early June (2018), jumped about 250 MMcf/d in late June to nearly 1.8 Bcf/d. And, Rover Pipeline, which had phased in another 600-MMcf/d of service starting June 1 (see Are You Ready, Part 2), took on another 100 MMcf/d or so by the end of the month.
All in all, the net effect of these changes is that Northeast production has posted record highs for the four consecutive weeks since mid-June. As of the week ended July 5, PointLogic estimates regional volumes average 28.3 Bcf/d, up from 27.5 Bcf/d in early June.
Texas
In the Lone Star State, where production rose from about 17.9 Bcf/d in early June to nearly 18.3 Bcf/d by late June, increases were smaller and scattered across the region. The biggest gains were in the Permian, where supply receipts rose about 150-200 MMcf/d during that time. As we’ve noted in RBN’s weekly NATGAS Permian report, incremental takeaway and power generation capacity in Mexico has allowed a bit more gas to flow across via the Roadrunner Pipeline, supporting a slight uptick in Permian production. As of the July 9 issue of the report, total Permian supply volumes hit just shy of 8.2 Bcf/d over the weekend and averaged 8.1 Bcf/d in the past week, after ending June near 8 Bcf/d.
Offshore Gulf of Mexico
Offshore volumes from the Gulf of Mexico increased by more than 300 MMcf/d in the last two weeks of June, with gas flow data indicating that at least some of this incremental volume — though perhaps not all could be production from new points. For example, Kinetica Deepwater Express’s receipts at the “G-GB 426 (Auger) RIP VR 397” point have climbed more than 100 MMcf/d in the past two weeks. Recent history indicates the point began flowing for the first time in September 2017, and has been flowing intermittently since then. It ramped up to about 175 MMcf/d in early May (2018) before dropping to zero in the last week of that month. Flows were recovering in early June but it wasn’t until the last week of the month that volumes reached 200 MMcf/d, the highest since the point began flowing last year.
Similarly, the Viosca Knoll Gathering System (VKGS) receipt point on Destin Pipeline jumped to a new high of 200 MMcf/d in the last week of June, from about 70 MMcf/d in the prior week, but the point first exceeded the 30-MMcf/d mark in late May and had reached 180 MMcf/d in early June before it fell off to that 70 MMcf/d in the week of June 21. Thus, these volumes were largely a recovery from a decline in the prior week.
PointLogic estimates Gulf of Mexico volumes averaged 2.6 Bcf/d in late June, compared to just under 2.4 Bcf/d in the first week of the month. But that still represents a decline from levels seen in February and March of this year, when the weekly average went as high as 2.7 Bcf/d.
Rockies
In the Rockies, a slew of gas processing plant outages — most likely for routine “shoulder season” maintenance — increased volatility in production flows in June. As several of these plants happened to return to service in the last week of June, they created a pile-on effect in terms of production volumes, given the timing. Volumes from the Lancaster plant in Colorado dropped down to about 200 MMcf/d in mid-June, for instance, from more than 400 MMcf/d normally. By the last week of June, volumes recovered to near 300 MMcf/d, though they remain below the usual level. The Sweetwater plant had dropped from about 100 MMcf/d to 25 MMcf/d in early June and then recovered to its pre-outage level by late June.
Southeast
In the Southeast, gains were concentrated in Louisiana, where Haynesville volumes ticked up a modest 130 MMcf/d or so through June to end the month just under 6 Bcf/d. Again, while these volumes reflect an increase from early June (2018), they don’t reflect growth from recent highs, given that output from the area had touched 6.1 Bcf/d in late May (2018).
The bottom line is that a variety of factors converged in late June to propel production to new heights. With peak summer demand likely still ahead and more takeaway capacity due online, production growth for this year is far from over. Recent filings suggest Rover is champing at the bit to get the last of its 3.25 Bcf/d capacity online, with ~ 1.0 Bcf/d still left to go, not to mention Transco’s Atlantic Sunrise project (due online later this year), and the possibility of LXP capacity returning by mid-July, among others.
https://rbnenergy.com/skys-the-limit-record-gas-production-reins-in-futures-prices
The American Petroleum Institute reported Tuesday that U.S. crude supplies fell by 6.8 million barrels for the week ended July 6, according to sources. The API data also showed supplies of gasoline down 1.6 million barrels, while distillate stockpiles climbed by nearly 2 million barrels, sources said.
Supply data from the Energy Information Administration will be released Wednesday. Analysts polled by S&P Global Platts expect the EIA to report a fall of 4.8 million barrels in crude supplies. They also forecast a supply decrease of 1 million barrels for gasoline, and an increase of 1.7 million barrels for distillates.
CME Group Inc said on Tuesday it will develop the first physically deliverable U.S. liquefied natural gas futures contract as growing worldwide demand has made the United States a key LNG exporter.
CME said the contract will take delivery at Cheniere Energy Inc’s Sabine Pass LNG export terminal in Louisiana. It could not say when it will launch the new product or provide details other than that it will trade on the CME’s New York Mercantile Exchange (NYMEX) like its Henry Hub natural gas futures.
Overall world LNG consumption has risen to a record 39.0 billion cubic feet per day (bcfd) in 2017 from just 29.1 bcfd in 2010 and is expected to keep growing by about 3 percent a year through 2050, according to U.S. energy data.
While LNG trade on exchanges like the CME is still small, experts believe volumes will increase rapidly in the near future as the United States becomes one of the world’s biggest LNG exporters.
Total U.S. LNG export capacity is expected to rise to 10.1 bcfd of gas in 2020 from 3.8 bcfd now, making the country the third-biggest LNG exporter in the world by capacity in 2019. One billion cubic feet is enough to fuel about 5 million U.S. homes for a day.
“We have spoken to the market and they have expressed a desire to have a physically delivered LNG contract that can help them manage price risks,” said Peter Keavey, global head of energy at CME.
Pricing at Cheniere’s Sabine Pass is currently linked to the Henry Hub gas benchmark traded on CME’s NYMEX. Sabine Pass was the first terminal in the U.S. lower 48 states to produce and deliver super-cooled LNG for export to the world.
Cheniere is the biggest buyer of gas in the United States, consuming over 3.1 bcfd, and is expected to increase purchases as more liquefaction trains at Sabine Pass and its Corpus Christi LNG export terminal enter service. The company’s current consumption represents almost 4 percent of total projected U.S. gas production of 81.3 bcfd in 2018.
“With Cheniere behind the CME futures contract...the odds would favor the CME contract especially if Cheniere immediately starts to sell its LNG on a Sabine Pass contract basis,” said Dominick Chirichella, director risk management, trading and advisory services at EMI DTN in New York.
The LNG market is in transition with a shift from long-term towards shorter-term contracts. Current users of LNG derivatives include big commodity trading houses like Trafigura, Vitol and Gunvor.
“I would surmise that in say five years there will be robust derivatives markets in LNG,” said Craig Pirrong, a finance professor specializing in commodities at the University of Houston.
Chinese buyers have reduced their imports of US propane since March in anticipation of increased tariffs and are diverting some term volumes to other buyers in Northeast Asia, US and Chinese market sources said.
The reduction has been particularly evident since April/May and intensified in June/July, they said recently.
"There is quite a small volume of US cargoes imported into China during that period," one Chinese trader said. "Most of the cargoes are diverted to South Korea and Japan," he said, adding that companies such as Oriental Energy -- a big buyer of US propane via term contract to supply two PDH plants -- as well as Wanhua Chemical -- another PDH plant operator -- had been showing their offers via brokerage Ginga physical trading window last week and via direct deals.
China was the third-largest importer of US propane in 2017, behind Japan and Mexico, according to the US Energy Information Administration.
While China has suspended publication of LPG import and export data since April, the latest EIA data showed US propane exports to China dipped to 2.078 million barrels in April, compared to 3.11 million barrels the previous month and 3.173 million barrels a year earlier.
S&P Global Platts Analytics expects May and June LPG exports to China -- which could include butane -- to total about 625,000-650,000 barrels, based on data from cFlow, S&P Global Platts' tradeflow software.
According to shipping data from JLC, a China domestic information provider, one US VLGC arrived in China in March, one and a half US VLGCs in April, three in May, two in June and none so far in July. In comparison, China imported an average of around 280,000 mt/month of US propane in 2017, nearly seven VLGCs every month.
A VLGC is capable of transporting about 44,000 mt of propane.
US-CHINA TRADE WAR
Propane was among the list of US products that could face a 25% tariff in response to US taxes on Chinese goods, but was not part of the tariffs that went into effect July 6. Propane currently carries an import tariff of 1%.
"We need to see if the US escalates next," a US shipbroker said.
Market sources have had mixed reactions to the possibility of increased tariffs on propane.
"I don't really think it will be a problem," a US trader said. "Ships will just get swapped around. US to Japan, Mid East to China."
Others predict global propane prices could get a boost.
"Our take on it here is that it will cause a reshuffling of where US cargoes end up, but won't impact overall US export volumes," Platts Analytics' analyst Carolyn Bergner said. "We think countries like South Korea, Japan, and Indonesia will increase their purchase of US barrels, while lowering Middle Eastern imports, and China will take up more Middle East LPG."
Interest in US propane that may be resold by Chinese term contract holders is also being seen from Taiwan, which uses LPG as an alternate petrochemical feedstock, as well as for households, trade sources said.
However, VLGC freight rates from the US Gulf Coast to Asia, which had jumped almost 48% since mid-April and would make US cargoes costlier, is a concern, they added.
OPEN ARBITRAGE
Despite market uncertainty regarding the potential for added tariffs, the US propane arbitrage window to Asia has been open since mid-June, Platts calculations show.
With FOB USGC propane cargoes, reflecting cargoes loading in H1 August, at $543.14/mt on Tuesday, a Houston-Chiba VLGC freight rate of $65/mt and CFR Japan propane cargoes for H1 September at $617.50/mt, the arbitrage looked to be open by about $9.40/mt. It was as wide as $18.12/mt on June 20, Platts data showed.
Increased propane production in the US has calmed fears of insufficient winter supply, in contrast to the summer of 2017, when US traders worried if inventories would last through the winter, resulting in stronger US prices and abundant cargo cancellations.
The natural gas industry is on a mission to prove it can keep up with the green energy industry, whose price reductions are starting to become a competitive threat to fossil fuels.
Gas and oil producers have slashed overheads by a third since 2014 and are finding deeper reductions harder to come by, according to energy consultants Wood Mackenzie. That’s spurring them to rewrite supply contracts, build mobile liquefied natural gas terminals and take more prosaic steps like fixing leaky pipes.
“This is about getting affordable energy out,” said Jens Okland, executive vice president of marketing, midstream and processing at Equinor ASA, Norway’s biggest energy company. “A lot of these LNG projects are huge. You need to make them cheaper, quite simply.”
Keeping gas affordable is a crucial ingredient of the world’s effort to shift toward less-polluting forms of energy, since it’s gas-fired power generators that can start and stop quickly, helping smooth fluctuations in supply coming from wind and solar farms. Its costs have to fall as cheaper wind turbines and solar panels make utilities scale back their most-expensive traditional power plants.
And gas has plenty of competition even before the rise of renewables. For example, to compete with coal in Asia, gas imports need to land there at about $4 to $6 per million British thermal units. That’s about half the cost of reported contracts, according to the International Gas Union trade lobby. In Germany, solar and onshore wind power are already comparable to gas based on the value of electricity the assets generate over their lifetime, Bloomberg New Energy Finance data show.
Expectations about costs are already influencing energy policy as governments decide how to balance supply needs against what voters are willing to pay for. Britain’s climate change adviser said last month the nation may need a fivefold increase in gas-fired plants by 2050 to guarantee power capacity -- a forecast that suggests a need for more investment at a time politicians are pressing for utilities to cut their bills to consumers.
Gas executives are confident they will keep a major share of the power generation business. So far, no batteries or other storage technology will give the “grid-stabilizing capability” that gas does, De la Rey Venter, Shell’s executive vice president for integrated gas ventures, said in an interview in Washington. “For the foreseeable future you can bank on gas.”
And companies are bringing down some expenses already by focusing on better-value projects, according to Sanford C. Bernstein analysts. An example is Woodside Petroleum Ltd.’s Scarborough gas field development in Australia. It will probably be more than 60 percent cheaper than Chevron Corp.’s giant Gorgon development, based on a measure of how much spending is needed for each unit of output, detailed in the chart below.
LNG projects get cheaper
Elsewhere, Exxon Mobil Corp. is seeking to reduce expenses as it expands its LNG projects in places as far-flung as Mozambique and Papua New Guinea.
“It’s really a function of using technology, using available supply sources out there and find a way to bring those to the market at the lowest-cost supply,” Darren Woods, chairman and chief executive officer, said in an interview in May.
Here’s more of the ways the gas industry is cutting costs:
1. Smaller LNG Terminals
Modular “plug and play” gas liquefaction plants and floating import terminals are smaller, expandable LNG facilities that cater to buyers that need less volume. They’re also cheaper to build, so don’t need decades-long contracts to fund them.
A converted LNG tanker deployed as a liquefaction facility in Cameroon cost just $1.2 billion. By contrast, Chevron’s Gorgon plant in Australia cost more than $50 billion.
2. New Contracts
Gas buyers are demanding shorter, flexible LNG contracts as supplier competition grows and market liquidity for the super-chilled fuel improves. That’s making the traditional oil-linked agreements increasingly irrelevant as LNG benchmark prices emerge. Just cutting contract clauses that specify a fixed destination can reduce shipping costs by reducing time and freeing up vessels.
3. Cool Running
Producing LNG in colder countries can also reduce costs because less energy is needed to liquefy the gas.
Novatek PJSC reckons its Yamal plant in Siberia can provide LNG around the world at less than half the prices that China, Japan and South Korea currently pay from other sources because of its temperature advantage over warmer climes such as Qatar, the biggest exporter of the fuel.
4. Reducing Leaks
The gas industry still underestimates how much of the fuel leaks away when it’s extracted and transported, according to a survey by the Energy Institute. Producers can reduce that leakage by 75 percent simply by improving practices in the supply chain, with about half of that cut at no net cost.
Opening new acreage to drillers on the British continental shelf sets the stage for a revival for the offshore sector, a government official said Tuesday.
The British Oil & Gas Authority said it was opening up more than 140,000 square miles of offshore territory from the west of Scotland to parts of the English Channel for potential drillers. Andy Samuel, the chief executive of the OGA, said in a statement that "following hot on the heels" of the previous round, the foundation was set "for the ongoing revival in exploration activity across all areas of the U.K. continental shelf."
Under the terms of the licensing rounds, companies have the chance to propose other parts of mature areas where supplementary work could occur. Claire Perry, the British energy minister, said the government has supported surveys, meanwhile, to get a better understanding of the reserve potential in frontier areas.
"That's why we provided $53 million in the 2015 and 2016 budgets for seismic surveys in under-explored frontier areas of the U.K. continental shelf, resulting in new data and new opportunities in this latest round of licensing," she said in a statement.
Trade group Oil & Gas U.K. said the inclusion of seismic data and the focus on frontier opportunities could lead to the start of a new era in British waters.
"Frontier exploration is however a long game and requires businesses to be confident future opportunities," exploration and production policy director Mike Tholen said in an emailed statement. "Fiscal and regulatory stability remains a prerequisite if we are to realize the benefits of exploration activity which is badly needed to boost production and activity."
The British continental shelf holds an estimated 1.5 billion barrels of oil equivalent in potentially commercial, but as yet undeveloped, reserves. The government said the last licensing round could help unlock 320 million barrels of those oil and gas reserves.
Interested parties have until Nov. 7 to apply for the acreage on the auction block. Award announcements are expected by the first half of 2019.
Executives at Canada’s largest integrated oil and gas producers on Tuesday downplayed the severity of transportation bottlenecks to move oil in the near term, citing existing pipeline commitments and refining capabilities.
Canadian producers have faced steep discounts for western Canadian heavy crude this year due to bottlenecks, while new pipeline projects have dealt with delays and protests from environmental groups.
Still, executives at Husky Energy Inc and Suncor Energy Inc said their existing pipeline commitments would help overcome constraints in the short-term.
