Mark Latham Commodity Equity Intelligence Service

Friday 24th February 2017
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    Oil and Gas

    Steel, Iron Ore and Coal


    China eyes tougher air pollution controls in Beijing, nearby regions

    China will impose tougher controls on air pollution in Beijing and nearby regions this year to combat heavy smog, mainly by closing illegal plants and slashing steel production, a senior environmental official said on February 22.

    To reduce winter pollution, Beijing, Tianjin and 26 cities in the surrounding provinces of Hebei, Shanxi, Shandong and Henan must attain their annual goals of cutting steel overcapacity ahead of schedule, Zhao Yingmin, vice minister of Environmental Protection Ministry, said at a press briefing.

    Those cities should shut down all illegal polluting factories by the end of October, and ensure a decrease in their total amount of coal consumption this year, Zhao said.

    During the winter heating season, major steel producing cities in Hebei, which is adjacent to Beijing, must cap their output at half of their capacity, he noted.

    Meanwhile, cement and casting industries in the Beijing-Tianjin-Hebei region will continue to halt production in winter.

    The production controls play a significant role in alleviating pollution in winter, as coal burning for heating usually leads to about a 30% increase in pollutant discharge, according to Zhao.

    He also demanded clean fuel be used for winter heating and urged stronger measures to curb car emissions.

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    Glencore reports 18 pct 2016 core profit rise on commodity rebound

    Miner-trader Glencore reported an 18 percent increase in 2016 profits, buoyed by a rebound in commodities, and said the company had never been so well-positioned financially, meaning it was ready for small acquisitions or big dividends.

    Earnings before interest, tax, depreciation and amortisation (EBITDA) were $10.3 billion, up 18 percent.

    Marketing Adjusted earnings before interest and tax was $2.8 billion, up 14 percent and above previous guidance of $2.5-$2.7 billion.

    For 2017, Glencore is guiding for $2.2 billion to $2.5 billion marketing profits and said the low range reflected the sale of 50 percent of Glencore Agriculture in December 2016.

    A commodities rout in 2015 led Glencore to announce asset sales and along with the rest of the industry, it embarked on resolute cost-cutting.

    On Thursday, it said low costs for copper, zinc and nickel would be sustained into 2017 along with expected higher coal margins.

    "Since our IPO in 2011 and subsequent acquisition and integration of Xstrata, Glencore has never been so well positioned as it is today," Glencore Chief Executive Ivan Glasenberg said.

    He told reporters in a media call surplus cash could be used for small deals, for instance, on the edge of existing assets and perhaps a special dividend.

    "We could do many things. We could give our long-suffering shareholders a generous gift of a special dividend, to ourselves as shareholders that would not be a bad thing to do."

    Glencore's board recommended on Thursday a dividend of 7 cents per share after promising late last year it would reinstate payouts.

    A glitch in the recovery was the decision to hedge 55 million tonnes of coal in a rising market, which led to what Glencore labelled an "opportunity cost" of $980 million.

    Glasenberg, however, said Glencore would carry on hedging as appropriate and was in the process of locking in coal prices with Japan over a year-long contract.

    Analysts said the results were ahead of consensus.

    "Today's results strengthen our view on the stock. The results were solid and we applaud the company's supply discipline again. Outperform," Bernstein wrote in a note.

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    Eskom and Transnet need to borrow billions more

    Eskom and Transnet need to borrow billions more than anticipated in 2016, National Treasury revealed in its 2017 Budget Review on Wednesday.

    Even as Eskom’s financial performance improved in 2015/16 as a result of a 12.7% tariff hike and a revenue increase by R10.5-billion to R161-billion, it still required borrowings for its new build and electrification projects.

    In addition, Transnet grew revenues by 1.7% to R62.2-billion in 2015/16. While it has spent R122.4-billion on capital expenditure in the last five years, it plans capital investments of R273-billion in the next seven years, Treasury said.

    These massive expenditure projects mean the entities take up the biggest share of government’s borrowings.

    “In 2016/17 it (borrowing) will amount to R254.4-billion, or 5.8% of GDP,” it said. “This is R32.8-billion more than was projected in the 2016 Budget, reflecting a larger consolidated budget deficit and higher borrowing estimates by State-owned companies – primarily Eskom and Transnet.”

    In 2015/16, borrowing by the six largest State-owned companies – the Airports Company of South Africa, Eskom, Sanral, SAA, the Trans-Caledon Tunnel Authority and Transnet – reached R128-billion.

    Eskom and Transnet accounted for 74% of the total, Treasury explained.

    Eskom increased planned borrowings in 2016/17 increased from R46.8-billion to R68.5-billion. “The increase results from Eskom’s revised assumptions of cost savings and lower-than anticipated tariffs during the current price determination period,” it said.

    Over the next seven years, Transnet plans capital investments of R273-billion, to be funded by earnings and borrowings against its balance sheet, it said.

    Foreign debt funding was lower than estimated, reaching R29.5-billion compared with an expected R42.6-billion.

    “The six companies project aggregate borrowing of R102.6-billion in 2016/17 and R307.1-billion between 2017/18 and 2019/20.

    “Gross foreign borrowings are expected to account for the majority of total funding over the medium term, largely as a result of Eskom’s efforts to obtain more developmental funding from multilateral lenders.”

    In 2016, Eskom concluded a deal with the China Development Bank to get a $500-million loan facility.

    However, Eskom is likely to need additional equity injections in the coming three to four years, according to Nomura emerging market economist Peter Montalto. “Its last equity injections stabilised ratios at very low levels, but are still a constraint,” he said in December. “Nuclear generation would severely leverage Eskom’s balance sheet without additional equity injections.”

    Referring to the “injection”, Treasury said the R23-billion equity injection and the conversion of the R60-billion subordinated loan to equity helped shored up Eskom’s balance sheet.

    “State-owned companies are responsible for much of the infrastructure on which the economy relies,” Treasury said. “Eskom, Transnet and … Sanral account for about 42% of public-sector capital formation.”

    “Over the past year, Eskom continued its capital investment programme – bringing new generating capacity to the electricity grid – and maintained steady power supply. Transnet continued to invest in getting more freight from road to rail.”

    Meanwhile, contingent liability exposure to independent power producers (IPPs) is expected to decrease in 2019/20.

    “Government has committed to procure up to R200-billion in renewable energy from IPPs,” Treasury said. “As at March 2017, exposure to IPPs – which represents the value of signed projects – is expected to amount to R125.8-billion. Exposure is expected to decline to R104.1 billion in 2019/20.”

    Government began to categorise power-purchase agreements between Eskom and IPPs as contingent liabilities in 2016.

    “These liabilities can materialise in two ways. If Eskom runs short of cash and is unable to buy power as stipulated in the power-purchase agreement, government will have to loan the utility money to honour its obligations.

    “If government terminates power-purchase agreements because it is unable to fund Eskom, or there is a change in legislation or policy, government would also be liable. Both outcomes are unlikely.”

    It said Eskom is expected to use R43.6-billion of its guarantee in 2016/17 and R22-billion annually over the medium term.

    It said SAA has used R3.5-billion of a R4.7-billion going-concern guarantee, with the remainder likely to be used in 2017/18.
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    Power struggle: Australian smelters grapple with electricity uncertainty

    Fed up with unpredictable and often exorbitant electricity prices, Sun Metals CEO Yun Birm Choi plans to invest A$183 million ($140 million) to build a massive solar farm to power his zinc refinery in the Australian outback.

    The decision by Sun Metals, owned by Korea Zinc Co, to turn to solar comes as Australia grapples with more frequent power failures and extraordinary price surges on its mainly coal-fired wholesale electricity markets.

    Australia mines more coal than almost any other country. But a shift away from coal-fired power plants to meet a national 20 percent renewable energy target by 2020 has wreaked havoc on smelting and refining businesses caught in the transition.

    "There is no bigger factor for a smelter than disruption to power supply," said Miles Prosser, executive director of the Australian Aluminium Council. "A disruption for even just a few hours can be almost catastrophic," he said.

    While Sun Metals are looking to build their own generation as part of an upgrade to boost production, other smelters plan to cut output and withhold investment because of the uncertainty.

    Mining giant Rio Tinto is set to shed jobs and reduce output by 45,000 tonnes from its 35-year-old Boyne Island aluminium smelter because of soaring power prices and fear of interruptions, a spokesman said, confirming local media reports.


    Generators, grid companies and market operators have traded blame for the shortcomings, while the federal government cites "ideologically driven" renewable energy targets for the problems.

    When most of Australia's smelters were built in the 1970s and 1980s they benefited from very cheap, long-term electricity agreements with state-owned power companies - paying about half the price paid by other large industrial electricity consumers.

    Supply contracts for large consumers now typically include clauses allowing generators to divert power to residential users and essential services such as hospitals. That forces smelters to bid on the open market, where prices can spike savagely.

    Electricity futures on the price of Queensland base load power [YBQc1] have averaged almost $180 per megawatt hour (MWh) this year, compared with an average of $63.45 in 2016. Prices have topped A$13,000 per MWhmore than 70 times so far in 2017, according University of Melbourne's Climate & Energy College.

    By comparison, wholesale power prices for baseload delivery next year in Germany cost 30.15 euros ($32.02) per MWh, while U.S. prices are between $25 and $35 per MWh.

    After a heat wave this month forced the Rio Tinto's Tomago aluminium smelter 150 km (90 miles) north of Sydney to curtail operations so power could be diverted to residents, the smelter's chief executive lashed out at the "insufficient generation" in the market.

    "We should have the cheapest, most reliable energy in the world and yet it's the most expensive and least reliable," Matt Howell, told reporters. "It's a disgraceful situation that needs to be fixed."


    In October alone, blackouts cost BHP Billiton over $30 million in lost output from its Olympic Dam smelter in South Australia following a fierce storm.

    When the lights went out again in December, BHP Chief Executive Andrew Mackenzie said it was a "wake-up call" across Australia on energy policy failure. Jobs and future investment were at risk, he said.

    "(BHP) is now saying that it's having difficulty competing, and industry generally is saying that they're having difficulty competing internationally because the electricity price in Australia is so high," said Queensland Resources Council Chief Executive Ian Macfarlane, a former federal resources minister.  

    At the nearby Port Pirie lead smelter - the largest source of refined lead in the world - a back-up diesel generator kept the furnace hot for the first hours of the October blackout. But as the outage dragged on, the slag in the blast furnace solidified, rendering it inoperable.

    The smelter's Belgian owner, Nyrstar, put repair costs as high as 5 million euros ($5.3 million).

    Faced with high costs and tough competition from new, more efficient Chinese smelters, Alcoa has already shut one 185,000 tonne a year aluminium smelter in Australia. In January, the U.S. giant came close to shutting down a second smelter near Melbourne after power outages cut operations by two-thirds.

    Production was restored only after the government bowed to a request by Alcoa for a $182 million aid package to defray power costs. [nL4N1F95LZ]

    After watching Sun Metal's energy bill balloon by 40 percent to A$70 million in 2016 and encouraged by plummeting costs for solar installation, Choi has expanded plans for the solar plant from 100 MW to 115 MW. That would make it Australia's largest solar farm.

    The smelter will still need backup supply from the main grid but might at least benefit when prices surge.

    "Primarily, the electricity produced from the solar farm will be consumed at the refinery," Choi said. "Subject to the refinery’s operation and the price of electricity, it will also sell electricity into the national energy market."

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    Bitcoin Soars Above $1100, Near Record Highs As Chinese Bypass Crackdown

    Despite concerted efforts by authorities to crackdown on capital outflows - specifically through virtual currencies - prices for Bitcoin are soaring as the Chinese find way around regulatory controls. Bitcoin just topped $1100 - near record highs - as Chinese traders shift their action off regulated-exchanges to local peer-to-peer marketplaces.

    China’s central bank has stepped up oversight of bitcoin exchanges this year, leading major trading platforms to impose halts on withdrawals and other checks to appease the regulator. But, as Quartz reports, Chinese traders aren’t playing along—they are apparently flocking to peer-to-peer marketplaces to continue buying and selling bitcoin.

    As Yuan trading on bitcoin exchanges has plummeted...

    Quartz notes that one of the longest established peer-to-peer marketplaces is LocalBitcoins, which acts as a kind of directory for buyers and sellers to find each other. Users can arrange to meet in person, on chat platforms, or talk on the phone to arrange exchanges involving bitcoin.
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    Anglo targets further $1bn in cost, volume improvements in 2017

    Diversified miner Anglo American is this year seeking an additional $1-billion in incremental net cost and volume improvements, while also aiming to return to an investment-grade credit rating and resume dividend payments.

    The group has already identified 75% of these targeted net cost and volume improvements.

    Additionally, Anglo plans to maintain its capital expenditure at $2.5-billion and increase its stay-in-business capital to $1.2-billion this year, with capital to be “appropriately prioritised” to ensure that protection is provided for the long-term value of its assets.

    During a teleconference call, on Tuesday, to discuss the group’s results for 2016, Anglo CEO Mark Cutifani said the “decisive and wide-ranging” operational, cost, capital and portfolio actions that Anglo put in place in 2016 had enabled the company to reduce its net debt to $8.5-billion from $12.9-billion in 2015, which was significantly below Anglo’s $10-billion target.

    He commented that despite a 3% decrease year-on-year in average commodity prices, Anglo had achieved a $3.5-billion increase in attributable free cash flow, a 25% increase in underlying interest, taxes, depreciation and amortisation (Ebitda) to $6.1-billion and increased its underlying Ebitda margin to 26%.

    Cutifani said this “substantial” underlying Ebitda improvement was achieved despite headwinds, such as the labour stoppages and record snowfall at the company’s Los Bronces copper mine, in Chile, and the smelter run-out at its platinum business in South Africa.

    He remarked that the $1.5-billion sale of the group’s niobium and phosphates businesses further supported its balance sheet recovery goal and combined with the sale of a number of coal and platinum assets during the year, Anglo received $1.8-billion of disposal proceeds in 2016.

    “The high-quality assets across our De Beers, platinum-group metals and copper businesses underpin our positions in those respective markets and are the cornerstone of a more resilient and competitive Anglo, through the economic and commodity price cycle,” Cutifani stated.

    In addition, he pointed out that the diversified miner continued to benefit from the performance of a number of its other assets across the bulk commodities of iron-ore, coal and nickel.


    Nonetheless, Cutifani noted that, while Anglo had received “strong interest” in a number of its assets for which the group had held sale processes during 2016 to further strengthen its financial position, Anglo had adhered to “strict value thresholds” and chose not to transact.

    “We will continue to upgrade our portfolio as a matter of course, although asset disposals for the purposes of deleveraging are no longer required. We, therefore, retain Moranbah, Grosvenor and our nickel assets, ensuring that they continue to be optimised operationally to contribute cash and returns, while being allocated capital to both protect and enhance value,” he highlighted.

    Cutifani pointed out that, with regard to the group’s South African assets, Anglo continued to work through all the potential options for its export thermal coal and iron-oreinterests, as the company recognised the high quality and performance of these businesses and was intent on ensuring that maximum value was created for all its shareholders.

    He emphasised that the retention of these assets remained a “viable position” given Anglo’s recent operational and other general improvements. “Therefore, our focus is on continuing improvements as we go forward,” Cutifani asserted.


    He said that despite the group’s significant progress, it was critically important that the lessons of recent years were applied, adding that although there was confidence in the long-term outlook for the company’s products, the balance sheet needed to be able to withstand expected price volatility in the short-to-medium term.

    Cutifani noted that Anglo would continue to refine its asset portfolio over time to ensure its capital was deployed effectively to generate enhanced returns.
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    Export companies tell U.S. Congress to push tax code rewrite

    Chief executive officers of 16 companies, including Boeing Co (BA.N), Caterpillar Inc (CAT.N) and General Electric Co (GE.N), have urged the U.S. Congress to pass a comprehensive tax code rewrite, including a controversial border tax.

    In a letter to Republican and Democratic leadership on Tuesday, the CEOs said a Republican-proposed border adjustment tax would make U.S.-manufactured products more competitive abroad and at home by making imported goods face the same level of taxation.

    "If we miss this chance to fundamentally reshape the tax code, it might take another 30 years before we have another chance to try," the group of CEOs wrote in the letter, according to a copy that Reuters obtained.

    It is the latest move in a back-and-forth lobbying effort from companies that proposed changes to the tax code would affect.

    Republican House Speaker Paul Ryan has proposed lowering the corporate income tax to 20 percent from 35 percent, imposing a 20 percent tax on imports and excluding export revenue from taxable income.

    The proposal has pitted large U.S. corporations that require imports, like retailers and auto manufacturers, against those that export much of their goods and therefore support the tax code changes.

    A group of retail CEOs met last week with President Donald Trump and congressional leaders to argue against the border adjustment tax.

    Trump is expected to release his own tax proposal in the coming weeks. While he has said the border adjustment tax is too "complicated," his administration has said taxing goods from Mexico could fund construction of a wall along the nation's southern border.

    The letter supporting the border tax was signed by 16 CEOs: Dennis Muilenburg of Boeing, John Coors of CoorsTek, Jim Umpleby of Caterpillar, Andrew Liveris of Dow Chemical Co (DOW.N), Mark Rohr of Celanese Corp (CE.N); Jeffrey Immelt of GE, Mark Alles of Celgene Corp (CELG.O), David Ricks of Eli Lilly and Co (LLY.N), Tony Simmons of McIlhenny Co, Thomas Kennedy of Raytheon Co (RTN.N), Kenneth Frazier of Merck & Co Inc (MRK.N), Douglas Peterson of S&P Global Inc (SPGI.N), Safra Catz of Oracle Corp (ORCL.N), Gregory Hayes of United Technologies Corp (UTX.N), Ian Read of Pfizer Inc (PFE.N) and Dow Wilson of Varian Medical Systems Inc (VAR.N).
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    US Small-Business Confidence Reaches Highest Point Since December 2004

    Confidence among small-business, in the upswing since the election, in January reached its highest point in more than a decade, according to the National Federal of Independent Business.

    The National Federation of Independent Business’s small-business optimism index edged up to 105.9 in January, the highest point since December 2004 and follows December’s largest month-over-month increase in the survey’s history. Meanwhile, economists surveyed by The Wall Street Journal projected the index to decline slightly to 104.8.

    “Small business owners like what they see so far from Washington,” NFIB Chief Executive Juanita Duggan said.

    The NFIB survey is a monthly snapshot of small businesses in the U.S., which account for most private-sector jobs and about half of the country’s economic output.

    Economists look to the report for a read on domestic demand and to extrapolate hiring and wage trends in the broader economy.

    The January survey is based on 1,874 responses.

    The NFIB—a conservative-leaning small-business lobby based in Washington, D.C.—said that while recent trends look much like the surge in 1983, which was followed by 7 years of gross domestic product expansion averaging 4.5%, such expansion is unlikely this time due to differences in excess capacity available to absorb higher demand.

    Talk of tax and regulatory overhauls along with lowering health insurance costs are resonating with small-business owners, NFIB Chief Economist Bill Dunkelberg said.

    Over all, 48% of respondents expect the economy to improve—down slightly from December, when it jumped 38 percentage points—and 25% think it’s a good time to expand, up 2 percentage points.

    That optimism—backed by government data that show strong, though decelerating, job growth—is translating into hiring and spending. Ultimately, Mr. Dunkelberg said, that could translate into higher gross domestic product expansion for the year.

    The inflation outlook remained stable, the NFIB said.

    Small firms, however, continue to face a shortage of certain skilled workers, with 47% of respondents saying they had few or no qualified applicants for the positions they were trying to fill, according to the report.
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    BHP Billiton boosts interim dividend as iron ore prices soar

    Mining giant BHP Billiton rewarded shareholders with a bigger than expected dividend on Tuesday, signalling its growing confidence amid a resurgence in commodity prices.

    The world's biggest miner reported a near eight-fold rise in underlying first-half net profit to $3.24 billion from $412 million a year earlier, just missing market forecasts for $3.4 billion. It declared a first-half dividend of 40 cents, up from 16 cents a year ago.

    "This is a strong result that follows several years of a considered and deliberate approach to improve productivity and redesign our portfolio and operating model," Chief Executive Andrew Mackenzie said in a statement.
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    Senate frets on Ryan plan

    Republican hopes for an ambitious tax overhaul rest on the House and Senate wings of the party ultimately reaching consensus on what that looks like. So far at least, signs aren’t promising.
    South Carolina’s Lindsey Graham Sunday noted the large number of senators uneasy about the tax plan emerging at the other end of the Capitol.

    Border adjustment tax is on 'life support,' and tax reform may come later ... and with less punch
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    China to start construction on 35 railway projects: report

    It is full steam ahead for China's railway sector asconstruction on 35 new railway projects will start in 2017 as the country plans to expandthe network, according to a recent report in Xinhua-run Economic Information Daily.

    Construction will begin on 2,100 km of new rail line, 2,500 km of double-track lines and 4,000 km of electrified railways this year, the report cited unnamed authorities as saying.

    To achieve the targets, China Railway Corp. (CRC) has been assigned a budget of 800 billion yuan (116.8 billion U.S. dollars) by the central government, the same as in 2016.

    The vice minister of transport, Yang Yudong, disclosed earlier that China will spend 3.5 trillion yuan on railway construction during the 13th Five-Year Plan period (2016-2020).

    By 2020, China will have increased the length of high-speed railways in operation to 30,000 kilometers, connecting more than 80 percent of its big cities.

    By the end of 2016, China had a 124,000 km railway network, featuring the world's largesthigh-speed rail network of more than 22,000 km.

    While the vast network has enhanced connectivity in large swathes of the country, construction lags behind in the less developed western regions. The government wants toaddress this gap.

    Much of this year's construction projects will happen in China's central and western regions, to support the wider poverty-relief campaign, according to CRC.
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    China to shed 50 Mtpa coal capacity, boost clean energy in 2017

    China plans to shut down at least 500 outdated coal mines and use more clean fuel in 2017, the country's top energy watchdog said on February 17.

    The closure of outdated coal mines should lead to a capacity reduction of 50 million tonnes per annum (Mtpa), according to guidelines released by the National Energy Administration (NEA).

    The capacity-target was 80% lower than that of 250 Mtpa for 2016.

    China has a total coal capacity of over 5 billion tonnes per annum, and 300 Mtpa was actually eliminated last year.

    Despite lower target, China may be confronted with greater difficulty in the de-capacity move this year, as the work will more be focused on shutting of operational mines instead of dormant mines dealt with last year, said Jiang Zhimin, deputy head of China National Coal Association, adding the problem of staff resettlement will also be prominent.

    Meanwhile, the guidelines targeted 3.65 billion tonnes of coal output for 2017, a year-on-year growth of 5.8%, noting that coal should account for about 60% of China's total energy consumption. The proportion stood at 64% in 2015.

    China saw its coal output fall for the third consecutive year to 3.36 billion tonnes in 2016, owing to shrinking demand.

    The world's largest coal producer and consumer is now committed to slashing coal capacity as excessive supply weighs on its economy and smog pollutes big cities.

    The guidelines also set goals of capping national energy consumption at around 4.4 billion tonnes of coal equivalent and reducing energy use per unit of GDP by 5%.

    The NEA said the ratio of non-fossil energy use to the total consumption should rise to about 14.3%, up from 13.3% in 2016.

    It specified plans to build more hydropower, wind power and solar power plants this year.

    For nuclear power, 6.41 million KW of installed capacity will be added through the completion of new projects, the NEA said.

    The Chinese government aims to reduce the share of coal in the country's energy mix to 58% by 2020 and increase the share of non-fossil fuels to over 15%.
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    Bridges are OK

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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

    Pioneer Natural Resources: How to Grow Production 15% in a Downcycle

    Pioneer Natural Resources continues to escalate the size of completions in the Permian

    The last year proved to be a difficult time for many oil and gas companies, but many were able to prosper even as oil prices hit multi-year lows and began a slow recovery through the second half of the year. Pioneer Natural Resources (ticker: PXD) was able to increase production 15% year-over-year in 2016, an impressive growth target even when prices were higher, but the company doesn’t plan to stop there.

    Pioneer announced in its fourth quarter and year-end release in February that the company plans to continue that record of growth over the next 10 years and eventually reach 1 MMBOEPD of production by 2026. The key to being able to make that claim is the company’s assets, said Executive Vice President of the South Texas Asset Team, Western Asset Team and Corporate Engineering Ken Sheffield.

    “We have a world-class asset that allows us to grow organically over the next 10 years while spending within cash flow starting in 2018, and generating free cash flow thereafter,” Sheffield told Oil & Gas 360.

    Running 18 rigs in the Permian

    The company’s 2017 capital expenditure plan will consist of approximately $2.8 billion focused primarily on Pioneer’s Spraberry/Wolfcamp horizontal drilling program. PXD will run 18 rigs in the Permian, which it believes will lead to another year of 15%-18% production growth on a BOE basis.

    “We’ll be increasingly using our Version 3.0 completions on the majority of our wells,” said Sheffield, referring to the company’s higher intensity, tighter spacing completion designs. “We’re also going to be testing even larger completions in 12 wells,” he added.

    “We’ve seen consistent increases as we’ve gone from version to version of our upgraded completions, and we may not have yet found the limit of the optimal point on those. We’re going to continue to push the envelope,” said Sheffield.

    Pioneer looks abroad to find customers for increased production: the “ability to export is increasingly important”

    Pioneer’s rapidly growing production needs a place to go, and, with the end of the crude oil export ban, PXD is looking to international markets more and more. The company has already exported to Europe and Canada, and plans to send two cargoes of crude to Asia in the first quarter of 2017, according to the company.

    “We’re in the early innings of international crude exports today, but we’re engaged in it and learning about it. We’re preparing ourselves for the future. With the increase in our production, that ability to export is going to be increasingly important,” explained Sheffield.

