Mark Latham Commodity Equity Intelligence Service

Thursday 15th December 2016
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    Head Of US Pacific Fleet Ready To Confront Beijing As China Warns Of US Carmaker Penalty For

    In what some have seen as the first warning shot of retaliation against Trump's threats of protectionism and part of China's escalating trade war involving the auto industry, overnight China Daily reported quoting a senior state planning official that Beijing will soon slap a penalty on an "unnamed U.S. automaker for monopolistic behavior."

    Investigators found the U.S. company had instructed distributors to fix prices starting in 2014, Zhang Handong, director of the National Development and Reform Commission's price supervision bureau, was quoted as saying. However, in the exclusive interview with the newspaper, Zhang said no one should "read anything improper" into the timing or target of the penalty, which likely suggests that there was nothing coincidental about the timing or the target of the penatly which comes at a sensitive time for China-U.S. relations after U.S. president-elect Donald Trump called into question a long-standing U.S. policy of acknowledging that Taiwan is part of "one China".

    China, the world's largest auto market, has become crucial to the strategies of car companies around the world, including major U.S. players General Motors and Ford Motor.

    For now, the two US auto giants stated on the record they were unaware of the Chinese decision: "We are unaware of the issue," said Mark Truby, Ford's chief spokesman for its Asia-Pacific operations. In a statement, GM said: "GM fully respects local laws and regulations wherever we operate. We do not comment on media speculation."

    As Reuters adds, the penalty follows a government crackdown on what it has called monopolistic behavior by foreign automakers and dealers.

    This would be the second penalty by the NDRC this month and the seventh fine issued to automakers since the commission began anti-monopoly investigations in 2011, China Daily reported. Previous targeted firms have included Germany's Audi, Daimler Mercedes-Benz and Japan's Toyota and one of Nissan's joint ventures.

    The United States is ready to confront China should it continue its overreaching maritime claims in the South China Sea, the head of the US Pacific fleet said on Wednesday, comments that threaten to escalate tensions between the two global rivals.

    China claims most of the resource-rich South China Sea through which about $5 trillion in ship-borne trade passes every year. Neighbours Brunei, Malaysia, the Philippines, Taiwan and Vietnam also have claims.

    The United States has called on China to respect the findings of arbitration court in The Hague earlier this year which invalidated its vast territorial claims in the strategic waterway.

    But Beijing continues to act in an "aggressive" manner, to which the United States stands ready to respond, Admiral Harry Harris, head of the US Pacific Command, said in a speech in Sydney.

    "We will not allow a shared domain to be closed down unilaterally no matter how many bases are built on artificial features in the South China Sea," he said. "We will cooperate when we can but we will be ready to confront when we must."

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    China Jan-Nov power consumption climbs 4.96pct on year, NDRC

    China's power consumption climbed 4.96% from the year prior in the first eleven months, said Zhao Chenxin, spokesman of the National Development and Reform Commission (NDRC), in a press conference held on December 14.

    The growth expanded from a year-on-year growth of 0.72% during the same period last year, thanks to the rapid increase of power consumption by tertiary industries and residential segment, which indicates further optimization of the country's power consumption structure.

    Zhao didn't give figures of actual power consumption, which is expected to be announced late in this week.

    The electricity use by residential segment gained 11.43% over January-November from a 4.73% increase in the corresponding period last year.

    For the non-residential segment, the primary industries – mainly the agricultural sector – reported a 5.16% growth of power consumption in the first eleven months, compared with a growth of 2.97% a year ago.

    The secondary industries – mainly the industrial sector saw power use climb 2.62% on year, up from a year-on-year drop of 1.12% in the same period last year.

    Power consumption by tertiary industries – mainly the service sector – increased 11.66% on year, compared with a 7.33% rise from the previous year.

    Over January-November, China's output of hydropower, nuclear and wind power increased 6.94%, 23.87% and 30.30% from a year ago, respectively, according to preliminary statistics.

    China's power consumption may grow at a slower pace in the fourth quarter than in the third, due to weaker temperature effect, said China Electricity Council (CEC).

    The power use of the whole year is expected to register a higher-than-expected growth of 4.5% or so, the CEC said.

    The CEC predicted the country's installed power capacity to hover at 1.64 TW in 2016, of which 36.5% will be from fossil fuels. For newly-installed capacity, the council said it may reach 120 GW, with newly-installed capacity of non-fossil fuels at 70 GW.
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    Global task force sets recommendations on climate risk disclosure

    Global financial regulators on Wednesday issued a series of recommendations for corporate disclosure of climate-related risk as part of a consultation on standards for financial reporting.

    The Task Force on Climate Related Financial Disclosure recommended that companies consider the impact of climate change as part of their governance, risk management and strategy.

    The TCFD's draft paper sets out metrics and scenarios that firms should consider disclosing.

    The paper, which launches a 60-day consultation, seeks input from publicly listed companies, investors, lenders and insurance underwriters about the financial risks companies face from climate change.

    The standards are intended to be voluntary in the first instance, allowing companies to work within a standardized set of reporting guidelines, helping investors assess and compare corporate exposure to climate risk.

    The TCFD's work aims to allow investors to make better informed decisions on capital allocation by avoiding projects, companies and sectors most exposed to climate risk and related regulation.

    The task force was set up in December 2015 by global financial watchdog the Financial Stability Board, at the request of the G20 group of most industrialized countries.

    Its purpose is to provide investors with the information they need to assess corporate exposure to climate change, within a wider FSB remit to mitigate threats to the global financial system.

    The FSB's focus is to coordinate at the international level the work of national financial authorities and international standard setting bodies and to develop and promote the implementation of effective regulatory, supervisory and other financial sector policies in the interest of global financial stability.

    "The disclosure recommendations will give financial markets the information they need to manage risks, and seize opportunities, stemming from climate change," FSB chairman and Bank of England Governor Mark Carney said in a statement Wednesday.

    "As a private sector solution to a market issue, the Task Force has focused on the practical, material disclosures investors want and which all capital-raising companies can compile," Carney said.


    In a speech in London in 2015, Carney set out the key types of risk that companies face from climate change:

    - Direct physical risks: damage through floods and other climate related events on property and business activity

    - Liability risks: legal actions in future by parties affected against those they hold responsible

    - Transition risks: financial risks that could result from the process of adjustment to a low carbon economy

    UK-based financial analysis group Carbon Tracker Initiative said the climate risk disclosure standards would address an information gap in the market.

    "Even before last year's watershed Paris Agreement, climate risk was high on the agenda of the world's largest institutional investors and asset managers," it said in a statement Monday ahead of the task force's report.

    "Record-high shareholder support (against board recommendations) for resolutions asking oil and gas companies to stress test their business models against a two-degree consistent climate outcome demonstrates that this is squarely a financial concern," said Carbon Tracker.

    "The recommendations mark a significant step forward towards meeting that market demand while also highlighting some of the most pertinent elements of existing voluntary disclosure frameworks," it said.

    "The focus on making a market for these risks -- underpinned by the international reach of the FSB -- should signal to capital markets regulators around the globe the prospect of consistent, comparable disclosure standards on climate risk both within sectors and across stock exchanges," it said.
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    Brazil's Braskem to pay 3.1 bln reais in leniency deal for corruption case

    Brazil's Braskem SA , the largest petrochemical producer in Latin America, signed a leniency deal on Wednesday with Brazilian prosecutors leading a sweeping corruption probe into political kickbacks at state-run oil company Petrobras, the company said in a securities filing.

