Mark Latham Commodity Equity Intelligence Service

Monday 20th February 2017
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    Anglo halts asset sales as least-loved mines become cash cow

    Anglo American’s worst mines are delivering a windfall.

    Iron ore and coal prices were among the hardest hit during the commodities rout and have bounced back strongly. Now that the mines are profitable instead of bleeding cash, Anglo is scrapping plans to sell some of its biggest assets, according to people familiar with the matter.

    During the depths of the commodities crisis, when investors were questioning whether Anglo could survive, the company unveiled a dramatic turnaround plan to unload assets and pay down debt. As metal prices steadily climb higher, those fears are long gone and Anglo is preparing to report its first annual profit increase in five years.

    “With all these commodities being up right now, they are trying to milk as much cash as possible,” Yuen Low, an analyst at Shore Capital Stockbrokers, said by phone. “They might be hoping that prices will stay strong for longer than most people think.”

    If Anglo waits too long and commodity prices retreat, the company “could then be again faced with the problem of asset disposals in a seller-unfriendly environment,” Low wrote in an e-mailed note on Thursday. “But at least its debt pile would (hopefully) be significantly reduced.”

    Anglo plans to keep assets including a Brazilian nickel mine and the giant Minas Rio iron ore operation, according to people familiar with the company’s strategy. The company also plans to keep metallurgical coal assets in Australia and its stake in Cerrejon mine, Colombia’s largest thermal coal exporter, they said.

    The change in strategy will be discussed at board meetings and announced when Anglo reports full-year results on February 21, according to the people, who asked not to be identified because the information is private.

    The company is still reviewing options for reducing its exposure to South Africa. That could include selling or spinning off its majority stake in Kumba Iron Ore, as well as coal mines serving both international and domestic customers.

    Chief executive officer Mark Cutifani has said Anglo will likely pay a dividend next year and may consider expanding through deals in the future.
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    Oil and Gas

    Asian refiners receive full Saudi crude allocations for March

    Saudi Aramco's major crude oil buyers in Northeast Asia and Southeast Asia are receiving full term allocations for Saudi crude oil loading in March, according to traders contacted by S&P Global Platts this week.

    March allocations for Chinese buyers were met and traders at China's top trading companies said they were not aware of any requirements that were not met.

    Traders at several Japanese end-users also said their March requirements were met and were not aware of cuts to any company in the country.

    The same was said by the biggest crude oil importers in South Korea and Taiwan.

    Traders at oil companies in Thailand, Malaysia, the Philippines and Indonesia also said their requirements for March were fully met.

    In India, a trader at a private refiner said he was not aware of any cuts to the country's buyers. State-controlled companies did not respond to Platts queries.

    Some buyers may be receiving lower volumes in March simply because their demand has fallen in part due to refinery turnarounds, according to market participants.

    Higher-than-expected official selling price differentials set by Aramco for its Asia-bound crude oil grades loading in March, especially on the lighter grades, could have also spurred some buyers to look for alternatives, traders said.

    This made it even more unlikely for Aramco to not meet their March requirements.

    A recent Platts survey showed Saudi Arabia's crude oil production in January had fallen to 9.98 million b/d.

    That is below its allocation of 10.06 million b/d under the OPEC and non-OPEC agreement to cut production, as crude oil exports declined by more than 500,000 b/d in the month, Platts trade flow software cFlow showed.

    It is also the first month Saudi Arabia's production has been below 10 million b/d since February 2015, according to the survey archives.

    Full allocations to Asian buyers seemed to be at Europe and US buyers' expense when total production is lower, with unconfirmed cuts to western customers heard.
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    Asian buying of Atlantic Basin crudes spikes on aligning factors

    Asian buying of Atlantic Basin crudes spikes on aligning factors

    Buying of Atlantic Basin crudes by Asian buyers -- particularly in China -- has spiked since the beginning of 2017 on a confluence of factors that include the OPEC production cuts and subsequent narrowing of the Brent/Dubai Exchange of Futures for Swaps, lower freight rates and strong refining margins.

    The front-month Brent/Dubai EFS -- which shows the relative value of Dubai crudes versus Brent -- has been stuck below $2/b so far this year, averaging $1.59/b, around 30% lower than the Q4 2016 average, according to S&P Global Platts data.

    A narrow EFS makes Brent-related grades attractive to the Asian market.

    The Dubai market has risen over the past couple of months in the wake of the OPEC cuts announced in late 2016, which has constrained volumes of sour crudes on the market, pushing up prices for Middle Eastern sour barrels and encouraging Asian refineries to look for alternative barrels, such as Russian Urals, North Sea Forties and Angola's sweet but heavy crude grades.

    At the same time, trading and refining sources say that cracking margins are healthy throughout Asia meaning refineries across the region are likely to be operating at maximum run rates in the near future. "I think [Asia's buying demand] is due to the combined factors -- freight is cheap, gasoline margins are up due to high demand and cracks look very healthy. Plus the Brent/Dubai EFS is also a big factor," said a crude trader.


    The narrow Brent-Dubai EFS has significantly increased the attractiveness of Forties crude to Far Eastern refiners in 2017, with huge quantities of the North Sea's medium sweet grade fixed to move to Asia in the first two months of the year.

    According to data from Platts trade flow software cFlow and trading sources, six VLCCs have already loaded Forties at Hound Point in January and February, with two further VLCCs -- the Bunga Kasturi Lima and Trikwong Venture -- expected to load in the next two weeks.

    In addition to this the Sandra is currently performing a ship-to-ship transfer of Forties crude from the New Success VLCC at Southwold and is due to begin steaming towards South Korea in the coming days. This means than a total of nine VLCCs of Forties crude are likely to head to the Far East in January and February.

    Whether such heavy flows will continue is uncertain, with few reports of ships being fixed for March despite the persistently narrow Brent-Dubai EFS. "Looking at the fundamentals the Brent/Dubai is narrow enough and freight isn't too bad, with it probably now below $5 million for a VLCC [for Hound Point-Far East]. But the question is, what is the cheapest alternative for the Chinese?" a trader said.

    Among the other alternatives for Chinese and other Far Eastern refiners are Urals and CPC Blend, with the former heard to be heading East in large quantities in February.

    The arbitrage from the North Sea to the East is looking more attractive as lumpsum prices to take VLCC have also dropped. The Hound Point-Far East VLCC route, basis 270,000 mt, was assessed at $5.8 million lumpsum on January 13, but this level had dropped to $5 million by February 15, according to Platts data.


    The West African crude markets have also seen significant upticks in the buying demand, mainly from China but also from refineries in India, Taiwan and Thailand at the start of 2017. The bulk of West African crude exports loading in February and March are headed to Asia, with limited volumes seen going to Europe and the Americas, according to trading sources.

    "If we take January, February and March the average volume going eastwards is 2.2-2.3 million b/d [from] across West Africa. This is compared to 2.1 million b/d in 2016," said one WAF crude trader.

    He added: "The Chinese have taken quite a bit more in Q1, which I think has to do with the teapots [independent refiners], but also the Indians have been taking a bit more, a bit more to Thailand, which we hadn't seen recently, while Taiwan has been stable. There is more [WAF] going to Asia than there was at this time last year."

    The trend has been most pronounced in Angola, with Platts data showing three-quarters of the March-loading program scheduled for Asian destinations, up from the 62% in March 2016. In the February Angolan loading program, 83% was scheduled for Asian destinations, versus just over half in February 2016.

    Other heavy crudes from the region have also seen increased buying from Asia, including Congolese grade Djeno and Chad's heavy Doba crude.