    “We believe there is incremental value attached to light sweet crude going to more transportation fuel-focused refineries,” said Sheffield. “U.S. refineries are a little oversupplied for light sweet crude, and they’re more geared to handle heavy crude. If we can redirect lighter sweet crude to hungrier markets, we think that’s a money winning proposition for the company.”
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    France's Engie starts global LPG desk to meet power demand, hedging needs

    France's international utility company Engie has started a global desk to trade liquefied petroleum gas (LPG) and plans to promote the fuel as a replacement for diesel in power generation, senior executives said on Thursday.

    The utility company's trading arm plans to hire 10 people in Singapore, Europe and Houston to move growing LPG supplies from the United States to other parts of the world, Engie Energy Management's CEO Eric Simon told Reuters.

    The United States has become the top exporter of LPG, already sending record volumes to Asia to meet growing demand from residences as cooking and heating fuel and petrochemical complexes for making plastics.

    LPG replaces coal in Engie's trading portfolio as the company has decided to exit that business to focus on cleaner energy sources such as gas and renewables, Simon said.

    "We have to replace this asset class with another one which has much less carbon emissions and which makes sense in terms of trading," he said.

    LPG is a mixture of propane and butane produced as a by-product of U.S. shale gas or other natural gas output.

    Besides supplying LPG globally, the trading unit will also provide risk management and work with Engie's utility division to promote power plants fuelled by propane in Asia, Latin America and Africa, according to the chief executive.

    LPG could replace diesel used in power generators in remote places such as islands and in countries that need time to start natural gas production or build infrastructure.

    "This could be a competitive solution especially if the alternative is diesel," said Engie Asia Pacific's President and Chief Executive Officer Jan Flachet.

    Myanmar, for example, is developing its own natural gas output but in the meantime it could install LPG-fired power plants, Flachet said.

    LPG is traditionally used a bottled cooking fuel, but the use of propane as a petrochemical feedstock has also been growing in Asia.

    Major LPG traders include U.K.-based Petredec, Japan's Astomos Energy, Royal Dutch Shell, Vitol and Itochu Corp.

    Engie - formerly known as GDF Suez - has been trading derivatives of crude oil and products such as middle distillates and fuel oil in Singapore since 2012, hedging risks for the company's other businesses and external clients, said Simon.

    "We're not interested in trading physical oil," he said. "What we're seeing is the development of gas and power markets in Asia," for instance in India, where changes to the gas price formula could increase hedging needs from end-users.

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    YPF, Shell sign deal for Vaca Muerta pilot project

    Argentina's state-run oil company YPF SA said it reached a preliminary deal with Royal Dutch Shell Plc on Thursday to develop oil and gas assets in the Vaca Muerta shale field, involving a $300 million investment from Shell.

    Both companies will take a 50 percent stake in the Bajada de Añelo field to develop a pilot program, which will be operated by Shell, YPF said in a statement. The agreement is subject to approval by provincial authorities, and Shell's investment will come in two phases, YPF said.

    Shell spokeswoman Kimberly Windon confirmed the agreement, adding that the definite terms would be agreed within 60 days and that the project would continue as a full-field development if the pilot is successful.

    The deal comes after President Mauricio Macri reached an agreement with oil companies and unions last month to stimulate investment in Vaca Muerta, which his government hopes can narrow Argentina's energy deficit and reduce costly gas imports.

    The unconventional formation in Patagonia, at roughly 30,000 square kilometers, is roughly the size of Belgium and is one of the largest shale reserves in the world.

    Under the January agreement, Argentina guaranteed a subsidized natural gas price for production from new wells of $7.50 per million British thermal units through 2020, while labor unions signed on to more flexible contracts.

    YPF and Shell, along with oil majors Chevron Corp, Total SA and BP unit Pan American Energy LLC [BPPAE.UL], agreed to invest a total of $5 billion to tap the formation in 2017 and double that in coming years, Macri said.

    YPF said it would invest $2.3 billion in Vaca Muerta this year, while the other companies did not announce specific investments.

    Last year, Shell said it planned to invest $300 million per year through 2020 in Argentina in exploration, refining, distribution and marketing. Bajada de Añelo totals some 204 square kilometers (78.76 square miles) and has both shale oil and shale gas resources, YPF said.
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    Iran says oil prices over $55 per barrel harmful for OPEC: Fars

    Iran said on Thursday an increase in oil prices to more than $55 per barrel was not in the interest of OPEC as it would lead to a rise in output by non-OPEC producers, the semi-official Fars news agency reported.

    "If oil prices specifically surge over $55 or $60 per barrel, non-OPEC producers will increase their crude production to benefit the most from the price hike," Iranian Oil Minister Bijan Zanganeh was quoted by Fars as saying.

    "OPEC is determined to reduce its production to help manage the market."

    Benchmark Brent crude oil was trading up $1.18 a barrel at $57.02 as of 1429 GMT.

    The Organization of the Petroleum Exporting Countries agreed on Nov. 30 to cut output by 1.2 million barrels per day for the first six months of 2017, in addition to 558,000 bpd of cuts pledged by independent producers such as Russia and Oman.

    OPEC Secretary-General Mohammad Barkindo said that January data showed conformity from participating OPEC nations with output curbs had been above 90 percent and oil inventories would decline further this year.

    Iran was exempted from the production cut as Tehran argued its output should be allowed to recover after the lifting of international sanctions in January last year.
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    Oil sold out of tanker storage in Asia as market slowly tightens

    tankers anchored off Malaysia, Singapore and Indonesia in a sign that the production cut led by OPEC is starting to have the desired effect of drawing down bloated inventories.

    Yet in the short-term, the crude released from tankers will weigh on markets and possibly undermine OPEC's goal of achieving a balanced market by mid-2017.

    The Organization of the Petroleum Exporting Countries (OPEC) and other producers outside the group, including Russia, announced late last year that they would cut output by almost 1.8 million barrels per day (bpd) during the first half of 2017, looking to drain a glut that pulled down prices from over $100 per barrel in 2014 to around $56.50 currently LCOc1.

    "OPEC's strategy is targeting inventories – given the scale of the overhang, the market won't rebalance in six months – we expect an extension into (the second half of 2017)," said Energy Aspects analyst Virendra Chauhan.

    As OPEC's cuts start to leave some demand unmet, a hefty 6.8 million barrels of crude has been taken out of tanker storage from Linggi, off Malaysia's west coast, in February, shipping data in Thomson Reuters Eikon shows.

    An additional 4.1 million barrels and another 1.2 million barrels have been taken out of storage on tankers in Singaporean and Indonesian waters, the data shows.


    In the short-term, the flood of crude from floating storage will add to supplies coming into Asia from as far away as the Americas and Europe.

    In the longer-term, however, clearing oil out of inventories like tankers is part of OPEC's goal to rebalance markets.

    "Inventories will continue to decline driven by the combination of production cuts and the strong demand growth," U.S. bank Goldman Sachs said this week in a note to clients, adding that it expected Brent prices to rise slightly in the second quarter, to $59 per barrel.

    Traders charter supertankers like Very Large Crude Carriers (VLCC), in which they can store up to 2 million barrels of oil for extended periods of time, when a market situation known as contango is in place, with prices for later delivery higher than those for immediate dispatch.

    The January to June 2017 contango in the forward curve was almost $3 per barrel, compared to a June premium of under half a dollar now.

    With prices further out into 2018 and beyond even falling, the curve has fallen into what traders call backwardation, which makes it unattractive to store oil on chartered tankers.

    "Dancing contango is now not a profitable thing to do, so we've sold out," said one oil trading manager who, until recently, held crude stored in a tanker. He spoke on condition of anonymity due to the commercial sensitivity of the issue.
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    Carrizo Oil & Gas, Inc. Announces Fourth Quarter and Year-End Results and Provides 2017 Guidance

    Carrizo Oil & Gas, Inc. Announces Fourth Quarter and Year-End Results and Provides 2017 Guidance

    Carrizo Oil & Gas, Inc. today announced the Company’s financial results for the fourth quarter of 2016 and provided an operational update, which includes the following highlights:

    Crude oil production of 28,727 Bbls/d, 15% above the fourth quarter of 2015
    Total production of 44,775 Boe/d, 11% above the fourth quarter of 2015
    Loss From Continuing Operations of $0.8 million, or $0.01 per diluted share, and Net Cash Provided by Operating Activities From Continuing Operations of $74.9 million
    Adjusted Net Income of $28.4 million, or $0.44 per diluted share, and Adjusted EBITDA of $118.1 million
    291% reserve replacement from all sources at a finding, development, and acquisition (FD&A) cost of $13.65 per Boe
    2017 drilling and completion capital expenditure guidance of $530-$550 million
    2017 crude oil production growth target of 23%
    Three-year compound annual crude oil production growth target of more than 20%
    Increasing Eagle Ford Shale inventory by more than 10% based on additional successful downspacing pilots

    Carrizo reported a fourth quarter of 2016 loss from continuing operations of $0.8 million, or $0.01 per basic and diluted share compared to a loss from continuing operations of $380.7 million, or $6.73 per basic and diluted share in the fourth quarter of 2015. The loss from continuing operations for the fourth quarter of 2016 includes certain items typically excluded from published estimates by the investment community. Adjusted net income, which excludes the impact of these items as described in the non-GAAP reconciliation tables included below, for the fourth quarter of 2016 was $28.4 million, or $0.44 per diluted share, respectively, compared to $18.5 million, or $0.32 per diluted share, respectively, in the fourth quarter of 2015.

    For the fourth quarter of 2016, Adjusted EBITDA was $118.1 million, an increase of 5% from the prior year quarter due to higher production volumes and commodity prices. Adjusted EBITDA and the reconciliation to loss from continuing operations are presented in the non-GAAP reconciliation tables included below.
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    Concho to operate 19 rigs in 2017

    Concho expects to 2017 CapEx to be between $1.6 and $1.8 billion, with 90% of this spent on drilling and completing wells. 60% of CapEx will be spent in the Delaware basin and 30% will be spent in the Midland, with the remaining 10% going to operations in the New Mexico Shelf. Concho expects to operate an average of 19 rigs in 2017, down slightly from the 21 operating currently. These rigs will fuel production growth of between 20% and 24% in 2017, with oil production growing 25%.

    Record average 30-day peak production in Midland basin

    Concho Resources is a pure-play Permian E&P, with all its acreage in the basin. The company owns about 540,000 gross acres in the Delaware basin, where Concho is currently operating 13 rigs. Concho is currently testing multi-zone pads in the Delaware, which seek to access several of the stacked pay intervals available from the same location.

    Concho’s Midland basin development, where the company owns 260,000 gross acres, has seen recent success. Extensive use of multi-well pads in the basin allowed Concho to add 11 wells in Q4, which produced a record average 30-day peak rate of 1,299 BOEPD. In the basin in 2017 the company plans to exclusively drill 10,000’ laterals from multi-well pads.

    Concho owns 130,000 gross acres in the New Mexico Shelf, which was the company’s first Permian basin property. While the New Mexico Shelf has historically been accessed with vertical wells, Concho is currently testing horizontals on the acreage. If these tests are successful the company will be able to further access the resource potential of the asset that allowed it to go public in 2007.
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    Explosion hits Nigeria LNG pipeline

    Nigeria LNG, the operator of the 22 mtpa liquefied natural gas plant on Bonny Island, reported a pipeline explosion on Wednesday, February 22.

    According to the company’s statement, the explosion went off “on a section of the Right of Way housing two gas transmission pipelines, one of which belongs to Nigeria LNG, about 3 kilometers from Rumuji in Rivers State.”

    So far the cause of the explosion has not been determined NLNG sai, adding that no injuries or fatalities have been reported.

    Nigeria LNG continues the investigation into possible reasons for the explosion that rocked its gas transmission system.

    The company further urged the communities closest to the explosion site to stay clear for safety purposes while the investigation continues.

    The company, owned by Nigerian National Petroleum Corporation (49 percent), Shell (25.6 percent), Total LNG Nigeria (15 percent) and Eni (10.4 percent), also supplies about 40 percent of the annual domestic LPG consumption.

    Further updates on the incident will be provided in due course, Nigeria LNG added.
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    Kosmos, BP firm ties on West African LNG project

    Kosmos Energy received governmental approval and completed the $916 million farm-out of assets in the Mauritania-Senegal basin to BP.

    Under the transaction, BP has acquired 49.99 percent interest in Kosmos BP Senegal, a joint company holding 65 percent participating interest in the Cayar Offshore Profond and the Saint Louis Offshore Profond blocks offshore Senegal, that could underpin a development of a “world-class” LNG project.

    According to the agreement announced in December last year, Kosmos will receive a $162 million upfront payment, $221 million carry on exploration and appraisal, including a drill stem test on Tortue expected to be completed in 2017 and $533 million maximum carry on development costs until first gas production on the Tortue project.

    Kosmos said it expects a front-end engineering and design study to be completed in 2017 with the objective of reaching a final investment decision by 2018.

    Kosmos will also receive a contingent bonus of up to $2 per barrel, for up to 1 billion barrels of liquids, structured as a production royalty, subject to a future liquids discovery and oil price.

    Commenting on the agreement, BP chief executive officer Bob Dudley that the cooperation with Kosmos Energy and the Mauritanian and Senegalese governments enable the creation of a new LNG hub in Africa.

    In order to reduce development time and drive capital efficiency, the partners plan to process and transport the gas from Tortue at a nearshore LNG facility. The proposed complex could be expanded in phases to accommodate future gas discoveries.
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    Chesapeake Energy posts smaller quarterly loss

    U.S. natural gas producer Chesapeake Energy Corp (CHK.N) on Thursday posted a smaller fourth-quarter loss than a year earlier, when it took huge charges to write down the value of some oil and gas assets.

    The company's shares were up 3.6 percent at $6.13 in premarket trading.

    Chesapeake said production averaged about 574,500 barrels of oil equivalent per day (boepd) in the quarter, down 13.1 percent from a year earlier.

    Chesapeake, like its peers, has been selling assets to lower its crippling debt load after a tow-year rout in oil prices depleted its cash balances.

    The company narrowed its 2017 capital budget last week, but maintained its production target of 532,000-562,000 boepd.

    The company's net loss available to shareholders narrowed to $741 million, or 84 cents per share, in the three months to Dec. 31, from $2.23 billion, or $3.36 per share, a year earlier.

    The year-ago quarter included charges of about $2.83 billion, mainly for asset impairment.

    Excluding items, the company earned 7 cents per share, in line with the average analysts' estimate, according to Thomson Reuters I/B/E/S.

    Chesapeake's total revenue fell nearly 24 percent to $2.02 billion in the latest quarter, narrowly missing analysts' average estimate of $2.08 billion.
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    Oil and gas producer Apache to spend 60 pct more this year

    Oil and gas producer Apache Corp said it would spend 60 percent more in 2017 than it did last year, joining a growing list of U.S. shale producers who are ramping up spending to take advantage of a recovery in oil prices.

    Apache, which reported a smaller loss on Thursday, plans to spend $3.1 billion in 2017, higher than the $1.9 billion it spent last year.

    The company said it would spend nearly two-thirds of its budget in Texas' Permian Basin, of which $500 million is budgeted for infrastructure development in the so-called Alpine High field.

    Total production was nearly unchanged at 490,376 barrels of oil equivalent per day in the fourth quarter.

    Apache said last September it had amassed more than 300,000 acres in the field it calls Alpine High, most of which is in Reeves County, Texas.

    U.S. crude prices, which dipped to a low of $26.05 last year have largely traded above $50 since late November.

    This has prompted producers such as Exxon Mobil, Chevron Corp and Hess Corp to boost their capital budgets for the year.

    Net loss attributable to Apache's common shareholders was $182 million, or 48 cents per share, in the three months ended Dec. 31. (

    The company had posted a loss of $4.02 billion, or $10.62 per share, a year earlier, when it incurred one-time charges of $5.9 billion.

    The Houston-based company's total revenue fell about 2 percent to $1.45 billion.

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    Sandbox: Volume not Price.

    Now, let's turn to our market outlook for this year. We're seeing surging demand for sand proppant and last mile logistics driven by the continued increase in U.S. horizontal rig count, longer laterals and a double-digit increase in proppant per foot drilled. If these trends continue 2017 demand for sand proppant maybe greater than our current forecast of 60 million tons. The significant increase in sand demand is also driving higher overall sand pricing and a tightening of the last-mile trucking market, making efficiency gains associated with Sandbox even more valuable to our customers.

    We have a comprehensive strategy to win in the current market environment and we're responding aggressively to deploy capital and resources to support our customers. Let me give me you a few examples. First, we plan to have all of our oil and gas sand assets operating at maximum capacity in the near future. Second, over the next 12 to 18 months, we expect to invest in a mix of expansions at existing sites, new greenfield sites and acquisitions that will collectively approximately double our low cost oil and gas production capacity to more than 20 million tons per year. Third, we'll make additional capital investments in Sandbox this year. We continue to add new customers and expand existing customer relationships and we're quickly ramping up capacity to meet the growing demand.

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    Norway oil companies raise 2017 investment forecasts -survey

    Norway's oil companies have increased their 2017 investment plans in the last three months, signalling a smaller-than-expected contraction for the industry, a survey by the statistics office showed on Thursday.

    Investments in oil and gas extraction and pipeline transport were still expected to fall for the third year in a row as companies cut the spending after oil prices fell by more than 50 percent over the last two-and-a-half years.

    The country's oil companies now plan to invest 149.4 billion crowns ($17.87 billion) next year in oil and gas extraction and pipeline transport, 1.9 percent more than the 146.6 billion crowns seen last November but down from 163.3 billion in 2016.

    "The increase is mainly due to higher estimates for field development, fields on stream and shutdown and removal," Statistics Norway said in a statement.

    The numbers were helped by some removal projects being postponed from the fourth quarter to 2017, it added.

    The 2017 forecast should be viewed as positive news for the economy, Nordea Markets economist Erik Bruce said, adding it was probably 4-5 percent ahead of the central bank's forecast when measured in inflation-adjusted terms.

    "It's an argument in favour of the central bank lifting its interest rate path projections at the March meeting,... but not to the point of raising rates." he added.

    SEB economist Erica Blomgren also said the survey was positive for the economy.

    "The central bank's forecast (for 2017) may turn out to be too pessimistic," she added.

    The Norwegian central bank said in December it expected to keep interest rates steady at a record low 0.5 percent in the years ahead, but added the probability of a rate cut was greater than the chance of a hike.

    Over the last two years oil and gas investments contracted by 27 percent, after rising by 70 percent from 2010-2014 when high and relatively stable oil prices supported new developments and high drilling activity offshore Norway.

    The Norwegian oil and gas industry's share of gross domestic product (GDP) contracted to 12 percent in 2016 from 25 percent at its peak in 2008.

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    Italy's OLT seeks up to 20 LNG cargoes for April-September delivery -sources

    Italy's OLT LNG import terminal moored off the Tuscan coast is seeking up to 20 cargoes of liquefied natural gas (LNG) for delivery between April and
    September, two trade sources with direct knowledge of the tender said on Thursday.

    The Italian firm is seeking delivery of two cargoes in September, three cargoes in the months of April and June, and four cargoes in May, July and August. The tender closes on Mar. 6 and will have same-day validity, the sources added.
    OLT is only expected to purchase 15 out of the 20 cargoes sought as the infrastructure capacity constraints at the project will limit its purchases to 1.5 billion cubic meters of natural gas (1.09 million tonnes of LNG), one of the sources said, adding that only bidders with industrial demand for gas in Italy
    could participate.

    Swiss trader Dufenergy last year secured four of five import slots to bring LNG into OLT.
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    Summary of Weekly Petroleum Data for the Week Ending February 17, 2017

    U.S. crude oil refinery inputs averaged about 15.3 million barrels per day during the week ending February 17, 2017, 187,000 barrels per day less than the previous week’s average. Refineries operated at 84.3% of their operable capacity last week. Gasoline production increased last week, averaging over 9.4 million barrels per day. Distillate fuel production decreased last week, averaging about 4.5 million barrels per day.

    U.S. crude oil imports averaged 7.3 million barrels per day last week, down by 1.2 million barrels per day from the previous week. Over the last four weeks, crude oil imports averaged about 8.4 million barrels per day, 7.5% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 367,000 barrels per day. Distillate fuel imports averaged 129,000 barrels per day last week.

    U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 0.6 million barrels from the previous week. At 518.7 million barrels, U.S. crude oil inventories are above the upper limit of the average range for this time of year. Total motor gasoline inventories decreased by 2.6 million barrels last week, but are at upper limit of the average range. Both finished gasoline inventories and blending components inventories decreased last week. Distillate fuel inventories decreased by 4.9 million barrels last week but are above the upper limit of the average range for this time of year. Propane/propylene inventories fell 3.3 million barrels last week but are in the middle of the average range. Total commercial petroleum inventories decreased by 11.0 million barrels last week.

    Total products supplied over the last four-week period averaged 19.8 million barrels per day, up by 0.7% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged 8.6 million barrels per day, down by 5.2% from the same period last year. Distillate fuel product supplied averaged about 4.0 million barrels per day over the last four weeks, up by 14.4% from the same period last year. Jet fuel product supplied is up 2.5% compared to the same four-week period last year

    Cushing falls 1.6 mlm bbls
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    US Oil Production breaks through 9.0mln bbls

                                                       Last Week   Week Before    Last Year

    Domestic Production '000........ 9,001            8,977            9,102
    Alaska .......................................... 518            ..  511               514
    Lower 48 .................................. 8,483            8,466            8,588
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    Here comes the Permian

    Image titleImage titleImage title
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    Leviathan gas field developers approve $3.75 billion investment

    Developers of the Leviathan natural gas field have approved a $3.75 billion investment (FID) in the first phase of the largest energy project in Israel's history, they said on Thursday.

    The reservoir, located 100 km (62 miles) west of Haifa, was discovered in December 2010. Its $3.75 billion budget follows $1 billion that has already been invested in exploration, appraisal and planning activities.

    According to a development plan approved by the government in 2016, the project will be completed in less than three years and gas will be available to the Israeli market by the end of 2019.

    Texas-based Noble Energy owns 39.7 percent of Leviathan, while Delek Drilling and Avner Oil Exploration, subsidiaries of Israel's Delek Group, each hold 22.7 percent. Israel's Ratio Oil holds 15 percent.

    Ratio shares were up 2 percent in afternoon trade in Tel Aviv, while Delek Drilling and Avner were 1 percent higher.

    The first stage of work will involve drilling four production wells at an average depth of around 5 km below sea level. These will produce about 12 billion cubic meters (bcm) of gas annually, which will double the volume of gas available to the Israeli market.

    "This is a day of good tidings for the economy and people of Israel. This move will provide gas to Israel and promote cooperation with countries in the region," Prime Minister Benjamin Netanyahu said on Twitter.

    The gas from Leviathan will be transported through two underwater pipes 120 km in length to a processing and production platform situated 10 km offshore.

    The processed gas will be piped from the platform, through a northern entry pipeline that will be connected to the national gas transmission system of Israel Natural Gas Lines.

    "Developing Leviathan and pursuing more export agreements, coupled with supply to the domestic market, will ensure energy security for Israel and will add to Delek Group's stability," said the company's chief executive, Asaf Bartfeld.

    Noble, the group's operator, said its share of the bill was $1.5 billion. It plans to fund phase one with operating cash flows from the nearby gas field Tamar, as well as east Mediterranean portfolio proceeds. Regional portfolio proceeds received to-date total about $575 million, it said.

    Noble said it was also securing access to a financing facility for additional funding flexibility.

    Noble projects operating cash flow for the first year following Leviathan's start-up to be at least $650 million net.
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    China’s LNG imports rise almost 40 pct in January

    Liquefied natural gas (LNG) imports into China, the world’s largest energy consumer, rose 39.7 percent in January as compared to the same month a year before, according to the General Administration of Customs data.

    China’s LNG imports increased to 3.44 million mt in January, the second-highest monthly import level, behind a record 3.73 million mt set the month before as a cold snap across the country spurred demand.

    The country is the world’s third-biggest LNG importer, behind South Korea and the top LNG buyer, Japan. Its imports rose 33 percent to 26.06 million mt in 2016.

    China started importing chilled gas in 2006. The country’s LNG imports are expected to continue to rise as it as it is seeking to cut its addiction to coal to reduce pollution.
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    Range Reports 2016 Earnings, Announces 2017 Capital Plans

    Highlights –

    Record average daily production of 1.854 Bcfe during the fourth quarter
    2017 capital budget set at $1.15 billion, projected to provide 33-35% year-over-year growth in 2017 and approximately 20% organic growth in 2018
    North Louisiana well costs reduced to $7.7 million per well from $8.7 million previously
    Fourth quarter 2016 unhedged cash margins improved by over four times to $0.97 per mcfe, compared to $0.22 per mcfe in fourth quarter 2015
    Reserve replacement of 292% at $0.34 per mcfe drill-bit development cost for 2016

    Commenting, Jeff Ventura, the Company’s CEO said, “2016 was a significant year for Range, as we completed the acquisition of Memorial Resource Development in September, providing Range operational and geographic diversity with wells that rival our prolific Marcellus wells.  In addition, we are beginning to see the advantages of a diversified marketing portfolio, as prices are expected to improve for all products in 2017, driving higher margins and a peer-leading recycle ratio.  Higher expected margins and cash flow provide us the opportunity to increase our capital budget to $1.15 billion in 2017, after two consecutive years of declining capital spending.  This increased activity in 2017 results in solid growth this year, but also positions us well for 2018 and beyond.  With thousands of future locations in our core inventory and talented operational, technical and marketing teams, Range is well-positioned to drive shareholder value for years to come.”
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    Exxon revises down oil and gas reserves by 3.3 billion barrels

    U.S. oil major Exxon Mobil Corp has revised down its proved crude reserves by 3.3 billion barrels of oil equivalent as a result of low oil prices throughout 2016, a company filing showed on Wednesday.

