Mark Latham Commodity Equity Intelligence Service

Tuesday 5th July 2016
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    Eskom moves towards a more stable financial position

    Eskom has moved to a more stable financial footing after reporting results for the financial year ending March 2016 on Tuesday.

    Earnings before interest, tax, depreciation, and amortization (Ebitda) increased by 37% to R32bn owing largely to greater cost savings than anticipated (R17.5bn vs. R13.4bn). This moved Ebitda margin from 15.9% to 19.8%.

    Revenue rose 10.6% to R163.4bn and net profit for the year rose to R4.6bn from R400m in the prior year.

    Eskom said it had secured 57% of required funding for the forthcoming financial year, something which will enable the utility to add 8 600MW of new capacity from its new build programme by 2020/21. In addition, the utility had signed 65 power purchase agreements with Independent Power Producers (IPP’s) to add 4 900MW of IPP capacity through renewables during the same period.

    From an operational perspective, there was an improvement in generation performance in the second half of the year, with plant availability averaging 73.5% in the last quarter (January – March). Unplanned outages improved from an average of 16.2% in April 2015, to 11.5% in March 2016. This allowed Eskom to drastically cut the amount of money it spent on fueling the open cycle gas turbines.

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    Norway says could achieve full carbon capture and storage by 2022

    Norway says could achieve full carbon capture and storage by 2022

    By 2022, Norway could realize every step in the development of a technology many see as critical to reducing global carbon emissions, carbon capture and storage (CCS), it said on Monday.

    Oslo said it could capture carbon dioxide from an industrial plant, transport it by ship and inject it into an empty North Sea oil and gas reservoir for 4.3 billion to 7.6 billion crowns ($915 million to $515 million) by 2022.

    If it goes ahead with the plan, it could help lower carbon emissions worldwide: the International Energy Agency says deployment of carbon capture and storage (CCS) technology is critical to reducing carbon emissions but wide adoption of the technology has been frustrated partly due to high costs.

    In 2014 Canada's Saskatchewan Power opened the world's first coal-fired power plant retrofitted with CCS and there are now 15 large-scale CCS projects in operation, according to the Global CCS Institute, an Australian-based lobby.

    But the transportation and storage infrastructure is still problematic, with a large up-front investment needed.

    Oslo said it could be possible to set up every step in the process within six years, according to a feasibility study released on Monday by the Norwegian oil and energy ministry.

    "The cost for planning and investment for such a chain is estimated at between 7.2 and 12.6 billion crowns (excluding VAT)," it said in a statement, adding the cost estimates had an uncertainty of 40 percent on the lower and upper end of the scale.

    Three firms could capture gas at their plants, said the ministry: carbon dioxide at an ammonia plant run by fertiliser-maker Yara International and at a waste incinerator owned by Oslo city council, and flue gas at a cement factory owned by Germany's HeidelbergCement in southern Norway.

    The carbon dioxide could then be transported by ship, said the ministry, citing North Sea gas infrastructure operator Gassco.

    Finally it could be transported via pipeline from an onshore installation and into an empty oil and gas reservoir in the North Sea, said the ministry, citing oil firm Statoil.

    The government said it would present further CCS plans in the 2017 state budget in October.

    If the scheme goes ahead, it would be a big step for Norway: it had to drop plans in 2013 for a costly large-scale project to capture carbon dioxide that the then government once compared in ambition to sending people to the Moon.
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    Rio Tinto commits to London head office after Brexit vote

    Rio Tinto Group’s new chief executive officer pledged to keep the head office of the world’s second-biggest miner in London after Britain’s vote to leave the European Union raised fears businesses will flee.

    “No doubt whatsoever about it,”  Jean-Sebastien Jacques, a 44-year-old Frenchman who’s also a British citizen, said in an interview at the offices in St. James’s Square, a short walk from Buckingham Palace. “ Rio Tinto doesn’t do any politics.”

    British voters backed a decision to leave the EU in a June 23 referendum, driving the pound to a more than 30-year low and sending shudders through equity and commodity markets around the world. Banks including JPMorgan Chase & Co. and HSBC Holdings Plc said the result may prompt them to move thousands of jobs from London.

    “We recognize the decision of the British people,” said Jacques, who replaced Sam Walsh on July 2. “When we did look at the level of trade we do between the UK and the EU, or the EU and the UK, it is very small.”

    Jacques’ views echo those of former Rio CEO Tom Albanese, who said June 24 that the biggest miners will likely retain UK headquarters. Albanese, now head ofVedanta Resources Plc, said Britain offers benefits for resource companies.

    “The direct impact on us is very small,” Jacques said. “However, we will continue to monitor the situation for obvious reasons in the coming weeks, months and years.”
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    Thyssenkrupp looking at further shakeup of Industrial Solutions

    German industrial group ThyssenKrupp is considering a further shakeup of its Industrial Solutions unit, which it is restructuring in the face of weak demand for plant engineering from companies hit by low oil and raw-material prices.

    Jens Michael Wegmann, the unit's chief executive, told reporters on Monday that Industrial Solutions - whose activities range from shipbuilding to mining technology to automotive engineering systems - aimed to increase sales from its services business to around a third from 13 percent now, but did not say by when. Its service business is more profitable than construction.

    To that end, it will need to redistribute its Germany-focused workforce more evenly around the world, establishing three or four project management competence centres to be closer to customers around the world, Wegmann said, speaking at ThyssenKrupp's headquarters in Essen.