    One aspect of the demand has also come from China's independent teapot refineries, which have continued to ramp up their appetite for international crudes since they received government permission to import crude at the beginning of 2016.

    The teapots have proved to be a lucrative outlet for Angolan sellers, according to market sources, with many willing to pay higher prices to obtain the heavy but sweet Angolan crudes that are a better match for their refineries than other regional crudes.

    As a result, major Angolan buyers such as Unipec, Sinochem and trading houses have been buying more Angolan crude to re-sell to teapot refineries, said traders. "A lot of the buying in March has been mostly based on expectation of demand from teapot refineries," said a second WAF crude trader.

    The VLCC and Suezmax routes from West Africa to China were soft through January, with VLCCs seeing lower rates due to weak demand in the leading VLCC market in the Persian Gulf, which pushed down Atlantic rates too, sources said. In the last month the VLCC route from West Africa to China, basis 260,000 mt, was assessed at a high of $18.20/mt on January 13, and dropped as low as $15.40/mt on February 2, a 15% decrease.

    Suezmax rates have also softened in the last month, in large part due to strong demand for VLCCs taking out a lot of February-dated Suezmax cargoes, sources said. The Suezmax route from West Africa to China, basis 130,000 mt, was valued at $27.57/mt on January 13, but this route dropped as low as $17.77/mt on February 3, a 35% decrease, according to Platts data.


    Equity holders of crude oil loading from the Mediterranean, Black Sea and the Baltics have also been using the narrow EFS to sell some of their wares into Asia.

    Urals loading in Northwest Europe as well as the Mediterranean has been sold to Asia in recent weeks. Two VLCCs have found homes in Asia in February, according to trading sources -- Unipec's VLCC the BW Utik, from Skaw in Denmark to Asia loading on an STS basis on February 14-17.

    The second is the Front Page, chartered by Trafigura, for which loading ports are not yet confirmed.

    "There are two likely options for the Front Page, one is that it only loads Urals at Skaw and the other is that it will be a co-load with Forties from Hound Point and Urals from Skaw," a trading source said.

    However, a ship broker said that is more likely to be just a Urals cargo going East with another trader saying that "double port charges and STS would severely harm the economics of the trade."

    For Urals loading at the Black Sea port of Novorossiisk, sources said there were four Suezmax vessels heading to Asia in February, which had in particular helped differentials appreciate at the beginning of the month.

    Additionally, one trading source said that "bids from Asian buyers for Med Urals have been coming in at around Dated Brent minus $2.00/b for CFR Augusta, which is a level you can certainly work with if you are the seller."

    On top of that, around 5 million barrels of Azeri Light have been sent to the East, with the majority being sold by Socar.

    Apart from a narrow EFS, the vast amount of sweet grades available in the Mediterranean has led to sellers looking for alternative homes for their cargoes and Asia emerged as a willing buyer that also helped to strengthen differentials for the grade.
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    Pakistan's LNG demand expected to reach 30 mil mt/year by 2022: PLL

    Pakistan plans to ambitiously grow its LNG imports over the next few years, Adnan Gilani, the chief operating office of Pakistan LNG Ltd. (PLL), re-affirmed at the LNG Supplies for Asian Market (LNGA) conference in Singapore this week.

    PLL expects Pakistan's 3.5 million mt/year (465 MMcf/d of gas equivalent) of LNG imports in 2016 to rise dramatically to 20 million mt/year in 2018 and 30 million mt/year by 2022, Gilani said.

    He added that the country views LNG as a short-to-medium term solution for meeting a projected gas shortfall of 2-4 Bcf/d, depending on assumption scenarios used.

    The country's gas shortfall recently culminated in a gas crisis in 2015, resulting in under-utilized gas-fired power plants, compensated for by expensive oil imports for power, and the country's fertilizer and textile sectors suffering shutdowns, Gilani said.

    PLL is therefore planning to take advantage of the current weak global LNG market outlook, and the country's well-developed gas infrastructure, to rapidly grow its LNG imports, he added.

    Pakistan relies on gas for around 50% of its total energy needs, has a vast gas pipeline network and is taking steps to remove pipeline bottlenecks inhibiting transporting gas from the south, where LNG imports are regasified, to the northern demand centers, according to Gilani.

    In addition to the currently operational 600 MMcf/d regas terminal at Port Qasim, another four are expected to start up by end-2018, bringing the additional regasification capacity in the country up to 2.8 Bcf/d, said Gilani.
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    Chevron’s Wheatstone project on track for first LNG mid-2017

    Chevron-led 8.9 mtpa Wheatstone LNG project west of Onslow, Australia, continues to progress.

    According to Chevron’s latest update, the activities being carried out offshore and at the LNG plant site support the delivery of the first LNG in mid-2017.

    The Wheatstone drilling campaign has been completed, with all nine development well flowbacks successful, while the hook-up and commissioning moves forward offshore at the Wheatstone platform.

    At the plant site, the export jetty and LNG loading platform are complete, and LNG Train 1 commissioning is underway, Chevron said. All Train 2 modules have so far been delivered, moved into place and set on foundations. Installation of piping, electrical and instrumentation continue as planned.

    The company said in its update adding that the storage and loading system is ready for commissioning and cooldown, with the LNG storage tanks and export loading jetty now complete.

    The installation and startup of gas turbine generators have also been achieved, securing permanent power supply for the facility.

    Chevron added that the operations centre facilities are complete and workforce mobilized while all the permanent buildings have been handed over to operations, all of which can be viewed in a video the company released.

    US-based energy giant Chevron, in October last year, that delays in module deliveries to the LNG project resulted in an additional $5 billion investment by the joint venture partners.

    The project located 12 kilometers west of Onslow in the Pilbara region includes two LNG trains with a combined capacity of 8.9 million tons per annum (MTPA) and a domestic gas plant.

    It is a joint venture between Australian units of Chevron (64.14 percent), Kuwait Foreign Petroleum Exploration Company (13.4 percent), Woodside (13 percent), and Kyushu Electric Power Company (1.46 percent), together with PE Wheatstone, part owned by Jera (8 percent).

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    Japan's heavyweight LNG buyers wrestle more flexible deals from suppliers

    Japan's liquefied natural gas (LNG) buyers are upending the traditional practices of the market, using their leverage as the world's biggest buyers of the fuel to wrestle concessions for more flexible terms.

    Japan's electric utilities have won provisions that will allow them to divert contracted LNG cargoes if they restart their nuclear reactors, most of which have been shut since the 2011 Fukushima disaster, three sources have told Reuters. This could set a precedent as more contracts start coming up for renewal.

    A shrinking population and greater use of alternative fuels has lowered Japan's LNG demand. Because of that, utilities have pushed to gain allowances to resell imported cargoes and reduce their dependence on long-term contracts.

    A persistent supply glut and low spot prices have given Japan's utilities the upper hand in their negotiations with sellers. About 32 million metric tonnes of annual LNG capacity will come online in 2017, according to a forecast from Reuters Supply Chain and Commodities Research, equal to about 12 percent of 2016's global imports.

    "With competition to place LNG heating up, price is not the only (contract) term under pressure. LNG suppliers will offer more innovative deals to secure sales," said Kerry Anne Shanks, head of LNG research for Asia at Wood Mackenzie. "Japan's power utilities are highly prized as customers."

    Japan has traditionally used so-called take-or-pay contracts for LNG purchases that oblige them to pay for a fixed volume of imports, and they are restricted from reselling cargoes if demand drops.