    The de-booking includes the entire 3.5 billion barrels of bitumen reserves at the Kearl oil sands project in northern Alberta, operated by Imperial Oil, a Calgary-based company in which Exxon has a majority share.

    It comes a day after ConocoPhillips Corp de-booked more than a billion barrels of its oil sands bitumen reserves, citing weak global crude prices.

    In total Exxon has 20 billion barrels of oil equivalent at year-end 2016, the Securities Exchange Commission filing said. The reduction reflects the number of barrels of oil equivalent that were now deemed uneconomic due to lower crude prices.

    In addition to the Kearl volumes, another 800 million barrels of oil equivalent in North America failed to qualify as proved reserves.

    However the reductions were partly offset by Exxon adding 1 billion barrels of new oil and gas reserves in the United States, Kazakhstan, Papua New Guinea, Indonesia and Norway.

    Under SEC rules Exxon and other U.S.-listed companies report reserves based on the average crude price on the first day of each calendar month during the year.

    Benchmark crude prices in 2017 have so far been higher than in 2016, meaning some of the volumes could be rebooked as proved reserves if these levels hold.
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    API reports oil inventory fall

    Crude inventories fell by 884,000 barrels in the week to Feb. 17 to 512.7 million, compared with analyst expectations for an increase of 3.5 million barrels, data from industry group the American Petroleum Institute showed on Wednesday. [API/S]

    That added to optimism earlier in the week when the Organization of the Petroleum Exporting Countries said a deal with other producers including Russia to curb output was showing a high level of compliance.

    However, for prices to break out of their trading ranges, the market needs to see signs that OPEC inventories are falling, said Tony Nunan, oil risk manager at Mitsubishi Corp in Tokyo.

    "It's a battle between how quick OPEC can cut without shale catching up," Nunan said, referring to U.S. drilling in shale formations that has shown an upsurge after prices rose this year. [RIG/U]

    "What OPEC really has to do is get the inventories down," he said.

    Eleven non-OPEC oil producers that joined the OPEC deal have delivered at least 60 percent of promised curbs so far, OPEC sources said on Wednesday, higher than initially estimated.

    In the United States, crude stocks at the Cushing, Oklahoma, delivery hub were down by 1.7 million barrels, while U.S. crude imports fell last week by 1.5 million barrels per day (bpd) to 7.398 million bpd, according to the API.
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    Pass the Oil Parcel

    Crude prices are selling off today as gasoline holds up relatively better, as refiners playing 'pass the parcel' of bearishness betwixt the two. As refiners make economic run cuts due to lower profit margins, gasoline inventories are set to drop going forward amid lower supply....while crude inventories are set to continue to swell.

    A key theme of last month's Clipper View presentations, when the mighty Abudi Zein and myself presented our six-month market outlook, was that product prices would lag crude because of high inventories. Our view was that this would ultimately lead to refinery runs being cut due to unfavorable economics, which would then encourage the de-stocking of product inventories. This scenario is coming to fruition.

    U.S. refiners are starting to cut refinery runs amid record high gasoline inventories and slumping profit margins. At least three refineries have made cuts, and more seem set to follow.

    While this will help to de-stock product inventories, this turns into a game of whack-a-mole for the crude complex. As product stocks ease due to lower refining activity, this is only going to encourage already-swollen crude inventories higher still. Refinery runs have just dropped below last year's level for the first time this year:

    While we are seeing record crude exports that could provide a bit of respite for rising US crude inventories, this is being offset somewhat by rising domestic production. As our ClipperData illustrate below, US waterborne crude imports this month are above both last year and February 2015, although lagging 2014's level by nearly 400,000 bpd.

    This lag makes sense given that domestic production and pipeline flows from Canada combined were about 10.5mn bpd in February 2014, while they have been around 12.5mn bpd for 2015, 2016, and now 2017 too.
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    Sanchez Energy Announces Fourth Quarter and Full-Year 2016

    Sanchez Energy Corporation, today announced operating and financial results for the fourth quarter and full-year 2016.  Highlights include:

    Partnership with Blackstone Energy Partners (“Blackstone”) to acquire Anadarko Petroleum Corporation (NYSE:APC) (“Anadarko”) interests in the Western Eagle Ford for approximately $2.3 billion, subject to normal and customary closing conditions (the “Comanche Transaction”) announced January 12, 2017;
    Active leasing program over the last twelve months resulted in the acquisition of 65,000 acres in the oil window of the Western Eagle Ford, and 45,000 acres in the dry gas window of the Western Eagle Ford;
    Total 2016 production of 19.5 million barrels of oil equivalent (“MMBoe”), or approximately 53,350 barrels of oil equivalent per day (“Boe/d”), exceeded the Company’s 50,000 to 52,000 Boe/d guidance;
    Year-end Proved Reserves increased by over 55% (excluding acquisitions and divestitures) to approximately 193 MMBoe, and generated an approximate 430% reserve replacement ratio;
    Recent development and pilot wells de-risked the Upper Eagle Ford in Northwestern Catarina, thereby confirming the presence of this additional zone on the Comanche acreage;
    North Central Catarina Step-out appraisal pad continues to produce 10-15% above Western Stack type curve forecast with yields over 250 Bbl of liquids per MMcf of natural gas; derisking the eastern portion of the West Stack area;
    Drilling and completion costs during 2016 at Catarina and Maverick averaged approximately $3.0 million per well, which included larger completion jobs at Catarina and Maverick during the second half of the year;
    The Company’s 2017 capital budget is estimated between $425 and $475 million, including expected activity on the Comanche acreage beginning March 2017;

    The Company reported net income of $48 million for the fourth quarter 2016;

    For the year ended December 31, 2016, the company reported a net loss of $273 million;
    Fourth quarter 2016 revenues were approximately $126 million, an increase of approximately 15% percent when compared to the fourth quarter 2015; Adjusted revenue (a non-GAAP financial measure), inclusive of hedge settlement gains, was approximately $145 million during the fourth quarter 2016;
    Full year 2016 revenues were approximately $431 million; Adjusted revenue (a non-GAAP) financial measure), inclusive of hedge settlement gains, was approximately $567 million for the year;

    Adjusted EBITDA (a non-GAAP financial measure) was approximately $79 million during the fourth quarter 2016;
    Full year 2016 Adjusted EBITDA (a non-GAAP financial measure) was approximately $307 million;
    On Feb. 6, 2017, the Company reinforced its strong liquidity position by closing the previously announced public equity offering, which resulted in net proceeds of approximately $136 million; and
    As of Dec. 31, 2016, the Company had approximately $800 million in liquidity with approximately $500 million in cash and cash equivalents and an undrawn bank credit facility with an elected commitment amount of $300 million.
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    Gas Pioneer Chesapeake Embarks on Oil Quest to Escape Junk Label

    Chesapeake Energy Corp., the No. 2 U.S. natural gas producer, thinks it has a one-word answer to its debt issues: Oil.

    Chief Executive Officer Doug Lawler is focusing 60 percent of the Oklahoma City-based driller’s 2017 budget on crude oil projects, mostly in South Texas, Oklahoma and Wyoming shale fields. The company plans about 320 new crude wells this year, compared with 90 for gas, Lawler said on Feb. 14. The hoped-for result: Oil output, set to grow 10 percent in 2017, could grow by double that rate next year.

    The former deep-water exploration chief for Anadarko Petroleum Corp. has been striving to bring the gas producer back on its feet after inheriting suffocating debt, collapsing cash flow and wilting reserves 3 1/2 years ago. Lawler’s emphasis on crude derives from the fact that oil fetches three or four times more money on an energy-equivalent basis.

    “He likes to set big goals and this is the biggest one of all,” said James Sullivan, senior analyst at Alembic Global Advisors in New York, one of six analysts following the company with the equivalent of buy ratings on Chesapeake’s stock.

    Chesapeake is expected to post its first profit since the end of 2014 when it reports fourth-quarter results on Feb. 23. Excluding one-time items, the company is forecast to disclose per-share profit of 6.1 cents, based on the average of 27 analysts’ estimates compiled by Bloomberg. That would compare with a loss of 16 cents a share for the final three months of 2015.

    The company lost a cumulative $18.5 billion over the past seven quarters, struggling with a combination of rock-bottom gas prices and strangling debt obligations. More than $21 billion in field writedowns during that period bled Chesapeake’s balance sheet as faltering prices dimmed the likelihood those assets would ever generate profits.

    As activist investor Carl Icahn’s hand-picked choice to replace Aubrey McClendon in 2013, Lawler let go of two out of every three employees, repurchased company bonds at cut-rate prices and dismantled complex financial instruments that were his predecessor’s forte. In January, the company restored dividends on four classes of convertible preferred stocks, though the payout on common shares remains suspended.

    A key step in Lawler’s plan to convince credit rating companies to bestow investment-grade blessings will be funding operations without having to borrow any money, a state known as cash-flow neutrality that he expects to reach in 2018. Moody’s Investors Service rates Chesapeake’s long-term debt Caa1, or seven levels below investment grade. S&P rates the company B-, six levels into junk territory.

    “We still have had this target about achieving investment-grade metrics,” Lawler said during a Credit Suisse event on Feb. 14. “And this still is a long-term target for the company. But we have a plan in which we believe we’ll be achieving that in the next few years.”


    The company has a long way to go before crude supplants gas as its main product. The furnace and factory fuel that Chesapeake was instrumental in unlocking from North American shale fields during the last decade still comprises about 85 percent of its production. In fact, Chesapeake pumps so much gas that only international energy titan Exxon Mobil Corp. has a bigger stake in U.S. gas markets, according to the Natural Gas Supply Association.

    Earlier aspirations to make Chesapeake an oil producer sputtered because the company’s precarious cash position forced it to devote scarce dollars to gas fields that needed sprucing up to make them suitable for sale, Alembic’s Sullivan said. That left Chesapeake too poor to exploit holdings it suspected were rich in crude but had yet to be drilled.

    Still, Lawler telegraphed his growing crude bias last year when he agreed to give up the company’s entire Barnett Shale portfolio and exit the birthplace of the shale revolution to escape almost $2 billion in onerous pipeline contracts.

    The Barnett region of North Texas is famous for the gassy content of any wells drilled there. By the time Chesapeake walked away, the Barnett has shriveled to just 10 percent of the company’s output, overshadowed by mammoth deposits in the Marcellus and Utica shales in the U.S. Northeast.

    “Now they have room that will allow them to deploy capital to higher-return” oil projects, said Jason Wangler, an analyst at Wunderlich Securities Inc. in Houston with a “buy” rating on Chesapeake shares.

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    Mexico turns to the Jurassic era for shale oil: Fuel for Thought

    Mexico's plans to develop its shale oil resources have finally taken a step forward following years of largely fruitless efforts by the state owned company Pemex.

    Canada's Renaissance Oil and Russia's Lukoil are joining forces to develop the Amatitlan block of the Chicontepec region. They aren't interested in the shallower tight oil, but in the stack's deeper Pimienta shale formation, which is what they consider Mexico's Eagle Ford.

    Renaissance and Lukoil agreed to a $60 million accelerated development plan for the Amatitlan block for 2017, which will include workovers of existing wells, and the drilling of new wells.

    The Pimienta formation, located in the Upper Jurassic layer of the Chicontepec, is an important play for the future production of Mexico, as output has been trending lower.

    Renaissance estimates original oil in place in the Amatitlan block at 4.2 billion barrels of oil equivalent, and estimated the Pimienta section at 564 boe per acre-foot, compared with Eagle Ford at 598 boe. Also, both formations have similar pore pressure.

    Despite being discovered in 1962, the Amatitlan is largely underdeveloped. The field has produced about 175,000 barrels of light oil, ranging from 34 to 44 API.

    Pemex estimates that the entire Pimienta holds 20.8 billion boe, mostly liquid hydrocarbons. In 2014, Pemex explored for the first time the Pimienta formations by drilling three conventional exploratory wells.

    According to Nick Steinsberg, director of engineering with Renaissance Oil, one of these wells has produced close to 800 b/d.

    Renaissance is bringing shale experience to the project. Steinsberg pioneered horizontal drilling in the US Barnett Shale with Devon Energy. Dan Jarvie, Renaissance's chief geochemist, was the former chief geochemist of EOG Resources, Eagle Ford's largest shale producer.

    The biggest challenge for the Amatitlan is cutting costs, Luis Miguel Labardini, country manager for Renaissance, told S&P Global Platts.

    Labardini said that key to bringing costs down have to do with good project management—reducing rig time and reaching the technical optimal rate of drilling.

    The structure of Mexico's oil service industry also presents a cost challenge, said Labardini.

    Renaissance has developed some bidding guidelines and will auction all the operating service contracts later this year, he said.

    Pemex's exploration plan for Amatitlan shows that the state oil company will drill an exploratory unconventional well named OPS-1 at the cost of $8.9 million.

    The well will have a depth of 12,112 feet and a horizontal length of 6,561 feet to exploit a target point at 9,465 feet in the Pimienta formation. Drilling and completing the well would take 122 days.

    Similar to Eagle Ford geology, not costs

    In contrast, Sanchez Energy said in September it was able to reduce per-well drilling costs in the Eagle Ford down to $3.5 million, while Chesapeake Energy said at the same time it was able to drill a well in as little as eight days.

    Pimienta is the Chicontepec region's biggest prize, said Colin Stabler, a geologist contractor with Pemex in the 1960s and later Shell E&P director for Mexico from 1997 to 2004.

    Stabler studied Pimienta and other Mexican Jurassic formations with Pemex. In 2013, during Pemex's Chicontepec auction round, he analyzed the Pimienta for a participating company as a consultant.

    “We recognized Amatitlan is the best block for Pimienta,” Stabler told Platts, adding that there are key differences between Pimienta and Eagle Ford including its depth and proximity to mountains.

    Stabler said he shares Renaissances optimism for Pimienta's geology. However, “geological similarities between Eagle Ford and Pimienta doesn't translate as well to economic similarities.”

    “Renaissance's biggest challenges are on the surface,” Pablo Medina, Latin America upstream research analyst at Wood Mackenzie, told Platts.

    Medina said the block has great potential, but access to water and roads, dealing with indigenous communities, migrating the service contract, a regulatory framework on the making, and low energy prices will need to be overcome.

    “It could be a game changer, but not because it is Amatitlan, but because they are the first. They will be trailblazing,” said Medina.

    Fulfilling Mexico's need for sweet crude oil will be an interesting market in the near future, said Labardini, adding that Pemex might need to import as many as 100,000 b/d of light oil in the coming years.
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    Repsol profitable in 2016. Production rises

    Spanish oil firm Repsol has reported a full year 2016 net profit of 1.7 billion euros, up from a net loss of around 1.4 billion euros a year ago.

    According to Repsol, this is the company’s highest annual net income in the last four years, boosted by the company’s successful execution of its efficiency program as it has managed to cut its operational costs by 1.6 billion euros.

    The company’s upstream segment also posted a net profit. The Upstream net profit was 52 million euros, a hefty increase compared to a loss of 925 million euros in 2015.

    Repsol CEO Josu Jon Imaz said that 2016 was a very demanding year.

    “Firstly, because of market volatility. Secondly, because it has been a year with low oil and gas prices. In this environment, Repsol has shown that it is able to create value at $43 per barrel Brent, and that with these prices and throughout its business, it is able to generate cashflow in organic terms after paying dividends to its shareholders.

    “All this has been possible, first of all, thanks to an efficiency program. We have reduced our operational costs by more than €1.600 billion and we have beaten by 50% the already ambitious goal we had set in our Strategic Plan. Secondly, thanks to exhaustive control of CAPEX, investments,” the CEO said.

    Average production increased 23% in the year to 690,200 boe/d, mainly the result of contributions from assets in Brazil, Norway, Venezuela, North America and Peru.

    In late December, Repsol resumed operations in Libya. At the current rate of production, this activity yields an additional 20,000 barrels of oil equivalent per day for Repsol. In 2016, Repsol increased its oil and gas reserves to 2.382 billion barrels of oil equivalent, with a replacement rate of 103%.

    Repsol said the reserves and projects already underway guarantee average production of 700,000 barrels per day through 2020, which will be maintained through 2025 by other discoveries already made and whose development will start in the next two years. In parallel with this production, the company will maintain a 100% average reserve replacement rate through 2020.
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    Delek inks Leviathan loan deal

    Delek Group signed loan agreements for up to $2.5 billion for the development of the Leviathan natural gas field offshore Israel.

    The company’s two units, Delek Drilling and Avner Oil signed the loan deal with a consortium of more than 20 Israeli and international financial institutions headed by HSBC Bank and J.P. Morgan.

    The loan will be used for the development of Delek’s share in the giant gas field.

    The loan has been divided into facilities, first of which is in the amount of $375 million per partnership and will be released following the financial investment decision.

    The remaining facilities, two of which are in the amount of $187.5 million per partnership and one in the maximum amount of $125 million will be contingent on the execution of the agreements for the supply of gas at a minimum agreed annual quantity.

    The loan agreement includes another facility of $375 million per partnership for the increase of the production and transmission system capacity.

    The Leviathan partners expect the natural gas from the Leviathan field will be produced by the end of 2019.

    In December last year Delek Group said that having assessed the development plan, the work plan and the proposed budget for the development of stage 1A of the development plan, with a capacity of 12 bcm per year, at a scope of US$3.5-4 billion, the board of directors of the general partner authorized the approval of the FID.
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    Petronas, Saudi Aramco may sign new deal on refinery project -sources

    Malaysia's state oil firm Petroliam Nasional Bhd (Petronas) and Saudi Aramco are expected to sign an agreement to collaborate in the country's Refinery and Petrochemical Integrated Development (RAPID) project, two industry sources said on Wednesday.

    Aramco had decided to suspend its partnership with Petronas in the refining and petrochemical complex in the southeast of the country, according to sources last month.

    The signing is expected to take place on Monday, said one of the sources with knowledge of the matter who declined to be identified, during a visit by Saudi Arabia's King Salman to Malaysia.

    Saudi Aramco declined to comment and Petronas was not immediately available for comment.
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    Weir hurt by weak oil prices while peer Petrofac sees order uptick

    Weir Group Plc, a maker of pipes and valves for energy and mining industries, reported a 22 percent fall in full-year pretax profit, hurt by a weak North American oil and natural gas market.

    Peer Petrofac Ltd said it saw an uptick in bidding activity in its core Middle Eastern markets.

    Weir's shares fell as much as 3.5 percent before trading at 1961 pence. Petrofac shares rose as much as 4.5 percent before paring losses to trade at 900.9 pence on the London Stock Exchange.

    "There is no doubt that over the last few months bidding activity has increased... we are seeing a number of projects deferred in 2016 coming back in 2017," Petrofac CFO Alastair Cochran told Reuters in a call.

    The order book backlog at year-end for Petrofac's core engineering and constructions unit stood at $8.2 billion dollars out of a total of $14.3 billion.

    Petrofac, which design and maintenance provides services to oil and gas projects reported a 125.6 percent rise in its core earnings to $704 million for the year ended Dec. 31, as record production in the Middle East drove up contract awards.

    Weir's full-year order input fell by 8 percent to 1.86 billion pounds, while revenue fell 11 percent to 1.85 billion pounds for the year, on a constant currency basis.

    The Scottish company said its pretax profit fell to 170 million pounds ($212.3 million) for the year ended Dec. 31, from 219 million pounds reported a year earlier.

    Peer John Wood Group Plc had reported a 62 percent fall in its 2016 profit as weak oil prices continued to force oil producers to slash spending.
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    China state firm in preliminary deal to buy Chevron's Bangladesh gas fields - oil executives

    China's state-run Zhenhua Oil has signed a preliminary deal with Chevron  to buy the U.S. oil major's natural gas fields in Bangladesh that are worth about $2 billion, two Beijing-based Chinese oil executives said.

    Zhenhua is a subsidiary of China's defense industry conglomerate NORINCO. A completed deal would mark China's first major energy investment in the South Asian country, where Beijing is competing with New Delhi and Tokyo for influence.

    Bangladesh, though, holds the right of first refusal on the assets and could block the transaction. The country, via its national oil company Petrobangla, is keen to buy the gas fields and is talking to international banks to raise financing, according to a banking source familiar with the process.

    Bangladesh is in the process of hiring global energy consultant Wood Mackenzie to assess the fields' reserves before placing a formal bid to buy the assets, two Bangladesh sources familiar with the matter told Reuters.

    The Bangladesh sources said they were not aware of Zhenhua Oil's competing interest in the Chevron fields.

    "As this project is in the process of commercial discussions, we can't comment based on our company policy," said Zhang Xiaodi, Zhenhua Oil's spokesman.

    Zhenhua Oil is a small oil and gas explorer that despite its connections to China's defence industry is dwarfed in comparison to state energy giants PetroChina and Sinopec.

    It is trying to formalize its deal with Chevron by June, after the two companies signed a preliminary pact in January, the two senior oil executives told Reuters.

    Zhenhua will partner with China Reform Holdings Corp Ltd, an investment vehicle under the State-owned Assets Supervision and Administration Commission (SASAC).

    Zhenhua will hold 60 percent of the deal and China Reform 40 percent, the two executives said.

    The executives declined to be named as these discussions were not public.

    Chevron, in an e-mailed statement, confirmed that it was in commercial discussions on its Bangladesh assets, but would not comment further as a matter of policy.

    Chevron had said in October 2015 that it planned to sell about $10 billion worth of assets by 2017 including geothermal projects in Indonesia and the Philippines and gas fields in Bangladesh amid a prolonged slump in energy prices.

    Bangladesh knows that Chevron is in talk with global companies, but has no specific knowledge about Zhenhua's interest, said Nasrul Hamid, state minister for power, energy and mineral resources.

    "This is Chevron's matter. We'll not interrupt but we are supposed to get the first priority," he said when asked if Bangladesh would try to block the China deal.

    "We will place a formal bid only if the project is viable," Hamid said.

    Chevron sells the entire output from its three gas fields - Bibiyana, Jalalabad and Moulavi Bazar, which account for more than half of Bangladesh's total gas output - to state energy firm Petrobangla under a production sharing contract.


    With output and revenue slashed by low oil prices for the last nearly three years, China's state energy firms are under pressure to step up efforts to boost reserves and profits as Brent crude LCOc1 stabilizes around $55 a barrel.

    Zhenhua Oil appears to have outrivaled competing bidders by partnering with the state investment vehicle China Reform, the Chinese executives said.

    Geo-Jade Petroleum Corp (600759.SS), an independent Chinese oil and gas explorer, was a close competitor with a bid at $2.3 billion, said one of the executives.

    "Possibly because Zhenhua is a state-owned company and has the backing of China Reform, that's why it was picked by Chevron," said the executive.

    Zhenhua Oil has oil and gas operations in Iraq, Kazakhstan, Syria, Myanmar and Egypt.

    If the Bangladesh deal materializes, it would hand the Chinese firm 16 million tonnes a year of oil equivalent output, including natural gas and condensate, a scale that would make it China's fourth-largest oil and gas producer, the two Chinese executives said.
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    European ethylene spot trades at premium to contract price amid tightness

    European ethylene spot traded Monday at a premium of Eur80/mt ($843/mt) to the monthly contract price of Eur1,020/mt FD NWE for February, reflecting a tightening market ahead of a major cracker turnaround season beginning in March.

    The trade represents a marked change in the market as spot prices were heard bid at a discount of about Eur50/mt just last week.

    "For me the [trade] is a combination of product availability and required incentives for producers to release some of their stocks," said a source Tuesday. Material availability had been heard tightening on the pipe as early as the first week in February as producers built up inventory.

    Compounding material availability issues in Europe is the strong Asian market which has acted to curb import availability in Europe. Asian ethylene prices were assessed Tuesday at $1,385/mt CFR Northeast Asia. The region's high prices have attracted material from Middle Eastern producers who favor netbacks from the region.

    "Prices in Europe are too low to attract imports," said a source earlier in the month.

    With a lack of imported material availability as a result of strong Asian prices, downstream markets have become increasingly dependent on domestic production. Should the trends in material availability continue, March ethylene prices will increase over February levels.
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    Ecopetrol reports 14% year-on-year decline in proven reserves

    State-controlled Ecopetrol reported a 14% year-on-year reduction in proven reserves through December 31, a decrease that reflects three years of declining oil field investment in Colombia's oil patch, it said Tuesday.

    Ecopetrol pegged year-end 1P reserves at 1.598 billion barrels, down 14% from 1.849 billion barrels at the end of 2015. The reserves were calculated using US Securities and Exchange Commission-approved standards by independent firms Ryder Scott Co. and DeGolyer & MacNaughton.

    Ecoptrol said the decrease was due to the "pronounced fall in oil prices" in 2016 that made a significant percentage of the company's previously reported reserves uneconomical to produce. Ecopetrol accounts for more than three quarters of Colombia's crude and natural gas reserves and output.

    The SEC price used to value Ecopetrol's reserves in 2016 was $44.49/b, down from $55.57/b in 2015, a 20% decline. Ecopetrol estimated that the price decrease was responsible for the loss of 202 million barrels of reserves, or roughly 80% of the year on year decline.

    But the country is also seeing the negative effects of the significant and ongoing decline in investment by Ecopetrol and other explorers in discovering new oil finds.

    More than half of Colombia's output is heavy oil, which costs more to process and transport, putting the country at a competitive disadvantage in attracting capital spending compared with Peru, Mexico and Argentina.