    He said he could not yet detail what this would entail in terms of cost or job cuts but ThyssenKrupp is consulting with employee representatives and aims to complete the review by the autumn.

    "Our culture is too much focused on acquiring big projects," Wegmann said. "The people who do that don't have the right mindset to win service contacts."

    "German engineering is still a brand in the world but it's not enough on its own - you have to be close to the customer."

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    Low scrap metal prices hurting even U.S. garbage scavengers

    Erica spends four hours daily walking miles of Milwaukee streets and alleys, digging through garbage and stuffing her red plastic grocery cart with aluminum cans and other small metal items to sell to support her three children.

    The 34-year-old scavenger has had to work longer and harder over the past year, underlining how a drastic decline in scrap metal and commodity prices has hurt even the poor who collect discarded metal to sell to scrap yards.

    Two years ago, Erica, who declined to give her last name, would have earned about $30 for a cart full of scrap. Now she makes about $15 due to the plummeting prices.

    "It is tougher to feed my family," Erica, who wanders the streets while her children attend school. "I have to panhandle and do other things to make ends meet now, or make more trips."

    Prices have fallen mainly because of a downturn in global demand from manufacturers, especially in China, pressure on supplies, and the increased use of substitutes, said Joe Pickard, chief economist and director of commodities at the Institute of Scrap Recycling Industries.

    "We get really walloped when all of those things are combined," he said.

    An index kept by the trade organization showed a downward trend in ferrous scrap metal commodity prices for several years until a plunge in 2015 made it probably the industry's worst year in decades, if not a generation, Pickard said.

    For example, the price for industry benchmark No. 1 heavy melt scrap metal was about $500 a ton in 2008 before sliding to about $330 at the beginning of 2015. It then fell to about $170 by the end of the year, Pickard said.
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    Oil and Gas

    World’s Top Oil Trader Says Prices Won’t Rise Much Further

    Oil prices won’t rise much further over the next year and a half as demand growth slows and refiners comfortably meet gasoline consumption, according to the world’s largest independent oil-trading house.

    "I cannot see the market really roaring ahead," Vitol Group of Cos. Chief Executive Officer Ian Taylor told Bloomberg Television in an interview. "We have a lot of oil in the system and it will take us considerable time to work that off."

    Since rallying from a 12-year low of $27.10 a barrel in January, Brent crude has been hovering around $50 a barrel for the last month. The international benchmark will probably end the year “not too far away from where we are today" and rise to about $60 by the end of 2017, Taylor said.

    The forecast, which coincides with a similar view from Goldman Sachs Group Inc., would mean oil-rich countries and the energy industry face a prolonged period of low prices, more akin to the 1986 to 1999 downturn than the swift recovery after the 2008 financial crisis. Vitol trades more than 6 million barrels a day of crude and refined products -- enough to cover the needs of Germany, France, Italy and Spain together -- and its views are closely followed in the energy market.

    Taylor, who has traded oil for nearly four decades, said one-off factors, including supply disruptions and stronger-than-expected demand growth, helped to tighten the market in the first half, lifting prices.

    Demand Growth

    "We probably expect demand growth to be slightly less in the second half of the year," he said. "There is a little less pull from the Far East” and basic Chinese refineries, known as teapots, seem well satisfied after having “overbought” crude in the first months of the year, he said.

    The summer driving in the U.S. may not be so bullish for oil because "the refinery system of the world has clearly been able to make enough gasoline, and the gasoline stocks are healthy,” Taylor said.

    U.S. wholesale gasoline futures for August delivery -- traditionally the peak of the driving season -- traded at $1.50 a gallon in New York at 12:01 p.m. Monday, below the price for futures to delivery in September, suggesting current supplies are plentiful. "We don’t see any shortages of gasoline," Taylor said.

    Supply Disruptions

    At the same time, "most of the disruptions are beginning to correct themselves," such as wildfires that halted Canadian output, Taylor said.

    The oil price outlook is unlikely to change significantly in 2017 as supply from new oilfields, including the super-giant Kashagan in Kazakhstan and others in the U.S. Gulf of Mexico, offset production drops elsewhere, Taylor said. The wild card for next year is U.S. shale supply, which appears to have reached a bottom, but it’s too early to say whether growth will resume.

    U.S. oil production was hit hard by the plunge in oil prices after the Organization of Petroleum Exporting Countries diverged from its traditional policy of adjusting supply to manage prices, announcing in late 2014 that it would maintain output to defend its position in the market. The nation pumped 8.6 million barrels a day last month, down from a peak of 9.6 million in June 2015.

    Vitol, which celebrates its 50th anniversary this year and is owned by its employees, didn’t made as much money in the first half of the year as in the same period in 2015, Taylor said. It earned $1.6 billion last year, the most since 2011, as it profited from price swings in the energy market.

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    Rystad: US oil reserves larger than Saudi.


    July 04, 2016

    By Per Magnus Nysveen, Head of Analysis, Rystad Energy

    A new independent estimate of world oil reserves has been released by Rystad Energy, showing that the US now holds more recoverable oil reserves than both Saudi Arabia and Russia. For US, more than 50% of remaining oil reserves is unconventional shale oil. Texas alone holds more than 60 billion barrels of shale oil according to this new data.

    The new reserves data from Rystad Energy also distinguishes between reserves in existing fields, in new projects and potential reserves in recent discoveries and even in yet undiscovered fields. An established standard approach for estimating reserves is applied to all fields in all countries, so reserves can be compared apple to apple across the world, both for OPEC and non-OPEC countries. Other public sources of global oil reserves, like the BP Statistical Review, are based on official reporting from national authorities, reporting reserves based on a diverse and opaque set of standards.