    The company agreed to pay 3.1 billion reais ($920 million) in fines to Brazilian authorities. Around half will be paid in cash immediately, while the rest will be paid in six years beginning in 2018. Braskem did not elaborate on previously disclosed negotiations with U.S. authorities.
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    Oil and Gas

    OPEC Says Supply Cuts Won’t Re-Balance Market Until Second Half

    OPEC said its agreement to cut production, while speeding up the re-balancing of the global oil market, won’t result in demand exceeding supply until the second half of next year.

    The Dec. 10 agreement between the Organization of Petroleum Exporting Countries and non-members such as Russia and Kazakhstan “will accelerate the reduction of global inventories and bring forward the re-balancing of the oil market to the second half of 2017,” OPEC said in its monthly report Wednesday. It’s a more pessimistic outlook than that published Tuesday by the International Energy Agency, which indicated a supply deficit in the first half.

    Oil prices have climbed about 16 percent since OPEC announced its first production cuts in eight years on Nov. 30 as it seeks to end a three-year glut that the group admits lasted longer than it expected. The accord was widened on Dec. 10 when 11 non-members signed up as well.

    Despite a commitment from those countries to lower their output in the first half by 600,000 barrels a day, the organization slightly increased forecasts for supplies from outside OPEC in 2017. It estimates that production in Russia, which pledged half of the non-OPEC cut, and in Kazakhstan, which also agreed to cut, will remain steady for the six months covered by the deal. The report doesn’t state whether the estimates take into account the most recent agreement.

    The non-OPEC growth forecast was increased by about 100,000 barrels a day, to 300,000 a day, “due to higher price expectations for 2017,” according to the report, produced by the bloc’s Vienna-based secretariat. The organization kept forecasts for U.S. supply in 2017 unchanged.

    The group said its own output climbed 150,800 barrels a day to 33.87 million a day in November, as Nigeria and Libya -- which are both exempt from any obligation to cut -- restored some of their disrupted supplies. This implies that, in order to meet the group’s target of 32.5 million barrels a day, the other nations would need to make deeper cuts than originally agreed.

    Another complication for the deal may come from the group’s revision of October output levels, which were used as the reference points for the accord. Production in Saudi Arabia, the biggest and most influential member, was assessed by the organization at 10.56 million barrels a day in October, higher than its reference level of 10.54 million.

    The organization has created a monitoring committee, composed of three members and two non-members, to ensure compliance with the agreement.

    Production data submitted directly by members, which is also included in the report, continued to show a discrepancy with the group’s own estimates. While data from Iraq, Iran and Venezuela have regularly differed, this month’s report showed a wider disparity for Saudi Arabia. The kingdom told OPEC it produced 10.72 million barrels a day in November, about 200,000 a day more than OPEC’s own assessment.
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    No Russian oil export cuts?


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    Protesters agree to end blockade of western Libya oil pipelines: officials

    Protesters blockading pipelines to Libya's Sharara and El Feel oil fields have promised to reopen them and production could restart in the coming days, security officials and an oil industry source said on Wednesday.

    Reopening the fields could add 365,000 barrels per day (bpd) to Libya's production, which has been drastically reduced by conflict and political disputes.

    National output has doubled since September to about 600,000 bpd after blockades at major ports were lifted, but it remains far below the 1.6 million bpd the OPEC member was producing before its 2011 uprising.

    A faction of Libya's Petroleum Facilities Guard (PFG) that has blockaded one pipeline since November 2014 and another since April 2015 said in a statement that they had agreed to reopen both.

    "The National Oil Corporation should start its work as soon as possible and we, as the Petroleum Facilities Guard, pledge to protect and defend the wealth of the Libyan state," the statement said.

    The PFG faction is aligned with the self-styled Libyan National Army (LNA), a force based in eastern Libya. Its statement was confirmed by the office of Idris Madi, head of the LNA's command center in its western outpost of Zintan. Madi's office said the blockade would end by Thursday.

    A National Oil Corporation (NOC) source confirmed the deal, but said the resumption of production was not guaranteed, as similar previous pledges had fallen through.

    He said that NOC subsidiaries at the Zawiya refinery and Mellitah complex, which are fed from Sharara and El Feel, had been readying for a restart.

    "Both companies are preparing their facilities to resume production. Also in the fields there have been preparations," he said, adding that any restart would be gradual.

    The NOC has said that it hopes to raise production to 900,000 bpd in the near future and to 1.1 million bpd next year, though it says those increases are dependent on blockades ending and the NOC receiving new funds for its operating budget.

    Libya's continuing political turmoil remains a threat to any production recovery, with rival governments in the east and west of the country and armed factions competing for power and oil wealth.
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    Merger talks stall between Maersk, Dong, report says

    Talks aimed at merging the oil businesses of Maersk and Dong Energy have stalled, a news report said, citing industry and banking sources.

    Dong confirmed last month that negotiations were under way, but sources have since told Reuters that the two Danish firms have failed to agree a valuation of their assets.

    A merger between the two firms’ oil and gas businesses was viewed by many industry observers as a good fit.

    In recent months, Maersk said it was splitting the group into separate energy and transport, while Dong has revealed plans to ditch its oil and gas business to focus on renewables.

    The two firms hold a large number of North Sea licences. Maersk is currently drilling the Culzean field, one of the biggest finds in the UK sector.

    Maersk and Dong both declined to comment on the report.
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    Gazprom, OMV reach outline deal on swap of Norway, Siberia assets

    Russian energy company Gazprom and Austrian oil and gas group OMV reached an outline deal on Wednesday to swap a 38.5 percent stake in OMV's Norwegian unit for a 25 percent stake in a section of Gazprom's Urengoy gas field.

    OMV Chief Executive Rainer Seele, who took the top job at Austria's biggest company last year, is reversing the policy of his predecessor who achieved output growth by buying assets in the North Sea, where production is expensive but reliable.

    Seele aims to generate cash by selling off non-core assets such as Turkey's Petrol Ofisi and to replenish the company's weakening reserves with access to oil and gas fields in low-cost countries such as Russia and the United Arab Emirates.

    Gazprom is set to benefit from diversifying its geographic footprint, as well as synergies in logistics and marketing and access to technology it could use in future for Russian offshore projects, Chief Executive Alexei Miller told reporters in Vienna.

    Both Miller and Seele sounded optimistic when asked about outstanding approval from Norwegian authorities for the deal, which will be an asset swap with no cash involved. Gazprom had previously said Norway might bloc it from acquiring a stake larger than 25 percent in OMV's Norwegian holding.

    "In Russia they always say problems should be solved when they occur and if they occur, presently we do not have this problem," Miller said.

    Without going into detail, Seele said dates for meetings with Norwegian authorities would be fixed soon, adding that he had received no indication that the swap might not go ahead.

    The effective date of the deal will be Jan. 1, 2017, pending regulatory approval, with the final deal expected to be sealed in the middle of next year, OMV said in a statement.

    OMV, which expects to invest around 0.9 billion euros ($955 million) in the field until 2039, anticipates its Urengoy output will start in 2019 with production reaching more than 80,000 barrels of oil equivalent per day (boe/d) in 2025.

    In the third quarter, OMV's output was 301,000 boe/d and Seele has said it might stagnate at that level until 2020 without the Russian deal, for which Seele once said there was "no plan B".

    OMV, which relies on mature fields in Austria and Romania for much of its output, would see its reserves swell by half with an expected contribution of 560 million boe until 2039 from the 24.98 percent stake in the Achimov IV and V sections of Urengoy.
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    Analysis: Iran emerges as high sulfur gasoil supplier for ARA refining hub

    Northwest Europe has opened its doors to the first shipments of Iranian gasoil after a 10-year hiatus, and these nascent flows are adding to the desulfurization opportunities within the Amsterdam-Rotterdam-Antwerp refining hub.

    The specifications of the recent fixtures put Iranian gasoil as a prime candidate for desulfurization and blending within the ARA hub, market sources said.

