Mark Latham Commodity Equity Intelligence Service

Wednesday 30th November 2016
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    China commodities, stocks slide as weak yuan spurs fears of liquidity squeeze

    China's stock markets fell and commodities prices plunged on Wednesday as government efforts to steady the sliding yuan currency and curb capital outflows added to fears of a liquidity squeeze in the banking system.

    Analysts said moves by China's central bank in recent days to shore up the yuan were sucking additional liquidity from the system even as banks and companies start to hoard cash as they typically do heading into the year-end.

    State-owned banks were seen selling dollars for a third consecutive day on Wednesday.

    That is pushing up borrowing costs, making investments in markets such as commodities and equities more expensive.

    Capital outflows spurred by the yuan's recent slide to 8-1/2 year lows in the face of a surging U.S. dollar are likely straining the system further, prompting authorities to intervene to steady the currency and discourage capital flight.

    "The stress could continue for a while," said Gu Weiyong, chief investment officer at hedge fund Ucom Investment Co, which specializes in fixed-income investment.

    "Whether the situation gets better depends on the willingness of the central bank to inject more liquidity into the system."

    Coking coal and steel rebar futures prices were on track for their biggest one-day drop on record as the costs of borrowing money. Investors also sold base metals to shore up cash.

    China's commodities prices had already been in sharp retreat after major commodity exchanges introduced further measures earlier this week aimed at taming a spectacular months-long rally which many suspect has been fueled largely by speculation.

    Short-term money rates spiked, while bond prices slid.

    Short-term borrowing costs in Shanghai continued to rise, with the overnight Shanghai Interbank Offered Rate (SHIBOR) climbing to 2.3160 percent, its highest since Sept.30.

    The overnight rate looked set to rise for the 15th session in a row.

    The seven-day SHIBOR stood at 2.4960 percent, the highest since last August, while the 3-month rate advanced to its loftiest level since mid-February.

    China shares also fell, with the blue-chip CSI300 Index down 0.7 percent and poised to snap a 7-day winning streak as raw material stocks weighed.

    An index tracking non-ferrous metals in Shanghai dropped roughly 1 percent, after slumping 4.1 percent on Tuesday, the biggest one-day fall in 16 months. Meanwhile, coking coal futures plunged over 7 percent.

    The volume-weighted average rate of the benchmark 14-day repo traded in the interbank market, a gauge of measuring general liquidity in China, shot to 3.6935 percent, the highest since January.

    Bond yields, which move inversely with prices, also rose.

    Benchmark 10-year treasury yields advanced to a five-month high of 2.943 percent, while 10-year treasury futures on Wednesday touched the lowest level since late April.

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    Australia home building boom fast turning to rubble

    Australia home building boom fast turning to rubble

    Australia is watching a much-needed boom in home building turn to rubble after approvals for new projects collapsed in October, a violent turnaround that could undermine policymakers' hopes for solid economic growth next year.

    Shock figures from the Australian Bureau of Statistics on Wednesday showed approvals to build new homes sank 12.6 percent in October from a month earlier, confounding forecasts of a 1.5 percent rise and the biggest drop since mid-2012.

    It was the third month of declines and brought the pullback since July to 22.5 percent.

    "Overall the update is unambiguously weak and puts a clear marker in the ground showing the construction cycle is now turning down," said Matthew Hassan, an economist at Westpac.

    Most of the damage came in the once high-flying apartment sector where approvals dived by a quarter in October alone, and were down more than 42 percent on the same month last year.

    That will be alarming news for the Reserve Bank of Australia (RBA), which has been counting on continued strength in home building to offset a lingering drag from a mining slump.

    Indeed, figures due next week had already been expected to show the economy all but stalled in the third quarter, and may even have shrunk - only the fourth negative quarter in 25 years.

    "Total approvals are still relatively high but the speed at which they are rolling over is a real surprise," said Shane Oliver, chief economist at AMP.

    "It already looks like the economy lost momentum in the third quarter and now residential investment could turn into a drag on growth next year," he added.

    "That only underscores our call for another rate cut next year."

    While the economy had been running at a brisk 3.3 percent in the year to June, that likely slowed closer to 2.0 percent for the year to September.

    The RBA has been playing down the need for further easing following cuts in August and May that took the cash rate to an all-time low of 1.5 percent.

    Policymakers argued that the massive drag from a slowdown in mining investment had almost passed, while a revival in prices for key commodity exports in recent months was set to boost national income.

    As a result, financial markets had all but given up on the chance of a further rate cut <0#YIB:> and were even toying with the idea of a hike late in 2017.

    "All talk of a hike is out the window after these building numbers," said Oliver.
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    Glencore pivots from disposals to dividends as stock rallies

    Glencore fended off questions in 2015 about its survival as commodity prices hit new lows, and now there’s talk that the company’s turnaround plan has gone so well that it could be months away from paying dividends again. Surging coal and zinc prices, a rebounding stock price and shrinking debt pile made Glencore one of mining’s biggest success stories this year.

    CEO Ivan Glasenberg, who will provide an update on corporate strategy on Thursday, spent the past year ticking off items outlined in a crisis-induced debt reduction plan, including a goal to sell $4-billion to $5-billion in assets. The market rewarded him for it, with the stock tripling in 2016 and clawing back almost all of last year’s losses.

    Now, backed by a strong rebound in profits from its coal and zinc divisions, Glasenberg is in a position to pay back shareholders for supporting him through Glencore’s darkest days as a publicly traded company. None more so than Harris Associates’ David Herro, who placed the biggest wager on a Glencore recovery. The firm invested more than $2-billion at a time when others like Lansdowne Partners, one of Europe’s largest hedge funds, were betting big on further declines.

    “Job one is to continue to make sure that the balance sheet is strong and could withstand any kind of aggressive falls in commodity prices,” Herro, a portfolio manager at Chicago-based Harris, which is Glencore’s fourth-biggest shareholder with about a 5% stake, said in an interview with Bloomberg Television in London this month.

    “Then, selectively look at opportunities on how to use that free cash,” he added. “If there’s something that could be bought at a discount, at a good price, by all means look at it. But if not, there’s dividends, there’s share buybacks, there’s all kinds of other things.”

    Glasenberg and CFO Steve Kalmin may outline 2017 forecasts for spending, costs and production at Glencore’s investor day on Thursday, according to Credit Suisse Group. The company may also reveal a new dividend policy after skipping the last two payments to pay down debt, which stood at $30-billion last year.

    Booming prices for thermal coal and zinc, both up about 80% this year, are bolstering profits and provide a path for the return of dividends as early as March, according to UBS Group AG, which predicts it may pay 5 cents a share in March.

    Glencore may resume payments after the first half and start a new policy of returning 40% of net profits after tax to shareholders, said Alon Olsha, a mining analyst at Macquarie Group in London.

    “Glencore is now able to talk about restarting the dividend ahead of expectations,” Clive Burstow, who helps manage about $475-million of natural-resource assets at Baring Asset Management in London, including Glencore shares, said in an interview. “It’s because suddenly their cash-flowgeneration has been a lot stronger. We’ve arguably moved through the trough of the cycle.”