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    Hedge funds to U.S. refiners: produce more diesel, less gasoline: Kemp

    Hedge funds and other money managers are betting diesel and heating oil will take over from gasoline as the main driver of U.S. refinery profitability in the second half of the year.

    For the past 18 months, refiners have been rewarded for maximising output of gasoline and minimising production of diesel, but that could all be about to change.

    By the middle of June, hedge funds had accumulated the largest net long position in heating oil futures and options since oil prices began to slump in July 2014.

    At the same time, hedge funds were running one of the smallest net long positions in gasoline contracts in the past decade.

    The most recent data published by the U.S. Commodity Futures Trading Commission shows some profit-taking on these positions in the week to June 28.

    But the strongly bullish position on heating oil and bearish position on gasoline remains fundamentally intact for the time being.

    At the start of the year, hedge funds were bearish towards heating oil and bullish on gasoline, but the position began to switch from March onwards.

    The switch in hedge fund positions has coincided with a marked strengthening in the refining margins for diesel and weakening of those for gasoline.

    The gross refining margin for diesel for October is now 35 cents per gallon compared with just 23 cents per gallon for gasoline (

    Despite record consumption of gasoline, refiners have struggled to work down the excess stockpiles that built up in January and February.

    Gasoline stocks remain close to the highest level for a decade even after adjusting for current record rate of demand(

    Gasoline stocks are currently equal to 24.6 days worth of consumption, down from 29.2 days at the end of January, but still well above the 22.7 days at this point last year and the 10-year average of 22.9 days.

    By contrast, the enormous overhang of diesel stocks that built up at the start of the year has been steadily reduced over the last two months (

    Diesel stocks have dropped from almost 50 days worth of consumption at the turn of the year to 39.3 days although they are still well above the 34.5 days this time last year and the 10-year average of 31.9 days.

    During the summer driving season, gasoline stocks normally fall while diesel stocks rise, as refiners run hard to produce motor fuel and find themselves with too much distillate as a by-product.

    But this year gasoline stocks show little signs of reducing while diesel stocks are exhibiting an unusual seasonal decline.

    Counter-seasonal stock movements suggest the U.S. market is on course to have surplus gasoline and not enough distillate once the summer driving season is over. Margins are adjusting accordingly.

    Hedge funds and futures prices are also anticipating stronger demand for diesel during the winter of 2016/17 after unusually weak demand over the winter of 2015/16.

    El Nino, which contributed to an unusually warm winter in parts of North America during 2015/16, is now giving way to La Nina.

    The unusually warm winter temperatures experienced last winter are unlikely to be repeated in the coming winter which should increase consumption of heating oil.

    Diesel demand should also get a boost from an eventual recovery in the freight market, provided the U.S. and global economies manage to avoid recession.

    Freight remains sluggish, but U.S. manufacturers, distributors and retailers do at last seem to be starting to get a grip on excess inventories, which could herald an eventual improvement.

    The realignment of gasoline and diesel margins seems to have a solid grounding in supply-demand-stocks fundamentals.

    The big problem is the large concentration of hedge fund positions, which makes the market vulnerable if they all attempt to unwind at the same time.

    With hedge funds already so bearish on gasoline and bullish on heating oil, and margins already having moved significantly, the risk now is that margins will recoil as the funds try to take some profits.

    Profit-taking already seems to have started in the final week of June but could still have some way to run.
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    Top Indian Refiner Plans $6 Billion Expansion as Demand Climbs

    Indian Oil Corp. will spend about 400 billion rupees ($6 billion) to boost capacity by almost 30 percent in the next six years to feed the booming fuel demand in the world’s second-most populous nation.

    “Fuel demand is rising and India’s excess capacity is very small,” Sanjiv Singh, director of refineries at India’s biggest processor, said in an interview Friday. “We all need to expand if demand sustains.”

    The expansion comes as Indian refiners are racing to add capacity amid rising fuel consumption. India is poised to surpass Japan as the world’s third-largest oil user this year and will be the fastest-growing crude consumer in the world through 2040, Paris-based International Energy Agency estimates.

    The state-run company aims to increase its capacity to about 104 million metric tons a year, or about 2 million barrels per day, over the next six years by expanding the existing refineries across the country, said Singh.

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

    India’s oil demand is forecast to reach 329 million tons by 2030, according to IEA. The country’s 23 refineries have a total capacity of 230 million tons a year, while total fuel demand was 183.5 million tons during the financial year that ended March 31, according to the oil ministry.

    Adding Capacity

    “In another 15 years, India should be adding another 100 million ton refining capacity,” Singh said. “By 2030, India would easily cross as much as 340 million-ton capacity.”

    Separately, Indian Oil is working with the government as well as other refiners to build a 60-million-ton-a-year refinery on the west coast. The proposed project, which would include petrochemical units, may cost about 2 trillion rupees, Singh said.

    They will build the refinery in two phases, with two crude units totaling 40 million tons in the first phase and a third one in the second phase, he said. “After getting possession of the land, it will take five to six years to complete the first phase,” he said.
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    India Demand Surge Sucks Up LNG Otherwise Meant for Europe

    India’s burgeoning demand for liquefied natural gas is dictating how many tankers make it to Europe, the world’s dumping ground for the fuel.