    Now, LNG buyers are being offered the restart provisions to entice them to sign up for new contracts, said an executive at one of Japan's gas importers. "This option was offered to us in a recent sales pitch."

    These offers come as data from the International Group of Liquefied Natural Gas Importers (GIIGNL) shows that several long-term contracts between Japanese utilities, including Chubu Electric, Tohoku Electric, Shizuoka Gas, and producers including Malaysia's Petronas and Australia's Woodside Petroleum started to expire last year and more will expire in 2017 and 2018.

    Many more of the contracts will be coming up for renewal in the coming five years, the GIIGNL data shows.

    Neither, the Japanese utilities nor Petronas were available for comment on the ongoing contractual negotiations. Woodside did not comment on the talks.

    Even as Asian spot LNG prices have dropped 65 percent from their 2014 peak, Japan's electric utilities still want to restart their nuclear reactors since they are a lower-cost power generation source.


    All but two of Japan's reactors remain shut since the 2011 Fukushima nuclear disaster, and many are going through a relicensing process that is taking longer than expected.

    At most, six reactors could restart this year, said Takeo Kikkawa, professor at the Tokyo University of Science, who advised the government on its most recent energy policy, adding the outlook was cloudy for further restarts past that.

    The utilities are likely taking advantage of downward quantity tolerances (DQT), standard provisions in gas contracts that stipulate the minimum amount of gas that must be paid for whether the buyer needs it or not, said a Japanese energy executive with more than 20 years of working in the gas business.

    Typically, DQTs are set at around 10 percent, meaning if a buyer signs up for 1 million tonnes of gas, it must take at least 90 percent of that on a guaranteed payment basis.

    "They are pushing for much greater DQTs," the executive said, adding that owners of older projects would likely offer these options.

    "The older projects are fully depreciated. They have been going for many years and they recovered all their costs so their costs basis is low," he said.

    In order to maintain market share in an oversupplied market, LNG sellers have become willing to tweak more flexible terms.

    "Our production costs a lot of money to develop, and what a buyer calls flexibility, we know as uncertainty," said a commercial manager at a major LNG supplier. "There's already more LNG in the market than is needed, and more is coming, so as a producer we'll have to become that much more flexible in order to remain competitive."

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    Dutch oil storage company Vopak warns of wait for profit growth

    Dutch oil storage company Vopak warns of wait for profit growth

    Dutch oil and chemical storage company Vopak warned investors that core profit might not rise until 2019 as divestment plans and cost cuts take time to pay off, sending its shares down as much as 10 percent.

    The company said that occupancy rates for its terminals were at 93 percent, up 1 percent year-on-year. For the current year, it expects an average occupancy rate of at least 90 percent.

    The incentive to store oil is diminishing as the futures curve has shifted from contango, in which longer-dated futures are more expensive than near-term contracts, into the reverse scenario, backwardation, after OPEC production cuts.

    However, de Kreij played down its impact.

    "When people are talking about implications of oil prices and contango, in fact you are talking about let's say a few basis points, a few percent points on the total occupancy rate but you are not talking about swings of 10, 20 percent on our utilisation," de Kreij said.
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    Iraq plans to acquire 'large fleet' of oil tankers

    Iraq plans to acquire a "large fleet" of oil tankers to transport the OPEC nation's crude to global markets, Oil Minister Jabar al-Luaibi said in a statement on Friday.

    The nation's tanker fleet was largely destroyed during the U.S.-led offensive to dislodge Iraq from Kuwait in 1991, according to the state-run Iraqi Oil Tankers Company's website. The company owned as many as 24 tankers in the 1980s.

    "The ministry is keen to restructure the company and develop its operations by building and buying a large fleet of tankers," Luaibi told the company's management, according to the statement.

    Iraq is OPEC's second-largest producer, after Saudi Arabia.
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    Beach doubles profits in half-year

    Oil and gas produced Beach Energy has doubled its net profit after tax for the interim period ending December, compared with the previous corresponding period, resulting from both higher prices and volumes.

    Net profit after tax for the interim period reached A$103.4-million, while revenue was up 26% to A$354.4-million.

    Sales volumes for the six months under review was up by 25%, to 6.4-million barrels of oil equivalent, owing to record half-year production, while sales revenue increased by 27%, to A$344-million, compared with the A$272-million reported in the previous corresponding period.

    Total net production for the period was 5.5-million barrels of oil equivalent, a 22% increase on the previous corresponding period. Oil production hit a record high of just over three-million barrels, while gas and gas liquid production reached 2.4-million barrels of oil equivalent.

    Gross profit for the year was up 309%, to A$104-million, with the higher oil and gas prices and sales volumes partly offset by higher royalties and depreciation and amortization charges.

    On the back of higher production during the interim period, Beach has increased its full-year production guidance from between 9.7-milion and 10.3-million barrels of oil equivalent, to between 10.3-million and 10.7-million barrels.

    Meanwhile, capital expenditure for the full year has been reduced from the previous estimate of between A$180-million and A$200-million, to between A$170-million and A$180-million.

    The revised capital guidance reflected the continued progress with cost savings and efficiencies, which resulted in an overall reduction in capital expenditure estimates, despite increased drilling activity.
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    As U.S. shale oil activity surges, sand could be in short supply

    Demand for frac sand has surged in recent weeks as U.S. producers rush back to the oil patch, stoking concern that supplies of the key component of drilling may not be able to keep up with demand later this year, industry professionals said.

    The growing appetite for frac sand comes as oil producers have added hundreds of rigs in U.S. oil fields from Texas to North Dakota. Last week, the U.S. rig count hit 591, the highest since October 2015 and nearly double the figure seen seven months ago.

    Raymond James predicts the number of rigs could approach 1,000 by the end of 2018.

    “The worm has turned,” said Chris Keene, CEO of Rangeland Energy LLC, a privately held logistics company in Sugar Land, Texas.

    U.S. producers pump frac sand and other materials into wells to break up shale rock and produce oil. Wells are getting longer and wider, requiring larger amounts of sand.

    The frac sand industry was among the hardest hit during the oil rout of the past two years, as producers slashed capital budgets and looked to shed – or renegotiate – long-term supply contracts with sand companies that had been made during the boom years. Several of the major frac sand companies saw shares plummet amid investor skepticism.

    But frac sand producers like Fairmount Santrol Holdings and U.S. Silica Holdings are regaining their price leverage and producers are once again looking to lock in long-term supply contracts amid widespread optimism that global oil production cuts will provide stable, higher prices.

    Raymond James, in a January investor note, estimated frac sand demand would hit record levels this year at roughly 55 million tons and exceed 80 million tons by next year, 60 percent above 2014 levels, due in large part to producers requiring more sand per well.

    Tudor, Pickering, Holt & Co ran a U.S. demand model early last year that significantly underestimated demand for 2017 and 2018, forcing the bank to revise its forecast in December to predict record demand for 2018. Tudor says tightening supplies and logistical challenges could send frac sand prices to 2014 levels, when there were 1,500 rigs in U.S. oil patches.

    Rangeland operates a frac sand terminal in New Mexico that delivers roughly 2 million tons of sand annually to producers in the Delaware Basin, an oil patch that stretches from West Texas into New Mexico. Rangeland CEO Keene said January frac sand deliveries out of the company's terminal reached record levels.


    Taylor Robinson, president of PLG Consulting, which helps companies solve transportation issues, said frac sand demand has “significantly” picked up in the past six weeks, and demand is expected to skyrocket over the next seven months.

    “I think people are looking at the potential demand numbers, and, for the first time, people are scared that there will not be enough sand to meet the demand,” Robinson said.