“Right now, 100 percent of our production, including all of the production from Fort Hills (Alberta), we have pipeline access to get to markets,” said Mark Little, chief operating officer for Suncor.
Husky has excess oil pipeline capacity to the U.S. and has enough capacity locked in to ship crude until about 2021, Chief Executive Rob Peabody said, speaking on the sidelines of the TD Securities Calgary Energy Conference.
The company, which aims to grow production by about 5 percent annually over the next five years, has about 75,000 barrels per day (bpd) committed on the existing Keystone pipeline and also has space on Enbridge Inc’s Mainline crude pipeline system, Peabody said.
Most executives also expressed optimism over the completion of three main projects that are seen as crucial for Canadian producers to transport oil to the U.S. and Canada’s western port: Line 3 replacement, Trans Mountain, and Keystone XL.
A Minnesota regulator late last month approved a certificate of need for Enbridge Inc to rebuild its Line 3 oil pipeline, angering environmentalists.
“We’re definitely seeing progress. The innate logic of replacing a pipeline that needs to be replaced is finally being seen by courts,” Peabody said, referring to Line 3.
The Keystone XL pipeline project has been a lightning rod of controversy for a decade, hotly contested by environmentalists even though Canadian oil producers say it is desperately needed.
On the Trans Mountain pipeline, Peabody was optimistic the line will be built.
“Every time I see the prime minister, he assures me it’s going to be built, so I believe that it will happen,” he said.
To be sure, some companies are more cautious, maximizing the use of every barrel.
Imperial Oil Ltd is boosting its refineries’ capabilities to handle more heavy oil, Chief Executive Richard Kruger said.
“The whole objective is to minimize the amount of barrels that are exposed to Alberta and the price discounts,” Kruger said.
Cenovus Energy Inc is awaiting more clarity on market access before it restarts construction on two deferred projects that will have a combined starting capacity of 75,000 bpd, said Cenovus Executive Vice President Al Reid.
Longer term, the companies stressed the need for more infrastructure to plan and invest in projects.
Inpex announced on 11 July that it expects to ship its first LNG cargo from its Ichthys project in Australia by the end of September after safety issues were resolved, maintaining earlier schedule.
Australian regulators had found some safety problems on the Ichthys offshore gas platform and were considering enforcement action.
Ichthys to start production after further “verifications” with safety regulators.
Inpex said it will start shipping condensate before LNG.
The United States Department of Energy has granted a long-term permit to Blue Water Fuels to export liquefied natural gas (LNG) from NuBlu Energy’s facility in Port Allen, Louisiana.
Initially, Blue Water Fuels requested a permit to export LNG in ISO containers or in bulk to any country which the United States has or will have a free trade agreement (FTA).
According to the DOE’s notice, Blue Water Fuels sought permission to export LNG in volumes equivalent to approximately 2.715 billion cubic feet (Bcf) per year, or 0.007 Bcf per day of natural gas, over a 25 year period.
LNG will be purchased from an existing LNG liquefaction facility owned and operated by Blue Water’s parent company, NuBlu Energy.
Blue Water states that the NuBlu Energy facility has an initial storage capacity of approximately 120,000 gallons of LNG and the capacity to produce 30,000
gallons of LNG per day, and, based on need, the ability to expand to produce 90,000 gallons per day.
Additionally, the NuBlu Energy Facility includes a load-out bay with equipment to fill ISO containers loaded on truck trailers.
As the facility is in operation already, there is no need for additional plant infrastructure to be built to accommodate the exports.
LNG will be loaded into ISO containers at the facility and transported on tanker trucks to the port of export where it will be loaded onto ocean-going vessels for transport to destination countries.
https://www.lngworldnews.com/usa-blue-water-gets-fta-lng-export-permit-from-doe/
U.S. crude oil refinery inputs averaged 17.7 million barrels per day during the week ending July 6, 2018, which was 1,000 barrels per day less than the previous week’s average. Refineries operated at 96.7% of their operable capacity last week. Gasoline production increased last week, averaging 10.7 million barrels per day. Distillate fuel production decreased last week, averaging 5.4 million barrels per day.
U.S. crude oil imports averaged 7.4 million barrels per day last week, down by 1,624,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 8.3 million barrels per day, 5.9% more than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 853,000 barrels per day, and distillate fuel imports averaged 104,000 barrels per day.
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 12.6 million barrels from the previous week. At 405.2 million barrels, U.S. crude oil inventories are about 4% below the five year average for this time of year. Total motor gasoline inventories decreased by 0.7 million barrels last week and are about 6% above the five year average for this time of year. Finished gasoline inventories increased while blending components inventories decreased last week. Distillate fuel inventories increased by 4.1 million barrels last week and are about 12% below the five year average for this time of year. Propane/propylene inventories increased by 2.4 million barrels last week and are about 10% below the five year average for this time of year.
Total commercial petroleum inventories decreased by 7.2 million barrels last week. Total products supplied over the last four-week period averaged 20.4 million barrels per day, down by 1.4% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.6 million barrels per day, down by 1.7% from the same period last year. Distillate fuel product supplied averaged 3.8 million barrels per day over the past four weeks, down by 6.1% from the same period last year. Jet fuel product supplied was up 0.1% compared with the same four-week period last year.
Last Week Week Before Last Year
Domestic Production '000...... 10,900 10,900 9,397
Alaska ........................................ 431 402 457
Lower 48 ............................... 10,500 10,500 8,940
Imports .................................... 7,431 9,055 7,610
Exports .................................... 2,027 2,336 918
Cushing...down 2.1 mln bbls
A refinery in Saudi Arabia has shipped its RBOB gasoline to the United States for the first time, a potential precursor for more deliveries to a region where prices are currently at seasonal three-year highs.
The 400,000 barrels-per-day Jubail Satorp refinery, a joint venture between Saudi Aramco and French company Total, said in its verified Twitter account that it sent the shipment of reformulated blendstock gasoline - commonly called RBOB - to the United States. It did not say whether those barrels had arrived yet, and its exact destination was unclear.
The shipment is unusual because when Satorp was founded in 2008, it was not expected to send RBOB to the United States, as Saudi gasoline demand remained strong, said Robert Campbell, head of oil products research at Energy Aspects in New York.
Satorp was not immediately available for comment.
Motor gasoline inventories in the United States fell to about 239 million barrels in the week to July 6, according to U.S. Energy Department data. Stockpiles were up from the same time last year, when inventories totaled 235.7 million barrels.
Market participants expect the additional supply could slow U.S. inventory drawdowns.
Cash prices for the product in New York Harbor were at 2.00 cents per gallon above the futures benchmark on the New York Mercantile Exchange on Tuesday, the highest seasonally since 2015. The RBOB futures contract on NYMEX settled at $2.1603 a gallon on Tuesday.
Energy trading companies often route vessels based on favorable spreads for crude oil and products, and right now moving gasoline to the United States is more profitable. But this shipment also could mean demand in Saudi Arabia is weakening, Campbell said.
The shipment suggests that the Americas has become one of the best destinations for surplus gasoline, he added. “It’s tough because that means Asia really is quite significantly oversupplied,” Campbell said.
Demand in Saudi Arabia has waned as the government has undertaken reforms that have reduced fuel consumption across several sectors, Campbell said.
Brazilian state-controlled oil company Petróleo Brasileiro SA is close to agreeing the sale of its stake in an African venture for around $1.3 billion, newspaper Valor Econômico said on Tuesday.
Petrobras, as the company is known, owns 50 percent of Petrobras Oil & Gas BV, or Petrobras Africa. Grupo BTG Pactual SA holds a 40 percent stake in the venture and Helios Investment Partners owns the remaining 10 percent.
All three shareholders would sell their stakes, valuing the venture at around $2.6 billion, Valor said, citing an unnamed source.
Reuters reported on June 18 that a consortium led by Vitol SA had entered exclusive talks to acquire stakes in Petrobras Africa, emerging as a winner from a number of bidders including rival commodity trader Glencore Plc.
Representatives for Petrobras and Glencore did not immediately respond to requests for comment. A Vitol representative declined to comment.
Petrobras Africa participates in two deepwater oil exploration blocks off the coast of Nigeria that contain the Akpo and Agbami producing fields and are operated by Total SA and Chevron Corp respectively.
Heavily indebted Petrobras unveiled plans to sell that stake in November as part of a divestment program aiming to offload $21 billion in assets by year-end.
A wave of stricter port restrictions in south China has left steel producers searching for alternative ports to allow them to berth vessels carrying their imported metallurgical coal cargoes.
A south China steel producer, which typically berths its vessels at Fangcheng port, has been prevented from doing so. An east China steel producer has been trying to get clearance to berth a cargo of Australian premium mid-volatile metallurgical coal at Wenzhou port in Zhejiang province but has now been denied entry. Both steel producers are scrambling to find an alternative.
Another south China steel producer might be barred from taking any more imported coal in the following months as port import quotas have nearly been reached, sources said.
"For Chinese steelmakers, especially those in the south, it is no longer a matter of prices but of which ports will actually allow them to berth," a China coal sales manager said. "At the moment, Jingtang port in Hebei province is stocked full with cargoes, as it is one of the few ports that actually allow vessels to berth and unload with minimal disruptions."
Trading firms have been particularly disadvantaged by these new restrictions. At Rizhao port in Shandong province, Chinese customs have allowed trading firms to unload cargoes only if they can provide proof that the cargo will eventually be sold to a buyer.
"They are essentially preventing traders from stockpiling cargoes at the port," a Zhejiang-based trader said. "At the same time there have been limits placed on trader sales. Traders can only offload and offer cargoes in the port that they are based in, instead of offering from various other ports, which limits the number of sales options that they have."
At least two to three cargoes of distressed premium mid-volatile hard metallurgical coal are currently held by Chinese trading firms, being offered in the spot market at huge discounts in a $184-185/t CFR China range as they struggle to find a home.
In contrast, the current Argus assessment for premium hard low volatile metallurgical coal loading in the normal 15 - 60 day window is $199.60/t CFR north China.
These port restrictions are not new but have been escalated. Since last year steel producers and trading firms were already reporting a spate of measures imposed by Chinese customs in an attempt to reduce coal imports into China.
This includes restricting the clearance of coal cargoes with high sulfur or ash content on grounds of environmental protection and extending the time required for cargoes to obtain clearance from customs officials, among other limitations.
Ports have also imposed annual volume quotas for coal imports. Once these quotas are exceeded buyers will not be allowed to import metallurgical coal for the remainder of the year.
These measures are aimed at indirectly discouraging Chinese buyers from importing coal from overseas. "An outright ban will be a bad idea because it opens the government up to criticism," a Chinese trader said. "So, these indirect methods are best."
The restrictions have added to the woes of Chinese metallurgical coal buyers, which have already been hit by higher import costs as a result of a depreciating Chinese yuan after continuing trade tensions between US and China hit sentiment in foreign exchange markets.
Typhoon Maria is also forecast to batter east China for most of the day up until 12 July. But some ports in the region, including Shanghai and Zhoushan, have remained open and are largely unaffected.
Real-time off-peak power prices in West Texas have spiked in recent months, propelled by the increased congestion caused by recent recovery of oil and gas drilling activities in the area, while the congestion was eased during on-peak hours, when growing solar generation in the region started to kick in.
According to data from Electric Reliability Council of Texas, West Load Zone real-time off-peak price averaged in the low $70s/MWh in June, hitting as high as $124/MWh June 19 and the highest level since late 2014, when S&P Global Platts started tracking it.
The same price has averaged in the high teens so far this year through late May, mostly pressured by high wind generation seen from February through April, when negative prices and windy conditions were not uncommon in West Texas at that time of the year.
But lately, significant growth in customer demand, driven by more robust hydrocarbon extraction activities in Permian Basin, has led to increased congestions seen in West Texas, Warren Lasher, senior director of system planning for ERCOT, said in an interview with Platts on Tuesday.
The grid operator said load in Far West Texas topped 3,400 MW on May 10 for the first time in history and regional power demand has increased by nearly 250 MW as the end of June, compared to the year-ago level, attributed to booming oil and gas activity in the region.
ERCOT also pointed out the load growth was concentrated in Culberson, Reeves, Loving, Winkler and Ward counties, an area served by transmission lines that form a loop known as the Culberson Loop.
Data from Baker Hughes showed oil rig counts in Reeves county and Ward county have both increased by 17 at the end of April from the same time last year, the largest increase among counties within the Permian Basin, while Culberson County increased by 11, Winkler county by 9 and Loving county by 2 over the same time.
Additionally, peak demand in West Texas grew at a rate of 8% from 2012 through 2017 and systemwide demand increased by 1% annually over the same time, while the same numbers were expected to be 8% and 2%, respectively, from 2018 through 2023.
STRONG SOLAR GENERATION, FLIPPED SPREAD
West Load Zone on-peak prices, usually at premium to off-peak prices, on the other hand, flipped to a discount starting in June, as increased solar output in the area during on-peak hours helped ease the high congestion seen in off-peak hours.
West Load Zone real-time on-peak prices averaged in the low $50s/MWh so far this month through Monday, about $30 below where its off-peak counterpart has averaged over the same time.
Meanwhile, the same spread was less than $7/MWh in June and has been mostly in the negative zone since late 2014.
Solar generation has been on the rise lately, with solar output taking up about 1% of total generation in the fuel mix from April through June, compared to 0.7% from the same time a year ago and 0.2% in 2016.
The rise was mostly attributed to rapid addition of solar generating capacity into the system over the last decade, starting from only 15 MW in 2010 to nearly 1,500 MW at the end of June, and that number was expected to increase by 18% to over 1,700 MW by the end of the year.
All of the four solar farms expected to be in service by the end of 2018 were located in the Permian Basin, with 182-MW Waymark Solar and 7-MW Barilla Solar in Pecos County, 30-MW BlueBell Solar in Coke County and 50-MW Lamesa Solar in Dawson County.
Lasher from ERCOT said it is a coincidence that the best solar resources in the state and oil&gas plays were at such proximity that a large amount of solar developments helped relieve the congestion.
TRANSMISSION PROJECTS UNDERWAY TO EASE CONGESTION
Several transmission projects are underway or under study to address congestion resulting from the significant load growth, especially in the area served by the Culberson Loop.
The grid operator has endorsed four new 345-kV line in the area since last summer, with the Odessa-Riverton and Bakersfield-Solstice lines endorsed last June expected to be in service by May 2020 and March 2022, and the Riverton-Sand Lake-Solstice lines endorsed this June still under study.
Additionally, ERCOT has endorsed three new 138-kV line since late 2016, with Riverton-Sand Lake line endorsed November 2016 expected to be completed in May 2019, while Kyle Ranch-Riverton and Horseshoe Spring-Riverton lines endorsed in June were still under study.
Back in October 2016, ERCOT also endorsed Line 69H rebuild and 138-kV conversion project, Permian Basin-Solstice 138-kV line rebuild project, and both projects were still under construction, with the first one's scheduled completion date delayed from June to October and the latter one scheduled to be in service in February 2019.
The leader of the Norwegian Safe union, which represents hundreds of striking oil workers, said on Thursday the union had not been touch with the Shipowners’ Association, which represents employers.
“We haven’t been contacted by the shipowners yet. They have to make the contact, they know our demands. Could be a strategic move from them to reach out before we shut more rigs on Sunday,” Safe leader Hilde-Marit Rysst told Reuters on Thursday.
The union plans to send an additional 901 workers on strike from midnight on Sunday, unless the dispute is resolved.
Iraqi police fired into the air to disperse protesters demanding jobs and better public services at one of three demonstrations outside major oilfields in the southern oil hub of Basra on Thursday, police sources said.
Two protesters were wounded, police and hospital sources said, without elaborating after the incident near an entrance to the giant West Qurna 2 oilfield, run by Lukoil.
Local workers said around 10 protesters managed to briefly enter a crude separation facility before police pushed them back. An angry crowd set fire to a caravan used by police, said two policemen at the scene.
The unrest did not impact production at West Qurna 2 or the other two fields, West Qurna 1 and Rumaila, two oil officials said.
Oil exports from Basra account for more than 95 percent of OPEC producer Iraq’s state revenues. Any potential disruptions to production could severely impact the economy.