    Oil field security is another issue. Despite the peace agreement signed in 2016 by the government and the largest rebel group FARC, the oil industry is still at risk from attacks by another rebel group called ELN, which continues to bomb oil installations and pipelines, which discourages investment.

    On Monday, Ecopetrol, which controls the bulk of the nation's pipeline network, reported the 13th attack so far this year on the critical 220,000 b/d Cano Limon pipeline, over which one quarter of the country's crude is transported to Covenas, the principal off-loading port on the Caribbean coast.

    Although Ecopetrol blamed unnamed "terrorists" for the attack, industry sources say ELN rebels, who regard all oil installations as military targets and who have long been active in the area of the attacks, were responsible for the bombings.

    With the addition of 186 million barrels to reserves as a result of new discoveries and better efficiencies, Ecopetrol reported a net replacement index of 79%, which means that 79 barrels replaced each 100 barrels produced. The current reserve level amounts to 6.8 years of inventory at current production rates.

    In 2016, the nation's crude output averaged 885,000 b/d, down 12% from the 1,005,400 b/d pumped on average during all of 2015.

    Ecopetrol also said it was taking several measures in 2017 to improve reserves, including several pilot projects to improve recovery rates.

    Earlier this year, the company reported it was increasing investment in exploration and production, reversing recent spend declines. Exploration spending this year is projected to be $650 million, more than double the $270 million spent last year.

    The company is especially focused in offshore exploration for gas finds, partly in an effort to compensate for rapid depletion of the country's reserves.

    Of 16 exploratory wells Ecopetrol plans to carry out in 2017, five will be drilled offshore. The company is also drilling appraisal wells in the Orca and Kronos offshore gas fields, where discoveries were previously announced, but which have not yet been declared commercially viable.

    Ecopetrol also said it is taking a new look at using its "strong cash position" to possibly grow its reserves "inorganically" by buying shares in existing reserves in other countries.

    The company said its goal is to add 600 million barrels of crude and crude equivalents to its ledger by 2020.
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    Post Oak Energy Capital, Moriah Henry Partners step up Midland Basin program

    Houston-based Post Oak Energy Capital led a $200 million equity commitment to Moriah Henry Partners, an exploration and production company headquartered in Midland.

    Its co-investors are Henry Energy and Moriah Energy Investments, which will manage the venture. Proceeds will be used to acquire and develop properties in the Midland Basin in west Texas.

    “We are delighted to partner with these industry veterans and leaders,” Frost Cochran, Post Oak managing director said in an announcement.

    “Their deep experience in the Midland Basin will allow us to capitalize on numerous opportunities in one of the most economic basins in the country.”

    Henry Energy is a privately held Permian Basin oil and gas producer founded by Jim Henry.

    “I am very excited to be focused, once again, in the core of the Midland Basin, where I began drilling Spraberry wells nearly 50 years ago,” Henry said.

    “Our relationship with Moriah and Post Oak enhances our capacity to drill horizontal Wolfberry wells in an area we are very familiar with.”

    Moriah Energy Investments manages oil and gas investments for diversified holding company Moriah Group.
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    Whiting Petroleum nearly doubles its capital spending budget

    Whiting Petroleum Corp, North Dakota's largest oil producer, nearly doubled its 2017 budget for capital spending as crude prices stabilize following a two-year rout.

    However, shares of the company were down 3.5 percent after the bell as the oil producer's revenue fell below analysts' expectations due to a steep drop in production.

    Oil companies are betting big on a continued rise in crude prices by buying up acreage and raising capital spending.

    Whiting boosted its 2017 spending to $1.1 billion from $554 million in 2016.

    The company's production fell 23.4 percent to 118,890 barrels of oil equivalent per day in the fourth quarter ended Dec. 31.

    Whiting's net loss available to common shareholders widened to $173.3 million, or 59 cents per share, in the quarter from $98.7 million, or 48 cents per share, a year earlier.

    Excluding items, the company posted a loss of 28 cents per share, smaller than the analysts' average estimate of 32 cents.

    Denver-based Whiting Petroleum's operating revenue fell 18 percent to about $342.7 million. Analysts had estimated revenue of $355.2 million, according to Thomson Reuters I/B/E/S.

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    Woodside flags growth options after tough year

    Woodside Petroleum Ltd said on Wednesday it sees its output rising by about 15 percent over the next three years, and flagged plans to expand near-term output in Western Australia as it seeks to defy views that it is short on growth.

    Australia's top gas and oil producer has come through the oil market rout over the past two years in better shape than rivals, with $2.7 billion in cash and undrawn debt, and sees itself well positioned as prices rebound.

    "We're a fundamentally different company to the one we were five years ago and the opportunity set in front of us is very much world class," Chief Executive Peter Coleman told reporters, pointing to prospects in Australia, Myanmar and Senegal.

    Woodside reported a 23 percent drop in annual underlying profit to $868 million for 2016, in line with analysts' forecasts, as it was hit by weaker oil and gas prices that offset cost cuts and a rise in output.

    The company cut its full year dividend to 83 cents a share from $1.09, slightly short of analysts' forecasts of 85 cents a share, according to Thomson Reuters I/B/E/S.

    Woodside's forecast for production to grow by 15 percent over the next three years, implying output of around 100 million barrels of oil equivalent by 2020, was ahead of some analysts' forecasts for growth of around 5 percent.

    All of its growth over the past five years has come from its Pluto liquefied natural gas project which began in 2012.

    The increase will come from the Wheatstone liquefied natural gas project (LNG), where operator Chevron Corp expects production to start in mid-2017, and oil from Woodside's Greater Enfield project.

    The company is also looking to boost output from Pluto by just under 1 million tonnes by running its facilities harder, and is considering a further expansion by adding a small new production unit of 1 million to 1.5 million tonnes.

    "It's something that can be brought to market quickly," Coleman said, contrasting the expansion option with the huge LNG plants that have been built in the region over the past five to 10 years.

    Woodside is also planning to build a truck terminal to supply LNG from Pluto to fuel the local mining industry and wants to supply LNG for the shipping sector, too, to build demand for its key product.

    Attached Files
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    ConocoPhillips revises down over one billion barrels of oil sands reserves

    ConocoPhillips has revised down over a billion barrels of oil sands reserves because of low global crude prices, a company filing showed on Tuesday, the latest sign that some of Canada's vast hydrocarbon potential may be left untapped.

    The U.S. oil major said developed and undeveloped reserves of bitumen - the heavy viscous oil found in northern Alberta's remote oil sands - totaled 1.2 billion barrels at the end of 2016, down from 2.4 billion barrels at the end of 2015.

    The oil sands have some of the highest full-cycle breakeven costs in the world, with new thermal projects needing U.S. crude prices around $60 a barrel. Crude futures settled at $54.33 a barrel on Tuesday.

    The U.S. Securities Exchange Commission (SEC) document provides a detailed breakdown of the global reserves cut Conoco announced in quarterly results in early February, when it debooked 1.75 billion barrels of oil equivalent of reserves.

    Al Hirshberg, Conoco's executive vice president for production, drilling and projects, told investors on the quarterly call the company expects to rebook the reserves if current prices hold.

    Likewise Martin King, an analyst with GMP FirstEnergy in Calgary, said the debooking likely had more to do with SEC rules requiring companies to evaluate economic reserves at year-end.

    But the fact that the oil sands make up 70 percent of the reduction underlines how much of Canada's resources are uneconomic in a weaker oil environment.

    "They (the oil sands) are at the upper end of the cost curve," said Judith Dwarkin, chief economist at RS Energy Group in Calgary. "It may or may not speak to future similar events from other producers."

    Calgary-based Imperial Oil Ltd , which is majority-owned by Exxon Mobil Corp , debooked 2.6 billion barrels of reserves in January.

    ConocoPhillips made the reserve reductions at the Surmont, Foster Creek, Christina Lake and Narrow Lakes projects.

    Surmont is operated by ConocoPhillips and a joint venture with Total E&P Canada, a unit of Total SA, and the other three are joint ventures run by Cenovus Energy Inc .

    Total also debooked undeveloped reserves at Surmont, according to SEC filings. But Cenovus, which reports to Canadian securities authorities, said its total proved reserves including non-oil sands operations rose 5 percent in 2016 versus a year earlier.

    Cenovus spokesman Reg Curren said the company assumed different rules relating to reserves reporting in Canada and the United States were behind the difference.
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    Oil, gas exploration explodes in province’s Peace region

    After a two-year downturn that pushed the Peace Region from having close to zero unemployment to the highest jobless rate in B.C. last year, jobs are suddenly flowing back into northeastern B.C.

    Oil and gas companies have dramatically stepped up drilling this winter compared with the last two years.

    “It’s been crazy,” said Dawson Creek Mayor Dale Bumstead. “It was like somebody turned a switch on about November, December. Before Christmas, all our hotels were almost 100% occupancy and rental accommodation was filling up.”

    “There’s optimism out there right now,” said Mark Salkeld, CEO of the Petroleum Services Association of Canada (PSAC).

    Between 2015 and 2016, new oil and gas rights sales dropped dramatically and drilling in northeastern B.C. slowed to a trickle, thanks to a sustained plunge in oil and gas prices and growing uncertainty over large liquefied natural gas (LNG) projects.

    But on January 18, the auction for petroleum and gas rights generated more sales in a single day – $40 million – than the total reaped in all auctions held in 2015 and 2016. PSAC recently bumped up its estimate for the 2017 winter drilling season in B.C. to 367 wells from 280.

    “We’re seeing it in company guidance,” said Mark Oberstoetter, lead oil and gas analyst with Wood Mackenzie. “A lot of companies are doubling or adding a lot of spend in 2017, versus the low scene in 2016. So we’re seeing a lot of optimism.”

    Art Jarvis, owner of FloRite Environmental Systems and executive director for Energy Services BC, said companies in Fort St. John that parked equipment and laid off 40% to 60% of their staff during the downturn are now scrambling to find workers again.

    While some might view the sudden activity as a sign of renewed optimism that an LNG industry will develop in B.C., Oberstoetter said it’s really just economics.

    Even throughout the last two-year drilling drought, midstream companies have pumped billions into the Montney, building new gas processing plants and pipelines. Veresen Inc. (TSX:VSN) and Encana Corp. (TSX:ECA), for example, are spending $2.5 billion building three new gas processing plants in the Fort St. John and Dawson Creek area under the Cutbank Ridge Partnership.

    But the more labour-intensive exploration side of the business, drilling and fracking, all but stopped between 2015 and 2016, thanks to a sustained plunge in oil and gas prices.

    Gas well drilling is labour intensive. Each well takes a crew of about 135. That’s not including all the related jobs created for service businesses like Jarvis’ company, which provides truck-mounted pressure vessels that bleed off pressure to separate liquids from gases at wellheads.

    In the Montney, companies will typically spend $3.5 million to $5 million per well, although some deeper and more complex wells may cost as much as $15 million.

    The Montney has proved to be one of North America’s lowest-cost regions. The sheer volume of gas makes for good wellhead economics, and an abundance of liquids such as light oil, condensate and propane provides added value to producers.

    “You get a lot of volumes for every well you drill,” Oberstoetter said. “They’re very big wells, and well costs have come down a lot.”

    During the last drilling cycle, between 2012 and 2014, much of the drilling was being done by companies like Progress Energy (owned by Petronas) and Shell, which were proving out wells in anticipation of a liquefied natural gas industry developing.

    The current boom involves companies that are after natural gas liquids, including some newcomers, like Crew Energy Inc. (TSX:CR) and Tourmaline Oil Corp. (TSX:TOU), which have been buying up assets in the Montney in both Alberta and B.C.

    Last year, Tourmaline bought $1.4 billion worth of natural gas assets from Shell in Alberta’s Deep Basin and B.C.’s Montney.

    Last year, when Terra Energy went bankrupt, Crew Energy snapped up some of its wells and processing assets.

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    Galp cuts investment plan, sees higher earnings growth

    Galp Energia on Tuesday cut its spending plan for the next five years by a fifth and trimmed its oil production growth forecast, but raised its earnings outlook after producing stronger than expected earnings for 2016.

    Galp, which is mainly an oil refiner, has stakes in various large oil fields off Brazil's coast and has been building up its oil and gas production.

    The company said it expected production from sanctioned oil and gas projects to grow at a rate of 15-20 percent a year until 2021, down from 25-30 percent under its previous plan that ran up to 2020. "We remain focused on delivering the projects under construction, on time, within the budget ... and targeting high returns," Chief Executive Officer Carlos Gomes da Silva told investors at the company's capital markets day on Tuesday.

    Galp shares were almost 2 percent lower in early trading, underperforming the broader market in Lisbon.

    Galp estimated annual average capital expenditure up to 2021 at between 0.8 billion and 1 billion euros, 20 percent lower than under the previous plan announced a year ago.

    But earnings before interest, taxes, depreciation and amortization (EBITDA) should grow at a rate of around 20 percent a year until 2021, up from the previous forecast of 15 percent.

    This year, it expects an EBITDA of 1.5 billion to 1.6 billion euros. Earlier on Tuesday, Galp reported an 8 percent drop in 2016 EBITDA to 1.41 billion euros ($1.49 billion), which exceeded its forecast of 1.2 billion to 1.3 billion.

    Galp also confirmed its previous projection that its free cash flow will break even next year. It put the cash breakeven price for oil production at around $65 per barrel in 2016-18 and below $35 per barrel 2019-21.

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    China's Sinochem may sell 40 percent stake in Brazil's Peregrino oilfield - sources

    China's Sinochem is exploring the sale of its 40 percent stake in Brazil's Peregrino offshore oilfield, four people familiar with the matter told Reuters, a deal that could see the state-owned conglomerate walk away from what was once touted as a key overseas asset because of historically low oil prices.

    The oil and chemicals firm agreed to buy the stake from Norway's Statoil (STL.OL) for $3.07 billion in 2010 - beating out a raft of Chinese rivals chasing high-quality assets. The Norwegian giant owns the other 60 percent of Peregrino, the largest heavy oilfield it operates outside its home patch.

    But two of the people with knowledge of the matter said Sinochem is moving to sell its largest overseas upstream stake - with capacity to pump 100,000 barrels a day - as it reshapes its assets to reflect oil prices having halved in the last two and a half years. With that in mind, one person said, Sinochem was pitching the sale at a big discount to its purchase price.

    "Peregrino has been a success story for Statoil, not just technically but also financially. It provides a lot of value and has a good operator in Statoil," said Horacio Cuenca, Rio de Janeiro-based research director for upstream Latin America at energy consultancy Wood Mackenzie.

    Long term expectations of oil prices, however, and capital expenditure required in the next two to three years to develop the second phase of production will determine the value of any potential stake sale, he said.

    Earlier this month, Reuters reported Sinochem was in early talks to buy a stake in Singapore-listed commodity trader Noble Group (NOBG.SI), a move that would further its ambitions to become more active in global energy trade and also develop China's gas industry.

    The process to sell the Brazilian stake is still at an early stage and a final decision would depend on how the negotiations progress, the people familiar with the matter said. They spoke on condition of anonymity because they were not authorized to discuss it publicly.

    Statoil declined to comment.

    In an e-mail reply, Sinochem's press office said: "The company has been monitoring a large amount of transaction opportunities in the market and is ready to re-adjust and optimize its asset structure at the right time." It added that company does not comment on specific projects.

    Two sources said Sinochem's intent to sell the stake has been shared with India's Oil and Natural Gas Corporation (ONGC.NS). ONGC did not respond to requests for comments.

    One person said the stake is also likely to be pitched to other international buyers, including some Japanese firms and Kuwait Foreign Petroleum Exploration Company, which snapped up Royal Dutch Shell's (RDSa.L) stake in Thailand's Bongkot gas field for $900 million last month.


    The potential sale of the stake in Peregrino - located 85 km off Brazil in the Campos basin below about 100 meters of water - comes as oil prices hover in a mid-$50s per barrel range, well below the highs of recent years. That trend has also prompted other industry players to consider selling once-prized assets.

    Earlier this week, Reuters reported Malaysian state-owned oil and gas firm Petronas is aiming to sell a large minority stake in a local gas project for up to $1 billion as it seeks to raise cash and cut development costs.

    For its part, Sinochem has seen growth in its key oil trading business stagnate, with increasing domestic competition from the likes of state oil traders Unipec and Chinaoil, while overseas oil and gas assets have struggled amid the prolonged low oil prices.

    "Sinochem is readjusting its energy asset structure," said a Beijing-based industry veteran familiar with the company's strategy. "As a medium- to small-sized oil producer, exposure to higher cost assets like deep water has become over-challenging."

    "The company sees itself more as an asset manager. This becomes a clearer direction under the new management," the industry executive said, referring to Sinochem chairman Ning Gaoning who took over the helm last year.

    The potential sale of the Peregrino stake also comes ahead of the second phase of the project's development, expected to cost about $3.5 billion with production from the new phase set to start by the end of the decade.

    The second phase is designed to add about 250 million barrels in recoverable reserves to Peregrino, which currently contains an estimated reserve of between 300 million and 600 million barrels of recoverable oil.
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    InterOil: ExxonMobil deal clears final hurdle

    InterOil corporation said the Supreme Court of Yukon granted a final order approving the proposed $2.5 billion takeover by the US-based energy giant ExxonMobil.

    The court decision follows a special meeting of InterOil shareholders at which 91 percent votes cast were in favor of the transaction.

    With the court decision, the arrangement has received all necessary approvals, InterOil said, adding that together with ExxonMobil it expects the transaction to be completed this week.

    The Supreme Court of Yukon initially approved the transaction in October last year, finding it “fair and reasonable”. However, the order was stayed by the Court of Appeal of the Yukon following an appeal lodged by InterOil’s former CEO Phil Mulacek.

    When concluded, the transaction will give ExxonMobil access to InterOil’s resource base, which includes interests in six licenses in Papua New Guinea covering about four million acres, including PRL 15, which includes the Elk-Antelope which is the anchor field for the proposed Papua LNG project.

    ExxonMobil earlier also said it aims to work with its co-venturers and the government to evaluate processing of gas from Elk-Antelope field by expanding the PNG LNG project.
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    Senex commits A$50m to Western Surat gas project

    ASX-listed Senex Energy will invest some A$50-million to a 30-well drilling campaign in the Western Surat gas project, marking its first major investment in the project.

    MD and CEO Ian Davies on Tuesday said the work programme would result in significant gas volumes from drill-ready acreage, with Senex already having a clear strategy for project acceleration.

    “We have seen immediate gas to surface from the Glenora pilot wells, brought online for continuous production in early February. We have also seen evidence of strong gas flows from wells on the Eos block during rehabilitation work being undertaken on legacy wells. These results demonstrate that coal seams in the Glenora and Eos blocks have already been partially dewatered by neighbouring operations.”

    Davies said the sanctioned well programme will further Senex’s understanding of the resource to support an accelerated project timeline, with potential to drill, complete and connect another 30 to 50 wells throughout 2018.

    “Under this scenario and, subject to regulatory approvals, Senex can seamlessly transition to a development phase targeting gas production of over 16 TJ a day by 2019, equivalent to one-million barrels of oil equivalent a year.”

    First wells are expected to come online in mid-2017 and are expected to produce some 10 TJ a day by mid-2018.

    “Finally, the 2017 work programme will give us the opportunity to fully embed our design, contracting and execution methodologies in order to demonstrate best-in-class safety and cost performance,” Davies said.

    With the Glenora and Eos blocks located directly north from the Gladstone liquefied natural gas (GLNG) project’s producing Roma field, Senex was planning to sell the raw gasto the GLNG project, subject to the agreement of commercial terms.

    A pipeline from the Glenora pilot to the GLNG low-pressure gathering network was built in 2016.
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    $294bn oil, gas projects underway in Mena

    Oil, gas and petrochemicals projects to the tune of about $294 billion are in the pre-execution phase across the Mena region even while concerns about global oversupply continue to suppress oil prices, a report said.

    Gas spending is also set to increase as countries such as Saudi Arabia and the UAE study higher-cost sour gas and shale gas plans to meet rapidly-growing domestic demand, reported the Times of Oman, citing Meed Insight’s Mena Oil and Gas Report 2017.

    Last year saw average crude prices drop to a 13-year low as oil and gas producers in the Mena region continued to face the impact of global oversupply.

    The drop in crude revenues coincided with an eight-year low in the value of engineering, procurement and construction (EPC) contracts awarded in the regional oil, gas and petrochemicals sectors.

    Investment in the Mena hydrocarbons industries hit an eight-year low in 2016, dropping 34 per cent to $32.4 billion.

    “The oil, gas and petrochemicals sectors will continue to be the backbone of economies across the Mena region,” Meed editorial director, Richard Thompson was quoted as saying in the report.

    “With an estimated $294 billion-worth of projects in the pre-execution phase, the sector provides a wealth of opportunity for business from Saudi Arabia’s ambitious oil-to-chemicals complex to the re-emergence of the Iran oil industry following years of sanctions.”
    Upstream investment has been driven by the need to meet rising demand, at both home and abroad, and the need to replace resources lost through natural depletion. In the GCC, Saudi Arabia, the UAE,

    Kuwait and Qatar have all raised their sustainable crude oil production capacity, while Oman has managed to reverse a slump in output through its enhanced oil recovery (EOR) programme. Outside the GCC, production capacity and output has stagnated or fallen in Algeria, Egypt and Libya, mainly due to the political problems in those states. Iraq has been able to increase capacity through one of the world’s largest upstream investment programmes.

    In terms of a subsector breakdown of future projects, the largest sector is petrochemicals with over a quarter of total projects planned. Many projects in this sector, however, are at an early stage and the current market environment for petrochemicals is not strong. The future of many of them also depends on the availability of feedstock, which has held back many GCC petrochemicals projects in the past. Oil refinery projects rank in second place with the announcement of several new refinery projects in Iraq boosting this sector. Spending is also anticipated on new refineries in Bahrain and Oman.

    With capital spending on oil & gas projects of about $44.3 billion, Kuwait has been by far the biggest spender over the past two years after a slump in project spending at the start of the decade. That was driven by major projects such as the Clean Fuels Project, the Al-Zour refinery (also known as the New Refinery Project) and the Lower Fars heavy oil handling facilities.

    Kuwait is only number five however in terms of pre-execution project value. This includes the estimated $7 billion Olefins 3 petrochemicals project and phases two and three of the Ratqa Lower Fars Heavy Oil project.

    In the UAE, lower prices have been a driver of workforce reduction and consolidation. Abu Dhabi National Oil Company (ADNOC) is merging its two offshore oil producers as well as several logistics subsidiaries to low costs and streamline operations. Job cuts have also been administered at Qatar’s major gas companies.

    Over the period in review the UAE has been the third most valuable market for hydrocarbons projects, spending $35.1 billion. Abu Dhabi in 2013 and 2014 awarded a string of contracts in the offshore oil sector. The UAE had quiet years in 2015 and 2016 as several major projects faced delays at the main contract bid phase. In 2016 the UAE was not in the top five countries in the region in terms of contract awards.

    The UAE is also eyeing major gas capacity expansions in the coming years, largely by developing new sour gas reservoirs. These include major projects on the Bab and Hail fields as well as the expansion of the Shah gas field. The UAE ran into delays at the contract award phase on several projects in 2015/16, including the $3 billion Bab Integrated Facilities Expansion, a new refinery in Fujairah and the Fujairah LNG import terminal.

    Meanwhile, Saudi Arabia plans to list the world’s largest oil and gas company, Saudi Aramco, on the stock market, in an initial public offering (IPO) that values the company at an estimated $2 trillion.

    Saudi Arabia had the region’s largest oil, gas and petrochemicals market in the 2011-2016 period, with a total of $69.37 billion worth of contracts awarded, accounting for over a quarter of the regional total. The bulk of these awards however were in 2011 and 2012 with over $47 billion spent in these two years combined. Average spending has dropped considerably in the subsequent four years.

    Saudi Arabia’s project pipeline is buoyed by the region’s two largest projects which are both at an early stage: Sabic’s oil-to-chemicals project and Aramco’s integrated refinery and petrochemicals development, both at Yanbu on the Red Sea coast. These projects aside, Aramco is likely to prioritise projects to expand its gas capacity which includes higher gas processing capacity, the development of non-associated gas fields in the Gulf and expanding shale gas production in the north.

    Saudi Aramco plans to spend $334 billion across the oil and gas value chain by 2025, meanwhile, Kuwait is expected to spend $115 billion on energy projects over the next five years to help boost crude production capacity to 4 million barrels a day by 2020.$294bn-oil,-gas-projects-underway-in-Mena

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    Japan’s LNG imports rise 14.6 percent in January

    Liquefied natural gas (LNG) imports into Japan increased 14.6 percent in January as demand for the chilled fuel for power generation rose on the back of low winter temperatures.

    Japan imported 8.30 million mt of LNG in January, as compared to 7.24 million mt the year before, according to the provisional data released by Japan’s Ministry of Finance.

    The country paid about $3.28 billion for LNG imports last month, a rise of 6.7 percent as compared to the same month in 2016, the data shows.

    Japan’s average price of spot LNG hit its two-year high record during January. The average price of spot LNG bought last month was $8.40 per million British thermal units, up from $8 in the previous month and the highest since January 2015.

    Worth mentioning, Japan imported 83.34 million mt of LNG in 2016, as compared to 85.05 million mt the year before.

    This was the second drop in Japan’s annual LNG imports since the devastating earthquake and tsunami in March 2011 which caused Japan to shut down its nuclear industry.

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    Rosneft to invest in Libya’s oil sector

    Libya’s National Oil Corporation (NOC) and Russia’s Rosneft company have signed a cooperation framework agreement that lays the groundwork for investment by Rosneft in Libya’s oil sector, said the message on NOC’s website.

    The agreement envisages the establishment of a Joint Working Committee of the two partners to evaluate opportunities in a variety of sectors, including exploration and production.