    LNG imports to India jumped 43 percent in May from a year earlier, a contrast to western Europe where shipments have stagnated over the past three months. The world’s second-most populous nation is expected to double its LNG intake over the next four years, according to energy consultants Wood Mackenzie Ltd.

    India overtook South Korea as the second-biggest buyer of spot and short-term LNG cargoes after prices crashed about 65 percent in almost two years, spurring demand for the cleaner fuel from fertilizer producers to power plants. For a supplier, having a closer market helps. It takes three days to ship LNG to western India from Qatar, the biggest producer of the fuel, compared with two weeks to get it to the U.K. where prices are lower.

    “India needs to be full before you start getting LNG imports in Europe going up,” Noel Tomnay, vice president of global gas and LNG research at Wood Mackenzie, said in an interview in London. “We haven’t seen a significant uptick in European LNG imports yet. What we have seen is a significant uptick in India.”

    The nation gets the fuel from Qatar at about $5 per million British thermal units, according to Petronet LNG Ltd., India’s biggest importer. That compares with $4.37 on average at Britain’s National Balancing Point trading hub in the second quarter, data from the ICE Futures Europe exchange in London show.

    “The NBP is below the western Indian market price, and that should gravitate the spot cargoes toward India,” Prabhat Singh, the chief executive officer of Petronet, said in an interview in New Delhi on June 30. “India is the place for world LNG to come if we handle the market well.”

    Import Surge

    India’s imports of cargoes under contracts with duration of four years or less rose 45 percent to 9.7 million tons in 2015, according to the International Group of LNG Importers. The country imported 14.6 million tons of LNG last year, little changed from a year earlier, according to the group.

    In May, the nation purchased a total of 2.08 billion cubic meters of LNG, or 1.57 million tons, according to provisional data from the Oil Ministry’s Petroleum Planning & Analysis Cell. That compares with 3 billion cubic meters imported into western Europe, a figure that’s slated to fall to 1.25 billion cubic meters in June, according to consultants Energy Aspects Ltd.

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    Western Europe is poised to take a bigger share of LNG imports “over the coming quarters” thanks to the region’s liquid trading hubs capable of absorbing excess LNG from the global markets, according to Fitch Ratings Ltd.’s BMI Research unit. Global supply is set to soar from the second half of this year as plants from the U.S. to Australia and Angola increase production, pressuring prices, BMI said in a June 30 research note.

    Stretched Infrastructure

    Increased deliveries have stretched India’s existing infrastructure. The Dahej terminal this year is running at an estimated 111 percent of its designed nameplate capacity and will be operating at 120 percent over the next six months, according to Petronet, which operates the facility. The company plans to complete an expansion of the terminal by September.

    India’s LNG price is forecast to fall to $4.8 per million Btu on average this year and $4.6 in 2017, down from $7.5 last year, according to Energy Aspects.

    “We have seen demand elasticity in India and it’s starting to stretch regas capacity,” said WoodMac’s Tomnay. “It is interesting to see how tested India will be as Asia’s natural sink.”

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    New Rival Seen in Mediterranean Gas Race ‘Before It’s Too Late’

    Lebanon may soon approve measures to push ahead with a stalled first auction of offshore oil and natural gas rights, ending years of political wrangling as it tries to catch up in a regional race to tap energy wealth in the eastern Mediterranean.

    The auction first scheduled for November 2013 was frozen by the government’s failure to pass decrees to demarcate energy blocks, establish production-sharing contracts and specify tender protocols. Mohammad Kabbani, head of the parliamentary energy committee, said Monday that he expected the decrees to be approved “a short period” after the Muslim holidays of Eid al-Fitr this week.

    “This would be the first serious step in three years,” Kabbani said in a phone interview in Beirut, without elaborating on the possible timing of an approval. “We should hurry up to be present in the market before it is too late.”

    Lebanon has lagged behind neighboring Israel, Cyprus and Egypt in developing oil and gas deposits that may lie beneath its share of the Mediterranean Sea. Seismic surveys show the country could hold at least 96 trillion cubic feet of gas and 850 million barrels of oil, then-Energy Minister Gebran Bassil said in a December 2013 interview. Exxon Mobil Corp. and Total SA are among 46 companies pre-qualified to bid to explore off the country’s coast.

    Lebanon has had no president for more than two years, and government institutions have been paralyzed by political divisions and sporadic violence that have deepened since the war in Syria erupted in 2011. Lebanon needs revenue to trim its public debt, the highest as a share of annual economic output among 22 Arab nations.

    A breakthrough to enable the energy auction looks close, partly because a dispute has been settled over which of 10 blocks should be awarded, Kabbani said. Companies will be allowed to bid for the blocks they want, and the government will then approve two or three, he said.

    The possibility that Lebanon shares offshore gas reserves with Israel adds urgency to the effort, Kabbani said. Turkey and Israel ended years of diplomatic estrangement in June, opening the way for Israel to export fuel to the Turks from its offshore Leviathan field. “We have to prove we are here and we are serious,” Kabbani said.
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    Two Eni workers killed in Niger Delta attack

    Two oil workers working for Italian major Eni were killed after their boat came under fire in the Niger Delta last week, it has emerged.

    The men were travelling in what is believed to have been a workboat in Bayelsa State when they came under fire some time on Wednesday.

    A spokesman for Eni told Upstream that the team from local subsidiary Agip was on its way to a well location to carry out a routine operation in the Nembe area when it was attacked.

    “Three members of the team managed to escape, reaching the near flow station, while another two were missing.