    “Oil producers are scrambling to lock in long-term contracts to avoid being caught short. People are really gearing up for the next wave.”

    The increased demand will push sand prices up by 60 percent, hitting the $40 per ton range over the next 18 months, Raymond James said. Sand costs are about $25 per ton today and reached $70 per ton prior to the downturn and when supplies were short.

    Keene said the real concern is the logistical challenges that come with moving high volumes of sand.

    Some producers are using a unit train - roughly 75 or more rail cars in a line - on each well, Keene says. He said that presents some significant logistical challenges that could hamper production.

    "People are going to have to build large, unit-train scale facilities at these volumes," he said. "Once you start fracking a well, you need to keep sand on it."

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    Texas adds 16 rigs, but panhandle wins; only 2 in Permian

    The number of oil and gas rigs in U.S. fields rose for the fifth straight week, another sign of optimism in the industry, despite stagnating oil prices.

    This week’s count jumped 10, a boom of almost 350 rigs since the count fell to its recent low last spring. U.S. oil drillers collectively sent six more rigs into the patch this week, the Houston oilfield services company Baker Hughes reported Friday. Gas drillers added four.

    Texas added 16 rigs — but the story, this week, wasn’t the Permian Basin, which has dominated the industry’s rebound so far. Instead, drillers added five rigs in the Texas Panhandle’s Granite Wash oil field, three in the gassy Haynesville play, and only two in the Permian.

    The total rig count rose to 751, up from a low of 404 in May, and up 237 rigs year over year.

    The number of active oil rigs jumped to 597 this week, gas rigs to 153. The number of offshore rigs dipped again, by three to 18, down seven rigs year over year.

    Outside of Texas, however, most rig counts fell this week: Louisiana lost three, New Mexico two, Alaska, North Dakota and Oklahoma one. Only Utah added one.

    Drilling activity has continued to rise despite oil prices that have stalled above $50 for weeks.

    U.S. oil prices settled on Thursday at $53.36, up 25 cents or less than 1 percent, and was dipping a bit in midday trading Friday.
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    The U.S. Offshore Rig Count is down again

    The U.S. Offshore Rig Count is down 3 rigs from last week to 18 and down 7 rigs year over year. Out of the 18 rigs in operation, 17 are drilling in the U.S. Gulf of Mexico, and one is drilling in Alaska.
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    Extreme US styrene shortage turning global trade flows upside down

    At the turn of the year the eyes of styrene traders were fixed on Asia, where a heavy turnaround season planned for the end of first quarter looked set to make the region the main price-setter globally.

    But, contrary to initial expectations, it is the US that has so far been dictating the pace of accelerating rises in global pricing.

    The unexpected styrene shortage in the US market, which propelled prices to a 30-month high last week, has left Asia and Europe without their usual resupply and opened the first opportunity to ship styrene to the US from both regions in almost a decade.

    Soaring styrene prices have pushed producers' margins to multi-month highs, while consumers, at least in the Atlantic region, are struggling to pass down these feedstock increases to their own customers, and are being forced to trim down run rates. IT'S ALL ABOUT US

    At the moment around 40% of US styrene production capacity is affected by various technical issues.

    Last week Americas Styrenics delayed the restart of its 950,000 mt/year unit in St James, Louisiana after a turnaround until mid-March as it sought to make repairs to critical equipment.

    This was followed by a problem with a superheater at the 1,179,500 mt/year Cos-Mar styrene plant, which led to a declaration of a force majeure on styrene supplies.

    Several EU-bound styrene cargoes from the US were canceled as a result of these hiccups, according to shipping reports.

    The US typically exports around 2 million mt of styrene a year, primarily to Latin America, Asia and Europe.

    While exports to Latin America have been largely stable over the past three years, the balance of supplies to Europe and Asia strongly depends on the prevailing market conditions in these regions. For example, Europe's share in total exports dropped from 33% in 2014 to 12% last year, while exports to Asia rose from 15% to 42% in the same period.

    The only source of styrene imports into the US is neighboring Canada, which sent 522,365 mt of styrene to the US last year.

    The last time the US imported styrene from Europe was in 2008, when supplies from Netherlands totaled 9,728 mt, while the last significant volumes of styrene moving from Asia to the US were in 2005 when Korea sent 1,000 mt. ASIA UPSIDE

    The Asian styrene market remains unexpectedly the lowest-priced market globally. In fact, last week saw a steep decline in Chinese prices, which put pressure on the rest of the region.

    East China styrene inventory levels surged as major downstream EPS manufacturers shut throughout the Lunar New Year holidays.

    Stocks were estimated at 122,000 mt last week, above the 2016 average of 81,702 mt.

    Since then the market has staged a bit of a rebound, with prices rising to $1,521/mt CFR China and $1,496/mt FOB Korea Monday.

    But the arbitrage window is now firmly open on paper, and traders, including some in China, have been heard trying to make it work.

    "I think that the US will still be very tight until end-April," a trader said. "If we can find [a] vessel end February or early March loading, you can get into US Gulf in April. That is still workable."

    A South Korean producer said he had fixed 5,000 mt of styrene to send to the US and another trader said he is loading 8,000 mt of styrene from Daesan within the next 10 days, also destined for the US Gulf.

    A third trader, in China, said he believed about 15,000 mt of FOB Korea styrene had been fixed recently to head to the US.

    Some were heard talking about selling bonded SM warehouse cargoes to international spot traders and loading them via Jiangyin port.

    One China-based trader said there could be challenges in terms of vessel space for this unusual route.

    It is expected that domestic China SM prices will rebound next month when demand from downstream returns and East China inventories sink.

    "I don't think the market can afford to lose so much inventory but in three weeks' time, when demand is back, what do they do? The market may come down more but it is set for rebound soon," one trader said.

    Another trader said: "I feel that yuan prices will be sustained and go up because Europe and the US are still very firm and the yuan price is the lowest in the world, so it has no reason to go down further."


    Global tightness and local production constraints are likely to keep European prices high for the rest of February and going into March.

    Poland's Synthos has reportedly experienced some production hiccups at the start of the month, leading to extra purchases of styrene. Further issues were heard in France, though these remained uncorroborated.

    Trinseo is set to start its regular maintenance works this week, and might go to the spot market to buy extra molecules to last it through to mid-March.

    Spot prices are already above the invoiced prices for contract deliveries, which is leading to consumers' maximizing their contractual offtake.

    Contract price for February was agreed at Eur1,560/mt FOB ARA. After a 12-13% rebate net contract price equates to Eur1,357-1,373/mt ($1,445-1,462/mt), or over $100/mt below the current spot market.

    While maximizing their offtake, some European consumers, such as EPS producers, are actually struggling to pass down the styrene rises to their customers, and are being forced to decrease run rates.

    The surplus of feedstock styrene can then be sold in the merchant market, providing these companies with extra revenue streams.

    Expensive styrene in Europe has also led to talk of a potential deterioration of competitiveness for European-origin styrene derivatives.

    One source said that this could result in an influx of cheaper polystyrene into Europe in coming months.

    The Europe-US styrene arbitrage is also open on paper at the moment.

    Should the spread widen, it is possible that even European styrene would flow to the US. In addition, some demand might emerge from Latin America should the US fail to supply this region. European traders estimated that around 10-15,000 mt of styrene already moved to Brazil in the second half of January.

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    Why You Need the Internet to Drill in the U.S.

    The Obama administration largely put an end to old-school federal energy auctions last year, just when they were starting to get interesting.

