Mark Latham Commodity Equity Intelligence Service

Wednesday 5th October 2016
Background Stories on

News and Views:

Attached Files


    James Lovelock: Climate change, fracking and lots more

    James Lovelock’s parting words last time we met were: “Enjoy life while you can. Because if you’re lucky, it’s going to be 20 years before it hits the fan.” It was early 2008, and the distinguished scientist was predicting imminent and irreversible global warming, which would soon make large parts of the planet uninhabitably hot or put them underwater. The fashionable hope that windfarms or recycling could prevent global famine and mass migration was, he assured me, a fantasy; it was too late for ethical consumption to save us. Before the end of this century, 80% of the world’s population would be wiped out.

    His predictions were not easy to forget or dismiss. Sometimes described as a futurist, Lovelock has been Britain’s leading independent scientist for more than 50 years. His Gaia hypothesis, which contends that the earth is a single, self-regulating organism, is now accepted as the founding principle of most climate science, and his invention of a device to detect CFCs helped identify the hole in the ozone layer. A defiant generalist in an era of increasingly specialised study, and a mischievous provocateur, Lovelock is regarded by many as a scientific genius.

    Eight years after our previous encounter, he appears to have aged not one bit. At 97, he’s conceived a beautifully illustrated book of essays described as a “tool kit for the future”,The Earth and I, and written the introduction and conclusion; he goes walking every day, his hearing is perfect, his focus forensic and his memory unimpaired. “Yes, why not? I’m writing a fiction book at the moment. It’s tremendous fun, you know.” He applies his holistic philosophy of science to his own health. “I’m a firm believer that if you don’t use it, you lose it – and if you do a lot of walking, and if you use your muscles quite a bit, your brain seems to work as well. You’ve got to look at the whole system, not just bits of it.”

    What has changed dramatically, however, is his position on climate change. He now says: “Anyone who tries to predict more than five to 10 years is a bit of an idiot, because so many things can change unexpectedly.” But isn’t that exactly what he did last time we met? “I know,” he grins teasingly. “But I’ve grown up a bit since then.”

    Lovelock now believes that “CO2 is going up, but nowhere near as fast as they thought it would. The computer models just weren’t reliable. In fact,” he goes on breezily, “I’m not sure the whole thing isn’t crazy, this climate change. You’ve only got to look at Singapore. It’s two-and-a-half times higher than the worst-case scenario for climate change, and it’s one of the most desirable cities in the world to live in.”

    There are various possible explanations for his change of heart. One is that Lovelock is right, and the models on which his former predictions were based were fatally flawed. Another is that his iconoclastic sensibility made revision irresistible. An incorrigible subversive, Lovelock was warning the world about climate change for decades before it began to pay attention, and just when the scientific consensus began to call for intervention to prevent it, he decided we were already too late. But there is a third explanation for why he has shifted his position again, and nowadays feels “laid back about climate change”. All things being equal – “and it’s only got to take one sizable volcano to erupt and all the models, everything else, is right off the board” – he expects that before the consequences of global warming can impact on us significantly, something else will have made our world unrecognisable, and threaten the human race.

    Lovelock maintains that, unlike most environmentalists, he is a rigorous empiricist, but it is manifestly clear that he enjoys maddening the green movement. “Well, it’s a religion, really, you see. It’s totally unscientific.” He was once invited to Buckingham Palace, where he told Princess Anne: “Your brother nearly killed me.” Having read that Prince Charles had installed grass-burning boilers at Highgrove, Lovelock had tried one in his house. “It’s supposed to smoulder and keep the place warm; but it doesn’t, because it goes out, and clouds and clouds of smoke come out.” He giggles. “Princess Anne thought this was hilariously funny.”

    Lovelock had been trying to heat his old mill in Devon, where he lived for more than 35 years, inventing contraptions in a workshop that resembled a Doctor Who set. He and his wife recently packed up his life’s work and downsized to a remote cottage on Chesil Beach in Dorset, after the bill to heat the mill for just six months hit £6,000. “I remember George Monbiot took me up on it and wrote that it was impossible, that I had to be lying. But I wasn’t lying, I’ve got the figures.” Monbiot doesn’t quite accuse him of lying, in fairness; just of “talking rubbish” and “making wild statements”. In any case, he says that in the US he found he could heat a house for six months, in temperatures of -20C (-4F), for just £60. As a result, he has withering contempt for environmentalists’ opposition to fracking. “You see, gas in America is incredibly cheap, because of fracking,” he says. But what about the risk of triggering earthquakes? He rolls his eyes.

    “Sure enough, that’s true, there will be an increase. But they’re tiny little tremors, they would be imperceptible. The only trouble is that you can detect them. The curse of my life has been that I’ve spent a lot of time inventing devices that are exceedingly sensitive. And the moment somebody can detect something, they’re going to attach a number to it, and then they make a fuss about it.” He chuckles, then pauses. “I’m not anti-green in the sense that I’m in favour of polluting the world with every damn thing we make. I think we’ve got to be careful. But I’m afraid, human nature being what it is, the thing gets exaggerated out of all proportion, and the greens have behaved deplorably instead of being reasonably sensible.”

    How James Lovelock introduced Gaia to an unsuspecting world

    We have learned so much about our home planet in the three decades since James Lovelock wrote Gaia: A New Look at Life on Earth. Has it stood the test of time?

    Even more heretical than his enthusiasm for fracking is Lovelock’s passionate support for nuclear power. But, like fracking, he says, it offers only “a stopgap” solution. “Because in the long term, they’ll use up all the uranium.” How long would that take? He pauses to do some quick mental arithmetic, as casually as I might tot up how many pints of milk to grab from Sainsburys.

    “Let’s see … I think uranium that is affordable to extract would last about 50 years, something in that range. It might be 100. When you’ve used all that up, you go to thorium, and that would last you three times as long as uranium – so, shall we say, about 200 years?” The most sensible energy solution would be to cover 100 sq miles of the Sahara in solar panels. “It would supply the whole of Europe with all the energy they needed,” but it won’t happen “because it would be so easy for terrorists to go and bugger it up”. So for now, nuclear energy is the only viable option.

    But all this, he clarifies cheerfully, is more or less academic. “Because quite soon – before we’ve reached the end of this century, even – I think that what people call robots will have taken over.” Robots will rule the world? “Well, yes. They’ll be in charge.” In charge of us? “Yes, if we’re still here. Whether they’ll have taken over peacefully or otherwise, I have no idea.”

    For robots, time happens a million times faster than it does for us. That’s rather wonderful in a way, isn’t it?

    He isn’t alone in this view: the influential philosopher Nick Bostrom has persuaded many people that artificial intelligence poses a real threat to the future of humanity; Elon Musk and Stephen Hawking, among others, have called for urgent research to mitigate the risks. Still, when Lovelock outlines this vision, his tone is so matter-of-fact that for a moment I wonder if he’s joking. He isn’t. “We’re already happily letting computers design themselves. This has been going on for some time now, particularly with chips, and it’s not going to be long before that’s out of our hands, and we’ll be standing aside and saying, ‘Oh well, it’s doing a good job designing itself, let’s encourage it.’” Computers will develop independent volition and intuition (“To some extent, they already have”) and become capable of reproducing themselves, and of evolving. “Oh yes, that’s crucial. We’ll have a world where Darwin’s working.” Darwinism doesn’t work now? “Oh no, we’ve temporarily turned Darwinism backwards. I mean, we preserve the ones that would not have survived.”

    He pauses, and adds quickly: “Don’t let’s get dangerous on this one. I don’t want this appearing in the Guardian that he just wants all the dumb and the lowlifes wiped out.”

    Lovelock doesn’t sound the least bit troubled by the prospect of robots taking over, though, despite the possibility that they will destroy us. “Once they become at all established anywhere, that’s the end, because to robots time happens one million times faster – that’s a fairly exact figure – than it does to us. That’s rather wonderful in a way, isn’t it?”

    I ask him to explain. “Well, for a neuron to travel a foot takes a microsecond – which is fairly fast. But for electrons to go down a foot of wire takes a nanosecond. It’s a million times faster, as simple as that. So to a robot, once fully established in that new world, a second is a million seconds. Everything is happening so fast that they have on earth a million times longer to live, to grow up, to evolve, than we do.”