    So far this year, the HSGO shipments have been straight run 0.7-0.9% gasoil from Bandar Mahshahr, middle distillates traders and sources close to the parties involved said.

    In aggregate, high sulfur gasoil exports from Iran have amounted to approximately 100,000 mt each month, booked for the West of Suez, the Mediterranean, Northwest Europe and West Africa, a source with knowledge of the matter said.

    The latest fixture to Northwest Europe was on board the Glorious, a 60,000 mt cargo, which discharged into Amsterdam on November 26, having left Bandar Mahshahr, Iran, on November 12, S&P Global trade flow software CFlow showed. The Mahshahr Oil Terminal is used to store products from the Abadan Refinery to the west.

    This vessel was laden with 0.7% sulfur gasoil, sources said.

    The identity of the charterer remains unclear.

    Among the other Iranian ports, Bandar Abbas exports 6-7 cargoes of 5,000 ppm (0.5%) gasoil each month, National Iranian Oil Company said, while port Lavan Island supplies one cargo on average of maximum 500 ppm gasoil.

    No high sulfur gasoil volumes are presently being offered from these ports.

    Before desulfurization facilities were launched this year, both Bandar Abbas and Lavan Island supplied high sulfur specifications around 10,000 ppm (1.0%) gasoil.

    Desulfurization facilities by Bandar Abbas port were made operational in November, while those at Lavan Island became active six months before, a NIOC source said.

    NIOC doesn't publish tenders for high sulfur gasoil, opting for private negotiations instead.

    So far this year, Iranian exports from Bandar Mahshahr have ranged between 7,000-9,000 ppm, sources said.

    The first gasoil shipment from Iran since its trade sanctions were removed was chartered by trading company Vitol, according to shipping sources and broker reports.

    Vitol wasn't immediately available for comment on the matter.

    The UN Security Council lifted petroleum sanctions on Iran in January.

    The trade sanctions were originally imposed by the UN Security Council in 2006, but were tightened up in 2008 and again in 2010 in opposition to Iran's nuclear program.

    Since the sanctions were lifted, Iran has exercised the opportunity to sell oil to Europe, with a large proportion of this crude and condensate rather than refined or finished products.


    Firstly, being straight run gasoil, the Iranian streams can be fed through a wide range of desulfurization units across the ARA region. Unlike cracked material, straight run gasoil contains fewer impurities and unwanted metals and is therefore a more malleable product.

    Certain desulfurization units apply restrictions on metal contaminants within cracked material, to optimize the longevity of the unit. Desulfurizers need to burn at higher temperatures in the presence of contaminants, which in turn reduces the desulfurization unit's life span, a refinery source said.

    Handling cracked material becomes more complex.

    "If there are additives beyond the technical specifications, you need to do a cost-benefit analysis. If the catalyst is burning at a higher temperature, this affects the life [of the unit]. So you must know the burn rate, and then you do the analysis," the refiner said.

    Conversely, the straight run nature of the Iranian gasoil offers better optionality in the way of desulfurization across units in Europe, where there is a vast desulfurization capacity.

    While the Iranian material could journey east toward Singapore's oil products hub, Northwest Europe offers superior desulfurization capabilities, with facilities built to manage Europe's cleaner energy evolution towards the current 10 ppm ultra low sulfur diesel specification.

    As sulfur content requirements became more stringent across Europe, the infrastructure was developed simultaneously within the region to satisfy the lower sulfur demands.

    "Singapore does not have desulfurization capacity, so it is easier to take into ARA. Freight is not too expensive on a bigger vessel [to ARA]," a trader said.


    Globally, the trend is for lower sulfur levels in gasoil and diesel. However, one of the few outlets left for high sulfur material is West Africa.

    Indeed, the Torm Sara loaded in Bandar Mahshahr and, after visiting the oil terminal at Fujairah, the vessel is now heading towards Lome, Togo, the main point in the West African offshore market.

    However, in West Africa the predominant grade traded is 0.3% gasoil -- high sulfur, high density, high flash gasoil. However, Iranian gasoil initially falls short on the latter two aspects.

    The flash point for the latest Iranian gasoil offered ranged between a minimum of 54-60 degrees Celsius, while the grade traded in the offshore Lome market typically requires a very high flash point of 70 C, according to sources.

    The density of Iran's gasoil also fails to meet WAF's requirements, as the typical traded density in the offshore market is a minimum of 0.865, according to traders.

    As a result, the material is likely to have been blended in Fujairah in order to meet the market's requirements.

    "It is too low density for WAF, even after desulfurization. ARA makes sense," according to the first trader, who also specializes in West African trade.

    Other high-sulfur consumer markets in the region are also a tricky prospect without blending. But even here the move is towards lower sulfur specifications.

    For example, Pakistan is set to move from 0.5% sulfur to 500 ppm at the beginning of 2017, and as part of the general trend to lower sulfur material, the ability of Iranian material to go into short positions without blending or being desulfurized is extremely limited.

    For now, Iran's gasoil shipments to ARA are expected to continue, market sources said, together with the existing flows of condensate and crude products.

    However, there remains uncertainty over the regularity of these shipments.
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    Exxon Names Darren Woods as New CEO to Replace Rex Tillerson

    Darren Woods, the man replacing Rex Tillerson as the leader of America’s most influential energy giant, helped transform Exxon Mobil Corp.’s refining business from a poor cousin of oil production to the primary profit generator.

    Woods, the company’s refining boss since 2012, was named the next chairman and chief executive officer effective Jan. 1 after President-elect Donald Trump picked Tillerson to become U.S. Secretary of State, the Irving, Texas-based oil company said in a statement Wednesday. Even if Tillerson doesn’t become America’s top diplomat -- three Republican senators have expressed misgivings about his nomination -- he was due to leave no later than March when he reaches Exxon’s mandatory retirement age.

    Woods, 51, inherits a drilling and refining behemoth hamstrung by a 2 1/2-year slump in energy markets, ill-timed investments in North American shale and Russia, and allegations of deceiving investors with a climate-change cover-up. Still, Trump’s election, OPEC’s plan to cut production and Woods’s ability to boost the value of the company’s refineries have all combined to change the face of the industry for Exxon heading into the future.

    “Validating the integrated model will be the challenge for the next leader of Exxon,” said Vincent Piazza, a senior analyst at Bloomberg Intelligence in New York. “Downstream and chemicals have been the few bright spots counterbalancing the negative impact of prices on the upstream segment.”

    Darren Woods

    Woods’s elevation to chairman and CEO was telegraphed with his promotion to president in January, the same time he became a member of the board of directors. He’s been on the six-person management committee that oversees day-to-day operations since June 2014. He steps into the new roles effective Jan. 1.

    Refining Reversal

    For the past five quarters at Exxon, refining has outperformed so-called upstream oil and natural gas wells, a reversal of the traditional relationship. Since June 2015, Exxon’s refineries and related business lines raked in $6.34 billion, compared with $3.05 billion for the oil and gas business. During that same period, refining burned through $3.1 billion in capital spending, compared with $23.2 billion in the upstream segment.

    A Kansas-born electrical engineer by training, Woods joined Exxon as an analyst in 1992 and rose through the ranks on the refining and chemicals side of the business. His main rival in the competition to succeed Tillerson was Jack Williams, a drilling engineer who oversaw oil and gas projects from Louisiana to Malaysia before taking control of XTO Energy, the shale explorer Exxon bought in 2010 for $35 billion.

    One of Woods’s most-pressing tasks will be figuring out how to rescue a stillborn Russian joint venture that locked up $1 billion in investments and a billion-barrel Arctic oil discovery behind a wall of international sanctions.

