U.S. President Donald Trump said on Monday he will impose 10 percent U.S. tariffs on about $200 billion worth of Chinese imports, but he spared smart watches from Apple and Fitbit Inc and other consumer products such as bicycle helmets and baby car seats.
Trump, in a statement announcing the new round of tariffs, warned that if China takes retaliatory action against U.S. farmers or industries, “we will immediately pursue phase three, which is tariffs on approximately $267 billion of additional imports.”
Collection of tariffs on the long-anticipated list will start September 24 but the rate will increase to 25 percent by the end of 2018, allowing U.S. companies some time to adjust their supply chains to alternate countries, a senior administration official said.
https://www.reuters.com/article/usa-trade-china-tariffs/trump-slaps-tariffs-on-200-bln-in-chinese-goods-threatens-267-bln-more-idUSW1N1VC01L
Premier Li Keqiang said Wednesday that China will adopt a stricter protection system on intellectual property rights (IPRs).
He made the remarks when addressing the opening plenary at the Annual Meeting of the New Champions 2018, also known as Summer Davos, in Tianjin.
Li said that protecting IPRs means protecting and stimulating innovation. China cannot achieve innovative development without an environment that respects knowledge and protects property rights.
Jack Ma, co-founder of Chinese e-tech giant Alibaba Group Holding Ltd, said on Thursday that people should make preparations for 20 years of China-U.S. trade frictions.
The economic situation is not good, and that could last for a long time, Ma said at the World Economic Forum in Tianjin.
Ma has already cautioned the trade war between the world’s two biggest economies could last decades, and China should focus on exports on the modern-day “Silk Road” that spans Africa, Southeast Asia and Europe.
Alibaba can no longer meet its promise to create 1 million jobs in the United States due to the trade tensions, Ma told Chinese news agency Xinhua on Wednesday.
Anglo American PLC has fought off three separate cyberattacks in the past 12 months, as large payments made by mining companies prove tempting for determined fraudsters.
Anglo's group chief information officer, Rohan Davidson, told Dow Jones Newswires that "determined" groups made three financial fraud attacks against the company since last September, but that these met with "limited success."
He said the company has in response roughly doubled its dedicated cybersecurity spend last year to face the growing threat posed by online attacks.
Mr. Davidson said that fraudsters are attracted by the size of the large transactions that mining companies like Anglo make, which make it easier to make a lot of money in one go.
He said Anglo American deals with cybersecurity threats on a weekly basis, and that the company's firewall defenses are probed every hour.
The cyber threats posed to Anglo American typically fall into one of three categories: insider fraud and data breaches, active intrusions aimed at committing financial fraud and rare threats expressly targeting the company itself, Mr. Davidson said. It is this second type of threat--organized intrusions--that take up most of the company's attention, he added.
"They go after us because we handle big payments. I think any company that handles big payments is an attractive target," Mr. Davidson said.
Describing the scammers that target mining companies as niche, he noted that "not everybody can make money out of sifting through the information flow of a shipment of iron ore but there are groups that operate in that area."
He said the company's dedicated cybersecurity spend was in the millions of dollars, while its cybersecurity provision--including staffing, tooling and services--now accounts for 4% of its total IT spend, up from 1% in 2015.
A report from Big Four accounting firm Ernst & Young published in March found that 97% of mining companies don't believe that their cybersecurity capabilities meet their needs, with 53% having increased their cybersecurity budget over the last year.
EY said mining companies' biggest vulnerabilities are their corporate network and internet exposure, with weakness stemming from their contacts with vendors and third parties who move around their premises on a daily basis.
Richard Watson, EY's lead partner in cybersecurity risk-management in Asia-Pacific, said large mining companies are spending an additional $20 million to $30 million a year to get ahead of cybersecurity risks.
Mr. Davidson said he is optimistic about Anglo American's current provision for online protection, but cautioned that cybersecurity "is a field where confidence is for the foolish."
Anglo American has beefed up its cybersecurity arsenal in recent years, doubling the size of the team that defends the company from possible attacks.
"We're broadly happy with the footprint of our cybersecurity operations. The key for us is not scale of the investment, but rather the ability to adapt as threats evolve," Mr. Davidson said.
Large mining companies benefit from having more money at their disposal with which to tackle these threats, Mr. Watson said, but they also have to deal with more points of vulnerability due to their size and scale.
"Whilst the bigger [companies] have more resources to throw at the problem, they're also more complex and global in nature with much more complex operations," Mr. Watson said.
However, while these types of businesses are rising to meet the challenges posed by cyberthreats, smaller miners still have some way to go.
"Some of the smaller companies are still relatively under prepared. [They] are still not at the stage of thinking about this as a strategic risk," Mr. Watson said.
https://www.marketwatch.com/story/anglo-american-fought-3-cyberattacks-in-past-year-2018-09-14
The Philippines’ environment minister on Monday ordered the stoppage of all small-scale mining activities in a mountainous region in the country’s north following major landslides after super typhoon Mangkhut hit the country.
“I officially order the cease and desist of all illegal small-scale mining in Cordillera Region,” Environment and Natural Resources Secretary Roy Cimatu told a media briefing.
Mangkhut, with hurricane-force winds well over 200 km per hour (124 miles per hour), barreled past the northern tip of the Philippines on Saturday, killing at least 50 people, the majority of them due to landslides.
It then skirted south of Hong Kong and neighbouring Macau, before making landfall in China.
The prime minister of Democratic Republic of Congo will sign a decree in the coming days to designate cobalt and other minerals as “strategic” and therefore subject to higher royalties, Mines Minister Martin Kabwelulu said on Saturday.
The change is part of a new mining code, which mining companies including Glencore and Randgold oppose as it axes tax exemptions and hikes royalties and profit taxes. They have been holding out the hope it might be watered down in further negotiations.
The government has not yet formally announced which metals will be classed as strategic in the new code and subject to royalties of 10 percent. Before the code was introduced, companies paid a rate of 2 percent for cobalt.
Addressing a mining conference in the copper and cobalt-mining city of Kolwezi, Kabwelulu said: “in the coming days, you will see the prime minister sign a decree to declare cobalt and certain other substances as strategic.”
Miners of cobalt would have paid a royalty of 3.5 percent under the new code if its designation had stayed the same.
The government considers minerals with the “strategic” designation important for the economic, social and industrial future of the country.
The new code came into effect in June. Companies say its tax hikes and cancelling of 10-year exemptions for existing projects against changes to the previous fiscal and customs regimes breach previous agreements with the government and will deter further investment.
Kabwelulu said all companies were paying the royalties and taxes as stipulated by the new code, despite Randgold saying in August it was still negotiating with the government. [nL5N1V06J0
“I know that Randgold made a statement, but it’s not true,” he said.
Congo is Africa’s top copper producer and the world’s leading miner of cobalt, a mineral which has seen a surge in demand to the manufacture of electric car batteries and mobile phones.
Other major mining companies with investments in Congo include AngloGold Ashanti, Ivanhoe Mines, China Molybdenum, Zijin Mining and MMG .
Chile lawmakers mull additional mining tax for copper, lithium
The Lower Chamber of Chile’s Parliament has begun studying a project that would set a 3% mining royalty for all companies operating in the country, which is the world’s top copper producer and the one with the largest known reserves of lithium.
The proposed tax, to be applied on the nominal value of extracted metals, would affect copper miners that produce more than 12,000 tonnes of the metal annually and those extracting 50,000 tonnes a year of lithium, used in batteries that power electric cars.
The idea is to have miners contributing part of their profits to the regions where they operate, Radio Universidad de Chile reported (in Spanish).
The last time Chile increased mining royalties was in 2010, following an 8.8 magnitude earthquake that left the government scrambling for additional funds to rebuild the devastated areas.
The bill, put forward by lawmakers from a number of small parties pushing for Chile's decentralization, is not thought to have the backing of the government or larger opposition parties.
The last time Chile increased its mining royalties was in 2010, following an 8.8 magnitude earthquake that left the government scrambling for additional funds to rebuild the devastated areas.
At the time, mining taxes went from between 4 and 5 percent to 4 percent to 9 percent of sales on a sliding scale. The royalty rose again early this year to between 5 to 14 percent.
After the lost crown
Chile, which holds about 52% of the world’s known lithium reserves, recently lost its top lithium producer crown to Australia. But both companies and the government are working hard on reversing that.
Over the past several months, Chile’s SQM — the world’s number two lithium producer — has been expanding its mines. The company recently finished the first stage of a lithium carbonate ramp-up in Chile’s Salar del Carmen, reaching a capacity of 70k million tonnes a year.
“Our next step will be to work towards our goal of 120k MT/year, which is expected to be completed by the end of 2019,” chief executive officer Patricio de Solminihac said last month.
The firm actually believes it will soon overtake US-based competitor Albemarle as the world's top lithium miner, by 2022 to be exact. SQM expects to boost its production capacity that year to 28% of the world's total versus Albemarle's 16%.
Chile expects lithium to soon become its second largest mining asset, just behind copper. It's currently the country's fourth biggest export.
http://www.mining.com/chile-lawmakers-mull-additional-mining-tax-for-copper-lithium/
China likely will not send a trade delegation to Washington after the Trump Administration announced plans to implement tariffs on $200 billion worth of Chinese goods, the South China Morning Post reported on Tuesday, citing an unidentified government source in Beijing.
The report said China is reviewing its previous plans to send a delegation headed by Vice Premier Liu He to the U.S. next week for fresh round of talks. The source told the paper that Beijing has not yet made a final decision but that a show of “sufficient goodwill” was a precondition for the planned talks.
The new U.S. tariffs would take effect on Sept. 24 at a rate of 10 percent and then escalate to 25 percent by the end of 2018.
BHP Billiton BHP, aims to remove the second half of its name this year, the next step in a rebranding push that has focused the world's biggest listed miner on its Australian roots.
In documents released Tuesday to the Australian Securities Exchange, the company said it would ask shareholders to vote to rename the company BHP Group.
Last May, the company shifted to a new logo that simply said "BHP" and dropped three stylized blobs that had been featured for years. It also adopted the motto "Think Big" in place of "Resourcing the Future."
The shortened name takes the company back to its origins as Broken Hill Proprietary Co., when it was formed more than 130 years ago around a silver, lead and tin mine in South Australia. It formally adopted BHP Ltd. a year before the 2001 merger with Britain's Billiton PLC, when it took on both names and a dual Australia- U.K.-headquartered and listed structure.
In recent years, the company has consolidated its portfolio of assets around iron ore, oil and gas, copper, and coal. In 2015, it spun off nickel, aluminum and other assets--much of which came from the Billiton side of the company--into South32 Ltd. (S32.AU). In late July, it struck a US$10.8 billion deal to exit its shale assets in the U.S., selling most of the oil and gas operations to BP PLCBP, -0.05%
Shareholders in BHP Billiton PLC will be asked to vote on the name change at the annual meeting in October, and owners of Australia-listed BHP Billiton Ltd. at the annual meeting the next month in Adelaide.
https://www.marketwatch.com/story/bhp-to-drop-billiton-from-its-name-2018-09-17
China will send out inspection teams to ensure that its provinces are complying with tough international restrictions on the production of ozone-depleting substances (ODS), government officials said on Monday.
China is a signatory of the 1987 Montreal Protocol, a global treaty that commits countries to phasing out the manufacturing of chemicals that not only contribute to global warming, but are also responsible for depleting the ozone layer, which protects the earth from harmful ultraviolet light.
The country has already eliminated 280,000 tonnes of annual ODS production capacity and has also pledged to speed up efforts to phase out hydrochlorofluorocarbons (HCFC), ozone-damaging refrigerant gases, as soon as possible, said Zhao Yingmin, the country’s vice environment minister, during a briefing.
But Chinese companies have been accused by environmental groups earlier this year of using a prohibited ozone-depleting chemical known as CFC-11, which serves as a blowing agent in the manufacture of polyurethane foam.
Zhao said China would “resolutely crack down” on any violations of the Montreal treaty.
China has a large number of foam manufacturers scattered throughout its regions and has struggled to bring them into line, with inspectors lacking the equipment and the resources to test for ozone-depleting chemicals.
Chen Liang, director general of the Foreign Economic Cooperation Office at the Ministry of Ecology and Environment, told Reuters that inspectors were now paying extra attention to violations and had a policy of “zero tolerance”.
He said inspections had already been completed at 1,700 of China’s 3,000 foam manufacturers, but only a few traces of CFC-11 had been discovered. Authorities are still running investigations to determine if they are truly illegal ODS.
“It will take time for China to eliminate all kinds of ODS,” he said.
Global banks and trading firms are launching the first blockchain-based platform for financing the trading of commodities from oil to wheat, they said in a joint statement on Wednesday.
The platform will be run by a venture called komgo SA, based in Geneva, Switzerland, and is due to go live later this year.
Banks and major trading firms have been testing numerous pilot schemes across commodities over the last few years but this venture will be the first that any firm can join.
The komgo founders include ABN AMRO, BNP Paribas, Citi, Crédit Agricole Group, Gunvor, ING, Koch Supply & Trading, Macquarie, Mercuria, MUFG Bank, Natixis, Rabobank, Shell, SGS and Societe Generale.
Blockchain, originally the platform behind cryptocurrency Bitcoin, is viewed by many as a solution to trade and settlement inefficiencies, and to improving transparency and reducing the risk of fraud.
A high-tech ledger, blockchain uses a shared database that updates in real-time and can process and settle transactions in minutes without the need for third-party verification.
Instead of sharing a mountain of paperwork between a long list of parties, a trader will instead be able to use a digital letter of credit, speeding up transactions considerably.
komgo will first be used for energy. The first trades will be crude cargoes in the North Sea, the benchmark setting region for much of the world’s crude trading.
From early next year, komgo will widen to agriculture and metals.
The firm will work alongside Vakt, an energy trading platform run by many of the same shareholders in komgo.
“The launch of komgo SA highlights a shared vision for industry innovation and underlines the ongoing commitment among members to build a truly open and more efficient network within commodity trading” said Souleima Baddi, Chief Executive Officer of komgo SA.
komgo will provide the financing via blockchain for all commodities and can scale itself up to new and emerging commodities.
The platform will be developed in partnership with blockchain technology company ConsenSys.
Global miner Rio Tinto said on Thursday it will return $3.2 billion to shareholders following the recent sale of some Australian coal assets.
Rio said it will conduct an off-market share buyback for up 41.2 million Rio Tinto Ltd shares, worth about $1.9 billion, and further on-market purchases of Rio Tinto plc (RIO.L) shares.
The buyback is in addition to existing buyback programs, of which $1.7 billion in shares still remains to be purchased and which will be completed by end-February 2019, it said.
Rio, which had announced plans for a $4 billion buyback in August, noted that the sale of its Dunkerque aluminum smelter in northern France was not yet complete, while Norway’s Hydro canceled plans to buy its ISAL smelter in Iceland.
The $3.2 billion in net proceeds comes from the sale of the Hail Creek coal mine and Valeria coal project to Glencore, Winchester South to Whitehaven Coal and the Kestrel coal mine to private equity manager EMR Capital and Indonesia’s Adaro Energy Tbk
.https://www.reuters.com/article/us-rio-tinto-buyback/rio-tinto-announces-3-2-billion-share-buyback-program-idUSKCN1LZ2Z9
Jilin Liyuan Precision Manufacturing, a maker of aluminium products, said on Thursday that it would be unable to make interest payments due Sept. 25.
In a statement posted on the website of the Shenzhen Stock Exchange Thursday, the company said it was unable to make interest payments of 51.8 million yuan ($7.56 million)due to insufficient funds.
It said the company was actively raising funds, and would attempt to make the interest payments as soon as possible.
Unlike the 2012-2015 Western sanctions on Iran, this time around only the United States is slapping sanctions on Iran’s economy and oil industry. But unlike in the previous round of sanctions, the U.S. Administration has now expanded the scope of the petroleum products that fall under sanctions. This time, not only crude oil, but oil products will be affected.
Iran has already started to see the impact of the returning U.S. sanctions, not only on its crude oil exports, but also on its oil product flows.
While analysts and market participants are estimating how much Iranian crude oil will come off the market with the U.S. sanctions, signs have started to emerge that Iran’s refined oil products and condensate flows are also being disrupted, according to an S&P Global Platts analysis, citing trade and market sources and trade flow data.
In a factsheet about the new sanctions on Iran’s oil, the U.S. Treasury says that the scope of “petroleum products” includes—as defined by the U.S. EIA—“unfinished oils, liquefied petroleum gases, pentanes plus, aviation gasoline, motor gasoline, naphtha-type jet fuel, kerosene-type jet fuel, kerosene, distillate fuel oil, residual fuel oil, petrochemical feedstocks, special naphthas, lubricants, waxes, petroleum coke, asphalt, road oil, still gas, and miscellaneous products obtained from the processing of crude oil (including lease condensate), natural gas, and other hydrocarbon compounds.”
Over the past weeks, Iran’s oil product exports have also started to take a hit, according to Platts data and sources.Related: How Iran Plans To Bypass The World’s Main Oil Chokepoint
Iranian fuel oil exports to Singapore collapsed in August, a source in the Middle East fuel oil market told Platts, adding that fuel oil exports to Fujairah and Singapore are expected to slow down.
While Iran’s liquefied petroleum gas (LPG) exports in August jumped to the highest in nearly two years, mostly thanks to China which imposed tariffs on U.S. LPG, Tehran lost customers in East Africa—Kenya and Tanzania have stopped importing LPG from Iran due to the sanctions, according to Platts tracking data and sources.
Iran imports gasoline because insufficient refining capacity and the previous round sanctions had prevented it from expanding its refinery base. According to Platts sources, Iran’s imports of gasoline, which originate from India, North Asia, and South East Asia will be affected by the sanctions.
Join the world's largest community dedicated entirely to energy professionals and enthusiasts
According to ship tracking data compiled by Bloomberg, Iranian oil and condensate exports were below 2.1 million bpd in August—the lowest levels since March 2016, with crude oil exports at their lowest since January this year.
Analysts expect the decline in Iran’s crude exports to accelerate this month and next, putting upward pressure on oil prices.
Bassam Fattouh and Andreas Economou at the Oxford Institute for Energy Studies wrote in a presentation in early September that they expect a total loss of 900,000 bpd of Iranian oil on the market.
The previous sanctions cut 1.22 million bpd of Iranian crude oil exports which averaged 1.1 million bpd between 2012 and 2015, the Oxford Institute for Energy Studies data shows.
Saudi Arabia, the United States and Russia can between them raise global output in the next 18 months to compensate for falling oil supplies from Iran and elsewhere, U.S. Energy Secretary Rick Perry said on a visit to Moscow on Friday.
U.S. sanctions on Iran’s oil exports, which come into force in November, have already cut supply back to two-year lows, while falling Venezuelan output and unplanned outages elsewhere could push up crude prices, hurting consumers.
But Perry, in an interview with Reuters, said he felt comfortable about the outlook for global crude output, and for oil prices.
“I don’t foresee spikes,” Perry said, although he added there was always the potential for unforeseen events.
Some analysts have expressed concerns about Saudi Arabia’s long-term ability to significantly boost output.
But Perry said: “There’s a number of things going on in the kingdom that continue to give me a very positive feeling about their ability to maintain their level and even increase their level” of crude production.
He cited the prospect that Kuwait and Saudi Arabia would soon resolve a border dispute, unlocking access to an oil field in a contested area. “They are working toward a solution in the not too distant future,” he said.
On U.S. production, which has already been growing over the past few years, Perry said: “You look out 18 months, and I think you’ll see even a more substantial increase in the United States because of pipeline capacity being built out.”
Russia, meanwhile, was “working diligently” to deliver its oil output to the world market, Perry said.
GOOD CITIZEN
Perry was in Moscow for talks with his Russian counterpart, Energy Minister Alexander Novak.
Visits by senior U.S. officials are a rarity after relations between Moscow and Washington nosedived, first over the Ukraine crisis and later over allegations of Russian meddling in the U.S. presidential election.
The administration of U.S. President Donald Trump has imposed sanctions on Russia, and Perry said that, while he would rather not see any more, that was a real prospect.
“You avoid that by being a good citizen. You avoid that by obviously tending to this issue with Ukraine, you do this by not meddling in our elections, you do this by not engaging in activities that are considered to be uncivilized, for instance, the poisoning of the people in the UK,” Perry said.
“Russia has the opportunity to send a message that they are going to be good neighbors, they are going to be civilized in the way they deal with their neighbors. That has yet to be seen, from our perspective, in dealing with Ukraine.”
Russia’s conduct toward other countries would influence whether the United States was compelled to impose sanctions on the Russian-led Nord Stream 2 pipeline project.
The project will expand the capacity for pumping Russian gas to northern Europe. Trump has criticized it, saying it will increase European dependence on Russian energy.
Referring to an internationally-brokered roadmap for resolving a conflict in eastern Ukraine between Kiev and Russian-backed separatists, Perry said: “If Russia deals with the Minsk agreement in an appropriate way, there are some signals being sent to the rest of the European Union.”
“Until those signals get sent, the potential sanctions of Nordstream 2 are still very real ... I’ll suggest to you that the ball is in Russia’s court,” he said.
In the interview, Perry issued a message for the European Union, saying it needed to wean itself off its dependence on Russian energy supplies.
“If you’re a country in the European Union and you see how Ukraine has been treated by Russia, then (Russia) being the sole source or practically the sole source of gas to your country will give you a pause,” Perry told Reuters.
“And I think that’s an appropriate and rightful position to take. Have alternatives. Have competition. Have other pipelines,” he said. “So Europe by and large understand that they need multiple sources of energy and we agree with them.”
https://www.hellenicshippingnews.com/category/commodities/commodity-news/
Baker Hughes on Friday reported that the number of active U.S. rigs drilling for oil rose by 7 to 867 this week. The oil-rig count had fallen by 2 last week. The total active U.S. rig count, which includes oil and natural-gas rigs, was also up 7 at 1,055, according to Baker Hughes.
Indian refiners will cut their monthly crude loadings from Iran for September and October by nearly half from earlier this year as New Delhi works to win waivers on the oil export sanctions Washington plans to reimpose on Tehran in November.
India’s loadings from Iran for this month and next will drop to less than 12 million barrels each, after purchases over April-August had been boosted in anticipation of the reductions.
The United States is renewing sanctions on Iran after withdrawing from a nuclear deal forged in 2015 between Tehran and world powers. Washington reimposed some of the financial sanctions from Aug. 6, while those affecting Iran’s petroleum sector will come into force from Nov. 4.
India, Iran’s No.2 oil client behind top buyer China, does not recognize the reimposed U.S. sanctions, but winning a waiver from the restrictions is a must for New Delhi to protect its wider exposure to the U.S. financial system.
India’s oil ministry in June told refiners to prepare for a “drastic reduction or zero” imports from Iran from November.
“Some refiners have either already exhausted or front-loaded their term contract to a large extent, which allows them the flexibility to go to zero if required, or until clarity on the waivers emerge,” Amrita Sen, chief oil analyst at Energy Aspect, told Reuters.
Washington will consider waivers for Iranian oil buyers such as India but they must eventually halt crude imports from Tehran, U.S. Secretary of State Mike Pompeo said last week in New Delhi after a meeting of high level officials.
The Indian government, already facing a backlash over a falling rupee INR=D2 and record high fuel prices, does not want to halt the oil imports from Iran as the Islamic republic offers a discount on oil sales to India.
Government sources said India made this point clear in last week’s meetings with U.S. officials and remains engaged with Washington to work out waivers on its oil purchases from Iran.
“We have a special relationship with both the U.S. and with Iran, and we are seeing how to balance this all, and also to balance out the interest of the refiners and end-consumers,” said one of the government officials.
But if Washington adopts a tough line, India would have no other choice than to end imports from Iran, they said.
CUTTING IMPORTS NEARLY IN HALF
India lifted about 658,000 barrel of oil per day (bpd) from Iran in April-August, according to data obtained from trade sources by Reuters, and the cuts projected for September and October would drop the daily average over those two months by about 45 percent to 360,000-370,000 bpd.
Indian oil refiners have already given the October loading plans to the National Iranian Oil Co (NIOC), sources familiar with the loading schedule said.
Top refiner Indian Oil Corp (IOC.NS) wants to lift 6 million barrels each in September and October, while Mangalore Refinery and Petrochemicals (MRPL.NS) would load 3 million barrels each for those two months, the sources said.
IOC would also lift 1 million barrel for its subsidiary Chennai Petroleum Corp in October, they said.
Bharat Petroleum Corp (BPCL.NS) would lift 1 million barrels in September and skip purchases in October, a company source said on Tuesday.
Bharat Petroleum has already drawn more than its fixed volumes - the amount it is obligated to purchase - that were contracted for 2018/19, its chairman said on Tuesday.
Nayara Energy, part owned by Russian oil giant Rosneft (ROSN.MM), plans to lift 1 million barrels each in September and October, the sources said. But the refiner began reducing its oil imports from Iran in June and aims to completely halt purchases from November.
Suu Kyi defends verdict against Reuters reporters
Hindustan Petroleum (HPCL.NS), Reliance Industries (RELI.NS) and HPCL Mittal Energy (HMEL) have no plans to buy from Iran in September and October, they said.
India refiners - excluding Reliance and HMEL, which do not have term contracts with Iran - will together lift about 73 percent of their fixed contract volumes from Iran by end-October, the loading data showed.
IOC, Nayara and MRPL did not respond to Reuters’ emails seeking comments.
Two of the world’s biggest oil companies are stepping up buying and selling of West African crude at the same time as a new regional swaps market has emerged, as merchants seek new ways to eke out profits in a tough trading environment.
Over the past week, BP Plc bought 7.6 million barrels of Nigerian crude from Vitol Group on a pricing window run by S&P Global Platts, doubling the entire activity of the past seven years, according to data compiled by Bloomberg. An associated swaps market has taken hold over the past two months, with as many as 8 million barrels transacted, people familiar with the derivatives say.
The sudden spurt in activity has surprised many participants in a West African market where cargoes are typically transacted privately. It comes at a time when oil traders are struggling to make money in challenging markets. BP made a rare and unusual loss in oil trading in the second quarter as it was wrong-footed by wild gyrations in U.S. markets.
Hedging Bets
The cash-settled swaps have attracted interest from oil majors and trading houses, with contracts equivalent to 5 to 8 million barrels changing hands since trading began two months ago, according to estimates from people involved in that market. As many as eight companies bought and sold the derivatives, they said.
The swaps, used to hedge or speculate on prices, are based on a basket of four Nigerian grades: Qua Iboe, Bonny Light, Forcados and Bonga, which are among the largest export grades from the West African country. The derivatives allow a buyer to exchange a fixed price for a floating one published by Platts. That means a bidder might profit if Platts assesses that the West African market has strengthened.
Normal Flows
When Nigeria isn’t riven by unrest, shipments of the four grades normally flow at a rate of about 700,000 to 1 million barrels a day, according to loading programs compiled by Bloomberg. They’re also the crudes that BP has been purchasing from Vitol on the Platts window since earlier this month.
While over-the-counter, or paper, trading plays a vital role in setting physical prices in many regional oil markets, especially the North Sea, the West African market doesn’t have its own benchmark, with spot cargoes priced against Dated Brent. Nigerian term cargoes are mostly allocated on the basis of the country’s official selling prices.
Hard Sell
The jump in trading activity comes at a time when Nigerian barrels are being squeezed by the rise of U.S. shale. Most Nigerian crudes are light and low in sulfur, and have therefore been hit hard by surging output of U.S. crudes with similar geological properties. Not only has the U.S. cut imports from Nigeria, but some traditional buyers, such as Taiwan’s CPC Corp., have also turned to American grades.
| DATE | SELLER | BUYER | GRADES | VOLUME | PRICES VS DATED | LOADING |
|---|---|---|---|---|---|---|
| Sept. 6 | Vitol | BP | Qua Iboe | 950k bbl | +$1.70 | Oct. 1-10 |
| Sept. 6 | Vitol | BP | Bonny | 950k bbl | +$1.70 | Oct. 12-16 |
| Sept. 7 | Vitol | BP | Bonga | 950k bbl | +$1.75 | Oct. 28-29 |
| Sept. 7 | Vitol | BP | Qua Iboe | 950k bbl | +$1.63 | Oct. 12-13 |
| Sept. 10 | Vitol | BP | Qua Iboe | 950k bbl | +$1.65 | Oct. 17-18 |
| Sept. 11 | Vitol | BP | Qua Iboe | 950k bbl | +$1.75 | Oct. 29-Nov. 5 |
| Sept. 11 | Vitol | BP | Bonny | 950k bbl | +$1.55 | Oct. 16-17 |
| Sept. 13 | Vitol | BP | Forcados | 950k bbl | +$1.53 | Oct. 11-12 |
| Sources: Traders monitoring Platts window | ||||||
Over the past six sessions, BP bought eight cargoes, including four Qua Iboe for loading from mid-October to early-November. There will be a total of nine shipments of Qua Iboe in October.
Sales of Nigerian cargoes have been slow this year. About 25 out of 60 Nigerian cargoes scheduled for October export remain unsold, while trading will switch to November shipments next week when new programs are released. BP, itself a huge refiner of crude, could try to resell the barrels it’s bought, or process them in its own plants.
While an enduring swaps market could increase liquidity, it wouldn’t help to find new buyers for Nigerian barrels, according to a survey of 5 crude traders involved in the market.
https://www.bloomberg.com/news/articles/2018-09-14/bp-snaps-up-west-african-crude-oil-as-new-swaps-market-emerges
Iran’s OPEC governor said on Saturday that Saudi Arabia and Russia have taken the oil market “hostage” as U.S. President Donald Trump seeks to impose fresh sanctions on Iranian oil sales.
Washington wants to cut Iran’s oil exports to zero by November, and is encouraging producers such as Saudi Arabia, other OPEC members and Russia to pump more to meet the shortfall.
“Russia and Saudi Arabia claim they seek to balance the global oil market, but they are trying to take over a part of Iran’s share,” Hossein Kazempour Ardebili was quoted as saying by SHANA, the oil ministry’s news agency.
“Trump’s efforts to cut Iran’s access to the global crude market has prompted Russia and Saudi Arabia to take the market hostage,” he said.
Kazempour Ardebili told Reuters on Friday that the United States will find it difficult to cut Iran’s oil exports completely as the oil market is already tight and rival producers cannot make up the shortfall.
On Saturday he accused Moscow and Riyadh of welcoming sanctions against Iran for their own gain, and warned that such actions would damage the credibility of OPEC.
“Saudi Arabia and UAE are turning the OPEC into a U.S. tool,” he said.
Under pressure from Trump to lower oil prices, the Organization of the Petroleum Exporting Countries and allies agreed in June to boost production, having participated in a supply-cutting deal in place since 2017.
While OPEC production has increased since then, Saudi Arabia has added less crude than it initially indicated.
The United Arab Emirates’ Brooge Petroleum & Gas Investment Co. plans to float 40 percent of its capital on the London Stock Exchange in October, Chief Executive Officer Nicolaas Paardenkooper said on Sunday.
Brooge Petroleum & Gas Investment (BPGIC) is looking to raise $400 million from Emirati and foreign investors in the IPO, to be conducted in a single tranche, Paardenkooper told Reuters on the sidelines of a company event in Dubai.
The company has already secured strategic investors and plans a roadshow next week in the United States and Europe, he said.