    It is possible, he goes on, that human beings may fuse with robots to become a blend of robotic and human tissue (“That’s one route”), but the likelier scenario will be pure robots. Why does he think we’ll go for all-out robots? He shoots me an amused look. “I don’t think we will. I think that they will – that’s the key thing here.”

    The implications for climate change are obvious. “The world that they’re going to be comfortable in is wildly different from the one that we feel comfortable in. So once they really get established, they will – with regret – start losing organic life.” Will they care about rising temperatures? “They won’t give a fourpenny fuck about the temperature, because to them the change will be slow, and they can stand quite a big change without any fuss. They could accommodate infinitely greater change through climate change than we can, before things get tricky for them. It’s what the world can stand that is the important thing. They’re going to have a safe platform to live in, so they don’t want Gaia messed about too much.”

    James Lovelock: The UK should be going mad for fracking

    Notwithstanding his caveats about the dangers of predictions, his confidence in the robotic future he describes is “fairly high. Yes, all sorts of things can happen, but that’s the intuitive feeling I have”. As for our interaction with robots: “Well, it’s going to be very peculiar.” In the classic Frankenstein tradition, will humanity not understand what it has created until it’s too late? “Well, too late is the wrong word. Let’s say, until it has happened.” The phrase “too late”, he explains, implies regret – but whereas the robots might see no use for our continued existence, “maybe we’ve got some special property that they will appreciate. But then, don’t forget, their timescale is a million times different from ours. They’d have a lot of trouble talking to us.” In the same sense that we have trouble talking to ants? “Oh no, it’s much worse than that. It’s really more like us talking to a giant redwood tree. And you never know, they may feel about us the same way as we feel about trees.” They might even, I suggest, want to hug us? Lovelock’s face lights up in delight. “Yes, exactly! Exactly. That’s a good one.”

    Lovelock was no less bafflingly cheerful when he believed climate change was about to wipe out 80% of the world’s population. How can he now feel just as sanguine about a global takeover by robots? “One may say: ‘Well, of course, he’s so old he’s stopped having any feelings.’ Not true, I’ll say!” He would have been, he insists, just the same 50 years ago. “And I would hate to think it was an affectation.” He would rather not be called a maverick, because it makes him sound like someone who “makes gadgets in his garage”.

    “But everything in life to me is just: ‘Oh, isn’t that interesting?’”
    Back to Top

    Shippers brace for new rules to cut deadly sulphur emissions

    The global shipping industry is bracing for a key regulatory decision that could mark a milestone in reducing maritime pollution, but which could nearly double fuel costs in a sector already reeling from its worst downturn in decades.

    The shipping industry is by far the world's biggest emitter of sulfur, with the SOx content in heavy fuel oil up to 3,500 times higher than the latest European diesel standards for vehicles.

    To combat such pollution, the International Maritime Organization's (IMO) Marine Environment Protection Committee will meet in London on Oct. 24-28 to decide whether to impose a global cap on SOx emissions from 2020 or 2025, which would see sulfur emissions fall from the current maximum of 3.5 percent of fuel content to 0.5 percent.

    "One large vessel in one day can emit more sulfur dioxide than all the new cars that come onto the world's roads in a year," said Thomas Koniordos, head of business line environmental solutions at Norway's Yara International.

    "That is reason enough to cap emissions," added Koniordos, whose firm makes scrubbers used to clean exhaust emissions.

    Large container ships of 15,000-18,000 TEUs (20-foot equivalent units) consume up to 300 tonnes of high-sulfur fuel a day at sea, while a 300,000 deadweight tonne (DWT) supertanker guzzles up to about 100 tonnes per day. Health experts say sulfur is responsible for deadly heart and lung diseases.

    The issue has been brewing for more than a decade and shippers said the industry was now bracing for tighter regulation to be introduced sooner rather than later due to political pressure.

    "The decision will likely be a political one - the European Union is pressing strongly for 2020," said Arthur Bowring, managing director of the Hong Kong Shipowners' Association.


    The European Union has already agreed that the 0.5 percent sulfur requirement will apply in 2020 within 200 nautical miles (370 km) of EU Member States' coasts, regardless of what the IMO decides.

    China, home to the world's busiest container ports, is also demanding cleaner fuels.

    Authorities in Shenzhen, the world's third biggest container port, introduced tighter controls this month, demanding that ships calling there do not use fuel with a sulfur content of more than 0.5 percent.

    Ship owners can comply with the tighter controls either by switching away from the sludgy and sulfur-rich so-called bunker fuels to diesel or liquefied natural gas (LNG), or by fitting scrubbers to clean exhaust emissions.

    A fuel-switch would impose extra costs on an already troubled shipping sector, which has seen high-profile defaults like South Korea's Hanjin as well as cases of stranded ships with crew left onboard ships unpaid and unsupplied.

        Using low-sulfur diesel instead of bunker fuel on a very large crude carrier (VLCC) class supertanker would boost fuel costs by around 44 percent from an average of $212 per tonne this year for heavy fuel oil to $379 per tonne for gas oil, according to figures from shipping broker Clarkson.

    For traded oil markets, the shift to low-sulfur fuel will "substantially reduce demand for bunkers in the run up to 2020 and increase demand for gasoil and alternative fuels including LNG," said Christopher Haines, head of oil and gas at BMI Research.
    Back to Top

    Oil and Gas

    OPEC sights set for now on $50-60 per barrel oil - PIRA's Ross

    OPEC producers have their sights set on a sustained oil price of $50-$60 per barrel, a modest ambition for the first cut in supply by the oil exporting group in eight years, says one of the industry's top forecasters.

    Benchmark U.S. oil prices CLc1 have risen around $4, or around nine percent, to over $48 per barrel since the Organization of the Petroleum Exporting Countries (OPEC) agreed last week to shave output.

    "You don't manage the market unless you have a price in mind," said Gary Ross, founder and executive chairman at the New York-based consultancy PIRA.

    "They are being cautious, they want to see what will happen with shale. But OPEC's price aspirations only go up over time. They don't go down."

    The deal marks the return to supply caps for the producer group after a brutal two-year free-for-all when OPEC members ditched output targets and pumped more than the market needed in a price war that bloodied U.S. shale producers.

    U.S. oil output fell to around 8.7 million barrels per day in July, the lowest since May 2014 and down over 730,000 bpd on the year, mostly as shale producers hit by low oil prices cut output.

    Ross challenged the assumption that a higher price could be self-defeating for OPEC because it will encourage shale producers to boost output.

    "We're not necessarily about to be overwhelmed by shale oil," he said. "The timing of this is quite deliberate, OPEC is doing this heading into winter and at a time when supply from non-OPEC producers is down."

    Peak northern hemisphere energy demand during the cold season provides OPEC with a window to reach its price aspirations, Ross said. Shale producers will need four to six months to bring new production online, and that may take longer in areas where cold weather prevents work.

    After letting thousands of employees go over the past two years, it will take time for shale producers to build up operations and costs will rise quickly, he added.

    The impact of fast-rising costs on shale producers was likely another factor in OPEC's thinking, Ross said. OPEC producers have less variable costs and so will benefit more from the uplift in oil prices than shale producers, he said.

    While the price rout hurt OPEC's competitors, the group's oil ministers were under pressure from their own central bankers and finance ministers to do something to reverse the impact of low prices on their own revenues, Ross said.

    Many have had to cut budgets and the generous benefits as they adjusted to the longest and deepest oil price rout since the 1980s.

    The $4 rise in prices is already worth over $100 million a day in additional revenue for OPEC producers pumping around 33 million bpd of crude.

    OPEC kingpin Saudi Arabia was not just dressing up a seasonal variation in output as a supply cut, Ross said. The kingdom typically reduces output after summer, when it no longer needs to burn crude for power generation to feed demand for air conditioning.

    "There is a lot more to it than that," he said. "The policy to push for market share is over. It's a matter now of going back to managing the market."
    Back to Top

    Non-OPEC participation in deal would cut 1.2 million barrels per day: Venezuela

    Venezuela's new Oil Minister Eulogio Del Pino attends a meeting at Miraflores Palace in Caracas August 20, 2015. REUTERS/Carlos Garcia Rawlins/File Photo

    Participation by non-OPEC countries in a deal to stabilize oil prices would remove a total of 1.2 million barrels per day from an oversupplied market, Venezuela's Oil Minister Eulogio Del Pino said on Tuesday.