    Glencore hit a 16-month high on Nov. 11 of 292 pence in London, more than double the price from last year’s share sale. The company has also been buying back bonds, widening a program to $1.5-billion last month. The stock fell 1.1% to 281.6 pence at 9:42 a.m. local time, valuing the company at $50-billion.

    Investors are also looking for guidance on whether Glencorewill restore production at mines, especially in zinc, according to Olsha. Credit Suisse estimates that about 100 000 to 150 000 tons of the 500 000 tons of annual zinc output suspended will be brought back next year.

    Another potential use of surplus cash is acquisitions, though it would be premature to expect any big deals, said Burstow of Baring Asset Management.

    “I’d like to see another six to nine months of them carrying down the path that they are on,” he said. “Let’s get the dividend restarted, let’s see that the balance sheet is firmly in a much healthier place.”

    Glasenberg built Glencore through a series of acquisitions since taking on the CEO role in 2002. He led the strategy of twinning mining assets with the trading business, steering Glencore through a $10-billion initial public offering in 2011 and $29-billion takeover of Xstrata a year later to add mines and smelters.

    The last major deal undertaken by Glencore was the $1.4-billion takeover of Caracal Energy in Chad in 2014 that gave the company control of oil fields. The company has since written off most of the value of the business after energyprices slumped.
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    Europe 'can cope this winter' despite French nuclear squeeze: power grid group

    Europe has sufficient electricity generation capacity to meet normal and severe demand this winter "even if the situation in France will be tense," transmission system operator group Entso-e said Tuesday in its Winter Outlook Report 2016-17.

    The report assesses generation adequacy across 35 synchronously-connected electricity markets in continental Europe including Turkey.

    France is undergoing the lowest nuclear power availability in 10 years, with safety test decisions by French nuclear safety authority ASN leading to additional nuclear outages lasting for several weeks this winter, Entso-e said.

    Capacity margins in France "will decrease significantly in the first three weeks of December," with the country dependent on imports during this time. French adequacy risks then re-emerge in the second week of January if temperatures drop.

    "Adequacy risk is assessed at 4% in the Weeks 49 to 51 of December compared to 3% in Week 2 of January," it said.

    "Risk can occur in the event of cold waves at least 3 degrees C[elsius] below normal temperatures in December and 5 degrees C below normal temperatures in January," Entso-e said, noting up to 2.4 GW load sensitivity in France per 1 C fall in temperatures.

    French transmission system operator RTE had contracted emergency load reduction in place in case of shortages, the report said.

    "Moreover, RTE can drop the voltage for several hours by 5% to lower the load and to maintain adequacy," it said. "Eventually, in the worst and unlikely case, RTE could curtail load locally in a preventive way to secure the system." Furthermore, TSO coordination through Regional Security Coordinators would monitor generation adequacy "and address additional countermeasures at regional level that might be required to ensure a secure operation of the power system," the report said.


    Great Britain's adequacy might be affected by the French situation, with the UK needing high imports "from all neighboring countries," Entso-e said.

    Under extreme conditions Great Britain had additional capacity from open cycle gas turbines and pump-storage plants that it could call on, it said.

    "National Grid also expects there will be excess volumes of Short Term Operating Reserve (which can also be used," Entso-e said.

    Under normal conditions, Week 50 in Great Britain had the lowest forecast remaining capacity (1.49 GW). Under severe conditions, Week 3 had the lowest remaining capacity (-2.60 GW), the report noted.

    "This can be managed by imports from Interconnectors, Supplemental Balancing Reserve (SBR) and we would expect the market to respond as well," it said.

    Week 52 night times in Great Britain, meanwhile, had the lowest downward regulation capabilities (4.27 GW) due to low load around Christmas.


    For Germany the risk was of regulating oversupply, not undersupply of electricity.

    "The period around Christmas could be critical due to a massive oversupply of the German control area," the report said.

    "This could result in strong negative prices for electricity and could contribute to a high upward frequency deviation. In such an event, the German demand for negative control reserve might not be covered by the usually procured reserves," it said.

    Increased reserves would be procured and the ability to reduce wind output extended during this period. Exports would also ease oversupply at times of minimum demand. Nevertheless, on Sunday mornings when demand dips Germany expects "a great amount of excess generation" that will require TSOs to down-regulate renewable power surpluses.

    "In situations of high RES feed-in in the north and high load in the south of Germany, the need of remedial actions is expected to maintain (n-1) security on internal lines and on interconnectors," the report said.

    While high levels of German nuclear outages were foreseen at the end of the year/beginning of next year, no critical situations were forecast due to general oversupply.

    Finally at the European level, a joint analysis with gas transmission group Entsog had shown "the robustness of the European electricity system, even in the event of a high demand situation with a simultaneous interruption of gas transit through Ukraine," Entso-e said.


    Net generation capacity in Europe has increased by around 11 GW year on year, the report said, driven by growth in wind and solar (13 GW added), in hydro or other renewables (7 GW), and in gas plant (5 GW).

    While gas-fired capacity additions were up, however, total dispatchable capacity was down 14 GW year on year, potentially reducing the system's ability to respond to shocks such as the French outages.

    Recent S&P Global Platts' analysis shows that a trend in falling dispatchable capacity is set to continue for the next three years.

    Conventional plant margins in Northwest Europe are set to fall by 17.7 GW between 2016 and 2018, removing 7% of the region's controllable thermal capacity.
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    Oil and Gas

    Russia, Iran agree to coordinate steps in oil market ahead of OPEC talks

    Russia's President Vladimir Putin and his Iranian counterpart Hassan Rouhani agreed to continue coordinating steps in global hydrocarbons markets in a phone conversation late Monday ahead of Wednesday's OPEC meeting, according to the Kremlin.

    "The presidents agreed to continue coordinating steps in global hydrocarbons markets, including as part of the energy dialog between Russia and the Organization of the Petroleum Exporting Countries," the Kremlin said in a statement.

    The leaders underlined "the crucial nature of OPEC measures to limit crude production as a key factor for stabilizing the oil market," it added. The statement came two days before 14 OPEC countries' ministers meet in Vienna to try to clinch what would be its first coordinated crude output cut since 2008, to help accelerate the market's rebalancing.

    They are expected to be joined by non-OPEC producers such as Russia, which has repeatedly said it will join any action agreed within OPEC.

    Putin said in October Russia is ready to join a coordinated production limit, but sees output freeze rather than a cut as sufficient. Russia's production stands at record levels of 11.2 million b/d.


    While Moscow has made attempts to secure a production deal in the past, such as at the producers' meeting in Doha in April, Tehran's position has been a major stumbling block in reaching an agreement.

    Iran did not send a representative to the April meeting, causing the talks to flop, has been among the countries asking for exemption from restrictions, and insisted on its right to regain its pre-sanctions market share of some 4 million b/d first.

    Putin's conversation with Rouhani came the day OPEC delegates held a technical meeting in Vienna, which resulted in an output proposal to the producer group's 14 ministers for approval at Wednesday's meeting but still left individual country quotas unsettled.

    Iranian oil minister Bijan Zanganeh on Monday reiterated his stance that OPEC members that increased their production and took Iran's market share while it was under western sanctions should bear a greater responsibility for cutting output to rebalance the market.

    The deal, preliminarily agreed in Algiers in September, set a ceiling for the group of between 32.5 million and 33 million b/d, which would require a cut of between 640,000 to 1.14 million b/d from its October levels, according to OPEC's own estimate.