BPGIC has engaged HSBC and First Abu Dhabi Bank (FAB) as advisors to work on the public share sale, sources familiar with the plans told Reuters earlier this month.
The IPO comes as BPGIC plans to boost storage capacity for crude and oil products in the Fujairah oil hub in the UAE.
Speaking at the same event on Sunday, OPEC Secretary General Mohammad Barkindo called on the group’s member countries to continue oil investments to meet future growth in demand.
“We must be able to continue to attract the required investment,” Barkindo said. “Going forward we must focus on continued investments across the (energy) supply chain.”
The UAE is a major OPEC producer and currently holds the OPEC presidency.
Fujairah, located on the east coast of the UAE at the entrance to the Strait of Hormuz, is one of two major bunkering ports in the region along with Oman’s Sohar and is a busy refuelling point for tankers taking crude on long voyages out of the Gulf.
BPGIC, which was set up in 2013, is one of the largest holders of storage assets in Fujairah. It completed the first phase of 400,000 cubic meters of storage across 14 tanks for middle distillates and fuel oil in October and began operations in January 2018.
The company is working on the second phase of its storage terminal, which will add 600,000 cubic meters of capacity for crude oil across eight tanks, it said in a statement on Sunday at the event to officially launch the expansion of its storage facilities.
“By first quarter of 2020, we expect our operations to expand, our storage capacity to rise by 2.5 times and for the first time we will be able to store crude oil,” Paardenkooper said.
The rise in oil prices brought about the recovery of Norway’s oil industry, with companies lining up plans to invest in boosting oil production on the Norwegian Continental Shelf (NCS)—surely most welcome news for Western Europe’s biggest oil and gas producer, which faces a decline from the mid-2020s onwards if new large discoveries are not made soon.
Smaller oil firms, some of which are a result of recent mergers, plan to invest billions of dollars in Norway’s offshore oil and gas over the next five years, launching an unofficial race to see who will become the third-largest oil producer in Norway behind state-participated companies Equinor and Petoro, and the largest independent non-state-held company operating on the shelf.
The three most likely candidates to become Norway’s top independent producer could be investing a combined US$20 billion offshore Norway by 2022, according to Bloombergcalculations.
These companies are Aker BP, the result of a 2016 merger between Aker and BP’s Norwegian unit; Vår Energi AS, the company that will emerge from the merger of Point Resources AS into Eni’s local unit; and Wintershall DEA, the company expected to emerge from the proposed merger between Germany’s Wintershall and DEA.
Over the past year, Aker BP has been actively pursuing acquisitions offshore Norway—it bought Hess Norge last year for US$2 billion, and two months ago it agreed with Total to acquire its interests in a portfolio of 11 licenses on the NCS for US$205 million.
Aker BP has a portfolio with potential to reach production above 330,000 barrels of oil equivalent per day (boepd) from 2023 from existing discoveries, at a compound annual growth rate (CAGR) of 13 percent from 2017, the company said in its corporate strategy update earlier this year. This year’s capital expenditure is set at US$1.3 billion.
Vår Energi AS—the company of the merger of private equity-backed Point Resources AS into Eni Norge AS, which is expected to complete by year-end—plans to invest more than US$8 billion over the next five years to bring projects on stream, revitalize older fields, and explore for new resources. The combined company’s production for this year is estimated at around 180,000 boepd from a portfolio of 17 producing oil and gas fields from the Barents Sea to the North Sea. By 2023, Vår Energi’s production is expected to reach 250,000 boepd, with a breakeven price of less than US$30 a barrel.
Wintershall and DEA, whose proposed merger has yet to be signed and approved, plan to invest US$2.3 billion (2 billion euro) each in Norway. Wintershall plans to invest a total of around 2 billion euro in exploring and developing its fields on the NCS from 2017 to 2020, the company said earlier this year, noting that more than a third of Wintershall’s global exploration budget will be used in Norway.
“With more than 100 licenses and shares in 20 producing fields, we could increase our joint production in Norway to over 200,000 barrels of oil equivalent per day in the near future,” Wintershall CEO Mario Mehren said about the new Wintershall DEA company, which, he noted, would be among the top five oil and gas producers in Norway.
The CEO of DEA, Maria Moraeus Hanssen, for her part, said at a conference in Stavanger last month that “As part of our long-term growth strategy, we are investing more than two billion Euros in our development projects on the NCS.”
Within five years, at least one of those three top contenders for Norway’s largest non-state producer will surpass France’s oil major Total in terms of production, according to Bloomberg calculations. Last year Total was the biggest producer in Norway behind state-participated Equinor and Petoro, with 214,000 boepd.
Lundin Petroleum could also join the race of smaller companies vying to become Norway’s top independent producer, thanks to its 22.6-percent stake in the giant Johan Sverdrup oil field in the North Sea, slated to start production in late 2019 and expected to be the main contributor to Norway’s rising oil production until 2023.
In its corporate presentation last month, Lundin said that its production in 2022, when Johan Sverdrup production will reach plateau, will be 160,000 boepd, double the 2018 production guidance of 78,000-82,000 boepd. Lundin’s production could even exceed 200,000 boepd by 2023, chief executive Alex Schneiter told Bloomberg.
https://oilprice.com/Energy/Crude-Oil/Norways-Offshore-Oil-Boom-Is-Back-On.html
BW Offshore said on Monday that that first oil from the BW Adolo FPSO was safely achieved on September 16, 2018, 18 months after the initial investment was made in the Dussafu license offshore Gabon.
“We have achieved first oil from the Dussafu license within budget and on schedule”, said Carl K. Arnet, the CEO of BW Offshore. “The execution of the Dussafu project confirms the attractiveness of our model by combining proven resources, a resourceful organization and access to production assets to achieve short time-to-oil.”
The Adolo FPSO had previously worked on the Azurite field but was later selected by BW for the Tortue development. The FPSO unit was prepared for deployment at Tortue by a Keppel shipyard in Singapore and officially named FPSO BW Adolo in early April.
The BW Adolo arrived in Gabon in late July and hook up of mooring systems, and installation of risers and umbilicals were completed in September.
The FPSO is installed on the Tortue field, one of five proven discoveries in the Dussafu license. The BW Adolo is a converted VLCC with a production capacity of 40,000 barrels of oil per day. The vessel has undergone an increased life extension scope enabling an extended production profile on the back of positive reserve developments.
Arnet said the priority now is to complete start-up activities and stabilize production on BW Adolo.
He added: “We will at the same time work towards the final investment decision on Tortue Phase 2, which will unlock additional production volumes, and continue the appraisal program of the recently announced discovery at Ruche NE as well as to confirm additional resources and strengthen the commerciality of the Dussafu license,” said Carl K. Arnet.
Ruche results soon
Dussafu is an Exclusive Exploitation Area (“EEA”) of 850 square kilometers located in southern Gabon. The area is valid for 20 years from first oil production. It contains 5 pre-salt oil discoveries, and holds multiple additional prospects and leads. Dussafu is operated by BW Energy and Panoro Energy holds a 8.333% interest.
The development concept entails a current Phase 1 consisting of two horizontal wells tied back to the FPSO BW Adolo.
John Hamilton, Chief Executive Officer Panoro Energy said: “Achieving first oil at Tortue is a material milestone for Panoro, having been involved in the evolution of the Dussafu PSC, from oil discoveries to modern interpretation following the seismic acquisition, and now to first commercial production. We are extremely pleased for all stakeholders in this major production asset in Gabon, and the commencement of oil production at Dussafu represents a significant accomplishment for Gabon and the Dussafu project team.”
Further announcements will be made in due course as to production rates and planning for Tortue Phase 2. In addition, the recent successful well at Ruche North East is currently being appraised following a side track and extensive logging. Results will be announced in the near future, Panoro said.
https://www.offshoreenergytoday.com/first-oil-flows-from-tortue-field-offshore-gabon/
Russia's oil export duty CL-EXPDTY-RU is expected to rise to $137.5 per tonne in October from $130.0 a tonne in September, data from the finance ministry showed on Monday.
The level of the duty is calculated by the finance ministry and is based on the monitoring of seaborne Urals URL-E URL-NWE-E crude oil prices from Aug. 15 to Sept. 14.
Container shipping company Maersk Line has announced a new system of bunker charges for its customers to reflect higher fuel costs as the International Maritime Organization's global sulphur emission limit drops to 0.5%.
The company will impose its new bunker adjustment factor (BAF) from the start of next year, replacing its current standard bunker adjustment factor (SBF) system, it said Monday.
The IMO's global sulphur limit is due to drop from 3.5% to 0.5% from the start of 2020, forcing most shipowners either to switch from burning fuel oil to cleaner, more expensive alternatives, or to install scrubber equipment on their vessels to clean emissions on board.
Maersk's new BAF will be calculated using the average fuel price at a few key bunkering ports around the world and a measure of average fuel consumption for each route. In its announcement Monday the company announced hypothetical BAF rates as an example of how much dry container freight could cost on various different routes at a range of different bunker prices.
At a bunker price of $400/mt on the north Europe to Far East route, the new BAF could be $280/FEU, while at a fuel cost of $700/mt it could rise to $490/FEU, the company said.
The company will initially be using high sulphur 380 CST fuel oil prices to calculate the BAF rate in 2019, before the sulfur cap is lowered to 0.5% at the start of 2020, a spokesman told S&P Global Platts Monday.
Iraq can increase oil production "immediately" to support the market ahead of the implementation of US sanctions on Iran, Iraq's crude sales chief told S&P Global Platts.
The comments from Alaa al-Yassiri, the director general of Iraq's State Oil Marketing Organization, come as officials from the group and its allies led by Russia are debating how to ensure market stability once the sanctions imposed by the order of US President Donald Trump come into force in November. Iran could lose up to 1.4 million b/d of exports by the end of the year, according to the latest projections by Platts Analytics.
"Some increase could be done immediately," said Yassiri referring to Iraq's output. Iraq pumped 4.68 million/b last month, an all-time high for OPEC's second-largest producer after Saudi, according to a Platts survey.
Oil prices spiked briefly above $80/b last week amid growing concern over the loss of Iranian barrels and the lack of spare capacity amongst its OPEC partners outside Saudi Arabia. The kingdom has already increased its shipments significantly to win more market share at Iran's expense.
However, Yassiri also urged OPEC members to support Iran, without elaborating on what specific backing the group can provide Tehran.
"Iran is a founding member state of OPEC, and all the members [of OPEC] should help Iran to get out of its crisis," Yassiri said.
"OPEC is supposed to keep the stability of the market," said Yassiri. "As a result, if there is no stability, there will be damage for the consumers and producers."
Ahead of the upcoming meeting of the joint OPEC, Non-OPEC, Joint Ministerial Monitoring Meeting in Algeria on September 23, Yassiri said member countries with the capacity to increase production should do so if required by the market.
"If the producers, the member states of OPEC, reach the conclusion that supply is less than the demands, certainly we will be seeking a decision for alternatives for members that have the ability to increase," he said.
Iraq, which has only recently returned to production targets set by OPEC, is expected to continue to boost output from fields operated by international oil companies. It has increased production by around 100,000 b/d in both July and August.
CAPACITY EXPANSION
Baghdad has plans to continue to aggressively expand its export capacity. Yassiri said capacity of its Persian Gulf terminals is at 3.7 million b/d, and work continues on the facilities, pipelines feeding them, and the onshore storage facility at Fao to further increase its scale. He said a political deal with the semi-autonomous Kurdistan region and Turkey to utilize a pipeline sending crude from northern Iraq to Ceyhan would "add an amount of 400,000 b/d of exports."
Accessing Kurdistan's pipeline to Turkey and Ceyhan storage would also require commitment that all of the crude would be sold by SOMO, officials have told S&P Global Platts. The fear is that crude would not be handed back over once it reached Ceyhan and would be sold by Kurdistan to cover claims of due payments.
An estimate for 2019 exports is going to be made in November when term contracts for the year are agreed to, said Yassiri.
"We will have a complete plan for 2019, about how much real production we will have, and how much will be consumed locally, and then I'll be informed about the amount available for the exports," he said. "Any amount that the Ministry of Oil decides, SOMO will be able to export it."
Yassiri said a crude swap deal with Iran remains in place, but was delayed by disputes within the Iraqi Customs Commission and the need for additional trucking companies to commit to sending oil from the Kirkuk area into Iran.
One senior North Oil Company official told Platts that around 5,000 b/d is being trucked to Iran, though that is likely to increase over the coming month.
"We already have 500,000 barrels of oil in Iran. And we are trying to reach to 1 million, in order to be a commercial shipment that we could sell it, before November 4," he said, referring to the day sanctions are due to kick in. Trucking "resumed more than a week ago."
TRADING
Yassiri also said there had been progress in expanding an experiment of forming joint ventures with trading arms of international oil companies in an effort to profit more from Iraqi crude after it is initially sold, gain more market share in strategic countries, and increase SOMO's experience in global trade.
While each JV has different aims unique to the partnership, they operate the same: it purchases crude from SOMO and sells it on into pre-agreed markets.
"We are very close to signing a deal with China's CNOOC," Yassiri said. "The Chinese market is very important for us."
This follows a joint venture with China's ZhenHua, which Platts first reported in March.
"With ZhenHua it is to get knowledge about China's market. It is a big market, and ZhenHua is a state-owned company," he said. Currently, the two split the profit of crude that ZhenHua sells into the Chinese market.
In November, he said, SOMO will decide whether to formalize the agreement into a company, in which SOMO will own 50% in addition to profit sharing.
The first such experiment was with Litasco, the crude trading arm of Lukoil. It formed a company, initially called Lima, now renamed Iraq Petroleum Trading.
"Right now, SOMO shares profits, but it doesn't have shares [in IPT]," he said. A decision on that is also set for November.
"We also have very good negotiations with BP, too," he added, without providing any details.
Brazil’s state-run oil firm Petrobras plans to shave another US$10 billion off its huge net debt and increase oil production by as much as 10 percent to 2.3 million bpd in 2019, chief financial officer Rafael Grisolia told Reuters in an interview published on Monday.
Petrobras benefited from the rising oil prices and reported in early August a thirty-fold yearly jump in its second-quarter net income, which also beat analyst expectations.
The heavily indebted company—the world’s most indebted oil company—cut more of its debt in the first half this year. Petrobras’ net debt stood at US$73.662 billion at the end of June 2018, down by 13 percent compared to the end of December last year.
Petrobras is on track to cut that debt to US$69 billion by the end of 2018, despite the fact that it is lagging behind with its US$21-billion asset sales goal, Grisolia told Reuters in New York.
Next year, the company expects to further reduce its net debt by US$10 billion, according to its CFO. The state-held oil firm, which has started to emerge from the huge corruption scandal, has plans to reach a net debt-to- earnings before interest, tax, depreciation, and amortization (EBITDA) ratio of 2 times in 2019, and to continue slashing debt to reach the net debt-to-EBITDA ratio of 1-1.5 times, on par with the ratios at most international oil majors.
At end-June, Petrobras’ net debt/adjusted EBITDA ratio was 2.5 times.
Petrobras currently aims to hit the 1.5 times net debt/EBITDA ratio in 2020, but reaching the goal would hinge on the price of oil and other variables, including foreign exchange rates for the Brazilian reals, Grisolia told Reuters.
Related: The U.S. Calls On Russia To Cap Soaring Oil Prices
In terms of oil production, the company aims to increase output by between 8 percent and 10 percent in 2019 from the expected 2.1 million bpd production this year, the manager said.
Referring to the early October wide-open presidential elections in Brazil, Petrobras has held meetings with economic advisors to candidates, Grisolia told Reuters, but declined to comment on discussions with the candidates’ representatives or on their energy policy strategies.
Russian Energy Minister Alexander Novak said on Tuesday that current high oil prices of between $70 and $80 per barrel were temporary and were mainly driven by sanctions, adding that the long-term price would stand at around $50 per barrel.
Speaking at a meeting of government officials and the heads of domestic oil majors, convened to discuss ways of propping up domestic oil production, he said the $50 per barrel forecast was based on estimates by analysts and oil companies.
“The current situation, related to the price rise to $70-$80 (per barrel), is mainly... connected to the premium in the price linked to the possible risks of sanctions and lower supply,” Novak said.
He didn’t specify which sanctions he was referring to but oil traders are concerned about the potential impact of U.S. sanctions on Iran and the effect on the availability of crude at the end of the year.
Novak said last week that global oil markets remained “fragile” due to geopolitics and production declines in several regions and that Russia was ready to crank up oil output.
Russia has been producing oil at the pace of around 11.21 million barrels per day, near a post-Soviet record high, but Novak warned that the output could sharply fall in a few years if the government fails to introduce measures to spur it.
Novak also said he expected Russia’s oil production in 2018 to total 553 million tonnes (11.105 million barrels per day), up from around 547 million tonnes in 2017, and that production would peak at 570 million tonnes in 2021.
On Tuesday, he outlined several measures aimed at encouraging a boost in oil production, which is declining in West Siberia, the country’s main oil producing region.
The measures include introducing benefits for exploration, greenfields developing, increasing production rates, as well as profit-based tax for all oilfields in West Siberia.
The proposals are yet to be approved by the government and the parliament.
China’s diesel demand has peaked and gasoline will peak in 2025, while natural gas demand will increase over the next two decades to feed a massive gasification campaign, according to a forecast released on Tuesday by a research arm on a state energy group.
The research unit of China National Petroleum Corp also said that China’s total oil demand will top out at around 690 million tonnes a year, or 13.8 million barrels per day (bpd), by 2030.
China, the world’s top crude oil importer, will maintain annual crude oil production of 200 million tonnes, or about 4 million barrels per day, before 2030, CNPC said.
Demand for diesel is waning amid moderating economic growth and tighter environmental scrutiny, while gasoline demand is capped by slowing growth in private car sales and the rise of electric and natural gas-fuelled vehicles.
One of the government’s recent plans is to replace a million heavy-duty diesel trucks, almost 20 percent of the national fleet, with ones that burn cleaner fuels such as natural gas and lower-sulphur diesel, as Beijing ramps up its war on pollution.
This would be a blow to China’s oil refineries, as diesel is a main contributor to its fuel sales revenue.
As additions to China’s refining capacity outpace the nation’s fuel demand growth, more than 50 million tonnes of surplus fuel is forecast for 2050, CNPC said.
The country’s natural gas demand will reach 620 billion cubic metres (bcm) by 2035, CNPC also said. That represents 160 percent growth from the consumption level for 2017.
Domestic gas production is expected to reach 300 bcm by 2035, the forecast said, more than doubling the 147 bcm produced last year.
China’s campaign to clear its skies has increased demand for the fuel and will keep it reliant on imports of liquefied natural gas (LNG) and piped gas.
Demand for the cleaner-burning fuel has risen nearly 17 percent in the first half of the year.
CNPC also brought forward the timeline for peak total energy demand for the world’s second-largest economy to 2035, from a previous forecast of 2040.
Oil firmed on Tuesday on signs that OPEC would not be prepared to raise output to address shrinking supplies from Iran and as Saudi Arabia signaled it was in no rush to bring prices down.
Ministers from OPEC and non-OPEC producers meet on Sunday to discuss compliance with output policies. OPEC sources have told Reuters no immediate action was planned and producers would discuss how to share a previously agreed output increase.
Bloomberg reported on Tuesday, citing unnamed Saudi sources, the kingdom was currently comfortable with prices above $80 per barrel, at least for the short-term.
The news agency reported that while the kingdom had no desire to push prices higher than $80 a barrel, it may no longer be possible to avoid it because of tightening supplies amid U.S. sanctions against Iran.
OPEC and industry sources have previously told Reuters the kingdom was keen to keep the lid on prices at $80 per barrel until U.S. congressional elections to avoid coming under any additional pressure from U.S. President Donald Trump.
“It casts doubts on whether Saudi Arabia will increase output to compensate for the loss of Iranian crude once sanctions come into effect,” said Carsten Fritsch, an analyst at Commerzbank in Frankfurt.
U.S. sanctions affecting Iran’s petroleum sector will come into force from Nov. 4.
Russian Energy Minister Alexander Novak said an oil price between $70 and $80 was temporary and sanctions-driven, adding that the long-term price would stand around $50.
U.S. Energy Secretary Rick Perry said last week in Moscow that he did not foresee any price spikes once sanctions came into effect and was positive about Saudi output.
“Oil markets are in a tug-of-war as Iran sanctions will continue to provide near-term support, while discussions around global demand in the wake of this morning’s tariffs and speculation of further OPEC supply increases should temper upside ambitions,” said Stephen Innes, head of trading at brokerage Oanda.
US Atlantic Coast imports of West African crude oil are expected to decline due to harsh arbitrage conditions made difficult by the large premium of ICE Brent futures over WTI, as well as strong premiums for WAF grades.
Traders tracking these grades exported in the US expect WAF imports to the USAC to fall to virtually zero.
The USAC from May to August imported an average of roughly 24 million barrels a month, of which 8.7 million were from West Africa, data from the Energy Information Agency compiled by S&P Global Platts showed.
"The arbitrage of WAF grades into the US is fully closed," a trader said.
Although negligible in outright terms, WAF arrivals in the region in the four months sampled compared to all foreign imports reached as high as 45.4% in June and as low as 19.8% in July.
Nigerian grades tend to make up 40% of WAF imports and Angolan 20%, the rest coming from smaller more regional grades.
Traders lose money in buying basis Dated Brent and selling basis WTI, implying the arbitrage only becomes possible when local buyers are able to cover the cost of conversion by bidding above, something which prompts them to look at alternatives when the spread is high.
The Brent/WTI spread closed at minus $10/b Monday last week, its highest level since mid-June, data from the InterContinental Exchange showed.
Cargo premiums basis FOB have also made the arbitrage difficult.
Healthy refinery margins in Europe and Chinese demand for Angola helped premiums reach fresh highs towards the end of the summer.
An increased cost of crude at loading will also push the overall price higher for delivery into the US.
Lastly, at a time when everything is becoming more expensive, US refiners are scheduled to enter seasonal maintenance throughout October, taking away the demand for foreign crudes.
The American Petroleum Institute reported that U.S. crude supplies increased by 1.249 million barrels for the week ended Sept. 14., according to sources. The build comes after a sizable decline of 8.6 million barrels for the week ended Sept. 7. Phil Flynn, senior market analyst at Price Futures Group, said the build up was likely a result of Tropical storm Gordon.
The API data also showed supplies of gasoline declined 1.485 barrels, while distillate stockpiles climbed by 1.536 million barrels.
Supply data from the Energy Information Administration will be released Wednesday. Analysts polled by S&P Global Platts forecast a fall of 3 million barrels in crude supplies in the latest week, with inventories of gasoline down 1.6 million barrels and distillates down 282,000 barrels.
Oil majors Shell and Eni will be carefully monitoring a first ruling this week by a Milan judge in one of the energy industry’s biggest corruption scandals for clues to what might be round the corner for them.
The two companies are embroiled in a long-running graft case revolving around the purchase in 2011 of one of Africa’s biggest oilfields - Nigeria’s OPL 245 - for about $1.3 billion.
The case, which involves Eni CEO Claudio Descalzi and four former Shell managers including one-time Shell Foundation Chairman Malcolm Brinded, has spawned legal cases spanning several countries and is expected to drag on for months.
But this Thursday, in a case running parallel to the main trial, a judge will decide, for the first time, whether $1.1 billion of the sum paid was siphoned in bribes to win the license to the field.
Eni and Shell, as well as their managers, deny any wrongdoing.
While the ruling will not tie the court’s hand in the main trial, it will nonetheless constitute a sort of pre-judgment, a legal source involved in the case said.
“It’s clear the ruling will become a first building block in favor of the prosecution or the defense ... it will be a first verdict by a third-party judge on the matter,” the source said.
In a fast-track procedure that began last November, the judge will be called on to decide whether Nigeria’s Emeke Obi and Italian Gianluca Di Nardo, who the prosecution says were middle men, should be convicted in the case or acquitted.
Prosecutors allege Obi received a mandate from former Nigerian oil minister Dan Etete to find a buyer for OPL 245, collecting $114 million. Di Nardo, they said, took $24 million of that amount for putting Obi in touch with Eni.
Those alleged payments were illegal kickbacks, prosecutors say.
Obi and Di Nardo, who have previously denied any wrongdoing, asked for a fast-track trial which under Italian law allows any eventual sentence to be cut by a third.
Etete has previously denied charges of bribery for channeling money from the OPL 245 deal to Nigerian politicians and officials.
Nigeria’s OPL 245 is one of the biggest sources of untapped oil reserves on the African continent with reserves estimated at 9 billion barrels. Because of the ongoing dispute, it has never entered into production.
If found guilty, the individuals on trial face possible jail terms for bribery while the companies face hefty fines.
Enbridge mainline optimisation/expansion could bring on 450k b/d as early as 2020 eliminating a large part of the takeaway capacity issue we are seeing in Canada.
Investors remain too bearish on Canadian heavy oil names.
@HFI_Research
U.S. crude oil refinery inputs averaged 17.4 million barrels per day during the week ending September 14, 2018, which was 442,000 barrels per day less than the previous week’s average. Refineries operated at 95.4% of their operable capacity last week. Gasoline production decreased last week, averaging 10.3 million barrels per day. Distillate fuel production decreased last week, averaging 5.5 million barrels per day.
U.S. crude oil imports averaged 8.0 million barrels per day last week, up by 433,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 7.7 million barrels per day, 6.9% more than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 561,000 barrels per day, and distillate fuel imports averaged 141,000 barrels per day.
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 2.1 million barrels from the previous week. At 394.1 million barrels, U.S. crude oil inventories are about 3% below the five year average for this time of year. Total motor gasoline inventories decreased by 1.7 million barrels last week and are about 8% 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 0.8 million barrels last week and are about 2% below the five year average for this time of year. Propane/propylene inventories increased by 0.1 million barrels last week and are about 12% below the five year average for this time of year. Total commercial petroleum inventories decreased last week by 0.4 million barrels last week.
Total products supplied over the last four-week period averaged 21.4 million barrels per day, up by 4.9% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.7 million barrels per day, up by 2.0% from the same period last year. Distillate fuel product supplied averaged 4.0 million barrels per day over the past four weeks, down by 0.8% from the same period last year. Jet fuel product supplied was up 5.0% compared with the same four-week period last year.
US Lower 48 production up, imports up and exports up
Last Week Week Before Last Year
Domestic Production....... 11,000 10,900 9,510
Alaska ................................. 470 452 462
Lower 48 ........................ 10,500 10,400 9,048
Imports ............................. 8,024 7,591 7,368
Exports ............................. 2,367 1,828 928
Cushing down 1.3 mln bbls
Light sour crude grades from the Persian Gulf have seen spot differentials flip from discount to premium amid firm buying interest from traders and end-users in Asia, market sources said Wednesday.
Now Barrels of light, medium and heavy sour crude grades loading from Middle Eastern ports in November headed to Southeast and Far East Asia have received firm buying interest across the board -- barely a month after trading at substantial discounts.
The rise in spot differentials paid for light sour crude grades such as Abu Dhabi's Murban and Qatar's Land has caught participants by surprise, as the market was thought to have been focused on securing replacement barrels for medium to heavy sour Iranian crudes.
"For mediums and heavies it [higher demand] was expected -- very surprising for the light sour end," a seller of Persian Gulf crude based in Singapore said earlier this month, when the differentials began rising.
Robust refining margins for middle distillates, combined with a closed arbitrage from the West of Suez to Asia, has spurred demand for light sour Persian Gulf crude grades this month, sour crude traders said.
In addition, producers such as ADNOC and Qatar Petroleum slashed official selling prices for lighter crudes earlier this month in line with the discounts seen in the spot market for October loading barrels last month.
Subsequently, November-loading cargoes of ADNOC's light sour Murban and Das Blend crude grades have thus far traded at premiums of around 35-45 cents/b to their respective OSPs.
Qatari light sour Land crude traded even higher, at premiums in the range of 50-60 cents/b to its OSP, sources said.
"EFS is wider and light sweet is going up in price everywhere else, so that will definitely drive the price of light sour up a little bit combined with OSP cuts," a North Asian buyer said.
"The Med and US arbs are not landing cheap any more," said a trader dealing in arbitrage grades for Asia.
The November Brent/Dubai EFS, a barometer of the viability of arbitrage of Brent-linked crudes into Asia, has averaged $3.34/b to date in September. The October EFS averaged $1.85/b in August -- almost 45% lower.
A higher or "wider" EFS number makes it harder to justify selling Brent-linked barrels into Asia, according to traders.
FOCUS ON MURBAN IN MOC PROCESS Active buying interest for Murban crude also emerged in the Platts Market on Close assessment process this week, with four 500,000-barrel clips traded Tuesday.
Oil major Total initially offered a 500,000-barrel cargo of Murban for November loading in the MOC process at a premium 60 cents/b and steadily offered lower until it was bought by trading house Vitol at a premium of 45 cents/b. Cargo was then re-offered and purchased repeatedly, amounting to a total of four trades between Total and Vitol for a total 2 million barrels of November-loading Murban crude.
Total also placed a second Murban offer in the MOC process Tuesday, selling barrels of the crude loading over October 15-November 15 from China's Yangpu port. The offer stipulated cargo sizes ranging from 500,000 to 2 million barrels and was priced on a floating basis against the November Murban OSP plus a differential.
Total initially offered the cargo at a premium of $1.80 to the OSP. At 0830 GMT, it stood at OSP plus $1.20/b FOB Yangpu, to no buying interest.
The MOC process also saw bidding interest for Murban earlier this week when Gunvor placed a bid for 500,000 barrel on Monday. It raised its bid to a premium of 40 cents/b to the November Murban OSP, while an offer from Total for a similar cargo stood at 45 cents/b at 0830 GMT in Monday's MOC process.
The MOC process saw its first ever cargo of Murban crude declared via the partials delivery mechanism late last month; a 500,000-barrel cargo of October-loading Murban declared by Total to Shell, after Total sold its 20th partial of Oman crude to Shell during the August 31 MOC process at $75.95/b.
"I felt like some watcher of the skies when a new planet swims into his ken."
John Keats, "On First Looking into Chapman's Homer"
It’s that "watcher-of-the-skies-when-a-new-planet" stuff, to borrow from PG Wodehouse, who borrowed from Keats. The discovery of a major new oil play like Guyana instils the same sense of wonder on we oil industry devotees. What’s the story? How big could it be? Will it change the oil market?
Few oil producing countries produce more than 1 million b/d. Outside of OPEC you can count them on two hands: Canada, USA and Mexico; UK and Norway; China, Brazil and Oman; Russia and most recently Kazakhstan – the only new member in the 21st century. New admissions to the group don't happen very often.
Guyana, with no upstream oil industry four years ago, has a very good chance of joining this elite group.
What’s the story?
The Hammerhead find last month is the ninth discovery offshore Guyana in three years. The oil-bearing Miocene sandstone formation is the third play unlocked by ExxonMobil, Hess and CNOOC in the Guyana basin following seven discoveries in Cretaceous turbidite sandstone reservoirs and one in Late Cretaceous carbonate reservoirs.
Latin America analyst Ruaraidh Montgomery reckons total reserves on the huge Stabroek block are now in excess of 4 bn boe, most of it oil.
The exploration success rate for commercial discoveries on the block is an astronomical 82%; the global industry average is under 20%.
These reserves will be commercialised in double-quick time. The partners envisage a phased development using floating platforms that will deliver over 750,000 b/d of oil by 2025. The size of reserves and reservoir quality underpin the economics, with project NPV,15 break-even under US$40/bbl.
