Aspate of large-scale street protests around the world, from Chile and Hong Kong to Lebanon and Barcelona, is fuelling a search for common denominators and collective causes. Are we entering a new age of global revolution? Or is it foolish to try to link anger in India over the price of onions to pro-democracy demonstrations in Russia?
Each country’s protests differ in detail. But recent upheavals do appear to share one key factor: youth. In most cases, younger people are at the forefront of calls for change. The uprising that unexpectedly swept away Sudan’s ancien regime this year was essentially generational in nature.
In one sense, this is unsurprising. Wordsworth expressed the eternal appeal of revolt for the young in The Prelude, a poem applauding the French Revolution. “Bliss was it in that dawn to be alive, But to be young was very Heaven!” he declared. Wordsworth was 19 years old when the Bastille was stormed.
Yet while younger people, in any era, are predisposed to shake up the established order, extreme demographic, social and political imbalances are intensifying present-day pressures. It is as if the unprecedented environmental traumas experienced by the natural world are being matched by similarly exceptional stresses in human society.
There are more young people than ever before. About 41% of the global population of 7.7 billion is aged 24 or under. In Africa, 41% is under 15. In Asia and Latin America (where 65% of the world’s people live), it’s 25%. In developed countries, imbalances tilt the other way. While 16% of Europeans are under 15, about 18%, double the world average, are over 65.
Most of these young people have reached, or will reach, adulthood in a world scarred by the 2008 financial crash. Recession, stagnant or falling living standards, and austerity programmes delivered from on high have shaped their experience. As a result, many current protests are rooted in shared grievances about economic inequality and jobs. In Tunisia, birthplace of the failed 2011 Arab spring, and more recently in neighbouring Algeria, street protests were led by unemployed young people and students angry about price and tax rises – and, more broadly, about broken reform promises. Chile and Iraq faced similar upheavals last week.
This global phenomenon of unfulfilled youthful aspirations is producing political timebombs. Each month in India, one million people turn 18 and can register to vote. In the Middle East and North Africa, an estimated 27 million youngsters will enter the workforce in the next five years. Any government, elected or not, that fails to provide jobs, decent wages and housing faces big trouble.
Numbers aside, the younger generations have something else that their elders lacked: they’re connected. More people than ever before have access to education. They are healthier. They appear less bound by social conventions and religion. They are mutually aware. And their expectations are higher.
That’s because, thanks to social media, the ubiquity of English as a common tongue, and the internet’s globalisation and democratisation of information, younger people from all backgrounds and locations are more open to alternative life choices, more attuned to “universal” rights and norms such as free speech or a living wage – and less prepared to accept their denial.
Political unrest deriving from such rapid social evolution is everywhere. Lebanon’s “WhatsApp revolution” is a perfect example. Yet some protests, such as those in Hong Kong and Catalonia, are overtly political from the very start.
FacebookTwitterPinterestYoung Hong Kongers face familiar problems over scarce jobs and high rents. But by taking on China’s authoritarian regime, they have assumed pole position in a struggle against autocratic “strongman” rulers everywhere. Their campaign has international resonance, which is why China’s President Xi Jinping fears it.
It is difficult, if not perverse, to watch protesters risking torture and death by challenging Egypt’s dictator, Abdel Fattah el-Sisi, and not relate their daring both to Hong Kong and, say, to Kashmiris’ efforts to throw off the yoke imposed by another “strongman”, India’s Narendra Modi. When Palestinian youths taunt the Israel Defence Forces with flags and stones, are they not part of the same global fight for democratic self-determination, basic freedoms and human rights espoused by young Muscovites opposing Vladimir Putin’s cruel kleptocracy?
In this sea of protest, a common factor is the increased willingness of undemocratic regimes, ruling elites and wealthy oligarchies to use force to crush threats to their power – while hypocritically condemning protester violence. Repression is often justified in the name of fighting terrorism, as in Hong Kong. Other culprits include Saudi Arabia, Turkey, Myanmar and Nicaragua.
Another negative is the perceived, growing readiness of democratically elected governments, notably in the US and Europe, to lie, manipulate and disinform. Distrust of politicians, and resulting public alienation, is the common ground on which stand France’s “gilets jaunes”, Czech anti-corruption marchers and Extinction Rebellion. As William Hazlitt, the 18th-century essayist and celebrated mocker of Wordsworth might have said, disbelief is the new spirit of the age.
Perhaps these protests will one day merge into a joined-up global revolt against injustice, inequality, environmental ruin and oppressive powers-that-be. Meanwhile, spare a thought for a different type of protest – the one you never hear about – and what that may entail. The stifling silence that hangs over North Korea’s gulag, China’s Xinjiang and Tibet regions, and dark, hidden places inside Syria, Eritrea, Iran and Azerbaijan could yet descend on us all. What helps protect us is the noisy, life-affirming dissent of the young.
https://www.theguardian.com/world/2019/oct/26/young-people-predisposed-shake-up-established-order-protest
Indonesia’s nickel miners agreed on Monday to stop nickel ore exports immediately, the country’s investment agency chief Bahlil Lahadalia said, after Jakarta last month brought forward a ban on shipments to January 2020 from 2022.
Exports due to be shipped from Indonesia, the world’s biggest nickel ore producer, will be bought by local smelter operators at an international price level, Lahadalia said.
“This agreement was carried out not on the basis of a letter from the government or technical ministry, but a joint agreement,” Lahadalia said. “Where the agreement is carried out by the nickel association with us the government.”
Indonesia’s government in September expedited the ore export ban by two years as part of its efforts to boost expansion of a local smelting industry.
Expectations of the Indonesian ban have pushed nickel CMNI3 prices on the London Metal Exchange (LME) up nearly 40% to around $17,000 a tonne now. In September, they hit a five-year high of $18,850 a tonne.
A spokesman at the mining ministry, which issues regulations on ore exports, said he could not immediately comment.
Lahadalia, who was appointed last week by President Joko Widodo in his new cabinet, said nickel companies agreed not to export ore based on “collective awareness” to create added value to Indonesian resource exports by processing them onshore.
Nickel smelters have been having problems buying raw material for their plants since Indonesia announced it was moving forward the ore export ban to January.
China’s Tsingshan, the biggest smelter operator in Indonesia, will cut production by 20% starting in November due to scarcity of ore and as the rainy season begins, to maintain its levels of ore inventory, said a company official in Jakarta.
Alexander Barus, executive director at PT Indonesia Morowali Industrial Park, Indonesia’s largest nickel industrial park -where Tshingshan operates - said smelters in Morowali were ready to buy ore from miners.
“We will buy according to our stockpile capacity and when the specification and prices are suitable,” Barus said after attending the meeting with the investment agency chief.
Meidy Lengkey, secretary general of Indonesian Nickel Miners Association, told Reuters that miners were fine with the export stoppage as long as the government helps to support domestic ore prices.
“We are supportive, but prices given to miners should be fair,” she said.
Miners have complained that local smelters are pricing nickel ore at much lower price compared to those exported.
The mining ministry said they will revise pricing rules to put a floor price for ore.
A poll conducted during LME week in London on Monday October 28 showed that both gold and nickel were voted as metals with the greatest potential for 2020, each garnering 27% of votes.
Copper, with 23% of votes, was runner-up.
Offshore, LNG buoy Baker Hughes in third quarter
Baker Hughes CEO Lorenzo Simonelli, left, comments about the new branding logo of Baker Hughes with the downgrading of GE ownership, as Chief Marketing and Technology Officer Derek Mathieson, right, listens during an interview with company officials at their offices Thursday, Oct. 3, 2019 in Houston, TX. CONTINUE to see recent earnings from area energy companies. less Baker Hughes CEO Lorenzo Simonelli, left, comments about the new branding logo of Baker Hughes with the downgrading of GE ownership, as Chief Marketing and Technology Officer Derek Mathieson, right, listens ... more Photo: Michael Wyke / Contributor Photo: Michael Wyke / Contributor Image 1 of / 39 Caption Close Offshore, LNG buoy Baker Hughes in third quarter 1 / 39 Back to Gallery
Offshore work and liquefied natural gas projects helped to buoy Houston oil field service company Baker Hughes during the third quarter.
In an early Wednesday morning statement, Baker Hughes reported posting a $57 million profit on nearly $5.9 billion of revenue during the third quarter. The figures were higher compared to the $13 million profit on nearly $5.7 billion of revenue during the third quarter of 2018.
This year’s this quarter figures translated into earnings per share of 21 cents for stockholders, which were higher compared to the 3 cents per share during the same time period last year.
Baker Hughes nonetheless missed Wall Street expectations of $6.1 billion of revenue and earnings per share of 24 cents.
Shale Slump: Oil field service sector braces for more pain
The company's earnings report come at time when $50 per barrel crude oil prices have created a drilling slump in shale fields across the United States and Canada that has sent the rest of the oilfield service sector hemorrhaging with losses.
In a statement, Baker Hughes CEO Lorenzo Simonelli said the company delivered a solid quarter based on contract wins from it turbomachinery and oilfield equipment divisions as well as improved margin from its oilfield services division.
Among the contract wins, Norwegian oil company Vår Energi tapped Baker Hughes to provide 16 underwater production systems in the Balder X field of the North Sea.
Venture Global LNG also awarded Baker Hughes a contract and granted a notice to proceed with construction for the Calcasieu Pass LNG export terminal in Louisiana.
A major oil company selected Baker Hughes as its sole artificial lift provider in the Permian Basin while Saudi Aramco signed a five-year contract with the Houston company for services in Saudi Arabia.
"Overall, we are very pleased with our execution as a team, and we believe Baker Hughes is firmly on the right path financially, operationally, and strategically,” Simonelli said.
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With roots in Texas going back to 1907, Baker Hughes now employs more than 64,000 people in 120 nations. The company reported a $195 million profit on nearly $23 billion of revenue during 2018.
The earnings report comes roughly seven weeks after Boston industrial conglomerate General Electric reduce its ownership stake to around 40 percent, allowing Baker Hughes to become an independent company.
Seizing upon that momentum, Baker Hughes rolled out a new logo in early October and rebranded itself as an oilfield technology company.
Read the latest oil and gas news from HoustonChronicle.com
The US military has conducted an operation against elusive Islamic State leader Abu Bakr al-Baghdadi, a US official says, as President Donald Trump prepares to make a "major statement" at the White House.
The official, speaking on condition of anonymity, was unable to say whether the operation against Baghdadi was successful.
Newsweek said it had been told by a US Army official briefed on the raid that Baghdadi was dead.
It said the operation took place in Syria's northwestern Idlib province, and was carried out by special operations forces after receiving actionable intelligence.
The official, speaking to Reuters, did not disclose details of the operation and other US officials contacted by Reuters declined to comment. The Pentagon did not immediately respond to a request for comment.
White House spokesman Hogan Gidley announced late on Saturday that Trump would make a "major statement" at 9am US eastern time on Sunday.
Gidley gave no further details as to the topic of Trump's statement.
The president gave an indication that something was afoot earlier on Saturday night when he tweeted without explanation, "Something very big has just happened!"
Trump has been frustrated by the US news media's heavy focus on the Democratic-led impeachment inquiry, which he calls an illegitimate witch hunt.
He has also faced withering criticism from both Republicans and Democrats alike for his US troop withdrawal from northeastern Syria, which permitted Turkey to attack America's Kurdish allies.
Many critics of Trump's Syria pullout have expressed worries that it would lead the Islamic State militancy to regain strength and pose a threat to US interests. An announcement about Baghdadi's death could help blunt those concerns.
Baghdadi was long thought to be hiding somewhere along the Iraq-Syria border. He has led the group since 2010, when it was still an underground al-Qaeda offshoot in Iraq.
On September 16, Islamic State's media network issued a 30-minute audio message purporting to come from Baghdadi, in which he said operations were taking place daily and called on supporters to free women jailed in camps in Iraq and Syria over their alleged links to his group.
At the height of its power Islamic State ruled over millions of people in territory running from northern Syria through towns and villages along the Tigris and Euphrates valleys to the outskirts of the Iraqi capital Baghdad.
But the fall in 2017 of Mosul and Raqqa, its strongholds in Iraq and Syria respectively, stripped Baghdadi, an Iraqi, of the trappings of a caliph and turned him into a fugitive thought to be moving along the desert border between Iraq and Syria.
US air strikes killed most of his top lieutenants, and before Islamic State published a video message of Baghdadi in April there had been conflicting reports over whether he was alive.
Rick Perry: World “awash” in crude, thanks to U.S. shale output
By Anthony DiPaola and Manus Cranny on 10/27/2019
DUBAI (Bloomberg) --Global markets are “awash” in crude thanks to the surge in U.S. oil output, and the boom looks set to continue, U.S. Energy Secretary Rick Perry said in a Bloomberg TV interview.
U.S. shale production has turned the world “on its head,” and Goldman Sachs Group Inc. is “off a bit” in a report last week saying that the bonanza is fading, Perry said on Sunday in Dubai.
Oil and natural gas from American shale fields have made the U.S. one of the world’s largest producers and enabled it to become a net energy exporter. Perry will travel in the coming week to Saudi Arabia to discuss possible sales of U.S. liquefied natural gas and Saudi efforts to develop a nuclear power program. Perry held talks in the United Arab Emirates and visited the country’s largest solar-power facility at a site near the U.A.E.’s commercial hub of Dubai.
The U.S. sent 11 LNG shipments to the U.A.E. over the past three years and is seeking to sell more of the fuel there and to Saudi Arabia, Perry said.
The world needs to be prepared for attacks disrupting the global economy, and the U.S., Saudi Arabia and other allies are discussing the safety of oil supply routes, he said. Aerial strikes against Saudi oil facilities on Sept. 14 temporarily knocked out half of the kingdom’s output, and the U.S. is currently doing enough to help Saudi Arabia defend against such attacks in the future, Perry said.
Washington won’t hold a grudge forever against Saudi Arabia over the murder last October of government critic and U.S. columnist Jamal Khashoggi, though there’s not a “massive amount of forgiveness” in Congress for his killing in the Saudi consulate in Istanbul, Perry said.
The energy secretary said he asked U.S. President Donald Trump to call Ukraine to try to sell U.S. LNG there. The approach to Ukraine is important for energy sales and to break that country’s over-reliance on Russian gas, he said.
The U.S. is “making progress” with its Middle East foreign policy, while efforts to impeach Trump won’t be an issue in the U.S. presidential election next year and will go away in six months, Perry said.
Related News ///
FROM THE ARCHIVE ///
WASHINGTON — The Federal Reserve wants to know what the internet is worth to you.
The answer could help the central bank solve one of the most puzzling paradoxes of the modern economy: The current expansion is the longest in history, yet productivity gains are weak and GDP growth, while steady, is far from stellar.
In a speech this week, Fed Chairman Jerome Powell raised the possibility that the problem is with the data itself. GDP measures the value of products and services that are bought and sold. But many of the greatest technological innovations of the internet age are free. Search engines, e-mail, GPS, even Facebook — the official economic statistics are not designed to capture the benefits they generate for businesses and consumers.
"Good decisions require good data, but the data in hand are seldom as good as we would like," Powell said.
Instead, Powell cited recent work by MIT economist Erik Brynjolfsson, one of the leading academics on the intersection of technology and the economy. In a paper with Avinash Collis of the National Bureau of Economic Research and Felix Eggers of the University of Groningen in the Netherlands, the authors conducted massive surveys to estimate the monetary value that users place on the tools of modern life.
The results? The median user would need about $48 to give up Facebook for one month. The median price of giving up video streaming services like YouTube for a year is $1,173. To stop using search engines, consumers would need a median $17,530, making it the most valuable digital service.
The authors also conducted more limited surveys with students in Europe on other popular platforms. One month of Snapchat was valued at about 2.17 euros. LinkedIn was just 1.52 euros. But giving up WhatsApp? That would require a whopping 536 euros. Twitter, however, was valued at zero euros.
"Over time, we're spending more and more of our waking hours interacting with the internet or using those services on our mobile phones," Brynjolfsson told CNBC. "A bigger share of our economy is being missed by GDP."
Brynjolfsson is advocating an entirely new measure of economic health that calculates benefit rather than output. He calls it GDP-B and estimates that the welfare gains from Facebook alone would have added 0.05 to 0.11 percentage points to its annual growth.
"What we really care about if we want to know how well off people are is the consumer surplus — how much benefit you get — not how much you actually pay," Brynjolfsson said.
Inside the Fed, a separate effort is underway to value the digital economy. Powell also highlighted research by David Byrne and Carol Corrado that uses the volume of data transmitted through broadband, cable and WiFi to estimate the value of online products and services. Their analysis shows that GDP would have been half a percentage point higher over a decade if the full scope of the digital economy had been incorporated.
"The highly visible innovations in consumer content delivery raises the question of whether existing national accounts are missing consequential growth in output and income associated with content delivered to consumers via their use of digital platforms," the authors say in their paper.
Powell delivered his speech at an annual convention of economists, where the theme was integrating old and new economies. At one point, Powell even waxed philosophical.
"How should we value the luxury of never needing to ask for directions?" he asked. "Or the peace and tranquility afforded by speedy resolution of those contentious arguments over the trivia of the moment?"
The answers to those questions may not be far off.
A new winter plan to curb emissions in northern China will not be enough to reverse last year’s sharp increase, official data shows, raising concerns that a weakening economy is eroding Beijing’s resolve to tackle pollution.
In an action plan for October 2019 to March 2020, China said 28 smog-prone northern cities, including the capital Beijing, would have to curb emissions of lung-damaging small particles known as PM2.5 by an average of 4% from a year ago.
The particles are a major component of the smog that engulfs China’s northern regions over winter as people switch on coal-fired heating systems.
However, the targeted decrease is 1.5 percentage points lower than an earlier draft, and would not be enough to reverse a 6.5% surge throughout the Beijing-Tianjin-Hebei region over the same period last year.
Last year’s jump came even though authorities targeted a cut of 3%, with efforts derailed by warmer weather and an increase in industrial activity after regions were given more flexibility to devise their own anti-smog measures.
This year’s lowered ambitions mean that as many as 15 of the 28 cities could have higher levels of smog than two years ago, even if they meet their targets, said Lauri Myllyvirta, senior analyst with Greenpeace.
An environment ministry official acknowledged last week that China’s pollution situation was still “serious”, with PM2.5 in the region up 1.9% in the first three quarters.
In setting this year’s targets, China had to consider “maintaining stability” as well as “actual working conditions” in each location, the official said in a statement, adding that there were risks the goals would not be met.
Only four of the 28 cities - Beijing, Handan, Cangzhou and Jining - met targets last winter, official data showed.
PM2.5 levels in Anyang, China’s most polluted city last winter, soared 13.7% last year. It is targeting a 6.5% cut this year. Nearby Puyang will target a 6% fall this year, even though its average PM2.5 surged more than 20% a year ago.
The environment ministry has been at pains to say China’s “war on pollution” would not be affected by a slowing economy, with local governments no longer judged merely on crude economic growth.
But there have already been signs Beijing will compromise, with Premier Li Keqiang saying earlier this month that China remains dependent on coal and will encourage clean and green mining.
China’s coal imports are also set to rise more than 10% this year, driven by loosened customs restrictions aimed at boosting the economy, analysts said.
“The lower air quality targets seem to reflect changed priorities,” said Myllyvirta. “The policymakers have let smokestack industries rebound, even if it means slowing progress on air quality.”
As many as a million Chileans protested peacefully late into the evening on Friday in the capital Santiago in the biggest rallies yet since violence broke out a week ago over entrenched inequality in the South American nation.
Protesters waving national flags, dancing, banging pots with wooden spoons and bearing placards urging political and social change streamed through the streets, walking for miles (km) from around Santiago to converge on Plaza Italia.Traffic already hobbled by truck and taxi drivers protesting road tolls ground to a standstill in Santiago as crowds shut down major avenues and public transport closed early ahead of marches that built throughout the afternoon.
By mid-evening, most had made their way home in the dark ahead of an 11 p.m. military curfew.
Santiago Governor Karla Rubilar said a million people marched in the capital - more than five percent of the country’s population. Protesters elsewhere took to the streets in every major Chilean city.
“Today is a historic day,” Rubilar wrote on Twitter. “The Metropolitan Region is host to a peaceful march of almost one million people who represent a dream for a new Chile.”
Some local commentators estimated the Santiago rally well over the million mark, describing it as the largest single march since the dying years of the dictatorship of Augusto Pinochet.
Chile’s unrest is the latest in a flare-up of protests in South America and around the world - from Beirut to Barcelona - each with local triggers but also sharing underlying anger at social disparities and ruling elites.
Protests in Chile that started over a hike in public transport fares last Friday boiled into riots, arson and looting that have killed at least 17 people, injured hundreds, resulted in more than 7,000 arrests and caused more than $1.4 billion of losses to Chilean businesses.
Chile’s military has taken over security in Santiago, a city of 6 million people now under a state of emergency with night-time curfews as 20,000 soldiers patrol the streets.
Clotilde Soto, a retired teacher aged 82, said she had taken to the streets because she did not want to die without seeing change for the better in her country.
“Above all we need better salaries and better pensions,” she said.
Chile’s center-right President Sebastian Pinera, a billionaire businessman, trounced the opposition in the most recent 2017 election, dealing the center-left ruling coalition its biggest loss since the country’s return to democracy in 1990.
But as protests ignited this week, Pinera scrapped previous plans and promised instead to boost the minimum wage and pensions, ditch fare hikes on public transportation and fix the country’s ailing health care system.
“We’ve all heard the message. We’ve all changed,” said Pinera on Twitter following the peak of the rallies. “Today’s joyful and peaceful march, in which Chileans have asked for a more just and unified Chile, opens hopeful paths into the future.”
Still, many protest placards, chants and graffiti scrawled on buildings around the city call for his exit.
MULTICOLORED CROWD
As crowds of colorful demonstrators stretched along Santiago’s thoroughfares as far as the eye could see, the noise of pots and pans being clanged with spoons, a clamor that has become the soundtrack for the popular uprising, was ear-splitting.
“The people, united, will never be defeated,” the crowds chanted over the din.
By early evening there had been no signs of violence or clashes with the security forces, who maintained a significant but low-key presence inside paint-spattered and stone-dented armored vehicles parked in side streets.
Beatriz Demur, 42, a yoga teacher from the suburb of Barrio Brazil, joined a stream of demonstrators shuffling toward Plaza Italia with her daughter Tabatha, 22.
“We want Chile to be a better place,” said Demur. “The most powerful have privatized everything. It’s been that way for 30 years.”Eyeing the crowds packing the square, her daughter said: “I have waited for this a long time ... It’s not scary, it’s exciting. It means change.”
Anali Parra, 26, a street hawker, was with her daughter Catalina, 9, and five-month-old son Gideon Jesus, his buggy decked in streamers and an indigenous Mapuche flag.
“This isn’t going to go away,” Parra said. “Pinera should just go now.”
‘URGENT’ REFORMS
On Friday morning, trucks, cars and taxis had slowed to a crawl on major roads, honking horns and waving Chilean flags. “No more tolls! Enough with the abuse!” read bright yellow-and-red signs plastered to the front of vehicles.
Many bus drivers in Santiago also staged a walk-off on Friday after one of their number was shot.
While much of wealthy east Santiago has remained calm under evening lockdown, the poorer side of the city has seen widespread vandalism and looting.
Pinera told the nation on Thursday he had heard the demands of Chileans “loud and clear.”
Chilean President Sebastian Pinera on Saturday added a major cabinet reshuffle to a growing list of reforms he has promised to tame inequality and quell mass protests that have rocked the South American nation.
October 25, 2019 18:58:46
Source: Xinhua News Agency
Xinhua News Agency, Beijing, October 25th The Political Bureau of the Central Committee of the Communist Party of China conducted the 18th collective study on the status quo and trend of blockchain technology development on the afternoon of October 24. In his study, General Secretary Xi emphasized that the integrated application of blockchain technology plays an important role in new technological innovation and industrial transformation. We must take the blockchain as an important breakthrough for independent innovation of core technologies, clarify the main direction, increase investment, focus on a number of key core technologies, and accelerate the development of blockchain technology and industrial innovation.
Chen Chun, a professor at Zhejiang University and an academician of the Chinese Academy of Engineering, explained the issue and discussed opinions and suggestions.
The comrades of the Political Bureau of the CPC Central Committee listened carefully to the explanations and discussed them.
General Secretary Xi delivered a speech while presiding over the study. He pointed out that the application of blockchain technology has extended to digital finance, Internet of Things, intelligent manufacturing, supply chain management, digital asset trading and other fields. At present, major countries in the world are accelerating the development of blockchain technology. China has a good foundation in the field of blockchain. It is necessary to accelerate the development of blockchain technology and industrial innovation, and actively promote the development of blockchain and economic and social integration.
General Secretary Xi stressed that it is necessary to strengthen basic research, enhance the original innovation ability, and strive to let China take the leading position in the emerging field of blockchain, occupy the commanding heights of innovation, and gain new industrial advantages. It is necessary to promote collaborative research, accelerate the breakthrough of core technologies, and provide safe and controllable technical support for the development of blockchain applications. It is necessary to strengthen the research on blockchain standardization and enhance the right to speak and rule in the world. It is necessary to speed up industrial development, give play to market advantages, and further open up the innovation chain, application chain and value chain. It is necessary to build a blockchain industry ecology, accelerate the deep integration of blockchain and frontier information technologies such as artificial intelligence, big data, and Internet of Things, and promote integrated innovation and integration applications. It is necessary to strengthen the construction of the talent team, establish and improve the personnel training system, build a variety of high-level talent training platforms, and cultivate a group of leading figures and high-level innovation teams.
General Secretary Xi pointed out that it is necessary to seize the opportunity of blockchain technology integration, function expansion and industry segmentation, and play the role of blockchain in promoting data sharing, optimizing business processes, reducing operating costs, improving synergy efficiency, and building a credible system. The role. It is necessary to promote the deep integration of the blockchain and the real economy, and solve the problems of difficulty in financing loans for SMEs, difficulties in controlling the risks of banks, and difficulties in departmental supervision. It is necessary to use blockchain technology to explore digital economic model innovation, provide power for creating a convenient, efficient, fair and competitive, stable and transparent business environment, and provide services for promoting supply-side structural reforms and realizing the effective docking of supply and demand in various industries, in order to accelerate new and old kinetic energy. Provide support for continuous transformation and promote high-quality economic development. It is necessary to explore the application of “blockchain+” in the field of people's livelihood, and actively promote the application of blockchain technology in the fields of education, employment, pension, precision poverty alleviation, medical health, commodity anti-counterfeiting, food safety, public welfare, social assistance, etc. The masses provide more intelligent, more convenient and better public services. It is necessary to promote the combination of the underlying technical services of blockchain and the construction of new smart cities, explore the promotion and application in the fields of information infrastructure, smart transportation, energy and power, and improve the level of intelligence and precision of urban management. It is necessary to use blockchain technology to promote greater inter-connectivity between cities in terms of information, capital, talents, and credit information, and ensure the orderly and efficient flow of production factors within the region. It is necessary to explore the use of the blockchain data sharing model to achieve the joint maintenance and utilization of government data across departments and regions, promote business synergy, deepen the “run-up once” reform, and bring better government service experience to the people.
General Secretary Xi emphasized that it is necessary to strengthen the guidance and regulation of blockchain technology, strengthen the research and analysis of blockchain security risks, closely follow development trends, and actively explore development laws. It is necessary to explore the establishment of a safety guarantee system that adapts to the blockchain technology mechanism, and guide and promote blockchain developers and platform operators to strengthen industry self-discipline and implement safety responsibilities. It is necessary to implement the rule of law network into the management of blockchain and promote the safe and orderly development of blockchain.
General Secretary Xi pointed out that the relevant departments and their responsible leaders should pay attention to the status quo and trend of blockchain technology development, improve the application and management of blockchain technology capabilities, and enable blockchain technology to build a network power, develop a digital economy, and help the economic society. Development and other aspects play a greater role.
The UK index of leading shares finished 25.02 points at 7,306.26. The FTSE 250 fell 41.83 points to close at 20,168.33
FTSE 100 closes down 25 points
Sterling higher as MPs begin debating December 12 election
The date of 9 December has also been mooted.
“Little is straightforward here, as is seemingly always the case with Brexit,” said market analyst David Cheetham at XTB.
China’s manufacturing sector continued to dwell in the doldrums in October, with sentiment among factory operators remaining in negative territory for the sixth month in a row.
The manufacturing purchasing managers’ index (PMI), released by the National Bureau of Statistics (NBS) on Thursday, stood at 49.3 in October, down from 49.8 in September and below the expectation in a Bloomberg survey of analysts for an unchanged reading. The October figure was the lowest since hitting 49.2 in February.
The non-manufacturing PMI – a gauge of sentiment in the services and construction sectors – came in at 52.8 in October, below analysts’ expectations for a 53.6 reading. The figure was also down from September’s 53.7, dropping to its lowest level since February 2016.
The composite PMI, a combined reading of both manufacturing and non-manufacturing, was 52, down from 53.1 in September.
The official PMI is a gauge of sentiment among larger and state-owned factory operators, with 50 being the line between expansion and contraction in sector activity. In the survey, manufacturers are asked to give a view on business issues such as export orders, purchasing, production and logistics.
The decline in manufacturing activity was led by a deterioration in the new orders which fell to the lowest level since June, with export orders declining to the lowest level since July. Overall production continued to expand in October, but at the slowest pace since February.
“The official PMIs fell by more than expected this month, reinforcing our view that the improvement at the end of Q3 didn’t mark the start of a sustained recovery,” said Julian Evans-Pritchard, senior China economist at Capital Economics. “The main driver was a sharp drop in the output component but new orders softened too. The decline in new export orders points toward a further slowdown in export growth. And the output price index, which closely tracks producer price inflation and industrial profit growth, also dropped back.”
The official PMIs fell by more than expected this month, reinforcing our view that the improvement at the end of Q3 didn’t mark the start of a sustained recoveryJulian Evans-Pritchard
The broad economic slowdown weighed more heavily on the construction and services sectors in October with the official non-manufacturing PMI falling to its lowest level in three and half years.
While there was a decline in October’s official manufacturing PMI reading, the fact that it remains in negative territory is indicative of the weak sentiment among producers even as trade negotiators from China and the United States agreed on the outlines of small-scale trade deal.
The China Federation of Logistics and Purchasing, who produce the survey with the NBS, said that while growth is slowing, the “quality of development is improving”.
China's economic structure is being optimised as high energy consuming industries are gradually being degraded, having a big impact on the overall economic growthChina Federation of Logistics and Purchasing
“China's economic structure is being optimised as high energy consuming industries are gradually being degraded, having a big impact on the overall economic growth,” they said in a statement.
Southeast Asia Energy Outlook 2019 Comprehensive review of a region on the rise
The IEA's 4th Southeast Asia Energy Outlook provides a comprehensive review of the energy system and current market trends in the ten countries of the Association of Southeast Asian Nations (ASEAN). It explores a set of possible futures for the region with a particular focus on cooling, regional power trade, and investment in the electricity sector. Download the full report Read press release
The growing weight of Southeast Asia
Any assessment of the outlook for global energy has to reckon with the growing weight of Southeast Asia. Home to nearly one-in-ten of the world’s population, the rapidly growing economies of the region are shaping many aspects of the global economic and energy outlook. Southeast Asia is a very diverse and dynamic region, but one common element is that policy makers across different countries have been intensifying their efforts to ensure a secure, affordable and more sustainable pathway for the energy sector. This includes action to facilitate investment in fuel and power supply and infrastructure, while focusing also on efficiency. The potential benefits of a well-managed expansion of the region’s energy system, in terms of improved welfare and quality of life for its citizens, are huge. There are encouraging indications in many areas, but also some warning signs. Rising fuel demand, especially for oil, has far outpaced production from within the region. Southeast Asia as a whole is now on the verge of becoming a net importer of fossil fuels for the first time.
Southeast Asia's growing economic and energy role
At the same time, Southeast Asia is well on the way to achieving universal access to electricity by 2030. Millions of new consumers have gained access to electricity since 2000, yet some 45 million people in the region are still without it today and many more continue to rely on solid biomass as a cooking fuel.
Southeast Asia’s growth in electricity demand, at an average of 6% per year, has been among the fastest in the world, but a number of power systems in the region are facing significant financial strains.
Since 2000, overall energy demand has grown by more than 80% and the lion’s share of this growth has been met by a doubling in fossil fuel use. Oil is the largest element in the regional energy mix and coal – largely for power generation – has been the fastest growing. This has underpinned the region’s development and industrial growth, but has also made air pollution a major risk to public health and driven up energy-related carbon dioxide (CO 2 ) emissions.
Southeast Asia has considerable potential for renewable energy, but (excluding the traditional use of solid biomass) it currently meets only around 15% of the region’s energy demand. Hydropower output has quadrupled since 2000 and the modern use of bioenergy in heating and transport has also increased rapidly. Despite falling costs, the contribution of solar photovoltaics (PV) and wind remains small, though some markets are now putting in place frameworks to better support their deployment.
Driven by rising incomes, industrialisation and urbanisation
In the Stated Policies Scenario, which explores the implications of announced policy targets as well as existing energy policies, Southeast Asia’s overall energy demand grows by 60% to 2040. The region’s economy more than doubles in size over this period, and a rise of 120 million in the population is concentrated in urban areas. The projected rate of energy demand growth is lower than that of the past two decades, reflecting a structural economic shift towards less energy intensive manufacturing and services sectors, as well as greater efficiency. Nonetheless, it still represents some 12% of the projected rise in global energy use to 2040.
All fuels and technologies play a part in meeting the growth in demand in this scenario. Southeast Asia’s oil demand surpasses 9 million barrels per day (mb/d) by 2040, up from just above 6.5 mb/d today. Oil continues to dominate road transport demand, despite an increase in consumption of biofuels. Electrification of mobility, with the partial exception of two and three wheelers, makes only limited inroads. This pathway suggests little change in Southeast Asia from today’s congested roads and poor urban air quality.
Southeast Asia is one of a few regions where the share of coal in the power mix increased in 2018 and, based on today’s policy settings, coal demand is projected to rise steadily over the coming decades. This is largely to fuel new and increasingly efficient coal-fired power plants, although the headwinds facing these projects are growing – including increasing difficulty to secure competitive financing for new coal facilities.
Natural gas faces competing pressures in Southeast Asia. It appears to be a good fit for the needs of the region’s fast-growing cities and lighter industries, as well as (in the form of liquefied natural gas [LNG]) a way to displace costly oil use in some island communities. However, increasing reliance on imports makes the fuel less price-competitive. In our projections, it is industrial consumers rather than power plants that are the largest source of growth in gas demand.
In the Stated Policies Scenario, the share of renewables in power generation rises from 24% today (18% of which is hydropower) to 30% by 2040, but this still lags far behind the levels reached in China, India and some other economies in Asia. Wind and solar are set to grow rapidly from today’s low levels, while hydropower and modern bioenergy – including biofuels, biomass, biogas and bioenergy derived from other waste products – remain the mainstays of Southeast Asia’s renewable energy portfolio.
Heading for rising energy import bills
The pathway that Southeast Asia is on includes the realisation of some major energy policy goals, including the vital task of ensuring universal electricity access and some progress with diversification of the energy mix.
Yet our Stated Policies Scenario also highlight some major potential risks. A widening gap between indigenous production and the region’s projected oil and gas needs results in a ballooning energy trade deficit. By 2040, Southeast Asia is projected to register a net deficit in payments for energy trade of over $300 billion per year, almost entirely due to imports of oil. This would also imply growing strains on government budgets, especially if subsidy policies remain in place that shield consumers from paying market-based energy prices.
The large increase in imports also raises energy security concerns. In the case of oil, the region’s overall dependence on imports exceeds 80% in 2040, up from 65% today.
... and rising emissions
The consequences of energy-related air pollution on human health remain severe. The number of annual premature deaths associated with outdoor and household air pollution in Southeast Asia rises to more than 650 000 by 2040, up from an estimated 450 000 in 2018. Some 175 million people across the region still remain dependent on the traditional use of solid biomass for cooking in 2040.
The projected increase in fossil fuel consumption, particularly the continued rise in coal demand, is felt in a two-thirds rise in CO 2 emissions to almost 2.4 gigatonnes (Gt) in 2040. In most other parts of the world, the power sector’s share of total energy-related emissions falls to 2040 even as electricity expands its role in final consumption. However, the relatively high carbon intensity of an expanding generation fleet in Southeast Asia means that the region’s power sector is responsible for just under half of CO 2 emissions in 2040, up from 42% today.
The future is electrifying in Southeast Asia
Southeast Asia’s electricity sector is in a very dynamic phase of development, both for supply and demand.
Relatively low generation costs and indigenous supply have traditionally given coal a prominent place in power sector planning. This is maintained in the Stated Policies Scenario – our measured assessment of planned additions means that the share of coal-fired generation in the region’s power mix remains broadly flat at near 40% over the next two decades, Natural gas-fired plants, based on domestic supply as well as imported liquefied natural gas are also set to maintain a strong foothold in Southeast Asia.
However, the declining costs of renewables and concerns over emissions and pollution are starting to alter the balance of future additions to the power mix. Recent revisions to policy planning documents have tended to boost the long-term share of renewables, typically at the expense of coal. Moreover, a switch is visible in near-term project developments, with a significant slowdown in decisions to move ahead with new coal-fired capacity and a rise in additions of solar and wind. In the first half of 2019, approvals of new coal-fired capacity were exceeded by capacity additions of solar PV for the first time.
On the demand side, electricity consumption in Southeast Asia doubles to 2040; the annual growth rate of nearly 4% is twice as fast as the rest of the world. The share of electricity in final energy consumption is 18% today but this rises rapidly to 26% in 2040 and reaches the global average.
Space cooling is one of the fastest growing uses of electricity to 2040, propelled higher by rising incomes and high cooling needs. For the moment, less than 20% of households across the region have air conditioning: in Indonesia, the most populous ASEAN country, around 10% do. In our projections, appliance ownership and cooling demand skyrocket, not only raising overall electricity demand but accentuating strains on power systems as the share of cooling in peak power demand rises towards 30%.
There are real opportunities for efficiency policies to reduce some of these projected strains: our detailed market analysis shows that the average efficiency of air conditioning units sold today is well below the global average, even though much more efficient units, including those manufactured locally, are available at comparable cost. Enhanced efforts to improve building and equipment efficiency (as in the Sustainable Development Scenario) would be sufficient to reduce the growth in cooling demand in 2040 by around half (read more in The Future of Cooling in Southeast Asia).
Energy investment
Whichever pathway the region takes, meeting Southeast Asia’s energy needs and policy priorities will require higher levels of investment. The need to step up investment is particularly acute in the power sector. Today’s investment levels fall well short of the projected needs in the Stated Policies Scenario and are more than 50% lower than what would be required in the Sustainable Development Scenario.
Mobilising investment requires broad participation from the private sector, as well as the targeted use of public funds. Public sources have thus far played a very important role in financing thermal power plant projects and large-scale renewables (such as hydropower or geothermal) with sizeable upfront capital needs. By contrast, wind and solar PV projects have relied much more on private finance, spurred by specific policy incentives.
There is a critical need in Southeast Asia to attract additional private sources of capital. This would require governments to address the risks that affect the bankability of projects; we highlight four priority areas for action:
- enhancing the financial sustainability of utilities;
- improving procurement frameworks and contracting mechanisms, especially for renewables;
- creating a supportive financial system that brings in a range of financing sources
- promoting integrated approaches that take the demand-side into account.
The types of investment that go ahead will also depend on the extent of regional cooperation and integration, especially progress with the ASEAN Power Grid – an ambitious project to interconnect the power systems in the region and establish multilateral power trading.
Regional power system integration is vital to facilitate growth in renewable sources of generation, in particular from wind and solar PV. Integration allows access to a larger and more diverse pool of flexible resources on the supply side (from sources such as hydro or gas-fired power) as well as the demand side. Interconnecting with neighbouring grids also reduces the system variability of wind and solar output, which is smoother when individual plants are aggregated over larger geographic areas.
Our detailed case study shows that multilateral power trading and an expansion of cross-border transmission bring major cost savings in building and operating the region’s power systems. They also bring significant environmental gains when they accompany and enable an expansion of renewables-based power.
Bradley armored vehicles rolled into eastern Syria on a mission to combat ISIS and prevent oil wells from falling back into the hands of the Islamic extremist group, according to an official with Operation Inherent Resolve.
Army Col. Myles B. Caggins III, a spokesman for the U.S.-led mission to defeat ISIS in Iraq and Syria, said the mechanized forces moving into Deir ez-Zor province, Syria, hailed from the 30th Armored Brigade Combat team, a National Guard unit from South Carolina.
NBC News was first to report it, citing OIR commander Army Lt. Gen. Pat White, that Bradleys and Army grunts had crossed into Deir ez-Zor.
Officials with the Pentagon and OIR did not detail the number of troops or armored vehicles tasked with protecting the oil wells in eastern Syria. But Secretary of Defense Mark Esper said Monday that American troops would continue to withdraw from northern Syria.
“We are repositioning" U.S. forces to Deir ez-Zor to continue partnering with the SDF “to defeat ISIS remnants, protect critical infrastructure” and to deny ISIS access to revenue sources. "Mechanized forces provide infantry, maneuver, and firepower,”OIR tweeted Thursday.
Esper said he expected troop levels to be below the 1,000 troops that were deployed to northern Syria prior to President Donald Trump’s decision to withdraw American troops from the country following a Turkish incursion.
Turkey launched operations on Oct. 9 to combat U.S.-backed Kurdish forces. Turkey believes the American anti-ISIS partner force in Syria is a terrorist group.
The decision to redeploy American forces into Syria appears to be reversal by Trump of his much criticized plan to withdraw U.S. troops from the country.
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American military veterans who served in armor units have argued mechanized forces in Syria could add logistical and manpower strains for U.S. forces in Syria — countering Trump’s aim to withdraw from the region and end America’s involvement in forever wars.
