Through Aug. 31, the S&P 500 has outperformed international stocks, as measured by the MSCI World ex USA Index, over the past one, three, five, 10, 15, 20, 25, 30, 35, 40 and 45 years, according to AJO, an institutional investment manager in Philadelphia. Had you put $10,000 in each in 1973 and reinvested all your dividends, your U.S. holdings would be worth $1.06 million; your international stocks, $356,000.
https://www.wsj.com/articles/the-dumb-money-is-bailing-on-u-s-stocks-thats-smart-1538146842
The dollar surges: Reagan, information age onset, global Trumpism.
Since 1973 we've created two economies larger than the US, but neither possesses a stock market that compares.
A judge released fresh testimony on Monday alleging corrupt practices involving members of Brazil’s leftist Workers Party (PT), whose candidate Fernando Haddad faces far-right lawmaker Jair Bolsonaro in this month’s presidential election.
Anti-corruption judge Sergio Moro unsealed the plea-bargain testimony of jailed former Finance Minister Antonio Palocci stating that PT founder and then-President Luiz Inacio Lula da Silva ordered the collection of bribe money in 2010 to fund the campaign of his successor Dilma Rousseff.
Lawyers for Lula, who was jailed in April and barred from running for office due to a corruption conviction, said publication of the testimony was politically motivated to harm Lula and his party.
Brazilians will vote on Sunday in the most polarized election in a generation and the Workers Party could return to office despite corruption cases against its leaders and allies. The Palocci testimony could increase anti-Workers Party sentiment, which has helped make Bolsonaro the frontrunner in the race.
Haddad has surged in voter support to six points behind Bolsonaro since he was confirmed as Lula’s replacement, according to opinion polls. The polls indicate the Workers Party candidate could win a likely second round runoff vote on Oct. 28.
Palocci resigned as Rousseff’s chief of staff in 2011 after only five months due a corruption accusation. In the testimony make public on Monday, he said he attended a meeting in 2010 where Lula ordered the then chief executive of state-run oil company Petroleo Brasileiro SA, José Sérgio Gabrielli, to commission 40 drill ships and use bribe money from the contracts to fund Rousseff’s campaign.
Palocci was arrested two years ago in the sweeping Car Wash investigation into the use of the contracts at Petrobras, as the state oil company is known, by the Workers Party and allied parties to siphon off funds for their political needs.
The court documents made public on Monday also cite alleged corrupt practices by Petrobras executives and one financial institution related to exploration blocks in Africa, where the company partnered with investment bank Banco BTG Pactual SA in a venture known as PetroAfrica.
BTG acquired a stake in the venture in 2013 and was trying to sell it until recently.
BTG’s most widely traded class of stock fell 3.4 percent on Monday, to 20.57 reais, after excerpts of Palocci’s plea deal were released.
The bank did not immediately respond to requests for comment. Gabrielli could not be immediately reached for comment.
Which is eye-catching. Then this am:
The European charge and high carbon ferro-chrome benchmark has dropped to $1.24 per lb for the fourth quarter of 2018, down 14 cents from the prior quarter.
1> Pence
As President Trump has made clear, we don’t want China’s markets to suffer. In fact, we want them to thrive. But the United States wants Beijing to pursue trade policies that are free, fair, and reciprocal. And we will continue to stand and demand that they do. (Applause.)
Sadly, China’s rulers, thus far, have refused to take that path. The American people deserve to know: In response to the strong stand that President Trump has taken, Beijing is pursuing a comprehensive and coordinated campaign to undermine support for the President, our agenda, and our nation’s most cherished ideals.
I want to tell you today what we know about China’s actions here at home — some of which we’ve gleaned from intelligence assessments, some of which are publicly available. But all of which are fact.
As I said before, as we speak, Beijing is employing a whole-of-government approach to advance its influence and benefit its interests. It’s employing this power in more proactive and coercive ways to interfere in the domestic policies of this country and to interfere in the politics of the United States.
The Chinese Communist Party is rewarding or coercing American businesses, movie studios, universities, think tanks, scholars, journalists, and local, state, and federal officials.
And worst of all, China has initiated an unprecedented effort to influence American public opinion, the 2018 elections, and the environment leading into the 2020 presidential elections. To put it bluntly, President Trump’s leadership is working; and China wants a different American President.
There can be no doubt: China is meddling in America’s democracy. As President Trump said just last week, we have, in his words, “found that China has been attempting to interfere in our upcoming [midterm] election[s].”
Our intelligence community says that “China is targeting U.S. state and local governments and officials to exploit any divisions between federal and local levels on policy. It’s using wedge issues, like trade tariffs, to advance Beijing’s political influence.”
In June, Beijing itself circulated a sensitive document, entitled “Propaganda and Censorship Notice.” It laid out its strategy. It stated that China must, in their words, “strike accurately and carefully, splitting apart different domestic groups” in the United States of America.
To that end, Beijing has mobilized covert actors, front groups, and propaganda outlets to shift Americans’ perception of Chinese policy. As a senior career member of our intelligence community told me just this week, what the Russians are doing pales in comparison to what China is doing across this country. And the American people deserve to know it.
Senior Chinese officials have also tried to influence business leaders to encourage them to condemn our trade actions, leveraging their desire to maintain their operations in China. In one recent example, China threatened to deny a business license for a major U.S. corporation if they refused to speak out against our administration’s policies.
And when it comes to influencing the midterms, you need only look at Beijing’s tariffs in response to ours. The tariffs imposed by China to date specifically targeted industries and states that would play an important role in the 2018 election. By one estimate, more than 80 percent of U.S. counties targeted by China voted for President Trump and I in 2016; now China wants to turn these voters against our administration.
And China is also directly appealing to the American voters. Last week, the Chinese government paid to have a multipage supplement inserted into the Des Moines Register –- the paper of record of the home state of our Ambassador to China, and a pivotal state in 2018 and 2020. The supplement, designed to look like the news articles, cast our trade policies as reckless and harmful to Iowans.
Fortunately, Americans aren’t buying it. For example, American farmers are standing with this President and are seeing real results from the strong stands that he’s taken, including this week’s U.S.-Mexico-Canada Agreement, where we’ve substantially opened North American markets to U.S. products. The USMCA is a great win for American farmers and American manufacturers. (Applause.)
But China’s actions aren’t focused solely on influencing our policies and politics. Beijing is also taking steps to exploit its economic leverage, and the allure of their large marketplace, to advance its influence over American businesses.
Beijing now requires American joint ventures that operate in China to establish what they call “party organizations” within their company, giving the Communist Party a voice –- and perhaps a veto -– in hiring and investment decisions.
Chinese authorities have also threatened U.S. companies that depict Taiwan as a distinct geographic entity, or that stray from Chinese policy on Tibet. Beijing compelled Delta Airlines to publicly apologize for not calling Taiwan a “province of China” on its website. And it pressured Marriott to fire a U.S. employee who merely liked a tweet about Tibet.
And Beijing routinely demands that Hollywood portray China in a strictly positive light. It punishes studios and producers that don’t. Beijing’s censors are quick to edit or outlaw movies that criticize China, even in minor ways. For the movie, “World War Z,” they had to cut the script’s mention of a virus because it originated in China. The movie, “Red Dawn” was digitally edited to make the villains North Korean, not Chinese.
But beyond business and entertainment, the Chinese Communist Party is also spending billions of dollars on propaganda outlets in the United States and, frankly, around the world.
China Radio International now broadcasts Beijing-friendly programs on over 30 U.S. outlets, many in major American cities. The China Global Television Network reaches more than 75 million Americans, and it gets its marching orders directly from its Communist Party masters. As China’s top leader put it during a visit to the network’s headquarters, and I quote, “The media run by the Party and the government are propaganda fronts and must have the Party as their surname.”
It’s for those reasons and that reality that, last month, the Department of Justice ordered that network to register as a foreign agent.
The Communist Party has also threatened and detained the Chinese family members of American journalists who pry too deep. And it’s blocked the websites of U.S. media organizations and made it harder for our journalists to get visas. This happened after the New York Times published investigative reports about the wealth of some of China’s leaders.
But the media isn’t the only place where the Chinese Communist Party seeks to foster a culture of censorship. The same is true across academia.
I mean, look no further than the Chinese Students and Scholars Association, of which there are more than 150 branches across America’s campuses. These groups help organize social events for some of the more than 430,000 Chinese nationals studying in the United States. They also alert Chinese consulates and embassies when Chinese students, and American schools, stray from the Communist Party line.
At the University of Maryland, a Chinese student recently spoke at her graduation of what she called, and I quote, the “fresh air of free speech” in America. The Communist Party’s official newspaper swiftly chastised her. She became the victim of a firestorm of criticism on China’s tightly-controlled social media, and her family back home was harassed. As for the university itself, its exchange program with China — one of the nation’s most extensive — suddenly turned from a flood to a trickle.
China exerts academic pressure in other ways, as well. Beijing provides generous funding to universities, think tanks, and scholars, with the understanding that they will avoid ideas that the Communist Party finds dangerous or offensive. China experts in particular know that their visas will be delayed or denied if their research contradicts Beijing’s talking points.
And even scholars and groups who avoid Chinese funding are targeted by that country, as the Hudson Institute found out firsthand. After you offered to host a speaker Beijing didn’t like, your website suffered a major cyberattack, originating from Shanghai. The Hudson Institute knows better than most that the Chinese Communist Party is trying to undermine academic freedom and the freedom of speech in America today.
These and other actions, taken as a whole, constitute an intensifying effort to shift American public opinion and policy away from the “America First” leadership of President Donald Trump.
But our message to China’s rulers is this: This President will not back down. (Applause.) The American people will not be swayed. And we will continue to stand strong for our security and our economy, even as we hope for improved relations with Beijing.
2>
By Ashley Carman@ashleyrcarman
Chinese operatives allegedly poisoned the technical supply chain of major US companies, including Apple and Amazon by planting a microchip on their servers manufactured abroad, according to a Bloomberg report today. The story claims that one chip, which was assembled for a company called Elemental by a separate company called Super Micro Computer, would allow attackers to covertly modify these servers, bypass software security checks, and, essentially, give the Chinese government a complete backdoor into these companies’ networks.
Affected companies are vigorously disputing the report, claiming they never discovered any malicious hardware or reported similar issues to the FBI. Even taking the Bloomberg report at its word, there are significant unanswered questions about how widely the chip was distributed and how the backdoor access was used.
But the mere idea of a malicious chip implant has already sent shock waves through the security world, which has traditionally focused on software attacks. Nicholas Weaver, a professor at Berkeley’s International Computer Science Institute described an alarming attack. “My initial reaction was ‘HOLY FUCKING SHIT’ [sic],” Weaver told The Verge. “This is a ‘god mode’ exploit in the system management subsystem.”
3>
23 Sep 2018 - Banerjee, R and B Hofmann (2018): "Corporate zombies: life cycle and anatomy", Bank for International Settlements, mimeo. Bank for International Settlements (2018): Annual Economic Report 2018, Box II.A, June. Bogdanova, B, I Fender and E Takáts (2018): "The ABCs of bank PBRs",BIS Quarterly Review, March, pp 81-95.
Canada and the U.S. ended weeks of intense bargaining Sunday with a last-minute trade deal that gives American farmers major new access to the dairy market here, but preserves a dispute-resolution system the United States wanted killed.
The deal capped a frantic weekend of negotiations and includes several provisions to “rebalance” the North American trading relationship, a Trump administration official said in a conference call shortly before midnight.
It is to be renamed USMCA – United States Mexico Canada Agreement – after President Donald Trump said the name NAFTA had “bad connotations.”
“This is going to be one of the most important trade agreements we’ve ever had,” said another American official on the background-briefing call. “We think this is a fantastic agreement for the United States, but also for Mexico and for Canada.”
The officials highlighted in particular that the U.S. had won a “substantial” increase in access to the Canadian dairy market, and that Canada had agreed to end the “class-seven” milk program that undercut American sales of a special dried-milk product.
That concession is a “big win for American farmers,” one official said. “We’ve got a great result for dairy farmers, which was one of the president’s key objectives in these negotiations.”
But Canada appeared to score a significant victory, as well, with the U.S. agreeing to keep intact the chapter-19 mechanism for resolving disputes over anti-dumping and anti-subsidy duties, which American negotiators felt undermined the autonomy of their courts.
The U.S. has also agreed to provide an “accommodation” to protect Canada’s auto industry in case the States decides to impose tariffs on auto imports, while Canada consented to extend the patent protection for an important class of prescription drugs by two years, the officials said.
Critics warn the drug provision will increase health-care costs by delaying the entry of cheaper generic copies of brand-name medicines onto the market. Generic-industry advocates said recently that Canadian negotiators told them they were fighting hard against the demand.
In Canada, Prime Minister Justin Trudeau convened a special federal cabinet meeting at 10 p.m. Ottawa time to approve the trade accord, which already included Mexico.
Ildefonso Guajardo, the Mexican economy minister, addressed his country’s senate on the pact at close to midnight.
Canadian officials divulged little information on the agreement Sunday night, though Foreign Affairs Minister Chrystia Freeland did release a joint statement with Robert Lighthizer, the U.S. Trade Representative and Trump’s top negotiator.
“USMCA will give our workers, farmers, ranchers, and businesses a high-standard trade agreement that will result in freer markets, fairer trade and robust economic growth in our region,” they said. “It will strengthen the middle class and create good, well-paying jobs and new opportunities for the nearly half billion people who call North America home.”
The agreement ends more than a year of hard-slogging talks on revamping the North American Free Trade Deal, and caps a weekend of last-ditch negotiations designed to meet a Monday deadline set by the U.S.
Swiss asset manager and commodities trader Tiberius Group AG is stepping into the $215 billion digital coin market by offering a new token backed by seven metals in a sale set for Oct. 1.
Aiming to distinguish its Tiberius Coin from the thousands that have no reference value, the company plans to make a market in the asset so that its value holds close to that of a price of a basket of copper, aluminum, nickel, cobalt, tin, gold and platinum.
Christoph Eibl’s 13-year-old investment company will enter a cryptocurrency panorama littered with failed projects giving assurances to buyers their coin’s value derives from more than just quasi-anonymity, a single reference asset like gold or a promise to not let issuance run wild.
The effort is led by the company’s Tiberius Technology Ventures AG arm in Baar, Switzerland, a nation that’s cutting one of the world’s more liberal profiles for embracing privately issued money.
“Instead of underlying the digital currency with only one commodity, we have chosen a mix of technology metals, stability metals and electric vehicle metals,” the unit’s Chief Executive Officer Giuseppe Rapallo said in an interview. “This will give the coin diversification, making it more stable and attractive for investors.”
The new coin will be offered at about $0.70 and will be sold under Swiss law, instead of as an unregulated initial coin offering, or ICO. The supply will be purely based on demand and only be limited by the availability of the underlying metals, Rapallo said.
Estonian Exchange
The company will list the coin on the Estonia-based LATOKEN exchange, chosen because it fulfills the necessary regulatory standards, Rapallo said.
Tiberius Group, founded in 2005 by Eibl, trades physical commodities and manages about $350 million for clients. Tiberius Technology Ventures’ Chief Scientist and Security Officer Philip Zimmermann is known for being the creator of Pretty Good Privacy or PGP, a widely used email encryption software.
Tiberius Coin will use blockchain technology to account for trades and aims to offer investors the option to use it as a digital currency, paying for a coffee or pair of trousers, for example, with a few grams of metal, simulating a traditional barter.
Gold has been used to back certificates, tokens and other medium with varying degrees of success. In the early days of the Internet, E-Gold, founded in 1995, was used by millions until it was shut down. With Bitcoin as the forerunner of digital currencies and the blockchain technology offering a decentralized accounting method, new commodity-backed coins like Golden Currency and GoldFinX saw the light of day, with mixed results.
“There are dozens of firms who launched stablecoins linked to metals, and so far none of them have gained any traction,” said Adrian Ash, the research director at London-based BullionVault Ltd, which has since 2005 offered trading of vaulted metal to 70,000 clients around the world who transact peer-to-peer on an online platform without the use of a blockchain -- the company stores $1.5 billion worth of gold.
“They’re trying to solve a problem that doesn’t exist -- all of this can be achieved without the additional cost of a distributed ledger,” Ash said.
At a relatively stiff price, holders can swap the cryptocurrency for physical commodities. If successful, it might provide traders or procurement departments of industrial companies a new way to buy and sell physical metals in the long-term.
Given that most commodities trade in tons rather than grams, Tiberius asks for a minimum fee of $10,000 for swapping the coin into the physical raw materials.
By Xinhua Published : October 01, 2018 | Updated : October 01, 2018
The global trading regime is in great need of change to avert real and potentially destabilising losses resulting from the escalating trade frictions between the United States and China and elsewhere, experts said.
The Trump administration has leaned heavily towards unilateralism in addressing what it sees as unacceptable status quo in which the United States has long been taken advantage of by countries around the world, including its allies, in terms of trade and others, defence included.
Trump has fired the first shot in this global trade battle by failing to adequately negotiate. Furthermore, China is increasingly singled out as the source of the world’s trade woes.
China's manufacturing sector expanded at a slower pace in September, official data showed Sunday.
The country's manufacturing purchasing managers' index came in at 50.8 in September, narrowing from 51.3 in August, according to the National Bureau of Statistics (NBS).
A reading above 50 indicates expansion, while a reading below 50 reflects contraction.
"Production continued to expand while market demand remained generally stable," said NBS senior statistician Zhao Qinghe.
Sub-index for production edged down from 53.3 in August to 53 in September, while the sub-index for new orders dipped from 52.2 in August to 52 in September.
The decline in the headline PMI was partially driven by the unfavorable working day effect as the Mid-autumn Festival shifted to September this year from October last year, but it also indicated strong headwinds on the manufacturing sector, said a report from China International Capital Corporation (CICC).
Well aware of the challenges, authorities have pledged coordinated efforts and policies to stabilize employment, finance, foreign trade, foreign investment, investment and expectations, with measures such as tax cuts and cheaper financing to support the real economy.
Continued efforts should be made to formulate policies that promote high-quality development in important areas including manufacturing, high-tech industries, public services and infrastructure, and to put protecting the people's interests at a more prominent position, said a statement released after the fourth meeting of the central committee for deepening overall reform.
Sunday's data also showed that China's non-manufacturing sector expanded at a faster pace, with the PMI for the sector standing at 54.9 in September, up from 54.2 in August.
The service sector, which accounts for more than half of the country's GDP, maintained stable growth, with the sub-index measuring business activity in the industry standing at 53.4 in September, flat with August.
Rapid expansion was seen in industries including air transport, retail and telecommunications, the NBS said.
http://www.xinhuanet.com/english/2018-09/30/c_137504137.htm
New export orders in particular fell to lowest since Dec 2016. Not looking good for export growth into year-end and early next year.
@Khoon_Goh
China Censors Bad Economic News Amid Signs of Slower Growth
China has long made it clear that reporting on politics, civil society and sensitive historical events is forbidden. Increasingly, it wants to keep negative news about the economy under control, too.
A government directive sent to journalists in China on Friday named six economic topics to be “managed,” according to a copy of the order that was reviewed by The New York Times.
The list of topics includes:
■ Worse-than-expected data that could show the economy is slowing.
■ Local government debt risks.
■ The impact of the trade war with the United States.
■ Signs of declining consumer confidence
■ The risks of stagflation, or rising prices coupled with slowing economic growth
■ “Hot-button issues to show the difficulties of people’s lives.”
https://www.nytimes.com/2018/09/28/business/china-censor-economic-news.html
China's environment ministry issued a stern warning on September 29 to heavy industrial companies not to flout the nations winter smog plan
Australia’s government expects the nation’s resource and energy exports to hit a record of A$252 billion ($182 billion) in 2018-2019, buoyed by climbing prices for commodities such as natural gas and by a weaker Australian dollar.
However, the country’s Department of Industry also said in a report that the value of such exports would edge back to around A$238 billion in 2019-2020 even as volumes rise again, pulled down as growing global supply and concerns over demand pressure prices. The figure for 2017-18 was A$227 billion.
“While global economic growth, industry production and manufacturing output have continued to grow strongly so far in 2018, there are some concerning signs for resource and energy commodity producers, particularly with rising global trade tensions,” the department said in the report, released on Tuesday.
China and the United States have been bogged down in a tit-for-tat trade dispute that has hit global markets and stoked worries over the outlook for the global economy.
China buys just over half of Australia’s commodity exports, followed by Japan, then South Korea.
Australia expects prices for steelmaking material iron ore to fall to around $52 a ton on a free on board basis in the 2019 calendar year and $51 a ton in 2020, as China’s steel production moderates, down from $59.40 this year.
Still, Australia’s iron ore exports are expected to increase to 878 million tons in 2019-2020 from 869 million tons this financial year and 849 million tons in 2017-2018, driven by a ramp up in production from the country’s largest producers.
But the overall value of iron ore exports is expected to drop to $56 billion in 2019-2020 from $61 billion in 2017-18.
The government said prices for metallurgical coal would average $159 a ton in the 2019 calendar year, trimming a forecast drop to $156.80 that it made in June. That would also be down from the $201 a ton it sees for 2018.
It also said that prices for the commodity would average $145 a ton in 2020, less than an earlier forecast of $147.90.
For the first time, the department offered an outlook for lithium, used to make batteries for electric cars. Australia accounts for 17 percent of the world’s lithium production.
Australia’s exports of spodumene, the raw material for lithium, are expected to rise to around $1.1 billion by 2020, from $780 million in 2017 and $117 million in 2012.
Five large plants are planned or under construction in the state of Western Australia that will turn spodumene into intermediate products for the lithium industry such as lithium carbonate or hydroxide.
That investment pipeline will ensure Australia shifts rapidly beyond concentrate production to becoming a refiner of “significant scale” by the early 2020s, the government said.
Fresh from clinching an updated North American commerce pact, U.S. President Donald Trump on Monday criticized Indian and Brazilian trade tactics, describing the latter as being “maybe the toughest in the world” in terms of protectionism.
Addressing reporters at a White House event to celebrate the agreement of an updated trilateral trade deal between the United States, Mexico and Canada, Trump added India and Brazil to a growing list of countries that, he argues, treat the world’s top economy unfairly in terms of commerce.
“India charges us tremendous tariffs. When we send Harley Davidson motorcycles, other things to India, they charge very, very high tariffs,” Trump said, adding that he had brought up the issue with Indian Prime Minster Narendra Modi, who he said was “going to reduce them very substantially.”
Modi’s office could not immediately be reached for a request for comment. India’s government has become more protectionist in recent months, raising import tariffs on a growing number of goods as it promotes its ‘Make in India’ program.
After criticizing India, Trump turned to Brazil, the second-largest economy in the Americas behind the United States.
“Brazil’s another one. That’s a beauty. They charge us whatever they want,” he said. “If you ask some of the companies, they say Brazil is among the toughest in the world - maybe the toughest in the world.”
Brazil is one of the world’s most closed major economies, and in recent months has tussled with the Trump administration over trade in sectors such as ethanol and steel.
After Trump’s comments, Brazil’s Foreign Trade Minister, Abrão Neto, defended the relationship, saying it was “very positive.” He added that over the last 10 years, the United States has enjoyed a trade surplus with Brazil of $90 billion in goods, and of $250 billion in goods and services.
Neto pointed out that the United States was Brazil’s second-largest trading partner, behind China, and that the two countries had a “complementary and strategic” commercial relationship that could, nonetheless, be improved.
Trump’s “America First” trade policies, particularly his escalating trade war with China, are aimed at boosting U.S. manufacturing, but they have spooked investors who worry that supply lines could be fractured and global growth derailed.
There are now U.S. tariffs active on $250 billion worth of Chinese goods, with threats on additional goods worth $267 billion.
U.S. President Donald Trump on Wednesday nominated a proponent of his administration’s plan to subsidize aging coal and nuclear plants to a federal agency that regulates power transmission, a move criticized by environmental groups who questioned his independence on the issue.
Trump nominated Bernard McNamee to the vacant seat of the five-member Federal Energy Regulatory Commission (FERC), an independent office of the Department of Energy, for a term expiring June 30, 2020. McNamee, a Republican, is now the head of the policy office at the department.
McNamee helped to roll out last year a plan by Energy Secretary Rick Perry to subsidize aging coal and nuclear plants. The coal industry is suffering because of an abundance of cheap natural gas and an expansion of wind and solar power.
Coal and nuclear plants are integral to making the power grid reliable and resilient, or able to bounce back quickly from storms, hacking or physical attacks, the Energy Department has said.
An unusual coalition of natural gas drillers, renewable power groups, power grid operators and consumer advocates opposed Perry’s plan. FERC rejected it in January in a setback for Trump.
Environmentalists decried McNamee’s nomination. The Sierra Club’s Mary Anne Hitt said the Trump administration is “trying to use FERC to manipulate America’s electricity markets to bail out dirty and expensive coal plants ... while locking in a fossil fuel future for communities across the country.”
Neither the White House, nor the Department of Energy immediately responded to requests for comment about criticism that McNamee could not be independent in any commission votes on plant bailout plans.
In June, Trump ordered Perry to take emergency measures to slow down the closure of coal and nuclear plants, arguing those facilities boost U.S. energy security because they can store months of fuel on site.
Perry told reporters last week that he was waiting for the executive branch to respond to his agency’s ideas on the emergency measures, saying they were still being “bandied about” at the White House.
Coal mining and mining and industrial communities form part of Republican Trump’s base and he has returned the favor of their support by overturning Obama-era regulations. His administration axed a moratorium on coal mining on federal lands, proposed a weaker plan to reduce carbon emissions from power plants, and announced its intent to withdraw the United States from the 2015 Paris agreement on curbing greenhouse gases.
McNamee needs to be confirmed by the Senate. He would replace Robert Powelson, a Republican, who resigned. The Commission currently has two Democrats and two Republicans.
Ten year bond.
China represents a “significant and growing risk” to the supply of materials vital to the U.S. military, according to a new Pentagon-led report that seeks to mend weaknesses in core U.S. industries vital to national security.
The nearly 150-page report, seen by Reuters on Thursday ahead of its formal release on Friday, concluded there are nearly 300 vulnerabilities that could affect critical materials and components essential to the U.S. military.
Reuters was first to report on the study’s major conclusions on Tuesday.
The analysis included a series of recommendations to strengthen American industry, including by expanding direct investment in sectors deemed critical. The specific plans were listed in an unreleased, classified annex.
China was given heavy emphasis in the report. It was singled out for dominating the global supply of rare earth minerals critical in U.S. military applications. The report also noted China’s global profile in the supply of certain kinds of electronics as well as chemicals used in U.S. munitions.
“A key finding of this report is that China represents a significant and growing risk to the supply of materials and technologies deemed strategic and critical to U.S. national security,” the report said.
Relations with China are already fraught, with a bitter trade war between the world’s two largest economies adding to tensions over cyber spying, self-ruled Taiwan and freedom of navigation in the South China Sea.
The report could add to trade tensions with China, bolstering the Trump administration’s “Buy American” initiative, which aims to help drum up billions of dollars more in arms sales for U.S. manufacturers and create more jobs.
Vice President Mike Pence accused China on Thursday of efforts to undermine President Donald Trump ahead of the Nov. 6 congressional elections, saying that Beijing was “meddling in America’s democracy.”
Pence’s comments echoed those of Trump himself in remarks at the United Nations last month, when Trump said that “China has been attempting to interfere in our upcoming 2018 election.” Chinese officials rejected the charge.
The report also examined U.S. shortcomings that contribute to weakness in domestic industry, including roller-coaster U.S. defense budgets that make it difficult for U.S. companies to predict government demand. Another weakness cited was in U.S. science and technology education.
“Although its findings are not likely to move markets, they present an alarming picture of U.S. industrial decay driven by both domestic and foreign factors,” wrote defense consultant Loren Thompson, who has close ties to Boeing Co and other companies.
A senior U.S. administration official, speaking to reporters on condition of anonymity, cited several new steps to ensure U.S. military’s supplies. These include an effort to build up stockpiled reserves of scarce materials and expand U.S. manufacturing capabilities in things like lithium sea-water batteries that are critical for anti-submarine warfare.
“There have just been market failures here. And so we can create new incentives to drive investment in areas to help diversify ourselves,” said Eric Chewning, a deputy assistant secretary of defense who oversees industrial base policy.
CHINESE DUMPING
Pentagon officials see national security risks from Beijing’s growing military and economic clout and want to be sure China is not able to hobble America’s military by cutting off supplies of materials or by sabotaging technology it exports.
The report noted that 90 percent of the world’s printed circuit boards are now produced in Asia, with over half of that occurring in China, presenting a risk to U.S. defense.
“With the migration of advanced board manufacturing offshore, (the Department of Defense) risks losing visibility into the manufacturing provenance of its products,” the report said.
The Pentagon has long fretted that “kill switches” could be embedded in transistors that could turn off sensitive U.S. systems in a conflict. The report cited the risk of “‘Trojan’ chips and viruses infiltrating U.S. defense systems.”
U.S. intelligence officials also warned this year about the possibility China could use Chinese-made mobile phones and network equipment to spy on Americans.
The report cited what it said were sometimes unfair and unlawful Chinese efforts to undermine U.S. industry through a host of strategies, including by subsidizing exports at artificially low prices and stealing U.S. technology.
The report identified multiple cases where the sole remaining U.S. producer of critical materials was on the verge of shutting down and importing lower-cost materials “from the same foreign producer county who is forcing them out of domestic production.”
Brazil’s currency weakened on Thursday afternoon and the Bovespa index slid on Thursday after a poll suggested leftist former mayor Fernando Haddad could inch past far-right firebrand Jair Bolsonaro in a presidential runoff later this month.
A second-round vote would be held on Oct. 28 if no candidate clinches more than 50 percent of ballots as expected in a hotly contested election on Sunday that has revealed deep divides among voters in Latin America’s largest economy.
The real currency weakened 0.49 percent to 3.8824 per dollar.
Despite current volatility, a cautious optimism that the winner of Brazil’s presidential elections will manage to rein in growing public debt will likely support the Brazilian real, the latest Reuters poll showed.
The Bovespa index, which closed 0.38 percent down at 82,952 points, giving back some ground following a two-day rally.
A poll Wednesday night showed that in a simulated second-round vote, Haddad would get 43 percent of the vote against Bolsonaro’s 41 percent, a technical tie.
Bolsonaro, a former army captain running on a law and order platform, has offended many with his racist and misogynist comments. But many business elites are betting he would promote market-friendly policies.
Meanwhile, Haddad, a Workers Party academic, is seen as more likely to overturn pro-business reforms made under unpopular center-right President Michel Temer and recently described markets as “an abstract entity that terrorizes the public.”
The oil firm said the production level shows an initial capacity of 50,000 barrels per day (10,000 barrels per day net to OMV), which will increase to 129,000 barrels per day (25,800 barrels per day net to OMV) by the end of 2018 and 215,000 barrels per day (43,000 barrels per day net to OMV) by 2023.
The Vienna-based OMV in April this year signed an agreement for the award of a 20% stake in the offshore concession Abu Dhabi – SARB (with the satellite fields Bin Nasher and Al Bateel) and Umm Lulu as well as the associated infrastructure. The agreed participation fee amounted to USD 1.5 bn and the duration of the contract is 40 years.
The SARB field, 120 km away from Abu Dhabi, and the Umm Lulu field, about 30 km away from Abu Dhabi, are both located offshore in shallow waters. The early production in Umm Lulu started in the fourth quarter of 2016.
OMV’s share of the reserves, for the period of the concession agreement, would amount to approximately 450 mn barrels oil for the two main fields, with upside potentials from the satellite fields Bin Nasher and Al Bateel, the company said.
OMV’s capital expenditures over the contract term are estimated to amount to approximately $2 bn, thereof approximately USD 150 mn will be spent per annum during the first five years, OMV said on Thursday.
https://www.offshoreenergytoday.com/omv-oil-starts-flowing-from-offshore-oil-fields-in-uae/
China’s Sinopec Corp is halving loadings of crude oil from Iran this month, as the state refiner comes under intense pressure from Washington to comply with a U.S. ban on Iranian oil from November, said people with knowledge of the matter.
The sources did not specify volumes, but based on the prevailing supply contract between the top Chinese refiner and the National Iranian Oil Company (NIOC), its loadings would be reduced to about 130,000 barrels per day (bpd).
This would be 20 percent of China’s average daily imports from Iran in 2017, dealing a blow to Tehran, which has counted its top oil client to maintain imports while European and other Asian buyers wind down purchases to avoid U.S. sanctions.
The cut marks Sinopec’s deepest reduction in years as the Hong Kong and New York-listed state oil company faces direct pressure from a U.S administration determined to choke off the flow of petrodollars to the Islamic Republic.
The move comes after senior U.S. officials visited the refiner in Beijing last month, demanding steep cutbacks in Iranian oil purchases, said one of the sources.
“This round is completely different from last time. Then it was more of a consultative tone, but this time it’s almost like an ultimatum,” said the source.
The sources declined to be identified due to the sensitive nature of the matter. Sinopec declined to comment. NIOC did not respond a Reuters email seeking comment.
Further complicating the matter, Iran is having difficulty securing insurance for its oil vessels, said shipping and insurance sources, as most European and U.S.-based re-insurance firms are winding down their Iranian business.
Chinese buyers, including Sinopec and state-run trader Zhuhai Zhenrong Corp, have since July shifted their cargoes to vessels owned by National Iranian Tanker Co (NITC) to keep supplies flowing amid the reinstatement of economic sanctions by the United States.
During the last round of United Nations sanctions around 2011, officials from Washington asked Chinese firms to curb investments in Iranian oil and gas fields, but stopped short of demanding a full stop to oil shipments.
It’s not clear if Zhuhai Zhenrong has also reduced loadings this month. The state trader is contracted to lift some 240,000 bpd from Iran, mainly to feed Sinopec refineries.
It’s also not clear if Sinopec and PetroChina are cutting loadings from their upstream investment in key Iranian oilfields that total between 100,000 to 150,000 bpd. These loadings are separate from their annual supply contracts.
Beijing has repeatedly defended its energy trade with Tehran, worth about $1.5 billion a month, as transparent and lawful. Some of the top oil refineries that come under Sinopec are configured to process Iranian oil.
Oil production in Russia averaged 11.347 million barrels per day (bpd) between Sept. 1 and Sept. 27 and was on track to reach another post-Soviet high, an energy sector source told Reuters on Friday.
Measured in tonnes, average daily oil production stood at 1.548 million tonnes in that period, the source said, citing preliminary data that the Russian Energy Ministry obtains from oil companies.
The ministry, which is due to publish monthly production data for September on Oct. 2, did not immediately reply to a Reuters request for comment.
In August, Russia’s oil output stood at 11.21 million bpd, virtually unchanged from July.
Russia appears to have increased oil production by more than 130,000 bpd in September compared with August levels, according to the preliminary data cited by the source.
Energy Minister Alexander Novak said earlier this month that oil production in September was expected to be higher than in August.
Last week, OPEC’s leader Saudi Arabia and its biggest oil-producer ally outside the group, Russia, ruled out any immediate additional increase in crude output even though oil had reached $80 per barrel - a price considered too high by some producers and consumers.
Asia’s emerging markets, the key driver for global oil demand growth, are being hit hard by soaring crude prices and sliding currencies, raising red flags over expectations of further increases in consumption.
Import-reliant economies are already aching under oil prices that have risen above $80 per barrel this week, the most since late 2014.
Analysts warn the inflationary combination of higher oil costs and weakening currencies, including India’s rupee, Indonesia’s rupiah and the Philippine peso, could cause a global economic slowdown that would also crimp oil demand in those countries.
The rumblings of falling demand undermines the current market narrative that projects rising crude prices, in some cases to $100 a barrel, amid the loss of Iranian supply as the United States is set impose new sanctions on the country on Nov. 4.
“The currency exchange for those emerging economies is leading to expensive prices at the pump... We expect this will lead to lower demand growth in the region,” said Keisuke Sadamori, director of energy markets and security at the International Energy Agency (IEA) this week.
Edward Morse, the global head of commodities at Citi Research, said the emerging market woes could shave 100,000 barrels per day (bpd) off oil demand growth in 2019.
The IEA currently expects global oil demand growth for 2018 and 2019 at 1.4 million bpd and 1.5 million bpd, respectively.
At $80 per barrel, Asia’s oil import bill would breach $1 trillion a year, and few traders or analysts expect crude prices to ease.
For the lower income countries of emerging Asia, fuel prices are too expensive at those levels.