    Moscow is also to host last-minute talks with two OPEC members on Tuesday, when Russia's energy minister Alexander Novak is expected to meet Algerian energy minister Noureddine Bouterfa and Venezuelan oil minister Eulogio del Pino, both of whom flew to Moscow on Monday, according to Algeria's energy ministry.

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    Winter Saudi-Europe Diesel Flows Seen Higher Despite Refinery Turnarounds

    Diesel shipments to Europe from Saudi Arabia show little signs of easing over winter, even as turnarounds at some refineries temporarily halt exports and some cargoes need blending to meet specifications in Germany.

    The 400,000-b/d Yasref refinery at the Red Sea port of Yanbu, one of about three Middle East facilities supplying Europe with diesel, is undergoing a turnaround, according to London-based consultants, Energy Aspects.

    The joint venture Aramco and Sinopec facility has shipped between one and three ultra-low-sulfur diesel cargoes varying in size from 40,000 tons to 90,000 tons each month to countries in northwest Europe and the Mediterranean over the last year, according to the OPIS Tanker Tracker.

    “Cold point has been an issue for ex-Yasref cargoes though they are supposed to address this during the current turnaround,” Robert Campbell, head of Energy Aspects oil product research said in an emailed response to questions.

    He said some Middle East diesel cargoes also did not meet German winter
    specifications, which complicated trading. But with blending, most cargoes were okay, he added.

    The last Yasref ULSD cargo was tracked leaving Yanbu port on on Nov. 2,
    discharging at Algeciras for Cepsa.

    But diesel shipments loading at another Saudi Arabian refinery at Jubail this
    month are already tracked higher than monthly volumes seen last winter.

    Four cargoes, all from the Sasref refinery, are currently on the water, with a
    total of 420,000 tons heading for Europe to arrive in December, data compiled from brokers, traders and vessel-tracking satellite data show.

    That’s just below the monthly average of 520,000 tons seen for ULSD imports to the 28 member countries of the EU from Saudi Arabia over the first eight months of this year, according to Eurostat trade data. Trade data show Saudi-Europe ULSD imports at 330,000 tons in November and 390,000 tons in December, falling to 230,000 tons by January.

    Middle East refinery turnarounds in November are estimated at 521,000 b/d, with 512,000 b/d offline in December. The region’s overall fourth-quarter global crude runs are forecast at 7.2 million b/d, out of a global total of 79.6
    million, according to Energy Aspects.
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    Norway's Kollsness and Nyhamna gas assets hit by unplanned outages

    Gas output capacity on the Norwegian Continental shelf was hit Tuesday afternoon with two unplanned outages -- at the Nyhamna and Kollsness gas hubs -- with a combined within-day impact of 17 million cu m/d for Tuesday's gas day while no day-ahead impact was indicated, Norwegian TSO Gassco said.

    The Kollsness outage, with a within-day volume impact of 11.5 million cu m, started at 1005 GMT and was expected to last 12-13 hours.

    The second unplanned event, scheduled to start Tuesday at 1547 GMT, will hit the Nyhamna gas processing field with a within-day impact of 5.5 million cu m and an expected duration of 1-2 days.

    Gassco reported process problems as the reason for both outages.

    Meanwhile, the Heimdal gas hub unplanned maintenance was ongoing with a 13.5 million cu m volume impact for the Tuesday gas day while day-ahead volumes will also be reduced by 13.5 million cu m/d, according to Gassco.

    The cut is set to last 2-5 days.
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    Singapore HSFO/Dubai crack swap hits 4.5-year high on crude weakness, tighter supply

    The Singapore high sulfur fuel oil front-month paper crack spread versus the front-month Dubai crude oil swap hit a four-and-a-half-year high Monday, due to recent weakness in international crude prices and tightening HSFO supply, S&P Global Platts data showed.

    The front-month December FOB Singapore 180 CST high sulfur fuel oil/Dubai crack swap -- which measures the relative value of the product to crude oil -- rose 82 cents/b day on day to minus 55.4 cents/b Monday.

    The crack was last assessed higher on June 29, 2012, at 4.5 cents/b, Platts data showed.

    The front-month FOB Singapore 380 CST HSFO/Dubai crack swap was assessed at minus $1.775/b Monday, up 81.9 cents/b day on day, also a four-and-a-half- year high -- last seen when the crack touched minus $1.648/b on June 29, 2012, Platts data showed.

    As at 0645 GMT Tuesday, brokers were pegging the front-month FOB 180 CST HSFO crack swap versus Dubai at around minus 55 cents/b, citing firm buying levels in the outright Singapore fuel oil swaps market.

    The HSFO cracks have been strengthening since early October, on the back of volatility in crude prices amid ongoing skepticism regarding OPEC's much-hyped production freeze agreement.

    With OPEC's official November 30 summit in Vienna barely a day away, the December Dubai swap was assessed at $44.57/b Monday, down 5.17% from $47/b assessed on October 31.

    Crude prices might hold back till any further announcement regarding a production freeze agreement is made, market analysts said.

    "Oil prices may be choppy until Wednesday. The outcome of the November 30 summit is a binary risk," Mizuho Bank said in a report.

    The strength in fuel oil cracks may, however, be attributable to more than just weaker crude prices, market sources said.

    "Crude can swing whichever way but the fact remains that flat prices [for fuel oil] are holding firm," a Singapore-based broker said Tuesday morning.

    Singapore 180 CST HSFO swap was assessed at $279.5/mt Monday, Platts data showed, after dipping to a monthly low of $260.45/mt on November 14.

    "It could be a number of factors, including strong fuel oil fundamentals and hedging volume," said a trader.

    Poorer quality Russian fuel oil grades could be reducing the supply of high quality blendstock in the Singapore region, market sources had said the previous week.

    "For Far East refiners like us, we are seeing less pure straight runs. The pure M-100 that we see, to blend, is getting heavier in density, and [has] higher viscosity. These factors reduce the supply pool, eventually leading the blending margin to drop," a refinery trader said.

    In Singapore, buying interest for December has been strong as most cargoes arriving from the West have been carrying blendstock components rather than ready-grade bunker fuel material, trade sources said.
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    Japan's Idemitsu JV plans to expand LPG use at naphtha cracker

    Japan's Idemitsu Kosan said on Tuesday its joint venture with Mitsui Chemicals would conduct work to expand the processing of propane at Idemitsu's naphtha cracker to take advantage of cheap liquefied petroleum gas (LPG) prices.

    The work will be carried out next autumn and last about a month, during which time the cracker will be shut, a company spokeswoman said.

    The upgrade will boost the cracker's capacity to process propane as feedstock by three or four times, said Hideki Gotoh, deputy general manager of Idemitsu's petrochemical business. He declined to give the current capacity.

    He added that Idemitsu would pay the costs for the upgrade, without giving a figure.

    The benefit from boosting propane and cutting naphtha as feedstock is set to lead to cost cuts of around 1 billion yen ($8.90 million) a year, the company spokeswoman said.

    The cracker will take advantage of its location next to the LPG import facility in Idemitsu's Chiba refinery. It will mainly rely on LPG imports for feedstock rather than a small quantity of LPG produced at the plant, officials said.