The demonstrations escalated after police opened fire last week to disperse dozens of protesters near the giant southern West Qurna-2 oilfield, killing one person and wounding three.
Tensions over basic services come at a sensitive time when Iraqi political blocs are attempting to form a coalition government after a May 12 parliamentary election tainted by allegations of fraud.
Easing hardship will not be easy. Iraq needs tens of billions of dollars to rebuild after its war with Islamic State.
“We want jobs, we want to drink clean water, and electricity. We want to be treated like human beings and not animals,” said Husam Abdul Ameer, 25, an unemployed college graduate from Basra.
Prime Minister Haider al-Abadi has ordered a ministerial committee to look into the protesters’ demands.
About 70 people gathered near a joint entrance leading to the key oilfields of Rumaila, operated by BP, and West Qurna 1, run by Exxon Mobil, said police officers in charge of protecting the oilfields perimeters.
Some called on foreign companies to create jobs.
“Why should young men from Basra beg for jobs while oil companies are hiring foreign workers,” protest organizer Falih al-Darraji told Reuters.
“That’s unfair and should stop, otherwise we will not only demonstrate near the oilfield but will break in.”
Some local officials said the complaints were justified.
“Protesters have fair demands and they are peaceful so far. If the government does not respond quickly, we fear things will get out of control in Basra,” said Faris Shaddad, the head of energy panel of Basra provincial council.
Other protesters gathered at a main road to the east of Basra leading to a border crossing with Iran, preventing trucks from moving, custom officials said.
ConcoPhillips said Thursday it is increasing its 2018 share buyback program to $3 billion from $2 billion. At the same time, the company's board has approved an additional $9 billion to its overall buyback authorization, increasing it to $15 billion.
The energy giant said it has paid down $2.1 billion of debt in the second quarter, and has achieved its $15 billion target "significantly" earlier than its original target date of year-end 2019.
Galveston Bay LNG, a unit of the US LNG export project developer NextDecade, has been granted a 20-year permit by the Department of Energy to export liquefied natural gas.
The company filed an application on December 22, 2017, seeking permit to export LNG in a volume equivalent to 785.7 billion cubic feet per year of natural gas from its proposed facility in Texas City to free trade agreement (FTA) and non-FTA countries, although the DoE noted it will review the non-FTA portion of the application separately.
Galveston Bay LNG states that the project will include natural gas treatment, compression, liquefaction and storage facilities, as well as ancillary facilities required to receive and liquefy natural gas, and to store, load, and export LNG.
The company further states that its parent company, NextDecade, has entered into a three-year lease for the site known as Shoal Point, with the northern and
western perimeters of the site located adjacent to the Texas City ship channel, from two landholders, the Texas General Land Office and the City of Texas City, Texas.
The project will consist of both land-based and marine components, the DoE notice says. It will include four LNG storage tanks, each with a storage capacity of approximately 200,000 cubic meters, three LNG trains, and truck and marine vessel loading facilities.
Each of the LNG trains will be capable of producing up to approximately 5.5 million tons per annum (mtpa) of LNG, for a total capacity of 16.5 mtpa of LNG.
According to Galveston Bay LNG, the project will be capable of processing an average of approximately 785.7 Bcf/yr of pipeline quality natural gas, which is the volume requested to be cleared for export.
To date, the project, that will be supplied by an approximately 85-mile long pipeline, to be developed by a Galveston Bay LNG affiliate, and run to the Katy Gas Market Hub, has not entered into contracts for the proposed exports.
However, it stated that it will file all the long-term and binding deals once they are executed.
https://www.lngworldnews.com/nextdecades-galveston-bay-lng-project-gets-export-permit/
China’s crude oil imports fell for a second month in a row in June to the lowest since December, as shrinking margins and volatile oil prices led some independent refiners, known as “teapots”, to scale back purchases.
June shipments came in at 34.35 million tonnes, or 8.36 million barrels per day (bpd), according to data from the General Administration of Customs.
That was down 9 percent from 9.2 million bpd in May and also down from 8.8 million bpd in June last year. Thomson Reuters Oil Research had pegged China’s crude oil arrivals in June at 35.13 million tonnes.
Imports for the first half of this year were still up 5.8 percent from a year earlier at 225 million tonnes, or about 9.07 million bpd, the official data showed.
While some state-run and independent plants were shut for regular maintenance, others took advantage of weakening margins and oil prices at near four-year-highs to conduct extended shutdowns.
“The numbers are lower than we expected, mostly because of slowing down at some teapot plants as they face growing domestic competition in refined fuel supplies and weakening margins,” said Seng Yick Tee of consultancy SIA Energy.
“The oil price volatility is certainly not helping as not many independent plants are doing sophisticated hedging.”
Shandong Shengxing Chemical Group shut its crude oil unit at the end of April and only expects to resume operations around mid-August.
Shandong Haiyou Petrochemical, a Rizhao-based teapot with annual import quotas of 3.2 million tonnes, has kept its crude unit shut since late May without a definite date to reopen.
Imports of oil products fell 26.5 percent to 2.22 million tonnes, while oil product exports fell 22.0 percent to 4.78 million tonnes, data showed.
However, total gas imports in June - including pipeline gas and liquefied natural gas - rose to 7.3 million tonnes, up 31 percent from a year ago, customs said.
Year-to-date imports hit 42.08 million tonnes, 35.4 percent higher than the same period in 2017.
Gas maintained high growth as demand remained strong for storage fills as well as for industrial uses.
Local governments are rolling out hikes in benchmark city-gate gas prices for residential use, following a policy change by Beijing in May to unify residential prices with industrial users. In a boost for gas producers, the change effectively removes long-running subsidies for the residential sector.
The U.S. Department of the Interior said on Thursday it would hold a record-sized auction for oil and gas leases in the Gulf of Mexico next month, in an attempt to spark interest in offshore drilling months after a similar sale received a weak response from energy companies.
The sale, to be held on Aug. 15, includes all available unleased areas in federal waters of the Gulf of Mexico in about 78 million acres (31.5 million hectares) off Texas, Louisiana, Mississippi, Alabama and Florida. It is the third sale in the agency’s 2017-2022 program, which aims to hold 10 sales in all.
The sale is part of what the Interior Department calls President Donald Trump’s America-First Offshore Energy Strategy. Vincent DeVito, an adviser to Interior Secretary Ryan Zinke, said the sale “is just one piece of the administration’s comprehensive effort to secure our nation’s energy future.”
The last Gulf of Mexico lease sale, held in March, brought in only $124.8 million, as just 1 percent of the then-record 77 million acres (31.2 million hectares) offered found bidders. In addition, nearly all the purchases showed big drillers stuck closest to existing operations.
In April, Zinke, who had earlier proposed opening up nearly all the country’s coasts to drilling, said the sale in March held “modest to little” interest from drillers and added there was little likelihood for strong demand elsewhere in the country. His plan to open up the Pacific and Atlantic coasts was criticized by environmentalists, politicians and tourism and fishing interests.
The U.S. government estimates the Outer Continental Shelf in the Gulf of Mexico contains about 48 billion barrels of undiscovered technically recoverable oil and 141 trillion cubic feet of undiscovered technically recoverable gas.
Most of the recent U.S. oil boom has occurred onshore, where it is cheaper to drill than in deepwater. In addition, many drillers are exploring in other places, such as Mexico, where energy reforms have brought in billions of dollars in investments.
Aker BP will increase its exploration spending plan this year due to new prospects off Norway, the oil firm said on Friday, as its second-quarter earnings jumped but missed forecasts.
The company, the result of a merger between Norwegian oil firm Det norske and the Norwegian operations of BP raised its spending target for exploring the new prospects to $425 million from $350 million.
"(This is) due to increased activity following the Frosk discovery and recent licence awards," the company said in a statement, referring to a find it made off Norway and to new licences it was awarded by Norwegian authorities.
The company will curb spending this year on decommissioning old oil wells at the Valhall oilfield in the North Sea, cutting the target to $250 million from $350 million citing "accelerated execution" of the work.
Operating profit rose to $552 million from $210 million a year earlier but missed the $573 million expected by analysts in a Reuters poll.
The company will pay a dividend of 31.24 U.S. cents in August, as expected, and maintained its dividend payment outlook.
The Thackaringa cobalt project, in South Australia, is expected to require a capital investment of A$550-million to develop a 5.25-million-tonne-a-year plant.
ASX-listed Cobalt Blue on Wednesday revealed that the project would produce some 3 657 t/y metal in sulphate, and life-of-mine totals of 32 453 t, over a nine year mine life.
The mine life was based on a mineral reserve of 46.3-million tonnes, grading 819 parts per million (ppm) cobalt.
A prefeasibility study (PFS) estimated a pre-tax net present value of A$792-million and an internal rate of return of 27%, based on a production target of 40 331 t of metal in sulphate over a mine life of 12.8 years.
The production target was modelled on a reserve of 58.7-million tonnes, grading at 802 ppm, and included the probable ore reserve and a partial component of the inferred resource.
“The PFS demonstrates the potential for Cobalt Blue to become a leading global supplier of cobalt sulphate to the lithium-ion battery industry. The project will now move into a bankable feasibility study,” said Cobalt Blue chairperson Rob Biancardi.
Cobalt Blue is currently earning an interest into the Thakaringa project, which is held by Broken Hill Prospecting. The company could take full ownership of Thakaringa through a four-staged farm-in.
With the completion of the PFS, Cobalt Blue has fulfilled the requirement of Stage 2 of the earn-in agreement.
Biancardi said that the company will now focus on further resource work to target a 20-year mine life, while a number of optimisation opportunities will also be pursued for the bankable feasibility study, including optimisations to the process plant, metal recoveries and power pricing.
Cobalt Blue will also undertake product marketing assessment, in order to negotiate offtake agreements, and will complete environmental permit studies.
http://www.miningweekly.com/article/thakaringa-gets-a-a550m-price-tag-2018-07-04
China's largest hydropower station the Three Gorges generated 38.9 TWh of electricity in the first half this year, up 0.28% or 110 GWh compared with the same period last year, industry media reported.
The Three Gorges cascaded hydropower station is composed of the Three Gorges and Gezhouba power station. Gezhouba, a runoff type power station, produced 8.5 TWh of power in the first half, about 10 GWh more than a year ago.
The accumulative water inflow to the Three Gorges in January-June totaled 148 billion cubic meters, down 1.4% from a year ago but 13.3% more than designed. During its water release session, the Three Gorges' reservoir outflow totaled 22.67 billion cu m, with the minimum daily outflow rate on average at 649 cu m per second.
The Three Gorges is the world's largest power station in terms of installed capacity (a total capacity of 22.5 GW with 34 generators). The hydropower station is run by China Yangtze Power, a listed subsidiary of China Three Gorges Corporation (CTGC).
Apart the Three Gorges and Gezhouba, CTGC operates and develops more massive hydroelectric projects on Yangtze River – Xiangjiaba Dam, Xiluodu Dam (the third world largest hydroelectric power plant), Baihetan Dam and Wudongde Dam.
China is considering a further reduction in electric-vehicle subsidies next year, Bloomberg reported on Friday, citing unnamed sources.
Beijing is scaling back subsidies to push automakers to focus more on technological improvements instead of relying on fiscal policy, the report said.
A U.S. judge on Friday ordered Chinese wind turbine maker Sinovel Wind Group Co Ltd to pay a $1.5 million fine after the company was convicted of charges it stole trade secrets from Massachusetts-based AMSC.
U.S. District Judge James Peterson in Madison, Wisconsin, also sentenced Sinovel to one year of probation, during which it must pay the unpaid balance of a $57.5 million settlement it struck with AMSC that was disclosed on Tuesday.
The U.S. Justice Department said Sinovel has already paid AMSC, formerly known as American Superconductor Corp, $32.5 million and will have to pay $850,000 to additional victims during the probation period.
The sentence came after a federal jury in January found Beijing-based Sinovel guilty on conspiracy, trade-secret theft and wire fraud charges. A lawyer for Sinovel did not respond to a request for comment.
The Justice Department announced charges against Sinovel in 2013 amid heightened concern about Chinese theft of U.S. trade secrets and a legal battle in the Chinese courts pitting Ayer, Massachusetts-based AMSC against Sinovel.
The case centered on technology that AMSC developed to regulate the flow of electricity from wind turbines to electrical grids that Sinovel purchased for its products.
Prosecutors said that Sinovel had contracted with AMSC for more than $800 million in products and services to be used in wind turbines it manufactured.
According to prosecutors, Sinovel conspired beginning in 2011 to obtain AMSC’s copyrighted information and trade secrets so that it could make wind turbines and retrofit existing ones without having to pay AMSC.
Sinovel recruited Dejan Karabasevic, an employee of an AMSC unit, to join the Chinese company and to secretly copy information from AMSC’s computer system, including the source code for the PM3000, part of its wind turbine control system, according to an indictment.
Sinovel then commissioned several wind turbines in Massachusetts and incorporated into them software that the Chinese company compiled from the stolen PM3000 source code, prosecutors said.
The Justice Department said AMSC subsequently lost more than $1 billion in shareholder equity and almost 700 jobs.
Karabasevic, who lives in Serbia, was convicted in a related case in Austria in 2011.
U.S. charges remain pending against him and two individuals who live in China and worked for Sinovel at the time, Su Liying, the deputy director of its research and development department, and Zhao Haichun, a technology manager.
The lithium mining industry is ripe for disruption.
MGX Minerals Inc, a mining junior based in Vancouver BC, is doing just that. And it’s already deploying its technology.
MGX, founded in 2012, and its Calgary-based water treatment subsidiary PurLucid, can cut extraction time of lithium from brine to a single day.
A number of Chilean lithium juniors and brine producers are testing the technology to speed up time to market and at the same time slash their environmental footprint (and to stop praying for it not to rain).
But cutting construction and production time for traditional lithium from brine producers is not even MGX's biggest selling point.
MGX produces lithium by cleaning up the oil industry’s wastewater.
The company has integrated PurLucid’s nanoflotation technology with its own rapid lithium recovery process. MGX bought 51% of PurLucid in September 2016 with an option to buy the firm outright.
North America's oil & gas sector pumps an astonishing 80–100m barrels of brine each day
While competitors have emerged, MGX is now in deployment phase with North American oil and gas companies as first customers. The company this week closed on a $15.5m private placement and revenues from its roll-out will flow before the end of the year.
CEO Jared Lazerson tells MINING.com that the company started out as an industrial minerals minor, but early on saw the opportunity in advanced materials:
“We liked the lack of volatility in industrial minerals but quickly segued into battery materials were the outlook is for strong growth for at least the next fifty years.”
MGX is advancing its Driftwood Creek Magnesium project in BC, hoping to become only the second producer of magnesium oxide in North America. A preliminary economic assessment for the project outlines a 19-year mine life, a three-and-a-half year payback and $400m net present value.
The North American wastewater treatment industry is worth $29 billion a year and the oil & gas sector pumps an astonishing 80–100m barrels of brine each day.
Recognizing the massive expertise built up in the Alberta oil patch to manage wastewater, MGX started to develop the idea of what it dubs “petrolithium”.
Lazerson says petrolithium enables “a beautiful transition” using robust industrial process to clean up the environment and reduce costs at the same time.
For Alberta, struggling to bring bitumen to new markets outside the US, petrolithium represents energy diversification.
For the Canadian province’s oil giants it provides not only environmental credentials but an on-ramp to the electric vehicle boom (not to mention a new revenue stream from water purification).
Lithium is on the list of 35 minerals deemed as "critical" by the US dept of the interior to promote domestic production
MGX have permits covering 1.7m acres in Alberta where it’s partnering with oil and gas majors and in the US, MGX has acquired leases over 110,000 acres in Utah’s Paradox basin. The company announced a seismic survey program in Utah this week. The MGX process can also be applied to wastewater from other industrial sources where lithium, an abundant resource, may be present.
Lithium is on the list of 35 minerals deemed as "critical" and of strategic importance by the US dept of the interior in an effort to promote domestic production.
Lazerson says the company was careful not to fall into a capex and growth trap, designing its technology to be modular:
“We can put the equipment in a container and ship it off and if you want more, we ship you another. There is a point where you would decide to build a $1 billion centralized plant, but as a company we did not want to be in a position where we spend all this money developing a technology and then have to go to shareholders and the market to raise money for a massive capital expenditure program.”