.@USArmy troops in 4-118th Infantry Regiment, @30thabct, @NCNationalGuard attached to the 218th Maneuver Enhancement Brigade, @SCNationalGuard, load M2A2 Bradley Fighting Vehicles to support the @CJTFOIR mission in Deir ez Zor, Syria. #DefeatDaesh pic.twitter.com/ZbFsvIemRW — OIR Spokesman Col. Myles B. Caggins III (@OIRSpox) October 31, 2019
The oil wells in eastern Syria are a contentious issue. Analysts contend the decision to deploy American armor to safeguard Syrian oil was made due to the threat of Russian and Syrian armor in the region.
How the Bradley will stack up to Russian armor is unknown. The small armor vehicle packs a 25 mm Bushmaster chain gun and is armed with the aging anti-tank missile system known as the TOW. But the Bradley could be highly effective against ISIS up-armored bomb-laden vehicles — a tactic that has grown in prominence among ISIS and Taliban fighters.
The vehicle is also highly maneuverable.
Syrian Democratic Forces, abandoned by their American partners, were forced to invite Russian and Syrian regime forces into towns and cities across northern Syria as Turkish troops and their Free Syrian Army proxy force rolled through the region.
The oil fields in eastern Syria were also the site of a clash between American commandos and Russian mercenaries. In February 2018, U.S. troops called in airstrikes against Russian mercenaries and pro-Syrian regime forces moving towards the American position near the Conoco oil fields in eastern Syria. Nearly 200 enemy troops were killed in the attack.
Esper and other U.S. defense officials have oft repeated that the U.S. wants to keep the Syrian oils from falling back into the hands of ISIS. Captured oil wells was a main source of income for ISIS during the height of its power in the Iraq and Syria.
But on Monday, Esper also said Russia and Syria would be denied access to the oil fields. Esper said the U.S. wanted to ensure its SDF partner force could use the oil revenue to fund their fighters and prison camps that are currently holding thousands of ISIS detainees.
Esper told reporters Monday that American forces protecting the oil fields where prepared to use “overwhelming military force” in self defense.
Esper said Monday that he has seen no sign of Syrian or Russian forces challenging U.S. control of the oil fields.
Russia calls US move to protect Syrian oil ‘banditry’ Russia’s Defense Ministry on Saturday harshly criticized the United States decision to send armored vehicles and combat troops into eastern Syria to protect oil fields, calling it “banditry.”
The Associated Press, citing a U.S. official, reported that the U.S. has detected what appears to be a massing of Russian and Syrian forces on the western side of the Euphrates River near Deir el-Zour.
Russian officials were contacted by phone, and the U.S. was given assurances that the staged forces would not move east, the official said, speaking on condition of anonymity to discuss a sensitive issue.
Jim Jeffrey, the Trump administration’s special envoy for Syria, seemed to refer to this episode when he said last Friday, “We are currently very concerned about certain developments in the south, in the Deir el-Zour area. I’ve talked to my Russian colleague about that and we’re having other contacts with the Russians concerning that situation. We think it is under control now.”
After expelling Islamic State militants from southeastern Syria in 2018, the Kurds seized control of the more profitable oil fields to the south in Deir el-Zour province.
In addition to that mission, the U.S. will also keep a small number of U.S. troops at the Tanf garrison near the Syria-Iraq border. American commandos housed at Tanf are tasked with training an anti-ISIS force separate from the SDF mission. And there is a Joint Special Operations Command compound in Syria, south of Kobani. where the raid that resulted in the death of ISIS leader Abu Bakr al-Baghdadi was launched.
“All Coalition military operations are de-conflicted with other forces operating in the region, through pre-existing channels and interlocutors in order to reduce the risk of interference, miscalculation, or unintended escalation of military operations,” Caggins said.
Partner pay at Grant Thornton has slumped and it has delayed publishing its accounts, as the UK’s sixth-largest accounting firm attempts to recover from a difficult year - FT
The firm has told the regulator that it would file its accounts next year, having changed its year end from 30 June to 31 December
The FT has revealed that Grant Thornton, the sixth largest accounting firm in the UK, won’t be publishing its accounts before the end of this year having extended its accounting period by six months.
This is the first time in roughly 15 years that the firm hasn’t published accounts before the new year.
In a tough year for the firm, it has been under scrutiny for its audit of Patisserie Valerie and faced questions over the sudden departure of CEO Sacha Romanovitch in 2018.
Grant Thornton also stepped down as auditor for Sports Direct this year, which left the company without an auditor until RSM took the post.
Documents seen by the FT also show that Grant Thornton partners will also be paid 13% less this year than the average profit per partner in 2018. Average pay will fall from £373,000 to £323,000.
The firm will not be required to publish a full transparency report until March, but has voluntarily published an interim report today.
Grant Thornton said that “full-share equity partner” pay was £343,000 last year. The figure wasn’t previously reported, the firm said, but means that the actual drop in pay this year is only 6%.
Profits have stagnated in the firm’s UK business, flatlining at around £72m, although the there has been a modest increase in turnover for the year to June 2019.
A spokesman for Grant Thornton said, "The firm has decided to adjust its financial year from 30 June to 31 December, as a later year end better matches the seasonality of our business and aligns with our global reporting commitments. This will not have any adverse impact on our people or clients."
Ipredicted well before the 2016 presidential election that Donald Trump would be elected. I had felt that way ever since he rode down that golden escalator with his rapist invective. Ever since he was elected, I’ve also believed that he’ll be re-elected, more easily this time.
An illustrative personal anecdote, one of many over the last three years: A creative writing PhD I know with tons of debt, whose wife happens to be an undocumented Filipina, became mightily angered by the promise of student debt cancelation. What about those who have paid their dues by taking out debt, he asked? No doubt he would refuse a blanket amnesty for “illegals” too. His DACA wife, as he sees it, paid her dues.
Columnists at the New York Times are all angry at the possibility of decriminalizing of border crossings, health care for the undocumented and the abolition of private insurance. In fact, they don’t want to do away with Trumpian inhumanity. They want the oppression to continue, but without the transparent rhetoric.
Minus the Trumpian rhetorical overlash, war, empire, violence, hollowness, junk goods and a junk life are all the people have ever known and all they want.
Historical movement in long cycles can’t be short-circuited, as we can see in the resistance of the liberal elite toward Bernie Sanders, the only candidate who could beat Trump, versus the stampede toward Elizabeth Warren, who provides a "safe" alternative and will surely lose.
But what kind of a fascist doesn’t start a war in three years? Trump doesn’t need war: He has brought the war home by making us confront our emptiness directly. He is the catalyst we needed at this time, and he is fulfilling his purpose beautifully. America is exhausted, which the liberal elites don’t get.
Trump keeps making noises about Iran, but he hasn’t actually done it yet. His pullback at the last moment, when the bombers were supposedly already on their way, is a trope that makes sense to a lot of people. We could have, in a science-fiction world, the repetition of this particular action — pulling back from the brink, the antithesis to Strangelove-style irrevocability — day after day, and it would be the right psychotropic drug to rouse us.
And what kind of a huckster is he? He constantly keeps changing his mind, which is not a character flaw, but the essence of his “deal-making.” America can’t find a better deal — from the New Deal to the Fair Deal to the imaginary Green New Deal, a landscape of lost opportunities and blighted dreams — so contingent honor, betrayed promises and infinite self-cancellation constitute the only kind of deal-making possible. And unlike on "The Apprentice," there can be no winner at the end, while the rest get fired, because the endless prevarication — saying two things at the same time, often diametrically opposite — is what constitutes deal-making. We’d better get used to it: It is the end point to a century of liberal social planning.
To be totally adrift, Trump is saying, is to have total freedom. The empire embraces its most recent eruption of vulgarity, barbarism and eco-destruction as a welcome development — or at least the dispossessed do, if not the meritocrats. To move beyond the dead language of liberal political correctness, which all the Democratic candidates suffer from, is a great service. Trump is preparing us for the imminent turmoil of the coming decades — concluding in secession and fragmentation by mid-century — with the kind of language the empire needs now. He’s reading history well, only too well, far better than his ideological opponents, the neoliberal globalizers or the democratic socialists.
Not one of his opponents is prepared to say that power is America — brute, unforgiving, no-second-chances power. This kind of power requires a base removed from liberal education. He reforms language every day, in his tweets, which emanate from our deepest unconscious, such as when liberal stand-up comedians turn out to be racists and misogynists in their revealing moments.
As we prepare for the age of brutality, he’s telling us — as the Times columnists confirm every day in the limits they impose to compassion — that the recent gloss of multicultural tolerance, in the Reagan/Clinton/Obama years, was the final fantasy. His border wall seeks to literalize the walls of segregation and inequality that have been going up relentlessly all throughout the interior. He won’t start wars of humanitarian liberation, because that was the foreign aspect to the domestic malevolence passing as tolerance.
Former UN ambassador Jeane Kirkpatrick counseled in the 1970s that we could work with good authoritarians around the world, but not with socialists. Trump’s affection for Narendra Modi, Jair Bolsonaro, Vladimir Putin, Kim Jong-un, and Mohammed bin Salman is nothing new. It is how we have always operated, even in the halcyon days of Henry Kissinger’s détente, when we violently crushed democracy in Chile and elsewhere, or under the spiritual Jimmy Carter, when we trapped the Russian bear in Afghanistan, much to Zbigniew Brzezinski’s delight.
Trump doesn’t want to restart history, to repudiate Francis Fukuyama or Bill Clinton. Nor does he want to start a clash of civilizations, to validate Samuel Huntington or George W. Bush. He is content with leaving history alone, which seems natural, coming so soon after the younger Bush's counselors, who wanted full-spectrum dominance. The deal, as Trump sees it, is ever-changing, immune from textual recreation, legal solidity, constitutional affirmation.
What is his obsession with China then? China for the last three decades has been a management consultant’s dream come true. Trump is not playing a zero-sum game, a chessboard called economic nationalism, with China. With him we move beyond oligarchic nationalism or even democratic fascism. China helps construct a total vacuum of thought, reaching even beyond the vulgarity of trashy American consumerism. We no longer want their tacky goods. We want the Harley-Davidsons back — or not, it’s OK if they don’t come back. If we can’t recall manufacturing, and we leave world trade, then we are thrown upon a manly ideal, where we make things and do things for ourselves, except that Trump and his followers know that that ideal is well past reach, going out of fashion with the rise of consumerism precisely a century ago.
The 2020s: An exact reversal of the rise of optimistic consumerism in the 1920s. History does have its symmetries, if you know where to look. The end to advertising, news broadcasting, modernist propaganda, the religion of self-help and therapy, physical fitness, institutionalized spying and technological utopia.
Trump's attack on the media, the breathing tube for an empty liberal consumerism that died long ago, is the most welcome move to his fervent supporters. You can’t believe a word you see. You have to create your own reality, which the Internet helped bring about starting in the 1990s. Consider the real scandal of Joe Biden’s son’s corruption, already noted matter-of-factly in leading newspapers, versus the impeachable scandal of just talking — airing out possible deals to land political opponents in trouble. Torture, assassination, deportation and ecocide are all within the pale, for the resistance, for those who would like to replace him with an acceptable alternative who will take empire back to where it was.
But it’s not going to happen, because he was never the bearer of a virus, which implies something alien. He is the perfect mirror, just as Nixon followed Lyndon Johnson, Reagan followed Carter, and Bush followed Clinton, in performing not so much an oscillation but an exaggerated return to form. Empires, heavy and difficult to maneuver, don’t engage in circular or sideways motions. Trump is the accelerant to the end point that empire needs now, just as Reagan and Bush served their functions earlier, and in that sense he is a true man of the people. You don’t beat a man of the people electorally. You just don’t.
Italian oil giant Eni has discovered new resources in the Abu Rudeis Sidri development lease, in the Gulf of Suez, offshore Egypt.
This is the location where Petrobel, a JV between Eni and by the Egyptian General Petroleum Corporation (EGPC), drilled an appraisal well of the discovery of Sidri South, announced last July.
The Sidri 36 appraisal well, drilled to assess the field continuity westward in a down-dip position with respect to Sidri-23 discovery well, encountered an important hydrocarbon column in the clastic sequences of the Nubia Formation (200 meters of hydrocarbon column), Eni said on Friday.
“This new and important result continues the positive track record of the “near field” exploration in Eni’s historical concessions in Egypt and prove how the use of new play concepts and of the technology allows to re-evaluate areas where exploration was considered having reached a high level of maturity,” Eni said.
The well will be completed and put into production in the next few days with an expected initial flow rate of about 5.000 barrels per day.
According to Eni, Petrobel immediately came up with a rapid development plan for the new discovery with a “fast-track” approach, leveraging on existing infrastructures in the vicinity of the well and maximizing facilities synergies; this strategy will be applied also in future activities in the Sidri area with the next delineation and development wells connected to the production in a short time.
The Sidri South discovery, which is estimated to contain about 200 million barrels of oil in place, will be reassessed following these new results, Eni said.
Eni’s current equity production in Egypt is around 350,000 barrels of oil equivalent per day. Production is expected to further grow within the year, thanks to the Zohr gas field and to the Baltim SW field ramp-up, Eni said.
At least three tankers are on their way to Asia with U.S. oil cargoes after Washington gave temporary approval to wind down transactions with a Chinese shipping company that it sanctioned last month, according to data and shipping sources.
In one of the biggest sanctions actions taken by the U.S. government since its crackdown on Iranian oil exports, Washington on Sept. 25 announced sanctions on Chinese tanker companies, including COSCO Shipping Tanker (Dalian), a subsidiary of China’s state-owned shipping group COSCO.
The surprise move by Washington and concern over shippers falling foul of U.S. sanctions led to oil freight costs hitting record highs around the world, adding millions of dollars in costs for every voyage.
Shipping sources said Washington had begun to grant temporary waivers for the conclusion of shipments around Oct. 15.
Refinitiv data showed three tankers - carrying millions of barrels of oil and owned by the designated COSCO subsidiary - set sail from the U.S. Gulf for destinations in Asia around that time, after waiting in the area for several weeks after sanctions were imposed.
The sources said on Friday that further COSCO tankers were preparing to sail with cargoes on board that had been held up.
This followed a notice from the U.S. Treasury on Thursday which allowed for the “maintenance or wind down of transactions” including offloading non-Iranian crude oil involving the COSCO subsidiary until Dec. 20.
One shipping source said ships with cargoes on board were more comfortable to discharge their cargoes, adding Thursday’s notice by the Treasury maybe formalizes what was already known.
“These sanctions by the Trump administration were worded in a way that you can never feel completely secure. I think that’s deliberate,” the source said.
Earlier this month, a source said a separate tanker owned by the affected COSCO subsidiary had received a temporary waiver from U.S. sanctions that allowed it to discharge its cargo.
Jonathan Chappell, an analyst with advisory firm Evercore ISI, said the Treasury notice was “fraught with legalese and therefore difficult to fully comprehend, opening the content up to possible misinterpretation.
“It appears that the intent of the update is to enable voyages/transactions that are already under way to be completed by Dec. 20 ... and it does not end or place a waiver on the current sanctions,” Chappell said in a note on Thursday.
CNOOC, China’s largest offshore oil and gas producer, said this week it would be affected by U.S. sanctions on COSCO’s subsidiary but there would be no impact on its oil and gas production.
A ambitious new Arctic oil project led by Russia’s top oil producer Rosneft will require about 10 trillion roubles ($157 billion) of investment, Russia’s deputy energy minister Pavel Sorokin told reporters.
Vostok Oil, a joint project of Rosneft and Independent Petroleum Company (IPC), is set to include some oil fields that are already producing and others which have yet to start, including Rosneft’s Vankor group and IPC’s Payakhskoye field.
The government has broadly agreed a new tax relief package to help develop the Arctic, seen as a new oil-producing region for Russia, which is among the world’s top crude exporters, Deputy Prime Minister Yuri Trutnev said this week.
Russia’s heavy support of oil production via a number a special tax breaks has been hotly debated at a time when the government is raising other taxes on its citizens and increasing pension ages.
Alexei Sazanov, the head of the tax department at Russia’s finance ministry, told reporters at the same event on Friday that tax benefits for Vostok Oil could cost up to 60 billion roubles per year. The comments by Sorokin and Sazanov were embargoed until early on Monday.
Russia’s budget surplus, projected at 1.7% of gross domestic product this year, is expected to shrink to 0.2% in 2022, partly due to the various supports offered to the energy sector, a cornerstone of budget revenue.
Rosneft hopes that foreign investors will also invest in Vostok Oil, which it expects to produce up to 100 million tonnes of oil per year (2 million barrels per day), or a fifth of what Russia currently pumps.
IPC is led by Eduard Khudainatov, a former Rosneft chief executive and a close ally of Igor Sechin, who now runs Rosneft.
U.S. refiner Phillips 66 beat estimates for quarterly profit on Friday, boosted by strong performance in its fuel sales business.
Phillips 66 processes, transports, stores and markets fuels and products and has been redesigning its Phillips 66, 76 and Conoco branded sites in the United States.
The efforts paid off with adjusted earnings in the segment jumping nearly 30% to $498 million.
Refined product exports rose nearly 16% to 220,000 barrels per day in the third quarter, the company said.
Net earnings fell to $712 million, or $1.58 per share, in the third quarter ended Sept. 30, from $1.49 billion, or $3.18 per share, a year earlier.
Excluding a $690 million impairment related to investments in DCP Midstream, the company earned $3.11 per share.
Analysts on average had expected a profit of $2.59 per share, according to IBES data from Refinitiv.
Buenos Aires — Argentina elected a left-leaning moderate as president Sunday, while a tighter race in neighboring Uruguay goes to a second round, elections closely watched by the energy sector because of the region's large oil, natural gas and power resources.
The focus for energy companies is on what happens next in Argentina, home to Vaca Muerta, one of the world's largest shale plays, which could make the country a major oil and gas exporter.
Alberto Fernandez, 60, emerged as the winner with 48% of the votes, according to the National Electoral Department. That was enough for him to avert a runoff against right-leaning incumbent President Mauricio Macri, 60, who received 40% of the votes.
After accepting defeat late Sunday, Macri said he would work on a smooth transition for Fernandez to take power December 10.
In his victory speech, Fernandez said, "Four years ago, they told us, 'We won't be back,' but tonight we came back, and we'll be better."
That may prove a challenge, and he said he understands that.
"The times that are coming are not going to be easy," he said.
Related podcast Oil Markets podcast Our podcast that provides analysis of key oil price movements across the globe. Listen
Argentina is entering its third year of recession and has defaulted on some bonds and may have to default on more. Inflation is more than 50%, the benchmark interest rate is touching 70%, and the fiscal accounts are in deficit. The central bank has tightened capital controls to contain the exchange rate and capital flight, and to stem inflation.
With the global economy slowing, the next government may struggle to attract the more than $10 billion a year in capital needed to develop Vaca Muerta, of which only 5% is yet in production.
"Vaca Muerta needs more than $100 billion in investment to achieve its full potential, but it will not be able to attract anything if the country is perceived to be a deadbeat," Walter Molano, head of sovereign research at BCP Securities, a Connecticut investment banking services firm, wrote in a recent note to clients.
ENERGY POLICY UNCERTAINTY
On the campaign trail, Fernandez was vague on his energy policies. His advisers have recommended freezing energy tariffs and unlinking oil and refined product prices from the US dollar as a way to reduce inflation and make the economy more competitive. There are proposals as well to improve the legal security for investing in Vaca Muerta, such as with tax incentives and leniency on keeping dollars from export sales outside the country, now restricted.
Analysts, however, have said that until there are concrete definitions on energy policy, it's hard not to think that the coalition will resort to the capital, currency, price and trade controls from when it was in power from 2003 to 2015. The last eight years of that period were governed by Cristina Fernandez de Kirchner, who is Fernandez's vice president-elect. While it is widely thought that she was on the ticket because of her popularity, a question is whether she will have any influence on economic and energy policy.
Fernandez de Kirchner's son, Congressman Maximo Kirchner, is the head of a radicalized faction of the coalition called La Campora, and it influenced energy policy from 2007 to 2015, a period when oil and gas production dwindled, imports surged and shortages were frequent.
Production has since recovered, led by Vaca Muerta, where majors like Chevron, ExxonMobil and Shell are developing blocks. Gas has reached a record 144 million cu m/d, and oil is touching 520,000 b/d, up from a 19-year-low of 479,000 b/d in 2017. The Energy Secretariat has forecast that production could double to 1 million b/d and 260 million cu m/d in 2023 from this year, allowing exports to surge to 500,000 b/d and 80 million cu m/d over the same period from around 60,000 b/d and less than 10 million cu m/d this year.
TOUGH CONDITIONS
An energy consultant, who asked not to be named, said the potential stems from the geology of Vaca Muerta, considered by some to be better than the Permian Basin in the US.
That is not enough, however, the consultant said.
"The US has some of the world's best shale and also legal security, economic stability, infrastructure and access to cheap financing," he said. "Argentina only has the geology."
Indeed, activity has slowed in Vaca Muerta since Macri imposed a 90-day freeze on diesel and gasoline prices in August that has cut local crude prices by 20%, reducing profit potential.
The freeze is due to be lifted November 14, but there are doubts about how this can be done given the high rate of inflation.
Jorge Colina, an economist at the Institute of Argentine Social Development in Buenos Aires, said he expects two more years of economic crisis and faster inflation as the central bank may have to print pesos to finance the fiscal deficit because of the country's lack of access to capital markets.
To bring investment to Vaca Muerta, the key is to contain inflation, restore the economy to growth and achieve a budget balance, all without any drastic changes in business conditions, he said.
"Vaca Muerta needs dollars," Colina said. "If the government breaks contracts for Vaca Muerta, the companies are going to stop investing, no new investment is going to come, and Vaca Muerta is going to be dead."
SECOND ROUND FOR URUGUAY
In Uruguay, meanwhile, the election is poised to go to a second round November 24, as the ruling left-leaning coalition, Broad Front, failed to win by a wide enough margin in the first round. Daniel Martinez, a 62-year-old former national energy minister, received 39% of the votes, while Luis Lacalle Pou, 46, of the right-leaning National Party garnered nearly 29%, according to the official results.
The energy sector is widely in favor of Lacalle Pou winning, as he would be expected to improve business conditions and regulations, helping to spur investment.
Uruguay gets most of its energy from hydropower and renewables, but it must import gas and oil, and officials of the current government have said they want to increase purchases from Argentina, but that depends on the pace of development of Vaca Muerta. The other options are to install a floating regasification terminal or import from Brazil, which is increasing its gas production.
-- Charles Newbery, newsdesk@spglobal.com
-- Edited by Bill Montgomery, newsdesk@spglobal.com
Washington — Enterprise Products Partners aims to add 450,000 b/d of capacity to its Midland-to-ECHO crude oil pipeline system by the third quarter of 2020, with a subsequent 450,000 b/d expansion allowing the company to convert the Seminole pipeline back to NGL service.
The fourth expansion of the system could ramp up to 540,000 b/d if demand supports it, CEO Jim Teague said during a third-quarter earnings call.
Teague said Enterprise would likely convert the Midland-to-ECHO 2 pipeline, formerly called the Seminole pipeline, back into NGL service, although he did not share timing expectations.
"Look at the math in our crude oil system: Enterprise can transport at optimum cost 1.3 million b/d," Teague said. "If the market needs more capacity, Enterprise can ramp that capacity to 1.8 million b/d with zero capital."
Enterprise moved an average of 2.3 million b/d of crude through its pipelines in Q3, up 21% from a year earlier.
Its crude exports from marine terminals on the Houston Ship Channel and at Beaumont, Texas, jumped to 987,000 b/d in Q3, up 56% from a year earlier.
VLCC RATE SPIKE
A spike in VLCC freight rates after the US sanctioned two affiliates of China's Cosco Shipping disrupted Houston's crude exports and took a couple of weeks to sort out, an executive said.
"In Houston, what we saw is people basically backed off," said Brent Secrest, senior vice president for commercial. "They backed off from exporting and the market was trying to fill itself out, and things had to reset, but that takes time."
Secrest said the incident highlighted Houston's better crude export potential, given storage capacity and access to refiners, allowing Midland producers to keep sending barrels. He said drillers tied to other export markets, presumably Corpus Christi, were forced to sell at a discount in Midland or Houston.
The company gave no updates on its proposed Sea Port Oil Terminal to fully load VLCCs with crude exports offshore Houston.
Teague said he is not concerned by falling rig counts and projections of slowing Permian production growth.
"I don't see someone like Exxon or Chevron slowing down, I don't know about EOG," he said. "We see what you're talking about, but the people we have that are really the anchors to our system are the really large guys."
-- Meghan Gordon, meghan.gordon@spglobal.com
-- Edited by Jonathan Fox, newsdesk@spglobal.com
LONDON/MOSCOW, Oct 28 (Reuters) - Russian oil producer Lukoil and Hungarian energy company MOL are set to sign a settlement deal over contaminated oil during Russian President Putin's visit to Budapest this week, four industry sources told Reuters.
A high level of organic chloride was found in late April in Russia's Druzhba pipeline, which connects Siberian oilfields with Belarus, Ukraine, Poland, Germany, Czech Republic and Hungary. The substance, which can damage refining equipment, was also detected in the Baltic Sea port of Ust-Luga.
The contamination disrupted oil exports from Russia to the West and has led to protracted negotiations over compensation.
A source familiar with the plans of Lukoil and MOL, said the companies were unlikely to disclose the amount of compensation to be received by MOL.
"We've been cooperating very closely, so it's just to make an official statement about successful settlement and prospects for future cooperation," the source said.
The agreement is set to be signed during Putin's visit to Budapest. Last week, his aide, Yury Ushakov, said Putin would travel to Hungary on Oct. 30.
Last month, Russia and Kazakhstan reached a preliminary deal over compensation for tainted oil, though the final agreement is yet to be signed.
Lukoil, MOL and Russian oil pipeline monopoly Transneft have not replied to requests for comments.
Up to five million tonnes of crude may have been contaminated by organic chloride, which is used in oil extraction.
Traders such as Glencore and BP have been struggling to sell the tainted oil, which could potentially be mixed with unaffected crude to become usable.
Transneft has said compensation won't exceed $15 per barrel. (Reporting by Olga Yagova and Dmitry Zhadnnikov; Writing by Vladimir Soldatkin; Editing by Mark Potter)
Our Standards: The Thomson Reuters Trust Principles.
Iran’s fiscal breakeven oil price—the one at which the country would be able to balance its budget—is US$194.60 a barrel for 2020, the International Monetary Fund (IMF) said in a report on Monday, in which it lowered its economic growth forecasts for the entire Middle East region.
Due to the U.S. sanctions severely constraining Iran’s oil exports, the Islamic Republic would have balanced its budget for 2019 if oil prices were at US$155.60 per barrel, according to the IMF’s estimates in its Regional Economic Outlook published today.
Saudi Arabia, the world’s top oil exporter and OPEC’s largest producer, would need oil prices at US$86.50 this year and US$83.60 next year in order to balance its budget, the IMF predicts.
In its report, the fund lowered its estimates for economic growth in the Middle East, citing volatile oil prices, faltering global growth rate, and heightened geopolitical tensions.
Economic growth in Gulf Cooperation Council (GCC) countries—that is Bahrain, Kuwait, Oman, Qatar, Saudi Arabia, and the United Arab Emirates (UAE)—is expected at just 0.7 percent this year, notably down from the 2-percent growth last year. This decline will be mostly due to the production cut agreement of the OPEC+ pact, the IMF said. Related: Oil Rebounds On Rare Market Optimism
Next year, the economies of those countries are expected to collectively grow by 2.5 percent, thanks to real oil GDP growth because of rising oil production in Kuwait and Saudi Arabia, the start of full operations at the Jizan refinery in Saudi Arabia, and increased natural gas production in Oman and Qatar, the IMF said. The 2020 projection, however, is uncertain because it’s not clear yet if OPEC and allies will let the production cuts pact to expire by March 2020, according to the IMF.
Saudi Arabia’s real GDP growth is set to edge up by just 0.2 percent in 2019, before picking up to 2.2 percent in 2020.
Iran’s economy, on the other hand, “has entered a steep recession,” with output expected to drop by 9.5 percent this year, the IMF said.
“Iran’s main export, oil, is severely restricted, and imports have collapsed,” the fund noted.
By Tsvetana Paraskova for Oilprice.com
More Top Reads From Oilprice.com:
Epic Crude Holdings LP is testing support for another expansion of its Texas intrastate oil pipeline that extends from Orla in the Permian Basin to the Port of Corpus Christi.
The open season, launched Monday, extends to Dec. 17. The crude pipeline completed its first open season in July 2018 and its second two months later. Epic, formed two years ago, is developing oil and natural gas liquids midstream infrastructure in the Permian Basin and Eagle Ford Shale.
Epic Crude Oil Pipeline runs parallel to the Epic Y-Grade Pipeline and services the Permian’s twin Delaware and Midland sub-basins, as well as the Eagle Ford Shale. The crude pipe has terminals in Orla, Saragosa, Crane, Wink, Midland, Upton, Hobson and Gardendale, with connectivity to the Corpus refining market and multiple terminals allowing export access on the coast.
Able to ship up to 400,000 b/d, Epic Crude began interim crude operations in August using the 24-inch diameter Y-Grade Pipeline. Once the 30-inch diameter crude pipeline is completed in 1Q2020, Epic Crude is to have initial capacity to transport 600,000 b/d and be expandable to transport up to 900,000 b/d.
Epic’s crude export dock in Corpus Christi is expected to be completed by the end of the year and be capable of loading Aframax tankers that carry up to 750,000 bbl. Another crude export dock is set for completion in 3Q2020 that would be able to load Suezmax tankers to transport up to 1 million bbl.
The Y-Grade Pipeline and Epic Olefins LP also are working to complete by 3Q2020 two 12-inch diameter pipelines for Gulf Coast Growth Ventures (GCGV) in San Patricio County near Corpus Christi. GCGV was formed last year by ExxonMobil Corp. and state-owned Saudi Basic Industries Corp., aka SABIC, to build what has been billed as the world’s largest steam cracker, a 1.8 million metric ton/year facility. The project, sanctioned in June, is expected to start up in 2022.
The Epic systems are backed by capital commitments from funds managed by Ares Management Corp.’s private equity group.
U.S. President Donald Trump’s suggestion on Sunday that Exxon Mobil or another U.S. oil company operate Syrian oil fields drew rebukes from legal and energy experts.
“What I intend to do, perhaps, is make a deal with an ExxonMobil or one of our great companies to go in there and do it properly ... and spread out the wealth,” Trump said during a news conference about the U.S. special forces operation that led to the death of Islamic State leader Abu Bakr al-Baghdadi.
Exxon Mobil Corp (XOM.N) and Chevron Corp (CVX.N), the two largest U.S. oil companies operating in the Middle East, declined to comment on his remarks.
“International law seeks to protect against exactly this sort of exploitation,” said Laurie Blank, an Emory Law School professor and director of its Center for International and Comparative Law.
“It is not only a dubious legal move, it sends a message to the whole region and the world that America wants to steal the oil,” said Bruce Riedel, a former national security advisor and now senior fellow at the Brookings Institution think-tank.
“The idea that the United States would ‘keep the oil’ in the hands of ExxonMobil or some other U.S. company is immoral and possibly illegal,” said Jeff Colgan, an associate professor of political science and international studies at Brown University. Colgan also said U.S. companies would face “a host of practical challenges” to operate in Syria.
Even getting Exxon or another major oil company to develop Syrian oil would be a “hard sell” given its relatively limited infrastructure and small output, said Ellen R. Wald, a senior fellow at the Atlantic Council’s Global Energy Center.
Syria produced around 380,000 barrels of oil per day before the country’s civil war erupted. An International Monetary Fund working paper in 2016 estimated that production had declined to just 40,000 barrels per day.
The International Monetary Fund’s latest regional outlook report for the Middle East and Central Asia, published Monday, paints a picture of uncertain economies weighed down by global factors like trade tensions as well as internal and regional turmoil.
Trade wars, oil price volatility, the risk of a disorderly Brexit and rising social unrest — and in the short term, a massive economic contraction in Iran as it buckles under heavy U.S. sanctions — are the biggest factors shaping the region’s outlook, according to the IMF.
“The outlook for the MCD region (Middle East and Central Asia) is driven by a large contraction in Iran in the short-term followed by a rebound in 2020,” the report said. “The risks around the forecast are skewed to the downside and are highly dependent on global factors.”
The IMF expects Iran to have a fiscal deficit of 4.5% in 2019 and 5.1% in 2020, and projects its growth to contract by a whopping 9.5% this year. The country of 80 million and third-largest OPEC producer has seen its currency go into free fall and inflation approach 40% after being hit by wide-ranging sanctions following the Trump administration’s withdrawal from the 2015 Iranian nuclear deal. The sanctions have slashed Iran’s crude exports by about 80%, according to Reuters estimates.
Broader international factors are also impacting the region’s growth, the report said.
“The region is this year growing at a slower pace than last year. And this is due to the various shocks or factors that are affecting the output of the region,” Jihad Azour, the IMF’s director for the Middle East and Central Asia, told CNBC’s Hadley Gamble in Dubai.
Azour said that oil importing countries should expect a growth slowdown from 4.3% to 3.6%, mainly driven by Pakistan and Sudan, while oil exporters — excluding Iran and countries impacted by war — should expect growth of 1.3% in 2019 compared to 1.6% the year before.
“For the oil exporting countries, non-oil growth is gradually picking up thanks to the reforms that they have introduced,” Azour said. “Yet the overall growth declined because of the volatility and the slowdown in the production due to the OPEC+ agreement (to limit oil output) and the negative growth in Iran and Libya.”
cnbc
ConocoPhillips Earnings Beat With Higher Rising Oil and Gas Production
ConocoPhillips reported better than expected third quarter earnings before the market opened Thursday. Houston based $COP is the largest U.S. based independent exploration and production firm based on production volumes.
ConocoPhillips Q3 Earnings
Conoco Phillips Inc. (NYSE: $COP) Reported Earnings Before Open Tuesday
$0.82 Beat $0.78 EPS Forecast And $7.76 Billion Missed $7.92 Bil Revenue Forecast
Earnings
ConocoPhillips (COP) on Tuesday reported third-quarter earnings of $3.06 billion, On a per-share basis net income was $2.74. Earnings, adjusted for non-recurring gains,was 82 cents per share. The results beat Wall Street expectations average estimate of four analysts of 78 cents per share. Revenue was $7.76 billion in the period.
ConocoPhillips NYSE: $COP
Market Reaction $57.89 +2.21 (+3.97%)
Highlights
"This business is all about having a sustainable strategy with consistent execution. We believe ConocoPhillips offers both - a shareholder-friendly, returns-oriented value proposition and strong delivery on our commitments," said CEO Ryan Lance.
Production
ConocoPhillips eported that total production, excluding Libya, rose 98,000 barrels per day to 1.322 million barrels per day thanks in part to increased production at the Eagle Ford, Bakken and Permian basins.
Guidance
For the fourth quarter, the company expects production to range between 1,265 million barrels and 1,305 million barrels per day.
What Analysts Will Be Watching
ConocoPhillips explores for, produces, transports, and markets crude oil, bitumen, natural gas, LNG, and natural gas liquids (NGLs) worldwide.
ConocoPhillips production of oil equivalent per day (BOE/D) to BOE/D guidance range.
Seasonal maintenance activities.
Update on third-party gas pipeline issue in Malaysia
$COP's share repurchase program. Conoco Phillips this year announced a 50% increase in this year's share buyback plan to $3 billion. The company also reported it reduced debt by $2.1 billion during Q2 and has already reached its 2019 year-end debt target of $15 billion.
ConocoPhillips capital budget, look for changes in CapEx.
ConocoPhillips' big three shale plays, Bakken, Eagle Ford, and Permian Basin are its key growth drivers in 2018, delivering 20% production growth versus last year. Haliburton in their earnings report warned that pipeline constraints in the Permian have had producers rethinking their plans.
ConocoPhillips has in the past hinted that it might reduce its drilling activities in the Permian due to the pipeline issues. CEO Ryan Lance said last month he is "not sure it makes sense to drill into that headwind." Will $COP reallocate capital away from the Permian and toward the Bakken and Eagle Ford.
Conoco’s portfolio includes resource-rich North American tight oil and oil sands assets; lower-risk legacy assets in North America, Europe, Asia and Australia; various international developments; and an inventory of conventional and unconventional exploration prospects. $COP has reloaded portfolio depth in the Bakken and Eagle Ford, and with visibility on future growth from a sizable position in the Permian.
About ConocoPhillips
ConocoPhillips explores for, produces, transports and markets crude oil, bitumen, natural gas, liquefied natural gas (LNG) and NGLs worldwide. Conoco’s portfolio includes resource rich North American tight oil and oil sands assets; lower-risk legacy assets in North America, Europe, Asia and Australia; various international developments; and an inventory of conventional and unconventional exploration prospects.
Source: ConocoPhillips
Live From The Pit
WASHINGTON - Liquefied natural gas could soon move around the country by rail as the Trump administration moves to loosen restrictions on transporting LNG in an effort to further boost to the nation’s energy sector.
The Department of Transportation has proposed allowing railroads to begin transporting LNG in cryogenic tanker cars, which can maintain temperatures of less than minus 300 degrees and are currently used to move chemicals like ammonia and ethylene. A final decision is expected early next year.
The railroad could offer an enticing alternative to natural gas customers when pipeline projects are under increasing scrutiny over natural gas’s contribution to climate change, with New York Governor Andrew Cuomo blocking construction of new pipelines running through his state and into New England. At the same time the rush to develop oil fields in West Texas - far from the nation’s pipeline network - has resulted in many drillers flaring the natural gas that is a byproduct of crude production.
“Pipelines are still the most optimal way to transport gas, but LNG by rail can be a great way to move gas into places with pipeline constraints, like the Northeast and potentially out of the Permian Basin,” said Katie Ehly, senior policy adviser at the trade group Natural Gas Supply Association. “It just makes sense.”
On HoustonChronicle.com: Trump's hard sell of American LNG
But tanker cars full of flammable natural gas traveling through American cities and towns represents a significant safety risk, the scale of which was evidenced six years ago when an oil train derailed in Lac-Mégantic, Quebec, setting off a massive explosion that killed more than 40 people.
The Pipeline and Hazardous Material Safety Administration, however, maintains it has studied the risks and decided they are manageable.
“This major rule will establish a safe, reliable, and durable mode of transportation for LNG, while substantially increasing economic benefits and our nation’s energy competitiveness in the global market,” PHMSA Administrator Skip Elliott said in a statement.
But some are questioning the thoroughness with which the administration has approached its review of longtime restrictions placed on the transport of liquefied natural gas. In August, the environmental group Earthjustice, representing a coalition of activist groups, warned that the administration has not done enough to establish that LNG could be moved safely by rail.
Under special permits, railroads in Florida and Alaska have been allowed move small quantities of LNG through pilot projects - using cryogenic containers placed on flat-bed rail cars, as opposed to traditional tanker cars. But the administration has yet to release any data from those projects to prove that moving LNG by rail is safe, said Fred Millar, an independent consultant formerly of the environmental group Friends of the Earth.
“The environmental assessment was a flimsy 23-page document, and they can say no disaster yet after these pilot projects,” he said. “Now we’re in the Trump era, industry is going in and getting everything it can.”
The American Association of Railroads, a trade group, did not respond to requests for comment.
More: Read the latest oil and gas news from HoustonChronicle.com
The transportation of LNG by rail car is already allowed in Canada and Japan. The oil company Japan Petroleum Exploration has moved LNG by cryogenic containers loaded onto trains for close to two decades, to get natural gas to areas where pipelines do not reach.
In Texas, some are already looking at a similar approach.
Enestas, a Mexican company with offices in Houston, uses trucks to transport natural gas from South Texas to clients in Mexico not located near pipelines. But with the Trump administration moving ahead on allowing LNG shipments by rail, the company is looking into the feasibility of using trains, said Gregory Pilkinton, vice president of sales and business development at Enestas.
“We’re following it closely,” he said. “We move a significant volume of LNG across to Mexico, and if we could do it more economically by rail that would be fantastic.”
james.osborne@chron.com
Twitter: @osborneja
On Saturday, the 26th of October 2019, US Energy Secretary Rick Perry said that talks with the Kingdom of Saudi Arabia, world’s leading oil exporter, over a nuclear program had shown signs of progress, as the closest US ally in the Middle East, Saudi insisted that it wanted to use nuclear power in a bid to diversify its energy production line, while the Kingdom had also expressed sheer interest over holding forth with a full-cycle nuclear program including uranium enrichment and production of heavy water for atomic fuel.
Meanwhile, in the face of Saudi’s repeated urge to go ahead with a nuclear program, multiple US companies were allured to compete for developing Saudi’s nuclear project, nonetheless, the world’s no. 2 crude oil producer behind United States, Riyadh would at first require to sign an agreement with Washington on peaceful capitalization of nuclear technology.
However, multiple media reports had revealed that a Saudi-US discussion on nuclear energy accord had witnessed a turbulent start-off as Saudi did not agree with a deal which could rule out possibilities of uranium enrichment or heavy water processing, both of which could lead to an emerge of another nuclear weaponized country in the Gulf, nonetheless, adding that the long-time allies would find a way to a nuclear accord, Perry said on Saturday (October 26th), “The kingdom and the leadership in the kingdom .. will find a way to sign a 1,2,3 agreement with the United States, I think. ”
The American Petroleum Institute late Tuesday said U.S. crude inventories fell 1.7 million barrels last week, according to news reports. API said gasoline stocks fell 4.7 million barrels, while distillates declined by 1.6 million barrels.
Inventory data from the Energy Information Administration will be released Wednesday. The EIA data are expected to show crude inventories up by 2.5 million barrels last week, according to analysts polled by S&P Global Platts. They also forecast supply declines of 2.5 million barrels for gasoline and 2.4 million barrels for distillates.
* Brazil oil output at record high - IEA
* OPEC delegates say no formal request made to join
* Comments come days before Brazil oil auction (Adds detail, context, OPEC delegate comments)
By Stephen Kalin, Rania El Gamal and Alex Lawler
RIYADH, Oct 30 (Reuters) - Brazilian President Jair Bolsonaro said on Wednesday that he wants his country to join OPEC, a move that would add the most significant new producer to the oil cartel for years.