    “Two days later their bodies were found. Investigations with security agencies were immediately undertaken and are still ongoing.”

    One source said the workers were on their way to the Obiama flow station when they were attacked around Okoroma waterway. The source added that the boat may have had no escort, which is not advisable in the locality.

    Some local reports have linked the Niger Delta Avengers (NDA) with the attack, although this would be a significant departure from their current modus operandi of attacking oil infrastructure such as wells and pipelines, while refraining from killings.

    The NDA has routinely claimed attacks through posts on its internet page or Twitter. However, the militant group’s Twitter account was disabled on Monday morning, but not before it used it to claim five attacks on infrastructure belonging to Chevron, Nigerian National Petroleum Corporation (NNPC) and Nigerian Production Development Company (NPDC) between Friday and Sunday.

    Attacks on oil companies this year has spiked in Nigeria’s oil-producing region due in some measure to political tensions and the continued low oil price. Information from Norwegian risk analysis firm Bergen Risk Solutions shows that there have been 65 incidents in the Niger Delta so far this year involving international oil players, compared with 42 for the whole of 2015.
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    Gulf Keystone debt default

    Gulf Keystone, struggling oil explorer told the market it had defaulted on its $26m April debt payment, but remains in crunch talks with its lenders.

    After Gulf Keystone failed to pay its April debt coupon its bondholders granted repeated extensions to its stay of execution. The oil producer has technically been in default since May but it has used a ‘stand-still’ period to shield itself from insolvency proceedings while it negotiates a rescue deal with its lenders.

    The freeze agreement expired on Friday evening and the company said it would not extend the stand-still period, or make the outstanding debt coupon payment, raising speculation that a deal with its lenders may be imminent.

    Gulf Keystone said its “restructuring discussions remain ongoing” with the bondholders and a further announcement would be made in due course, but a company spokesman declined to comment further.

    A deal to restructure its debt is expected to deliver a heavy blow to existing Gulf Keystone shareholders, who have already seen the stock plummet from 410p in early 2012. The company has been hit hard by the oil market crash and geopolitical tensions in the Iraqi region, which have crimped oil payments from the local government.

    In addition to April’s $26m debt coupon Gulf Keystone is due to make another $26m payment in October before repayments rocket to $250m in April 2017 and $325m in October next year.
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    Ecopetrol takes over Cusiana operation

    Colombian state-oil player Ecopetrol has taken over operations at the large light oil and gas condensate field Cusiana after ending a long-term contract with partners Equion Energy and Emerald.
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    Total reshuffles management in renewables drive

    French oil major Total has moved the head of its refining and chemicals arm to run its newly created gas, renewables and power division as the group strives to become a leading renewables and electricity player within 20 years.

    The appointment of Philippe Sauquet to oversee Total's expansion in renewables makes room for Bernard Pinatel to return to the company as president of the refining and chemicals arm.

    Pinatel returns from Bostik, a former Total subsidiary that was sold to Arkema. He was a member of Total's refining and chemicals management committee from 2012 to 2014.

    Pinatel will join Total's executive committee, as will Namita Shah, who was appointed executive vice president and will take charge of Total's human resources division and oversee the newly created Total Global Service.

    The new appointments will take effect from Sept. 1.
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    Nigeria's oil minister replaced as state oil company boss

    Nigerian President Muhammadu Buhari has replaced Oil Minister Emmanuel Ibe Kachikwu as group managing director of state oil company NNPC as part of a wider board overhaul.

    Oil accounts for about 70 percent of Nigeria' revenue, but the OPEC member has been hit hard by a prolonged drop in crude prices that has caused the deepest crisis in Africa's biggest economy for more than a decade.

    Dr Maikanti Kacalla Baru, previously group executive director for exploration and production, will take the reins from Kachikwu, who will remain on the board as chairman, the president's spokesman said on Monday.

    Buhari, elected last year, has accused the previous administration of failing to save when crude oil cost more than $100 a barrel. In 2013 the central bank governor said that tens of billions of dollars in oil revenue had failed to make it into state coffers, which the company denied.

    Kachikwu was appointed minister of state for oil last year, making him a junior minister, while Buhari kept the petroleum minister portfolio for himself in order to oversee energy sector reforms.

    Baru's previous roles at the state oil company included a six year stint, from 1993 to 1999, as an executive at the National Petroleum Investment Management Services (NAPIMS), an NNPC subsidiary, where he worked on gas-related projects.

    "President Buhari urges the new board to ensure the successful delivery of the mandate of NNPC and serve the nation by upholding the public trust placed on them in managing this critical national asset," said Buhari's spokesman Femi Adesina.

    The president's chief of staff, Abba Kyari, joins the new board, which replaces the one dissolved by Buhari in June last year.

    "Reconstituting the board appears to be an attempt to adopt a different approach with a sense of proper oversight and accountability," said Antony Goldman, head of Nigeria-focused PM Consulting.

    "The issue in the past has been that NNPC has been involved in deals that benefited certain individuals but not Nigeria as a whole," he added.

    Kachikwu, a former Exxon Mobil executive, was brought in by Buhari as head of NNPC last August and was named as minister of state for oil when his cabinet was appointed a few months later.

    Rolake Akinkugbe, head of energy and natural resources at FBN Capital, said there was "always a question around how you could have the head of the national oil company who was also the oil minister".