“We have already heard anecdotes from around the world that customers try to economise at the pump by downgrading their fuel consumption from high quality fuel to lower quality fuel to save the extra few bucks,” said Janet Kong, chief executive of Integrated Supply and Trading Eastern Hemisphere at BP.
RECORD FUEL PRICES
Global oil consumption is set to increase by 1.4 percent in 2018, according to the IEA. But that number may fall as Asian governments and consumers try to cut their oil costs.
In India, the world’s third-biggest oil importer, refiners are considering the risky move of cutting back crude imports, hoping to use up stocks until prices fall back.
The currency’s plunge has meant oil prices have risen nearly 50 percent in rupee terms this year.
Indonesia, Southeast Asia’s biggest country and economy, increased its subsidy of diesel sold in fuel stations and its imports of lower quality gasoline.
The Philippines, another major Asian emerging economy, is allowing the sale of lower quality fuels to consumers to combat inflation, according to two trade sources.
When oil prices declined in 2014, many governments including India and Indonesia, increased fuel taxes or removed subsidies leading to record high retail fuel prices as crude prices rose.
The IEA’s Sadamori said there is increasing pressure on some countries to re-introduce fossil fuel subsidies.
“That’s something we are really concerned about,” he added.
Iraq plans to increase the production and exports of light crude oil to 1 million barrels per day in 2019, as part of its strategy to boost state revenue, its oil minister Jabar al-Luaibi said on Sunday.
The light crude oil is a new grade with an API gravity of around 34-43, while the current Basrah Light grade that Iraq exports will be renamed Basrah Medium, one Iraqi industry source familiar with the matter said.
“This (decision) will boost Iraq’s position in the global oil markets by producing three crude grades: light, medium and heavy,” al-Luaibi said in a statement.
Iraq is OPEC’s second-largest producer after Saudi Arabia and pumps around 4.6 million bpd. The majority of its crude exports go to Asia.
The bulk of Iraq’s oil is exported via the southern terminals, which account for more than 95 percent of the OPEC producer’s state revenues. Iraq exported 3.583 million bpd from the southern ports on Gulf in August.
Iraq’s crude exports have risen in recent months as shipments drop from Iran, OPEC’s third biggest producer, which is facing renewed U.S. sanctions.
Iraq decided to split its oil supply into two grades in 2015 to resolve quality issues. It offered Basrah Heavy produced from southern oilfields separately from its traditional Basrah Light crude.
The shift by Iraq’s state-oil marketer SOMO was widely supported by crude buyers who until then had to deal with variations in the quality of a blend of Basrah Light with heavier, high-sulfur content oil produced from newer fields.
Selling Basrah Heavy and Basrah Light separately increased buyers’ confidence in quality, and cut the time ships spent waiting for different crudes to reach terminals and that had added to costs.
But the current Basrah Light grade, was itself a blended grade using crude from different oilfields, which has also led to varying qualities in different cargoes, the source said.
Now Iraq will sell the current Basrah Light grade as Basrah Medium with a lower API.
The volumes for the new light crude will come from the Luhais, Tuba, and Artawi southern oilfields, an Iraqi oil official familiar with the project’s execution told Reuters.
“We expect rising demand from Asian refiners for the low-sulfur Basrah light crude in 2019. Meeting demands of buyers will help Iraq win more customers in the Asian markets.”
Iraq, which relies on oil to generate most of its budget revenues, is seeking to increase crude production capacity to 7 million bpd by 2022 from 5 million bpd now.
Talk about inconvenient timing. Just as Saudi Arabia is about to switch the way it prices its oil exports, the new benchmark throws a spanner in the works by surging inexplicably.
Oman crude futures traded on the Dubai Mercantile Exchange (DME) rushed to their highest level in four years last week, trading as high as $90.90 a barrel on Sept. 26.
While the sharp rise in prices isn’t without precedent, especially given market concern over the imminent loss of much of Iran’s exports, what was unusual was that Oman swept past Brent futures, the global benchmark.
This has happened only on a handful of occasions in the past decade, most recently in September last year, and then only for a day and at a relatively modest premium of 54 cents a barrel, according to calculations by S&P Global Platts.
Oman and Brent futures have different daily settlement times, but when the DME contract finished on Sept. 26 it was at $88.96 a barrel, while at that time Brent was at $82.14.
Oman normally trades below Brent as it is a medium-sour crude, which is typically more costly for refiners to process and doesn’t yield as much of the high-value products such as gasoline as does Brent, which is a light, sweet oil.
For Oman to romp to such a large premium to Brent, and maintain it for four sessions, is unusual and will no doubt be of concern to both the DME and Saudi Arabia, as well as the refiners who buy Saudi crude.
Traders appear largely to have been caught by surprise by last week’s spike in Oman, if comments at the annual industry gathering in Singapore were anything to go by.
But the likelihood is that the increase in Oman will be unwound in coming days, given that it seems to have been largely driven by buying by Chinese refiners.
The bulk of delivered Oman heads to China and it appears that refiners in the world’s largest crude importer, especially smaller independent operators, were keen to stock up before the end of the year to use up their import allocations.
Chinese buying may also have been boosted by the fact that this week is a holiday for the country’s National Day, meaning most crude trading businesses will be closed.
There is also likely a smaller element of buying boosting the Oman contract, and that is the potential looming shortage of heavier and sour grades of crude as renewed U.S. sanctions against Iran ramp up to include all of the Islamic Republic’s crude exports from November.
Many Asian refiners prefer heavier crudes, having invested in units that can process these grades into higher value products, especially middle distillates such as diesel and jet fuel.
ARAMCO’S SWITCH
While it’s likely that Oman’s premium to Brent will be unwound in coming days, the timing couldn’t have been worse for Saudi Aramco, the state-owned producer that is the world’s largest exporter of crude.
From October, Aramco was changing the benchmarks used in calculating its official selling prices (OSPs), for the first time since the mid-1980s.
The Saudis used to use the average of Oman and Dubai prices, as assessed by S&P Global Platts in calculating the OSPs.
From this month it will use the average monthly price of DME Oman futures as well as the Platts average for physical Dubai quotes.
The change has been a long time coming and is perhaps a reflection of the success the DME has had in building Oman futures into a viable benchmark for Middle East medium heavy and sour crude.
The Platts assessments are also long-standing and well-respected in the market, but were perhaps more vulnerable to price spikes given the relatively small amount of physical crude underpinning the pricing.
This happened in 2015 when the trading arms of China’s state-controlled refiners bought up large amounts of the oil available through the Platts pricing mechanism in a matter of days, leaving the pricing subject to volatility and spikes.
The switch to using DME futures as one-half of the Saudi benchmark was supposed to make the pricing more transparent and robust, given the Oman contract has more physical volumes behind it and the backing of a cleared exchange.
But last week’s surge has shown that the Oman contract can also shift dramatically in a short space of time, if the demand for crude is there.
The Saudi OSPs tend to set the pattern for crude pricing from Iran, Iraq and Kuwait, meaning some 12 million barrels per day of exports are impacted.
Asian refiners will now be worried that last week’s price action will result in higher than anticipated OSPs, with the Saudis likely to announce their prices at the end of this week.
This isn’t the start the DME and Aramco would have wanted for the new pricing system, but the chances are it is merely a blip, rather than the harbinger of sustained volatility and uncertainty.
OPEC kingpin Saudi Arabia plans another boost in government spending in 2019 to spur its economy, but is proceeding cautiously with an eye on potential oil market headwinds in the year ahead.
Register Now The world's largest crude exporter, whose fiscal plans are scrutinized for hints of how it will manage the oil market, released its 2019 preliminary budget, estimating a 7% year-on-year rise in government expenditure to 1.1 trillion riyals ($295 billion).
It also forecast revenue, some 70% of which come through oil sales, would come in at 978 billion riyals ($261 billion), an 11% increase from 2018, due to this year's surge in crude prices.
Finance Minister Mohammed al-Jadaan said in a statement that the deficit spending is intended to further the country's ambitious structural reforms under the Vision 2030 program, which seeks to diversify Saudi Arabia's economy away from oil revenues. The kingdom aims for a balanced budget by 2023, he added, but warned that stability in the oil market would be key to making the reforms sustainable.
"The kingdom's public finance is facing challenges, notably oil price fluctuations, which hinder fiscal planning," the preliminary budget stated.
Further 2019 budget details are expected to be released in December.
Analysts with Saudi-based investment bank Al-Rahji Capital said the budget appeared "conservative," given that oil prices have risen and Saudi Arabia's crude exports are likely to increase in the months ahead under an agreement reached June 23 by OPEC and 10 non-OPEC allies to raise production by some 1 million b/d. Brent crude futures were trading at $83.01/b at 0006 GMT, up almost 50% from a year ago.
But Saudi officials have warned of a potentially soft oil market in 2019, with many forecasts showing demand growth leveling off while non-OPEC crude production rises. OPEC is wary of flooding the market by pumping too wantonly, Saudi energy minister Khalid al-Falih told reporters at an OPEC/non-OPEC monitoring committee meeting in Algiers last week.
"We could have an oversupply situation," Falih said. "Given where we are today on inventory levels, we need to make sure we don't get into a sustained build of inventories in 2019."
Saudi Arabia has been under pressure from the US to supply the market with more oil to cool prices, which are at a four-year high in large part due to fears of a looming shortage as US sanctions on Iran go into force in November.
King Salman bin Abdulaziz al-Saud and US President Donald Trump spoke Saturday by telephone to discuss "efforts to maintain supplies to ensure the stability of the oil market and ensure the growth of the global economy," according to the Saudi Press Agency.
Trump, who has scolded OPEC five times on Twitter over oil prices, kept the pressure on after the phone call, suggesting in a speech at a campaign rally Saturday night that he could cut military support for Saudi Arabia.
"I said, 'Saudi Arabia, you're rich, you've got to pay for your military,'" Trump said, describing his phone call with King Salman.
Saudi Arabia has never pumped more than 10.7 million b/d across an entire month, according to its own figures reported to OPEC, but could approach or even surpass those levels this month.
Falih said in Algiers that the kingdom's production in September would be higher than August's 10.4 million b/d, with October output shaping up to be even higher on increased demand.
But he added that Saudi production volumes would be dictated by customer requests, not geopolitics.
Skyrocketing premiums for Far East Russian ESPO Blend crude oil loading from Kozmino over October and November has compelled refiners to search for cheaper alternatives, sources told S&P Global Platts on Monday.
Premiums for M2 November-loading ESPO crude reached near five-year high on Friday, where it was assessed at $6.75/b to Platts front-month Dubai assessments, up 50 cents/b from Thursday. The premium stood at the same level on December 4, 2013, data from S&P Global Platts showed.
"I expected ESPO premiums to go around mid-$4s to Dubai this month, but close to $6/b and above is a shock," a Singapore-based trader said.
Cargoes from the ESPO Blend's November-loading program offered by equity holders were heard to have been picked up at premiums of around $4.85/b to as high as $6.75/b to the mean of Platts front-month Dubai assessments, market sources said.
Overall front-month premiums for ESPO Blend crude averaged $4.39/b in September, compared to $2.51/b in August, Platts data showed.
Growing demand from China, a favored destination for the Far East Russian grade, coupled with the fundamental strength seen in underlying Dubai prices and robust refining margins, has contributed to the rising spot premiums, market sources said.
The spike in premiums has attracted interest for similar middle distillate-rich sour crudes, one such possibility being ADNOC's flagship Murban grade, trade sources said.
"Given where ESPO premiums are, it opens up the window for Murban cargoes", a crude trader said.
Being more distillate-rich, ESPO Blend in general demands a quality premium over Murban and a shorter voyage journey from the port of Kozmino to China provides a freight advantage as well, sources said.
The recent surge in spot premiums however may have resulted in Murban grades looking more economically viable to source instead of ESPO, said sources.
Barely a month after trading at substantial discounts, premiums for light sour crude grades such as Murban rose to trade in premiums in the month of September.
"For mediums and heavies it [higher demand] was expected, [it is] very surprising for the light sour end," a seller of Persian Gulf crude based in Singapore said last month.
Robust refining margins for middle distillates, combined with a closed arbitrage from the West of Suez to Asia, spurred demand for light sour Persian Gulf crude grades this month, sour crude traders said.
In early September, November-loading cargoes of Murban and Das Blend crude grades traded at premiums of around 35-45 cents/b to their respective OSPs. In subsequent weeks, Murban cargoes traded during the Platts Market on Close assessment process, at premiums ranging from 45 cents/b up to 60 cents/b, showcasing firm Asian demand for the grade.
However, not all Chinese independent refiners that run ESPO have the capacity to switch fluidly to Murban or similar Persian Gulf crudes. This may cap the upside in premiums for these barrels, sources said.
"Unlike majors, Chinese independents don't have the capacity to switch grades. They would prefer to stick to the grades they are used to running," a China-based crude trader said.
"Therefore ESPO would still be bought," he added.
The Saudi crown prince held talks with Kuwait’s ruler about increasing cooperation on oil policies. In the shadows of their discussions lies the fate of two jointly owned fields that can produce half a million barrels a day of crude and help OPEC fill a possible supply gap.
Khafji and Wafra, the fields located in the shared Neutral Zone between Saudi Arabia and Kuwait, are crucial for the kingdom to meet its official production ceiling of 12.5 million barrels a day of oil. State-owned Saudi Arabian Oil Co., the world’s biggest exporter known also as Aramco, directly controls 12 million barrels of daily Saudi output.
Crown Prince Mohammed Bin Salman Al Saud met with Kuwait’s Emir Sheikh Sabah Al-Ahmed Al-Sabah on Sunday, according to the official Saudi Press Association. The visit is expected to increase the convergence of Saudi and Kuwaiti oil policies and bring more stability to global oil markets, according to a Saudi government statement. The Saudi prince left Kuwait early on Monday, SPA reported, without giving details of the talks.
A resumption in output at even one of the shared fields could make up for about half of the shortfall from production targets that OPEC and its allies set for themselves a few months ago. The Organization of Petroleum Exporting Countries and its partners agreed in June to achieve 100 percent compliance with quotas they established in 2016, yet they’ve been pumping about half a million barrels a day below their collective target.
Kuwaiti Oil Minister Bakheet Al-Rashidi said last week in an interview in Algiers that his country was holding “positive” talks with Saudi Arabia about resuming production at the shared deposits.
Khafji closed in October 2014 due to unspecified environmental concerns, while Wafra, which Chevron Corp. operates on behalf of Saudi Arabia, closed in May 2015 because of difficulties in securing work permits and access to equipment. The fields have a combined capacity of more than 500,000 barrels a day.
Oil extended gains on Monday after the longest quarterly rally in a decade, a surge that has prompted comments and criticism from U.S. President Donald Trump. Concerns are mounting over a looming shortfall of crude as U.S. sanctions restrict Iranian oil exports, and Trump and Saudi King Salman bin Abdulaziz on Saturday discussed efforts to maintain supplies.
Production of hard-to-recover oil in Russia is expected to rise by 10 percent to 43 million tonnes (860,000 barrels per day) this year, boosted by tax incentives, Russian Deputy Energy Minister Pavel Sorokin said in an interview.
He also said the government had no immediate plan to reduce oil exports in order to curb an increase in domestic fuel prices.
Russia is pinning its hopes on hard-to-recover oil, hidden beneath non-porous rocks, as conventional oil reserves in West Siberia, its main oil-producing region, are becoming increasingly depleted.
As part of Western sanctions over the conflict in Ukraine, the United States imposed restrictions on providing Russia with technology for hard-to-recover oil, also known as shale oil.
But despite the sanctions, oil production, including hard-to-recover crude, is growing.
“Many of our companies have advanced in this direction,” Sorokin said of Russian producers’ ability to extract such oil.
“We expect that the production of hard-to-recover oil will rise from 39 million tonnes (in 2017) to 43 million tonnes by the end of 2018,” he said.
Russia’s oilfield licenses regulator Rosnedra has put the country’s hard-to-recover oil reserves at around 12 billion tonnes, or 88 billion barrels - two-thirds of all Russian oil reserves, and enough to supply the world with oil for 20 years.
The state has introduced tax incentives for hard-to-recover oil production, including a zero-rate mineral extraction tax.
NO EXPORT LIMIT
Overall oil production in Russia is seen at 553 million tonnes this year, up from 547 million tonnes last year.
Sorokin, who with Energy Minister Alexander Novak has been heading Russia’s efforts to forge closer ties with oil producer group OPEC, said Moscow had no immediate plan to restrict oil exports in order to dampen domestic fuel prices.
It is more profitable for companies to sell fuel abroad than on the domestic market for several reasons, including the weakening of the rouble.
“We’re not talking about physical restrictions at the moment,” the deputy minister said, adding that there are no fuel shortages on the domestic market.
Russia is unable to materially increase crude supplies to Asian markets who are faced with the loss of Iranian imports due to existing transportation constraints, Russia's deputy energy minister Pavel Sorokin told S&P Global Platts in an interview Monday.
Infrastructure limiting eastern exports
But Russia could send more barrels to Europe in the coming months if the economics there become more attractive with US sanctions on Iran's oil exports kicking-in from early November, Sorokin said.
Russia has nearly tripled crude exports to Asian markets to over 1 million b/d over the last eight years after the East Siberia-Pacific Ocean (ESPO) pipeline came into operation in 2010, redirecting some barrels from less lucrative westbound directions.
"We have been supplying as much as we can to Asia, as this is a premium market. We've always maximized and will maximize volumes flowing there..." Sorokin said. "This is why our ESPO and Novorossiisk are used at full capacity."
Although China, Iran's biggest crude buyer, has said it plans to ignore the imminent US sanctions on Iran, Japan and South Korea and India are all expected to abide by the curbs and restrict their imports of Iranian crude.
Iran's exports have already fallen by some 700,000 b/d since US President Donald Trump pulled out of the nuclear deal with Iran in May, forcing end-users to seek alternative grades. Total Iranian exports are expected to fall by up to 1.7 million b/d when the US sanctions become fully effective on November 5.
URALS ALTERNATIVE
Sorokin said that Russian crude producers could increase crude supplies to European markets, as there are no transportation constraints, in contrast to the situation with Russia's eastward infrastructure, which is being used at its full capacity.
"If the oil price grows in Europe due to drops in Iranian crude volumes [anticipated in the wake of US sanctions' re-imposition], companies will increase deliveries to this region at the expense of less attractive directions. We'll supply [more] to where the economics are the most attractive," he said.
Medium sour Urals has been seen by international buyers as one of the best alternatives to Iranian barrels, due to its proximity to the market, with many refineries in Europe built specifically to process Russian crude.
Urals was trading around multi-year highs relative to Dated Brent in both Northwest Europe and the Mediterranean in late August-early September. Its price, though, has weakened in late September due to growing barrels available for Europe amid maintenance season in Russia.
OUTPUT GROWTH
In August, Russia restored the bulk of its output reduced under the OPEC-led production cut deal and has the potential to increase it further by the end of this year. The ministry has though avoided providing any concrete estimates of crude output levels over the coming months.
"The current potential is around 200,000-300,000 b/d up to the end of 2019 from the current level, thanks to fields that have been prepared for full-scale development such as Yurubcheno-Tokhomskoye or Tagul," Sorokin said in comments close to those provided by the energy minister Alexander Novak in late September.
Russia's output amounted to 11.21 million b/d in August, compared to 11.23 million b/d in October 2016, according to Russia's Central Dispatching Unit, the statistical arm of the energy ministry.
In order to support crude production, the Russian energy ministry is now focusing on development of new stimuli for West Siberia, as the country's oil output is currently estimated to peak in early 2020s and start falling afterwards, Sorokin said.
"West Siberia has substantial potential, but nearly half of the reserves in the region, which has the highest level of [oil] taxation, are not profitable for development," he said, adding that production growth seen in Russia over the last 10 years came mainly from other regions that enjoy significant tax breaks.
On the contrary, West Siberia, Russia's main oil province which accounts for some two-thirds of the country's total output, has faced natural decline over the same period. Without new tax breaks, crude production will "inevitably" start falling in the near term, Sorokin said.
The ministry has proposed to the government implementation of six additional measures to address the problem, and hopes they will be approved in the near future. The ministry estimates Russia crude output could drop to as low as 7 million b/d by 2030 without new stimuli.
READY FOR IMO 2020
Sorokin also commented on the introduction of tougher regulations by the International Marine Organization that foresee a significant drop in sulfur content in bunker fuel from January 1, 2020, saying that Russian refiners are mainly prepared for the changes.
"We expect neither a catastrophe nor major problems for Russian companies," Sorokin said.
"Those companies that have modernized their refineries and bunker fuel production in particular [in anticipation of the tougher regulation] are unlikely to notice any change, given stimuli payments [by the state]," he said.
Recently approved changes to the tax legislation, under a so-called tax maneuver, envisages payments of Rb1,000/mt (about $15.25/mt) for fuel that meets new bunker fuel standards, he pointed out.
The country consumes domestically some 15 million mt/year of fuel oil, of which around 4.5 million mt/year is used for heating, with the remaining 8 million -9 million mt/year is used for bunkering, Sorokin said.
Sunrise Pipeline set rates for its new crude pipeline extension from Loving County, Texas in the Permian basin to the storage hub of Cushing, Oklahoma, effective Nov. 1, according to a regulatory filing on Monday.
The startup of the expanded line is expected to ease a bottleneck that has depressed crude prices in nearby Midland, Texas for months. Crude is already flowing in the line and it is expected to go into full service in early November.
The pipeline established uncommitted spot rates at $1.69 per barrel and committed rates for anchor shippers at $1.70, while committed non-anchor shippers will be charged $1.75 a barrel, Sunrise said in a U.S. Federal Energy Regulatory Commission filing.
Committed shippers must have entered an agreement with Sunrise during the open season held in 2017. Anchor committed shippers must have contracted to ship at least 80,000 barrels per day (bpd) with Sunrise for a term of at least seven years.
The pipeline, operated by Plains All American LP, is one of two projects slated to begin partial operations slightly ahead of original schedules.
Plains’s 670,000 barrels per day (bpd) Cactus II line from the Permian to Corpus Christi will begin partial service in the third quarter of 2019.
Pipeline companies are racing to add lines as production in the Permian Basin, the largest U.S. oil patch, has outpaced pipeline shipping capacity. New lines are expected to add more than 1.5 million bpd in additional capacity by mid-to-late 2019.
West Texas Intermediate at Midland traded at about $7 and $7.50 a barrel below benchmark U.S. crude futures on Monday, well above a discount of about $17 a barrel in late August, the weakest level in four years.
Plains has been an active buyer in the spot market, scooping up barrels to fill the line and that has helped support prices, traders said.
Kuwait Petroleum Company said on Monday news reports of a drop in crude exports to the United States were “inaccurate and do not explain the implications of a reduction in the rate of exports between the two countries”.
Bloomberg reported earlier that Kuwait had all but stopped shipping crude to the United States for the first time since the aftermath of Saddam Hussein’s invasion in 1990.
Kuwait Halts Crude Shipments to US
Kuwait has all but stopped shipping crude to the U.S. for the first time since the aftermath of Saddam Hussein’s invasion in 1990, eroding an economic link between Washington and the Arab petro-monarchy.
The halt is the latest sign that booming demand for oil in Asia, particularly as the U.S. re-imposes sanctions on Iran, and rising supplies from America on the back of the shale revolution are re-drawing petroleum trade routes.
U.S. imports of Kuwaiti crude fell to zero over four weeks through late September, the first time that shipments have completely stopped since weekly data became available in June 2010, according to the U.S. Energy Information Administration. Based on monthly data, Kuwaiti shipments to the U.S. haven’t stopped since May 1992, when the OPEC producer was still recovering from oil-field fires ignited by retreating Iraqi troops in the first Gulf War.
Kuwait is diverting its barrels instead into the more lucrative Asian market, where prices are higher for the type of high-sulfur crude the small Middle Eastern nation pumps, according to a person familiar with the matter, who asked not to be identified because the matter isn’t public.
Kuwaiti oil fetches about $80 a barrel in Asia compared with about $79 in the U.S., according to Bloomberg calculations based on benchmark prices and the country’s official selling prices. Kuwaiti crude sells at about $76 a barrel in Europe.
“Iranian sanctions are providing a chance for others to sell more into Asia where prices are better than for sales into the U.S.,” Andy Lipow, president of consultant Lipow Oil Associates LLC, said in Houston.
While its shipments to the U.S. have plunged, Kuwait faces limits on its production due to a dispute with Saudi Arabia over shared oil fields along their border where both nations in the past pumped as much as 500,000 barrels a day. The shared fields in the so-called neutral zone halted production more than three years ago, though the two governments are in talks to reactivate them.
Kuwait Petroleum Corporation’s reduction of crude exports were “coordinated with U.S. and European clients,” the company said in a statement on Kuwait News Agency (KUNA) website. The American market is “strategically important” and its supply contracts are “functional”, the state-owned oil producer said.
Kuwait has typically exported about 80 percent of its oil to Asia, and those shipments are increasing with the ramp-up of operations at the Nghi Son Refinery and Petrochemical Co. in Vietnam. KPC co-owns the plant, which can process 200,000 barrels a day.
Despite the lower prices, Kuwait’s crude sales to the U.S. helped the Arab state diversify its exports and offset episodes of weak demand in Asia during economic downturns in that region. The exports also provided a strong economic link with Washington, which played a crucial role in liberating Kuwait after the Iraqi invasion. The U.S. in 1990 forged a coalition of 35 countries with more than a million troops to drive out the Iraqis in Operation Desert Storm.
Valero Energy Corp., Marathon Petroleum Corp., Exxon Mobil Inc., and Royal Dutch Shell Plc had been the largest U.S. buyers of Kuwaiti crude oil so far this year, supplying refineries in California, Texas and Louisiana, according to EIA data.
Kuwait grabbed market share in the U.S. from Saudi Arabia and Iraq between 2012 and 2014, shipping more than 400,000 barrels a day in some months. After that, however, Kuwaiti exports to the U.S. declined sharply, and Riyadh and Baghdad boosted their sales. On a four-week average basis, Saudi Arabia shipped 1.01 million barrels a day, while Iraq, a fellow member of the Organization of Petroleum Exporting Countries, exported 408,000 barrels a day.
http://businessweekme.com/kuwait-halts-crude-shipments-to-us/
U.S. East Coast oil refiners are ramping up rail deliveries of crude from Western Canada, grabbing stranded barrels that full pipelines have driven to a record discount.
That trend is expected to accelerate, as prices will remain weak, with no new Canadian export pipelines expected until late 2019. Rail volumes from Canada to East Coast refineries averaged 35,000 barrels a day for the 12 months ending in July, up from 16,000 bpd for the prior 12-month period.
Canada is having difficulty building and expanding pipelines due to environmental and aboriginal opposition, prompting a swing back to its crude-by-rail delivery system.
Bottlenecks helped drive the discount of Western Canadian Select heavy crude, the primary grade of oil produced in the province of Alberta, to a record $43.50 below U.S. West Texas Intermediate oil futures late last week.
Canadian light synthetic crude trades around $18 below WTI, making both Canadian benchmarks more attractive to U.S. East Coast refiners than U.S. grades of oil or crude imported from Europe or Africa. Brent, the international benchmark, is currently trading at nearly a $10 premium above U.S. crude.
“Historically, East Coast refiners would be at the mercy of global waterborne Atlantic pricing, but given how North American crude differentials materially weakened, this has been a significant boon,” said Michael Tran, commodity strategist at RBC Capital Markets.
With five of the top 10 U.S. refiners of Canadian crude scheduled to go offline for maintenance in the next six months, Canadian prices may remain depressed, Tran said.
If the Canadian differential stays wide and rail capacity grows, traders expect volumes east to return to record levels around 100,000 bpd, last reached in 2014.
Just one East Coast refinery regularly processes the heavy oil that accounts for most Western Canadian production, traders said. Recent rail shipments of heavy crudes have gone to PBF Energy Inc’s (PBF.N) 190,000-bpd Delaware City refinery, and light crude to Philadelphia Energy Solutions Inc’s 335,000-bpd complex, sources said.
Phillips 66 (PSX.N) took in Canadian heavy crude to its 258,000-bpd New Jersey refinery in April for the first time in a year and a half, and also imported in May and June, the last months for which data is available. PBF, Phillips 66 and PES declined to comment on commercial operations.
Rail volumes from Canada to Gulf Coast refineries are larger than those to the East Coast, but their growth rate is slower. Those volumes averaged 81,000 bpd in the 12 months to July, up 26 percent from the previous 12-month period, EIA data showed.
“There’s existing shippers who have increased their volumes to the east,” said Iqbal Gill, head of hydrocarbon supply for BarrelTex. “Gulf Coast shipments have increased as well but not to the degree Eastward movements have.”
Canada’s overall crude exports by rail hit a new record at 206,624 bpd in July. This is expected to keep rising, yet shipments may be hindered by competition from other commodities like grains and a shortage of rail cars.
Regulators are fast-tracking the phase-out of older, more puncture-prone cars, while top U.S. railroad BSNF is limiting the use of retrofitted cars on its lines, citing safety concerns.
Those changes together affect roughly 17 percent of the current fleet of crude rail cars in North America, said Matt Murphy, an energy analyst with Tudor, Pickering, Holt & Co.
This will limit volumes of Canadian crude to East Coast refineries, say traders.
“Every refinery out there that has access to rail is looking for more unit trains but they’re nowhere to be found,” said one East Coast refinery trader, who declined to be named, citing company policy.
Iran plans to start offering oil for exports via its national stock exchange as early as next week, the Islamic Republic News Agency (IRNA) reported on Monday, quoting the head of the state oil company and deputy oil minister Ali Kardor.
Iran will be offering one million barrels via the stock exchange, with all those barrels bound for exports, Kardor, who is managing director of the National Iranian Oil Company (NIOC), said.
In July, Iran’s First Vice-President Eshaq Jahangiri said that the country would be looking to offer oil via the stock exchange because of the U.S. sanctions on Iran that will restrict its oil exports, IRNA reports.
While analysts now expect that the losses of Iran’s oil exports could be higher than 1 million bpd with the U.S. sanctions returning in early November, Iran continues to claim that it has the means to ‘defeat’ the restrictions, continue to sell its oil, and ‘easily’ get the revenues from oil sales.
Iran’s oil ministry’s news service Shana quoted on Sunday Kardor as saying that Iran has no plans to reduce its oil production, that NIOC has access to all its revenues, and that it “easily collects the money from selling crude oil.”
The national oil company is also providing by itself coverage for shipments, Kardor said.
According to OPEC’s secondary sources, Iran’s oil production for August—the latest available official OPEC data—was 3.584 million bpd, down by 150,000 bpd compared to July.
Iran is also said to have returned to storing oil in tankersas the sanctions are cutting its ability to ship the oil. Moreover, the Islamic Republic is also reportedly switching off tanker tracking systems, a method that Tehran is said to have used in the previous round of sanctions in 2012-2015.
The U.S. efforts to choke off Iran’s oil this time look much more coercive, and even the largest refiner in Tehran’s biggest single customer China may have come under U.S. pressure. Last week, reports emerged that Sinopec is halving Iranian oil imports as of September.
According to preliminary tanker tracking data by Bloomberg, Iran’s oil exports have dropped by 870,000 bpd since April this year and are on track for less than 2 million bpd for a second consecutive month in September.
A total of 1.56 Mb of crude oil are floating in strait of Malacca as of sept. 30: Data from cargo-tracking and intelligence Kpler That’s down ~72% from 5.669 Mb a month earlier
@baryal111
Freight rates for VLCCs making long-haul voyages east out of the US Gulf Coast and Caribbean continued to soar Monday, jumping $1 million in just two trading sessions as tonnage availability continued to wane, with an increased number of Asian buyers looking to cover cheaper US crude cargoes.
"All of the Japanese and Korean charterers are stepping up," one shipbroker said of the influx in cargo inquiries, while a shipowner pointed to the re-entry of China's Unipec into the US crude buying sphere as an additional bullish factor for VLCC freight rates.
The rate to take a VLCC carrying a dirty cargo on a USGC-Singapore run, has climbed nearly 23% since Thursday, the day before rates jumped $800,000 day on day. Freight rates rose another $200,000 Monday to reach a lump sum of $5.4 million, the highest level since S&P Global Platts began assessing the route in March 2018.
Market participants initially looked to a deal by Occidental Petroleum, booking a to-be-nominated Bahri ship, with options for discharge at Singapore at a $5.2 million lump sum and China at $6.2 million, to move the market higher Friday.
The vessel is set to load on the USGC on October 26-31. Litasco also booked a to-be-nominated ship to cover a cargo for the same route at the same rate for November 5-10, sources said Monday.
Rates continued to move higher as Monday progressed, with Hundayai Oil Bank placing a to-be-nominated Bahri ship on subjects to lift a cargo from the east coast of Mexico, with options for discharge at Singapore for $5.6 million and South Korea at lump sum $6.6 million.
There were at least five fixtures reported over the course of Monday and Friday for VLCCs heading to the East Asia for late October and early November dates and a possible three additional cargoes -- two for loading on the USGC and one in the Caribbean -- in the need of vessels for the same time period.
Some shipping sources also said a desire to move barrels before the end of the month was lending to the bullish sentiment created by cargo inquiries from Asian charterers.
The "tonnage is not there," a different shipbroker said of the firming market, "but the cargoes are still there and owners want more."
DEMAND PUSHING US CRUDE EXPORTS HIGHER
The spread between NYMEX WTI and ICE Brent has allowed US Gulf Coast crude grades to strengthen over the past week.
The frontline Platts Brent-WTI Houston Swaps spread ended Friday at $9.50/b, compared with $9.19/b on Thursday and $9.20/b on September 26. The spread narrowed slightly Monday, ending at $9.38/b. However, US crudes continued to find support.
The wider spread tends to boost WTI-linked USGC crudes as they are appealing to buyers in Asia and Northwest Europe.
International demand for US crude is expected to boost exports in the coming weeks.
The US exported 2.64 million b/d in the week that ended September 21, according to the Energy Information Administration, the highest volume of exports from the US since the week that ended July 20, when 2.68 million b/d was exported. The all-time high of 3 million b/d was seen in the week that ended June 22.
As a result of the widening of the Brent-WTI spread, US crude differentials are strengthening. The WTI FOB assessed value has followed WTI at the Magellan East Houston terminal higher, with the assessed value assuming an average loading cost of 60 cents/b. MEH strengthened 25 cents/b Monday and was assessed at WTI cash plus $7.60/b.
UNIPEC RE-ENTRY ADDS TO TIGHTNESS
China's Unipec has begun to buy US crude barrels again and could be contributing to waning tonnage availability, the shipowner said.
"Unipec started buying US crude again this month and so the general cargo count is up by four to five cargoes," the shipowner said. "And there aren't many natural positions to cover that."
Unipec placed a ship on subjects to make the same journey late Thursday at lump sum $4.6 million for a Singapore discharge and $5.6 million for China.
This is the first time Unipec has been seen looking for a VLCC to cover a US cargo since June 26, according to Platts data. The vessel name was unclear by Monday afternoon, with some shipbrokers pointing to the Xin Wei Yang and others to the Bunga Kasturi Tiga.
The Xin Wei Yang is currently located at the Galveston Offshore Lighterage port while the Bunga Kasturi Tiga is off the coast of Brazil and expected to arrive at the Lousiana Offshore Oil Port on October 19, according to data from Platts' cFlow trade flow software.
The global VLCC market has been relatively tight over the past week, with heavy fixture activity for cargoes sailing out of the West Africa and the Arabian Gulf, adding to the tightening tonnage list as shipowners hold out from ballasting to the USGC and Caribbean, the shipowner said.
Chief executive Paul Vonk described himself as "obviously pleased", though the unexpected presence of water flow complicates the picture somewhat
The number of well testing phases were limited by the project's planning permissions
Angus Energy PLCshares advanced in Tuesday’s early deals after revealing oil test results from a new test of a horizontal well at the Balcombe project, in southern England.
Having started as much as 10% higher, Angus shares were up 0.48p or 5.88%, changing hands at 8.6p each.
The AIM-quoted firm has a 25% stake the project, near the village of Balcome south of Crawley, where environmental protests made headlines in 2013, alongside operator Cuadrilla which is best known as a UK shale gas company - but, Balcombe is not a shale project nor does it involve fracking.
The Balcombe-2z well is, in fact, part of the increasingly high-profile Kimmeridge hydrocarbon play which also includes the Horse Hill oil discovery near London Gatwick airport along with other exploration and appraisal projects in the region.
Angus today revealed that the Balcombe well flowed naturally at a rate equivalent to 853 barrels of oil per day plus 22.5% water.