Production ramp up would be faster than anything ever achieved in a complex of giant fields in frontier deep water. The timing in the cycle is good, the joint venture has been able to leverage spare capacity in the supply sector, and best practice in project execution was honed in the downturn.
Even so, delivering these targets will be a challenge, reflected in our own more cautious forecasts of just under 700,000 b/d two years later.
How big could it be?
The Guyana basin is the westerly ‘third’ of the wider Equatorial Margin, and includes Suriname (a modest onshore heavy oil producer) and French Guiana (one sub-commercial offshore discovery) as well as Guyana. The basin as a whole may hold another 8-10 bn boe of reserves, our estimate of yet-to find (YTF) reserves using creaming curve analysis. This would take the total to three times what’s been found so far in Guyana’s Stabroek block.
A health warning: extrapolating success from a handful of sweet spots can be pretty unreliable, in both directions. It’s worth bearing in mind too the ups and downs explorers have had over the last decade in proving up early breakthroughs across the Atlantic on the analogous West African Transform Margin.
The rest of the Equatorial Margin is in Brazil - the extensive Foz de Amazonas basin and smaller basins where small discoveries have been made in shallow water. These cover a vast area and deep water zones are only lightly explored. There are some doubts as to the source rock quality in places. The industry though is all over the Equatorial Margin - forty-two IOCs and NOCs hold acreage with Total, ExxonMobil, Anadarko, Hess and Equinor the biggest players. We expect around 50 exploration wells to be drilled over the next five years.
The last breakthrough play of similar scale was the Brazilian Santos basin pre-salt. In 2009, three years after the first discoveries, we forecast peak production of 0.9 million b/d.
Today, after 49 pre-salt exploration wells yielding many more discoveries, we expect over 2 million b/d.
This simple metric suggests Guyana itself might be headed for over 1 million b/d of production if exploration succeeds in converting YTF; the broader basin higher still if the plays extend into Suriname and French Guiana.
Will it change the oil market?
Not much on its own, for now at least. Guyana doesn’t look like rivalling Permian tight oil, well on the way from scratch towards 5 million b/d. But it is oil that the market will need to fill the supply gap in the early 2020s as mature provinces decline and demand still growing. And we need more Guyanas, many more.
Perhaps the biggest lesson from Guyana is that it shows the way forward for conventional explorers emerging from the downturn looking for growth opportunities. There are new plays out there, giant oil discoveries waiting to be unearthed and which can compete on full cycle economics.
KRG's Finance Minster #Rebaz_Hamlan has said that the Kurdistan Region exports around 350,000 barrels of Crude oil per day, sells each barrel to $60-63, collects $600m per month/ spends $320m of it to pay public worker salaries & the rest is spent to repay loans by IOCs.
@Chawsawa
Spot premiums for Russia’s ESPO Blend crude oil have hit their highest in more than four years, buoyed by a jump in Chinese demand, multiple trade sources said on Thursday.
Producers Surgutneftegaz and Gazprom Neft have sold three cargoes loading in the first week of November at premiums of $5 to $6 a barrel to Dubai quotes, the sources said, up to $2 higher than deals the month before.
The premiums are the highest since 2014 and have overtaken those for better-quality Russian grade Sokol, according to the sources and Reuters data.
The companies could not immediately be reached for comment.
“It’s quite unusual for ESPO to trade higher than Sokol as it has a higher sulfur content ... than Sokol,” said a China-based trader.
China’s crude demand, which is usually strong ahead of the peak winter season, has been stoked further as some Chinese independent refiners, known as teapots, are snapping up cargoes to use up import quotas by year-end, the sources said.
“They want to receive the crude by end-December for customs records and for winter demand,” one of the sources said, adding that Chinese buyers also typically pile up stocks ahead of Lunar New Year, which falls in February in 2019.
Demand for Russian and Middle Eastern crude priced off Dubai quotes has also been strong this month because of a wider price gap between the Middle East benchmark and Brent, while the upcoming U.S. sanctions on Iran have reduced Iranian oil exports to Asia, traders said.
The average spot premium for November-loading Oman crude, another popular grade among Chinese buyers, has almost tripled from the previous month to about $1.90 a barrel above Dubai quotes, according to Reuters calculations.
For ESPO, Surgutneftega on Tuesday sold a cargo for loading on Oct. 31-Nov. 5 at a premium of about $4.90 a barrel to Dubai quotes, the sources said, declining to be identified as they were not authorised to speak with media.
On Wednesday, Gazprom Neft sold a cargo at $5.40-$5.50 a barrel above Dubai quotes, while Surgutneftegaz sold a second cargo loading on Nov. 3-8 at a premium close to $6 a barrel, the sources said.
The strong premiums took some traders by surprise and they said they doubted the trend would last as Chinese buyers are likely to seek other supplies as their profit margins get squeezed by high feedstock costs.
“It certainly eats into margins badly,” said a Chinese crude buyer.
Russian oil producer Surgutneftegaz (SNGS.MM) is pushing buyers to agree to pay for oil in euros instead of dollars if the need arises, apparently as insurance against possible tougher U.S. sanctions, traders who deal with the firm told Reuters.
Russia has been subject to Western sanctions since its 2014 annexation of Ukraine’s Crimea region, but Washington has threatened to impose extra sanctions, citing what it has called Moscow’s “malign” activities abroad.
The prospect that causes most alarm for Russian firms is inclusion on a Treasury Department blacklist that effectively cuts them off from conducting transactions in dollars, the lifeblood of the global oil industry.
Surgutneftegaz, whose chief executive Vladimir Bogdanov is already on a U.S. blacklist in a personal capacity, declined to respond to Reuters questions.
“We do not comment on our commercial activity,” said the company, Russia’s fourth largest by output.
To date, Russia’s oil industry has been able to weather Western sanctions. In response to restricted access to Western finance and technology, firms have switched to borrowing from Russian state banks and developed their own technology.
Most Russian oil majors, including Rosneft and Lukoil, also sell the lion’s share of output via long-term contracts with clients, giving them more time to work out alternative forms of payment when the contracts expire.
But most of Surgutneftegaz’s exports — around 2 million tonnes per month — is sold through monthly tenders on the spot market, the largest volumes by far among its Russian peers. So it would have only around 30 days to find alternative payment methods.
“AVOIDING PROBLEMS”
Six traders who regularly deal with Surgutneftegaz said the company had been asking buyers to agree to an addendum to their contracts stating that they accept the option of settling payments in euros.
According to a message sent by Surgutneftegaz to one of its customers asking them to sign the addendum, the oil company cited the need to “avoid any possible problems with payment in USD.” Reuters has seen a copy of the message.
Three of the traders said Surgutneftegaz had already begun discussions with its partners last summer about the possibility of settling payments in euros.
But the company was now raising the issue with greater urgency, and had in some cases warned it would reject bids from buyers for cargoes of oil unless the buyers signed the addendum, according to four of the traders.
In its message to customers, Surgutneftegaz did not mention the risk of new sanctions, but two traders said from their interactions with the company it was clear to them that this was the reason behind the change.
“Surgut is afraid of sanctions,” a source in a European oil major which has dealings with Surgutneftegaz told Reuters, on condition of anonymity because he is not authorized to speak to the media.
The U.S. government cannot forbid anyone from using dollars, but it can prevent U.S. banks from doing business with a sanctioned entity.
Most dollar-denominated transactions pass through the U.S. banking system, and those banks, to avoid violating sanctions, can refuse to handle money linked to blacklisted companies or individuals.
It is not clear how widely the Russian oil sector is preparing for the possibility of tougher sanctions.
A source at Gazpromneft, Russia’s third-biggest oil company by output, said most of its contracts already contained a clause on possible payments in non-dollar currencies.
A second source at the company said that when it is drafting supply contracts with customers for 2019, it will make sure they include a non-dollar payment option in all cases.
Several other oil firms also already have clauses in their contracts allowing non-dollar payments under some circumstances, said four industry sources.
TURNING UP THE HEAT
Washington’s decision in April to include on its sanctions blacklist Russian firm Rusal, one of the world’s biggest aluminum producers, signaled to Russian business that Washington was ratcheting up the pressure.
It was the first time a major Russian company with international partners had been blacklisted.
Some elements of the sanctions have been temporarily watered down, but Rusal’s inclusion has disrupted its access to raw materials, led to the cancellation of some orders and prompted some foreign partners to sever ties.
Washington has not spelled out when or how it plans to toughen sanctions further, but it has signaled that they are coming this year, partly in response to the poisoning in Britain of former Russian spy Sergei Skripal and his daughter.
Britain and its Western allies say Russian intelligence agents carried out the poisoning using a military-grade nerve agent, an allegation Moscow has denied.
State Department official Manisha Singh said this month there would be a “very severe second round of sanctions” unless Russia meets a November deadline to comply with international chemical weapons law.
The source in the European oil major said Surgutneftegaz, in its push to arrange the option of payments in euros, was focused on what might happen in November.
There is no indication from Washington if Surgutneftegaz would be a target for the next round of sanctions.
But CEO Bogdanov was included on the Treasury Department list, published in January, of Russian oligarchs with a net worth of $1 billion or more.
In April, the Treasury Department added Bogdanov to its “Specially Designated National” list, freezing any U.S. assets he owns and barring him from travel to the United States.
It said he was being blacklisted “for operating in the energy sector of the Russian Federation economy.”
India’s Chennai Petroleum will stop processing Iranian crude oil from October to keep its insurance coverage once new sanctions by the United States against Iran go into effect, three sources familiar with the issue said.
Iran’s Naftiran Intertrade Co Ltd, a trading arm for state-owned National Iranian Oil Co, owns a 15.4 percent stake in Chennai Petroleum, which has two refineries with a total combined capacity of 230,000 barrels of oil per day (bpd).
In May, U.S. President Donald Trump pulled out of an international nuclear deal with Iran and announced new sanctions against the country, the third-largest producer among the Organization of the Petroleum Exporting Countries (OPEC). Washington is pushing allies to cut Iranian oil imports to zero once the sanctions on the petroleum sector start up on Nov. 4.
United India Insurance has informed Chennai Petroleum that its new annual policy that is set to take effect from October will not cover any liability related to processing crude from Iran, the three sources said. This has forced the refiner to cancel a scheduled loading of 1 million barrels in October, they said.
Indian insurers do not fall directly under the sanctions, but need to hedge their own risk on the Western reinsurance market, which will not accept Iranian exposure.
“It is quite complicated.. reinsurers are quite apprehensive about extending cover for Chennai Petroleum,” said one of the sources, who asked not to be identified because of the sensitivity of the issue.
Chennai Petroleum’s reduced demand will further cut India’s imports from Iran to about 10 million tonnes in October, lower than previous estimates reported by Reuters. .
“Reinsurers have said they can not provide full 100 percent cover. They have agreed to provide support for only 85 percent cover,” said a second source, who also declined to be identified.
Chennai Petroleum, a subsidiary of the country’s biggest refiner Indian Oil Corp (IOC), has a deal to buy up to 2 million tonnes, or 40,000 bpd, of oil from Iran in the fiscal year 2018/19.
IOC imports oil on behalf of Chennai Petroleum.
Chennai Petroleum and United India Insurance did not respond to requests for comment.
With Chennai’s absence, Iran is left with just two Indian clients, Managalore Refinery and Petrochemicals Ltd, and IOC.
State-owned refiner Hindustan Petroleum Corp has already halted purchases due to insurance problems, while Bharat Petroleum Corp boosted Iranian purchases earlier this year and expects to sharply cut Iranian flows once the sanctions take effect.
Nayara Energy is also preparing to halt Iranian imports from November, while Reliance Industries and HPCL-Mittal Energy Ltd have already stopped buying Iranian oil.
A Milan court sentenced two defendants in a Nigeria corruption case to jail on Thursday in what is a first ruling on one of the oil industry’s biggest graft scandals.
Nigeria’s Emeka Obi and Italian Gianluca Di Nardo were both found guilty of international corruption and each given four-year jail sentences, two sources with knowledge of the ruling said.
Lawyers for Obi and Nardo were not available for immediate comment.
Milan prosecutors allege bribes totalling around $1.1 billion euros were paid to win the licence to explore the field which because of the dispute has never entered into production.
The main case – which besides Eni and Shell also involves Eni CEO Claudio Descalzi and four ex-Shell managers including former Shell Foundation Chairman Malcolm Brinded, is expected to drag on for months.
But Obi and Di Nardo, accused of being middle men and taking illegal kickbacks, had asked for a separate fast-track trial which, under Italian law, allows sentences to be cut by a third.
India’s government is planning to ask state oil firms to lock in their crude futures purchase prices, a government source said on Thursday, anticipating a spike when U.S. sanctions on Iran snap back again in November.
The move would be another step to tackle a slide in the rupee, as oil prices are putting pressure on India, which imports some 80 percent of its crude demand. Its currency has fallen sharply this year against the U.S. dollar, amid a wider sell-off in emerging markets.
“The futures should be locked in when crude price is down,” said the source, who is familiar with deliberations on the matter, adding the step should have been taken earlier.
The rupee, Asia’s worst performing currency this year, has depreciated about 12 percent year-to-date against the U.S. dollar, closing at 72.39 on Wednesday, after a record low of 72.99 on Tuesday. Markets were closed on Thursday.
The government is expected to announce a set of measures to discourage non-essential imports to stem the slump in the currency.
Separately, a senior finance ministry official said there was a view that the rupee could weaken further in the next two months if proposed steps failed to kill “speculation in the rupee market”.
“The gap between the announcement of steps and action is creating a space for speculation. We have to stop this,” said the official.
Officials at oil companies said they were open to the idea of locking in futures if the government asked.
A senior official at Indian Oil Corp, a state-owned oil marketing company, said they were considering some options in terms of forward contracts. He declined to give details saying this was “market sensitive information”.
An official at BPCL, another state-owned oil firm, said they were trying to hedge margins, under a policy reviewed every quarter.
BPCL is also studying a proposal to buy dollars directly from the Reserve Bank of India instead of the market, in a bid to quell strong dollar demand that is denting the rupee.
“Whenever, there is sharp volatility in exchange rates, this dollar window is opened. We’re studying the proposal,” he said.
Another official at state-run HPCL said the government had not officially asked for it to examine forward contracts.
“In case it is needed, or the government wants us to, we will then look into it,” the HPCL official said.
The officials declined to be named as the proposals are still under consideration.
India’s risk-averse state-owned refiners have in the past been reluctant to engage in futures trading or hedging strategies, fearing administrative blow-back if bets go wrong.
The refiners typically buy up to 70 percent of their oil needs through term deals and the remainder through spot markets.
Unlike state refiners, private players Reliance Industries and Nayara Energy use hedging tools to lock in costs on the international market.
India’s state-held oil and gas companies continue to explore participation in more oil and gas projects in Russia, Indian Oil Minister Dharmendra Pradhan said at an India-Russia forum on Thursday at which one of the world’s largest energy importers and one of the largest exporters discussed bilateral oil and gas ties.
“Today, Russia is our largest investment destination in the oil & gas sector. I believe that our time tested relationship has no expiry date. Russia will always be a priority in India’s foreign & energy policy and both our countries will remain as a role model for global communities,” Pradhan tweeted after the forum.
Russia, as one of the world’s largest oil and natural gas producers could become an important source to meet India’s energy needs, the minister said. The India-Russia energy ties, including some major investments, are one of the pillars of the bilateral relations, Pradhan noted.
“India has embarked on the path of becoming a gas-based economy. Russian supplies will help us in meeting the objectives of price stability & energy security. Our oil & gas PSUs are continuing to explore their participation in more oil & gas projects in Russia,” the minister added.
Some of the recent deals between Indian and Russian companies include Russia’s oil giant Rosneft selling 15 percent in Vankorneft to India’s ONGC Videsh for US$1.27 billion in 2016. Rosneft subsidiary Vankorneft was set up to develop the giant Vankor oil and gas condensate field in the North of Eastern Siberia.
Last year, Rosneft, for its part, bought 49 percent of India’s Essar Oil Limited.
In another energy relations boost, in June this year, India received its first liquefied natural gas (LNG) cargo from Russia under a long-term supply contract with Gazprom, in a move that Minister Pradhan described as a “historic milestone in India-Russia energy ties” that would diversify India’s energy sources.
US LNG export terminal developer, Freeport LNG has won an approval from the Department of Energy (DOE) for short-term exports from its facility currently being built in Texas.
The US DOE said in a statement it had issued an order on September 6 granting the Freeport LNG project to export up to 2.14 billion cubic feet per day (Bcf/d) of natural gas as LNG over a two-year period to both free-trade and non-free trade agreement countries.
This order authorizes Freeport’s initial commissioning volumes and other exports pursuant to short-term contracts, the statement said.
During this two year authorization period, Freeport LNG will be authorized to export LNG to any country not prohibited by U.S. law or policy.
The two-year export term will become effective on the date of the commencement of the facility’s first export of LNG, currently projected to be in the third quarter of 2019, it said.
The short-term authorization issued to Freeport LNG is not additive to any of the prior long-term export authorizations DOE has issued to the Freeport LNG project.
Rather, the recent short-term order issued to Freeport LNG allows for additional flexibilities to export LNG pursuant to short-term contracts and for the initial commissioning volumes from the project, the statement said.
Freeport will also still be able to export LNG pursuant to its long-term authorizations from DOE.
To remind, Freeport LNG’s first three trains are expected to enter service between September 1, 2019, and May 1, 2020, after being delayed earlier this year due to the effects of Hurricane Harvey that saw equipment lay-yards flooded.
Each of the three liquefaction trains are expected to have a capacity in excess of 5 million tonnes per year. The fourth liquefaction train will have a similar nominal production.
https://www.lngworldnews.com/freeport-lng-secures-short-term-export-permit-from-us-doe/
Oil and gas discovery made with first of two wells in offshore KG basin
Cairn India has made an oil and gas discovery in the offshore Krishna-Godavari basin off south-east India. The company’s parent Vedanta said it had notified the Ministry of Petroleum and Natural Gas
http://www.upstreamonline.com/live/1582377/cairn-india-hits-kg-jackpot
Brazil leftist presidential candidate Fernando Haddad said on Thursday that state oil firm Petroleo Brasileiro SA should be allowed to set prices above cost, breaking from former party policy.
Between 2010 and 2014, former administrations of Haddad’s Workers Party (PT) forced Petrobras, as the firm is commonly known, to keep its fuel prices down as part of a bid to control inflation, which drained the world’s most indebted oil company of billions of dollars as oil prices climbed.
But Haddad said on Thursday that Petrobras should not be used as a tool to combat inflation, although it should also not be given complete autonomy.
“I’m against using Petrobras to combat inflation. Petrobras is a company, it has shareholders,” said Haddad, speaking to a group of foreign correspondents.
Haddad recently replaced former President Luiz Inacio Lula da Silva, who cannot legally run due to a corruption conviction, as the PT’s official candidate.
Although his support is likely to rise with Lula’s backing, Haddad was in fifth place in a major opinion poll released on Tuesday, with 8 percent of the vote.
If no candidate wins a majority in an Oct. 7 first-round vote, as is likely, the top two vote getters will advance to a runoff. Right-wing Congressman Jair Bolsonaro is currently leading in the first-round, and will likely face a centrist or leftist opponent in the second round.
Russia’s largest shipping company Sovcomflot and the Russian Ministry of Natural Resources and Environment on Wednesday signed an agreement on the development of long-term cooperation, including LNG as fuel, in the Russian Arctic zone.
The document was signed by Sergey Frank, President and CEO of Sovcomflot, and Dmitry Kobylkin, Russian Minister of Natural Resources and Environment in Vladivostok.
“The agreement, in particular, provides for the development of proposals for the implementation of comprehensive measures to stimulate the use of new environmentally friendly types of marine fuel, primarily LNG,” Sovcomflot said in its statement.
Ii also includes the development of other “green technologies,” as well as information exchange and joint activities to prevent substandard navigation in the Arctic seas.
“Strengthening the interaction between business and government agencies to protect the fragile environment of the Arctic is becoming critically important amidst increasing traffic along the Northern Sea Route,” Frank said in the statement.
Worth mentioning here, Sovcoflot ordered earlier this week two LNG-fuelled aframax tankers at the new Zvezda Shipbuilding Complex in a push to reduce emissions.
The vessels will have a deadweight of 114,000 tonnes and a 1A/1B ice class, which makes them able to operate all year round in areas with difficult ice conditions, including sub-Arctic seas and Russian ports of the Baltic region.
https://www.lngworldnews.com/russias-sovcomflot-in-lng-fuel-push/
Several independent Chinese refineries are drawing up plans to build petrochemical complexes in east China’s Shandong province, aiming to join an investment boom in the world’s top chemicals market.
China is allowing greater access by global players and independent local companies to build new plants to help narrow an import gap of plastics, rubber and polyester as middle-class consumers chase high-end goods from cars to electronics.
U.S. major Exxon Mobil Corp and Germany’s BASF have announced multi-billion-dollar investments over the past two months as they look to rival local firms like Hengli Group and Zhejiang Rongsheng.
Facing tight cash flows and fierce competition in a saturated fuel market, China’s small refiners, known as “teapots”, are also eyeing petrochemicals as a potential growth area, although analysts warn they will face big challenges in logistics and funding.
“The widely accepted notion among Shandong refiners is that if you don’t move into petrochemicals quickly enough you’ll die faster,” said an executive at a Shandong refiner.
Shandong Shouguang Luqing Petrochemical Corp and Shandong Chambroad Group have each hired a state-run engineering firm for plant design, including processing technologies and capital spending estimates, said a second industry executive with knowledge of the matter.
He did not give details of products or plant size being considered, but said that for a petrochemical complex to be competitive it needs at least a 1 million tonne per year (tpy) ethylene plant plus about a dozen units making products from polyethylene to aromatics.
The two executives declined to be named as the plans are at an early stage and not yet public. Media relations officials at Chambroad and Shouguang Luqing declined to comment.
Other teapots have been mulling similar projects.
Wanda Tianhong Group is waiting for government feedback after submitting in March a proposal to build a 1.2 million tpy ethylene facility in Dongying, said a company executive.
Shandong Lihuayi Group is eyeing a 1 million tpy plant to make paraxylene, an intermediate for polyester, said a company official.
China’s nearly 40 independent refineries enjoyed several years of bumper profits after they were allowed to process imported crude oil in 2015. But their fortunes have dwindled due to tighter tax scrutiny and a ban on fuel exports, while looming competition from newer, larger private refiners is set to squeeze margins further.
Some have already moved into new areas. Shandong Haike Group opened a new factory that makes electrolytes used in lithium batteries for electric vehicles in April.
The push into petrochemicals, however, would involve a minimum spend of at least $2 billion, analysts said, which would pose challenges.
“Large state-owned banks will be reluctant to loan to teapots for such large fixed asset spending because of the uncertain prospects,” said an executive at a Shanghai-based state-owned lender who funds teapots for oil imports.
Located inland with no easy access to deep-water berths, Chambroad and Luqing and similarly located Shandong refineries are at a logistical disadvantage compared with petrochemical plants in coastal areas and closer to consumers.
“I doubt any teapot in Shandong can invest in big ethylene plants under current circumstances. It needs large capex,” said Seng-Yick Tee of consultancy SIA Energy.
UK labour union Unite has agreed to suspend strike action that had been set for Monday at Total's North Sea oil and gas platforms following new proposals on working conditions put forward during talks Thursday.
In a statement, Unite said it would put the latest proposals to its members.
The series of 12- and 24-hour strikes at the Alwyn, Dunbar and Elgin-Franklin complexes began on July 23 and has hit oil and gas output at the sites. Monday would have seen the sixth daily strike.
Gas production has been reduced by as much as 13 million cu m/d and oil output by 70,000 b/d during the industrial action. Much of the oil component feeds into the Forties pipeline, source for the UK's main crude export blend.
"Unite can confirm that further proposals were put forward at ACAS talks with Total," it said late Thursday.
"Unite will now postpone Monday's (17 September) scheduled industrial action to allow our members to take part in a consultative ballot," it said.
Earlier in the week, Unite had said it was still a "significant way" off from agreement.
Further strikes are still scheduled for October 1, 15 and 29.
The dispute centers on Total's demands for all its North Sea offshore workers to accept three-week offshore shifts.
It partly reflects variations in the contracts of different members of the workforce, resulting from Total's takeover of Denmark's Maersk Oil this year, which meant some workers were offshore for two-week stints.
Total has defended three-week stints as necessary for the viability of its North Sea business.
Total had said it had exhausted the negotiation process, but then agreed to mediation by the industrial mediation service ACAS.
Matador Resources was the anonymous purchaser of drilling rights in the Permian shale that fetched a record $95,000 acre. The shares dropped the most in more than a year.
Chief Financial Officer David Lancaster confirmed on Wednesday that the record lease was part of the $387 million the Dallas-based company spent on 8,400 net acres in the Permian’s Delaware basin. The U.S. Bureau of Land Management, which conducted New Mexico auction last week, had identified the winning bidder as Federal Abstract Co., a firm in Santa Fe that bids on behalf of anonymous investors.
“We’re comfortable in what we paid,” Lancaster said by telephone late Wednesday. “We feel it’s some of the best acreage in New Mexico.”
The leases are for a 10-year term and a royalty of 12.5%, Lancaster said. That gives operators better terms than Texas properties on the other side of the border, where leases typically last up to five years with about 25% royalties.
Still, Matador’s shares dropped 7% in New York, the most since August 2017. West Texas Intermediate, the U.S. benchmark oil price, fell 2.5% to $68.59/bbl on Thursday.
Matador hiked its production and capital spending targets after crude output from the Delaware Basin exceeded the company’s expectations so far this year, according to a statement last month. The purchases won’t affect its 2018 capital budget as they won’t be drilled until late next year, Matador President Matt Hairford said by phone.
“The acquired acreage includes 2,800 acres in the State Line Area, the most prolific portion of the Permian, in our view,” Scott Hanold, an analyst at RBC, said in the research note to clients. All leases purchased by Matador were for land in Lea and Eddy Counties in the state.
The hefty price tag is causing some analyst jitters, since it amounts to about 10% of the driller’s $3.7 billion market value, Neal Dingmann, analyst at SunTrust Robinson Humphrey Inc., said in a research note to clients Wednesday.
The purchased segments of land will allow the company to drill longer laterals of up to two miles or more. Since the late 1990s, when fracking began, shale production has meant drilling sideways, pumping water, sand and chemicals at high pressure to create cracks in rock deep in the ground to release oil.
“Slightly under half the acquired position offsets existing Matador acreage, while the other half is blocky and in well-established and very prolific areas,” Dingmann said in the note.
Matador now holds rights to a total of 123,800 net acres in the Delaware. The sale was a record-setter for the state, raising a total of $972 million for bids on 142 parcels of land.
https://www.worldoil.com/news/2018/9/14/matador-revealed-as-mystery-buyer-in-record-permian-auction
South Korea, the world’s second buyer of liquefied natural gas (LNG), received 2.92 million tonnes of the chilled fuel in August, a rise of 12.4 percent year-on-year.
Compared to the previous month, LNG imports rose 6 percent, according to the customs data.
The data shows that South Korea paid $1.54 billion for LNG last month. This compares to $1.1 billion in August last year.
Qatar, the world’s top LNG producer, remained the dominant source of South Korean imports with 0.93 million tonnes of the chilled fuel imported from Qatar in August, almost flat on year.
Australia was the second-largest LNG supplier to Korea last month with 513,795 mt, followed by Indonesia with 381,926 mt, Oman with 362,009 mt and the US that supplied 342,406 mt of LNG.
The remaining volumes imported into South Korea last month were sourced from Malaysia, Peru, Egypt and Equatorial Guinea, the data shows
https://www.lngworldnews.com/south-korea-boosts-august-lng-imports/
USD Partners LP has begun expansion work at one of Canada’s largest crude by rail loading terminals, which will boost capacity at the facility by 50 percent and be completed by year end, the head of the company’s Canada unit told Reuters.
The expansion at Hardisty, Alberta, will increase loading capacity to three 120-car unit trains per day, or roughly 225,000 barrels, to meet strong demand from both producers and refinery customers amid pipeline bottlenecks, said Jim Albertson, senior vice president of parent USD Group’s Canadian Business Unit,
The group operates a network of oil and fuel loading, unloading and storage terminals across North America.
“We have started the process of expanding the (Hardisty) terminal by the equivalent of one train a day. That is planned to be, by the year end, in commission,” he said in an interview on Friday, declining to say how much the expansion would cost.
The terminal currently has loading capacity for two 120-car unit trains per day.
The expansion comes at time when new pipeline projects are facing long delays and the discount on Canadian oil has widened to its biggest spread in nearly five years.
Canada’s crude by rail exports hit a record of nearly 205,000 barrels per day (bpd) in June as rising oil production in Western Canada has outstripped pipeline capacity. Exports are expected to top 300,000 bpd by year-end and continue rising in 2019 as producers and railways sign transport deals.
Houston-based USD’s plan will add a second set of loading arms and a new inside loop, allowing trains to be loaded from both sides of the existing rack at once, Albertson said.
Loading terminals are needed to get the oil onto the trains.
USD Partners said last month that it was “evaluating a potential expansion” at Hardisty, a major Canadian oil hub northeast of Calgary, due to strong customer demand, but it has not previously confirmed the project was moving ahead.
Albertson said that partner Gibson Energy Inc will be ready to flow higher volumes of oil to the facility by year-end and that railway operator Canadian Pacific Railway Ltd is also on board, though the shift to three trains per day will not be immediate.
“The ramp-up will be very gradual in the first quarter (of 2019), which will allow us to make sure that everything is seamless on the loading and outbound operations,” said Albertson.
A spokesman for Gibson declined to comment on the project status but said the company would be ready to supply increased volumes of crude as soon as needed. A spokesman for CP did not offer an immediate comment.
Reuters reported this month that major oil producer Cenovus Energy Inc had signed a deal with Canadian National Railway Co to move more crude by rail.
USD canceled a previous planned expansion at Hardisty in 2016, which would have doubled capacity to four unit trains per day. That expansion would have required major new infrastructure and a federal environmental review.
Egypt has signed a deep-water oil and gas exploration deal with Royal Dutch Shell and Malaysia’s Petronas worth around $1 billion for 8 wells in the country’s West Nile Delta, the petroleum ministry said on Saturday.
The country also signed a second $10 million deal with Rockhopper, Kuwait Energy and Canada’s Dover Corporation for exploration in the Western Desert, a ministry statement said.
Egypt aims to be a regional hub for the trade of liquefied natural gas (LNG) after a string of major discoveries in recent years including Zohr, which holds an estimated 30 trillion cubic feet of gas.
There is no doubt that the U.S. NGL market has entered a period of disruption unlike anything seen in recent memory. Mont Belvieu fractionation capacity is, for all intents and purposes, maxed out. Production of purity NGL products is constrained to what can be fractionated, and with ethane demand ramping up alongside new petchem plants coming online, ethane prices are soaring. But that’s only a symptom of the problem. Production of y-grade — that mix of NGLs produced from gas processing plants — continues to increase in the Permian and around the country. Sooo … If you can’t fractionate any more y-grade, what happens to those incremental y-grade barrels being produced? How much can the industry sock away in underground storage caverns? Does it make economic sense to put large volumes of y-grade into storage if it will be years before it can be withdrawn? — i.e., “you can never leave.” And what happens if y-grade storage capacity fills up? Today, we begin a blog series to consider these issues and how they might impact not only NGL markets, but the markets for natural gas and crude oil as well.