    The Organization of the Petroleum Exporting Countries (OPEC) agreed last week to bring its production to between 32.5 million and 33.0 million bpd by cutting some 700,000 bpd.

    The group, which meets in Vienna on Nov. 30 to finalise the deal, has invited Russia and other non-OPEC producers to join in making cuts.

    "With the deal between OPEC countries, some 700,000 bpd are taken out of the market, and by adding non-OPEC, it's 1.2 million bpd," Del Pino said in a televised broadcast.

    Price hawk Venezuela, which is suffering a deep economic crisis worsened by a fall in oil prices, has been pushing for a deal for months and has said it expects non-OPEC countries to support efforts to boost oil prices.

    Negotiations with countries outside OPEC are "very advanced" and nations including Russia, Oman, Azerbaijan, and Kazakhstan will join the "historic agreement," Del Pino said.

    Iran's oil minister said earlier on Tuesday that the cooperation of non-OPEC producers would play an important role in stabilizing oil prices.

    Both Brent and U.S. crude on Tuesday added slightly to a rally since last week on bets that OPEC and non-OPEC oil producers could reach an agreement on limiting production.
    Back to Top

    Oil prices rise on report of U.S. crude stock draw

    Oil prices rose in early trading on Wednesday after a report that U.S. fuel inventories may have fallen for a fifth straight week, but contracts remained near the $50 marker where many traders currently see fair value for crude.

    U.S. West Texas Intermediate (WTI) crude oil futures were trading at $49.14 per barrel at 0430 GMT, up 45 cents, or 0.9 percent, from their last settlement.

    Traders said the higher prices were largely a result of a report by the American Petroleum Institute (API) late on Tuesday showing that U.S. crude inventories likely fell for a fifth straight week, declining by 7.6 million barrels. [API/S]

    The U.S. government's Energy Information Administration (EIA) will report official stockpile numbers on Wednesday, although analysts polled by Reuters expect the EIA to report a stock build of 2.6 million barrels for the week ended Sept. 30. EIA.

    In international oil markets, benchmark Brent crude futures were trading at $51.29 per barrel, up 42 cents, or 0.8 percent.

    Gary Ross, founder and executive chairman at the New York-based consultancy PIRA, said that a planned deal by members of the Organization of the Petroleum Exporting Countries (OPEC) to cut output would likely lead to only a modest price increase.

    Jason Gammel of U.S. investment bank Jefferies said implementation of the OPEC deal "may prove unsuccessful" due to rivalries within the group but he added that "the mere threat of a production cut should put a floor under oil prices until the next OPEC meeting on November 30."

    Beyond the uncertainty of an OPEC-deal, Gammel said "security conditions in Nigeria and Libya seem to us the most acute uncertainties in the market," adding that if output in any of these countries recovered "that would mean a very hefty cut from the remaining OPEC members if they want to meet the output target."

    ING bank also warned not to read too much into the planned OPEC production cut before details were agreed.

    "This is still only a plan, and no final agreement has been made," the bank said, adding that even modest cuts face hurdles given that Iran, Nigeria and Libya have campaigned for exemptions, which would mean members such as Venezuela and Saudi Arabia would have to stomach larger cuts.

    The Dutch bank said that higher prices "are possible within the coming weeks to next few months, although limited."
    Back to Top

    India’s Biggest Oil Processor to Boost Refinery Expansion Plan

    Indian Oil Corp. is scaling up an expansion plan for its biggest refinery in northern India at a cost of 150 billion rupees ($2.3 billion), as it races to meet demand in one of the world’s fastest-growing crude consumers.

    India’s top refiner will expand its Panipat refinery to 25 million metric tons a year (500,000 barrels a day) from the current 15 million tons, according to Sanjiv Singh, director of refineries. The state-run processor previously planned to boost capacity to 20.2 million tons.

    “Fuel demand growth has been very strong and India’s excess capacity is very small,” Singh said in New Delhi. “We have to keep adding capacities.”

    Increased use of trucks, cars and motorbikes spurred by rapid economic expansion has made the world’s second-most populous nation a bright spot for global oil demand, drawing interest from Saudi Aramco to Rosneft PJSC. Local refiners are racing to add capacity amid rising fuel consumption.

    India’s fuel consumption rose about 11 percent last year, surpassing China’s growth of 7 percent, making the South Asian nation the biggest driver of global energy demand, Kapil Dev Tripathi, the top bureaucrat in India’s oil ministry, said Monday.

    Six Years

    Indian Oil plans to spend 1.84 trillion rupees through 2022 to expand its refining, pipelines and distribution infrastructure. The state-run refiner will add annual capacity of 24 million tons to its existing refineries over the next six years, Chairman B. Ashok said last month.

    Indian Oil last week said it would spend about 83 billion rupees to increase the capacity of its Barauni plant in eastern India by 50 percent, along with a petrochemicals unit.

    “Next, we will take up expansion of Panipat, Gujarat and Mathura refineries,” Singh said. “The Panipat expansion would take about 42 months to complete after the project is approved.”

    Indian Oil can currently process 80.7 million tons of crude a year from its nine plants and two owned by its unit Chennai Petroleum Corp. It accounts for 35 percent of the nation’s total output, according to its website.
    Back to Top

    South Africa Picks Ports for $3.7 Billion LNG Infrastructure

    South Africa will invest $3.7 billion at the ports of Richards Bay and Coega to build infrastructure for a gas-to-power program aimed at easing the country’s dependence on coal.

    A plant at Richards Bay will generate 2,000 megawatts of electricity from liquefied natural gas imports, with another 1,000 megawatts at the Coega industrial development zone, the Department of Energy said in a memorandum on Monday. The government will seek bidders to manage the project, underpinned by a power-purchase agreement between the winning applicant and state electricity utility Eskom Holdings SOC Ltd.

    The program, which coincides with low LNG prices, will create wider opportunities for chemical industry and domestic applications, Trade and Industry Minister Rob Davies told investors at a conference in Cape Town. Apart from the 3,000 megawatts generated at the ports, another 600 megawatts will come from the appointment of a strategic partner for a gas-fired plant and a further 126 megawatts is allocated to a domestic gas program.

    Richards Bay initially will require 1 million tons a year of LNG and Coega 600,000 tons a year, Karen Breytenbach, head of Independent Power Producers Procurement Program Office, told reporters Tuesday. The ports will each require 25 billion rand ($1.8 billion) in infrastructure, she said. The program is looking to hedge the LNG, which is priced in dollars.

    Demand for LNG throughout the country could increase to more than 10 million tons a year after a decade, according to studies by the Department of Energy. That includes long-term demand in KwaZulu-Natal province of 3.1 million tons, Eastern Cape at 3.9 million tons, with the addition of a gas market in Gauteng, Mpumalanga and Free State of 3.2 million tons.

    “The program is designed to ensure that the LNG import and regasification facilities are complementary to the development of indigenous gas and/or development of a regional gas pipeline network,” the department said.

    Pipeline Network

    South Africa’s existing pipeline infrastructure is limited, with Johannesburg-based Sasol Ltd. using a link to import gas from Mozambique to Gauteng province. Another line was constructed to pipe gas to the steel industry and to markets in Richards Bay and Durban.

    The term of a power-purchase agreement with Eskom for the projects is anticipated to be 20 years from the commercial operation date, according to the memorandum. Prequalification for the program will be announced in April, after bidders make submissions in February. The final request for proposals is expected in August, the Energy Department said.
    Back to Top

    PTT to sign more favourable gas contract with BP, Shell

    PTT, Thailand's state-owned oil and gas conglomerate, will sign a 15-year contract for liquefied natural gas with Shell Eastern Trading and BP Singapore before the end of the year.

    LNG imports will begin in April, a year later than initially planned. PTT postponed an earlier contract because the sharp drop in global oil and gas prices opened the way to cheaper purchases through spot contracts. Energy demand in Thailand has also been weakened by the sluggish economy.

    The new contract is awaiting cabinet approval and priced in a way that should save PTT roughly 100 billion baht ($2.88 billion) over the period, Chief Executive Tevin Vonvanich said on Monday. He said the new formula is more resilient to price fluctuations.

    Thailand meets 70% of its energy needs with natural gas and with diminishing reserves in the Gulf of Thailand is increasingly turning to imported LNG and to investing in foreign gas fields.