    Russia Quandary

    When Exxon signed a 2011 agreement to join with Rosneft PJSC in drilling Arctic, deepwater and shale fields, it was seen as a crowning achievement of Tillerson’s career. But the work slammed to a halt when the U.S. and European Union imposed economic sanctions against Russia in 2014 as punishment for its annexing Crimea and supporting Ukrainian separatists. The venture has been mostly idle ever since.

    On the home front, Woods will face allegations by attorneys general from New York, Massachusetts and other states that Exxon misled investors about the threat posed to the company’s portfolio by climate change. Under Tillerson, the company has aggressively defended its record and said the probes are politically motivated.

    Exxon shares have risen 16 percent this year, lagging the 19 percent advance by the Bloomberg World Oil & Gas Index. Chevron Corp. and Royal Dutch Shell Plc have also outperformed their bigger rival, with gains of 29 percent and 40 percent, respectively.

    Woods made $28,848 in political contributions during the past four years. The biggest recipient was Exxon’s political action committee, which took in $13,700. Woods also gave the Republican National Congressional Committee $10,000.

    Exxon’s leadership change comes after the Organization of Petroleum Exporting Countries and several non-OPEC nations including Russia committed to cutting almost 1.8 million barrels a day of crude starting next year. Oil in New York has risen about 15 percent to over $50 a barrel since the Nov. 30 accord.

    Legendary oil tycoon T. Boone Pickens sees crude reaching $60 a barrel within a month, and $75 some time next year. “I’m long oil,” Pickens said during a Bloomberg Television interview on Monday. OPEC members “will carry out what they say they will do. They will cut supply.”
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    Conoco sells $1.3 billion in oil land, assets

    ConocoPhillips, the world’s largest independent oil company, sold $1.3 billion in oil land and other assets this year, generating cash for debt reduction, share repurchases and operations.

    Conoco, based in Houston, said on Wednesday it will record $800 million in sales this quarter: interests in Senegal, Indonesia, Alaska’s North Cook Inlet and Minnesota iron ore. The sales will reduce company oil and gas production by 27,000 barrels per day. Still, Conoco doesn’t expect the loss to effect its 2016 production totals; It says 2017 production, excluding work in Libya, won’t dip and could grow as much as 2 percent.

    The company paid down $1.25 billion of debt in October and another $150 million in December, totaling about $2.2 billion of debt this year.

    Conoco plans to repurchase $3 billion in shares, and began in mid-November.

    In the third quarter, Conoco lost $1 billion, $100,000 less than it lost in the second quarter of 2016 and the third quarter of 2015. It cut about $300 million in capital expenses as it shifted money from offshore projects to hydraulic fracturing operations in U.S. shale fields. It also slashed operating expenses by 17 percent, or $300 million.

    But it still reported $27 billion in long-term debt.

    The company said on Wednesday that it plans on selling $5 billion to $8 billion in assets over the next two years.
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    Summary of Weekly Petroleum Data for the Week Ending December 9, 2016

    U.S. crude oil refinery inputs averaged 16.5 million barrels per day during the week ending December 9, 2016, 57,000 barrels per day more than the previous week’s average. Refineries operated at 90.5% of their operable capacity last week. Gasoline production decreased last week, averaging over 9.8 million barrels per day. Distillate fuel production decreased last week, averaging 5.0 million barrels per day.

    U.S. crude oil imports averaged about 7.4 million barrels per day last week, down by 943,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged 7.7 million barrels per day, 2.0% below the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 624,000 barrels per day. Distillate fuel imports averaged 233,000 barrels per day last week.

    U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 2.6 million barrels from the previous week. At 483.2 million barrels, U.S. crude oil inventories are near the upper limit of the average range for this time of year. Total motor gasoline inventories increased by 0.5 million barrels last week, and are well above the upper limit of the average range. Finished gasoline inventories decreased while blending components inventories increased last week. Distillate fuel inventories decreased by 0.8 million barrels last week but are above the upper limit of the average range for this time of year. Propane/propylene inventories fell 3.6 million barrels last week but are near the upper limit of the average range. Total commercial petroleum inventories decreased by 2.0 million barrels last week.

     Total products supplied over the last four-week period averaged over 19.4 million barrels per day, down by 2.5% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged over 8.9 million barrels per day, down by 3.0% from the same period last year. Distillate fuel product supplied averaged over 3.9 million barrels per day over the last four weeks, up by 11.0% from the same period last year. Jet fuel product supplied is up 3.4% compared to the same four-week period last year.

    Cushing up 1.2 mln bbl

    EIA reports shows refiners exporting huge amount of product, 5.7 MMbbl/day total, 1.1 are mogas, 1.3 distillate. 30% of product is exported!
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    Jump in lower 48 oil production

                                               Last Week  Week Before  Last Year

    Domestic Production '000.......... 8,796          8,697         9,176
    Alaska ....................................... 520            522            524
    Lower 48 ................................. 8,276          8,175         8,652
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    STONE ENERGY CORPORATION Announces Filing for Court Approval of Prepackaged Restructuring Plan

    Stone Energy Corporation, and its domestic subsidiaries (together with the Company, the “Debtors”), today announced that they had filed voluntary petitions under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) to pursue a pre-packaged plan of reorganization (as amended, the “Plan”) in accordance with its previously announced comprehensive balance sheet restructuring efforts.

    As previously disclosed, on November 17, 2016, the Debtors commenced a solicitation to seek acceptance by a majority of those voting in each voting class of claims of the Company’s creditors under the Plan, including (a) the lenders (the “Banks”) under the Fourth Amended and Restated Credit Agreement, dated as of June 24, 2014, as amended, modified, or otherwise supplemented from time to time (the “Credit Agreement”) among Stone as borrower, Bank of America, N.A. as administrative agent and issuing bank, and the financial institutions named therein, and (b) the holders of the Company’s 1 3⁄4% Senior Convertible Notes due 2017 (the “Convertible Notes”) and the Company’s 7 1⁄2% Senior Notes due 2022 (the “2022 Notes” and, together with the Convertible Notes, the “Notes” and the holders thereof, the “Noteholders”).  Stone expects the solicitation period to end on December 16, 2016.  Copies of the Plan, then in effect, and the disclosure statement related to the solicitation were furnished as Exhibit 99.1 to Stone’s Current Report on Form 8-K filed on November 18, 2016.

    As previously announced, on October 20, 2016, the Debtors and Noteholders holding approximately 85.4% of the aggregate principal amount of Notes executed a restructuring support agreement (the “Original RSA”).  On December 14, 2016, the Debtors, the Noteholders holding approximately 79.7% of the aggregate principal amount of Notes and the Banks holding 100% of the aggregate principal amount owing under the Credit Agreement entered into an Amended and Restated Restructuring Support Agreement (the “A&R RSA”) that amends, supersedes and restates in its entirety the Original RSA.  In connection with entry into the A&R RSA and the commencement of the bankruptcy cases, the Debtors amended the Plan.

    Pursuant to the terms of the Plan as revised to be consistent with the terms of the A&R RSA and the term sheet annexed to the A&R RSA (the “Term Sheet”), Noteholders, Banks and other interest holders will receive treatment under the Plan, summarized as follows:

    Noteholders will receive their pro rata share of (a) $100 million of cash, (b) 96% of the common stock in reorganized Stone and (c) $225 million of new 7.5% second lien notes due 2022.

    Existing common stockholders of Stone will receive their pro rata share of 4% of the common stock in reorganized Stone and warrants for up to 10% of the post-petition equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants.

    Banks signatory to the A&R RSA will receive their respective pro rata share of commitments and obligations under an amended Credit Agreement on the terms set forth in Exhibit 1 to the Term Sheet, as well as their respective share of the Company’s unrestricted cash, as of the effective date of the Plan, in excess of $25 million, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA, defined below.