Fractionation, the process of splitting natural gas liquids (NGLs) into purity products — ethane, propane, butanes and natural gasoline — is as important to the NGL market as refining is to the crude and products markets. In fact, the functions are quite similar — take a raw material with no direct use and transform it into usable products. We’ve talked often about fractionation here in the RBN blogosphere, going back to oldies but goodies like Can Mont Belvieu Handle the NGL Supply Surge? and Talkin’ ‘Bout My F-F-Fractionation. Earlier this year, as fractionation capacity constraints started to become an issue, we kicked off a blog series on Mont Belvieu and other Texas fractionators (see Magical Mystery Tour, Part 7), and in We're Not in Kansas Anymore - Conway vs. Mont Belvieu, we showed how fractionation capacity constraints were the primary culprit behind the blowout in NGL price differentials between the NGL market hubs at Mont Belvieu (TX) and Conway (KS).
In those blogs, we considered the implications of a tight fractionation market, but did not get the NGL heebie-jeebies. So what has changed? The answer is mostly one of magnitude. The situation is quickly becoming more dire. Fractionation capacity in Mont Belvieu, the rest of Texas and Louisiana is running at or near full capacity. Railcars of “x-grade” NGLs (mixed NGLs with less ethane than y-grade that can be transported by rail) are fanning out across the country looking for open fractionator space. Marcellus/Utica fractionators are being inundated with barrels from as far away as the Permian. Some midstream companies that move y-grade from the Permian through Mont Belvieu fractionation are said to be charging between 70 and 80 c/gal for spot transportation and fractionation fees (T&F), up from 15 c/gal before all this started.
Ethane Price
There is more evidence that mayhem is afoot when we look at NGL price relationships. In fact, ethane tells a big part of the story. Since mid-May 2018, the price of Mont Belvieu ethane has more than doubled, from 25 c/gal to 55 c/gal on Friday (September 14), according to OPIS (Figure 1). All measures of ethane value that we monitor here at RBN are back to levels not seen since 2012. Ethane is now three times the price of natural gas on a per-Btu basis (see graphics in RBN Spotcheck). The last time we saw that was May 2, 2012. The ethane price is up to 34% of West Texas Intermediate (WTI) crude oil. Last year at this time, it was 20%. The frac spread, where ethane is a big component, is up to $8/MMBtu, the highest level since crude prices crashed in 2014 (see Help! for more on the frac spread calculation).
Figure 1. Mont Belvieu Ethane Price. Source: OPIS
Two things are driving this dizzying ascent of ethane prices. First is increasing ethane demand from all the new U.S. ethane-only crackers coming online plus growing ethane exports (see Ethane Asylum). The second factor is the focus of this blog: the fractionation capacity constraint. Maxed-out fractionation capacity caps ethane production. Ethane can’t be delivered to petchem plants or export docks until it has been fractionated. But not only does fractionation capacity cap ethane production, there is a more nefarious process at work. Even though ethane prices are now three times natural gas prices, ethane rejection (the sale of ethane as natural gas) is on the rise. That is because processors are rejecting ethane to make room for the fractionation of propane and the heavier NGLs. There are all sorts of quirks that happen when rejection is driven by fractionation capacity constraints instead of natural gas-versus-ethane value economics, not the least of which is that lowering the ethane content of incoming y-grade actually reduces the effective capacity of the fractionator (more on that math in an upcoming blog). But regardless of the math, the net result is lower ethane supply just when ethane demand is cranking up. No surprise that ethane prices are skyrocketing.
Mont Belvieu vs. Conway Price Differentials
For another piece of evidence that we’re in uncharted territory, we need to look no further than the differential — the basis — between NGL prices in Mont Belvieu and Conway. Back in July, when we examined this phenomenon (We're Not in Kansas Anymore), Mont Belvieu ethane was 23 c/gal over Conway, propane was higher by 20 c/gal, normal butane by 26 c/gal and natural gasoline by a dime. In that blog, we concluded that since the wide differentials were happening to all NGLs, then it is reasonable to assume that it is happening to that mix of all NGLs — y-grade.
We traced the basis blowout back to three culprits:
Not enough pipeline capacity that can move purity products fractionated in Conway to Mont Belvieu.
Unit trains of propane coming into Conway from the Marcellus/Utica due to the Mariner East fiasco (delays in completing Mariner East 2 and the Mariner East 1 outage this summer).
The Mont Belvieu fractionation capacity constraint. It does no good to move additional y-grade from Conway to Mont Belvieu if there is no fractionator capacity there to process the mixed NGLs into purity products.
Consequently, even though there is sufficient pipeline capacity to move more y-grade south from Conway to Mont Belvieu, and pricing for purity products is far better in Mont Belvieu than in the Conway market, the lack of fractionator capacity acts like a constraint on regional y-grade flows. As shown in Figure 2, since July, the differentials have continued to widen. Mont Belvieu ethane is now almost THREE TIMES the price of ethane (in E/P mix) in Conway, a 40 c/gal differential. Propane is 30 c/gal higher, normal butane is higher by 34 c/gal and natural gasoline by 32 c/gal. That is solid evidence that the fractionation capacity problem is getting worse.
Figure 2. Mont Belvieu vs. Conway Price Differentials. Source: OPIS
Texas Fractionation Capacity Utilization
You might think it would be relatively easy to confirm that fractionation capacity is fully utilized, but it turns out to be a fairly convoluted exercise. That’s because not all y-grade from Texas gas plants and pipeline inflows from the Midcontinent and the Rockies (PADDs 2 and 4, respectively) moves to Mont Belvieu. Also, it is difficult to split out y-grade pipeline flows from purity product flows. And fractionation capacity is not a constant — it changes based on a number of factors, the most important of which lately is the percentage of ethane in the mixed NGLs. But do the capacity calculation across all of Texas and factor in a few assumptions, and it’s possible to come up with a reasonable estimate of what is going on, shown in Figure 3. This just confirms what market prices have already told us: Utilization is at the ragged edge of capacity.
Figure 3. Texas Fractionator Capacity vs. Production and Inflows. Source: RBN
Market Implications
We’ve seen that the shortfall in fractionation capacity can cap production of purity products, tightening the market and driving prices up. And lack of fractionation capacity can drive down the prices of the components of y-grade in other locations (e.g., Conway) because there is nowhere for the y-grade to go. But more significant problems may lie ahead. That’s because y-grade production has continued to increase: Even in the face of Permian crude and gas pipeline constraints (see Hell in Texas and No Time), total y-grade from U.S. gas processing plants is up 500 Mb/d over the past year alone.
Assuming y-grade production continues to increase, with fractionation maxed out, where will the y-grade go? In fact, the market is already dealing with this problem. Some y-grade is going into storage. Several major players are said to have millions of barrels of y-grade in storage, and are converting purity product storage caverns into y-grade service to store even more. Other y-grade is being piped to Louisiana for fractionation, but that outlet is understood to be filling fast. Still more y-grade (or more accurately, x-grade) is being shipped all over North America by rail and truck, again filling that distant capacity to the point where locals are concerned with getting their own barrels fractionated.
RBN’s outlook is that this is not a short-term phenomenon. Yes, there are new fractionation projects in Mont Belvieu and elsewhere in Texas coming online over the coming months and years (see Magical Mystery Tour), but at the rate of production growth we expect, it won’t take long for those fractionators to fill up. Certainly, when all the new Permian crude oil and gas pipes start coming on in late 2019, there will be a surge of y-grade accompanying those volumes.
So what happens if production continues to outpace fractionation capacity? Presumably, at some point, there is no more storage capacity for y-grade. How about exporting the surplus? That’s what happens with purity products like ethane and propane. While theoretically possible, exports of y-grade are extremely problematic — there are no appropriately configured docks or ships. Consequently, if storage is full, production must be curtailed. But here’s the catch: Y-grade gets produced as a byproduct along with associated and “wet” gas production. The only way to dial down y-grade production is to dial down the production of associated gas (which means pulling back on crude oil production), or to reduce wet gas production — or both. That would be an unprecedented market development.
Could such a scenario happen? Crude and gas curtailments because of NGL fractionation capacity constraints? Seems improbable. But stranger things have happened in these markets. We know one thing for sure. Producers and processors with firm fractionation deals are a lot happier today than those without those firm arrangements.
https://rbnenergy.com/hotel-fractionation-far-reaching-impact-of-the-unprecedented-shortfall-in-ngl-fractionation-capacity
Asian middle distillates back-pedaled in the second week of September, tracking weaker demand which saw the gasoil and jet market giving up some of its gains from the start of the month. In the Asian gasoil market, sentiment was still buoyant for the benchmark FOB Singapore 10 ppm sulfur gasoil grade with traders saying that demand continued to be steady even as regional supply balances were still seen limited.
The front-month October/November Singapore gasoil timespread remained rangebound over the same period to be assessed at plus 66 cents/b Friday, up a cent/b from the start of the week.
Meanwhile, the Q4/Q1 timespread dipped 11 cents over the week to be assessed at plus 94 cents/b Friday.
Traders said late last week that while the cash differential for the FOB Singapore 10 ppm sulfur gasoil grade has been rangebound for a while now, it was more a function of the product having found equilibrium in the market.
"It's at quite an acceptable level for both sides, sellers as well as buyers," a trader said last week.
"It [the FOB Singapore 10 ppm sulfur gasoil cash differential] may be rangebound, but it's maintaining on the high side. And while further push-up may be harder, it's still the high demand season where we see winter demand activities in Korea and Japan for stockpiling kerosene. The recent typhoons in North Asia are also supportive factors as some refineries had to suspend loadings due to weather-related issues," he added.
At the Asian close Friday, the cash differential for 10 ppm sulfur gasoil loading from Singapore was assessed at plus 60 cents/b to the Mean of Platts Gasoil assessments, FOB Singapore, down 3 cents/b from Thursday.
Looking ahead, market participants were heard to be awaiting the results of the very first gasoil buy tender from the Philippines' PNOC Exploration Corporation.
The company issued a tender on August 24 for 50,000 mt of 50 ppm sulfur gasoil, with a view of subsequent shipments of up to four gasoil cargoes per month, for up to one year, after negotiations with the potential seller. PNOC's tender closed on September 13, but results could not immediately be confirmed Monday.
EXCESS LENGTH WEIGHS ON JET FUEL
Meanwhile, sentiment in the co-distillate jet fuel market weakened, in line with continual weakness in the physical market as buying appetite remained dull approaching the end of peak summer travel season.
In addition, market sources added the region was saddled with ample supply as a closed arbitrage to move barrels from Asia and the Middle East to the west of Suez has trapped surplus barrels in the region.
The front-month October/November timespread for the same period flipped into a contango structure to minus 15 cents/b Thursday on weak fundamentals. This marked a 59-week low for the jet fuel timespread but on Friday, the timespread improved slightly to minus 9 cents/b.
The quarterly Q4/Q1 spreads were also down to plus 44 cents/b Friday, marking a plus 33 cents/b decline from the start of the week.
FOB Singapore cash differentials for physical cargoes fell by 10 cents/b from the start of the week to minus 43 cents/b to Mean of Platts Singapore jet fuel/kerosene assessment on September 12, before rebounding to minus 19 cents/b on Friday.
Market participants were eyeing award details from Qatar Petroleum for the Sale of Petroleum Products, or QPSPP's tender to supply 240,000 mt of Pearl GTL jet fuel for loading from Ras Laffan over October-March, 2019.
Several market observers also noted that results from Bahrain Petroleum Co., or Bapco's could likely set the tone for jet fuel cargo premiums loading from the Arab Gulf region. The refiner is closing a sell tender to supply 40,000-60,000 mt of jet A-1 fuel on September 17. The cargo is slated for loading from Sitra over October 7-10.
Spain’s Cepsa will sell a stake of about 25 percent in an initial public offering that sources close to the matter expect to value the company at around 10 billion euros ($11.6 billion), making it one of the largest oil company listings in a decade.
The listing, expected in the fourth quarter, will be for a 25 percent stake prior to any greenshoe option whereby more shares could be sold depending on demand, according to the company, owned by Abu Dhabi state investor Mubadala.
The price range and implied market value are still to be decided, Cepsa added in a statement.
A recovery in oil prices in recent months, after a deep sell-off that started in 2014, has analysts expecting an acceleration of public listings of oil and gas companies.
Rothschild is the sole financial adviser of the Cepsa deal, while Banco Santander, Citigroup Global Markets Limited, Merrill Lynch and Morgan Stanley are acting as joint global coordinators and joint bookrunners, Cepsa said.
The flotation is subject to market conditions, Mubadala said in a separate statement.
Cepsa will also continue with plans for a private placement of shares that could take place alongside the public share sale, a source with knowledge of the matter told Reuters.
Cepsa employs more than 10,200 people and has fields in Latin America, North Africa, southeast Asia and Spain, with a total production of more than 175,000 barrels a day of oil equivalent.
The company is also a significant player among European oil refiners, with a processing capacity of 483,000 barrels a day in Spain.
Cepsa set aside more than 1 billion euros for new investments in 2018, its chief executive Pedro Miro told Reuters in an interview in November 2017.
After years of stakebuilding in Cepsa, the Abu Dhabi sovereign wealth fund bought the remaining shares it did not already own from France’s Total in 2011, valuing the Spanish company at around 7.5 billion euros.
September 17th, 2018 – Cheniere Energy, Inc. announced today that its subsidiary Cheniere Marketing, LLC has entered into a liquefied natural gas sale and purchase agreement with Vitol Inc.. Under the SPA, Vitol has agreed to purchase approximately 0.7 million tonnes per annum of LNG from Cheniere Marketing on a free on board basis for a term of approximately 15 years beginning in 2018. The purchase price for LNG is indexed to the monthly Henry Hub price, plus a fee.
“We are pleased to announce this long-term SPA with Vitol, one of the fastest growing players in the global LNG market,” said Jack Fusco, Cheniere’s President and CEO. “This agreement continues Cheniere’s commercial momentum and supports our growth plans, while demonstrating the value LNG buyers place on Cheniere’s unique ability to offer flexible solutions tailored to the needs of LNG customers worldwide.”
Russell Hardy, Group CEO at Vitol said “We are delighted to be working with Cheniere, a pioneer in U.S. liquefaction. Vitol is committed to the long-term development of the LNG market. We believe that LNG has an important role to play in the future energy mix and that its evolution will require a more flexible and tradeable LNG market.”
https://www.vitol.com/cheniere-and-vitol-sign-15-year-lng-sale-and-purchase-agreement/
LyondellBasell Industries 263,776 barrel per day (bpd) Houston refinery was flaring on Monday afternoon due to a malfunction at Royal Dutch Shell Plc’s nearby Deer Park, Texas chemical plant, according to Gulf Coast market sources.
The Shell chemical plant takes fuel gas supplied by pipeline from the Lyondell refinery, the sources said. Compressors that transport the fuel gas from the pipeline into the chemical plant were said to be malfunctioning on Monday afternoon.
US LNG engineer KBR and compatriot ConocoPhillips are working on the design of a mid-scale liquefied natural gas train that is expected to be available for new projects starting in 2019.
KBR and ConocoPhillips have agreed to complete a front-end engineering and design (FEED) quality reference design for a mid-scale capacity LNG train (1.5 – 3.0 MTPA) suitable for a wide range of feed gas and ambient temperature conditions, according to a KBR statement on Monday.
The integrated design approach will utilize ConocoPhillips’ optimized cascade process technology and will be constructed with integrated modularized construction.
Work began with ConocoPhillips in 2017 with KBR applying their SmartSPENDSM methodology to achieve cost reductions for LNG facilities using the optimized cascade process technology, the statement said.
“Building on this experience and responding to demand in the marketplace, the parties decided to focus on developing a mid-scale LNG solution that achieves low unit costs and fast deployment while maintaining high efficiency and operability,” KBR said.
The duo will also continue to cooperate on large scale LNG trains utilizing similar methodology and technology.
KBR has delivered approximately one third of the world’s current LNG production capacity and has been consistently active in the LNG industry for over 40 years, the statement said.
The ConocoPhillips optimized cascade process is utilized in LNG plants producing about 23 percent of the world LNG supply, it said.
https://www.lngworldnews.com/kbr-conocophillips-partner-on-mid-scale-lng-solutions/
Enbridge Inc. agreed to acquire the shares it doesn’t already own in three North American units for about $7.1 billion as the Canadian pipeline giant moves to simplify its corporate structure.
The rollup will also streamline Enbridge’s capital structures and bring all of its core liquids and gas assets under the umbrella of a single publicly-traded entity to the benefit of all shareholders and unitholders, the company said Tuesday.
The deals are part of a broader industry trend for pipeline companies to streamline their operations, such as folding in master limited partnerships, after tax changes made those structures less attractive to investors. Williams Cos., billionaire Kelcy Warren’s Energy Transfer and Loews Corp. have also been getting rid of their MLPs.
Calgary-based Enbridge said in a statement it will buy all remaining outstanding shares of Enbridge Income Fund Holdings Inc., which includes renewable-generation assets and the largest oil pipeline crossing into the U.S. from Canada, for C$4.7 billion ($3.6 billion).
In a separate statement, Enbridge said it take ownership of master limited partnership Enbridge Energy Partners LP, and Enbridge Energy Management LLC, for about at $3.5 billion.
China announced Tuesday retaliatory tariffs on an additional $60 billion worth of US imports that included a 10% tariff on LNG, effective September 24, but Beijing kept crude oil off its latest list of products incurring charges.
The Chinese Ministry of Commerce's list imposed a 10% additional tariff on 3,571 US items, including LNG, and a 5% additional tariff on 1,636 US products -- all effective September 24.
LNG does not attract a tariff currently.
The latest tit-for-tat escalation in the trade war between the two countries came after the US said Monday it would implement a 10% tariff on an additional $200 billion worth of Chinese imports from September 24, and will further lift the duty to 25% January 1.
When the owners of Norwegian oil firm Aker BP decided to digitize its assets and operations, they searched high and low for the right software company. But they failed to find a suitable one.
So instead they set up their own, Cognite www.cognite.com, to create digital maps of Aker BP's oil industry assets, integrating data from equipment such as pumps, heat and pressure sensors, maintenance records and even staff rotas to improve efficiency and safety.
Less than two years later, Cognite is selling its software to Aker BP’s rivals and one competitor, Sweden’s Lundin Petroleum (LUPE.ST), has even agreed to share its real-time oilfield data with Aker in what they say is an industry first.
“This will be the first time two different operators, or oil companies, will share operations/production data live from two producing fields, that is between Edvard Grieg and Ivar Aasen,” a Lundin Norway representative told Reuters.
By combining all the data that typically sits in different digital silos - such as matching flow sensors with the piece of machinery they actually sit on - Cognite says its software can help reduce maintenance costs, extend the lifespan of equipment and avoid damaging breakdowns.
Digitizing industrial assets can also mean fewer people need to be offshore, less downtime for oil platforms, more targeted maintenance and better analysis of information such as geological data and valve pressures.
For Lundin Petroleum, sharing information from its Edvard Grieg field on the Norwegian continental shelf with Aker BP’s adjacent Ivar Aasen field makes sense because getting more real-time production data from a rival in a similar geological area could help it improve its own oil output.
“Aker BP’s view is that, unlike seismic data interpretation for oil exploration, operational data is not a strategic know-how to be protected,” said its chief Karl Johnny Hersvik.
For Aker ASA, the biggest shareholder in Aker BP and Cognite, the Lundin Petroleum deal is part of its plan to create software for an industry that can be improved and refined the more it gets used by different clients - rather than just focusing on an in-house model for Aker BP.
“The value that Cognite’s technology brings to the Aker companies will increase with the number of customers Cognite serves,” Aker Chief Executive Oeyvind Eriksen told Reuters.
Aker ASA, which together with Aker BP owns more than 75 percent of Cognite, is even considering floating the company on the stock exchange within two years.
Controlled by Norwegian billionaire Kjell Inge Roekke here, Aker also has interests in oil, engineering and construction services as well as fishing.
‘THAT’S RIDICULOUS’
John Markus Lervik, a software engineer who founded Cognite, said it has grown from just 2 people to about 110 in 18 months, has clients in oil and shipping and is only planning 12-months ahead for now because “things are happening so quickly”.
It might seem counterintuitive to share technological expertise with rivals, but by learning from usage across companies and industries, software can be improved - even if no oilfield specific data is exchanged. Improvements can then be rolled out to clients, including Aker BP.
“To provide the algorithm and the software to be able to map or connect sensors to the right equipment, that’s a big challenge all oil companies and also other companies have,” Lervik said.
“The more companies we work with to create advanced algorithms to do this mapping, the more advanced, the more automatic, that mapping will be.”
While Cognite is not alone in developing systems that can link masses of data historically kept in different systems, Alfonso Velosa at tech advisory firm Gartner www.gartner.com/en reckons when it comes to oil and gas, Aker is out in front for now.
“Those systems tended to be stuck in proprietary legacy systems and this is now an approach that is trying to marry (them) together,” he said.
“This is a trend that’s coming down and they’re just ahead of the trend at the moment in the oil sector.”
Other companies looking to bring thousands of data points together in the oil sector include Eigen www.eigen.co, a software firm in the United Kingdom founded by oil and gas engineers.
Chief strategy officer Gareth Davies said a new generation of people entering the oil and gas industry is partly behind the drive to come up with better digital systems.
“The guys who come in now who are in their 20s expect to have the information,” said Davies.
“It’s like, well you have to go to that system, you have to ask him to log in there and he’ll export it here, and they look at you like: What are you talking about? That’s ridiculous.”
In one of its recent projects, Eigen digitally linked up 10,600 sensors on Italian oil company ENI's (ENI.MI) Golihere floating production, storage and offloading (FPSO) unit, the world's most northerly oilfield in production.
The system brings together gas and pressure detection to prevent accidents and fire detectors, sprinklers and extinguisher systems, evacuation plans, life boats and other data into one stream of integrated information.
“Up until now this would have been done through a monthly report,” Davies said. “You don’t want to know it every month, you want to know now.”
Saudi Aramco is working on boosting its gas production to meet soaring local consumption by tapping conventional and unconventional reserves.
The company is the sole supplier of natural gas in Saudi Arabia, which has the seventh largest natural gas market in the world, according to the company’s 2017 annual review released in August.
Saudi Aramco in 2017 unveiled plans to double its gas production to 23 billion cubic feet per day over the coming decade. This, in turn, put more pressure on the company to fast-track its unconventional and conventional gas programs to supply gas for power generation, desalination and petrochemicals plants.
The company made progress on several new gas processing plants that are designed to boost supplies of natural gas to local market while lowering greenhouse gas emissions and improving air quality.
Saudi Aramco processed 12.4 billion standard cubic feet a day (Bscf/d) of raw gas and supplied 8.7 Bscf/d of natural gas with an energy content of 1,080 Btu per scf/d last year, according to the review.
While the company made gas discoveries in the Sahba field in Jauf, it made major strides by tapping unconventional gas reserves. Saudi Aramco’s unconventional gas exploration program targeted three areas including North Arabia, the South Ghawar and the Jafurah Basin east of Ghawar.
In North Arabia, Saudi Aramco achieved raw gas production while reducing costs through optimized well design and drilling practices. In 2017, the company said that it made available 55 million scf/d (MMscf/d) of natural gas to Wa’ad al-Shamal Industrial Complex, honoring its commitment to deliver 55 MMscf/d of gas by year-end 2017 to industrial and electrical power facilities in the Wa’ad Al Shamal industrial city project.
https://www.epmag.com/saudi-aramcos-unconventional-gas-ambitions-gain-momentum-1716116
EERC falls to 2,755
EnerCom has released its latest Effective Rig Count, examining the state of drilling activity correlated to production in major shale basins.
The Effective Rig Count fell to 2,755 in August, continuing the decline seen last month. The drop in total EERC was due to declining efficiencies, as reported rig counts rose slightly in August.
These two months represent the only declines seen in the Effective Rig Count since May 2016, when the downturn bottomed out.
.
https://www.oilandgas360.com/niobrara-drilling-accelerates-ahead-of-setback-vote/
Japanese imports of liquefied natural gas (LNG) rose 4.4 percent in August when compared to the same month a year ago, according to the provisional data released by Japan’s Ministry of Finance.
Japan, the world’s top LNG buyer, imported 7.57 million tonnes of LNG last month compared to 7.25 million tonnes in August 2017, the data shows.
The value of August LNG imports was about $3.49 billion, a rise of 28.6 percent on year.
The country’s coal imports for power generation dropped by 11.3 percent to 11.24 million tonnes last month.
To remind, Japan’s LNG imports declined in June and they were flat in July as the country’s power utilities are bringing online more nuclear reactors that had been shut in the wake of the Fukushima atomic disaster in 2011.
However, Japan has been hit by various extreme weather since the beginning of July with record-breaking heat boosting demand for cooling. The country has also experienced devastating floods and landslides.
https://www.lngworldnews.com/worlds-largest-lng-buyer-boosts-aug-imports/
Russia’s largest independent natural gas producer Novatek said two new hydrocarbon deposits were discovered at the Utrenneye field owned by its unit Arctic LNG 2.
The discovery was made during the drilling and testing of the well #294 and commercial viability has been confirmed, Novatek said in its statement.
The two new deposits’ reserves under the Russian reserve classification are estimated at 405 billion cubic meters (bcm) of natural gas and 40 million tons of gas condensate.
The Utrenneye field is located in the Gydan peninsula in the Yamal-Nenets Autonomous District.
As of December 31, 2017, the Utrenneye field’s reserves under the Russian reserve classification totaled more than 1.5 trillion cubic meters of natural gas and 65 million tons of liquids.
“The natural gas reserves of the Utrenneye field including discovering of new deposits amount to about 2 trillion cubic meters,” said Novatek’s head Leonid Mikhelson.
He added that the new deposits expand the reserve potential of the field and open additional opportunities for implementing the Arctic LNG 2 project.
https://www.lngworldnews.com/novatek-expands-resource-base-for-arctic-lng-2/
Shell-led consortium on track to take final investment decision soon for project in British Columbia
Montney producers and market watchers are confident the Shell-led LNG Canada consortium is on track to take a long-awaited final investment decision on its planned liquefied natural gas
.http://www.upstreamonline.com/focus_editions/1575601/lng-canada-moving-toward-fid-after-delay
Shale gas developer Cuadrilla will start fracking at its Preston New Road site in northwest England in the next few weeks, it said on Wednesday as it announced government approval for a second well.
Hydraulically fracturing, or fracking, involves extracting gas from rocks by breaking them up with water and chemicals at high pressure and was halted in Britain seven years ago after causing earth tremors.
But the British government, keen to cut its reliance on imports as North Sea supplies dry up, has tightened regulation of the industry and gave consent in July for Cuadrilla to start fracking a first well at Preston New Road.
After approval for a second well at the site, Cuadrilla said on Wednesday that it would begin work “in readiness to start hydraulically fracturing both wells in the next few weeks”.
Cuadrilla said it would run an initial flow test of the gas produced from both wells for approximately six months.
The British Geological Survey estimates shale gas resources in northern England alone could amount to 1,300 trillion cubic feet (tcf) of gas, 10 percent of which could meet the country’s demand for almost 40 years.
However, attempts to extract the gas have come under fire from local communities and campaigners concerned about the potential effect on the environment and ground water, and arguing that extracting more fossil fuel is at odds with the country’s commitment to reducing greenhouse gas emissions.
British energy and clean growth minister Claire Perry said consent for the second well had been granted after the company had met a number of criteria, including showing it had the necessary funds to carry out work at the site until at least June 30, 2019.
“Shale gas has the potential to be a new domestic energy source, further enhancing our energy security and helping us with our continued transition to a lower-carbon economy,” she said in an emailed statement.
Cuadrilla first attempted to frack gas near Blackpool in the northwest of England in 2011, but the practice led to an earth tremor registering 2.3 on the Richter scale.
The company said the quakes were caused by an unusual combination of geological features at the site, but they led to an 18-month nationwide ban on fracking while further research was carried out.
The government has since introduced a traffic-light system that immediately suspends work if seismic activity of 0.5 or above on the Richter scale is detected. It has also increased monitoring standards, including checks on ground water.
Fracking consent was introduced in 2015 as an additional step to the government’s regulatory regime and ensures environmental, health and safety permits have been obtained.
“Our world class regulations will ensure that shale exploration will maintain robust environmental standards and meet the expectations of local communities,” Perry said.
Both the European gas market and the LNG market in Asia look "tight" for the duration of the upcoming winter, with prices likely to remain elevated until at least March 2019, Shell's head of integrated gas Maarten Wetselaar said.
Speaking on the sidelines of the Gastech conference in Barcelona, Wetselaar said LNG is currently priced at near oil parity for the winter, which, he said, was high.
"The winter looks bullish for gas," Wetselaar said, adding that the markets in Asia and Europe looked tight "all the way out to March and April."
"Gas prices in Europe are relatively high, with storage levels not quite recovered from the tough winter, so with a tight LNG market in Asia, Europe might well see high prices as well," he said.
Europe has struggled to attract LNG cargoes given a recovery in price for Asian deliveries over the past few years, especially in the winter.
S&P Global Platts assessed the Asian benchmark JKM spot LNG price for November delivery at $12.07/MMBtu on Monday, while the JKM swap assessment for January and February was assessed much higher at $13.25/MMBtu.
The Dutch TTF day-ahead price, meanwhile, is currently trading at Eur27.60/MWh, according to Platts assessments, the equivalent of $9.45/MMBtu, while the Q1 2019 price was assessed at Eur28.18/MWh.
NO 'GLUT'
Shell last year famously went against popular opinion that the LNG market was oversupplied, saying there was no glut.
High LNG prices triggered by surging demand and some upstream issues meant the market eventually sided with Shell, agreeing that the market was not in a state of oversupply.
"There wasn't a glut," Wetselaar said, adding that the market would in fact become tighter again from late 2021.
"What happens in between -- summer 2019 to summer 2021 -- is a bit 'unknowable'," he said.
He said that quite a lot of supply was coming on stream in that two-year period and demand in China in particular continued to ramp up.
"I don't exclude that we'll never have a soft market, but in that period we could have one," he said.
Andree Stracke, chief commercial officer at Germany's RWE Supply and Trading, added that the LNG market was buoyant at present for suppliers.
"Every cargo produced is finding a home," he said.
Stracke added that the LNG market was also benefiting from a significant increase in trading liquidity, with greater liquidity around the JKM benchmark and greater numbers of market participants.
FAST-CHANGING MARKET
The CEO of Qatar Petroleum, Saad Sherida al-Kaabi, also said Monday during the Gastech conference that the LNG market was changing quickly, conceding that the view of an LNG glut from now until 2025 was no longer so widely held.
"The market is changing very quickly and we need to make sure we know how to manage projects," al-Kaabi said. "We need to make sure there is ample supply."
Qatar is set to expand its LNG production capacity from 77 million mt/year to at least 100 million mt/year through the construction of three more trains.
Wetselaar said Shell -- which already has a stake in Qatargas 4 -- would be interested in taking part in the Qatar LNG expansion.
"We are in talks with Qatar Petroleum on that," he said.
According to Steve Hill, Shell's executive vice president for gas marketing and trading, the LNG industry has shifted away from trying to bring mega-trains online quickly to a focus on being the "low-cost" producer.