    Reportedly, Rosneft and NOC also signed a crude oil offtake agreement (an agreement between a producer and a buyer to buy/sell a certain amount of the future production).

    The accord represents a step forward in NOC’s plans, announced by chairman Mustafa Sanalla in London last month, to encourage investment by foreign oil companies in the expansion of Libya’s oil production to levels of 2.1 million barrels per day by 2020, said the message.

    “We need the assistance and investment of major international oil companies to reach our production goals and stabilize our economy,” said Sanalla.

    Alongside with Nigeria, Libya was exempted from the output cut deal during the meeting of OPEC countries held in Vienna Nov.30.
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    Japan plans second offshore methane hydrate output test from late April

    Japan plans to conduct a second testing round for offshore production of methane hydrate from around late April, aiming to run the tests non-stop for up to a month, an official at the Ministry of Economy, Trade and Industry said Monday.

    This will be the world's second offshore methane hydrate production test after Japan produced 120,000 cubic meters, or 20,000 cu m/day, of gas from methane hydrate in a first, six-day offshore production test in the Pacific Ocean in March 2013. That trial followed more than a decade of field research as well as testing of various technologies.

    Like the last round, METI will conduct the trial using the decreasing pressure system at the Daini-Atsumi Knoll in the eastern Nankai Trough, 70-80 kilometers (43.4-49.6 miles) south of the Atsumi Peninsula in Aichi Prefecture, the official said.

    The key objectives for the upcoming production test are to evaluate whether Japan can produce gas from methane hydrate using the decreasing pressure system stably for a given period, with a view to commercializing output in the future, the official said.

    State-owned Japan Oil, Gas and Metals National Corporation, or Jogmec, is leading the methane hydrate output test for METI.

    Starting from mid-April, operator Japan Methane Hydrate Operating Co. will extend its two production wells that have already been drilled by a further 50-60 meters to reach methane hydrate layers about 300 meters below the seabed at a water depth of around 1,000 meters, the official said.

    JMH, which will charter the Chikyu drilling ship from early April, has to date drilled a total of five wells including the two production wells with monitoring wells.

    JMH was formed in October 2014 as a joint venture of 11 Japanese companies, to take part in the planned next round of testing of pore-filling type methane hydrate.

    JMH stakeholders are Japan Petroleum Exploration (33%), Japan Drilling Co. (18%), Inpex (13%), Idemitsu Kosan (5%), JX Nippon Oil & Gas Exploration Corporation (5%), Nippon Steel & Sumikin Engineering (5%), Chiyoda (5%), Toyo Engineering (5%), JGC (5%), Mitsui Oil Exploration Co. Ltd. (5%), and Mitsubishi Gas Chemical Company (1%).
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    OPEC Extension?

    OPEC could extend its oil supply-reduction pact with non-members or even apply deeper cuts from July if global crude inventories fail to drop to a targeted level, OPEC sources said.

    The group, together with Russia and other non-OPEC oil producers, agreed late last year to cut output by 1.8 million barrels per day (bpd) to reduce a price-sapping glut. The deal took effect on Jan. 1 and lasts six months.

    For global petroleum inventories to fall by some 300 million barrels to the five-year average, producing countries must comply 100 percent with the supply accord and growth in demand for crude will have to stay healthy, the sources said.

    "If we have full commitment by everybody, inventories will go down. By sometime in the middle of this year, maybe they will go near the five-year average. But that's if you have 100 percent compliance," one OPEC source said.

    "The question is, by how much will they fall? For that, you have to wait and see."

    The Organization of the Petroleum Exporting Countries meets next on May 25 to decide on supply policy, with non-members possibly also invited to attend.

    OPEC producers in January achieved 93 percent compliance with the pledged reductions, of which the group's de facto leader, Saudi Arabia, contributed the biggest chunk.

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    Oil Search steps up spending for next leg of growth

    Australia's Oil Search Ltd said it will boost capital spending this year to help expand output in Papua New Guinea in coming years, despite reporting a 70 percent drop in annual core profit on weak oil and gas prices.

    The PNG-focused oil and gas firm is pushing global giants ExxonMobil Corp and France's Total SA, its partners in two rival projects, to work together to expand liquefied natural gas (LNG) exports from the country.

    While slumping LNG prices due to a flood of new supply have forced several proposed projects to be shelved, projects in PNG are still seen as promising, thanks to the quality of the gas, low costs and proximity to big buyers in Asia.

    Oil Search Managing Director Peter Botten said on Tuesday a recent rebound in Asian LNG prices, which more than doubled to $9.75 per million BTUs between April and January, was unlikely to last, but saw the market improving within a few years.

    "While we expect spot LNG prices to soften from current levels through 2017, the long-term LNG market fundamentals remain strong, with major Asian buyers expected to have substantial new LNG requirements early next decade," he said in a statement.

    Oil Search plans to roughly double capital spending this year to between $360 million and $460 million, particularly on work to understand a new find, Muruk, in the highlands of PNG, which could provide a cheap source of gas to expand PNG LNG.

    The Muruk partners, ExxonMobil, Oil Search and Santos Ltd , believe the field could hold between 1 trillion and 3 trillion cubic feet of gas, which would be on top of a recent 25 percent increase in the resource estimate for the PNG LNG fields to 11.5 trillion cubic feet.

    Oil Search is also a partner in the Papua LNG project, run by Total, which is looking to develop the Elk-Antelope gas fields. Oil Search believes billions of dollars could be saved if those fields are used to help expand the PNG LNG project, rather than building a completely new LNG plant.

    ExxonMobil will also become a partner in Papua LNG, once it completes its delayed takeover of InterOil.

    Oil Search's net profit before one-offs fell to $106.7 million for 2016 from $359.9 million a year earlier, as average liquefied natural gas (LNG) prices dropped by a third and oil prices slid 12 percent. The result matched analysts' forecasts of $107.9 million, according to Thomson Reuters I/B/E/S.

    The firm cut its full year dividend to 3.5 cents a share from 10 cents, slightly ahead of analysts' forecasts at 3 cents.

    Oil Search expects to produce between 28.5 million and 30.5 million barrels of oil equivalent in 2017, flat to slightly weaker than last year's record output.
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    Energy impacts of Pruitt's confirmation as EPA administrator

    Scott Pruitt was confirmed Friday as administrator of the US Environmental Protection Agency by a 52-46 Senate vote.

    Oklahoma's attorney general since 2011, Pruitt has sued EPA on behalf of the state and argued it overstepped its authority into areas that states should control. But he struck a more moderate tone during his confirmation hearing, saying he would honor Congress' intent in carrying out regulations.

    Highlights of his energy-related comments during the confirmation process that could signal his impact on policy ahead:


    Pruitt said he would uphold the Renewable Fuel Standard and only deviate from statutory volume increases after careful deliberation, distancing himself from his previous criticism of the policy as an "unworkable" and "flawed program."

    While Pruitt is not expected to change 2017 blending levels, he could lower 2018 targets due in November and possibly side with refiners and blenders urging the agency to move the RFS point of obligation to the wholesale rack.

    "The EPA needs to better administer this program to provide involved entities with the certainty they need," he said.


    Pruitt said he would work with Congress to administer the corporate-average fuel economy standards but did not say whether he would uphold a midterm review that the Obama administration finalized in its last weeks in office. The review found that automakers are meeting the 2022-25 emissions standards quicker and at lower costs than expected, creating no need to curb the federal targets set in 2012.

    Pruitt would ensure the rules "provide the best possible legal framework for governing American fuels, fuel infrastructure, and vehicles, and for promoting American energy independence, energy security, and environmental protection," he said.


    While President Donald Trump expressed a desire to get rid of EPA while campaigning and has called the agency's work a disgrace, Pruitt said EPA served a valuable role and still has much work to do. But he said the agency under his leadership would respect the rule of law, partner with states and respect public participation when making regulations.

    "We must reject as a nation the false paradigm that if you're pro-energy, you're anti-environment, and if you're pro-environment, you're anti-energy," Pruitt said. "I utterly reject that narrative."

    When asked about his environmental philosophy and what he would do to protect the environment, Pruitt said the regulated community currently suffers from an "inability to predict or know what's expected of them as far as their obligations under our environmental laws." He said EPA's mission is to protect natural resources, improve air and water quality, help ensure the health and welfare of citizens and pursue vigorous enforcement where necessary.

    When asked if he believed there was a need to transform the US energy system away from fossil fuels to protect the planet for future generations, Pruitt said that the EPA and its administrator have "a very important role in regulating the emissions of CO2." He declined to expand on that response.


    Pruitt said states are "not mere vessels of federal will -- they don't exist simply to carry out federal dictates from Washington, DC."

    "There are substantive requirements, obligations, authorities, jurisdiction granted to the states under our environmental statutes," he said.

    When states' rights are not respected, "that is what spawned most of the litigation referenced here today," he said. "It matters that the states participate in the way Congress dictated, and they've been unable to do so for a number of years."


    Pruitt made clear that he disagreed with Trump's campaign statements that climate change was a hoax, conceding that the climate is changing and that "human activity in some manner impacts that change." But, "the ability to measure with precision the degree and extent of that impact and what to do about it are subject to continuing debate and dialogue," he said.

    When pressed to share what he believed to be causing climate change, Pruitt said his personal opinion was immaterial to the job of EPA administrator. Rather, that job "is to carry out the statutes as passed by this body," and those statutes put constraints on what EPA can do in regards to carbon emissions, Pruitt said.


    Asked why he took no action as Oklahoma attorney general in response to a spike in earthquakes tied to wastewater injection wells, Pruitt said the state has taken the issue very seriously and has successfully regulated hydraulic fracturing for decades.

    "While earthquakes have increased in frequency in recent years, the state has taken aggressive actions and reports have indicated the rate of seismic events has recently declined," he said. "Seismic activity can of course have significant impacts on communities and the activities linked to seismicity concerns in Oklahoma are regulated under state law by other agencies that my office works with as appropriate under Oklahoma law."


    Asked about reports that the Trump administration wanted to slash EPA's budget, Pruitt said he had no first-hand knowledge of such a plan. "If confirmed, I will work to ensure that the limited resources appropriated to EPA by Congress are managed wisely in pursuit of that important mission and in accordance with all applicable legal authorities," he said.
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    Asian LNG prices continue to fall

    According to the latest Reuters report, Asian spot LNG prices fell for a sixth consecutive week as a series of sell tenders launched this week are seen offering supplies into a market with thin demand following a warmer-than-expected winter in North Asia.

    Spot prices for LNG for April delivery were pegged at around US$6.40 per million British thermal units, approximately 50 cents below last week's levels.

    Falling prices at Britain's gas trading hub, National Balancing Point (NBP), have dashed expectations of an influx of shipments heading to Europe, leaving more for other regions.

    Import tenders from India's Gail, Thailand's PTT and Argentina's Enarsa have done little to counter the supplies offered by Russia, Angola and Abu Dhabi this week.

    Russia's Sakhalin II LNG project issued two tenders to sell a combined nine shipments loading in 2017/2018 this week. The first tender offers three cargoes for loading on 23, 26 and 29 April, while the second tender is offering cargoes for loading between May and March next year.
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    Russia Overtakes Saudi Arabia as World's Top Crude Producer

    Saudis lose No. 1 spot for 1st time since March: official data
    U.S. ranked No. 3 with output of 8.8 million barrels a day

    Russia overtook Saudi Arabia as the world’s largest crude producer in December, when both countries started restricting supplies ahead of agreed cuts with other global producers to curb the worst glut in decades.

    Russia pumped 10.49 million barrels a day in December, down 29,000 barrels a day from November, while Saudi Arabia’s output declined to 10.46 million barrels a day from 10.72 million barrels a day in November, according to data published Monday on the website of the Joint Organisations Data Initiative in Riyadh. That was the first time Russia beat Saudi Arabia since March.

    Saudi Arabia and fellow producers from the Organization of Petroleum Exporting Countries decided at the end of November to restrict supplies by 1.2 million barrels a day for six months starting Jan. 1, with Saudi Arabia instrumental in the plan. Non-member producers, including Russia, pledged additional curbs. Brent crude prices have climbed about 20 percent since the end of November.

    The U.S. was the third-largest producer, at 8.8 million barrels a day in December compared with 8.9 million barrels a day in November, according to JODI. Iraq came in fourth at 4.5 million barrels a day, followed by China at 3.98 million barrels a day, the data show.

    Saudi Arabia’s crude exports declined to 8 million barrels a day in December, from 8.26 million barrels a day, the biggest outflow for any month since May 2003, according to JODI data.
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    Iraq and Iran sign MoU on Kirkuk oil export pipeline study

    Iraq and Iran signed a memorandum of understanding on Monday to study the construction of a pipeline to export crude oil from the northern Iraqi fields of Kirkuk via Iran, the Iraqi oil ministry said in a statement.

    The agreement, signed in Baghdad by the oil ministers of the two countries, also calls for a commission to solve a conflict about joint oilfields and the possible transportation of Iraqi crude to Iran's Abadan refinery, it said.

    Iraqi Oil Minister Jabar al-Luaibi said in the statement that he also agreed with visiting Iranian counterpart Bijan Zanganeh to cooperate on the policies of the Organization of the Petroleum Exporting Countries.
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    India’s LNG imports down almost 15 pct in Jan

    India’s imports of liquefied natural gas (LNG) dropped 14.7 percent in January as compared to the same month a year ago.

    This is the third monthly LNG import decline since April 2016. India’s monthly LNG imports were down in July and December, respectively.

    India imported 1.64 billion cubic meters or about 1.21 million mt of LNG in January, as compared to 1.92 Bcm in the same month in 2015, according to the data from oil ministry’s Petroleum Planning and Analysis Cell (PPAC).

    Domestic natural gas production rose 11.9 percent in January to 2.73 Bcm.

    In the April-January period, India’s LNG imports rose 16.1 percent year-on-year to 20.73 Bcm or about 15.09 million mt of LNG, PPAC data shows.

    India’s LNG imports have been rising steadily in the last 12 months, boosted by low prices of the chilled fuel.

    Costs of importing LNG into India have dropped sharply last year after the country’s largest importer, Petronet LNG signed a revised long-term contract with Qatari LNG producer RasGas.

    India paid $0.5 billion for January LNG imports. In the April-January period, LNG import costs reached $4.8 billion, PPAC said.

    To remind, the country also recently announced plans to halve its basic customs duty on imports of the chilled fuel.

    India aims to reduce the basics customs duty on LNG from current 5 percent to 2.5 percent as part of its plans to shift to a natural gas-based economy.
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    Shell’s first LNG Outlook: LNG demand to grow at twice the rate of gas demand

    The Hague-based LNG giant Shell on Monday launched its first” LNG Outlook”, an assessment of the global liquefied natural gas (LNG) market.

    According to the outlook, global demand for gas is expected to increase by 2% a year between 2015 and 2030 while LNG demand is set to rise at twice that rate at 4 to 5%.

    The oulook says that many expected a strong increase in new LNG supplies would outpace demand growth during 2016. Instead, demand growth kept pace with supply as greater than expected demand in Asia and the Middle East absorbed the increase in supply from Australia, according to the outlook.

    “Global LNG trade demonstrated its flexibility time and again in 2016, responding to shortfalls in national and regional gas supply and to new emerging demand,” said Maarten Wetselaar, Integrated Gas and New Energies Director at Shell.

    China and India driving growth

    China and India – which are according to the report set to continue driving a rise in demand – were two of the fastest growing buyers, increasing their imports by a combined 11.9 million tones of LNG in 2016. This boosted China’s LNG imports in 2016 to 27 MT and India’s to 20 MT.

    Total global LNG demand increased following the addition of six new importing countries since 2015: Colombia, Egypt, Jamaica, Jordan, Pakistan and Poland. They brought the number of LNG importers to 35, up from around 10 at the start of this century.

    Egypt, Jordan and Pakistan were among the fastest growing LNG importers in the world in 2016. Due to local shortages in gas supplies, they imported 13.9 MT of LNG in total.

    The bulk of growth in LNG exports in 2016 came from Australia, where exports increased by 15 MT to a total of 44.3 MT. It was also a significant year for the USA, after 2.9 MT of LNG was delivered from the Sabine Pass terminal in Louisiana, the report said.

    LNG prices and trade changes

    Global LNG prices fell dramatically in the last two years following to the slump in oil prices.

    According to the report, global LNG prices are expected to continue to be determined by multiple factors, including oil prices, global LNG supply and demand dynamics and the costs of new LNG facilities. In addition, the growth of LNG trade has evolved into helping meet demand when domestic gas markets face supply shortages.

    In addition, the growth of LNG trade has evolved into helping meet demand when domestic gas markets face supply shortages.

    LNG trade also is changing to meet the needs of buyers, including shorter-term and lower-volume contracts with greater degrees of flexibility. Some emerging LNG buyers have more challenging credit ratings than traditional buyers, the report noted.

    New investments needed

    While the industry has been flexible in developing new demand, there has been a decrease in final investment decisions for new supply.

    Shell said it believes further investments would need to be made by the industry to meet growing demand, most of which was set to come from Asia, after 2020.

    The report noted that in China, a government target has been set for gas to make up 15% of the country’s energy mix by 2030, up from 5% in 2015. Meanwhile, Southeast Asia is projected to become a net importer of LNG by 2035, a significant transformation for a region which includes Malaysia and Indonesia – currently among the major LNG exporters in the world, the report said.

    Looking forward, the outlook says that from 2020 to 2030 most new LNG demand growth will be driven by: policy, floating storage regasification units (FSRUs), replacing declining domestic gas production, small scale LNG and transport.
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    Platts revamps Brent oil benchmark for first time in a decade

    Oil pricing agency S&P Global Platts said on Monday it was making the first major overhaul of its Brent oil assessment in a decade to address falling supply underpinning the benchmark that prices most of the world's oil.

    A decline in supply from North Sea fields has led to concerns that physical volumes could become too thin and hence at times could be accumulated in the hands of just a few players, making the benchmark vulnerable to manipulation.

    Platts said on Monday it would add Norway's Troll crude to the four British and Norwegian crudes it already uses to assess dated Brent from Jan 1. 2018. This will join Brent, Forties, Oseberg and Ekofisk, or BFOE as they are known.

    "Overall we have had significant support for the addition of a new grade to the basket," Jonty Rushforth, global editorial director for S&P Platts Global's oil and shipping price group, said at an industry conference.

    "Far and away, Troll has received the most support."

    Brent is used to set the price of billions of dollars of daily oil trade though a forward market for BFOE crude cargoes, swaps markets, physical benchmark dated Brent and Brent crude futures.

    Supply of the four BFOE grades is expected to fall next month to a rate of 884,000 barrels per day (bpd), from February's originally planned 943,000 bpd rate, based on loading programmes from trading sources.

    This will be the smallest programme since November.

    Typically, Troll produces about 10 to 15 cargoes of 600,000 barrels each per month. Platts said its inclusion should boost volumes by about 20 percent, helping to improve liquidity.

    Troll, a light, sweet crude, is operated by Norwegian state producer Statoil, which also contributes to the Oseberg, Statfjord, Gullfaks, Grane and Asgard streams.

    The last change to the dated Brent benchmark was in 2007 when Platts added Ekofisk, a light, sweet crude produced jointly by British- and Norwegian-owned fields.

    Platts added Oseberg and Forties, a slightly heavier, more sour grade, to the basket in 2002.

    In an earlier move to boost liquidity, Platts began to apply quality premiums to two better-quality crudes - Oseberg and Ekofisk - to encourage delivery of these into contracts. There are no plans yet to apply one to Troll.

    "The market appreciates a measured response in terms of changes," Rushforth told a media briefing. Platts will be sticking with the BFOE name.

    Thomson Reuters, parent of Reuters news, competes with Platts in providing news and information to the oil market.
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    Rosneft-led consortium plans to complete Essar acquisition next month -sources

    A consortium led by Russian oil major Rosneft plans to finally complete its $12.9 billion acquisition of India's Essar Oil next month, two Russian sources close to the deal told Reuters.

    Acquiring the refiner will give state-owned oil Rosneft access to India, one of the world's fastest-growing energy markets. The deal was announced to fanfare in October but has still not closed.

    The sources said the delay was due to the complexity of Essar's structure and financing, not to any issues relating to the buyers, who will buy 98 percent of Essar. Rosneft is under Western sanctions due to Moscow's role in the Ukraine crisis.

    The deal, announced during a visit to India by Russian President Vladimir Putin, is now set to be completed on March 15, the two sources said.

    Rosneft will acquire a 49 percent share in Essar and another 49 percent will be shared between commodities trader Trafigura and Russian private investment group United Capital Partners (UCP).

    The deal was structured to avoid the risk of Western sanctions, the chief executive of Russian bank VTB, which is involved in financing the deal, told Reuters last year.

    Essar Oil operates a 400,000 barrel-a-day refinery in Vadinar on India's west coast and sells fuels through its 2,470 filling stations across the country.

    Trafigura has said that VTB would co-fund Trafigura and UCP's 49 percent stake. Rosneft has said it may use its own funds, external financing or both to pay for its share.

    One of the sources close to the deal said discussions about the management team at Essar were holding up completion of the deal, but did not elaborate.

    The second source said that Essar's Indian creditor banks, who include State Bank of India (SBI), must approve a change of control at the company. The deal was also complicated by Essar's ongoing debt restructuring programme, the source said.

    "The process of receiving lender approvals, including SBI, for the transaction is underway. Sanctions provisions do not apply to the transaction," Essar said in emailed comments to Reuters.

    A senior SBI official said the bank was on course to approve the deal, and did not see U.S. sanctions getting in the way, but did not give a timeframe.

    VTB earlier agreed to provide Essar with up to $3.9 billion for debt reconstruction.

    In response to Reuters queries, Rosneft said it expected to close the deal in the first quarter of 2017. Trafigura gave the same timeframe, and said it was also replying on behalf of UCP.
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    Petronas considers $1 bln stake sale in offshore gas project

    Malaysian state-owned oil and gas firm Petronas is aiming to sell a large minority stake in a prized upstream local gas project for up to $1 billion (804.57 million pounds) as it seeks to raise cash and cut development costs, two sources familiar with the matter said.

    Petroliam Nasional Bhd (Petronas) is looking to sell a stake of as much as 49 percent in the SK316 offshore gas block in Malaysia’s Sarawak state, the sources told Reuters, a move that would be one of its first major recent sales as it grapples with oil prices that have slumped by half from two-and-a-half years ago.

    Petronas is working with an investment bank on the stake sale and kicked off the process this month, one of the sources said. Petronas did not respond to a request for comment.

    Gas from the NC3 field in the SK316 block feeds Malaysia’s liquefied natural gas (LNG) export project, known as LNG 9, Petronas’ joint venture with JX Nippon Oil & Energy Corp that started commercial production in January.

    The sources said the stake is expected to include a combination of the producing NC3 gas field, the potential development of the Kasawari field in the same block and other exploration acreage in the block.

    The funds raised could contribute to the future development of the Kasawari field, one of the largest non-associated gas fields in Malaysia, which has an estimated recoverable hydrocarbon resource of about three trillion standard cubic feet.

    The stake could appeal to firms such as Indonesia’s state-owned Pertamina, Thailand’s PTT Exploration, and Production PCL and some Japanese companies, the sources said.

    As huge production comes online in Australia and the United States, LNG markets are oversupplied, resulting in an almost 70 percent slump in the Asian spot LNG price since 2014 to $6.40 per million British thermal units now.

    Despite this, Malaysia’s LNG assets are viewed as attractive thanks to comparatively low production costs and due to their proximity to North Asia’s big consumption hubs of Japan, China, and South Korea.

    Petronas is currently gauging interest from potential bidders, said the sources, who declined to be identified as they were not authorised to speak about the matter.

    A slump in oil markets since 2014, which has seen crude prices halve to little more than $50 per barrel, has squeezed Petronas’ cashflow and forced it to announce a 50 billion Malaysian ringgit ($11.2 billion) cut in capital expenditure in January 2016 over four years.
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    Japan readies for LNG bunkering as marine industry turns to cleaner fuels

    Japan, the world's largest LNG importer and accounting for about 35% of global demand, is set to play a significant role in LNG bunkering as the marine industry turns to cleaner fuel options to comply with stricter environmental regulations.

    In October 2016, the International Maritime Organization decided to cut global sulfur emission limits for marine fuels from 3.5% to 0.5% by 2020.

    Currently, the demand for heavy fuel oils as marine fuel is about 250 million mt/year. Ship operators will have to switch to cleaner, more expensive fuels or invest in emissions cleaning systems. LNG is another option.

    Major impediments to the widespread adoption of LNG bunkering have been high infrastructure costs, lack of sufficient enforcement as well as current low crude oil prices.

    Another problem is matching the expectations of the buyers and sellers. While sellers are keen to lock in long-term contracts, ship operators, who are already facing challenging market conditions, prefer to buy spot cargoes.

    LNG could be a viable and cheaper alternative as the price for middle distillates rises, sources said.

    Besides tackling sulfur emissions, LNG addresses other environmental aspects too.

    It has no detectable sulfur, and LNG-fueled vessels emit lower particle and nitrogen oxide than those using marine fuels.

    "The volume of fuel oil bunkering, which has to be replaced by low sulfur fuel oil is huge. It is 2 million b/d. Almost equal to... or a little bit less than Iran's oil production. But it is huge. How can it be replaced in three years?" Fereidun Fesharaki, chairman of Facts Global Energy, said at an energy event in Tokyo last week.

    Blending diesel and fuel oil to create 5,000 ppm sulfur fuel was extremely difficult, he said, adding that compliance would be impossible.

    "Not in 2020, not in 2023, 2024, 2025. In that process, there will be more LNG bunkering definitely ... it is a very, very big challenge," Fesharaki said.