A subsequent test, meanwhile, saw relative water volumes reduce. The second flow period measured a rate equivalent of 1,587 barrels of oil per day, with 6.6% water.
Paul Vonk, Angus chief executive, said: "We are obviously pleased with the results of the Balcombe-2z flow test and encouraged as we take our next steps towards producing from the Kimmeridge layers in the near future at the Brockham Field.”
Water flow was not expected
Significantly, perhaps, Angus said the water flows were unexpected but it believes they are the result of the well intersecting a small high-pressure water zone in the horizontal section and that would need to be isolated in the future.
It added that the technical team doesn’t believe that the water production comes from the main Kimmeridge reservoir. Unfortunately, an attempt to qualify this view with additional well logging was unsuccessful due to what Angus described as a third-party equipment failure.
The company noted that at one point during the initial flow testing, the overall flow rate hit a rate of 3,000 barrels per day though it had to be constrained due to equipment limitations (as it exceeded separator operating capacity).
Nonetheless, Angus claimed that it believes it can isolate the water producing zone and establish commercial production under normal pumped production conditions.
It also noted that the duration of the tests were limited and due to planning restrictions on the operations, the programme had to be curtailed after only two tests.
Angus said it anticipates that the oil quality will be similar to that seen elsewhere in Kimmeridge formations (samples from Balcombe were measured at 34 API though samples were potentially affected by the use of nitrogen in the well).
The company explained that nitrogen was used to ‘clean and prime’ the well prior to testing. It added that no carbon dioxide or hydrogen sulfide gases were observed or measured during the programme.
http://www.proactiveinvestors.co.uk/companies/news/206174/angus-energy-shares-rise-as-it-reveals-balcombe-well-test-results-206174.html
Executives at the world’s biggest oil and gas companies are under growing pressure to loosen the purse strings to replenish reserves, halt output declines and take advantage of a crude price rally after years of austerity.
With oil at a four-year high of $85 a barrel, exploration departments are urging company boards to drill more, wages are creeping higher, service companies say rates will have to rise and some investors say Big Oil must start growing again soon.
For the heads of companies such as BP, Chevron and Royal Dutch Shell who have pledged to stick to lower spending after slashing budgets by as much as 50 percent since 2014, the pressure may become hard to resist.
As in previous oil price cycles, there are concerns about the strength and duration of the business cycle, now in its 10th year of growth after the 2008 financial crisis.
Unlike previous oil price cycles, there is the prospect, eventually, of an end to growth in oil demand as the world shifts to cleaner energy.
But there are already signs some cost cuts implemented after oil slumped from $115 a barrel in 2014 to $26 in 2016 are being rolled back.
Shell, for example, said last month its teams in the UK North Sea will switch to a less tiring rota of two weeks offshore then three weeks onshore. During the austerity years, teams spent three weeks offshore then four onshore.
More frequent rotations mean more ships and helicopters will need to be chartered. Shell says the change will increase costs slightly but is convinced it will make its North Sea operations more cost effective and productive.
More generally, salaries across the oil and gas sector have edged up about 6 percent so far in 2018 after declining in the previous three years, according to a survey published by Rigzone www.rigzone.com.
At one major firm, senior managers who had been meeting by video conference for several years are now getting flights approved for face-to-face gatherings, according to an executive at the company.
The boards of large oil firms are facing more internal requests to invest in new projects and acquisitions, and to beef up staff, according to senior executives present at such discussions.
“There is lots of pressure from all the units to get more money,” said an executive at a large European oil company.
LONG-CYCLE INVESTMENTS
New project approvals are picking up. Shell and its partners this week gave the green light to LNG Canada, one of the largest liquefied natural gas (LNG) projects in recent years.
"Shell's motivations for the project are clear: without this project, the company's upstream, LNG contract portfolio and LNG production was set to go into decline early next decade," Wood Mackenzie www.woodmac.com analyst Dulles Wang said.
Typically, after a period of lower capital spending, or capex, and low prices comes an era of rapid investment as oil recovers and supplies tighten.
During the lean years, companies cut back sharply. Now, they generate as much cash as in 2014 and are vowing to remain thrifty to focus on higher dividends, buying back shares and reducing debt. But in an industry where reserves and production decline naturally as oil is pumped from fields, continued investment is considered critical.
“We are likely in need of more long-cycle investments given the persistent and accelerating base declines observed in global conventional and offshore projects,” said a source at in investment firm with large stakes in big oil companies.
Although some companies such as BP (BP.L) were able to stem production declines thanks to technology and lower costs, a drop in new production has taken a toll on the longer-term outlook for many companies.
Oilfield decline rates doubled from 3 percent in 2014 to 6 percent in 2016. For the big oil firms, rates went from 1.5 percent to just over 2 percent during the same period, according to Morgan Stanley.
"I expect capex rises due to a significant drop in reservoir life. Some capex will be used to reinvigorate existing wells," said Darren Sissons, partner at Campbell Lee & Ross Investment Management www.clrim.com/site/home, adding that increases would be cautious initially.
The American Petroleum Institute reported that U.S. crude supplies rose by 907,000 barrels for the week ended Sept. 28, according to sources. The API data also showed supplies of gasoline declined by 1.7 million barrels and distillates fell by 1.2 million barrels, sources said.
Supply data from the Energy Information Administration will be released Wednesday. Analysts polled by S&P Global Platts expect the EIA to report a climb of 2.76 million barrels in crude supplies. They also expect supply declines of 672,000 barrels in gasoline and 1.83 million barrels in distillates.
U.S. crude oil shipments to China have “totally stopped”, the President of China Merchants Energy Shipping Co (CMES) said on Wednesday, as the trade war between the world’s two biggest economies takes its toll on what was a fast growing businesses.
Washington and Beijing have slapped steep import tariffs on hundreds of goods in the past months. And although U.S. crude oil exports to China, which only started in 2016, have not yet been included, Chinese oil importers have shied away from new orders recently.
“We are one of the major carriers for crude oil from the U.S. to China. Before (the trade war) we had a nice business, but now it’s totally stopped,” Xie Chunlin, the president of CMES (601872.SS) said on the sidelines of the Global Maritime Forum’s Annual Summit in Hong Kong.
Noble Midstream announced a letter of intent with Salt Creek to partner on the construction of a 200 thousand barrel of oil per day newbuild pipeline system in the Delaware Basin. The 95-mile, 20-inch diameter pipeline system will originate in Pecos County, Texas, with additional connections in Reeves County and Wink County, Texas. The project footprint will be served by a combination of in-field crude gathering lines and a trunkline to Wink Hub. The Partnership anticipates the execution of definitive agreements and closing of the transaction to occur in the fourth quarter of 2018.
At closing, the project would be underpinned by approximately 180,000 dedicated acres and nearly 100 miles of pipeline in Pecos, Reeves, Ward and Winkler Counties. This includes an in-basin oil transportation dedication of the southern portion of Noble Energy’s Reeves County position totaling approximately 70,000 acres. Noble Midstream will continue to provide oil gathering services for Noble Energy’s Permian development in the Blanco River DevCo and the northern Reeves County acreage position remains dedicated to the Advantage Pipeline system for in-basin oil transportation through the Trinity River DevCo.
“We are excited to partner with Salt Creek on the formation of this joint venture and look forward to bringing both our commercial and operations expertise to the table,” stated Terry R. Gerhart, Chief Executive Officer of Noble Midstream. “The pipeline system will provide critical downstream connectivity and enhanced market optionality for producers in the Southern Delaware Basin.”
Salt Creek CEO Zach Lee added, “We are excited to be working in partnership with the Noble Midstream team in the Southern Reeves area. We have known and respected the Noble Midstream team for some time and look forward to building a world class crude oil business with them as a partner in the Delaware Basin.”
Salt Creek has commenced construction of the pipeline, with an expected operational date in the second quarter of 2019. The project provides access to 200,000 barrels of new crude oil storage, with expansion potential to 300,000 barrels. The five-year net capital investment for Noble Midstream is anticipated to total approximately $60 to $80 million. The investment is supported by an average customer acreage dedication term of approximately 15 years.
China is set to boost its crude imports from West Africa to the highest in at least seven years this month as the trade war with the U.S. prompts the Asian nation’s refiners to find alternatives.
Chinese refiners have bought about 1.71 MMbpd of crude for October loading from West Africa, the most since at least August 2011 when Bloomberg started compiling the data, according to a survey of traders and analysis of loading programs. In total, Asia’s crude imports from West Africa in October will jump to 2.44 MMbpd, also a seven-year high.
The trade war with the the U.S. has cut China’s interest in buying shale oil which is similar in quality to West African crude. Unipec, the trading arm of top Chinese refiner Sinopec, recently put a plan to boost U.S. crude imports on hold. The impending return of sanctions on Iranian crude further limits the availability for Chinese buyers.
The majors in China need to “make up not only for lost U.S. grades, but more importantly for a cut in imports from Iran,” said Michal Meidan, an analyst at researcher Energy Aspects. Chinese refineries also need to replenish their crude stocks which are well below year-ago levels, she said.
Unipec bought about 30 MMbbl of West African crude for loading in October, the highest since at least August 2011, according to the survey. Other Chinese companies, including independent refineries, or teapots, also boosted their purchases. Teapot refineries typically increase their imports in the fourth quarter as they need to use up their crude import quota before it expires at the end of the year.
“After heavy maintenance over the summer and tight credit, they are now coming back to the market to try and exhaust their import licences for the year and to capitalise on strong margins as well as rising domestic product prices,” Meidan said.
Compliance with the International Maritime Organization's global sulfur limit for marine fuels will likely settle around 90% in the initial years after 2020 as most shipowners switch to 0.5% sulfur bunker fuels to meet the rule, a bunker industry veteran and senior partner at 2020 Marine Energy Adrian Tolson said Tuesday.
Less than 15 months remain for the regulation to be implemented, but there have been widespread industry concerns in the past about the extent of compliance with the rule due to the magnitude of the change and the costs involved. Availability of 0.5% sulfur compliant bunker fuels has also been cited as a potential deterrent to achieving full compliance to the impending regulation.
However, this is changing as shipowners plan ahead and refiners make investments to provide such fuels, Tolson told S&P Global Platts on the sidelines of the 20th Singapore International Bunkering Conference and Exhibition.
"In the transitional months, mostly everybody [shipowners and operators] will look at purchasing distillates... but the shift to very low sulfur fuel oil will be fairly quick," he said.
In the initial six months or so after 2020, the differential between HSFO and distillates could be as high as $450-$600/mt, Tolson said.
However, this is expected to narrow as the distillate market gets over the initial shock and HSFO availability dwindles due to the limited uptake of exhaust gas cleaning systems, or scrubbers, he said.
While there is momentum around LNG bunkering, its contribution in the global bunker fuel mix is only expected to be around 5% by 2030, Tolson said.
"LNG could be a cheap and viable compliant fuel option, but only if you can get through the infrastructure issues and build the volumes," he said.
As the years progress, VLSFO is expected to become significantly cheaper than diesel, prompting its widespread use, Tolson said.
"While quality issues around VLSFO consumption have been a concern for some, I have far more faith in their use," he said. "The sort of contaminants in 0.5% sulfur bunker fuels are not significantly much different from those found in 3.5% sulfur bunker fuels," he added.
Concerns around stability and compatibility are also expected to diminish over time as refiners are increasingly developing fuels to overcome such issues, he said.
Compliance with the IMO 2020 rule is also likely to be spurred by strict enforcement by both flag states and port authorities, Tolson said.
"Compliance is primarily the shipowners' responsibility... and most will be unlikely to risk non-compliance," Tolson said, adding that errant players will have to deal with fines, penalties and detentions, as well as a possible loss of charter parties.
CHANGING INDUSTRY LANDSCAPE
While the product mix is set to change due to the 2020 rule, the industry is also re-organizing itself, Tolson said.
The role of independent bunker suppliers is being increasingly challenged amid increasing competition and shrinking margins, requiring many to reinvent themselves as 2020 approaches, he said.
"As we approach the post-2020 world, bunkering companies firstly need to position themselves as more than just basic suppliers, looking at every opportunity within the physical supply chain to add value, beyond the typical storage, distribution and supply process," he said.
"What shipowners and operators really need is help in structuring their purchasing habits, utilizing technology, data and intelligence so that their procurement and buying process is fully optimized. This can yield 1% to 2% in fuel cost savings, which is significant when we consider the dramatic increase in prices post 2020," he added.
Traditional oil companies and large commodity players will likely emerge as the major beneficiaries post 2020, but many of them may not want to deal with credit, logistics and claims, so there will always be room for suppliers, Tolson said.
In addition to the global sulfur cap rule, to meet IMO's upcoming greenhouse gas emissions reduction targets, the industry will have to move to clean energy sources, from hydrogen-based fuels, biofuels, wind to battery power and so forth; distillates and hybrid products just won't exist, he said.
Physical suppliers need to consider what their role and position in this new world looks like now, and begin the process of building a business model and brand that can deliver it and is fit for purpose, he added.
U.S. crude oil refinery inputs averaged 16.6 million barrels per day during the week ending September 28, 2018, which was 77,000 barrels per day more than the previous week’s average. Refineries operated at 90.4% of their operable capacity last week. Gasoline production increased last week, averaging 10.0 million barrels per day. Distillate fuel production increased last week, averaging 5.0 million barrels per day.
U.S. crude oil imports averaged 8.0 million barrels per day last week, up by 163,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 7.8 million barrels per day, 10.2% more than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 713,000 barrels per day, and distillate fuel imports averaged 162,000 barrels per day.
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 8.0 million barrels from the previous week. At 404.0 million barrels, U.S. crude oil inventories are at the five year average for this time of year. Total motor gasoline inventories decreased by 0.5 million barrels last week and are about 7% above the five year average for this time of year. Finished gasoline inventories increased while blending components inventories decreased last week. Distillate fuel inventories decreased by 1.8 million barrels last week and are about 3% below the five year average for this time of year. Propane/propylene inventories increased by 2.4 million barrels last week and are about 8% below the five year average for this time of year. Total commercial petroleum inventories increased last week by 8.0 million barrels last week.
Total products supplied over the last four-week period averaged 20.5 million barrels per day, up by 1.1% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.3 million barrels per day, down by 1.5% from the same period last year. Distillate fuel product supplied averaged 3.9 million barrels per day over the past four weeks, down by 2.9% from the same period last year. Jet fuel product supplied was up 6.6% compared with the same four-week period last year.
Last Week Week Before Last Year
Domestic Production '000....... 11,100 11,100 9,561
Alaska ......................................... 482 472 497
Lower 48 ................................ 10,600 10,600 9,064
Imports .................................... 7,965 7,802 7,214
Exports ................................... 1,723 2,640 1,984
Cushing up 1.7 mln bbls
Saudi Arabia plans to raise oil production in November from an October output level of 10.7 million barrels per day (bpd) to meet rising crude demand, the energy minister of the world’s top exporter said on Wednesday.
Khalid al-Falih told a conference in Moscow attended by Russian President Vladimir Putin that the kingdom was in weekly communication with Russia to stabilize global oil markets, which touched a four-year high above $85 a barrel this week.
Oil producers have added a total of about 1 million bpd output in “recent weeks and months” and the global market was well supplied, the Saudi minister said, adding that Saudi Arabia had raised its oil output to 10.7 million bpd in October.
Asked about surging oil prices, Falih said the current price “was not based on fiscal flows of supply and demand”.
“This is created in financial markets,” he said.
Benchmark Brent crude fell 12 cents to $84.68 a barrel at 1125 GMT, reversing an earlier gain. [O/R]
Russian Energy Minister Alexander Novak told reporters before the conference that the global oil market had more or less stabilized but uncertainties remained that could push up prices, including factors such as U.S. sanctions on Iran.
Reuters reported on Wednesday that Falih and Novak had agreed at a series of meetings, held when crude prices were heading towards $80, to lift output from September through December.
The two oil producers struck a private deal in September to raise oil output to cool prices and had informed the United States, which has been pushing for action by OPEC and other producers, four sources familiar with the plan told Reuters.
The private pact was reached before a meeting of oil producers in Algeria.
U.S. President Donald Trump has blamed the Organization of the Petroleum Exporting Countries for high crude prices and demanded that the group boost output to bring down fuel costs before U.S. congressional elections on Nov. 6.
Riyadh planned to lift output by some 200,000 bpd to 300,000 bpd from September until the end of 2018 to help fill the gap left by lower Iranian output due to the sanctions, Reuters reported.
Russian oil output reached a post-Soviet record high of 11.36 million bpd last month.
Russian energy giant Lukoil's President Vagit Alekperov stated on Wednesday that the domestic companies have reached maximum production of oil, the local media reported.
"As far as I know, Russian companies have already reached the maximum production, and have we, too," said Alekperov. The businessman noted that since the OPEC output cuts were lifted back on September 23, Russian companies have been working at a maximum. "Projects that allow for increased production are being considered. Including projects that have been stopped, for example, the gray zone between Kuwait and Saudi Arabia with a potential of 400,000 to 600,000 barrels per day," Lukoil's chief added.
He also stated that new projects in the Caspian Sea and the Komi Republic are also in consideration, stressing again that "everything id st its maximum!" His comment comes after on Monday, Iranian Oil Minister Bijan Zanganeh stated OPEC and other major oil producers, including Russia, only pretend they can raise their outputs indefinitely while in fact, they can't.
*NOVAK SAYS RUSSIA COULD ADD SPARE 200-300K B/D IN `FEW MONTHS
@Lee_Saks
Anyone who would have said 1.5 m bpd back in May would have been laughed at. And yet here we are. But the truth is that we’ll only know how many barrels truly come off the market when we see it with our own eyes. Or rather, the satellite trackers eyes
@EnergzdEconomy
Trafigura said consensus in the oil market is that sanctions on Iran will now remove up to 1.5M b/d of exports from the market, up from an earlier range of 300K to 700K b/d. US State Dept issued statement calling on OPEC to dig deeper into spare capacity.
@cmarie_burke
India gave the green light to businesses hurt by the rising costs of crude oil to start borrowing up to $10 billion in foreign money that will offset the heavy weight of rising oil prices and the falling rupee, Reuters reported on Wednesday.
India’s current commercial borrowing rules prevent businesses from borrowing more than $750 million in foreign money—the previous limit as outlined in April by the Reserve Bank of India (RBI) as cited by Lexology.
Rising oil prices spurred by increasing fears that Iran’s crude oil exports will take out more oil from the market than previously thought—up to as much as 2 million barrels per day—has weighed heavily in recent months on the country, which is well on its way to overtaking China in terms of oil demand growth—a marker expected to be reached in 2024 according to an August news release from Wood Mackenzie.
But equally as worrisome for the Asian nation is the falling rupee, which today has reached a record low of 73.38, according to Business Today.
Iran has not wavered from its insistence that India will continue to purchase its crude oil, despite sanctions, and despite being unable so far to obtain a waiver from the United States for doing so. Reports, however, show that India has drastically reduced its call for Iranian crude oil, asking for zero Iranian cargoes in November, according to Bloomberg.
Regardless of where India purchases its oil, the crude oil price rise will push up fuel prices for consumers in India, which will chew up cash that consumers would otherwise be spending elsewhere.
Indian refiners have been drawing from inventory to put off crude oil imports, and praised the flexibility of increased foreign funds. “We have a working capital needs on a permanent basis. This is a welcome and a positive move by RBI and will definitely bring down the import cost,” A.K. Sharma, head of finance at Indian Oil Corp, said, as quoted by Reuters.
The United Arab Emirates, which has a history of talking tough on Iran while still buying its oil, appears to be taking steps to comply with looming U.S. sanctions against the Islamic Republic’s energy industry.
Dubai is the UAE’s main importer of Iranian oil. The country’s biggest city buys a light oil called condensate that’s produced in Iran’s natural gas fields and refines it into jet fuel and other products for local use. The UAE port of Fujairah, the Middle East’s biggest oil-trading hub, provides storage for Iranian fuel oil that supplies vessels plying the Indian Ocean.
Both export streams may be at risk for Iran when U.S. sanctions take effect on Nov. 4. Condensate shipments to Dubai’s government-owned refiner Emirates National Oil Co. already dropped by half in September, according to Bloomberg tanker-tracking data. UAE customs officials have started to require oil tankers docking at Fujairah’s fuel terminal to provide a certificate attesting to the origin of their cargoes, according to people with knowledge of the matter who asked not to be identified because the information is confidential.
“The UAE could be looking to tightly police the cargoes entering and leaving its port, ahead of the deadline for U.S. sanctions on Iran,” said Den Syahril, a senior analyst at industry consultant FGE in Singapore.
Alternative supplies
Iran’s exports have slumped since May as customers including South Korea and France halted imports. India will stop buying Iranian crude in November, people with knowledge of its imports said last week. Oil is at the highest level in almost four years amid concerns about possible supply shortages due to the sanctions on Iran and production disruptions in other Organization of Petroleum Exporting Countries members such as Venezuela.
The UAE is committed to abiding by the sanctions and will look for condensate supplies from countries other than Iran, Energy Minister Suhail Al Mazrouei said on Tuesday. “The alternatives are available in the market,” he said, without specifying.
The UAE is a U.S. ally and has welcomed a tougher stance against Iran. Together with Saudi Arabia, the UAE is waging a proxy war with the Islamic Republic in Yemen.
When it comes to oil and gas imports from Iran, however, the UAE has a track record of prioritizing domestic energy needs over regional rivalries. The last time the U.S. targeted Iran’s oil industry, under former President Barack Obama, Dubai reduced but didn’t eliminate its condensate purchases. More than a year after cutting ties with Qatar for its alleged cozy relations with Iran, the UAE continues to buy Qatari gas to keep its lights on.
ENOC, the Dubai refiner, operates a 140,000-bpd plant that bought enough condensate from Iran to meet its needs during the first half of the year. That trade, while diminished, appears to be continuing, according to tanker tracking.
The oil tanker Falcon Pride departed Assaluyeh in Iran for the UAE on Oct. 1, the data show. The vessel is loaded with a cargo and anchored now off Dubai’s Jebel Ali port, according to the data. ENOC declined to comment on what it will do once U.S. sanctions take effect.
Iranian oil vessels aren’t currently banned from Fujairah, and the reason why the customs department is demanding certificates of cargo origin isn’t known. Even so, tighter controls could deter traders seeking to store Iranian oil before sanctions kick in.
If the UAE does restrict access to Fujairah, Iran -- one the region’s biggest exporters of fuel oil -- will lose a major market. Most large trading houses stopped dealing in fuel oil from Iran after Washington announced sanctions in May, due to difficulties in securing payments, according to people familiar with the trade, who asked not to be identified because the information is confidential.
How energetically the UAE cracks down, Den said, “depends on the U.S. and whether it emphasizes strict adherence to sanctions.”
https://www.worldoil.com/news/2018/10/3/irans-oil-buyer-and-rival-uae-may-be-cracking-down-on-trade
China's crude oil output edged up 0.9 percent year on year in August, data from the National Development and Reform Commission showed.
Crude oil output came in at 16.1 million tonnes during the period, which saw 48.9 million tonnes of crude refined, up 0.4 percent year on year.
China is one of the world's largest oil purchasers, with about 60 percent of its oil consumption coming from imports.
In August, China consumed 28.41 million tonnes of refined oil products, up 5.9 percent year on year.
Meanwhile, natural gas output totaled 12.8 billion cubic meters, gaining 9.6 percent year on year.
China aims to increase domestic crude oil output to 200 million tonnes by 2020, while supply capacity for natural gas should exceed 360 billion cubic meters.
Major tasks for the oil industry include accelerating exploration to ensure domestic oil supply, speeding up construction of pipeline networks and developing clean alternatives.
Norwegian oil company Equinor has struck oil at the appraisal well of the Cape Vulture discovery from 2017. The well, located in the Norwegian Sea, and drilled by the Songa Encourage drilling rig, confirms a volume potential of 50-70 million recoverable barrels of oil.
According to Equinor, the discovery more than doubles the remaining oil reserves to be produced through the Norne field.
“Originally planned to be shut down in 2014, the productive life of Norne has already been extended to 2036, which will generate substantial spin-offs. This discovery will boost production in the years to come. The further maturing of the field development has upside potential for additional recoverable reserves from Cape Vulture,” Equinor said.
“We are very pleased to have proven and appraised a new substantial oil discovery off the coast of Nordland. The appraisal well confirms a new play on the Nordland Ridge in the Norwegian Sea,” says Nick Ashton, Equinor’s senior vice president, Exploration, Norway & UK.
“The discovery demonstrates the importance of our new exploration strategy. We intend to take new approaches and try out new and untested ideas to unlock the remaining commercial resources on the Norwegian continental shelf (NCS). This is in line with Equinor’s recently updated roadmap for the NCS, which aims to secure activity for many decades to come,” Ashton maintains.
More potential around Norne
“The Cape Vulture discovery also opens additional opportunities in the area. As an immediate consequence, we will already next year drill a well on a similar prospect on the Nordland Ridge. We are also maturing other opportunities for the coming years that may help substantially increase the reserves around the Norne field,” Ashton adds.
The appraisal of the Cape Vulture discovery is now most likely completed, Equinor said on Tuesday. The partnership in the Norne license will progress the discovery towards a development decision. The discovery demonstrates that considerable resources may still be recovered through existing infrastructure on the NCS, the oil company added.
Siri Espedal Kindem, Equinor’s senior vice president, Operations North says: “New data and creative exploration ideas generate resources, new revenues for society, and important jobs in Northern Norway. Cape Vulture came as a gift in early 2017, and it confirmed that exciting subsurface secrets still remain to be unlocked in the Norne area.”
“Our exploration people have been scrutinizing the area for more than 40 years, and they are still cracking codes.”
Norne was the first field development off Nordland, coming on stream in 1997. The remaining recoverable oil reserves in the fields producing through the Norne FPSO (in addition to the Norne field, this is Alve, Urd, Skuld and Marulk) are currently estimated at approximately 40 million barrels. There are also recoverable gas reserves corresponding to about 80 million barrels of oil equivalent still in place in these five fields, according to Equinor.
The Cape Vulture discovery is located 7 kilometers northwest of the production vessel on the Norne field.
“Even in an early phase of development planning, this discovery will more than double the oil resources produced through the Norne infrastructure towards 2036, which we are very pleased to see. This is a great day for the Norwegian Sea and the industry in Northern Norway,” Kindem adds.
“Exploration results like Cape Vulture are essential to Equinor. We will explore for this type of resources in the years ahead. Discoveries like this will be key to supporting our ambition to extend the lifespan of existing infrastructure,” Nick Ashton says.
The exploration drilling in the Cape Vulture well (6608/10-17S) started in early December 2016. The drilling of the appraisal well, including side-tracks (6608/10-18, 6608/10-18B and 6608/10-18C), started in mid-July 2017. The wells were drilled in production license 128, a result of production license 128D awarded in the APA round (award in predefined areas) in 2015. The Cape Vulture Appraisal well was drilled by the Songa Encourage rig.
https://www.offshoreenergytoday.com/equnors-latest-oil-discovery-doubles-norne-reserves/
The Middle East sour crude complex surged to near five-year highs Wednesday, spurred by supply concerns and end-of-year demand, market sources said.
The spread between December Dubai cash and swap assessed by S&P Global Platts touched a backwardation of $1.65/b at the close of Asian trading hours Wednesday.
The spread was up from $1.54/b Tuesday, and was last higher on November 29, 2013, at $2.29/b, Platts data showed.
In only three days of the December trading cycle for Middle East sour crudes, the structure -- an indication of trading sentiment -- has averaged $1.57/b, up from $1.41/b last month.
The rise follows close on the heels of the front-month physical price for Dubai hitting four-year highs on Tuesday. December Dubai crude, or cash Dubai M1, rose to $82.95/b at the end of Asian trading hours Tuesday. It was last higher in 2014, when the flat price touched $83.61/b on October 31, 2014, according to Platts data.
Cash Dubai M1 continued to rise Wednesday, landing at $83.35/b, according to Platts assessments.
The Middle East complex has risen to such strengths quite early in the cycle, well before any spot trading is likely to have been started on December-loading barrels in Asia.
Crude oil traders and end users tend to wait for official selling prices to be released by producers in the Persian Gulf before recalibrating their margins and procuring cargoes. The OSPs are expected this week, with traders and refiners largely expecting producers such as Saudi Aramco, Abu Dhabi National Oil Company and Qatar Petroleum to raise prices from the previous cycle.
Persian Gulf crudes typically trade two months forward in the spot market, meaning December-loading crudes will begin trading in October.
Saudi Arabia will invest $20 billion in the next few years to maintain and expand its spare oil production capacity, Saudi Energy Minister Khalid al-Falih said on Thursday.
Saudi Arabia’s oil production capacity stands at 12 million barrels per day.
Enable Midstream Partners employs 120 in Houston, with holdings mostly in North Dakota, Oklahoma, Arkansas and on the Louisiana-Texas border.
A pipeline company backed by Houston's CenterPoint Energy is proposing a $550 million natural gas pipeline project to feed the burgeoning liquefied natural gas exporting business along the Gulf Coast.
Oklahoma-based Enable Midstream Partners said it plans to build a 165-mile gas pipeline from northwestern to southwestern Louisiana along the Texas state line. The project would take gas from the Haynesville shale and other regions and ship it down to new LNG export terminals in Louisiana and Texas.
Enable is controlled by CenterPoint and Oklahoma City-based OGE Energy.
"We are excited about this opportunity to diversify and expand Enable's transportation footprint to connect directly to U.S. Gulf Coast markets," said Enable Chief Executive Rod Sailor.
The goal is to complete the project as early as 2022.
The pipeline is a direct competitor with the Haynesville Global Access Pipeline proposed less than a year ago by Houston-based Tellurian, which also is seeking to develop a pipeline from West Texas' Permian Basin and a major LNG terminal in Louisiana.
Project proponent Royal Dutch Shell Plc and its joint venture partners — Petronas, PetroChina, Mitsubishi Corp. and Korea Gas Corp. — are expected to give the green light to the project within days.
“I think we’ve presented to our joint venture participants what we consider to be a very compelling case, but they are going to be the ultimate arbiter on this project,” Pierce told reporters after the event.
Anticipation grew Friday with a report that the boards of Kogas and PetroChina separately approved their multibillion-dollar stakes in the facility.
Scorpio Group will install 100 hybrid-ready scrubbers across its fleet of 56 bulkers and 109 tankers, favoring the larger vessels within each group, chief operating officer Cameron Mackey said Thursday.
"We have decided to install scrubbers on the majority of our fleet to be ready sometime in 2020," Mackey said during a luncheon presentation at the Association of Ship Brokers & Agents cargo conference in Miami.
Two-thirds of the scrubbers will be fitted by January 1, 2020, and the remainder is expected to be installed during the first three month that year, Mackey said later on the sidelines of the conference.
The International Maritime Organization has mandated bunker sulphur limits to drop to 0.5% sulphur on January 1, 2020, from 3.5% sulphur currently, and the installation of scrubbers allows shipowners to continue using 3.5% sulphur bunkers as the exhaust gas cleaning systems bring emissions in line with the tough 0.5% sulphur limit onboard the vessel.
Hybrid scrubbers have provide the flexibility to either operate in open-loop or closed-loop mode, thereby either essentially washing the sulphur into the ocean or collecting the sulfur onboard the vessel and disposing of it onshore.
"Intellectually, the right thing to do is to remove sulphur at the source and not on the ship," Mackey said. "Intellectually, we don't agree, but there is a period where a scrubber is economically right."
Other compliance options include the use of marine gasoil or low-sulphur bunker fuels, or the installation of dual-fuel engines to use LNG, LPG or methane as bunker fuel.
Scorpio owns and operates 56 drybulk vessels built between 2014 and 2018, including 18 Kamsarmaxes and 38 Ultramaxes. The Scorpio Tankers fleet list comprises 14 Handymaxes, 45 Medium Range tankers, 12 Long Range 1 tankers and 38 Long Range 2 vessels, all built between 2012 and 2017.
Scorpio is the third shipowner this week to announce the installation of scrubbers as means to comply with the global 0.5% sulphur mandate.
French container shipping company CMA CGM made plans public to order several scrubbers for its ships Monday, while International Seaways announced the purchase of seven exhaust gas cleaning systems on its 14-vessel strong VLCC fleet. The company has an option for another three scrubbers covering the remaining three modern VLCCs in its fleet.
Scrubber orders and installations are getting close to quadrupling in 2018 in preparation for the IMO 2020 sulphur mandate from 344 units installed and ordered in January to around 1,200 units so far in September, according to industry sources.
Baker Hughes on Friday reported that the number of active U.S. rigs drilling for oil fell by 3 to 863 this week. The oil-rig count had edged down by 1 last week.
The total active U.S. rig count, which includes oil and natural-gas rigs, was up by 1 at 1,054, according to Baker Hughes.
Energy companies Wintershall and DEA will reduce headcount as part of their ongoing merger and will develop as a predominantly gas-focused company, DEA’s supervisory board chairman, Lord John Browne said, on Friday.
High-sulphur fuel oil (HSFO), essentially the leftovers of an oil refiner’s output, will still flow from refineries around the world even after new rules start up in 2020 curtailing its use in the global shipping fleet, a Reuters survey showed.
Sixty percent of the 33 refineries contacted by Reuters in a global survey will still produce HSFO in 2020 although the supply will tighten as 70 percent of these refiners plan to reduce their output.
Starting that year, ships will have to use marine fuel, which primarily consists of residual fuel oil, with a maximum sulphur content of 0.5 percent under International Maritime Organization (IMO) rules to reduce air pollution.
Currently, the global shipping fleet, which includes oil and chemical tankers as well as container ships, uses as much as 3.3 million barrels per day of HSFO with a maximum of 3.5 percent sulfur.
Refiners will have little incentive to produce HSFO after the regulations though some demand will remain as a small but growing number of vessels are fitted with smokestack scrubbers that remove the sulphur from the exhaust fumes and power plants will continue to consume the fuel.
“Although HSFO demand for ships is expected to decline substantially in 2020, the oil’s demand for power generation and general users will remain,” Japan’s second-largest refiner Idemitsu Kosan told Reuters in the survey.
“In future, demand for scrubber-equipped ships is projected to recover, so we expect HSFO output to continue.”
When asked how they plan to reduce HSFO output, just over half of the refiners said they will upgrade their plants to further process their fuel oil to produce more higher value products such as gasoline and diesel.
Two-thirds of the 16 refiners who responded to a question about how much investment they plan to pump into their plants to produce more ultra-low and low-sulphur fuel oil, said they plan to spend less than $100 million. Five of them are investing between $500 million and more than $1 billion in such projects.
Polish refiner Grupa LOTOS will spend more than $600 million to convert its heavy residue to middle distillates and coke by the end of 2019 while Kuwait has a $6.25 billion clean fuels project.
Fuel oil, or residue fuel, is the remaining product from crude oil processed through crude distillation units at a refinery. To extract more value from residue, it is further processed at secondary refining units such as residue fluid catalytic crackers, hydrocrackers and cokers to produce gasoline and diesel.
However, secondary units are costly and require years to build while expansion projects in some countries have to overcome tough environment regulations.
“We will need (the Environment Protection Agency’s) approval if we want to expand the coker and that is tough in Taiwan now,” Formosa Petrochemical Corp spokesman KY Lin said.
Formosa has adjusted its coker unit, which uses heat and pressure to break down the residue fuel into other products, to run at 95 percent utilization from 90 percent to reduce its HSFO output, Lin said.
FUEL OIL LOSSES TO WIDEN
Refiners will want to cut their HSFO output as much as possible to offset the expected drop in value.
By January 2020, 380-centistoke HSFO in Singapore will be worth $16.70 a barrel less than Middle East benchmark Dubai crude, down from a discount of $5 for October 2018, according to swap values.
Besides upgrading, a handful of refiners said they would also process more lower sulphur crude oil to reduce the sulphur content in their products output.
Refiners may also cut their overall CDU runs to reduce their residue output if low fuel oil margins drag down overall profits, according to the survey.
“Forward prices are scary,” Formosa’s Lin said.
Other refiners will look at alternative markets for their HSFO.
“If fuel oil demand falls, we will switch our configuration to produce bitumen which is in high demand in India due to its road-building program,” said an official from Indian Oil Corp.
BEYOND 2020
Some refiners prefer to stay flexible by being able to switch their output between low- and high-sulphur fuel oil according to market demand.
India’s Bharat Petroleum Corp Ltd said it will be able to produce either fuel oil or switch to other products depending on demand after 2022.