This comes against the background of the burgeoning cheap US LNG supply industry, Qatar's new LNG expansion and the emergence of Novatek as a low-cost LNG producer in Russia.
Novatek CEO Leonid Mikhelson told reporters late Monday on the sidelines of Gastech that his company could be profitable even when LNG prices were at their lowest.
"We can be very competitive on both capital expenditure and operating expenditure," Mikhelson said, adding that Novatek could produce feedgas at one third the price of Henry Hub.
Cyprus has signed an intergovernmental agreement with Egypt for the construction of a subsea natural gas pipeline which will carry gas from Cyprus’ Aphrodite offshore field to Egypt and then to the EU.
The agreement was signed by the Cypriot Minister of Energy Yiorgos Lakkotrypis and Egypt’s Minister of Petroleum and Mineral Resources Tarek El Molla.
The signing ceremony was also attended by the Head of the International Relations and Enlargement Unit of the Directorate-General for Energy of the European Commission Anne-Charlotte Bournovilleand the representatives of Noble Energy, Shell, and Delek, the consortium behind the Aphrodite natural gas field.
Aphrodite is a gas discovery made by Noble energy offshore Cyprus in 2011. The field, located approximately 170 kilometers south of Limassol, was declared commercial in 2o15, however, it has yet to be developed.
Aphrodite field map / Map Source: Noble Energy
Commenting on the signing of the deal, Minister Lakkotrypis said: “Today’s signing […] constitutes another crucial step towards its goal to efficiently exploit the underwater wealth in its EEZ, and specifically gas from Aphrodite for the benefit of all Cypriots. In addition, it reinforces the joint efforts by the countries in the Eastern Mediterranean to establish the synergies required for attracting the multi-billion infrastructure investments for hydrocarbons production and transport,” said.
Gas to be converted to LNG
The agreement is the first of its kind in the region and, according to the Cypriot minister, establishes a formal strategic partnership in the energy sector between the two nations.
It is also worth noting that the agreement and the planned pipeline have the full support and backing of the EU. The pipeline is intended to transport Cypriot natural gas to Egypt for reexport to Europe in the form of liquified natural gas (LNG).
Lakkotrypis said that a joint monitoring committee would be established within the next 30 days, consisting of representatives from the energy ministries and regulatory authorities of the two countries.
“Once build, we are confident that the direct submarine natural gas pipeline crossing the Cypriot and Egyptian EEZs, will be beneficial to all parties involved. Ultimately, through reexports of Aphrodite gas in the form of LNG, the pipeline will allow for the transport of the first molecules of East Med gas to the EU, thus contributing to the Union’s much sought-after security of supply and diversification of sources and routes,” the minister added.
https://www.offshoreenergytoday.com/cyprus-egypt-ink-deal-for-subsea-gas-pipeline/
Energy Department warns that oil drillers are leaving Texas amid pipeline woes
The Energy Department says a lack of pipelines is beginning to drive oil companies out of the big shale region known as the Permian Basin, as they focus investment in regions where the oil is easier to get to market.
The Energy Information Administration released its latest weekly oil analysis on Wednesday, focused on the lack of pipeline "takeaway capacity," which translates to there being plenty of oil, but not enough ways to move it to refiners or export terminals. The report highlights the case for more spending on pipes and for easing or expediting permitting decisions.
The federal agency said it is tracking 45 publicly-traded oil companies' investment strategies, and spotted a trend. "As a result of these constraints, some producers with a geographically diverse portfolio of upstream assets announced plans in their second-quarter earnings releases to redirect capital expenditures from the Permian Basin to other regions," read EIA's Week in Petroleum report.
The oil firm Baker Hughes is cutting the number of drilling rigs in the Permian, and the Houston-based Noble Energy announced "the reallocation of capital expenditures from the Permian to other U.S. onshore basins because of the transportation constraints," EIA said.
"Outside of the Permian, Noble Energy has U.S. onshore operations in the Denver-Julesburg Basin in Colorado and in the Eagle Ford region in Texas," the new report read.
The Permian Basin, which covers Texas and New Mexico, is one of the richest shale oil deposits in the United States. But the lack of pipelines to move the oil to market is dropping the price, and making it economically unattractive for some companies to continue production there.
Some are deciding to stay and continue production because of higher oil prices due to dwindling oil surpluses and U.S. sanctions on Iran.
Last week's Week in Petroleum discussed the effect of Iran sanctions on the price of oil. EIA said it was adjusting its monthly price projections upward to reflect the higher prices from U.S. oil sanctions kicking in sooner than anticipated.
But beyond the lost oil supply coming from Iran, Wednesday's government analysis shows challenges also continue to persist domestically to get oil to market. The constraints in the Permian are expected to continue through the middle of next year, said EIA.
Nevertheless, the 45 companies that the agency tracks are on track to invest a record amount in 2018 in both the Permian region and elsewhere, according to the report.
"These 45 companies have announced $63 billion in asset purchases and corporate acquisitions through September 18 of this year," the agency said. Total 2018 expenditures are on pace "to meet or surpass the previous high" four years ago, which saw $83 billion in drilling-related spending.
More than half of the 45 companies are spending on corporate acquisitions or purchases of oil reserves.
To be sure, a portion of the investment is going back into the Permian, with BP, for example, spending $10.5 billion to buy BHP Billiton's onshore assets, according to the agency. Other multi-billion dollar acquisitions were common in the second quarter.
It’s no secret by now that Permian natural gas pipelines have been running near full the last few months, jam-packed like Southern California traffic while trying to whisk away copious volumes of mostly associated natural gas to markets north, south, west and east of the basin. Despite every major artery running near capacity this summer, Permian prices had so far managed to avoid falling below the dreaded $1.00/MMBtu threshold, a precipice that historically defines a gas producing basin as definitively oversupplied. That all changed yesterday, as word came in that Southern California Gas Company, one of the largest recipients of Permian gas, has nearly filled its gas storage caverns and will soon need far less gas hitting its borders. That’s particularly bad news for the Permian, which has few other options if it needs to reduce the supply that is currently flowing west out of the basin to California. A large unplanned outage for maintenance was also announced on one of the pipelines leaving the Permian and heading north to the Midcontinent. As a result, the SoCalGas news and maintenance combined to put a huge dent in Permian gas prices, some of which plunged as low as 50 cents in Wednesday’s trading. Today, we detail this most recent development and the implications for Permian gas takeaway.
We’ve written extensively on Permian Basin natural gas the last few months, most recently detailing the proposed Whistler Pipeline in Whatever It Takes. We also looked at Kinder Morgan’s Permian Highway Pipeline, which recently became the second new Permian pipeline to reach a final investment decision (FID) to proceed, in our blog titled P.H.P., Dynamite!. Our last blog focusing specifically on Waha gas prices was in July, when Rollercoaster analyzed the price swings this summer. Earlier in the summer, in Trouble Every Day, we outlined potential options for Permian natural gas should pipeline capacity out of the basin fill up before the first new pipeline — Kinder Morgan’s Gulf Coast Express (GCX) — starts up in late 2019. We also recently discussed GCX and other potential competing projects as part of our Blame It On Texas series. Today, we dive into the drivers behind yesterday’s news that has likely turned the Permian gas pipeline traffic jam into a pileup.
Maybe it was the shellacking the Texas Longhorns football team put on the University of Southern California on Saturday or maybe it was just timing (definitely the latter), but the Southern California gas markets sent news Wednesday that sacked the Permian natural gas market. Football references aside, here are the facts of what happened as we have been able to ascertain. On Tuesday (September 18) at 12:23 PM Pacific Time, the electronic bulletin board of SoCalGas, the Southern California gas utility owned by Sempra Energy, posted an update to its maintenance schedule for the Aliso Canyon Storage Facility. The posting indicated that Aliso Canyon would be filled to its currently authorized maximum inventory of 34 Bcf on September 24 (this coming Monday). This is big news for not only the SoCalGas gas market, but also the supply basins that send natural gas to Southern California, including the Rockies, San Juan, and Permian. With Aliso Canyon reaching capacity early next week, the SoCalGas system will see a storage injection reduction of 400 MMcf/d, according to the SoCalGas website. This is a bummer for the Permian, given the huge volumes of gas that leave the basin and head west to California. The posting came out after gas markets had closed, so market participants had to wait until trading started on Wednesday morning to gauge the impact of the news. We’ll get to those ramifications in a moment, but first a little history on the situation regarding Aliso Canyon and SoCalGas.
A combination of pipeline outages, low storage levels, and extremely hot weather combined to send prices in the SoCalGas market as high as $40/MMBtu. One of the main drivers of the price spike was low storage inventory at one of SoCalGas’ largest storage fields, Aliso Canyon. (See California Sunset for more on Aliso Canyon.) Nagging pipeline outages on the SoCalGas system also limited imports from the two major pipelines serving the market, Kinder Morgan’s El Paso Natural Gas (EPNG) and Energy Transfer’s Transwestern. That was no help to Permian producers looking to flow additional volumes into California, but the SoCalGas market really bore the brunt of the outages as 100-degree heat hit the Los Angeles area and prompted some dramatic price spikes. The situation also elicited a response from the California Public Utilities Commission (CPUC). In a step to mitigate the lingering pipeline outages and prepare for the high loads likely to hit the SoCalGas system during the winter, CPUC granted approval in early July to increase Aliso Canyon’s capacity from 25 Bcf to 34 Bcf. Since then, Aliso Canyon has been able to inject up to 400 MMcf/d and it has apparently been busy getting full. Now, according to SoCalGas, it’s about to get busy not injecting, as forecasts now show the field full by Monday. With less demand out west, the basins that supply California will have to compete on price to see who maintains their share of the SoCalGas market. The Permian essentially must maintain all of its share, given its limited alternatives, and responded yesterday with a price signal that supports that aim.
As if the SoCalGas news wasn’t enough to dim the prospects for Permian gas over the next few weeks, Kinder Morgan’s NGPL announced a major unplanned maintenance event expected to limit gas takeaway capacity from the Permian to the Midcontinent markets. NGPL informed market participants just about an hour after the SoCalGas news hit that it was declaring a force majeure event at its Barton Compressor Station in Kansas due to a “line strike.” While Kansas is far from the Permian, the compressor outage will limit combined outflows on NGPL from the Permian and Midcon markets by as much as 60% until mid-October. The capacity reduction means Permian and Midcon gas will be fighting for share of the remaining space on NGPL to Midwestern markets.
The SoCalGas and Kinder Morgan announcements combined to create an extremely chaotic day of trading at the Permian Basin’s Waha hub, where prices were already under pressure. As shown in Figure 1 below, basis prices at Waha have been significantly weaker this year and it’s easy to see the most recent drop (dashed red oval). Note that we calculate basis by taking the difference between Henry Hub and Waha as reported by our friends at Natural Gas Intelligence (NGI). So far this year, Waha has averaged just over $0.80/MMBtu under Henry, but there have been days where the basis has priced meaningfully lower than that. Most of these days have been in the last few weeks. At the end of August, Waha basis dropped to what was then its lowest level since 2008 at $1.69/MMBtu under Henry Hub. That level was eclipsed yesterday, when the NGI Waha basis price dropped to $2.45/MMBtu under Henry. However, that price is an average that includes most of the various points traded on the numerous pipelines at Waha and yesterday’s chaotic trading witnessed some huge spreads among those individual points. For some pipelines at Waha, the daily price actually averaged in the range of $2.50 to $2.60/MMBtu under Henry Hub. With Henry Hub averaging $3.09/MMBtu in Wednesday’s trading, the math is easy — many points in the Permian traded well under $1.00/MMBtu yesterday. And while a few Permian points fared better than that, futures prices for the balance of September, the “balmo” (or balance-of-month) contract in trader parlance, indicate Permian basis is expected to remain around $2.00/MMBtu under Henry Hub. While the futures market has proven to not always be the best predictor of, well, the future, it does indicate that market participants have rather a gloomy outlook on Permian gas at present.
Figure 1. Waha Daily Cash Basis, Source: NGI
If the basis prices in Figure 1 don’t drive home the severity of the situation right now in the Permian, a look at the absolute daily price at Waha (Figure 2) certainly should. As we said, the price reported by NGI is the average of a number of points traded at Waha and doesn’t represent the worst of yesterday’s pricing, but at $0.61/MMBtu (dashed red oval) it is the worst ever seen in our pricing dataset from NGI that goes back to 2007. It also has broken the perceived $1.00/MMBtu threshold that for many market participants signals that a severe oversupply situation exists. Think Rockies vintage 2006 or Dominion South in the summer of 2013. How long prices remain below this psychological threshold depends on many factors, most of which we have referenced in the blogs noted above. A combination of production curtailments or flaring may play a role now that we have reached levels where some producers may not find it profitable to produce gas into a pipeline. Weather could certainly help demand, although we’re probably two months away from that being a significant factor. A few small brownfield expansions could also help alleviate some of the takeaway constraints — projects such as Enterprise Products’ and Energy Transfer’s Old Ocean project. However, in our view, it is likely that we’ll see an increasing frequency of days like yesterday over the next year, until Gulf Coast Express provides some real relief in late 2019.
Figure 2. Waha Daily Cash Price, Source: NGI
Given the speed and severity of yesterday’s price movements, we expect the Permian gas market to remain volatile in the days ahead as production remains healthy and demand is falling seasonally. Yesterday’s events are just one of many maintenance-related impacts that could roil the Permian markets over at least the next year, until Kinder Morgan’s GCX comes online.
https://rbnenergy.com/la-freeway-socal-storage-constraints-sideswipe-permian-gas-prices
Brazil could face a diesel shortage at the end of 2018 as a result of the government’s mispriced subsidy program which has discouraged suppliers, and the state-controlled oil company Petroleo Brasileiro SA may be forced to sell diesel at a loss, broker INTL FCStone said on Tuesday.
Brazil’s oil industry regulator ANP said it approved the payment of 871.5 million reais to Petrobras on Tuesday to compensate for the diesel subsidy.
Petrobras Chief Financial Officer Rafael Grisolia had earlier told Reuters on Friday that the firm expected to receive 2 billion reais to 2.5 billion reais ($484 million to $605 million) from ANP within two weeks to make up for subsidies.
Earlier this year, a nationwide truckers’ protest over rising diesel prices paralyzed Latin America’s largest economy and forced the government to lower diesel prices through tax cuts and subsidies.
But the subsidy program announced in May has set prices too low to compensate most diesel importers, FCStone said in a statement.
Companies have stopped selling the fuel, forcing Petrobras to supply most of the market at a loss and raising the specter of a shortage in the coming months, the commodity broker added.
“Private imports are paralyzed, and Petrobras is practically the only agent bringing the product to Brazil,” FCStone said.
“Unless oil regulator ANP raises diesel prices and starts paying subsidies, we will have diesel shortages in the last months of the year or Petrobras will have to face the cost alone of supplying the whole market at a loss,” FCStone said.
The subsidy plan ended the truckers’ strike but it raised the specter of a new and costly round of state meddling in the affairs of Petrobras, still the world’s most indebted oil company.
Brazil will need to import some 5.5 million cubic meters of diesel in the last four months of the year, a 12 percent increase over the same period last year, FCStone said.
The growing need comes after an explosion in August at Replan, Petrobras’ largest refinery, hurt output and as a thriving agriculture industry drives demand higher.
Mexico could be at the precipice of a region-wide energy revolution, and natural gas is the key. The future of Mexico’s gas sector will be up for debate at the Latin American and Caribbean Gas Conference & Exhibition (LGC) held in Mexico City next month. Major industry players will meet from October 9-11 to discuss, among other topics, the country’s potential to become a major energy hub for Latin America.
The LGC meeting will be held in partnership with non-profit organization International Gas Union, which works to advocate for the incorporation of natural gay as a key component to sustainable energy systems. Also present will be decision-makers from ENGIE, AES, MAN Diesel, MODEC, Shell, TOTAL, Petrobras and other key players in the energy industry.
Orlando Cabrales Segovia, Regional Manager of the International Gas Union described the event as “an opportunity to discuss how to increase demand and take advantage of the gas potential in order to improve the competitiveness of our economies and the air quality of our cities by using natural gas in transportation” after five years of plateaued “production, incorporation of reserves and gas consumption in South America and Central America.”
Five years ago, Mexico received nearly $4 billion USD in investments specifically for the purpose of building and maintaining natural gas pipelines and other gas infrastructure. The country’s National Hydrocarbons Commission (CNH) recently created a public bidding system that offers up 35 exploration and extraction areas.
Mexico is the only Latin American member of the International Energy Agency, and therefore has the status of a first level oil and gas producer, adding to its distinguished position as the most promising nation for natural gas investment in the entire region. Mexico’s unique advantage in its region does not come without significant challenges, however. The nation critically lacks gas storage infrastructure and will need to invest approximately $250 million USD to complete a project that would turn unviable wells into storage facilities. Furthermore, Mexico will need to make significant improvement to their gas transport system and to optimize of the electrical distribution network to integrate renewable energy.Related: Norway’s Offshore Oil Boom Is Back On
That being said, infrastructure is not the only challenge that the energy industry faces in Mexico, nor the gravest. According to a recent issue brief by Jose I. Rodriguez-Sanchez of the Baker Institute for Public Policy, corruption is swiftly becoming the norm in Mexican society, and the energy industry is a major reason for this unfortunate trend. Mexico ranks among the most corrupt countries in the world across multiple indexes that measure such corruption.
This in no small part thanks to state-owned oil company Petroleos Mexicanos (Pemex), which has supplied a whopping 30 percent of the government’s revenue in the past. Rodriguez-Sanchez wrote that Pemex “signed and paid contracts to private companies that were very problematic in exchange for $11.7 billion from 2003 to 2012. These firms overcharged Pemex for their work, and in some cases, the work was of poor quality or never completed.” Brazil’s Petrobras was central to some of these suspicious contracts and subsequent corruption scandals, but they will notably still be attending LGC in the Mexican capital in October.Related: Is Russia Smuggling Fuel To North Korea?
If Mexico is successful in its ambitions to become a major natural gas producer and a natural gas hub in Central and Latin America, it will have wide-reaching implications and their neighbors to the north will certainly not be among those rejoicing in Mexican energy independence. As domestic energy production remains low, Mexico is currently one of the biggest importers of natural gas from the United States. In fact, later this year, four new pipelines are expected finally be ready to begin to distribute U.S. natural gas throughout Mexico, and U.S. producers are depending on continued demand.
Incoming Mexican President Andrés Manuel López Obrador, who recently won in a landslide election, ran on a platform that was not only extremely anti-corruption, but heavily in favor of energy independence for his country. He has already pledged to dramatically increase spending on production and infrastructure in Mexico’s energy sector. Although Mexico is making the motions to end their era of dependence on the United States and dramatically decreased energy production, they have a long road ahead. While LGC could be an important first step, it’s just the beginning.
https://oilprice.com/Energy/Natural-Gas/Mexico-Aims-To-Become-The-Energy-Hub-Of-Latin-America.html
Riverstone Holdings LLC is preparing to sell oilfield services equipment company Abaco Energy Technologies, which could fetch about $900 million, according to people with knowledge of the matter.
The private equity firm is working with an adviser to run an auction for the Houston-based company, said the people, who asked to not be identified because they weren’t authorized to speak publicly. Abaco is drawing interest from other private equity firms, they said.
A representative for Riverstone declined to comment while representatives for Abaco didn’t respond to requests for comment.
Abaco makes, designs and services parts used for powering so-called mud motors, the section of an oil and gas well drilling system that rotates the drill bit far underground.
Riverstone committed to invest $200 million in the company when it was founded in 2013 with the goal of acquiring energy manufacturing and services businesses, according to a press release at the time. Abaco agreed to acquire drilling-equipment maker Basin Tools Inc. a year later, according to a statement.
Abaco CEO Ken Babcock previously worked for Titan Specialties Ltd. and International Logging Inc., two other companies that Riverstone previously owned.
Abaco should benefit from increased demand over the next 18 months from oil and gas explorers, according to a research note this week from Moody’s Investors Service Inc., which upgraded its credit rating.
While the company has a small revenue base, it is "competitively positioned within its niche market," Moody’s said.
Riverstone, which has offices in New York, London, Houston and Mexico City, has raised $38 billion for energy investments since it was founded in 2000 by David M. Leuschen and Pierre F. Lapeyre Jr., according to its website.
The firm raised $4.2 billion for its most recent buyout fund, which closed in 2015, according to data compiled by Bloomberg.
Japan's Inpex has sold the first condensate cargo from its operated Ichthys project in Australia, with shipment "as early as at the end of September," a source familiar with the matter told S&P Global Platts Wednesday.
The 350,000 barrel cargo of offshore condensate was sold to an unspecified buyer for loading at the end of September onward, the source said.
It wasn't immediately clear when Inpex will be able to market onshore condensate from the project.
Inpex's sale of the first offshore Ichthys condensate cargo comes after it said on July 30 that it had commenced production of gas from the wellhead at its Ichthys LNG project. Inpex said on August 9 it would start shipments from the Ichthys project from around the end of September to the October-December quarter in the order of condensate, LNG and LPG.
The facility, which is set to become Australia's largest condensate project, with a production capacity of 100,000 b/d condensate and 1.6 million mt/year of LPG, involves piping gas from the offshore Ichthys field in the Browse Basin in northwestern Australia, over 890 km to the onshore 8.9 million mt/year LNG plant near Darwin.
Once the Ichthys condensate production reaches a plateau level, Inpex will likely offer up to three 650,000 barrel cargoes a month of the offshore condensate and one 300,000 barrel cargo/month of onshore condensate, both on a FOB basis, an Inpex official told Platts in an interview in June 2015.
This was based on the assumption that Inpex would likely be in charge of marketing 70% of the volume, which is equal to its own equity in the project and stakes held by the minority stake holders.
Inpex holds a 62.245% operating stake in Ichthys, with Japanese LNG customers Tokyo Gas, Osaka Gas, Kansai Electric, Jera and Toho Gas holding stakes of 1.575%, 1.2%, 1.2%, 0.735% and 0.42%, respectively. Taiwan's CPC holds a 2.625% interest, while France's Total holds the remaining 30%.
Japan's top LPG supplier, Astomos Energy, said in March 2017 that it has agreed in principle with Inpex Trading to buy its equity "lifting volumes" of LPG produced from the Ichthys project in Australia.
Under the agreement, Astomos will buy an unspecified lifting volume from Inpex Trading, a wholly owned subsidiary of Inpex, on an FOB basis.
China’s CNOOC sold access to its Yuedong liquefied natural gas (LNG) terminal to state-owned Zhenhua Oil and private logistics firm Longkou Shengtong Energy, its first such auction as the country pushes to liberalize its vast oil and gas market.
The logo of China National Offshore Oil Corp (CNOOC) is pictured at its headquarters in Beijing, China April 4, 2018. Picture taken April 4, 2018. REUTERS/Stringer
In the auction on the Shanghai Petroleum and Gas Exchange, Zhenhua Oil and Longkou agreed to pay CNOOC Gas and Power Group 0.265 yuan ($0.04) to CNOOC per cubic meter of imported LNG for access to the terminal, Zhenhua Oil, a subsidiary of Chinese defense conglomerate Norinco, said in a statement.
The total value of the deal was 26.5 million yuan ($3.87 million).
CNOOC has also sold LNG in auctions on the Shanghai bourse this year but this is the first time it has auctioned space at a receiving terminal.
The sale marks the latest move by China, one of the world’s top gas importers, to liberalize natural gas prices, open up access to oil and gas infrastructure and shore up supplies as the peak winter demand season approaches.
Other state-owned companies such as PetroChina have leased terminals to third-party users before in private deals. The auction from CNOOC, however, gave third-party players equal opportunity to bid for access.
“This is the first time that LNG terminal leasing rights were put up for auction,” Zhenhua Oil said in the statement, adding that Zhenhua is looking to meet rising gas demand from China as it expands into LNG trading.
The deal comes just months after Zhenhua set up a business to invest in LNG terminals and trade the fuel.
Zhenhua Oil plans to import 100 million cubic meters of LNG to Yuedong in between Oct. 24 and 26, it said.
The company will pick up its cargo from the terminal by trucks, Zhenhua said.
China’s diesel demand will grow at its fastest in at least five years as a pick-up in diesel-intensive sectors in the world’s second-biggest economy coincides with lower output from domestic refineries, several sources and analysts said.
Estimates of the hike in diesel use from three analysts and two oil industry sources range from 0.3 to 1.7 percent for 2018 compared with last year’s stagnant growth, pointing toward a recovery for the industrial and transport fuel.
Diesel accounts for about 30 percent of China’s appetite for petroleum products and is typically used to fuel trucks, as well as mining and construction equipment. The slight pick-up in Chinese demand helped to boost Asian diesel margins to their highest in more than three years earlier this month.
“Our outlook for Chinese diesel demand remains positive, with consumption set to remain supported over the coming years with positive ... trends in key diesel-intensive sectors, such as construction, manufacturing, freight and mining,” said Richard Taylor, oil and gas analyst at Fitch Solutions.
This year’s diesel growth will be the fastest since 2011, said Energy Aspects analyst Nevyn Nah.
The demand increase is likely temporary, however, said the research unit of China National Petroleum Corp (CNPC), with economic growth moderating and tighter environmental scrutiny from Beijing.
“China’s diesel demand will stay around peak levels until 2020. After that, consumption will slowly go down,” said Wang Lining, researcher from CNPC Research Institute of Economic and Technology.
“We noticed the recent pickup in infrastructure investment which led to a temporary boom in diesel consumption,” Wang said.
Besides increased demand from industry and mining, the lifting of an annual fishing ban of up to four months in certain areas this year has created pent-up demand for diesel, the industry sources said, speaking on condition of anonymity as they were not authorized to speak to media.
INDUSTRY, TRUCKS, TAX RULES PUSH DEMAND
Higher industrial output ahead of the Golden Week holiday in early October also boosted demand, the sources said.
Industrial output in China rose 6.1 percent in August from a year earlier, the National Bureau of Statistics (NBS) said last week, a tick higher than in July.
Medium and heavy truck sales were up 3.5 percent in the first eight months from a year ago as car producers sold 2.6 million trucks in the period, data from China Association of Automobile Manufacturing also showed.
Also, tightening tax rules implemented in March have led to a cut in imports of blending stocks such as light cycle oil (LCO), stoking demand for diesel in the domestic market instead, two of the sources said.
Premiums for LCO exported from South Korea this year have at least halved to $5 to $6 a ton since last year, indicating a drop in demand from its main customers in China, one of the sources said.
Led by a spike in benchmark crude prices, wholesale diesel prices in China have jumped 22 percent from the start of the year to 7,838 yuan ($1,140.40) per ton, the highest in four years, according to consultancy JLC.
In comparison, the price of 10ppm diesel loading in Singapore is just over $700, about 5,000 yuan, a ton, Reuters data showed.
The disparity in prices also led to a recent rare import of diesel cargo into China, and has boosted margins and diesel appetite among fuel sellers, the sources said.
Diesel margins were also lifted because of lower diesel output due to prolonged maintenance by independent Chinese refiners amid higher oil prices and a shift toward cleaner diesel in the marine sector.
U.S. oil firms ExxonMobil, Chevron, Occidental Petroleum are set to join the Oil and Gas Climate Initiative (OGCI), an initiative representing 13 of the world’s largest oil and gas producers working on solutions to mitigate the risks of climate change.
OGCI was established following the 2014 World Economic Forum and formally launched at the United Nations Climate Summit the same year. Members include BP, CNPC, Eni, Equinor, Pemex, Petrobras, Repsol, Royal Dutch Shell, Saudi Aramco, and Total.
The three new companies will become official members of OGCI as of September 24, 2018. Each will commit $100 million dollars to the OGCI Climate Investments fund.
OGCI focuses on developing practical solutions in areas including carbon capture and storage, methane emissions reductions and energy and transportation efficiency.
The OGCI said that the three new members represented 5% of global oil and gas production.
“With these additions, OGCI members now represent around 30% of global oil and gas production and supply close to 20% of global primary energy consumption. The 13 member companies represent regions including China, the Middle East, Latin America, Europe and now the United States, widening OGCI’s global reach and making its members’ collaborative effort in support of the Paris Agreement, a significant global action,” the OGCI said.
Collective effort to address climate change
In a joint statement, the heads of the OGCI member companies said: “Over the past four years, OGCI has brought together international and national oil and gas companies to accelerate the deployment of concrete solutions to reduce greenhouse gas emissions. Our ambitions increase each year and as we welcome three new member companies, we will continue to build momentum and strengthen our collective reach and impact to deliver practical action on climate change.”
https://www.offshoreenergytoday.com/exxonmobil-to-join-oil-and-gas-climate-initiative/
SDX Energy has confirmed it is “in discussions” to purchase a “significant package of assets” from oil giant BP.
The North African focused firm added that the deal would constitute a reverse takeover under Rule 14 and would be subject to shareholder approval.
SDX said that the firm’s selling of shares had been currently suspended until confirmation arrives that the deal will proceed.
The company said in a statement: “In accordance with the AIM Rules the Company’s shares have been suspended from trading on AIM with immediate effect and will remain suspended until an AIM admission document has been published or until the Company confirms that the Acquisition is not proceeding.
“Trading in the shares of the Company on the TSX Venture Exchange will also be halted during such time.
“A further announcement will be made as and when appropriate.”
The U.S. Environmental Protection Agency (EPA) published new data detailing how it drastically expanded a biofuels waiver program for oil refiners since President Donald Trump’s administration took office, responding to pressure from the corn lobby to boost transparency over the opaque program.
The details published on the EPA’s website on Thursday showed the agency issued exemptions for 29 small refineries for 2017, freeing them from their requirement under the Renewable Fuel Standard to blend biofuels into gasoline and diesel, according to agency data released on Thursday.
That was up from 19 waivers granted for 2016 and 7 in 2015, the EPA said.
The data provides the most complete picture of the EPA’s expansion of the controversial small refinery waiver program to date. The waivers save the oil industry money, but biofuels groups worry they also cut into the nation’s demand for ethanol and other biofuels, and have criticized Trump’s EPA for over using the exemptions.
“Increasing transparency will improve implementation of the RFS and provide stakeholders and the regulated community the certainty and clarity they need to make important business and compliance decisions,” EPA Acting Administrator Andrew Wheeler said in a statement.
The data showed that the number of gallons exempted from the RFS under the 29 waivers granted in 2017 amounted to 13.62 billion, nearly double the 7.8 billion exempted in 2016. More details of the gallons waived are available here: [L2N1W61A7].
The EPA is still considering five waiver requests for 2017, and has received a total of 11 requests for 2018, all of which are also still pending, according to the data.
EPA had previously been more stingy with its waivers. It granted 19 of the 20 waivers requested for the 2016 compliance year - with some of those decisions made in 2017 - but only seven out of 14 requests for 2015.
The RFS requires oil refiners to blend increasing amounts of biofuels like ethanol into their fuel each year, or purchase credits from those that do.
Small refineries can apply for and receive waivers if they demonstrate that compliance with their requirements would cause them financial hardship.
The EPA does not divulge information on who applies for or receives the waivers, arguing the information is business-sensitive, and until now it has been sparing with details on the numbers of waivers and quantities of fuel exempted.
A ‘STEP IN THE RIGHT DIRECTION’
The expansion of the program occurred mainly under former EPA Administrator Scott Pruitt, who left the post in July. His management of the program had prompted calls from biofuels supporters that the agency release more detail on the waivers.