The comments come ahead of a massive auction of oil rights in Brazil, which is boosting output rapidly. OPEC membership would likely require Brazil to limit oil production, potentially throwing future expansion plans into doubt.
The Organization of the Petroleum Exporting Countries groups top exporter Saudi Arabia and 13 other countries. Since 2017, OPEC has had a deal with several non-member producers, excluding Brazil, to limit supply in an effort to bolster prices.
"I personally would very much like Brazil to become a member of OPEC," Bolsonaro said at an investment conference in Riyadh, speaking through a translator.
Brazil would be the most significant producer to join OPEC, founded in 1960, for years. The country's current output would make it OPEC's third-largest producer, far above that of recent new members such as Congo and Equatorial Guinea.
The Brazilian president said he would have to consult his economy and energy ministers to ensure they could follow through if a decision was made.
He said Brazil had larger oil reserves than some OPEC members and that when the country was among the top six producers in the world, that would help stabilise the global market.
OPEC delegates said membership talks with Brazil were going on although it had made no formal request to join the group.
OUTPUT RISING
Oil output has been rising rapidly in Brazil from offshore fields and production surged by 220,000 barrels per day (bpd) in August to a record 3.1 million bpd, according to the International Energy Agency.
That would make Brazil the third-largest OPEC producer after Saudi Arabia and Iraq, pumping the equivalent of more than 10% of current OPEC output.
Brazilian authorities have approved 14 companies to participate in the oil bidding round next month, in which total signing bonuses are expected to be the biggest so far, exceeding $25 billion, according to national oil regulator ANP.
The so-called transfer-of-rights auction is scheduled for Nov. 6, and concerns a zone of Brazil's southeastern coast. Companies participating include global oil majors as well as state-run Petroleo Brasileiro SA, or Petrobras.
Brazil is a bigger producer than the several others that have left and joined the group in recent years. Nigeria, which pumps almost 2 million bpd, is the biggest producer to join Vienna-based OPEC and remain a member since it did so in 1971.
Ecuador plans to exit in 2020. Qatar quit this year. Equatorial Guinea joined in 2017 and Congo became a member last year. (Reporting by Stephen Kalin; writing by Rania El Gamal and Alex Lawler; editing by Jason Neely and Dale Hudson)
https://finance.yahoo.com/news/2-brazil-president-bolsonaro-says-133306604.html
Saudis ready for deeper cuts, says OPEC minister
By Nayla Razzouk and Manus Cranny on 10/29/2019
DUBAI (Bloomberg) - Saudi Arabia’s Energy Minister Prince Abdulaziz said his country is ready to make deeper cuts in oil output than it agreed to with other global producers, according to Nigerian Minister of State for Petroleum Resources Timipre Sylva.
“He assured me that they are very ready to even cut deeper,” Sylva told Bloomberg TV in Riyadh. The OPEC minister said he and Prince Abdulaziz didn’t discuss new output levels when they spoke on Monday.
Saudi Arabia is leading the Organization of Petroleum Exporting Countries and other top producers like Russia into a collective production cut extending though the end of March. OPEC and its allies are due to meet in December to discuss whether steeper cuts to oil supply will be needed to shore up prices amid a surplus and signs of weaker demand.
Nigeria is fully complying with its new production quota and is currently pumping 1.774 million barrels a day, Sylva said. He said he was also speaking with Gabon, South Sudan and Angola about compliance with the cuts.
Nigeria is holding talks with Saudi Arabia for the supply of oil products to the African country where all refineries are not currently producing, Sylva said. There is still no agreement about the volume, he said.
“We are also discussing the possibility of fixing one of our refineries with the Saudis and then we are also discussing the development of an oil and gas industrial pact in the Niger Delta,” he said.
Related News ///
FROM THE ARCHIVE ///
The ExxonMobil-operated Liza-1 development, located in the Stabroek Block offshore Guyana, is now expected to start production through the Liza Destiny FPSO in December 2019, which is earlier than expected.
The Liza field sits in the giant Stabroek block, which covers almost 27,000 square kilometers, circa 200 kilometers offshore Guyana. ExxonMobil has struck more than a dozen oil discoveries at the block which are yet to be developed, meaning a couple of more FPSOs should be deployed in Guyana in the upcoming years.
The Stabroek Block is operated by ExxonMobil with a 45% interest while Hess and CNOOC Petroleum have 30% and 25% interest, respectively.
According to a Wednesday report by Hess, production from Phase 1 of Liza development is now targeted for startup in December 2019. First oil was previously expected to be produced in the first quarter of 2020.
Hess Chief Executive Officer, John Hess, said: “In September, we announced our 14th discovery in the Stabroek Block at Tripletail, offshore Guyana and are now targeting December for first oil from the Liza-1 development.”
The Liza Phase 1 development is now targeted to start production in December of this year and will produce up to 120,000 gross bopd utilizing the Liza Destiny FPSO, which arrived in Guyana on August 29, 2019. The FPSO was converted from a VLCC by Keppel. It will be able to store 1.6 million barrels of crude oil.
The Liza Phase 2 development was sanctioned in May 2019 and will use the Liza Unity FPSO to produce up to 220,000 gross bopd, with first oil expected by mid-2022. Pending government approvals, a third development, Payara, is expected to produce up to 220,000 bopd with startup in 2023.
Full speed ahead on Stabroek Block
Hess also said that exploration and development drilling activities continue on the Stabroek Block.
After completion of operations at Tripletail, the Noble Tom Madden drillship will next drill the Uaru-1 exploration well, located approximately 10 miles east of the Liza-1 well.
The Stena Carron drillship is continuing drilling and evaluation activity at Ranger-2. The drillship will next conduct a production test at Yellowtail-1.
The Noble Bob Douglas drillship is currently conducting development drilling operations for the Liza Phase 1 project.
A fourth drillship, the Noble Don Taylor, is expected to arrive in Guyana in November 2019 and will drill the Mako-1 exploration well located approximately 6 miles south of the Liza-1 well.
Offshore Energy Today Staff
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KBR immune from shale slump during third quarter
KBR CEO Stuard Bradie. Energy projects helped to push revenue higher for Houston information technology company KBR at a time when other companies are feeling the effects of a slump in activity across shale fields in the United States and Canada. NEXT: See recent earnings from area energy companies. less KBR CEO Stuard Bradie. Energy projects helped to push revenue higher for Houston information technology company KBR at a time when other companies are feeling the effects of a slump in activity across shale ... more Photo: Steve Gonzales, Houston Chronicle / Staff Photographer Photo: Steve Gonzales, Houston Chronicle / Staff Photographer Image 1 of / 39 Caption Close KBR immune from shale slump during third quarter 1 / 39 Back to Gallery
Energy projects helped to push revenue higher for Houston information technology company KBR at a time when other companies are feeling the effects of a slump in activity across shale fields in the United States and Canada.
In an early Wednesday morning statement, KBR reported posting a $56 million profit on $1.4 billion of revenue during the third quarter. The figures were mixed compared to the $58 million profit on $1.3 billion of revenue during the third quarter of 2018.
This year’s this quarter figures translated into earnings per share of 39 cents for stockholders, which were down compared to the 41 cents per share during the same time period last year.
KBR nonetheless beat Wall Street expectations of $1.4 billion of revenue and earnings per share of 37 cents.
Shale Slump: Oil field service sector braces for more pain
The company's earnings report come at time when $50 per barrel crude oil prices have created a drilling slump in shale fields across the United States and Canada that has sent the rest of the oilfield service sector hemorrhaging with losses.
In a statement, KBR CEO Stuart Bradie said revenues from company's energy saw 31 percent growth during the third quarter, leading the company's government and technology divisions.
"The results we report today demonstrate the laser-focused commitment and dedication of our 38,000 people, working together to ensure our clients achieve their missions and objectives," Bradie said.
Leading the company's energy division growth were cost-reimbursable projects that include revamping a refinery along the U.S. Gulf Coast, expanding a crude terminal expansion in the Permian Basin and building a new methanol plant in Louisiana.
A joint venture between KBR and Japanese engineering, procurement and construction firms JGC and Chiyoda also completed work on the onshore portion of the Ichthys LNG, a $40 billion liquefied natural gas project in northwest Australia being developed by Japanese oil company Inpex and French oil major Total.
Ichthys LNG receives natural gas from underwater wells that is pipelined to shore where the gas will be processed and converted into its liquid form and then shipped to customers around the world.
"This world-class facility is now in full production and export mode," Bradie said.
Fuel Fix: Get daily energy news headlines in your inbox
Headquartered in Houston and with roots in the city going back to 1919, KBR was founded as an engineering, procurement and construction company with heavy ties to the oil and natural gas industry.
Earlier this year, stock traders reclassified KBR as an information technology company following a strategic shift where the company now earns most of its revenue from from government contracts with agencies such as NASA and the Department of Defense.
With more than 36,800 employees in 40 nations, KBR reported making a $281 million profit on $4.9 billion of revenue in 2018.
Read the latest oil and gas news from HoustonChronicle.com
US stocks reached all-time highs this week as optimism grew that Trump and Xi have a trade deal on the way and the US Federal Reserve would lower interest rates later this week.
On the trade front, President Trump reaffirmed that "Phase 1" of the deal is largely complete after China's leadership said the first part of the agreement was "basically done" over the weekend. The first part of the deal is reported to include Chinese concessions on intellectual property, agreements to buy more US agricultural products and additional freedoms for US financial firms to operate in China. In return, the US is canceling a scheduled round of tariffs aimed at $250 billion in Chinese goods. President Trump has stated that he would like to sign Phase 1 with Xi at APEC next month in Chile.
Meanwhile, in bond markets US Fed Chair Jerome Powell is expected to deliver his third consecutive rate decrease this week to juice an economic recovery that is showing signs of strain from old age. US government yields rallied due to the optimism on the trade front, but futures markets still see two rate decreases from the Fed between now and June of 2020. Equity markets applauded the news by lifting US shares to a record high with the S&P 500 trading 3,040- up about 6% in the last six months. Meanwhile, the Shanghai Composite rallied to 2,980 for a nearly 8% rally in just the last two months.
Unfortunately, commodity markets seem to be taking a more moderate view of the economic outlook, cautioning it might not be time for bulls to break out the champagne. In fact, relative to stocks, commodity returns have been wretched with copper, oil and US gasoline prices down 10%, 18% and 19%, respectively, over the last six months.
So why the disconnect? How can risk assets which are both dependent on economic strength offer such disparate views on the economic outlook?
We've written here before that it will be tough for oil to rally substantially until you remove the macro ceiling of the US/China trade war. However, this doesn't create a guarantee that commodities will rally if a deal gets signed. Stock markets are clearly pricing in increased odds of a deal. Perhaps commodity markets are also pricing a deal in and simply saying that even a large bilateral trade agreement won't be enough to lift global demand out of its slump. There is a very real risk that a trade deal could result in a ‘buy the rumor, sell the news’ type of reaction.
And why are oil market operators glummer than their stock brethren? Buried in the background of market headlines the EIA, OPEC and IEA continue to forecast sizeable crude inventories builds (with supply outpacing demand) through the first half of 2020 despite the recent declines in US production. We think it’s likely the oversupply trend- while less flashy than any headline including the word ‘Trump’- is dampening any market enthusiasm and traders are simply waiting on better supply/demand data before sending the market higher. While stock markets appear content to feast on central bank easing and trade deal hope, oil traders appear to be waiting for something more; good fundamentals.
U.S. crude oil refinery inputs averaged 16.0 million barrels per day during the week ending October 25, 2019, which was 133,000 barrels per day more than the previous week’s average. Refineries operated at 87.7% of their operable capacity last week. Gasoline production increased last week, averaging 10.2 million barrels per day. Distillate fuel production increased last week, averaging 5.0 million barrels per day.
U.S. crude oil imports averaged 6.7 million barrels per day last week, up by 840,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 6.3 million barrels per day, 16.5% less than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 673,000 barrels per day, and distillate fuel imports averaged 158,000 barrels per day.
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 5.7 million barrels from the previous week. At 438.9 million barrels, U.S. crude oil inventories are about 1% above the five year average for this time of year. Total motor gasoline inventories decreased by 3.0 million barrels last week and are about 2% above the five year average for this time of year. Finished gasoline and blending components inventories both decreased last week. Distillate fuel inventories decreased by 1.0 million barrels last week and are about 11% below the five year average for this time of year. Propane/propylene inventories decreased by 0.1 million barrels last week and are about 12% above the five year average for this time of year. Total commercial petroleum inventories decreased last week by 2.2 million barrels last week.
Total products supplied over the last four-week period averaged 21.3 million barrels per day, up by 3.4% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.5 million barrels per day, up by 3.6% from the same period last year. Distillate fuel product supplied averaged 4.2 million barrels per day over the past four weeks, down by 0.7% from the same period last year. Jet fuel product supplied was up 9.6% compared with the same four-week period last year.
Domestic production unchanged at 12,600,000 bbls day
Exports 3,327,000 bbls day down 356,000 bbls day
Cushing 46,000,000 bbls up 1,500,000 bbls
Encana Corporation said on Thursday it intends to move its corporate domicile from Canada to the United States and rebrand under a new name, amid a growing investor and company exodus from the Canadian oil patch plagued by pipeline capacity shortage and general anti-oil sentiment.
Encana’s move to the US is expected to take place early next year, pending shareholder, stock exchange, and court approvals, the company said in a statement.
The new company will rebrand under the name Ovintiv Inc. After completing its corporate base shift and adopting the new name, the new company will begin trading on both the New York and Toronto stock exchanges under the ticker symbol "OVV."
“A domicile in the United States will expose our Company to increasingly larger pools of investment in U.S. index funds and passively managed accounts, as well as better align us with our U.S. peers,” CEO Doug Suttles said, noting that the move will not affect day-to-day operations.
“The Company is generating significant free cash flow, returning cash to its shareholders and generating industry-competitive liquids growth from its multi-basin portfolio of assets. It is this unique combination that the Company believes will ultimately be differentiated by the market,” Encana said in today’s release.
Related: Is A Full-Blown War In The Persian Gulf Inevitable?
Encana has several high-impact assets in the U.S., including in the Permian, the Bakken, the Eagle Ford, the Anadarko basin, and the Uinta Basin in Utah. At the beginning of this year, Encana acquired Newfield Exploration Company in an all-stock transaction, gaining additional exposure to the Permian, Anadarko, and Montney basins.
Meanwhile, in Canada, insufficient market access and continued uncertainty over additional pipeline capacity have finally caught up with the growth projections of the Canadian Association of Petroleum Producers (CAPP), which estimates that Canada’s crude oil production will continue growing from now until 2035, but at a much slower pace than previously thought.
Most recently, Canada’s energy giant Husky Energy slashed jobs earlier this month as part of its reduced annual spending plans.
By Tsvetana Paraskova for Oilprice.com
More Top Reads From Oilprice.com:
The government of Alberta said on Thursday it would allow energy firms to produce more oil despite the industry-wide production cuts, if those firms move the additional barrels by rail, as continued pipeline capacity shortage dampens the prospects of Alberta’s oil and gas sector.
The provincial government will be providing special allowances to oil companies to raise their oil production above the individual curtailment limit permits, on the condition that firms move the additional oil by rail.
The special allowances are set to come into effect as of December and the volumes will be based off an operator’s average rail shipments for Q1 2019. Volumes moved under an allowance by rail cannot be nominated onto pipelines, the Alberta government said.
“The special allowance program will protect the value of our oil by ensuring that operators are only producing what they are able to move to market. Pipeline delays ultimately have constrained market access and dampened investment in our oil sector,” Sonya Savage, Alberta’s Minister of Energy, said.
Canadian producers have had a tough couple of years with constrained market access that drove the price of Western Canadian Select (WCS)—the benchmark price of oil from Canada’s oil sands—to a discount of US$50 to WTI Crude in the fall of 2018. This blow-out in the differential between the Canadian benchmark and the U.S. benchmark prompted Alberta’s government to impose at the beginning of 2019 a mandatory production cut across all companies in the province to help ease congested takeaway routes and lift the abnormally low price of Canadian oil.
Related: A Warm Winter Would Be 'Catastrophic' For Natural Gas
This September, Alberta’s government eased the production cuts, saying that it would allow oil producers to pump 3.8 million bpd of crude in November and 3.81 million bpd in December. That’s up from 3.79 million bpd in October and 3.56 million bpd in January this year.
Canadian energy companies continue to believe that the long-term solution to Canada’s oil industry’s woes is the construction of major new pipelines to increase market access, and potentially, to tap new export markets outside the buyer of nearly all Canadian oil exports, the United States.
By Tsvetana Paraskova for Oilprice.com
More Top Reads From Oilprice.com:
Today's Market View: EIA reports a crude oil inventory build of 5.7MMbbls
Market Update: Thursday 31 October 2019
Genel Energy ( ): Tawke to maintain 120kbopd in 2020
Echo Energy ( ) - Tapi Aike Update
Energy Prices
Brent Oil US$60.5/bbl vs US$60.7/bbl yesterday
WTI Oil US$55.4/bbl vs US$55.6bbl on yesterday
Natural Gas US$2.6/mmbtu vs US$2.5/mmbtu yesterday
Oil Price News
Oil prices were off slightly as the EIA reported a crude oil inventory build of 5.7MMbbls for the week to October 25, pressuring prices a day after the API reported an estimated fourth consecutive inventory build, of 592,000bbls
Consensus estimated an expected a build of 729,000bbls for last week after a 1.7MMbbl draw interrupted a string of five weekly inventory builds, which added more than 19MMbbls to crude oil inventories
Following the reports, U.S. crude futures were also down 0.2% at $54.3/bbl on the New York Mercantile Exchange
US-China trade tensions and the outlook for Fed policy remain the single largest drivers of oil prices in our view
Gas Price News
Natural gas prices moved higher on yesteday rising another 3.6%, ahead of today’s inventory report Expectations are for an 84Bcf build in stockpiles according to Estimize following last week’s 87Bcf increase in inventories
The weather is expected to be colder than normal for the next 6-10 and 8-14 day forecast according to a report from the National Oceanic Atmospheric Administration
M&A activity builds momentum across the sector
Given the depressed economic environment, we are seeing a number of listed companies coming to the conclusion that it is cheaper to purchase reserves through the stock market rather than adding through the drill-bit.
The past 12 months has seen the acquisition of Faroe Petroleum (FPM.L) by DNO (DNO ASA); a £380m bid for Eland Oil & Gas (ELA.L) by (SEPL.L); and (AMER.L) currently engaged in a competitive bid.
Aramco’s proposed IPO is another good barometer for sector sentiment in our view. Days before a widely expected official approval for what would be the world’s largest IPO ever, Saudi Arabia has yet again delayed the much-hyped listing by at least several weeks, with international investors seemingly not buying the Saudi insistence that the biggest oil company in the world is worth US$2tn.
UK Sector Backdrop
Despite a tough capital market environment, UK equities in the Oil & Gas sector remained flat YTD (2018: -16%) wiping out September’s 8% gains
AIM Oil & Gas indices were also flat YTD despite some volatility, yet stabilising 2018’s 13% decline
These indices have largely tracked the oil price, and with the futures market also remaining steady
The small/mid cap constituents of the sector are due to engage in an active year of operational activity in 2020, with a number of high impact drilling catalysts
Company News
Genel Energy ( ): Tawke to maintain 120kbopd in 2020
Share price: 189p, Market Cap: £527m
In the Kurdistan Region of Iraq, third quarter production at the Tawke licence averaged 119,800 bopd. Production in the quarter was impacted by a workover of the P-2 well and side-track of the P-3 well at the Peshkabir field.
The operator of the field (DNO) expects to exit the year with Tawke licence production averaging 120,000bopd and to maintain this rate into 2020.
The Tawke licence cumulative production recently reached the milestone of 300MMbbls, underlining the productive nature of the reservoirs.
DNO also confirmed that the Peshkabir-to-Tawke gas project is on track to be delivered in Q1 2020, effectively eliminating gas flaring while enhancing recoverability at the Tawke field.
Conclusion: Another strong update from Genel and DNO. Genel is sufficiently funded for an aggressive capex budget, a material and progressive dividend as well as M&A when appropriate. It gives Genel a yield of around 7%, which will appeal to high income funds as well as sector investors in our view.
Echo Energy ( ) - Tapi Aike Update
Share price: 3p, Market Cap: £17.5m
Following the successful completion of seismic analysis which has resulted in a positive decision to drill and, the subsequent refinement and finalisation of detailed engineering work, Echo has announced that the final location for the first well of a four well Tapi Aike exploration programme has now been selected by the comapny and the operator (CGC).
The well will be located in the Chiripia Oeste, the eastern portion of the Tapi Aike 3D survey area, and will be re-named Campo La Mata x-1 ("CLM x-1") on account of the now confirmed location.
All permits to enable operations to commence have been received, contracts have been awarded and, construction works are now being finalised on the well pad and access roads to the drill site.
The primary target of CLM x-1 is a stratigraphic trap which lies in the Magallanes Formation at an approximate depth of 2,000m.
A secondary horizon in the Anita Formation (D3) and a shallower secondary interval (Magallanes 60) will also be targeted by the well.
Technical work with the Operator has identified a high negative amplitude signature at the target area and Class III amplitude vs offset characteristics.
Conclusion: The company is now in the final stages of preparation ahead of mobilisation of the contracted drilling rig for the upcoming CLM x-1 well, the first of four wells in the Tapi Aike drilling programme. The initial CPR showed grounds for significant optimism and could reveal ‘material value’ for the company and its shareholders in a success case.
nd could reveal ‘material value’ for the company and its shareholders in a success case.
Independent private-equity company Kerogen Capital is reportedly seeking offers to sell its majority ownership in North Sea-focused oil and gas firm Zennor Petroleum.
Citing industry sources, Reuters said Thursday that Kerogen was looking for offers from “a select number of bidders” after receiving several approaches.
Also, the news agency cited a banking source who said that Serica Energy was one of the companies that could make an offer. Reuters further said that bids might be in by the end of the year.
Offshore Energy Today has reached out to Zennor and Kerogen, seeking confirmation of the Reuters report. We will update the article if we receive any response.
Zennor has a portfolio that includes five producing North Sea fields and, according to its website “a number of undeveloped discoveries.” The company last year bought an 8.97 percent working interest in the Britannia field -then operated by ConocoPhillips – in the Central North Sea.
Also, the Zennor is currently developing the 100% owned Finlaggan field in the UK Central North Sea.
The development project is targeting 30 mmboe of gas condensate reserves from two subsea production wells tied back 20km to the Britannia platform, which is now operated by Chrysaor.
Zennor received approval from UK’s Oil & Gas Authority to proceed with the Finlaggan field development back in October 2018.
At the beginning of the October, Zennor announced that it completed the 2019 Finlaggan subsea installation campaign. The Finlaggan development project remains on schedule for the first production in 4Q 2020 as planned.
According to Reuters, since its acquisition of Zennor in 2015, Kerogen has invested $300 million in the oil company whose current production levels stand at around 5000 boepd.
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Canadian oil company Husky Energy has said that the development of its West White Rose offshore oil field project has passed a 52% completion mark.
Husky approved the West White Rose development in May 2017. The West White Rose field in Canada’s Atlantic is being developed using a fixed wellhead platform tied back to the SeaRose floating production, storage and offloading (FPSO) vessel.
In a statement on Thursday Husky said the West White Rose Project construction work on the concrete gravity structure and related topsides was progressing and that the project “is now 52% complete.”
“Construction continued on the Concrete Gravity Structure (CSG) for the West White Rose Project. A third planned slipform was completed at the dry-dock in Argentia, Newfoundland and Labrador, and the first three interior decks were installed. A fourth slipform was completed in mid-October,” Husky Energy said.
As previously reported, Husky awarded a contract for the construction of the CGS to a general partnership between SNC-Lavalin, Dragados Canada, and Pennecon.
The CGS will have an overall height of 145m, a base diameter of 122m and will require 76,000 m3 of concrete.
The installation work, expected in 2021, will be carried out by Norway’s Kvaerner, who will perform engineering, analysis, planning, and execution of marine operations related to tow and installation of the CGS. At its final location offshore on the Grand Banks, Kvaerner will be responsible for installing the concrete gravity structure on the seabed.
Husky Energy’s partners in the project are Nalcor and Suncor Energy. The first oil production from the field is expected around the end of 2022.
3Q earnings tumble
Husky on Thursday reported third-quarter results. Net earnings fell to $273 million, compared to net earnings of $545 million in Q3 2018.
Husky attributed the drop in earnings to lower profit from Upstream operations due to lower global crude oil benchmark prices and lower production.
It also said that its total earnings were affected by lower earnings from crude oil marketing activities due to the tightening of location pricing differentials between Canada and the U.S.; and lower realized Upgrading and U.S. Refining margins
Total production in barrels of oil equivalent was 294,800 boe/day, compared to 296,700 boe/day in the third quarter of 2018.
Offshore Energy Today Staff
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Growing Recognition of the Climate Emergency
In June 2019, Canada's federal House of Commons passed a motion (186 to 63 votes) to declare a national climate emergency. This declaration followed reporting from Environment and Climate Change Canada (ECCC) that past and future warming from climate change in Canada is approximately double the global average and may be "effectively irreversible".1 The damage caused to Canadians by climate change, while projected to grow, is already significant; annually, chronic exposure to greenhouse gas (GHG) emissions and accompanying pollution contributes to the deaths of over 7,000 Canadians2 and the weather effects of climate change impose billions in costs on Canadian communities and businesses.3
The reality of the climate emergency is increasingly recognized globally. In May 2019, the Parliament of the United Kingdom declared a climate emergency, and in June 2019, all but four members of the European Union (EU), namely Poland, Czech Republic, Hungary and Estonia, voted in favour of the EU adopting measures to ensure a transition to carbon neutrality by 2050.4 The members of the Carbon Neutrality Coalition, which, as of September 27, 2019, include 19 countries and 32 major cities across four continents, have pledged to become emissions neutral by 2050.5 Canada is among the countries, and Toronto and Vancouver are among the cities, which are members of this coalition.
As global temperatures continue to rise and the world becomes increasingly focused on solutions, an increasing number of jurisdictions (led by Canada) are implementing or plan to implement a carbon tax or emission trading system.6 As the Canadian experience has shown, however, political opposition to carbon pricing can interfere with or delay implementation, even in jurisdictions where a significant portion of the population supports strong action against climate change.
Federal Pricing Act: Federal Carbon Levy and OBPS
As detailed in our January 7, 2019 Update, Federal and Ontario Updates on Climate Change and Clean Growth Plans, the federal Output-Based Pricing System (OBPS), which is part of the Greenhouse Gas Pollution Pricing Act ("Federal Pricing Act"), is designed to create a price incentive for large industrial emitters to reduce their GHG emissions while also promoting innovation and maintaining competitiveness. On June 28, 2019, the federal government released the regulations implementing the OBPS.
By way of background, the Federal Pricing Act has two parts:
Part 1 establishes a charge on the fossil fuels used by households and businesses (" Federal Carbon Levy ").
"). Part 2 applies the OBPS, which will be administered by ECCC and Canada Revenue Agency, to emissions-intensive, trade-exposed industrial facilities which generate substantial GHG emissions.
The Federal Pricing Act operates as a backstop, applying only in provinces where the Governor-in-Council concludes GHG emissions are not priced at the minimum standards established by the Federal Pricing Act.
The Federal Pricing Act came into force on June 21, 2018.7 The Federal Carbon Levy came into effect in Ontario, New Brunswick, Saskatchewan, and Manitoba in April 2019, and in Nunavut and Yukon in July 2019. The OBPS came into effect in Ontario, Manitoba, New Brunswick, Prince Edward Island and Saskatchewan in January 2019,8 and in Yukon and Nunavut in July 2019. The Federal Pricing Act will apply in Alberta in January 2020.
Federal Carbon Levy
The Federal Carbon Levy applies to gasoline, diesel fuel and natural gas, as well as combustible waste. The applicable rates of charge are set out in Schedule 2 to the Federal Pricing Act. The rates for 2019 represent a price of $20 per tonne of CO 2 equivalent (CO 2 e) emitted by the combustion of each fuel. The rates will increase annually by $10 per tonne, up to $50 per tonne in 2022.
OBPS
Under the OBPS, the government will set an emissions threshold per unit of output for each sector. Companies that emit below their annual limit will receive credits and those that exceed the threshold must either buy credits from other companies or pay an additional charge.
Participation: Mandatory and Voluntary
The federal OBPS is mandatory for facilities that:
are located in a jurisdiction where the OBPS applies;
have reported 50,000 tonnes of CO 2 e or more in 2014 or a subsequent year to the Greenhouse Gas Reporting Program (which requires facilities that emit 10,000 tonnes or more of CO 2 e per year to report to ECCC); and
e or more in 2014 or a subsequent year to the Greenhouse Gas Reporting Program (which requires facilities that emit 10,000 tonnes or more of CO e per year to report to ECCC); and carry out a covered activity in certain specified sectors.
The list of covered activities is set out in Schedule 1 of the OBPS regulations. The list includes certain activities relating to oil and gas production, mineral processing, chemicals production, pharmaceutical production, iron and steel, mining and ore processing, food processing, pulp and paper, automotive assembly and electricity generation, among others.
The regulations also allow for voluntary participation in the OBPS. Facilities that carry out a covered activity with annual emissions between 10,000 and 50,000 tonnes of CO 2 e per year, and facilities with more than 10,000 tonnes of CO 2 e per year in sectors not listed under Schedule 1 but at significant risk of carbon leakage and competitiveness impacts from carbon pollution pricing, may also apply to opt in to the OBPS. Once a qualifying facility chooses to participate, it will be subject to the OBPS regime, and will not be subject to the Federal Carbon Levy.
Pricing Standards
Facilities subject to the federal OBPS are required to pay compensation for the portion, if any, of their GHG emissions that exceed their applicable emissions limit, based on a sector specific output-based standard. The annual facility emissions limit is determined by multiplying the facility's production by the applicable output-based standard.
The output-based standard is generally set at 80% of the national, production-weighted average emissions intensity of a specific industrial activity. The production-weighted average emissions intensity is calculated as the total emissions of a given industrial activity (or grouping of facilities carrying out the same listed activity) divided by the total production of that sector. In calculating the emissions of a given industrial activity, data is considered from all relevant Canadian facilities that emitted at least 50 kilotonnes of CO 2 e from 2014 to 2016.
For certain sectors at particular risk of "carbon leakage" (i.e., the flight of production to less strictly regulated jurisdictions), the outputbased standard is set at 90% or 95% (thereby increasing the threshold of allowable emissions relative to the 80% standard). These "atrisk" sectors include various petrochemical-related industries, iron and steel, and cement, among others.
The only exception to the foregoing approach is with respect to electricity generation, which has explicitly defined output-based standards. These standards will generally decline on a linear basis (to zero for the 2030 compliance period) for all solid fuel generation facilities and any new gas generation facilities in jurisdictions subject to the federal OBPS.
Compensation and Credits; Compliance Flexibility
A facility subject to the federal OBPS that emits less than its annual emissions limit will receive surplus credits. A facility subject to the OBPS that exceeds its annual emissions limit must pay compensation at a price of $20 per tonne of CO 2 e in 2019, rising by $10 per tonne annually to $50 per tonne of CO 2 e in 2022. The price is expected to flatten after 2022 but may then be reassessed. Compensation for excess emissions must be paid by a certain deadline (generally, December 15 of the subsequent calendar year), failing which compensation due is multiplied by a factor of four.
The federal OBPS enables certain flexibility for compliance in addition to the payment of monetary penalties. Credits can be sold between facilities or banked for future use. The regulations under the Federal Pricing Act also contemplate a variety of other mechanisms for compensation that may be enacted, such as offset programs.
The Ontario Landscape
Ontario Emission Performance Standards Regime
On July 4, 2019, the Ontario government released the regulations implementing industrial emission performance standards (EPS).
Participation: Mandatory and Voluntary
The EPS applies to facilities in the same sectors that fall under the scope of the federal OBPS. The main components of the EPS are:
mandatory participation for facilities listed in the sectors in Schedule 2 to the EPS regulations, with emissions of 50,000 tonnes of CO 2 e per year or more (the " Mandatory Threshold ");
e per year or more (the " "); voluntary participation for facilities with emissions between 10,000 tonnes of CO 2 e per year and the Mandatory Threshold, and which satisfy the other requirements to participate in the EPS;
e per year and the Mandatory Threshold, and which satisfy the other requirements to participate in the EPS; a lower threshold on a megawatt hour basis for the electricity sector; and
complementary amendments to the Greenhouse Gas Emissions: Quantification, Reporting and Verification regulation under the Ontario Environmental Protection Act to align the verification threshold with the Mandatory Threshold for the EPS program.
Emissions Standards; Many Varying Standards
Annual emissions limits for facilities covered by the EPS are determined in accordance with the "GHG Emissions Performance Standards and Methodology for the Determination of the Total Annual Emissions Limit" (the "Provincial Methodology"), which is published by the Ontario Ministry of the Environment, Conservation and Parks.
The Provincial Methodology prescribes various standards for calculating a facility's annual emissions limit, depending on the industry in question. The different standards that can apply include sector-specific, facility-specific and historical performance standards, as well as a standard based on energy use (i.e., how much fuel is used instead of how much GHG is emitted). Electricity generation, thermal energy and cogeneration are each subject to different specific standards.
The Provincial Methodology also distinguishes between fixed process emissions, which are generally the result of chemical or physical reactions unrelated to combustion ("Fixed Process"), and non-fixed process emissions such as combustion (e.g., GHG from the burning of fuel), fugitive (e.g., equipment leaks and unintentional losses) and on-site mobile sources ("Non-Fixed Process") of facilities. Specifically, most Non-Fixed Process emissions are subject to a "stringency factor" of less than 100% and, therefore, an increased reduction of these emissions is required as compared to Fixed Process emissions. The table below summarizes the stringency factors (SF) prescribed by the Provincial Methodology based on industrial activity emissions type.
Industrial Activity Emission Type 2019 SF 2020 SF 2021 SF 2022 SF All Industrial Activities Fixed Process 100% 100% 100% 100% Generating Electricity Using Fossil Fuels Non-Fixed Process 100% 100% 100% 100% Transmitting Natural Gas Non-Fixed Process 95% 90% 85% 80% All Other Industrial Activities Non-Fixed Process 98% 96% 94% 92%
Compensation and Credits; Compliance Flexibility
The EPS establishes two types of compliance instruments: emissions performance units (EPUs) and excess emissions units (EEUs). Each EPU or EEU represents one tonne of CO 2 e. A facility subject to the EPS that exceeds its annual emissions limit must purchase EPUs from the government. The cost of EPUs will be $20 per unit in 2020, $30 in 2021, $40 in 2022 and $50 in 2023. A facility subject to the EPS that emits less than its annual emissions limit will receive EEUs correspondingly. Generally, EEUs must be removed from a facility's account before any EPUs can be removed. However, the EPS permits certain compliance flexibility. EEUs can be banked for up to five years to address future compliance obligations. Alternatively, subject to certain notice requirements, EEUs may be transferred between facilities that are covered by the EPS.
Non-Applicability
The EPS regulations apply retroactively to January 2019 and are intended to serve as an alternative to the federal OBPS. However, the EPS regulations only apply to the extent that Ontario is not subject to the OBPS. For now, and unless the federal Governor-in-Council decides to remove Ontario from the OBPS or the decision of the Court of Appeal for Ontario (the "ONCA") in the constitutional reference (discussed further below) is overturned by the Supreme Court of Canada (the "Supreme Court"), the OBPS (not the EPS9) applies in Ontario.
Next Steps
The continued application of the federal OBPS may be affected by the outcome of the upcoming federal election (discussed further below). For now, industrial emitters in the designated provinces, including Ontario, are subject to the Federal Pricing Act and, if applicable, the OBPS.
Developments in Alberta
Alberta is the leading GHG emitter among Canadian provinces, and the home of significant oil and natural gas extraction and production centres. The provincial government of Alberta is led by the United Conservative Party (UCP), which was elected in April 2019 after promising, among other things, to scrap the carbon tax that had been put in place by the prior government (the "Alberta Levy").
Repeal of Alberta Levy and Consequent Application of Federal Pricing Act
The UCP repealed the Alberta Levy as its first legislative act. The repeal was made effective as of May 30, 2019. As a result, the federal government announced that Alberta will be subject to the backstop under the Federal Pricing Act. Consequently, the Federal Carbon Levy and federal OBPS are scheduled to take effect in Alberta on January 1, 2020. In response, Alberta filed a reference case with the Alberta Court of Appeal (the "ABCA") challenging the constitutional validity of the Federal Pricing Act. The ABCA will consider the issue afresh, but will have the benefit of the reasons laid out in the decisions of the Ontario and Saskatchewan courts.10
Cancellation of Reform to Electricity Sector
In July 2019, the UCP cancelled the planned overhaul of Alberta's energy system, thus providing that electricity generators in Alberta will continue to be paid only for the electricity they produce instead of being paid on the basis of capacity. Several Canadian provinces use a capacity-based system, including Ontario since 2004.
The UCP states that maintaining an energy-only (i.e., not capacity-based) system will benefit Albertans, who will only be charged for electricity that is used instead of paying for electricity capacity regardless of how much is used. Critics of the government's decision maintain that, if generators are not incentivized on a capacity basis, they will not invest in clean energy generation. There is also a concern that, if generators are not incented to install capacity, they will not build enough and there may be insufficient electricity available to satisfy peak demand. This is an issue of significant interest for the cleantech sector.
Federal Conservative Party Position
In anticipation of the federal Canadian election scheduled to take place on October 21, 2019, in June 2019, the Conservative Party of Canada (CPC) released a policy document entitled A Real Plan to Protect Our Environment (the "CPC Climate Plan"). Although vague in many respects, it is clear that the CPC Climate Plan would involve the repeal of the Federal Pricing Act, thereby eliminating the Federal Carbon Levy and terminating the OBPS.
In the place of the OBPS, the CPC Climate Plan refers to new and different GHG emissions standards that would apply to major emitters. Emitters who exceed these standards would be required to make certain "investments" in research and development of emissions-reducing technology relating to their industry. Notably, however, the CPC Climate Plan is silent with respect to:
the methodology by which the emissions standards would be set; and
the quantum of the "investments" that would be required to be made by emitters who exceed the emissions standards.
The CPC Climate Plan would make other changes of importance, including cancellation of the proposed Clean Fuel Standard (CFS), which is currently scheduled to come into effect in January 2022. The CFS is designed to incent the innovation and adoption of clean technologies in the oil and gas sector and the development and use of low-carbon fuels throughout the economy. Some stakeholders believe the changes proposed in the CPC Climate Plan would result in substantially higher emissions than under the Federal Pricing Act and other policies implemented by the Liberal government.11
The CPC has also promised to remove the GST from home heating and energy bills, which it believes will save the average Canadian household $107 per year.12 While modest in its expected impact, this change would appear to represent an additional subsidy of home heating fuels and to reduce the economic incentives to either conserve or replace GHG emitting heating equipment with non-emitting alternatives.
Challenges to the Federal Pricing Act and Implications for the Cleantech Sector
In July 2018, the Government of Ontario announced its withdrawal from the national carbon pricing program, revoked its cap-and-trade regulation, prohibited trading of emissions allowances and cancelled seven programs to be co-funded by the federal government through the Low Carbon Economy Fund.13 In August 2018, Ontario announced a reference to the ONCA to challenge the constitutionality of the Federal Carbon Levy and the OBPS under the Federal Pricing Act.
On June 28, 2019, in a 4-1 ruling, the ONCA found the Federal Pricing Act to be constitutionally valid. Writing for the majority, Chief Justice Strathy explained that setting minimum national standards for GHG emissions, as the Federal Pricing Act does, is a valid exercise of the federal government's jurisdiction under the "national concern" branch of its peace, order, and good government (POGG) power. He wrote that "the [Federal Pricing Act] strikes an appropriate balance between Parliament and provincial legislatures, having regard to the critical importance of the issue of climate change caused by GHG emissions, the need to address it by collective action...and the practical inability of even a majority of the provinces to address it collectively."
Further, Chief Justice Strathy explained that because the Federal Pricing Act only establishes minimum standards, it respects the jurisdiction of the provinces and allows them to legislate standards that meet or exceed minimums or address other aspects of GHG regulation, such as laws addressing the causes and effects of GHG emissions in a particular province.
The sole dissenting judge, Justice Huscroft, concluded that the Federal Carbon Levy and OBPS are not valid exercises of the national concern branch of the POGG power, partly on the basis that there is "no meaningful distinction" between the cumulative effects of GHG emissions and GHG emissions per se (which is a matter of provincial jurisdiction). He wrote that inaction by a province is not indicative of provincial incapacity to address GHG emissions, but is instead "a reflection of legitimate political disagreement on a matter of policy."
The immediate effect of the ONCA's decision is that the Federal Pricing Act continues to apply to Ontario. Ontario indicated it will appeal the decision to the Supreme Court. Saskatchewan, which lost a parallel reference case before its appellate court in May 2019, already commenced an appeal to the Supreme Court that is scheduled to be heard in January 2020. While the validity of the Federal Pricing Act has been upheld in the two appellate court decisions, Alberta (discussed above) and Manitoba have each filed their own challenges, and New Brunswick and Quebec have announced plans to intervene in support of Saskatchewan's appeal of the Federal Pricing Act before the Supreme Court.14
These ongoing court challenges, together with the CPC's commitment to repeal the Federal Pricing Act if it wins the upcoming federal election, have increased the uncertainty faced by cleantech businesses seeking to capitalize on the opportunities created by the price on GHG emissions under the Federal Pricing Act, and have made the outcome of this election a matter of considerable importance to the cleantech sector.
The recognized need for the cleantech sector to engage more effectively in the development of policies affecting the sector has led to the formation of the Ontario Clean Technology Industry Association and to increasing activity nationally by the Canada Cleantech Alliance.
For further information concerning these developments, please contact the authors or any other member of our Cleantech Group.
Footnotes
1. See the full text of the report: https://www.nrcan.gc.ca/sites/www.nrcan.gc.ca/files/energy/Climate-change/pdf/CCCR_FULLREPORT-EN-FINAL.pdf.
2. See the full text of the report of the Lancet: http://www.lancetcountdown.org/media/1418/2018-lancet-countdown-policy-brief-canada.pdf.