MGX , listed in October 2014 and is worth C$112m on the Canadian Securities Exchange. The spot price of battery grade lithium carbonate in China has declined this year and was assesses at $21,000 per tonne at the end of May according to MetalBulletin data. That compares to $7,700 a tonne in June 2015.
http://www.mining.com/vancouver-junior-shaking-lithium-mining-industry/
Beijing Electric Vehicle Co. (BJEV) is offering battery swaps for private customers in an attempt to gain a competitive edge in the world's largest new energy vehicle (NEV) market.
BJEV launched a pure electric vehicle with a mileage range of 300 km Thursday, at a price of 79,800 yuan (12,000 U.S. dollars)Customers can change a depleted battery for a full one by paying monthly rent of 458 yuan for the battery and additional money for the electricity.
Zheng Gang, president of BJEV, said the service can allay customers' range anxiety and reduce their costs. Many customers do not have charging poles and there are not enough public charging poles.
The carmaker plans to build 3,000 battery swap stations in 50 cities by 2022. It already has 116 stations in four cities serving 6,000 taxis.
Compared with direct current fast-charging poles, the slow-charging from swap stations could prolong the battery's life, according to BJEV.
China has remained the world's largest NEV market for three years, with some 777,000 cars sold in 2017, over half of the global market.
China on Tuesday issued a three-year plan on cleaner air, calling for NEV sales of 2 million units in 2020.
Shandong Lubei Enterprise Group General Company recently completed the construction of new lithum carbonate capacity of 20,000 mt, and plans to commission it in October, reported Asian Metal.
Mass production at the Bizhou plant in Shandong province is expected to begin by the end of this year. Production will use imported lithium concentrate from Australia for raw materials.
The company is also planning additional capacity of some 10,000 mt on top of the new capacity.
Lithium exports from Chile, the country’s with the largest known reserves of the white metal in the world, jumped in 2017 becoming its fourth largest mining export behind copper, molybdenum and iron ore.
Lithium exports hit $684.2 million last year, up 47% from $465 million in 2016.
Shipments of the key ingredient for making batteries that power electric vehicles (EVs) and high tech devices, hit $684.2 million last year, up 47% from the $465 million they represented in 2016, according to figures publishedby the Chilean Copper Commission (Cochilco).
Copper remained Chile’s main mining export, representing 89% of the total or $33.9 billion. Molybdenum came in second place at $1.2 billion, while iron ore took came number three at just over $ 1billion.
Both Chilean authorities and analysts believe lithium has the potential to become the nation’s second largest mining export. Earlier this year, the South American country’s development agency Corfo struck a deal with local producer SQM, allowing the private company to expand its production capacity of lithium from 48,000 tonnes to 70,000 tonnes this year, and then to 100,000 tonnes by 2019.
Geological Fortune
All of the Chile's reserves are found in brines, underneath vast salt flats located in the north. Brines only require enough space for evaporation to occur, which is taken care of by the sun and the expansive solid surface that is a salt flat.
In contrast, reserves in Australia, the world’s top lithium producer according to the United States Geological Survey (USGS), are found in hard-rock sources, which make them more expensive to process than brines.
By 2035, Chile could have an industry of about $10 billion, made up of a combination of carbonate and lithium hydroxide output as well as value-added products, such as cathodes, according to the the Chilean Copper Commission (Cochilco).
Aware of its geological good fortune, Chile has announced plans to build out a downstream processing and battery industry.
“By 2035, Chile could have an industry of about $10 billion, made up of a combination of carbonate and lithium hydroxide output as well as value-added products, such as cathodes,” Sergio Hernández, Cochilco’s executive vice president, told MINING.com last month.
Investors, however, are growing increasingly concerned about a wave of new lithium projects sprouting up from Australia to Nevada to take advantage of rising prices. Lithium carbonate, a key ion battery raw material, have climbed almost 40% in the past 12 months on the back of increasing electric car production, according to Benchmark Minerals Intelligence.
Shares in the world’s largest producers of lithium, in turn, have gone the opposite way this year, following double-digit gains in 2017.
http://www.mining.com/lithium-becomes-chiles-no-4-mining-export/
Bloom Energy seeks to raise up to $252 million in shares
Bloom Energy Corp. is the latest Silicon Valley “unicorn” hoping to join the likes of Dropbox Inc. DBX, -1.57% in roiling equity markets this year.
Bloom Energy BE, has set the terms of its initial public offering, seeking to sell 18 million shares between $13 and $15 a piece to raise up to $252 million, according to a filing on Monday. Underwriters include J.P. Morgan, Morgan Stanley, and Credit Suisse.
Bloom had filed the initial paperwork last month with a placeholder amount of $100 million.
Bloom is a rare clean-energy “unicorn,” Valley-speak for a privately held startup valued at more than $1 billion. Its backers include Sand Hill Road powerhouses Kleiner Perkins Caufield & Byers and New Enterprise Associates. The company long has been on lists of Silicon Valley companies poised for going public, but it backtracked from a confidential IPO filing in 2016.
The Sunnyvale, Calif., company hopes to trade on the New York Stock Exchange under the ticker symbol BE.
Here are five things to know about Bloom Energy ahead of its IPO.
What Bloom Energy makes and its client list
Bloom makes solid oxide fuel cells that are used in stationary power-generation servers. The servers convert natural gas or biogas into electricity through an electrochemical reaction, which results in lower emissions, Bloom Energy says.
The company claims that each on-site server, with a footprint of half the size of a shipping container, can provide around 250 kilowatts of power to its customers, or enough to power 160 average U.S. homes. That is more space-efficient than other forms of alternative energy, and unlike intermittent solar and wind power, the servers provide a constant source of electricity, Bloom says.
Clusters of servers can provide tens of megawatts for large-scale clients, and the company focuses on commercial and industrial customers. Some of its largest clients include AT&T Inc. T, +1.09% utility Delmarva Power, a subsidiary of Echelon Corp. ELON, -0.24% Equinix Inc. EQIX, +0.76% and Home Depot Inc.HD, +0.78% among others.
Utility holding company Southern Co. SO, +2.09% is a financing partner, buying the servers that are sent to customers’ facilities in order to provide electricity as a service. Southern and Delmarva Power were Bloom’s largest customers last year. In the filing, Bloom Energy disclosed that business is concentrated with few customers, saying that in 2017 its top 20 customers accounted for about 91% of its revenue “and two customers accounted for approximately 53% of our total revenue.”
Federal tax credits are essential
Bloom Energy had a good reason to thaw its IPO plans after years of hand-wringing. Crucial federal tax credits for alternative energy systems were allowed to expire in December 2016, but President Donald Trump’s budget deal in February restored those credits, known as investment tax credits, or ITC, and made them retroactive to January 2017. The Wall Street Journal reported in March that Bloom had gone back to the IPO path.
The tax credits plus state tax credits and other incentives offset the price of each Bloom server and are a key component of Bloom Energy’s business model. When the tax credits disappeared, Bloom reduced its prices to make up the difference, which damaged its revenue.
For instance, Bloom Energy delivered on 166 orders in the first quarter, an increase of 39.5% compared with 119 in the year-ago period, but first-quarter product revenue increased 338%, from $27.7 million to $121.3 million.
The big difference between the rise in product revenue and the rise in deliveries, or acceptances, in company parlance, was thanks in part to one-time product revenue benefit from the retroactive ITC renewal as well as price increases linked to the tax credits’ return.
Financial picture
For the three months ended in March, Bloom listed total revenue of $169 million, compared with $72 million in the year-ago period. First-quarter net losses attributable to shareholders reached $18 million, or $1.14 a share, compared with losses of $60 million, or $3.91 a share, in the first quarter of 2017.
Bloom is an “emerging growth” company, meaning it faces fewer reporting requirements because its revenues are less than $1 billion a year.
The company listed revenue of $376 million in all of 2017, compared with $209 million in the prior year.
GAAP losses for the ‘foreseeable future’ as debt piles up
Since its founding in 2001, Bloom has “incurred significant net losses and have used significant cash” in its business, accumulating a deficit of $2.3 billion as of March, it said in the filing.
“We anticipate that we will incur net losses on a GAAP basis for the foreseeable future,” it said.
In addition, those servers do not come cheap, and to help potential customers afford them Bloom offers leasing programs and power purchase agreements, or PPAs, in which the cost of the server is funded by an investment entity financed by Bloom Energy and third-party investors.
“Our ability to attract third-party financing depends on many factors that are outside of our control, including the investors’ ability to utilize tax credits and other government incentives, our perceived creditworthiness and the condition of credit markets generally,” the filing said. “If we are unable to help our customers arrange financing for our Energy Servers, our business will be harmed.”
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As its business suffered last year with the ITC lapse, Bloom Energy had to lower the price of its servers. The incentive could be repealed in the future, creating havoc on company’s budget.
Bloom Energy also lists as risks the possibility that it overestimates the useful life of its servers, the servers’ overall on-site performance, and natural-gas prices.
And then there’s debt.
As of March, Bloom Energy and its subsidiaries had about $951 million in debt, according to the filing. About a quarter of that is convertible debt that will become shares in the company just ahead of its offering, but Bloom admitted in its filing that conditions on some of its debt, particularly its 10% notes, make it hard to raise more debt.
In addition, Bloom conducts operations and gets equity allocations from its PPA entities, which also contribute to its cash flow. But since these are separate entities, they are of no avail to Bloom when it comes to make good on debt.
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Bloom appears to be in serious need of the cash infusion an IPO would provide. The company reported cash and cash equivalents of about $88 million at the end of the most recent quarter, in which it burned about $37 million of its cash.
Major ownership and share structure
Bloom is offering to sell class A common stock in the IPO, which entitles holders to one vote a share. Each share of Bloom’s Class B stock has 10 votes a share and is convertible into one share of class A common stock.
K.R. Sridhar, with a background in aerospace, is the founder and chief executive of Bloom Energy, and he owns about 3.6% of the company in Class B shares ahead of the IPO. Kleiner Perkins owns about 16% of the company in Class B shares, while New Enterprise owns about 11%, according to the filing. Other large shareholders include the Kuwait Investment Authority, with roughly 11%, and pension manager Alberta Investment Management Corp., with 7.5%.
The U.S. Environmental Protection Agency ditched a detailed plan that would have forced refiners to blend more biofuels into their gasoline and diesel in 2019 to compensate for volumes likely to be exempted under the agency’s small refinery hardship waiver program, according to newly released EPA documents.
A fuel nozzle from a bio diesel fuel pump is seen in this photo illustration taken at a filling station in San Diego, California January 8, 2015. REUTERS/Mike Blake
The plan would have boosted the renewable fuel blending obligation for the refining industry to 11.76 percent from 10.88 percent to offset volumes lost under the waiver program, which has been expanded sharply under President Donald Trump’s EPA, and keep overall blended volumes on target.
The idea was aimed at assuaging the powerful U.S. corn lobby which has accused Trump’s EPA of undermining demand for biofuels like corn-based ethanol through the waiver program, but was scrapped amid intense protest from the refining industry.
“What this shows is the EPA acknowledges it has the authority and the ability to reallocate the volumes lost under the small refinery exemption program,” Geoff Cooper, an executive at the Renewable Fuels Association, said on Wednesday.
The EPA said the documents reflect the agency’s process for administering the Renewable Fuel Standard (RFS), which is done in conjunction with the departments of Energy and Agriculture as well as the White House.
The move would have likely rallied compliance credit prices that have plunged to multi-year lows amid reports of the agency’s expansion of the waiver program.
CONTENTIOUS PROGRAM
Under the RFS, the EPA must set annual requirements for the volume of renewable fuels that oil refiners and other fuel companies must blend with their petroleum-based products. The 2005 policy has been a source of contention between powerful corn and oil lobbies in Washington.
The agency also has the power to exempt smaller refineries from the blending requirements if they can prove that complying with the regulation would cause them financial stress.
The EPA, under recently-resigned director Scott Pruitt, has roughly tripled the number of exemptions granted to small refiners, angering Midwest farmers and their legislative backers who say he effectively lowered the annual biofuels mandate.
Exemptions representing some 2.25 million gallons worth of biofuel were granted for 2017 and 2016, according to the EPA. That includes waivers covering 1.46 million compliance credits, called RINs, in 2017, the EPA said.
Under the scrapped plan, the EPA would have estimated the number of gallons of gasoline and diesel that would likely be exempted in 2019 under the small refinery waiver program and force the larger refineries to make up the difference.
The EPA projected some 8.18 billion gallons of gasoline and 5.44 billion gallons of diesel produced by small refiners would be exempt from the requirements in 2019, the documents showed.
The documents were published by the EPA as part of requirements aimed at providing the public more insight into federal decision making. Reuters and other news outlets reported on the EPA’s 2019 volumes proposal, but the documents provide new details about the agency’s approach.
The proposed changes came in a June 19th email from Tia Sutton of the EPA to the White House Office of Management and Budget. Pruitt, who resigned amid ethics scandals last week, had just returned from a Midwest tour where he met with farmers angry over his expansion of the exemption program.
A day later, some legal justification was added to the proposed rule, stating “this approach is consistent with the text of our regulations, which accounts for the amount of gasoline and amount of diesel projected to be produced by exempt small refineries in 2019.”
Refiners learned of the changes and made a full-court press to the agency and White House to reverse it.
Refinery-state senators Ted Cruz of Texas and Pat Toomey of Pennsylvania, both Republicans, had calls with Pruitt a day after reports of the changes circulated, according to Pruitt’s public schedule.
On June 22, the EPA struck the changes in a new email to the OMB office, the documents showed.
The final proposed rule was published on June 26.
The growing use of electric vehicles could increase peak electricity demand in Britain by between 5 and 8 gigawatts (GW) by 2030, National Grid said on Thursday.
Last year, the government said it would ban the sale of new petrol and diesel cars and vans from 2040 to help reduce air pollution and help Britain to cut carbon emissions by 80 percent by 2050 from 1990 levels - the target it has set itself.
Although some conventional cars will remain on the road, numbers of electric vehicles (including cars, motorbikes, vans and buses) could swell to 11 million by 2030 and 36 million by 2040, according to National Grid’s annual Future Energy Scenarios report.
As a result, electricity demand will increase, driven initially by the charging of electric vehicles and later as the pace picks up to decarbonize the heating sector.
Under scenarios which envisage Britain meeting its 2050 carbon reduction target, additional peak electricity demand could be between 5 and 8.1 gigawatts (GW) by 2030. This represents a 9 to 14 percent rise from 2017 peak electricity demand in Britain of 57 GW.
This also takes into account both residential and non-residential charging and depends on the use of smart-charging technologies, charging vehicles at off-peak times, the National Grid added.
After 2030, vehicle-to-grid technology, which will help electric vehicles power households, should help reduce additional peak power demand further.
“Through smart charging and vehicle-to-grid technologies, this year’s analysis reveals electric vehicles will be able to support the continued growth in renewables by storing excess generation and releasing it back onto the network when it is needed,” the report said.
Panasonic Corp (6752.T) plans to halve the cobalt content of its mass-produced automotive batteries “in two to three years”, an executive at the Japanese conglomerate said on Thursday, as battery makers look to reduce costs.
“At the research and development level, we’ve already achieved such batteries,” Yoshio Ito, the chief of Panasonic’s automotive business, said at a media roundtable.
“But we need to go through various evaluation processes” before mass-producing them, he said.
Panasonic, the exclusive battery cell supplier for Tesla Inc’s (TSLA.O) current production models, previously said it was aiming to develop cobalt-free batteries, but did not give a specific time frame.
Panasonic has already significantly reduced cobalt content, to about 10 percent in its nickel-cobalt-aluminium cathode chemistry.
Battery makers have been scrambling to reduce cobalt content in lithium-ion batteries as prices of the rarer mineral have multiplied in recent years, and the spread of electric vehicles (EVs) is widely expected to result in cobalt shortages.
This week, the chief executive of U.S. partner Tesla, Elon Musk, sealed a deal with Chinese authorities to build an auto plant in Shanghai, its first factory outside the United States, that would double the size of the EV maker’s global manufacturing.