    The cracker is separately scheduled to undergo planned maintenance next spring, company sources said.

    Idemitsu and Mitsui Chemicals set up the 50:50 venture in 2010 to jointly operate their naphtha crackers in Chiba, east of Tokyo, to save on costs.

    Idemitsu has a naphtha cracker adjacent to its Chiba refinery with capacity to produce 414,000 tonnes per year of ethylene, while Mitsui has one with a capacity of 612,000 tonnes per year.

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    Report: Maersk, Dong discuss oil merger

    Denmark’s A.P. Moller-Maersk and Dong Energy are reportedly in talks to merge their oil and gas operations.

    Reuters reported on Monday, citing sources familiar with the matter, that the deal would create a business worth over $10 billion, including debt. The news agency also informed Maersk is working with Bank of America while J.P. Morgan is assisting Dong.

    Maersk said in September it was working to split the company into two separate entities – one focused on shipping and logistics and the other on oil and gas sector – with an aim to find solutions for future for the oil and oil related businesses within two years.

    Dong Energy recently said it was rethinking its oil and gas business, looking to focus on renewable energy. The company also stated it was no longer considering oil and gas as a long-term strategic commitment. Dong hired a banking and financial services company J.P. Morgan to conduct a preliminary market assessment for its oil and gas business.

    Reuters quoted a spokesman for Dong as saying: “We are in the very early stages of the sales process. There will be no sale before the end of the year and it is far too early to speculate over timing and indeed potential buyers.”
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    China to further open up upstream oil and gas sector by 2020

    China will open up its upstream oil sector further between 2016 and 2020, the official Xinhua news agency reported, citing the vice minister of the Ministry of Land and Resources.

    The world's largest energy consumer will introduce private investment in upstream prospecting and push forward reforms of the oil gas prospecting system, Xinhua reported.

    In addition, China will also open up the upstream uranium prospecting sector and allow private capital in the markets.

    China aims to add 5-8 mega oilfields with at least 100 million tonnes of reserves and 5-10 natural gas reserves with at least 100 billion cubic meters of deposit by 2020.
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    Australia takes aim at oil and gas industry in tax review

    Australia is targeting the oil and gas industry for a tax review ahead of next year's budget, in a push to boost revenue after a sharp slump over the past three years and collect more from multinational giants.

    Treasurer Scott Morrison said on Wednesday that takings from the nation's petroleum resource rent tax had halved to A$800 million ($600 million) since 2013, while revenue from crude oil excise taxes had more than halved due to a collapse in oil and gas prices and falling output.

    "This is about ensuring sustainability and effectiveness and efficiency of our tax system. It is actually not primarily about revenue. It is important these companies pay their fair share when it comes to these issues," Morrison told reporters.

    The drive comes as Australia is not expected to reap as much as hoped from a more than $200 billion investment spree over the past few years that will make it the world's biggest exporter of liquefied natural gas (LNG) by around 2019.

    That is because the petroleum resource rent tax (PRRT) is designed to collect revenue after projects have recouped their investment and are profitable, which will take longer than expected in a world of weak oil and gas prices.

    "LNG projects, unlike conventional oil and gas projects, involve billions of dollars of up-front investment. It will take 10 or more years to recover that investment before making a return," Shell Australia Chairman Andrew Smith said in an emailed statement.

    Canberra has already been tackling multinationals over clever accounting and the use of trading operations offshore to lower their tax exposure in Australia, and Morrison said the oil and gas focus is part of that effort.

    Australia last targeted the resources industry in 2010, when then Labor Prime Minister Kevin Rudd proposed a super profits tax at the height of the mining boom which was eventually heavily watered down after a bitter fight with miners and contributed to his downfall.

    The oil and gas tax review follows a recent audit, which found that Australia's biggest petroleum operation, the North West Shelf joint venture, whose owners include Chevron Corp and Royal Dutch Shell, may have underpaid royalties by taking ineligible deductions.

    Morrison said deduction calculations will be examined as part of the review.


    The oil and gas industry said it would cooperate with the review, in contrast with the mining industry in 2010, saying the petroleum resource rent tax was working as intended.

    ExxonMobil said it had paid over A$12 billion in PRRT since 1990.

    "We welcome the review. This will give us another opportunity to talk about our contribution," ExxonMobil Australia Chairman Richard Owen said at an event in Sydney.

    The Australian Petroleum Production and Exploration Association said the industry had paid more than A$5 billion in taxes in 2015, despite recording its first ever net loss.

    "The continued payment of taxes at a time when the industry is under severe pressure debunks critics' suggestions that the industry is not somehow paying its way," APPEA Chief Executive Malcolm Roberts said in a statement.

    Oil and gas company shares fell on Wednesday along with oil prices, as OPEC looked like it would fail to agree on a production cut. Woodside fell 2 percent, Santos dropped 3.5 percent, while Beach Energy slid 4.8 percent.
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    Queensland LNG production may need to be slashed: WoodMac

    All three of Queensland's liquefied natural gas plants could end up running at less than full capacity as they struggle to remain in the black at current low LNG prices, according to respected consultancy Wood Mackenzie.

    The firm is warning that as ventures extend their drilling to lower quality coal seam gas acreage, many wells wouldn't be economic unless LNG prices recover. Up to a quarter of the projects' total production risks becoming unprofitable, it said.

    While Santos has already said it would not run its new $US18.5 billion GLNG venture at full production given the cost of sourcing additional gas, Origin Energy's Australia Pacific LNG venture and Shell's Queensland Curtis venture could find themselves in the same position should LNG prices remain depressed, said Wood Mackenzie analyst Saul Kavonic.

    "We think that with time it's going to impact all three projects," Mr Kavonic said. "They're just not delivering the way they were expected when they took sanction."

    The three Queensland projects differ from the conventional LNG projects on the north-west coast as they require ongoing drilling of coal seam gas wells to maintain production. But with Asian LNG spot prices in a slump that is expected to last several years, making that extra investment may not be worthwhile, especially as drilling extends beyond the "sweet spots" that hold the richest resources.

    "What's new about this is, we've never had in Australia or really globally the case of an economic decision to run LNG projects below capacity: it's always been once they are up and built and most of the capex is sunk, you try and squeeze out every drop that you can," Mr Kavonic said.

    "That is what will happen on the west coast with Gorgon, Wheatstone and Pluto and so on, but for these ones [in Queensland], because of the ongoing cost of drilling, it's a different story."

    Spokesmen for Shell and APLNG couldn't immediately respond.

    Other analysts have also pointed to the possibility the Queensland LNG projects will export less than envisaged. Credit Suisse's Mark Samter recently said that at lower oil prices that scenario was "possibly the most financially rational outcome for all parties".

    In its analysis, Wood Mackenzie found up to 43 per cent of the up to 8000 new wells needed across the three ventures over the next 30 years would be unprofitable if LNG prices remain low. It suggested the ventures may renegotiate LNG sales contracts to reduce contracted deliveries over the next few years given the well-supplied market.

    The findings raise more questions about the stubborn insistence of the Queensland LNG players to build three separate projects on Gladstone's Curtis Island, at a cost of at least $70 billion.