3. See the 2015 report commissioned by the Insurance Bureau of Canada: http://assets.ibc.ca/Documents/Studies/IBC-The-Economic-Impacts.pdf.
4. The goal of carbon neutrality by 2050 originates in a report of the Intergovernmental Panel on Climate Change (IPCC), which highlighted the climate change impacts that will likely arise unless global warming is limited to 1.5°C instead of 2°C. See the full text of the IPCC report: https://report.ipcc.ch/sr15/pdf/sr15_spm_final.pdf.
5. See the Declaration of the Carbon Neutrality Coalition: https://www.carbon-neutrality.global/wp-content/uploads/2018/09/CNC-Declaration-final.pdf.
6. See the full text of the "State and Trends of Carbon Pricing 2019" report of the World Bank: http://documents.worldbank.org/curated/en/191801559846379845/pdf/State-and-Trends-of-Carbon-Pricing-2019.pdf.
7. See our January 23, 2018 Update, Feds Announce Proposed Carbon Pricing System as Part of Pan-Canadian Clean Growth Plan.
8. In Saskatchewan, the federal OBPS applies only to facilities engaged in electricity generation and to natural gas transmission lines.
9. Except for certain registration requirements that apply as of January 2019.
10. See our May 16, 2019 Update, Saskatchewan Court of Appeal Rules Federal Carbon Price is Constitutionally Valid.
11. For an example of an analysis reaching this conclusion, see: https://policyoptions.irpp.org/magazines/august-2019/emissions-will-rise-under-conservative-climate-plan/.
12. See: https://www.conservative.ca/conservatives-to-remove-gst-from-home-heating/.
13. See our January 7, 2019 Update, Federal and Ontario Updates on Climate Change and Clean Growth Plans, our November 12, 2018 Update, Cap and Trade Formally Cancelled in Ontario – Federal Carbon Pricing Regime Clarified, our August 7, 2018 Update, Ontario Introduces Bill to Cancel Cap and Trade and Launches Carbon Tax Case and our June 27, 2018 Update, Going, Going, Gone – Ontario Premier-Designate Announces Cancellation of Cap and Trade; Pulls Ontario Out of August GHG Auction.
14. Quebec and New Brunswick have announced plans to join the Saskatchewan appeal as interveners. See: https://nationalpost.com/news/politics/a-unified-messageprovinces-move-to-synchronize-battle-plans-against-carbon-tax/.
The content of this article does not constitute legal advice and should not be relied on in that way. Specific advice should be sought about your specific circumstances.
(MENAFN - Gulf Times) China became the world's biggest natural gas buyer last year. Now it wants to start setting its own price.
That's because importers have been paying rates influenced by events unrelated to China's supply and demand balance from European weather to Middle East conflicts. So like it has for oil, gold and iron ore before, producers, distributors and financial exchanges in the top commodities market are seeking prices that they say better reflect Chinese fundamentals, and in their own currency.
The search for an internationally recognised Chinese natural gas price, including a proposed futures contract, follows the larger pattern of the world's biggest commodities consumer seeking a greater say in how to price the raw materials it consumes.
'We've been taken advantage of by foreign firms, Xu Tong, a deputy general manager of distributor Beijing Gas Group Co, said in an interview. Domestic indexes will 'reduce premiums significantly.
China is also opening its commodities derivatives markets to foreign traders, partly in an effort to broaden the appeal of its currency, the yuan. In March 2018, an exchange in Shanghai introduced an oil futures contract for overseas investors, while Dalian followed two months later by opening up its iron ore trade.
China's natural gas demand has boomed in recent years as the government of President Xi Jinping pushed industrial and residential customers away from coal. But domestic production of the gas hasn't kept pace with consumption. Imports, meanwhile, surged almost 32% last year.
Domestic gas sales follow two different pricing structures: a government-set price for pipeline supplies, which is open to some negotiation between buyers and sellers, and the unregulated market for liquefied natural gas transported on trucks. And for imports, China mostly pays in US dollars at prices based mainly on either global oil or gas benchmarks set in the US or Europe.
The structure can contribute to losses for Chinese companies that resell overseas gas at lower domestic rates. PetroChina Co, the top oil and gas supplier, has chalked up $34bn of losses since 2011, when it began regularly reporting the figures.
LNG contracts first became tied to oil prices at a time when the fuel competed with petroleum used for home heating and power generation. More importantly, oil provided transparent and liquid price benchmarks that allowed buyers to hedge and sellers to secure bank financing. But prices have begun to uncouple as the global gas market deepens.
'Gas fundamentals can't be reflected by oil they are two separate products, Wu Yifeng, deputy general manager of natural gas at PetroChina's international unit, said in an interview in Beijing.
Europe and the US have natural gas benchmarks that reflect supply and demand in their respective markets and are liquid enough to bank on. Asia doesn't have that yet. A futures contract built around the current spot benchmark in northeast Asia assessed by S & P Global Platts is gaining traction, but remains a far cry from what's seen in the west.
Chinese gas companies are trying to build their own, drawing on the success of the nation's Dalian iron ore futures, which global traders look to for daily price signals because of the sheer size of the market.
The Shanghai Futures Exchange has said it plans to launch natural gas futures, though no timing has been set. The Shanghai Petroleum & Natural Gas Exchange, or SHPGX, hosts auctions for small quantities of domestic gas and publishes daily trucked LNG prices.
Whether China is able to achieve the clout it desires with gas prices may depend on ease-of-use and investor interest. Currently, crude oil, iron ore, rubber and purified terephthalic acid (used to make plastics and polyester) are open to foreigners, and most other commodity futures are isolated to only the domestic market. The gas contract SHFE is mulling will allow offshore entities to trade.
Another key factor for China's pricing ambitions is a long-awaited national pipeline reform. The move to give more suppliers access to the transportation networks, which is now mainly operated by the three state-owned giants, must happen for prices to freely reflect the broader market, said Chen Gang, an assistant to the general manager at SHPGX.
Only then can domestic prices become a benchmark, with support from the derivatives market, according to Chen. The final step may be to link those prices to imported gas, he said.
MENAFN2610201900670000ID1099184753
Just days before a widely expected official approval, for what would be the world’s largest initial public offering (IPO) ever, Saudi Arabia has delayed, yet again, the much-hyped listing of its oil giant Aramco - by at least several weeks.
With international investors not really buying the Saudi price tag of $2 trillion for the biggest oil company in the world, Riyadh had little option, but to delay the listing - once again.
Over the past two months, once the Khashoggi saga was almost sidelined, Aramco had noticeably accelerated the timeline for the much-hyped listing. The $2tr valuation that the Saudis have been seeking, has been one of the sticking points, together with the international venue for the listing and concerns over the transparency of Saudi reserves.
At a meeting to endorse the IPO last week, the banks Aramco had hired for the listing, made clear that foreign investors were not rushing in to invest in the Saudi state oil company at the targeted valuation of $2tr, Bloomberg reported.
Most bankers didn’t agree with the valuation of the company that Saudi Crown Prince Mohammed bin Salman (MBS) and his negotiating team have been insisting upon. According to one of those sources, if Aramco wanted to stir real interest among international investors, the valuation needed to be closer to $1.5tr.
During the meeting, bankers highlighted the lack of appetite among the international players in investing in the state oil firm of the kingdom, where production levels, governance, and management would continue to be controlled by Saudi Arabia. With Aramco potentially listing just 5 per cent on the stock market, all major decisions at the company would also remain in the hands of Riyadh - the Organisation of the Petroleum Exporting Country’s largest producer and its de facto leader.
With the emergence of alternatives, the ongoing shale revolution and the future of crude demand at risk, courtesy the ongoing climate debate and the Green movement, not many seemed ready to make the bet, with a $2 trillion tag on it, bankers insisted.
Can now Riyadh realise its valuation target of $2tr remains a moot point of discussion.
As per Bloomberg, MBS has now two options. One is to drop the $500 billion from his initial $2tr valuation or to raise the money from wealthy Saudi families or from the sovereign wealth funds. Talks reportedly took place with Abu Dhabi Investment Authority, Singapore’s GIC and other funds.
Looking to diversify their portfolio, sovereign funds in the oil-rich Gulf region were known to be typically shy of energy exposure, reports indicated. On its part, Aramco wanted the anchor investors to cover no less than 40pc of the offering.
Sovereign wealth funds were thus not eager to jump on. One Gulf institutional investor, involved in the discussions, said Aramco was unable to answer valuation questions fully, during initial talks with investors.
A debate within Saudi Arabia is also raging – in hushed tones. Informed circles indicate that the head of the former, high profile, Saudi Energy Minister Khalid Al-Falih had to be rolled, once it was felt, he was not too enthusiastic about the IPO, given the current oil market environment. He had to pay a price and so he did.
A highly-paid army of bankers, financial advisers, consultants and public relations flacks drafted into the kingdom, have once again failed to deliver the Aramco IPO on schedule.
Yet, there are silver linings at the end of the tunnel too. A number of Russian investors are interested to invest in Saudi Aramco, Kirill Dmitriev, the chief executive officer of Russian sovereign wealth fund RDIF said while in Riyadh.
China has also offered to buy up to 5pc of Saudi Aramco directly, recent reports said. Chinese state-owned oil companies PetroChina and Sinopec have written to Saudi Aramco in recent weeks, expressing their interest in a direct deal, industry sources told Reuters. “The Chinese want to secure oil supplies,” one of the industry sources said. “They are willing to take the whole 5pc, or even more, alone.”
The issue of valuation here is still not clear though.
Sources told Reuters a couple of weeks earlier that Saudi Aramco was evaluating a private placement of shares to a Chinese investor as a precursor to an international IPO. Sovereign wealth funds from South Korea and Japan, other major buyers of Saudi oil were also interested in acquiring a stake in Aramco – and for obvious reasons.
Yet, the task is uphill. Royals generally do not swallow their words. MBS may not be an exception, too.
Published in Dawn, October 27th, 2019
What does the shale industry have in common with Silicon Valley startups? Both are losing favor with investors tired of spending money and seeing few returns.
Operators pulled the highest number of oil and gas rigs out of service as they have in six months as the energy slowdown continues to squeeze operators to cut back oil production.
U.S. oil and gas operators pulled a net 21 rigs out of service last week, 17 oil and four gas, according to the Baker Hughes North America rig count, the most in a single week since April. The majority of the decline was driven by Permian Basin operators, where a net five oil and gas rigs were lost.
The huge decline brought the nation's total number of oil and gas rigs to 830, more than 200 fewer than the same week a year ago.
The shale boom has been losing momentum as the oil and gas industry faces the prospect of another downturn. Oil prices are stuck in the $50-$60 per barrel range -- hardly enough for oil and gas companies to turn a profit -- and shale companies have lost favor with investors after failing year after year to deliver returns.
The slowdown is beginning to affect jobs in oil-rich states. Texas employers, for example, have cut nearly 6,000 jobs in energy over the last four months.
BP and Kosmos Energy have made a “major gas discovery” offshore Mauritania.
Dallas-headquartered Kosmos said the Orca-1 well — about 75 miles off the coast — was estimated to have about 13 trillion cubic feet of gas in place.
The well also confirmed gas in a down-structure position relative to the original Marsouin-1 discovery well.
Kosmos said it believes Orca and Marsouin have de-risked up to 50 tcf of gas.
Andrew Inglis, chief executive of Kosmos, said: “The Orca-1 well concludes a very strong year for exploration and appraisal in Mauritania and Senegal.
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“Orca-1, which we believe is the largest deepwater hydrocarbon discovery in the world so far this year, further demonstrates the world-scale quality of the Mauritania gas basin.
“With sufficient resource in place at the BirAllah hub, Kosmos looks forward to working with the Government of Mauritania and its partners to bring benefits to the people of Mauritania through the development of cost competitive, low carbon intensity projects.”
BP and Kosmos are partners on the acreage alongside the Mauritanian Government.
https://www.energyvoice.com/oilandgas/africa/210682/bp-kosmos-in-major-gas-find-off-mauritania/
If it’s not one thing, it’s another in the Permian natural gas market. Just as it appeared that prices in the West Texas basin were finally turning a corner and strengthening with the full start-up of Kinder Morgan’s Gulf Coast Express Pipeline (GCX) late last month, various issues have again conspired to send daily Permian cash prices back down to near zero yet again. And it’s not just the daily spot markets that have come under pressure; forward prices were also severely discounted a few days ago when Kinder Morgan announced that the in-service date of its next long-haul pipeline from the region — the Permian Highway Pipeline project — would be delayed from late 2020 to early 2021. Keeping track of the roller-coaster ride of Permian gas prices and the drivers behind the highs and lows continues to keep heads spinning. Today, we explain the latest wild moves in the Permian natural gas market.
To start things off, let’s consider the recent price volatility at the Permian Basin’s primary natural gas market trading location, the Waha Hub, based on the daily spot price index published by our good buddies over at Natural Gas Intelligence (NGI). After prices plunged to almost $6.00/MMBtu below zero in early spring (Figure 1, shaded red circle; see Don’t Dream It’s Over for more on negative prices from earlier this year), some factors such as production shut-ins and power demand helped stabilize the price at Waha to between zero and around $1.00/MMBtu through the rest of spring and summer (shaded gray rectangle). But nothing did more to strengthen Waha prices than the start of Kinder Morgan’s GCX, which began partial service in mid-August and entered full commercial service on September 25. A few weeks of strong prices followed (shaded green circle) and, as we said in Pinch Me, we expected the available takeaway capacity on GCX to hold Permian prices in positive territory (i.e., above zero), at least until “the holidays.” Turns out that holiday in question may have been Columbus Day, as things in the daily gas markets have certainly taken a turn for the worse as Halloween (another holiday of sorts) approaches (purple arrow). One thing is sure: Christmas hasn’t come early for Permian natural gas marketers (last quip, we promise). While Waha gas prices still remain well above the lows set earlier this year, they are again treading just barely above zero.
Figure 1. Waha Daily Average Price. Source: Natural Gas Intelligence (NGI)
So, as customers of our weekly NATGAS Permian Report have been asking lately, what in the world has happened at Waha? The answer, in our opinion, is quite simply: production. With the start-up of GCX, which added 1.98 Bcf/d of new capacity from Waha to South Texas, Permian production was no longer constrained by pipeline takeaway capacity. As you can see in Figure 2 below, until GCX came online, gas production in the basin had been trending sideways for most of this year, with flows already having exhausted all the pipeline capacity for moving gas out of Waha to other regions of the U.S. and Mexico (dashed line in Figure 2). Over this period of constrained pipeline takeaway, the Permian was also relying heavily on the local power-generation and gas-storage sectors to soak up as much production as possible. [See our Money For Nothing, Gas For Free blog for more on Permian power demand.]
Once GCX began full operation in late September, however, production immediately ramped higher, eclipsing the previous record highs of just over 10.0 Bcf/d and charging up to near 11.5 Bcf/d in recent days. In addition to the sharp uptick in production, GCX pulled away some volumes from the previously mentioned power and storage operators in the Permian, and a small amount of gas was also diverted to GCX from other pipelines, particularly gas that had been flowing from the Permian north to the Midcontinent (see Omaha). As a result, GCX filled to near capacity almost immediately. Then, throw in a few capacity-reducing maintenance events on the basin’s already-constrained legacy takeaway pipes, and gas prices at Waha once again came under pressure, less than a month after a brand-new pipeline had started up (remember the purple arrow in Figure 1).
Figure 2. Permian Natural Gas Production. Source: RBN’s NATGAS Permian Report
In fact, things have deteriorated so quickly that the Waha gas price even turned negative on one day recently. But if you thought that was the only curveball being thrown outside of the World Series, think again. More bad news has hit the Permian gas market in recent days. Having just started GCX (red line in Figure 3) slightly ahead of the original schedule of October 1, Kinder Morgan announced on its October 16 earnings call that permitting delays had impacted the schedule for its next major project, the Permian Highway Pipeline (PHP). We wrote about PHP (dashed orange line) last year and, at the time, the 2.1-Bcf/d pipeline to the Texas Gulf Coast was still on track, given that a recent court ruling in Austin seemed to pave the way for construction to begin in the Texas Hill Country. We still don’t know the details on the PHP delays, but Kinder at least tipped the market that the original start date planned for the fourth quarter of 2020 wasn’t going to happen and PHP is now expected to start in early 2021. That was not what the forward Waha basis markets wanted to hear last week.
Figure 3. Permian Natural Gas Pipeline Projects. Source: RBN Energy
Back in July 2017, the 2020 calendar strip for Waha basis was sitting about $0.35/MMBtu below Henry Hub (gray line in Figure 4). My, how things have changed. For starters, the Waha forward curve has drifted lower over the last couple of years, and as of October 15, 2019 — just before Kinder Morgan announced the PHP delay — the 2020 basis strip, in particular, sat at about $1.35/MMBtu below Henry (red line in Figure 4). That calendar average included a dramatic strengthening of forward basis later in 2020, reflecting market expectations for PHP to add 2.1 Bcf/d of new pipeline capacity out of the Permian in the fourth quarter of 2020. Using closing prices for Waha basis from Bloomberg on October 15, the last three months of 2020 were trading an average of just $0.95/MMBtu below Henry, much stronger than the months preceding the start of PHP. However, the news from Kinder Morgan regarding PHP the following day elicited a quick reaction from the market. By market close on October 18 (blue line in Figure 4), Waha basis for the fourth quarter of 2020 had dropped a staggering $0.55/MMBtu (shaded green circle), bringing the full 2020 calendar strip down $0.15/MMBtu on average versus the day before the announcement (October 15). Even worse for those looking to sell their gas at Waha, the uncertainty on PHP’s start date even took down the 2021 calendar strip for Waha, which dropped by $0.10/MMBtu between October 15 and 18. No doubt, a few million dollars were likely transferred among the traders that play the Waha basis markets, but for those producers not yet hedged, the missed opportunity certainly stings.
Figure 4. Waha Basis Forward Prices For 2020 and 2021. Source: Bloomberg
So, what happens next? Well, it isn’t going to be pretty. There is no changing the fact that no new pipelines out of the Permian will be coming online over the next year, and we have little doubt that production will continue to grow. Is there a glimmer of hope at least? Well, maybe. For one, Permian power plants could likely soak up more gas than they did for most of 2019, but this will only occur if Waha prices remain near zero or dip into negative territory again. And, there’s always the hope that pipelines to Central Mexico will finally be completed. Despite our desire to be optimistic around changes south of the border, however, we have found ourselves constantly revising lower our Mexico export assumptions over the last few years. There’s also always flaring, although recent data from the Texas Railroad Commission (RRC) suggests that producers are still not broadly using this approach to dispose of excess gas. That really only leaves the last-resort option of shutting in “dry” gas, and potentially “wet” gas, particularly if it doesn’t require shutting in wells that focus on crude oil. How much of this can be done remains to be seen. Shut-ins during 2019 seemed to occur only once absolute prices for Permian gas fell below zero, and gas volumes didn’t return until prices returned to firmly positive territory once GCX started up. That said, there is reason to believe next year’s takeaway constraints, which we see starting sometime in the first quarter, could be more severe and last longer than those of 2019. That means that the volumes required to be curtailed could be larger. Want to shut in more Permian gas than 2019? Well, that would require even lower prices, which implies that 2020 could test the record-setting negative price levels seen earlier this year.
https://rbnenergy.com/taste-the-pain-permian-natural-gas-prices-get-crushed-again
Apache executive’s departure sparks worst rout since 2016
By Rachel Adams-Heard on 10/27/2019
HOUSTON (Bloomberg) - The high-profile geologist leading one of Apache Corp.’s most-important exploration ventures has stepped down. The company’s shares and bonds tumbled, and the cost to insure against default surged.
Steven Keenan, Apache’s senior vice president of worldwide exploration, resigned two days ago, company spokesman Phil West said in an email on Friday. The geologist’s departure may fuel concerns about the fate of Apache’s search for crude in Suriname, adjacent to an Exxon Mobil Corp. discovery that’s one of the world’s biggest finds in years.
“Mr. Keenan’s resignation is not connected to Suriname,” West said. “The drill bit is still above the first target zone in the Suriname well.”’
Apache may provide an update on the progress of its exploratory efforts across the 1.4-million-acre offshore tract known as Block 58 as soon as Oct. 30, when the Houston-based company is scheduled to report third-quarter results.
The shares fell as much as 11% on Friday for the biggest intraday drop since January 2016. The stock was down 5.6% to $21.93 at 1:34 p.m.
The cost to insure against an Apache default jumped to the highest since August 2016. Five-year credit-default swaps tied to the company were among the worst performers in the investment-grade CDS market, widening to as much as 31 basis points on a day when the overall market tightened by 1.2 basis points.
The yield on Apache’s most actively traded bond, 4.375% notes that mature in 2028, widened by 21 basis points, according to Trace, and were among the most actively traded notes in the investment-grade market.
As recently as last week, Bank of America Merrill Lynch touted the Suriname prospect as potentially game-changing for Apache.
It “has potential to reset the investment case,” Merrill Lynch’s veteran oil-industry analyst Doug Leggate said in an Oct. 18 note to clients. On the strength of that thesis, Leggate upgraded his rating on the stock and said a single good well could translate into a $6-a-share benefit for Apache.
Keenan was hand-picked by Apache’s then-Chief Executive Officer Steve Farris in 2014 to replicate the dramatic discoveries he oversaw for EOG Resources Inc. in the Eagle Ford shale basin in South Texas.
Not long after he joined Apache, the company announced its Alpine High discovery in a little-drilled corner of the Permian Basin in West Texas. At the time, the company said the play held 3 billion barrels of crude and 75 trillion cubic feet of gas.
But Apache’s stock has underperformed rival producers since it first touted the Alpine High find, which turned out to be far richer in gas than more valuable crude.
Related News ///
FROM THE ARCHIVE ///
Israel has granted offshore exploration blocks to two consortia of oil companies that placed their bids in the recent licensing round.
Energy ministry on Monday granted Cairn, Pharos (ex-SOCO), and Ratio eight licenses, in Blocks 39,40,47,48 (group A) and 45,46,52,53 (group C).
Oil and gas companies Energean and Israel Opportunity were awarded exploration licenses in blocks 55,56,61,62 (group D)
As reported in July, the Energy Ministry had in the licensing round tendered 19 exploration licenses, each one up to 400 km² in size. The 19 licenses were grouped into five zones, each up to 1,600 km² in size.
According to the ministry, the decision to market the areas in zones of 3-4 licenses was taken to provide a higher degree of compatibility between the geological structures within the exploration areas, which could contain oil and natural gas reservoirs.
It was the ministry’s view that holding larger exploration areas would enable the companies to undertake more extensive and thorough geological and geophysical surveys.
Pharos (until recently known as Soco International) and Cairn will further expand the presence of the international oil companies in the Israeli waters.
Currently, the U.S. Noble Energy operates the Tamar gas field and is working to bring the giant Leviathan gas field online by the end of 2019. In addition to Noble, the Greek company Energean is developing the Karish and Tanin fields, which it bought from Noble Energy in 2016.
The Israeli energy ministry has previously said that exploration licenses would be granted for a period of 3 years.
During this period, the licensees are expected to carry out the committed work program, which centers on examining the awarded area. After this, the licensees can request another two-year term extension, contingent upon an updated work program being submitted to include drilling a well in at least one of the licenses it respective clusters.
The third licensing round is due to be held in 2021.
Offshore Energy Today Staff
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Norwegian oil and gas giant Equinor has selected oil and gas advisory and classification society DNV GL as the certifying authority for the Bay du Nord project off Canada.
DNV GL said on Monday that it would ensure that new infrastructure that would be built for Equinor’s Bay du Nord oil field project was compliant to local and global safety requirements.
The classification society will oversee design review activities and site surveillance during construction, commissioning, and installation, after being awarded the certifying authority and classification contract.
The Bay du Nord field is located around 480 kilometers northeast of St. John’s, Newfoundland and Labrador, in the Flemish Pass Basin.
The field will be the first one developed in this basin. No existing infrastructure is in the immediate area, which is known for its harsh environmental conditions, including large sea states, high winds, sea ice, and icebergs.
Bay du Nord was discovered in 2013, aiming to produce its first oil in 2025. The project is currently in the pre-FEED phase, and the final investment decision is planned in the second quarter of 2021.
The field development comprises an FPSO, a disconnectable turret and moorings system, steel lazy wave risers, and a subsea development with four subsea templates.
Halfdan Knudsen, Equinor’s project director, said: “Safety, environmental protection, and regulatory compliance are fundamental requirements for the Bay du Nord Project.
“DNV GL has been selected as the certifying authority and classification society for the project, supported by our development partner Husky Energy.”
Liv A. Hovem, CEO of DNV GL – Oil & Gas, added: “I am delighted Equinor has recognized that we possess the technical expertise and global footprint to assure safety on the ambitious Bay du Nord project. We have worked closely with Equinor on many projects over the years, including challenging sites in the North Sea, and this contract win is a sign of the strength of our relationship.”
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Sempra Energy, Mitsui enter deal for future expansions of two LNG export terminals
San Diego utility company Sempra Energy and Japanese industrial conglomerate Mitsui & Co. have entered into a memorandum of understanding to expand a liquefied natural gas export terminal in Louisiana and another in Baja California. less San Diego utility company Sempra Energy and Japanese industrial conglomerate Mitsui & Co. have entered into a memorandum of understanding to expand a liquefied natural gas export terminal in Louisiana and ... more Photo: Melissa Phillip, Houston Chronicle / Staff Photographer Photo: Melissa Phillip, Houston Chronicle / Staff Photographer Image 1 of / 7 Caption Close Sempra Energy, Mitsui enter deal for future expansions of two LNG export terminals 1 / 7 Back to Gallery
San Diego utility company Sempra Energy and Japanese industrial conglomerate Mitsui & Co. have entered into a memorandum of understanding to expand a liquefied natural gas export terminal in Louisiana and another in Baja California.
The two companies are part of a consortium building three liquefied natural gas production units during the first phase of development at the Cameron LNG export terminal in southwest Louisiana. Under the memorandum, the companies have agreed to help each other build two more production units as part of a phase 2 expansion.
Sempra and Mitsui also agreed to help each other develop an LNG export terminal at the already existing Energia Costa Azul import terminal along the Pacific Ocean south of Tijuana.
Slideshow: Five LNG export terminals now operating in United States
Mitsui has agreed to buy up to one-third of the available capacity for phase 2 of Cameron LNG. The Japanese company also agreed to buy up to 1 million tons of LNG per year and invest in the Energia Costa Azul expansion.
“This agreement signals continued momentum in the growing U.S. liquefied natural gas export market, while reinforcing the unique competitive advantage that Sempra offers customers seeking LNG export capabilities from the Gulf Coast, as well as the West Coast of North America,” Sempra LNG President Justin Bird said in a statement.
Cameron LNG sent out its first cargo in late May. The shipment was classified as a commissioning cargo, which is used to stabilize production and test the performance of equipment during an LNG plant's startup process.
Sempra owns 50.2 percent of Cameron LNG. Its partners include French energy company Total, Japanese industrial conglomerate Mitsui & Co. and Japan LNG Investment — a joint venture between Mitsubishi Corp. and Nippon Yusen Kabushiki Kaisha.
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Federal regulators have given crews until September 2020 to complete the second and third production units at the Louisiana facility.
Once all three are in operation, Cameron LNG will be able to make nearly 12 million metric tons of liquefied natural gas per year.
Those production figures translate roughly to about 1.7 billion cubic feet of natural gas per day, enough energy to power 8.5 million U.S. homes for a day.
Read the latest oil and gas news from HoustonChronicle.com
Drilling Down: Callon, Carrizo drill up to last minute of merger vote
An aerial view shows drilling activity at a Carrizo Oil & Gas wells in northern LaSalle County. An aerial view shows drilling activity at a Carrizo Oil & Gas wells in northern LaSalle County. Photo: Carrizo Oil & Gas / Carrizo Oil & Gas Photo: Carrizo Oil & Gas / Carrizo Oil & Gas Image 1 of / 1 Caption Close Drilling Down: Callon, Carrizo drill up to last minute of merger vote 1 / 1 Back to Gallery
Callon Petroleum and Carrizo Oil & Gas are drilling right up to the last minute of a controversial Nov. 14 merger vote between the two companies.
The proposed $3.2 billion merger faces investor opposition, but both companies stand behind the deal. If the merger is approved, the combined company would become one of the top 20 drillers in Texas, a review of drilling permits shows.
In the meantime, Carrizo filed for 15 drilling permits over the past week with the Railroad Commission of Texas, the state agency that regulates the oil and gas industry. Carrizo is seeking permission to drill eight horizontal wells in the Permian Basin and another seven in the Eagle Ford Shale.
Carrizo’s leases in Texas produced nearly 17 million barrels of crude oil, nearly 64 billion cubic feet of natural gas and more than 4 million barrels on condensate in 2018.
Focused on the western end of the Permian Basin, Callon has filed for 41 drilling permits so far this year — all of them in Howard and Ward counties. The company’s leases in Texas produced nearly 15 million barrels of crude oil and 27.8 billion cubic feet of natural gas last year.
Permian Basin
Top 10 Texas Drillers (Wednesday, Oct. 16 through Tuesday, Oct. 22) Pioneer Natural Resources 20 EOG Resources 18 Marathon Oil 16 Carrizo Oil & Gas 15 Exxon Mobil 15 Occidental Petroleum 10 Kinder Morgan 7 Chevron 6 Guidon Energy 6 BP 5 Source: Railroad Commission of Texas
Irving oil and gas company Pioneer Natural Resources is preparing to drill 20 horizontal wells targeting the Spraberry field in Midland and Reagan counties at total depths up to 10,325 feet. One of the top 5 drillers in Texas, Pioneer has filed for 322 drilling permits so far this year.
Eagle Ford Shale
Houston exploration and production company Marathon Oil is gearing up to drill 15 horizontal wells and one vertical well split between Atascosa, Gonzales and Karnes counties. Thirteen of the horizontal wells target the Eagle Ford formation and two target the Austin Chalk. The vertical well is for a future saltwater disposal well targeting the Eagle Ford.
Haynesville Shale
Irving oil major Exxon Mobil is planning to drill a pair of horizontal wells on leases in Shelby and San Augustine counties that target the natural gas-rich Carthage field of the Haynesville geological layer at total depths up to 20,000 feet.
Barnett Shale
No drilling permits were filed for horizontal wells in North Texas this past week, but Granbury oil company Caribou Operating is drilling a vertical well on its Briscoe lease in Jack County. Located five miles east of Antelope, the well targets the Caddo, Ellenburger and Pool formations at a depth of 6,500 feet.
Conventionals
Located just west of San Antonio, Medina County is emerging as a conventional drilling hot spot. Civron Petroleum Resources of Devine plans to drill a vertical well targeting the Fairfield field at a depth of 1,600 feet on its Young lease about 15 miles southeast of Hondo. Brookshire-based Texas Secondary Oil Corp. plans to drill two vertical wells targeting the Taylor-Ina field on its Wilson P Unit 3 lease about 5 miles west of Biry.
Mild weather in 2018/19 has meant gas stores - accounting for about a fifth of annual demand - are well up on the roughly 52% level a year ago, said Berlin-based Fernleitungsnetzbetreiber (FNB), releasing its outlook report.
"Winter may start. We are prepared," said FNB's managing director Ralph Bahke, saying possible shortfalls in some locations could be met with flexibility elsewhere.
Germany, Europe's biggest gas market after Britain and an importer of more than 90% of its needs, receives Russian gas via Ukraine and Poland and via the Nord Stream 1 pipeline across the Baltic Sea for onward distribution to countries in the region.
Opal was ordered in September to cut some 40% of shipments received from Nord Stream after Poland successfully contested Russia's supply dominance in court.
The effect of the reduction has been limited so far, thanks to the availability of cheap alternative supplies.
This has also been the case for TENP 1, which runs from the Netherlands to Italy and Switzerland via south-western Germany and has been grappling with corrosion problems, prompting moves to explore rebuilding parts of it by 2025.
Norway and the Netherlands also supply large volumes of gas to Germany, where users have also begun tapping into ample supplies of liquefied natural gas (LNG) on the world market.
FNB said it would monitor throughout the winter the impact of the Opal and TENP 1 challenges on storage drawdowns.
It will also monitor talks between Russia and Ukraine over the future of gas transit flows after a long-term contract expires at the end of this year.
FNB said intra-European gas market provisions could be activated to help cope with any disruptions that might require additional gas flows from central to south-Eastern Europe.
Another long-term challenge is a change to full high-calorific gas specifications as the Netherlands phases out its production of a low-calorific gas type commonly used in transport and consumer infrastructure in northwest Europe.
FNB members include Gascade Gastransport, Ontras Gastransport [LANDWE.UL] and Open Grid Europe.
(Reporting by Vera Eckert; Editing by Mark Potter)
The largest banking lenders to the oil and gas sector are becoming more cautious, marking down their expectations for oil and gas prices that underpin loans in a move expected to put further financial stress on struggling producers, industry and banking sources said.
Major banks including JPMorgan Chase (JPM.N), Wells Fargo (WFC.N), and Royal Bank of Canada (RY.TO) have, as part of regular biannual reviews, cut their estimated values for oil-and-gas companies’ reserves, which serve as the basis for those companies to receive reserve-based loans (RBLs), according to more than a dozen sources familiar with the activity.
While the size of the RBL market is unclear, it is estimated that a few hundred companies take such loans, with the cumulative size in the billions of dollars.
Those lenders have marked down the perceived value for both oil and natural gas for the coming five years, with the changes kicking in as early as this month.
Expected natural gas prices have been cut by around $0.50 per million British thermal units, about 20% below levels set in the spring. Industry sources are forecasting some firms face a 15% to 30% reduction in loan size as a result. Oil prices are expected to be about $1 to $2 lower than spring estimates.
“Some banks believe they have too much energy exposure and want to reduce some of this risk,” said Ian Rainbolt, vice president of finance at Warwick Energy, a private equity firm with upstream investments in Oklahoma and Texas.
That is a threat to smaller companies, which are already struggling to find other methods of financing - such as issuing stock or bonds - as investors grow restless with years of poor returns in the shale sector even as the United States has risen to become the world’s largest oil and gas producer.
Reduced funding could slow growth in U.S. oil and gas production, and also threaten more bankruptcies in the sector. Bankruptcy filings among U.S. oil and gas producers are at levels not seen since 2016, when U.S. crude slumped to $26 per barrel, according to law firm Haynes and Boone.
Companies heavily focused on natural gas drilling may be the most threatened. Banks are forecasting natural gas prices between $2 and $2.35 per million British thermal units for the next 12 months, and up to $2.50 at the end of the five-year term, all lower than in the spring.
“I expect the biggest issues to be with over-leveraged natural gas producers, especially those without firm transportation in geographically-disadvantaged areas,” said Brock Hudson, managing director at investment bank Carl Marks Advisors, who referenced companies in Appalachia, the Rockies and parts of Oklahoma.
Smaller RBLs can have huge consequences: Alta Mesa Resources, an Oklahoma-focused producer headed by former Anadarko Petroleum chairman Jim Hackett, filed for bankruptcy a month after its borrowing base was slashed by almost half in mid-August.
A number of banks, including JP Morgan, Wells Fargo, and Comerica Inc (CMA.N), declined to comment or did not respond to requests for comment.
REDUCED AVAILABILITY
Eight sources indicated larger banks have set their price decks, the industry term for the value they will ascribe to hydrocarbons behind the RBLs, with oil between $46 and $51 per barrel for the next five years.
There are fewer financing options available to help bridge the gap from lower RBLs. Just one U.S. producer, Contango Oil & Gas (MCF.A), has issued any new equity in 2019, while there has only been one high-yield bond offering by a shale producer since March, according to Refinitiv data.
Since 2018, the S&P 500 Energy Sector .SPNY is the worst performing sector in the Standard & Poor’s 500, falling 18% against a 12.8% increase for the broader index, and many publicly-traded shale companies have done even worse.
Those facing lower loan guarantees also can not rely on selling unwanted assets to raise cash as mergers and acquisitions activity is at its lowest level in a decade. Profiting from further production is also difficult, as the number of active oil and gas rigs is at its lowest level since April 2017, according to Baker Hughes.
Scott Richardson, head of U.S. energy investment banking at RBC Capital Markets, said any uptick in bankruptcies would likely come from the SCOOP/STACK area of Oklahoma and the gas-heavy southern portion of Texas’ Midland Basin.
Loan covenants are also being tightened, according to a Dallas Federal Reserve Bank energy survey published Sept. 25. The survey said some participants noted banks had lowered the maximum debt level permissible to 2.5 to 3 times earnings before interest, taxes, depreciation and amortization (EBITDA), from 3.5 to 4.0 times.
Some regional lenders have kept prices for oil and gas in fall’s redetermination higher than the larger institutions, according to three of the sources.
Warwick’s Rainbolt, who has oversight over four RBLs, said it was switching to regional banks, which offered better price decks. One bank priced gas starting at $2.37, rising to above $3 in the final year, with crude at $52 rising to near-$60 a barrel.
BP’s (BP.L) third-quarter profit dropped sharply, but still beat expectations, hurt by weaker oil prices, lower production and one-off charges linked to large divestments.
London-based BP reported on Tuesday third-quarter underlying replacement cost profit, the company’s definition of net income, of $2.3 billion, exceeding forecasts of $1.73 billion in a company-provided survey of analysts.
That compared with $3.83 billion a year earlier and $2.81 billion in the second quarter of 2019.
The sharp drop will not come as a surprise to investors after BP indicated earlier this month that it would take a non-cash charge of $2 to $3 billion in the quarter as it gets closer to divestments worth $10 billion by the end of 2019, a year ahead of schedule.
Reported oil and gas production for the quarter averaged 3.7 million barrels of oil equivalent a day, an increase compared to 3.6 million barrels of oil equivalent a day a year earlier.
Underlying Upstream production, excluding Rosneft in which BP has a stake, was down 2.5% from a year earlier, reflecting maintenance across a number of regions and Hurricane Barry shutting BP’s US Gulf of Mexico offshore platforms for two weeks.
Bob Dudley, BP chief executive who is soon to retire, said: “BP delivered strong operating cash flow and underlying earnings in a quarter that saw lower oil and gas prices and significant hurricane impacts. Our focus remains firmly on maintaining financial discipline and delivering safe and reliable operations throughout BP. We’re also continuing to advance our strategy, making strong progress with our divestment plans and building exciting new opportunities in fast-growing downstream markets in Asia.”
Looking ahead, BP said it expected the fourth-quarter 2019 reported production to be higher than the third quarter due to the completion of seasonal maintenance and turnaround activities.
Source: U.S. Energy Information Administration, U.S. Energy Information Administration, Natural Gas Monthly
Updated at 1:00 P.M. to correct figures.
From January through June of 2019, U.S. net natural gas exports averaged 4.1 billion cubic feet per day (Bcf/d), more than double the average net exports in 2018 (2.0 Bcf/d), according to data in the U.S. Energy Information Administration’s (EIA) Natural Gas Monthly. The United States became a net natural gas exporter (exported more than it imported) on an annual basis in 2017 for the first time in almost 60 years.
The United States exports natural gas by pipeline to neighboring Canada and Mexico and exports liquefied natural gas (LNG) to several other countries. Much of the recent increase in total exports is a result of more LNG facilities coming online. Total U.S. exports of LNG through the first half of 2019 were 37% higher compared with the same period in 2018. Total U.S. LNG export capacity as of June 2019 was 5.4 Bcf/d across four facilities and nine liquefaction trains.
Two new liquefaction units—referred to as trains—came online in the first half of 2019: Cameron LNG Train 1 in Louisiana and Corpus Christi LNG Train 2 in Texas. Cameron LNG was the fourth U.S. LNG export facility placed into service since February 2016. Cameron LNG, which will have a capacity of 1.7 Bcf/d when its three liquefaction trains are completed, shipped its first cargo in May 2019 (as part of the initial commissioning process) and then another one in June before ramping up operations in July and August. Corpus Christi LNG Train 2, with a capacity of 0.6 Bcf/d, shipped its first cargo in July and reached substantial completion in September.
More LNG facilities have come online in the second half of 2019: the first train at Freeport LNG in Texas, with a capacity of 0.7 Bcf/d, and the first ten trains at Elba Island in Georgia, with a capacity of 0.03 Bcf/d. These two new LNG export facilities, along with the completion of Cameron LNG, will increase U.S. LNG export capacity to 8.9 Bcf/d by the end of 2020 from 4.9 Bcf/d at the end of 2018.
Source: U.S. Energy Information Administration, U.S. Energy Information Administration, Natural Gas Monthly
Although U.S. LNG exports have grown substantially, most U.S. natural gas trade is transported via pipeline across shared borders with Canada and Mexico. In the first half of 2019, net exports of natural gas by pipeline to Mexico grew by 5%, and net exports of natural gas by pipeline to Canada remained relatively flat. In every month from April through August, U.S. natural gas exports by pipeline have exceeded natural gas imports by pipeline, the longest consecutive stretch of exporting more natural gas by pipeline than importing by pipeline on record.
U.S. pipeline export capacity to Canada grew in the last few months of 2018 when the second phase of both the Rover pipeline and the new NEXUS pipeline entered service, transporting natural gas from the Marcellus and Utica plays in the Appalachian Basin to the St. Clair point of exit northeast of Detroit, Michigan. Total U.S. natural gas exports to Canada reached 3.3 Bcf/d in February 2019, the highest level this year as of August 2019.
Source: U.S. Energy Information Administration, U.S. Energy Information Administration, Natural Gas Monthly
U.S. pipeline net exports of natural gas to Mexico in the first half of 2019 averaged 4.9 Bcf/d, 0.4 Bcf/d higher than the average for the first half of 2018. Pipeline deliveries to Mexico grew in 2019 as new projects such as the Texas-Tuxpan pipeline transported natural gas from the U.S. Permian Basin to demand centers in Mexico. U.S. natural gas exports by pipeline to Mexico reached all-time highs of 5.2 Bcf/d in June 2019 and 5.3 Bcf/d in July 2019.