“We will not reduce fuel oil output to zero completely as we need our refineries to be flexible,” a BPCL official said. The official declined to be named as they are not authorized to speak to the media.
Italy’s Eni said it “will produce the minimum amount of HSFO just to satisfy the market demand of the ships that will have installed the scrubbers.”
An official from India’s Hindustan Petroleum Corp Ltd said the company will be producing some fuel oil but the output will be “very, very low beyond 2022”.
A third of the respondents said they are either already not producing any HSFO or will stop producing in 2020.
Polish refiner PKN Orlen said it will produce fuel oil with 1 percent sulfur content from 2020 while a spokeswoman from Italy’s SARAS refinery said, “We are already ready to face IMO-2020 and we already produce basically no HSFO.”
Canada’s Husky Energy Spokesman Mel Duvall said the company expects to benefit from the new IMO rule since it will boost diesel demand.
“It is expected that there will be an increase in global demand for diesel fuel as ship operators switch from high-sulphur fuel oil,” he said.
Two of Royal Dutch Shell’s Asian partners in a liquefied natural gas venture in western Canada approved their share of the investment, pushing the multibillion-dollar development one step closer to a final approval.
The board of PetroChina, the nation’s largest oil and gas company, approved its $3.46 billion share of the LNG Canada project, the company said in a filing to the Hong Kong stock exchange Friday. Korea Gas Corp. made a similar announcement in Seoul about its stake.
All the partners, including Malaysia’s Petroliam Nasional and Japan’s Mitsubishi Corp., need to make similar moves for the venture to approve a final investment decision. Shell declined to comment. Petroliam Nasional, known as Petronas, didn’t immediately respond to requests for comment. A Mitsubishi spokesman said Friday it hasn’t yet made a decision.
“LNG Canada looks like it is pretty much getting over the line, so deciding not to go ahead with it now would be a big surprise,” said Trevor Sikorski, an analyst at Energy Aspects Ltd.
Shell said in 2014 that the project could cost as much as C$40 billion ($31 billion). PetroChina’s announcement Friday about its 15% share implies a total investment of roughly $23 billion across all partners, according to Bloomberg calculations. With the capacity to eventually export as much as 26 MM metric tons/year, primarily to Asia, it could be the biggest new LNG terminal to be sanctioned in years.
Canadian oil and gas producer Husky Energy Inc said on Sunday it has made an unsolicited bid to acquired rival MEG Energy Corp in a deal valued at C$6.4 billion ($5 billion) including debt.
The combined company would have total production of more than 410,000 barrels of oil equivalent per day (boepd) and refining and upgrading capacity of about 400,000 barrels per day (bpd), Husky said in a statement.
The offer comes as many Canadian oil producers have struggled with transportation bottlenecks as output has surged, pushing Canadian heavy crude to near-historic discounts to U.S. light crude.
Husky Chief Executive Rob Peabody told Reuters that the combination of MEG’s top-quality assets and staff with its own production and downstream network would allow MEG to circumvent some of the effects from the Canadian crude discount, and provide benefits for both sets of shareholders.
The Husky offer comes less than two months into the tenure of Derek Evans, an industry veteran who took over as chief executive of MEG in August.
“We acknowledge that we have received an unsolicited offer from Husky,” John Rogers, vice president of investor relations and external communications at MEG, said in a statement.
“The management and board will be reviewing the offer in due course and make a determining if it is in the best interest of shareholders.”
Under the terms of the proposal, each MEG shareholder will have the option to choose to receive consideration of C$11 in cash or 0.485 of a Husky share for every share held.
That offer is subject to a maximum aggregate cash consideration of C$1 billion and a maximum aggregate number of Husky shares issued of about 107 million.
“The MEG Board of Directors has refused to engage in a discussion on the merits of a transaction, giving us no option but to bring this offer directly to MEG shareholders,” Peabody said in the statement.
Husky’s offer delivers a 44 percent premium to the 10-day volume-weighted average MEG share price of C$7.62 as of Friday, and a 37 percent premium to MEG’s Friday close of C$8.03.
Goldman Sachs Canada Inc is acting as financial adviser and Osler, Hoskin & Harcourt LLP is acting as lead legal adviser to Husky.
The proposal, which has been unanimously approved by Husky’s board of directors, is expected to result in C$200 million per year in near-term, realizable synergies.
Iran’s foreign minister, Mohammad Javad Zarif, said on Saturday that Tehran was closing in on an agreement to sell oil to European nations despite American threats of sanctions against any countries that do business with Iran.
If the arrangement comes to fruition — some British and French officials say they have their doubts — it would constitute the most open break between President Trump and European allies that objected vociferously to his decision to pull out of the 2015 nuclear deal.
Several of those nations openly confronted Mr. Trump on Wednesday, when he led a United Nations Security Council meeting about weapons of mass destruction. They argued that he was throwing away the best chance the world has to keep Iran from building nuclear weapons in coming years.
In an hourlong conversation with reporters, Mr. Zarif, who negotiated the nuclear accord with John Kerry, who was then the secretary of state, sounded far more optimistic than he had in recent months that he could peel away America’s traditional allies to break Mr. Trump’s effort to cut off Iran’s revenues.
Mr. Zarif is capitalizing on a renewed enthusiasm among some of the allies to push back at what they term bullying by Washington to sever ties with Iran simply because Mr. Trump decided to forsake the nuclear pact. All the other signatories to the agreement — Britain, China, France, Germany, Iran and Russia — have vowed to stand by it.
“No sovereign country or organization can accept that somebody else decides with whom you are allowed to do trade with,” Federica Mogherini, the European Union foreign policy chief, said this past week. She predicted that the financial arrangements could be in place before Mr. Trump issues the next set of sanctions in November, aimed at banks, businesses and countries that conduct business with Tehran.
At the core of the agreement that Iran and Europe are trying to forge is a mechanism for paying for Iran’s oil in barter and local currencies, rather than in American dollars. The idea is to route around the United States and prevent it from blocking financial transfers — and perhaps from identifying those involved in the transactions.
“This is for us to sell our oil and get the proceeds,” Mr. Zarif said, noting that under the United Nations resolutions passed once the 2015 agreement was reached, countries have the legal right to trade with Iran.
Trump administration officials argue that the agreement was deeply flawed because it does not permanently ban Iran from producing nuclear fuel — it is free to do so after 2030 — and does nothing to stop Iran’s missile exports, its activity in Syria and its support of terrorist groups.
Mr. Trump’s aides, led by Secretary of State Mike Pompeo, argue that the effort to route around American sanctions will not work. Mr. Trump has threatened to bar companies engaged in buying Iranian oil, or other goods, from doing business in the United States. The threat has led companies to flee Tehran, sending Iran’s currency plummeting.
British and French officials say it is possible Mr. Trump will prevail, with European firms from Airbus to Total, the French oil giant, already canceling billions of dollars of investment in Iran in anticipation of the additional American sanctions.
Two weeks ago, Brian Hook, the State Department envoy for Iran, said the United States was seeking “the new deal that we hope to be able to sign with Iran, and it will not be a personal agreement between two governments like the last one; we seek a treaty.”
Mr. Zarif, who is American-educated and has a deep interest in the workings of United States politics, seemed on Saturday to have no interest in such a deal. He conceded that Mr. Trump may win the opening rounds of what has essentially become a litmus test of whether countries will follow the president’s confrontational approach.
He and the country’s president, Hassan Rouhani, have said Mr. Trump is trying to bait them into violating the accord, setting the stage for a resumption of the long-running crisis that the 2015 deal was supposed to de-escalate.
“You are just another country,” he said at one point. “Just act as a normal country.” Mr. Pompeo has said essentially the same about Iran.
Mr. Zarif was dismissive of Mr. Trump’s escalating verbal attacks on Iran’s missile sales and its support of Hezbollah, Hamas and the Syrian government of Bashar al-Assad. He laughed when asked whether the United States could bring down the current Iranian government with mounting financial pressure — a regime change strategy that Rudolph W. Giuliani, a lawyer for Mr. Trump, recently said was the real goal. (The State Department denied Mr. Giuliani’s characterization.)
Nor did Mr. Zarif expect the United States to attack key Iranian facilities, he said.
“If the U.S. believed it would have succeeded in such an attack, it would have done so already,” he said. (In fact, the United States has mounted an attack, using computer code to destroy Iranian centrifuges at the end of the Bush administration and the first years of the Obama administration.)
Asked about his recent conversations with Mr. Kerry, whom Mr. Trump and Mr. Pompeo have accused of undermining American foreign policy, Mr. Zarif said the messages were simple.
“What he has done is encourage us to stay in the deal,” he said. As for the threats by Mr. Trump to investigate Mr. Kerry, he said: “I didn’t realize you still had witch hunts going on in the United States” — a nod to one of Mr. Trump’s favorite phrases about the Russia investigation.
On the subject of claims by the Israeli prime minister, Benjamin Netanyahu, on Thursday that Iran had hidden nuclear-related components in a warehouse in Tehran, Mr. Zarif said he believed that it was a cleaning facility for Persian rugs. But he would not commit to letting inspectors from the International Atomic Energy Agency visit.
https://www.nytimes.com/2018/09/29/us/politics/iran-trump-zarif.html
Total U.S. rig count up by one; but Oklahoma adds seven rigs
Drilling activity increased slightly in the U.S. this week, according to the latest edition of Baker Hughes’ Weekly Rig Count.
There was little change in rig count overall, with only a net one rig beginning operations. This rig was land based, and inland waters and offshore activity held flat, meaning there are now 1,029 land, five inland waters and 20 offshore rigs drilling in the U.S.
Operations shifted toward gas targets this week, with three gas rigs beginning operations, while three oil rigs shut down. This is the largest net shift toward gas since March, as most weeks see oil increasing in prominence. One miscellaneous rig also began drilling this week; a total of 863 oil, 189 gas and two miscellaneous rigs are currently operating.
Drilling activity shifted in favour of horizontal drilling this week, reversing last week’s decline. Three horizontal rigs began drilling this week, while directional activity was constant and two vertical rigs came offline. There are currently 922 horizontal, 69 directional and 63 vertical rigs actively drilling in the country.
Individual states saw widespread changes in rig count, despite the minor change overall. Five rigs began drilling in Oklahoma, meaning there are now 141 rigs active in the state. This is only one less that the post-downturn high of 142 seen in early June. One rig also came online in Alaska, Colorado, Louisiana and Utah, while one shut down in Wyoming and Nevada. Two rigs also stopped drilling in California, New Mexico and Texas.
The Cana Woodford saw an even larger increase in activity than Oklahoma overall, with seven rigs beginning operations. Two rigs also began drilling in the Haynesville and one came online in the Ardmore Woodford and DJ-Niobrara. One rig ceased operations in the Granite Wash, while two stopped drilling in the Permian.
https://www.oilandgas360.com/scoop-stack-activity-roars-back-reversing-last-weeks-decline/
U.S. shale production is at record highs and the momentum is still not over. A lot has been said about the energy self-sufficiency implications of this trend, but there’s something that has not garnered a lot of attention: U.S. shale is light crude, great for making gasoline and other light fuels, but not so great for products such as middle distillates. Why this is important? Because gasoline demand is stagnating while demand for middle distillates is set for a serious boost ahead of the new IMO regulations on maritime vessel emissions.
In a recent article for Forbes, Wood Mackenzie’s VP for Chemicals and Oil Markets, Alan Gelder, warned that U.S. refiners may very soon find themselves struggling with excess production of gasoline that exceeds demand for the fuel. At the same time, to make matters worse, the production slump in Venezuela is reducing the availability of heavy crude needed for middle distillates, not to mention that not all U.S. refiners have upgraded their facilities to produce more low-sulfur bunkering fuel products.
The problem concerns Asia as well, Gelder notes. Most refineries there need heavy sour crude to function, and there could be a shortage of this particular type of crude on the horizon because of the situation in Venezuela.
If you are wondering if this shortage may have something to do with Beijing’s recent decision to extend a US$5-billion lifeline to Caracas, you may have a point. Iran also produces heavy crude besides a light grade and condensate, and this, too, will be cut off from markets, if we are to believe the dominant narrative arguing that Iran will lose more than half of its exports when U.S. sanctions kick in.
The good news is that, according to the Wood Mac expert, things will change soon enough and the shortage, if it ever occurs, will be short-lived. Chinese refiners are spending a lot of money on upgrades that will increase their portion of gasoline and reduce the production of other fuels, notably diesel and gas oil.
That is fine if only gasoline demand grows, but the IMO emissions rules will also spur greater demand for low-sulfur diesel and gas oil—part of the group of fuels that are called middle distillates—as they come in between light fractions such as gasoline, and heavy ones, such as fuel oil. Depending on how strong this spur is, a shortage might occur, although, according to Gelder, the chances of that happening are not that great.
Still, it would pay to be prepared. Gelder may be skeptical about the extent of the disruption that IMO’s new rules will have, but others see it as one of the greatest shocks that the oil industry has ever experienced.
For instance, the head of S&P Global Platts Analytics, Chris Midgley, said at this week’s Asia Pacific Petroleum Conference that the new rules will have an impact worth US$1 trillion on the industry over a period of five years as well as reverberations across many other industries.
A senior Equinor executive, the head of the Norwegian company’s marketing division, also demonstrated wariness. "To us it seems that the market is not fully prepared for IMO 2020," Tor Martin Anfinnsen told the S&P Global Platts event. "We expect that the IMO [regulation] will increase market volatility, spreads and trade flows for some time.”
What do all these predictions have to do with U.S. refiners? Well, they chime in with Gelder’s final words in the Forbes story: “The pressure on the refiners is to use their flexibility to shift yields towards diesel/gas oil.”
https://oilprice.com/Energy/Crude-Oil/Refiners-Struggle-To-Adapt-To-The-Shale-Boom.html
China plans to build two large coal-bed methane production bases in the northern coal-rich province of Shanxi, as the country seeks to increase gas use while curbing pollution and reducing heavy reliance on coal.
The two bases, one to be located in the Qinshui Basin and the other in the eastern Erdos Basin, each have a recoverable reserve of 1 trillion cubic meters, according to the Shanxi provincial development and reform commission, which has made environmental impact assessments public.
In the five years to 2020, China plans to newly add proven coal-bed methane reserves of 420 billion cubic meters and build two to three large coal-bed gas production bases. By 2020, the country's annual coal-bed methane output is expected to reach 24 billion cubic meters.
The two bases in Shanxi are major projects promoted by the National Energy Administration, with their outputs expected to reach a combined 8.3 billion cubic meters.
In 2020, Shanxi plans to raise its coal-bed gas output to 20 billion cubic meters and transport six billion cubic meters of gas from the two bases to other parts of the country through pipelines.
Coal represented 84.6 percent of Shanxi's energy mix in 2017 and local authorities plan to reduce the coal share to 80 percent in 2020 in a bid to fight pollution.
The U.S. Office of Foreign Assets Control (OFAC) has issued a new license to BP related to continuing operations on the Rhum field in the UK North Sea.
Serica Energy, which is in process of buying BP’s interests in the Bruce, Keith, and Rhum (BKR) fields, said on Monday that BP had received a new license relating to the Rhum field.
The license authorizes the provision of essential goods, services and support by certain U.S. persons and businesses to the Rhum field until November 4, 2018, replacing an existing authorization which expired on September 30, 2018.
Serica added that discussions continue with OFAC regarding the conditions under which authorization may be given for the provision of goods, services and support to allow Rhum production to continue beyond November 4.
BP and Serica earlier in September decided to postpone the completion of acquisition of BP’s interest in BKR fields to enable the completion of regulatory processes extending the completion timetable until early November 2018.
Meanwhile, Serica has already said it will be ready to assume operatorship once the outstanding conditions have been met.
Mitch Flegg, Chief Executive of Serica Energy, commented: “Serica welcomes the new license which ensures that production from the Rhum field can continue. Discussions with OFAC and other parties regarding longer term arrangements to protect this valuable UK asset are continuing and all parties are working towards a successful conclusion.
“The transaction between Serica and BP under which Serica will acquire BP interests in the Bruce, Keith and Rhum fields upon receipt of the appropriate licenses is an important part of this process and we are encouraged by the issuance of this interim license. Both BP and Serica remain committed to completion.”
https://www.offshoreenergytoday.com/bp-gets-temporary-license-for-rhum-field/
Trio of projects agree to continue supplying gas to meet domestic demand
The operators of the three liquefied natural gas export projects on Curtis Island in Queensland have extended an agreement with the Australian government to ensure there is enough gas to meet domestic demand
http://www.upstreamonline.com/live/1595138/oz-lng-exporters-extend-supply-pact
Energy majors developing the Karachaganak gas condensate field will pay $1.1 billion to Kazakhstan to settle a profit-sharing dispute, Kazakhstan’s Energy Ministry said on Monday.
Kazakhstan and the consortium led by Shell and Eni will also amend the terms of their production-sharing agreement so that the former Soviet republic will receive a higher share of future revenues from one of the Central Asian nation’s biggest hydrocarbon fields.
The ministry estimated the extra income to amount to $415 million by 2037 based on the Brent crude price of $80 per barrel. The group has also agreed to provide a $1 billion long-term loan to Kazakhstan for infrastructure development.
Kazakhstan filed a $1.6 billion claim against foreign firms developing Karachaganak in 2015, Russia’s Lukoil - another consortium member - has said.
The claim stated, in essence, that Kazakhstan had not received its fair share of income from the giant project. The two sides have since discussed various ways of settling the row.
The Energy Ministry told Reuters in May that Astana expected to settle the dispute within a month and that it expected a large one-off payment from energy majors as well as a higher share of future revenue.
The consortium, which includes Chevron and Kazakh state-owned company KazMunayGaz, produced 8.4 million tonnes of condensate - a product marketed together with oil - at Karachaganak in January-August this year.
The Energy Ministry said the companies have pledged to invest $5 billion more in the field so that it would generate billions in additional revenue and agreed to supply feedstock for local refineries and chemicals plants on commercial terms.
The consortium said this month it would spend $1.1 billion on a project that would sustain Karachaganak’s output at its peak for a longer time.
Norway’s Equinor will buy Chevron’s 40% operated interest in the Rosebank project, one of the largest undeveloped fields on the UK Continental Shelf (UKCS). The financial details were not disclosed.
Equinor, who will become the operator of Rosebanks, on Monday said the transaction would strengthen its UK portfolio, which includes the Mariner development, attractive exploration opportunities, and three producing offshore wind farms.
Al Cook, Equinor’s executive vice president for global strategy & business development and UK country manager saud: “We have a proven track record of high-value field developments across the North Sea and will now be able to deploy this experience on a new project in the UK.
“Today’s agreement allows us to buy back into an asset in which we previously had a participating interest, demonstrating our strategy of creating value through oil price cycles. The acquisition of Rosebank complements our portfolio of oil, gas and wind assets in this country, in line with our strategy as a broad energy company.” he said.
The Rosebank field was discovered in 2004 and lies about 130 km northwest of the Shetland Islands in water depths of approximately 1,110m. The other partners in the field are Suncor Energy (40%) and Siccar Point Energy (20%).
“With Rosebank, a standalone development in the underexplored West of Shetland region, we strengthen our upstream portfolio, which also includes Mariner, one of the largest investments on the UKCS in over a decade. As we have done with other projects in our portfolio, such as Johan Castberg and Bay du Nord, we intend to leverage our experience and competence to create further value in Rosebank, in alignment with the UK Government’s priority of maximizing the economic recovery of the UKCS,” says Hedda Felin, Equinor’s senior vice president for UK & Ireland offshore.
https://www.offshoreenergytoday.com/breaking-equinor-buys-share-in-chevrons-rosebank-field/
Egypt’s imports of liquefied natural gas are coming to close following the delivery of final cargoes during the past week.
The country’s minister Tarek El Molla said the imports have been halted as the domestic production keeps ramping up at the recently discovered gas fields, Reuters reports.
El Molla did not unveil how many cargoes Egypt already imported this year.
After turning from a net gas exporter to a net gas importer due to a shortage of domestic supply in recent years, Egypt strived on recent discoveries like the giant Zohr gas field.
The country is now aiming to establish itself as the regional LNG trade hub. Its production grew from 6 billion cubic feet per day in July to 6.6 billion cubic feet per day last month, on the back of volumes produced at the Zohr field.
Earlier in the year, El Molla said that Egypt would halt imports of LNG which would save the country $250 million on a monthly basis.
Encana Corp said on Monday it would sell its San Juan assets in New Mexico for US$480 million to privately held oil and gas producer DJR Energy Llc.
The Calgary-based company’s San Juan assets include about 182,000 net acres, which produced about 5,400 barrels of oil equivalent per day in 2017.
Denver-based DJR Energy, LLC says the US$480-million acquisition will about double its land in the San Juan Basin to 350,000 net acres (141,639 hectares) and increase its production to more than 6,000 barrels per day.
DJR is an exploration and production company formed in April 2017 with funds from Trilantic Capital Management LP, Waveland Energy Partners and Global Energy Capital.
The sale is expected to close in the fourth quarter of 2018 with an effective date of April 1, 2018.
Royal Dutch Shell PLC said Tuesday that affiliate Shell Canada Energy has given the green light to invest in LNG Canada, a major liquefied natural-gas project in British Columbia in which the Anglo-Dutch oil company has a 40% working interest.
Shell said that with LNG Canada's joint-venture participants having also taken a final investment decision on the project, construction will start immediately and first liquefied natural gas is expected before the middle of the next decade.
The company's 40% share of the project's capital cost is within its current overall capital investment guidance of $25 billion-$30 billion a year, Shell said.
Shell didn't give a specific number for its investment but recent press reports suggested that the project could cost 40 billion Canadian dollars ($31 billion).
Chief Executive Ben van Beurden said global demand for liquefied natural gas is expected to double by 2035. He said LNG Canada is expected to deliver an integrated internal rate of return of around 13% to Shell, while the project will generate cash flow that is significant, long-life and resilient.
LNG Canada will initially export liquefied natural gas from two processing units, known as trains, totaling 14 million metric tons a year. There will be potential to expand production to four trains in the future.
The project has a 40-year export license in place and all major environmental permits are in place for the plant and the pipeline, Shell said.
https://www.marketwatch.com/story/shell-first-lng-seen-before-middle-of-next-decade-2018-10-02
A planned tie-up of BASF’s Wintershall and LetterOne’s DEA could be listed in the second half of 2020, its designated chief executive told a German newspaper in an interview published on Tuesday.
Last week, BASF and LetterOne signed a merger agreement to combine their respective oil and gas businesses into a merged entity, to be named Wintershall DEA, which will be headquartered in Kassel and Hamburg.
Asked when the merged entity — in which BASF will initially hold 67 percent while LetterOne will own the rest — will go public, Mario Mehren told Handelsblatt: “If everything goes according to plan in the second half of 2020. That is very ambitious. Closing of the transaction is planned for the first half of 2019.”
As associated gas production in North Dakota's Bakken Shale continues to set records, which is leading to higher rates of flaring, Oneok has decided to add a second processing plant at a facility currently under construction, which would double its capacity.
Oneok announced plans to construct a 200 MMcf/d plant, dubbed Demicks Lake II in McKenzie County, a core region of the Bakken for $410 million.
Demicks Lake 1, also a 200 MMcf/d capacity facility, is already under construction. Oneok CEO Terry Spencer said it will reach capacity soon after its completion, prompting the need for the second facility.
"Additional natural gas gathering and processing capacity in the Williston Basin is critical to supporting record-setting crude oil and natural gas production in North Dakota and helping producers meet regional natural gas capture targets," Spencer said.
Demicks Lake II is the eighth new plant or plant expansion slated to come online within the next year-and-a-half, according to S&P Global Platts Analytics NGL Facilities Databank. Once completed, the facilities will add 1.2 Bcf/d of new processing capacity.
Demicks Lake I is slated for an in-service date during the fourth quarter next year with Demicks Lake II following suit during the first quarter of 2020. The plants will be located northeast of Watford City, North Dakota. They will give Oneok a total of 1.4 Bcf/d of processing capacity in the Williston Basin.
ASSOCIATED GAS GROWING
Although the wave of new processing plants will provide enough processing capacity through 2021, new plants or expansions will be required afterward in order to keep up with continued gas production growth, according to Justin Kringstad, director of the North Dakota Pipeline Authority.
In July, gas production struck a record high of 2.4 Bcf/d, according to the most recent data from the North Dakota Department of Mineral Resources. The high production came with a cost, though, as producers flared 436 MMcf/d, or 18%, of all gas produced, which was highest rate flared since September 2015.
It was also the third straight month producers failed to capture the state mandate of 15%. Producers can face fines from the state for failing to meet the requirements. And on November 1, the gas capture requirement increases to 88%.
The record gas production stemmed from oil production also setting a monthly high of 1.2 million b/d.
The increased drilling in the Bakken makes sense from a producer standpoint as internal rates of return per well in the play are the highest in the Lower 48 at 52.2%, according to Platts Analytics. It is more than 10% higher than returns on drilling in the prolific Permian Basin, as takeaway pipeline constraints in West Texas and New Mexico have dragged down regional prices and Permian returns per average well.
IRRs are based on half-cycle analysis which excludes the expenses associated with exploration and development (sunk costs) and federal income tax.
Pacific Oil & Gas said that its unit, Woodfibre LNG signed heads of agreement with CNOOC Gas and Power Trading & Marketing for the supply of liquefied natural gas from its project in British Columbia, Canada.
The deal signed with the CNOOC Gas and Power Group’s unit, would see Woodfibre LNG deliver 0.75 mtpa of LNG from its project.
The deal has a 13-year term with the deliveries set to start in 2023, Pacific Oil & Gas said in its statement.
The Woodfibre LNG project involves the construction and operation of a liquefied natural gas (LNG) export facility on the previous Woodfibre pulp mill site, which would have a storage capacity of 250,000 cubic meters and would produce approximately 2.1 million tons per year of LNG.
https://www.lngworldnews.com/woodfibre-lng-lines-up-supply-deal-with-cnooc/
Resurgent crude prices kept Apache Corporation’s North Sea business on an upward trajectory last year.
Apache North Sea (ANS), whose US parent company is based in Houston, chalked up pre-tax profits of £98 million in 2017, against a surplus of £8.6m the previous year.
Average crude prices were 24% higher at $53.58 per barrel last year, pushing ANS’s revenues up 2.3% to £513m.
Production quotas introduced by Opec and its allies at the start of 2017 were the main catalyst for that improvement in prices.
Higher revenues offset the impact of the Forties Pipeline System shutdown at the end of last year, which dented production at ANS and several other operators.
ANS, operator of the Forties field, has been on the recovery trail since 2015, when it suffered pre-tax losses of £262m against a backdrop of plummeting oil prices.
The UK Treasury’s decision to cut petroleum revenue tax to 0% in the March 2016 Budget, from 35% previously, has supported ANS’s upturn in fortunes in recent years.
The government also reduced the supplementary charge – an additional tax on profits in the industry – to 10% from 20% at the start of 2016.
In its 2017 accounts, just released by Companies House, ANS said it recorded a £90.6m deferred tax benefit in 2016, following a reassessment of its “deferred income tax liability” for 2015.
ANS’s lifting costs for 2017 rose 28% to $17.01 per barrel as a result of lower production volumes, higher direct expense and increased workover activity.
Natural field decline meant net production at ANS dropped to 34,200 barrels of oil per day (bpd) last year from 41,500 bpd in 2016.
The decline could have been more severe, but for the drilling four development wells in the Forties area, three of which were productive.
ANS invested £48m in the UK North Sea last year, down from £72.5m in 2016, as the company rigorously managed its portfolio and maintained a “disciplined financial structure”.
Its exploration well on the Val d’Isere prospect, drilled north-west of Forties in December 2017, proved to be a dud, and was plugged and abandoned.
ANS forecasts a 27% increase in North Sea investment to £61.2m this year as it targets eight wells on Forties.
In his strategic report for 2017, ANS managing director Jon Graham said the North Sea region played a “strategic role in Apache Corporation’s portfolio by providing competitive investment opportunities and potential reserve upside with high-impact exploration potential”.
Earlier this year, the company said it had made a 10m barrel discovery at the Garten field, located in the Beryl area.
In August 2018, ANS agreed to sell its 35% working interest in the Seagull development and its 50% stake in the
Isabella prospect to private-equity-backed newcomers Neptune Energy.
Liquefied natural gas (LNG) shipping and terminal operators Golar and Hoegh said on Monday they would invest about $50 million into an LNG company set up last year by fellow Nordic firm Stolt-Nielsen.
The investments aim to build Avenir LNG into an entity with small LNG vessels and terminals that are expected to be increasingly used in remote locations or to supply LNG as vehicle or ship fuel.
Small-scale LNG is a new frontier of the rapidly developing industry which has been dominated by ever larger and more complex multi-billion projects.
“Avenir LNG intends to utilize the best-in-class capabilities of its anchor investors to build a global presence as the leading provider of small-scale LNG,” Golar and Hoegh said in a statement.
“It will be among the first movers in this market with a fleet of small-scale LNG carriers and terminals,” they said.
The two companies will invest $24.75 million each to receive a 25 percent stake each in Avenir LNG.
They said the funds were part of a $182 million commitment with Stolt-Nielsen to opportunities in small-scale LNG “including the delivery of LNG to areas of stranded demand, the development of LNG bunkering services and supply to the transportation sector”.
Stolt-Nielsen will transfer all its LNG projects to Avenir LNG, the statement said, which includes four small-scale LNG carriers already on order as well as the development of an LNG terminal in Sardinia, Italy.
The Permian basin, which produces almost 4 MMbopd, has expanded so quickly that suppliers of the electricity needed to keep wells running are struggling to keep up. The Delaware portion alone consumed the equivalent of 350 megawatts this summer, tripling the load from 2015. That’s enough to power about 280,000 U.S. homes. And providers say the draw is likely to triple again by 2022.
Providers are rushing to build new power lines, but it takes three to six years to get them up and working. In the meantime, drillers are bemoaning the reliability of the system and desperately seeking alternatives, exploring the use of solar and natural gas to fuel power-generating gear on-site.
The electrical grid in West Texas “was not set up to withstand that much power going through it," said Marco Caccavale, a V.P. at the oilfield services company Baker Hughes. "Plain and simple, you have reliability challenges."
Power is just one more oilfield complication in a region struggling to deal with extraordinary growth over an incredibly short period of time. Worker and pipeline shortages are major concerns, along with the growing levels of water and sand needed for fracing. Meanwhile, highways initially designed for minimal use are gridlocked in the day and deadly at night.
Conventional drilling with vertical wells in the region reached an apex in 1973, producing about 763 MMbbl for the year. Output then steadily declined, falling to 309 MMbbl in 2006. That threatened to turn a hot and dry region with few large communities back into a dusty afterthought requiring minimal electricity.
Then, fracing hit.
The iconic 40-horsepower “nodding donkeys” that power vertical wells draw about 30 kilowatts each. But since the advent of fracing a decade ago, they’re being supplanted by sophisticated equipment that needs more and more power to operate. At the same time, the well count has grown dramatically, rising by 33,483 since 2006, according to Austin-based Drilling Info Inc.
Shale wells developed using fracing can run horizontally for miles. To lift oil out, companies now depend on electric submersible pumps that individually draw about 300 kilowatts, according to Toni Jameson, an electrical-engineering consultant who leads a coalition of Permian companies studying the issue.
"Power is the last thing that anybody really ever thinks about," Jameson said. "Most operators and producers out here, they’re here to produce. No one thinks about power until they realize, ‘We can’t produce that well without it.’"
One-lane road
The industry has studied the use of solar and wind at well sites, she said, but found the costs were high and that they couldn’t provide the power and consistency needed to run the new oilfield machinery. The Permian power grid is the equivalent of a one-lane country road, she said, adding, "we need about a 12-lane highway in both directions."
The oilfield’s big-ticket items, drilling rigs and frac pumps, still mainly run on diesel engines, and aren’t affected by power outages. But for a well that’s moved past the drilling stage and into its longterm production phase, power is often the No. 1 operating cost.
Determined to find alternatives, the industry is experimenting with gear that can run off the natural gas produced in nearby wells. Gas-compressor sales in the region are up, which suggests more field gas is being processed locally to be used to generate power, James West, a New York-based analyst at Evercore ISI, said in an email.
Gas-fired turbine
Baker Hughes is working with several customers on a pilot project to power its electric submersible pumps from a gas-fired turbine, which can be more powerful than a diesel generator and requires less maintenance. The world’s second-biggest oilfield service provider sees its turbines filling a void in areas where the electrical grid hasn’t yet expanded, or where power cuts out too often.
The production process isn’t the only factor draining the region’s power, however. The ability to handle sand and water, vital ingredients in fracing, are also involved. It’s become a key factor in determining where to place pumps for moving water to the frac job, according to Bill Zartler, the CEO of Solaris Midstream.
In some areas expensive generators have had to be used temporarily to run the pumps because there were no power lines to hook into, according to Zartler. In other spots, it’s been able to tap into customers’ electricity lines, he said.
There are solutions coming down the line.
Electrification projects
Dave Stover, CEO at Noble Energy Inc., told analysts and investors in August the Houston-based explorer is working on an electrification project to solve that problem too. "Some of the supply of electricity is not that reliable in the southern Delaware basin," Stover said. "We’ve got some dollars going toward an electrification project that will help improve reliability there."
Noble has a distribution system in place already, and anticipates constructing two substations near their wells in early 2019 to help relieve the load on the local distribution system.
https://www.worldoil.com/news/2018/10/1/power-to-the-permian-spotty-at-best
Russian natural gas flows to Western and Central Europe stayed above 11 Bcm in September as demand for Russian gas remained robust, particularly for storage injection, S&P Global Platts Analytics data showed Tuesday.
Deliveries dip on August, but higher year on year
Gazprom sales move 5.8% higher than Jan-Sep 2017
Oil-indexed gas competitive through Q1 2019
Russian deliveries are likely to remain high in the coming months as winter demand kicks in and oil-indexed contract prices continue to be competitive against European hubs.
Russian gas flows via its three main pipeline routes to Western and Central Europe totaled 11.03 Bcm in September -- down on August, but well up on September 2017 and 2016, according to the data.
Russian deliveries have been high all year, and in January-September totaled 97.77 Bcm, up 2.2 Bcm on the year.
Supplies via the Nord Stream pipeline totaled 4.7 Bcm last month -- or an average of 157 million cu m/d -- as the link continued to pump at full capacity.
Flows via the Yamal-Europe pipeline at the Mallnow interconnection point to Northwest Europe were also almost maxed out in September, totaling 2.52 Bcm -- or an average of 84 million cu m/d.
The northern pipelines helped Germany in particular to boost its storage levels, which by the end of September were just 0.8 Bcm below last year's level at 16.8 Bcm having started the injection season 3 Bcm down, according to Platts Analytics data.
VELKE KAPUSANY SWING
With both the northern routes running at full capacity, it was again the route via Ukraine at the Velke Kapusany point on the border with Slovakia that took the swing in September.
Russian gas exports through Velke Kapusany totaled 3.79 Bcm last month -- more or less on a par with August and March through June.
Gazprom's own sales data -- which comprise volumes sold to customers, including from storage, not just physical export volumes -- showed an increase to 149.2 Bcm in the "Far Abroad" (Europe plus Turkey but not the countries of the former Soviet Union) in January-September.
That is an average of 549 million cu m/d.
According to S&P Global Platts' calculations, September sales were 15.9 Bcm -- an average of 530 million cu m/d.
Gazprom said supplies to several selected European countries increased in the first nine months of 2018.
Gazprom's supplies to the Far Abroad hit a new record high of 194.4 Bcm last year, and are on track to break through the 200 Bcm level if current supply rates are maintained.
A source at Gazprom Export said last week the latest estimate is 201-202 Bcm for 2018.
Pricing may determine how much Russian gas is sold in Europe and Turkey over the remainder of 2018. The range of 85-100% oil-indexed contracts is estimated at Eur20-Eur23.50/MWh for October, according to Platts Analytics.
The TTF price for October balance of month, by comparison, is considerably higher at Eur27.40/MWh, according to Platts assessments Monday.
But with oil prices moving above $85/b, oil-indexed contracts are set to become significantly more expensive in the coming months themselves, with the top of the range topping Eur27/MWh in May next year, indicating a stronger price incentive to purchase Russian oil-indexed gas sooner rather than later.
Oil indexation is thought to not be so prevalent in Northwest European gas import contracts, but Gazprom has said that it remains part of many contracts either under a hybrid oil-hub mix or as part of a price corridor, with hub-based ceilings and floors.