    Banks not signatory to the A&R RSA will have the option to receive either (a) the same treatment as the Banks signatory to the A&R RSA, or (b) their respective pro rata share of new senior secured term loans plus collateral for their respective pro rata share of issued but undrawn letters of credit.
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    Gulfport Energy Corporation Announces Entry into the SCOOP Play with Complimentary Acquisition of Approximately 85,000 Net Effective Acres

    Gulfport Energy Corporation today announced that the Company has entered into a definitive agreement with Vitruvian II Woodford, LLC (“Vitruvian”), a portfolio company of Quantum Energy Partners, to acquire approximately 46,400 net surface acres in the core of the SCOOP, including approximately 183 MMcfe per day of net production for October 2016 for a total purchase price of $1.85 billion.

    Acquisition Highlights

    Substantially contiguous acreage position totaling approximately 85,000 net effective acres, which includes rights to 46,400 Woodford acres and 38,600 Springer acres, in Grady, Stephens and Garvin Counties, Oklahoma, with approximately 80% held by production.
    Stacked-pay potential with approximately 1,750 gross drilling locations, including over 775 gross locations with internal rates of return of approximately 75%, targeting the Woodford and Springer intervals with significant upside potential through infill drilling and additional prospective zones.
    Existing production of approximately 183 MMcfe per day in the month of October 2016.
    Total estimated proved reserves at September 30, 2016 were 1.1 Tcfe.

    As of December 13, 2016, Gulfport entered into a definitive agreement with Vitruvian to acquire approximately 46,400 net surface acres with multiple producing zones, including the Woodford and Springer formations, in Grady, Stephens and Garvin Counties, Oklahoma. Given the potential for numerous producing intervals across this high-quality position, Gulfport has identified approximately 1,750 gross drilling locations, composed of only Woodford and Springer zones with significant upside potential through infill drilling and additional prospective zones present on the acreage. The acquired properties are located primarily in the over-pressured liquids-rich to dry gas windows of the play and include approximately 183 Mmcfepd of net production for October 2016. The transaction also includes 48 producing horizontal wells and an additional interest in over 150 non-operated horizontal wells. Four rigs are currently operating on the acreage and Gulfport currently intends to maintain a four rig cadence in the play during 2017 and add an additional two rigs at the beginning of 2018. Based on the estimated internal reserve report prepared by Vitruvian as of September 30, 2016 and audited by Netherland, Sewell & Associates, Inc., the estimated proved reserves attributable to the acreage are approximately 1.1 Tcfe.  The acquisition is expected to close in February 2017, subject to the satisfaction of certain closing conditions.

    Consideration in the transaction includes a total purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash and approximately 18.8 million in shares of Gulfport common stock privately placed to the sellers, subject to adjustment.  The Company intends to fund the cash portion of the acquisition through potential debt and equity financings prior to closing.

    Chief Executive Officer and President, Michael G. Moore commented, “Today is a defining day for Gulfport Energy. Combining Vitruvian’s high-quality SCOOP position with our prolific Utica assets will transform our company and solidify Gulfport with core positions in two of North America’s high-return natural gas basins. In Vitruvian, we believe we have found a prolific stacked pay resource with strong production history, a multi-year, high-return drilling inventory – an opportunity with significant upside from both a resource and operational perspective.  The asset consists of a low-risk, substantially contiguous acreage position in the core of the SCOOP. This acquisition is not only additive to our Company but in our opinion truly one-of-a-kind. The transaction is expected to be accretive to cash flow and net asset value per share and provides us with a blocky, sizeable and scalable footprint in a new operating area.”

    Vitruvian CEO and President, Richard F. Lane commented, “We are pleased to be part of this significant transaction, both for the complimentary asset it represents for Gulfport and for the achievement it represents for Vitruvian’s employees and stakeholders. We plan to work closely with the Gulfport team to ensure a seamless transition of the asset to Gulfport.”

    President of Quantum Energy Partners, Dheeraj Verma commented, “We are excited about this transaction and believe that the combination of these assets will provide Mike and his team with more opportunities for margin expansion and cash flow growth immediately. We are quite optimistic about the value creation potential here and look forward to participating in this upside as a shareholder of the combined company.”

    BofA Merrill Lynch acted as exclusive financial advisor to Gulfport in connection with the transaction and Akin Gump Strauss Hauer & Feld LLP served as Gulfport’s legal counsel. Jefferies acted as financial advisor to Vitruvian in connection with the transaction and Vinson & Elkins served as Vitruvian’s legal counsel.

    About Gulfport

    Gulfport Energy Corporation is an Oklahoma City-based independent oil and natural gas exploration and production company with its principal producing properties located in the Utica Shale of Eastern Ohio and along the Louisiana Gulf Coast. In addition, Gulfport holds a sizeable acreage position in the Alberta Oil Sands in Canada through its 24.9% interest in Grizzly Oil Sands ULC.
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    Statoil getting out of oil sands, takes $500 million loss

    Statoil ASA, the Norwegian-owned oil and gas major, does not believe it has a future in the Canadian oil sands.

    Citing concerns over profitability, the company said Wednesday it will sell its Kai Kos Dehseh (KKD) assets in the Alberta oil patch to Athabasca Oil (TSX:ATH) and take a loss of at least $500 million.

    The deal with Athabasca Oil involves two oil sands leases, a 24,000 barrel a day test project and a greenfield facility which was expected to produce 40,000 barrels a day, which Statoil shelved in 2014.

    “This transaction corresponds with Statoil’s strategy of portfolio optimization to enhance financial flexibility and focus capital on core activities globally,” Statoil said in a statement. Through the sale, a cash and share transaction totalling CAD$832 million, Statoil will earn a 20% stake in Athabasca Oil. But the divestment will also trigger an impairment of between USD$500 million to $550 million.

    The deal with Athabasca Oil involves two oil sands leases, a 24,000 barrel a day test project and a greenfield facility which was expected to produce 40,000 barrels a day – the latter of which Statoil shelved in 2014.

    The Norwegian oil company entered KKD through the acquisition of North American Oil Sands Corporation in 2007. In 2011 PTTEP acquired a 40% interest, and in 2014 Statoil and PTTEP agreed to divide their respective interests in KKD. Since then, Statoil has continued as owner-operator of the Leismer and Corner projects.

    Statoil, of course, is not the first European company to scale back investments in the Canadian oil sands, which have been hit hard by the crude oil price collapse. France's Total SA (NYSE:TOT) shelved its Josyln project in 2014, and also divested some of its interest in the $13.5 billion Fort Hills facility to Suncor (TSX:SU).

    Last year Royal Dutch Shell (LON:RDSA) pulled the plug on the development of its Carmon Creek thermal oil sands project and took a $2 billion charge as a result.

    American companies are also taking a hard look at the oil sands. In October, Exxon Mobil (NYSE:XOM) said it would have to cut its oil reserves by 19%, including removing 3.6 billion barrels from its books, from the Kearl oil sands project in northern Alberta.

    Even with prices climbing above $50 a barrel, oil sands producers are challenged by high upfront capital costs – making new projects difficult -, new carbon emissions regulations and limited access to pipelines, which forces companies operating in Canada to accept lower prices for their products.

    “Since we entered the oil sands in 2007, our portfolio has changed and also the energy markets have shifted quite fundamentally since then,” Paul Fulton, Statoil’s country president, told The Globe and Mail. “We’ve seen a decline in the oil price, and Statoil has a broader portfolio of assets that it needs to allocate its capital to.”
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    Hedging activity maintains high pace set in Q3

    Oil and gas hedging activity skyrocketed in Q3 to the highest level in a year. Will activity climb higher in Q4 as prices break through the US$50/bbl threshold? Our corporate research experts look at the Q3 numbers and analyse hedging volumes, trends as Q4 wraps up, and what's to come in a post-OPEC-cuts 2017.