Asked about joining Tesla in producing automotive batteries in China, Ito said the Japanese company “has not received any official request” from the EV maker, but that it “would consider the possibility if requested”.
Renewable energy sources satisfied more of Germany's power demands than coal during the first half of 2018, marking a shift towards clean power as the Bundesrepublik continues to debate how best to phase out coal.
According to data released on July 10 by the German Association of Energy and Water Industries (BDEW), wind, solar, hydropower and biogas met 36.3% of Germany's electricity needs between January and June 2018, while coal provided just 35.1%.
Although renewables have hit notable benchmarks in the past, outstripping fossil fuels on certain days or even weeks, this is the first time coal has fallen by the wayside during such a long period of time in Germany.
In comparison to the same period in 2017, renewables only met 32.5% in the first six months of last year, with coal generating 38.5%. Experts say this was partly due to favourable weather conditions and lower consumption.
That reduction in coal use was predominantly based on a drop-off in carbon-heavy hard coal or anthracite, while use of lignite or brown coal, which contains the least concentration of carbon, remained relatively stable between 2017 and 2018.
Scratch beneath the surface and Germany still has a big problem emissions are not falling, despite progress in building up renewable energy capacity.
Efforts to green the transport sector remain in their infancy and Berlin's decision to start phasing out emission-free atomic power, following 2011's Fukushima nuclear disaster, continues to be felt in the power generation game.
Coal power plants also remain online and recent research by British climate NGO Sandbag showed that seven of Germany's lignite power stations are among the top ten CO2 polluters in Europe.
The German government has long pledged to come up with a plan to ditch coal power and finally launched a special commission dedicated to the task in June.
Future planning
EU negotiators recently wrapped up talks on three crucial clean energy files, including updates to the renewables and energy efficiency directives. During the talks, Germany's revamped government emerged as an obstacle to more progressive member states.
New energy minister Peter Altmaier refused to consider anything above a 32% renewable energy target for 2030, cutting down any hopes that national capitals could be convinced to back the European Parliament's proposed 35% mark.
Altmaier ultimately got his way and negotiators signed off on a deal that set 32% as the target and MEPs on the Parliament's energy committee rubber-stamped the agreement on July 10.
At the same time in Brussels, the European Commission formally launched its consultation on a 2050 climate strategy, which the EU executive hopes to present by the end of the year at the COP24 summit in Katowice, Poland.
Trade conflict between the United States and China could further boost already booming grain and oilseed exports from the Black Sea region, traders and analysts said.
New opportunities to sell wheat, corn and soybeans to China and even the European Union are set to open up for the region’s main exporters Russia, Ukraine and Kazakhstan, whose recent ascendancy has already ended full U.S. dominance in markets such as Nigeria and Mexico.
The United States and China slapped tit-for-tat duties on $34 billion of each other’s imports on Friday, with Beijing accusing Washington of triggering the “largest-scale trade war”.
The Black Sea region’s share of the international wheat market climbed to about 37 percent in 2017/18, according to the International Grains Council, comfortably topping the United States and Canada combined.
China is the world’s top wheat producer but still imports about 4 million tonnes of the grain each year.
In the 2017/18 season (June/May) the United States exported 902,400 tonnes of wheat to China, down from 1.56 million in the prior season, according to U.S. government data.
SPONSORED
For Kazakh wheat, the pick-up in Chinese imports started due to Beijing’s Belt Road policy and before the trade dispute took off, but the tariff row accentuates the trend.
“We have just started buying wheat from Kazakhstan this year. Our first order was for several thousand tonnes,” a Chinese wheat trader said. “We will see about sales and profits. If they’re good, we will increase imports for sure. It is related to the current trade war.”
“Now that you can’t bring in American wheat, it gives us more incentive to buy from Kazakhstan. And once your trading of Kazakh wheat reaches a certain volume, you get government preferential support,” the trader added.
Among the risks for this strategy are difficult logistics and unstable quality seen in Kazakh and Russian wheat, said another trader who has been looking for more Kazakh wheat deals.
Black Sea wheat may not be able fully to replace its U.S. counterpart due to different quality grades, meaning some traders will also turn to Canadian wheat, he added.
According to statistical data, Russia and Ukraine, whose traditional buyers had been in North Africa and the Middle East, boosted wheat supplies to Vietnam, Indonesia, the Philippines, Spain, Tunisia, Tanzania, Sudan, Oman, Mexico and Kenya in the 2017/18 season.
One location in which Russia has taken away from U.S. wheat market share is Nigeria, which like Brazil traditionally favors a higher-protein grain such as U.S. hard red winter.
PRICES LOUDER THAN WORDS
In a sign that may worry some U.S. wheat traders further, Brazil bought Russian wheat in July for the first time in eight years.
“In this new era of trade wars, prices talk louder than words,” said Swithun Still, director of Solaris, which specializes in trading Russian agricultural commodities.
“It’s likely that China will aim to buy more grains and oilseeds from the Black Sea and more beans from South America. Mexico has been buying lots of Russian wheat and will continue as prices are attractive compared to U.S. wheat,” he added.
The trade spat could also boost exports of Black Sea corn and soybeans.
Russian authorities recently reported a record 850,000 tonnes of soybean exports to China in July 2017-May 2018, more than double the 340,000 tonnes a year earlier, Svetlana Malysh, Kiev-based Black Sea agriculture market analyst at Thomson Reuters, said.
“Black Sea countries, mainly Russia, may intensify their soybean shipments to China in case of any U.S. deliveries’ disruption,” she added.
The trade conflict is also a chance for Ukraine to boost supplies of its corn to the European Union, which imposed a 25 percent import duty on U.S. corn in June, Malysh said.
China can also turn to Ukraine and Russia for corn in case it reduces purchases from the United States, according to Matt Ammermann, commodity risk manager with INTL FCStone.
A federal U.S. judge on Tuesday allowed hundreds of lawsuits alleging that Monsanto Co’s glyphosate-containing weed-killer Roundup causes cancer to proceed to trial, finding that there was sufficient evidence for a jury to hear the cases.
The decision by U.S. District Judge Vince Chhabria in San Francisco, California, followed years of litigation and weeks of hearings about the controversial science surrounding the safety of the chemical glyphosate,the key ingredient in Monsanto’s top-selling weed-killer. Monsanto is a unit of Bayer AG .
India’s environmental court did not allow Vedanta Ltd to reopen its copper smelter in the southern Indian state of Tamil Nadu, a lawyer representing the state said on Thursday after a hearing on the matter.
India’s National Green Tribunal did not accept Vedanta’s request to reopen the smelter on an interim basis, V. Mowli, a lawyer for the Tamil Nadu Pollution Control Board (TNPCB) said outside the court.
Vedanta has also sought a permanent injunction against the Tamil Nadu state government from interfering with the operations of its copper smelter.
The lawyer representing Vedanta in the hearing, Rohini Musa, did not respond to repeated calls requesting comment. A company spokesman for Vedanta confirmed there was a case before the Tribunal but did not comment specifically on Thursday’s decision.
The Tamil Nadu government ordered the permanent closure of the plant and disconnected its power supply in May following protests that turned violent and culminated in the police opening fire on protesters, killing 13 of them.
The protesters had demanded a permanent shutdown of the plant, which they said was causing air and water pollution, and as a risk to fisheries. Vedanta says the protests were based on false notions.
Vedanta Ltd, a subsidiary of billionaire Anil Agarwal-controlled Vedanta Resources, argued that the closure of the smelter was only based on “political considerations and to appease the public protests,” according to a copy of the petition reviewed by Reuters.
However, the Tamil Nadu government will stick to its stance that the plant is polluting, said Rakesh Sharma, a second lawyer representing the TNPCB.
“We’ll argue on their violation on environmental aspects,” he said. The case will be heard next on July 18 for the state to reply to the issues raised in Vedanta’s petition.
Vedanta said in its petition that inspections by the TNPCB whose findings were used to shut down the plant never happened.
“No such inspection (was) carried out by the officials of the TNPCB” on May 18 or 19, the company said.
Vedanta, which exports copper worth over $1.3 billion annually, is also one of India’s largest producers of sulphuric acid and phosphoric acid, both of which are used to make fertilizers.
The shutdown of the smelter, which employs more than 3,500 people, has lead to a rise in the price of copper in India by over 10 percent, and the price of sulphuric acid by more than 6 times, the company said.
This is a roundup of China’s base metals output in June. SMM surveyed major producers in the market to obtain first-hand information for calculation.
Copper
China's output of refined copper in June dipped 3.3% on the month but rose 10.5% on the year and came in at 722,500 mt, SMM survey showed. Output during the first half of the year stood at 4.33 million mt, up 12.9% from last year.
Maintenance, equipment failure, and technical upgrades on environmental grounds accounted for the month-on-month decline, which was in line with SMM's expectations. The decline occurred even as Jinchang smelter in Anhui province commissioned new capacity.
Qinghai Copper, which began trial production at its 100,000-mt-capacity project on May 29, has not begun to produce copper cathode. Another copper smelting project with an annual capacity of 400,000 mt at Chinalco Southeast Copper in Ningde of Fujian province started trial production on June 30. This is the largest copper smelting project in China in the last five years.
SMM estimates copper output to dip further in July to around 712,800 mt, as production cuts are scheduled at Jinchuan, Fuye Group, Minmetals Copper, and Zhangjiagang United Copper. Year on year, output will grow 12.6%. Output in the first seven months of 2018 is expected to come in at 5.04 million mt, up 12.8% on the year.
Aluminium
China produced 3.02 million mt of primary aluminium in June, down 2.3% from a year ago. For the first half of 2018, output stood at 17.81 million mt, down 2.7% year on year.
Annualised operating capacity grew 580,000 mt from May to 36.76 million mt in June as production in Henan province resumed and as new capacity in Guangxi, Inner Mongolia and Gansu provinces was commissioned.
We expect output in July to grow 0.2% year on year and stand at 3.13 million mt as domestic aluminium producers cut production on supply-side reform last year and as operating capacity increase in 2018. Capacity swaps are likely to continue to bolster operating capacity, even as some capacity in Xinjiang and Shaanxi provinces would be cut later this year.
SMM lowered our expectations of 2018 output, to 37 million mt. This will be up 1.9% from 2017, slower than the 14.2% growth last year, as new capacity is commissioned and production recovers slowly.
Alumina
China's alumina output in June rose 5.4% year on year and registered at 5.97 million mt, SMM data showed. Average daily output rose 1.8% from May and stood at 199,000 mt in June as production resumed at Sanmenxia Kaiman and Fusheng Aluminium, and as output increased at Guangxi Huayin and Chinalco Henan. Output also grew as maintenance at Pingdingshan Huiyuan ended and as Shanxi Huaqing commissioned new capacity.
Production for the first half of 2018 gained nearly 2% from 2017 and came in at 35.63 million mt. SMM estimates that alumina output in July will stand at 6.01 million mt with average daily output lower at 194,000 mt. Producers in north China, such as Chinalco Shanxi, Henan Wanji, and Shandong Xinfa, plan to cut production or undertake maintenance in July as prices of alumina fall towards the cost lines. This is likely to account for the daily output decline.
Nickel
With fewer working days in June than May, nickel production in China dipped 2.5% month-on-month in June to 11,900 mt. Year on year, production shrank 5.3%, showed SMM data.
Output in the first half of the year declined 8% from the same period last year and stood at 71,300 mt.
With more working days in July than June, nickel production in July is likely to stand at 12,300 mt. Operating rates are likely to remain flat from June.
Nickel pig iron (NPI)
China’s NPI output in June fell 12.8% from May to 32,500 mt in nickel content amid a sharp decline in high-grade resources due to environmental probes across Jiangsu, Inner Mongolia, Shandong and Guangdong provinces, etc. The production was 3% higher from the same period last year, however.
In June, high-grade NPI output went down 14.3% from a month ago to 28,000 mt in nickel content and low-grade NPI output dipped 1% to 4,300 mt in nickel content.
In the first half of the year, overall NPI production came in at 219,800 mt in nickel content, up 16.5% year on year.
We expect output in July to increase 7.8% to 35,100 mt in nickel content as some plants would resume their production after the month-long probes come to an end.
Nickel sulphate
China produced 28,900 mt of nickel sulphate, in physical volumes, last month. This translates to 6,357 mt in metal content, down 26% from May. China’s output during the first half of the year registered at 206,800 mt, up 43% from the same period last year.
Last month, plants in Guangdong and Guangxi provinces underwent rectification as environmental probe focused on illegal dumping of solid waste, and producers in Jiangsu and Jiangxi provinces cut production on local environmental policies. These accounted for the month-on-month decrease in output. In addition, demand weakened from downstream ternary precursor industry due to financial pressure, resulting in a pile-up of inventory.
Production is expected to rebound in July as environmental restrictions ease.
Zinc
China produced 429,800 mt of refined zinc in June, up 1.6% month on month but down 7.1% year on year. The output during January-June came in at 2.69 million mt, up 3.7% from the same period last year.
We expect the output to decrease 21,600 mt, or by 5%, to 408,100 mt in July. This would be 10.3% lower than July 2017. However, the January-July production would see a 1.6% year-on-year increase.
Primary lead
China produced 236,700 mt of primary lead in June, down 5.5% month on month and 9.6% year on year. In the first six months of this year, the output came in at 1.43 million mt, down 8.7% from a year ago.
In June, inspection teams from the central government settled in Henan, Hunan, and Yunnan provinces to review the rectification works for previous environmental issues across those regions. A 30-50% production cut was also seen in Jiyuan city in Henan, a major lead producing province in China, due to polluted weather.
Technical upgrades at Anhui Tongguan, maintenance at Jiangxi Jinde and Yunnan Mengzi also accounted for the month-on-month decline in output. Smelters that suspended production in May, however, recovered their production last month.
Tin
China produced 12,215 mt of refined tin in June, down 16.5% from May as production in major production areas such as Yunnan, Guangxi, Jiangxi and Guangdong provinces was affected by the environmental reviews initiated by the central government. Some medium-sized and small producers across these regions suspended briefly between late June to early July while Guangxi-based China Tin Group stopped production from June 10 for equipment maintenance.
We expect output to further decline to 12,200 mt in July as it remains unclear when China Tin can resume production. Maintenance at China Tin, the largest producer of tin in China, was scheduled to end by July 25.
Production across other producers is likely to gradually recover after month-long environmental checks end.
Labour negotiations at BHP Billiton Plc Escondida copper mine in Chile, the world’s largest, are entering into the final three weeks before a 30-month contract expires at the end of July.
The closely watched talks come little more than one year after failure to reach a labor deal at the sprawling deposit led to a 44-day strike that jolted the global copper market.
HOW ARE TALKS GOING?
BHP and the union have reached agreement on about one-fifth of the “points of interest,” raised by either party, according to an internal union document seen by Reuters that summarized progress in negotiations during the month of June.
The union filed its demands with the company on June 1. The proposals include a one-time bonus equivalent to 4 percent of dividends distributed to shareholders in 2017, or between approximately $34,000 and $40,000 per worker, depending on the exchange rate and other factors. The union also requested a 5 percent increase in workers’ salaries.
BHP’s initial response on June 11 made no mention of either salary adjustments or the signing bonus.
A Reuters point-by-point review of sticking points suggested the two parties were yet to reach a consensus in several areas. Carlos Allendes, a union official, confirmed to Reuters that they were “far from agreement” and accused BHP of “stubbornness.”
Patricio Vilaplana, Escondida’s vice president for corporate affairs, told reporters on Thursday the company was “calm” about the negotiations and the union has shown “good faith” at the negotiating table.
WHAT ARE THE KEY POINTS OF CONTENTION?
According to a progress update seen by Reuters that included BHP´s proposals and the union response, the main bones of contention are:
* NEW HEALTHCARE PLAN: BHP wants to bid out its existing healthcare plan. The union wants coverage guarantees in writing and to take part in bidding.
* CONTRACT BENEFITS: The company wants to extend benefits and the signing bonus to non-unionized workers. The union called some of the changes “discriminatory.”
* GOOD PRACTICE BONUSES: BHP has proposed changes to “operational practice” standards that earn workers a daily bonus for good behavior.