TransCanada Corporationannounced today that it will proceed with construction of the Coastal GasLink pipeline project (Coastal GasLink) after a decision to sanction the LNG Canada natural gas liquefaction facility in Kitimat, British Columbia (B.C.) was announced earlier today by the joint venture participants of LNG Canada, a consortium comprised of Shell, PETRONAS, PetroChina, Mitsubishi Corporation and KOGAS (the LNG Canada Participants).
“Today’s announcement signifies an important step forward for Coastal GasLink as well as for the province of B.C. and the country,” said Russ Girling, TransCanada’s president and chief executive officer. “The magnitude of the work undertaken over the past six years has been extensive. It demonstrates the commitment of our teams, our partners, B.C. communities and Indigenous groups to work together toward a single goal of fostering an LNG industry off Canada’s West Coast that will help maximize the value of our important natural gas resources in a sustainable and responsible way.”
Coastal GasLink is a 670-kilometre (420 mile) pipeline designed to transport natural gas from the Montney gas-producing region near Dawson Creek, B.C. to the LNG Canada facility in Kitimat. The pipeline will have an initial capacity of approximately 2.1 billion cubic feet per day (Bcf/day) with the potential for expansion of up to approximately 5 Bcf/day. Construction activities are expected to begin in early 2019 with a planned in-service date in 2023.
The estimated Cdn$6.2 billion project is underpinned by 25-year transportation service agreements (with additional renewal provisions) entered into with the LNG Canada Participants and includes pre-development costs to date of approximately $470 million. The majority of the spend on construction will occur in 2020 and 2021. Subject to terms and conditions, differences between the estimated capital cost and final cost of the project will be recovered in future pipeline tolls. As part of the funding plan, TransCanada intends to explore joint venture partners and project financing for Coastal GasLink and has retained RBC Capital Markets as advisors.
“Once constructed, Coastal GasLink will become a critical component of British Columbia’s natural gas pipeline infrastructure, connecting our abundant, low-cost natural gas resources to global markets,” added Girling. “Solid underlying market fundamentals, combined with robust commercial support for the project, position us to prudently fund Coastal GasLink over its multi-year construction along with our existing $28 billion near-term capital program in a manner consistent with our long-established strong financial profile.”
https://boereport.com/2018/10/02/transcanada-to-construct-coastal-gaslink-pipeline-project/
JYPF SA, Argentina’s state-run energy producer, is closing the tap on some of its natural gas wells as the nation’s second recession in three years curbs demand, according to people with direct knowledge of the matter.
The company had been investing heavily in shale gas as the government subsidized production to reverse a costly energy trade deficit. But the economic slump means it’s now having to pare back supply, said the people, who weren’t authorized to speak publicly.
Argentina’s economy is forecast to contract 1.6 percent this year and get even worse in the first quarter of 2019, after investor concerns over the fiscal deficit triggered a currency rout. Even before the recession hit, drillers were already bracing for the problem of seasonal demand surges.
Argentina consumes far less gas in summer than in the colder winter months and it has recently made sales to neighboring Chile to mitigate the situation. The oversupply is compounded by a government contract to import from Bolivia through 2026. There’s also the emergence of a rival to YPF, Tecpetrol SA, which is flooding the market with gas from the Vaca Muerta shale play -- Argentina’s answer to the Permian Basin -- at its Fortin de Piedra project.
“There’s no doubt about the geological characteristics of Vaca Muerta. The rock can deliver, and Fortin de Piedra is a clear example,” said Juan Manuel Vazquez, head of equity and credit research at Puente Hnos. in Buenos Aires. “However, there is a demand problem due to seasonality and the drop in economic activity.”
YPF’s gas production in the second quarter of the year -- when the recession began -- averaged 44 million cubic meters a day, 1.3 percent lower than in the same period in 2017, “because of lower demand,” according to an earnings report.
General Electric Co’s (GE.N) unit Baker Hughes is preparing an offer for a production-sharing deal with Brazil’s Petrobras, a Baker Hughes executive said on Tuesday, as the state-run oil company seeks creative ways to boost output from mature fields.
Reuters reported in June that Baker Hughes was considering a bid, while Halliburton Co (HAL.N) and Schlumberger NV (SLB.N) were already preparing them, seeking to clinch Petrobras’ first-ever tender for a production sharing deal with an oil services company.
“It’s a lot of work. Anything that is the first time requires lots of work,” Alejandro Duran, Baker Hughes’ Brazil country manager, told Reuters in an interview. He added that talks with Petrobras were already under way.
He said Baker Hughes will host additional meetings in Houston soon to discuss the issue.
“It is interesting, Petrobras coming to the market with a new thing. It has to be a win-win. That is the most important thing now.”
Petrobras did not immediately respond to a request for comment.
Petrobras, the world’s most indebted oil company, is looking for ways to squeeze better returns from some of its aging fields as it focuses its limited capital budget on developing the country’s prolific pre-salt fields, where billions of barrels of oil are trapped under a thick layer of salt offshore.
A deal would represent a novel way for it to boost output from mature fields without losing control or risking capital, by partnering with one of the world’s largest oil service providers.
It would also allow services companies to put to use expensive equipment idled for years as Brazil’s oil industry was hammered by low oil prices and a massive investigation into corruption at Petrobras.
The state-owned oil company is paying an $853 million fine to the U.S. Justice Department to settle charges related to that probe, which found evidence that political appointees on its board and elsewhere handed overpriced contracts to engineering firms in return for illicit party funding and bribes.
The oil services companies are expected to compete in the tender by promising to boost production from the Potiguar basin’s waning Canto do Amaro field in northern Brazil, where production began in 1986, and offering a bigger share of output to Petrobras, sources said in June.
Based on the results from the project, Petrobras will decide whether to apply this model in other areas, the oil company said in July, confirming the Reuters story.
Proposals were originally due in June, but at least one company sought an extension.
Duran said he thought proposals were due this month but could be extended again.
The winner would be responsible for investment and operation and maintenance costs for the wells. The tender includes a 15-year contract and Petrobras would remain the operator.
GE’s Baker Hughes has not typically taken stakes in customer projects. However, last year it announced a deal with Twinza Oil Limited to provide a range of services for the development of an offshore gas field in Papua New Guinea.
Oil and gas companies and their supporters have poured $20.3 million since August into a campaign to defeat a Colorado ballot initiative that would limit new drilling in populated areas, according to state financial filings released on Tuesday.
Colorado, the sixth largest and one of the fastest growing U.S. oil-producing states, votes on Nov. 6 on a citizens’ petition that would require new wells be at least 2,500 feet (762 m) from homes, schools and parks.
The initiative, which received 172,834 signatures to get a spot on the ballot, was aided in part by the deaths of two men last year in an explosion caused by gas leaking from an abandoned well near a home in Firestone, Colorado.
The state’s oil production rose 26 percent in the 12 months through July as companies used higher prices to expand in the state’s Denver-Julesberg basin.
Oil and gas companies with operations in the state, including Anadarko Petroleum Corp, DCP Midstream LP and Noble Energy Inc, have donated more than $1 million each to Protect Colorado, a group fighting the citizens’ initiative.
Anadarko did not respond to a request for comment, and Noble was immediately available to discuss contributions. DCP Midstream referred questions to Protect Colorado.
The group still has more than $10.2 million in financial and service contributions available to fight the measure with just weeks to go before the vote, according to state filings.
A Protect Colorado spokeswoman said the financing - more than 100 times that raised by initiative backers - is no guarantee of victory.
“It’s really going to depend on voter turnout,” said Karen Crummy, a spokeswoman for the group. “Most people assume this November will have a high turnout, no matter where you are.”
Colorado Rising, which led the signature-gathering effort to get the measure on the ballot, currently has about $100,000 and has recruited about 2,000 volunteers to conduct pro-initiative phone calls and text messages, and to canvas neighborhoods, according to Anne Lee Foster, a spokeswoman for the group.
“We’ve seen many times where the industry has outspent communities and we’ve still won at the ballot box,” Foster said.
Americans for Prosperity, a political advocacy group backed by billionaires Charles and David Koch, also has joined the opposition. Its Colorado chapter is planning a digital campaign to communicate directly with voters, state director Jesse Mallory said in an interview.
Opponents say the set-back restrictions would curtail some 85 percent of new oil and gas development and harm the state’s economy. Colorado mayors and other elected officials have called for a “no” vote.
“There are better ways to protect the health and safety of our communities while keeping our state’s economy strong,” said Denver Mayor Michael Hancock.
Exxon Mobil Corp is exploring the sale of many of its U.S. Gulf of Mexico assets, as higher prices prompt the world’s largest publicly traded oil company to review its portfolio, people familiar with the matter said on Tuesday.
Major oil companies have been looking to concentrate development operations in a few key areas. Irving, Texas-based Exxon is focusing on promising acreage in offshore areas such as Guyana and Brazil and onshore in the Permian basin of Texas.
Exxon has asked a small number of parties to gauge their potential interest in the company’s Gulf assets, ahead of deciding how to proceed, according to two of the sources, adding that any sale would likely happen next year.
The company is considering selling deepwater assets in the Gulf of Mexico that currently produce about 50,000 barrels per day of oil, one of the sources added. The company has stakes in Gulf assets that produce the equivalent of more than 200,000 barrels of oil per day and 730 million cubic feet of gas daily, according to company data.
Exxon produces the equivalent of about 2.2 million barrels of oil daily. While Exxon is the most valuable publicly traded oil company, it is only the ninth-largest operator in the Gulf, trailing heavyweights like Royal Dutch Shell (RDSa.AS) and BP Plc (BP.L), along with smaller Gulf-focused independent oil companies like Fieldwood and Talos.
The Gulf of Mexico, once considered a reliable basin for oil exploration and production, has become overshadowed by shale formations onshore and by new offshore plays like Guyana, where Exxon’s giant Liza field is expected to produce 120,000 barrels per day of crude in its first phase.
“Exxon Mobil continually reviews its assets for their contribution toward meeting the company’s operating needs, financial objectives and their potential value to others,” a spokeswoman for Exxon said in a statement.
“We remain committed to conducting business in the U.S. Gulf region, as we have for more than 100 years.”
The sources asked not to be identified because the matter is confidential.
Exxon’s positions in the Gulf of Mexico include a 50 percent stake in development of the large Julia oil field, and a 47 percent stake in the Hadrian South natural gas field, which it operates. The company also has a 9 percent piece of Heidelberg field and 23 percent of the Lucius oil and gas field, both of which are operated by Anadarko Petroleum Corp, according to Exxon’s latest annual report.
Exxon’s partners in developing many of these sites could have a contractual right of first refusal on any opportunity to acquire Exxon’s interest, one of the sources said.
Exxon has sold 29 leases or stakes in leases to other companies since 2014, according to data from the U.S. Bureau of Ocean Energy Management.
The company has not acquired any leases from other companies in that period. In the last 10 federal lease sales of oil acreage, Exxon has bid on 28 leases, compared with rivals like BP, which has bid on 52 leases.
Qatar, which has a number of partnerships with Exxon, including in Brazil, would be well positioned to make an offer for the Gulf of Mexico assets, the sources said. Exxon has an extensive partnership with Qatar, including partnering with Qatar Petroleum [QATPE.UL] to develop the world’s largest non-associated natural gas field off that country’s coast.
Qatar Petroleum also bought a 30 percent stake in two of Exxon’s affiliates in Argentina in June, giving Qatar access to oil and gas shale assets in the Latin American country.
Qatar Petroleum’s chief executive told Reuters in May that the company was expanding its upstream business and assets abroad, particularly in the United States.
Qatar Petroleum is the majority owner of the Golden Pass LNG terminal in Texas, with Exxon and ConocoPhillips holding smaller stakes.
It could not be established whether Qatar will indeed make an offer. Qatar government officials did not immediately respond to requests for comment.
This week, Chevron Corp agreed to sell its North Sea holdings off the shore of Britain.
It’s crunch time in the race to advance the next-round of liquefaction/LNG export projects along the U.S. Gulf Coast to a Final Investment Decision (FID). And if we’re to assume that only a small number of these multibillion-dollar projects will get their financial go-aheads, it would seem eminently reasonable to put a win-place-or-show bet on a joint venture that includes the world’s leading LNG producer (by far) and one of the largest U.S. natural gas producers — oh, and the partners have very fat wallets too. Size and money aren’t everything, of course, but as we discuss in today’s blog, the team behind the Golden Pass LNG project plans to build its liquefaction trains at the site of an existing LNG import terminal with strong interconnections with coastal pipelines already in place.
2019 will be a pivotal year for the second wave of U.S. LNG export projects. Global demand for LNG continues to rise, and LNG marketers and customers — acutely aware of how much it takes to build new liquefaction capacity — are eager to line up the incremental LNG supply they will need in the early to mid-2020s. Want proof? Royal Dutch Shell, the lead partner in the LNG Canada project, on Tuesday (October 2) announced a FID on the 14-million-metric-tonnes-per-annum (MMtpa) liquefaction/export terminal in Kitimat, BC. (The project’s other partners are Petronas, PetroChina, Mitsubishi and Korea Gas.)
As it turns out, the U.S. is in many ways one of the best places in the world to locate a new liquefaction/LNG export project. There’s ample natural gas supply in the Marcellus/Utica, Permian and other U.S. plays, an extraordinary network of gas pipelines in place, and a skilled workforce capable of executing these very complicated facilities. By the end of next year, there’s a good chance that at least one new liquefaction/LNG export project will get the financial go-ahead and start construction. More may follow in 2020.
This is the fifth episode of our blog series on the projects that appear to be in the running. In Part 1, we reviewed the dramatic shift in U.S. expectations regarding LNG a few years back. Through the 1990s and the first two-thirds of the 2000s, the general thinking was that U.S. gas output had peaked, and that over time, increasing amounts of LNG would need to be imported to keep pace with gas demand. It became clear by 2010-11, however, that the Shale Revolution — and the resulting boom in U.S. gas production — had eliminated the need for LNG imports. Almost overnight, many of the companies that had just finished building LNG import terminals started exploring the possibility of adding liquefaction plants at those sites to export LNG instead. Since then, six liquefaction/LNG export projects advanced to FID and construction — and five liquefaction trains (four at Cheniere Energy’s Sabine Pass in southwestern Louisiana and one at Dominion’s Cove Point in Maryland) with a combined capacity of more than 23 MMtpa are up and running.
We started our analysis of second wave projects in Part 2, where we reviewed Tellurian’s Driftwood LNG, a proposed 27.6-MMtpa liquefaction/LNG export terminal in Louisiana’s Calcasieu Parish, south of Lake Charles. In contrast to the large-scale liquefaction trains now operating at Sabine Pass and Cove Point and under construction along the Gulf Coast (generally with capacities of 4 MMtpa or more each), Driftwood LNG will consist of as many as 20 smaller, modular-based trains (1.38 MMtpa each). Also, Tellurian is acquiring natural gas reserves that will be tapped to produce gas for the LNG project, and it is developing two 2-Bcf/d long-haul pipelines — and a 96-mile, 4-Bcf/d connector pipe — to deliver most of the natural gas that the Driftwood trains will demand. To help finance its project, Tellurian is seeking a handful of customers/partners that would take a combined 60% to 75% equity interest in a holding company that will own all those assets, which will give the customers/partners equity LNG at the tailgate of the liquefaction trains at cost (an estimated $3.00/MMBtu). In Part 3, we turned our attention to Venture Global’s plan for two large projects, also along the Louisiana coast: the 10-MMtpa Calcasieu Pass project in Cameron Parish (south of Lake Charles) and, after that, the 20-MMtpa Plaquemines project along the Mississippi River southeast of New Orleans. Venture Global is “going small” too, planning a total of nine liquefaction “blocks” at Calcasieu Pass, each with two 0.6-MMtpa liquefaction trains, for a total of about 11 MMtpa of capacity. The modular design of the trains is aimed at accelerating the pace of construction and minimizing project costs. (The Plaquemines project will have 18 liquefaction blocks, again each with two 0.6-MMtpa trains.) Unlike Tellurian, however, Venture Global is adopting the same approach to project financing taken by the first round of U.S. liquefaction/LNG export projects, namely lining up a number of long-term, “take-or-pay” Sales and Purchase Agreements (SPAs) with international LNG traders, foreign utilities and other major LNG buyers. And in Part 4, we reviewed NextDecade’s Rio Grande LNG project, which would be constructed at the Port of Brownsville (TX) and consist of as many as six large liquefaction trains with a nominal capacity of 4.5 MMtpa each. The project’s front-end engineering design (FEED) process indicated that the estimated engineering-procurement-construction costs appear to be highly competitive: as little as $500/ton of capacity if a minimum of two liquefaction trains are built and as low as $450/ton if three to six trains are constructed. The natural gas to supply the Rio Grande LNG facility would come primarily from the Permian in West Texas (and southeastern New Mexico) as well as from the Eagle Ford in South Texas. To access that gas, NextDecade plans to build a 137-mile greenfield pipeline (Rio Bravo) from the Agua Dulce Hub (near Corpus Christi) to Brownsville.
Today, we look at Golden Pass LNG, a joint effort by three global energy powerhouses — Qatar Petroleum, ExxonMobil and ConocoPhillips — to expand their existing LNG import terminal (photo above, magenta diamond in Figure 1) on the Sabine-Neches Waterway near Sabine Pass, TX, into a liquefaction/LNG export facility. Much like Austin’s East Sixth Street is a mecca for live music and New Orleans’ Bourbon Street is a hub of late-night debauchery, the greater Sabine Pass area (on the border of Louisiana and Texas) already has drawn more than its share of liquefaction/LNG export facilities (Sabine Pass LNG, Cameron LNG and a number of second wave contenders, including Venture Global’s Calcasieu Pass), and for good reason. There’s easy, deep-water access to the Gulf of Mexico and large tracts of waterfront land, but just as important, there are few places on the planet with as many long-haul gas pipelines nearby to deliver large volumes of U.S.-sourced natural gas.
Like most of the initial round of U.S. liquefaction/LNG export projects now in operation or under construction, the Golden Pass LNG site already is home to an LNG import terminal that was developed in the 2000s, when almost everyone was expecting a flood of LNG from Qatar and other foreign sources. Having docks, storage tanks and connecting pipelines in place gives these brownfield projects at least a modest financial leg up over their greenfield-site competitors — their import-related investments were made and paid for years ago. Qatar Petroleum (which owns 70% of Golden Pass LNG), ExxonMobil (with 17.6%) and ConocoPhillips (with 12.4%) are planning to build three 5.2-MMtpa liquefaction trains for a total of 15.6 MMtpa of capacity. That would require a total of about 2 Bcf/d of natural gas (using a rule-of-thumb ratio of 1 Bcf/d for each 7.6 MMtpa of liquefaction capacity). They also are planning onsite, gas-fired power plants with a capacity of 200 to 250 MW that would provide power for the liquefaction trains and other terminal operations.
Figure 1. Golden Pass LNG Project. Source: RBN
When the joint-venture partners built the LNG import/regasification terminal’s docks along with the storage and regasification units a few years ago, they also constructed the 42-inch-diameter Golden Pass Pipeline (magenta line), which runs about 33 miles from the terminal to an interconnect with the Texoma Pipeline (green line, part of Energy Transfer Partners’ HPL System) in Orange County, TX, and from there, to an interconnect with Williams’s Transcontinental Pipe Line (Transco, blue line) in Calcasieu Parish, LA. (There are several other interconnects with interstate and intrastate pipelines along the Golden Pass Pipeline’s 69-mile route.) The project now awaiting a FID would expand the existing pipeline system and allow for bi-directional flow so that up to 2.5 Bcf/d of U.S.-sourced gas could be transported to the terminal for liquefaction and export as LNG. Among other things, that work to increase the pipe’s capacity would involve the addition of new compressors near Golden Pass Pipeline’s interconnections with Kinder Morgan’s NGPL (pink line) in Jefferson County (TX), the Texoma Pipeline in Orange County (TX) and the Texas Eastern Transmission Co. (TETCO, orange line) in Calcasieu Parish (LA). Also, about three miles of new 24-inch-diameter pipe — known as the Calcasieu Loop — would be installed parallel to the northernmost section of the existing pipeline between TETCO and Tennessee Gas Pipeline (TGP, purple line) in Calcasieu Parish. Further, modifications would be made at Golden Pass Pipeline’s interconnections with NGPL, Texoma Pipeline, TGP, TETCO and Transco to allow for bi-directional flow.
Qatar Petroleum’s Qatargas is the world’s largest LNG producer. With its merger with RasGas, another Qatari LNG supplier, in January 2018, Qatargas now has 14 liquefaction trains (including six 7.8-MMtpa “mega-trains”) with a combined capacity of 77 MMtpa — the equivalent of about 10 Bcf/d of natural gas. All but one of the 14 trains was developed with a U.S. partner. The Qatari LNG company’s primary LNG markets are Asia, which accounted for about 67% of Qatargas and RasGas’s 2017 deliveries according to the International Group of LNG Importers, and Europe, which made up 23% of deliveries last year. Qatar Petroleum has indicated for some time it is seeking to diversify its crude oil and gas supply, with the U.S. being a primary target because of its vast and economically advantaged shale resources. In June (2018), a top executive at the parent company said that, over the next five years, Qatar Petroleum plans to invest a total of about $20 billion in U.S. oil and gas reserves (with the first deal likely to be announced by the end of 2018), as well as another $5 billion in downstream assets.
ExxonMobil, in turn, ranks second among the U.S. natural gas producers — its output averaged about 2.6 Bcf/d in the first half of 2018, according to the Natural Gas Supply Association (NGSA). (Only EQT Resources produced more — an average of about 3.7 Bcf/d in this year’s January-through-June period.) Most significant to our discussion about the Golden Pass LNG project, ExxonMobil in February 2017 acquired vast oil and gas reserves in the Permian Basin from the Bass family for $6.2 billion. ConocoPhillips is a major U.S. gas producer too (its production averaged nearly 600 MMcf/d in the first half of this year); the company also is one of the world’s largest liquefaction technology providers.
The Qatar Petroleum/ExxonMobil/ConocoPhillips joint venture behind the Golden Pass LNG project offers in spades a lot of what a successful liquefaction/LNG export project requires — namely, experience in developing similar projects, low-cost gas supply and global LNG marketing expertise, not to mention the deep pockets that projects of this magnitude demand. There’s also that site, with its existing docks, storage tanks and pipeline connections. Golden Pass LNG has all its key regulatory approvals in hand, and Qatar Petroleum, the project’s lead partner, has indicated that the trio expects to make a FID as soon as early 2019, which suggests the first liquefaction train there could be up and running by 2023. In the next blog in this series, we’ll look at a group of other possible contenders in the race to build second-wave liquefaction/LNG export projects.
https://rbnenergy.com/coming-up-part-5-the-experienced-deep-pocketed-team-behind-the-golden-pass-lng-project
AN ANTONIO—Modern microseismic monitoring technology better resembles a meat thermometer that can teach operators how to cook each stage of a downhole completion just right, vs. earlier technology that was more like a stethoscope, only able to listen to the external chest sounds of a reservoir, according to Peter Duncan, president and CEO of MicroSeismic Inc. And many operators are unaware of the predictive capabilities of the data generated with microseismic today, he said.
“In these days of big data, just as you have AI [artificial intelligence] algorithms that will drive your drilling rig, we’re going to have AI data that will drive your completion based on what we’re seeing in real time in the field as you treat each well … The value is that you can now cook every stage just right.”
Duncan spoke to attendees at Hart Energy’s DUG Eagle Ford conference in San Antonio in September.
Beyond the “dots-in-a-box” data capture that most operators equate with microseismic, cutting-edge microseismic can illustrate not just when and where the rock broke upon treatment, but how it broke. From this, a discrete fracture network model can be created, in which data can then be put into a simulator that will predict how much the well is going to produce and, more importantly, where it is going to produce from.
“Probably the most important thing we want to be able to tell you is where you are going to drain the reservoir—not just in the first six months, but over the next five or 10 years through the life of that reservoir. We ought to be able to get you to that point. And, in fact, we can,” Duncan said.
He illustrates with an example in the Permian Basin’s Central Basin Platform. Element Petroleum had planned to drill four wells in the San Andres Formation within a six-square-mile section in Cochran County, Texas. Before the first well was drilled, MicroSeismic placed 2,354 surface geophone stations in an array around the well and captured data on the stimulation of that well. He then ran a predictive simulation for volumes produced and drainage area over a period of five, 10 and 20 years.
“What we found was that—while the operator, running his economics, was basing his economics on doing four wells per section—the interaction between wells just wasn’t there, even when modeled out years in advance. We could increase the number of wells he could put in a square mile to six without negative impact well to well.”
In doing so, production would increase by 43% by adding two more wells at a cost that was offset by that increase in production. Net present value went up by 28%.
The simulation also tested eight wells, but doing so would have had a negative impact on production due to well interference, based on the reservoir model.
“Six seemed to be the magic number. That’s where we’re taking microseismic analysis today.”
But Duncan wants to deploy the technology even further. He proposes that operators install a permanent array of subsurface geophones throughout a field prior to development to gain a more complete image, allowing real-time customization as wells are being completed.
An operator typically might monitor one well in a field, develop a template for completing subsequent wells, then just “turn the crank up. I call it pumping and praying,” he said.
But inevitably some stages don’t produce as much as others, and some wells get “bashed” by the well next door. Identical treatment design does not account for variability in geology or stress state along the lateral, thus overstimulating the well and resulting in capital inefficiency. And these inefficiencies are accepted as part of the business.
“What I am proposing is that you monitor every well,” said Duncan.
“We believe you can watch every stage and see whether or not after two hours you’ve met the distance out from the well that you need and, if you haven’t, keep pumping. But if you actually meet your given need for that stage after one hour, why not stop and save yourself an hour? Why not stop and protect yourself from bashing the well next door?”
Although well spacing like in the Element example can’t be customized while in motion, he said, “I believe you can customize your treatment on the fly.”
The obvious question is cost: how can operators afford to do that?
“Because you’re amortizing the cost of the equipment across the life of the field, the unit cost can be a few thousand dollars, perhaps $2,000, per stage to monitor the wells … For very little incremental cost [you can] observe each one of the wells as you complete them. It gives you a much more complete picture of what you’ve done.
“Most people say they’ll monitor one or two wells and that will be good enough. But look at the variation well to well. I believe it’s important that you monitor this many wells.”
The U.S. midterm elections are only a few weeks away and a lot is at stake for the energy industry.
It isn’t just the fate of the U.S. Congress that is up for grabs, although that is incredibly important. There are also 36 governor’s races, state legislature races, and a raft of ballot initiatives that will have a direct impact on oil and gas. The results will have enormous implications going forward.
The Republicans currently control 33 governor’s mansions, but that could soon change as most polls indicate significant wins for the Democrats are in the offing. For instance, as InsideClimate News points out, Nevada, New Hampshire and Maine all saw their legislatures pass renewable energy initiatives over the past year, only to have them vetoed by their Republican Governors. Those policies could quickly move forward if the Democrats take over in those states. The same could be true in a series of other states if power changes hands.
Then there will be questions related to the energy industry that will be directly decided by voters. Perhaps the most consequential ballot initiative affecting the oil and gas industry is in Colorado, where voters will decide on greater setback distances for oil and gas drilling. Initiative 97 will require drillers to stay a minimum of 2,500 feet away from “occupied structures,” including houses and parks, up from just 500 feet currently. Because so much drilling in the state takes place in densely populated areas, the industry is decrying the initiative as one that could potentially kill off the drilling.
But a house explosion from a residential gas line in 2017 that killed two people has galvanized drilling opponents, who have called for stricter regulations.
To top it off, the governor’s race in Colorado pits a Democrat who is in favor of policies to transition to 100 percent clean energy (although he notably does not support Initiative 97 requiring greater setback distances, in a sign of how much the shale industry has sway in the state) versus a Republican candidate who has promised to expand oil and gas development.Related: Underwhelming OPEC Fuels Oil Price Rally
The choices are also stark in New Mexico, which hosts part of the Permian basin and has seen oil production more than double over the past four years to 670,000 bpd as of July 2018. As InsideClimate News points out, the Democrat running is promising a “renewable energy economy” while the Republican is heavily backed by the oil and gas industry. Indeed, he actually owned an oilfield services company.
Then there is the carbon tax in Washington State, which seems to have sparked somewhat of a panic from the oil and gas industry. Texas oil companies have reportedly mustered more than $17 million in spending to oppose the measure, according to the Houston Chronicle. Phillips 66, Andeavor and the U.S. subsidiary of BP have marshalled resources to defeat what could be the first carbon tax in the United States.
The tax would amount to $15 per metric ton of carbon placed on large emitters beginning in 2020, a levy that would increase by $2 each year and would be adjusted for inflation. It would impact fossil fuels sold or used within the state. It would also apply to electricity generated in Washington as well from sources imported from neighboring states. State officials believe the tax will raise $2.2 billion in revenue in the first five years, which will be reinvested in public transit, energy efficiency and renewable energy.Related: How Much Spare Capacity Does Saudi Arabia Really Have?
Meanwhile, the federal races are also not to be overlooked, although the impact will be a little more ambiguous. The U.S. House and Senate are on the line, and while Democratic wins would not likely translate into a major shift in policies, given that Donald Trump would still occupy the White House, it could slow the deregulatory effort underway in Washington.
If the Democrats took majorities, they could launch investigations into the agencies that oversee regulatory policy for oil and gas (namely the EPA and the Interior Department), they could block Trump’s nominees to agencies, as well as his future judicial appointments. At the risk of venturing even further into speculative territory, the results of the 2018 midterms could have an enormous impact on future environmental and energy policy following the 2020 electoral cycle, especially with the 2020 Census and redistricting taking place. Democratic majorities sealed this year could even pave the way for clean energy legislation and attacks on oil and gas should the next president be a Democrat. In other words, the impact of the November elections could be profound, but hard to predict from the vantage point of today.
Thus, the oil and gas industry has its sights set on damage control at the state level, where there are a series of elections and ballot initiatives that could have a direct and immediate impact.
https://oilprice.com/Energy/Energy-General/Should-The-US-Oil-Industry-Fear-The-Midterms.html
Offshore drilling company Borr Drilling has begun the activation of four jack-up rigs despite not having secured contracts for them.
The driller on Wednesday said the move to reactivate four additional jack-ups was made based on recent contracts secured and a rise in customer inquiries-
Borr Drilling said: “Supported by the strong increase in direct customer requests and the material increase in tender activity of approximately 50% year to date, the Board has decided to initiate the activation without having secured firm employment for the four rigs. However, the Board sees several interesting opportunities for employment at attractive rates.”
The Oslo-lised company did not say which rigs exactly are being activated.
Activity is coming back
The offshore drilling company has recently secured commitments for three of its newbuild units and its North Sea based jack-up “Ran”, all of which are currently undergoing (re)activation and have been awarded LOIs. These rigs are expected to begin work in the first half of 2019.
Borr Drilling also said the delivery time for critical equipment was increasing, currently standing at around six months.
“We believe we have seen the trough in equipment prices and as activity is coming back we also expect a tightening of the labor market. Given the improving jack-up market outlook, we are increasingly positive about future contracting opportunities for our modern rigs but emphasize our continued disciplined approach to contracting with focus on opportunities that generate significant positive cash return after activation cost,” Borr Drilling said.
Oil firms BP and Aker BP have entered into a pact to explore ways of developing pioneering new technologies together.
They expect to invest in technological advancements, including developments in digital twins, advanced seismic techniques and processing, and subsea and robot technology.
Steve Cook, BP Technology’s chief commercial officer, said: “BP has built a strong track-record of targeted investment through BP Ventures in a range of technologies and sectors.
“Working together with Aker BP, our alliance will be focused on identifying technologies that could be transformational in the upstream sector, enabling the digital transformation of subsurface characterisation and workflows.
“Our alliance will help both companies identify and invest in innovation that will help secure and advance our industry’s future.
“We believe that working together can deliver real value for both BP and Aker BP.”
Aker BP Karl Johnny Hersvik said: “Aker BP is very pleased to expand the cooperation with BP. We want to leverage this alliance to expand our capacity to identify innovative technology companies that can help us to solve our key business challenges.
“Aker BP targets to become a preferred partner for such companies through various cooperation models, including potential equity investments.”
Aker BP was formed in 2016 through the combination of Det norske oljeselskap and BP’s Norwegian exploration and production business.
https://www.energyvoice.com/oilandgas/182969/bp-enters-technology-development-pact-with-aker-bp/
Argentina Tuesday opened bidding for 38 offshore blocks with the aim of attracting explorers to one of the world's last frontiers, Energy Secretary Javier Iguacel said.
"There is a lot of interest," he told S&P Global Platts on the sidelines of an energy seminar in Buenos Aires.
A dozen companies have acquired seismic data to prepare for making offers in the round, and two want to produce more seismic to meet the demand for data, he said.
The main driver of the interest is that Argentina's vast offshore region is "practically the last frontier" for offshore exploration, he said.
Africa and Brazil's offshore has been largely explored in the Atlantic, and discoveries have been made recently off the coasts of Guyana and Suriname, while Uruguay has been tested. That leaves Argentina as the last big spot for exploration, Iguacel said.
The 38 blocks are in three basins in the South Atlantic: Argentina Norte, Austral and Malvinas Oeste. Water depths run from 100 meters to 4,000 meters, among the deepest in the world.
Most of the interest is in the continental slope, where the country's wide continental shelf descends into deeper waters. This would be a similar geology to offshore Guyana and Suriname, Iguacel said.
The bids are due in February, when they will be opened.
To drum up interest in the round, the first of what could be several, the Energy Secretariat will hold roadshows in Buenos Aires, Houston and either London or Paris.
Dominique Marion, director general of Total Austral, a unit of France's Total, said his company may bid.
The company is looking at the blocks in the Malvinas Oeste basin off the coast of the southernmost province of Tierra del Fuego, he told Platts on the sidelines of the seminar.
That would expand its offshore interests in Argentina, which are in the shallower waters of the Austral Basin, inshore from Malvinas Oeste, where it operates blocks producing some 20 million cu m/d of gas.
He said there could be synergies between the Austral and Malvinas Oeste basins, but the focus of any potential exploration would not be gas. "We will look for oil," he said.
John Padilla, managing director of energy consultancy IPD Latin America, said he expects interest in the round to be healthy.
"Any time you put acreage on the block that hasn't been really tested out over the last 10-12 years, it is compelling. This is particularly so in light of Guyana," he told Platts by phone. "People are looking for that next play."
Robust demand for gasoline in East of Suez markets, amid supply tightness in the region, has seen the number of arbitrage barrels loading in Europe in September and early October rise above 10 million, market sources said.
The tightness was partly as the result of a reduction in Chinese gasoline exports, while an excess of summer-grade barrels in Europe has also helped open the arbitrage.
"The East-West [arbitrage] is there. Q4 and Q1 are historically high demand periods for Asia," a broker based in Europe said, while a European trader said: "The market is for LR2s".
The East-West -- the spread between the Platts FOB Singapore October gasoline swap and the Platts October Eurobob barge swap -- averaged $1.05/b last month, up from minus $2.42/b in August, S&P Global Platts data showed.
The spread was mostly negative between end-February and late August, Platts data showed.
Traders first started booking ships to carry European gasoline to the Middle East to cover a shortfall in production stemming from refinery outages around mid-August.
Subsequently, additional demand was heard from some national oil companies from Iraq, Oman and Pakistan. Also, China and India were heading towards their peak gasoline demand season, market sources said.
At least 23 product tankers carrying 1.300 million mt, or 11.050 million barrels, of European gasoline were chartered to ship September and early October-loading cargoes through the Suez to the Middle East and Asia. Some 478,000 mt of August European gasoline made it into the East of Suez market.
"The East is pulling a lot [of gasoline]. The paper market, as well, is supporting flows from the West to East," another trader said.
Fixture data showed several product tankers carrying another 305,325 mt of European gasoline to the Americas or to Africa also had options to discharge in the East of Suez market.
Meanwhile, Indonesia's state-owned Pertamina plans to import 11 million barrels of gasoline in spot and term cargoes this month, slightly below its year-to-date high of 11 million-12 million barrels planned for September.
Pertamina, which recently awarded gasoline buy tenders for the fourth quarter, has sought 69,822 mt of gasoline via spot tenders for October loading.
Texas-based Noble Energy sold its 43.5 percent stake in Israel’s Tamar Petroleum after announcing last week that it would help finance a gas export deal with Egypt, the Israeli business daily The Marker reported on Wednesday.
Noble’s sale of 40 million Tamar shares, at 15.50 shekels ($4.26) each, took place on the Tel Aviv Stock Exchange, The Marker said in the unsourced report.