Pressure mounted after Reuters reported that large refining companies including Chevron, Exxon Mobil, Marathon and Andeavor all had applied for the exemptions, which can be granted based on the size of an individual refinery unit rather than the whole company.
Renewable Fuels Association President and Chief Executive Officer Bob Dinneen described the EPA’s new data release as a “step in the right direction.”
But he said more was needed.
“Market participants and the public deserve to know exactly who is receiving small refinery exemptions and what criteria is being used by EPA in making the decision to grant or deny a waiver request,” he said in an emailed statement.
Prices of blending credits, known as Renewable Identification Numbers (RINs), have plunged as a result of policy uncertainty and expansion of the waiver program. They fetched around 18 cents each on Thursday, traders said, little-changed from the previous session and matching a near 6-1/2-year low struck in June.
After Pruitt’s exit, Wheeler said he would follow up on the work of his predecessor to overhaul the RFS in a way that would satisfy both the oil industry and the biofuels sector.
Fracking is entering a new expansion phase in this Canadian town more than 2,000 miles from the center of the U.S. oil boom—one that heavily favors the world’s energy giants.
Chevron Corp. is laying the groundwork here for what it calls a “factory model” for shale drilling, master planning an entire region of small shale wells by locking up labor, building infrastructure and securing sand and other needed materials, all at once.
Shale drilling, once the province of small, scrappy operators, has run into growing pains in places such as the Permian Basin in Texas and New Mexico, as producers struggle with pipeline bottlenecks and rising labor and material costs.
Big oil companies seeking to re-create the U.S. shale boom in countries such as Canada and Argentina are trying to avoid these problems by managing shale sites in concert to prevent logistical difficulties and streamline operations, similar to the way they run traditional oil megaprojects.
Already in Texas, there is evidence that larger companies such as Chevron and Exxon MobilCorp. are weathering the bottlenecks and rising costs there better than smaller rivals—and continuing to ramp up production—because they have the economies of scale and wherewithal to develop their own solutions to these problems.
The big international oil companies were initially slow to recognize the potential of fracking and found themselves behind the competition in the first phase of the shale boom as smaller operators locked up land and stepped up production in places such as North Dakota and Texas. But they have since become major players in the Permian Basin, and are in the process of trying to leverage large footprints in the region into tangible shale profits—something that to date has eluded many of their smaller rivals.
“They can transfer technology and skilled people across assets and parts of their portfolio from North America to Argentina,” said Andrew Slaughter, executive director of the Center for Energy Solutions at Deloitte LLP. “These bigger companies have the scale to build or finance infrastructure and secure the best equipment and supplies. They have come to shale in quite a material way.”
The “bigger is better” mantra has started pushing smaller operators toward a new era of consolidation in fracking. A similar pattern has played out throughout the history of the oil industry, with wildcatters pioneering new technologies and discovering new fields, and larger, better-financed companies eventually taking over.
Deals among smaller oil-and-natural-gas companies that don’t own refineries are on track to reach almost $300 billion for 2017 and 2018, the highest two-year merger volume in more than two decades, according to Dealogic. The biggest tie-ups have occurred in the Permian Basin, where oil this year has sold at a price as much as $20 a barrel below global benchmarks because of bottlenecks and other constraints.
As Chevron seeks to expand shale around the world, it is taking lessons from Texas oil fields and from a model it pioneered in Southeast Asia in the 1990s. In the Gulf of Thailand, Chevron drilled thousands of wells to access isolated pockets of oil and gas. Over time, Chevron learned the value of standardizing equipment and processes to save money and keep costs low.
Earlier this decade, as the company began to turn its attention to fracking, teams of engineers working in Canada, Texas and Pennsylvania began visiting Thailand to see how they could improve in the U.S. oil patch.
“Shale was a great fit because of the quantity of wells you’re going to drill, the repeatability, well designs and rig types,” said Kim McHugh, vice president of drilling and completions at Chevron. “It’s a working ecosystem.”
In Fox Creek, about 160 miles northwest of Edmonton, Chevron is putting what it has learned into practice. That includes the use of underground data sensors linked via fiber-optic cables to analyze continuing fracking jobs, which blast rock layers with water, sand and chemicals. The company uses the resulting information to make adjustments and stimulate the release of more trapped oil and gas.
But it is also making changes to account for local conditions—and leveraging its size.
At a remote well site in Alberta, where employees are more likely to contend with logging trucks or bears than residential neighbors, Chevron built a facility that functions like a grain elevator and can store 1,800 tons of the sand that drillers use in fracking.
Known as the Sahara Sand Storage unit, it allows Chevron to continue drilling and avoid having to wait for deliveries from dozens of trucks a day. That is especially important after spring, when frost here melts and road bans stemming from the thaw’s effects can limit accessibility.
Chevron hasn’t disclosed how much oil and gas it might ultimately produce from the region. Analysts were once skeptical about the company’s Canada prospects, but many now say its position might be worth billions of dollars.
Shale development has taken off in the country, where production linked to fracking is expected to reach the equivalent of about three million barrels of oil and gas a day in 2020, according to Rystad Energy. That is more than five times higher than in 2011.
“We should be able to accelerate faster here based on our success in the Permian,” said Andrea Schnare, a Chevron operations manager who recently switched assignments from West Texas to Canada. “It’s much easier to adopt best practices across different areas.”
https://www.oilandgas360.com/oil-giants-use-size-to-overcome-fracing-challenges/
The leading global contractors that are bidding to build the second wave of US LNG export terminals gave developers Thursday a simple message to think about on their flights home from Spain: "You get what you pay for."
As Gastech wrapped up in Barcelona, executives at Bechtel, Fluor, KBR, McDermott International and Spain's Tecnicas Reunidas sought to inject a sense of realism about the costs that are necessary to ensure projects are completed when the market expects to see them.
The concerted effort comes in the face of delays at several of the first wave export terminals under construction along the Gulf and Atlantic coasts, including at Freeport LNG's facility in Texas, Sempra's Cameron LNG site in Louisiana and Kinder Morgan's Elba Liquefaction Project in Georgia. Startup of Cheniere Energy's second export terminal, being built by Bechtel in Texas, is expected ahead of schedule.
"Enthusiasm is not a strategy," Fluor CEO David Seaton said during a panel discussion at the conference. "That's a lot of what we see with the new customers who are more the developer type. All they are doing is looking at their spreadsheet rather than the real cost of building one of these things."
With more than a dozen terminals being proposed as part of the second wave of US projects that are targeted to go online in the early- to mid-2020s, there is intense competition for long-term contracts with buyers of the capacity.
With that comes pressure to sign engineering, procurement and construction deals for the lowest possible amount.
"From my perspective, the way we hear about dollars per ton this and dollars per ton that. The answer is not the lowest dollar per ton," Bechtel President Alasdair Cathcart said. "The answer is we have collaborated and innovated to make sure we have the best possible cost, the best possible schedule and the best possible certainty of outcome."
Cameron LNG's experience is an example of what can happen when insufficient attention is paid on the front end to properly bidding for the realistic cost of construction, according to McDermott International CEO David Dickson, whose company inherited its contractor role on the project when it acquired CB&I earlier this year. It took a writedown in the second quarter because of extra costs related to construction.
"A lot of it went wrong at the time of the estimation," Dickson said at the conference. "Early engagement, technology, where we feel we can get closer to the customer in the early stages. In the US, particularly, where there is a lot of excitement about a new wave of LNG contracts, there are also challenges, especially on the construction side."
With so many projects, skilled workers could be harder to come by for the second wave of US projects. Tighter restrictions on immigration in the US under the Trump administration are also affecting the situation, the executives said. Invariably, that could drive up costs.
LESSONS LEARNED
Committed to not making the same mistake again, McDermott recently backed away from signing an EPC contract to build NextDecade's proposed Rio Grande LNG export terminal in Brownsville, Texas. It wants to secure a partner and have a better handle on the true cost of construction.
NextDecade has opened the job up to a competitive bid process, which will include Bechtel and Fluor.
Juan Llado Arburua, CEO of Tecnicas Reunidas, which agreed to an engineering contract for Venture Global's proposed Calcasieu Pass LNG export terminal in Louisiana, said builders don't want to be left holding the baby, so they are pushing back against developers' efforts to always secure a lower EPC deal than the previous project.
"We are trained to run risks, but we are not trained to be insurance companies," he said.
Norwegian oil company Aker BP has drilled four wells in the North Sea off Norway. As a result, two wells are dry and the other two have moderate to good reservoir quality.
Aker BP, the operator of production license 028 B, has concluded the drilling of appraisal wells 25/10-16 S, A and C on the Hanz field, as well as wildcat well 25/10-16 B drilled in production license 915 just southeast of the Hanz field, the Norwegian Petroleum Directorate (NPD) said on Friday.
The wells were drilled about 14 kilometers north of the Ivar Aasen field in the central part of the North Sea and 180 kilometers northwest of Stavanger. The Hanz field was proven in Upper Jurassic reservoir rocks (Intra-Draupne formation sandstones) in 1997. Prior to the drilling of wells 25/10-16 S, A and B, the operator’s resource estimate for the discovery was between 1.9 and 3.0 million Sm3 of recoverable oil and between 0.3 and 0.4 billion Sm3 of recoverable gas.
According to the NPD, the objective of the wells on the Hanz field was to delineate the field, investigate potential additional resources in underlying Middle Jurassic reservoir rocks (the Hugin formation), reduce the uncertainty as regards the extent of the reservoir sandstones and thus lower uncertainty for the field’s estimated resources.
The primary exploration target for wildcat well 25/10-16 B was to prove petroleum in Upper Jurassic sandstones (the Intra- Draupne formation), while the secondary exploration target was to investigate the underlying Hugin formation. The prospect was partially situated in production license 915, just to the southeast of production license 028 B.
Results
Appraisal well 25/10-16 S encountered an approximate 30-meter gas column and a 30-meter oil column in the Draupne formation, of which the effective reservoir totaled about 20 meters in sandstone layers, mainly with good reservoir quality. The oil/water contact was not encountered. An aquiferous sandstone layer, about 15 meters thick, was encountered in the underlying Hugin formation, with moderate to good reservoir quality.
In appraisal well 25/10-16 A, there is an approximately 15-meter gas column in the Hugin formation, in sandstone with moderate to good reservoir quality. The gas/water contact was proven. The overlying Draupne formation contains a total of about ten meters of tight and partially tight sandstone layers.
Wildcat well 25/10-16 B encountered a total of about 15 meters of tight and partially tight sandstone layers in the Draupne formation. Approximately ten meters of aquiferous sandstone with moderate to good reservoir quality was encountered in the Hugin formation. The well is dry.
In appraisal well 25/10-16 C, there is approximately 15 meters of aquiferous sandstone in the Hugin formation, with moderate to good reservoir quality. In the overlying Draupne formation there is a total of about five meters of tight and partially tight sandstone layers. The well is dry.
Uncertainty for Hanz
Preliminary estimates of the size of the field lie within the range of uncertainty for the resource estimate before the wells were drilled. The Hanz field is included in the Ivar Aasen field’s plan for development and operation (PDO).
The wells were not formation-tested, but extensive volumes of data and samples have been acquired.
These are the four first exploration wells in production license 028 B.
Appraisal wells 25/10-16 S, A and C were drilled to respective vertical depths of 2643, 2496 and 2626 meters and respective measured depths of 2765, 3660 and 4382 meters below the sea surface. Wildcat well 25/10-16 B was drilled to a vertical depth of 2574 meters and a measured depth of 4870 meters below the sea surface. All wells were terminated in the Skagerrak formation in the Upper Triassic.
Water depth is 115 meters. The wells have been permanently plugged and abandoned. The wells were drilled by the Maersk Intrepid jack-up drilling rig, which will now drill development wells on the Martin Linge field in the North Sea, where Equinor Energy is the operator.
https://www.offshoreenergytoday.com/mixed-results-from-aker-bps-north-sea-wells/
China's output of ternary materials increased 8.3% from July to 13,000 mt in August, SMM data showed, as more downstream orders from leading companies grew production enthusiasm across producers.
New capacity in Guangdong province and in some north China also accounted for the higher output. As major cathode materials plants operated close to capacity, new orders moved to plants that commissioned new capacity or to medium-sized plants, SMM learned.
Production is likely to extend its increase in September as demand from major domestic battery plants will continue to grow, SMM expects.
https://news.metal.com/newscontent/100839078/ternary-materials-output-rise-83-in-aug/
China will speed up efforts to ensure its wind and solar power sectors can compete without subsidies and achieve "grid parity with traditional sources like coal.
Some regions have basically reached price parity whilst others need to offer technological support and policy support.
Although no date has been set for an end to subsidies, the solar sector is still reeling from the last cut in subsidies and restricted new capacity
Australia’s Lake Resources NL and America’s Lilac Solutions recently announced that they had established a partnership with the idea of developing the Kachi Lithium Brine Project in Argentina.
Lake owns the project, which is located in the northwestern Catamarca province, some 100 kilometres south of FMC's Hombre Muerto lithium brine operation. Back in 2017, Kachi received results of over 200 mg/L lithium, recorded from near-surface auger brine sampling. The results maxed out at 204 mg/L lithium. Meanwhile, Lilac is the company in charge of providing its ion exchange technology to produce lithium at the 54,000-hectare site.
What sets this partnership apart is that both the miner and the techie claim they can produce lithium carbonate or lithium chloride more rapidly and at a lower cost than others. According to Lilac, this is possible because its system eliminates the need for sprawling evaporation ponds, which are expensive to build, slow to ramp up, and vulnerable to weather fluctuations.
“Even for the world's best lithium reserves in the Atacama desert, conventional evaporation ponds take many years to ramp up and remain vulnerable to weather volatility. Lilac's projects will run at full capacity from year one of commissioning and maintain that output regardless of weather or brine chemistry. We have done benchtop testing in other brines and we saw recoveries over 95% in less than 2 hours versus 9-24 months in evaporation ponds,” the company’s CEO, Dave Snydacker, told MINING.com.
Snydacker explained that the reason why the processes run by his company are so fast is that his engineers have developed ion exchange beads that absorb lithium directly from the brine. Once they do that, the beads are then loaded into ion exchange columns and brine is flowed through such columns. As the brine contacts the beads, the beads absorb the lithium out of the brine. Once the beads are saturated with lithium, the alkali metal is recovered from them as a lithium solution, which is later on processed into battery-grade lithium carbonate or lithium hydroxide using streamlined plant designs.
According to Snydacker, this technology can economically access brines with
low lithium concentrations and high concentrations of other salts, such as magnesium. “With conventional lithium processing, very large quantities of lime and sodium carbonate need to be trucked in to remove magnesium and calcium from the brine. Lilac dramatically decreases the volumes of reagents that need to be trucked in, so we can unlock resources in remote locations. On top of this, our technology is modular so the physical footprint of our facilities is approximately 1,000 times smaller than conventional lithium brine projects using evaporation ponds,” he said.
Lake and Lilac plan to install on-site pilot plants in early 2019 and start commercial production in 2020 with the idea of selling their product to battery companies and affiliated chemical companies producing cathode powders such as NMC, NCA, and LFP.
“We currently have four process engineers working on the Lake project. For the on-site pilot plant next year, we will add three field engineers and three technicians. Each commercial plant will employ dozens of people, and we're excited to develop positive ties with the communities where we operate,” the executive said.
http://www.mining.com/aussie-miner-american-tech-company-plan-extract-lithium-quickly-argentina/
Major U.S. ethanol producer Green Plains Inc is shutting down two ethanol plants in Iowa and cutting output at another in Minnesota due to low profit margins, three industry sources told Reuters.
The production cuts come after the Trump administration’s escalating trade disputes cut off U.S. access to ethanol markets in China, contributing to a domestic supply glut that has pushed biofuel prices to near their lowest in over a decade.
Green Plains idled until further notice its facility in Superior, Iowa, and soon will shut down the plant in Lakota, Iowa, while the company’s plant in Fairmont, Minnesota, was running at half of its capacity, said the sources, who asked not to be named.
Company spokesman Jim Stark did not immediately respond to requests for comment on Monday. Green Plains in an Aug. 30 regulatory filing said, “Based on current market conditions, the company is re-assessing our production levels.”
Together, the plants represent about 20 percent of Green Plains’ annual ethanol production capacity of roughly 1.48 billion gallons. Green Plains is about tied with Valero Energy Corp as the No. 3 ethanol maker in the United States, behind POET LLC and Archer Daniels Midland Co.
Construction of a lithium-ion power battery and system project, invested by Guangzhou Great Power, was kick off at Jincheng High-tech Industry Park in Jintan district, Jiangsu province, on September 17.
The new project has a total planned investment of 5.8 billion yuan from Great Power. Its construction area is scheduled at 331,000 m², with an annual production capacity of 10Gwh lithium-ion power battery and 5Gwh lithium battery PACK, SMM learned.
The project will focus on customizing high-end production capacity, amid current shortage of high-end lithium battery capacity and surplus low-end one. It is constructed in three phases, one of which will be put into operation next June. The annual sales revenue is expected at 10 billion yuan, and its annual profit and tax at 2 billion yuan, SMM learned.
The United States did not include rare earth elements, metals used in magnets, radars and consumer electronics, from its final list of tariffs on $200-billion of Chinese goods, underscoring its reliance on China for the strategic minerals.
China is the world's largest producer of rare earths and the biggest supplier to the United States, according the US Geological Survey.
Rare earth elements and minor metals have broad applications in US industry, ranging from jet engines to mobile phones to oil and gas drilling.
Most of the minerals the US had originally targeted for tariffs were on a list of 35 minerals published by the US Department of the Interior in May that were deemed critical to the country's security and economic prosperity.]
Rare earth metals and their compounds, as well as mixtures of rare earth oxides or chlorides, were all included on a provisional list of tariffs on Chinese goods unveiled by the Office of the US Trade Representative (USTR) in July.
However, the final list released on Monday does not mention rare earths, a group of 15 lanthanide metallic elements plus the metals scandium and yttrium. The latest tariffs will go into effect on September 24 at a rate of 10%.
Permanent metal magnets and articles intended to become permanent magnets, which could include rare earth oxides neodymium and praseodymium, also dropped off the list. That category accounted for $191.2-million of imports in 2017, according to the USTR.
The United States is aware of the strategic importance of rare earth metals as illustrated by a US law passed last month that bans the purchase of rare earth magnets from China for the military in the 2019 fiscal year, said Dylan Kelly, a resources analyst at brokerage CLSA in Sydney.
The law "clearly highlighted how exposed the nation was to any kind of disruption to the Chinese supply chain," said Kelly. US politicians "should be very aware of the corner they have pinned themselves into."
Whether the Chinese will retaliate and use rare earths as a bargaining chip or "strategic lever" in future talks with the United States remains to be seen, Kelly said. "But obviously that's where a lot of investors have focused their attention."
Some minor metals used in high-tech industries, such as bismuth, titanium and cobalt, are still on the tariff list.
However, barite and antimony are not included in the new tariffs. Antimony, along with antimony oxide, made up $108.5 million of imports from China last year, according to USTR data.
Natural graphite, which is used in steelmaking and lithium-ion batteries, also won a reprieve.
Tungsten, used to harden steel, now only features in 11 categories on the final tariff list, half the original number.
Neoen has registered with France’s AMF financial regulator over a possible initial public offering (IPO), the renewable energy company said on Wednesday.
Neoen, which has around 2 billion euros ($2.3 billion) worth of assets, said the possible IPO could raise 450 million euros and would fund future investment plans and growth in production capacity.
Its plans call for total capacity in operation or under construction of at least 5 gigawatts by the end of 2021, Chief Executive Xavier Barbaro said.
Neoen was founded in 2008 by Jacques Veyrat, the former chief executive of commodities trading company Louis Dreyfus, who still owns a 56 percent stake in Neoen through his investment vehicle Impala. Neoen said Impala would remain its majority shareholder.
Neoen is also one of several start-up French renewable energy companies competing with market leaders EDF and Engie.
China produced 1.19 billion units of lithium-ion batteries in August, down 9.6% from a month ago but up 17.8% from a year ago, data from the National Bureau of Statistics (NBS) showed.
This marked the first monthly decline in China’s lithium-ion battery output since April.
In January-August, the output stood at 9.04 billion units, up 10.2% from the same period last year.
https://news.metal.com/newscontent/100839815/china%27s-lithium-ion-battery-output-down-96-in-aug/
Turkmenistan launched a $1.5 billion nitrogen fertiliser plant on its Caspian coast on Monday, seeking to diversify exports dominated by natural gas.
The plant, built by Japan’s Mitsubishi Corp and Turkey’s Gap Insaat in collaboration with Mitsubishi Heavy Industries, will produce 1.1 million tonnes of urea annually using natural gas as feedstock, and export most of its output.
Export revenues in the Central Asian nation, which sits on the world’s fourth-biggest natural gas reserves, took a hit after global energy prices plunged and Russia, once the biggest buyer of Turkmen gas, halted all purchases in 2016.
The Ashgabat government is now trying to process more gas domestically into fuel, electric power and fertilisers which it can then export, and tap the country’s other mineral resources. Last year, it launched a $1 billion potash fertiliser plant.
The Japan Bank for International Cooperation provided most of the financing for the Garabogaz nitrogen fertiliser plant, while state firm Turkmenhimiya paid the remaining costs.
The former Soviet republic has maritime links with Iran, Azerbaijan, Russia and Kazakhstan through the Caspian Sea.
Widespread frost has dented hopes that wheat growing areas in Australia’s west could provide a much needed boost to output, analysts and traders said on Monday, further tightening supplies amid a prolonged drought.
Australia, the world’s fourth largest wheat exporter, expects production of its largest rural commodity to hit a 10-year low this season at 19.1 million tonnes, as drought across the country’s east wilts output.
Many private forecasters had pegged production from Western Australia at above the 9.6 million tonnes recently estimated by the country’s chief commodity forecaster.
But as temperatures plummeted over the weekend and meteorologists warned of further cold weather this week, analysts said estimates were being quickly wound back.
“There were some in the market that were expecting 12 or even 13 million tonnes. That won’t happen now,” said Phin Ziebell, agribusiness economist, National Australia Bank.
“It will be a struggle to get to double figures.”
Tight supplies from Australia will add to concerns over global shortfalls that helped push benchmark prices to a three-year high last month.
Lower production from Western Australia may limit the country’s exports.
Australia typically ships out more than two-thirds of its production, but with drought drying out grazing and crop land across the country’s east coast, domestic millers and livestock producers are likely to dominate consumption.
Major customers of Australian wheat such as Indonesia will be forced to look to alternative markets for their supplies, a boost to the export prospects of the United States and South America particularly.
For Australia, the adverse weather in Western Australia darkens the economic outlook. The Reserve Bank of Australia in August warned that the severe drought along the east coast would cause a potential headwind to the economy.
The executive from one of China’s biggest soybean crushers sat on a panel at a Kansas City agricultural exports conference, listening to an expert beside him explain why China would remain dependent on U.S. soybeans to feed its massive hog herds.
When his turn to speak came, Mu Yan Kui told the international audience of soy traders that everything they just heard was wrong. Then Mu ticked off a six-part strategy to slash Chinese consumption and tap alternate supplies with little financial pain.
“Many foreign business people and politicians have underestimated the determination of Chinese people to support the government in a trade war,” said Mu, vice chairman of Yihai Kerry, owned by Singapore-based Wilmar International (WLIL.SI).
The comments echo a growing confidence within China’s soybean industry and government that the world’s largest pork-producing nation can wean itself off U.S. soy exports – a prospect that would decimate U.S. farmers, upend a 36-year-old trading relationship worth $12.7 billion last year, and radically remap global trade flows.
Just one prong of the strategy Mu detailed - to slash soymeal content in pig feed - could obliterate Chinese demand for U.S. soybeans if broadly adopted, according to Reuters calculations.
Cutting the soy ration for hogs from the typical 20 percent to 12 percent would equate to a demand reduction of up to 27 million tonnes of soybeans per year – an amount equal to 82 percent of Chinese soy imports from the United States last year. Chinese farmers could cut soymeal rations by nearly half without harming hogs’ growth, experts and academics said.
FACTBOX:
Soy meal provides the protein and amino acids that pigs need to thrive, but reducing their use will be easier in China than elsewhere because farmers here have long included more soy than needed to keep their hogs healthy, according to industry experts in China and the United States.
The standard 20 percent ration dates to a recipe promoted by U.S. soybean industry advocates in the 1980s as they entered what was then a newly opened market for foreign investment.
Most Chinese pig farmers have continued to use high levels of soymeal even as their U.S. counterparts reduced soy content after advancing the science of optimizing feed ingredients to provide the best nutrition at the lowest cost.
Major Chinese agriculture firms have recently started adopting the same tactics, but the nation’s pork sector remains dominated by smaller operations that - until now - didn’t have a strong financial incentive to justify the time and expense required to overhaul feeding systems and formulas, industry experts said.
Now, China’s 25-percent tariff on U.S. soybeans - a retaliation against levies by U.S. President Donald Trump on a wide range of Chinese imports - is accelerating the push to slash soymeal rations.
“The Sino-U.S. trade tensions will inevitably promote the wider application of this know-how,” said Yin Jingdong, professor in animal nutrition at China Agricultural University.
A feed mill owned by Beijing Dabeinong Technology Group Co (002385.SZ), for instance, plans to eliminate imported U.S. soybeans from its feed mix by October, said Zhang Wei, a manager at the mill, one of China’s top farmers and feed makers. The firm will replace soy imports with more cornmeal and alternative protein sources, including domestically produced soymeal, which has typically been grown for human consumption.
At the Kansas City conference, held by the U.S. Soybean Export Council, Mu highlighted reduced soymeal rations as part of a broader strategy, including seeking alternative protein sources such as rapeseed or cotton seed; tapping surplus soybean stocks, including a government reserve, and domestically grown soybeans; and continuing to boost soybean imports from Brazil and Argentina.
Mu’s presentation reflects the line of thinking now broadly accepted by China’s government and its state-run agriculture firms - and marks a shift since the onset of the trade war. When Beijing threatened soybean tariffs in April, Chinese feedmakers and agriculture experts worried the move would inflict more pain on the domestic industry than its top trading partner because China would struggle to replace U.S. supplies.
Seated to Mu’s right at the panel table was Wallace Tyner, a Purdue University economist who had moments earlier argued that the United States and China would suffer about equal financial damage from the soybean trade war.
He called Mu’s remarks a “political speech.” The tenants of the China strategy Mu outlined were achievable, Tyner said in a later interview, “but each one of them cost money.”
USDA spokesman Tim Murtaugh downplayed the threat of China displacing U.S. soybean supplies. The Trump administration, he said, is analyzing import demand and ultimately aims to win back access to the China market under better terms.
“It’s not surprising that China would float this idea, given the trade dispute,” he said.
A REVOLUTION IN TRADE
In the early 1980s, the U.S. farm lobby sold Chinese farmers on the promise that they could use imported soybeans to slash the amount of time needed to their fatten pigs, said Dabeinong’s Zhang and Feng Yonghui, chief analyst and market veteran with Soozhu.com, a Chinese hog consultancy.
The U.S. industry wanted access to a market with more than a billion people and rising per capita income, and the American Soybean Association opened an office in Beijing four years into China’s landmark economic reforms.
“They knew someday that China would need to import,” said John Baize, president of John C. Baize & Associates and a consultant for the U.S. Soybean Export Council.
China’s communist government saw another opportunity in the arrival of U.S. soy - for profits and jobs from the massive soy-crushing industry it would build to process imported beans into meal and oil, with plants strategically located near seaports. Beijing fostered the industry with a tax system that encouraged soybean imports but punished those of finished soy products.
In 1982, China imported 30,000 tonnes of soybeans. Last year, it imported 95.5 million tonnes, including 32.9 million from the United States, according to Chinese customs data. U.S. soybean plantings shot up from nearly 71 million acres in 1982 to nearly 90 million this year, worth a total of $41 billion.
FRAYED NERVES
Now, China is urgently looking elsewhere for imports. Chinese crushers bought all the South American beans they could over the past few months, building record stocks of beans and meal.
In July, the National Development & Reform Commission (NDRC) - the state economic planner - discussed ways to switch up pigs’ diets with major feedmakers and pig farmers, New Hope Group [NWHOP.UL], Dabeinong, CP Group and Hefeng Group.
On September 4, an executive of top bean processor Jiusan predicted that China will only need to buy 700,000 tonnes of soybeans from the United States in the marketing season that starts this month, a tiny fraction of what it bought last year.
With no sign of a resolution to the trade war, Bob Metz, a South Dakota corn and soybean farmer, is making plans to reduce the number of acres he devotes to soybeans next spring. He’s alerted his seed dealer that he may need more corn seed and less soy.
“It makes me very nervous,” he said, because China has been such a dominant buyer of U.S. beans.
James Lee Adams - a retired farmer from Camilla, Georgia, and past president of the American Soybean Association - was among those who worked in the 1980s to open the Chinese market to U.S. soybeans.
Now, he worries the profitable relationship could collapse.
“You develop trade partners over a long period, but you can lose them overnight,” he said. “When you start becoming an unreliable supplier, people are going to start looking elsewhere.”
The United States has supplanted Brazil as the European Union’s top supplier of soybeans since a deal in July with President Donald Trump to avert a trade war, according to EU data seen by Reuters on Thursday.
In the 12 weeks to mid-September, U.S. soybeans accounted for 52 percent of imports to the EU, rising 133 percent compared with the same period last year to 1.47 million tonnes. The United States had just 25 percent of the market in the same period of 2017.
Imports from Brazil dropped to a 40-percent share of the bloc’s roughly 35 million tonne annual import market for the animal feed staple.
European Commission President Jean-Claude Juncker pledged in a White House deal in late July that Europeans would buy more U.S. soy as part of a package to avert threatened tariffs from Washington on U.S. imports of EU cars.
The EU executive has been collating frequent new import data to prove it is keeping its side of the bargain - even though the trends are largely the result of price movements in world markets. The EU had no previous barriers to U.S. soybeans.
In June, China largely stopped buying U.S. soybeans in retaliation for trade measures Trump targeted at Beijing — prompting European farmers to switch to buying cheaper U.S. soy.
U.S. and EU negotiators have begun discussions on how to free up some trade in what Washington wants to be a bigger deal that would cut the U.S. deficit in merchandise trade.
Japanese trading Mitsubishi and Sumitomo are said to be interested in becoming a partner of Teck Resources at Canada’s largest diversified miner’s Quebrada Blanca copper mine in northern Chile.
Teck, which last month received regulatory approval for a $4.8-billion extension of the mine, has been looking for a development partner that could invest $2billion for up to 30% to 40% stake in the project.
Other companies interested in partnering with Teck include Freeport-McMoRan, China’s Aluminum Corp of China (Chinalco) and Canada’s base metals miner Lundin Mining.
Other than Mitsubishi and Sumitomo, companies that could bid for a stake in the project include Freeport-McMoRan , the world’s largest publicly-traded copper company, China’s state-owned Aluminum Corp of China , and Canada’s base metals miner Lundin Mining , which recently abandoned its quest for fellow miner Nevsun, sources with knowledge of the matter told Reuters.
In the past two years, Japanese trading companies have been grabbing assets and increasing their stakes on a few of them thanks to higher commodities prices, which have boosted their profits.
They have been particularly keen on copper assets as supply of the metal is expected to significantly outstrip supply from 2020, due to increasing demand for power generation and electric vehicles (there’s 300kg of copper in an electric bus and nine tonnes per windfarm megawatt).