    PTT's first long-term LNG purchasing agreement was signed in 2015 when it entered a 20-year contract with Qatar Gas, the world's largest LNG producer, to buy 2 million tons annually.

    PTT has operated an LNG receiving terminal in Rayong on the eastern seaboard of the Gulf of Thailand since 2011. The terminal's second phase development is due for completion by the end of the year and for commissioning in March just before the contract with Shell and BP kicks in. The terminal's capacity will more than double to 11.5 million tons per year.
    Back to Top

    Mozambique, Eni ink LNG supply deal with BP

    Italy’s Eni and Mozambique have reportedly signed a 20-year deal with UK-based BP for the supply of liquefied natural gas from the Coral FLNG project, moving the project further forward.

    The final investment decision for the Coral FLNG project is expected to be reached by the end of the year, Reuters reports citing a statement by the state-owned Empresa Nacional de Hidrocarbonetos (ENH).

    LNG World News contacted Eni, BP and ENH seeking comments on the LNG sales contract. We did not receive any response by the time this article was publsihed.

    Eni secured the approval from the Mozambique government for the development plan of the Coral FLNG project that is expected to produce around 3.4 mtpa, in January this year.

    The approval relates to the first phase of development of 5 trillion cubic feet of gas in the Coral discovery, located in the Area 4 permit.

    The giant discovery, located approximately 80 kilometers offshore of the Palma bay in the northern province of Cabo Delgado, is estimated to contain around 16 trillion cubic feet (TCF) of gas in place.

    The plan of development, the very first one to be approved in the Rovuma Basin where 85 Tcf of gas have been discovered, foresees the drilling and completion of 6 subsea wells and the construction and installation of a floating LNG facility, Eni said after receiving the approval.

    Eni is the operator of Area 4 with a 50 percent indirect interest, owned through Eni East Africa (EEA), which holds a 70 percent stake of Area 4.

    The other partners are Galp Energia, Kogas and ENH with a 10 percent stake each. CNPC owns a 20 percent indirect interest in Area 4 through Eni East Africa.
    Back to Top

    Oil Major BP Buys First Iranian Oil Since Lifting of Sanctions

    Iran’s state-owned oil company sold natural gas condensate to BP Plc for the first time since sanctions were lifted in January, marking the country’s re-emergence as one of the world’s top suppliers of crude oil and natural gas liquids.

    National Iranian Oil Co. will supply South Pars condensate to BP for loading between September and October, said an NIOC official, asking not to be identified because of internal policy. The shipment may be used by one of BP’s own refineries or resold to other users, the official said by phone.

    A London-based spokeswoman for BP declined to comment on the deal when contacted by phone.

    The sale is a milestone for OPEC’s third-largest producer, which has been ravaged by sanctions targeting its nuclear program. Iran has vowed to recover its lost market share by restoring its crude oil output to pre-sanctions levels of slightly over 4 million barrels a day. The country also wants torevitalize its refining and petrochemical industries to improve the quality of fuel sold on the domestic market and wean itself off imported oil products.

    Iran is also working with traders such as Trafigura Group, which lifted a cargo of Iranian Heavy in June in an attempt to expand its reach into the Chinese independent refining market. Royal Dutch Shell Plc shipped a cargo of Iranian crude to Europe in July, while France’s Total SA was the first oil major to resume purchases of Iranian oil in February this year.
    Back to Top

    Russian pipeline gas exports back above 10 Bcm in September

    Combined natural gas exports from Russia via the Nord Stream, Yamal, and Brotherhood pipelines rose back above the 10 Bcm mark last month, climbing to a six-month high, data from Platts Analytics' Eclipse Energy showed.

    Total pipeline gas exports through Nord Stream, Yamal, and Brotherhood rose 13% month on month and 7% year on year to 10.108 Bcm in September, the highest monthly flows seen since March and the fifth-highest total recorded for a calendar month.

    Flows breached the 350 million cu m/d mark on several occasions last month, with gas throughput via the Brotherhood pipeline -- transiting Russian gas to Slovakia via Ukraine -- rising to their highest in over two years early last month due to Nord Stream maintenance.

    Brotherhood flows in September were steady month on month at 4.260 Bcm, but were well up on September 2015 levels of 3.498 Bcm.

    Flows via the Nord Stream pipeline -- transiting Russian gas direct to Germany via the Baltic Sea -- rose to 3.368 Bcm last month, higher than the 2.488 Bcm seen during August due to a lighter maintenance schedule in September compared to the previous month.

    Flows via the Yamal pipeline -- transiting Russian gas to Germany via Poland and Belarus -- were again steady at 2.480 Bcm in September, with the pipeline typically used at the full 84 million cu m/d full capacity.

    Total Russian flows via these pipelines for the first nine months of the year stood at 85.603 Bcm, 13% higher when compared to the January-September, 2015, period and over 12 Bcm up on the same time in 2014.

    Moreover, after Norwegian pipeline gas exports fell to their lowest in over five years in September, Russian gas supplies stand nearly 9 Bcm higher than Norwegian gas supplies during the first nine months of 2016.

    Russian gas flows during the Winter 2016-17 delivery period are set to continue at high levels, with oil-indexed gas prices under Gazprom's structure ending September below hub levels for both Q4 2016 and Q1 2017, incentivizing high nominations from customers during the winter period.
    Back to Top

    Alaska Oil Known Reserves May Have Just Grown 80% on Discovery

    Alaska’s oil reserves may have just gotten 80 percent bigger after Dallas-based Caelus Energy LLC announced on Tuesday the discovery of 6 billion barrels under Arctic waters.

    The light-oil reserves were found in the company’s Smith Bay leases between Prudhoe Bay and Barrow along the Arctic shore, according to a statement from Caelus. As much as 2.4 billion barrels is estimated as recoverable, according to a release issued by the company. That compares with the state’s proved reserves of 2.86 billion barrels in 2014, almost 8 percent of the U.S. total, Energy Department datashow.

    “This discovery could be really exciting for the state of Alaska,” Caelus Chief Executive Officer Jim Musselman said in the statement. “It has the size and scale to play a meaningful role in sustaining the Alaskan oil business over the next three or four decades.”

    Alaska’s oil output has been gradually declining, to 483,000 barrels a day last year from a peak of more than 2 million barrels a day in 1988, Energy Department data show. The last major field brought online was Alpine in 2000, which averaged 62,000 barrels a day in September, Alaska Department of Revenue data show.

    Peak Production

    Caelus said its newly discovered field could produce as much as 200,000 barrels a day. That compares with 483,000 barrels a day pumped in Alaska last year, Energy Department data show. The Eagle Ford shale region, the largest U.S. field, yielded 238,000 barrels a day in 2013.

    The discovery of light oil was made after seismic data was collected and two wells were drilled this year, the company said. Another well will be drilled in early 2018, Casey Sullivan, a company spokesman, said in a phone interview. The discovery would be the biggest in four decades, the company said. Prudhoe Bay, the state’s biggest field, was discovered in 1967.

    A driller on the North Slope needs oil at about $40 a barrel on average to be profitable, Sarah Erkmann, external affairs manager at the Alaska Oil and Gas Association, said in a phone interview. Oil traded at about $49 a barrel today in New York.

    “At these depressed prices, that makes it very challenging,” she said.
    Back to Top

    Growth in propane exports drove U.S. petroleum product export growth in first half of 2016

    Image title

    In the first half of 2016, the United States exported 4.7 million barrels per day (b/d) of petroleum products, an increase of 500,000 b/d over the first half of 2015 and almost 10 times the crude oil export volume. While U.S. exports of distillate and gasoline increased by 50,000 b/d and nearly 140,000 b/d, respectively, propane exports increased by more than 230,000 b/d. Propane surpassed motor gasoline to become the second-largest U.S. petroleum product export, after distillate.

    Although total U.S. petroleum product exports grew, export destinations remained largely unchanged. Mexico,Canada, and the Netherlands received the greatest volumes of U.S. petroleum products in the first half of 2016, importing 775,000 b/d, 579,000 b/d, and 271,000 b/d, respectively. U.S. petroleum products tend to stay in the Western Hemisphere. In 2015, approximately 60% of total petroleum product exports remained within the Western Hemisphere, down slightly from 65% in 2005.