    Those barker-and-gavel sessions, long the primary way the Bureau of Land Management sold leasing rights for oil and gas drilling on federal property, had become targets for climate activists. A year ago, a conservationist worried about drilling near her home in Utah paid $2,500 for the rights to 1,120 acres of federal land. (She put the purchase on a credit card.) The BLM rescinded the lease months later after she’d made it clear she didn’t intend to drill.

    The bigger disruption came in May, when hundreds of protesters blockaded a 7,000-acre auction at a Holiday Inn in Lakewood, Colo. Police eventually broke the blockade, and Kathleen Sgamma, president of Western Energy Alliance, a powerful industry lobbying group, told a local newspaper she’d ask the BLM “to get rid of this circus by just holding online auctions.”

    Over the summer, the BLM changed its rules to do just that, and this year only two of its 26 auctions will be held in person. The rest have been contracted to EnergyNet, a privately held company in Amarillo, Texas, that runs the country’s largest auction site for oil and gas properties. Obama’s BLM gave EnergyNet a five-year exclusive to manage the bureau’s online auctions, and the company has since made similar deals with state agencies in Colorado, New Mexico, North Dakota, Texas, Utah, and Wyoming.

    EnergyNet takes a 1.5 percent commission on its BLM auctions, and sales of federal and state lands on the site topped $158 million last year. Overall sales on the platform rose to $745 million, more than triple the 2013 figure. Partly, that’s because cratering oil prices have pushed leaseholders to put their rights up for sale.

    EnergyNet auctions naturally filter out most protesters. Under the terms listed on the website, registered lessees must be able to prove that they’re professionals “engaged in the oil or gas or other minerals business on an ongoing basis.” Still, Chief Executive Officer William Britain is clearly worried about activists. He responded to an interview request by asking that a Bloomberg Businessweek editor call to confirm the reporter’s identity. “With the government work we are doing, we have a lot of protesters,” Britain says. “You can’t be too careful these days.”

    Britain, previously an oil and gas driller, founded EnergyNet in 1999 and started pitching the site to the BLM in 2009. At the time, a Reagan-era federal mandate required that all auctions be conducted in person and relatively near the land being auctioned, so “we went to work trying to get that law changed,” he says. Eventually, the company helped get language giving the BLM power to shift its auctions online tucked into the 2015 National Defense Authorization Act, the annual Pentagon budget. “Everyone should want it to be easier to buy federal leases,” Britain says, “rather than just these little regional live auctions they’d been having.”

    Anti-drilling activists say the result is opacity, not efficiency. “The real effort here is to take auctions out of the public spotlight and to scurry into the cover of darkness to escape people who want to protest,” says Jason Schwartz, a spokesman for Greenpeace, which helped organize the Lakewood protest.

    Then again, the old auction process wasn’t exactly transparent, either, says Nada Culver, director of the BLM policy group at the Wilderness Society, another conservation advocate. “The guy in the cowboy hat and the boots at the auction is not the giant oil and gas company that ends up with the lease,” she says. “This is not a process that’s ever been open to regular people.”

    The bottom line: Sales on EnergyNet more than tripled in three years, reaching $745 million in 2016, including $158 million in government lands.

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    Canada's Enbridge misses profit estimate as expenses rise

    Canada's Enbridge misses profit estimate as expenses rise

    Enbridge Inc , Canada's largest pipeline company, reported a smaller-than-expected quarterly profit on Friday as expenses jumped and the company said its deal to buy Spectra Energy Corp was on track to close this quarter.

    Earnings attributable to the company's shareholders fell 3.4 percent to C$365 million ($279 million), or 39 Canadian cents per share, in the fourth quarter, hurt by charges, including for asset impairment and restructuring.

    Excluding items, Encana earned 56 Canadian cents per share, missing analysts' average estimate of 58 Canadian cents per share, according to Thomson Reuters I/B/E/S.

    Enbridge said its expenses jumped 11 percent to about C$9 billion in the three months ended Dec. 31.

    Revenue rose nearly 5 percent to C$9.34 billion, edging past analysts' estimate of C$9.31 billion.

    Enbridge announced its deal to Spectra Energy for about $28 billion in September, and on Thursday got U.S. antitrust approval for the transaction that will create the largest North American energy infrastructure company.

    Enbridge's pipelines mainly send Canadian crude from oil sands to refiners on the U.S. Gulf Coast, while Spectra's network ships natural gas to the U.S. East Coast.
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    TransCanada files Keystone XL route application in Nebraska

    TransCanada Corp filed an application with Nebraska authorities on Thursday to route its Keystone XL pipeline through the state, saying it expected a decision this year for this crucial leg of the $8 billion project that had been stymied by environmental groups and other opponents.

    U.S. President Donald Trump cleared the way for the project at the federal level last month, reversing an earlier decision by former President Barack Obama, who had blocked it over environmental concerns.

    Obama's veto in November 2015 led Canada's No. 2 pipeline company to withdraw its original route application to the Nebraska Public Service Commission.

    The 1,179-mile (1,900-km) Keystone XL pipeline is meant to ship 830,000 barrels per day of mainly oil sands crude from the Canadian province of Alberta to Nebraska, before heading on to the world's largest refining market for heavy crude on the U.S. Gulf Coast.

    The Nebraska Public Service Commission process "is the clearest path to achieving route certainty for the project in Nebraska and is expected to conclude in 2017," TransCanada said.

    Opposition in Nebraska from environmentalists and some landowners concerned about oil spills had been among several major hurdles facing the Keystone XL project. The line's route through the state was the subject of a court case over whether former Governor Dave Heineman was entitled to approve the route.

    A Nebraska Supreme Court decision in 2015 ruled in support of the pipeline, but a number of Nebraskan landowners filed suits against TransCanada alleging the project violated the state's constitution. (

    "Keystone XL is and always will be all risk and no reward," said Jane Kleeb, president of the Bold Alliance, an activist network opposing the pipeline.

    In a quarterly earnings call TransCanada Chief Executive Officer Russ Girling said the company was in talks with crude shippers to update contracts for volume commitments on Keystone XL.

    He acknowledged that oil prices and supply forecasts had changed since November 2015. Late last year the Canadian government approved two other major export pipelines: Kinder Morgan's Trans Mountain expansion and Enbridge Inc's Line 3 replacement project.

    "While some of the shippers may increase or decrease the volume commitments we do expect to retain commercial support to underpin the project," Girling said.

    The most recent cost estimate for Keystone XL is $8 billion, although TransCanada said that would be refreshed this year.

    The company's net loss attributable to shareholders narrowed to C$358 million, or 43 Canadian cents per share, in the fourth quarter ended Dec. 31, from a loss of C$2.46 billion, or C$3.47 per share, a year earlier when TransCanada had to take a C$2.9 billion writedown on Keystone XL.

    Comparable earnings for the quarter were C$626 million, or 75 Canadian cents per share, helped by higher contributions from TransCanada's U.S. natural gas pipeline business, due to its $13 billion acquisition of Columbia Pipeline Group in July.
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    Partial sale of Dakota Access Pipeline completed after construction resumes

    Dallas-based Energy Transfer Partners completed a $2 billion sale of stakes in the controversial Dakota Access Pipeline, which restarted construction this week after receiving regulatory approval from the U.S. Army Corps of Engineers.

    Energy Transfer sold a 36.8 stake in the roughly $4 billion pipeline project to affiliates of Calgary-based Enbridge and Ohio-based Marathon Petroleum. That includes 27.6 percent to Enbridge and 9.2 percent to Marathon.