    "Being moved to chairman, where he will not be involved in day-to-day operations but retains strategic input, helps to resolve that issue," she said.
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    Gran Terra launches $525m bid for third Colombian acquisition this year

    Calgary,Alberta-based oil and gas major Gran Tierra Energy has launched a $525-million bid to acquire independent exploration and production company PetroLatina Energy, marking the company’s third multi-million dollar push this year into Colombia.

    Under terms of the acquisition agreement,Gran Tierra would make an initial $500-million cash payment at closing, and a deferred payment of $25-million before December 31.

    "The acquisition represents a unique material opportunity inColombia in terms of scale and upside potential, and will add a new core area for Gran Tierra in the prolific MiddleMagdalena Basin. The combination of Gran Tierra's strong, positive cash-flowing asset base and PetroLatina's attractive portfolio of development opportunities will create a premierColombia-focused exploration and production company,”Gran Tierra president and CEO Gary Guidry stated.

    Gran Tierra advised that the acquisition was expected to be funded through a combination of the comany’s current cash balance, available borrowings under existing credit facilities, a new $130-million debt facility, and a private placement of up to $173.5-million of subscription receipts priced at $3 each. Each receipt would entitle the holder thereof to one share of common stock in the capital of the corporation. The pricing reflected a 7.9% discount from the five-day volume weighted average price of $3.26 a share.

    Guidry pointed out that Gran Tierra was acquiring significant proved, probable and possible reserves in a new core area in the Middle Magdalena basin, which he expected to enhance the company’s long-term growth strategy and to be a fit withGran Tierra's current reserves and resources base in the Putumayo basin.

    The transaction was expected to provide Gran Tierra with a significant growth platform in the Middle Magdalena basinwith significant proved plus probable (2P) reserves additions of 53-million barrels (100% oil), increasing Gran Tierra's pro forma December 31, 2015 2P reserves by 70% to 129-million barrels of oil equivalent.

    The PetroLatina deal was expected to close by October 31.

    Earlier this year, Gran Tierra completed the acquisitions ofPetroamerica Oil Corp and PetroGrenada as part of its corporate strategy to expand and diversify Gran Tierra's oil and gas growth portfolio in Colombia.

    In May, the company increased its 2016 capital budget by between $33-million and $43-million to a range of $140-million to $150-million, from the previously budgeted $107-million.

    Despite the TSX-listed stock being down as much as 5.5% on Monday at C$4.12 apiece, the stock had gained more than 41% since the start of the year, buoyed by more optimistic crude oil prices.
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    Petrobras to sell 'junk' fields as big finds delayed: sources

    Petrobras' plans to sell 'junk' oil fields off the coast of Brazil's Sergipe and Ceara states will do little to boost the economic prospects of the regions, hampered by company cutbacks and delays at larger discoveries nearby, sources said on Monday.

    Brazil's state-owned oil company on Monday said it plans to sell nine shallow-water oil fields that produce a total of 13,000 barrels of oil and equivalent natural gas a day from multiple wells.

    Furthermore, the sale of the fields, among Brazil's oldest, will not significantly cut the debt of Petroleo Brasileiro SA as the company is formally known, the sources said. Petrobras' $126 billion of debt is the largest in the world oil industry.

    Not only do the fields produce very little oil or natural gas compared to other Petrobras assets, the sources said, their age will require substantial investment to maintain commercially viable output, a situation made more difficult by oil prices near decade lows.

    Additionally, the ageing wells come with large future costs for safe closure under environmental and other laws.

    "The fields are junk," one of the sources said. "Unless Petrobras shoulders the labor-related costs of selling the fields and laying off workers and some of the shut-in costs that will come sooner rather than later, the fields offer little upside even though almost anybody can run them cheaper than Petrobras."

    The sources, who asked for anonymity because their dealings with Petrobras are confidential, have either direct knowledge of the fields up for sale or were briefed on the proposed sale on Monday by Petrobras chief executive Pedro Parente.

    Petrobras announced the sale hours after Parente met with Sergipe officials to explain the company's cutbacks at low-output onshore fields in the state.

    He also addressed repeated delays in developing giant offshore discoveries it owns with Indian companies Oil and Natural Gas Corp and IBV Brasil Ltda, a 50-50 joint venture between Bharat Petroleum Corp and Videocon Industries Ltd, a source at the briefing said.

    Earlier on Monday, Reuters reported that Petrobras told IBV in April that oil output at the Sergipe offshore areas would be delayed until 2022, four year later than promised. The Indian partners have invested $2.1 billion in the giant deepwater fields near the state.

    The prospects owned by Petrobras and the Indians dwarf the rapidly declining Sergipe onshore and shallow water fields and are among the world's largest discoveries in decades. Sergipe gets about a quarter of its industrial output from Petrobras.

    "We're stuck," one of the sources said. "Petrobras is cutting crucial investment and thousands of jobs in Sergipe and can't or won't invest in new discoveries that could transform people's lives here. The shallow water sales, even if they happen, won't help much."

    Parente has promised to sell or slash investment and sell assets in underproducing areas to focus the company's limited cash on the so-called "subsalt" region near Rio de Janeiro. Some single wells in the subsalt produce 40,000 barrels a day, among the highest levels ever seen in offshore development.
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    Base Metals

    Chile's copper output falls in May on lower ore grades

    Chile’s copper production declined 6.8% year-on-year in May on lower ore grades, the country's national statistics institute, INE, said.