    Oil and gas hedge volume soared in Q3 2016 — more than in any of the prior three quarters. What drove this surge in activity? And what conclusions might we draw as Q4 comes to a close and we enter 2017 with historic production cuts by OPEC?

    Covering a peer group of 32 of the largest upstream companies with active hedging programmes, our analysis shows the volume of oil hedges in Q3 were up 72% compared to Q2, and gas was up 45%. This surge may simply be due to higher oil and gas prices relative to H1 2016, with a majority of derivatives within US$5/bbl of a US$50/bbl (Brent) oil price and a minimum of US$3 per thousand cubic feet of gas (Henry Hub).

    Notably, only three operators were responsible for 42% of the volumes added in oil hedging, and just two of their peers accounted for 58% of gas hedging volumes. The rush to lock in US$50/bbl oil and US$3.20/mcf gas suggests that producers may not have sensed much price upside beyond those levels for the near term. But recent OPEC announcements have altered the outlook.

    A recent flattening in the curve for oil-price futures suggests that the pace of oil-hedging activity has remained strong during Q4. Producers appear to be rushing to lock in $55/bbl oil for 2017. The extent of the activity cannot be quantified until producers disclose updates to derivative positions in Q4 results documents. We will be watching for a few key signals:

    1) Will Q4 activity exceed the year-to-date highs we saw during Q3?;
    2) With several sub-$50/bbl hedges already in place, how much will producers' weighted-average hedge price increase?; and
    3) Will the new activity raise 2017 hedge protection to similar levels as 2016 and 2015?
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    Wood Group shows recovery in U.S. shale on rising oil prices

    Oilfield services company John Wood Group Plc's CFO David Kemp said on Wednesday that the company showed modest recovery in some of its oil and gas markets, including U.S. shale and offshore oil exploration and drilling businesses.

    * U.S. shale is the largest contributor to company's operations and maintenance contracts in its west region, which includes the Americas. John Wood Group said a steady rise in rig count would help its assets in the Permian, Eagle Ford, Marcellus, Utica and Bakken basins as the market recovers in 2017.

    * The number of oil rigs operating in the United States rose for a fifth straight week to 477, reaching the highest level since January as a surge in crude prices continued to bring equipment back into operation, weekly data from oil and gas services company Baker Hughes showed.

    * U.S. shale production is set to recover from a five-month decline in January, the U.S. government said on Monday. Oil rose to an 18-month high on Monday after OPEC and some of its rivals reached their first deal since 2001 to jointly reduce output to tackle global oversupply, though prices slipped late in the day.

    * Wood Group, which counts BP Plc as one of its customers, said in August that it expected a 20 percent drop in full-year EBITA.

    * Full-year revenue was expected to be $5.18 billion, according to company-provided consensus on its website. Pretax profit was expected to be $247 million.

    * The company reiterated on Wednesday it would raise its 2016 dividend by double-digit percentage points.

    * Oil companies have cut back on spending for exploration drilling and maintenance, reducing demand for engineering firms such as Wood Group that provide services such as overhaul of compressors, pumps, generators and rotating equipment.

    * The company, founded in 1912 as a ship repair and marine engineering firm, said it expected earnings before interest, tax and amortisation (EBITA) to be in line with the company-provided consensus of $370 million for the full-year ended Dec. 31.
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    Alternative Energy

    S.Korea pairs state utility, private tech giants in $37 bln bid to seize global green energy lead

    South Korea aims to vault from laggard to leader in the renewable energy industry, as Seoul prepares to hook the country's tech giants up to nearly $40 billion in public funds in a bold plan to become a new global leader in green power.

    Amid questions over the future of clean energy in the United States under President-elect Donald Trump, as well as China's appetite for cutting fossil fuel reliance, Seoul is accelerating into battery and 'smart' grid technology - vital to store and transmit power whose generation changes with the weather.

    Fresh from unveiling a 42 trillion won ($37 billion) support package, Seoul said last month it now aims to double the amount of green energy it produces by 2025 - 10 years ahead of previous plans. As well as cutting overwhelming reliance on coal and nuclear power, the plan aims to tap into the prowess of Korean tech leaders like Samsung - previously focused on consumer electronics - to build a major new export industry.

    "South Korea definitely has the potential when it comes to clean tech because of government incentives but also the already established companies there," said Vishal Sapru, Program Manager, Power Quality/Power Supplies at consultancy Frost & Sullivan. "They are strong contenders when it comes to utility-scale storage...They have the bandwidth to meet aggressive demand."

    The push by Asia's 4th-largest economy comes as global climate change treaty commitments dovetail with a race among the world's tech firms for new revenue streams while growth in goods like smartphones slows. The International Energy Agency now sees 28 percent of the world's power being generated from renewable sources by 2021, up from 23 percent in 2015.


    Firms from General Electric to Europe's ABB are eyeing growth in smart grids and batteries - and have a head start. But by combining the power transmission know-how of its state utilities with private sector expertise in batteries and power controls, South Korea is well placed to gain ground, industry executives say.

    "One of Korea's strengths is IT technology, particularly semiconductors and battery," said Lee Jeong-min, a senior manager of energy storage systems sales team at Hyosung Corp . "If we link them together with new energy business, we can catch up."

    Hyosung is among several private firms partnering with state utility Korea Electric Power Corp (KEPCO) to develop smart grid and energy storage systems at home and in international markets.

    KEPCO is now working on some 40 overseas energy and power distribution projects. It agreed in November with the U.S. state of Virginia to develop 10 energy projects, echoing similar deals it has agreed with Canada's Ontario state as well as Dubai.

    "We play our role in operating the power grid and leading new businesses, while private sector partners do their part by making products and supplying them," Hwang Woohyun, vice president of KEPCO, told Reuters in an interview.


    To help extend Korean companies' global reach, KEPCO plans to invest 8.3 trillion won in collaborative programmes by 2020. Meanwhile partner Samsung SDI is eying 3 trillion won in investments on battery development by 2020.

    LG Chem is also bullish on energy storage as solar panel costs drop and government support rises.

    "This year energy storage system revenue is expected to grow over 60 percent to 270 billion won and to increase further next year, about 80 percent to more than 500 billion won," Kang Chang-Beom, LG Chem vice president said in a recent conference call.

    For SDI, part of the Samsung empire and the world's top maker of handset batteries, the government push offers a way to help it further expand into energy storage systems.
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    Subsidies for home renewable energy creation to increase

    Subsidies for renewable technologies to heat homes, such as heat pumps and biomass boilers, are being increased, the Government announced.

    And plans to drop solar thermal panels – which use the sun to heat water – from the heating subsidies scheme have been abandoned, with payments for the technology maintained at current levels.

    The moves come as part of reforms to the “renewable heat incentive” which aims to encourage the take-up of clean technologies for heating and hot water in homes and other buildings.

    Heating accounts for 45% of UK energy consumption and more than 30% of carbon emissions, energy minister Baroness Neville-Rolfe said.

    But the Government has faced criticism from its own climate advisers as progress on cutting carbon from heating – most of which is provided by gas in the UK – has stalled.

    Ministers have announced that subsidies for air source and ground source heat pumps, which run on electricity and work like reverse fridges to heat homes, will be increased.

    There will also be a slight increase in payments for boilers that burn biomass such as wood pellets to heat homes, returning support to a previous level, which was a response to a consultation on reforming the incentive scheme.

    And solar thermal will stay in the scheme and continue to receive the same level of payments.