    Image title

    Distillate exports averaged 1.2 million b/d in the first half of 2016, an increase of 50,000 b/d from the same period of 2015. Central and South America accounted for the largest share of U.S. distillate exports, averaging more than 620,000 b/d in the first half of 2016, up more than 30,000 b/d from the same period of 2015. The largest single destination overall for U.S. distillate exports was Mexico, which averaged 147,000 b/d in the first half of 2016.

    U.S. propane exports increased from 562,000 b/d in the first half of 2015 to 793,000 b/d in the same period of 2016. Exports to Asia and Oceania accounted for 94% of this growth. Japan imported the most U.S. propane at 159,000 b/d in the first half of 2016, an increase of 111,000 b/d from 48,000 b/d in the same period of 2015. U.S. exports of propane to Panama, however, fell from 41,000 b/d in the first half of 2015 to 7,000 b/d in the first half of 2016.

    The large increases in propane exports to Japan and decreases in propane exports to Panama could be a result of reduced ship-to-ship transfer activity. Some of the propane exports from the United States that undergo ship-to-ship transfers will cite the location of the transfer and not the final destination of the propane. This often results in larger-than-actual export numbers for the countries where the ship-to-ship transfers take place and in less-than-actual numbers for some final destinations.

    Gasoline exports increased 138,000 b/d in the first half of 2016 compared with the first half of 2015. North America (Canada and Mexico) accounted for most of the growth, with an increase of 92,000 b/d. Similar to U.S. distillate fuel exports, Mexico represented the largest single recipient of U.S. gasoline exports at 363,000 b/d in the first half of 2016, up from 283,000 b/d in the first half of 2015. As part of the energy reforms passed in 2013, Mexico liberalized its energy sector, allowing market participants other than the state company Petroléos Mexicanos (Pemex). In January 2016, as part of the liberalization process, Mexico began to allow companies besides Pemex to import fuels, resulting in increased exports from nearby refineries along the U.S. Gulf Coast. Canada was the second-largest recipient of U.S. gasoline at 66,000 b/d in the first half of 2016, up from 55,000 b/d in the first half of 2015.

    Attached Files
    Back to Top

    New wave of power plants is fuelling U.S. gas demand

    The United States is experiencing a structural increase in gas demand with more gas-fired power stations operating more hours per year and consuming a record volumes of gas.

    But domestic gas production is turning down, with output nearly 4 percent lower in July 2016 compared with July 2015 ("Falling U.S. gas output meets stronger demand", Reuters, Oct 3).

    Growing demand for gas and shrinking supplies are not sustainable, so gas prices will have to rise to encourage more drilling and limit the use of some gas-fired power plants.

    U.S. power producers had 448 gigawatts of gas-fired generation capacity in July 2016, an increase of 25 gigawatts since the end of 2012, according to the Energy Information Administration (

    Installed gas-fired capacity is scheduled to grow by another 11.5 gigawatts to 459 gigawatts by the end of 2017, when it will be almost 9 percent higher than five years earlier.

    Most of the extra capacity uses combined-cycle technology. Total gas-fired capacity will have risen nearly 9 percent between 2012 and 2017 but combined-cycle will increase by almost 14 percent over the same period (

    Historically, most gas-fired power plants burned gas in a boiler to raise steam (similar to a coal-fired plant) or combusted it directly in a gas turbine (similar to an aircraft jet engine).

    Steam turbines and especially combustion turbines waste lots of heat and are relatively inefficient and expensive ways to generate electricity.

    But they can ramp production up and down more quickly than coal-fired steam turbines, which made them ideal for meeting short periods of peak power demand in summer and winter.

    Used mostly in peaking mode, gas-fired steam turbines were used for less than 12 percent of the time on average in 2015 while combustion turbines were used less than 7 percent of the time.

    Combined-cycle units, however, are designed to operate far more efficiently: gas is first burned in a combustion turbine and then the exhaust heat used to raise steam in a boiler.

    Both the turbine and the boiler can be used to drive generation sets, enabling more of the fuel's energy content to be converted into electricity.

    Combined-cycle units are designed to provide baseload throughout the year rather than just during periods of peak demand.

    The average combined-cycle plant operated more than 56 percent of the time in 2015, according to the Energy Information Administration.


    Capacity factors for combined-cycle plants have been trending upward over the last few years as they replace coal-fired units thanks to stricter emissions regulations and falling gas prices.

    The average gas-fired combined-cycle plant operated for the equivalent of 4,932 hours at full power in 2015, up from 4,489 hours in 2012, an increase of almost 10 percent.

    Average coal unit operation dropped to the equivalent of 4,783 hours from 4,981 hours over the same period ("Average utilization for natural gas combined-cycle plants exceeded coal plants in 2015", EIA, April 2016).

    Capacity factors at combined-cycle units continued to increase in 2016, while coal-fired power plants sat idle more of the time, thanks to low gas prices.

    The proliferation of combined-cycle plants with high capacity factors is driving a big structural increase in gas consumption and tightening the gas market.

    Unusually high temperatures across the most populous parts of the United States since the end of May helped drive record gas combustion by power producers this summer (

    But with more gas-fired power plants being installed and running for more hours, underlying gas demand has been increasing, whatever the weather.

    With more combined-cycle capacity due to come online, gas consumption will continue to increase, other things being equal.

    The combination of rising gas consumption with stagnating or falling gas production is clearly unsustainable in the medium term (

    Gas prices will have to rise to reverse the slump in gas production and cut capacity utilization at combined-cycle plants to conserve fuel.

    The EIA forecasts gas use in the power sector will decline by 2.3 percent in 2017 as rising gas prices spur a modest switch back towards coal ("Short-Term Energy Outlook", EIA, September 2016).
    Back to Top

    Canada Oil Sands in Race With Shale, Batteries for Survival

    Canada’s oil-sands industry is in a race with other forms of crude production and emerging technologies such as electric cars to remain a relevant energy source in the coming decades, according to consultancy Deloitte LLP.

    Among various scenarios, oil-sands producers face the risk of a “forced transition” away from oil and natural gas as power generation is dominated by solar panels and wind turbines and as electricity replaces oil as a transportation fuel, Deloitte said in a report released Tuesday. Most of Canada’s oil and gas would be stranded and only the lowest-cost producers would survive by spending on innovative technology.

    “Companies should reflect on what actions they might take today to provide resilience in the face of different future scenarios,” Andrew Swart, Daniel Rowe and Paul Craig wrote in the report.

    Companies including Suncor Energy Inc., Imperial Oil Ltd. and competitors have beenslashing operating costs as they wait for crude prices to rise in order to deploy the latest, cost-saving equipment that will make oil production less carbon intensive. Canada’s industry is hampered by its higher costs and lack of access to global markets, which has depressed prices for commodities.

    Foreign Investment

    Another possible scenario would see hydrocarbons remain a significant source of global energy as commodity prices remain competitive and with only incremental improvements in battery technology, the report said. Foreign investment in Canadian oil and gas, as well as new pipelines, would allow companies to remain competitive in global markets.

    No matter what, companies must focus on innovation to improve performance and engage with stakeholders to retain their social license to operate, the authors said.

    Canada’s oil industry is on track to post a combined pre-tax losses of C$10 billion ($7.6 billion) this year, following a record loss of C$11 billion in 2015, according to the Conference Board of Canada. The industry will likely return to profit next year, the group said in its industry outlook.
    Back to Top

    Canada’s oil industry to lose $10 billion this year

    Canada’s oil extraction industry is on track to post a second consecutive year of shortfalls — to the tune of $10 billion — on the back of ongoing revenue woes, combined with a slower than anticipated cost cutting response, a local think-tank said Tuesday.

    According to the Conference Board of Canada’s latest outlook for the industry, the crude sector’s losing streak will last about three years, from the last quarter of 2014 through to the second quarter of 2017.

    Investment cutbacks are expected to continue this year and next, which will result in lower production levels.

    The report also estimates that profit margins will hit record lows this year to a negative 19% and that while they will improve from 2017 onwards to roughly 4% in 2020, return to profitability remains uncertain.

    In terms of production, the board expects it to contract slightly this year for the first time since the 2008 global financial downturn.

    When it comes to investment in the sector, the think-tank is not positive either. It says that only last year producer slashed to $25 billion in expenditure and that the cutbacks expected to continue this year and next. From 2014 to 2017, industry investment will have been cut by an estimated $38 billion, it noted.