On Sept. 27, Noble, Israel’s Delek Drilling and the Egyptian East Gas Co said they would buy a 39 percent stake in the EMG pipeline to enable a landmark $15 billion deal to export natural gas from Israel to Egypt to begin next year.
The $518 million purchase will enable the supply of 64 billion cubic metres of gas over 10 years from Israel’s offshore Tamar and Leviathan fields. Delek and Noble, which are partners in the fields, will each pay $185 million while the Egyptian East Gas Co will pay $148 million.
Marathon Oil has launched the sale of its British North Sea oil and gas fields, a document seen by Reuters showed, the latest U.S. firm to retreat from the basin to focus on onshore shale production at home.
The sale includes stakes in the BP-operated Foinaven fields in the west of Shetland area as well as interests in the Brae complex northeast of Aberdeen, according to a sales document seen by Reuters.
The process, launched this week, is being run by Jefferies and bids are due by December. The assets could fetch up to $200 million, according to two banking sources.
Marathon Oil joins several companies including Chevron, ConocoPhillips and EOG Resources that have sought to pull out of the North Sea in recent years as they focus operations on rapidly expanding shale production.
Marathon Oil spokeswoman Lee Warren declined to comment directly on the sale but said “portfolio management is an ongoing and integral element of our successful business model as we continue to simplify and concentrate our portfolio to our highest return opportunities with a focus on our differentiated position in the U.S. resource plays.”
The company, which produced around 419,000 barrels of oil equivalent per day in the second quarter, will invest over 90 percent of its 2018 capital in U.S. shale production, according to its website.
The North Sea, one of the oldest offshore basins that started production in the 1970s, has undergone a broad change of guard in recent years as veteran producers have been replaced by smaller, often privately-owned companies, which say they can squeeze more oil and gas out of the fields.
According to the sales document, Marathon’s North Sea assets have a total production of 15,000 barrels of oil equivalent per day, a resource of 31 million barrels and are expected to produce $85 million of cash flow in 2019.
Marathon holds a 40 percent stake in the Brae Area complex, one of the oldest in the basin, as well as stakes in pipelines. One of the complex’s platforms, Brae Bravo, is being dismantled after production ceased in recent years in what is known as decommissioning.
The Foinaven area comprises of two producing fields, Foinaven and Foinaven East, in which Marathon holds 28 percent and 47 percent interests respectively, the document said.
Marathon agreed to sell its Libyan assets to France’s Total earlier this year for $450 million.
A $4.6 billion natural gas pipeline that’s already been delayed by about a year is facing yet another setback after a court vacated a key permit.
A U.S. appeals court voided a federal authorization for EQT Midstream Partners LP’s Mountain Valley conduit, which is designed to carry natural gas from the Marcellus basin in Appalachia -- America’s biggest reservoir of the fuel -- to southeast markets.
The court sided with environmental groups in a ruling Tuesday, saying the Army Corps of Engineers wasn’t allowed to require a certain method for building across rivers after West Virginia had already imposed a special condition for that work.
The decision is “a huge blow to the project and a real surprise to us,” said Brandon Barnes, an analyst at Bloomberg Intelligence in Washington.
A spokeswoman for EQT Midstream didn’t immediately respond to a request for comment.
Mountain Valley has faced mounting legal and regulatory hurdles, which have pushed the project’s start date to the fourth quarter of 2019 from its original timeline a year earlier and forced the developer to raise cost estimates by almost $1 billion.
Other eastern U.S. pipeline projects, including Dominion Energy’s Atlantic Coast line, have faced similar woes. The conduits would join several built in the region over the past few years as Marcellus drillers seek outlets for abundant shale supply.
The same court in late June issued a stay on a portion of the Army Corps’ permit, which was lifted on Aug. 29. Since the initial stay, EQT Corp. has seen its shares fall 21%.
The Federal Energy Regulatory Commission, which oversees state-crossing gas pipelines, will likely halt all construction on the project in response to the court’s most recent order, Barnes said. Work on the pipeline was already ordered to stop for about a month after the U.S. Court of Appeals for the Fourth Circuit vacated permits from the Bureau of Land Management and Forest Service.
Mountain Valley would transport Appalachian shale gas 303 mi from northwestern West Virginia to southern Virginia. The project is a joint venture of EQT Midstream, NextEra Energy, Consolidated Edison, WGL Holdings, and RGC Resources.
https://www.worldoil.com/news/2018/10/3/troubled-46-billion-gas-pipeline-hits-new-snag
Austrian energy group OMV said it had agreed to buy Siberian gas assets from Gazprom instead of swapping them for some of its own assets, giving in to opposition from Norway to the initial plans.
OMV agreed in 2016 to swap 38.5 percent of its Norwegian assets for 24.98 percent of the Russian company’s Achimov IV and V phase development in the Urengoy gas fields. It had hoped to seal the deal by the end of this year.
However, sources told Reuters in May that the Austrian group might buy the assets outright after Norway criticized the plan to give Russia’s largest natural gas producer access to its continental shelf.
“The ‘basic sale agreement’ replaces the ‘basic agreement’ concluded between OMV and Gazprom on December 14, 2016,” OMV said in a statement.
The purchase price will be “negotiated in good faith”, it said.
Of the 10 billion euros ($12 billion) set aside for acquisitions to 2025, OMV has so far spent 2 billion.
It is also negotiating the price for its planned purchase of a 50 percent stake in Malaysian Sapura Energy Bhd’s upstream business.
Last year, OMV paid 1.75 billion euros for a stake in the Yuzhno Russkoye field, one of Russia’s largest gas fields, which added 100,000 barrels of oil equivalent (boe) per day to its production.
In 2016, OMV said that the Siberian Achimov assets would add more than 80,000 boe per day by 2025. For OMV, production in the area is cheap and pipelines to Austria are available.
The Austrian group is one of Gazprom’s partners in building the new Nord Stream 2 gas pipeline, which is planned to double Russia’s capacity to pipe gas across the Baltic Sea to Europe.
The original swap deal would have allowed Gazprom access to technological know-how in Norway.
However, OMV managers have said that Gazprom will benefit just as much from OMV’s technological expertise in developing the fields in Russia.
Once a purchase price has been agreed, the deal will be subject to regulatory and corporate approvals. The signing of the final transaction documents is expected early next year.
Independent global completions service company Tendeka, has launched the MajiFrac Solution, a new portfolio of applications which aims to reduce water use and pumping time during completion operations in unconventional shale plays in the U.S.
Unique to Tendeka, the MajiFrac Solution is the combination of a wide range of high-performance technologies and products, which can be used either individually or collectively. It includes a specially blended thermally stable modified acid system, the company’s field proven MajiFrac Composite Plug, which incorporates a pump down feature to minimize water by-pass, and MajiFrac, a range of high viscosity friction reducers (HVFR).
“As is often the case when it comes to technology, it’s not the specific, off-the-shelf components that solves the problems but how to combine solutions together that delivers tangible results,” said Elizabeth Cambre, Tendeka’s Business Development Manager – Production Enhancement. “In one example, the MajiFrac Solution delivered savings of up to 50,000 bbl of water and reduced pump operating times by 200 hrs. The sequence in which the MajiFrac technology is deployed enables optimized fluid distribution across the interval. This can lead to more contact area with the formation resulting in increased production.”
The modified acid system, which can be prepared in produced water, boasts a combination of spotting a spearhead acid with plug and perforating guns. It is harmless to the skin and achieves ultra-long-term corrosion protection compared to conventional acids, thereby reducing risk to personnel, the environment and eliminating the hazards of casing integrity. While maintaining the positive aspects of solubility and reactivity rates, it minimizes unsafe exposure levels and effluent rates, as well as costly transport and storage. It has already been tested and approved by several major operators.
Tendeka’s MajiFrac Composite Plug is proven to be unaffected by acid. Its superior design deploys the plug to its setting depth with considerably less water than other leading industry plugs. The fast mill out time also reduces operational schedules with minimal remaining debris. Furthermore, high speed lines are achievable at low pump down rates.
The MajiFrac Solution incorporates Tendeka’s MajiFrac suite of HVFRs. Designed and manufactured in-house by the company’s Production Enhancement team, MajiFrac HVFRs delivers improved drag reduction, without the need for a booster, at ultra-low dosages. Because of its elasticity, it can transport high loadings of sand at low dosages. It can also be used across a wide range of water qualities without losing its efficacy.
Saudi Aramco shores up its position as one of the world's biggest refiners with the impending startup of new capacity at two facilities, its subsidiary Aramco Trading Company is deepening its footprint in the global gasoil market.
ATC's gasoil derivatives trading volume in the Platts Market on Close assessment process over January-September was up more than threefold from 2016. Its gasoil paper trades totaled 33.3 million barrels over the same period, already more than double the 16.41 million barrels it recorded over full year 2017.
ATC traded 27.95 million barrels of this volume over March-August alone, displacing Hong Kong-based Winson Oil Trading for the highest trade derivative volume in the period. Winson's total was 27.25 million barrels, and was followed by Totsa at 24.9 million barrels, BP Singapore at 24.65 million barrels and Vitol Asia at 22.1 million barrels.
ATC has notably been more active, especially on the derivatives front, since S&P Global Platts started to publish any bids, offers or expressions of interest to trade from the company in the MOC process in September 2014.
It currently trades 4 million b/d of refined products and crude, including volumes from the US, and sees Asia as its key growth market, President and CEO Ibrahim Al-Buainain said during an on-stage interview at the S&P Global Platts Asia Pacific Petroleum Conference in Singapore in late September.
The company is targeting boosting its refined products and crude trading volume by 50% to 6 million b/d by 2020 and plans to launch an office in Europe by the second half of 2019, he added.
EXPANDING INTO GASOLINE
The second half of 2018 has seen ATC enter into more structural supply agreements in Southeast Asia, including taking part in the region's largest gasoline buyer Pertamina's term tender for H2.
In the tender, ATC joined 15 other regional suppliers in offering to supply 88 RON and 92 RON gasoline cargoes on an FOB and CFR basis to meet Indonesia's growing gasoline requirements over July-December.
According to market sources, ATC will supply one or two 200,000-barrel parcels/month of 88 RON gasoline on an FOB Singapore/Malaysia basis and one 200,000-barrel parcel/month of 92 RON on a CFR basis over H2, at prices that could not be confirmed. According to some trade sources, ATC sold at CFR delivered prices that were at similar levels to FOB Singapore/Malaysia term basis prices.
Other suppliers in the tender included ExxonMobil, Total, Hin Leong, PetroChina, Shell, Lukoil, Reliance, PTT, Statoil, BP, Phillips 66, Gunvor and Trafigura, traders said.
In order to supply into Pertamina's term contract, ATC was reported to have moved gasoline from its storage facilities in Fujairah to Southeast Asia.
NEW CAPACITY COMING ON STREAM
Saudi Aramco will see a significant increase in refined oil products output in coming months due to the completion of its 400,000 b/d Jazan refinery in Saudi Arabia and 300,000 b/d joint venture Rapid refinery in Malaysia, which are both slated to commercially ready by year end or in early 2019.
The Jazan refinery will be able to produce around 75,000 b/d of gasoline, 100,000-160,000 b/d of ultra low sulfur gasoil and 160,000-220,000 b/d of fuel oil, depending on the crudes processed, according to the EPC Engineer website.
The Rapid refinery and petrochemicals joint venture between Petronas and Saudi Aramco in southern Malaysia could boost ATC's trading and supply volumes closer to the Asian oil trading hub of Singapore.
The 300,000 b/d refinery is designed to produce 98,000 b/d gasoline, or a yield of about 33%, 88,000 b/d of gasoil, 28,000 b/d of Jet A1 and 5,000 b/d of fuel oil, Platts reported earlier.
For ATC this potentially means a monthly supply of around 170,00-175,000 mt of gasoline, 175,000-180,000 mt of diesel and 50,000-55,000 mt of Jet A1.
With ATC's increased derivative exposure and growing physical presence in Asia, the trading arm of Saudi Aramco is positioning itself as a formidable competitor in the region.
Russia’s Gazprom is in talks with China on additional gas supplies via the Power of Siberia pipeline, the Interfax news agency cited Gazprom’s CEO Alexei Miller as saying on Thursday.
It cited him as saying that the existing contract was for 38 billion cubic meters per year.
Australian watchdog starts LNG netback price publication
The Australian Competition and Consumer Commission started publication of LNG netback prices in order to boost transparency.
An LNG netback price is an export parity price that a gas supplier can expect to receive for exporting its gas. It is calculated by taking the delivered price of LNG and subtracting the costs of liquefying natural gas and shipping it to the destination port.
It represents the price that a gas supplier would expect to receive from a domestic gas buyer to be indifferent between selling the gas to the domestic buyer and exporting it, ACCC said.
The watchdog added that the LNG netback price is not the sole factor influencing the domestic prices in the east coast gas market.
“The prices paid by domestic gas users could also depend on demand and supply. If there were sufficient additional gas produced to fill existing LNG train capacity, excess gas available to the domestic market could see prices below the LNG netback price,” ACCC chair Rod Sims said.
In addition, the prices will depend on the terms and conditions of the gas supply and applicable transportation or retailer charges.
When the current ACCC gas inquiry commenced in April 2017, however, many domestic gas buyers in the east coast were receiving offers for gas supply at prices that were well in excess of LNG netback prices, ACCC said.
The published LNG netback price series will assist east coast gas users to identify trends in LNG netback prices and to estimate an indicative reference price of gas for supply over the near term.
LNG netback prices have increased considerably since the start of the ACCC’s gas inquiry, driven by an increase in global demand for gas and a weaker Australian dollar.
The average LNG netback price at the Wallumbilla Gas Supply Hub has been $10.69/GJ so far in 2018, compared to $7.27/GJ over the same period in 2017 and is currently expected to be on average around $12.40/GJ over the same period in 2019.
However, ACCC still notes there is a need to produce more lower-cost gas, especially in the south.
The published forward LNG netback price series is likely to be most useful for gas users that are negotiating gas supply with a term of up to two years.
https://www.lngworldnews.com/australian-watchdog-starts-lng-netback-price-publication/
Concerns over abundant supply arriving in Asia from the US and Middle East have flipped the front-month November/December Saudi Contract Price swap timespread to a contango structure, after being in backwardation since September 3, S&P Global Platts data show.
The market last switched to a contango on July 19.
The November/December CP propane swap was in a $2/mt contango at the Asian close Wednesday, from a $2/mt backwardation Tuesday. Early Thursday, it was notionally indicated at a $3/mt contango, though December/January remained at a $3/mt backwardation, reflecting firm demand during winter amid supply uncertainty.
"The market is a bit over supplied, and that NATPET (plant) being down won't help," one trader said.
He was referring to Saudi media reports of a fire Tuesday at a petrochemical refinery in Yanbu in western Saudi Arabia, operated by the National Petrochemical Industrial Co. The fire could limit domestic feedstock usage if operations were affected, leading to possible exports of surplus LPG by the company.
On the other hand, the resumption of operations at Al Waha Petrochemicals' 450,000 mt/year polypropylene unit in Jubail late Friday, after a 17-day maintenance, could absorb more LPG feedstock that had been made available for export during the shutdown, trade sources had said.
Traders also attributed the price slide Wednesday to players cutting losses amid a well-supplied market, with more supply being offered to meet robust bidding seen in recent weeks.
The November CP swap fell $15.5/mt day on day to $649.5/mt Wednesday, while the front cycle H1 November CFR Japan physical propane was assessed at $668/mt -- almost a one-week low -- and also down $15.5/mt on the day, Platts data show.
In the face of China's higher tariffs on US LPG imports, sellers such as Chinese PDH plant operator Oriental Energy, are offering more propane cargoes in the Singapore physical market this week totaling around 69,000 mt daily for H1 November deliveries.
CONTANGO SEEN SHORT LIVED AS WINTER NEARS
Oriental has also taken bids for 23,000-mt propane lots for H1 November delivery from Petredec and BP this week.
Before the fall this week, the arbitrage from the US to Asia had been wide open, with at least 1.8 million mt set for October-loading and seeking markets in Indonesia, Taiwan, South Korea, Japan and South Asia, as Chinese imports are limited by the higher tariffs.
The backwardation in past months were also due to rare spot demand from Indian Oil Corp., which bought via tenders over August and September about 176,000 mt of evenly split LPG for deliveries over October and November.
Traders, however, noted that IOC's spot demand has not reemerged since and a source said the state-run firm will next issue a tender for a one-year term requirement this week.
As the LPG market weakened this week, the discount of propane swap versus the Mean of Platts Japan naphtha assessment widened to $64/mt Wednesday, prompting Taiwan's Formosa Petrochemical to issue a spot tender seeking 23,000 mt of propane for November 1-10 delivery. This is Formosa's first spot tender since July.
Chinese buyers have been taking alternative supply from the Middle East and Africa even as they resell their US term cargoes, and have been the main buyer of shipments from Iran.
After Iran had loaded 568,000 mt in August for export, the highest since previous Western sanctions for its nuclear plan were lifted in January 2016, volumes eased to 356,000 mt in October ahead of new US sanctions next month, shipping sources said.
At the onset of winter, the December/January market persisted in a backwardation, as worries turn to supply shortfall amid restrictions on Iranian shipments at the year-end, traders said.
Natural gas at the UK's National Balancing Point (NBP) hub continued an unrelenting march upwards during September, as the monthly average of day-ahead price assessments jumped by 18% on the month, their biggest percentage increase for two years, according to S&P Global Platts data.
NBP day-ahead contracts averaged 73.152 p/th during September, the highest monthly average for the year, and up 60% compared to the September 2017 average. The rises continued the recent trend for NBP spot prices, and the wider European market as whole.
The October front-month contract notched up comparable gains, averaging 73.218 p/th during September, constituting an increase of 16% on the month and a rise of 61% year on year.
The September monthly contract was finally assessed by Platts at 68.55 p/th at the close of the instrument, meaning that shippers with short positions going into the month would have had to pay a significant 4.60 p/th premium to procure spot gas at short notice. This was a discernible pattern throughout the whole of Q3, with September proving no exception.
A major factor supporting September's prices was the annual maintenance period for the Norwegian Gassco offshore gas network. Considerable production unavailability during the planned works, and other unplanned outages, meant gas was less readily available for anybody that needed to buy it. Ongoing industrial action and unplanned technical outages also dented gas availability from the UK continental shelf at times.
This was reflected in the production figures for both territories. Norwegian imports were down by a quarter compared to September 2017, while UK production saw a marginal 1% fall, compensating for Norwegian losses when it could. Overall supply actually fell by 15% year on year, in response to muted demand. However, the timing of unavailability resulted in an inconsistent supply base, reflected in a volatile day ahead trading range of 70.20-78.85 p/th for September.
LAUNCH THE REPORT
On the demand side, gas-to-power offtakes and export volumes to Belgian shaped the downward trajectory, as CCGT requirements fell by 22% compared to last year, while participants saw little benefit in exporting volumes ahead of the long-term IUK transportation capacity expiry, with metered exit volumes at IUK Bacton dropping by 16% to total 689 million cu m. Exports to Ireland also fell, down 41% year on year to 238 million cu m.
Storage-wise, MRS sites saw a drawdown in inventories during September this year as they did in 2017, with net withdrawals totaling 184 million cu m, down by just over a quarter on year.
Platts' final assessment of the NBP October contract rested at 71.90 p/th, having traded within a 69.70-77.875 p/th range while positioned as the front month. Such volatility could be attributable to a combination of mirrored spot movements, uncertainty surrounding the termination of the long-term Interconnector capacity contracts, and speculative efforts on the contract. Carbon prices were also hugely influential on the October contract during the period.
Following a volatile opening to October trading, on the spot and near curve in particular, prices began to stabilize in a way they had not during Q3, as the picture for UK supply fundamentals clarified. Much less interest was seen on balance-of-month or working-days-next-week (WDNW) contracts than was at the start of Q3, indicating a reduced need to cover short positions.
The new gas winter is expected to be well hedged, with winter purchasing having helped build momentum on the front-month contract. A resumption of sendout from the Dragon LNG terminal has helped pressure day-ahead prices since October began; the contract was last assessed below the October closing price at 70.45 p/th. This fed bearish sentiment to the prompt as the LNG outlook for October improved, with LNG players likely to have sold at peak prices during the preceding month.
Oil and gas explorer Beach Energy Ltd said on Friday it will sell a 40 percent stake in its Victorian Otway gas assets for A$344 million ($243 million), and trimmed its earnings and production guidance.
Beach said the stake would be sold to a unit of Eyal Ofer’s O.G. Energy, part of the privately held Ofer Global group of companies.
Following the sale, four new joint ventures will be formed, with Beach operating and having a 60 percent interest in each joint venture, the company said in a statement.
“We intended to sell down our interest and will be applying the sales proceeds to reduce debt and fund a portion of our future capital expenditure program,” Chief Executive Matt Kay said.
In a separate statement, Beach cut its fiscal year 2019 production and core earnings guidance.
The company now expects to report earnings before interest, tax, depreciation and amortization (EBITDA) between A$1.05 billion to A$1.15 billion, lower than previous guidance of A$1.1 billion to A$1.2 billion.
It expects to produce between 25 to 27 million barrels of oil equivalent (mmboe), down from previous guidance of between 26 to 28 mmboe.
India’s government has introduced a fuel relief as prices at the pump rise inexorably, following soaring international benchmarks, Indian media report, citing the official statement by Finance Minister Arun Jaitley.
The move was made after consultation with local oil companies, which agreed to reduce prices by US$0.034 (2.5 rupees) per liter of gasoline and diesel, of which they will absorb US$0.014 (1 rupee) per liter of fuel, and the government will shoulder the rest by cutting excise duties on fuels.
The Finance Minister said, however, that the higher oil prices were not the only factor that prompted the decision: India was also getting hit by higher U.S. interest rates, although he added that only the country’s current account deficit was swelling under the twin pressure of prices and rates, while the national fiscal deficit was enjoying the positive effects from direct tax collection rates.
The fuel price cut decision is only the latest in India’s government efforts to cushion the blow from rising oil prices. Yesterday, media reported that the Modi government had allowed local companies affected by the rise in oil prices to borrow internationally up to US$10 billion.
India’s current commercial borrowing rules prevent businesses from borrowing more than $750 million in foreign money—the previous limit as outlined in April by the Reserve Bank of India (RBI) as cited by Lexology.
Yet now that the higher oil prices have combined with a falling rupee after the latest quarterly economic growth figures turned out disappointing, with the deficit widening, India is facing a serious challenge in sustaining its growth while reducing the adverse impact of the latest oil market developments.
Asia’s second-biggest economy and the fastest-growing is particularly vulnerable to the effects of oil market movements as it is dependent on imports of crude oil for over 80 percent of its consumption. Earlier today, Transport Minister Nitin Gadkari told media that the country will face an economic crisis if prices continue to rise.
Volkswagen AG, BMW AG and Mercedes-Benz have halted sales of some of their plug-in hybrid cars in Europe in the wake of new emissions regulations, Automotive News reported on Thursday.
The new Worldwide Harmonized Light Duty Vehicles Test Procedure (WLTP) regime, which went into effect on Sept. 1, gives higher CO2 readings than the old New European Driving Cycle (NEDC) system, pushing vehicles into a higher tax bracket.
The new rules could take away tax incentives offered to cars with ultra-low emissions in certain countries, the Automotive News report said.
Automakers have to decide whether the extra cost to fit a bigger battery is worth the incentives given, according to the report.
The introduction of WLTP has forced some carmakers to withhold non-conforming models from showrooms, prompting them to discount other models to defend their market share.
Clean, green energy has become a growth industry in China, driven by the need to reduce carbon emissions and cut air pollution.
China has become the worlds third largest Ethanol producer as part of its move to introduce E10 in 2020
China produced 6,260 mt of lithium iron phosphate in August, up 14% from July, SMM data showed.
Demand improved last month and major producers in Beijing, Anhui and Guangdong stepped up their production. Producers in Jiangxi also gradually recovered their output.
Some producers told SMM that orders grew in August. Output of lithium iron phosphate is expected to amount to 6,800 mt in September, SMM estimates.
Foreign-backed Salar Blanco expects to begin construction on its lithium mining project at the beginning of 2020 in Chile’s north, once its environmental permit is approved by the government.
The approval process for the necessary environmental permit for the initiative, which includes an investment of $527 million, began this month. Salar Blanco CEO Cristobal Garcia-Huidobro said he expects it to be approved by the end of next year. Garcia-Huidobro said the company is in talks with Chilean authorities to finalize the project’s operation, considering it already has the permission of the nuclear power regulator.
“We are working very closely with the ministry of mining in order to define what will be the best structure to use,” Garcia-Huidobro told Reuters.
The Maricunga salt flat, where Salar Blanco’s project is located, lies about 450 miles (740 kilometers) northeast of capital Santiago and 3,756 meters above sea level. It is a highly prized deposit in the lithium triangle, a concentration of the largest reserves below Argentina, Bolivia and Chile.
Lithium is a key ingredient in batteries used for products ranging from cell phones to electric vehicles.
Garcia-Huidobro said the mining company has the necessary water rights for the entire project amid concerns about water scarcity in Chile.
Salar Blanco aims to produce 20,000 tons of lithium carbonate per year and 58,000 tons of potassium chloride. EXPANSION POTENTIAL
Salar Blanco said it identified 2.15 million tonnes of lithium carbonate at the site of its Maricunga project.
“We have resources that probably more than triple the size of the project. Therefore, the future growth capabilities of this project will depend on how the market develops,” García-Huidobro said.
In July, the company dropped a lawsuit against Chile to block state-run Codelco from exploiting a lithium deposit where both have claims.
Garcia-Huidobro attributed the decision to a positive attitude in the administration of center-right President Sebastian Pinera to encourage investments aimed at growing the economy of the world’s largest copper producer.
The company is in talks with China’s Sichuan Fulin Industrial Group, which has plans to construct a materials plant in Chile with an investment of $100 million in its first phase.
Fulin was one of the favored companies in a bid by Chile to develop investments linked to lithium in an agreement with local miners SQM and Albemarle in order to offer a preferential price for companies that operate in the country.
Three offshore wind farm projects in Belgium have received EU State Aid totaling Eur3.5 billion ($4.1 billion), the European Commission said Thursday.
The European Commission said Belgian plans to support three offshore wind farm projects were in line with EU state aid rules, and will further energy and climate goals without unduly distorting competition in the single market.
The 235-MW Mermaid, 252-MW Seastar and 219-MW Northwester 2 wind farm projects, located in Belgian territorial waters in the North Sea, will receive EU state aid.
The Commission said the projects were likely to help Belgium meet its target of producing 13% of its energy needs from renewable sources by 2020.
Saudi Arabia has shelved a $200 billion plan with SoftBank Group Corp (9984.T) to build the world’s biggest solar-power-generation project, the Wall Street journal reported on Sunday, citing Saudi government officials.
The logo of SoftBank Group Corp is displayed at SoftBank World 2017 conference in Tokyo, Japan, July 20, 2017.
No one is actively working on the project, and instead, the Saudi kingdom is working up a broader, more practical strategy to boost renewable energy, to be announced in late October, the WSJ reported
SoftBank Chief Executive Masayoshi Son had announced in March a plan to invest in creating the world’s biggest solar power project in Saudi Arabia, a project expected to have the capacity to produce up to 200 gigawatts (GW) by 2030.
Softbank declined to comment.
Russia’s Gazprom kicked off the construction of its first cryogenic filling station near Okulovka, Novgorod region, on the Moscow – St. Petersburg highway.
The cryogenic filling station will be used primarily for fueling heavy-duty trucks with LNG, Gazprom said.
Gazprom is constructing NGV refueling infrastructure along the M-11 highway, part of the North-South and Europe–China international transit routes, as part of the cooperation with Avtodor. A total of six cryogenic filling stations will be built there.
In October 2017, Gazprom and Avtodor signed the action plan to develop the gas filling infrastructure along the federal highways under the responsibility of Avtodor.
The projected highway traffic will be about 5,000 trucks a day, with some of them to be powered by LNG.
Europe–China international transit route is an investment project spanning Russia, Kazakhstan, and China, over 8,000 kilometers long.
Efforts to create natural gas filling infrastructure along the Europe–China route are being taken as part of the cooperation between Gazprom, CNPC, and KazMunayGas, as agreed in a memorandum signed on October 5, 2017.
https://www.lngworldnews.com/gazprom-start-building-lng-station-on-moscow-st-petersburg-highway/
The Ministry of Energy, Industry and Mineral Resources (MEIM) reaffirmed its plans to transform Saudi Arabia’s power sector to be more diversified, sustainable, competitive and efficient in accordance with Vision 2030.
Contrary to recent media reports, MEIM alongside the Public Investment Fund, SoftBank and other Kingdom’s stakeholders continue to work on a number of large-scale, multi-billion dollar projects relating to the solar industry. The long-term goal of these investments is to manufacture 200 GW of PV capacity by 2030. Investors, technical advisors, and contractors have been invited to take part in this program. Plans are also underway to develop shorter-term pilot projects.
Further detailing the Ministry’s role, during the 11th Annual Arab Energy Forum held in Marrakesh, His Excellency Abdulrahman Abdulkareem, Advisor to His Excellency Minister of Energy, Industry and Mineral Resources, outlined the Kingdom’s plan to become a global leader in solar energy and to develop $200 billion of investment opportunities in this promising sector.
MEIM has also outlined the power sector transformation plan which will be comprised of three main components:
Restructuring the power market to enhance its competitiveness for consumers and its attractiveness for private sector investments.
Transitioning the Kingdom’s fuel and technology mix to include a significant capacity of renewables, primarily solar, but also wind. There will also be substantive investment in new high efficient gas-powered generation capacity.
Investing, industrializing and localizing the full value chain of the power industry for domestic and export-oriented manufacturing of conventional power components and services as well as new technologies.
Key decisions regarding the transformation of the power sector have been taken, details of which will be announced in due course.
Europe will likely need more coal and natural gas this month as the region is spared the usual autumn storms.
A high pressure weather system is likely to reroute and block stormy weather that normally travels in easterly paths across northern Europe to boost the output from thousands of wind mills. That will leave the region relying on alternative power sources at a time when benchmark prices in Germany are already near a seven-year high.
“The storm track is usually over the U.K., north Germany and Scandinavia,” said Giacomo Masato, an analyst and meteorologist at Marex Spectron in London. “The high pressure moves away the storms and strongest winds from these areas. It could end being windless and warmer.”
Waning wind means power producers in Germany and the U.K. will need to fire up more of their their coal and gas plants to cover, potentially hampering the refill of gas storage sites before the coldest winter weather from December through February. Imports from the Nordic region to the rest of Europe will also be limited by low wind and the lowest hydro reservoir levels since 2010 after a dry summer.
With last month on track to be confirmed as the warmest September on record, the outlook for October is more mixed. Half of the six meteorologists surveyed by Bloomberg News expect cooler weather and the remainder forecast near normal to slightly above-average temperatures. The same conditions that are set to block windy weather in northern Europe could also stabilize temperatures, according to Peter Hocking, a meteorologist at Ubimet GmbH in Wein, Germany.
“There is a 70 percent chance of October being colder than average due to the presence of a stationary high-pressure system over western Europe pushing cold air over the continent,” Hocking said. “The jet stream, or winds very high up in the atmosphere, will split into two pathways over Europe, which will result in large-scale weather systems such as high-pressure systems moving very little.”
Germany's coalition parties agreed to pass the law for 8 GW additional wind and solar tenders this October after months of debate about the details for the subsidized measures.
Tender law was delayed as parties were split on details
Agreement was for 4 GW wind and 4 GW solar by 2020
Coalition also confirms 65% RES by 2030 target
Additional tenders for 2019 and 2020 were first included in the coalition treaty in February but with the caveat that the grid needs to be able to absorb the additional capacities, leading to speculation the tenders would get delayed because of slow progress on the grid expansion.
In a framework agreement between party leaders reached overnight into Tuesday, mainly focused on the diesel car compensation compromise, the coalition parties agreed to "quickly realize" the additional tenders with details to be passed by cabinet before the end of October.
It follows appeals by wind lobby groups warning of a sharp slowdown in wind turbine growth in 2019 and 2020 as fixed feed-in-tariffs end this year.
The measures would add 4 GW onshore wind and 4 GW ground-based solar projects to the already planned 6 GW of tenders for 2019 and 2020, it said.
It also includes an as yet undefined contribution by offshore wind maximizing already available onshore grid links before 2025.
In total, the additional renewables would reduce Germany's CO2 emissions by 8-10 million mt/year, the statement said adding that this would help to reduce the gap to the 2020 climate targets, which were scrapped in February.
The new statement also eased the grid caveat saying "more attention will be paid to a better synchronization between grid and renewables expansion" as well as promising measures to improve "public acceptance of onshore wind" amid planning delays for new projects due to new spatial planning rules.
The coalition parties also confirmed the higher 65% target for renewables' share in the power mix by 2030 to be made legally binding.
Chancellor Angela Merkel's coalition of CDU/CSU and SPD has struggled to progress any policies this year amid internal strife ahead of regional elections in the CSU's core region of Bavaria on October 14 with migration and the diesel compensation issue dominating the political debate.
Electricity prices in Mexico could drop by 40% by 2024 because of growing renewable capacity, according to a study released Wednesday by the Mexican Business Coordination Council (CEE), the country's largest business group.
Greater renewable generation capacity could lead to average locational marginal prices in Mexico of $38/MWh in 2024 from $64/MWh in 2017, according to the study co-authored by the Mexican wind and solar energy associations, AMDEE and ASOLMEX.
Renewable generation can make Mexico a more competitive country, Leopoldo Rodriguez, director of AMDEE, said on Wednesday at a release event for the study.
"It is clear CFE is contracting the lowest electricity prices in the world without investing a peso in new power plants," Rodriguez said. The price forecast assumes the country achieves its goal of generating 35% of its electricity from clean sources by 2024, he added.
In 2017, Mexico generated 69.4 GWh, or 21% of all of its electricity, from 22.3 GW of clean generation capacity, which represents 30% of its total capacity, data from Mexico's Energy Secretariat (SENER) shows.
As a result of the three long-term electricity auctions Mexico has held, the country will double its wind and solar generation capacity in the coming years from 11 GW of capacity in 2017, Rodriguez said.
The study is based on market data from long-term electricity auctions, self-supply projects and private bilateral power purchase agreements in Mexico since the energy reform was enacted three years ago, Rodriguez said.
"Data have shown renewable generation in Mexico has more than surpassed all our expectations," he added.
The study shows that levelized cost of electricity (LCOE) for renewable generation in Mexico can be lower than combined-cycle gas turbine (CCGT) plants.
While the LCOE for CCGT in Mexico is in a range of $42-78 MW/h, the estimated cost for wind is $19-67/MWh and for solar is $18-$66/MWh, the study found.
The study highlights that the final LCOE of power projects will depend on the quality of resources and the capacity of the companies to execute the projects efficiently.
However, to continue Mexico's exponential clean generation growth, the country needs to expand its transmission grid, Eduardo Reyes, an energy partner with PwC Mexico, said Wednesday.
Based on the SENER's latest long-term forecast the country requires 28 GW of new CCGT and 32 GW of clean generation capacity to meet its power demand in 2030.
Today, Mexico has 44 GW of CCGT and clean generation capacity under development applying for grid interconnection, Reyes said.
"All these projects won't be developed, but the number under development is substantial," Reyes said, adding that the interconnection demand surpasses the available interconnection capacity in the country by 12 times.
Expanding Mexico's transmission grid will allow the country to enhance the reliability of its electric system by enabling a higher flow of intermittent electricity among different regions, he added.
To expand the country's transmission grid, it will be key to attract and further open this segment to private investment, Reyes said.
Shares in Australian explorer Anson Resources (ASX:ASN) went ballistic on Wednesday after it announced it had produced its first lithium hydroxide product from its Paradox project in Utah, United States.
The product, said Perth-based company, was manufactured during precipitation test work carried out by Lilac Solutions on a 1,000-litre bulk sample extracted from the free-flowing Cane Creek 32-1 well.
With this development, the Australian miner has now produced both lithium carbonate and lithium hydroxide from Paradox, its flagship project.
With this development, Anson has now produced both lithium carbonate and lithium hydroxide from Paradox, its flagship project.
The miner said it was examining different production processes to assess the best recovery and purity results from the Cane Creek brines, which will also provide the best financial returns.
Lilac’s production process uses a newly developed technology that extracts only lithium from the brine using an adsorption methodology.