    Demand from LNG will also be boosted by the lower prices of natural gas in the future, Robin Meech, managing director at Marine & Energy Consulting, said, adding that global annual demand for LNG bunkers could rise from less than 1 million mt currently to as high as 8 million mt by 2025.


    Japan carried out a feasibility study for the development of an LNG bunkering hub at the port of Yokohama, on the Pacific side as it serves as a bunkering base on the Asian side of the Pacific route.

    A report by Japan's Ministry of Land, Infrastructure, Transport, and Tourism in December set a three-phase road map for the development of an LNG bunkering base.

    According to the report, Phase I has already started with the introduction of truck-to-ship bunkering.

    "The optimization has been realized since November 2016," the report said. Phase II comprises ship-to-ship bunkering by using the LNG terminal in Tokyo bay (Sodegaura terminal) where the required facilities are already in place for supplying LNG to ships by 2020.

    Phase III will strengthen ship-to-ship supply capacity by introducing new LNG supply system and another bunkering ship at Yokohama once demand reached a certain scale, it said.

    In October 2016, the ministry became part of an international focus group to co-operate on LNG bunkering. The group comprises the ports of Singapore, Rotterdam, Antwerp, Zeebrugge, Jacksonville, the Norwegian Maritime Authority, and South Korea's Ulsan Port Authority.

    "We think the market [for LNG bunkering] will be surely growing, seeing strong environmental regulations ... Yes, Japan can be one of the most important hubs," a spokesman at NYK Line said.

    The Japanese shipping line said on Wednesday that it, together with ENGIE, Fluxys and Mitsubishi Corporation, has taken delivery of ENGIE Zeebrugge, the first purpose built LNG bunkering vessel.

    A number of other vessels that NYK could use for LNG bunkering are also under study. "Details are not been decided though, study is on-going," a company spokesman said.

    Mitsui O.S.K. Lines, another Japanese shipper, said last month that it had reached an agreement to launch a joint study of an LNG-fueled Capesize bulker with five other companies -- BHP Billiton, DNV GL, Rio Tinto, Shanghai Merchant Ship Design and Research Institute and Woodside Energy.

    "The MOL Group continually takes a proactive approach to developing and adopting technologies that contribute to reducing environmental impact and enhancing safe operation, while providing safe and reliable transport services," it said in a statement in January.
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    Iran finds 2 billion barrels shale oil reserves in western province: agency

    Iran has found shale oil reserves of 2 billion barrels of light crude in its western Lorestan province, a senior official at the state-run National Iranian Oil Company (NIOC) was quoted as saying on Saturday.

    "Based on studies, it is estimated that the shale oil reserves in Ghali Koh in Lorestan amount to 2 billion barrels of oil in place,” Bahman Soleimani, NIOC’s deputy director for exploration, told the semi-official news agency Tasnim. "The oil is light."

    Soleimani said exploration was also being carried out for shale gas reserves in the area, and the studies were expected to be completed by October, 2017.

    Iran's proven oil reserves of about 160 billion barrels, almost 10 percent of the world's total, rank it fourth among petroleum-rich countries.

    Attached Files
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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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    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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    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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    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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    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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    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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    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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    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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    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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    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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    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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    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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    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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    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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    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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    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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    Alternative Energy

    China bans new wind power projects in six regions

    The National Energy Administration (NEA) has issued red alerts, or the highest warning, in six provincial regions where new wind power projects will be prohibited this year, Securities Daily reported, citing a statement published on the NEA's official website on February 22.

    The six restricted regions include northeastern Heilongjiang and Jilin, northwestern Gansu, Ningxia and Xinjiang, as well as northern Inner Mongolia.

    In these regions, new construction approvals and access to grid connections will be put on hold.

    Large amounts of wind power were wasted in these regions last year, an industry analyst told the newspaper, adding that the NEA hopes to urge local governments to more actively solve the problem through administrative measures, which have active significance for the healthy development of the industry.

    According to official data, last year the waste proportion of these regions were Gansu (43%), Xinjiang (38%), Jilin (30%), Inner Mongolia (21%), Heilongjiang (19%).

    China had 149 GW of installed wind power capacity as of the end of 2016, with 19.3 GW added last year, according to the NEA.

    Wind power facilities generated 241 TWh of electricity in 2016, 4% of the country's total electricity production, compared with 3.3% in 2015.

    However, nearly 50 TWh of wind power was wasted last year, up from 33.9 TWh a year earlier, due to distribution of wind resources and an imperfect grid system.

    The three-tier warning system distinguishes the risk levels by green, orange and red and the NEA releases the results annually.
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    Tesla says Model 3 on track for volume production by Sept

    Tesla Inc posted a smaller quarterly loss and said its mass-market Model 3 sedan was on track for volume production by September.

    The company's net loss attributable to common shareholders narrowed to $121.3 million, or 78 cents per share, for the fourth quarter ended Dec. 31 from $320.4 million, or $2.44 per share, a year earlier.

    Tesla, which is led by billionaire entrepreneur Elon Musk, said revenue rose 88 percent to $2.28 billion.

    The company is betting big on Model 3 to help it meet its goal of producing 500,000 cars annually in 2018.
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    New Scientist trashes Drax and others; finally

    The EU’s renewable energy policy is making global warming worse


    Simon Dawson/Bloomberg via Getty

    By Michael Le Page

    Countries in the EU, including the UK, are throwing away money by subsidising the burning of wood for energy, according to an independent report.

    While burning some forms of wood waste can indeed reduce greenhouse gas emissions, in practice the growing use of wood energy in the EU is increasing rather than reducing emissions, the new report concludes.

    Overall, burning wood for energy is much worse in climate terms than burning gas or even coal, but loopholes in the way emissions are counted are concealing the damage being done.

    “It is not a great use of public money,” says Duncan Brack of the policy research institute Chatham House in London, who drew up the report. “It is providing unjustifiable incentives that have a negative impact on the climate.”

    The money would be better spent on wind and solar power instead, he says.

    It is widely assumed that burning wood does not cause global warming, that it is “carbon neutral”. But the report, which is freely available, details why this is not true.

    More emissions

    Firstly, burning wood produces more carbon dioxide, methane and nitrogen dioxide per unit of energy produced than coal. When forests are logged, their soils also release carbon over the next decade or two. There are also emissions from the transport and processing of wood, which can be considerable.

    By contrast, forests that are left to grow continue soak up carbon. This is true even for mature forests, the report says. Older trees absorb much more carbon than younger trees, so despite the death of some trees, mature forests are still a carbon sink overall.

    As for the idea that all the CO2 emitted when wood is burned is eventually soaked up when trees regrow, this can take up to 450 yearsif forests do indeed regrow, the report says. To avoid dangerous climate change, however, emissions need to be reduced right away.

    Dirty reality

    Supporters of bioenergy claim the industry is only using waste from sawmills and such, rather than whole trees. Producing energy from genuine wood waste that would otherwise be left to rot can indeed be better than burning fossil fuels.

    But in reality, there simply is not enough waste wood to meet demand. What waste there is often contains too much dirt, bark and ash to burn in power plants, or is already used for other purposes. Instead, there is substantial felling of whole trees for energy, the report says.

    “I think the evidence is pretty strong,” says Brack. Official definitions are so poor that companies can cut down whole trees and count them as waste, he says.

    There is also no evidence that new forests are being planted to meet demand for bioenergy, as some bioenergy enthusiasts claim. For instance, forest area in the southern US, which provides much of the wood pellets burned in the EU, is not increasing.

    Policy changes needed

    Substantial changes in policies are needed to ensure biomass burning reduces rather than increases emissions. In particular, the report recommends the introduction of much stricter criteria to ensure only genuine waste wood is used.

    It also recommends a number of changes to close the various carbon accounting loopholes that allow the EU to claim its bioenergy policy is reducing its greenhouse gas emissions, when it is fact it is having the opposite effect.

    “Many countries are increasing use of biomass as renewable energy,” Mary Booth of the US-based Partnership for Policy Integrity and a reviewer on the report, said in a statement. “Alarmingly, the Chatham House report concludes that uncounted emissions from the ‘biomass loophole’ are likely large, and likely to significantly undermine efforts to address climate change.”

    Read more: Revealed: The renewable energy scam making global warming worse

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    China leads global wind power installation in 2016

    China once again led the way globally in terms of installed wind power capacity in 2016, illustrating its continued commitment to reduce greenhouse gas emissions, state media reported.

    In 2016, China installed 23.3 GW of wind power capacity, almost three times the 8.2 GW that the U.S., which took second place, installed in the same year.

    However, the total capacity installed in China in 2016 fell by almost a quarter compared to 2015, when it installed 30 GW of wind power capacity.

    According to Steve Sawyer, Global Wind Energy Council (GWEC) secretary general, this reduction was "driven by impending feed-in tariff reductions," and because "Chinese electricity demand growth is slackening, and the grid is unable to handle the volume of new wind capacity additions."

    However, he added that the market is expected to pick up again this year.

    In terms of capacity installed in 2016, China and the U.S. were followed by Germany, which installed 5.4 GW of wind power capacity, and India, which saw 3.6 GW of installations.

    At the end of 2016, China's cumulative installed capacity stood at 169 GW, or 34.7% of the global total. It was followed by the U.S. with 82 GW, or 16.9% of the global total, Germany (10.3%) and India (5.9%).

    The Chinese offshore wind power market also responded strongly in 2016, with China overtaking Denmark to rank third in the cumulative global offshore rankings after the UK and Germany.

    In 2016, China stood third globally in terms of offshore wind power installation with 592 MW installed, behind Germany (813 MW) and the Netherlands (691 MW).

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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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    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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    China to kick off 8 nuclear power units construction in 2017

    China planned to kick off construction of eight nuclear power units this year, with installed capacity totaling 9.86 GW, said the National Energy Administration (NEA) in a notice released on February 17.

    Meanwhile, China will complete construction of Sanmen #1, Fuqing #4, Yangjiang #4, Haiyang #1, Taishan #1 units this year, adding 6.41 GW of new nuclear power capacity to the country's total, according to NEA.

    The country will strengthen technical cooperation with Russia and the U.S. in nuclear power sector, and further promote cooperation with Argentina, Turkey and Romania in nuclear projects.

    Separately, China planned to complete construction of a few hydropower stations this year, with newly-added installed capacity of 10 GW. Construction of Baihetan, Batang, Lawa, Tuoba hydropower stations will kick off this year, with installed capacity expected to be 30 GW.

    The wind and solar power units will also kick off construction in 2017, adding new installed capacity of 25 GW and 20 GW, respectively.
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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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    U.S. corn delays open door for China sales to Asia

    Delays in corn shipments from the United States have offered China a chance to showcase its grain to major Asian buyers like Japan and South Korea, raising the prospect of a new player in global grain markets.

    One deal is close and talks have begun on two more, sources said, with China benefiting from its close proximity to big Asian customers and bulging stockpiles left over from a now-abandoned farmer support scheme.

    While volumes so far are tiny, any challenge to established trade flows would unnerve a saturated global market and the world's main exporters, including the United States, which is under pressure to unload its own record stockpiles in the export market.

    "Disposing of corn stocks is a top priority for China's ag policy this year. I think there's also a substantial surplus of new-crop corn that could be exported," said Fred Gale, senior economist at the United States agriculture department.

    For now, China's role may be limited to a regional supplier of last resort, given it is charging a hefty premium for its corn and struggling to reacquaint itself with a business it gave up about a decade ago, traders and experts said.

    Further out, however, traders say it is still unknown how far the government will back regional exports.

    A step-up in sales would help run down vast stockpiles - equal to more than a year's consumption - but longer term China's annual corn surplus is expected to narrow to less than 10 million tonnes, putting a limit on exports.

    One major trading house has forecast China will export as much as 2 million tonnes in 2017/18, a source told Reuters, compared with nearly 57 million tonnes of U.S. exports this year and 28 million tonnes by Brazil, according to USDA forecasts.


    China's unexpected sales opportunity has come as Asian customers face potential corn shortages after severe winter weather in the United States slowed rail deliveries of crops to shippers.

    Japan, the world's top corn importer with purchases of about 15 million tonnes a year, has said it expects to tap emergency stockpiles.

    "Japan needs some corn to replenish its stocks. It will be buying more corn from China," said Nobuyuki Chino, a Tokyo-based veteran grains trader.

    "It is emergency supplies which should be 200,000 tonnes, that is my expectation. Japan will try and limit its purchases from China as Chinese corn is more expensive than world corn prices."

    Japan's Mitsubishi Corp is finalizing the purchase of a 15,000 tonne cargo of corn from China's state-controlled Cofco, two sources told Reuters last week, China's first meaningful seaborne grain exports in at least seven years.

    The cargo is expected to ship next week, said one of the sources.

    Mitsubishi has agreed to pay as much as $230 per tonne FOB for its cargo, trading sources said, well above a price below $200 a tonne it paid for its delayed U.S. corn.

    Cofco did not respond to requests for comment. A Mitsubishi spokesman said the company is considering buying corn from other countries, including China, Russia and South America, but it has not yet finalized a purchase.

    Despite the high price tag, talks are underway for at least two more deals between China and Japan, one of the two sources said.

    China's does have an advantage over Brazil, Ukraine and the United States of being close to Asia's big importers, including Vietnam and Taiwan.

    It takes three or four days to get corn from northern China to Japan, compared with two weeks from the U.S. Pacific Northwest, and up to 35 days from Brazil and Ukraine, which translates into a cost saving of up to $12 a tonne, traders said.

    The price gap between South American corn and Chinese corn has already narrowed to about $30-$40 a tonne, said a Singapore-based trader, and further falls would boost China's competitiveness.

    "It depends on how desperately China needs to get the corn out. If it's desperate, it could drop the price to $210, even $200," he said.

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    Armyworm caterpillars ravage maize crop in southeast Congo

    Crop-destroying caterpillars known as armyworms have ravaged 63,000 hectares of maize in southeastern Democratic Republic of Congo since December, causing local maize prices to triple, a U.N. spokeswoman said on Wednesday.

    Suspected outbreaks have already erupted in Zambia, Zimbabwe, Malawi, South Africa, Namibia and Mozambique, and scientists say the armyworm could reach tropical Asia and the Mediterranean in the next few years.
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    Potash demand destruction likely in India, after gov't hints at subsidy cut

    Already reeling from decades-low prices, potash miners are staring at another headwind, this time from India, a major importer of the crop fertilizer ingredient.

    The news out of India today is highlighting a proposal by the Indian government to cut the potash subsidy by 17% in order reduce fiscal debt. Doing so, however, would have the effect of raising the prices paid by companies that import it; India relies on imports to meet its roughly 4 million tonnes of potash demand annually. That in turn would lead to a reduction in Indian demand, which would affect producer companies like Uralkali, Potash Corp, Agrium Inc, Mosaic, K+S, Arab Potash and Israel Chemicals.

    "The subsidy reduction will weigh on the new contract negotiations. We cannot offer higher prices in new contracts due to the proposed subsidy reduction": Indian government official

    Such companies had been hoping for an uptick in demand to counter lagging prices, which are hovering just above $200 a tonne – over half of what the market was offering five years ago.

    For instance Potash Corp – the world's biggest fertilizer producer – recently reported its profit is down by 70% on weak prices, but sounded an upbeat note on better expected demand:

    “With increased demand and limited new capacity additions, we anticipate relatively balanced market fundamentals in 2017,” it said in an end-of-January statement.

    Similarly, Mosaic’s Colonsay potash mine in Saskatchewan is re-opening based on rosier predictions for potash.

    Reuters reports that India's fertilizer ministry has proposed fixing the potash subsidy at 7,669 rupees ($114.61) a tonne for the 2017-18 fiscal year beginning in April, down from 9,280 rupees per tonne this year. Doing so would save the government almost $100 million based on 4 million tonnes of imported product.

    "The subsidy reduction will weigh on the new contract negotiations. We cannot offer higher prices in new contracts due to the proposed subsidy reduction," Reuters quoted a government official who negotiates with overseas miners.

    The proposal still has to passed by the Indian Cabinet headed by Prime Minister Narendra Modi. Contracts signed by India and China are considered global benchmarks.

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    Precious Metals

    Toyota's new technology a blow for platinum, palladium price

    Toyota sold more than 10 million vehicles last year placing it in a virtual tie with Volkswagen as the world's number one automaker.

    Stricter pollution regulations around the world and intense competition mean that top priority for  traditional car companies is to cut costs and reduce emissions.

    A new technology unveiled by Toyota on Wednesday is win for the Japanese company on both counts. Toyota announced the availability of a new, smaller catalyst that uses 20% less precious metal in approximately 20% less volume, while maintaining the same exhaust gas purification performance.

    Toyota's "world's first integrally-molded Flow Adjustable Design Cell (FLAD)" is not the first time researchers have found innovative ways to reduce pricey platinum group metals in exhaust systems. But those technologies seldom make it all the way to the assembly line.

    Roughly 75% of palladium demand is from the autocatalyst sector while application of platinum is more evenly spread

    What sets Toyota's FLAD apart is that the company says it's ready to start mass producing the catalyst. The first vehicle to sport the the new catalytic converter, Toyota's luxury flagship Lexus LC 500h, will get it later this year. Volume models further down the ranks will gradually follow says the company.

    Roughly 75% of palladium demand is from the autocatalyst sector while application of platinum is more evenly spread with jewellery and other industrial uses making up more than half the total. 85% of rhodium is used in the auto sector, but it's a tiny market –  about 30 tonnes produced in good years.

    Clearly it will take a long time for FLAD to work its way through to PGM markets. If at all; events in South African and Russia which together is responsible for 80% of the world's PGM output generally have the biggest impact (not to mention the vexing issue of the real amount of above ground stocks).

    Nevertheless, a 20% cut is substantial, and the automakers have a long history of copying each others' technology.

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    Newmont's quarterly profit misses as costs surge

    Gold and copper miner Newmont Mining Corp (NEM.N) reported a smaller-than-expected quarterly profit on Tuesday, as costs and expenses jumped more than 51 percent.

    Newmont, the world's second-biggest gold producer by market value, said gold production rose 17 percent to 1.3 million ounces during the fourth quarter.

    The company produced 4.9 million ounces of gold in 2016, up 7 percent from a year earlier.

    Newmont's all-in sustaining costs (AISC), the gold industry cost benchmark, fell to $918 an ounce in the three months ended Dec. 31, from $1,036 an ounce a year earlier.

    Net loss attributable to stockholders from continuing operations widened to $391 million, or 73 cents per share, from $276 million, or 54 cents per share, a year earlier.

    The company recorded a $970 million impairment charge related to a mine closure in Peru, which it had warned of in December.

    Newmont reported adjusted earnings of 25 cents per share.

    Analysts on average had expected the company to earn 33 cents per share, according to Thomson Reuters I/B/E/S.

    Newmont's costs and expenses jumped 51.3 percent to $2.58 billion in the fourth quarter.

    Total sales rose 23.2 percent to $1.79 billion.

    Shares of the company, which had gained 47.6 percent in the past 12 months, were down 1.6 percent at $36.84 in after-market trading.
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    Russian gold miner Polyus reports 42 pct net profit jump, forex gains

    Polyus Gold reported a 42 percent jump in 2016 net profit to $1.4 billion on Tuesday as Russia's largest gold producer saw higher sales and gains in foreign exchange and derivatives.

    Higher sales volumes and higher gold prices powered a 20 percent rise in adjusted earnings before interest, taxation, depreciation and amortisation (EBITDA) to $1.5 billion.

    Revenue rose 12 percent to $2.5 billion.

    Profit excluding non-cash items was largely flat at $952 million due to higher interest payments, said the company, which is controlled by the family of Russian tycoon Suleiman Kerimov.

    Polyus said it expected to produce 2.075 million to 2.125 million troy ounces of gold in 2017, topping a record 1.968 million ounces in 2016.

    It said it remained on track to hit its target of at least 2.7 million ounces by 2020.

    This year Polyus aims to commission its Natalka gold deposit in Russia's Far East, its main greenfield project now, the company said.

    Polyus in a joint venture with state conglomerate Rostec also bought the development rights for the Sukhoi Log, one of the world's largest untapped gold deposits, for 9.4 billion roubles ($162 million) in January.

    In 2016, Polyus raised a credit facility to finance a $3.4 billion buyback of shares from its controlling shareholder. Polyus net debt stood at $3.2 billion at the end of 2016, up from $364 million a year earlier.

    "Polyus continued to proactively manage its debt portfolio and successfully tapped the Eurobond market twice during the last four months, placing a total amount of $1.3 billion," it said.

    Its capital expenditure rose 75 percent to $468 million in 2016.

    On Tuesday, the company said it was still working on a plan to increase its free-float to 10 percent, declining further comment.

    Polyus has said it plans a placement of 5 percent of its shares on the Moscow Stock Exchange to meet the bourse's 10 percent free float requirement.

    Polyus plans to use either existing or new shares with the funds from the placement going to the company. It has also said it would consider placing global depository receipts (GDRs) in London in the future.
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    Free cash rockets to $278m, dividend resumed – AngloGold

    Gold mining company AngloGold Ashantiwill resume dividends after lower operating and interest costs helped it nearly double free cash flow to $278-million on lower production.

    In the 12 months to December 31, AngloGold Ashantiproduced 3.6-million ounces of gold across its 17-mine portfolio at a total cash cost of $744/oz, compared with the higher 3.8-million ounces at $712/oz in the prior year.

    Production was hit by weaker output from the South Africa mines mainly because of safety-related stoppages, lower grades from Kibali in the Democratic Republic of Congo(DRC), a planned decrease in head grades at Tropicana in Australia and Geita in Tanzania, and no production contribution from Obuasi in Ghana.
    Both the Mponeng and Moab Khotsong gold mines in South Africa upped production over the prior year, along with Iduapriem in Ghana, Siguiri in Guinea and Sunrise Dam in Australia.

    Mponeng, where a brownfield expansion feasibility study is expected to be concluded towards the middle of next year, upped production by 16% and cut all-in sustaining costs (AISC) by 14% year-on-year.

    The JSE- and NYSE-listed company, under CEO Srinivasan‘Venkat’ Venkatakrishnan, has since 2013 used self-help measures, including asset sales and efficiency improvements, to reduce debt and improve balance sheet flexibility, without diluting shareholders.

    It continues to prioritise inward investment in brownfield projects over acquisitions, as it seeks to improve the quality of its production base and extend mine lives.
    Overall AISC were $986/oz, up from $910/oz in 2015, with proven and probable gold reserves of 50.1-million ounces at year-end offsetting depletion during the year.
    Six operating fatalities were recorded in South Africa during 2016, where a fatality-free fourth quarter was achieved across all business units, made up of one million fatality-free shifts at Mponeng, Kopanang and Moab Khotsong and two-million fatality-free shifts in the Vaal River region.

    Moab Khotsong achieved a full calendar year without a fatality in September and the Surface Operations unit achieved a full year with no lost-time injury.
    Production for 2017 is being guided at potentially up to 3.755-million ounces, with total cash costs of $750/oz at the low end and AISC of $1 100/oz at the high end.
    Capital expenditure of not more than $1. 050-billion is anticipated, with reinvestment at the Cuiaba gold mine, in Brazil, where a greater rate of ore reserve development is expected to improve mining flexibility; at Iduapriem to strip waste rock from the Teberebie orebody to extend mine life and lower cash costs; at Geita, to replace the mine’s original 20-year-old power plant to ensure reliable electricity supplyand also continue the ramp-up of underground production in advance of depletion of openpit ore in future; at Sunrise Dam, in Australia, where investment in plant modifications is expected to improve gold recoveries; and at Kibali, where additional ore reserve development will be conducted ahead of a production ramp-up.

    There was lower capital spend than initially planned in South Africa, where the small-range reef boring innovationprogramme was discontinued and the Sandvik/Cubex machine decommissioned at the Savuka section of the mine, owing to stage-gate review challenges.

    AngloGold COO South Africa Chris Sheppard assured Mining Weekly Online during a media conference that the efforts of the innovative Mark III and Mark IV high-technology machines were continuing according to plan.

    These machines are being developed to improve the economics of gold mining in South Africa’s low-height, hard-rock reef.

    “We still have our stage gates in place. Our research and development programme is still on track and I’m still upbeat about our reef-boring component on the Mark IV machine,” Sheppard told Mining Weekly Online, adding that the Mark IV had bored four holes this quarter, achieving 90 hours per hole, compared with the benchmark of 72 hours per hole, and the initial eight to nine days per hole.

    “The key issue outstanding is that we are not on a 24/7, and that 72 hours productivity level is based on being able to operate the machine on a 24/7 basis, which we don’t have at present,” he said.

    When it comes to South Africa’s  brownfield expansion options, Mponeng remains the option of highest potential.

    Sheppard said in response to Mining Weekly Online that a prefeasibility study had been concluded at Mponeng on the original Phase 2 project, which has resulted in the phased approach being rejected and a consolidated approach being adopted.

    He said that both the carbon leader reef and the Ventersdorp contact reef would be pursued below the current Phase 1 project.

    It entailed moving away from a phased ramp-up based approach to that of a sub-shaft deepening approach to realise a better investment proposition.

    “We’re currently in feasibility study and that will be concluded around the middle of next year,” Sheppard said, adding that the company was continuing with critical path activities in order to preserve value of the investment case.

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    Gemfields says India's demonetisation drive to hurt FY results

    British precious stone miner Gemfields plc said on Monday India's move to scrap higher value banknotes forced the company to delay an emerald auction and would hurt its full-year revenue and core earnings.

    Shares in the company fell as much as 7.9 percent to 46.50 pence in morning trading before recovering to 48.6 pence by 0832 GMT.