    Baroness Neville-Rolfe said the improvements to the renewable heat incentive would “do more to encourage households and businesses to install electric heat pumps and indeed biomass boilers, instead of conventional fossil fuel systems”.

    “The reforms will also make sure we are improving the value for money of spend through the scheme and that consumers are protected,” she said in a speech at an event on making heating greener at think tank Policy Exchange.

    Paul Barwell, Solar Trade Association chief executive, said: “Solar thermal is back, which is great news for consumers who want to bring down their energy bills and do their bit to mitigate climate change.”

    Isabella O’Dowd, policy analyst for the STA solar thermal group, added: “The UK lags behind on solar thermal internationally but its potential in this country is huge.

    “It is a low hassle choice for households with even limited roof space; once installed solar thermal typically provides around half of your hot water and it can take around 10% off the average energy bill, with very little on-going maintenance.”

    With the payments under the incentive scheme, costs can be recovered within 10 years, she said.
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    Precious Metals

    Finance titans face off over $5tn London gold market

    Some of the biggest names in finance are fighting for control of the London goldmarket – a $5 trillion, three-century-old trading hub that is being forced to adapt to a digital e.

    As the London Bullion Market Association revamps over-the-counter trades that are the market’s major pricing benchmark, new ways of buying and selling precious metals are set to start next year from CME Group , Intercontinental Exchange and the London Metal Exchange. Some big bankshave stakes in the outcome, including Goldman Sachs Group, HSBC Holdings and JPMorgan Chase and Co.

    “There are four weddings, and we have to dance at all of them, because we don’t know which marrie will last,” said Adrien Biondi, the global head of precious metals at Commerzbank in Luxembourg. “Only one will win.”

    Almost half the world’s known gold trading occurs in London. OTC transactions are sealed by virtual handshakes, leaving default risk with buyers and sellers rather than relying on clearinghouses, which use collateral to mane and offset risk. But since the financial crisis, all markets have been reevaluating how they do business and mane risk as regulators step up scrutiny. That’s particularly true for major price-setting exchanges, after it was discovered in 2012 that banks were manipulating a key benchmark for global interest rates.

    A push for fewer risks and more disclosure has forced the LBMA to seek changes that would make it more transparent and secure for customers. The association, which counts HSBC and JPMorgan among its members, will introduce trade reporting for its members and a new trading platform in the first half of next year. That’s also when competitors plan to unveil new precious-metals derivatives built around the clearinghouse models.

    Gold remains one of the world’s most-popular commodities and a core reserve for central banks around the world. While prices slumped for three straight years through 2015, demand has since rebounded. Holdings by exchange-traded funds are up 30% this year, and investors have poured a net $25.5-billion into precious metals funds, data compiled by Bloomberg show.

    That’s helped boost the business of buying and selling gold. In October, LBMA reported gold trading rose to a daily avere of 18.6-million ounces. That’s about $23.5-billion, based on the avere value of bullion for the month. Prices are up 9.4% this year at $1 160.30 an ounce as of Wednesday.

    The LME, the world’s largest base-metals exchange, found so much promise in precious metals that it announced in August plans to start offering cleared gold and silver contracts in the first half of 2017. Eventually, it will add platinum and palladium. The exchange had the backing of a group of five banks including Goldman Sachs, ICBC Standard Bank and Societe Generale SA, as well as the World Gold Council, a group backed by the mining industry that seeks to develop markets for the metal.

    ICE, which owns commodity and financial exchanges, already runs the daily London gold auction on behalf of the LBMA among 13 authorized participants who set the daily price. In October, the Atlanta-based company said it would start its own gold contract in February that would involve bullion held in London and traded on its New York exchange.

    Chico-based CME Group, owner of the Chico Board of Trade and the world’s largest futures exchange operator, sought an even earlier entree into the London marketplace. In November, during LME Week, CME said it would start London gold and silver contracts Jan. 9 that offer a spread between spot prices and benchmark U.S. futures.

    “We’re going to see five years of turmoil in this market before things settle down,” Tony Dobra, an executive director at the UK’s biggest gold refiner, Baird & Co., said by phone from London on Dec. 6. “The good old London OTC market will keep soldiering on until we see some sort of consensus.”
    Opinion Split

    Senior traders, including Biondi and Simon Grenfell, global co-head of commodities at Natixis SA, an LBMA member bank which offers trading and risk manement services, said the change is both necessary and inevitable.

    The development “reduces credit risk in the system and makes it easier to trade,” Grenfell said by e-mail from London. “While the overhaul to gold markets may reduce credit margins on client business, improving transparency is a welcome change.”

    Opinion remains split on who will come out on top. Dobra, Biondi and founding member Raj Kumar, head of precious metals business development at ICBC Standard Bank, all said the LME offers the best solution for the market. Brad Yates, trading head for Dallas-based refiner Elemetal, said the CME would best fit his business needs. And participation on ICE’s benchmark, which underlies its contract, keeps growing, with trading house INTL FCStone the latest to join the process.

    “There will always be an OTC market in London, but much of what currently takes place here will shift to the exchanges,” said Kumar, who works at a unit of  Industrial & Commercial Bank of China (Asia), the world’s biggest bank. “Participating in any new contract incurs set-up costs, and so firms will need to prioritise which venues they are likely to trade.”
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    Newmont facing up to $1.2B impairment charge due to upcoming Yanacocha closure

    As every mining company knows, closing a mine can be costly, especially one the size of Newmont's  Yanacocha in Peru.

    On Tuesday, the largest U.S. gold company said in a filing with the US Securities and Exchange Commission that it will likely record a non-cash impairment charge of between $1 billion and $1.2 billion in the fourth quarter due to runaway costs associated with closing the mine, which is nearing the end of its life.

    Started in 1993, Yanacocha is the largest gold mine in South America, and number 6 on Frank Holmes' list of top 10 producing gold mines.

    In a statement, Newmont said it expects increasing costs to retire the mine in the order of $400 million to $500 million in Q4, based on more costly water treatment, demolition and earthworks expenses. Denver-based Newmont has to submit a closure plan to Peruvian government authorities  every five years. The mine is currently 51.3%-owned by Newmont, with the rest owned by Minas Buenaventura of Peru (43.6%) and International Finance Corporation (5%).

    Newmont planned to replace Yanacocha production from the nearby Conga copper and gold mine, but years of local opposition including violent protests in 2011, led the company to abandon the $5 billion project earlier this year.

    While Newmont acknowledged that local opposition was an important factor in their decision, a company spokesman noted there were many other factors involved.

    “At the end of the day, our decision to reclassify Conga’s reserves as resources was a business decision triggered by certain operating and construction permits expiring at the end of 2015, uncertain prospects for future development and permitting and market conditions,” he told back in April.
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    Base Metals

    Copper supply from top world mine threatened as export ban looms

    Exports from the world’s second-largest copper mine in Indonesia are under threat as a government ban on overseas concentrate shipments is scheduled to come into force from the middle of January.

    While Ministers are rushing to revise the regulations so miners that have committed to build smelters can continue to export ore concentrates, an intermediate product used to make copper, there’s no guarantee that the deadline will be met. The rules as they stand now only permit shipments of refined metal after January 11.

    Richard Adkerson, CEO of Freeport-McMoRan, the world’s biggest publicly traded copper miner and owner of the massive Grasberg mine in Papua province, says he’s confident the issue will be resolved. He told a conference in the US last week that without a resolution the company would have to cut back operations and potentially curb development of the underground mine where it’s spending $1-billion a year.