Early this year, Mitsui & Co. increased its stake in Chile’s Collahuasi copper mine to 11.03%. In June, Mitsubishi Corp upped its interest in Anglo American's Quellaveco copper project in Peru by 21.9% for $600 million, taking its holding to 40%.
Last year, Quebrada Blanca produced 23,400 tonnes of copper, generating a $182 million-revenue.
The upgrade for which Teck wants a partner is expected to boost mine production to 300,000 tonnes of copper a year. The project includes building a new 140,000-tonne-per-day concentrator and the first large-scale use of desalinated seawater for mining in Chile’s arid Tarapacá region.
The Vancouver-based miner owns 90% of the mine and the country’s national mining company — ENAMI — holds a 10% preference share interest in it, which does not require the state agency to fund capital spending.
Copper, one of four business units at Teck besides steelmaking coal, oil and zinc, is considered a company's priority.
http://www.mining.com/mitsubishi-sumitomo-said-tecks-quebrada-blanca-m
Praise is pouring in for New Century Resources’ zinc tailings project at a former mine site north-west of Mount Isa, Queensland, with Mines Minister Anthony Lynham declaring it an “exciting new approach” and Queensland Resources Council CEO Ian Macfarlane labelling the project “ingenious”.
The project entails a mine site at Lawn Hill, where New Century reprocesses zinc tailings, a 304 km pipeline to transport zinc slurry, and a port facility at Karumba in the Gulf of Carpentaria.
The company has invested A$50-million to extract zinc concentrate for export from 15-million tonnes a year of tailings waste.
"Our business model focuses on extracting value from the remaining assets on the Century mine to complete the site’s required rehabilitation in a profitable and timely manner,” said New Century MD Patrick Walta.
Congratulating the company on the opening of the zinc tailings project, Lynham said that the model of economic rehabilitation was an exciting approach to dealing with mine sites once they had concluded their original intended purpose.
“It’s the ultimate recycling story, and a tangible boost and security to the north-west economy, where it’s creating 250 local jobs.”
The project is powered by Queensland gas, supplied by Santos. In terms of an agreement between the companies, Santos will supply about 9 PJ of gas to meet the electricity demands of the tailings operation.
QRC’s Macfarlane said the project demonstrated not only the sector’s collaborative approach to resources, but its ability to reprocess.
“Ultimately this zinc mine was closed because it was uneconomical, but due to the ingenuity of New Century, it’s now a jobs and exports story for Queensland,” he said.
The Century mine began openpit production in 1999. During its 16 years of operation, Century was one of the largest zinc mines in the world, producing and processing an average of 475 000 t/y zinc concentrate and 50 000 t/y lead concentrates at Lawn Hill.
The cessation of processing operations by MMG at Century in early 2016 following depletion of the Century ore reserves presented an opportunity for a focused junior to monetise valuable remaining mineral assets. These include over 2.2-million tons of zinc metal equivalent resources located within mineralised tailings, and more than one-million tons of zinc and lead resources in the Silver King, South Block and East Fault Block base metal deposits. In addition, Century hosts several substantial phosphate deposits, which are yet to be developed.
http://www.miningweekly.com/article/new-century-brings-new-life-to-former-queensland-mine-2018-09-14
U.S.-based private equity firm Black Mountain is set to buy a nickel project in Australia, pushing into a market expected to see a boom from electric vehicle demand.
A unit of the company, Black Mountain Metals LLP, will buy the Lanfranchi nickel project in the state of Western Australia for $15.1 million from Panoramic Resources, Panoramic said on Thursday.
Although the deal is not large, it underscores the growing interest in Australia’s nickel sector, where the metal is mostly found in sulphide deposits that are cheaper to turn into battery-ready material than laterite deposits which account for most of the world’s resources of the commodity.
Battery makers have been boosting nickel in their products to cut down on expensive cobalt and as it helps keep a charge over longer distances.
The deal comes after Black Mountain’s offer last month for miner Poseidon Nickel was rebuffed, although Poseidon said the two parties were still in talks.
In the meantime, Poseidon launched a A$74.6 million ($53.6 million) capital raising to restart its Black and Silver Swan mines in Western Australia. The offering closed on Wednesday.
Trading in Poseidon Nickel shares was halted on Thursday. The firm’s major shareholder, Squadron Resources, is led by Australian iron ore magnate Andrew Forrest.
If Black Mountain Metals’ bid for Poseidon is eventually successful, the Texas-based firm would secure access to a string of nickel mines as well as exploration rights and processing infrastructure. Poseidon’s assets include six mines and two concentrators.
Black Mountain also has a ready buyer in the form of BHP Billiton.
Its new Lanfranchi mine, which was put under so-called care and maintenance in 2015, is contracted until February to sell ore to BHP’s Nickel West operations, which are being retooled to supply nickel sulphate to the global battery market.
Black Mountain, founded in 2007 to invest in the commodity and energy sector, did not answer calls outside U.S. trading hours. It registered an Australian entity in July.
Panoramic said the sale would shore up its balance sheet as it restarts its own flagship Savannah nickel copper cobalt project which is due to ship concentrate early in March 2019.
The deal is awaiting regulatory approval and is expected to complete in the final quarter of the year.
Nickel producers eye Indonesia to plug into EV battery market
Several global metals producers have set their sights on Indonesia’s nickel reserves to tap an expected surge in demand for the metal for electric vehicle batteries.
Sumitomo Metal Mining Co Ltd (SMM) said on Thursday that it and nickel miner PT Vale Indonesia are conducting a feasibility study to build a nickel processing project in Pomalaa, Southeast Sulawesi.
A spokesman for Vale said the plant would make an intermediate nickel and cobalt product that would then be processed into nickel sulphate for batteries.
Major nickel producers are taking a closer look at Indonesia whose large nickel laterite ore reserves are already prized for nickel pig iron used in stainless steel production.
Indonesia’s nickel ore has largely been overlooked by battery producers, as extracting the high purity nickel they need from it requires plants that are more costly and difficult to operate than conventional nickel smelters.
That could change if producers are willing to plough investments into high pressure acid leach (HPAL) plants. The plants, which use heat and pressure to remove the nickel and cobalt from the ore, are regarded as technically challenging and expensive but produce high quality metal.
Xiao Fu, Head of Commodity Market Strategy at BOC International, said on the sidelines of Asian Nickel conference this week that the EV market “could represent growth opportunities in Indonesia” and attract interest from Chinese battery makers.
“In Asia, everyone is racing toward this new game,” she added, referring to developing projects by, which is developing a huge nickel sulphate plant Western Australia, and by China’s Jinchuan Group.
“Indonesia’s strength is in nickel ore, and nickel pig iron, but there could be a shift if this is where the opportunities are,” Xiao said.
Vale Indonesia is working on obtaining environmental permits for the proposed 40,000-tonne smelter which will process ore extracted using high-pressure acid leaching (HPAL), Business Development Manager Steve Brown said on the sidelines of the conference.
HPAL technology is “still emerging” in Indonesia, said Brown, noting that early entrants willing to invest in the more technically challenging field could be well rewarded. Brazil-based Vale is the world’s biggest nickel producer.
Chinese stainless steel-maker Tsingshan Holding Group, Indonesia’s biggest nickel producer, is leading a group seeking investors for a nickel sulphate plant to produce EV batteries in a $10 billion industrial park linked to its Weda Bay concession, the group said last month.
The group, which also includes China’s Huayou Cobalt Ltd and Zhenshi Holding Group, is looking to develop 9.3 million tonnes of nickel reserves in Weda Bay, in Malaku, jointly owned by France’s Eramet.
A China-based spokesman for Tsingshan deferred questions to its subsidiary Shanghai Decent Investment Group, which declined to comment.
Huayou’s board secretary did not immediately respond to a request for comment.
Liu Cheng, chief engineer and vice president of the China ENFI Engineering Corp, said his company is conducting studies for four Indonesian projects using HPAL to produce nickel for batteries.
Liu declined to name the companies involved because of non-disclosure agreements, but said the process could use nickel ores high in cobalt that is often discarded by Indonesia’s nickel pig iron industry.
Akira Nozaki, president of Sumitomo Metal Mining, said the feasibility study for the Pomalaa project would “probably” take up to two years.
SMM would like to take a majority stake in the project if it uses HPAL technology, Nozaki told Reuters.
Negotiations for Japanese fourth-quarter aluminium premiums moved on with eight settlements reported so far at $103/mt plus London Metal Exchange cash, CIF Japan, while more than 10 companies are still engaged in talks, sources said Friday.
A $103/mt CIF Japan premium represents a decline of 22% from $132/mt CIF Japan for the third quarter.
The eight deals are for 6,000-8,000 mt/month shipments of standard P1020/P1020A aluminium ingot combined, to be shipped over October-December period.
One producer has offered $110/mt plus LME cash CIF Japan, and a second producer $112/mt plus LME cash CIF Japan, while Japanese buyers are bidding $103/mt plus LME cash, CIF Japan or less, sources said.
Russian producer Rusal has offered $111/mt plus LME cash, CIF Japan for Q4, sources said.
Japanese buyers have not responded to the Rusal offer due to the US sanctions against the company. There is no clarity whether the sanctions will be lifted or continue after October 23, the last day of the sanction wind-down period, the buyers said.
The Japanese import volumes of primary ingot from Russia over January-March, before the April 6 US sanctions, totalled 62,672 mt, or roughly 20,000 mt/month, according to Japanese customs data.
There was no decline in volumes after April, with 21,448 mt imported in that month, 24,986 mt in May, 22,969 mt in June and 23,367 mt in July.
Not all Japanese companies have been able to process transactions with Rusal. Some Japanese buyers have decided to suspend them until the sanctions were lifted, sources said.
Japanese traders said the decision related to Japanese banks' policies. One city bank was able to process Rusal transactions, but another bank decided to wait for more clarity, they added.
But companies that have suspended trades with Rusal were buying limited volumes and did not affect the overall imports from Rusal, they said.
Norway’s Hydro said on Friday it had dropped plans to buy several of Rio Tinto’s assets, including an aluminium plant in Iceland, after approval from European Commission regulators took longer than anticipated.
The Rio Tinto's company logo is featured on a TV monitor at the mining company' annual general meeting in Sydney, Australia, May 4, 2017. REUTERS/Jason Reed
In February, Hydro made an offer to buy the aluminium plant, as well as a 53 percent stake in a Dutch anode facility Aluchemie and 50 percent of the shares in a Swedish aluminum fluoride plant Alufluor for about $345 million.
“The European Commission competition approval process has taken longer than anticipated and remains outstanding,” Hydro said in a statement.
“After considering alternative timelines, outcomes and developments, Hydro requested to terminate the transaction and the parties have signed a termination agreement,” it said.
Hydro has withdrawn its EU competition filing, it added.
Hydro, which is not interested in acquiring aluminium plants that use coal-fired power, was hoping the deal would be part of efforts to make its output as green as possible and bolster its position in Europe.
Under the deal, Hydro would have been the sole owner of the Dutch factory, while the Swedish factory would have been 50/50 owned with fertilizer maker Yara International.
Shares in top global aluminium producer China Hongqiao Group tumbled a second day after its home province of Shandong announced new fees for onsite power plants.
Hongqiao shares fell as much as 8.5 percent on Monday to HK$5.30 ($0.675), a two-year low. The shares fell nearly 16 percent on Friday.
The declines came after the Shandong commodity price bureau said owners of captive power plants would have to pay 0.05 yuan ($0.0073) per kilowatt hour (kWh) of electricity generated from July 2018, rising to 0.1016 yuan per kWh after the end of 2019.
China wants to curb the use of onsite coal-fired electricity plants - which provide cheaper power than the grid - as part of a campaign for cleaner air.
Shandong is one of the first provinces to publish such fees after China’s top economic planner, the National Development and Reform Commission, said in July it would force factories with onsite power plants to pay fees to help fund $12 billion in cuts to commercial and industrial electricity prices.
The policy will increase aluminium production costs for smelters using captive plants in Shandong by around 500 yuan a tonne in the initial 18-month period alone, said Helen Lau, an analyst with investment house Argonaut.
Lau put average industry production costs at 14,500 yuan per tonne. Aluminium on the Shanghai Futures Exchange closed down 1 percent at 14,445 yuan a tonne on Monday.
“The unit profit (for Chinese smelters) may be 200 or 300 yuan per tonne,” Lau said. “If this cost increased by 500 yuan per tonne, their profit will be wiped out.”
Smelters’ margins have already been squeezed in recent months by the rising price of alumina, the raw material used to make aluminium.
If applied across Hongqiao’s operating aluminium capacity of 6.46 million tonnes a year, the extra 500 yuan a tonne in costs would total about 3 billion yuan, Lau said. Hongqiao posted a net profit of 1.8 billion yuan in the first half of 2018.
Hongqiao said in an email to Reuters that since it has received no official notice from Shandong province on the policy that it cannot make any comment on the rise in production costs.
In a Hong Kong stock exchange announcement, however, the company said such a policy would affect the cost advantage of its “power plants to some extent but will not have a fundamental impact on the core competitive advantages of the Group.”
Brazilian mining company Nexa Resources plans to invest some $1.17 billion in copper and zinc projects in Peru and Brazil over the next five years, the company’s general manager Ricardo Porta said on Friday.
About $816 million will be invested in Peru, including $555 million in copper projects and $216 million in zinc, Porta said in an interview.
The proposed mine closest to being developed is Aripuana, a $354 million zinc project in Brazil slated to start production in 2020. “We hope to achieve final (government) approval of the project in coming months,” Porta said on the sidelines of a mining conference in Lima.
The Shalipayco zinc project and the Magistral and Pukaqaqa copper projects in Peru would follow, Porta said. Shalipayco would likely start production in 2021, Magistral in 2022 and Pukaqaqa in 2023, he said.
“Between Brazil and Peru we have seven projects,” Porta said, adding that the company’s priority was to raise its reserves, which have been growing at about 5 percent per year.
Nexa operates five mines in Brazil and the Milpo, Atacocha and El Porvenir mines and the Cajamarquilla zinc refinery in Peru.
The company expects to produce 600,000 tonnes of zinc this year, Porta said.
Baikal Mining Company, operator of Russia’s biggest untapped copper deposit Udokan, plans to raise $1.25 billion in project financing from a Russian bank by the start of 2019, its chairman, Valery Kazikayev told Reuters.
Spurred by high global appetite for cooper, which many expect to be in demand for use in electric vehicles, the company in September started preparing the site for construction of a massive plant at the deposit, which has remained in limbo in Siberia for almost 70 years.
With total reserves of 26.7 million tonnes of copper, Udokan is one of the biggest untapped deposits in the world. However, it remained virgin since its discovery in 1949 due to lack of technology for its unique and difficult ore.
When Kazikayev was receiving a PhD in Economics from the Moscow Mining Institute in 1976, one of the ideas being researched by his fellow students was a “clean” nuclear blast but that remained on paper.
It took 10 years for Baikal Mining Company, owned by Russian billionaire Alisher Usmanov, to solve the difficult parts of the project. Usmanov bought the right to develop Udokan for $500 million from the Russian government right before the 2008 financial crisis.
An additional $330 million was spent on creation of a new geological model for the deposit as it turned out that the Soviet estimate did not correspond with the real content of copper in Udokan’s ore, Kazikayev said in a rare interview.
A mix of flotation and hydrometallurgy was chosen as production technology for the project, mainly focused on Chinese and other Asian markets.
The Baikal Mining Company needs $1.35 billion to build a plant able to mine 12 million tonnes of ore a year and produce 130,000 tonnes of copper from it. Half of the product will be cathode copper and the other half copper concentrate.
TIMELINE
The company plans to invest $100 million in the project and raise the $1.25-billion project financing for the rest of the sum, Kazikaev said. With annual capacity of 12 million tonnes of ore, the project will have an internal rate of return of at least 21 percent.
Udokan, which can potentially be expanded to 48 million tonnes in future, may speed up expansion subject to favourable market conditions for copper.
“Copper is one of the most promising metals,” Kazikaev said. “That is why I think that the timeline of the project’s capacity reaching 24, 36 or 48 (million tonnes of ore) may be tightened.”
Two of four global mining giants and three Chinese companies have expressed interest in the project, and while the Russian company remains in contact with them, it currently plans to go ahead with the project on its own.
“We have not been offered enough (for a stake in the project) to make us strongly interested in this. We believe that we can do the first stage of the project on our own and thus increase the capitalisation of our project to a beneficial level,” Kazikayev said.
Any foreign investment in the project, Kazikayev added, would be limited by Russia’s law, which allows foreign investors to own a stake of only up to 25 percent in deposits like Udokan, deemed strategic for Russia, and also limits investment from companies owned by other countries’ governments.
The operator plans to start sub-commercial production at the deposit at the end of 2021 which will reach its full production capacity in 2022.
China’s zinc production in August fell to its lowest since October 2012, according to National Bureau of Statistics data released on Monday, as weak margins and an environmental crackdown continue to crimp output.
* China August zinc output falls 7.9 pct y/y to 431,000 tonnes – stats bureau
* China August iron ore output rises 5.6 pct y/y to 64.66 mln tonnes – stats bureau
* China August alumina output rises 6.3 pct y/y to 5.59 mln tonnes, lowest since December 2017 – stats bureau
* China August refined copper output rises 10.5 pct y/y to 749,000 tonnes – stats bureau
* China Aug lead output rises 8.1 pct y/y to 413,000 tonnes – stats bureau
https://www.hellenicshippingnews.com/china-aug-zinc-output-lowest-since-oct-2012-stats-bureau/
Chinalco plans to invest some 5.81 billion yuan to construct a new alumina project in Fangchenggang of Guangxi province, the company announced on Monday September 17.
The project has an annual capacity of 2 million mt, and will be monitored by Guangxi Huasheng New Materials in terms of its construction and operation. In light of this, Chinalco also plans to increase the capital of Guangxi Huasheng by 838 million yuan, SMM learned.
The new project will leverage Chinalco's overseas bauxite projects and regional aluminium projects, according to the company announcement.
https://news.metal.com/newscontent/100839349/chinalco-to-invest-in-fangchenggang-alumina-project/
Hong Kong- and Australia-listed MMG has lowered its 2018 copper concentrate production guidance for the Las Bambas mine, in Peru, to between 375 000 t and 395 000 t, from an earlier guidance of 410 000 t to 430 000 t.
The lower production forecast is as a result of wall instability restricting access to mining in sections of the Ferrobamba pit, where instability was also a problem in late 2017.
Mill throughput rates, although having improved, also remain below planned levels, the company said on Tuesday.
As a result, production will be lower and costs will go up, with the C1 cost guidance having been increased to between $1.10/lb and $1.20/lb, compared with a previous guidance of $1/lb to $1.10/lb.
MMG noted that the issues were not expected to have an impact on production in the medium term.
http://www.miningweekly.com/article/mmg-slashes-las-bambas-copper-forecast-2018-09-18
Armenal, an aluminium foil plant in Armenia, has started reducing output due to U.S. sanctions which have hit its owner, Russian aluminium giant Rusal, said a source at the plant and a source close to Rusal.
Base metals producer Central Asia Metals (CAML) on Wednesday reported a more than doubling in first-half revenue and profits following the acquisition of a mine in Macedonia and said it was actively looking for new opportunities to expand.
Aim-listed CAML bought the Sasa zinc and lead mine in Macedonia in September 2017 for $402.5 million, with a combination of debt and equity. The company also owns a copper mine in Kazakstan.
Miners are struggling to find opportunities to grow, especially in copper, a metal expected to be in strong demand from a more electrified economy.
CAML’s share price rose 1.3 percent by 0859 GMT, after a nearly 30 percent fall so far this year.
Share prices in the sector have been hit by the trade dispute between China and the United States that has knocked commodity prices. Copper has fallen around 15 percent this year.
Nigel Robinson, CAML’s CEO, said in an interview the company was focused on controlling costs to offset weakening markets and it was looking for a further acquisition, in copper or another base metal.
“Given that our Sasa integration process is now largely complete, we are once again actively looking for additional growth opportunities,” he said, adding he was largely agnostic as to where.
CAML has managed to hold zinc costs steady at the Sasa mine at 44 cents per pound mined, but copper costs in its Kazakh operations rose to 53 cents per pound from 45 cents per pound mined. Robinson said the increase was down to higher staff costs and electricity prices.
Revenues and EBITDA (earnings before interest, tax, depreciation and amortisation) rose to $102.4 million and $64.6 million respectively, both around 160 percent higher versus the same time a year ago.
CAML held its dividend steady at 6.5 pence per share, which analysts at Peel Hunt said was a sign of confidence from management.
The start of aluminium production at Russia’s Taishet aluminium smelter, a project of sanctions-hit Rusal, has been postponed until after 2020, Russia’s economy ministry said in materials prepared for a government meeting.
Rusal, which was targeted by U.S. sanctions in April, previously planned to build the first line of the Siberian smelter, with an annual capacity of 430,000 tonnes, by 2020.
“Construction of ... Taishet smelter continues. However, the time frame for commissioning of aluminium production capacity is postponed until after 2020,” the ministry said.
Rusal, the world’s No.2 aluminium producer after China’s Hongqiao, declined comment.
Russian power company Rushydro, Rusal’s potential partner in the Taishet project, did not reply to a request for comment. Rushydro said previously that its plans to join the project had been complicated by the U.S. sanctions.
The United States imposed sanctions on several Russian businessmen, including Rusal’s co-owner Oleg Deripaska, and some of the companies they control in April, in response to what it termed “malign activities” by Russia.
Rusal started work on the Taishet project in 2006. The project was mothballed in 2009 due to weak aluminium prices, but dusted off last year as prices recovered. In April, Rushydro’s board approved the move to join the project with total investments seen at around $1 billion.
Rusal’s other Siberian smelter - Boguchansk - plans to launch new capacity after expansion in 2019, the economy ministry added. Rusal plans to double Boguchansk’s capacity from the current 150,000 tonnes.
Rusal’s Armenian foil-rolling plant, Armenal, has started cutting production due to the U.S. sanctions, a source at the plant and a source close to Rusal said on Tuesday.
The Shanghai Futures Exchange (ShFE) will launch copper options trading on Friday, aiming to take a slice of a $270 billion global market in one of its biggest challenges yet to London and New York rivals.
The product, which follows the launch of sugar and soymeal options last year, comes as the exchange also considers opening its flagship copper futures to foreign investors, and is a major step in China’s prolonged effort to develop its derivatives industry.
Options help metal consumers, producers and traders manage price exposure. A contract gives the buyer the right - but no obligation - to assume a futures position at a specified price.
Over the past decade, the Shanghai bourse which was set up in 1999 has carved out a bigger share of the global copper futures market, challenging the London Metal Exchange’s (LME) near dominance as China’s economy boomed and retail investors flocked to commodities futures trading.
Now it wants a part of the burgeoning options business.
Volumes of copper options traded on the LME totaled around $265 billion last year at current prices, up 0.3 percent on a year earlier, while Comex copper options traded on CME Group (CME.O) almost tripled to 104,490 lots in 2017, worth about $7.3 billion.
Some Chinese copper firms already trade options on the established London and New York markets, but others are not able to stump up the foreign currency required as collateral for trading. The ShFE copper contract is denominated in yuan.
“At the moment, ShFE copper options can be best seen as alternative to onshore market participants with restricted or no access to LME copper options,” said Rochelle Wei, CEO of J.P. Morgan Futures Co.
Hedging in China rather than overseas may also better reflect the domestic market for local players, said Qiu Guoyang, assistant general manager at Shenzhen-based brokerage Jinrui Futures.
He expected the ShFE launch to eventually have an impact on options volumes on the LME, which was founded in 1877, although not in the short term.
In an emailed response, the LME said it sees the Chinese market as a complementary trading system “stimulating arbitrage flow and helping to grow the market as a whole.”
CME global head of metals, Young-Jin Chang, also welcomed the new product and noted that 20 percent of its volume originates outside U.S. trading hours, pointing to demand in Asia.
GOING GLOBAL
Underscoring its determination to support the options contract, the ShFE has lined up 18 market makers, to fuel activity, far more than the handful that is usual for international exchanges.
Those include a unit of Jinrui Futures, a subsidiary of Jiangxi Copper Co (600362.SS), (0358.HK), one of China’s biggest copper smelters, and state-run diversified metals firm China Minmetals Corp [CHMIN.UL].
Swiss commodity trading house, Trafigura [TRAFGF.UL], which has a China-based trading unit, will also be involved in the first day of trading, a spokesperson said.
Success may depend on whether smelters and fabricators use the home product for hedging or if it becomes a playground for speculative investors, who often dominate other Chinese futures markets, like iron ore and coal, and cause wild volatility in prices, analysts said.
Launching an options contract will also help ShFE garner more traction with international players as it prepares to open its copper futures contract to foreign investors.
ShFE has not given a date for the internationalisation yet.
The exchange launched a crude oil futures contract [0#ISC:] in March that aims to compete with rival global benchmarks and the Dalian Commodity Exchange opened its iron ore futures [0#DCIO:] to outside investors in May.
Some 164,600 mt of copper scrap, across more than 40 companies, received the green light in the 20th and latest batch of approvals for restricted solid scrap imports, according to the release earlier this week by the solid waste management centre of China's Ministry of Ecology and Environment (MEE).
The latest batch of approved volume stood the highest among the 20 batches thus far this year.
Zhejiang Judong and Taizhou Chiho-Tiande were included in this batch, with their volumes accounting for some 43% of the overall approved volume.
The 20th batch of approvals brought total approved copper scrap imports this year to 903,200 mt, down some 70% from the volumes approved in 11 batches last year.
China’s bauxite imports increased 8.4% from July in August, after a 2.2% month on month decline in July, showed China Customs data. More imports from Guinea as its rainy season ended, and higher demand from Yunnan province, accounted for the rebound.
Data showed that China’s bauxite imports stood at 7.89 million mt last month, up 20.9% from a year ago. This brought the overall imports during the first eight months up 28.5% on the year, to 57.47 million mt.
Last month, imports from Guinea grew 16.5% from July to 3.45 million mt, and imports from Australia rose 20.7% to 3.15 million mt. Imports from the two counties accounted for a larger share of 83.5% in total imports for August, SMM learned.
In addition, China also imported more cargoes from Malaysia, which came in at 196,000 mt in August, as the Malaysian government eased its ban on bauxite export. Greater demand in Yunnan bolstered imports from Jamaica to 91,000 mt last month.
More traders have participated in bauxite import trade, SMM learned. Forward cargoes procured by State Power Investment Corporation (SPIC) arrived at Chinese ports in August, totalling 243,000 mt.
https://news.metal.com/newscontent/100840052/bauxite-imports-rebound-in-aug-after-rainy-season/
Global miner BHP Billiton Ltd said on Thursday that a fire at its Spence copper mine in Chile had forced it to partially shut down operations.
No one was injured in the fire, which has since been extinguished, the company said.
“Operations in the area were stopped immediately and we undertook the safeguards and procedures necessary to protect our workers,” a company representative told Reuters.
Spence produced 198,600 tonnes of copper in 2017.
India's 12 major government-owned ports imported 12.49 million tonnes of coal in August, up 34.21% year on year but down month on month.
Some stainless steel producers in Ningbo of Zhejiang province have suspended as of September 14 as provincial inspection team visited the city earlier this week on Tuesday. Output of #201 products will be affected if those plants failed to resume within the month, SMM expects.
The inspection is scheduled to last 20 days, until September 30. It aims to check the effect of the previous rectification work.
The type 201 stainless steel is a mid-range product with a variety of useful qualities. While it is less expensive than some other alloys, due to its low nickel content, it is not a good choice for structures that may be prone to corrosive forces. In China, it is often used as a lower-cost substitute for #300 products.
Australia's Hancock Prospecting subsidiary Redstone has sweetened its takeover offer for fellow Australian company, iron ore miner Atlas Iron, the takeover target said in a statement to the Australian Securities Exchange Thursday.
"Redstone has stated that its offer price will increase to A4.45 cents ( $3.21 cents) per Atlas share if Redstone's voting power increases to 87%, or more during the offer period. If the condition is satisfied, Redstone will also pay an additional A0.25 cents per Atlas share to shareholders who accepted the Hancock Offer prior to any change in the offer price," Atlas said.
Previously the bid was for A4.2 cents per share. Redstone's current voting power in Atlas is 76.3%, Atlas said.
Previously, the directors of Atlas had unanimously recommended Hancock's offer to shareholders.
The offer is currently due to close September 21.
Atlas, which operates in Western Australia's Pilbara region, has been struggling with the impact of discounts for lower-grade iron ore, and higher operating costs.
In 2017-2018 (July-June) fiscal year, the miner sold 9.22 million wet mt of iron ore, which is down 36% from 14.35 million wmt the year prior, Atlas said earlier in the year.
Its' C1 cash cost in the fiscal year was A$39.30/wmt, which is up from A$34.76/wmt in fiscal 2016-2017. Its full cash cost was A$59/wmt, up from A$53/wmt over the same period, it said.
Meanwhile, the company's realized price for iron ore for the period was level with the full cash cost at A$59/wmt, down from A$61/wmt the year before.
Atlas had previously said it will formulate its fiscal 2018-2019 guidance once it has considered the outcomes of Redstone's strategy review, and in the interim will continue operating its Mt Webber mine at around 7 million mt/year.
Steel mills in Tangshan, China’s top steelmaking city, are rushing to install equipment to meet new ‘ultra-low’ emissions targets by an Oct. 31 deadline, as the measures to battle pollution threaten more upheaval in the debt-laden sector.
Only a handful of mills have installed the technology that removes sulfur, nitrogen and dust and costs up to 200 million yuan ($29 million), according to analysts who have tracked the more than 150 sintering plants in the city affected by the new rules, which were only announced in July.
“Everyone is trying to speed up the (upgrade) project ... Still, time is very tight,” said an environmental manager at Hebei Donghai Special Steel Co, a privately owned mill with annual capacity of 10 million tonnes. She declined to be named as she is not authorized to talk to media.
The environment ministry said in February it would enforce tough new emissions on steel mills, but did not give details.
In July, the Tangshan city government ordered companies in the steel, coke and coal-fired power sectors to comply with the new standards and gave mills until end-October to meet the targets.
Until last week, only five of the 152 sintering machines in Tangshan that need to be upgraded have met the stricter emissions targets, according to research by analysts at Huatai Futures and Guosen Securities.
Much is at stake for mills. Those that comply with the restrictions in time will be exempt from curbs to output during the winter heating season.
If they miss the deadline, they will have to cut output and the government has warned that some sintering plants may be shut down.
This is the second year that China will force steel mills, aluminum smelters and other heavy industry in the smoggiest northern regions to cut output during winter to counter a rise in emissions from the country’s coal-fired power stations due to increased demand for heating.
Tangshan Delong Steel Co Ltd, a privately owned mill with annual capacity of 2.4 million tonnes, started work on its upgrade last year and is one of the first to comply with the new standards.
“It takes time to install and test the devices,” said Kan Ruimin, manager at the engineering department.
Mills must cut the concentration of particulate matters to 10 micrograms per cubic meter from 40 micrograms, while sulfur dioxide and nitrogen oxide concentrations must drop to 35 micrograms from 180 and to 50 micrograms from 300, respectively.
“Big mills are enforcing the emission regulations, but for some debt-laden producers, funding is a big obstacle,” said Zhao Yu, steel analyst at Huatai Futures.