    Wood Mackenzie calculates that at current LNG prices in Asia of under $US7 per million British thermal units, new wells needed to be able to supply gas at less than $US6. But it estimates that up to 43 per cent of yet-to-be-drilled wells would fail to do so.

    "That then raises the question why would you drill all of that acreage up," Mr Kavonic said.

    While the decision whether to drill or not would be based on future prices rather than current ones, Wood Mackenzie is forecasting LNG prices won't materially increase until a structural oversupply of LNG wanes after 2020.

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    Leaner and meaner: U.S. shale greater threat to OPEC after oil price war

    In a corner of the prolific Bakken shale play in North Dakota, oil companies can now pump crude at a price almost as low as that enjoyed by OPEC giants Iran and Iraq.

    Until a few years ago it was unprofitable to produce oil from shale in the United States. The steep slide in costs could encourage more U.S. shale output if OPEC members cut supplies, undermining the producer group's ability to boost prices. OPEC ministers meet Wednesday to weigh output cuts to end a two-year glut that has pressured global oil prices.

    In shale fields from Texas to North Dakota, production costs have roughly halved since 2014, when Saudi Arabia signaled an output free-for-all in an attempt to drive higher-cost shale producers out of the market.

    Rather than killing the U.S. shale industry, the ensuing two-year price war made shale a stronger rival, even in the current low-price environment.

    In Dunn County, North Dakota, there are around 2,000 square miles where the cost to produce Bakken shale is $15 a barrel and falling, according to Lynn Helms, head of the state's Department of Mineral Resources.

    "The success in Dunn County has been fantastic," said Ron Ness, president of the North Dakota Petroleum Council.

    Dunn County's cost is about the same as Iran's, and a little higher than Iraq's. Dunn County produces about 200,000 barrels of oil a day, about a fifth of daily production in the state.

    It is North Dakota's sweet spot because it boasts the lowest costs in the state, yet improved technology and drilling techniques have boosted efficiency for the whole state and the entire U.S. oil industry.

    The breakeven cost per barrel, on average, to produce Bakken shale at the wellhead has fallen to $29.44 in 2016 from $59.03 in 2014, according to consultancy Rystad Energy. It added that in terms of wellhead prices, Bakken is the most competitive of major U.S. shale plays.

    Wood Mackenzie said technology advances should further reduce breakeven points.

    Landlocked Bakken producers still need a substantially higher international price than their breakeven cost to make a profit, since they pay more to transport crude to market than producers in most other U.S. regions.

    International oil prices of $45 a barrel are enough for some Bakken producers to profit, Ness said, and $55 would encourage production growth.

    Benchmark Brent prices plummeted from nearly $116 a barrel in mid-2014 to just $27 earlier this year. Prices have since recovered to nearly $46. That is still too low for members of the Organization of the Petroleum Exporting Countries, whose state budgets depend on petrodollar revenues that plummeted during the price war.

    For OPEC ministers meeting in Vienna on Wednesday, a major concern is that an output cut would encourage a quick response from U.S. shale producers, who have slashed costs and have been steadily adding drilling rigs.

    "Right now, OPEC understands we're in a push-and-pull experiment with the United States," said Michael Tran, director of energy strategy at RBC Capital Markets in New York.

    "Two years ago, we thought prices hovering around $50 to $60 meant that non-OPEC production growth would end. But U.S. production came back stronger."

    In a recent earnings call, Hess Corp said it has improved its cost performance in the Bakken, with well costs falling and initial production rates rising, though it did not give more details.

    "Everybody is drilling wells faster and completing them better," said Mike Breard, an energy stock analyst at Hodges Capital Management in Dallas. "It's not just a Bakken phenomenon."

    Breard said he prefers shale stocks in the Permian basin in Texas, where he is expecting more big gains in production next year. He is eyeing firms such as Parsley Energy Inc, Ring Energy Inc and Matador Resources Co.

    Oil companies are already investing big money to benefit from shale's resurgence. Tesoro Corp recently snapped up Western Refining Inc in a $4 billion deal to bulk up its exposure in Texas.

    Separately, trading firm Castleton Commodities International LLC bought more than $1 billion in assets from Anadarko Petroleum Corp to increase its stake in East Texas.

    Occidental Petroleum Corp's top executive recently said that company has enjoyed steady improvement in well productivity and lower drilling and completion costs in the Permian Basin.

    "Simply put, we can deliver more production with fewer wells," Vicki Hollub, the company's president and chief executive, told analysts on a recent call.

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    US shale gas: The new industrial revolution

    The shale gas revolution has not yet completed its first decade as increasing yields and production now join a bipartisan consensus in Washington. Push US exports. US cost structure and LNG sendout mean the shale gas cost curve will stay connected to European gas markets. Against continental pipe gas or Australian LNG, the US shale gas revolution will drive the cost curve for global production.

    “Its not a supply story it’s a cost story”, said a speaker at the European Autumn Gas Conference (EAGC).

    Marcellus productivity, a four-fold increase in 6 years: Natural gas fracking rigs in the Marcellus have seen a huge jump in productivity. Rigs averaged 8-10 wells and 4-5000 feet in 2010. Now in 2016 laterals average 8000 feet and rigs average 20-25 lateral drills. Giving rig productivity a four-fold increase in 6 years.

    At the European Autumn Gas Conference, Jeff Nanna, VP – Upstream Investment Banking at Tudor, Pickering, Holt & Co. cited as example: The world’s longest lateral drill of 5880 feet took 50 days in 2013. This record was eclipsed in 2106 in the Ohio Utica with an 18,554-foot lateral taking only 18 days to drill. Sand used to prop open fractured pay zones has risen from 3 million lbs. per well to 9 million lbs. per well, greatly enhancing yield.

    Another speaker at the EAGC cited some equally amazing Marcellus productivity data. In 2010 a 1000 feet of lateral drilling cost $1800 a foot and produced 1.7 bcf of gas. In 2016 a similar 1000-foot lateral cost $1000 a foot and produced 2.2 bcf of gas, a 40 % drop in costs. Such growth in productivity allows a producer to make the same returns at $2 he once made at $3.50.

    The Golden Age of gas is only at the dawn: In Washington bipartisan support is building not only to expand the current soft ceiling of 120 bcma (12 bcf/d), but to expedite the review process and move towards a new ceiling of 20 bcf/d.

    Tapping into this fortuitous confluence: Falling feed gas costs, global low cost per ton liquefaction plants and a political push to expand current gas exports. The Golden Age of gas is only at the dawn.

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    Canada approves new pipelines to boost exports, greens ready to fight

    Canada on Tuesday approved Kinder Morgan Inc's hotly contested plan to twin a pipeline from the Alberta oil sands to the Pacific coast, setting up a battle with environmentalists who helped elect Prime Minister Justin Trudeau.

    The government, under pressure from both green groups and the energy industry, said allowing Kinder Morgan to build a second pipeline next to its existing Trans Mountain line will help ensure oil exports reach Asia and reduce reliance on the U.S. market.

    "Our duty is to permit infrastructure so Canada's resources get to market in a more environmentally responsible way, creating jobs and a thriving economy," Trudeau told a news conference, adding he was "under no illusions" that the Kinder Morgan decision would be bitterly disputed.

    The government blocked Enbridge Inc's Northern Gateway pipeline from Alberta to the Pacific Coast, as expected. Trudeau had long opposed the project, which would run through the Great Bear Rainforest.