    The auction, which was pushed to February from December, sold about 84 percent of the total emeralds on sale by weight, and generated $22.3 million in revenue, the company said in a statement on Monday.

    The sale yielded the third highest value per carat to date for the company, with an average price of $63.61 per carat and total volume of 349,935 carats, Gemfields said.

    "A normal high quality auction delivers revenue normally of $32-$35 million on 500,000-600,000 carats of sales. Today they delivered very good pricing... but it was only on 350,000 carats sold, so a significantly smaller auction," analyst Michael Stoner at brokerage Peel Hunt told Reuters.

    "We would like to see that kind of strength to pricing on higher volumes," he said.

    The company, which mines for emeralds and amethysts in Zambia and for ruby and corundum in Mozambique, reported a loss of $4.3 million for the half year ended Dec. 31. Revenue fell 45.7 percent to 51 million pounds.

    The company rescheduled the auction for higher quality rough emeralds due to India's demonetisation programme and had cancelled another higher quality emerald auction, Chief Executive Ian Harebottle said in a statement.

    Indian Prime Minister Narendra Modi scrapped 500-rupee and 1,000-rupee banknotes in November in a bid to flush out cash earned through illegal activities, or earned legally but never disclosed.

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    Base Metals

    Philippines' minister says Duterte agrees with ban on mining in watershed areas

    The Philippines' environment minister on Thursday said that President Rodrigo Duterte had supported her decision to bar mining in watershed areas at a meeting earlier this week.

    "He said, 'I agree with you. Don't worry, you are my cabinet secretary and I also believe that there should be no mining in watershed,'" Regina Lopez told reporters at a briefing, recalling her meeting with Duterte on Monday.

    Lopez on Monday told Reuters she's standing by her decision to shut or suspend 28 of the country's 41 operating mines for environmental infractions, despite complaints from the mining industry. Many of them were located in watershed zones, she said.
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    Escondida will wait 30 days into strike to replace workers

    Chile's Escondida copper mine, the world's largest, said on Tuesday it would not begin replacing striking workers for at least 30 days into the work stoppage to show its commitment to dialogue.

    The mine can legally hire temporary workers after 15 days of a strike. Tuesday marked 13 days since unionized workers walked off the job at Escondida, which is controlled by BHP Billiton .

    Waiting to replace workers means there will be no production from Escondida for at least another two weeks if the strike continues. That will likely push copper prices, which have already hit 20-month highs on supply concerns, even higher.

    Government-mediated talks on Monday failed to get workers and representatives of the mine to commit to a schedule of new wage talks.

    The company and union are far apart on a number of issues, including shift pattern changes, the size of a one-time bonus, and BHP's wish to give new workers lower benefits.

    It was unclear for days if the meeting would even take place as BHP blamed striking workers for interfering with non-unionized service employees on their shift changes.

    Escondida is majority-controlled by BHP with minority interests held by Rio Tinto and Japanese companies including Mitsubishi Corp The mine produced about 5 percent of the world's copper in 2016.
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    Anglo American to walk away from Chile copper mine if no permit

    Anglo American will walk away from its El Soldado copper mine in Chile if it cannot agree a permit for a redesign of the operation, Chief Executive Mark Cutifani said on Tuesday.

    The group hopes it will get regulatory approval for the mine in three to four weeks, but if a satisfactory permit cannot be agreed, "we won't continue going forward with the operation", he told a results presentation.

    Anglo said last week it had temporarily suspended operations at the mine after failing to get regulatory approval for the redesign.
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    Sherritt mulling Ambatovy retreat to pop debt balloon

    Sherritt's dream of lifting Madagascar out of poverty and making a handsome packet for itself on the proceeds from a huge nickel mine appear to be in jeopardy.

    The Toronto-based company revealed it is looking at exiting the Ambatovy nickel and cobalt project – a mine it spent 90% of the $5.5 billion it cost to develop, with its Asian partners – in an effort to relieve a crushing debtload that has caused red ink to spill.

    “It’s an enormous debt number for a company our size”: CEO David Pathe

    To build the mine, Sherritt had to go cap in hand to its Korean and Japanese partners, and borrow US$650 million to pay for its 40% share of what is the world's biggest nickel mine, with the capacity to produce 60,000 tonnes of nickel and 5,600 of cobalt a year. According to CEO David Pathe, that loan has now grown to around $1.3 billion.

    “It’s an enormous debt number for a company our size,” Pathe said in an interview with the Globe and Mail at the Mining Indaba mining conference in South Africa.

    Sherritt, which also owns oil and gas operations in Cuba and mines cobalt and nickel on the island through its Moa joint venture, recently reported a net loss of $378.9-million for 2016. 2015 was quite a bit worse, with a net loss of $2.1 billion largely due to a $1.6-billion writedown on Ambatovy.

    In discussions with Pathe, the Globe reports that while Sherritt is supposed to receive a 12% share of Amabotovy's cash flow, the mine has yet to make any cash to distribute. The mine was expected to produce between 48,000 and 50,000 tonnes of nickel in 2016 and 3,300-3,800 tonnes of cobalt.

    The company's current preferred option is to work out a deal with its partners that would involve surrendering some equity in exchange for reducing its debt, but if that option fails, a complete exit from the project is “potentially still on the table,” according to the newspaper.

    Sherritt's stock was beaten down by the news, closing the day nearly 10% in the red, on double average volumes.

    Sherritt was Canada's largest thermal coal producer before it sold its entire coal business in late 2013 for $946 million, to Westmoreland Coal and Altius Minerals.

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    Escondida copper miners and BHP meet as strike drags on

    The union representing striking workers at Chilean copper mine Escondida and mine owner BHP Billiton Plc sat down to talk on Monday afternoon after the government called a meeting in hopes of ending the 12-day-old strike.

    The stoppage at the world's biggest copper mine helped boost copper prices on expectations of tighter supply, although news of the pending meeting had cooled the rally.

    The company had stipulated over the weekend that it would attend only if strikers did not interfere with nonunionized service employees on their shift change.

    It said on Monday after the shift change it would go ahead with the meeting, but that access to the mine for the contractors had been "partial."

    "Some 112 workers were stopped for more than an hour before the blockade was lifted ... and 21 contractors had to return to the city," BHP said in a statement.

    Escondida, which produced about 5 percent of the world's copper last year, is located about 170 kilometers from the regional city of Antofagasta.

    The union said there were no blockades and the buses with the contractors were allowed through, but that workers had checked that no strike-breakers were entering the mine.

    The meeting is aimed at getting the two sides to commit to a schedule of fresh wage contract talks, after initial negotiations failed.

    However, significant differences remain, including the company's wish to give new workers lower benefits. Other issues include shift pattern changes, a one-off bonus paid every four years, and other benefits.

    Escondida is majority-controlled by BHP with minority interests held by Rio Tinto and Japanese companies including Mitsubishi Corp.

    A government-mediated meeting between BHP Billiton and striking workers at its Escondida mine in Chile has failed, and workers will head back to their encampment without any future dialogue planned, a union spokesman told Reuters on Monday.

    "The company is continuing with their stubborn posture, and thus there is nothing to discuss anymore and we're going back to our camp," spokesperson Carlos Allendes said after the meeting.

    BHP was not immediately available for comment.
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    Philippine panel says review of decision to shut mines may take three months

    A Philippine panel tasked to review the environment minister's decision to shut more than half of the country's mines could take three months to complete it, a member of the committee said on Monday.

    "Three months is probably reasonable," Finance Undersecretary Bayani Agabin told reporters. "It will merely be a fact-finding body, it should be unbiased."

    The government's Mining Industry Coordinating Council will review Environment and Natural Resources Secretary Regina Lopez's order earlier this month to close 23 of the country's 41 operating mines for environmental violations including damaging watershed areas. Another five mines were suspended.
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    Aluminium producer looks for 30-pct hike in Q2 premium from Japan buyers -sources

    A major aluminium producer has made an indicative offer of a premium of $125 per tonne to Japanese buyers for April-June primary metal shipments, up 32 percent from the last quarter, three sources directly involved in pricing talks said on Monday.

    The offer comes as premiums climb in the United States and Europe, and as some Japanese buyers face lower inventories due to healthy local demand.

    The sources, who declined to name the producer, did not want to be identified as they were not authorised to speak with media.

    Japan is Asia's biggest aluminium importer and the premiums for primary metal shipments that it agrees to pay each quarter over the London Metal Exchange (LME) cash price set the benchmark for the region.

    "A producer sent us an email last Friday with an indicative price of $125, citing higher overseas premiums and lower inventories in Japan," said a source at an end-user in Japan.

    U.S. spot premiums and European spot premiums have risen by about $30-40 per tonne over the past three months, according to the sources.

    "Given stronger overseas premiums, we will need to accept an increase for the next quarter. But we would aim to get somewhere between $115-120 a tonne," said a source at a trading firm.

    For the January-March quarter, Japanese buyers agreed to pay a premium of $95 per tonne PREM-ALUM-JP, up 27 percent from the prior quarter due to higher spot premiums.

    The quarterly pricing negotiations between Japanese buyers and miners, including Rio Tinto Ltd , Alcoa Inc , South32 Ltd and Rusal, are expected to continue through next month

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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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    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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    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.

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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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    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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    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.

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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

    Britain's coal output falls by half to record low

    Britain's coal production fell by 51 percent to a record low last year as all large deep mines closed and others neared the end of their operational life, preliminary government statistics showed on Thursday.

    Coal output fell to just over 2 million tonnes of oil equivalent last year, the Department for Business, Energy and Industrial Strategy (BEIS) said in 2016 provisional energy data.

    Britain's coal production has fallen by 77 percent in the last five years.

    Coal accounted for 10.6 percent of electricity supplied in 2016, down from 25.8 percent in 2015, due to coal plant closures and a carbon price floor which has made coal-fired generation more expensive than gas-fired power.

    More detailed estimates of 2016 will be published on March 30, BEIS said.
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    Brazil's Vale swings to profit on higher iron ore prices

    Brazilian miner Vale SA reported on Thursday net profit of $525 million for the fourth quarter, falling short of analyst expectations but reversing a heavy loss in the period a year earlier thanks to record output and higher iron ore prices.

    A Reuters poll of analysts had forecast net profit of $1.8 billion in the quarter, but the world's largest producer of iron ore fell short on account of impairments totaling $2.9 billion, principally on fertilizer and nickel assets.

    In the same period of 2015, Vale reported a net loss of $8.6 billion.

    The quarter marked a return to cash generation for the miner on the back of rallying iron ore prices .IO62-CNO=MB, which rose around 80 percent in 2016.

    Vale posted adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) of $4.77 billion, the highest since the fourth quarter of 2013.

    Analysts at Bernstein said the results were positive, noting the company had trimmed net debt to $25.08 billon at the end of 2016, from $25.23 billion at the same point in 2015.

    "We continue to like Vale, as we believe that we have reached an inflection point for the company; cash generation and rapid de-gearing is the agenda henceforth, and we believe that the positive results today should lend further weight to this argument," Bernstein's Paul Gait said in a note.

    With higher prices and iron ore production reaching record levels, Vale reported net profit of $3.98 billion for the full year, a huge swing from a loss of $12.13 billion in 2015, the biggest loss in the company's history.

    "With strong production and the recovery in prices, it was forecast we'd have a strong quarter and finish the year strongly. And that's exactly what happened," Vale's Chief Financial Officer Luciano Siani said in a video on the company's website.
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    Shanxi to add 70 Mtpa advanced coal capacity in 2017

    Shanxi province, a major coal producing base in northern China, will move vigorously to boost advanced coal mining capacity and reduce outdated capacity in 2017, in order to optimize and upgrade its coal industry.

    The province planned to add 70 million tonnes per annum (Mtpa) of advanced capacity this year, said Xiang Erniu, director of Shanxi Coal Industry Administration.

    A total of 358 coal mines in Shanxi were assessed as "Safe and Efficient Mines" for the year 2014 and 2015, accounting for 46.92% of the nation's total, showed a document released by the China National Coal Association.

    Shanxi reduced 23.25 million tonnes of coal production capacity and shut down 25 coal mines last year. The province cut coal production by 143 million tonnes in the year, accounting for some 40% of the country's total production reduction, according to data from the administration.

    The province will draft capacity replacement and reduction plans for those mines that have gained approval yet not passed acceptance check or received preliminary approval to start construction.

    Small and medium sized coal mines would be regrouped and scaled back in capacity, and mines are allowed to deploy no more than two working faces so as to improve productivity.  

    Meanwhile, Shanxi will plow more into safety facilities in order to raise safety and quality standards.
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    Atlas returns to profit in H1

    Iron-ore miner Atlas Iron has swung back to a profit for the six months to December 31, on the back of increased underlying earnings before interest, taxes, depreciation and amortisation (Ebitda) and higher exports.

    Net profit for the interim period reached A$18.9-million, compared with a loss of A$114.3-million in the first half of the prior financial year. Underlying Ebitda for the same period was up from A$20.5-million to A$66.2-million.

    Atlas on Thursday said the results reflected the benefits of increased production, with 8.1-million tonnes produced in the first half of 2017, compared with the 6.9-million tonnes produced in the previous corresponding period, as well as significant ongoing savings and higher realised prices.

    “This strong result marks a key turning point for Atlas on several levels. Importantly, we increased production and reduced costs, enabling us to take advantage of the improvement in iron-ore prices.

    “The performance also meant we were able to make debt repayments of A$71-million, including A$54-million on January 5, reducing the balance of our Term B debt to A$118-million,” said Atlas MD Cliff Lawrenson.

    “The strong first half positions us well as we transition from the Wodgina and Abydos mines and commence the development of the recently approved Corunna Downs mineover the remainder of the 2017 calendar year.”

    Atlas earlier this month approved the development of the Corunna Downs project, with capital costs expected to reach between A$47-million and A$53-million to deliver the four-million-tonne-a-year lumps and fines project. Corunna Downs is expected to have a mine life of five to six years.

    Lawrenson on Thursday said the second half of the financialyear has started with challenging weather conditions, including rainfall levels around the mines well above those reported in recent years.

    “However, we retain our full 2017 production guidance rage of between 14-million and 15-million tonnes. Increasing price discounts on lower-grade ores are impacting realised prices, particularly on those cargos which are hedged and do not benefit from the overall increase in the headline 62% prices. However, we anticipate discounts should reduce over time to levels that more accurately reflect the relevant value of the various ores to the end users,” he added.
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    Seaborne thermal coal market to see supply dearth by 2030: Noble Group

    Demand for seaborne thermal coal is expected to exceed supply by about 400 million mt by 2030, with new coal-fired electricity capacities coming onstream, according to Noble Group.

    The trading company has estimated that the largest growth in demand would be from additional planned power generation capacities in Southeast Asia, which would reach about 249 million mt by 2030.

    "By 2030 Southeast Asia imports will be 50% more than the Atlantic coal market," said Rodrigo Echeverri, head of Energy Coal Analysis, Noble Group, at the Coaltrans Conference, which is currently being held in New Delhi.

    Demand from African countries, excluding South Africa, would be close to 40 million, Echeverri said, adding that 80% of South Africa's coal exports would be to other African countries and the Middle East.

    "Supply will not increase until price corrects," said Echeverri, adding that the backwardated market structure prevents capital from being used to producing coal.

    "Unless prices remain strong, Indonesia and Australia will not be able to ramp up production when the market needs it 2020 onwards."

    While greenfield projects, mainly in Australia and South Africa, will be required in just five years, coal from Colombia and the US might also be needed to fulfill base requirements in Asia.

    Echeverri said that he expects Indian import of coal to slide lower year on year until about 2021 and increase thereafter, exceeding 250 million mt by 2030. "The biggest risk to Indian imports of thermal coal is the production from captive coal blocks," he said.

    India's electricity production, which has grown at a 5.3% compound annual growth rate in 2015, is expected to fall from 5.6% in 2017 to 4.2% by 2030, Noble Group said in its presentation at the conference.

    While the share of gas in the fuel-mix for electricity generation is currently growing at 7.2%, for which the base is actually very small, the share of coal in the fuel-mix is expected to fall from 80% currently to 70% by 2030.

    Over this period, the demand for coal in electricity generation is expected to grow at 4.8% CAGR.

    "India has a lot of untapped demand [for electricity]," said a source with a power producer, adding that coal still is the cheapest source for producing power.
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    Vale to redeem next month $792 mln in bonds maturing in March 2018

    Vale SA, the world's largest iron ore producer, will redeem next month 750 million euros ($792 million) of bonds that mature in March 2018.

    The company said in a securities filing on Wednesday the bonds will be redeemed on March 27. The early repayment is consistent with the company's debt reduction strategy, the filing added.
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    China to speed up steel output cuts to curb winter pollution

    China will ratchet up planned steel production cuts and target illegal factories in an effort to reduce pollution during the winter, an official said on Wednesday.

    Beijing launched a campaign to cut steel overcapacity early last year in an attempt to stem a supply glut and crack down on pollutants from non-compliant producers.

    The government committed to cutting 100-150 million tonnes of annual crude steel capacity over five years, though critics say the curbs are yet to have a material effect.

    State media agency Xinhua reported that 26 cities in northeast China will be required to meet annual goals to cut steel overcapacity by October, targeting illegal factories, citing Zhao Yingmin, vice minister of environmental protection.

    Steel producing cities in China's Hebei province must also cut production in half during the winter season and seasonal production halts on cement and casting industries in the same region will remain in effect, Zhao was quoted as saying.

    Earlier this month environment group Greenpeace released research in which it said the world's biggest steel producer actually increased production in 2016.

    China's State Council warned in December of crackdowns on officials who fail to meet inspection standards.

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    Shaanxi Shenmu 2016 raw coal output at 215 mln T

    Shenmu county in Shaanxi province, a main coal producing base in northwestern China, produced 215.26 million tonnes of raw coal in 2016, local media reported.

    Raw coal sales of the county stood at 213.44 million tonnes last year. Of this, 86.65 million tonnes were sold by central government-owned producers, while 71.22 million tonnes were sold by enterprises owned by provincial- and prefectural-government.

    Shenmu vigorously carried forward de-capacity campaign last year to help improve its coal industry, and it has been promoting large scale and refined development of coal chemical businesses.

    In 2016, its semi-coke output stood at 20.47 million tonnes, and the volume in 2015 was 18.3 million tonnes.

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    Indonesia 2016 coal exports edge up 0.5pct on year

    Indonesia exported 369 million tonnes of coal in2016, edging up 0.52% year on year, showed data from the BPS-Statistics Indonesia.

    The country's exports of coking coal climbed 2.67% from a year ago to 83.08 million tonnes during the period, while that of thermal coal dropped 8.04% on the year to 228 million tonnes.

    Lignite exports stood at 58.25 million tonnes last year, surging 50.97% year on year.

    In December, Indonesia exported 32.22 million tonnes of coal, increasing 5.32% from the preceding year but down 4.38% from November. Value of the exports rose 39.71% on the year and 6.34% on the month to $1.64 billion.

    Exports of coking coal were 6.66 million tonnes in the month, dropping 15.33% year on year, while that of thermal dipped 0.88% from a year ago to 20.14 million tonnes.

    Lignite exports in December increased nearly 1.25 times year on year to 5.42 million tonnes.
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    India’s iron-ore production poised for five-year high

    With the current financial year drawing to a close in little over a month, Indian iron-ore production is poised to hit a five-year high.

    While official aggregate production data was yet to be available, granular province-wise iron-ore production data collated indicate that Indian iron-ore production during 2016/17 was expected to touch 180-million tonnes, the highest since 2010/11 when it was pegged at 207-million tonnes.

    The industry optimism over rebound in iron-ore mining was reinforced by the fact that for the first time in the last five years, growth in production was sustained over two consecutive years.

    The higher production expected in the current fiscal comes on back of 155-million tonne achieved in 2015/16.

    It was pointed out by an official in Federation of Indian Mineral Industries (FIMI), the sustained growth in production over two consecutive years indicated that miningwas getting fundamentally stronger riding on steady gains in international prices and improved local businessenvironment.

    It was also noted that over the last few years, a production growth in one year was followed by a slump the very next year and recent data indicated a reversal of such a trend.

    Citing examples, he pointed out that since the recent peak of 207-million tonnes in 2010/11, production slipped to 167-million tonnes the next fiscal and further to 136-million tonnes in 2012/13.

    Production rebound to 152-millio tonnes in 2013/14 but only to slide sharply to 129-million tonnes the very next year.

    The rebound of iron-ore production at the aggregate level was result of strong showing of the sector in two of the largest producing provinces of Odisha in the east and Goa in the west.

    Report from the Odisha government early this month, showed that iron-ore production in the region had already touch the 80-million tonne mark during the period of April-January 2016/17 and reach the 100-million tonne level by close of the financial year on March 31, a rise of estimated 50% over previous year.

    According to an official in Odisha government, the incremental production in the province was largely owing to a number of mines being brought back into production during the year.

    The government had taken an aggressive initiative to ensure that iron ore mining leases which had expired were renewed and in number of cases 50-year new leases granted under new legislative provisions.

    In the western province of Goa, the annual production ceiling of 20-million tonne imposed by the Supreme Court was also closing in with the Goa government apprehensive that some mines might have to curtail or close down production unless the ceiling was relaxed soon.

    Meanwhile, with the current financial year drawing to a close, the Goa government was attempting a balancing act within the overall production ceiling, a government official said.

    The government had allocated additional production quota to 30 mining lease-holders by taking away unused production quote of other lease-holders.

    He said that the 30 mines have been given varied hike in production limits by transferring unused production quota from mines which have failed to achieve their allocated quotas.

    This was done so that it could be firmly established that the apex court set aggregate production quota had been definitively achieved by all the mines and quotas were not left unutilized and this would make a stronger case for the government when it seeks court’s approval for a higher production ceiling for the coming fiscal, the official added.
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    Global steel production is surging in 2017

    The price of iron ore reached a 30-month high on Monday, while coking coal is trading 80% higher than this time last year. The rally in the steelmaking raw materials may gain further momentum this year as global steel production kicks off the year on a strong footing.

    World Steel Association data released on Tuesday, showed a 7% jump in global steel output in January to 136.5 million tonnes.

    The 50-year old industry body estimates that steel production in China, which is responsible for just shy of half the global total rose 7.4% year on year, but was fairly flat on a month-on-month basis.

    What makes Chinese output particularly strong is that the country's extended Lunar New Year holiday fell in January this year.

    World number three producer India recorded the biggest gain of the major producing countries, with output increasing by 12% year-on-year.  India's infrastructure push should keep blast furnaces on the subcontinent humming throughout this.

    Japanese output declined slightly last year, but the world's number two producer is having a strong start to 2017 with  an increase of 2.7% compared to January last year and 3.3% compared to the prior month.

    US output also rose in January following an annual decline in 2016, surging 6.5% in year on year terms. The strong numbers reflect the impact of anti-dumping measures against China spurring domestic output and optimism about President Donald Trump’s infrastructure plans.

    Some of the strongest growth was recorded in Russia and Ukraine, the world's fifth and tenth largest producers of steel. Russian output was 11.6% higher than January 2016, while Ukraine crude steel production rose 8.5%.
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    ARA coal stocks continue to slide

    Combined coal stocks at three delivery terminals in Northwest Europe's Amsterdam-Rotterdam-Antwerp trading hub slipped a further 3.86% over the week, as end users continued to draw down on port inventories following a recent cold snap and lifting of transport restrictions.

    Stock levels drifted down to 4.61 million mt according to data collected from port sources. Buyers were widely said to have ramped up barge reloads in order to replenish inventories at their facilities now that water levels on the Rhine River -- Germany's main transportation waterway for goods -- have risen. This reduced barge costs significantly as vessels could now load close to full capacity, one source said.

    Although the week-on-week reduction is the second in a row, stocks remained 32.8% higher in year-on-year comparisons, a trend that is expected to continue for the remainder of the first quarter, according to one source.

    Stocks at OBA Bulk Amsterdam's terminal fell 200,000 mt over the week to 2 million mt, while levels at the EMO dry bulk terminal in Rotterdam were only marginally lower, at 2.17 million mt, a 30,000 mt reduction.

    The only facility to show a slight uptick over the week was the OVET dry bulk terminal in Vlissingen, which had 440,000 mt of coal in stock, an increase of 45,000 mt on the week.

    "We've seen a good level of reloading again this week but arrivals are still in line with expectations for the time of year," one source said. "I think stocks will hold this sort of level until the end of February now."

    CIF ARA thermal coal prices had been more or less rangebound over the previous week as uncertainty over the direction of the market and limited demand kept buyers on the sidelines.

    S&P Global Platts assessed the price of European-delivered CIF ARA thermal coal basis 6,000 kcal/kg NAR and for delivery within the next 15-60 days at $81/mt Monday, a reduction of 30 cents on the week.
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    Rio Tinto considers coal mine sale in Queensland

    Rio Tinto was said in a for sale sign for its last two Queensland coal mines with expectations of a $2 billion deal, the Courier Mail reported on 21 February.

    Reports from London indicated that Rio Tinto has invited banks to tender for the job of advising the mining giant on the sale of the Hail Creek and Kestrel mines, the report said, noting that Merrill Lynch is apparently favoured to get the role.

    The reports suggest Rio has had unsolicited offers for the mines, following Rio's strategic retreat from coal.
    Earlier this year, Rio Tinto agreed to sell $2.45 billion of Australian mines to Yanzhou Coal Mining Co. Queensland's coal sector has undergone a radical transformation since the end of the boom with several collapses followed by major miners selling projects for token amounts.

    Peabody has shut its Burton mine while Glencore has closed and reopened its Collinsville mine. The Blair Athol coal mine, near Clermont, was sold by Rio Tinto to TerraComm for just $1 and is expected to start mining in less than six weeks.