    Output totalled 473,825 tonnes in May, according to preliminary figures from INE. This compares with 508,135 tonnes in the corresponding month of 2015...
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    BHP Billiton digs deep at Escondida copper mine in Chile

    BHP Billiton has approved an ­effective plant expansion at the giant Escondida mine in Chile that will provide an extra 150,000 tonnes of annual copper production for a development spend of just under $US200 million ($266m), in a prime example of chief Andrew Mackenzie’s push to unleash low-cost latent capacity.

    The approval, which reverses a previous decision to demolish the Los Colorados concentrator at ­Escondida to gain access to high-grade ore, was revealed by BHP’s new head of American mining operations, Daniel Malchuk, in an interview with The Australian.

    The Santiago-based Mr Malchuk said BHP remained keen on copper from a market perspective and would still be prepared to make acquisitions in the metal if the right assets came to market during the current downturn.

    And, he said the company would consider buying partner Anglo American out of the Cerrejon coalmine in Colombia at the right price. Saving the Los Colorados concentrator at Escondida, the world’s biggest copper mine, is part of Mr Mackenzie’s plan to squeeze more from existing assets and increase BHP production by 10 per cent, by spending $US1.5 billion activating latent capacity.

    By overhauling and keeping Los Colorados, BHP will capture 100,000 tonnes of daily ore processing capacity for less than $US200m.

    That is less than one-tenth the capacity cost of the 150,000 tonnes-per-day Organic Growth ­Project 1 concentrator, approved at a cost of $US3.8bn in 2012, originally planned to go after the high-grade ore located under Los ­Colorados.

    “This is amazingly high capital efficiency,” Mr Malchuk said of the Los Colorados extension. “As you can imagine the return is very high — it’s north of 100 per cent.”

    No extra mining will be required; instead more ore will be processed through the concentrators, rather than sent to Escondida’s sulphide leach circuit, where rates of copper recovery from ore are about half that of the ­concentrators. The Los Colorados extension was approved by the Escondida partners, BHP (which owns 57.5 per cent), Rio Tinto (30 per cent) and Japan’s JECO (12.5 per cent) on June 30, just meeting a previously announced 2016 ­financial-year target.

    It was not publicly announced because the development spend was kept low enough not to cross the threshold BHP and Rio deem to be significant.

    Mr Malchuk took over as copper boss in March 2015 and was made president of the Minerals Americas unit under a BHP restructure earlier this year that separated operations heads from corporate functions, like finance and human resource.

    The same restructure saw coal boss Mike Henry made president of Minerals Australia.

    Mr Malchuk said BHP was still prepared to make copper acquisitions, in addition to the latent ­capacity expansions, if the right opportunity presented.

    “The kind of assets we are interested in — there are not too many around,” he said.

    “And we haven’t yet seen a significant opportunity in terms of those assets being placed in the market.”

    The Americas mining boss also said there was the potential for BHP to increase its interest in the Cerrejon coalmine in Colombia, following Anglo American’s recent announcement that it wanted to sell out of the three-way joint venture with BHP and Glencore.

    “We haven’t had those conversations yet, but we will be open to see how this situation evolves and see if there is an opportunity for us,” Mr Malchuk said.

    The “three concentrator strategy” at Escondida, under which Los Colorados will be retained, was first flagged in late 2014.

    The previous plan had been to pull down Los Colorados, enabling access to higher grade ore once the OGP 1 concentrator was finished last year.

    But through some innovative mine planning, which included making the pit wall steeper, higher-grade ore will now be accessed without demolishing Los Colorados until at least 2030.

    That effectively gives Escondida average extra annual copper production of 150,000 tonnes and helps keep costs near $US1 per pound as the big mine’s overall grades ­decline.

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    Steel, Iron Ore and Coal

    PWCS coal exports to China down 36 pct on mth

    Australian coal exports from the Port Waratah Coal Services terminals at Newcastle to China fell 36% on the month to 1.03 million tonnes in June from a 16-month high of 1.6 million tonnes in May, PWCS said on July 2 in an operating report.

    The exports to China were the lowest seen from the terminals in a month since March, but well above the 0.58 million tonnes seen in January, port data showed.

    Month-on-month declines in exports were also seen to key destinations of Japan, South Korea and India.

    After China, the second sharpest fall came in exports to Japan — which gets the lion’s share of Newcastle exports — with 3.99 million tonnes shipped in June, down 9% from 4.38 million tonnes in May, PWCS data showed.

    Japan’s year-to-date average of 4.25 million tonnes lagged 2015’s monthly average of 4.54 million tonnes.

    Japan has received 48% of all Newcastle coal exports for the year to date, with South Korea taking 13%, China 12% and India 1.1%, the Monthly Exports Statistics report said.

    PWCS coal exports to South Korea were relatively stable on the month at 0.92 million tonnes in June, compared with 0.93 million tonnes in May.

    This is well below the 1.79 million tonnes in June last year. South Korea’s year to date monthly average was at 1.14 million tonnes, down 0.31 million tonnes from the 2015 average.

    There were no coal cargoes exported to India in June — the second time this has happened this year. In May, 0.034 million tonnes was exported, while the year-to-date monthly average was at 0.10 million tonnes, in line with the 2015 average.

    Total coal exports from the PWCS terminals at Newcastle in June were 8.31 million tonnes, down from 9.38 million tonnes in May, the data showed.

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    CIL Jun output down 6.17pct on month

    Coal India Ltd (CIL), India's biggest producer of thermal coal, produced 42.72 million tonnes of coal in June against a target of 43.31 million tonnes, falling 6.17% from May and helping to ease the glut accumulating at the company's mines.