    Enbridge, however, will be allowed to replace the Canadian segments of its ageing Line 3 from Alberta to Wisconsin. The proposed upgrade had been less controversial than Northern Gateway project. Enbridge said it expected the pipeline to enter service in 2019, pending U.S. regulatory approval.

    Canada's energy sector, hit hard by a two-year slump in oil prices, wants more pipelines to help ease bottlenecks in moving crude out of Alberta. Canada, home to the world's third-largest crude reserves, wants to diversify away from its reliance on the United States and into Asian markets.

    Kinder Morgan's C$6.8 billion ($5.06 billion) project would nearly triple capacity on the artery to 890,000 barrels a day.

    ""We are getting a chance to break our landlock. We're getting a chance to sell to China and other new markets at better prices," Alberta Premier Rachel Notley said in a statement.

    Environmental groups, who say the risk of a spill is too great, were quick to promise resistance to the Trans Mountain project.

    "You will see the movement continue to escalate in the streets as the number of protests and actions continue to grow, in the courts, and at the ballot box here in (British Columbia) and beyond," said Sven Biggs of climate group Stand.Earth.

    Trudeau, keen to show environmentalists he is not selling out to the energy industry, also said the government would ban tanker traffic along the northern coast of British Columbia.

    Earlier this month he said Ottawa would toughen its response to oil spills at sea, which some saw as a signal Trans Mountain would be approved.

    The Liberals have taken other measures recently to shore up their green credentials, including speeding up plans to virtually eliminate coal-fired electricity, promising to bring in a minimum price on carbon emissions by 2018 and vowing to revamp the national energy regulator.

    Canada's former Conservative government had approved Northern Gateway in 2014 but a federal court overturned the approval last June.
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    Baker Hughes teams with private equity to create new BJ Services

    Baker Hughes is selling a majority of its hydraulic fracturing and cementing business to private equity partners to create the new BJ Services company in the Houston area.

    The new company will operate as a standalone joint venture — it won’t be publicly traded —  and restore the BJ Services name as its own company. Baker Hughes bought BJ Services Co., of Houston, for $5.5 billion in 2009, to expand into the fracking business, and the deal has served as a financial drag for Baker Hughes ever since.

    The deal comes less than a month after it was announced that Baker Hughes is combining with a unit of General Electric in a $32 billion merger that would create an expanded Baker Hughes. GE, based in Boston, would own 62.5 percent of the combined company, which will continue to trade under Baker Hughes’ BHI stock ticker.

    The BJ Services pressure pumping deal brings Baker Hughes into partnerships with Houston-based CSL Capital Management private equity firm and Goldman Sach’s merchant banking fund, called West Street Energy Partners. Baker Hughes will keep a 46.7 percent ownership stake in BJ Services.

    Baker Hughes’ pressure pumping business will combine with CSL’s Allied Oil & Gas Services business, which was acquired earlier this year. New Allied Chief Executive Warren Zemlak, a veteran of Schlumberger, will lead the new BJ Services, which will be headquartered in Tomball.

    Baker Hughes Chairman and CEO Martin Craighead  said the deal creates a “pure-play pressure pumping competitor” that can better compete with industry leaders Schlumberger and Halliburton.

    CSL and Goldman Sachs will together contribute $325 million in cash to the new company. Baker Hughes will receive $150 million of the total, while the remaining $175 million will position BJ Services for growth.

    “We look forward to renewing the BJ Services legacy and utilizing our experience building highly reliable teams and efficient operations to create a North American pressure pumping leader,” Zemlak said in the announcement.

    Ever since the failed acquisition of Baker Hughes by Halliburton earlier this year, Craighead has said the plan was to sell a stake in the pressure pumping business as Baker Hughes focuses more on technology and product sales.

    The new BJ Services deal is an “expected outcome” for Baker Hughes to “wash its hands of a very unfortunate legacy,” said Bill Herbert, a senior energy analyst Piper Jaffray & Co., an investment research firm.Baker Hughes is essentially getting a $150 million return on the majority of a business is paid more than $5 billion to acquire.

    “Baker didn’t have an especially strong negotiating hand because it had destroyed so much value,” Herbert said.

    However, the new BJ Services is better positioned with Zemlak’s leadership and CSL’s strong track record in oilfield services, Herbert said, noting that the business still could have strong long-term value.
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    Alternative Energy

    China to invest $174 billion in hydro and wind from 2016-2020: NEA

    China will spend at least 1.2 trillion yuan ($174 billion) on hydro and wind energy infrastructure between 2016 and 2020, the National Energy Administration (NEA) said in blueprint document for the two industries.

    NEA said construction of new wind farms would provide about 300,000 new jobs by 2020. In addition, the country aims to have a market-based subsidy system for the wind industry.
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    S.Korea unveils new tariffs, incentives to boost renewable energy

    South Korea plans to provide new incentives for renewable producers and consumers as its seeks to double power from green sources to 11 percent of the country's electricity supply by 2025 from 4.5 percent last year.

    Seoul will implement a competitive market auction system for power producers as early as the first quarter of 2017, shifting away from the current feed-in-tariff system, the country's energy ministry said in a statement on Wednesday.

    The new system means utilities can buy electricity from renewable power producers via tenders and fixed-price deals for up to 20 years - helping green energy producers ensure stable profits.

    The move comes after Asia's fourth-largest economy said in July it would pump 42 trillion won ($35.85 billion) into meeting its pledge at the Paris Climate summit last year to cut greenhouse gas emissions by 37 percent by 2030.

    "The penetration rate of renewable energy sources is expected to grow up to 11 percent by 2025, and we can meet this goal 10 years earlier than we have aimed," Energy Minister Joo Hyung-hwan said at a meeting with power generators and companies.

    Joo said Korea's upcoming power supply plan, due to be released next year, will be more environmentally friendly in line with the country's new renewable plans.

    At present, utilities can purchase electricity from renewable producers at prices set by the government via feed-in tariffs (FIT). That has allowed producers to secure sales of renewable energy at fixed prices, but has not stoked lower prices through competition.

    "We are planning to set a long-term goal to generate 30 percent of our power with renewable energy sources by 2030," Lee Jong-sik, executive vice president of Korea Southern Power Co Ltd (KOSPO), told Reuters.

    In addition to the competitive auction system, the ministry will expand subsidies to cover up to 50 percent of the cost of installing solar power systems in homes and schools.

    With the new plans, the ministry expects green energy sources to supply 11 percent of the country's total electricity by 2025. The aim is to increase installed capacity of renewable energy power to 45.5 gigawatts (GW), from 13.7 GW in 2015.

    Korea currently generates nearly 40 percent of the country's electricity from coal, followed by nuclear power at 30 percent with the rest coming from oil, gas and renewable energy sources.

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    Base Metals

    Hedge funds have never been this bullish about copper price

    After hitting an 18-month high on an intraday basis on Monday, the copper price has come under pressure as the bullishness about the impact of Trump's $500 billion infrastructure plans on demand for the bellwether metal begins to cool.

    In Asian trade on Wednesday copper for delivery in March, the most active contract, exchanged hands for $2.5570 per pound ($5,637 a tonne) on the Comex market in New York. Copper is now down 7% from this week's peak.