    That pullback in investment will, in turn, result in lower production levels, the board warns, adding that it expects Canada’s crude output to fall by 1% this year. This, mostly as a direct consequence of disruptions caused by wildfires in Fort McMurray earlier in the year, as well as ongoing investment cutbacks.

    Recent data from Statistics Canada shows the country’s economy shrank in the second quarter of the year touching levels not seen since 2009, mostly due to Alberta fires.
    Back to Top

    SandRidge Energy Emerges from Reorganization with Approximately $525 Million of Liquidity

    Relisted on New York Stock Exchange and Resumed Trading Under Ticker "SD"

    $3.7 Billion of Debt Eliminated

    SandRidge Energy, Inc. today announced it has emerged from Chapter 11, having satisfied all the necessary provisions of its Plan of Reorganization (the "Plan"). SandRidge received approval to relist on the New York Stock Exchange in conjunction with its emergence and resumed trading of newly issued common stock on October 4, 2016, under the ticker symbol "SD".

    Combining its unrestricted cash balance with the availability under its first lien credit facility following emergence, SandRidge exits its restructuring with approximately $525 million in total liquidity.

    New Capital Structure Summary

    SandRidge's new capital structure consists of a $425 million first lien revolving credit facility ("RBL") (maturing in 2020) and approximately $282 million in mandatorily convertible notes, bearing no interest and converting at any time at the option of the holders or mandatorily at the earlier of certain events or four years from the effective date of the Plan. As previously disclosed, SandRidge's pre-petition second lien secured and general unsecured claim holders receive 100% of the newly issued common equity in the reorganized company.
    Back to Top

    Resolute Energy Corporation Announces $135 Million Delaware Basin Acquisition

    Resolute Energy Corporation today reported that it has entered into a definitive agreement (the "Acquisition Agreement") with Firewheel Energy, LLC, a portfolio company of EnCap Investments, toacquire certain oil and gas properties located in Reeves County, Texas, for a purchase price of $135 million. The transaction is expected to close on October 7, 2016.

    The Firewheel Properties consist of 3,293 net acres in our highly productive Delaware Basin operating area, and include interests in thirteen horizontal and fifteen vertical wells, which produce approximately 1,200 net Boe per day. Approximately 95% of the acreage and substantially all of the production and proved reserves are located within the Resolute-operated Mustang project area in Reeves County. The remainder of the acreage is also in Reeves County. The Firewheel Properties contain estimated proved reserves of 6.2 MMBoe with PV-10 of $45.8 million, using strip pricing at June 30, 2016. The acquisition also includes Firewheel's interest in the Earn-Out Agreement (to which we are also a party) with Caprock Permian Processing LLC and Caprock Field Services LLC (collectively, "Caprock"). Following the closing of the acquisition, Resolute will receive 100% of all payments from Caprock under the Earn-Out Agreement.

    The purchase price for the acquisition is $135 million, consisting of $90 million payable in cash and the issuance to Firewheel of 2,114,523 shares of our common stock, equal to $45 million, based on 90% of the volume weighted average price of our common stock as traded on the NYSE for the 15 trading days ending on October 4, 2016. We expect to finance the cash portion of the acquisition price with the net proceeds of a private offering of a newly created class of preferred stock of the Company, and borrowings under our Revolving Credit Facility (which is currently undrawn).

    The acreage to be acquired represents an approximately 25% increase in our net acreage in Reeves County while leaving our gross acreage position essentially unchanged as the Company already owns interests in all of the same properties. The completion of this acquisition will result in a higher interest in the production and cash flow generated from our operated wells, further leveraging the work of our field staff.$135+Million+Delaware+Basin+Acquisition/12103464.html
    Back to Top

    Enerplus seeks buyer for Marcellus natural gas assets: sources

    Canadian energy producer Enerplus Corp (ERF.TO) has put its natural gas assets in the U.S. Marcellus shale region up for sale, according to three sources familiar with the situation.

    The assets could fetch about $500 million, the sources said, speaking on condition of anonymity as the matter is not public.

    Enerplus, which owns oil and natural gas assets in Canada and the United States, expects the sale to make its asset portfolio more geographically concentrated and allow it to pay down debt, the sources said.

    The company's net debt as of June 30 was about C$700 million ($530 million).

    Enerplus could also make an acquisition with the money, one of the sources said.

    After the Reuters report, Enerplus shares turned positive and rose as much as 3.8 percent. There were trading at C$9.02, up 2.7 percent, in afternoon trade.

    The Marcellus assets, in Pennsylvania, have drawn interest from parties in the United States and Asia, the sources said, adding that private equity firms are the most likely buyers.

    Enerplus, which calls the Marcellus shale gas project one of the most economic dry gas plays in North America, did not respond to a request for comment.

    The company says on its website that it has oil assets in the Williston Basin in North Dakota, where it expects to spend C$145 million this year. That compares with C$20 million for the Marcellus project.

    In a recent investor presentation, Enerplus cited "over $1.2 billion of net divestment proceeds since 2010," which it said has helped focus the portfolio. Its website lists the Marcellus asset as one of its focus areas.

    About 35 percent of the company's production in 2016 is expected to come from its Marcellus shale business, according to the website.
    Back to Top

    Nucor, Encana end drilling deals, enter into lease agreement

    A major steelmaker and the oil and gas producer Encana have ended deals compelling them to jointly develop thousands of natural gas wells in western Colorado’s Piceance Basin when gas prices are high enough.

    In their place, Nucor has bought a 49 percent oil and gas lease interest from Encana on about 54,000 acres in the Piceance, with Encana retaining a 51 percent controlling interest in that acreage.

    The companies both said ending their joint venture gives them more flexibility in decisions about where to make capital investments. In the short term, at least, that could mean a delay in any resumption of drilling by Encana locally. Under the joint venture with Nucor, Encana would have been obligated to drill once natural gas prices rose to a predetermined level.

    “We wanted to have the flexibility to really direct our capital where we felt we would have the highest (profit) margins,” Encana spokesman Doug Hock said.

    For now, anyway, that means spending money in what Encana considers its four core areas — two basins in Texas and two in Canada that are more liquids-rich than the Piceance, which primarily produces natural gas.

    As for Nucor, the new transactions with Encana “preserve Nucor’s long-term access to low cost gas resources in support of Nucor’s raw material strategy. We think this … is a win-win for both companies,” John Ferriola, Nucor’s chairman, chief executive officer and president, said in a news release.

    Encana and Nucor have ended a drilling agreement reached in 2010 and a larger one that came two years later. They involved sharing in the upfront cost of drilling wells in exchange for Nucor gaining a working interest in the wells that are drilled.

    The 2012 agreement held the potential for Encana to drill more than 4,000 wells over 20 years on some 50,000 acres of federal leases stretching from Garfield County into Rio Blanco County. Nucor said at the time that it expected to invest $542 million over the following three years and about $3.64 billion over the estimated 13- to 22-year term of the agreement.

    Nucor, based in North Carolina, is a heavy consumer of natural gas and got involved with Encana as a hedge against the possibility of rising natural gas prices. The joint venture wasn’t designed to ship the gas produced to its factories, but rather was intended to ensure that if gas prices go up, Nucor also is invested on the gas supply side.

    Encana and Nucor eventually suspended drilling under the joint venture under terms allowing for that if prices fell too low. By late 2013 Encana decided to stop drilling altogether in the Piceance, and it hasn’t drilled locally since. A Nucor official later told The Daily Sentinel that as many as 300 wells probably had been drilled under the joint venture before work was suspended. Nucor said Tuesday it is keeping all producing wells it owns.

    Hock said Nucor’s new lease ownership covers the same acreage that was involved in the 2012 agreement. Encana, as majority owner, would decide if and when to drill on the acreage, and Hock said Nucor would have a 49 percent ownership of proceeds from any drilling.

    Nucor said in its release that the new ownership structure “provides Nucor full discretion on its participation in all future drilling capital investment.”

    Nucor also sold its half-interest in Hunter Ridge Energy Services LLC to Encana. Hunter Ridge was formed by the two companies to provide gas gathering and water services.