    The deal reduces Energy Transfer ownership to a controlling 38.25 percent, while Houston-based Phillips 66 maintains its 25 percent stake. Energy Transfer said it will use the proceeds for debt reduction.

    The partial sale was delayed for months after the nearly completed oil pipeline project encountered regulatory holdups under the Obama administration. President Donald Trump put a quick end to that.

    The pipeline project was nearing completion last summer when the Standing Rock Sioux tribe launched protests to block the project, drawing international attention and environmental activists from around the country. Hundreds were arrested and injured during recent protests and skirmishes. Protests remain ongoing, but construction has resumed.

    The pipeline project is designed to carry crude oil from North Dakota’s Bakken Shale to Illinois, where the pipeline connects to existing networks to bring the oil as far south as Nederland, Texas.
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    Alternative Energy

    BP mulls wind turbine upgrades to compete with gas

    BP is weighing plans to update as many as 200 of its U.S. wind turbines with newer, higher-capacity equipment, a move that would represent the company’s biggest investment in renewable energy since its last wind farm came online in 2012.

    If the company green lights the project — a decision that could be reached by mid-year — it would represent about 400 megawatts of capacity.

    Laura Folse, chief executive of BP Wind Energy, said the move would allow the U.K. energy giant to capitalize on production tax credits while optimizing operations at farms in Texas and Kansas. The company put an initial investment down in December in order to qualify for the full tax credit, which started scaling down this year.

    The updates involve swapping out aging equipment such as gearboxes, drive trains and blades, while keeping existing towers and foundations. BP expects the upgraded technology to improve efficiency and reliability while increasing overall energy output.

    “It’s not a done deal, but it is very real,” Folse said in an interview. “The newer technology and the improvements make it economic,” Folse said.

    With 14 wind farms — including one operated by another company in Hawaii — BP says it has the largest wind-energy business of all major oil companies. BP tried selling off its wind business in 2013, ultimately dropping the plan after failing to find a suitable buyer.

    Folse said she was initially skeptical of the economics of replacing equipment at BP sites, including the 60-megawatt Silver Star Wind Farm near Dallas, Texas. But the company seized on the idea as a way to lower operating costs and make its wind more competitive against natural gas-fired power. That’s especially important in Texas, where BP doesn’t have long-term contracts in place to sell wind energy and must compete with the daily vagaries in the power markets.

    Congress’ renewal of the production tax credit in 2015 gave wind farm developers a powerful incentive to retrofit turbines, said Alex Morgan, a New York-based analyst for Bloomberg New Energy Finance. Thousands of turbines totaling 9,700 megawatts across the U.S. are between 10 and 20 years old, making them a prime target for upgrades, he said.

    BP made an investment at the end of last year that gives the company the option to buy replacement equipment for about 200 wind turbines and still qualify for the full production tax credit, worth 2.3 cents per kilowatt hour of electricity over the next 10 years.

    That approach was mirrored by other companies with enough room in their balance sheets to support at least a 5 percent down payment, Morgan said.

    Tax Credits

    The value of the credit drops annually through 2019. In order to qualify for the tax credit at the 100 percent level, wind developers must have begun construction by the end of last year or committed at least 5 percent of the project costs.

    BP now has roughly four years to install the equipment to claim the credit. Folse declined to specify the potential project expense or the suppliers it’s considering.

    Such repowering may become more common throughout the industry as wind developers take advantage of the production tax credit to offset the cost of replacing aging, less-efficient blades and gearboxes with new, improved models.

    BP’s last big investment in its renewable portfolio came with the installation of its Trinity Hills wind farm near Olney, Texas in 2012.
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    Borrego Solar Closes 2016 with 76% Growth in Megawatts Installed

    Borrego Solar Systems, a leading engineer, developer, installer, financier and operator of grid-tied solar photovoltaic and energy storage systems, today announced another record year in which it saw a 76 percent increase in total megawatts (MW) installed from 2015. The company achieved a 100 percent increase in profits, representing its eighth consecutive year of profitable growth.

    “The tremendous growth we’ve had in 2016 is a testament to the incredible team we have assembled at Borrego Solar. The people who work here are passionate about renewable energy and dedicated to finding ways to reduce the cost of solar for our customers. We’re thankful for the trust that our customers across the country placed in us to engineer, construct and maintain high performing solar projects,” said Mike Hall, CEO of Borrego Solar. “In addition we are very grateful to our partners who worked so closely with us to make this happen. We have built relationships with a great network of subcontractors and suppliers who work with us consistently across our three core markets. We look forward to many more years of profitable growth together.”

    Borrego Solar was once again among the top commercial developers nationally and held the largest market share in two of its key geographic markets, Massachusetts and New York, according to GTM Research’s Leaderboard.

    In Massachusetts, the company installed more than 90 MW in 2016, a 144 percent increase from 2015, bringing its total installed capacity to 213 MW. In New York, the company installed 28 MW, a slight uptick from 2015, bringing its total capacity to 55 MW—an amount achieved just two years after fully entering the market. In California, Borrego Solar installed 45 percent more MW than in 2015, bringing its total capacity in the state to more than 86 MW.

    In 2017, the company will continue to focus on reducing the cost of solar for its customers. While solar is already delivering meaningful savings compared to conventional power in all of Borrego Solar’s major markets, the company's goal is to enable more market segments and geographies to benefit from low-cost renewable energy.

    Energy Storage and O&M

    In 2016 Borrego Solar expanded beyond solar with the launch of its energy storage division. Led by General Manager Dan Berwick and Director of Technology and Operations John duPont, the energy storage division is offering energy storage solutions to both solar and non-solar customers. The company aims to leverage storage in order to enable higher penetration of renewable energy on the grid.
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    Uranium price rally comes to screeching halt

    Uranium was the glaring exception amid a broad-based rally in metals and minerals in 2016.

    The price of U3O8 fell 41% in 2016 with the industry tracker UxC's broker average price hitting 12-year lows below $18 per pound in November.  That price compares to an all-time high of nearly $140 a pound reached in June 2007.

    Then, against expectations, the price started to turn. When top supplier Kazakhstan announced in the second week of January that it's cutting output by 2,000 tonnes, equal to 3% of global production, the rally seemed more than justified.

    Enough uranium is above ground for the next eight years

    By February 10 the price had climbed to $26.68 a pound, a 32% year to date gain, but all that changed this week with the price of U3O8 falling 6.3% to end Friday at $25.00.

    Enough uranium is above ground for the next eight years

    Haywood Securities, a Vancouver-based investment dealer, points out that the fall should have been expected:

    The rise in the price of uranium has come as a surprise to investors considering the underlying fundamentals do not seem to have changed; in fact, TEPCO’s announcement that they had declared Force Majeure on a key uranium delivery contract from Cameco Corp. (CCO-T) two weeks ago suggested a fall in the price of uranium was likely.

    The announcement indicates that the start-up of nuclear reactors in Japan continued to be protracted. Given the performance of uranium over the last 3 months, it is unlikely investors are overly concerned at this stage; however, with the status of nuclear energy in Japan remaining uncertain, sentiment towards uranium remains clouded.

    Uranium's weakness persists despite strong fundamentals with only reactors already being built – 66 in total, mostly in China – expected to increase the global need for uranium by a fifth from today's levels.

    But in the short term there seems no relief in sight for the battered industry. Following the Fukushima reactor meltdown in 2011, market expectations were that Japan would move quickly with restarting their reactors, but 38 remain shut five years on.

    Uranium that would have been delivered to Japan is being stockpiled. UxC estimates global inventories as high as 1.4 billion pounds of which some 800m pounds are sitting utilities and most of the remainder with the Russian and US governments.