    After vastly underperforming other metals and steelmaking raw materials in 2016, copper is still looking much healthier than pre-Trump with a 20% rise year-to-date.

    The change in sentiment is striking considering the radical shift in the positioning of large-scale derivatives speculators such as hedge funds.

    While continuing to reduce bullish silver, platinum and gold bets, on the copper market hedge funds have added to long positions – bets on higher prices in future – for three weeks in a row.

    According to the CFTC's weekly Commitment of Traders data up to November 22 (released yesterday due to the US long weekend) so-called managed money investors have taken the net long to an all-time high of 76,346 lots or the equivalent of just over 1.9 billion pounds.

    Saxo Bank points out that this is a whopping 55% above the previous record from July 2014:
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    Steel, Iron Ore and Coal

    Weekly US coal production estimate again hits 2016 high: EIA

    Weekly US coal production totaled an estimated 17.23 million st in the week ended November 19, the highest total so far this year, US Energy Information Administration data showed Monday.

    Coal production has largely increased since bottoming in early April, with estimates in the last four weeks counting among the highest reported year to date. Sources attribute the increase to stockpile building, as utilities look to accelerate deliveries to meet minimum commitments for the year.

    The weekly estimate -- which was issued Monday due to last week's Thanksgiving holiday -- was up 2.8% from the prior week, and up 6.5% from the year-ago week, the fourth straight week the estimate has lapped the year-ago comparison.

    The weekly estimate also showed coal production in Central Appalachia, Northern Appalachia and the Illinois Basin totaled year-to-date highs.

    For the year, US coal production totaled an estimated 657.48 million st, down 18.8% through the same period last year. On an annualized basis, US coal production in 2016 would total 727.2 million st, down 18.8% from last year.

    For the week, coal production in Wyoming and Montana, which is mostly made up of production from the Powder River Basin, totaled an estimated 7.7 million st, up 0.7% from the prior week but down 2.4% from the year-ago week.

    Year-to-date coal production in the region totaled an estimated 289.1 million st, down 22.9% from last year, and would total 320.5 million st on an annualized basis, down 23.2% from last year.

    In Central Appalachia, weekly coal production totaled an estimated 1.7 million st, up 7.9% from the prior week and up 4.8% from the year-ago week.

    Year-to-date production in the basin totaled an estimated 70 million st, down 26.7% from last year, and would total 77.4 million st on an annualized basis, down 25.2% from last year.

    Weekly coal production in Northern Appalachia totaled an estimated 2.4 million st, up 2.3% from the previous week and up 14.2% from last year.

    Year-to-date production totaled an estimated 91.6 million st, down 12.2% from last year, and would total 101 million st on annualized basis, down 13% from last year.

    In the Illinois Basin, weekly coal production totaled an estimated 2.3 million st, up 4.8% from the prior week and up 11.5% from the year-ago week.

    Year-to-date production totaled an estimated 91.8 million st, down 18.6% from last year, and would total 101.4 million st on an annualized basis, down 18.2% from last year.

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    Vale to sell 13 million mt Moatize coal in 2017, boost index sales

    Brazil's Vale said Tuesday it expects to sell 13 million mt and produce 17 million mt of coal at Moatize, Mozambique, over 2017, up from 6 million mt produced in 2016.

    No coal sales are earmarked for China, with 11 million mt sold via Nacala and the reminder using the Beira rail and port corridor, according to a company presentation delivered in New York.

    Coal sales will be split 65% as met coal, 35% as thermal.

    The company has 2017 coal sales evenly split into three regions, with 34% to northeast Asia of Japan, South Korea and Taiwan, a third to the Atlantic excluding South America, and the remaining third going to surrounding mainly Southern Hemisphere countries such as India, those in Africa and Brazil.

    Pricing for met coal in 2017 is expected to be dominated by index-linked at 66%, with a reduction in exposure to the benchmark for pricing after 70% was priced off the benchmark in the first nine months of 2016.

    "Index-based sales [will] increase to manage pricing volatility," Vale said, explaining the move in pricing.
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    Mechel reports third-quarter loss, misses out on coal price surge

    Metals and mining group Mechel on Tuesday reported a third-quarter net loss of 2.8 billion roubles ($43 million) as a surge in the price of its main product coking coal came too late to bolster its earnings.

    Prices for coking coal - a key component in steel production, - have more than doubled since July on expectations of lower supply, sending Mechel's shares to three-year highs.

    But Mechel, Russia's second-biggest coal producer after market leader Evraz, said even though spot coking coal prices were currently at more than $300 per a tonne this had not supported its financial earnings in the third quarter.

    "The rapid growth of coal prices, which began in mid-summer, didn't have time to make a full impact on the third quarter's financial results," Mechel Mining Management Chief Executive Officer Pavel Shtark said.

    "We saw this hike's reflection in our contracts only by the very end of this reporting period," he said. "The current favourable market situation will definitely be reflected in the results of the fourth quarter and future periods."

    Mechel, which was hit by a collapse in global steel prices, has been in lengthy talks with creditors to restructure its debts and is yet to sign final debt restructuring deals with all the creditors.

    Mechel said its coking coal sales fell 10 percent in the third quarter to 2 million tonnes, but it had increased sales to China, Japan and India in the period.

    Steel and coal production both fell 5 percent quarter-on-quarter to 1 million and 5.6 million tonnes respectively, the company said.

    Mechel's third-quarter core earnings totalled 15.9 billion roubles, up slightly from 15.7 billion roubles in the previous quarter. Revenue slipped from 68 billion roubles to 66.2 billion. The company made a net profit of 8 billion roubles in the second quarter of this year.
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    Gansu halts outbound coal supplies to ensure adequate supply

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    Inner Mongolia Ordos starts safety inspection on coal mines

    The local government of coal-rich Ordos in the northern autonomous region of Inner Mongolia announced a city-wide safety inspection on all of its coal mines, after a roof caving accident killed three miners at Wantugou mine on November 25.

    The coal mine is owned by Inner Mongolia Boyuan Coal Chemical Industry Co., Ltd. and has an annual production capacity of 3 million tonnes.

    It still needs time to see whether and to what extent the safety inspection would impact local coal supply.

    Raw coal output in Ordos accounts for over 60% of the total output in the autonomous region, which stood at 609.67 million tonnes in the first three quarters this year, down 10.7% from a year ago, according to the National Bureau of Statistics.

    The city government aims to keep coal output steady at around 600 million tonnes and complete sales of 550 million tonnes in 2016.

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    Yancoal in talks over Rio's $1 bln coal mine portfolio

    China's Yancoal is believed to have entered exclusive negotiations to buy Rio Tinto's $1 billion-plus coal portfolio, The Australian reported on November 29, citing market sources.

    The situation sees global trader Glencore take a back seat in the contest, which involved a handful of parties but more recently has been perceived as a two-horse race between Yancoal. It is unclear whether the talks are officially exclusive.

    On offer are the company's NSW thermal coal mines, which constitute its Coal & Allied business, although sources have said that other coking coal mines could be incorporated in the sale.

    The listed suitor has recently booked losses, but Yancoal has plenty of acquisition fire-power, as it is 78%-owned by Yanzhou Coal, which is backed by the Chinese Government, and 13%t by the Noble Group.