    Nucor didn’t disclose in its news release the dollar amounts involved in the lease and Hunter Ridge transactions.
    Back to Top

    Select Sands Enters Into an Agreement Including Option to Purchase Dry Plant, Operating Equipment, and Sand Inventory

    Select Sands Corp.  is pleased to announce that it has entered into a binding agreement with Tutle Holding, LLC and Steve Hackmann, Ozark Premium Sand, LLC ("OPS") pursuant to which Select Sands' wholly owned subsidiary, American Select Corp., will purchase certain of OPS's equipment and shall have the option to purchase OPS's dry processing plant, operating equipment, saleable inventory, and customer lists amongst other miscellaneous assets owned by OPS.

    Included in the assets in respect of which the Company will have an option to purchase is a 26-acre fully operational drying facility with storage located within 50 miles of Select Sands' "Sandtown" quarry in Arkansas, USA. The 26-acre facility is located on the Union Pacific Rail Line. If the option is exercised, this transaction will transform Select Sands into a fully integrated, self-sufficient Tier 1 sand producer with capacity to process more than 600,000 tons per year with an excellent logistics and storage advantage. In addition, the facility can be easily expanded to increase the amount of sand that can be processed.

    Rasool Mohammad, President, CEO and Director of Select Sands states, "We are very pleased to come to terms on this transaction that is very favourable for both parties moving forward. In the energy market, Tier-1 regional (40/70 and 100 mesh) sand is in high demand right now, and the market is tightening for this finer sand. Our timing to become a new supplier of high-purity, finer mesh sand couldn't come at a better time for our shareholders."

    Pursuant to the terms of the agreement, Select Sands will pay US$500,000 upon signing of the agreement to the vendors in respect of the purchase of certain heavy equipment. Select Sands will take title to these assets upon payment of the US$500,000.

    Select Sands will then have 60 days to complete its due diligence on the remaining assets that are subject to the agreement. If Select Sands is satisfied with its due diligence, then before the end of the due diligence period it must pay an additional US$250,000 to the vendors for certain specified additional heavy equipment and US$250,000 as a payment for the option to acquire the remaining assets within the period expiring on the one year anniversary of the date of payment of the above referenced US$250,000 option payment. The purchase price for the remaining assets subject to the option will be US$3,317,000, after deducting the US$250,000 option payment.

    As per the June 2015 PEA report by Tetra Tech of Golden, Colorado, USA and Vancouver, BC, Canada, the Sandtown property has a pre-tax net present value of US$160 million and a post-tax net present value of US$92 million. The PEA was completed on a portion of the current silica sand mineral resources (see the Select Sands' June 10, 2015 News Release).

    Within this PEA, the CAPEX for the drying plant, equipment, storage and loadout was ~US$32M, whereas the total purchase price that encompasses the vast majority of this CAPEX totals US$4,317,000.

    Mr. Mohammad continues, "This transaction demonstrates our commitment to become a fully integrated producer in the most accretive way possible and demonstrates our aligned interests with shareholders."

    The Company is fully funded to make the first two payments from treasury and is in the position to fully evaluate all financing options to finalize the proposed transaction as the Company continues to increase sales and ramp production.
    Back to Top

    Alternative Energy

    South Aus electricity outage: wind to blame?

    Image title
    Back to Top


    Cargill first-quarter profit jumps 66 percent

    Cargill first-quarter profit jumps 66 percent

    Global commodities trader Cargill Inc [CARG.UL] on Tuesday reported a 66.4 percent rise in net quarterly profit, helped by lower beef prices due to increased cattle supplies and renewed demand.

    The privately held company said net income rose to $852 million in the first quarter ended August 31 from $512 million a year earlier.

    Excluding items, the Minnesota-based company's operating profit rose to $827 million from $611 million a year earlier.

    Revenue fell marginally to $27.1 billion from $27.5 billion.
    Back to Top

    Precious Metals

    Erdene Intersects 24 Metres of 7.5 g/t Gold within 116 Metres of 2.0 g/t Gold from Surface

    Erdene Resource Development Corp.  is pleased to announce results from the first seven holes of its originally planned 5,000 metre drill program at its 100%-owned, high-grade Bayan Khundii gold project ("Bayan Khundii") in southwest Mongolia. In addition, the Company announces an expanded drill program with a total of 9,000 metres now anticipated to be completed in Q3-Q4 at Bayan Khundii and at the Company's neighbouring, 100%-owned Altan Nar and Altan Arrow gold projects. Included with this release, for reference, are two plan maps and a cross-section showing project locations, the position of today's drill holes, as well as areas where drill results are pending.

    "Bayan Khundii continues to deliver exceptional, near-surface gold grades over wide intervals and today's results increase our confidence in the continuity of these gold zones and the broad extent of the lower-grade mineralization," said Peter Akerley, Erdene's President and CEO. "As the drill program advances we will be testing multiple targets outside of the known mineralized area, predominantly under younger cover rocks, to better establish the size potential of the Bayan Khundii gold system."


    Striker Zone drilling (BKD-49) returns 24 metres of 7.5 g/t gold within 71 metres of 3.1 g/t gold, both within a wider intersection of 116 metres of 2.0 g/t gold, from surface
    Additional drilling in the Striker Zone (BKD-51) returns 112 metres of 1.2 g/t gold, from surface
    Multiple, very high-grade gold intersections in the Striker Zone containing several gold-bearing quartz veins returning 1 metre samples exceeding 40 g/t gold
    A new near-surface zone, southwest of the Striker Zone, was intersected in hole BKD-46, returning 16.7 metres of 4.6 g/t gold from surface, including 7 metres of 10.2 g/t gold
    Hole BKD-46 also returned an additional 22 metres of 2.2 g/t gold, including 7 metres of 6.4 g/t gold, at 100 metres depth, representing a down-dip extension of the Striker Zone
    Additional drill results for step-out holes testing Bayan Khundii targets under younger cover are anticipated in late October

    Attached Files
    Back to Top

    De Beers rakes in $485m from diamond sales

    Diamond producer De Beers has raised $485-million from its eighth sales cycle during the year.

    CEO Bruce Cleaver said on Tuesday that the demand for its rough diamonds continued to reflect the improved midstream trading environment compared with 2015.

    “Our rough diamond sales were slightly ahead of expectation during the cycle, given the normal seasonal demand patterns, the shorter-than-usual period between sights 7 and 8, and the forthcoming holidays in some of the major diamond cuttingcentres,” he noted.
    Back to Top

    Base Metals

    Indonesia expects mining rule overhaul within weeks

    Indonesia is finalizing an overhaul of its mining rules that could give companies up to five more years to build smelters, and reopen exports of nickel ore banned since 2014, the country's mining minister said on Tuesday.

    The proposed changes provide a way around a 2017 deadline for full domestic processing of mineral ores, potentially pushing completion of that aim to 2022, but also possibly undermining investor confidence.

    "We will provide an opportunity to companies building smelters, in the form of a relaxation ... in accordance with their smelter development progress," Mining Minister Luhut Pandjaitan said.

    Miners that fail to build smelters within five years could have their mining permits revoked, Pandjaitan said.

    Present rules would stop miners of copper, zinc, lead, manganese and iron from exporting concentrates after January 2017, after which only shipments of processed metals will be allowed.

    The proposed change could be a breakthrough for miners such as U.S. giant Freeport-McMoRan Inc, for whom it would avert a stoppage of copper concentrate shipments from the giant Grasberg mine in Papua in far eastern Indonesia.

    A Jakarta-based spokesman for Freeport did not immediately respond to requests for comment on the matter, but Indonesia's largest copper miner has previously said it was confident the government will not push ahead with the 2017 deadline, as the move could harm the economy.


    The government is also looking to possibly change rules on nickel ore with a 1.8 percent metal content, "because no one can process it domestically. Perhaps we will consider exporting it," Pandjaitan said.

    Nickel companies have said they fear the rule changes could weaken metal prices, undermine confidence in the newly budding smelting industry and risk up to $12 billion in investments.

    The Philippines took the crown as the world's top nickel ore exporter after Indonesia banned nickel ore shipments, and now accounts for around one-quarter of the world's mined nickel supply, most of which is shipped to China.

    But Indonesia has found compensation in shipping pig iron to China, India and other buyers, and this industry now worries that resuming ore exports could undermine the prices for such semi-finished and refined metals.

    "Actually no one supports there being ore (exports) any more," Jonatan Handojo, executive director of Indonesia's main smelter industry association, told Reuters.

    Overturning the ban would go against the wishes of most participants in Indonesia's nickel industry, Handojo said.