Source: U.S. Energy Information Administration, U.S. Energy Information Administration, Natural Gas Monthly
According to EIA’s Short-Term Energy Outlook, net natural gas exports are expected to continue rising through the end of 2019 as additional LNG export capacity comes online and natural gas pipeline infrastructure in Mexico is placed into service. EIA expects the United States to continue to export more than it imports with net natural gas exports averaging 4.6 Bcf/d in 2019 and 7.2 Bcf/d in 2020.
Principal contributor: Kristen Tsai
Malaysian energy giant Petronas, through its unit Petronas LNG, has signed the time charter party with MISC Berhad and Avenir LNG to charter a 7,500 cubic meters of liquefied natural gas bunker vessel.
The collaboration positions Petronas among the first LNG bunkering service providers in the South East Asia region, moving Malaysia closer towards becoming a LNG bunkering hub, the company said in its statement.
The LNG bunker vessel is capable of providing bunkering services to LNG fueled vessels across Malaysia, and also transporting smaller scale LNG cargoes across the region.
Petronas vice president of LNG marketing and trading and CEO of Petronas LNG, Ahmad Adly Alias said, “We are also collaborating with various ministries, authorities and fellow industry players to co-develop the policies, guidelines and procedures for safe and effective bunkering operations in embracing the IMO 2020 regulations.”
Petronas has set up the necessary infrastructure for LNG bunkering services at Pengerang, Johor and Sungai Udang, Melaka.
The company is also actively working towards the establishment of LNG bunkering global network through partnerships with port operators and international industry players, the statement reads.
Bankruptcy Looms For America's Largest Underground Coal Miner Murrey Energy
Murray Energy Corporation, America's largest underground coalminer is battling to stave off bankruptcy, Yesterday it extended forbearance agreements with its lenders and elected not to make interest payments to noteholders
Statement From Murrey Energy:
Murray Energy Corporation previously disclosed, on October 2, 2019 Murray Energy Corporation (“Murray Energy” or “the Company”) entered into forbearance agreements with lenders holding in excess of 50% of outstanding loans under its Superpriority Credit and Guaranty Agreement and with lenders holding in excess of 50% of outstanding loans under its ABL and FILO credit facilities.
Under the terms of the forbearance agreements, the lenders agreed to forbear from exercising any and all remedies available to them in respect of any event of default arising from the missed amortization and interest payments due on September 30, 2019. On October 15, 2019, Murray Energy and its lenders amended the previously disclosed forbearance agreements, extending the forbearance period through 11:59 p.m. (New York time) on October 28, 2019, unless further extended.
The forbearance agreements will terminate upon the earlier of the end of the forbearance period or the occurrence of a specified forbearance termination event. With discussions with its lenders and noteholders regarding strategic options to strengthen the Company’s business, liquidity and capital structure ongoing, the Company elected not to make the cash interest payments due on October 15, 2019 to holders of the Company’s 12.00% Senior Secured Notes due 2024 and 11.25% Senior Secured Notes due 2021. via Murrey Energy Statement
Further inquiries should be directed to This email address is being protected from spambots. You need JavaScript enabled to view it. .
S&P downgraded Murray to default status
Murray Energy focused on exports witht he trade war those shipments have shrank with plunging prices overseas.
US coal exports are estimated to have dropped to 20.9 million short tons in the third quarter, according to the US Energy Information Administration. That represents a 28% drop from the same period of 2018. The EIA expected coal exports to keep falling, slipping to 17.3 million by the end of 2020.
"International thermal coal prices have made exports unprofitable for most of 2019, leading to mine idling and deteriorating cash flows," S&P Global Ratings analyst Vania Dimova wrote in a report this week.
Murray Energy is under so much pressure that it failed to make amortization and interest payments during a grace period that ended on October 7. That led S&P Global Ratings to downgrade the company's credit rating to "default." In a statement last week, Murray Energy said it plans to use the grace period that expires after October 17 to consider its next steps.
About Murrey
Energy Murray Energy Corporation is the largest privately owned coal company in the United States, producing approximately seventy-six million tons of high quality bituminous coal each year, and employing nearly 7,000 people in six states, and Colombia, South America. Murray Energy now operates fifteen active mines in five regions in the United States, plus two mines in Colombia, South America.
Murray Energy operates twelve underground longwall mining systems and forty-two continuous mining units. They operate ten transloading facilities, and five mining equipment factory and fabrication facilities.
Source: Murrey Energy
Enterprise Products' Growth Projects Keep Coming
Industry Segment: Pipelines | Word Count: 909 Words
SUGAR LAND--October 29, 2019--Researched by Industrial Info Resources (Sugar Land, Texas)--Like other midstream companies, Enterprise Products Partners LP (NYSE:EPD) (Houston, Texas) is reaping the profits to be made from the growing production of oil, natural gas and natural gas liquids (NGL) in the U.S. and plowing some of its gains into growth projects. Although the company's quarterly net earnings were down from $1.3 billion in third-quarter 2018, it still reported a $1 billion profit in the just-passed third quarter. Enterprise spent $1 billion in growth capital projects in the third quarter and expects growth capital expenditures next year to be $3 billion to $4 billion. Industrial Info is tracking more than $15 billion in active Enterprise projects.
Within this article: Details of Enterprise Products' active growth projects
Other companies featured: LyondellBasell Industries NV (NYSE:LYB)
U.S. oil company Hess Corporation has made an oil discovery at the Esox-1 exploration well located in Mississippi Canyon Block No. 726 in the deepwater Gulf of Mexico. Hess plans to tie back the new discovery to Tubular Bells production facilities.
Esox-1 is located approximately 6 miles (10 kilometers) east of the Tubular Bells production facilities. Hess said on Tuesday that the well was drilled in 4,609 feet (1,405 meters) of water and encountered approximately 191 net feet (58 meters) of high quality oil bearing Miocene reservoirs.
“We are delighted with the success of the Esox well, which demonstrates the value of our infrastructure led exploration program in the deepwater Gulf of Mexico,” CEO John Hess said.
“We expect the well to be producing in the first quarter of 2020. As a low cost tieback to existing infrastructure, Esox should generate strong financial returns.”
Hess Corporation is operator and holds 57.14% interest in Esox and its partner Chevron holds the remaining 42.86% interest.
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Report: Saudi Aramco shares to start trading in December
A Saudi organizer at the Future Investment Initiative conference, "FII", smiles as she welcomes participants, in Riyadh, Saudi Arabia, Tuesday, Oct. 29, 2019. The FII drew 6,000 people and international firms to Riyadh for a forum that's the brainchild of the 34-year-old Prince Mohammed. less A Saudi organizer at the Future Investment Initiative conference, "FII", smiles as she welcomes participants, in Riyadh, Saudi Arabia, Tuesday, Oct. 29, 2019. The FII drew 6,000 people and international firms ... more Photo: Amr Nabil, AP Photo: Amr Nabil, AP Image 1 of / 18 Caption Close Report: Saudi Aramco shares to start trading in December 1 / 18 Back to Gallery
RIYADH, Saudi Arabia (AP) — A long-delayed initial public offering of the state-run oil giant Saudi Aramco will see its shares traded on Riyadh's stock exchange in December, a Saudi-owned satellite news channel reported Tuesday as the kingdom's showcase investment forum began.
The report by Dubai-based Al-Arabiya enlivened the start of the Future Investment Initiative, a summit of panels and talks convened by the kingdom's powerful Crown Prince Mohammed bin Salman that aims to showcase Saudi Arabia's potential for investors.
However, some major firms stayed away and attendees at times hid their nametags behind their suit jackets, a sign of the shadow still cast over the event by the assassination last year of Washington Post columnist Jamal Khashoggi at the Saudi Consulate in Istanbul. Authorities also barred foreign journalists, including those from The Associated Press, from photographing or filming panels and speeches themselves despite having been invited to the event. They did not give a reason for the ban.
Prince Mohammed hopes for a very-optimistic $2 trillion valuation for Aramco, which produces 10 million barrels of crude oil a day and provides some 10% of global demand. That would raise $100 billion he needs for his ambitious redevelopment plans for a Saudi Arabia hoping for new jobs, as unemployment stands at over 10%.
However, economic worries, the trade war between China and the U.S. and increased crude oil production by the U.S. has depressed energy prices. A Sept. 14 attack on the heart of Aramco already spooked some investors, with one ratings company already downgrading the oil giant.
The initial report by Al-Arabiya did not elaborate and cited anonymous sources for the information. However, the channel often breaks news before even the kingdom's state-run media and is widely believed to have a direct line to the Al Saud royal family.
The station's English arm later offered more details, saying that a final price for the stock will be set Dec. 4, with shares then beginning to be traded on the Riyadh-based Tadawul stock market on Dec. 11. It added that the Saudi Capital Markets Authority will make a formal announcement about the IPO plans on Sunday. Pricing will begin Nov. 17, it said.
"The Aramco IPO is a cornerstone of Saudi Arabia's Vision 2030 plan, which aims to wean the kingdom off its reliance on oil to diversify the economy," the channel said in its report.
Saudi state media and government officials did not immediately acknowledge the report. Saudi Aramco said it "does not comment on rumor or speculation," but did not dispute the report. Analysts cautioned that the kingdom has blown through several planned dates already after Prince Mohammed first announced his intention to offer shares of Aramco in 2016.
There also have been decisions seemingly forced onto Aramco recently, including the nearly $70 billion purchase in March of the petrochemical firm Saudi Basic Industries Corp. just before it announced a plunge in its quarterly profits. That has seen a change in the long-standing perception that a "strong Saudi Aramco is a strong Saudi Arabia" to viewing the company as a "great source of capital," said Ellen R. Wald, an Aramco expert who wrote the recent book on the firm called "Saudi, Inc."
The kingdom has in the past used the company as a piggy bank for development companies, back when it was still an American company. Since buying a 100% interest in the firm by 1980, the royal family as its sole "shareholder" largely hasn't interfered in the company's long-term business decisions as its revenue provides around 60% of all government revenue.
"It's a trend that I see is disturbing," Wald told the AP. "It could be potentially damaging to the company, and then in the long term, damaging to the source of funding that has made Saudi Arabia so strong."
Despite that, Wald said the IPO could prove positive for Aramco in the long term. She anticipated the firm offering as much as 3% of its worth on the Tadawul, with hopes a lot of interest in it would drive up its valuation ahead of a possible foreign listing. However, any dip in values likewise could pose a challenge in taking the shares abroad. As much as 5% of the company is likely to be offered publicly between the two markets.
Indian Prime Minister Narendra Modi and Jordan's King Abdullah II both attended the summit's opening Tuesday. Also attending was Jared Kushner, U.S. President Donald Trump's son-in-law and a White House adviser.
The event is held in part at Riyadh's Ritz-Carlton Hotel, which served as a detention facility during Prince Mohammed's 2017 purge targeting businessmen, princes and others. Described at the time as an anti-corruption campaign, the arrests targeted wealthy potential challengers to the prince and cemented his grip on power amid allegations of torture denied by the kingdom. Authorities later said it saw the government recoup over $100 billion.
There were also big names in global finance who didn't take part. Among them was Jeff Bezos, the CEO of Amazon and the owner of the Washington Post, who had been in negotiations to open data centers in the kingdom before the killing and dismemberment of Khashoggi.
U.S. officials and a recent United Nations special rapporteur's report suspect Prince Mohammed had a role in the slaying, as members of the team of assassins sent to kill Khashoggi had links to the prince. The kingdom denies that.
As the forum started, panelists like Ray Dalio, the founder of the world's largest hedge fund Bridgewater Associates, offered stark warnings about the state of the global economy, rising inequality and "a conflict between capitalism and socialism." He compared times now to those in the Great Depression of the 1930s.
"There's a form of revolution taking place," Dalio said.
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Associated Press writer Malak Harb in Riyadh, Saudi Arabia, contributed to this report.
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Follow Jon Gambrell on Twitter at www.twitter.com/jongambrellAP .
In order to rein in runaway climate change, we must do more than curtail emissions — we must actively remove carbon dioxide from the atmosphere. There are two major pathways toward that goal: natural sequestration methods involving forestry and agriculture; and, of course, those grounded in new technologies.
On the technology side, direct air capture (DAC) is gaining considerable attention, in part due to the inclusion of the 45Q tax credit for carbon sequestration in the FUTURE Act. Another development that deserves close, ongoing scrutiny is the collaborations being announced between major oil and gas companies and fledgling companies in the DAC space.
One partnership announced in January is between carbon capture company Carbon Engineering and Oxy Low Carbon Ventures, a subsidiary of Occidental Petroleum. Occidental, along with Exxon-Mobil and Chevron, joined the Oil and Gas Climate Initiative last year. Oxy CEO Viki Hollub said at the time, "Industry innovation and collaboration have a critical role to play in addressing climate change." Occidental was the first among the major oil companies to declare a goal of carbon neutrality.
One year later, Oxy, along with Chevron, announced it would provide equity investments in Carbon Engineering, a DAC company based in British Columbia, to accelerate the commercialization of the company’s technology.
Carbon Engineering was founded in 2009 by Harvard professor David Keith. The company has developed what it is positioning as a scalable industrial process that can pull carbon dioxide out of the air. The technology follows a "keep it simple" philosophy, using many off-the-shelf components and materials in an effort to keep costs low.
In June 2018, Carbon Engineering made news when it announced, in a peer-reviewed paper, that it could pull CO2 from the atmosphere at a cost of "less than $100 per ton," at a time when conventional wisdom was saying this process would cost $600 or more. Carbon Engineering claims each plant it builds will have the capacity to remove 1 million tons of CO2 from the air each year. The company also has developed a second process that can convert carbon dioxide into fuel.
The fundamental value proposition for direct air capture ... is that we need to decarbonize, and we need to do so quickly, but we're not in a position where we can eliminate fossil fuel overnight. The first of these capabilities captured Oxy’s attention, because it coincides well with the mission of the recently formed company to capitalize on Occidental’s "enhanced oil recovery leadership by developing carbon capture, utilization and storage projects that source anthropogenic carbon dioxide and promote innovative technologies that drive cost efficiencies and economically grow Occidental’s business while reducing emissions."
One advantage of DAC technology is that it is location-independent (because atmospheric CO2 concentration is more or less the same everywhere). That means it can be co-located with an oilfield operation for enhanced oil recovery. After drilling is complete, the wells are sealed and the carbon dioxide remains underground. If more CO2 is pumped underground than is contained in the oil recovered, the process can be considered carbon-negative.
Representatives of both Oxy and Carbon Engineering were on hand at VERGE 2019 to discuss their plans. Carbon Engineering CEO Steve Oldham spoke at a breakout session, "Carbon Removal Will Create a Wealth of Opportunities. Are You Ready?" Oxy President Richard Jackson participated in "Capturing Carbon from Industrial Sources and Directly from the Air."
"If you’re an oil company and you want to be carbon-neutral, you’re going to need partners," Jackson told the VERGE 19 audience.
As Oldham explained to GreenBiz, "The importance of getting that first full-scale plant up and running can’t be overstated." This is true from both an economics and a capability perspective: "We're a carbon capture company, but we need a partner who can bury it," Oldham said.
In addition to the deal with Carbon Engineering, Oxy has invested in NET Power, developer of a low-cost, natural gas power system that generates zero atmospheric emissions and includes full carbon dioxide capture. It also signed an agreement to work with Texas-based White Energy, "to evaluate the economic feasibility of a carbon capture, utilization and storage project that would capture carbon dioxide at White Energy’s ethanol facilities in Hereford and Plainview, Texas, and transport it to the Permian Basin, where it would be used for [enhanced oil recovery]."
Fuel for thought
The agreement between Chevron and Carbon Engineering is focused on synthetic fuel development. Chevron, California’s largest fuel supplier, is looking for a way to reduce the carbon intensity of its fuel. Carbon Engineering’s synthetic fuel process uses clean hydrogen, which is combined with the CO2 to make a synthetic crude with a very low carbon intensity. This allows the fuel supplier to meet the carbon intensity criteria spelled out in the state’s Low Carbon Fuel Standard. The standard assesses a $200/ton penalty on excess CO2 in the fuel, so avoiding that penalty by using this fuel is the lower-cost option.
In both cases, movement at the public policy level helped to get these deals done.
The Permian Basin alone could hold 100 years' worth of emissions. Some people on the environmental side balk at the idea of capturing CO2 only to use it to produce more oil and gas.
Oldham addresses this. "The fundamental value proposition for direct air capture that I think people are beginning to understand is that we need to decarbonize, and we need to do so quickly, but we're not in a position where we can eliminate fossil fuel overnight," he said. "So how do you decarbonize while continuing to support the economy and the energy needs that we all have?"
Oil and gas produced in conjunction with CO2 captured from the air, which ends up stored underground, does have a lower climate impact than oil and gas produced conventionally. So, it does become the "lesser evil."
And, as Oldham points out, "Direct air capture can also be used to offset those emissions that are most difficult to eliminate," such as those related to aviation, marine and other heavy equipment activities. Perhaps most important of all, "Direct air capture can also contribute to the effort to reduce those legacy emissions that are already in the atmosphere," he said.
When asked how much carbon removal capacity could be developed in the years ahead, Oldham said "there is no limit on storage.
"The Permian Basin alone could hold 100 years' worth of emission. There's no limit on our ability to build plants. (No rare or exotic materials are involved.) The technology is available for licensing. It's simply a matter of choice. In the more immediate term., the market is waiting to see large scale direct air capture demonstrated and proven, which is why this plant in Texas is so important for us."
That plant should be operational between 2022 and 2023, which could represent a tipping point for commercialization of Carbon Engineering's technology, Oldham said.
Frac sand miner U.S. Silica Holdings reported a bigger-than-expected loss for the third quarter on Tuesday, battered by weaker prices and softer demand from shale oil drillers.Shares of the Katy, Texas-based company fell about 7.8% to $7.20 in low volume before the bell.
Sand prices have been dropping as shale producers in the Permian and other basins have been sourcing more from local basins to cut transportation costs involved in buying Northern White sand from Wisconsin.
Sand is used to open cracks in shale rocks to release oil and gas and is the most widely used proppant in fracking.
The company sold 3.9 million tons from its oil & gas segment in the third quarter, down 1% from the prior quarter. For the fourth quarter, it expects the slowdown in well completions in North America to hit volumes by 10% sequentially.
Price per ton of sand was also hit in the quarter as multiple new mines came online in West Texas, worsening conditions in an already oversupplied market.
According to the company’s estimates, the frac sand demand for the year is just about 100 million tons to 110 million tons, whereas the total effective supply is estimated at a much higher 140 million tons to 150 million tons.
U.S. Silica said it has already taken out about 5 million tons per year of supply from the market by completely idling some plants or cutting shifts and working days.
The company’s Sandbox unit, which provides transportation and storage facilities for proppant used in fracking, also moved fewer tons in the third quarter compared with the second. The company expects this sequential decline to continue in the fourth quarter.
U.S. Silica reported a net loss of $23 million, or 31 cents per share, for the quarter ended Sept. 30, compared with a profit of $6.3 million, or 8 cents per share, a year earlier.
Adjusted loss came in at 17 cents per share, well below analysts’ average estimate of 3 cents, according to Refinitiv IBES data.
Revenue fell 14.5% to $361.8 million, missing estimates of $395.5 million.
Russian gas producer Gazprom has finished filling the Power of Siberia pipeline to China with natural gas, it said on Tuesday.
Gas flows to China from east Siberia are scheduled to start by the end of the year, Gazprom said.
French energy major Total said on Wednesday that record production growth in the third quarter help keep its cash flow steady, as adjusted net profit tumbled due to lower oil and gas prices.
Production rose 8.4% to a record output in a quarter at over 3 million barrels of oil equivalent per day compared with the same period last year. Total said it was on track to hit 9% output growth this year.
“The group continues to achieve solid results despite a third-quarter environment compared to a year ago that was marked by an 18% decrease in the Brent price to $62 per barrel and gas prices that fell by about 55% in Europe and Asia,” Total’s CEO Patrick Pouyanne, said in a statement.
Total’s debt-adjusted cash flow fell 2% to $7.4 billion, while adjusted net profit slumped 24% to $3.02 billion compared with the same quarter in 2018.
Like its peers, Total is under pressure from investors to boost returns. BP shares fell 3.8% on Tuesday despite earnings that beat estimates, as investors’ hopes of a dividend increase this year were dashed.
As announced in September, Total’s interim dividend for the third quarter will rise by 6% year on year to 68 euro cents. It plans to boost its payout by 5% to 6% annually in the coming years, up from a previous plan for 3% growth.
New Projects
Oil and gas production climbed 8.4% from a year earlier to 3.04 million barrels equivalent a day. Thanks to project startups in the UK North Sea (including the Culzean field), Norway and Brazil, output is on track to grow by 9% for the full year, the company said.
Sales of liquefied natural gas grew 20% in the quarter to 7.4 million tons, helped by the ramp-up of projects in Australia and Russia, and the start of the first liquefaction plant at Cameron LNG in the U.S. Cash flow from Total’s integrated gas, renewables and power segment jumped by 53% to $848 million.
The downstream division benefited from better petrochemicals margins in Europe and rising sales of gasoline and other petroleum products. The unit generated almost $2 billion of cash flow in the third quarter, up 14% from a year earlier, and is “well positioned” to generate close to $7 billion of cash flow this year, the company said.
https://www.energyvoice.com/oilandgas/210868/total-profit-beats-estimates-as-culzean-boosts-output/
U.S. oil and gas producer Concho Resources Inc on Tuesday missed Wall Street estimates for adjusted profit for the fourth straight quarter, dragged down by natural gas and crude prices.
U.S. oil prices remained in the mid-$50s in the September quarter, down more than 18% on average from a year earlier, after a spike to over $60 a barrel in September following an attack on Saudi Arabian oil infrastructure.
Excluding items, Concho’s profit fell to 61 cents per share, below analysts’ average estimate of 69 cents per share, according Refinitiv IBES.
Concho said in early September it would sell a portion of its New Mexico assets for $925 million to KKR-backed Spur Energy Partners LLC and planned to use the money to lower its debt and buy back shares.
Special items impacting earnings for the quarter included a $101 million impairment, primarily related to the sale of its New Mexico Shelf assets.
Concho said average realized price for crude oil and natural gas for the third-quarter, including hedging was $36.46 per barrel of oil equivalent (boe) compared to $43.56 per boe in the year-ago quarter.
The company reported net income of $558 million, or $2.78 per share, in the quarter ended Sept. 30, compared with a loss of $199 million, or $1.05 per share, a year earlier.
Concho said total production in the quarter rose to 329,803 barrels of oil equivalent per day (boepd) from 286,634 boepd a year earlier.
·INDIAN TOTAL OIL PRODUCTS DEMAND IN AUGUST FELL BY 104 KBD MONTH-ON-MONTH TO 12-MONTH LOW OF 4.55 MBD: JODI DATA
Japanese provider of offshore floating solutions MODEC has signed a contract with ConocoPhillips to supply a floating production storage and offloading (FPSO) vessel for the Barossa field, offshore Australia.
MODEC said on Wednesday that the Barossa FPSO was intended to produce gas and condensate from subsea wells, and after treatment, supply feed gas to the Darwin LNG plant via a gas export pipeline.
The company was awarded a FEED contract of the Barossa FPSO in June 2018 and has now been selected as the turnkey contractor based upon its successful performance and deliverables of the FEED contract.
The Barossa FPSO is MODEC’s largest gas FPSO to date, which will be able to export over 600 million standard cubic feet of gas per day as well as store up to 650,000 barrels of condensate for export.
It has been designed to withstand a 100-year cyclone event at a water depth of 260 meters and located some 300 kilometers off north of Darwin. The Barossa FPSO will be MODEC’s 6th FPSO in Australia.
According to the company, it will be responsible for the EPCI work on the FPSO, including topsides processing equipment as well as hull and marine systems.
Scheduled for delivery during 2023, the FPSO will be permanently moored by an internal turret mooring system supplied by a MODEC group company – SOFEC.
It is worth noting that the Barossa FPSO will be the first application of MODEC’s M350 hull design, which was developed to accommodate larger topsides and larger storage capacity than conventional VLCC tankers, with a design service life of 25 years and beyond.
Yuji Kozai, president and CEO of MODEC, said: “This contract award of a gas FPSO reinforces one of our important business strategies, which we aim to penetrate into the gas-related market.
“Also, this new contract represents a significant milestone for MODEC in applying our next generation new built FPSO hull design of which we have developed to meet the new market demands for larger FPSOs.”
The Barossa joint venture is operated by ConocoPhillips Australia Barossa with a 37.5 percent interest. The two partners in the project are SK E&S Australia and Santos, with 37.5 and 25 percent interest, respectively.
Following a number of delays, Danish authorities have granted a construction permit for the Nord Stream 2 offshore gas pipeline in the Baltic Sea.
Nord Stream 2 AG, a subsidiary of Russia’s Gazprom and operator of the Nord Stream pipeline, said on Wednesday it had obtained the permit to construct its planned pipeline system in the Danish Exclusive Economic Zone (EEZ) southeast of Bornholm. The permit was granted by the Danish Energy Agency, which is in charge of the application, and covers a 147-km-long route section.
“We are pleased to have obtained Denmark’s consent to construct the Nord Stream 2 Pipeline through the Danish continental shelf area in the Baltic Sea southeast of Bornholm. We will continue the constructive cooperation with Danish authorities to complete the construction of the pipeline,” said Samira Kiefer Andersson, Permitting Manager Denmark at Nord Stream 2 AG.
The company said that preparatory works, such as the installation of concrete mattresses and rock placement for the crossing of existing infrastructure (cables and pipelines), and the subsequent pipelay, would start in the coming weeks. The Danish section of the pipeline will be built with pipes currently stored in Mukran, on the German island of Rügen.
As of Wednesday, October 30 more than 2,100 kilometres of the Nord Stream 2 Pipeline have been laid. Pipelay has been completed in Russian, Finnish, and Swedish waters, and for the most part in German waters. The construction of both landfall facilities in Russia and Germany is nearing completion.
Nord Stream 2 has invested more than 6 billion euros in the project.
Slow process
Since 2017, Nord Stream 2 AG has forwarded three applications to the Danish Energy Agency (DEA) with three different routes.
On April 3, 2017, the Danish Energy Agency received an application for a permit to construct transit pipelines southeast of Bornholm in Danish territorial waters and on the Danish continental shelf. The company withdrew this application in June 2019.
On August 10, 2018, the Danish Energy Agency received an application for a route northwest of Bornholm on the continental shelf. As this route raised a number of questions in relation to the impact on the environment and shipping, the DEA requested Nord Stream 2 AG in March 2019 to investigate a southeastern route on the continental shelf.
On April 15, 2019, Nord Stream 2 AG applied for two route alternatives on the continental shelf southeast of Bornholm with a length of respectively 147 km and 164 km. At the time, the company accused Denmark of making deliberate attempts to delay the project by asking for another route option.
“Asking for a third route option to be developed, despite two fully processed, ready-to-be-permitted applications on the table, can only be seen as a deliberate attempt to delay the project’s completion,” Nord Stream 2 AG said in April 2019.
On April 17, 2019, Nord Stream 2 AG filed an appeal against the March 26th decision of the DEA related to the North-western permit application requesting the company to investigate and submit an environmental impact assessment (EIA), accompanied by a permit application, for a route southeast of Bornholm to the Danish Energy Board of Appeal.
The Environmental Impact Assessment report for the Nord Stream 2 AG natural gas offshore pipeline route to the southeast of Bornholm, Denmark was made available to the public by the country’s coordinating authority, the Danish Energy Agency, in mid-May.
Southeastern route preferable to northwestern
Following the granting of the permit, the Danish Energy Agency said on Wednesday, October 30 it had assessed that the southeastern route on the continental shelf is preferable to the northwestern route.
This is mainly due to an assessment of the impact on shipping and Natura 2000 areas, the agency said. Among the two southeastern route alternatives proposed by the company, the Danish Energy Agency said it had approved the shortest route, since this route provides the least risk and impact from an environmental and safety perspective and therefore is the preferable choice.
Based on consultation responses and close dialogue with relevant Danish authorities, the Danish Energy Agency has assessed that the southeastern route which has been granted a permit to is the preferable based on environmental and safety considerations.
The pipeline project on the Danish continental shelf is part of a larger pipeline project, consisting of two parallel pipelines of 1230 km for the transport of gas from Russia to Germany.
The natural gas pipelines starts in Russia and passes through Finnish, Swedish, Danish, and German marine areas and goes ashore at the German coast. The pipelines can transport 55 billion m3 of natural gas per year. The authorities in Russia, Finland, Sweden, and Germany have all granted permits for the project.
Offshore Energy Today Staff
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ISLAMABAD: In a major move, the Power Division is seeking an end to the existing minimum guaranteed annual Liquefied Natural Gas (LNG) offtake to facilitate privatisation of $2 billion power plants in Punjab amid strong resistance from state-owned oil and gas companies.
Top government officials confirmed to Dawn that three major oil and gas suppliers — Sui Northern Gas Pipelines Ltd (SNGPL), Sui Southern Gas Company Ltd (SSGC) and Pakistan State Oil (PSO) — have put on record in recent meetings that they would not remain financially viable entities as their entire LNG supply chain from Qatar to end consumers was based on guaranteed offtakes.
This comes after an estimated investment of about $7bn on the LNG supply chain infrastructure. The basic premise of LNG imports over the past decade had been to reduce import bill through substitution of expensive furnace oil, increase power sector efficiencies and lower carbon emissions.
Gas companies fear LNG glut if decision implemented
As a result, more than 80 per cent of total LNG imports were consumed by the power sector. The total infrastructure investment included about $5bn on four LNG power plants in Punjab, more than $1bn on LNG pipeline network, another $1bn two re-gassification terminals.
The Power Division has now suggested three options in a draft summary to the Economic Coordination Committee (ECC). Under the first option, it has proposed “to withdraw the existing minimum guaranteed offtake of 66pc on annual basis”. Accordingly, the annual production plan shall continue to be provided without any minimum guaranteed offtake of 66pc and this shall be reflected in the revised Power Purchase Agreement (PPA), Gas Supply Agreement (GSA) and Implementation Agreement (IA) to be executed for the purpose of privatisation of National Power Parks Management Company Limited (NPPMCL).
The NPPMCL is a subsidiary of the Power Division and the owner of Haveli Bahadur Shah and Baloki Power Projects of 1320MW each.
The second option entails two further choices in case the government is contractually bound to adhere to the PSO agreement with Qatar Gas till the year 2025. The first choice is to withdraw the existing minimum guaranteed off-take of 66pc immediately after the review period of PSO agreement with Qatar Gas in 2025.
However, a change should be incorporated in the revised PPA, GSA and IA to be offered for privatisation to ensure that SNGPL to follow National Power Control Centre’s instructions pertaining to diversion of unutilised RLNG and such instructions shall take precedence over any other LNG supply arrangement of SNGPL with any power sector project operating on RLNG on ‘as and when available basis’.
The second choice under this option is that till 2025, the difference of the RLNG requirements for these two power plants as per economic merit order principle and the RLNG requirements for minimum 66pc guaranteed offtake should be utilised by other sectors of the economy on Oil and Gas Regulatory Authority notified price of RLNG or sold back to the spot market.
Under the third option, the Power Division has proposed that an additional cumulative impact of about Rs471bn on the basket arising due to the guaranteed off-take of 66pc up to 2025 on account of dispatch of these power plants beyond the principle of economic merit order shall be allowed as subsidy to power sector consumers.
When contacted, the Power Division’s Senior Joint Secretary Zargham Eshaq said he was not aware of any such proposal while Secretary Power Irfan Ali did not respond.
Informed sources told Dawn that based on this summary, the Petroleum Division has directed the PSO and the two gas companies to submit their written risk allocation profile within 36 hours so that their viewpoint could also be placed before the ECC.
A Petroleum Division official said that in case of 66pc “take or pay” clause gone, the SNGPL and PSO would go bankrupt because they would not be left with any dependable consumer class to sell this imported gas that had guaranteed agreements with foreign suppliers involving heavy penalties.
He said the two gas utilities had no substitute consumers. “The only consumers that exist in the system are those who consume it for almost free like domestic consumers and those who want it subsidised like zero-rated sectors and fertiliser”.
He said the Power Division was now more interested in coal-based plants to be operated after it contracted more than the required generation capacity and has exposed the entire energy sector to heavy losses.
The PSO’s receivables had gone beyond Rs330bn while the receivables of two gas utilities were more than Rs100bn as of now. Producers like Oil and Gas Development Company Ltd and Pakistan Petroleum Ltd have more than Rs300bn in outstanding dues and most of these funds remain stuck up with the power sector.
On top of this, private entities have now been allowed direct LNG imports that would drive transport sector and other industries away from the gas utilities. The PSO’s foreign guarantees would also be exposed in case of non-fulfillment of its obligations to take full LNG quantities.
The SNGPL has told the government that GSAs were finalised on the basis of back to back arrangements with the upstream agreements. Therefore, any amendment in IA and PPA to change the risk profile of current RLNG supply chain will adversely impact not only SNGPL but also PSO and SSGC, being the key players involved in G-to-G negotiated RLNG supply chain.
The company has advised the government not to amend these contracts with respect to any change in offtake obligations of the GPPs just to make the project bankable and to attract the investors at the expense of huge losses to other entities like SNGPL, PSO, SSGC, etc.
Published in Dawn, October 30th, 2019
The global LNG supply glut will likely continue to weigh on prices and US export flows until 2022 when market for LNG will start to rebalance, BP chief financial official Brian Gilvary said Tuesday.
Spot gas prices in Asia and Europe have nosedived in 2019 amid a wave of new LNG plants coming onstream and subdued gas demand growth in Asia.
In Europe, gas storage sites have been filling to capacity at the time as coal-to-gas switching fuel switch has maximized.
"The UK is full on LNG right now. Europe is full on LNG imports. We do not anticipant that all of the gas that was planned to be exported from the US will be able to hit a demand market any time soon," Gilvary said on a quarterly earnings call.
"You are looking at the back end of 2021 to see this massive supply overhang clear out...gas feels pretty bearish right now. You will see some exports out of the US but not anywhere near the capacity that has been built."
With US spot Henry Hub gas prices currently trading around $2.2/MMBtu, Gilvary said the economics of much US LNG moving to Europe were not workable.
"Although there is no question that US gas is still the lowest cost production in the world, it us going to hard for it find a market in the next two years probably," Gilvary said.
BP reported $2.6 billion a non-cash impairment charge during the third quarter after selling off US legacy shale gas assets for less than it had on its books.
BP agreed the sale of its Alaskan business to Hilcorp for $5.6 billion in August and said it planned to divest four packages of legacy US shale gas assets. Gilvary said the asset sales were prompted by BP's outlook on US gas prices
"Strategically we were looking to get out of these assets and we've chosen to proceed."
Gilvary said further US gas asset sales will continue in the fourth quarter with the potential for further
China's Sinopec third-quarter profits down 35% year-on-year on fierce competition
Sinopec Corp, Asia’s top refiner, posted a third-quarter net profit of 11.94 billion yuan ($1.69 billion), down 35% from the same period last year, according to a Reuters calculation based on a company filing on Wednesday.
The decline follows the launch of two privately owned mega refineries and the expansion of some major refining plants, which has added to the surplus in the Chinese refined oil market and slashed profit margins in the refining industry.
Hengli Petrochemical Co in May launched a refinery with a crude processing capacity of 400,000 barrels-per-day (bpd) and Zhejiang Petrochemical Co completed a 200,000 bpd refining facility in southern China.
In the first nine months of 2019, Sinopec’s net profit was down 27.8% at 43.28 billion yuan under Chinese accounting standards, while revenue reached 2.23 trillion yuan, up 7.7% from the year earlier period, the company said in its filing to the Shanghai Stock Exchange.
So far this year, Sinopec produced 212.78 million barrels of crude oil, down 1.6% from a year earlier, and 773.41 billion cubic feet of natural gas, up 8.4% on the year.
Capital spending in the company was 78 billion yuan in the first three quarters, mainly used in shale gas exploration in southwestern China and oilfield expansion in the northwestern part of the country, and the construction of its Zhanjiang integrated refinery in Guangdong.
PetroChina third-quarter profit tumbles on lower oil prices, slowing gas demand
PetroChina Co, Asia’s largest oil and gas producer, reported a sharp fall in third-quarter profit on Wednesday, dragged down by weaker global energy prices and slowing growth in its domestic gas market.
Net profit for the July to September quarter was 8.83 billion yuan ($1.25 billion), down 58.4% compared with the same period a year ago and the weakest quarterly results this year, according to a company filing with Hong Kong stock exchange.
For the first nine months of 2019, net income fell 23.4% from a year earlier to 37.25 billion yuan, the state firm said.
“Amid an increasingly complex and rigid global economic and trade environment ... international oil prices have fallen over last year,” the company said.
“Domestically, China’s refined fuel supply capacity is in severe overcapacity...(and) growth in the natural gas market is slowing.”
Revenue for the quarter edged up 1.8% from a year ago to 618.14 billion yuan. For the first nine months, revenue rose 5.1% to 1.81 trillion yuan.
PetroChina also said its natural gas import business recorded a 21.76 billion yuan net loss during the January-September period, deepening from a 19.96 billion loss recorded for the same period in 2018 due to a weaker Chinese currency and higher import cost.
The group’s crude oil output increased 2.9% during the first nine months versus a year earlier to 682.7 million barrels, while gas output rose 8.7% to 289.3 billion cubic feet (bcf).
The stronger growth in gas versus crude oil production follows an accelerated drilling program in key basins such as Sichuan in the southwest, Ordos in the north and Tarim in the northwest.
This has also led to sizeable discoveries such as conventional gas deposits in the Bozi-9 well in the Tarim basin of Xinjiang region and shale gas in the Changqing-Weiyuan and Taiyang blocks in Sichuan.
The company’s Hongkong-listed shares have fallen by 18% so far this year, weighed by concerns that Beijing’s plan to set up a national oil and gas pipeline group will force it to cede control of its dominant pipeline assets, which have generated steady revenues.
PetroChina, which is also China’s second-largest oil refiner, processed 906 million barrels of crude in the first nine months of the year, up 4.3% from a year earlier.
Despite the growth in throughput, PetroChina’s operating profits at its refining department shrank nearly 90% during the period to 3.4 billion yuan as a domestic supply overhang squeezed margins, the firm said.
Continental Resources Inc reported a 41% fall in third-quarter adjusted profit on Wednesday, as weaker crude and natural gas prices muted higher production from its Bakken shale basin.
The slide in earnings is the latest in a set of weak results from shale companies as an 18% drop in crude prices undercut higher production that has helped prop up the United States as the world’s largest crude producer.
Concho Resources Inc said on Tuesday that its adjusted earnings more than halved, while Hess Corp reported a quarterly loss on Wednesday dragged down by lower oil and gas prices.
Continental said net sales prices averaged $33.30 per barrel of oil equivalent in the third quarter, about 25% lower than in the year-ago quarter.
Total production rose 12% to 332,315 barrels of oil equivalent per day (boepd), primarily boosted by higher output at its Bakken shale basin that spreads across North Dakota and Montana.
That helped the company post earnings of 54 cents, above the streets view of 47 cents, according to Refinitiv IBES data.
Net income fell to $158.2 million, or 43 cents per share, in the quarter ended Sept. 30, from 314.2 million, or 84 cents per share, a year earlier.
Total revenue fell 13.9% to $1.10 billion, broadly in line with analysts’ estimates.
The Hague-based LNG giant Shell saw its third-quarter profit slip 15 percent on lowest realized oil, LNG and gas prices.
The company reported a profit of $4.8 billion, which compares to $5.8 billion in the corresponding quarter last year. Compared to the previous quarter, however, Shell did report a 37.7 percent jump in earnings.
For the first nine months, Shell’s earnings reached $13.5 billion, 14 percent below the figures in the corresponding period last year.
The earning are reflecting lower realized oil, LNG and gas prices, as well as weaker realized refining and chemicals margins, Shell said in its statement, adding that this was partly offset by significantly stronger contributions from LNG and oil products trading and optimization as well as higher realized margins in retail and global commercial.
Commenting on the results Royal Dutch Shell CEO Ben van Beurden said, “This quarter we continued to deliver strong cash flow and earnings, despite sustained lower oil and gas prices, and chemicals margins. Our earnings reflect the resilience of our market-facing businesses and their ability to capitalize on market conditions, including very strong trading and optimization results this quarter.”
Compared with the third quarter 2018, Integrated Gas earnings excluding identified items primarily reflected significantly stronger contributions from LNG trading and optimization as well as higher volumes, partly offset by lower realized LNG, oil and gas prices. Segment earnings reached $2.6 billion, 23 percent up on the $2.1 billion reported in the corresponding quarter last year.
Compared with the third quarter of 2018, production increased mainly due to field ramp-ups in Australia and Trinidad and Tobago.
LNG liquefaction volumes increased by 9 percent, mainly as a result of new LNG capacity from the Prelude floating LNG facility as well as increased feedgas availability compared with the third quarter of 2018.
Volumes reached 8.95 million tonnes in the quarter under review, which compares to 8.18 million tons in the third quarter of 2018.
LNG sales volumes have also jumped 9 percent, reaching 18.90 million tonnes, compared to 17.27 million tonnes in the third quarter of 2018.
https://www.lngworldnews.com/shells-third-quarter-profit-slips-on-low-prices/
(Bloomberg) -- The Keystone crude oil pipeline was shut following a spill in North Dakota, the third along the pipeline’s route in less than three years, roiling Canadian and U.S. oil markets.
TC Energy Corp.’s 590,000 barrel-a-day pipeline that carries crude from Alberta to refineries in the U.S. Midwest and Gulf Coast ruptured overnight and caused a spill near the city of Edinburg in North Dakota, Brent Nelson, an emergency manager for Walsh County, said by phone.
TC Energy declared force majeure on the pipeline system after the shutdown, according to people familiar with the matter who asked not to be identified because the information is private. An emergency response team has contained the impacted area, the company said in a statement on its website, adding that it doesn’t have a figure for the volume of oil released. The northern segment of the line will remain shut for investigation, TC Energy said earlier.
The spill comes as TC Energy is seeking to build the controversial Keystone XL pipeline. The company said Keystone was probably the source of a spill in Missouri in February that shut a segment of the line. In 2017, a spill in South Dakota reduced rates on the line for months, causing Canadian oil prices to collapse.