    The investment bank Deutsche is selling the assets on behalf of Rio, which has declined to comment on the status of the negotiations.

    Sources now believe that Anglo American may opt to hold its $1 billion-odd Moranbah and Grosvenor, after the period of exclusivity with Apollo private equity lapsed without a deal, following a sales process run by Bank of America Merrill Lynch.

    However, suitors are expecting flyer documents for Anglo American's Capcoal complex — said to be worth several hundred million dollars — by Christmas.

    It will be interesting to see what the bankrupt Peabody Energy ultimately does with its Millennium coking coal mine in Queensland that is understood to be planning to sell.

    South32, advised by JPMorgan, purchased the other mine up for sale in recent weeks — the Metropolitan coal mine in NSW.

    Rio is considering a sale at a time that thermal coal remains a less favorable form of power supply due to environmental concerns, as it tries to keep its debt levels in check.

    Already, Yancoal manages the Cameby Downs and Premier coal mines in Queensland and Western Australia respectively on behalf of Yanzhou Coal, and the Ashton, Austar and Donaldson mines in NSW on behalf of Watagan Mining Company.
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    Rio seeks iron-ore premium from China mills in likely pricing war revival - sources

    Australian miner Rio Tinto is asking Chinese steel mills to pay a premium for its highest grade iron ore product for the first time since an annual pricing system collapsed in 2010, two sources familiar with the situation said.

    The demand by the world's No. 2 iron-ore miner comes as Chinese steel producers recover from years of losses, buoying demand for the steelmaking raw material, but could revive tensions between miners and mills over pricing that they seemed to have ditched six years ago.

    Rio is seeking up to $1 per tonne more than the index price for its Pilbara iron-ore product, or PB fines, from Chinese mills on long-term contracts for 2017, the sources said, in a break from a years-long trend of pricing at spot values. Previously, Rio was selling the ore at a premium only to traders.

    The miner has also pushed up the premium it seeks from traders to between $2 and $2.50 per tonne over the index price for the same product for January to April, they said.

    That would be a record high and up from a premium of $1.50 for the four-month period through December this year, said one of the sources who works closely with Rio in China.

    From Chinese mills, Rio initially sought a 15-cent premium, but this week increased it to about $1, said the same source.

    "The steel market is so hot this year and they think it's something that buyers can accept," the source said. "If Rio gets it, other miners may follow."

    Rio Tinto declined to comment.

    A reduction in China's steel capacity along with a push to spend more on infrastructure has fuelled an 81 percent spike in Chinese steel prices this year, sparking a similar rally in iron ore prices.


    After four decades of fixing iron-ore contract prices annually, the miners and mills in 2010 began setting them more frequently and in shorter periods against spot index prices such as those published by Platts and Metal Bulletin.

    "This is illogical," said the second source on Rio's planned premium for mills. "The index already reflects the spot market, why add a premium?"

    The spot index breached $80 a tonne on Monday for the first time since October 2014, gaining 86 percent this year after a three-year slide.

    The China Iron and Steel Association (CISA), which groups the biggest steel producers in the world's top market, called the planned price markup "unfair" in a report by Xinhua News on November 18 which did not identify the leading iron ore producer.

    Li Xinchuang, vice-secretary general of CISA, said "currently it's not easy to demand" a premium for iron orefrom Chinese mills.

    "The steel market is still very weak, not only in China but globally," Li told Reuters by phone.

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    Baogang to provide technical support for India's steel giant

    Baogang Group has reached a cooperation agreement with Jindal Steel and Power Ltd (JSPL) on providing technical services for JSPL, reports Baotou Daily.

    The agreement is designed to support the Belt and Road Initiative and is expected to increase production and improve product quality.

    Baogang Group, or Baotou Iron and Steel Group, is an iron and steel State-owned company based in Baotou, Inner Mongolia autonomous region. It is the largest steel business based in the autonomous region, and one of the oldest iron and steel industrial bases in China, with a large production base of iron and steel, and the largest scientific research and production base of rare earth metals in China.

    Baogang Group has been well-received in the Indian market for their high quality products and flexible service.

    JSPL is a steel and energy company, based in New Delhi, India. Backed by the $18 billion diversified Jindal Group conglomerate, JSPL is the third largest steel producer in India. The company produces steel and power through backward integration from its own captive coal and iron-ore mines.
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    High ferrochrome prices could speed sector consolidation

    Rocketing ferrochrome prices are expected to accelerate consolidation among producers in South Africa, increasing the global stainless steel industry's reliance on mining group Glencore and chrome ore company Samancor.

    Nearly 60 percent of the world's production of global chrome ore -- used to make stainless steel raw material ferrochrome -- comes from South Africa, where Glencore and Samancor are casting an acquisitive eye over smaller rival Hernic Ferrochrome.

    Four Sources in the stainless steel and ferrochrome industries told Reuters that Glencore is looking to reinforce its dominant position with the purchase of Hernic, which is majority owned by Japan's Mitsubishi Corp.

    Swiss-based Glencore expects to produce 1.57 million tonnes of ferrochrome this year but has capacity for nearly two million tonnes. Hernic would give it a further 420,000 tonnes.

    "Hernic would be a good fit for Glencore ... and (Glencore) won't want to see new players in South Africa's chrome industry," said Mark Beveridge, of commodities consultancy CRU.

    "Glencore has invested a lot of money in South Africa and is a driving force behind consolidation. It's not good news for stainless steel producers."

    Glencore declined to comment.

    The industry sources said that Mitsubishu is considering a sale, given that current ferrochrome prices are likely to push up Hernic's value. The sources gave no valuation estimates for the company, which describes itself as the world's fourth-largest integrated ferrochrome producer.

    Macquarie analysts estimate global ferrochrome output at 10.7 million tonnes this year against demand above 11 million tonnes, which has helped to lift prices by more than 70 percent since September to about $1.10 per lb.

    A Mitsubishi Corp spokesman in Tokyo, when asked whether the Japanese trading house is looking to sell its 50.1 percent stake, would only say that "Mitsubishi Corp is considering all possible ways to support sustainable operations of Hernic Ferrochrome".


    Two of the sources said that South Africa's Samancor is also interested but that Glencore is in a stronger position to fund acquisitions than at the start of 2016, with group revenues rising on the back of the recent rally in commodities prices.

    A Samancor representative was not immediately available for comment.

    Samancor is Glencore's biggest rival in ferrochrome, with CRU's Beveridge putting its capacity at 1.4 million tonnes a year, rising to 2 million tonnes including joint ventures.

    "Glencore isn't going to let someone else move on Hernic," one chrome industry source said, though he added that the company may want to wait to see where prices settle and that China's role in the market will be important.

    Ferrochrome importer China also has the ability to produce its own supplies, having built large amounts of capacity over the past 10 year, with the potential to stabilise prices.

    China's chrome ore stocks are running low, but restocking may not be difficult, sources say, because smaller producers in South Africa, India and Turkey have restarted or likely to restart mothballed capacity.

    "If the Chinese can get the ore, they can make money by producing ferrochrome," CRU's Beveridge said.

    Recent data from the International Stainless Steel Forum showed Chinese output at 11.73 million tonnes between January and June, up 7.9 percent from the first six months of last year.

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