* PRODUCTION GOAL BONUS: BHP has raised this to $7,700 but also boosted the production goal to 98 percent from 96 percent to 97 percent. The union said the higher goal brought greater risk to workers and to product quality.
WHAT´S CHANGED SINCE LAST YEAR´S NEGOTIATIONS?
Workers last year invoked a legal provision that allowed them to extend their current contract through July 2018, allowing the implementation of a new labor law passed under former center-left Chilean President Michelle Bachelet that allows workers to use existing benefits as the “floor” for current negotiations.
Last year’s impasse also brought an additional, unexpected benefit to unions: A sharp increase in the price of copper on the London Metal Exchange - more than 50 percent since hitting a nine-year low in 2016.
The price hike prompted the union to kick off negotiations with demands that included a bonus of up to $40,000.
In recent weeks however, the U.S.-China trade dispute has reversed the trend, sending the copper price to a nine-month low. Allendes said the lows were temporary and would have little bearing on negotiations.
IS THE RISK OF A STRIKE PRICED INTO COPPER?
Kash Kamal, a research associate at BMO Capital Markets, told Reuters that amid an “aggressive sell-off” of copper over the past 10 days because of the trade dispute, it remained unclear what impact a strike would have.
“Labor negotiations certainly helped support prices in the first half of the year, and the contract talks that have concluded have done so with very little disruption,” he said. “However, investors are split down the middle when it comes to Escondida and recent comments from union officials haven’t struck the most positive tone.”
IS $40,000 BONUS A LOT?
BHP has called the bonus “exaggerated,” and said it exceeded even the demands of the union in 2013, with copper prices approaching record highs.
But the generally robust copper price and strengthened labor laws suggest the union has substantial leverage in the ongoing Escondida negotiations.
Joaquin Villarino, an industry veteran and head of Consejo Minero, Chile´s mining industry group, said a big bonus could serve to eliminate more permanent benefits that made contracts more expensive and miners less competitive.
WILL THE RESULTS OF THESE TALKS AFFECT OTHER MINES?
The Escondida talks come halfway through a big year for labor negotiations at Chile´s copper mines, including 19 at top producer Codelco.
Though Codelco has thus far avoided strikes, 11 negotiations remain, including at its sprawling El Teniente deposit.
“Outside of Chile, markets aren’t taking this into account,” said Juan Carlos Guajardo, an analyst with consultancy PlusMining in Santiago, citing recent tensions at Codelco’s Salvador and Chuquicamata divisions.
“Escondida will be a benchmark. Because of its notoriety, it will influence (upcoming negotiations).”
WHAT COMES NEXT?
Conversations can continue until July 24, at which point BHP must present its final offer, according to a negotiation schedule provided by the company.
Between July 27 and July 31, the union will vote to either accept the company´s offer or go on strike. After the vote, either party has as many as four days to request a period of government mediation that can last 10 days.
If there is no agreement when the mediation process ends, a strike would begin the following business day.
Bauxite prices in Shanxi province have risen from March. Supplies remained tight as the government clamped down on illegal mining, SMM learned.
High- and low-grade bauxite across the region rose by 40 yuan/mt and renewed their record high prices this month. As of Monday July 9, resources with a aluminium/silicon ratio at 6-7 stood at 495 yuan/mt with those at 4.5-5.5 standing at 415 yuan/mt, excluding value-added tax or resource tax. The prices came in at 626 yuan/mt and 525 yuan/mt, including tax, respectively.
From March 1, the Shanxi government began its clampdown on illegal mining to protect ore resources. This is expected to last until October.
Inspectors from the central government will settle in Shanxi this month for about a month, and will target open pit mining. This is set to further weigh on bauxite supply across the region and prices are likely to extend their gains.
Bauxite prices gained 20 yuan/mt in Henan province in July, just 35 yuan/mt shy of the record high of 490 yuan/mt.
Bauxite supply in Henan is also expected to tighten as regulations on bauxite mines across the region would intensify this month. The stricter regulations come after rectification works at those mines came under fire during probes by the central government in June. Captive mines at some alumina refineries in Henan have been shut, SMM learned.
Some alumina refineries in the two provinces were heard to have purchased bauxite from Guizhou province.
https://news.metal.com/newscontent/all_all_100816951/bauxite-prices-in-shanxi-hit-record-high/
The Philippines’ nickel ore exports could drop by up to 17 percent this year as weaker prices curb output in the world’s second-biggest supplier, the head of a nickel mining industry group said on Tuesday.
Shipments of nickel ore, used to make stainless steel, could fall to 30-35 million tonnes from 36 million tonnes in 2017, Dante Bravo, president of the Philippine Nickel Industry Association, told a media forum.
“As a whole, we expect exports this year to be less than what we saw last year because the price of low-grade nickel now is weak,” he said.
The Philippines is the world’s No.2 nickel ore supplier after Indonesia, shipping the bulk of its output to top buyer China.
The price of nickel on the London Metal Exchange fell to an eight-week low of $13,830 a tonne on Friday and has lost nearly 5 percent this month, caught in a broad-based selloff of risky assets amid deepening trade tensions between the United States and China.
Philippine President Rodrigo Duterte last week warned he would soon halt mining in the Southeast Asian nation because of the environmental damage it has caused.
There are 50 operating mines in the Philippines, 30 of which extract nickel ore. But the industry contributes less than 1 percent to gross domestic product, with only 3 percent of 9 million hectares identified by the state as having high mineral reserves.
“The challenge is to be able to address the communication gap,” said Bravo, on Duterte’s threat.
“We are perceived to be damaging (the environment), rather than contributing to the economy. We need to be more understood.”
In April, Duterte told miners to reforest areas where they operate, saying he would revoke their permits if he didn’t see trees as tall as he is in six months.
Bravo said miners had intensified their reforestation efforts, planting about 4.2 million trees in mining areas in the southern Mindanao region and in the southwestern province of Palawan.
Century Aluminium hit its goal of at least partially restarting the first of three long-idled potlines at its 252,000 mt/year smelter in Hawesville, Kentucky, by the end of June, according to a company official.
The potline is energized and an unspecified number of aluminium-making pots again are producing metal, although the entire line is not yet back in production, the official, who asked not to be identified, told S&P Global Platts in an interview.
The Chicago-based company's plan still is to gradually restart more pots on the 50,000 mt/year line before restarting two additional potlines by early 2019.
Once on line, the three potlines are expected to add about 150,000 mt/year of annual output to the plant's two roughly 50,000 mt/year potlines that have continued to run since the three potlines were curtailed in late 2015 during a period of low aluminium prices.
Century president and CEO Michael Bless has credited the Trump administration's imposition of a 10% tariff on imported aluminium from several countries, notably China, for the company's decision to restart the three potlines.
Yingkou Xintai Aluminium has secured green light to commission 322,500 mt of new primary aluminium capacity in Liaoning province in north China.
This is through a capacity swap between the company and Henan Yugang Longquan Aluminium, according to Liaoning Provincial Industry and Informatization Commission earlier this month.
Yingkou Xintai kicked off the construction of 460,000 mt of aluminium capacity in June 2012 and planned to commission the latest allowance this month.
The plant is located in Yingkou Coastal Industries Base and the old capacity in Henan province has been demolished.
Serbia’s RTB Bor copper miner and smelter has drawn interest from 11 companies and the tender could take place this week or next, Belgrade daily Politika reported on Wednesday.
Serbia has tried and failed three times since 2007 to sell the debt-laden mining complex, which suffered a long period of neglect during the Balkan Wars and the country’s international isolation in the 1990s.
Politika quoted Energy and Mining Minister Aleksandar Antic as saying Belgrade would launch a tender to privatize the company this week or next.
Companies from China, Russia, Canada and Turkey, as well as a consortium from Kazakhstan, have expressed interest in buying RTB Bor, Politika quoted Antic as saying.
Last week, at a 16+1 summit between European and Chinese leaders in Sofia, Antic said the buyer would have to invest around $300 million in the company. He also said that Zijin Mining [601899.SS] could be among bidders.
RTB Bor’s first-half copper exports rose 23 percent to 15,000 tonnes, company data showed.
Export revenue between January and June stood at $107.1 million and it sold copper worth an additional $30.9 million domestically.
To speed up reforms and spur growth, as recommended by the International Monetary Fund, Serbia must dispose of remaining state-run companies.
Attempts to sell RTB Bor in 2007 and 2008 failed as bidders did not meet terms of those tenders.
A mineral sands operation on the South African coast run by Rio Tinto has been closed since Friday due to violent community protests which saw a security guard killed earlier this week, the company and a union said on Wednesday.
Community unrest is a common feature of South Africa’s social landscape, which is marred by high jobless rates and glaring income disparities, underscoring the social risks for investors in the country’s mining sector.
“Due to the escalation in activity around the blockades on the access roads, staff were sent home on Friday. Our highest priority is the safety of our people,” a Rio spokesman said. The operation, Richards Bay Minerals, is on South Africa’s Indian Ocean coast.
Mzi Zakwe, the regional secretary for the National Union of Mineworkers (NUM), told Reuters the union’s 900 members were on forced leave because of the violence, which he said was rooted in grievances between the company and contractors.
Unrest has hit the area before, which is also near South Africa’s main coal terminal.
Elsewhere in South Africa, the eastern limb of the platinum belt was hit by more than 400 incidents of social unrest impacting mining operations since between the start of 2016 and April this year according to data compiled by Anglo American Platinum and reviewed by Reuters.
BHP Billiton Plc handed in a proposal for a new labour contract to the union at its Escondida copper mine in Chile that includes a salary readjustment linked to inflation and a $23,000 bonus per worker, the company said on Wednesday.
The offer falls short of fulfilling some of the demands laid out by the union previously.
In its proposal in early June, the union asked for a bonus equal to 4 percent of profits in 2017, or up to almost about $40,000 per worker. It also demanded a 5 percent increase in salaries.
The company said that its offer, which hinges on the new contract being signed this month, also increases payment of a bonus for exceptional performance and benefits on education, health care and retirement.
“We hope our workers value the effort the company is making to deliver this offer, which is sustainable,” said Patricio Vilaplana, vice president of corporate affairs at Escondida.
The union declined to provide immediate comment on what it thought of the proposal.
Labor talks at Escondida are in the final stretch before a 30-month contract expires at the end of July.
The closely watched talks come little more than one year after failure to reach a labor deal at the sprawling deposit led to a 44-day strike that jolted the global copper market.
Canada’s Barrick Gold Corp lowered its full-year copper production forecast on Wednesday while increasing its cost estimates, saying the change reflected operational challenges and planned work at its Lumwana mine in Zambia.
Barrick, which looks likely to lose its rank as the world’s biggest gold producer this year, maintained its 2018 output estimate of between 4.5 million and 5 million ounces of gold at all-in sustaining costs of $765 to $815 an ounce.
Rival Newmont Mining Corp has said it expects to produce between 4.9 and 5.4 million ounces of gold in 2018.
Toronto-based Barrick lowered its 2018 copper production forecast to between 345 million and 410 million pounds, from an April estimate of 385 million to 450 million pounds. Mill shutdowns and lower grades hurt Lumwana’s performance in the first quarter.
All-in sustaining production costs, an industry benchmark, are forecast between $2.55 and $2.85 per pound of copper for 2018, above its previous estimate of $2.30 to $2.60 per pound.
Barrick, which plans to report full financial results on July 25, said it produced 83 million pounds of copper in the second quarter, according to preliminary production data, a slight drop from the first quarter.
The company said it expects higher Lumwana production in the second half of the year, reflecting improved grades and crusher reliability.
Second-quarter gold production of 1.07 million ounces mirrored first-quarter output, but all-in sustaining costs were about 5 to 7 percent higher, due to planned maintenance at its Nevada roaster and stripping at its Pueblo Viejo mine in the Dominican Republic, Barrick said.
Gold production is expected to be higher in the second half of 2018 and at lower costs in comparison to the first six months, as maintenance work is completed and higher grades are mined at Barrick Nevada and Pueblo Viejo, the company said.
The average market price for its products in the second quarter was $1,306 an ounce of gold and $3.12 per pound of copper, Barrick said.
Indonesia is set to announce later on Thursday the details of a deal to acquire a majority stake in the local unit of U.S. copper miner Freeport McMoRan Inc, a source with knowledge of the matter said.
Indonesian President says state mining company makes deal to raise stake in Freeport unit to 51 percent
The announcement is expected to include the share price, share holding and structure of the deal, which would give Indonesia’s state mining company, PT Inalum, a majority holding in Grasberg, the world’s second biggest copper mine.
Finance Minister Sri Mulyani Indrawati is scheduled to sign a heads of agreement with PT Freeport Indonesia at 4 p.m. (0900 GMT) on Thursday, a ministry spokesman said.
Representatives from Freeport and Inalum, along with the ministers of state-owned enterprises, energy and mineral resources, and the environment are expected to attend the signing.
A U.S.-based spokesman for Freeport could not be reached for comment.
Phoenix, Arizona-based Freeport has been in negotiations with Indonesia to secure long-term operating rights at Grasberg after the government introduced new rules last year aimed at giving Jakarta greater control over the nation’s resources.
As part of the proposed deal, Inalum was expected to acquire the 40 percent participating interest in Grasberg held by mining giant Rio Tinto (RIO.AX)(RIO.L).
Efforts to finalize a deal have been overshadowed by concerns over the environmental impact of the project in the eastern Indonesian province of Papua.
Indonesian President says state mining company makes deal to raise stake in Freeport unit to 51 percent
Indonesian President Joko Widodo said on Thursday that state-owned mining company PT Inalum has reached an initial agreement with Freeport-McMoRan Inc to increase its stake in Freeport’s local unit to 51 percent.
The larger stake would give Inalum a controlling stake in Freeport’s Indonesian assets, including the Grasberg mine, the world’s second-biggest copper mine.
Widodo said the government hopes to get larger amount of income from tax revenue and royalties under the deal and that Indonesia’s national interest should be prioritized in the agreement.
Coordinating Minister for Economic Affairs Darmin Nasution told Reuters the prices for the shares to be purchased under the deal have not been determined yet.
Indonesia on Thursday struck an agreement with Freeport-McMoRan Inc and Rio Tinto to buy a controlling stake in the world’s second-biggest copper mine via a series of transactions valued at $3.85 billion.
The heads of agreement establishes a structure for Indonesia, through its state-owned mining holding company PT Inalum, to gain control of the Grasberg mine located in the country’s eastern province of Papua. The deal should cap years of wrangling over the rights for the site as Jakarta seeks to gain greater control over its mineral wealth.
Last August, the two sides agreed to let Freeport keep operating the mine possibly until 2041 while ceding control over its local unit, PT Freeport Indonesia.
Aside from increasing government revenues, Jakarta hopes the agreement will serve as “a commitment to a conducive investment climate” in Indonesia, Finance Minister Sri Mulyani Indrawati said at a signing ceremony.
Under the agreement, Inalum plans to acquire the Indonesian unit of Rio Tinto, which holds a 40 percent participating interest in Grasberg, for $3.5 billion, said Inalum chief executive Budi Gunadi Sadikin.
That interest would then be transferred to Freeport Indonesia and converted into a 40 percent equity holding in the local unit via a rights issuance that would then be given to Inalum.
A subsequent purchase of the share of Grasberg held by Freeport-McMoRan unit PT Indocopper Investama, worth $350 million, would give Indonesia a total holding of 51.38 percent in Freeport Indonesia, Sadikin added.
The transactions will be completed later this month, said State-Owned Enterprises Minister Rini Soemarno.
Freeport Chief Executive Officer Richard Adkerson called the agreement a “positive step.” He added, “We’re committed, totally committed, to make this public-private partnership a success story.”
ROYALTIES
Freeport estimates the deal will mean Indonesia takes more than 70 percent of the “benefits” of Grasberg through taxes, royalties and dividends to Inalum, Adkerson said, estimating a total figure of between $60 billion to $90 billion.
Earlier, Indonesian President Joko Widodo praised the agreement as “a leap forward.”
“We have to have a larger amount of income from tax, royalties, dividends ... so, the value of our mining sector can benefit everybody,” Widodo told reporters before the agreement was signed.