Closures of sintering plants will likely spur demand for iron ore pellets, adding further upwards pressure on prices, which have risen a third this year, Zhao said.
Iron ore fines go through a highly pollutive sintering process before they are thrown into the furnace to make steel. Higher grade iron ore pellets can go straight into the furnace, avoiding that process.
India’s steel minister said on Thursday he wanted the finance ministry to scrap the 2.5% duty on imports of coking coal, a key steelmaking raw material, to limit input costs.
“We are pursuing a cut,” Chaudhary Birender Singh told reporters. “We want to make it zero. It cannot be 2.5% to 2%.”
India’s coking coal imports rose 13% in the 2017/18 fiscal year that ended in March.
Mining giant Glencore Plc and Japanese utilities have resumed thermal coal supply negotiations, restarting talks that fell apart earlier this year as prices hovered near a six-year high.
Glencore and Japan’s Tohoku Electric Power Co are discussing an annual supply contract starting in October at $103 to $118 a metric tonne, analysts at Credit Suisse Group AG wrote in a report this week.
Previous efforts to reach a deal, for supplies starting in April this year, broke down.
Spot prices for Australia’s Newcastle coal, a regional benchmark, have been robust the past three months, trading near the highest in more than six years.
Glencore declined to comment on contract discussion. A spokesman for the Japanese utility said the company holds discussions with suppliers as needed, but declined to comment specifically on talks with Glencore. “Tohoku usually buys more volume under the October-September contract, therefore, a settlement is more likely to be reached this time,” said Prakash Sharma, research director at Wood Mackenzie Ltd, predicting they would eventually agree to around $110. “Even if the April episode is repeated, we don’t think it would be the end of the reference pricing system as some buyers in Japan and wider Asia continue to have a preference for contract pricing.”
Newcastle coal on the Globalcoal index hit $117.95 a ton in July, the highest since February 2012. The fuel has averaged about $105 in 2018, heading for the most since 2011.
Prices closed at $114.40 on Thursday.
Japanese coal users have raised concerns over Glencore’s expansion in Australia, where Japan gets about three-quarters of its thermal coal.
Jera Co, one of Japan’s biggest buyers, warned the nation’s antitrust regulators last year that Glencore’s purchase of Rio Tinto Group’s Hunter Valley mines in Australia would give it a dominant position as a supplier and hurt competition, Bloomberg News reported in December.
Analysts at Credit Suisse see possible support for those worries.
Major miners could avoid trading cargoes on platforms such as Globalcoal to keep visible pricing illiquid, they wrote in the September 12 note, citing a McCloskey report that Glencore won a tender to sell coal to Korean companies at $95 a tonne.
“We conclude that Glencore – the biggest Hunter Valley coal producer – would prefer to win contracts at lower prices than add liquidity to the spot market,” they wrote. “Extreme illiquidity has probably helped the Newcastle spot coal price remain so resilient.
It could be intentional – an expression of the pricing power that major miners are beginning to exercise over the price following consolidation.”
https://www.hellenicshippingnews.com/glencore-returns-to-japan-coal-talks-scuppered-by-high-prices/
Yangquan, a key anthracite base in eastern Shanxi province produced 3.96 million tonnes of raw coal in July, dropping 13.4% on year.
The price spread of high-grade nickel pig iron (NPI) and nickel in the Chinese market turned into discounts as of Friday September 14 as supplies grew significantly in September, SMM learned.
Discounts stood at 3.50 yuan/mtu as of Monday September 17.
Two major stainless steel mills in east China are expected to import some 40,000 mt in physical content of high-grade NPI in September, after they failed to import any in May-August. A producer in the east also added 30,000 mt in physical content of high-grade NPI into the market earlier this month.
https://news.metal.com/newscontent/100838996/supply-surge-weighs-on-prices-of-high-grade-npi/
Harbin, capital city of Heilongjiang province in northeastern China, may suffer a shortage of coal totalling 7 million tonnes in heating season
Tokyo Steel Manufacturing Co Ltd, Japan’s top electric-arc furnace steelmaker, on Tuesday said it would hold steel product prices steady in October to make sure hikes implemented early this year were absorbed by the market.
This will mark the eighth straight month Tokyo Steel has kept the prices unchanged. It last raised prices in February.
The company’s pricing strategy is closely watched by Asian rivals such as South Korea’s Posco and Hyundai Steel Co, as well as China’s Baoshan Iron & Steel Co Ltd (Baosteel).
Prices for steel bars, including rebar, will remain at 69,000 yen ($617) a tonne, while the company’s main product, H-shaped beams, will stay at 89,000 yen, Tokyo Steel said.
“Overseas steel prices remained firm reflecting vigorous demand, while Japan’s domestic demand continued to be strong in segments such as automobiles, machineries and construction,” Tokyo Steel Managing Director Kiyoshi Imamura told reporters at a briefing.
“But works at end-users of steel have been delayed due to a shortage of fabricator capacity, making wholesalers staying hesitant to raise product prices,” he said.
Imamura said, though, that the company wants to raise prices soon to pass on surging expenses for electrodes and electricity.
Asked about the escalating trade spat between the United States and China, Imamura said there has been limited negative impact on the global steel market, given solid local demand in China, the world’s biggest consumer of the metal.
“We are closely watching China’s output. But we expect no change in healthy demand in China and limited exports from China at least until the end of this year,” he said.
U.S. President Donald Trump escalated his trade war with China on Monday, imposing 10 percent tariffs on another $200 billion in Chinese imports, but sparing smart watches from Apple and other consumer products such as bicycle helmets and car seats for babies.
Australian miner New Hope Corp on Tuesday said thermal coal prices would push higher in coming months, extending a rise that helped boost its profits in the last financial year.
The company said its full-year pretax profit climbed 6 percent to A$149.5 million ($107.49 million) from $140.6 the year before, as markets for thermal coal priced in Australian dollars soared on the back of pollution-linked output curbs in major supplier China.
“We are seeing continued (demand) strength for that premium product, and it is attracting a good price because there is no significant increase in supply being driven by the price signal,” New Hope Chief Executive Shane Stephan told Reuters.
“Australian mines are at their capacity and it’s very difficult to get approvals for any new coal mines, and as a result people can’t react quickly.”
Australian spot thermal coal cargo prices in recent months hit their highest in six years, and at $120 per tonne remain a third above lows in seen in April. They were boosted by a heatwave across the northern hemisphere, as well as by the output cuts in China, the world’s biggest consumer of coal.
“We would (usually) be expecting to see lower coal prices than we are currently seeing in markets because right now is shoulder season, so it’s the end of the northern hemisphere summer,” Stephan said.
“(Consumers) don’t really start restocking for winter until the end of October to the start of November, and we are still seeing quite high prices ... These are good signals for the immediate future.”
New Hope, one of Australia’s main coal miners, is waiting on approval to extend its Acland operations in the state of Queensland, with regulators set to consider the move in early October.
The firm said on Tuesday that in the last financial year it lodged a A$132 million impairment on its Colton project, also in Queensland, as part of ‘take-or-pay’ obligations linked to access to the Wiggins Island Coal Export Terminal (WICET).
The terminal obtained court approval last week for a $3.2 billion debt refinancing plan, offering respite to its owners including Glencore and New Hope who would have had to start repayments this month.
New Hope sells most of its coal to Japan and Taiwan, ahead of China. It has also seen a pick up in demand from Vietnam.
The miner has not seen any change to its investor base as a result of environmental concerns, Stephan said.
Japanese trading house Marubeni Corp said on Tuesday it would halve its net coal-fired power generating capacity of about 3 gigawatts in the current business year by 2030 to reduce its greenhouse gas emissions.
“As a general principle, Marubeni will no longer enter into any new coal-fired power generation business,” the company said in a statement announcing its new business policies on coal-fired power and renewables.
But it added that it might consider pursuing projects that adopt the best available technology and are compliant with the policies and measures of the Japanese government and any country in which the project will be executed.
“Looking forward to the expansion of the renewable energy generation business, Marubeni will strive to expand the ratio of power generated by renewable energy sources in its own net power supply from approximately 10 percent to approximately 20 percent by 2023,” it added.
In Asia Pacific thermal coal circles it is known as the “great decoupling” and refers to the yawning gap between spot traded prices for Newcastle 6,000 NAR thermal coal and another grade of Newcastle thermal coal, 5,500 kcal/kg NAR.
That gap has blown out to an unprecedented $50/mt, from only $10/mt in early February, and the phenomenon has not gone unnoticed in wider business circles.
A September 12 report in the London Financial Times headlined “Why Asia needs a new thermal coal price benchmark” discusses this dramatic price gap and speculates that it might imperil existing benchmark indices for the 6,000 kcal/kg NAR grade.
Proponents of high prices for Newcastle 6,000 kcal/kg NAR coal insist supply of this specification remains tight due to underinvestment in Australia’s coal sector and recent industry consolidation. Others are unconvinced, pointing to the small number of spot trades for this grade at irregular intervals, and clustered around the time of Japanese contract price talks.
The price gap could be squeezed sooner than many expect, as Japan quietly moves to restart a number of its stalled nuclear power generators left idle since the Fukushima accident in 2011.
Newcastle 6,000 kcal/kg NAR benchmark prices also appear to have decoupled from market prices for other grades of thermal coal, including Platt’s NEAT coal index for Japan, South Korea and Taiwan, and which some would argue is a contender for Asia’s new price benchmark for thermal coal.
For NEAT, an index that tracks the price of cargoes delivered to Japan on a 5,750 kcal/kg NAR CV basis, the price differential to Newcastle 6,000 kcal/kg NAR prices is currently $30/mt, after hitting a high of $37/mt in August.
The NEAT price index is based on traded prices for the liquid Newcastle 5,500 kcal/kg NAR market, which is generally shipped to China, though cargoes have traveled to India, Turkey and Mediterranean Europe, plus indicated freight for Panamax ships on the Newcastle to Kinuura, Japan trading route.
The lift-off in Newcastle 6,000 kcal/kg NAR prices started in early May, around the time that annual price negotiations for deliveries of Australian shipments to Japanese power plants over the 2018-2019 Japanese financial year became intractable.
Instead of being wrapped up quickly in convivial meetings over tea in Tokyo, this year’s talks foundered amid a soured atmosphere as price negotiators for the largest buyer and seller of Australian thermal coal in the Japanese market were unable to agree a price for their April-year term contracts.
Eventually, the April talks were abandoned, and a benchmark deal was salvaged when two other Japanese power companies and their large Australian supplier agreed a price of $110/mt for shipments of Newcastle 6,322 kcal/kg GAR — equivalent to 6,000 kcal/kg NAR thermal coal — for the Japan’s fiscal year 2018-19.
The price differential between Newcastle 6,000 kcal/kg NAR prices and NEAT and Newcastle 5,500 kcal/kg NAR continued to expand through June to August as Chinese demand for high-ash Australian thermal coal slumped on import controls, and its price hit close to $60/mt FOB Newcastle.
How much longer prices for Newcastle 6,000 kcal/kg NAR thermal coal — the grade used mostly by Japanese power generators — can remain out of kilter with wider Asian market prices will have to be seen.
It is a multi-million dollar question, to which only the market can provide an answer. But, when it happens, the price correction could deliver a heavy blow to those with bullish market positions for Newcastle 6,000 kcal/kg NAR thermal coal.
https://www.hellenicshippingnews.com/out-of-kilter-newcastle-6000-nar-thermal-coal-prices-put-future-of-asian-benchmark-in-question/
Shanghai rebar steel futures edged higher on Monday after weekend data showed that China’s home prices accelerated in August at the quickest pace in almost two years, boding well for steel demand in the world’s top consumer.
Signs of more and stricter production curbs in China this winter also helped buoy steel prices, but investors are keeping a close eye on new tariffs that the United States could announce on about $200 billion of Chinese imports as early as Monday.
The most-traded January rebar on the Shanghai Futures Exchange closed up 0.6 percent at 4,100 yuan a tonne. The construction steel product has gained nearly a fifth this year.
Average new home prices in China’s 70 major cities rose 1.4 percent in August from a month earlier, according to Reuters calculations from an official survey published on Saturday.
Evidence of a strong housing market in China helped mitigate the weak data on fixed-asset investment, ANZ analysts said. Fixed-asset investment growth slowed to 5.3 percent in January-August, below market forecasts for 5.5 percent, on slower infrastructure expansion.
“Rising home prices should not trigger stricter tightening measures in (China for) fear of derailing economic growth amid increasing external uncertainties,” Argonaut Securities analyst Helen Lau said.
Also aiding steel prices, China’s top steelmaking city of Tangshan is considering smog-busting steps this winter that set penalties for heavy industry, pharmaceutical and pesticide firms based on their efforts to curb emissions.
Among steelmaking raw materials, coke and coking coal prices were firmer while iron ore slipped. The most-active January coke on the Dalian Commodity Exchange rose 1.2 percent to settle at 2,278 yuan per tonne.
Coking coal added 0.1 percent to 1,292 yuan a tonne and iron ore eased 0.4 percent to 500 yuan.
https://www.hellenicshippingnews.com/shanghai-rebar-rises-after-upbeat-china-housing-data/
Global coal shipments grew by 3.8% – or by 30.6 million tonnes – during the first eight months of the year to 835.5 million tonnes, shipbroker Arrow said on September 14, citing vessel tracking data.
"Growth was once again driven by strong demand from the Asia-Pacific countries, led by China and India," it said in a note.
"Other developing countries in the region, such as Pakistan and Vietnam, also saw strong growth as their energy consumption continue to grow rapidly and they depend heavily on the coal-fired capacity for power generation".
Imports into Pakistan were up by 45%, while Vietnam's imports grew by 65%, according to Arrow estimates.
"Although domestic coal production in India grew by 8%, imports of thermal and coking coal also continued to rise rapidly," the shipbroker said, adding imports were up by 15%, or 14.2million tonnes in the first half of the year as power generation and steel output grew by a "robust" 5.3% and 5.1%, respectively.
"Chinese coal imports were also up sharply so far this year as demand from the power generation and steel industries remained strong, but domestic coal production dwindled," it said, noting in the first eight months, imports including lignite were up by 14%, whereas raw coal production fall by nearly 3%.
China’s three major steel groups and a state-backed asset management company have create an asset management joint venture to offer financial support for consolidation in the steel sector.
Baowu Steel Group, Ansteel Group, Magang Group and China Orient Asset Management Co have invested 2 billion yuan ($291.30 million) to set up Huabao Metallurgical Assets Management Co, according to a statement issued by Magang on Monday.
Baowu will hold 37.5 percent of the new joint venture, while Orient Asset and Ansteel will take 25 percent each with Magang holding 12.5 percent.
“I hope each shareholder of Huabao could fully use their resources...to actively manage the non-performing assets in steel and related industry through market measures,” said Wei Yao, chairman of Magang Group in the statement.
The establishment of Huabao will help China to meet its goal of cutting excessive production capacity in the steel sector by phasing out inefficient mills through mergers and acquisitions that will further streamline the industry.
By 2020, China’s top 10 steelmakers will account for 60 percent of national capacity, up from one-third currently, according to central government’s latest five-year plan.
In 2015, Baosteel acquired its rival company, Wuhan Iron and Steel, and formed the country’s biggest steel company Baowu Group.
“Huabao will aim to offer a new solution for consolidation in steel sector,” said Chen Derong, chairman of Baowu Steel Group in a separate statement.
Finland’s Outokumpu, one of the world’s largest stainless steelmakers, said the United States would grant very few steel tariff exemption requests, adding it expected U.S. stainless prices to resume their upward trend as a result.
U.S. President Donald Trump slapped a 25 percent tariff on imported steel this spring but allowed companies to apply for exemptions if the metals they needed were not available in sufficient quality or quantity, or in reasonable time.
As of Aug. 20, the U.S. Commerce Department had received more than 37,000 exemption requests but approved just 1,780, despite hiring extra employees and contractors to deal with the deluge of requests.
U.S. stainless prices have recently held steady despite the tariffs, but Outokumpu said the pause was temporary and U.S. prices should resume their upward trajectory.
“As always with trade disruptions, the dust has to settle,” Outokumpu Chief Executive Roeland Baan told Reuters at an industry gathering in Helsinki.
He said U.S. importers were officially paying the tariff but steelmakers outside the United States were effectively absorbing it by lowering their export prices by some 25 percent.
“They’re doing this because they expect that ultimately their clients will get exemptions. That’s not going to happen. When (this) becomes clear, I see more upside potential for pricing in the U.S.,” he said.
Outokumpu reported record high stainless deliveries in the second quarter, but earnings fell 32 percent due to higher U.S. costs and lower stainless prices in Europe, where imports have surged as an indirect result of the U.S. tariffs.
Baan said European orders had yet to pick up despite the EU having, since July, imposed both tariffs and quotas on steel imports in a bid to prevent steel originally meant for the United States from being diverted to Europe.
“(Stainless) imports are still taking up almost a third of the EU market,” said Baan. But he said EU producers would feel the benefits of the EU measures by the end of the year as import quotas would by then be full.
Outokumpu’s largest competitors include China’s Tsingshan and TISCO, Spain’s Acerinox and Luxembourg-based Aperam.
Jincheng city in the south-east of Shanxi province finalised the degree of output cuts across the coke, steel and foundry sectors for the 2018/2019 winter, according to a document from the city government.
Steel mills across the city will be required to cut capacity by half from November 1, 2018 to March 15, 2019. Mills with pollutant emissions below the ultra-low standards will be excluded from the output cuts, except when an orange-level alert is issued for pollution.
The document also requires coke plants to cut production by 30% from October 1, 2018 to March 15, 2019. This excludes plants that can meet pollutant emission standards and upgrade emission systems before October 1.
India’s steel ministry has proposed increasing the effective import duty on some steel products to 15 percent from current rates ranging from 5 percent to 12.5 percent, according to two sources and a government document reviewed by Reuters, as the country looks to support the rupee.
The proposal, which is part of a broader government plan to cut “non-necessary” imports to stop an outflow of dollars that has sent the rupee to record lows, will be discussed in the trade ministry on Wednesday, according to one of the sources involved in the matter.
“The broader message is to address the trade balance but we will try to promote ‘Make in India’ by encouraging domestic (steel) production,” said the source, who declined to be named ahead of a possible decision.
The source said there was no certainty that the proposed duty would be imposed.
The steel and trade ministries did not immediately respond to requests seeking comment.
In the three months to end-June, India became a net steel importer for the first time in two years, with foreign supplies reaching 2.1 million tonnes, up 15 percent from a year earlier, according to official data.
In calendar 2017, India imported more than 7 million tonnes of steel from countries including South Korea, Japan and China.
China Shenhua Energy Co., Ltd, a listed arm of China Energy Investment Corporation, produced 25.4 million tonnes of coal up 9.5% year on year.
Some secondary lead smelters without production license in Henan province are likely to continue their suspension of output this month as the provincial environmental protection bureau would kick off a round of probes over hazardous wastes businesses during September 18-30, SMM expects.
Transportation and treatment of battery scarps are also expected to face more rigorous scrutiny.
The environmental protection bureau’s another week-long round of inspections over polluting enterprises across the province, starting from September 13, shuttered those secondary lead smelters. This impacted secondary lead supply by 300-400 mt per day. Some local refiners told SMM that secondary lead supply was tight last week. Such shortage eased this week thanks to resources outside the province.
A push to expand subway networks in some of China’s biggest cities along with a drive to boost broader infrastructure investment in the world’s No.2 economy are helping brighten the outlook for the nation’s mammoth steel sector.
The northeastern cities of Jiangsu and Changchun, as well as Shenzhen in the south, last month announced plans to spend the equivalent of billions of dollars boosting their underground systems by a total of around 1,600 kilometers (1,000 miles), gobbling up steel as they expand.
While on Tuesday, the top state planner said it would ramp up investment in infrastructure and accelerate spending on projects that have already been approved, as the nation tries to spur economic growth amid a festering trade war with Washington.
The steps, which mark a return to Beijing’s traditional playbook for boosting the economy, are good news for steelmakers in the world’s top producer of the material, who have been grappling with a slowing construction sector and weakening auto sales.
“The approval of the infrastructure spending will surely boost expectations of more steel demand and lead to a price rally in steel,” said Richard Lu, steel analyst at CRU in Beijing.
The three cities’ subway plans will require about 80 million tonnes of the commodity, 10 percent of China’s annual demand, according to Reuters calculations based on industry standards for subway design, although that will be spread over a few years.
In addition to high-strength steel track, the expansions will also need multiple stations, extensive underground building work using reinforced steel and rail cars made from alloy steel sheet rather than aluminum used in long-distance trains.
Magang Group, which makes steel that it then uses to produce train wheels, and Ansteel Group, which churns out steel that it uses to make railway tracks, are among the companies likely to benefit from the policy. They did not respond to requests for comment.
Shares in infrastructure companies rallied on Tuesday after the state planner’s pledge to rev up spending.
STIMULATING TOPIC
The scale of the push to develop infrastructure is unlikely to match the tremendous outlay seen a decade ago when Beijing rushed to protect the economy from the global financial crisis.
The government will want to avoid provincial governments piling on debt to finance projects or adding more excess industrial capacity.
“The approvals (of infrastructure) are partly aimed at hedging the risk of global trade and ensuring stable growth of the Chinese economy,” said CRU’s Lu.
“The government has already realized the risk behind the property market, so infrastructure could be a better measure to stimulate the economy.”
The steps will add further upward momentum to steel prices, even as mills produce record amounts of metal.
The most-active futures for rebar steel used in construction are up over 20 percent this year as the government curbs outdated excess capacity and heavy industry as part of its war on smog.
“With demand being maintained, steel prices are expected to strengthen as supply cuts play a bigger role,” said Sharon Xia, principal consultant at Wood Mackenzie.
Northern China's Inner Mongolia, Shanxi and Shaanxi produced 68.42% of the country's total raw coal in January-August
Coal exports from Indonesia will be restrained this year, which could frustrate a plan by the government to ease a burgeoning trade deficit while keeping prices elevated, according to an industry group.
Producers in the world's largest shipper face an order backlog of 18 months as they aren't able to get hold of additional mining equipment, Pandu Sjahrir, chairman of the Indonesian Coal Mining Association, said in an interview in Jakarta. The slow rampup in supply will probably keep coal prices buttressed at about $100/t through the end of next year, he said.
"Supply restriction is still quite real," Sjahrir, who's also finance director at miner Toba Bara Sejahtra, said on September 17. "It'll be the end of 2019 before they can fulfill some of their orders today."
That's bad news for President Joko Widodo's government, which is trying to rein in a current-account deficit and bolster the currency that's tumbled to the weakest level since the 1997 to 1998 Asian financial crisis. A rally in coal prices and the abundant reserves in Indonesia makes the commodity an ideal target in the government's drive to boost exports and shore up dollar earnings.
Major coal producers and contractors in Indonesia are having difficulties accessing additional mining equipment, Shirley Zhang, an analyst at Wood Mackenzie, said in an emailed note. "Upside for Indonesian coal exports from their current level is limited" in the near term, she said.
Asia-Pacific benchmark Newcastle prices have rallied about 11% this year and are averaging $105/t, the highest level since 2011, amid resilient demand in China, the world's largest user. The prospects for tighter supply to support prices at about $100/t have also been flagged by Australia miner New Hope Corp.
The Indonesian government approved an extra 22 million tonnes of coal output for the rest of the year, about a fifth of the 100 million tonnes it was open to endorsing. While an increase of about 30 million tonnes in the next six months might be possible, according to Sjahrir, that would still be a relatively small amount compared with overall output.
Indonesia produced 461 million tonnes in 2017 and shipped about 389 million tonnes, from 456.2 million tonnes and 370 million tonnes respectively a year earlier, according to data from BP Statistical Review and Bank Indonesia.
Almost 90 percent of China’s steel capacity will have complied with new emission standards by 2025, an official of top iron ore supplier Vale said on Thursday.
“By 2025 almost 90 percent of steel capacity in China will have complied to these new standards,” Peter Poppinga, executive director at Vale, told an industry conference.
China has been aggressively pushing cities to curb industrial production to fight pollution, including plants in the top steelmaking city of Tangshan.
Poppinga also said Vale’s iron ore production is running at 400 million tonnes a year currently.
“We think this is a healthy level going forward when you think about margin optimisation,” he said.
Osaka Steel, Japan’s largest producer of sections, has decided to lift its section prices for October contracts by Yen 3,000/mt ($27/mt), the company confirmed Wednesday.
The company last raised prices by Yen 2,000/mt for February contracts.
An Osaka Steel official is unavailable for comment on details.
“Production costs from October are expected to become higher, so the company has to lift prices to maintain stable production,” an Osaka-based distributor said.
Osaka Steel does not reveal its list prices, but market prices of channels (100×50 mm) in Tokyo and Osaka are Yen 87,000-88,000/mt ($777-$786/mt), up Yen 1,000/mt from a month ago and up Yen 2,000-3,000/mt from February.
Prices of angles (6×50 mm) in Tokyo and Osaka are at Yen 85,000-86,000/mt, unchanged from a month ago but up Yen 1,000-2,000/mt from February, sources said.
Meanwhile, Japan’s leading electric arc furnace mill Tokyo Steel Manufacturing, will keep its list prices for all finished products, including sections, for October unchanged, a Tokyo-based construction steel trader said, adding it may be not easy for the market to absorb Osaka Steel’s price hike.
“But Tokyo Steel also said it was eyeing to lift prices to pass on higher input costs, so the timing is different, but we expect not only Osaka Steel but other section producers will lift prices soon for the same reason,” he said.
Section orders (excluding H-beams) booked in July totaled 173,000 mt, up 13.1% year on year and 5% from June, data released Tuesday by the Japan Iron and Steel Federation showed.
https://www.hellenicshippingnews.com/japans-osaka-steel-raises-domestic-section-prices-by-27-mt/
Mining giant Vale is looking at expanding its flagship iron ore project in Brazil, a company official said, hoping to cash in on a growing appetite for higher-grade varieties of the commodity in its top market China.
China, the world’s biggest consumer of the steelmaking ingredient, has ramped up buying of higher-quality, less polluting grades of iron ore as it battles to clear its notoriously smoggy skies.
Peter Poppinga, executive director at Vale, said at an industry conference in China that the world’s largest iron ore miner was studying expanding its S11D project in the Amazonian state of Para, even though it was still being brought up to the planned capacity after it was inaugurated in December 2016.
“Given all these quality trends (that are) favorable to us, we are studying to increase the project, but there are no numbers yet,” Poppinga said.
Heavy spending on the project, which churns out rich grades of ore, has driven up Vale’s debt, coinciding with a sharp slide in iron ore prices.
Poppinga said S11D’s iron ore output would be close to 90 million tonnes next year, up from around 60 million tonnes now.
However, he said Vale is aiming to keep its total production at around 400 million tonnes, replacing low-quality iron ore with higher-grade material.
“We think this is a healthy level going forward when you think about margin optimization,” Poppinga said.
“We are not after market share, we are after value and not after volume.”
Poppinga said he expects almost 90 percent of Chinese steel capacity will comply with new emission standards by 2025.
FORTESCUE, ROY HILL
Fortescue Metals Group, the world’s fourth-largest iron ore producer, is aiming to start producing higher-grade iron ore as well from December as it addresses the widening discount for its lower grade material.
The Australian miner expects to start shipping from December a 60-percent iron content product called West Pilbara Fines, ahead of the development of its Eliwana mine and rail project.
Initial production volume of West Pilbara Fines would be 10 million to 15 million tonnes a year, Fortescue Chief Executive Elizabeth Gaines told Reuters at the conference.
“Once we have Eliwana we can continue to produce West Pilbara Fines at rates of around 40 million tonnes per annum,” Gaines said.
Fellow Australian miner Roy Hill, controlled by billionaire Gina Rinehart, which produces above 60-percent grade iron ore, also plans to raise its annual output to 60 million tonnes, from 55 million tonnes, its chief executive said.
Thyssenkrupp’s interim chief executive dismissed speculation that it would pull out of its steel joint venture with India’s Tata Steel in the wake of management upheaval at the German industrial conglomerate.
Last week, media reports said the implementation of the landmark deal, signed in late June, was stalling over the sudden departure of Thyssenkrupp’s CEO Heinrich Hiesinger, the main architect of the transaction.
“The contrary is the case,” Guido Kerkhoff told Reuters on the sidelines of a company event in Duisburg on Thursday. “We are continuing to implement the joint venture with Tata Steel with all our strength.”
The deal will create Europe’s second-largest steelmaker after ArcelorMittal and is expected to close at the end of this year or in early 2019, giving Thyssenkrupp a way to cut capacity in the volatile steel market.
Kerkhoff has taken the helm until a long-term successor has been found for Hiesinger. Sources told Reuters last week that he could eventually become a permanent candidate for the top job himself if a restructuring of the industrials unit goes well.
Ingo Speich, fund manager at Thyssenkrupp shareholder Union Investment, said that Kerkhoff could also serve as chief operating officer alongside a new CEO.
Whoever will take over at the group on a long-term basis is facing a debate over whether Thyssenkrupp’s conglomerate structure still makes sense. Activist fund Elliott on Thursday reiterated it was not in favour of a breakup.
China’s iron ore demand has already peaked and is expected to stay flat, an official of the country’s biggest listed steelmaker, Baoshan Iron & Steel Co, said on Thursday.
China bought a record 1.08 billion tonnes of the steelmaking raw ingredient last year, the second successive year in which purchases crossed the 1-billion mark.
“China’s steel mills have been focused on the quality of iron ore and that trend will be even more clear,” Ji Chao, an assistant to the company president, told an industrial conference.
“However, mills still need to consider cost, and hopefully we can find a balance.”
Low-quality iron ore from overseas will remain competitive, he added.
As China adopts tougher environmental rules and stockpiles of steel scrap grow, output from electric-arc furnaces, or mini-mills that use only scrap as raw material, is expected to rise, Ji said.
President Donald Trump’s U.S. steel resurgence might be thwarted as more workers go on strike.
About 15,000 workers at plants owned by ArcelorMittal voted on Tuesday to go on strike as contract disputes drag on, USW International said.
“The flexibility of our contracts and world-class efficiency and productivity of this particular group of steelworkers enabled ArcelorMittal to survive floods of unfairly traded and illegally dumped foreign imports that brought about the harshest market conditions our industry has faced in decades,” said Leo Gerard, president at USW International, in a statement.
“Now that the company is generating enormous — even historic — amounts of cash, it is an insult that bargaining progress has been hindered by management’s unrealistic concessionary demands and unfair labour practices,” Gerard said.
This follows another strike by 16,000 U.S. Steel workers that was approved earlier this month. Collectively, U.S. Steel and ArcelorMittal account for about 25 percent of the country’s overall steel production. A strike this big could hinder what Trump calls a “thriving” industry in the U.S.
Trump tweeted on Monday that the U.S. steel industry is “is the talk of the World,” adding it has been “given new life.”
Trump’s tweet comes months after the U.S. slapped tariffs on all steel and aluminium imports, including those from key allies such as Canada, Mexico and the European Union.
The administration has said repeatedly that protecting the country’s steel industry is a matter of national security. Trump said in a proclamation in May that “steel mill articles are being imported into the United States in such quantities and under such circumstances as to threaten to impair the national security of the United States.”
Steel and aluminium producers initially cheered the administration’s measures, but now workers want to reap some of the benefits.