The shutdown threatens to reduce shipments of oil to the key Cushing, Oklahoma, supply hub. Oil prices reacted quickly, with U.S. crude futures recouping some earlier losses, while prices in Alberta weakened.
“If you start to see this situation where flows are reduced for a long period of time, that’s when you’ll see a price impact” on both U.S. futures and Canadian crude prices, Mike Walls, an analyst at Genscape Inc., said by telephone.
Long-Delayed Keystone XL
The spill is estimated to be 1,500 feet in length by 15 feet wide and it has impacted a wetland, the Division of Water Quality within the North Dakota Department of Environmental Quality said in a statement Wednesday. The agency said the volume is currently unknown.
The shutdown comes as U.S. Gulf Coast refineries seek alternative heavy crude supplies amid sanctions on Venezuela, lagging output from Mexico and OPEC production cuts. At the same time, Alberta’s oil producers are struggling to cope with production limits imposed earlier this year when too much oil encountered too few pipelines, causing prices to collapse.
Heavy Western Canadian Select crude’s discount to West Texas Intermediate futures widened $2 to an $18.75 a barrel discount on Wednesday, the widest since last December, data compiled by Bloomberg show. After the Keystone spill in South Dakota in 2017, prices widened from about $11 a barrel to more than $25 a barrel.
The long-delayed Keystone XL oil pipeline has been on the drawing board for a decade. The 1,200-mile (1,900-kilometer) pipeline would help carry 830,000 more barrels of crude a day from Alberta’s oil sands to U.S. Gulf Coast refineries. The project has been a top target of environmentalists, who argue that the pipeline would contribute to catastrophic climate change.
No new export pipelines out of Canada are planned until late next year at the earliest, when Enbridge Inc.’s Line 3 is scheduled to start operation. Two other pipeline projects including the government-owned Trans Mountain line to Vancouver area as well as the proposed Keystone XL have faced regulatory and legal delays in addition to fierce opposition from environmental groups and landowners.
Keystone runs from Hardisty, Alberta, to Steele City, Nebraska, where it splits into two segments running to Cushing and to Patoka, Illinois. From those hubs, oil is transferred to other lines running to the U.S. Gulf Coast, home to about half the nation’s refining capacity.
(Updates with force majeure declaration in third paragraph.)
--With assistance from Michael Bellusci and Sharon Cho.
To contact the reporters on this story: Robert Tuttle in Calgary at rtuttle@bloomberg.net;Sheela Tobben in New York at vtobben@bloomberg.net;Catherine Ngai in New York at cngai16@bloomberg.net
To contact the editors responsible for this story: David Marino at dmarino4@bloomberg.net, Catherine Traywick, Steven Frank
©2019 Bloomberg L.P.
http://www.bnnbloomberg.ca/keystone-pipeline-shuts-after-oil-spill-in-north-dakota-1.1340534
IN FOCUS Can US Stop Nord Stream 2 Now?
Gazprom cleared the final hurdle for its Nord Stream 2 project after Denmark finally gave the green light for the gas pipeline to be laid through its territorial waters in the Baltic Sea on its route from Russia to Germany. The 55 billion cubic meter per year pipeline could be up and running next year, strengthening Moscow's hand in its negotiations with Kiev over terms for a new gas transit deal to run from the start of 2020 for the existing pipeline system across Ukraine to Europe. Nord Stream 2 is backed by European heavyweights Royal Dutch Shell, Germany's Uniper and Wintershall Dea, France's Engie and Austria's OMV, but Washington takes a different view, seeing it as increasing Europe's dependence on Russia. US President Donald Trump has complained that it makes Germany "captive" to Russian gas but no meaningful sanctions have yet been applied. Has the US missed its moment to stop Nord Stream 2, or could there still be a nasty surprise in store? Michael Ritchie, London Clear cache RELATED ARTICLES
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Nigerian oil company Lekoil has paid the $7.5 million license extension fee for OPL 310 as mandated by the Federal Government of Nigeria and the Ministry of Petroleum Resources.
Lekoil said on Thursday that it had funded this payment from a mix of existing financial resources and debt facilities.
In accordance with the license extension, the oil company had to pay the extension fee within 90 days effective from August 2, 2019.
The company added that it had also paid outstanding general and administrative arrears of approximately $3 million together with $1 million of the $5 million operator’s fee due to its partner in the block, Optimum Petroleum.
The balance of this $4 million fee is due by February 2, 2020, which Lekoil expects to fund from a combination of existing financial resources and a potential funding partner.
Lekan Akinyanmi, Lekoil’s CEO, said: “We are pleased with the positive momentum being created with our partner Optimum and the Federal Government of Nigeria in taking the block forward. We continue to expect to unlock significant value in this asset for all stakeholders involved, who we thank for their patience and support.”
The three-year extension for the block was granted to Optimum and Lekoil by Nigerian authorities in early September.
Both Optimum and Lekoil agreed to progress the appraisal of the block and subsequent conversion to an oil mining license (OML) at the end of the exploration period, as soon as practicable.
Following a successful appraisal, a full field development (FFD) program will be undertaken for which Lekoil and Optimum are in advanced discussions with a potential funding partner.
Offshore Energy Today Staff
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ISLAMABAD: Amid continuous rise in flour prices, the government on Wednesday decided to immediately release another 650,000 tonnes of wheat to Sindh, Balochistan and Khyber Pakhtunkhwa (KP) to ease out demand and supply equilibrium in the market.
The decision was taken at a meeting of the Economic Coordination Committee (ECC) of the cabinet presided over by Prime Minister’s Adviser on Finance and Revenue Dr Abdul Hafeez Shaikh which also offered incremental power consumption at a flat rate of Rs11.91 per unit.
The ECC was informed that wheat flour price was continuously rising almost across the country due to an insignificant buffer in demand and supply situation. It was reported for example that national average for 20kg wheat four stood at Rs1,140 on October 26 compared Rs1,100 exactly a month ago in September.
Likewise, the 20kg price of flour was recorded at Rs1,050 on October 26 in Hyderabad compared to Rs1,000 on September 26 while 20kg flour price had increased from Rs750 on August 25 to Rs1,030 on October 26 in Faisalabad.
The ECC also approved a uniform seasonal pricing structure of “Use more electricity-pay less”
The ECC noted the rising trend in wheat prices, and “approved a proposal by the Ministry of National Food Security and Research (MNFSR) for release of 300,000 tonnes each to governments of Khyber Pakhtunkhwa and Sindh and 50,000 tonnes to the government of Balochistan,” an official statement said.
Rs2.75bn for Passco approved
The ECC also approved an amount of Rs2.745 billion to be paid to Pakistan Agricultural Storage and Services Corporation (Passco) as incidental charges at the ratio of 50:50 to be equally shared by the federal and respective provincial governments.
The latest release follows an earlier release of 250,000 tonnes of wheat to the governments of Sindh and KP governments – 100,000 tonnes for the former and 150,000 tonnes to the latter –from Passco stocks on an ECC decision taken in its meeting on Oct 2, 2019. The Passco incidental charges for the previous release had also been shared at the ratio of 50:50 equally by the federal and respective provincial governments.
The MNFSR informed the ECC that Passco and provincial food departments had reported their stocks at 6.44 million tonnes as compared to 10.09m tonnes of the corresponding period of the last year. However, despite the fact that the total availability of wheat this year was estimated at 28.26m tonnes, including the leftover stock of 3.78m tonnes as compared to the national requirement of 26.91m tonnes of the country, the prices of wheat and flour showed upward trend in the local market.
‘Use more electricity-pay less’
On a proposal of the Ministry of Energy, the ECC also approved a uniform seasonal pricing structure of “Use more electricity-pay less” to be applicable during the four winter months from November 2019 to February 2020. Under the decision, a flat rate of Rs11.9 per unit will be applicable on all units consumed over and above the units consumed in the corresponding months last year by the consumers. The facility will be applicable to domestic consumers (5kW and above), Time of Use (ToU) meters, commercial consumers 95kW and above), ToU meters, and all except temporary industrial consumers.
The ECC was told that the proposal was aimed at utilising the massive surplus electricity during the winter months when the demand plunges to 8000-9000 MW from an installed capacity of 35,000 MW. The energy ministry said the proposal was expected to lead to utilisation of additional electricity to the tune of Rs24bn in four months.
Wapda, PSO issue
The ECC constituted a committee led by Minister for Economic Affairs Hammad Azhar to resolve within two weeks the issue of outstanding payments to the port authorities by Wapda and Pakistan State Oil (PSO). The meeting was informed that Wapda owed an amount of Rs1.076bn to Karachi Port Trust (KPT) after 52 consignments imported by the power authority were cleared by the KPT Board on Wapda’s request on deferred payment and following approval of the federal government. Wapda paid a sum of Rs334m as against Rs1.41bn while the remaining Rs1.076bn is still pending.
Likewise, the Petroleum Division owed an amount of Rs1.696bn to Port Qasim Authority (PQA) for wharfage charges against the LNG imported by Pakistan State Oil. The Ministry of Maritime Affairs requested the ECC to direct Wapda and the Petroleum Division to make their respective payments to the PQA.
On a proposal by the Ministry of Energy, the ECC extended the timeline by another one and a half year for the commencement of Competitive Market Operations/commercial operation date (COD) of the Competitive Trading Bilateral Contracts Market (CTBCM).
The ECC was told that the CTBCM model and plan prepared by the Central Power Purchasing Agency Limited (CPPA) following an ECC decision for transition of the power market to a Competitive Trading Bilateral Contract Market, had been submitted to Nepra for review and regulatory approval and the approval was anticipated by December 2019.
Therefore, the ECC allowed that the full operations should begin 18 months after the Nepra’s approval i.e July 2021 as required under Schedule-I of the National Electric Power Regulatory Authority (Market Operator Registration, Standards and Procedure) Rules, 2015.
Gas supply to HCPC
The ECC also took up an issue regarding the supply of gas to Habibullah Coastal Power Company (HCPC) and approved a proposal by the Petroleum Division for supply of indigenous gas for the interim period of 3 to 6 months, purely on ‘as and when available basis’ with no Liquidated Damages attached, to HCPC.
During this period the supply of RLNG would be evaluated together with commercial terms, if CPPA agreed to switch the plant on RLNG and extend the Power Purchase Agreement (PPA) accordingly.
The Ministry of Energy informed the ECC that no long term firm commitment of supply of indigenous gas to HCPC could be offered in view of the depletion of indigenous gas and the widening gap between demand and supply. However, considering the plant location of Quetta and voltage issues, the abrupt suspension of gas supply upon expiry of GSA might not allow CPPA to make alternate arrangement to stabilise the grid which is neither in the interest of Balochistan nor the country.
The ECC also approved allocation of up to 8 mmcfd gas from Chabbaro and up to 10 mmcfd gas from Gundanwari to the M/s SSGCL with the price of gas as per the applicable Petroleum Policy.
Published in Dawn, October 31st, 2019
(Bloomberg) — Canada’s beleaguered energy sector suffered another morale blow as Encana Corp. — one of its marquee companies that was born out of the 19th-century railway boom — announced plans to move its headquarters to the U.S. and drop the link to Canada from its name.
The Calgary-based company said Thursday that it will establish a corporate domicile in the U.S. early next year, pending various approvals, and rebrand under the name Ovintiv Inc. The shares fell as much as 9.3% in Toronto, the biggest drop in a year.
The move is likely to intensify the gloom already hanging over the Canadian energy industry, which has suffered from a lack of pipeline space that has choked off prospects for growth, prompting foreign companies to ditch more than $30 billion of assets in the past three years. Encana joins pipeline owner TransCanada Corp., which changed its name to TC Energy Corp. earlier this year.
“Canada is no longer viewed as a world-class destination for capital, both generally and specifically for oil and gas,” Mac Van Wielingen, founder and partner of ARC Financial Corp., a Calgary-based private equity firm focused on the Canadian energy industry, said in an interview. “There’s a whole combination of factors at work that are really working against Canada.”
Investor confidence in the sector has been eroded by the cancellation of the Northern Gateway crude oil pipeline in 2016 as well as new laws passed in recent years that may make it harder to build new energy infrastructure projects and which ban some shipments of crude from Canada’s Pacific Coast, Wielingen said. In recent years, ConocoPhillips, Royal Dutch Shell Plc and Marathon Oil Corp. have sold major Canadian assets and redeployed the proceeds in other countries.
For Encana, the move is a logical shift since Doug Suttles, a Texan, took over as chief executive officer in 2013. Suttles soon set about selling Canadian assets and building a major position in the U.S. through the purchase of Permian driller Athlon Energy and the acquisition of Freeport-McMoRan Inc.’s Eagle Ford shale assets. The company moved into the Scoop and Stack shale fields in Oklahoma, the Bakken region of North Dakota and the Uinta play in Utah with its purchase of Newfield Exploration, which closed in February.
Encana now gets about 80% of its production from U.S. plays and invests a roughly equal portion of its capital spending in them.
Suttles himself has already left Canada, moving to Denver in March of last year. In November he said he envisioned Encana as a “headquarterless” company. Last quarter, he lamented on the company’s earnings conference call that Encana shares hadn’t yet achieved the valuation worthy of a “premium” exploration and development company.
Encana said Thursday the U.S. move will expose it to larger pools of investment including American index funds and passively managed accounts, and better align the company with U.S. peers. Less than 10% of Encana’s stock is owned by passive accounts, less than the 30% average for its U.S. peers, executives said on a conference call Thursday.
Suttles said no job cuts are planned and there won’t be any decrease in Canadian investment.
Encana’s “exciting and engaging” new name isn’t meant to denigrate Canada or its policies and politics, he added, and that the recent federal election, in which the pro-energy Conservative Party failed to unseat Prime Minister Justin Trudeau, wasn’t a factor in the move.
“We don’t want people to see this as some negative reflection on Canada,” Suttles said in an interview with BNN Bloomberg television.
Encana traces its Canadian roots back to the late 1800s, when the Canadian Pacific Railway accidentally discovered natural gas while drilling a water well for workers. The company was eventually spun out from Canadian Pacific and took the name EnCana in 2002. Encana then spun off its oil sands business into Cenovus Energy Inc. in 2009.
Both stocks have underperformed since then, with Encana down about 78% including dividends, while Cenovus has dropped 48%. Canada’s benchmark stock gauge has doubled in the same period.
As part of the corporate shift, shareholders will get one common share of Ovintiv for every five shares of Encana. The move needs the support of two-thirds of votes cast at a shareholders meeting early next year.
Separately, Encana reported third-quarter adjusted operating earnings that were in line with estimates. The company raised its 2019 production outlook while maintaining its capital spending guidance, and said Permian output rose to a quarterly record while Anadarko production climbed 13% from a year earlier.
ARC’s Van Wielingen declined to speculate on whether other companies may follow Encana’s lead and decamp from Canada, but noted that investors already are asking the country’s remaining large producers some tough questions.
“Some of the ones that are left are under a lot of pressure, trying to justify their existence to their shareholders and their commitment to Canada,” Van Wielingen said.
Bloomberg.com
By Sarah McFarlane
LONDON -- Royal Dutch Shell PLC's profit rose in the third quarter, demonstrating the energy giant's resilience to weak energy prices thanks in part to its big bet on natural gas.
Shell on Thursday reported profit on a net current cost-of-supplies basis -- a figure similar to the net income that U.S. oil companies report -- for the three months ended Sept. 30 of $6.08 billion, compared with $5.57 billion in the year-earlier period.
The strong result stood out in an industry that has been hurt by weaker oil and gas prices. The U.K.'s BP PLC and France's Total SA both announced falls in third-quarter earnings, citing lower energy prices. The downstream results for all three companies were better than analysts expected, however, with BP citing high utilization of its refining capacity and Shell noting strong trading revenue.
Exxon Mobil Corp. and Chevron Corp. are due to report results on Friday.
However, Shell's adjusted profit -- excluding items such as income from asset sales -- fell to $4.77 billion from $5.62 billion a year earlier.
Shares in Shell were down 2.4% in early trading in London.
Shell's gas business reported a 23% increase in earnings for the period as production increased from fields in Australia, Trinidad and Tobago, and from the Prelude floating liquefied natural gas project. Shell's energy mix pivoted toward gas with its acquisition of BG Group in 2015.
The company also noted stronger contributions from LNG and oil-product trading. The upstream business was helped by a one-off gain from the sale of assets.
"Upstream was light due to lower natural gas liquids prices, but downstream and integrated gas (LNG) were stand out showstoppers this quarter," said Oswald Clint, analyst at Bernstein.
Shell reiterated its intention to buy back $25 billion of shares, a commitment it made after its acquisition of BG Group, having completed $12 billion so far. The company warned that there was some uncertainty on the pace of the remaining buyback, however, raising doubts over whether the program would be completed by the end of 2020, as previously planned.
"The prevailing weak macroeconomic conditions and challenging outlook inevitably create uncertainty about the pace of reducing gearing to 25% and completing the share buyback program within the 2020 time frame," said Chief Executive Ben Van Beurden in a statement.
Write to Sarah McFarlane at sarah.mcfarlane@wsj.com
(END) Dow Jones Newswires
October 31, 2019 05:40 ET (09:40 GMT)
Copyright (c) 2019 Dow Jones & Company, Inc.
EL DORADO, Ark.--(BUSINESS WIRE)--Murphy Oil Corporation (NYSE: MUR) today reported financial and operating results for the quarter ended September 30, 2019, including net income attributable to Murphy of $1.1 billion, or $6.76 per diluted share. Adjusted net income, which excludes discontinued operations and other one-off items, was $57 million, or $0.36 per diluted share.
As previously announced, Murphy closed the Malaysia asset divestiture in the third quarter for $2.0 billion in cash proceeds. These assets were reported as “discontinued operations” and classified as “held for sale” for financial reporting purposes beginning with the first quarter 2019. Unless otherwise noted, the financial and operating highlights and metrics discussed in this commentary exclude discontinued operations and noncontrolling interest.1
Operating highlights for the third quarter:
Produced 192 thousand barrels of oil equivalent per day (MBOEPD), which includes 113 thousand barrels of oil per day (MBOPD) – Murphy’s highest oil volumes since first quarter 2015, excluding Syncrude and heavy oil
Increased Eagle Ford Shale production by 15 percent from second quarter 2019 to 51 MBOEPD, with oil volumes increasing 22 percent during the same period
Reduced lease operating expenses to $7.68 per barrel of oil equivalent (BOE), driven by improvements in the Eagle Ford Shale and the Gulf of Mexico
Sanctioned St. Malo waterflood project in the Gulf of Mexico, which is expected to contribute an estimated ultimate recovery of 30 to 35 million barrels of oil equivalent (MMBOE) contingent resources net to Murphy
Expanded exploration acreage in Brazil with a farm-in to three blocks in Potiguar Basin and successful bid on three additional blocks in Sergipe-Alagoas Basin, bringing the total in Brazil to 12 blocks
Financial highlights for the third quarter:
Generated adjusted EBITDA of $438 million in the quarter, the highest level since fourth quarter 2014
Delivered cash flow in excess of property additions and dry hole costs of $134 million
Repaid borrowings of $1.4 billion under the $1.6 billion senior unsecured revolving credit facility and $500 million senior unsecured term loan with proceeds from the Malaysia asset divestiture
Continued the $500 million share repurchase program, which was completed in the fourth quarter, leading to a total share count reduction since April 2019 of 20.7 million shares, or approximately 12 percent of outstanding shares, to 152.9 million shares as of October 2019
Entered into additional crude oil commodity hedge contracts, resulting in 35 MBOPD hedged for fourth quarter 2019 at an average price of $60.51 per BOE, and subsequent to the third quarter, 45 MBOPD hedged for 2020 at an average price of $56.42 per BOE
THIRD QUARTER 2019 RESULTS
The company recorded net income, attributable to Murphy, of $1.1 billion, or $6.76 per diluted share, for the third quarter 2019. The results include a gain on the divestiture of Malaysia assets of $960 million. Adjusted net income, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, was $57 million, or $0.36 per diluted share for the same period. The adjusted income from continuing operations excludes both the gain on the Malaysian asset sale and the following primary after-tax items: a $39 million mark-to-market non-cash gain on crude oil derivatives and a $22 million mark-to-market non-cash gain on contingent consideration. Details for third quarter results can be found in the attached schedules.
Adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) from continuing operations attributable to Murphy was $438 million, or $24.65 per barrel of oil equivalent (BOE) sold. Adjusted earnings before interest, tax, depreciation, amortization and exploration expenses (EBITDAX) from continuing operations attributable to Murphy was $450 million, or $25.35 per BOE sold. Details for third quarter EBITDA and EBITDAX reconciliations can be found in the attached schedules.
Beginning with the third quarter 2019, Murphy is disclosing weighted average realized prices excluding transportation, gathering and processing expenses. A separate line item on the income statement reports transportation, gathering and processing expenses. Comparative periods have been conformed to current presentation.
Murphy continued to realize premium pricing in the third quarter 2019, with Eagle Ford Shale oil prices registering above $58 per barrel and North America offshore prices approaching $61 per barrel, both excluding the impact of commodity hedges. In the third quarter, more than 94 percent of the company’s oil volumes were sold at a premium to the average West Texas Intermediate (WTI) price of $56.45 per barrel.
Third quarter production averaged 192 MBOEPD with 66 percent liquids. Overall, production was impacted by non-operated, unplanned downtime of 2,600 BOEPD in offshore Canada and 1,400 BOEPD in the Gulf of Mexico, partially offset by higher than anticipated volumes of 500 BOEPD from operated Gulf of Mexico assets and 1,000 BOEPD in Kaybob Duvernay. Details for third quarter production can be found in the attached schedules.
“ Our company is performing exceptionally well. With a significant gain on sale of nearly $1.0 billion, we have the Malaysia divestiture behind us and are pleased to complete our first quarter as a transformed and streamlined Murphy. As an oil-weighted, Western Hemisphere focused company, our primary operations in the Gulf of Mexico and Eagle Ford Shale continue to achieve low operating costs and strong realized prices, driving healthy EBITDA given their prime access to premium markets,” stated Roger W. Jenkins, President and Chief Executive Officer.
FINANCIAL POSITION
Murphy repurchased an additional $106 million of outstanding shares in the third quarter, with the remaining $94 million under the authorized $500 million stock repurchase plan acquired in the fourth quarter, marking completion of the program. Since the beginning of the program on April 30, 2019, the company has reduced its outstanding shares by approximately 12 percent, or 20.7 million shares, from 173.6 million shares to 152.9 million shares outstanding as of October 4, 2019.
The company had $2.8 billion of outstanding long-term, fixed-rate notes at the end of third quarter 2019. The fixed-rate notes had a weighted average maturity of 7 years and a weighted average coupon of 5.5 percent.
As of September 30, 2019, Murphy had approximately $2.0 billion of liquidity, comprised of full availability under the $1.6 billion senior unsecured credit facility and $435 million of cash and cash equivalents.
“ Murphy has meaningfully de-levered its balance sheet and improved liquidity this quarter with cash from the Malaysia asset sale as part of ongoing portfolio transformation,” said Jenkins. “ As promised, we consistently return cash through our substantial dividend and reliably delivered on our share repurchase program ahead of schedule, supporting Murphy’s tenet of benefitting our shareholders.”
Continued weakness in natural gas and liquids prices has led Apache Corp. to drop rigs and defer some drilling into 2020 in its No. 1 prospect Alpine High in the Permian Basin.
The Houston-based super independent, which works in the Lower 48, deepwater Gulf of Mexico and overseas, reported third quarter losses in part on slumping commodity prices. Volatile prices also have led Apache to cut the 2020 capital expenditure outlook by 20%.
The big bet over the last few years has been within the Permian Delaware sub-basin, where Alpine High opened up opportunities in a little drilled area of West Texas. However, with little control over prices, Apache is taking control of what it can.
To that end, CEO John Christmann said the company is undergoing an overhaul.
“Apache has historically employed a decentralized, region-focused approach to operations, he said. “In recent years, we have centralized certain key activities, and today we see an opportunity to capture greater efficiencies by taking further steps in that direction.
“To accomplish this, we have initiated a comprehensive redesign of our organizational structure and operations that will position us to be competitive for the long term.”
The process, which began over the summer, is set for completion by the end of March, targeting at least $150 million of combined annual savings.
“As we look to 2020, based on current strip prices, we anticipate our upstream capital budget will be 10-20% below this year’s program of $2.4 billion,” the CEO said. “This will enable us to generate organic free cash flow that covers the current dividend and puts us on pace to fund a multi-year debt reduction program, while also delivering modest year-over-year oil production growth.”
Apache had deferred around 250 MMcf/d of gas volumes in March because of low Waha gas prices, but those lost volumes ramped in August and September as the 2 Bcf/d Gulf Coast Express ramped up.
However, “continued weakness” in gas and natural gas liquids (NGL) pricing has led Apache to reduce Alpine High drilling activity to two rigs from the five it was running in the third quarter, and it “has chosen to defer some fourth quarter completions into 2020.
“These changes, combined with a reduced production outlook for a recent multi-well pad, has resulted in a 5% decrease in fourth quarter Alpine High production guidance.”
The Alpine High had average production of 76,000 boe/d in the third quarter. In addition to running five rigs ran on average with one completion crew between July and September, 15 wells were placed on production.
Declining Gas Volumes
Apache’s overall U.S. gas volumes from onshore and offshore in 3Q2019 declined 14% year/year to 563,162 Mcf/d. Permian gas volumes, 4% higher year/year, accounted for nearly all of the production at 539,132 Mcf/d.
U.S. NGL volumes climbed 20% to 72,005 b/d from a year ago, also carried by the Permian, with output up 53% to 69,703 b/d. Total domestic oil volumes declined by 3% to 100,045 b/d. Only the Permian, which also accounted for the bulk of oil output, had higher volumes, up 5% to 94,873 b/d.
In the Permian overall, oil output in the second half of this year “has been modestly impacted by some unplanned downtime events and completion schedule delays,” management said. As a result, fourth quarter Permian oil volumes are projected to be around 100,000 b/d.
Within the Delaware sub-basin outside of Alpine High, Apache used two rigs on average during 3Q2019 and placed nine wells on production. In the twin Midland sub-basin, three rigs were running and 22 wells were turned to sales.
“Good results from a Lower Cline test well in the Azalea Field will lead to further evaluation and potential expansion of Apache’s core development inventory” within the Midland, management said.
Apache fetched an average of only 97 cents/Mcf for its U.S. gas production, versus $2.09 in 3Q2018. For the Permian gas, the realized price was 91 cents, versus 3Q2018 prices averaging $1.98. U.S. realized oil prices fell year/year to an average of $54.70/bbl from $61.20, while NGL volumes received an average $13.26/bbl compared with $30.84.
Net losses totaled $170 million (minus 45 cents/share) in 3Q2019, versus year-ago profits of $81 million (21 cents). Revenue declined to $1.44 billion from $1.98 billion.
Albemarle Corp (ALB.N), the world’s largest lithium producer, on Thursday cut its sales and profit forecasts for the year, hit by a continued slump in prices for the white metal, sending its shares down nearly 7% in extended trading.
Demand for lithium, a key component of batteries used in cell phones, electric vehicles and other consumer goods, is widely expected to spike by 2025.
But global trade tensions, the scaling back of electric vehicle subsidies in China and increased production have pressured prices in recent months.
The company now expects adjusted earnings per share in the range of $6.00 to $6.20 in the year, compared with its previous estimate of $6.25 to $6.65.
Albemarle also trimmed its 2019 net sales forecast range to $3.6 billion to $3.7 billion, from $3.65 billion to $3.85 billion.
The company also reported preliminary third quarter adjusted profit of $1.53 per share hit by weakness in its lithium unit, which offset results from its bromine and catalysts units.
Analysts on an average expect the company to report an adjusted profit of $1.63, according to IBES data from Refinitiv.
The company said lithium unit sales volume in the quarter was lower than expected mainly due to Typhoon Tapah, in late September, that caused lithium shipments from ports in Shanghai to be delayed into October.
Overall lithium pricing was flat to slightly up in the third quarter versus prior year with continued price pressure on lithium sales in China hitting its core earnings by about $5 million.
“Despite one-time items impacting our third quarter results and challenging market conditions heading into 2020, we remain confident in the long-term growth prospects of lithium,” said Chief Executive Officer Luke Kissam.
Two Equinor-operated fields located offshore Norway, the Sleipner field centre and the Gudrun field, will receive power from shore to further reduce CO₂ emissions on the Norwegian Continental Shelf.
The Utsira High Area power grid, which will become operational in 2022, will provide power from shore to the Johan Sverdrup, Edvard Grieg, Ivar Aasen, Gina Krog, and Sleipner fields.
The licenses that now will receive power from shore from the Utsira High area solution are operated by Equinor, Lundin Norway, and Aker BP.
Equinor said on Monday that the area’s license partners have recently agreed on maximizing the utilization of power from shore to the area by enabling partial electrification of the Sleipner field centre as well. The overall area solution will contribute to an average reduction in CO₂ emissions close to 1.2 million tonnes of CO₂ per year.
Anders Opedal, executive vice president for Technology, projects & drilling in Equinor, said: “The Norwegian continental shelf (NCS) is leading in producing oil and gas with low greenhouse gas emissions. By enabling partial electrification of Sleipner and tie-in fields, we are making maximum utilization of the area solution for power from shore to the Utsira High to further reduce emissions from the NCS.”
The original area solution for power from shore to the Utsira High comprises the Johan Sverdrup, Edvard Grieg, Gina Krog, and Ivar Aasen fields.
The power from shore solution included in the second phase of the Johan Sverdrup development will provide additional capacity of 35 MW in order to meet increased power demand from existing or additional fields in the future.
Power from shore for Sleipner & Gudrun
According to Equinor, based on the result of recent negotiations by the license partners, the Sleipner field centre, together with the Gudrun platform and other tie-ins, will receive power from shore to meet parts of their power demand. This solution will also ensure that the Lundin Norway-operated Edvard Grieg platform will be able to fully meet its power demand through power from shore.
Equinor noted that emission reductions based on the Utsira High area solution were estimated at more than 1 million tonnes of CO₂ on average per year. Further emission reductions by partial electrification of Sleipner are estimated at more than 150,000 tonnes of CO₂ per year.
“I am pleased that the Sleipner license partners support a solution enabling the Sleipner field centre and tie-ins to be connected to the power from shore solution. It was not an easy task to find a technical and commercial solution that meets the needs of all licenses in this area, so I would like to thank all involved companies and Norwegian authorities who have helped ensure a maximum and holistic utilization of the power from shore capacity in the area,” said Opedal.
The Sleipner field centre solution calls for Sleipner to lay a power cable to the Gina Krog platform, which will be connected to the Utsira High area solution by a separate power cable by the end of 2022. In certain periods the field’s power from shore demand may exceed the capacity of the area solution. In such periods Sleipner will use gas turbines to cover its shortage.
The industry’s NOx Fund provides up to NOK 430 million to realize the partial electrification of Sleipner and tie-ins.
The Sleipner license partners are planning to make a final investment decision during the second quarter of 2020.
“Due to the transition we are facing on the NCS, we must reduce the carbon footprint from our operations to protect and develop the value from the Norwegian shelf,” says Arne Sigve Nylund, executive vice president for Development & production Norway in Equinor.
Plan to fully electrify Edvard Grieg
Lundin Norway is the operator of the Edvard Grieg platform with a 65 percent working interest and the partners are OMV Norge and Wintershall DEA with 20 and 15 percent working interests, respectively.
The Edvard Grieg power from shore project involves the retirement of the existing gas turbine power generation system on the platform, installation of electric boilers to provide process heat and installation of a power cable from Johan Sverdrup to Edvard Grieg. When the facilities are all operational, Lundin Norway’s net capital investment in power from shore facilities at Edvard Grieg and Johan Sverdrup will total approximately $500 million, half of which has already been spent.
Alex Schneiter, President and CEO of Lundin Petroleum, said: “Full power from shore for Edvard Grieg, as part of the Utsira High power grid, will not only significantly reduce the carbon emissions from the area to below 1kg of CO2 per barrel but will also allow us to drive further value from the asset base through higher production efficiency, reduced operating costs and less carbon tax.
“The CO2 saved from Edvard Grieg alone, will amount to approximately 200,000 tonnes per year from 2022, in addition to the emission savings as a result of power from shore to Johan Sverdrup. The Edvard Grieg project will further solidify Lundin Petroleum’s position as a world leading low carbon emissions oil producer, with its two key assets fully or becoming fully electrified, using power from shore mainly sourced from renewable energy.”
Offshore Energy Today Staff
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IEA published their Offshore Wind Outlook 2019
Executive Summary
The need for affordable low-carbon technologies is greater than ever
Global energy-related CO2 emissions reached a historic high in 2018, driven by an increase in coal use in the power sector. Despite impressive gains for renewables, fossil fuels still account for nearly two-thirds of electricity generation, the same share as 20 years ago. There are signs of a shift, with increasing pledges to decarbonise economies and tackle air pollution, but action needs to accelerate to meet sustainable energy goals. As electrification of the global energy system continues, the need for clean and affordable low-carbon technologies to produce this electricity is more pressing than ever. This World Energy Outlook special report offers a deep dive on a technology that today has a total capacity of 23 GW (80% of it in Europe) and accounts for only 0.3% of global electricity generation, but has the potential to become a mainstay of the world's power supply. The report provides the most comprehensive analysis to date of the global outlook for offshore wind, its contributions to electricity systems and its role in clean energy transitions.
The offshore wind market has been gaining momentum
The global offshore wind market grew nearly 30% per year between 2010 and 2018, benefitting from rapid technology improvements. Over the next five years, about 150 new offshore wind projects are scheduled to be completed around the world, pointing to an increasing role for offshore wind in power supplies. Europe has fostered the technology's development, led by the United Kingdom, Germany and Denmark. The United Kingdom and Germany currently have the largest offshore wind capacity in operation, while Denmark produced 15% of its electricity from offshore wind in 2018. China added more capacity than any other country in 2018.
The untapped potential of offshore wind is vast
The best offshore wind sites could supply more than the total amount of electricity consumed worldwide today. And that would involve tapping only the sites close to shores. The IEA initiated a new geospatial analysis for this report to assess offshore wind technical potential country by country. The analysis was based on the latest global weather data on wind speed and quality while factoring in the newest turbine designs. Offshore wind's technical potential is 36 000 TWh per year for installations in water less than 60 metres deep and within 60 km from shore. Global electricity demand is currently 23 000 TWh. Moving further from shore and into deeper waters, floating turbines could unlock enough potential to meet the world's total electricity demand 11 times over in 2040. Our new geospatial analysis indicates that offshore wind alone could meet several times electricity demand in a number of countries, including in Europe, the United States and Japan. The industry is adapting various floating foundation technologies that have already been proven in the oil and gas sector. The first projects are under development and look to prove the feasibility and cost-effectiveness of floating offshore wind technologies.
Offshore wind's attributes are very promising for power systems
New offshore wind projects have capacity factors of 40-50%, as larger turbines and other technology improvements are helping to make the most of available wind resources. At these levels, offshore wind matches the capacity factors of gas- and coal-fired power plants in some regions – though offshore wind is not available at all times. Its capacity factors exceed those of onshore wind and are about double those of solar PV. Offshore wind output varies according to the strength of the wind, but its hourly variability is lower than that of solar PV. Offshore wind typically fluctuates within a narrower band, up to 20% from hour to hour, than solar PV, which varies up to 40%.
Offshore wind's high capacity factors and lower variability make its system value comparable to baseload technologies, placing it in a category of its own – a variable baseload technology. Offshore wind can generate electricity during all hours of the day and tends to produce more electricity in winter months in Europe, the United States and China, as well as during the monsoon season in India. These characteristics mean that offshore wind's system value is generally higher than that of its onshore counterpart and more stable over time than that of solar PV. Offshore wind also contributes to electricity security, with its high availability and seasonality patterns it is able to make a stronger contribution to system needs than other variable renewables. In doing so, offshore wind contributes to reducing CO2 and air pollutant emissions while also lowering the need for investment in dispatchable power plants. Offshore wind also has the advantage of avoiding many land use and social acceptance issues that other variable renewables are facing.
Offshore wind is on track to be a competitive source of electricity
Offshore wind is set to be competitive with fossil fuels within the next decade, as well as with other renewables including solar PV. The cost of offshore wind is declining and is set to fall further. Financing costs account for 35% to 50% of overall generation cost, and supportive policy frameworks are now enabling projects to secure low cost financing in Europe, with zero-subsidy tenders being awarded. Technology costs are also falling. The levelised cost of electricity produced by offshore wind is projected to decline by nearly 60% by 2040. Combined with its relatively high value to the system, this will make offshore wind one of the most competitive sources of electricity. In Europe, recent auctions indicate that offshore wind will soon beat new natural gas-fired capacity on cost and be on a par with solar PV and onshore wind. In China, offshore wind is set to become competitive with new coal-fired capacity around 2030 and be on par with solar PV and onshore wind. In the United States, recent project proposals indicate that offshore wind will soon be an affordable option, with potential to serve demand centres along the country's east coast.
Innovation is delivering deep cost reductions in offshore wind, and transmission costs will become increasingly important. The average upfront cost to build a 1 gigawatt offshore wind project, including transmission, was over $4 billion in 2018, but the cost is set to drop by more than 40% over the next decade. This overall decline is driven by a 60% reduction in the costs of turbines, foundations and their installation. Transmission accounts for around one-quarter of total offshore wind costs today, but its share in total costs is set to increase to about one-half as new projects move further from shore. Innovation in transmission, for example through work to expand the limits of direct current technologies, will be essential to support new projects without raising their overall costs.
Offshore wind is set to become a $1 trillion business
Offshore wind power capacity is set to increase by at least 15-fold worldwide by 2040, becoming a $1 trillion business. Under current investment plans and policies, the global offshore wind market is set to expand by 13% per year, passing 20 GW of additions per year by 2030. This will require capital spending of $840 billion over the next two decades, almost matching that for natural gas-fired or coal-fired capacity. Achieving global climate and sustainability goals would require faster growth: capacity additions would need to approach 40 GW per year in the 2030s, pushing cumulative investment to over $1.2 trillion.
The promising outlook for offshore wind is underpinned by policy support in an increasing number of regions. Several European North Seas countries – including the United Kingdom, Germany, the Netherlands and Denmark – have policy targets supporting offshore wind. Although a relative newcomer to the technology, China is quickly building up its offshore wind industry, aiming to develop a project pipeline of 10 GW by 2020. In the United States, state-level targets and federal incentives are set to kick-start the offshore wind market. Additionally, policy targets are in place and projects under development in Korea, Japan, Chinese Taipei and Viet Nam.
The synergies between offshore wind and offshore oil and gas activities provide new market opportunities. Since offshore energy operations share technologies and elements of their supply chains, oil and gas companies started investing in offshore wind projects many years ago. We estimate that about 40% of the full lifetime costs of an offshore wind project, including construction and maintenance, have significant synergies with the offshore oil and gas sector. That translates into a market opportunity of $400 billion or more in Europe and China over the next two decades. The construction of foundations and subsea structures offers potential crossover business, as do practices related to the maintenance and inspection of platforms. In addition to these opportunities, offshore oil and gas platforms require electricity that is often supplied by gas turbines or diesel engines, but that could be provided by nearby wind farms, thereby reducing CO2 emissions, air pollutants and costs.
Offshore wind can accelerate clean energy transitions
Offshore wind can help drive energy transitions by decarbonising electricity and by producing low-carbon fuels. Over the next two decades, its expansion could avoid between 5 billion and 7 billion tonnes of CO2 emissions from the power sector globally, while also reducing air pollution and enhancing energy security by reducing reliance on imported fuels. The European Union is poised to continue leading the offshore wind industry in support of its climate goals: its offshore wind capacity is set to increase by at least fourfold by 2030. This growth puts offshore wind on track to become the European Union's largest source of electricity in the 2040s. Beyond electricity, offshore wind's high capacity factors and falling costs makes it a good match to produce low-carbon hydrogen, a versatile product that could help decarbonise the buildings sector and some of the hardest to abate activities in industry and transport. For example, a 1 gigawatt offshore wind project could produce enough low-carbon hydrogen to heat about 250 000 homes. Rising demand for low-carbon hydrogen could also dramatically increase the market potential for offshore wind. Europe is looking to develop offshore "hubs" for producing electricity and clean hydrogen from offshore wind.
It's not all smooth sailing
Offshore wind faces several challenges that could slow its growth in established and emerging markets, but policy makers and regulators can clear the path ahead. Developing efficient supply chains is crucial for the offshore wind industry to deliver low-cost projects. Doing so is likely to call for multibillion-dollar investments in ever-larger support vessels and construction equipment. Such investment is especially difficult in the face of uncertainty. Governments can facilitate investment of this kind by establishing a long-term vision for offshore wind and precisely defining the measures to be taken to help make that vision a reality. Long-term clarity would also enable effective system integration of offshore wind, including system planning to ensure reliability during periods of low wind availability.
The success of offshore wind depends on developing onshore grid infrastructure. Whether the responsibility for developing offshore transmission lies with project developers or transmission system operators, regulations should encourage efficient planning and design practices that support the long-term vision for offshore wind. Those regulations should recognise that the development of onshore grid infrastructure is essential to the efficient integration of power production from offshore wind. Without appropriate grid reinforcements and expansion, there is a risk of large amounts of offshore wind power going unused, and opportunities for further expansion could be stifled. Development could also be slowed by marine planning practices, regulations for awarding development rights and public acceptance issues.
The future of offshore wind looks bright but hinges on the right policies
The outlook for offshore wind is very positive as efforts to decarbonise and reduce local pollution accelerate. While offshore wind provides just 0.3% of global electricity supply today, it has vast potential around the world and an important role to play in the broader energy system. Offshore wind can drive down CO2 emissions and air pollutants from electricity generation. It can also do so in other sectors through the production of clean hydrogen and related fuels. The high system value of offshore wind offers advantages that make a strong case for its role alongside other renewables and low-carbon technologies. Government policies will continue to play a critical role in the future of offshore wind and the overall pace of clean energy transitions around the world.