    Stanmore Coal also bagged the Isaac Plains mine for $1 from Vale and Sumitomo.

    Batchfire also bought the Callide mine from Anglo which also put the for sale sign in front of Moranbah North and Grosvenor Mines, along with its Moranbah South development project.

    But Anglo American looks like it has had a change of strategy. It has swung back to profitability, a dramatic rebound for a company that only a year ago was planning to implement a sweeping restructuring plan.

    It has reported a net profit of $US1.6 billion for the year ended December 31, compared with a net loss of $US5.6 billion the previous year. Revenue was largely unchanged, rising to $US23.1 billion last year from $US23 billion a year ago.
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    Fortescue says H1 profit jumps 383 pct, misses market expectations

    Australia's Fortescue Metals Group Ltd on Wednesday reported a 383 percent rise in interim net profit to $1.2 billion, surpassing the $319 million in the year-earlier period on the back of a surprise surge in iron ore prices, but still fell short of market expectations.

    Analysts had forecast profit for the six months to Dec. 31 of about $1.5 billion, according to Thomson Reuters data.

    "Our successful operational performance combined with positive market conditions produced strong cash flows facilitating further debt repayments of $1.7 billion," Managing Director Nev Power said in a statement.

    Fortescue declared a dividend of A$0.20 ($0.1535) per share.

    Fortescue, Australia's third-biggest producer, is aiming to ship up to 170 million tonnes of ore in fiscal 2017, mostly to China.

    A push to hammer down costs has left Fortescue on par with larger rivals Vale SA, Rio Tinto Ltd and BHP Billiton Ltd , which combined control more than 70 percent of global sea trade in iron ore.

    Iron ore was one of the best-performing commodities in 2016, defying analyst forecasts for a correction on the back of plentiful supply and an expected slip in demand from China, the world's biggest buyer.

    Iron ore and steel markets grew at a modest rate during 2016, industry figures show, with China importing a record 1.02 billion tonnes of ore, and steel production rising by 1.2 percent versus 2015.
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    Ternium to pay 1.26 bln euros to buy Thyssenkrupp's Brazilian mill CSA

    Ternium SA has agreed to buy 100 percent of Thyssenkrupp's Brazilian mill CSA, the company said in a statement on Tuesday. Ternium will pay Thyssenkrupp 1.26 billion euros, and assume 0.3 billion euros in CSA's debt.
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    Large Chinese coal miners call for 276 working-day rule

    Most of China's large coal producers including Shenhua Group suggested the government to resume 276 working-day rule at all mines after the heating period ending in mid-March, in a bid to underpin price and ease anticipated supply pressure, sources learned from a meeting held by China National Coal Association on February 21.

    The association didn't give specific answers to whether and how the production reduction policy would be implemented this year, sources said.

    But officials with the association did suggested coal miners to enforce capacity cut resolutely.

    Both thermal and coking coal miners said they were faced with great sales and inventory pressure, which were weighing on prices.

    Besides Shenhua Group, another 16 large coal companies attended the meeting, including China National Coal Group, Datong Coal Mine Group, Shanxi Coking Coal Group.

    A draft proposal has been submitted to the National Development and Reform Commission, according to which some mines may be allowed to operate 276 working days over March-August.

    This, however, will not apply to advanced mines, mines with 70% production being primary coking coal or fat coal and mines in provinces buying outsourced coal to supplement supply, industry insiders said recently.

    All thoese are still under discussion, according to the NDRC.
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    Hebei to eliminate three batches of coal-fired power units

    North China's Hebei plans to eliminate condensing power units with capacity below 300 MW, coal-fired power units with capacity below 200 MW and all illegal power plants, in order to optimize energy mix, the provincial Development and Reform Commission said lately.

    Hebei has published the first batch of 16 coal-fired units to be eliminated this year, each with generating capacity at 174 MW.

    The second batch will be published in late March, mainly including illegal coal-fired power plants to be closed by end-2017.

    The third batch, to be published in late June, will phase out small condensing heating units with generating capacity below 300 MW.

    Hebei will shut all illegal coal-fired power units and those with capacity below 100 MW by end-2017, the commission said.

    All condensing heating units with capacity below 100 MW will be shut in 2017, it added.

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    China to curtail 75 Mtpa steel capacity over 2017-20

    China planned to curtail 75 million tonnes per annum (Mtpa) of steelmaking capacity in the next four years, said Chinese Ministry of Industry and Information Technology at a press conference on February 17.

    China has adjusted down de-capacity goal for its steel industry over 2016-2020 at 140 Mtpa, compared with the original target of 100-150 Mtpa proposed in 2016.

    Last year, China slashed a total 65 Mtpa of steelmaking capacity.

    Meanwhile, Chinese steel makers posted a year-on-year surge of 2.02 times in profit  in 2016, while the total losses dropped 51% compared with losses suffered in 2015.
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    South African coal miners look to domestic market for higher prices

    South African thermal coal miners are looking increasingly at the domestic market, with inland consumers more willing to pay higher prices than buyers in the export market and shipments out of the country falling, according to market sources.

    S&P Global Platts assessed the FOB price of Richards Bay physical thermal coal basis 5,500 kcal/kg NAR and for delivery within the next 7-45 days at $70/mt. This is equivalent to Rand 917.83/mt for exporters of such material at Richards Bay Coal Terminal.

    According to XMP Consulting senior analyst Xavier Prevost, the average price of sized coal in the South African domestic market is Rand 606.67-788.91/mt ($46.27-$60.17/mt) FOT for A and B grade coal, and he believes these prices and their projected increases would eventually shift a lot of exportable coal to the local market.

    A grade coal has a minimum calorific value of 27.5 MJ/kg (6,568 kcal/kg), while B grade coal has a CV of 26.5-27.5 MJ/kg (6,329-6,568 kcal/kg).

    "Inland prices are increasing a lot and export prices, regardless of what some analysts say, are not going to be good in the long term," he said.

    According to recent research made by XMP Consulting, before 2009, domestic prices rose by an average 10%/year, with prices rising 8%/year over 2011-15 and 5% in 2016.

    Even with South African 5,500 kcal/kg NAR thermal coal export prices reasonably high compared with the low of $37.50/mt FOB hit in October 2015 and FOB prices in the $40s/mt for large parts of last year, material sold inland is on a FOT basis at the mines, meaning that sellers are not saddled with extra export costs such as processing, rail transport to port, handling fees and port allocation.

    In addition, many mines could achieve higher production yields by supplying the inland market, with B grade coal, which is what most inland industrial customers buy, according to the XMP Consulting research.

    The research found that, as there has never been a formal price index for sized coal sold to domestic users in South Africa, miners have "generally taken their lead from each other and set their prices accordingly, with Glencore predominantly setting most prices." According to a letter to customers at the beginning of February seen by Platts, large miner Glencore has adjusted prices to charge as much as Rand 1,300/mt ($99.15/mt) FOT for sized-coal from its Tweefontein operations, Goedgevonden Colliery, Graspan Colliery and Wonderfontein Colliery.

    According to Prevost, local coal sales were 181.2 million mt last year, split between electricity (66%), synthetic fuels (23%), industries (4%), merchant and domestic (4%) and metallurgical (3%).

    He said sized coal was used by all industry, besides state-owned utility Eskom and synfuel and chemical company Sasol, with some users using small amounts of unsized coal and merchants buying any coal available and exporting some.


    Another factor that could make the South African inland market increasingly attractive to mining companies is falling export demand. In 2016, South African coal exports declined for the first time since 2009. Shipments for the year were 72.81 million mt, 3.4% less from 2015's record high 75.39 million mt to their lowest annual volume since 2013.

    Large miner Anglo American's 2016 thermal coal export sales were down 8% on the year to 34.1 million mt, according to its annual production report, while domestic sales for the year rose 9% to 34.5 million mt.

    South 32's South African thermal coal unit sold 5.86 million mt of export thermal coal during July-December 2016, down 27% on the year. The company's financial year runs from July to June. Domestic sales registered a much smaller drop of 2% to 8.92 million mt.

    Glencore did not provide sales totals for the year, but its South African thermal coal production for export in 2016 dropped 13% to 17.2 million mt, although output for the domestic market fell too.

    Some factors will continue to promote exports, such as demand from routine buyers, take-or-pay rail agreements between mining companies and state-owned freight company Transnet Freight Rail -- 10-year contracts were signed in 2014 -- as well as penalties for volumes not delivered to RBCT under port allocation agreements.
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    China to launch nationwide coal mine inspections in March

    The work safety watchdog will launch a widespread safety check of coal mines nationwide in March, a move prompted by three coal mine accidents that killed 32 miners this year, said officials with the State Administration of Coal Mine Safety.

    The campaign, which will last until the end of the year, will look for safety hazards and focus on accident prevention, Huang Yuzhi, head of the State Administration of Coal Mine Safety, said at a work conference on February 21.

    The most recent fatal incident, a gas explosion at Zubao Coal Mine in Lianyuan, Hunan province, killed 10 miners on February 14. Fatal incidents that together killed 22 occurred in Dengfeng, Henan province, on January 4, and in Shuozhou, Shanxi province, on January 17.

    Huang said the three accidents exposed the lack of legal awareness among coal mine owners, given that two of the mines were found to have been operating in prohibited areas.

    The campaign will be led by provincial coal mine safety departments and divided into two phases. In the first phase, the authorities will assess the safety situation of all coal mines and identify problems. In the second phase, the authorities will check on how the problems have been rectified.

    The provincial watchdogs are also expected to formulate a report on each coal mine regarding ways to improve their work safety situation and solve existing problems, Huang said.

    Production would be suspended at coal mines that fail the work safety standards or are deemed to pose safety hazards, he said.

    Yang Huanning, head of the State Administration of Work Safety, has warned of possible risks associated with the extreme weather conditions that many parts of the country are seeing this week.

    He also said higher prices for resources like coal, steel and nonferrous metals have spurred coal mines to produce beyond their designed capacity.

    In one extreme case, a coal mine in Shanxi province, with designed annual capacity at 900,000 tonnes, produced 5.2 million tonnes of coal last year, according to Huang.

    China saw 11 accidents from accumulations of flammable gas at coal mines since the fourth quarter of last year, and 140 people were killed in those incidents, according to the work safety watchdog.
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    Australia: clean energy fund could underwrite new coal plants

    Australia is considering altering legislation to enable funds slated for clean energy developments to be used to bankroll construction of new low emission, coal-fired power plants, Reuters reported on February 18.

    The suggestion by Energy Minister Josh Frydenberg comes after a major power outage during a heat wave in South Australia state worsened a row with the national government over energy security and the state's heavy reliance on wind and solar power.

    Frydenberg said current laws governing the Clean Energy Finance Corporation (CEFC) prevented it from investing in the high-energy, low emission (HELE) coal plants.

    "In the Act it explicitly rejects carbon capture and storage and nuclear power," Frydenberg stated on February 12. "It actually confines investments to ones which reduce emissions by more than 50% on what the average is across the national electricity market."

    The government suggestion to tap taxpayer funds to build the HELE plants also comes after industry participants indicated the private sector was not interested in investing in the plants.

    Frydenberg said that while the cost of renewable energy had fallen considerably, it did not solve the problem of integrating intermittent energy supplies into a grid designed to transmit baseload sources of supply, mainly from coal.

    New South Wales state Premier Gladys Berejiklian said her state, the country's most populous and one heavily reliant on coal-fired power plants, was open to new coal-based sources of energy supply.

    Australia is one of the largest carbon emitters on a per capita basis due to its reliance on coal-fired power plants. Power generators account for roughly one-third of Australia's carbon emissions.

    The national government wants 23.5% of Australia's energy mix to come from renewables by 2020, but nearly all states have set much more ambitious renewable goals to cut carbon dioxide emissions from their electricity sector – clouding the outlook for many generators.
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    Iron ore price sets fresh 30-month high

    The Northern China import price of 62% Fe content ore gained 2.7% on Monday, reaching $92.7 per dry metric tonne, the highest since mid-August 2014 according to data supplied by The Steel Index.

    After a 85% rise in 2016, the price of iron ore has improved by over 16% so far this year and has more than doubled in value since hitting near-decade lows at the end of 2015.

    The rise in the price of the steelmaking raw material has flummoxed market observers given supply growth expected in 2017, record-setting inventory levels at ports and an uncertain outlook for demand from China.

    FocusEconomics in its January survey of analysts and institutions shows the price of iron ore averaging $56.70 a tonne during the final quarter of next year. For Q4 2018, analysts expect prices to moderate further to average $55.70 over the three month period.

    None of the analysts foresee iron ore holding at today's prices – Dutch bank ABN Amro is the most optimistic calling for a $76 average towards the end of 2017 while London-based Investec sees an average of $71.50 over the cours of this year.

    BMO Capital Markets see prices correcting sharply from today's levels to average $45 by the start of 2018 while Oxford Economics expects iron ore to average $53 this year and below $50 in 2018.

    Record imports

    Imports by China continued to strengthen in 2017 after hitting an all-time high last year.

    Trade figures released earlier this month showed China imported 92 million tonnes of iron ore in January, up 12% or just less than 10 million tonnes compared to a year ago. Shipments for January were the second highest on record valued around $7 billion.

    The all-time record for monthly Chinese imports in terms of volume was in December 2015 with shipments totalling 96.3 million tonnes. But the price of iron ore fell to below $40 a tonne, the lowest in nearly a decade during that month, pushing the value of shipments below $5 billion.

    The all-time record in terms of dollar value was set in January 2014, when the country imported $11.3 billion worth of iron ore back when prices were firmly in triple digit territory.

    Forging more than half the world's steel, Chinese imports of iron ore for the full year 2016 topped one billion tonnes for the first time. The 1.024 billion tonnes constitute a 7.5% increase over the annual total in 2015 and is indicative to what extent exporters from Brazil and Australia has been able to displace high-cost domestic producers.

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    Vale to scrap controlling bloc, merge shares in major governance move

    Vale SA plans to become a company with no defined controlling shareholder as soon as possible, in a landmark step aimed at enhancing transparency and equal rights for all shareholders in the world's largest iron ore producer.

    Controlling shareholders grouped under holding company Valepar SA agreed to stay together for up to three and a half more years. Under terms of that, they will present a proposal soon by which Vale will incorporate Valepar and proceed to merge the company's several classes of stock into a single, common one by November.

    The existing 20-year accord governing Valepar that expires in May will be extended through November to guarantee the transition. Holders of Vale's Class A preferred shares (VALE5.SA) who join the share conversion voluntarily will receive 0.9342 common stock (VALE3.SA), as part of the process.

    To ensure completion of the plan, Vale would pay owners of Valepar a 10 percent premium for their shares, implying a 3 percent dilution for all shareholders. The former Valepar owners can sell the equivalent of up to 22 percent of Vale's common shares after a lock-up period starting in August expires, provided they keep a combined 20 percent by November 2020.

    The change represents a milestone in a country long hobbled by corporate governance abuses and reorganizations that hampered minority investors in most cases. Reuters reported on Jan. 19 the planned to make Vale a company with dispersed share ownership and the listing of a single type of stock.

    The announcement sparked a surge in common shares of Rio de Janeiro-based Vale, which touched their highest level since December 2012. Preferred shares, Vale's most widely traded class of stock, also hit their highest since January 2013.

    "This represents a historical opportunity for Vale, and it's an invitation that the controlling bloc is extending to investors to join a company with the strictest governance standards," Chief Executive Officer Murilo Ferreira said at a conference to discuss the Valepar proposal.

    At least 54 percent of holders of Vale's preferred shares will have to approve the conversion, whose approval is also linked to the passage of the entire proposal. Ferreira expects the company to convene a shareholder assembly to vote the entire plan around June.

    "The transaction seems to be a win-win for both controlling and minority shareholders," said Rodolfo de Angele, a senior basic materials analyst with JPMorgan Securities.


    People familiar with the matter told Reuters in January that Valepar members Bradespar SA (BRAP4.SA) and pension fund Previ Caixa de Previdência [PREVI.UL] wanted a dispersed share ownership in Vale as a way to attract more investors.

    Once the final accord expires in November 2020, a shareholder who owns over 25 percent of Vale will be forced to launch a buyout offering.

    The partners in Valepar include Previ - currently Vale's largest shareholder, Bradespar, Japan's Mitsui & Co (8031.T), an arm of state development bank BNDES, and pension funds Petros Fundação [PETROS.UL], Funcef [FUNCEF.UL] and Fundação Cesp.

    The plan could give some of those cash-strapped pension funds the possibility to cash out from Vale, whose two classes of shares have almost risen four-fold over the past 12 months.

    Shares in Bradespar, which is controlled by Banco Bradesco SA (BBDC4.SA), posted their biggest intraday jump ever, adding as much as 20 percent. Analysts said the accord increases the value of Bradespar's net assets while freeing it up from having to make a large cash payment to Previ for renewing the accord.


    Currently, Vale's American depositary receipts (VALE.N) trade at the equivalent of 10.5 times estimated earnings for this year, below Rio Tinto Plc's (RIO.L) 10.7 times and BHP Billiton Plc's (BLT.L) 15.9 times, according to Thomson Reuters data.

    The implications of Monday's announcement on investor perception about Vale's governance should translate into a faster convergence of Vale and Rio Tinto share prices, Banco BTG Pactual's trading desk said in a client note, adding the move could help unleash 21 percent more value for Vale shareholders.

    The plan will also help limit government interference in Vale - an aspect that weighed down the company's stock during President Dilma Rousseff's five years in office. Improved governance stemming from the move could help Vale's stock cut the valuation gap relative to global mining peers.

    "It's a brutal change of governance for the company," the BTG Pactual note said.

    Still, the Brazilian government will keep a so-called golden share, a legal mechanism that allows it to fend off hostile takeover attempts and shape strategic decisions, Ferreira said.

    "It's a political event ... that in my view, should not impact the Vale case being discussed today," he said at the call.

    The strategy replicates the move that helped put planemaker Embraer SA (ERJ.N) out of the government's control in 2006 in which the share conversion was done simultaneously with the scrapping of the planemaker's shareholder accord. The government, however, kept a golden share in Embraer.

    The 3.073 billion-real ($990 million) goodwill generated by Vale's incorporation of Valepar will be split equally among all shareholders, Chief Financial Officer Luciano Siani said at the call.

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    Coal price rise fuels giant Whitehaven recovery

    Whitehaven Coal's half-year profit has risen steeply thanks to a jump in coal prices late last year and increased production, the Australian Associated Press reported on 17 February.

    The miner's net profit of $157.5 million for the six months to December 31 is up from $7.8 million a year ago.

    Revenue has also jumped sharply from the same time last year - up 43 per cent to $823.5 million.

    "Whitehaven Coal is capturing the benefit of the improved coal price environment, aided by a sustained focus on cost reduction," chief executive Paul Flynn said.

    The profit growth during the quarter was driven by a sharp rebound in coal prices during the last few months of 2016.

    The company said it received an average price of $92 a tonne for thermal coal and $104 a tonne for metallurgical coal during the December quarter. For the half, its realised price averaged $81.3 a tonne, compared to $59.8 a tonne in the 2016 first half.

    As a result, its average profit margin on coal sales jumped to 42 per cent during the first half, from 19 per cent a year earlier.

    Coal sale volumes also rose, by 6 per cent, to 7.8 million tonnes, helped by higher production at its two main mines — Narrabri and Maules Creek in NSW.

    Last month, the company had lowered the production guidance for its Narrabri mine by about 6 per cent after encountering "adverse geotechnical conditions" at the site, but today it reaffirmed its guidance for full-year coal production to be between 21 million and 22 million tonnes.

    Whitehaven said production in the second half of FY2017 is planned to be higher than in the first half.

    It did not declare an interim dividend, but Mr Flynn said the increased profits and strong cash flows meant the business was well positioned to accelerate debt reduction.
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    China coal firms to discuss moves to stabilize output on Tuesday: media

    China's top coal producers will meet on Tuesday to discuss plans for stabilizing output this year, the official Shanghai Securities News reported.

    The meeting organized by the China Coal Association will assess current operations and explore further measures to ensure stable output, the newspaper said in a report on its website on Monday.

    Talk in the market that the government will reinstall daily limits on coal mining output after the winter heating period pushed up thermal coal futures last week.

    Coke and coking coal futures rose on Monday after Beijing suspended imports of North Korean coal as part of its efforts to implement United Nations sanctions against the country.

    The output cuts, introduced in April 2016, ordered mines to limit the number of days they operate each year to 276 from 330 as part of Beijing's effort to cut inefficient surplus capacity.

    But the limits were abandoned in November after a double-digit percentage drop in output triggered a sharp rally in prices ahead of the key winter heating season.

    The report said that Shenhua Group, China National Coal Group and others are backing renewed cuts to 276 working days from 330, but that details on the implementation still needed to be worked out by the government.

    It added that targeted output cuts in 2017 are expected to be lower than last year but more difficult to achieve.
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    China steel mills caught on the hop by North Korea coal ban

    China's steel mills and traders were scrambling to find alternative supplies of coking coal for steel making on Monday after Beijing slapped a surprise ban on coal imports from its isolated northern neighbour.

    Chinese prices of steel, coking coal and coke all rallied, as traders and analysts said mills will likely be forced to buy more expensive domestic material or seek alternatives further afield from Russia or Australia, driving up costs.

    While North Korea accounts for only a small portion of China's total coal imports, it is the main foreign supplier of high-quality thermal coal, called anthracite, which is used to make coke, a key ingredient in steelmaking.

    "This news really took us by surprise. We are looking at a couple of alternative plans," said a steel mill purchasing manager, based in the northern province of Liaoning.

    These included buying anthracite from Shanxi province or buying more coke from local providers, but both were more costly, said the manager, whose firm uses about 10,000 tonnes of North Korean anthracite each month.

    Business with North Korea had become increasingly difficult under years of sanctions and the once-bustling trade handling coal from the north had shrunk to just a few private merchants.

    Still few mills or traders anticipated the complete suspension of imports, which came a week after Pyongyang tested 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 bought 22.48 million tonnes of anthracite from North Korea in 2016, 85 percent of its total imports.


    Steel mills often blend anthracite with coking coal to make coke, a fuel used in blast furnaces, rather than using only more expensive coking coal.

    China's most-active futures contract for rebar, a steel product used in construction, rose 2.6 percent by 0640 GMT on Monday, while coke and coking coal added 2.6 percent and 2.4 percent respectively.

    Shares in Chinese anthracite producer Yangquan Coal Industry rose 2.8 percent.

    "Rebar jumped on anticipation that the ban on North Korean anthracite could lead to higher costs for steel mills that will struggle to find cheaper alternatives in the domestic market," said Zhang Min, a coal analyst based in Zibo, Shandong with Sublime Information Group.

    A coke producer said he expected to ban to lead to a rebound in coke prices, which had fallen since late December due to good supply and reduced demand for the Lunar New Year.

    "I am not planning to take any new orders from new clients right now, because we believe coke powder prices will rebound sharply this week on the news," said the manager of a domestic coke plant, based in Shandong province.

    Some mills could seek other imports, but producers such as Australia, Russia and Vietnam didn't produce enough to pick up the slack and shipping it would cost significantly more than from North Korea, traders said.

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    US coal mines are opening in a year of `cautious optimism’

    Add Corsa Coal Corp. to the short list of U.S. coal producers doing something that’s become a bit of a rarity these days: opening mines.

    The Canonsburg, Pennsylvania-based company will start a new operation in Pennsylvania as early as May. It joins Ramaco Resources Inc., which began producing at its first mine in West Virginia in December and plans to open two more this year in Central Appalachia. They’re among the few turning more bullish on the business following an unprecedented market collapse that has shut hundreds of mines and left thousands jobless in recent years.

    “We’re staffing up,” Corsa Chief Executive Officer George Dethlefsen said in a phone interview this week. “We’re going to hire 100 people, and we’ve gotten hundreds of applications.”

    There’s newfound optimism in America’s coalfields with spot prices for metallurgical coal — the sort used in steelmaking — twice as high as they were a year ago. China curtailing its own production and tightening seaborne markets helped stoke a rally last year. President Donald Trump is now promising to bring coal jobs back, making his first move this week to roll back Obama-era environmental regulations that targeted the sector.

    “There’s definitely cautious optimism after years of being brutally beaten down,” Jeremy Sussman, an analyst at Clarksons Platou Securities Inc., said in a phone interview.

    Global demand for the carbon-intensive, power-plant fuel is still weakening. A new age of clean, cheap natural gas and renewables has emerged, thanks to the shale boom and fears of global warming. Miners including Corsa have said they’re focused on financial metrics such as rates of return and credit ratings rather than simply production to survive in the shrinking market.

    Earlier this month, Ramaco held the industry’s first initial public offering in two years. On top of the three mines it’s planning to open this year, the miner’s working to get one in Pennsylvania permitted so it can start operations in 2019.

    “We will be a very big shot in the arm down into an area that certainly needs some help and good news,” Ramaco Chairman Randall Atkins said in a phone interview.
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    Ningbo coal imports fall in recent three yrs

    Ningbo port, located in southeastern China's Zhejiang province, saw coal imports fall for three straight years in 2014-2016, showed data from the local Entry-exit Inspection & Quarantine Bureau.

    In 2016, coal imports through Ningbo, the largest coal import port in eastern China, stood at only 4.66 million tonnes, with total value at $309 million, about 20% of the highest level ever reached, data showed.

    The port imported a record high of 12.92 million tonnes in 2013, with value at $1.19 billion.

    The decline was mainly impacted by China's new quality standards for imported commercial coal implemented since January 1 2015, weakening demand from downstream sectors, and lower prices of domestic coal.

    Its major products -- bituminous coal, anthracite coal, coking coal and lignite, were mainly shipped from Australia, Indonesia, Canada and Russia.

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    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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    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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    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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