    He dismissed a "handful" of companies, such as Indonesian state miner Aneka Tambang, which hope that Indonesia will again open up nickel ore exports to prop up income and support financing for smelter investments.


    As part of the overhaul, the finance ministry is working on a progressive export mineral export tax, to be imposed in stages according to how far companies have advanced with their smelter development, Pandjaitan said.

    Further details of this and the mining overhaul are expected within weeks, Pandjaitan said.

    "There is no way we can satisfy everyone, but we are trying to be as fair as possible, and to act in the interests of the government, the people of Indonesia and investors in that sector," he said.

    Indonesia's growth cooled to its slowest in six years in 2015, partly as a result of weaker returns from commodities, and the government has been rolling out new measures this year to reenergize the economy and boost its revenues.

    Nickel prices hit a seven-week high of $10,900 a tonne on the London Metal Exchange last week, after the Philippines intensified its environmental crackdown on nickel miners.
    Back to Top

    Steel, Iron Ore and Coal

    Coking coal surge could kill quarterly pricing

    The stunning rise in the price of coking coal shows now signs of reversing, and the nearly three-fold rise in the price of the steelmaking raw material since hitting multi-year has pushed the quarterly benchmarking system to breaking point.

    Metallurgical coal was exchanging hands at $213.40 on Tuesday according to data provided by Steel Index as it consolidates at higher levels following weeks of panic buying not seen since 2011, when floods in key export region in Queensland saw the price touching to $335 a tonne.

    Image title

    A new research note Adrian Lunt, head of commodities research at the Singapore Exchange, says the traditional quarterly benchmark mechanism has "arguably been losing relevance for some time, but the recent spot market volatility has put it under potentially fatal strains":

    The commoditisation and rising adoption of indexation has been a key feature in the seaborne coking coal market in recent years. In recent years the quarterly settlement has largely followed the spot market, and a prolonged period of price stability perhaps enabled the quarterly benchmark to persist (albeit pricing an ever-shrinking portion of the international market).

    During Q3, the daily spot price averaged almost $133 per tonne, approximately 44% higher than the Q3 quarterly benchmark agreed in late June. With spot and benchmark pricing deviating more than ever, strains are likely to persist on the outdated quarterly pricing mechanism. Continued market volatility could spur a more widespread transition to index-linked pricing over the coming months, which may in turn serve as an important catalyst in the development of the international coking coal derivative market.

    Attached Files
    Back to Top

    US coal legend Ernie Thrasher close to bagging Anglo mines

    Apollo Global Management is said to be in exclusive talks to buy Anglo American's metallurgical coal mines in Australia.

    According to the Financial Review, the  Grosvenor and Moranbah mines could fetch around $1 billion and the private equity firm could sign a deal within two weeks:

    Apollo is working in a heavyweight consortium with Pennsylvania coal exporter Xcoal Energy & Resources, the largest exporter of coal in the United States and founded by coal legend Ernie Thrasher.

    Downsizing  may no longer be the right strategy for Anglo with metallurgical coal prices doubling during the third quarter

    The Queensland-based operations have been up for sale since February, when chief executive officer Mark Cutifani outlined a radical divestment strategy to generate between $3bn and $4bn from asset sales this year to drive down debt.

    Other firms have also circled the coal mines at various stages of the process, including BHP Billion  through its joint venture with  Japan's Mitsubishi, South32, Glencore and US-based Coronado Coal, with varying reports as to which remain in contention.

    Earlier this year, Anglo sold its 70% stake in Foxleigh coal mine, also located in Queensland, to a consortium led by Taurus, an Australian fund manager that invests in the commodities industry. The sale amount was not disclosed.

    Some observers have commented that downsizing  may no longer be the right strategy for Anglo with metallurgical coal prices doubling during the third quarter, iron ore 50% above its December lows and a broad improvement in base metal prices.

    Metallurgical coal was exchanging hands at $213.40 on Monday according to data provided by Steel Index as it consolidates at higher levels following weeks of panic buying not seen since 2011, when floods in key export region in Queensland saw the price touching to $335 a tonne.
    Back to Top

    Indonesian coal miner Bumi posts record loss of $1.9 bln

    Indonesian coal miner PT Bumi Resources Tbk reported a record loss of nearly $2 billion for 2015 on Tuesday, mainly due to asset impairments and write-offs for its receivables.

    Bumi's net loss of $1.9 billion for the year ended Dec. 31, 2015 was far wider than a revised loss of $370.5 million for 2014. That was the biggest annual loss it ever posted, according to Thomson Reuters data.

    Bumi, part of the Bakrie Group conglomerate, has been struggling to service its debt as an oversupply of coal and weaker demand from China hurt its cash flow. The coal miner had previously delayed the release of its 2015 financial results.

    Bumi made a loss of $885.5 million due to asset impairments and $522.6 million as a result of writing off receivables, it said in a filing to the Jakarta stock exchange. Revenue fell to $40.5 million from $61.9 million.

    Bumi impaired Gallo Oil, which operates two oil and gas exploration concessions in Yemen, "owing to stressed market and economic conditions in the sector," Bumi director Dileep Srivastava said in a text message.

    Other assets impaired include coal mines on the Indonesian island of Sumatra, Srivastava said. The company also wrote off some receivables from Indonesian company Bukit Mutiara due to its "potential insolvency", he said.
    Back to Top

    India expects SAIL/ArcelorMittal JV to start production in two years

    India expects a joint venture between state-owned Steel Authority of India Limited (SAIL) and ArcelorMittal to start producing automotive-grade steel in two years, a government official said on Tuesday.

    Officials from the two companies are due to meet on Thursday to take forward talks about a proposed 60 billion rupee ($902 million) plant that will produce 1.2 million tonnes of steel per year to begin with, Steel Secretary Aruna Sharma told Reuters.

    SAIL and ArcelorMittal, the world's largest steel producer, signed a preliminary agreement in May last year to expand in what is one of the world's fastest growing steel markets and a major car exporter.

    "In another two years it should be in the manufacturing stage, provided we freeze everything within one and a half months and in December we take off," Sharma said. "We will go more for import replacements. We have solutions for it."

    She said the government was working on raising demand for steel in India - whose per-capita consumption of about 60 kg is less than one-third of the global average - by replacing concrete with steel in major infrastructure projects.

    The World Steel Association expects India's steel demand to rise 5.4 percent this year and next, even as countries such as China see a decline. (

    Apart from ArcelorMittal, India's growing steel demand is also keeping other major companies such as South Korea's POSCO interested, despite regulatory hurdles and difficulties acquiring land.

    Sharma, who moved to the steel ministry more than two months ago, has already met POSCO officials who are eager to expand in India despite the de facto scrapping of the company's proposed $12 billion steel plant in the eastern state of Odisha after a decade of protests over land.

    "They will like a plug-in kind of an arrangement (to set up a new plant)," she said.

    Sharma also said that to protect the domestic steel industry from cheap imports, the government may impose provisional anti-dumping on 21 products within two weeks.

    Top Indian steel makers such as JSW Steel Ltd, Tata Steel Ltd and Jindal Steel & Power Ltd have lobbied the government hard to take more measures to protect their margins from cheap imports from China, Japan and South Korea.
    Back to Top
    Commodity Intelligence LLP is Authorised and Regulated by the Financial Conduct Authority

    The material is based on information that we consider reliable, but we do not represent that it is accurate or complete, and it should not be relied on as such. Opinions expressed are our current opinions as of the date appearing on this material only.

    Officers and employees, including persons involved in the preparation or issuance of this material may from time to time have "long" or "short" positions in the securities of companies mentioned herein. No part of this material may be redistributed without the prior written consent of Commodity Intelligence LLP.

    Company Incorporated in England and Wales, Partnership number OC334951 Registered address: Highfield, Ockham Lane, Cobham KT11 1LW.

    Commodity Intelligence LLP is Authorised and Regulated by the Financial Conduct Authority.

    The material is based on information that we consider reliable, but we do not guarantee that it is accurate or complete, and it should not be relied on as such. Opinions expressed are our current opinions as of the date appearing on this material only.

    Officers and employees, including persons involved in the preparation or issuance of this material may from time to time have 'long' or 'short' positions in the securities of companies mentioned herein. No part of this material may be redistributed without the prior written consent of Commodity Intelligence LLP.

    © 2018 - Commodity Intelligence LLP