Full PDF version
LME Week: Stung by sliding prices, lithium industry pares back expansions
Albemarle Corp, SQM and other lithium producers have been scaling back expansion plans as near-term oversupply concerns drag on prices, unnerving investors who are pushing the industry to focus more on profitability.
Volkswagen (VOWG_p.DE), BMW and other automakers planning to produce all-electric fleets of vehicles during the next decade with lithium-ion batteries are expected to help global demand for the white metal more than triple by 2025 to 917,469 tonnes, according to Canaccord Genuity.
But shareholders worry lithium producers have boosted production to levels far above current needs. Global supply is 5% higher than demand, the Canaccord Genuity data showed.
“The problem in lithium is the growth rate is so high, that when producers over-deliver, they over-deliver big,” said Jon Hykawy, a battery minerals analyst at Stormcrow Capital. Battery metals are expected to be a major part of the discussion this week as the world’s metals industry gathers in London for the London Metal Exchange (LME) Week. Lithium shareholders seem keen not to repeat the mistakes made by early investors in the U.S. shale boom, which prioritized growth over cash flow in a push to make the United States the world’s largest oil and natural gas producer. A decade after that boom began, many U.S. shale companies are not profitable.
Albemarle, the world’s largest lithium producer, is delaying construction plans for about 125,000 tonnes of additional lithium processing capacity, part of a plan to be cash flow positive within two years.
Based in Charlotte, North Carolina, Albemarle last week cut its sales and profit forecasts for the year, citing the continued slump in prices for the metal.
“When I talk to shareholders, the number one thing I hear is, ‘When are you going to be free cash flow positive?’” Albemarle Chief Executive Officer Luke Kissam said.
AUTOMAKERS PUSH AHEAD
Santiago-based rival SQM, the world’s second-largest lithium producer, is delaying an expansion in Chile’s Atacama salt flat until the end of 2021.
Sliding spot prices around the globe, particularly in China, have hurt large and small producers alike.
Global trade tensions, slowing growth and the scaling back of Chinese electric vehicle (EV) subsidies have undermined demand. Lithium carbonate prices in China are down 65% to $8,500 per tonne since the start of 2018, according to data from Benchmark Minerals Intelligence.
Prices for lithium derived from Australian hard rock, also known as spodumene, are down 38% to $543 per tonne. A Benchmark global price index is down about 52% in the same time period.
There may be a short-term boost in prices as protesters from indigenous communities in the Atacama block access to lithium operations amid Chilean rallies over inequality.
Automakers, meanwhile, are pushing ahead. South Korea’s LG Chem, the battery maker that counts General Motors and Volkswagen as customers, expects global EV sales to jump from 2.4 million last year to 13.2 million in 2024, which would account for 15% of total vehicle sales that year.
The divergence in lithium prices, even as EV projections rise, is confusing for investors, much to the chagrin of Kissam and other industry executives.
“Wall Street is struggling to differentiate lithium stories,” said Paul Graves, CEO of Livent Corp, which operates in northern Argentina. “There’s an oversimplification among analysts. They just look at Chinese spot prices, but the lithium market is so much more than that.”
Commentary: Understanding the World Energy Outlook scenarios
Today's energy choices and their consequences
Today’s energy choices will shape the future of energy, but how should we assess their impact and adequacy? This is the task the World Energy Outlook takes on. It aims to inform the thinking of decision makers as they design new policies or consider new investments. It does so by exploring possible futures, the ways they come about and some of the main uncertainties – and it lays out the consequences of different choices for our energy use, energy security and environment.
One key element of this is to assess where the global energy system is heading, based on the policy plans and investment choices we see today. A second is to assess what would need to be done differently in order to reach the climate, energy access, pollution and other goals that policy makers have set themselves.
As ever, this year’s World Energy Outlook, to be released on 13 November, brings many changes from the 2018 edition. In this commentary, we wanted to highlight two in particular.
Introducing the Stated Policies Scenario
In this year’s Outlook, the New Policies Scenario is renamed as the Stated Policies Scenario (the acronym is STEPS – STated Energy Policies Scenario). As with its predecessor, this scenario is designed to reflect the impact not just of existing policy frameworks, but also of today’s stated policy plans. The name change underlines that this scenario considers only those policy initiatives that have already been announced. The aim is to hold up a mirror to the plans of today’s policy makers and illustrate their consequences, not to guess how these policy preferences may change in the future.
The planned policies analysed in this scenario cover a wide spectrum. For example, a country might state that it intends to remove fossil-fuel consumption subsidies or, alternatively, that it will walk back a previous reform. Another might say that it will tighten future fuel efficiency standards or step up support for electric vehicles. One might open up new resource developments in oil and gas while another might limit them.
Many countries today are raising their ambitions for clean energy deployment, as reflected by the rising interest in offshore wind that we explored in depth in a special focus from this year’s World Energy Outlook that was released separately in Copenhagen last week. Countries may also announce new rural electrification targets or ambitions to bring clean fuels to parts of their population that rely on firewood or other solid biomass for cooking.
All of these stated policies are assessed individually and their impacts are modelled. In our updated and expanded online explainer on the World Energy Model, the large-scale simulation model that is used to generate all our projections, we have made all the key policy assumptions available for all scenarios, along with all the underlying assumptions on population, economic growth and energy resources (which are held constant across the scenarios) and information on prices and technology costs (which vary by scenario depending on the market and policy context).
There is one type of policy announcement that deserves special attention: the growing number of long-term decarbonisation targets, including “net zero” commitments. After the UN Climate Summit in September, there were at least 65 jurisdictions, including the European Union, that had set or were actively considering long-term net-zero carbon targets. These economies together accounted for 21% of global gross domestic product and nearly 13% of energy-related CO2 emissions in 2018.
Under discussion In policy document Proposed legislation In law Achieved European Union 9.6359925 Other 2.5550351 Portugal 0.1555503 Finland 0.1305446 Ireland 0.1094669 Norway 0.1065267 Switzerland 0.1138041 Denmark 0.095809 Costa Rica 0.0232429 Uruguay 0.017998 Iceland 0.0066602 Marshall Islands 0.0003147 Chile 0.263819 New Zealand 0.0988062 Fiji 0.004413 United Kingdom 1.0993528 France 0.9381333 Sweden 0.1153616 Suriname 0 Bhutan 0
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Are these “net zero” targets all incorporated into the Stated Policies Scenario? It depends. The target has to be announced or adopted officially, but the crucial variable is how visible the pathway is to reach it. As always with the World Energy Outlook, the details matter. Is there a strategy to decarbonise heat? What about heavy industry? What about trucks or aviation? To the extent that these pathways are laid out, then the overall ambition is also reflected in this scenario.
And it’s not only about national governments: other commitments are becoming increasingly important, whether from sub-national authorities, cities, companies or investors. We also keep a close eye on changing public attitudes and preferences, as these can be very significant in shaping energy use (as, for example, with the rising popularity of SUVs).
In aggregate, these commitments are enough to make a significant difference. The comparison with the Current Policies Scenario, which only looks only at policies in place but from which the effects of announced policies are excluded, makes this clear. However, there is still a large gap between the projections in the Stated Policies Scenario and an energy system that meets global sustainable energy goals.
Extending the Sustainable Development Scenario to 2050
What should policy makers do? What pathways might help meet these targets? What technologies need a boost? Where should innovation, research and investment be directed? How can we balance growing energy demand with the need to reduce air pollution and carbon emissions? How can millions of people gain access to critical energy services while also meeting climate goals?
The IEA seeks to help policy makers in government and industry shape a more secure and sustainable energy future. This is why the World Energy Outlook has been providing detailed climate mitigation scenarios for more than a decade. Two years ago, we introduced a new scenario, the Sustainable Development Scenario, which also incorporates two other crucial elements of the Sustainable Development agenda: cleaner air and universal access to energy, in addition to climate targets.
In the IEA’s view, these elements are profoundly interconnected aspects of global energy transitions. The Sustainable Development Scenario is one of the very few deep decarbonisation scenarios that considers all of them in detail and provides a pathway that achieves them simultaneously, along with detailed attention to the security and affordability of energy supply. In our view, no vision of a sustainable energy world can be considered complete if parts of the global population do not have access to modern energy.
Another new feature of this year’s WEO is that the horizon for the Sustainable Development Scenario is extended by a decade to 2050. This has little impact on achieving modern energy for all, both for electricity and clean cooking. That goal is reached by 2030 in this scenario. But it provides a clearer view on how dramatic improvements in air quality reduce pollution-related premature deaths. And it gives considerable additional clarity on how the scenario meets the Paris Agreement goal of holding the rise in global temperatures to “well below 2°C … and pursuing efforts to limit [it] to 1.5°C.”
The Sustainable Development Scenario models a rapid and deep transformation of the global energy sector. It is consistent with all the “net zero” goals contemplated today being reached on schedule and in full. The technology learning and policy momentum that they generate means that they become the leading edge of a much broader worldwide effort, bringing global energy-related CO2 emissions down sharply to less than 10 billion tonnes by 2050, on track for global net zero by 2070.
This means that the Sustainable Development Scenario is “likely” (with 66% probability) to limit the rise in the average global temperature to 1.8 °C, which is broadly equivalent to a 50% probability of 1.65 °C stabilisation. These outcomes are achieved without any recourse to net negative emissions.
Compare the new SDS 2019 to IPCC scenarios with a less than 1.5°C 1.5-1.6°C 1.6-1.7°C 1.7-1.8°C 1.8-1.9°C 1.9-2.0°C temperature rise in 2100
How does this scenario relate to the pursuit of a 1.5 °C outcome? For one answer to this question, we turned to the IPCC Special Report on 1.5 °C. Almost all the 1.5 °C scenarios assessed by the IPCC (88 out of 90) assume some level of net negative emissions. A level of net negative emissions significantly smaller than that used in most scenarios assessed by the IPCC would provide the Sustainable Development Scenario with a 50% probability of limiting the rise in global temperatures to 1.5°C.
However, as we have pointed out in the past, there are reasons to limit reliance on early-stage technologies for which future rates of deployment are highly uncertain. That is why the Outlook has always emphasised the importance of early policy action. That is also why, in the WEO-2019, we explore what it would take to achieve stabilisation at 1.5 °C with a 50% probability without net negative emissions.
Two different types of scenario make a powerful mix
The World Energy Outlook incorporates two different approaches to scenario design. The first defines a set of starting conditions and sees where they lead; the Stated Policies Scenario and the Current Policies Scenario are of this type.
The second approach does the opposite, defining a set of ambitious future outcomes and then working out how they can be achieved: this is the principle underlying the Sustainable Development Scenario.
Each of these approaches, on its own, offers powerful insights. In combination, they provide a broad perspective not just on the energy and climate challenges that we face today, but on what can be done to address them.
panorama
BNEF: solar and wind reach parity with power prices in California, China and parts of Europe
Latest Levelized Cost of Electricity (LCOE) figures by BloombergNEF (BNEF) reveal that the global benchmark LCOE for onshore wind and PV projects has reached $47 and $51/MWh, down 6 percent and 11 percent respectively from six months ago, mainly owing to cheaper equipment while the offshore wind LCOE benchmark sits at $78/MWh, down from 32 percent last year.
New PV and onshore wind power plants have now reached parity with average wholesale prices in California, China and parts of Europe. These technologies are winning the race as the cheapest sources of new generation with two-thirds of the global population living in countries where PV or wind are cheaper than coal and gas power plants.
New solar and onshore wind power plants have now reached parity with average wholesale prices in California and parts of Europe. In China, their levelised costs are now below the average regulated coal power price, the reference price tag in the country.
For wind the figures are mainly due to the fall in the price of wind turbines, 7 percent lower on average globally compared to the end of 2018. In China, the world’s largest solar market, the capex of utility-scale PV plants has dropped 11 percent in the last six months, reaching $0.57 million per MW. Weak demand for new plants in China has left developers and engineering, procurement and construction firms eager for business, and this has put pressure on capex.
BNEF estimates that some of the cheapest PV projects financed recently will be able to achieve an LCOE of $27-36/MWh, assuming competitive returns for their equity investors. Those can be found in India, Chile and Australia. Best-in-class onshore wind farms in Brazil, India, Mexico and Texas can reach levelised costs as low as $26-31/MWh already.
Offshore wind has seen the fastest cost declines, down 32 percent from just a year ago and 12 percent compared to the first half of 2019. BNEF’s current global benchmark LCOE estimate is $78/MWh. New offshore wind projects throughout Europe now deploy turbines with power ratings up to 10 MW, unlocking capex and opex savings. In Denmark and the Netherlands, BNEF expects the most recent projects financed to achieve $53-64/MWh excluding transmission.
“This is a three-stage process” said Tifenn Brandily, associate in BNEF’s energy economics team and the report’s author. “In phase one, new solar and wind get cheaper than new coal and gas plants on a cost-of-energy basis. In phase two, renewables reach parity with power prices. In phase three, they become even cheaper than running existing thermal plants. Our analysis shows that phase one has now been reached for two-thirds of the global population. Phase two started with California, China and parts of Europe. We expect phase three to be reached on a global scale by 2030.”
Mr Brandily added that as this all plays out, thermal power plants will increasingly be relegated to a balancing role, looking for opportunities to generate when the sun doesn’t shine or the wind doesn’t blow.
BNEF’s 2H 2019 LCOE analysis covers nearly 8,000 projects across 20 technologies and 46 countries globally. All updated technology costs and performance inputs are available on BloombergNEF’s digital platforms.
For additional information:
BloombergNEF (BNEF)
https://www.renewableenergymagazine.com/panorama/bnef-solar-and-wind-reach-parity-with-20191029
Lower output forecasts and project returns from Orsted eclipsed a jump in third-quarter profit, sending shares in the world’s largest offshore wind energy developer down as much as 10% on Tuesday.
Upgraded modeling of expected energy production prompted the lower output forecasts, it said.
“Our current production forecasts underestimate the negative impact of two effects across our asset portfolio, i.e. the blockage effect and the wake effect,” the company said.
Growth in average core earnings from operating wind farms through 2023 will remain unchanged at around 20%, however its target for “unlevered lifecycle IRR”, its returns on seven wind farm projects, would be reduced to 7.0-8.0% from 7.5-8.5%, it said.
It lowered its projected annual production from 10 European wind farm projects to 48% of maximum capacity from an earlier 48-50%.
“Investors have grown accustomed to (and perhaps therefore taken for granted), that there could come further upgrades to guidance. So the downgrade hits extra hard,” Nordnet analyst Per Hansen said.
COST CUTTING
“Not to talk it down, but for me this is not a major setback for the industry at all,” chief financial officer Wiinholt said in a conference call with media.
“The industry will still grow, we are in a way more competitive than gas and coal,” she added.
European oil majors like Total and Equinor are looking to offshore wind amid pressure from shareholders to show how they plan to align their businesses with global efforts to cut emissions.
In a bid to stay ahead as industry leader, Orsted said it would cut costs by 500-600 million crowns between 2020 and 2022, including one-off reductions and “reductions across our staff functions”.
Following the announcement, Orsted issued its third-quarter results report a day ahead of schedule.
It reported an 85% jump in EBITDA to 4.12 billion Danish crowns ($611.45 million), topping the 3.27 billion forecast by seven analysts in a poll provided by the company.
It maintained its outlook for the year - a target it raised in September with earnings before interest, tax, depreciation and amortization (EBITDA) seen at 16-17 billion Danish crowns, up from a previous 15.5-16.5 billion.
“We had a very strong third quarter with high wind speeds and a ramp-up generation from new wind farms,” CEO Henrik Poulsen said in a statement.
Earnings from wind farms in operation increased by 23% in the first nine months to 8.6 billion crowns, it said.
Orsted shares were down 8.44% at 1343 GMT.
Cobalt supply will remain robust despite a price slide that has already led to the closure of a major mine, Russia’s Norilsk Nickel said, as most is produced as a byproduct of more buoyant metals like nickel and copper.
Prices of the battery metal surged in 2017 and 2018 on expectations for an electric vehicle revolution, but have fallen this year due to excessive supply and the impact of the U.S.-China trade war.
They are now down 60% from their spring 2018 peak.
In August global mining and trade giant Glencore said it would shutter its Mutanda mine in the Democratic Republic of Congo from year-end for two years due to low cobalt prices.
The mine accounts for 15% of global cobalt supplies, according to Credit Suisse estimates.
“The fact that one mine is being removed from supply does not radically change the situation - we do not have a shortage of the metal,” Anton Berlin, head of Nornickel’s marketing department, told Reuters. “We do not see a structural problem for the market.”
Nornickel, the world’s eighth largest cobalt producer with about 3% of global output, mines the metal in mixed ores in its Arctic deposits along with nickel, palladium, copper and platinum.
“In most cases, the cobalt market is in surplus,” Berlin said. “Probably because it is a by-product, no one limits (its production) because of low prices.”
Speaking ahead of LME Week, a gathering of the metal industry in London this week, Berlin also said Nornickel’s battery materials project with Germany’s BASF was unlikely to be affected by lower cobalt prices.
BASF is building a factory to make cathode materials for electric car batteries in Finland, close to Nornickel’s nickel and cobalt refinery, which supplies raw materials to the project.
While cobalt consumption is still growing, Nornickel sees expectations for demand as overstated as the industry focuses on boosting the nickel content of batteries at the expense of cobalt, part of a bid to increase energy storage capacity.
KUALA LUMPUR: As Malaysia and the European Union continue engaging in a dispute over the sustainability of palm oil production, the local palm oil market faces another challenge — with its largest buyer and the world’s biggest edible oil importer, India.
According to market observers, Indian traders are now sourcing more palm oil from Indonesia following a recent advisory by India’s top vegetable oil trade body to its members to refrain from importing palm oil from Malaysia.
The advisory from the Solvent Extractor’s Association, representing India’s oilseed crushers, was issued in protest over Prime Minister Tun Dr Mahathir Mohamad’s political remarks at the UN General Assembly on the Kashmir conflict.
However, local industry experts viewed that a ban is unlikely, noting there have not been any official directives from the Indian government so far.
Even if the ban materialises, any market disruptions will only be short term before it normalises, said CGS-CIMB Research head of agribusiness Ivy Ng.
“We expect some negative impact in terms of Malaysia’s palm oil exports to India in November and December. There may be trade disruptions in the short term, if there is a sudden change in preference by India towards Indonesian palm oil and this may lead to higher accumulation of palm oil stocks in Malaysia,” she told The Edge Financial Daily.
However, she believes the potential diversion of palm oil demand by India from Malaysia to Indonesia may not last due to supply constraints in the Indonesian palm oil market.
“If Indonesia fulfils the additional demand from India and domestic requirement due to a higher B30 biodiesel mandate in 2020, it will have less palm oil to sell to other markets and demand for palm oil may be diverted back to Malaysia over [some] time,” said Ng.
She added that higher demand for Indonesian palm oil could help narrow the price gap between Indonesian and Malaysian crude palm oil (CPO). Malaysian CPO usually trades at a premium to Indonesian CPO.
An analyst, declining to be named, concurred, saying a ban is unlikely as palm oil constitutes about half of India’s edible oil consumption.
The analyst believes talk of a ban by India on import of palm oil from Malaysia is more about pressure on its government to further raise the import tax on Malaysian palm oil.
India last month raised the import duty on refined palm oil from Malaysia to 50% from 45% to curb imports and boost local refining.
“Unless that is the agenda ... It is a zero-sum game [if the ban happens] since refined palm oil from Malaysia will eventually go somewhere,” the analyst said.
“The most likely scenario is for India to buy less in the near future until the news dies down ... Meanwhile, I believe that CPO sold from estates in Indonesia [by Malaysian companies] will be insulated from the ban. These companies can sell to the middleman and later sell to India as Indonesian palm oil,” he added.
Last year, Malaysia’s total trade with India rose 2.2% to RM62.76 billion from RM61.38 billion in 2017.
Besides palm oil, Malaysia’s trade with India includes oil and gas, automobiles, chemicals, electrical and electronics, food and other finished goods.
In the first nine months of this year, Malaysia exported 3.91 million tonnes of palm oil to India, 107% higher than 1.89 million tonnes exported a year ago, statistics from the Malaysian Palm Oil Board showed.
To fill the gap left by Malaysia would be tricky for Indonesia, currently facing supply constraints, said palm oil expert MR Chandran.
He added that it makes little economic sense for Indian traders to source from Indonesia as they would end up paying more.
“If India switches to Indonesia, why should Indonesia sell at a discount? Indonesia would become a monopoly as far as Indian demand is concerned and has the bargaining power.
“Also, whatever orders placed, they would abide to avoid hefty penalties, which is why prices are still holding at current levels. And those wanting to switch their futures contracts to Indonesian palm oil might face logistical issues and additional costs from having shippers to diverge their ships,” he said.
At last Friday’s close, the benchmark third-month palm oil futures contract rose another RM14 to trade at RM2,398 a tonne — its highest since notching RM2,402 in June 2018, Bloomberg data showed.
More importantly, Chandran pointed out Indonesia’s hands are tied to an extent, given its plateauing production and ambitious B30 biodiesel mandate.
It was reported that the country’s energy ministry had allocated 9.59 million kilolitre of unblended biodiesel for its mandatory biofuel programme in 2020, up a whopping 45% from 6.63 million this year.
Chandran believes India, a price-sensitive market, will continue trading with Malaysia because of palm oil’s competitive price advantage, now trading at a US$200 (RM838) per tonne price discount to that of soybean oil.
“[Palm oil] trade today is between private sectors. It all goes back to pure economics of trade. To traders and buyers, it’s about money and not political decisions because it is not a government-to-government agreement,” he added.
Chandran said the first step to addressing this issue is to seek clarification on the Indian government’s official stance.
“We don’t want to get caught in all these trade disputes when the world economy is not doing well and costs are rising.”
SINGAPORE — Chicago corn futures slid for a second session on Tuesday, while
soybeans lost ground, as progress in the harvest of both crops in the United States weighed on
prices.
Wheat edged higher after dropping to its lowest in almost two weeks on Monday.
FUNDAMENTALS
* U.S. farmers have harvested 62% of their soybean crop, up from 46% a week ago although below
the average pace of 78% at this time of the year, the U.S. Department of Agriculture said after the
market closed on Monday.
* U.S. corn harvest stood at 41%, up from 30% a week ago and lower than the average pace of
61%, the agency said.
* The U.S. Crop Watch growers report decent progression of the corn and soybean harvests last
week, and the overall sentiment toward the crop is unchanged on the week, Karen Braun, a market
analyst for Reuters, wrote in a column.
* “However, parts of North Dakota continue to struggle in the wet conditions, which are
preventing harvest equipment from entering the fields.”
* There are expectations of rapid progress in harvest of both crops in the days ahead with
forecasts of generally dry weather across parts of the U.S. grain belt.
* The market is watching progress in U.S.-China trade talks.
* U.S. and Chinese officials are “close to finalizing” some parts of a trade agreement after
high-level telephone discussions on Friday, the U.S. Trade Representative’s office and China’s
Commerce Ministry said, with talks to continue.
* The U.S. Trade Representative is studying whether to extend tariff suspensions on $34 billion
of Chinese goods set to expire on Dec. 28 this year, the agency said on Monday.
* Analysts also noted uncertainty surrounding any potential change to Argentina’s grain and
soybean export tax policy after the election of Alberto Fernandez as the country’s next president.
U.S. President Donald Trump’s demand that Beijing commit to big purchases of American farm products has become a major sticking point in talks to end the Sino-U.S. trade war, according to several people briefed on the negotiations.
Trump has said publicly that China could buy as much as $50 billion of U.S. farm products, more than double the annual amount it did the year before the trade war started.
U.S. officials continue to push for that in talks, while Beijing is balking at committing to a large figure and a specific time frame. Chinese buyers would like the discretion to buy based on market conditions.
“China does not want to buy a lot of products that people here don’t need or to buy something at a time when it is not in demand,” an official from a Chinese state-owned company explained.
If U.S. agricultural products “enter China in a concentrated way, it might be hard for the domestic market to digest,” the Chinese official added.
Oversupply of agricultural products in China would hit local prices really hard, he said, “and break the supply-demand balance.”
Moreover, a massive outbreak of African swine fever has decimated the pig herd in China, battering demand for soybeans, a key feed ingredient and the biggest agricultural import from the United States.
Chinese agricultural buyers, representing a mix of state and private enterprise, typically import from the cheapest source. The U.S. demand that China commit to buying a huge volume of products, regardless of whether they were economical or in demand, would require state intervention to be implemented.
That contradicts a core demand the United States is making of China in the current trade war, and a U.S. policy goal for decades: that China become a more market-based economy and stop subsidizing state companies and favoring local firms at the expense of foreign competitors.
The upside-down nature of the situation is striking, some trade experts say.
“The U.S. government doesn’t normally regulate the pricing or timing of ag exports — a private sector role — but in this case the president has already taken this step,” said Miriam Sapiro, former acting U.S. Trade Representative under Barack Obama and advisor to president Bill Clinton, now a senior vice president at Sard Verbinnen.
“It is ironic that China is pushing back, saying ‘We want the market to address this,’” said Nicole Lamb-Hale, a former assistant secretary of Commerce and a managing director at Kroll, a risk management firm.
The hefty agricultural purchases Trump is asking for are market distortive, Lamb-Hale said. China is telling Trump they are “just not feasible.”
Asked specifically about concerns that the administration’s push for big agricultural buys contradict the longer-standing U.S. free trade message, a White House spokesman said: “The president has been clear that he wants real structural changes that yield actual, verifiable, and enforceable results, leading to fairer trade, more efficient markets, and increased prosperity for both countries.”
Commerce ministry spokesman Gao Feng told reporters on Oct. 17 that China would “increase U.S. farm purchases based on domestic demand and market principles, while the U.S. would provide favorable conditions.”
U.S. farmers watched their exports plummet after the trade war started.
A U.S. administration official said Tuesday that the two sides might not agree to a “Phase One” deal by the Asia Pacific Economic Cooperation meeting in Chile in mid-November.
In recent weeks, China has purchased large amounts of soybeans from Brazil, after prices of U.S. soybeans jumped as investors bet on big China buys.
President Donald Trump and White House officials insist that China will be buying $40 billion to 50 billion worth of U.S. agricultural products annually over the next couple of years, if the countries nail down a trade deal in the coming weeks. Now, ag industry leaders are looking at the feasibility for U.S. farmers, processors and exporters to meet that challenge.
No details have been released for the "phase one" deal that’s expected to be signed in mid-November on the sidelines of the Asia-Pacific Economic Cooperation meeting in Chile. But it's possible to significantly increase sales to China if the agreement puts the U.S. on an even footing with competing nations by lowering tariffs and non-tariff barriers, industry officials tell Agri-Pulse.
U.S. Trade Representative Robert Lighthizer
“They’re all obviously watching what happens with China,” U.S. Soybean Export Council CEO Jim Sutter said about farmers across the country. “They want to see if something really gets done. Is this phase one agreement going to get signed and what exactly does it mean? Depending on what exactly the deal is, I think farmers will react by producing more.”
The U.S. ag sector can export billions more worth of pork, beef, dairy, ethanol, sorghum, soybeans and ethanol, producer groups and economists tell Agri-Pulse, but only if U.S. negotiators succeed in getting agreements from the Chinese to drop tariffs and other barriers, including a ban on growth hormones and a restrictive biotechnology approval process.
U.S. ag exports to China, at its height in 2012, sold about $26 billion worth of farm commodities, but that figure included very little ethanol, no beef, sorghum, rice and just a fraction of the wheat that the U.S. is capable of shipping there, according to USDA data.
“I don’t think it would take that much, frankly, to get to that point,” American Farm Bureau Federation economist Veronica Nigh tells Agri-Pulse about the possibility of massively increasing U.S. ag exports to China. “Because so much of our trade with China has been strictly in soybeans … If we’re able to diversify our exports to that market more, I don’t see why we couldn’t hit the $40-$50 billion mark.”
One of the biggest winners could be beef. The U.S. exports only small amounts, but if China were to do away with its tariffs and non-tariff barriers on the meat, U.S. exports could get a big boost in a relatively short period of time. Last year the U.S. sold only about $60 million worth of beef to China, but even that was a record-setting level.
If U.S. beef got the same level of access to China as it does to other foreign markets like Mexico or Japan, U.S. exporters could easily ship as much as 250,000 metric tons – worth roughly $1.9 billion – in 2020, according to an estimate provided to Agri-Pulse by the U.S. Meat Export Federation.
U.S. negotiators would have to win China's agreement to cut the current 47% tariff down to 12% (the base WTO-allowed level) and withdraw the hormone ban, but that is definitely possible, according to Kent Bacus, director of international trade and market access for the National Cattlemen’s Beef Association.
“China has a lot of potential … for U.S. beef, but unless we address those significant barriers, it’s just not going to be as lucrative of an opportunity as we would hope,” said Bacus.
He said U.S. and Chinese negotiators have been going back and forth on those trade barriers for months now. “That is a tremendous market there … We’re hopeful we will see a positive outcome from these negotiations.”
Bacus said he expects the Chinese beef market to be worth more than $4 billion over the next five years.
Another rapidly growing Chinese market is for pork. China, the world’s largest pork-producing and pork-consuming country, is suffering from nationwide outbreaks of African swine fever, killing off swine to try to stop the spread of the virulent disease while at the same time trying to rebuild herds.
The country is so desperate for pork, it is already buying record amounts from the U.S. even with a 72% tariff. The U.S. exported about 174,000 metric tons of pork to China in the first eight months of this year, and that’s more than the total amount of shipments for the entire year in 2017 or 2018.
U.S. pork exports to China in 2020 – especially if China lowers the tariff – will be much higher, says Dermott Hayes, an economist at Iowa State University.
“They’ve just lost half their pork herd and pork is by far the meat of choice over there … so they will be buying a lot of our pork,” said Hayes, who predicted that the U.S. could easily sell China 1 or 2 million metric tons.
That would add up to 5% to 10% of total U.S. production and be worth billions in new sales.
U.S. exports of ethanol, DDGs and sorghum are other examples of potential for growth markets that could add billions of additional dollars in new ag exports to China, says U.S. Grains Council CEO Ryan LeGrand.
Ryan LeGrand
Right now, China has punitive tariffs totaling 70% on U.S. ethanol at a time when the country is looking to consume and import more.
About two years ago China announced it would mandate that 10% of all the gasoline sold in the nation would be ethanol. That’s now looking like it won’t be possible, but the country’s national blend rate has moved up to about 2.5% this year and is expected to reach 3.5% next year. That’s a lot of corn-based fuel for a country that consumes about 40 billion gallons of gasoline per year.
The U.S. is largely being left out because of the tariffs, but the turnaround could be sharp and profitable if tariffs are cut in the phase 1 agreement.
“It could potentially be a huge market,” said LeGrand. “People are starting to talk about 1 billion gallons going to the Chinese market. That potential is there if the tariffs are taken off.”
That would add an extra $1.5 billion in annual ag exports to China.
The tariffs on U.S. DDGs are even steeper due to China’s antidumping and countervailing duties that are as high as 96% on the feed product. If those duties come down, LeGrand said, U.S. exports could bounce back quickly, reaching about 5 million metric tons, or about $1.3 billion, annually.
And another $2 billion-plus in U.S. exports to China could come from sorghum sales. Back in the peak year of 2012 for U.S. ag exports to China, there were no sorghum sales. Exports of the grain skyrocketed over the next three years, eventually reaching $2.1 billion in sales in 2015, but then dropping down steadily for the next few years.
“We could go right back to that,” LeGrand said about the $2.1 billion in sorghum exports to China. “It’s doable. We’ve done it before.”
What’s also doable is increasing U.S. soybean exports to China, but only if farmers are truly convinced that the Chinese market will open back up and stay open without the threat of a return to the tariffs that basically shut down trade in 2018, says USSEC’s Sutter.
“Hopefully once we get the phase one agreement signed, we’ll see a further increase in prices and then we’ll see U.S. soybean farmers reacting by planting more acres,” he said. “I think farmers are more optimistic now than they were a couple months ago. They’ve heard about this phase one deal, but they’ve got to see it before they start increasing acreage significantly.”
But both Sutter and the Farm Bureau’s Nigh don’t expect an immediate, massive jump in production and exports. When Trump announced on Oct. 11 that the phase 1 deal would boost U.S. ag exports to China to $40 billion to 50 billion, annually, U.S. Trade Representative Robert Lighthizer was quick to specify that it would take a couple of years to get there.
“It takes a while to build markets in a sustainable way,” Nigh said. “That’s the thing we’re most interested in and focused on. A $40-billion blip sale is fantastic, but what would be better is if we got … to sustain $40 billion (annually). That would be huge.”
For more news, go to: www.Agri-Pulse.com
Bear Creek Mining Corporation, an exploration stage company, engages in the acquisition, exploration, and development of precious and base metal properties in Peru. The company explores for silver, lead, zinc, gold, and copper deposits. Its flagship property is the Corani silver-lead-zinc project, which consists of 12 mineral concessions covering an area of approximately 5,700 hectares located to the southeast of Cusco, Peru. The company was incorporated in 1999 and is headquartered in Vancouver, Canada.
MarketBeat Community Rating for Bear Creek Mining (CVE BCM)
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Vanguard 500 Index Fund (the Fund) is an open-end investment company, or mutual fund. The Fund offers four classes of shares: Investor Shares, Admiral Shares, Signal Shares, and Exchange Traded Fund (ETF) Shares. The Fund seeks to track the investment performance of the Standard & Poor's 500 Index, an unmanaged benchmark representing the United States large-capitalization stocks. The Fund employs a passive management-or indexing-investment approach designed to track the performance of the Standard & Poor's 500 Index. The Fund attempts to replicate the target index by investing all, or substantially all, of its assets in the stocks that make up the index, holding each stock in approximately the same proportion as its weighting in the index.
Basic Details Issuer Vanguard Fund NameVanguard S&P 500 ETF Tax ClassificationRegulated Investment Company SymbolNYSEARCA:VOO Inception Date9/7/2010 Fund ManagerDonald M. Butler, Michelle Louie http://www.vanguard.com/ Web PhoneN/A Fund Focus Asset ClassEquity BenchmarkS&P 500 Index CategorySize and Style FocusLarge Cap Development LevelDeveloped Markets RegionNorth America Fund Statistics Assets Under Management$120.99 billion Average Daily Volume$2.44 million Discount/Premium-0.04% ETF Expenses Management Fee0.02% Other Expenses0.01% Total Expenses0.03% Fee Waiver0.00% Net Expenses0.03% Administrator, Advisor and Custodian AdministratorThe Vanguard Group, Inc. AdvisorThe Vanguard Group, Inc. CustodianState Street Bank and Trust Company DistributorVanguard Marketing Corporation Transfer AgentThe Vanguard Group, Inc. Trustee Lead Market Maker AMEX:VOO Rates by TradingView Receive VOO News and Ratings via Email Sign-up to receive the latest news and ratings for VOO and its competitors with MarketBeat's FREE daily newsletter.
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Community Ranking: 2.6 out of 5 ( ) Outperform Votes: 83 (Vote Outperform) Underperform Votes: 77 (Vote Underperform) Total Votes: 160
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The Fund seeks to match as closely as possible the price and yield performance of the AMEX Gold Miners Index. The Fund, utilizing a passive or indexing investment approach, attempts to approximate the investment performance of the Index by investing in a portfolio of stocks that generally replicate the Index.
Basic Details Issuer Van Eck Fund NameVanEck Vectors Gold Miners ETF Tax ClassificationRegulated Investment Company SymbolNYSEARCA:GDX Inception Date5/16/2006 Fund ManagerHao-Hung Peter Liao, Guo Hua Jason Jin WebN/A PhoneN/A Fund Focus Asset ClassEquity BenchmarkNYSE Arca Gold Miners Index CategorySector FocusBasic Materials Development LevelBlended Development RegionGlobal Fund Statistics Assets Under Management$11.36 billion Average Daily Volume$62.45 million Discount/Premium0.08% ETF Expenses Management Fee0.50% Other Expenses0.02% Total Expenses0.52% Fee Waiver0.00% Net Expenses0.52% Administrator, Advisor and Custodian AdministratorVan Eck Associates Corporation AdvisorVan Eck Associates Corporation CustodianThe Bank of New York Mellon Corporation DistributorVan Eck Securities Corporation Transfer AgentThe Bank of New York Mellon Corporation Trustee Lead Market Maker AMEX:GDX Rates by TradingView Receive GDX News and Ratings via Email Sign-up to receive the latest news and ratings for GDX and its competitors with MarketBeat's FREE daily newsletter.
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iShares U.S. Oil & Gas Exploration & Production ETF, formerly iShares Dow Jones U.S. Oil & Gas Exploration & Production Index Fund (the Fund), is an exchange traded fund. The Fund seeks investment results that correspond generally to the price and yield performance of the Dow Jones U.S. Select Oil Exploration & Production Index (the Index). The Index measures the performance of the oil exploration and production sub-sector of the United States equity market, and includes companies that are engaged in the exploration for and extraction, production, refining, and supply of oil and gas products. The Fund invests in a representative sample of securities included in the Index that collectively has an investment profile similar to the Index. Due to the use of representative sampling, the Fund may or may not hold all of the securities that are included in the Index. The Fund's investment advisor is BlackRock Fund Advisors.
Basic Details Issuer iShares Fund NameiShares U.S. Oil & Gas Exploration & Production ETF Tax ClassificationRegulated Investment Company SymbolBATS:IEO Inception Date5/1/2006 Fund ManagerDiane Hsiung, Jennifer Hsui, Greg Savage, Alan Mason http://www.iShares.com/ Web Phone+1-800-4742737 Fund Focus Asset ClassEquity BenchmarkDow Jones US Select Oil Equipment & Services Index CategorySector FocusEnergy Development LevelDeveloped Markets RegionNorth America Fund Statistics Assets Under Management$213.77 million Average Daily Volume$103,227.70 Discount/Premium0.01% ETF Expenses Management Fee0.44% Other Expenses0.00% Total Expenses0.44% Fee Waiver0.00% Net Expenses0.44% Administrator, Advisor and Custodian AdministratorState Street Bank and Trust Company AdvisorBlackRock Fund Advisors CustodianState Street Bank and Trust Company DistributorBlackRock Investments, LLC Transfer AgentState Street Bank and Trust Company Trustee Lead Market MakerLatour Trading IEO Rates by TradingView Receive IEO News and Ratings via Email Sign-up to receive the latest news and ratings for IEO and its competitors with MarketBeat's FREE daily newsletter.
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NovaGold Resources Inc. explores for and develops mineral properties in Canada and the United States. The company primarily explores for gold, silver, and copper deposits. It primarily holds a 50% interest in the Donlin Gold property that covers an area of 71,420 acres located in the Kuskokwim region of southwestern Alaska. It also holds a 50% interest in the Galore Creek property, a copper-gold-silver project covering an area of 293,837 acres in northwestern British Columbia. The company was formerly known as NovaCan Mining Resources (1985) Limited and changed its name to NovaGold Resources Inc. in March 1987. NovaGold Resources Inc. was founded in 1984 and is based in Vancouver, Canada.
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Perth-listed European base metals developer, Adriatic Metals, has tapped the market and completed a two-tranche institutional placement for $25m to expedite an aggressive program of exploration and development through to a BFS at its exciting, Vareš, multi-metals project in Bosnia.
The placement was well supported by new and existing investors, including cornerstone shareholder, Sandfire Resources, Adriatic said.
In addition, the company is also seeking a secondary listing of its shares on the Standard Segment of the Main Market of the London Stock Exchange during the current December quarter.
Adriatic Managing Director and co-founder, Paul Cronin said: “The placement leaves us in a very strong financial position and will allow the company to progress work on the Vareš Project up to a construction decision, including the completion of a BFS, without additional funding.”
“In pursuing the LSE listing, we hope to foster the interest we have received to date from investors in the United Kingdom and Europe and facilitate the participation of new investors in what is shaping up to be a world-class project.”
The company recently released a maiden mineral resource for the high-grade Rupice deposit that totalled an impressive 9.4 million tonnes grading 5.1% zinc, 3.3% lead, 1.8 g/t gold, 183 g/t silver, 0.6% copper and 31% barite.
It also updated the nearby Veovača mineral resource, now recording 7.4 million tonnes grading 1.4% zinc, 0.9% lead, 0.1 g/t gold, 41 g/t silver and 13% barite.
The preliminary metallurgical results from the project were also particularly encouraging, throwing up some excellent recoveries and concentrate grades, Adriatic said.
The Veovača prospect is a historical, zinc-lead-barite-silver mine and Rupice is a high-grade zinc polymetallic deposit, within the highly prospective Vareš mining district, effectively ignored over the last 25 years as the country rebuilt after conflicts in the 1990s.
A mothballed processing plant is already located on-site and the recent met work indicates that the plant will be suitable for processing ore streams from both deposits further down the track.
The addition of the precious metals, silver and gold, from the emerging Rupice deposit is a significant bonus for Adriatic, as it aspires to maximise net smelter revenues from a future operation at Vareš.
Based on the initial results of the metallurgical work, it seems feasible that a marketable metal concentrate may well be economically produced from the project.
Adriatic’s strategic objectives for Vareš appear to be running to plan and the broader market will soon get an idea of the potential metrics of this remarkable project in the company’s upcoming scoping study, due in 2020.
All eyes will be on the results of the scoping study when it comes out, with a positive outcome likely to de-risk future mining studies, permitting, off-take agreements and project development financing.
It has been a spectacular ride for Adriatic since it finalised the acquisition of the Vareš project in 2017 and then listed on the back of the asset early last year.
Originally listed at 20c, the company completed a 55c capital raising of $10.8m last November, reaching a 52-week high of $1.23 last July and is now sitting at $1.08 per share this week.
The company has been very active on the ground, with drilling ongoing and attractive ground geophysical survey interpretations across the project, indicating that it still has so much more to offer.
At this point, Adriatic is looking to convert its current exploration concessions into exploitation permits for mine production by mid-2020, pending the completion of several KPIs to the regulatory authorities in Bosnia.
This week’s $25m top up to the coffers has the company well-placed to take the Vareš project quickly towards an advanced development stage, particularly with its existing high-grade resources and undoubted blue-sky exploration potential in the region.