    Its deliveries for June stood at 44.96 million tonnes, against a target of 47.52 million tonnes.

    CIL has boosted output at a record pace over the past two years and the government has urged state power generation companies to buy local coal and reduce imports.

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    Indonesia’s Jul HBA thermal coal price up 2.3pct on month

    Indonesia's Ministry of Energy and Mineral Resources set its July thermal coal reference price, also known as Harga Batubara Acuan or HBA, at $53/t FOB, up 2.3% from June, but down 10.4% compared with the same month last year.

    The HBA is a monthly average price based 25% on the Platts Kalimantan 5,900 kcal/kg gross as received assessment; 25% on the Argus-Indonesia Coal Index 1 (6,500 kcal/kg GAR); 25% on the Newcastle Export Index -- formerly the Barlow-Jonker index (6,322 kcal/kg GAR) of Energy Publishing -- and 25% on the globalCOAL Newcastle (6,000 kcal/kg NAR) index.

    The HBA for thermal coal is the basis for determining the prices of 75 Indonesian coal products and for calculating the royalties Indonesian producers have to pay for each metric ton of coal they sell locally or overseas.

    It is based on 6,322 kcal/kg GAR coal, with 8% total moisture content, 15% ash as received and 0.8% sulfur as received.
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    Rio Tinto sells Australian coal mine for a dollar

    A small Australian miner on Monday bought Rio Tinto's Blair Athol coal mine in Queensland state for a token A$1, swooping in as big miners offload unprofitable assets after years of low coal prices.

    TerraCom Ltd, a subsidiary of Orion Mining Pty Ltd, said it will also receive A$80 million ($60.10 million) from the mining giant to meet rehabilitation costs at the site.

    Cameron McRae, TerraCom's chairman, said the mine represented a good opportunity despite weak thermal coal prices.

    "We believe that we can make a good return at the current coal prices," McRae said by telephone. "Any upside, is obviously good for us."

    Coal from Australia's Newcastle port was trading at around $52.85 per tonne last week, up from a low of under $50 earlier in June.

    The Blair Athol coal mine, which was closed in late 2012, is one of the oldest in Queensland and the second in the Bowen Basin to be sold for A$1 in the past year.

    In July 2015, Stanmore Coal paid Vale and Sumitomo Corp A$1 for the Issac Plains coking coal mine, which is about 100 kilometres (62 miles) from the Blair Athol mine.

    McRae, who worked at Rio Tinto for 28 years, said the Blair Athol Mine had a 30-year history of selling a high energy, low-in-cost coal to Asia.

    "Thermal coal is still going to be a large part of the energy mix in the future," he said.

    TerraCom plans to start more than 50 hectares (124 acres)of site rehabilitation while bringing the mine back into production.

    The company estimated more than 100 people would be employed once work started and said it hoped to be producing 2 million tones per year by the end of 2016.

    David Lennox, a resource analyst at Fat Prophets, said the rock-bottom sale price would be an advantage to TerraCom given the condition of the thermal coal market.

    "The fact they outlaid such a small capital amount will be beneficial, but they have to get their operating prices down."
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    Iron ore surges past $55 as Rio Tinto exits Simandou

    The two events may not be directly connected, but it's likely that Rio Tinto's decision to shelve its huge Simandou iron ore project in Guinea bid up the price today.

    On Monday the steelmaking ingredient ran past US$55.90 a tonne, according to The Steel Index, a gain of 3.5 percent from the previous session. Iron ore is now at its highest level since May 18, despite dropping down to $47.90 a tonne on June 2nd.

    The price is down sharply since trading within shouting distance of the $70 mark in mid-April but is back in bull territory for 2016 with a 24.5% rise since the beginning of the year, as of last Tuesday, and a 44% rebound since hitting near-decade lows in December.

    We’ve been very clear that it’s a very expensive project … in the current ­market environment we don’t see a way forward in relation to Simandou.

    Analysts at Morgan Stanley became the latest to upgrade their outlook for iron ore, although forecasts for the rest of the year still call for a steep decline in the price from current levels.

    The price increase comes as iron ore major Rio Tinto decided to put its Simandou project in Guinea on ice due to the iron ore glut that is keeping a lid on prices – despite delivering a bankable feasibility on the project in May.

    The Australian reported new CEO Jean-Sebastien Jacques saying that the cost of developing the US$20 billion mine isn't justified due to the bleak prospects for iron ore in the next decade. The incoming chief executive's position contrasts with his predecessor Sam Walsh who favoured the project, which was said to produce over 2 billion tonnes of iron ore and double the size of Guinea's economy.

    "We’ve been very clear that it’s a very expensive project. We did deliver the BFS (bankable feasibility study) to the government as per the agreement a few weeks ago and we’ve been very clear that in the current ­market environment we don’t see a way forward in relation to ­Simandou. We’ve been absolutely on record on this one. It’s not the right time to develop this project from a Rio standpoint."

    Along with its exhorbitant cost, Simandou also created headlines for accusations that BSG Resources, a rival of Rio Tinto, bribed the wife of the Guinean dictator to win control of the concession. BSG, controlled by Israeli diamond tycoon Beny Steinmetz, later sold half of its concession to Vale (NYSE:VALE), while not admitting any wrongdoing.

    Rio acquired the rights for the vast mountain deposit more than 15 years ago and has already spent more than $3 billion on the project. In February, the company swung into the red primarily due to a $1.1 billion writedownin the value of its investment.

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