With presidential elections due in 2019, sealing a deal to get a majority stake for Indonesia in Grasberg is a priority for Widodo, who is widely expected to seek a second term in office.
The deal is also critical for the massive investment needed to develop underground mines at Grasberg as the current open-pit operation is phased out later this year.
Still, planned agreements on how Freeport will manage mine operations with Inalum as the majority shareholder also need to be resolved.
“All parties have committed to work towards agreeing and signing binding agreements before the end of the second half of 2018,” Rio Tinto said in a statement.
Rio warned that “there is no certainty that a transaction will be completed.”
During Freeport’s five decades of operating Grasberg, there has been frequent friction between the government and the company over revenue sharing and the mine’s social and environmental impact.
Efforts to finalise a deal have been complicated by concerns over the environmental impact of the project, in particular its handling of mine waste or tailings.
Environment Minister Siti Nurbaya must still issue a recommendation to Freeport Indonesia before the miner can secure the rights to Grasberg up to 2041.
“We hope the environmental management continues to improve,” Nurbaya said at the signing ceremony, “(and) we believe Freeport can protect the sustainability of affected areas.”
Indonesia’s state-owned miner Inalum has secured $5.2 billion in financing from 11 foreign and local banks, according to sources with knowledge of the matter, to be used in part to buy a majority stake in the Grasberg copper mine.
This comes a day after Freeport-McMoRan Inc (FCX.N) said it would sell a majority stake in the world’s second-biggest copper mine to the Indonesian state-owned miner via a series of complex deals worth $3.85 billion.
The Grasberg deal will be paid off quickly, helped by forecast returns from the mine, Inalum CEO Budi Gunadi Sadikin told Reuters on Friday.
“By our calculations it will be two years,” he said, without providing any further details.
Freeport has said the deal will be positive for both sides, but noted the agreed value was far less than it could have gotten, highlighting the company’s desire to end more than six years of wrangling that has weighed on its shares.
The union for Chile’s Escondida copper mine on Thursday rejected a contract offer by the company and threatened to strike unless changes were made.
The mine, controlled by BHP, is in the middle of labor negotiations after workers extended the current contract last year, following a 44-day strike that shook the global copper market and caused huge economic losses in Chile.
The offer by Escondida, the world’s largest copper mine, included a signing bonus of about $23,000 and a salary readjustment linked to inflation, which was below the guild’s initial demand.
“This proposal is unacceptable and if there is no substantial change, the union will be forced to vote for a strike,” the union said in a statement.
Union officials said the proposed signing bonus was too low.
“We regret that the company, again resorting to bad negotiation practices, makes its offer through the media, giving an ultimatum in that the offer is only valid until July 17,” the union said.
After a long-drawn battle with Karnataka’s steel producers, the state-owned National Mineral Development Corporation (NMDC) Ltd has cut the base price of iron ore by Rs 300 per tonne.
Steelmakers of the southern state have welcomed the snip in the floor price, but said there was a need for further correction in ore prices to bring it at par with prices in Chhattisgarh and Odisha.
T R K Rao, director (commercial), NMDC, has confirmed the price-slash in an email response to queries sent by DNA Money.
“Yes, NMDC in Karnataka has reduced the base price of iron ore by Rs 300 per tonne,” he wrote back.
R K Goyal, president, Karnataka Iron & Steel Manufacturers’ Association (Kisma) and managing director of Kalyani Steel, said local steel producers have been informed about the slash in the ore prices, which will reflect in the e-auction document expected to be out soon.
“We have been told the base price will be cut by Rs 300 per tonne. This will be reflected in the prices that will be mentioned in e-auction documents to be held shortly,” he said.
For instance, iron ore with 63% Fe content was sold at base price of Rs 2,700 per tonne for fines and Rs 3,000 per tonne for lumps in the last auction. Both will be lowered by Rs 300 a tonne in the next auction. The reduction in the floor price of ore will be across all grades.
M V S Seshagiri Rao, CFO and joint managing director, JSW Steel, lauded the NMDC move but said it did not close the gap between prices of same grade iron ore of Karnataka and Odisha.
“It’s a welcome step. Karnataka steel industry has been looking for iron ore prices being brought in line with Odisha. In Karnataka, a 59.5% grade iron ore loaded into wagon, including the taxes/royalties, is priced at Rs 3,306 per tonne. The same grade of iron ore is available in Odisha at around Rs 900 per tonne. That is the kind of difference in prices while the reduction is only Rs 300 per tonne. So, we still have a long way to go,” he said.
There has been a stand-off between the steel producers and miners over pricing of ore for some time now.
The former has accused the latter of taking advantage of shortage and charging a premium on the commodity.
Miners, on the other hand, have alleged that with steel producers lifting iron ore from other states, they were finding it difficult to find buyers for their ore stock at auctions in Karnataka.
R K Goyal also echoed similar sentiment as JSW’s Rao.
“It is still much higher compared to the same grade iron ore in other states. It’s (base price cut) not bad but it’s not substantial either. There is still a difference of over Rs 1,000 per tonne. We request the miners to reduce it further and bring it at par with Chhattisgarh and Odisha,” he said.
According to him, the price-cut would do little to improve margins as steel players have lately been dealing with rising coking coal prices. He said coking coal prices have shot up by around $50 per tonne in the last one month.
Goyal said Kalyani Steel was looking at hiking steel prices in October when the company’s contract with original OEMs) comes up for renewal. “Coke (coking coal) prices are going up so a price-cut will not improve our margins. It will only provide some relief in terms of cost,” he said.
https://www.hellenicshippingnews.com/nmdc-cuts-base-price-of-ore-by-rs-300-per-tonne-in-karnataka/
Japanese trading house Mitsui & Co may boost its stake in Brazil's Vale SA if other shareholders sell part of their holdings, a senior executive said, giving it greater influence over the iron ore giant's management.
Several Brazilian pension funds and BNDESPar, the investment arm of state development bank BNDES have been considering the sale of part of their stakes in Vale, equating to about 3% of the miner's shares in total and worth up to eight-billion reais ($2-billion).
Buying an additional stake was "an option", Yukio Takebe, Mitsui's senior executive managing officer who oversees the energy and metals business, told Reuters in an interview on Thursday.
"We want to keep being involved in Vale's management in the future," Takebe said. Mitsui, one of Vale's four controlling shareholders under its previous dual-share structure, currently has two positions on the miner's 11-member board.
The sale of Vale stakes has been a subject of market speculation since the world's largest iron ore miner moved to a single class of stock in October. Mitsui currently holds a 5.51% stake in Vale.
Asked whether Mitsui could buy all of the shareholders' stake if it were offered as a parcel, Takebe said: "I wouldn't rule out the possibility, but it's unlikely that we would buy all the shares on sale."
Iron-ore is a mainstay resource asset for Mitsui and it aims to boost its annual equity output - its share of output from equity stakes it holds in miners or mines - to 64-million tonnes in two years from 60.9-million tonnes last year ended March.
"Boosting iron ore output is our priority for the metals business," Takebe said.
Mitsui, which has an interest in nickel and cobalt through a joint venture with Sumitomo Metal Mining in the Philippines, may also look at other projects given likely demand for rechargeable batteries for electric vehicles.
"We don't have assets in other battery metals such as lithium, but we want to keep an option to own such assets if attractive deals come up," Takebe said.
However, Mitsui would be cautious as most attractive assets were already taken and new entrants may be forced to pay high prices for assets in difficult locations to develop.
Mitsui said in May a final investment decision (FID) on a US Anadarko-led offshore liquefied natural gas project in Mozambique is expected by end-March.
Takebe said Mitsui and its partners have won basic agreements from buyers in Japan, India and others for 10-million tonnes supplies in the 12-million-tonnes-per-year project and they are in the process of formalising contracts.
http://www.miningweekly.com/article/japans-mitsui-may-raise-its-stake-in-vale-executive-2018-07-06
Miner Yancoal Australia said on Monday that production at the Austar coking coal mine in New South Wales state would be halted until it resolves a dispute with the state regulator over a resumption of operations.
Yancoal said it will start standing down employees, and is aiming to redeploy most workers to other underground operations owned by the company.
The miner is seeking a review of two notices issued by the regulator that prohibited all underground longwall production at the Hunter Valley mine after a so-called coal burst, where tonnes of coal exploded from the longwall face.
No workers were injured, but the incident followed other similar events, including one where an employee was treated for a hand injury after 50 tonnes of coal exploded from a longwall, according to local media reports.
Yancoal was advised on May 18 that the prohibition order would remain in place until a detailed geotechnical assessment was completed and the resources regulator was satisfied workers would be protected from further coal bursts.
“Until all legal avenues have been exhausted and we can re-enter the mine to move the longwall, we are unable to continue proposed longwall activity,” Yancoal Chief Executive Reinhold Schmidt said in a statement.
Two Austar employees died in another underground wall collapse four years ago.
Hot-rolled steel production across 25 major Chinese steel mills in July is expected to increase by 7% in July, SMM survey showed
China is taking more seriously its efforts to tackle air pollution and may increasingly prioritize use of imported high grade iron ore, coking coal, and natural gas, along with expanding steel sector operating controls, consultants Wood Mackenzie said Monday.
The measures may lead to uncertainty for commodity prices, especially as the transition to adopt the recommended measures is likely to be gradual, Wood Mac's Prakash Sharma, head of China research, said in a note.
China's "'blue sky action plan' offers tougher limits and proposes a quicker shift to cleaner fuels such as LNG and electricity, and high grade iron ore, coal and metals," Sharma said.
"The measures taken so far are falling short of government goals and public expectations."
China's import iron ore pellet premiums have surged, with the S&P Global Platts weekly assessment hitting a record $61.95/dry mt on July 4.
Demand for the direct charge feedstock rose on steel margins incentivizing utilization, and measures limiting domestic iron ore material and sintering of iron ore fines. Lump iron ore premiums have also picked up over June, with imports mainly from Australia and South Africa.
"The challenge is many of these commodities are not produced competitively locally and need to come from outside," he added.
The ability of the steel sector to use more domestic ferrous scrap may need new EAF plants, which melt iron and need electricity.
For natural gas, switching quickly to more expensive gas and reliance on LNG imports would be difficult, while China's power sector works around capacity controls for new coal-fired and gas power plant, it said.
Heating demand in northern China is 300 Bcm gas equivalent, according to Wood Mac, which estimates actual gas consumption at 30 Bcm.
China's State Council released a three-year action plan to cut air pollution on July 3 which extended the target area to more cities, mainly in northeast and eastern China.
The plan, which could also lead to more usage and imports of natural gas and renewable energy, along with effects on logistics and transportation, may raise domestic costs, Wood Mac said.
CLOSER SCRUTINY
"With expansion of the target area, we estimate more than half of China's steel-making capacity will now come under scrutiny on emissions control and will be subject to production curbs during autumn and winter."
"This means steel production growth could slow later this year keeping the market tight and prices higher. Demand for high grade iron ore will continue to find support as mills will chase productivity to maximize output."
Wood Mac expects domestic iron ore and bauxite mines in Shanxi, Shaanxi and Henan provinces will fall under greater supervision for emissions and dust control. This could lead the areas to struggle to raise or maintain production levels, it said.
As for China's goal to eliminate trucking of raw materials such as coking coal, iron ore and limestone from port to plant by 2020, this could lead to higher costs, Wood Mac said. It may improve supply consistency, as haulage via rail would be less affected by weather, it said.
"In the near term, the move could result in increased clearance time for imported coal cargoes, as witnessed last winter," Wood Mac said.
China's plan aims to ban new capacity additions in the steel, coking and aluminum smelter sectors in the target areas, which is home to just over half the country's total 1.115 billion mt/year crude steel production capacity, 54% of hot metal production and 46% of met coke production, Wood Mac estimates.
Wood Mac expects smelting capacity for copper, zinc and lead in the target area will need to either upgrade to meet new emission guidelines or face production curbs. Up to 2.6 million mt/year of copper smelting capacity could be affected along with 1.4 million mt/year of primary and secondary lead capacity, it said.
As for power, Wood Mac expects it will be a challenge to switch to gas completely, because of the cost and limited domestic supply to meet demand.
"One can imagine the potential impact on global gas markets if China were to switch fully, or quickly," it said.
"We expect gas supply prioritization and rationing to continue to serve heavily polluted residential areas of the Beijing-Tianjin-Hebei cluster and Fenwei plain."
Steel mills in Xuzhou city in China's second biggest steelmaking province are preparing to resume production after shutting for 2-1/2 months for an environmental upgrade.
Xuzhou, home of 18 steel mills with total annual crude steel capacity of 13 million tonnes in the eastern province of Jiangsu, ordered steel manufacturers in April to close until they met tough anti-pollution rules to clear up the smoggy sky.
The city was identified by the Environmental Ministry as one of the 10 cities across China with the worst air quality in the first five months of the year.
A team of Beijing-led inspectors left on July 6 following a month of environmental checks in Jiangsu.
"Our production process is fairly short and straightforward compared to those who use blast furnace to make steel, which makes us easier to pass the check," said Wang Guangrui, deputy general manager at Jinhong.
EAFs, or mini-mills, uses scrap steel and electricity to generate steel, emitting far less carbon than blast furnaces which use coal and iron ore in a sintering process that generates more pollution.
Huahong Special Steel Co in Xuzhou is also expected to resume operation this week, two industrial sources told Reuters.
"Huahong started to preheat its furnaces last week and is expected to churn out hot metal by this weekend," said a Xuzhou-based steel trader.
Huahong, one of the biggest mills in Xuzhou, has two blast furnaces with total capacity of 2.08 million tonnes a year.
"The environmental check is very stringent. Most of mills are still unable to meet the standards," said Wang, adding he expected only two or three factories to pass the checks so they could reopen in July.
Steel mills in Xuzhou were asked to install environmental equipment such as dust collectors, desulfurisation units and denitration devices, requiring millions of yuan of investment.
Xuzhou plans to ensure the concentration in the air of small particulate matter, known as PM2.5, remains below 60 micrograms per cubic metre. In the first half of this year, the average PM2.5 level in the city was 73.17 micrograms.
India’s JSW Steel is looking to acquire smaller steel plants in India and overseas that produce specialized products, a top executive said on Tuesday, as it tweaks its acquisition strategy after missing out on some recent deals.
JSW Steel, India’s biggest steelmaker in terms of domestic capacity, failed to outbid rival Tata Steel in March for bankrupt steelmaker Bhushan Steel. The company also lost out to UK-based steel manufacturer Liberty House for Bhushan Power following a bankruptcy resolution process for both companies in April.
Earlier this year, JSW was beaten out by ArcelorMittal SA (MT.AS), the world’s largest steelmaker, for Italian steel major Ilva SpA.
After the recent setbacks, JSW Steel is now looking to focus on buying more niche, lower capacity plants which do not require huge investments to turn around, said Seshagiri Rao, joint managing director and the group financial head of JSW Steel.
“In the next round, our strategic thinking is to now focus on special product units that generally have a capacity of about a million tonnes,” said Rao, referring to an upcoming round of auctions under India’s new bankruptcy law, during which a second wave of steel assets will be up for grabs.
India’s steel demand has been growing at over 8 percent for the last few months. The growth is being led by higher motorcycle and automobile sales and government-sponsored infrastructure projects.
Rao said that JSW Steel is scouting for opportunities in the specialized steel segment that are dedicated to meeting specific customer demands. He did not name the prospective targets.
INTERNATIONAL PLANS
JSW has steelmaking capacity of 18 million tonnes per year, around 13 percent of India’s installed capacity. It is investing 268 billion rupees ($3.9 billion) over the next three years to expand to 24 million tonnes.
By 20230, JSW plans to increase its capacity to 40 million tonnes in India and 10 million tonnes overseas.
Buoyed by its two recent acquisitions of relatively smaller steel plants in the United States and Italy, the company is now looking for similar-sized plants elsewhere in Europe.
“There are five or six mainly downstream projects that we’re evaluating,” said Rao, adding the strategy would be similar to its acquisition plans in India.
In March, JSW bought Acero Junction Holdings for $80.85 million in the United States and Italy’s Aferpi for 55 million euros in May.