Other minerals present in the brine, including boron, bromide, iodine and magnesium are not recovered using this process.
However, Anson said that Colorado-based Hazen Research has already begun a series of bench-scale experiments to examine the potential extraction and purification of boron, bromide and iodine from a Cane Creek brine sample.
The company’s first vial of lithium hydroxide product from its Paradox project in Utah. (Image courtesy of Anson Resources.)
While test work is continuing with producing battery-grade lithium products, Anson’s managing director Bruce Richardson said the company was also looking forward to Hazen’s results.
“It is considered that the extraction of these minerals may not only provide additional revenue streams but also contribute to improving the quality and recovery of lithium carbonate and/or lithium hydroxide,” he said.
Shares in the company climbed about 35% to 12 Australian cents by 1:00 PM on the news, closing at 10 cents.
http://www.mining.com/anson-resources-produces-first-lithium-hydroxide-utah-project/
China’s top lithium producer Ganfeng Lithium, a supplier to carmakers such as Tesla and BMW, has priced its Hong Kong listing at the bottom of its marketed range, raising $421 million, according to a source involved in the deal.
Ganfeng priced its offering at HK$16.50 ($2.11) per share, the source said, at the bottom end of an indicative range of between HK$16.50 and HK$26.50 ($2.11-$3.38).
The company declined to comment.
The weak pricing comes at a time when an oversupply of lithium has pushed down prices even as demand for the metal is expected to increase as electric cars become more mainstream.
Hong Kong, on track for a bumper year of listings, has nevertheless seen a lot of them trade below their offering prices, with increasing Sino-U.S. tensions weighing on market sentiment.
The company could raise up to $448 million if a greenshoe, or over-allotment, option is exercised after shares begin trading on Oct. 11.
The Shenzhen-listed firm had earlier this year delayed plans to raise up to $1 billion in a Hong Kong listing as lithium prices had dropped sharply due to a raft of new supply that raised concerns about a short-term surplus.
But demand for lithium, a key ingredient in rechargeable batteries, is expected to rise in the long term as Tesla, Volkswagen and other manufacturers bring electric cars to the mainstream market.
Demand should also get a major boost as China, the world’s top auto market, aggressively promotes electric vehicles to combat air pollution and help domestic carmakers leapfrog the combustion engine to build global brands.
Ganfeng last month announced an agreement with Tesla to supply about 20 percent of its annual production to the electric carmaker’s battery suppliers. The agreement is valid until the end of 2020 and may be extended for three years.
It has also struck a five-year deal with BMW to supply its battery makers with lithium products.
Ganfeng plans to use proceeds from the Hong Kong listing to acquire lithium resources and expand its production capacity of lithium metals, batteries, compounds and recycling.
It secured six cornerstone investors including China Structural Reform Fund and South Korean battery makers LG Chem and Samsung SDI, who together have committed to buy $229.8 million in shares.
Chile’s antitrust court approved on Thursday a deal struck between Chilean regulators and Tianqi, allowing the Chinese miner to purchase a nearly one-quarter stake in lithium producer SQM.
Chilean antitrust watchdog FNE and Tianqi had presented the agreement, intended to limit the exchange of commercially sensitive information between the two companies, to Chile’s antitrust court in September.
It was approved by the five-member court without conditions.
“The approval of this extrajudicial agreement does not prevent third parties with a legitimate interest, who think that the facts in this agreement ... affect free competition, from taking whatever action they feel is most appropriate,” the court said in a statement emailed to Reuters.
The agreement stipulates that Tianqi cannot name any of its executives or employees to SQM’s board, and requires that the Chinese miner notify regulators of any future, lithium-related deal struck with either SQM or rival Albemarle.
In a statement, Tianqi said the deal ensured competition in the lithium market would be maintained.
“With this resolution, and considering the timeline, we anticipate the transaction will be completed in the last quarter of 2018,” Tianqi said.
SQM, which had objected to the deal on the grounds it did not go far enough to limit Tianqi’s access to corporate secrets and sensitive information, did not immediately reply to a request for comment.
Chile’s antitrust regulator launched an investigation in June, shortly after Tianqi said it would buy 24 percent of SQM for $4.1 billion, giving it a coveted stake in one of the world’s top producers of lithium, a key component in the batteries that power everything from cellphones to electric vehicles.
Beijing is aggressively promoting electric vehicles to combat air pollution and help China’s domestic carmakers leapfrog the combustion engine to build global brands.
Rio Tinto, the world’s second largest miner, has been talking to China National Nuclear Corporation (CNNC) about selling the state-owned company its stake in Namibia’s Rössing uranium mine.
While the mining giant has not officially acknowledged the negotiations with CNNC, Namibia’s energy minister Simeon Negumbo confirmed them to local paper The Namibian.
Rio has close to a 69 percent interest in the mine, the world's longest-running open pit uranium operation, while the rest is held by the Iranian Foreign Investment Company (15 percent), the Industrial Corporation of South African (10 percent), the government of Namibia (3 percent) and local interests (3 percent).
http://www.mining.com/chinese-interested-buying-rios-namibian-uranium-business/
The financial squeeze on India’s farmers is set to worsen because of record high fuel prices and surging costs of fertilisers, posing a challenge to Indian Prime Minister Narendra Modi in an election that must be held by May.
The rise in input prices could not have come at worse time for farmers, already grappling with falling domestic product prices due to rising yields and abundant harvests.
Yet, the government has few easy options to respond. Rival global producers have complained about Indian state support and falling global farm product prices undermine export prospects.
Indian farmers voted overwhelmingly for Modi in 2014. But a fall in rural incomes risks damaging that support next year.
Thousands of farmers marched on New Delhi on Tuesday to demand better prices for their produce. Police responded with teargas and water cannon. Farmers suspended their protests after talks with officials that ran into early Wednesday morning.
But their demands and those of other agriculture workers, who together make up about half India’s 1.3 billion people, have not gone away.
“Although we have decided to end our protest, we still believe that the government is not serious about addressing the concerns of the farmers,” Anil Talan, national secretary of farmers body Bhartiya Kisan Union, said after the march.
Diesel prices have surged 26 percent this year, making tilling fields, harvesting and transporting crops expensive for India’s 263 million farmers who mostly use diesel tractors.
Alongside rising diesel costs, prices of key fertilizers such as potash and phosphate have jumped nearly 15 and 17 percent respectively in a year, as companies pass on the rise in global prices and the impact of the weak rupee to farmers.
FILE PHOTO: A farmer arranges harvested tomatoes in a tractor trolley on the outskirts of Ahmedabad, India, February 7, 2018. REUTERS/Amit Dave/File photo
India, the world’s second-biggest producer of staples such as rice and wheat, imports all its potash needs and relies on foreign supplies for nearly 90 percent of the phosphate it uses.
“It’s a double whammy for farmers who have to bear the brunt of lower crop prices and higher input costs,” said Devinder Sharma, an independent food and trade policy analyst, saying this explained “why farmers’ anger has come to the fore.”
Diesel demand is rising as farmers have started harvesting summer crops. After tilling, they will plant wheat and rapeseed, the main winter crops.
Union official Talan said the government needed to prop up commodity prices and keep a lid on farmers’ costs to support the agricultural industry, which accounts for about 16 percent of India’s $2.6 trillion economy.
COUNTING THE COST
“Because of higher diesel prices I need to spend nearly 20 percent more on harvesting soybean but soybean prices have crashed this year,” said Uttam Jagdale, a farmer from Pune, about 150 km (94 miles) south of Mumbai.
Nilesh Sable, a cane farmer from Sangli in the western state of Maharashtra, said fertilizer prices were rising each month.
Fertilizer firms say they have little choice but to pass on at least some extra costs due to a sharp fall in the rupee and a 20 percent rise in international potash and phosphate prices.
“Still, we are not passing the entire burden to farmers,” said an official with a state-run fertilizer company, asking not to be named in line with government policy.
Greater farm efficiency is partly to blame. Mechanized farming, high-yielding seed varieties and increased use of pesticides have pushed up harvests. Output of most crops has soared to record levels each year.
India’s production of pulses, such as lentils and beans, surged to 24.51 million tonnes in the year to June 2018, up from 23.13 million tonnes in the previous 12 months.
Imports of pulses, such as lentils from Canada, Australia and Russia, fell to 1.2 million tonnes in the financial year to March 2019, the lowest since 2000/01 and well below the 6.6 million tonnes imported in 2016/17 after back-to-back failures in the monsoon.
Plentiful supplies extend to other crops. India is set to surpass Brazil as the world’s top sugar producer in the 2018/19 season, but rising output has driven down local sugar prices by 15 percent and left mills nursing losses.
In bid to help the sector, the government unveiled measures last week such as transport subsidies and incentives to export at least 5 million tonnes of sugar. Brazil, Thailand, Australia and other rival producers were quick to complain.
Vegetable prices, especially onions, cabbage and tomatoes, have also fallen 25 percent from last year, largely because of overproduction. Without enough refrigerated trucks, excess production cannot be stored.
Domestic milk prices dived more than 25 percent in the past year, but a global glut has made Indian exports uncompetitive.
Harish Galipelli, head of commodities and currencies at Inditrade Derivatives & Commodities in Mumbai, said India needed to find markets abroad to reduce its inventories.
“But exports will not be easy, as global prices are depressed, and there is no export parity for most commodities,” he said.
Barrick Gold Corp will seek Chinese investments in some of its African mines to offset higher risk stemming from its planned $6.5 billion all-stock acquisition of Africa-focused miner Randgold Resources, people familiar with Barrick’s thinking said.
Toronto-based Barrick will also lean on Randgold Chief Executive Officer Mark Bristow’s expertise in dealing with governments in challenging jurisdictions to navigate the Africa continent risk, the people said, addressing a concern of some Barrick shareholders.
The sources asked for anonymity because they were not authorized to publicly discuss the matter involving the world’s biggest gold miner.
Barrick’s African expansion is a departure from its recent strategy of focusing on relatively safe regions like the United States. Africa will represent about 30 percent of Barrick’s net asset value after the deal closes, up from some 15 percent, Desjardins Securities estimates.
Chinese involvement in Africa will likely include minority stakes or joint ventures in mines, the people familiar with Barrick’s thinking told Reuters.
China’s Zijin Mining Group and Shandong Gold said this week the deal provides additional opportunities to expand their partnerships with Barrick in Africa.
“The question for Barrick is, how do you balance the risk profile with the growth profile?” said David Neuhauser, managing director of U.S. hedge fund Livermore Partners and a Barrick shareholder, who supports the deal but recognizes the risks associated with Africa.
“Barrick’s potential partnerships with the Chinese could de-risk its African exposure,” he added.
A Barrick spokesman declined to comment. Randgold did not immediately respond to a request for comment.
Barrick’s executive chairman, John Thornton, a former Goldman Sachs banker, has been building relationships with Chinese miners as part of a plan to reduce exposure to risky jurisdictions. That work has intensified in recent years, notably with Shandong’s near billion-dollar investment in Barrick’s Argentine mine in 2017.
Barrick shares were down 1.5 percent by Friday afternoon, but still up about 6 percent since the deal was announced. Randgold shares have gained 10.7 percent since the deal.
‘PREFERRED RELATIONSHIP’
“It’s been a goal of ours to build a distinctive and preferred relationship with China,” Thornton said on a conference call on Monday.
Barrick unit Acacia Mining had been discussing an asset-level joint venture with Chinese miners, but two of the people said those talks have been put on hold. The potential Chinese partners are waiting for a tax issue with the Tanzanian government to be resolved, one of the sources said.
Thornton and Bristow first explored a partnership three years ago and renewed discussions this year, which was how the Randgold deal came together, the people added.
The two men hit it off. Frustrated with the mining industry’s poor performance, they share a philosophy that mining companies should be run with a disciplined focus on financials.
Bristow has said the caliber of mines offsets issues about location.
“I’ve always said asset quality overrides jurisdiction,” Bristow said on a conference call with analysts following the deal on Monday.
Some shareholders are betting that China, with its large African investments, would find it easier to deal with governments in the mineral-rich continent than Barrick would.
“If you are a Canadian company operating in Africa, you don’t have a ton of political pull,” said Greg Taylor, a portfolio manager at Purpose Investments and a Barrick shareholder.
“Certainly the Chinese are very active in their building of infrastructure. The Chinese partnership with Barrick would go a long way to add some moral suasion to the politicians.”
Small inverted head and shoulders on the GDX miners etf.
If Gold moves, then Silver is the play: here's Fresnillo.
The diamond trade must confront its tarnished image and revamp its certification scheme or risk seeing increasingly demanding consumers spurn natural stones in favor of cheaper synthetic diamonds, a senior U.S. official said.
Bloody African civil wars in the 1990s prompted diamond companies, governments and rights groups to come together to set up the Kimberley Process to prevent the sale of so-called “blood diamonds” from funding conflicts.
But the body only considers conflict stones to be those whose sales fund armed groups seeking to overthrow legitimate governments, a definition that does not cover a wide range of human rights and labor abuses.
Efforts to broaden the scope of the scheme have been stymied for a decade, civil society groups say, by member states including China, Russia and a number of African nations.
“(Consumers) probably think they’re getting anything from a green standard to a human rights standard to a high labor standard, and in fact none of that is really conveyed by the Kimberley Process,” Pamela Fierst-Walsh told Reuters on Monday.
Fierst-Walsh - senior advisor on conflict minerals for the United States, the world’s top consumer of diamonds - spoke as Kimberley Process members weigh reforms ahead of a meeting in Brussels in November.
She said failure to take action could threaten the future of the $14 billion global rough diamond trade.
“Consumers want more and we need to make sure they’re getting more. Otherwise ... they’re going to start buying those shiny synthetic diamonds that are super pretty and way less expensive,” she said.
SYNTHETICS GROWTH
Sales of rough laboratory-made diamonds stood at just $75 million to $220 million in 2016, the mean of which represented just 1 percent of the global value for rough diamonds, Morgan Stanley analysts said in a note.
But rapid improvements in quality and size mean that synthetic diamonds - which typically sell for 30 to 40 percent less than mined stones - will likely capture around 15 percent of the gem-stone market by 2020, the note said.
Competition from synthetic stones this year pushed De Beers, a unit of Anglo American and the world’s biggest seller of natural diamonds by value, to launch a company to sell its own laboratory-produced diamonds.
While the Kimberley Process is generally credited with curtailing the role diamonds once played in the funding of wars, critics say it has been ineffective in curbing other serious violence.
For example, human rights groups say government security forces killed at least 200 miners when they seized diamond fields in Zimbabwe’s eastern Marange region in 2008.
But after an initial suspension, the Kimberley Process allowed exports to resume in 2011 despite rights groups’ claims of ongoing abuses and smuggling. And several civil society organizations, including corruption watchdog Global Witness, have since withdrawn from the scheme.
“The fact that this blot on the reputation on diamonds ... is being exploited by the synthetics is waking a lot of governments and the industry up to the need for change,” said Ian Smillie, chair of the Ottawa-based Diamond Development Initiative.
India’s gold imports may rise in the fourth quarter as investors seek alternatives to faltering equity markets and a plunging rupee at the same time traditional buying will rise during the festival season, said multiple sources involved in the market.
Increased buying by the world’s second-biggest gold consumer would support global prices that have traded roughly near $1,200 an ounce since late August, but also widen India’s trade deficit and add to pressure on the Indian rupee, which fell to a record low on Wednesday.
In the fourth quarter of 2018, gold imports could rise 9 percent from a year ago to 250 tonnes, said Bachhraj Bamalwa, a bullion dealer based in Kolkata who was formerly the Chairman of the All India Gems and Jewellery Trade Federation.
“In the December quarter, festival demand would be robust. Investment demand is also gaining traction,” said Bamalwa.
Demand for gold usually strengthens at the end of the year on purchases for the traditional wedding season and major festivals including Diwali and Dussehra, when bullion buying is considered auspicious.
In the fourth quarter of 2017, India imported 229.6 tonnes of gold, according to metals consultancy GFMS.
Gold investment demand may rise as falling stock markets have prompted investors to diversify their portfolios, Bamalwa said.
India’s NSE equity index has fallen 7 percent from a record peak in August, while local gold futures have risen 6 percent since the recent low hit in mid-August.
“Rupee is consistently falling and we don’t know how much it will fall further. It is prompting investors to hedge their risk with exposure to gold,” said Daman Prakash Rathod, a director at MNC Bullion, a wholesaler in Chennai.
The rupee has fallen 13 percent in 2018, increasing the price for dollar-denominated bullion in rupee terms even as gold has dropped 7.6 percent this year.
REGAINING LUSTRE
Investment demand for gold had dwindled since 2014 as India’s equity markets rallied on optimism that Prime Minister Narendra Modi would rejuvenate the economy. An appreciating rupee also cut into demand at the time.
“Stocks have doubled in four years, but now investors think there is limited room for upside. So they are moving back to gold,” said Ashok Jain, proprietor of Mumbai-based wholesaler Chenaji Narsinghji.
Mangesh Parekh, an apparel merchant, bought two gold coins, each weighing 10 grams, last week.
“I have invested in stocks through mutual funds. Now since stocks are falling, I am parking a small amount in gold,” Parekh said.
Indians usually buy gold as jewellery, but investors prefer gold bars and coins to save on jewellery making charges.
India’s government has, in the past, raised import taxes on gold to bolster the rupee since it is seen as a non-essential commodity.
But that may not be a viable option as a hike in import duties could boost gold smuggling and black market sales, said Harshad Ajmera, a gold wholesaler in Kolkata.
Smugglers brought in about 120 tonnes of gold in 2017, with nearly the same amount expected in 2018 unless the government reduces import taxes, the World Gold Council estimated.
In 2013 India raised gold import taxes to a record 10 percent, while in 2017 it added a 3 percent sales tax.
For now, India’s finance ministry does not favour raising the tax but investors buying gold currently are expecting a better return if a duty is levied later, said the head of a bullion importing bank in Mumbai.
“If the government raises import tax by 3 percent as speculated, returns will go up by 3 percent. Gold becomes more attractive for investors,” he said.
China’s alumina exports are likely to boom in September as large numbers of orders made in July-August have yet to be fulfilled, SMM believes.
SMM research found that over 400,000 mt of alumina was ordered by buyers overseas in July-August. Data from the Customs showed that only 134,000 mt was exported for the same months. The gap is expected to be fulfilled in September-October.
Cooling stockpiling enthusiasm among international consumers, however, is expected to dwindle down the export volume in September.
FOB Australia alumina prices rose from the end of June to early September. SMM assessments showed that the prices averaged $640/mt as of September 7, up $200/mt or 45% from $440/mt recorded on June 28. In July-August, primary aluminium producers overseas stockpiled for the fourth quarter of year and this bolstered the prices.
As the stockpiling wave wound down, alumina prices declined in the past fortnight and stood at $535/mt as of September 28, down $105/mt or 16% from $640/mt.
https://news.metal.com/newscontent/100842092/jul-aug-orders-to-boost-sep-alumina-exports/
Chinese battery firm GEM Co Ltd on Friday said it was teaming up with four companies to invest a total of $700 million in a project to produce battery-grade nickel chemicals in Indonesia.
The investment comes as several global metals producers have also set their sights on Indonesia’s nickel reserves, looking to tap an expected surge in demand for the battery metal from the electric vehicle sector.
The companies joining GEM include units of top Chinese lithium battery maker Contemporary Amperex Technology Ltd (CATL) and stainless steel-maker Tsingshan Holding Group.
They aim to establish nickel smelting capacity of at least 50,000 tonnes per year at Tsingshan’s industrial park in Morowali on the Indonesian island of Sulawesi.
The project will also have 4,000 tonnes of cobalt smelting capacity, as well as churning out a range of battery chemicals, including 50,000 tonnes per year of nickel hydroxide intermediates.
“In the future, the product structure will be adjusted according to the global market demand and the production scale will be expanded,” GEM said in an emailed statement, without providing a launch date.
Japanese trading house Hanwa and Indonesia PT Bintangdelapan Group are the other firms involved in the project.
The partners will rely on Tsingshan, the biggest nickel producer in Indonesia, to provide the ore that will be processed to make the chemicals. Nickel is also used to make stainless steel.
A Hong Kong unit of Tsingshan will hold 21 percent of the project, with GEM subsidiary Jingmen GEM owning 36 percent. Brunp, the recycling arm of CATL, will hold 25 percent, with Hanwa on 8 percent and Indonesia Morowali Industrial Park (IMIP) on 10 percent. IMIP is a joint venture between Indonesia PT Bintangdelapan Group and Tsingshan.
Shenzhen-based GEM is best known as a battery recycler but in March announced a deal to buy around one-third of Glencore’s cobalt production over the next three years. It has previously been linked with a move for a stake in Vale’s Goro nickel-cobalt mine in New Caledonia.
Separately on Friday, GEM and Tsingshan held a groundbreaking ceremony for a joint-venture plant in Ningde, in southeastern China’s Fujian province, which will produce 70,000 tonnes per year of battery materials.
The plant involves initial investment of 1.85 billion yuan ($268.72 million), according to the GEM statement.
Zambia will introduce new mining duties and increase royalties to help bring down mounting debt and narrow its fiscal deficit, Finance Minister Margaret Mwanakatwe said on Friday.
Presenting a 86.8 billion kwacha ($7.10 billion) budget, Mwanakatwe said Zambia planned to trim its fiscal deficit to 6.5 percent of gross domestic product (GDP) in 2019 from 7.4 percent this year.
The economy of Africa’s No.2 copper producer was expected to grow at least 4 percent in 2019, around the same level as a forecast for this year, she said.
Mwanakatwe announced plans to increase the country’s sliding scale for royalties of 3 to 9 percent by 1.5 percentage points. The scale is adjusted so royalties are paid at higher levels as commodity prices climb and are reduced as prices fall.
A new 15 percent export duty on precious metals, including gold and gemstones, will be introduced, while copper and cobalt concentrate imports will incur a new 5 percent levy.
“As mineral resources are a depleting resource, it is vital to structure an effective fiscal regime for the mining sector to ensure that Zambians benefit from the mineral wealth our country is blessed with,” Mwanakatwe said.
Construction of an alumina project with annual capacity of 2 million mt in Fangchenggang, Guangxi, invested by Aluminum Corporation of China Limited (Chalco) was kicked off on Friday September 28, SMM learned.
Guangxi Huasheng New Materials would monitor the construction and operation of the project.
Premiums for Japanese aluminium shipments for the October to December quarter were set at $103 per tonne, down 22 percent from the previous quarter, as Asian spot premiums fell amid ample supply, four sources directly involved in the pricing talks said.
The new premium compares with the $132 per tonne premium in the July to September quarter and follows three quarters of rising premiums.
Japan is Asia’s biggest importer of aluminium and the premiums for primary metal shipments it agrees to pay each quarter over the London Metal Exchange (LME) cash price set the benchmark for the region.
“We’ve settled with all of our Japanese customers at $103 a tonne,” a source at a producer said.
“All contracts were signed at $103 per tonne last week after producers made a compromise to come down as there were no feeling of supply tightness,” another source at an end-user said.
The final price was below the initial offers of $112 to $115 per tonne made by producers.
Japanese buyers had sought lower levels as local spot premiums were hovering below $100 per tonne while suppliers had claimed that U.S. sanctions on Russian aluminium giant United Company Rusal and new import tariffs on the metal posed risks of supply tightness, the sources said.
“Basically, there has been enough supply in Asia mainly because many traders and users had secured extra ingots quickly after U.S. sanctions against Rusal in April, but easing of the sanctions boosted supply in the global market,” the second source said.
The United States on Sept. 21 extended the deadline for investors to divest holdings in Rusal.
Aluminium stocks held at three major Japanese ports have been rising since April, according to data provided by trading house Marubeni Corp.
“Many people in the industry expect the United States to cancel or further mitigate sanctions against Rusal after the U.S. midterm elections in November,” a third source at a buyer said.
The latest quarterly pricing negotiations began about a month ago between Japanese buyers and global producers, including Alcoa, Rio Tinto , and South32 Ltd.
Ivanhoe Mines soars on third major copper discovery in Congo
Shares in Canadian miner Ivanhoe Mines jumped Monday after it announced a significant new discovery of high-grade copper on its 100%-owned Western Foreland asset, west of the Kamoa-Kakula mining licence in the Democratic Republic of Congo (DRC).
The find, named Makoko, is Ivanhoe’s third major copper discovery in the DRC, as well as the first of multiple high-potential target areas identified by the company’s exploration team to be tested by drilling.
The company’s shares climbed in Toronto as much as 8.4 percent to C$2.98 on the news at 9:35 am, and were still trading 5.82% higher at C$2.91 by 11:49 am local time.
Ivanhoe began drilling Western Foreland in the third quarter of 2017, with most of the 50 holes drilled made in the Makoko area, a flat lying and near surface stratiform deposit, similar to its flagship Kamoa-Kakula project.
The find, named Makoko, is Ivanhoe’s third major copper discovery in the DRC, as well as the first of multiple high-potential target areas identified by the company’s exploration team to be tested by drilling.
The 6.75 sq. km discovery remains open in all directions, while the company continues drilling other targets on Western Foreland for high grade copper, Ivanhoe said.
“Given the early drilling success at Makoko, we are highly confident that we have the secret blueprint for additional exploration successes in the Western Foreland area in 2019 and beyond,” Ivanhoe executive co-chairperson Robert Friedland said in the statement.
Last month, a unit of Chinese state-run conglomerate CITIC became the biggest shareholder in billionaire Friedland’s company, following a decision to give up a 20% stake for about $548 million (C$723m).
Another Chinese firm, Zijin Mining Group — which acquired a stake in Ivanhoe Mines in 2015 through a wholly-owned subsidiary — exercised its existing anti-dilution rights through a concurrent private placement. This means that Zijin owns now 9.7% of Ivanhoe Mines.
Ivanhoe Mines estimates its flagship Kamoa-Kakula project, discovered in 2007, holds the equivalent of at least 45 million tonnes of pure copper. The company aims to extract 300,000 tonnes per year once the mine is operating at full tilt.
An initial, independent resource estimate for the Makoko copper discovery is expected to be completed in the current financial quarter.
http://www.mining.com/ivanhoe-mines-soars-third-major-copper-discovery-congo/
London Metal Exchange (LME) on-warrant aluminium stocks, metal not earmarked for delivery, are at their lowest since January 2006 at 608,050 tonnes — a far cry from the peaks hit over 2010-14.
Appearances, however, can be deceptive. There is a strong suspicion that erosion of LME inventory is as much to do with the exchange’s warehousing function as with market reality.
SHADOW STOCKS
Exchange stocks of any commodity are only ever part of the bigger inventory picture.
When LME aluminium stocks exploded in 2009, it was partly down to the immediate impact of slumping demand but also to the squeeze on credit, which forced those holding off-market inventory to deliver to the market of last resort.
And when those infamous load-out queues emerged at Detroit and the Dutch port of Vlissingen over the course of 2012-2014, the metal wasn’t going to a consumer but back to cheaper off-market storage.
The exchange’s multiple measures to deal with those queues simply accelerated a mass relocation of metal to the statistical shadows.
All of which makes it impossible to say with any certainty exactly how much inventory the aluminium market has been carrying. There are as many estimates as there are analysts.
But it is this metal, not LME-stored metal, that is the market of first resort for the physical supply chain.
It is being eroded, but there is no evidence yet of an availability crisis.
The LME three-month price, currently trading at $2,090 a tonne, is down 7.5 percent percent from the start of 2018.
Physical premiums are still unwinding from their post-sanctions highs. Fourth-quarter shipments to Japan, a benchmark for the Asian region, has just settled at $103 a tonne over LME cash metal, down from $132 in the third quarter.
As one Japanese buyer told Reuters: “Producers made a compromise to come down as there were no feelings of supply tightness.”
WAREHOUSING SQUEEZE
Rather than signalling a squeeze on aluminium, the scale of decline in LME inventory may be signalling a squeeze on its warehousing companies.
The cumulative effect of the LME’s queue-killing rule changes, particularly the cap on rents and faster load-out requirements, has been to reduce their ability to incentivise metal into their sheds.
And a good thing, too, many physical aluminium players will say.
The guaranteed income from long load-out queues allowed warehouse companies to outbid the physical market for fresh units.
With no structural load-out queues and this year’s elevated physical premiums, they cannot compete.
That’s a problem for those entities specialising in LME storage - witness the collapse of Worldwide Warehouse Solutions last July.
Warehouse operators have even lobbied for the exchange to relax its rules to allow longer queues; a suggestion that provoked outrage when it was floated past the exchange’s users committee.
INCENTIVE TO MOVE
In truth, warehouse operators may have only themselves to blame for the accelerated departure of aluminium from the LME system.
After the exchange broke the old queue model of warehouse revenue, operators evolved ever more ingenious ways to attract metal. One in particular, rent-sharing, may be behind moves out of LME storage.
A “lifetime” incentive allows someone delivering physical metal onto LME warrant and then selling it to receive a share of the warehousing rental until such time as the warrant is eventually cancelled by a new owner.
This not only limits the ability of the new owners to negotiate their own rental deals but raises uncomfortable questions about the flow of information between the warehouse operator and original seller with whom the rent is being split.
Concerns about such “back-ended” incentives led the exchange to issue a reminder in October 2016 that “the LME expects warehouses to maintain the confidentiality of information it holds on the stock of metal under warrant.” (“Guidance notice in relation to lifetime incentive arrangements”, Oct. 12, 2016).
Many market participants are unconvinced, opting for the easier solution of cancelling their metal and moving it out of LME storage as soon as they can.
WHAT GOES AROUND...
These new warehousing and stocks dynamics should not come as any surprise.
The LME itself accepted in its “Strategic Pathway” document of September 2017 that the result of its rule changes would mean that “less metal would be expected to reside in the LME system”.
“Indeed, this has been the experience of the market; stocks of metal in queued warehouses (...) have fallen significantly, and the outflowing metal has broadly not been re-absorbed into the LME system, given the inability of any other operator to pay a suitable incentive in the post-queues environment,” the report said.
In many ways we’re returning to the status quo that existed prior to 2008, when LME stocks were generally much lower than the amount of shadow inventory sitting off-market.
Given the right market incentive, as opposed to warehouser incentive, the metal will reappear when it is needed.
That much was clear in February, April and July this year, when tight time-spreads acted to draw aluminium back into the LME system.
But in terms of market signal, low LME aluminium stocks now are no more than the inverse of high aluminium stocks earlier this decade.
They say as much about the LME warehousing cycle as they do about the aluminium market cycle.
Hydro's alumina refinery Alunorte in Brazil announced today, October 3, that the plant is preparing for full curtailment of its operation. The decision was taken as the bauxite residue deposit area 1 (DRS1) is close to reaching its capacity, due to the embargo on the state-of-the-art press filter and the newly developed bauxite residue deposit area (DRS2).
Alunorte has been running at 50% production since March, following embargos from Brazilian authorities. Environmental authorities have confirmed that there was no spill or overflow from the residue areas. The embargos have prevented Alunorte from utilizing the newest bauxite residue deposit area (DRS2), which was under commissioning in February, as well as the state-of-art press filter technology, representing an investment of more than BRL 1 billion. The press filter is the most modern and sustainable technology for depositing bauxite residue, reducing the required storage area and environmental footprint. Alunorte has since the embargo made efforts towards authorities for permission to utilize the press filter, as well as DRS2, without success.
The Century Zinc Mine, which was officially re-opended last month, made revenue of A$27.2M from zinc concentrate sales in September.
The company earned $7.04M (A$9.8M) to date from production of 7,000 tonnes of zinc concentrate and $12.5M (A$17.4M) from the forward sale of 13,000 tonnes of October production.
Century says its first concentrate shipment to China is scheduled for the end of this month. Century is planning for a feed rate of about 8.0Mtpa into its processing plant.
In November 2017 the mine's owner, New Century Resources (ASX:NCZ), raised $52.9 million to restart.
The mine was the third largest zinc mine in the world prior to its closure in 2016 and still hosts mineral resources in excess of 2.6Mt of zinc, 0.7Mt of lead and 42.5Moz of silver.
http://www.mining.com/un-mothballed-century-mine-sells-a27m-zinc-concentrate-september/
Peru’s ability to post eight consecutive months of investment growth is calming fears that political woes would derail mining activity in the world’s second-largest producer of copper, zinc and silver.
Mining investment in Peru jumped 6.3% August compared with last year, to $395-million, according to the latest report by the- Energy and Mines Ministry. Investment in development and preparation, the first stages in building a mine, reached $63-million, the highest in more than four years.
"Peru has a natural geological potential that other countries don’t," said Ricardo Labo, a former deputy mines minister, in an interview. "But this political noise distracts from change; you can’t have ministers and vice-ministers distracted when they should be focused on vital issues like cutting back permitting."
Pedro Pablo Kuczynski quit as Peru’s President in March on the eve of an impeachment vote and his successor, Martin Vizcarra, has clashed with Congress as he grapples with one of the country’s biggest corruption scandals. Meanwhile, in the last two years, the country has had four mining Ministers and local communities have blocked access to several large copper mines.
Still, mining companies seem to be taking it all in stride: Since June, Anglo American, Minsur and Aluminum Corp of China have all approved the start of large investments.
“We’re expecting to get at least $21-billion of investments going in the next three years," Francisco Ismodes, the current energy and mines minister, said in an interview in Lima. “Given the international context, with demand forecast to support metal prices, we’re expecting sustained growth in investment."
In July, Anglo American approved the $5.3 billion Quellaveco project while Minsur okayed its $1.6-billion Mina Justa mine in September.
These projects are part of a $58.5-billion portfolio of mining investments that could double Peru’s copper output, Ismodes said. Next year, he expects Teck Resources to begin developing the $1.2-billion Zafranal copper project and First Quantum Minerals to start building its $2.8 billion Haquira mine.
Another project already helping lift investment in the country is Southern Copper’s expansion of the copper concentrator plant in Toquepala.
REGIONAL POLLS
All eyes will be on the results of regional and municipal elections across the country on October 7. Governors and mayors have been able to block projects in regions in the past. But now, surveys indicate that fewer candidates are campaigning on an anti-mining platform, according to a BTG Pactual research note.
"Unlike 2010 and 2014, when there were strong anti-mining contenders and winners, in some regions, we do not expect a similar outcome in this election," said Cesar Perez-Novoa, an analyst at BTG Pactual. "A market-positive outcome from these elections could potentially lead to an upgrade” in Peru’s pipeline.
This could be the case in Cajamarca, in northern Peru, where anti-mining politicians governed for years, blocking projects and resulting in a lack of investment and increasing poverty, Perez-Novoa said. A change in leadership in the region could accelerate stalled projects for Buenaventura and Southern Copper in the region, he added.
In Apurimac, in the south, political leadership will be key to ease tensions around the MMG Ltd-owned Las Bambas copper mine. The largest copper project developed recently in Peru has faced several road blockades from protesting local communities. The last one ended last month only after the government declared a 30-day emergency on 482 km of highway in the Andes mountains and deployed troops to help police restore order.
Peru has the potential to overtake Chile to become the world’s biggest copper producer, but it’s being held back by a lack of infrastructure and a ten-fold increase in permitting in the last seven years, said Juan Luis Kruger, chief executive officer at Minsur. The government can’t change the rules of the game and must make sure that the law applies to everyone, he said at a September 28 event in Lima.
"The main challenges are within the country," Kruger said. "We can’t have world class assets – billions of dollars in investments – that every day suffer blockades, blackmail and extortion, and that aren’t protected by the law."
Australia’s Axiom Mining on Wednesday said it was close to deciding on a partner to take nickel ore supplies from its mine in the Solomon Islands in exchange for finance.
Mining at the San Jorge project in the Pacific nation will start in December, with ore shipments expected to begin in the first quarter of next year, Axiom said in a statement.
The Solomon Islands approved a mining lease last month and ore loading facilities are currently being built, the firm said.
A previous mine finance arrangement with Gunvor Singapore, for A$5 million ($3.6 million) in funding and up to A$10 million towards mine construction, that was made in 2015 has now expired, Axiom said.
“With the recent grant of the mining lease there has been an increase of interest and demand from nickel ore consumers for Axiom’s San Jorge material,” it said.
The San Jorge mine is a nickel laterite ore deposit.
“Terms and conditions of proposed agreements continue to be refined and are in a final stage of negotiation,” Axiom said, without giving further detail.
China’s overseas expansion will spread over land that is home to more than half the world’s population, potentially boosting copper use by 1.6 million tonnes, or roughly 7 percent of annual demand, major miner BHP said on Thursday.