Is your ASX listed company doing something interesting ? Contact : matt.birney@wanews.com.au
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Basic Details Issuer Vanguard Fund NameVanguard S&P 500 ETF Tax ClassificationRegulated Investment Company SymbolNYSEARCA:VOO Inception Date9/7/2010 Fund ManagerDonald M. Butler, Michelle Louie http://www.vanguard.com/ Web PhoneN/A Fund Focus Asset ClassEquity BenchmarkS&P 500 Index CategorySize and Style FocusLarge Cap Development LevelDeveloped Markets RegionNorth America Fund Statistics Assets Under Management$121.00 billion Average Daily Volume$2.32 million Discount/Premium0.13% ETF Expenses Management Fee0.02% Other Expenses0.01% Total Expenses0.03% Fee Waiver0.00% Net Expenses0.03% Administrator, Advisor and Custodian AdministratorThe Vanguard Group, Inc. AdvisorThe Vanguard Group, Inc. CustodianState Street Bank and Trust Company DistributorVanguard Marketing Corporation Transfer AgentThe Vanguard Group, Inc. Trustee Lead Market Maker AMEX:VOO Rates by TradingView Receive VOO News and Ratings via Email Sign-up to receive the latest news and ratings for VOO and its competitors with MarketBeat's FREE daily newsletter.
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The Fund seeks to match as closely as possible the price and yield performance of the AMEX Gold Miners Index. The Fund, utilizing a passive or indexing investment approach, attempts to approximate the investment performance of the Index by investing in a portfolio of stocks that generally replicate the Index.
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Eurasian Resources Group, which has operations in Kazakhstan, Africa and Brazil, has had a long-term strategic partnership with the People’s Republic of China.
The Fourth Industrial Revolution, or Industry 4.0, refers to the recent revolutionisation of the industrial world through the application of new technologies – including the introduction of smart systems, the internet of things, cyber-physical systems, cognitive computing, cloud computing, the industrial internet of things and artificial intelligence – to manufacturing processes.
The ongoing collaboration between ERG and China has already taken many forms, including engineering, procurement and construction, equity partnerships, off take and sales agreements and financing. China currently accounts for between 20% and 25% of ERG’s total sales volumes and the partnership is now seeking to build on that momentum.
The Chinese government is leading the way in the global push to switch to electric vehicles, looking to dominate this market. By 2020, the Chinese government desires around 12% of overall vehicle sales to be comprised of EVs. This drive to transition to a greener, more sustainable economy will lead to a demand for more key battery components and raw materials, which include copper and cobalt. ERG mines copper and cobalt ore and produces copper and cobalt in the Democratic Republic of the Congo, and China also has strong demand for other metals including alumina, iron ore and ferrochrome, which form a key part of ERG mining operations worldwide.
ERG, and the businesses it operates now, have co-operated with strategic partners in China for many years. In the mid to late 2000s, these collaborations began to escalate. The Kazakhstan Aluminium Smelter, which is the first production facility for aluminium in the country, was launched in 2007. It is now owned by ERG and was developed in record time in conjunction with China Non-Ferrous Metal Industry’s Foreign Engineering and Construction Co., Ltd. The smelter was completed in just 27 months.
In the DRC, collaboration between China and ERG resulted in the delivery of another project, the Metalkol RTR facility. This operation has a target capacity of 120kt of copper and 24kt of cobalt per annum. When working to full target capacity, this project has the potential to make ERG one of the largest cobalt suppliers to China and to the rest of the world. Metalkol RTR applies the Clean Cobalt Framework initiative of ERG, which aims to enhance responsible cobalt production through transparency in the supply chain. ERG is piloting a blockchain technology system in support of this initiative.
The Chinese government provides financial and infrastructural support to many key international initiatives and projects in Kazakhstan in collaboration with ERG, as well as generating significant benefits for the country in investment and trade. This includes the establishment of a series of dedicated networking platforms to facilitate and increase co-operation.
Forward-looking reforms in China, combined with a rapidly developing economy, will deliver multiple opportunities for the country, for ERG, and other international partners.
Prices of copper and other industrial metals are expected to be capped next year as weak economic growth weighs on the market, a Reuters poll showed.
The London Metal Exchange index of six base metals has inched up only 1% so far this year, held back by worries about a possible global recession and a trade war between the United States and top metals consumer China.
But the average is deceptive, because sharp gains for nickel of over 50% cover the fact that half of the metals are in the red, with losses of up to 15%.
“Unfortunately, we expect that the macroeconomic environment will deteriorate further. We expect flat copper prices in 2020, but significant downside risks persist,” said analyst Daniela Corsini at Intesa Sanpaolo Bank in Milan.
The LME cash copper price is expected to average $6,050 a tonne in 2020, a median forecast of 29 analysts shows, a 3% increase from the price on the afternoon of Oct. 25.
Analysts have become more bearish since a similar poll in July, downgrading their consensus by 6%.
Forecasts of a market deficit in 2020 have been upgraded by 12% to 191,000 tonnes, but since investors regard copper as a signpost of the global economy, only severe shortages would lift the price amid a weak economic outlook, analysts say.
NICKEL TO DRIFT
The nickel price has been the best performer so far this year with 59% gains, spiking after top producer Indonesia brought forward a ban on ore exports by two years to Jan. 1.
But prices have largely absorbed the bullish news and aside from possible short-term spikes due to speculative moves are unlikely to settle higher next year, analysts said.
“The impact of the ore ban won’t really be felt until the second half of next year, and the reason for that is the Indonesian government has given ore exporters four months’ notice of the ban,” said analyst Jim Lennon at Macquarie.
Indonesian exporters are due to ship out an additional 80,000-100,000 tonnes of contained nickel before the end of the year, keeping Chinese producers well supplied during the first half of 2020, Lennon added.
The LME cash price of nickel, mainly used to make stainless steel, is expected to average $16,500 a tonne next year, down 2% from the current price.
The market deficit is expected at 30,000 tonnes next year, a rise from 26,000 tonnes forecast for 2019, according the poll, but still minimal when compared to 144,000 tonnes in 2018, according to the International Nickel Study Group.
ALUMINIUM SURPLUS
Aluminium prices will see only modest growth next year as the market moves into a surplus, hit by a combination of a pullback in demand growth and continued gains in supply.
“The current demand downturn has the misfortune of being timed with the start of the strongest period for ex-China supply growth since the late 1990s,” said analyst Nicholas Snowdon at Deutsche Bank in London.
“The story for 2020 is likely to be about the pace at which smelter cuts emerge to balance demand trends.”
The global market is due to flip into a surplus of 304,000 tonnes next year from a deficit of 658,500 tonnes in 2019, according to the consensus numbers.
In the last poll in July, analysts had expected a deficit of 88,000 tonnes next year.
Analysts expect cash LME aluminium to average $1,814 a tonne in 2020, up 6% from the current price.
RISING ZINC OUTPUT
Zinc is also expected to move into surplus next year as rising mine production is smelted into metal after bottlenecks had blocked ore processing over the past few years.
“We expect the 2020 zinc market be in a material surplus on the back of still moderate demand growth and strong growth in Chinese refined production,” said Mikhail Sprogis at Goldman Sachs.
Zinc, mainly used for galvanizing in the steel industry, is expected to see a surplus of 158,000 tonnes in 2020 after a deficit of 50,500 tonnes this year, the poll consensus showed.
Analysts have shaved their 2020 forecast for cash LME zinc by 4% since the last poll to $2,315 a tonne, down 9% from the latest price.
Ecuador is moving forward with plans to move from an explorers hotspot to mining exporter as the country’s only large-scale copper mine readies to ship its first large cargo in November.
The $1.4 billion Mirador open-pit mine, owned by a joint venture of Tongling Nonferrous Metals Group and China Railway Construction (EcuaCorriente), opened in July. Operations, however, slowed down earlier this month as a precautionary measure to protect workers following massive protests against an end to fuel subsidies, since then scrapped.
The Chinese consortium gained access to Mirador through the acquisition of EcuaCorriente during the government of former President Rafael Correa.
The asset, in the southeastern Zamora-Chinchipe province, has an estimated 3.2 million tonnes of copper reserves, along with 3.4 million ounces of gold and 27.1 million ounces of silver.
According to government’s figures Mirador has already stockpiled 30,000 tonnes of copper, which it plans to export on Nov. 14.
“Initially we planned to have it done by the end of this month,” Ecuador’s vice minister of mines, Fernando Benalcazar, told Reuters on the sidelines of a mining conference in Australia. “It will be the first time we have a larger scale exportation going out,” he noted.
Canada’s Lundin Gold (TSX:LUG), which has been developing its Fruta del Norte gold project for almost two years, is set to follow suit.
The Vancouver-based miner, acquired the project in 2015 for $240 million from fellow Canadian miner Kinross Gold (TSX:K) (NYSE:KGC), is expected to declare commercial production in two weeks’ time.
Other major mining projects in Ecuador include the Cascabel copper-gold project, operated by Australia’s SolGold (LON, TSX:SOLG); and the Llurimagua copper mine, to be run by Ecuador’s Enami and Chile’s Codelco, the world’s No. 1 copper producer.
Ecuador has gained ground as a mining investment destination in the past two years thanks to a revised regulatory framework and a major investor engagement campaign. Existing and future projects, however, risk delays and potential halts due to growing local opposition to the extraction of the country’s resources, a report by Fitch Solutions Macro Research shows.
As mining projects face headwinds from rising tensions, investors’ courage will be tested, the study concluded, which could thwart Ecuador’s plan to attract $3.7 billion in mining investments over the next two years, significantly up from the $270 million it received in 2018.
https://www.mining.com/ecuador-moving-from-explorers-hotspot-to-copper-exporter-with-first-cargo/
The metals world is descending on London for the biggest annual bash in the industry’s calendar, but there’s not much to celebrate.
At last year’s LME Week, the industry was mostly optimistic. This time, things are looking bleak.
The outlook for some key metals is at the weakest since the financial crisis as the U.S.-China trade war and a synchronized global slowdown pummel consumption and investor sentiment. Economic bellwether copper is flashing warning signals, with demand growth stalling this year as manufacturing contracts.
The only standout in the group is nickel, which has surged amid concerns about tight supply.
Overall, though, there’s “a no-growth picture for the commodity markets for the foreseeable future,” said Mark Hansen, chief executive officer of metals trader Concord Resources Ltd. The trade war “has dragged on now so long that it is impacting people’s willingness to make investments and have confidence in the foreseeable future.”
Here are five charts that show how things have turned bleak for most metals, with nickel as the clear exception:
1. PMI Pain
Copper is especially vulnerable to a global manufacturing slowdown because it’s used in such a wide range of products and industries, from plumbing to power cables and car radiators to high-tech electronics.
The International Copper Study Group expects the market will swing into a surplus next year as new capacity is added in China and some smelters and refineries ramp up after operational setbacks.
2. Demand Stalls
Global copper demand — total consumption of refined metal and direct use of scrap — will probably decline 0.2% this year, due to a contraction in Europe and a slowdown in the U.S., according to Wood Mackenzie.
“Given the size of the market, it’s essentially flat year-on-year,” said Wood Mackenzie analyst Eleni Joannides. “But that means that the growth is at its weakest since the global financial crisis.”
To be sure, the supply outlook has tightened this month as civil unrest in top supplier Chile disrupted some mines and halted others. More widely, limited new mine supply is among the factors helping support copper prices despite the gloomy demand outlook — futures on the London Metal Exchange have fallen less than 1% this year.
3. Chinese Capacity
Chinese production has been ramping up, with refined copper rising to a record in September, and the country’s zinc smelters are also accelerating production.
While disruptions elsewhere are preventing a surplus and supporting prices for now, increased Chinese domestic output means that an excess of zinc metal still looms, according to Morgan Stanley analysts including Susan Bates.
4. Glut Ahead
In the aluminum market, stockpiles are close to a decade low and a global deficit is forecast in 2019. However, analysts including at HSBC Holdings Plc, expect a slight surplus next year, which may widen into 2021.
Prices for the metal used in cars, airplanes and drinks cans have fallen about 6% this year, headed for a second annual drop. Large producers are also sounding a warning, with Alcoa Corp. and Norsk Hydro ASA forecasting demand may decline this year for the first time since 2009.
“It’s a pretty rough situation, and the question is when the industry is going to reach its worst point, when all the bad news is priced in,” said Ingrid Sternby, a commodities strategist at Valent Asset Management.
5. The Superstar
While other major metals flounder, nickel has surged after a surprise decision by Indonesia to accelerate a ban on unrefined exports spurred a buying spree on the LME.
Nickel demand will rise 5% this year, according to the International Nickel Study Group.
While production of stainless steel — one of the main uses of the metal — has fallen in Europe and the Americas, the decline is being offset by a surge in Chinese output, according to Anton Berlin, head of analysis and market development at Russia’s MMC Norilsk Nickel PJSC.
https://www.hellenicshippingnews.com/what-a-difference-a-year-makes-gloom-and-doom-at-metals-week/
Unionized workers at BHP’s Escondida copper mine, the world’s largest, said late on Monday they would walk off the job for part of the work day on Tuesday in a show of solidarity with protests in Chile.
Escondida’s Union No.1, the mine’s largest, said in a statement workers on each of the day and night shifts on Tuesday would walk off the job for half of their working hours.
“Our workers ... have agreed in near unanimity to protest against a series of abuses and violations by the company, and to show solidarity for the demonstrations against economic and social policies that affect us as workers,” the union said in the statement.
BHP did not immediately respond to a request for comment.
Chile, the world’s top copper producer, has long been one of the region’s most prosperous and stable free-market economies. But entrenched inequality and spiraling costs of living ignited massive, and sometimes violent, protests last week.
Riots, arson and looting have led to at least 17 deaths, resulted in more than 7,000 arrests and caused upwards of $1.4 billion in losses to Chilean businesses.
Copper mining companies in Chile last week said nationwide riots had mostly spared production but continuing protests had hobbled port facilities, public transportation and supply chains, impacting operations.
Indonesia could resume nickel ore exports in one to two weeks once an investigation into “massive violations” of export rules has been completed, Luhut Pandjaitan, coordinating minister overseeing maritime and mining, told reporters on Tuesday.
Pandjaitan said exports of nickel ore had surged since September when the government announced it was moving forward a ban on ore exports to January 2020 from 2022.
“We are evaluating this. For the time being we are stopping exports while integrated inspections are carried out,” he told reporters.
Authorities are investigating reports of manipulation that is resulting in large scale exports of high-grade nickel ore, as well as other irregularities, Pandjaitan said.
Indonesia only allows exports of ore with less than 1.7% nickel content and only issues export quotas to companies that are building smelters onshore as it aims to develop the country’s downstream nickel industries.
Exports of nickel ore have jumped to nearly three times the normal monthly shipment level since Indonesia announced its export ban was being expedited, he said.
The government has asked Indonesia’s anti-corruption agency to be involved in the review.
Exports may resume after one to two weeks of evaluation, Pandjaitan said.
Energy and Mineral Resources Minister Arifin Tasrif said the official ban on ore exports was still set for January 2020 but the ministry will stop issuing export quota recommendations while the investigation is carried out.
Nickel miners, after meeting with the head of Indonesia’s Investment Coordinating Board (BKPM) on Monday, agreed to stop exporting nickel ore immediately, BKPM chief Bahlil Lahadalia said.
Domestic nickel smelters have agreed to buy ore from miners at “international prices” during the pause in exports, Pandjaitan said.
Alexander Barus, executive director at PT Indonesia Morowali Industrial Park, Indonesia’s largest nickel industrial park where Chinese giant Tshingshan operates, said the two biggest smelting groups in Indonesia currently have a combined annual input capacity of around 40 million tonnes of ore.
He added that smelters in Morowali are ready to buy nickel ores, subject to storage capacity, specification and pricing.
Aluminum Corp of China Ltd posted a sharp fall in both aluminium output and sales in the third quarter, data released on Wednesday showed, after the company earlier reported a slump in quarterly profit.
Chalco, the listed arm of state-owned aluminium firm Chinalco, reported a 10.4% year-on-year fall in aluminium production in July-September to 950,000 tonnes, in a data sheet for analysts reviewed by Reuters.
Aluminium sales fell by a steeper 13.8% to 940,000 tonnes, indicating lacklustre demand in China, the world’s top consumer of the metal.
The declines comes after Chalco closed a 200,000 tonnes per year plant in eastern China’s Shandong province in January due to high electricity costs, and said later it would transfer 190,000 tonnes of capacity from northern China to an affiliate in Yunnan.
Its output still topped Russian rival United Company Rusal, which produced 942,000 tonnes in the third quarter, retaining Chalco’s spot as the world’s second-biggest listed aluminium producer after China Hongqiao Group.
Production of alumina, which is used to make aluminium, rose by 3.6% year-on-year to 3.41 million tonnes in the third quarter, the data showed. The company did not immediately confirm the numbers.
Chalco late on Tuesday reported an 83.9% fall in third-quarter net profit from a year earlier to 102.61 million yuan ($14.53 million), as higher costs canceled out an increase in revenues.
Third-quarter operating revenues - which also include alumina chemicals, coal and electricity sales - rose 17.2% year-on-year to 50.77 billion yuan. But this was nearly matched by the total cost of operations, which surged 20.5% to 50.35 billion yuan, the company said in a filing to the Hong Kong stock exchange.
The wafer-thin profit underscores the cost pressures faced by aluminium smelters in China, the world’s biggest producer of the metal. Shanghai aluminium prices have been struggling to hold above 14,000 yuan a tonne, often considered a break-even level. Prices are currently around 13,800 yuan a tonne.
In Wednesday’s data sheet, Chalco said its average aluminium sales price in the third quarter was 13,924 yuan a tonne, down 4.2% year-on-year.
The third-quarter result marked Chalco’s lowest profit since the fourth quarter of 2017, excluding a net loss in October-December last year.
Profits in the first nine months of 2019 fell 47.7% year-on-year to 808.37 million yuan.
The company produced 192,510 tonnes of copper and 70,120 ounces of gold in the September quarter, up 27% and 56% respectively from a year earlier.
The new Cobre Panama mine had contributed 56,221t of copper and 21,484oz of gold to the result, of which 19,438t and 7,914oz were deemed commercial.
The company had declared commercial production at the giant Panama mine on September 1 and Newall told an earnings conference call the operation was "very quickly establishing itself as a cornerstone asset".
"It's fair to say that it's a special moment in the evolution of First Quantum as our largest and likely our most complex project to date has entered commercial production," he said.
Elsewhere, Newall said the company was seeking clarification on Zambia's tax changes, with a proposed sales tax scrapped in the latest budget and adjustments flagged for the VAT system.
He reiterated the company was holding discussions regarding a potential sale of a minority stake in its Zambian copper assets but said there was no guarantee a transaction would result.
In Spain, he said the Las Cruces copper mine had "begun its recovery" from a January land slippage earlier this year.
In Western Australia, First Quantum was aiming to restart its Ravensthorpe nickel operation in the first quarter of 2020 and produce about 25,000t per year.
He said capex figures on the Ravensthorpe restart were still soft at this point.
"We can start-up in the existing pit, but there's only a couple of years left of resources in that pit," he said on the call.
"It's the move to the next pit that is where there is capital expenditure.
"And the largest component of that is an overland conveyor, including a bridge across a highway to the next ore body."
First Quantum reported a loss of US11c per share, down from earnings of 9c a year ago, and comparative earnings per share of 5c, compared with 19c in the previous corresponding period.
Sales revenue was $9 million higher at $987 million.
The company ended the quarter with $406 million of net unrestricted cash and cash equivalents.
Its share price gained 3.7% yesterday to close at C$11.64, capitalising First Quantum at $8 billion (US$6.1 billion).
It had peaked at $16.63 in April but fell as low as $7.835 in August.
Peru has given an important green light for Southern Copper Corp’s much-delayed Tia Maria copper mine, but the government cautioned it would not move ahead with the project without the right social and environmental conditions being met.
Prime Minister Vicente Zeballos said on Wednesday the government would not “impose” the $1.4 billion project on the country, after it had earlier received the go-ahead with a construction license from Peru’s mining council.
In August the government had suspended a permit for the project amid violent protests in order to allow officials to evaluate objections from local authorities in the Arequipa region where the plant would be built.
Zeballos, speaking at the presidential palace, said the government recognized the importance of private investment.
“But we also reaffirm that our government will not impose the Tía Maria mining project if there are not the environmental and social conditions for its development,” he said.
Zeballos added that, beginning Thursday, an environmental inspection commission would evaluate the project’s viability.
Southern Copper, controlled by the Mexico Group, said in a statement it planned to develop the project “within the framework of a more favorable social climate” and to work with the local population.
Southern Copper has sought to build Tia Maria for nearly a decade, but opposition from local farmers and residents who fear pollution and loss of water supply has thwarted the effort.
Protests in 2011 and 2015 against the copper project left six dead and dozens injured after clashes with the police that sought to unlock a road to the site.
“It is an abuse of authority to try to impose a project that has not been accepted by the population of the Tambo Valley of Islay province,” said Elmer Pinto, a local adviser.
“It leaves a lot to think about how economic interests trump the decision of the people.”
Tia Maria is expected to produce about 120,000 tons of copper per year and help revitalize the country’s economy. Peru is the second largest producer of copper in the world and the mining sector accounts for 60% of its exports.
It is seen as key to boosting investments in the sector.
“It is an important signal that will boost mining investment and the national economy,” Manuel Fumagalli, president of the National Society of Mining, Petroleum and Energy, said in a statement.
AGL Energy, Australia’s largest power producer, said on Wednesday it is working hard to ensure its two biggest single customers, the Portland and Tomago aluminium smelters, remain open.
“We will work as a good citizen to do everything we can to keep those smelters going,” AGL Chief Executive Brett Redman told analysts at an investor briefing.
Portland smelter operator Alcoa Inc and Tomago co-owner Rio Tinto have both flagged that their smelting operations are struggling with low aluminium prices and high alumina input costs.
Soaring power prices have hit Tomago as well, while Portland has survived with the help of subsidies from the state of Victoria and the Australian government through June 2021.
Vessels carrying nickel ore left Pomalaa mining area in Indonesia this morning, SMM learned.
Indonesia, the world’s biggest nickel ore producer, temporarily stopped nickel ore exports after authorities launched an investigation into “massive violations” of export rules late last week. This jittered the market and propped up nickel prices.
SMM learned that mines who have export quotas have recovered the loading of nickel ore with a Ni grade lower than 1.7%, and that leaving vessels are still subject to an inspection into ore grade.
This round of investigations is expected to end tomorrow November 1.
TORONTO--(BUSINESS WIRE)--Sierra Metals Inc. (TSX:SMT, BVL:SMT) (“Sierra Metals” or the “Company”) announces the filing of Sociedad Minera Corona S.A.’s (“Corona”) unaudited Financial Statements and the Management Discussion and Analysis (“MD&A”) for the third quarter of 2019 (“Q3 2019”).
The Company holds an 81.8% interest in Corona. All amounts are presented in US dollars unless otherwise stated, and have not been adjusted for the 18.2% non-controlling interest.
Corona’s Highlights for the Three Months Ended September 30, 2019
Revenues of US$44.4 million vs. US$38.1 million in Q3 2018
Adjusted EBITDA of US$20.5 million vs. US$17.6 million in Q3 2018
Total tonnes processed of 307,239 vs. 283,446 in Q3 2018; a new record
Net production revenue per tonne of ore milled increased by 10% to US$145.64
Cash cost per zinc equivalent payable pound decreased by 21% to US$0.38
All in sustaining cost (“AISC”) per zinc equivalent payable pound consistent at US$0.66
Zinc equivalent production of 57.2 million pounds vs. 42.9 million pounds in Q3 2018
$29.0 million of cash and cash equivalents as at September 30, 2019
$56.8 million of working capital as at September 30, 2019
The Company achieved record quarterly equivalent metal production and ore throughput from the Yauricocha Mine during Q3 2019, which has helped to continue to make-up for the lost production realized during the illegal strike during March and April 2019. Revenues increased by 17%, and Adjusted EBITDA increased by 16% during Q3 2019 compared to Q3 2018, and the cash flows generated during Q3 2019 allowed the Company to fund its capital expenditure programs despite a challenging base metal price environment, and significant increases in zinc treatment and refining costs. Cash costs decreased by 21% quarter over quarter due to a 40% increase in zinc equivalent payable pounds, as a result of the 8% increase in throughput, and higher head grades and recoveries for all metals, except zinc. However, the increase in zinc payable pounds was offset by the increase in treatment and refining charges related to the zinc concentrate produced, as well as higher general and administrative costs incurred from higher labour costs, which resulted in the All-in sustaining cost per zinc equivalent payable pound remaining consistent, quarter over quarter. In addition to the record quarterly production realized during Q3 2019, the Company has also been able to build-up a stockpile of approximately 30,000 tonnes of polymetallic ore which is expected to be processed during Q4 2019.
Igor Gonzales, President and CEO of Sierra Metals commented, “I am very pleased with the Yauricocha Mine’s excellent quarterly financial results as highlighted with notable improvements to revenue and adjusted EBITDA, while seeing lower realized cash costs. These strong improvements were made possible by the excellent production results that were realized this quarter. Our efforts to recover as much lost tonnage as possible from the illegal strike earlier in this year have been successful and we remain committed to falling within the published guidance for Yauricocha. In addition, we continue to reap the benefit of improvements being made at the Mine and Plant and expect these improvements to continue to benefit the Company through the remainder of the year.”
He continued, “Looking ahead, the fourth quarter is an important time for projects, improvements, and exploration at Yauricocha. We are working to complete the Yauricocha NI 43-101 Reserve and Resource Update which is expected in December this year. We are continuing surface drilling at Don Leona and Kilkaska which are high value, exploration targets and will hopefully have newsflow with the results before year end. Additionally, work continues on the completion of the next level of the tailings deposition facility, needed for the expansion of Yauricocha to the 3,600 tonnes per day level. Furthermore, we continue to sink the Yauricocha shaft towards the 1270 level to provide the Company access to further reserves and resources in the Mine. Finally, work has commenced on the ramp connecting the 820 level with the 720 level of the Yauricocha Mine providing for an additional 10,000 tonnes per month of increased capacity to move ore and waste from the Mine.”
He concluded, “Yauricocha continues its strong operational and financial performance for the Company and Corona continues to have a solid balance sheet and strong liquidity. Management remains positive that continued operational efficiencies and future operational and resource growth are possible at Yauricocha.”
The following table displays selected unaudited financial information for the three months and nine months (“9M 2019”) ended September 30, 2019:
energy saving
Energy Efficiency Leads Energy Sector Job Growth
Energy efficiency is the fastest-growing segment of US energy-sector employment, now employing more than 2.3 million Americans, according to recent analysis from E4TheFuture and the national, nonpartisan business group E2 (Environmental Entrepreneurs). Energy efficiency workers now account for 28 percent of all US energy jobs.
The report, Energy Efficiency Jobs in America, finds energy efficiency jobs grew 3.4 percent in 2018 –more than double the rate of growth for overall jobs nationwide — with 7.8 percent growth projected for2019. Among the states, California leads energy-efficiency employment with 318,500 jobs, followed byTexas (162,800), New York (123,300), Florida (118,400), and Illinois (89,400). Thirteen states sawefficiency jobs increase by more than five percent in 2018, led by New Mexico (11.6 percent), Nevada (8.1 percent),Oklahoma (7.2 percent), Colorado (7.2 percent), and New Jersey (7.1 percent). Not a single state saw declines in energyefficiency employment in 2018.
The report highlights energy efficiency’s continued economic importance.
“While politicians argue over the direction of our energy transition, the economic benefits of improving energy efficiency continue to unite America’s business and environmental interests,” said Pat Stanton, Director of Policy at E4TheFuture. “Not only is expanding America’s energy efficiency key to solving multiple climate policy goals, it is now integral to businesses’ expansion plans – saving money and creating local jobs that cannot be outsourced.”
Efficiency businesses added 76,000 net new jobs in 2018, accounting for half of all net jobs added by America’s energy sector (151,700). The sector also employed twice the number of workers in 2018 as all fossil fuel industries combined (1.18 million). There are now more than 360,000 energy efficiency businesses operating across the US.
Energy efficiency jobs include positions in manufacturing, such as building ENERGY STAR® appliances, efficient windows and doors and LED lighting systems. They include jobs in construction – retrofitting buildings, offices and schools to make them more efficient. Efficiency careers are found in high-tech design and software and professional services, as well as at the heating, ventilation and air conditioning (HVAC) companies that upgrade outdated inefficient HVAC systems, boilers, ductwork and other equipment.
Energy efficiency jobs aren’t limited by geography, geology or political persuasion. There are workers in energy efficiency in every state and in virtually every US. county, the report shows. More than 317,000 energy efficiency jobs are located in rural areas, while 928,000 jobs are found in the nation’s top 25 metro areas. In 41 states and the District of Columbia, more Americans now work in energy efficiency than fossil fuels.
Other key findings:
• 10 percent of energy efficiency jobs are held by veterans — nearly double the national average of 6 percent
• Construction and manufacturing make up more than 70 percent of U.S. energy efficiency jobs
• More than one out of every six U.S. construction workers spend 50 percent or more of their time on energy efficiency (1.3 million workers)
• 321,000 energy efficiency jobs are in manufacturing
• More than 1.1 million energy efficiency jobs are in heating, ventilation, and cooling technologies
• Efficient lighting technologies employ 370,000 workers
• ENERGY STAR appliances employ 167,000 workers
• Energy efficiency employers are projecting 7.8 percent job growth in 2019
• Small businesses are driving America’s energy efficiency job boom, with 79 percent of energy efficiency businesses employing fewer than 20 workers
• 17 states employ more than 50,000 workers, and 40 states are home to at least 10,000 energy efficiency workers
SMM statistics showed that iron ore stocks across 35 Chinese ports rose 1.28 million mt from a week ago to 118.79 million mt as of October 25, but were 14.2 million mt lower than a year ago.
Stocks in Tangshan surged some 3 million mt compared to levels before the National Day holiday, driven by higher arrivals and environmental restrictions.
Daily average deliveries from the 35 ports declined 163,000 mt on a weekly basis and 147,000 mt on a yearly basis to 2.62 million mt last week. Some steel mills in Shandong and Shanxi were required to restrict production for about five days to fight air pollution, which lowered demand for iron ore.
Deliveries from ports are likely to pick up slightly this week with the removal of environmental restrictions in Tangshan and other regions.
https://news.metal.com/newscontent/100985985/mmi-daily-iron-ore-report-oct-25/
Samarco Mineração, a joint venture between Vale and BHP received on Friday its Corrective Operation License (LOC) for its operating activities in the Germano Complex, located in the state of Minas Gerais, Brazil.
The license was approved by the Mining Activities Chamber (CMI) of the State Council for Environmental Policy (COPAM). Samarco has now obtained all environmental licenses required to restart its operations.
The news comes four years after a tailings dam burst at Germano in November 2015, killing 19. A torrent of mud and debris was unleashed, polluting local rivers and reaching the Atlantic ocean. The incident has been called the worst environmental disaster in Brazil’s history.
Vale has previously said that it expected production at the joint venture, which is trying to restructure $3.8 billion in debt it defaulted on about a year after the accident, to resume in the second half of 2020.
The mine, which once produced nearly 25 million tonnes of iron ore a year, will restart at an annual rate of less than a third of that, Vale said, with a potential increase to 14 to 16 million within another six years.
https://www.mining.com/bhp-and-vales-samarco-licensed-to-restart-operations/
Baoshan Iron and Steel Co., Ltd (Baosteel), a listed subsidiary of China Baowu Group, reported a sharp slump of 43.65% in earnings for the first three quarters this year
Operating revenue came in at 216.9 yuan down 3.75% for the same period
In the third quarter Baosteels earnings were down 53.17% with operating revenue down 1.02%, operating costs were down 4.8 billion yuan for the three quarters.
India’s biggest steelmakers may be suffering from buyer’s remorse as assets they bought from bankrupt rivals stretch their bottom lines while market conditions have worsened.
Less than 18 months after scooping up these distressed assets in the hopes of extracting value and boosting market share, the steelmakers are struggling to meet sales and production targets because of a slowdown in the key construction and auto sectors.
Tata Steel Ltd, JSW Steel Ltd and others are also wrestling with falling revenues amid high debt loads.
“The operating environment has changed from when they bid for these plants,” said Amit Dixit, senior steel analyst with brokerage firm Edelweiss Financial Services. “So their payback period obviously gets elongated now.”
Steel prices were high and demand was booming then. Now, confronted with falling prices and slower consumption, steelmakers are facing the risk of credit downgrades, job losses and cuts in capital expenditure.
Arnab Kumar Hazra, assistant secretary general at the Indian Steel Association, an industry group that also represents major steel producers, noted companies would take a longer time to turn their assets around in the current environment.
A deepening credit crunch in India’s shadow banking industry following the collapse of a major infrastructure lender in 2018 has sharply dented spending on cars and real estate in India.
Domestic steel consumption in September was at its lowest since the start of the fiscal year 2019/20, according to official data.
A synchronised global economic slowdown amid the U.S.-China trade war has compounded the problem, quashing global steel consumption and intensifying competition among exporters.
JSW Steel Ltd, which bought Monnet Ispat & Energy Ltd in September last year, had promised to turn it around within a year but now says it will take another year.
The company will also miss its sales and production target for 2019/20 by 3% and has had to cut its capital expenditure by a third, said Seshagiri Rao, JSW’s joint managing director and group chief financial officer.
“There is a credit squeeze, there is prolonged monsoon, a weaker government expenditure and fall in consumer demand,” Rao said.
Tata Steel, which bought specialty steel firm Usha Martin Ltd in April, told Reuters the turnaround of the company would be delayed.
Tata Steel and JSW are not alone.
The world’s biggest steelmaker ArcelorMittal and partner Nippon Steel and Sumitomo Metal Corp, which committed $6 billion to acquire a 10 million tonne steel plant in India, will face similar issues, analysts have said.
PRESSURE BUILDING
The problems afflicting the steel majors, which together control over half the country’s total steel production, have already surfaced among mid-sized firms.
“Inventory is high, debtor days have extended, and most mid-level steel companies are now contemplating job cuts,” said R.K. Goyal, managing director of Kalyani Steels Ltd which relies heavily on the automotive sector for steel orders.
The credit crunch and slowdown in autos and real estate pushed India’s GDP growth to a six-year low of 5% in the April-June quarter, in a troubling sign for the steel sector whose fortunes are closely tied to the broader economy.
The extent of the slowdown is prompting companies to revise capital expenditure plans and others to question the ability of companies to achieve debt reduction goals.
Despite Tata Steel’s move to partially defer expenditure on expansions, IIFL analyst Anupam Gupta said its plans to cut debt by $1 billion this fiscal year look ambitious, given weakening profitability across India and Europe.
Brokerage firm Edelweiss expects both JSW Steel and Tata Steel to see increases this year in their debt to EBIDTA ratios - a metric that reflects the cash available to companies to pay debts.
And the downward pressure on steelmakers does not look set to reverse soon.
“We are just sitting idle and waiting for the tide to turn,” Kalyani Steels’ Goyal said.
https://www.reuters.com/article/india-steel/indian-steelmakers-face-debt-challenges-after-ill-timed-bets-idUSL3N2681KJ
Japan Iron and Steel Federation Chairman Yoshihisa Kitano said on Tuesday that a year-on-year fall in global crude steel output in September, which was the first drop in 41 months, underlined a slowdown in the world economy.
Global crude steel output in September fell 0.3% from a year earlier to 151.5 million tonnes, the first decline since April 2016.
Kitano, who is also president of JFE Steel, a unit of JFE Holdings, also told a news conference that higher steel exports from India and Russia to ASEAN, reflecting a slower economy in Europe and India, are weighing on Asian steel markets.
Hyundai Steel Co. Tuesday announced its third-quarter operating profit fell sharply due to mounting iron ore costs and low demand in the construction sector.
The steelmaker under South Korea’s Hyundai Motor Group reported a meager operating profit of 34.1 billion won ($29.28 million) over sales of 5.04 trillion won for the July-September period. Operating profit plunged 66.6 percent from a year earlier and whopping 85.3 percent from the previous three months. Sales declined 3.6 percent from a year ago and 9.4 percent from a quarter ago. The bottom line showed a loss of 65.8 billion won in the third quarter.
Hyundai Steel shares on Tuesday closed 1.49 percent down at 32,950 won in Seoul.
The steelmaker blamed the poor performance to a 20 percent spike in prices of iron ores for making steel plates and its failure to reflect the cost increase on key products in a timely manner.
Lackluster sales in shaped steel mainly used in the construction industry also contributed to a slump in the profit.
Hyundai Steel is focusing on saving costs by optimizing material formulation and improving facility efficiency. Company-wide cost control efforts paid off in the third quarter, leading to cost savings of 145.7 billion won, the company said. Global sales of steel sheet for cars reached 523,000 tons on a cumulative basis in the third quarter, up 13 percent from a year ago, driven by technical marketing and new customers in Southeast Asia and Latin America.
Hyundai Steel also said it will expand the capacity of a metal separating plant by late next year to cover demand for 30,000 additional cars in response to Hyundai Motor Group’s vision for hydrogen and electric-powered vehicles.
Australia’s Iluka Resources Ltd, the world’s largest producer of zircon, said on Thursday it was considering a demerger of an asset that earns royalties from a BHP Group iron ore operation - Mining Area C (MAC).
Iluka holds a royalty over iron ore produced from specific properties of MAC, resulting from a 1994 agreement. MAC is a large iron ore mining area in Pilbara, and is operated by BHP.
The mineral sands producer said it expected much higher royalties from MAC following the completion of BHP’s development of its South Flank project.
“Thanks to the South Flank development, it (MAC) has significant growth in expected cash flows. In addition, further growth in the value of MAC is possible given the potential for the development by BHP of deposits within the area covered by the royalty agreement,” Iluka Managing Director Tom O’Leary said.
Iluka said the possible demerger is part of a broader review of its two “principal” businesses- its mineral sands operations and MAC.
Shares of the company rose as much as 7% after the announcement.
Mining major Rio Tinto on Thursday flagged a 5% increase in iron-ore shipments for 2020, compared with 2019, while also deferring $500-million of planned capital expenditure from 2019 to 2020.
The miner told an investment seminar in London that total capital expenditure for 2019 would be $5.5-billion, with the 2020 capital expenditure guidance standing at $7-billion.
For 2021, the miner has maintained a capital expenditure target of around $6.5-billion, similar to the level expected for 2022.
The miner told investors that Rio remained committed to maintaining an appropriate balance between investment in the business and cash returns to shareholders.
“Over the last three years, our pay-out ratio, excluding returns from divestments, has averaged more than 70%, above our returns policy range of 40% to 60% in recognition of the strong free cash flow generation of the business,” said CEO Jean-Sebastian Jacques.
“Rio Tinto has a world-class portfolio, delivering superior margins and free cash flows, with an established track record of generating resilient returns. This includes $32-billion returned to shareholders since 2016, in a volatile macro environment.
“We are not complacent, and will step up our operational performance to fully optimise our assets and maintain strong cash delivery. We will continue to create value by strengthening relationships with our customers and with other partners, both of which are crucial for our future success."
Meanwhile, Jacques on Thursday said that iron-ore shipments from its Pilbara operations are expected to increase by 5% in 2020, up from the targeted 320-million to 330-million in 2019.
Sustaining capital expenditure for the iron-ore operations is now expected to be $1-billion to $1.5-billion per year from 2020, versus earlier guidance of around $1-billion.
Meanwhile, Rio’s head of aluminium, Alf Barrios, has reportedly said that the current power situation in Australia meant that the company’s aluminium assets in the region was not sustainable, given the high prices of electricity.
"The smelters ... do lag internationally competitive prices which undermines the viability of the asset,” Barrio’s was quoted by Reuters.
He said Rio was speaking with power providers and the government.
“I’m not going to speculate on the outcome but clearly the current situation is not sustainable," he said.
Barrio’s comment comes just days after the miner announced a strategic review of its 79.36% interest in New Zealand’s Aluminium Smelter (NZAS) at Tiwai Point.
The review will determine the operation’s ongoing viability and competitive position, given the challenging short- and medium-term outlook for the aluminium industry on the back of the current market conditions and high energy costs.
https://www.miningweekly.com/article/rio-lays-out-plans-for-investors-2019-10-31
Mongolian state-owned coal miner Erdenes Tavan Tolgoi JSC is ramping up work on a planned Hong Kong initial public offering that could raise more than $1 billion, people familiar with the matter said.
The coal miner has hired an adviser to oversee preparations for the share sale, including the underwriter selection process, said the people, who asked not to be identified as the information is private. The company has been interviewing banks seeking a role on the IPO and targets a listing as soon as next year, the people said.
A successful share sale would mark at least the third effort to raise money to develop the Tavan Tolgoi mine after international partnerships failed in 2011 and 2015. Mongolian lawmakers in 2018 approved a plan to sell up to 30% of Tavan Tolgoi mine.
IPOs in Hong Kong have raised $20.4 billion this year, down from $32.7 billion during the same period in 2018, according to data compiled by Bloomberg. A successful listing of Tavan Tolgoi would represent a victory for the Hong Kong bourse after years of seeking to lure big foreign mining companies to list in the city.
Deliberations on the share sale are at an early stage and details including size and timing may change, the people said. Representatives for Mongolia's Ministry of Mining and Tavan Tolgoi didn't immediately respond to requests for comment.
Tavan Tolgoi, which means "five hills," refers to the original location of the coal ore, according to its website. Tavan Tolgoi coal mine, located in the Gobi desert, is the largest coal ore deposit in Mongolia. Its deposit is estimated at a total of over 6 billion metric tons of coal, and more than one-third of which is high-grade hard coking coal, the website said.
Mongolia has been hopeful of a share sale of Tavan Tolgoi since the country started exporting coal to China in 2011. A $3 billion international share sale plan for 2012 didn't materialize after Ulaanbaatar changed its plans for investment in the coal mine. An attempt to shore up $4 billion investment from a consortium including China Shenhua Energy Co. and Japan's Sumitomo Corp. fell through in 2015 after the parliament stepped in saying it needed to review terms of the deal.