Together, along with its plate and pipe mill in the U.S., it now has a total overseas capacity of 4 million tonnes per year.
“I think both the acquisitions we’ve announced fit well with our strategy,” Rao said.
Wetter than normal weather in recent months has slowed coal shipments from one of the main producing regions in Indonesia, the world’s top thermal coal exporter, according to weather data, brokers and analysts, supporting prices of the fuel.
Thomson Reuters Eikon data shows the cumulative rainfall in the province of South Kalimantan this year was 37 percent higher than average as of July 10, and 27 percent more than average in East Kalimantan.
Queues of dry bulk vessels in those two provinces were also higher than average, after rains turned hauling roads into mud, disrupting coal loading, according to Eikon shipping data.
“It’s been fairly slow in the last couple of weeks,” a Singapore-based shipping broker said, referring to Indonesian coal exports, adding there were “literally no cargoes moving out of Indonesia” last week.
“We know that there are pretty decent queues and pretty limited activity out of there,” he said. But conditions had now begun to improve with shipments to south and central China, he said.
Slower Indonesian exports along with robust demand from China, where hot weather has increased power usage, and increased imports by India, South Korea and Japan, thermal coal prices in Asia hit six-year highs last month.
A spokesman for Indonesia’s biggest coal miner Bumi Resources, Dileep Srivastava, said rains were “heavier than usual over May and most of June” and there “could be some vessel slippages.”
The weather in those areas was “still wet but drier conditions (are) now apparent,” he said.
But Bumi, which has mines in South and East Kalimantan was still targeting output of 90 million tonnes for 2018, Srivastava said.
Coal production at Indonesia’s second-biggest producer by volume, Adaro Energy, had been affected by wet weather this year, but these were largely anticipated and were “still manageable”, spokeswoman Febriati Nadira told Reuters.
Adaro was still optimistic of achieving its annual production goal of 54-56 million tonnes, Nadira said.
“The first week in July was really wet,” said Keith Whitchurch, head of mining engineering consultancy SMG in Jakarta, referring to East Kalimantan.
“It’s been a wet year.”
All steel mills in Tangshan are likely to face a fresh round of production cuts for July, as the municipal government tries to improve the city's air quality ranking, which currently ranks last among 74 major Chinese cities.
As of Tuesday July 10, most steel mills have yet to receive notice from the government. Mills currently adopt rotating production schedules for the non-heating season, SMM learned.
The new round scheduled from July 10-31 will last longer than previous cuts and will affect blast furnaces. This compared with Tangshan's previous short-term, frequent cutthat targeted sintering machines and shaft furnaces, and affected the supply of raw materials.
Capacity will be cut by 50% for blast furnaces at steel plants in the districts of Guzhi, Fengrun, Fengnan, and Luan and Yutian counties. The cut will also apply to all sintering machines and shaft furnaces at steel mills in the city.
Just one blast furnace each will be allowed to operate at Tangsteel south, north, and at Tangyin Iron & Steel, SMM learned. Blast furnaces in plants other than the above-mentioned areas will have to cut capacity by 30%.
Coking duration at all coke plants in the city is required to be extended to 33 hours. All steel rolling plants in Tangshan will be suspended by the end of July.
Such restrictions do not apply to plants with dry desulphurisation facilities.
From March 16 to November 14, steel enterprises in the main urban area of Tangshan are required to cut production by 15%, and those beyond the area will cut by 10%. This is according to the 2018 non-heating season production plan for the iron and steel industry in Tangshan.
World’s No.1 miner BHP , has been given the green light to go ahead with a planned expansion of its operations in Australia iron ore-rich Pilbara region for the next 50 to 100 years, which will secure its grasp over one of its most important commodities.
Western Australia’s environmental authority approval of BHP’s proposal, first submitted 2012, will allow the miner build new mines at Caramulla, Coondiner, Gurinbiddy, Jinidi, Marillana, Mindy, Ministers North, Mudlark, Munjina/Upper Marillana, Ophthalmia/Prairie Downs, Rocklea, Roy Hill and Tandanya. It also lets BHP expand its existing operations.
Approved plan includes the possible construction of 13 new iron ore mines and the expansion of existing operations.
The state’s Environmental Protection Authority (EPA) deputy chairman Robert Harvey said the consent for the strategic expansion came after years of careful consideration of the miner’s projected impact on fauna, flora, surface and ground water, air quality and social surrounds.
BHP still has to refer proposals on an individual basis to assess whether it meets the environmental requirements set out in the strategic assessment. This will be done in case there is any new information or environmental changes that may result in reassessment, Harvey said in the statement.
Opponents have until July 23 to appeal Western Australia’s EPA resolution.
BHP has renewed investment in the iron ore sector in the past two years. Only last month, the company’s board approved a $2.9-billion expansion of the South Flank iron ore project in Western Australia, which will give it another 25 years of further production.
BHP said the South Flank ore will increase the average grade of its iron ore mined in Western Australia to 62% from 61%. It also said the project, to start production in 2021, will replace Yandi mine, which is reaching the end of its life.
http://www.mining.com/bhp-secures-iron-mining-rights-australias-pilbara-another-century/
The duration of further potential industrial action by workers on rail operator Aurizon's Australian Central Queensland Coal Network this week has been extended by three days, an Aurizon spokeswoman said in response to S&P Global Platts' queries via email Wednesday.
Aurizon had been hoping to avoid further strikes following 24-hours of stoppages by unionized network controllers on Tuesday and Wednesday by offering to resume negotiations.
Aurizon had said on Tuesday that there was the threat of further action by the Rail, Tram and Bus Union from Thursday to Saturday.
It now says it has received notices of industrial action, which included rolling stoppages and overtime bans, from Thursday until Tuesday July 17.
"We are assessing the impact of this protected industrial action and will update customers as required," the spokeswoman said.
"Aurizon this week wrote to the unions offering to resume negotiations if an undertaking is given to cease protected industrial action, while those talks take place. If the unions agree, Aurizon will work towards the objective of reaching in-principle agreement," she said.
Network controllers who are members of the RTBU working on all control boards already took 24-hours of industrial action from 4.00am local time Tuesday (1800 GMT Monday) to 4.00am local time Wednesday.
"Through contingency planning, Aurizon Network to date has been able to continue to safely operate services across the Central Queensland Network, although rail operators may experience some transactional delays in obtaining authorities for travel across the network," the spokeswoman said.
The action is in relation to the current Staff Enterprise Agreement negotiations. Aurizon says it was offering wage increases of 2% per year for four years, and changes to conditions that are "better aligned to competitors and industry".
The Central Queensland Coal Network is one of the world's largest and most complex supply chains. It connects mines in the region to both domestic coal users and the export terminals at Abbot Point, Dalrymple Bay, Hay Point and the Port of Gladstone.
Traders with old Tanda Registrasi and associated Ekspor Terdaftar licences to export coal since July 1, 2018 have been forbidden to do so, according to Wood Mackenzie.
"Market rumours suggest the ban only applies to companies that have defaulted in paying duties and taxes, irrespective of whether it is a trader or a miner," it said.
Most of the vessels are in South Kalimantan and East Kalimantan, either loaded or waiting to be loaded, and are mostly destined for China, according to WoodMac.
The affected vessels, with a capacity of 2.5 million tonnes of coal, equate to about 15% of Indonesian seaborne supply for the next 15 to 20 days.
"Indonesia is the largest exporter of thermal coal in the world and traders play an important role, especially in the blended coal segment." WoodMac said.
"We understand the government's aim in introducing this policy is to regulate exports and make sure that royalties, duties and taxes are paid for each tonne of coal produced and exported."
Coal-rich Shanxi province in northern China has decided to launch an inspection over implementation of production capacity filing and announcement work by operating mines, a step to further strengthen management of coal mines.
Coal mines in the province should conduct self inspection over July 10 to August 10. Meanwile inspectors will make random check on coal quality management work at mines, those who fail will be punished.
World stainless steel melt shop production rose 9.5% on the year to 12.767 million mt in the first three months of 2018, according to figures released Tuesday by the International Stainless Steel Forum.
Output was also up 1.8% from 12.545 million mt in the fourth quarter of 2017.
Chinese production was up 6.5% year-on-year to 6.524 million mt in Q1, but slipped 1.9% from output of 6.652 million mt in the fourth quarter of 2017.
Asian production excluding China and South Korea had a 4% year-on-year rise to 2.072 million mt from 1.992 million mt in Q1 2017, but also edged down 1.6% from output of 2.105 million mt in Q4.
European production reached 2.014 million mt in Q2, up 1.7% from output of 1.98 million mt a year earlier and up a hefty 10% from 1.83 million mt in Q4 last year.
The US was the only regaion to post a year-on-year drop in Q1, off a marginal 0.4% to 718,000 mt from 721,000 mt in Q1, 2017, but output was up 9.8% from 654,000 mt in Q4 last year.
The ISSF’s “others” category (comprising Brazil, Russia, South Africa, South Korea and Indonesia), shad melt shop output of 1.439 million mt in Q1, up 70.2% from 845,000 mt in Q1 last year and up 10.3% from 1.304 million mt in Q4.
https://www.hellenicshippingnews.com/world-stainless-melt-shop-production-up-9-5-on-year-in-q1-issf/
Average daily output of crude steel at key mills across China during June 21-30 stood at 1.96 million mt, down 1.79% or 35,600 mt from the level during June 11-20, according to data from the China Iron and Steel Association (CISA).
For the same period, average daily output of pig iron slipped 2.23% or 40,200 mt to 1.76 million mt while that of steel products increased 6.51% or 121,600 mt to 1.99 million mt.
Key mills across the country produced 19.55 million mt of crude steel, 17.63 million mt of pig iron and 19.91 million mt of steel products in the last 10 days of June.
China’s Dalian Commodity Exchange said on Wednesday it will raise the quality standards for delivery of coking coal , a key fuel for steelmaking, in order to meet market demand for high-grade industrial ingredients.
The new standards lower the allowable amount of impurities such as ash and sulphur, according to a statement on the exchange website.
The bourse also set discounts for deliveries below the benchmark quality thresholds.
New delivery standards will take effective from July 2019 contract.
https://www.hellenicshippingnews.com/chinas-dalian-exchange-to-raise-coking-coal-delivery-standards/
Germany’s antitrust authority has fined six stainless steel makers, an industry association and 10 individuals a total of 205 million euros ($239 million) for price fixing and exchanging market-sensitive information.
“Over years, the companies agreed on important aspects of stainless steel prices,” Federal Cartel Office President Andreas Mundt said in a statement on Thursday.
The Cartel Office was alerted to the price-fixing by Austrian steelmaker Voestalpine, which said in a separate statement that it had discovered the violations during routine internal audits.
Cartel Office investigators searched several offices and homes in November 2015 and found evidence that steel companies had since 2004 been agreeing on how to calculate scrap and alloy surcharges.
They also coordinated increases in the base price of engineering steel and exchanged information about their order books, their customers’ inventories, production outages and planned price increases, the Cartel Office said.
The six companies being fined are ArcelorMittal Commercial Long Deutschland GmbH, a German division of ArcelorMittal, Doerrenberg Edelstahl GmbH, Kind & Co. Edelstahlwerke GmbH & Co.KG, Saarstahl AG, Schmidt + Clemens GmbH + Co. KG and Zapp Precision Metals GmbH.
The Cartel Office said it was still investigating four further companies, which it did not name. It also did not name the individuals it was fining.
The industry association that was involved in the price-fixing was the Edelstahl-Vereinigung e.V., which has since been disbanded, the Cartel Office said.
Voestalpine will not face a fine because it blew the whistle on the cartel.
The Austrian company said the employees who were mainly involved no longer worked for the group. No members of its management board were involved in the violations, nor were they aware of them, it said.
China’s iron ore imports dropped 11.6 percent in June from the previous month, customs data showed on Friday, hit as Beijing intensifies its push to clean up the country’s environment and by mounting stockpiles at ports.
Arrivals into the world’s top importer of the steelmaking material reached 83.24 million tonnes last month, according to the General Administration of Customs, down from May’s 94.14 million tonnes and from 94.7 million tonnes in June last year.
Imports for the first-half of 2018 dipped 1.6 percent from the year before to 530.69 million tonnes, the data showed, curbed by wide-ranging steel production restrictions in the first three months.
Iron ore stockpiles at Chinese ports stood at 156.38 million tonnes last week, not far from a record 161.98 million tonnes in early June, data compiled by SteelHome consultants showed. Last week’s level is nearly 40 percent higher than the five-year average of 113.45 million tonnes.
Month-long environmental inspections in 10 regions across China, including top steelmaking province Hebei, dented appetite for iron ore in June.
Crude steel output at major steel companies last month reached 59.3 million tonnes, down from 61 million tonnes in May, according data from China’s Iron & Steel Association (CISA).
“Iron ore demand may be further suppressed by environmental measures in the coming months,” said Zhuo Guiqiu, analyst at Jinrui Futures.
On Wednesday, Tangshan, the biggest steelmaking city in northern China, ordered steel mills, coke producers and utilities to cut output further for six weeks from July 20 until Aug 31 to clear its smoggy sky.
The sintering process, where iron ore is heated into a mass as a precursor to making hot metal, and blast furnaces are expected to be major targets in curbing pollution. Analysts expect up to 150,000 tonnes of hot metal output to be affected.
Industrial plants in the Beijing-Tianjin-Hebei region may also face more stringent environmental measures as China’s cabinet has launched a new cross-ministerial leadership group, headed by vice-premier Han Zheng, to help draw up plans to tackle air pollution in the area.
“Utilisation rates at mills have reached a relatively high level and it is hard for those who are exempted from the environmental crackdown to improve output,” said Zhuo.
Weekly utilization rates at blast furnaces across China had reached 70.86 percent as of Friday, not much lower than the 8-month peak level of 71.96 percent in late May, data from Mysteel consultancy showed, as seasonal maintenance at mills kicked in.
China’s thermal coal imports in June rose 18 percent from a year ago to 25.47 million tonnes, according to customs data on Friday, as utilities went on a buying spree to shore up electricity generation.
June’s imports also rebounded from 22.33 million tonnes in May, the data from the General Administration of Customs showed, after traders said China relaxed customs checks to let in foreign supplies.
Robust imports led to higher inventories at port and power plants, easing worries that China’s electricity output might not be able to meet surging demand from provinces such as Hebei and Shandong due to hot weather.
Major Chinese cities such as Wuhan in Hubei and Hefei in Henan province last month reported heavy loads on their power grid and indicated that they might started rationing electricity.
In the first half, coal imports rose to 146.19 million tonnes, up 10 percent from a year earlier, data showed.
China's steel rebar futures hit their highest in 10 months on July 12 amid potential tight supply as the government intensifies efforts to clean up the environment.
On July 11, China's cabinet launched a new cross-ministerial leadership group, headed by the vice-premier Han Zheng, to help draw up plans to tackle air pollution in northern regions.
"The high-class leadership group will certainly be a strong deterrent to environmental violations and may also restrain output at mills and mines," said Zhuo Guiqiu, an analyst at Jinrui Futures.
And Tangshan, China's biggest steelmaking city, has ordered steel mills, coke producers and utilities to cut output further for six weeks from July 20 until August 31 to improve its notorious air quality.
"With high environmental pressure, more regions may order their industrial plants to reduce emissions," said Zhuo.
The most-active rebar contracts on the Shanghai Futures Exchange had risen 2.1% after earlier touching 3,960 yuan/t ($591.24/t), its highest level since September 6.
Spot steel prices edged up 0.2% to 4,320.36 yuan/t on July 11, data showed.
Daily crude steel output by major steel companies over June 21-30 reached 1.96 million tonnes, down 1.8% compared to mid-June, data from China Iron & Steel Association (CISA) showed on July 11.
Steel inventory at mills dropped over the same period, falling 24,700 tonnes to 11.42 million tonnes, CISA data showed.
Prices for steelmaking raw ingredients also climbed. The most-traded coking coal contract for September delivery rose 2.2% to 1,157 yuan/t. Coke futures were up 2.3% at 2,065 yuan/t at 0214 GMT.
Dalian iron ore futures gained 1.6% to 464 yuan/t, with investors saying increased profit margins at mills would offer some support to the raw material.