    While not all stockpiles can easily be brought onto the market, roughly 173 million pounds are needed per year to feed the world's more than 400 operable reactors which means enough uranium is above ground for the next eight years.
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    Base Metals

    BHP Billiton, Escondida workers far apart one week into strike

    The positions of BHP Billiton and the striking union at its Escondida copper mine, in Chile, the world's largest, remain distant even as the two parties agreed this week to return to the table.

    Escondida's 2 500-member union officially walked off the job on February 9 after contract talks with the company ended in failure. Copper prices then spiked to 20-month highs on supply concerns.

    The rally cooled on news Tuesday that the parties had agreed to meet to see if talks could be restarted.

    But the proposals of the company remain far from those of the workers, union spokesman Carlos Allendes told reporters in Santiago on Thursday, after meeting with Chile's labour minister.

    BHP declined to comment on the union spokesperson's remarks.

    Allendes said the union had three non-negotiable demands and were prepared for a long fight should those demands not be met.

    "These three points are basic for us, they're very, very fundamental," he said.

    First, workers demand that every miner be offered the same benefits package. The union has said that BHP is offering new employees benefits that are less generous than those already at Escondida, which workers see as a ploy to undermine a new labour code going into effect in Chile in April.

    Second, the two sides are in disagreement as to whether shift patterns should be changed.

    Third, workers are demanding that the company not reduce any benefits, such as vacation and healthcare, which are in the previous contract signed four years ago.

    And the two sides will also need to address the thorny issue of the one-time bonus typically given to miners when labour contracts are renegotiated in Chile.

    In 2013, when copper prices were significantly higher, the company paid out a bonus of $49 000 per miner, the highest ever in Chilean mining.

    In current talks, the workers have been asking for $38 000 - more than in 2013, in local currency terms. But the company is offering just $12 000.

    The union, however, says the size of the bonus remains a relatively distant issue.

    "We haven't even negotiated that," Allendes told reporters. "We haven't even come close to considering it."

    BHP has repeatedly said that its offer maintains the current salary structure and benefits for workers with existing contracts, and includes some new benefits.

    Escondida, majority-controlled by BHP with minority participation by Rio Tinto and Japanese companies including Mitsubishi Corp, produced about 5% of the world's copperlast year.

    Attached Files
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    Indonesian ministry backs Freeport's copper concentrate exports

    Indonesia's mining ministry said on Friday it has issued a recommendation that is expected to allow the local unit of Freeport McMoRan Inc to resume copper concentrate exports within days.

    The announcement comes after a more than one-month stoppage which push global copper prices to 21-month highs this week. Freeport will be allowed to export 1.1 million tonnes of copper concentrate over the next one year, the mining ministry said in a statement seen by Reuters.
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    Freeport Indonesia says could seek arbitration over mining contract violations

    Freeport-McMoRan Inc's Indonesian unit said on Monday it hoped to resolve a dispute with the government over its mining contract, but reserved the right to start arbitration against the government and seek damages.

    Freeport has submitted a notification to Indonesia's mining ministry describing breaches and violations of its contract of work by the government, the company said.

    Freeport warned in a statement of "severe unfavorable consequences for all stakeholders" if the dispute is not resolved.

    The consequences could include "the suspension of capital investments, a significant reduction in domestic purchases of goods and services, and job losses for contractors and workers as we are forced to adjust our business costs to match constrained production," it said.

    Freeport has been negotiating with the Indonesian government over the terms of a special mining permit to replace its contract of work after halting its exports of copper concentrate due to new mining rules.

    On Friday, it said it could not meet contractual obligations for copper concentrate shipments from the mine following a five-week export stoppage. All mining work was stopped last week at its giant Grasberg mine in the eastern Indonesian province of Papua.

    The chief executive of Freeport's Indonesian unit, Chappy Hakim, appointed in November to lead the company through a period of regulatory uncertainty, resigned on Saturday.

    Under its current contract signed in 1991, Freeport said on Monday it had invested $12 billion in Indonesia.

    But the company cannot make the $15 billion additional capital investment to develop underground mining without fiscal and legal guarantees from the government, Freeport-McMoRan's CEO Richard Adkerson told a news conference in Jakarta.

    Indonesia's mining minister, Ignasius Jonan, on Saturday warned Freeport that bringing the dispute to arbitration could harm the relationship between the company and the government, "but it would be a much better step rather than always using the issue of firing workers as a tool to pressure the government."

    Adkerson also said on Monday the company's Indonesian unit has made its first lay-offs since the dispute over its mining contract started with the Indonesian government and may let go of more workers this week.

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    Anglo to suspend copper mining at El Soldado in Chile

    Anglo American PLC will temporarily suspend operations at its El Soldado copper mine in Chile after failing to receive regulatory approval for a redesign that would have helped keep output flowing, the company said on Friday.

    Chilean mining regulator Sernageomin has rejected the permit request for the redesign, Anglo said, confirming a Reuters story from Thursday.

    "The company has as a result decided to immediately and temporarily suspend mine operations, while it analyses in detail the report issued by the institution and decides on the next steps in respect of the future of said operation," Anglo said in a statement.

    Options could include appealing or coming up with a new plan, it added.

    The mine's output - it produced around 36,000 tonnes of copper in 2015 - is small by the standards of Chile, the world's top copper producer.

    But the stoppage could impact the market at a time when the two biggest copper mines, Escondida in Chile and Grasberg in Indonesia, have both declared force majeure after production ground to a halt.

    El Soldado is part of the Anglo American Sur complex, in which state-run Codelco and Japan's Mitsui and Mitsubishi also hold stakes.

    It has lost money in recent years and has been following an aggressive savings plan against a backdrop of falling copper prices. It said last year that the mine's long-term viability was at risk under current market conditions and laid off 10 percent of the workforce.
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    First Quantum narrows Q4 profit on higher costs, lower prices

    First Quantum narrows Q4 profit on higher costs, lower prices

    Base metals producer First Quantum Mineralshas narrowed its profit for the three months ended December, reporting profit of $12-million, or $0.02 a share, as higher costs and lower metals prices weighed on the bottom line.

    For the year, the Toronto-based company reported that its loss narrowed to $45-million, or $0.07 a share.

    Comparative earnings fell 27% year-over-year to $27-million, or $0.04 a share.

    Revenue for the quarter fell 4.2% to $689-million, down from $719-million a year earlier.

    Copper production unit cost rose in the quarter as lower goldcredit, higher maintenance and mining costs at Kansanshi and planned maintenance shutdown and seasonal electricity cost at Las Cruces partially offset the embedded benefits of the Kansanshi smelter and cost savings initiatives, the company stated.

    Copper production and sales of 146 101 t and 136 265 t, respectively.

    For 2017, the company expects to produce 570 000 t of copper, up from 539 458 t in 2016; 25 000 t nickel, up from 23 624 t in 2016; 200 000 oz gold, down from 214 012 oz last year; and 20 000 t zinc.

    First Quantum Minerals shares have gained 22% since the start of the year. The company’s TSX-listed stock lost 5.48% on Friday to close at C$15 apiece.
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    LME aluminium warrants in Asia trading higher, tracking US physical premiums: traders

    Warrants for aluminium stored in the London Metal Exchange warehouses in Asia are trading at almost twice as high as in end of last year, tracking the US spot physical premiums, traders said Friday.

    A Japanese trader said he has heard LME aluminium warrants in Southeast Asian warehouses offered, possibly by a bank, at around $45/mt, while another Japanese trader said he was hearing offers at $25-$30/mt.