BHP has analysed the impact of China’s Belt and Road Initiative (BRI), a network of overseas construction projects, on commodity demand on the basis of a database it constantly updates.
It said China’s overseas expansion plan covered 115 partners across Eurasia, parts of Africa, Latin American and Oceania, up from 68 countries or regions it cited in a previous blog post in September last year.
Its latest analysis estimated the BRI represented one third of the global economy and would drive spending of up to $1.3 trillion over the decade to 2023.
Vicky Binns, BHP’s vice president for minerals marketing, told Reuters if anything the expectation an extra 1.6 million tonnes of refined copper would be needed over the same time period was conservative.
More than 70 percent of that demand is from 100 power projects, which typically are not the biggest source of copper consumption - accounting for between 13 and 22 percent of all copper use depending on the region.
Such initial investment could lead to knock-on demand from other sectors.
“Increasing the international competitiveness of manufacturing in these regions may create a major lift in future demand from copper intensive sectors, such as automobiles, consumer durables and machinery,” BHP says.
Binns downplayed the impact of mounting trade tensions between the United States and China on demand, saying long-term fundamentals were likely to be robust.
China is expected to be a major beneficiary of increased demand because of its massive copper smelting capacity, but Binns said BHP was also well-placed because it can develop its own capacity and work with junior players.
The major has said the commodities in which it seeks to expand are copper and oil and in September it bought a 6.1 percent stake in SolGold to get access to a promising copper-gold project in Ecuador. [nL3N1VQ5P6]
BHP, which operates the world’s largest copper mine Escondida in Chile, said in its 2018 report it derived 28 percent of its underlying earnings before interest, tax, depreciation and amortization from copper.
Its ranking varies from year to year, but said the latest figures make it the third largest copper company behind Chile’s Codelco and U.S.-based Freeport McMoRan.
An Indian court on Wednesday ordered an interim stay on the cancellation of land allotted for expansion of Vedanta’s south Indian copper smelter, in a relief to the conglomerate whose unit was shut on environmental grounds.
The Tamil Nadu state government ordered a permanent closure of the plant, canceled land allocated for expansion and disconnected power supply to the smelter in May following protests that turned violent and culminated in the police opening fire, killing 13 protesters.
“It appears the impugned order is passed as a knee jerk reaction,” the Madurai bench of the Madras High Court said in an order which provided interim relief to Vedanta. The case will be heard again on Oct. 25.
Protesters say the smelter was causing air and water pollution, and a risk to fisheries, and the plant has not been reopened ever since it was shut. India’s junior minister for water resources told lawmakers in July that the ground water in the area where Vedanta’s smelter is located contained heavy metals exceeding acceptable limits for drinking water.
Vedanta says the protests are based on false notions.
The company has sought a permanent injunction against the Tamil Nadu state government from interfering with the operations of its copper smelter, and India’s environment court in August ordered an independent probe to decide whether to allow Vedanta to reopen its copper smelter.
“We are happy that the high court has only considered the facts in the case and granted a stay to the state’s order which was purely made considering the people’s emotions,” P Ramnath, Chief Executive Officer of Vedanta Ltd’s copper unit Sterlite Copper said in a statement.
Production at BHP's Kalgoorlie nickel smelter restarted on Wednesday after a fire last month, a company spokeswoman said on Thursday.
"There was a fire at the BHP Nickel West Kalgoorlie Smelter on September 23 in the furnace building. The smelter is operating and production restarted again yesterday," the spokeswoman said in an emailed statement.
Vale, flush with cash from its booming iron-ore sales to China, is expected to approve a $1-billion expansion of a Brazilian copper mine later this month, according to a person with knowledge of the matter.
Building out the Salobo mine – known as the Salobo 3 project – would likely take about three years to complete and add about 50 000 t to capacity at the mine in Para state, the person said, asking to remain anonymous because the talks are confidential. Salobo currently produces about 200 000 t of copper a year.
The plan by the world’s largest iron-ore producer to invest in the new copper project comes as global copper stockpiles fall, while there has been growing consensus the copper market will be in deficit next year.
Rio de Janeiro-based Vale continues to reap the rewards of China’s surging demand for its low-cost, higher quality iron ore. At the same time, Vale is producing at record levels, while the depreciation of the Brazilian real is bolstering the company’s earnings. Vale’s success has allowed it to slash debt, increase dividends and use free cash to buy back shares.
At the end of August, Vale CFO Luciano Siani Pires said the company was planning to make a new copper announcement. In early September, BTG Pactual SA analystLeonardo Correa said Salobo 3 would cost Vale about $400-million, while $600-million could be funded by Wheaton Precious Metals Corp.; the Canadian streaming company has rights to a majority of Salobo’s gold, which is mined as a byproduct. Vale “lacks material growth opportunities, although there are several smaller projects that could be approved,” Correa wrote at the time, citing Salobo 3.
Vale declined to comment on Tuesday, while Wheaton said it would “welcome the opportunity to make an additional investment into an asset as high caliber as Salobo.”
“Any payment that we make to Vale is dependent on the scale and the timing of the expansion, and is only payable once the expansion is complete and up and running,” Wheaton CEO Randy Smallwood said in an emailed statement.
A week ago a local Brazilian newspaper reported Vale representatives met with officials in Para state, where Vale’s Amazon mining operations are located, and said the Salobo expansion could generate as many as 3 000 jobs.
Vale’s shares fell 0.3% to 61.01 reais as of 10:54 a.m. on Wednesday in Sao Paulo.
http://www.miningweekly.com/article/vale-is-said-close-to-approving-1bn-copper-expansion-2018-10-04
Demand for automotive aluminium is set to more than double by 2025, driven by surging growth in Asia, a senior executive at Novelis Inc, the world’s largest maker of rolled aluminum products, said on Thursday.
Automakers are turning to aluminium to replace high-strength steel, as well as combine with materials such as carbon fiber and plastics to produce lighter body panels for use in electric vehicles that meet stricter environmental standards.
“Typically what we see is an increase of aluminium percentage of the (automotive) body, which is why we’re projecting to grow from 1.5 million tonnes of aluminium demand this year to 3.5 million tonnes a year in 2025,” said Pierre Labat, vice president of global automotive at Novelis.
“We will continue to add new products in the years to come which make the value proposition of aluminium very compelling for strength and light weight,” he told Reuters.
Of the estimated 1.5 million tonnes of global automotive body sheet demand in 2018, Asia accounted for only about 10 percent, or about 150,000 tonnes, Labat said.
However, Asia is expected to be the fastest growing region in coming years and match European demand by 2025.
“China and the rest of Asia will almost grow from 10 percent to one third of global demand,” he said.
Amid heightening Sino-U.S. trade tensions, Novelis said in May it would double its automotive body sheet capacity in China in a bid to meet the country’s growing electric vehicle demand.
Labat said he does not expect “a lot of impact” from the intensifying trade row, adding that it was too early to say how it would affect aluminium demand.
“What we see, which is positive, is customers like Tesla that we serve in North America coming to China and opening new facilities in China. So this is going to increase aluminium demand in China,” he said.
The Atlanta-based company, owned by India’s Aditya Birla Group, supplies aluminum to automakers including Jaguar Land Rover and Ford Motor Co and also to drinks makers such as Coca-Cola.
While aluminium is lighter than steel, it is also more expensive, and steel has been fighting back with some car makers.
Labat said aluminium was increasingly used in automotive bodies such as doors, but would not replace steel completely.
“I think we are convinced that the world at least in the next 10 years will be multi-material architecture with aluminium tripling its size,” he said.
Uncertainty about how metals demand will be hit by trade wars, rising U.S. interest rates and a slowdown in China is weighing on industrial metals prices, submerging signals pointing to potential shortages.
The index of copper and five other top industrial metals traded on the London Metal Exchange has shed 11 percent this year while prices for the worst-performing metals, zinc and lead, have tumbled by about a fifth.
But as speculators pile on bearish positions and investors flee from the metals market during tit-for-tat trade volleys, signs of metals shortfalls are building.
Aluminium inventories are at their lowest in more than a decade and nickel’s have touched five-year lows while physical premiums for zinc have hit their highest level in six years.
The price of aluminium touched its highest in more than three months on Thursday, supported by worries over potential shortages after the world’s biggest producer of alumina announced a shutdown.
“The macroeconomic backdrop is pretty negative, and that has overwhelmed for the time being the tightening of supply/demand fundamentals,” said Robin Bhar, head of metals research at Societe Generale in London, speaking before the LME Week industry gathering that starts on Monday.
“In the meantime, prices are back in value territory, having fallen so far. The consumers are looking to put in hedges, do some physical buying as we go into Q4.”
HIGH VOLATILITY, LOW VOLUMES
Prices are off their lows, but high volatility means traders are holding only light positions, resulting in low market liquidity.
“You may get some decent news out one day and prices spike, but then the next day they can turn back down quite quickly. It’s one step forward and two steps backwards,” said Sucden Financial senior broker Liz Grant.
Many analysts and traders expect the macroeconomic fog to clear, allowing the tight supply backdrop to take centre stage and send prices higher.
They disagree, however, on the timing.
Michael Widmer at Bank of America Merrill Lynch expects copper to bounce to an average of $6,750 a tonne in the fourth quarter and $7,050 in the first quarter of next year, up 8 percent and 12 percent respectively from current levels.
However, Capital Economics expects copper prices to continue to hover around the $6,000 level for the rest of the year before gradually recovering to $6,500 by the end of 2019.
INVENTORIES SLIDE
Some of the most stark signals of how demand is outstripping supply are coming from the erosion of global inventories.
Global stocks of copper - a favourite of many investors because of its extensive use in construction, power and transport - have slid by nearly half over the past six months.
“If the market continues to see extreme tightening effects in the Chinese copper market, then that’s going to offset the negative effects from the ongoing trade war developments,” said Deutsche Bank analyst Nicholas Snowdon.
Aluminium inventories in LME-certified warehouses slipped below the 1 million mark last week for the first time since March 2008 and have tumbled 82 percent since touching a record 5.5 million tonnes in February 2014.
In China, the top consumer of industrial metals, zinc stocks in warehouses approved by the Shanghai Futures Exchange have slid to their lowest in more than a decade.
At the same time, premiums for buying physical material has soared for several metals, showing strong demand on the ground.
Premiums in China for copper SMM-CUYP-CN have soared 75 percent since mid-July to $120 a tonne while zinc premiums ZN-BMPBW-SHMET have more than doubled to $305 in the same period.
TRADE WAR EXAGGERATED?
While metals demand is largely healthy, fears about a global trade war are misplaced, said Dan Smith, head of commodities research at Oxford Economics.
“We’ve moved away from this period of very, very low tariffs, but in reality we’re nowhere near where we were in the bad old days,” he said.
Global average tariff rates peaked at more than 20 percent in the trade wars of the 1930s, but the current skirmishes have edged them up to only 3.04 percent, with a prospect of 3.76 percent if threatened tariffs are implemented, according to Oxford Economics research.
The Chinese government is already taking action to counter any damage to its economy from the trade war by cutting taxes, unleashing spending on infrastructure and easing credit.
“People are always looking to bet against China and keep getting it wrong. When you see (metals) prices get so low, then the balance of risk is being a bit optimistic,” Smith said.
Pan Pacific Copper, Japan's biggest copper smelter, said on Friday it plans to produce 296,800 tonnes of refined copper from October to March, up 11 percent from a year earlier.
Pan Pacific Copper (PPC) is 67.8 percent-owned by JXTG Holdings Inc and 32.2 percent-owned by Mitsui Mining and Smelting Co Ltd.
Following are details of PPC's output plan, with comparisons against estimated production in the first half of the financial 2018/19 year and actual production in the second half of
2017/18.
(Copper in tonnes, gold and silver in kilograms): H2 FY18/19 H1 FY18/19 H2 FY17/18 Copper 296,800 301,000 267,400 Gold 17,800 18,900 15,700 Silver 156,800 166,400 150,600
NMDC has increased iron ore prices owing to a rise in demand in the international and domestic markets as well as higher steel and pellet rates.
The company said that lump ore price has been increased by Rs 300 from Rs 3,550 per tonne to Rs 3,850 per tonne, and fines price by Rs 200 from Rs 3,110 per tonne to Rs 3,310 per tonne.
This is the second time that prices are being increased in September, with the first one being its regular price announcement during the first half of the month.
The price hike is applicable to the Karnataka mines also. Basant Poddar, former chairman and member of Federation of Indian Mineral Industries (FIMI) South, said as global and domestic steel prices are strong, this move is in the right direction.
He added that the reasons for price hike are rains, less production in Eastern India coupled with robust demand along with very strong steel and sponge iron prices.
He also said that these price hikes may have very little impact on price realisation until the government curbs imports and steel companies start procuring iron ore only from locals.
Up to August 2018, NMDC’s total production was 9.85 million tonnes while the sales was 11.05 million tonnes. The additional quantity was supplied from the inventory which piled up in Karnataka.
While Chattisgarh sales stood at 8.17 million tonnes against production of 6.17 mt, sales at Karnataka was 2.87 mt against production of 3.68 mt.
China rail coal shipments were 1.57 billion tonnes climbing 10.1% over Jan-Aug, NDRC
Rio Tinto and its joint venture partners, Mitsui & Co (8031.T) and Nippon Steel & Sumitomo Metal (5401.T), will spend about $1.55 billion to maintain production capacity at two iron ore projects in Western Australia.
Rio will invest a total of $820 million to develop the projects at the Robe River Joint Venture in Australia’s mineral rich Pilbara region, the Anglo-Australian miner said in a statement on Monday.
Rio said the investments would enable it to sustain production of its Pilbara Blend brand of iron ore and its Robe Valley lump and fines products.
The move follows similar announcements by rivals BHP Billiton and Fortescue Metals.
“It’s really about production replacement,” said Rohan Walsh, investment manager at Melbourne based Karara Capital.
“(It’s) generally expected that all the major Australian iron miners face the need to invest in projects to sustain current production rates from 2020 onwards,” he said.
In June, BHP gave the go-ahead for a $2.9 billion spend on its huge South Flank iron ore expansion, while Fortescue said in May it would spend $1.28 billion to build up its higher grade Eliwana project also in the Pilbara.
Australian miners and Brazil’s Vale SA have been shipping record amounts of ore to China as it seeks higher grades to offset stricter environmental regulations.
Investors are still waiting for Rio Tinto’s decision as to whether it will approve development of its Koodaideri site in the Pilbara, which would mark a key expansion in its production volumes.
Rio said the two new projects will be serviced by 34 existing haul trucks that are retrofitted with autonomous technology. Subject to approvals, construction of both projects was expected to start next year.
The project funding has been included in Rio’s replacement capital guidance of around $2.7 billion from 2018 to 2020.
The move comes as Rio has been selling off its coal assets, with a view to focusing on its core commodities, such as iron ore.
The work is expected to create about 1,200 jobs, the miner said. Rio Tinto owns 53 percent of the Robe River Joint Venture.
The company’s Australian shares were flat at midday in a broader market down 0.6 percent .
After hitting a snag earlier this year, Nippon Steel & Sumitomo Metal's bid to acquire Indian steelmaker Essar Steel India is gathering steam again, raising hopes -- and some fears -- over the Japanese steel producer's future.
Steelmakers around the world are competing for a slice of the fast-growing Indian market. Nippon Steel has also made its bid for Essar, India's fourth-biggest steelmaker, central to its midterm business plan.
Nippon Steel's current plan runs from fiscal 2018, which started in April, to fiscal 2020. Many market participants view its strategy in the South Asian country favorably. But even if Nippon Steel's purchase of Essar goes through, the price is likely to be higher than it anticipated. This has raised concerns among some market players the Japaneses steelmaker may overpay.
Nippon Steel teamed up with Luxembourg-based ArcelorMittal, the world's biggest steelmaker, to take part in the bidding that began in February to select investors to bail out financially troubled Essar.
The Nippon Steel-ArcelorMittal alliance is believed to have submitted an initial bid of about 300 billion rupees ($4.15 billion). The takeover attempt stalled after Essar's creditors committee decided that ArcelorMittal was ineligible to bid. But on Sept. 7, India's National Company Law Appellate Tribunal conditionally declared Nippon Steel and ArcelorMittal eligible, removing a major obstacle to the purchase.
Essar is an attractive prize for steelmakers that have set their sights on the Indian market.
"If we build a blast furnace from scratch, it will cost nearly 1 trillion yen ($8.91 billion). Furthermore, it will take time to complete the necessary procedures, such as certification," said a Nippon Steel executive. Buying a company that already has a furnace will save time and money.
The Indian steel market is growing rapidly, driven by strong demand from automakers, infrastructure builders and construction companies. India's annual crude steel production exceeded 100 million tons for the first time in 2017, and the market has strong growth potential, with per capita steel consumption still only around one-tenth that of China.
But while the business tribunal's ruling opened the door to Nippon Steel-ArcelorMittal's acquisition of Essar, concerns have grown among market participants since ArcelorMittal announced on Sept. 11 that it was reviewing the bid. Indian media reports said that ArcelorMittal raised its bid for Essar to about 420 billion rupees and the European steelmaker hinted that the reports were correct.
Nippon Steel has not disclosed details, such as the proposed acquisition price.
Many market participants think that under the revised takeover proposal, Nippon Steel's investment in Essar is likely to total between 250 billion and 300 billion yen. "The acquisition will involve taking over Essar's debts, purportedly worth hundreds of billions of yen, as well as investing in the company," said Atsushi Yamaguchi of Japan's SMBC Nikko Securities.
"If [the Nippon Steel-ArcelorMittal alliance] acquires Essar after further raising its bid, it will become difficult [for Nippon Steel] to recoup its investment," Yamaguchi said.
Nippon Steel tripled its budget for business investment, such as acquisitions, under its current midterm business plan to about 600 billion yen, compared with the previous three-year plan that ended in fiscal 2017. But an official at a Japanese securities company said, "If Nippon Steel does not restrict the amount of money it spends on Essar to 300 billion yen or less, it will have few options left for other acquisitions."
It is unclear how the bidding war for Essar will play out. Among the Nippon Steel-ArcelorMittal tandem's rivals is Numetal Mauritius, in which Russia's VTB Capital has an equity stake. Numetal and Indian steel juggernaut JSW Steel submitted a joint bid for Essar in the second round of bidding. Japan's JFE Holdings holds an equity stake in JSW.
If Nippon Steel wants to remain among the big players in the global steel industry, it cannot bow out of the takeover battle for Essar easily. India's steel market is expected to grow faster than any in the world. If Nippon Steel loses Essar to a rival, its effort to tap into that market will suffer a big setback.
On the other hand, if Nippon Steel overextends itself to buy Essar, the risk could be even greater. Nippon Steel's stock price has been relatively flat recently, perhaps reflecting concerns about the effect of the takeover bid on its bottom line.
Although a one-to-one comparison is not possible because Nippon steel switched to International Financial Reporting Standards in fiscal 2018, Nippon Steel expects its pretax profit to rise this year, helped by higher steel prices. But the company's estimated price-earnings ratio remains around 8, considered low for the industry, partly due to concerns about a trade war. Even if Nippon Steel is able to buy Essar under the current terms, the Japanese steelmaker's shares may not rise if it cannot spell out how it will recoup its investment.
https://asia.nikkei.com/Business/Markets/Nippon-Steel-raises-stakes-in-bidding-war-for-India-s-Essar
Key merchant miners in Odisha are looking at scaling up their iron ore mining capacities because of robust demand. Apart from the firm demand from end-use industries, buoyancy in prices is spurring miners to expand output.
KJS Ahluwalia, a major non-captive miner, has sought green clearance to raise capacity at its Nuagaon iron ore mines from 5.62 million tonnes per annum (mtpa) to 7.99 mtpa. The miner is also keen to install a beneficiation plant with two-mtpa capacity along with crusher and screen plants. The facilities are to come up within the miner’s leasehold area.
Aditya Birla Group-owned Essel Mining & Industries Ltd, too, has proposed to enhance the capacity of its Koira iron ore mines from four to six mtpa. The public hearing for the proposed expansion is scheduled for October 30.
Besides, Thakurani Iron Ore Mines, under the leasehold of Kaypee Enterprises, has sought to expand its production capacity from 5.5 to 7.99 mtpa.
“Demand continues to be strong in both the domestic and international markets. Miners are scaling up to meet the enhanced demand as outlook is firm”, said a mining industry source.
According to a recent report by CARE Ratings, iron ore production in the country is projected to strengthen by two-to-five per cent in this financial year on stable demand from infrastructure and automobile industries. Iron ore production in the last financial year was 210 million tonnes, a growth of nine per cent year-on-year.
Of late, iron ore prices have been on a rampage in the domestic market. NMDC Ltd, the largest producer, announced its second price hike for September recently. The central PSE raised the price of lumps by 8.4 per cent to Rs 3,850 per tonne, and those of fines by 6.43 per cent to Rs 3,310 a tonne.
The company ascribed the price hike to lower production due to rains, robust demand for ore and firming up of steel and sponge iron prices.
Iron ore fines prices have soared 80 per cent in Odisha between June and September despite international prices staying range bound. Fines prices till the last round of hike soared from Rs 1,862 to Rs 3,350. Lumps prices, too, had moved up 29 per cent in the period under review, increasing from Rs 4,094 to Rs 5,300 per tonne. By contrast, prices of benchmark Fe-62 grade fines inched up moderately from $63.95 to $66.2 per tonne.
Some end-user industries in Odisha feel merchant miners were pressuring iron ore prices by producing below the approved EC (environment clearance) limits. Odisha is the biggest iron ore producer- the state logged 102 million tonnes of output in 2017-18.
The state has an approved iron ore mining capacity of 163.8 mtpa. Of this, the merchant or non-captive lessees have approvals to mine 118.35 mt. In FY18, 26 non-captive miners in the state despatched 67 mt, denoting 65.79 per cent of their approved EC (environment clearance) limit of 101.96 mt. Iron ore despatches have been well below the agreed EC limits as between FY14 and FY18, they never exceeded 70 per cent.
China’s Hebei province, the country’s biggest steel producer, will force all its mills to comply with strict new emissions standards by 2020 as part of its campaign against air pollution, according to newly published industry guidelines.
In a policy document, the provincial environmental protection agency said newly built steel producers will be forced to comply with “ultra-low” emissions restrictions starting from 2019, while existing firms will be given until October 2020 to meet the new standards.
Particulate matter emissions will need to be kept within 10 micrograms per cubic meter, sulfur dioxide within 35 micrograms and nitrogen oxides within 50 micrograms, according to the document, which has been circulated by industry consultancies and reviewed by Reuters.
The new standards are more stringent than the state limits, which stand at 40, 180 and 300 micrograms respectively.
Hebei province, which surrounds the capital Beijing, is routinely the location of six of China’s 10 smoggiest cities, and has been on the front line of the country’s war on pollution, now in its fifth year.
As part of the campaign, it has shut down or suspended millions of tonnes of steel and cement production capacity, curbed coal consumption and imposed restrictions on traffic. It has also set up reward and punishment mechanisms in order to encourage local governments to comply.
The province aims to bring concentrations of hazardous floating particles known as PM2.5 to 55 micrograms by 2020, down from 65 micrograms last year, although still above the state standard of 35 micrograms.
According to data published by the provincial government on Monday, average PM2.5 levels in Hebei stood at 31 micrograms in September, down 40.4 percent on the year, and the lowest monthly level on record.
Rebar prices have started rising in the Tokyo market after producers adopted a firm stance on prices, market sources said Tuesday.
The current market price of base-sized rebars in Tokyo is around Yen 74,000-75,000/mt ($650-$650/mt), up Yen 1,000/mt from a week ago, sources said.
A Tokyo-based distributor said rebar prices had been stable since spring until the latest increase began.
"Producers have been taking strong stances on their prices, claiming higher input costs from October such as for electrode, power and distribution fees. Customers acknowledge this and have finally started accepting higher prices," he said.
"But previous hikes by producers have not been fully absorbed in the market and we expect producers to make additional hikes soon -- we need to accelerate and lift our prices to secure profit margins," he said.
Japan's largest rebar producer Kyoei Steel lifted its rebar prices by Yen 2,000/mt for September and has since said it will leave prices for October unchanged while it waits for that hike to be fully absorbed, but also flagged that another price hike was possible in coming months.
Another distributor in Tokyo said the rebar supply-demand balance was tight, with producers struggling to meet demand.
"We don't see any change in stance by producers -- customers will have to accept higher prices to secure their needs," he said.
Japan produced 689,500 mt of small bars in August, up 1.2% year on year but down 5.3% from July, latest Japan Iron & Steel Federation data showed.
The government has directed Coal India and its subsidiaries to give priority to power plants in fuel supply as plants are grappling with acute coal shortage, an official said.
"Coal and Railway Minister Piyush Goyal in a video conference asked Coal India and its arms to prioritise power sector," the official said.
The CMDs of all subsidiaries of Coal India (CIL), and the CMD of NTPC along with others were part of the video conference held on September 22, the official said.
Mahanadi Coalfields Ltd (MCL) in a letter said in view of the acute shortage of coal at power plants, it was decided in the meeting that rakes will be loaded only for power plants.
After meeting the requirement of power plants, "CPSUs like RINL, Nalco and SAIL (RSP) are to be loaded until the crisis is over", the letter said.
A fall in the generation of thermal power, wind and hydro-power due to multiple factors has spiked power rates in spot markets in the last two weeks.
Power tariff on Sunday touched a decade high of Rs 17.61 per unit on the Indian Energy Exchange due to low hydro and wind energy production and coal shortage at thermal plants.
According to sources, captive power plants (CPPs) were grappling with the issue of coal shortage. CPPs generate electricity for their own manufacturing facilities like steel, cement and others.
According to the Central Electricity Authority data, as many as 19 thermal plants had coal stocks of less than seven days of consumption as on September 27.
Coal India accounts for over 80 per cent of the domestic coal output.
Brazilian prosecutors in Minas Gerais state said on Tuesday they reached a final compensation deal with mining companies Samarco, Vale and BHP Billiton regarding a 2015 dam burst, Brazil’s largest ever environmental disaster.
According to a statement from prosecutors released late on Tuesday, the deal allows for compensation payments to start to relatives of the 19 people killed in the disaster, as well as to people who lost their houses and other properties.
No financial details of the deal were disclosed in the short statement on Tuesday, but the chief prosecutor in the city of Mariana will hold a press conference on Wednesday to discuss the agreement.
Brazil’s worst environmental catastrophe happened when a dam designed to hold back mine waste from the Samarco iron pellets operation in Mariana burst, leaving a trail of destruction for hundreds of kilometers in Minas Gerais and Espírito Santo states.
Another deal had been reached by the mining companies and prosecutors in regions hit by the disaster away from Mariana, where victims found that offer insufficient. With this last settlement, companies might be able to prepare to resume operations in the region more than two years after the accident.
Vale has said it expects the Samarco unit to resume operations in 2018 or early next year, but has pushed back forecasts several times.
The mine still needs permits to reopen, and the lack of a clear timeline makes it harder for the controlling companies to renegotiate the debt Samarco will carry from the disaster.
The steel industries of Mexico and Canada on Tuesday urged their governments to resolve a tariff dispute with the United States before signing a new trilateral trade deal that was unveiled this week.
In late May, the Trump administration announced tariffs of 25 percent on steel imports and 10 percent on aluminum imports, prompting quick retaliation from top trading partners including Canada and Mexico.
Late on Sunday, the United States and Canada reached a deal to overhaul the North American Free Trade Agreement (NAFTA), complementing an accord the Trump administration brokered with Mexico, the third member of NAFTA, in late August.
Mexican steel producers association Canacero welcomed the new trade pact, called the United States-Mexico-Canada Agreement (USMCA), but said it viewed “with concern” the ongoing steel dispute and the “serious situation” it created for the industry.
U.S. President Donald Trump said on Tuesday that U.S. steel and aluminum tariffs would remain in place for Canada and Mexico until they “can do something different like quotas, perhaps.”
In a statement, Canacero said it supported efforts to find a solution to the impasse before the leaders of Mexico, the United States and Canada signed USMCA, which officials say could happen at a G20 summit at the end of November.
If no solution can be found, Mexico should put tariffs on U.S. steel to level the playing field, Canacero said.
Mexico has already slapped tariffs on U.S. pork, bourbon, motor boats and other products. Canada has levied tariffs on a range of U.S. imports, including steel and aluminum.
Joseph Galimberti, president of the Canadian Steel Producers Association, said he expected Canada’s government to continue to support the industry after the USMCA breakthrough.
“There is clearly an opportunity to constructively engage the United States between the achievement of a deal in principle and the ratification or signature of that deal,” he said.
Canada is the top exporter of steel and aluminum to the United States. The United Steelworkers of Canada adopted a less conciliatory tone after the new trade deal was announced, calling it a “sell-out” for Canadian workers.
Mexican officials have said they hope the steel and aluminum dispute can be resolved before USMCA is signed.
Since the tariff row broke out, Mexican steel exports to the United States had fallen 30 percent on average, Canacero said.
Atlantic Basin iron ore blast furnace pellet premiums for cargoes in October remained steady, with growing expectations of increases in premiums charged for 2019 and any additional spot tons procured beforehand. A $73/dry mt premium was heard agreed by a CIS pellet producer, based on fourth-quarter volumes into specific quarterly pricing contracts. This was not considered more broadly reflective of the wider market, where earlier headline premiums were being extended at “benchmark levels of $58/dry mt,” a buyer said.
Business for small volumes under contract was described as less significant with wider Brazilian, Canadian and Swedish pellet trade.
S&P Global Platts Monday assessed estimated Atlantic monthly contract blast furnace pellet premiums at $58/dmt for October, steady from September.
Pricing normalized to 65% Fe pellets rose 7.39 cents/dry mt unit to $1.6604/dmtu in October.
Sources familiar with the region related to $73/dmt sales were not immediately able to confirm such business, with one starting the underlying premium for regional acid pellets was $56/dmt and there was no change.
Chinese import spot pellet premiums recently in the high $80s/dmt, may have led to a Q4 contract premium in the middle of the $56-$90/dmt range, a CIS source said.
A buyer believed premiums were moving higher or 2019, but had yet to see any increase imposed on delivered in Q4. Earlier Q3 spot demand was not yet confirmed for Q4, although Indian pellets may be available for desperate users paying higher levels than top tier high CCS and lower impurity material under contract.
Platts Atlantic blast furnace pellet assessment reflects the premium charged for top tier contract 65% Fe pellet with lower silica than the China spot import grade, specified at 3%.
Alumina is at 0.5%, while CCS is higher at 275 and low temperature disintegration over 6.3 mm, at 80%; sizing over 9 mm greater than 94%; and sizing below 6.3 mm smaller than 2.5%.
Platts assessed pellet price takes into account Platts IODEX 62% Fe iron ore fines prices on a monthly average netback to Brazil for the previous month as its pricing basis. It uses Platts spot Capesize freight rates between Brazil and China for the same assessment.
The pellet price is adjusted for quality to 65% Fe by adding to IODEX a multiple of the 1% Fe differential monthly average, also for the previous month.
Platts 1% Fe differential between 60%-63.5% Fe grades rose to $1.343/dmt in September, from $1.338/dmt in August.
Pricing for 65% Fe fines over IODEX saw the differential remain high in September, at $27.225/dmt, from August’s $27.031/dmt.
DR PREMIUMS
Direct-reduction grade premiums continue to find support on demand from direct reduced iron plants in the Middle East and North Africa, with Egypt and Algeria in need of supplies.
Platts on Monday assessed October direct reduction iron ore pellet premium at $62.50/dmt, stable from September, based on 67.5% Fe grade, with the premium applied to a 65% Fe base.
The spread between 62% Fe IODEX and 65% Fe fines remains wide.
This was said to be a key factor in discussions for 2019 DR pellet pricing, where moving the basis of pellet pricing to 65% Fe, and taking this outright spread into account for new contract premiums may be considered, a buyer said.
Over 2017, the spread between 62% Fe IODEX and 65% Fe fines was around $16/dmt, while over January to September 2018, the spread has averaged at just over $21/dmt.
Negotiations for 2019 premiums in contracts for DR-grade may be still early to see concrete talks, source said.
Preliminary information may be received and exchanged for now, and a move to discuss pricing may not occur until November.
To aid planning and budgeting, current underlying changes in BF pellet premiums in the spot market, and how this may be applied in DR premiums, were being considered.
Pellet premiums were shaping expectations for margins with steel prices after a year of healthy margins for DRI-based steel plants.
Tight DR pellet supply is leading to lump ore usage at one major DRI producer, with premiums for lump ore also considered low enough to justify use.
Global miner Glencore and Japan’s Tohoku Electric Power agreed on a price of $109.77 per tonne for supplies of thermal coal from Australia for the year through September 2019, according to a source with direct knowledge of the matter.
The agreed price, which serves as an industry benchmark for supplies of seaborne thermal coal in Asia, was 16 percent higher than the contract for the year through September this year.
Glencore has two annual supply contracts with Japanese utilities but talks with Tohoku Electric on supplies for April 2018-March 2019 broke down earlier this year, forcing other utilities to set their own prices in the opaque market.
Australian spot thermal coal prices have traded around six-year highs in recent months, pushed up by a summer heatwave across the northern hemisphere as well as output cuts in China, the world’s biggest consumer of coal.
With annual imports of around 115 million tonnes, Japan is one of the world’s biggest importers of thermal coal. Its utilities buy about 40 percent of all Australian thermal coal exports.
But volumes under long-term contract have been declining as utilities try to diversify supply sources and trade more in the spot market as part of Japan’s energy market liberalisation.
The deal would see the U.S. miner acquire 80% of its Colombian peer to expand its global footprint
U.S. miner Peabody Energy Corp. has held discussions to buy Colombian peer Drummond International LLC, people familiar with the matter said, cementing a swift comeback from bankruptcy for America’s largest coal producer.
It is unclear how advanced the talks are or if the two sides will reach an agreement.
The potential deal would see Peabody acquire 80% of Drummond International, Colombia’s top coal exporter, leaving the remaining 20% in the hands of Japanese trading house Itochu Corp., the people familiar with the matter said. The deal could be valued at between $4 billion and $4.5 billion, according to one of the people. Itochu paid $1.5 billion for the 20% stake in Drummond in 2011.
Peabody was pushed into bankruptcy in 2016 by large debts and lower coal prices, and emerged from the process last year. Its revival comes as the price of thermal coal, which is used to generate power, hits its highest levels in several years. The coal industry has also been backed by President Donald Trump, who has replaced Obama-era climate policies with new rules to help coal-burning power plants.
Diversified giant BHP on Thursday confirmed that it had reached an agreement with the State Prosecutor of Mariana in Minas Gerais, in relation to compensation for the impact of the Samarco dam failure in 2015. However, the miner said that operations were unlikely to restart next year.
The miner told shareholders that the agreement outlined the process and principals for the negotiation and implementation of the Renova Foundation of the formal compensation programme for those people impacted in Mariana.
Reuters earlier reported that the deal allows for compensation payments to start to relatives of the 19 people killed in the disaster, as well as those who lost their houses and other properties.
No financial details of the deal were disclosed in the short statement made by prosecutors earlier this week, or by BHP.
“To date, the Renova Foundation has been providing compensation and support to many of the individuals in Mariana who have been imapcted by the dam failure,” BHP said on Thursday.
While BHP said that a restart of operations in 2019 was highly unlikely, Samarco has said that it expected to obtain the licences needed to resume operations next year.
India’s Supreme Court allowed ArcelorMittal SA (MT.AS) and NuMetal to bid for debt-ridden Essar Steel [ESRG.UL] after clearing their outstanding dues within two weeks, according to a court ruling on Thursday.
The world’s largest steelmaker, which recently raised its bid for Essar Steel, is forming a joint venture with Japan’s Nippon Steel & Sumitomo Metal Corp (5401.T) in competition with NuMetal, a company led by Russian lender VTB (VTBR.MM), and Vedanta Resources.
The embroiled Essar Steel was among a dozen of the country’s largest debt defaulters that were pushed to bankruptcy court last year after a central bank order aimed at clearing a bad loan mountain at the nation’s banks that is choking new lending.
"We give one more opportunity to both (ArcelorMittal & NuMetal) resolution applicants to pay off the NPAs (non-performing assets) of their related corporate debtors within a period of two weeks from the date of receipt of this judgment," the court order said here
The order added that upon meeting the deadline, the companies can resubmit their resolution plans but if they are not “found worthy of acceptance,” Essar Steel shall go into liquidation.
ArcelorMittal and NuMetal did not immediately respond to Reuters’ request for comments.