    Both traders agreed at the end of last year, they were hearing $15/mt or less. Around June last year, warrants for some origins were heard at as low as $5/mt.

    Warrants are trading higher in Asia, as US demand is strong, and traders are taking LME stocks out of warehouses for sale in the US, traders said.

    The Platts Midwest Transaction premium, basis delivered Midwest, has stood at a near two-year high of 10 cents/lb ($220/mt) since February 6.

    Cost breakdown of bringing LME warehouse stocks to the US was $25-$45/mt for acquiring warrants, $0.5/mt for canceling the warrants, $25-$40/mt for bulk freight from Asian main port to the US, $40-$50/mt for transporting the metal from the warehouses to ports, also known as headline FOT charge, and $30-$40/mt truck freight from the US main ports to the Midwest, traders said.

    Attached Files
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    Philippine miner ordered shut says to ship nickel ore in March

    Philippine miner Marcventures Mining and Development Corp, whose nickel mine was one of 23 ordered to close by the environment ministry, said on Friday it will take legal action to overturn the ruling and plans to ship out ore next month.

    Marcventures' mine in southern Philippines was among those ordered shut by Environment and Natural ResourcesSecretary Regina Lopez for environmental violations in a ruling that has led to an outcry from the industry. Another five of the 41 mines in the world's largest nickel ore supplier were suspended.

    A unit of Marcventures Holdings Inc, the company said its mine was ordered to close as it was located in a declared watershed, where mining is prohibited.

    But the area was only declared a protected watershed by the government in 2009, while Marcventures secured its miningcontract in 1993, the company said in a filing to the Philippine Stock Exchange.

    It also contested the agency's finding that that it failed to plant three million seedlings, saying efforts were underway and there was no basis for the closure order.

    "We will take all the necessary legal actions and exhaust all remedies available to prevent the implementation of the order," it said. "We expect to operate as usual and to start shipments of nickel ore by first week of March 2017."

    Mining typically halts in the southern Philippines during the monsoon season that starts around October and ends in the first quarter of the following year.

    Lopez has said her decision on February 2 to shut mines operating in watershed zones is non-negotiable, arguing they will affect water supply and quality.

    She has also canceled almost a third of contracts for undeveloped mines she said were located in watershed areas.

    "The environment is under siege from forces of greed and selfishness and it is the government's duty to regulate it such that the environment benefits our people," Lopez told local radio on Friday.

    Mines ordered shut can appeal to President Rodrigo Duterte, who has so far backed her latest actions.

    Australian miner OceanaGold Corp, which runs the Philippines' biggest gold mine and was ordered to suspend operations, said earlier this week it has filed an appeal with Duterte's office, putting a stay on the execution of the suspension order.
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    Steel, Iron Ore and Coal

    China to suspend all imports of coal from North Korea

    China will suspend all imports of coal from North Korea starting Feb. 19, the country's commerce ministry said in a notice posted on its website on Saturday, as part of its efforts to implement United Nations sanctions against the country.

    The Ministry of Commerce said in a short statement that the ban would be effective until Dec. 31.

    The ministry did not say why all shipments would be suspended, but South Korea's Yonhap news agency reported last week that a shipment of North Korean coal worth around $1 million was rejected at Wenzhou port on China's eastern coast.

    The rejection came a day after Pyongyang's test of an intermediate-range ballistic missile, its first direct challenge to the international community since U.S. President Donald Trump took office on Jan. 20.

    China announced in April last year that it would ban North Korean coal imports in order to comply with sanctions imposed by the United Nations and aimed at starving the country of funds for its nuclear and ballistic missile programmes.

    But it made exceptions for deliveries intended for "the people's wellbeing" and not connected to the nuclear or missile programmes.

    Despite the restrictions, North Korea remained China's fourth biggest supplier of coal last year, with non-lignite imports reaching 22.48 million tonnes, up 14.5 percent compared to 2015.
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    Champion hopeful of Bloom Lake restart

    Dual-listed Champion Iron is targeting the restart of the Bloom Lake iron-ore mine, in Quebec, following a positive feasibility study.

    Champion on Friday reported that the feasibility study demonstrated that restarting iron-ore mining at Bloom Lake was financially viable, and that the asset would be competitive in global iron-ore markets with the potential to be one of the region’s leading long-life iron-ore mines.

    “This is a major result for the company. Based on conservative assumptions, the feasibility study demonstrates that Bloom Lake is clearly viable. In fact, very few iron-oreprojects offer the potential of 20+ years of production at industry-low operating costs, while being strategically located in close proximity to all necessary infrastructure and situated in what we consider to be a superior mining jurisdiction,” said Champion chairperson and CEO Michael O’Keeffe.

    The feasibility study estimated that the restart would require a capital investment of C$326.8-million to produce some 7.4-million tonnes of concentrate a year, over a mine-life of 21 years.

    Life-of-mine average operating costs have been estimated at C$44.62/t, with the project expected to generate life-of-mine revenues of C$15.1-billion and after-tax net cash flows of C$2.3-billion.

    The project is estimated to have an after tax net present value of C$984-million and an internal rate of return of 33.3%.

    “I am confident that the feasibility study, and these attributes, will allow Champion Iron to secure investor support and funding as we bring the Bloom Lake mine back into full-scale production,” O’Keeffe said.

    The mine has already been authorised for operation under the federal and provincial environmental authorities.

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    ArcelorMittal, SAIL's India joint venture talks at an impasse - sources

    A proposed joint venture between state-owned Steel Authority of India Ltd and ArcelorMittal SA to build an $897 million automotive steel plant in India has hit an impasse, with the two disagreeing on key terms, officials said.

    India's biggest state-owned steel company and the world's No. 1 producer of the metal signed a deal in May 2015 to set up a plant for automotive grades to tap rising demand in one of the world's fastest growing steel markets and a major car export hub.

    After a series of failed attempts to hammer out several sticking points - the most important being a revenue-sharing formula - negotiations have come to a standstill, the sources said.

    A deadline to close the deal ends in May.

    ArcelorMittal declined to comment. A SAIL spokesman said the negotiations are still in progress.

    SAIL, which has been posting losses for seven straight quarters, was hoping the joint venture will help it move to higher grades of steel in the automotive segment, dominated by private players such as Tata Steel Ltd and JSW Steel Ltd.

    A separate technical tie-up between South Korean steel major POSCO and SAIL has also failed to take off.

    A collapse of the proposed joint venture with ArcelorMittal would further hamper its efforts at a turnaround, and would add to steel ministry's headache when the government is looking to sell its stakes in three of SAIL's loss-making units.

    Failure to close the deal would also hurt billionaire Laxmi Niwas Mittal-controlled ArcelorMittal, which had been looking at the deal as a way to expand its presence in India, one of the most lucrative markets in the world.

    Late last year, India's steel ministry expressed hopes that the joint venture would be finalised by December 2016 and last month SAIL chairman said he was seeking a fair share of return.

    But talks between SAIL and ArcelorMittal hit a major obstacle when SAIL objected to a revenue-sharing structure that it believed would lead to a loss of up to 4 billion rupees ($59.69 million) a year, said three government officials, who did not wish to be identified because they are not authorised to talk to the media.

    SAIL also opposed a payment timeline to access ArcelorMittal's technology and demanded a higher price for supplying low-grade steel for the proposed joint venture, these officials said.

    Further, ArcelorMittal wanted an upfront fee for its technology, while SAIL wanted to pay it over time, the officials said.

    ArcelorMittal also asked for a franchise fee, which SAIL believed would be a big drain on its finances, they said.
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