    CRU Group, a consultancy, says the regulations will be changed.“CRU’s view is that the rules will be revised and Freeport McMoRan will be able to continue to exportGrasberg concentrates,” Christine Meilton, principal consultant, copper supply and raw materials, said by e-mail from London. “This may not happen before January 11, when the current export licence is also due to expire, in which case we may see a disruption to exports. Our base case forecast assumes that any disruption does not continue long enough to result in a cutback in production.”

    Grasberg is the world’s largest mine in terms of coppercapacity after Escondida in Chile, according to the International Copper Study Group, while Freeport says the deposit has the single biggest reserves of gold. Any disruption could support prices of copper, which is the best performer among its peers this quarter, as banks from Goldman Sachs Group Inc. to Citigroup take a bullish view on the metal next year.

    Indonesia, Southeast Asia’s largest economy, prohibited exports of raw, unprocessed ores in January 2014 as it sought to build a processing industry and prevent its mineral wealth from disappearing overseas. While the rules allowed time for producers to build smelters, the government said that after three years shipments of semi-processed ores would no longer be permitted.

    Progress building plants has been slow because of problems with investment, power supplies and falling prices for metals, which in January hit the lowest since 2009. Luhut Panjaitan, the co-ordinating Minister of Maritime Affairs, said last month the government is expediting a revision to the law to allow semi-processed exports as long as miners are constructing smelters.

    The outlook has been muddied by uncertainty over the role to be played by parliament. The head of a commission which overseas energy and mineral resources policy said in October parliament would only have time to consider a revision to the law next year. The government has said the changes could be made by revisions to regulations rather than to the law itself.

    “It’s all still in discussion,” said Bambang Gatot Ariyono, director general of minerals and coal at the Energy & Mineral Resources Ministry. “We are still looking at things from all sides,” he told reporters in Jakarta on Friday.

    Whatever the process, this is an important moment for Freeport in Indonesia. The regulation as it stands prohibits the export of concentrates, Adkerson told the conference last week. “If that’s not resolved, that will have a significant impact on us in terms of our employment there, our investments that we’re making,” he said, according to a Bloomberg transcript.

    It’s not just a question of concentrate exports. Freeport is also seeking clarity on the conditions that will permit it to operate in the country beyond 2021 when the 30-year term on its contract expires. Then, there is also a requirement for the company to build a new smelter so it can continue to exportconcentrate under government rules.

    “Building a copper smelter in Indonesia is hugely uneconomic because of the excess of smelters globally,” Adkerson said last week. “We’ll arrange project financing. We’ll bring in partners. The world will have a new smelter and we’ll do that. But we can’t start spending money on it until we get a contract extension. It’s a four-year or probably five-year construction project.”

    All this is at a time when Freeport is aggressively selling assets to reduce debt, which stood at $19-billion at end-September, and after its credit ratings were cut to junk earlier this year. It’s involved in a tussle over the sale of a coppermine in the Democratic Republic of Congo and is battling bondholder objections to the sale of its Gulf of Mexico assets. Cowen Group, an investment firm, rates the producer as its top metals and mining pick for 2017.

    Freeport has forecast sales from Grasberg next year will be 1.45-billion pounds of copper and 2.75-million ounces of gold.
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    Oyu Tolgoi resumes copper shipments to China

    Canada’s Turquoise Hill Resources, which is 51% owned by Rio Tinto and holds two-thirds of the massive Oyu Tolgoi copper-gold mine in Mongolia, said Wednesday it had resumed concentrate shipments from the operation to China.

    The Vancouver-based miner said that after two weeks of talks with Mongolian and Chinese authorities, Oyu Tolgoi has been allowed to restart shipping ore across the border, but it will follow a new joint coal and concentrate crossing route at the border between the two nations.

    Oyu Tolgoi — located in Mongolia’s remote southern Gobi desert, close to the country’s border with China — is expected to produce 560,000 tonnes of copper per year, along with gold and silver by-products.

    Production at the mine, expected to reach 560,000 tonnes of copper per year once at full tilt, was unaffected during suspension, Turquoise Hill said.

    Rio Tinto approved in May a $5.3 billion expansion of Oyu Tolgoi, one of the world's largest copper mines and a key component of the company’s master plan to become less dependent on iron ore for profits and become one of the world’s biggest copper producers.

    The planned expansion, with its nearly 200 km (125 miles) of underground tunnels that will track three times as deep as the Empire State Building is tall, will more than double the copper output from Oyu Tolgoi, which is mostly sent south to China, the world’s main metals consumer.

    It is also expected to help Rio and Turquoise Hill get to the most valuable part of the deposit, which also contains gold and silver, and where there has been a open pit mine running since 2013.

    First production from the extended underground area is expected by 2020, when a shortage of copper is tipped to emerge. Full ramp up is slated for 2027.
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    Ivanhoe PEA outlines dual alternatives for DRC-based Kamoa/Kakula deposits

    A new preliminary economic assessment (PEA) has outlined two potential initial development scenarios for Ivanhoe Mines’ “disruptive” Kamoa-Kakula copper project, in the Democratic Republic of Congo (DRC).

    The PEA examined two initial scenarios for development of the high-grade copper deposits at the Kamoa-Kakula project, located on the Central African copper belt, west of the DRC’s established Katanga mining region.

    "Kamoa-Kakula is an incredibly disruptive, district-scale, Tier 1 copper project that is still in its early days of discovery and development. Kakula's high copper grades and thicknesses establish Kamoa-Kakula as the most remarkable and rapidly-growing mineral discovery with which I've been associated during my 30-plus years in the explorationbusiness," stated founder and executive chairperson Robert Friedland.

    "We've already discovered as much copper in measured and indicated resources as we found with the original Ivanhoe Mines at Oyu Tolgoi, in Mongolia's South Gobi – but this time at much higher grades. Significantly, both the Kamoa and Kakula discoveries are open for future expansions. We remain focused on expediting development of Kamoa and Kakula.

    The first option entails the initial Kakula Phase 1 mine, calling for a high-grade initial phase of production at a head grade of 8.1% copper in year two and an average grade of 7.52% copper over the initial five years of operations, resulting in estimated average copper output of 209 000 t/y.

    The operation will hit peak production at 262 000 t in year three.

    The PEA calculated an initial capital cost, including contingency, of $1-billion, which is about $200-million lower than previously estimated in the March Kamoa prefeasibility study (PFS).

    The initial phase has an after-tax net present value (NPV), at an 8% discount rate, of $3.7-billion, an increase of 272% compared with the after-tax NPV of $986-million estimated in the March Kamoa (PFS).

    The after-tax internal rate of return (IRR) has been calculated at 38%, which is more than double the IRR of the 2016 Kamoa PFS. The IRR also includes a payback period of 2.3 years.

    Average mine-site cash cost is expected to average $0.37/lb of copper during the first decade of operations.

    Ivanhoe pointed out that Kakula is expected to produce a very-high-grade copper concentrate of more than 50% copper, with extremely low arsenic levels.


    The PEA also outlined an alternative eight-million-tonnes-a-year development scenario for the Kakula and Kamoa deposits, proposing to develop the two deposits as an integrated mining and processing complex.

    This scenario envisages the construction and operation of two separate facilities: the Kakula Phase 1 mine on the Kakula deposit and the Kansoko mine on the Kansoko Sud and Kansoko Centrale areas of the Kamoa deposit.

    Ivanhoe expects each operation to be a separate undergroundmine with an associated processing facility and surfaceinfrastructure.

    Under this scenario, Ivanhoe will process a higher head grade of 8.1% copper in year two and an average grade of 7.1% copper over the initial five years of operations, for an average output of 224 000 t.

    Combined, the Kakula and Kansoko mines are planned to produce on average 292 000 t/y of copper at an average grade of 5.81% copper during the first ten years of operations. The operations will reach peak output of 370 000 t/y by year seven.

    The alternative scenario is also expected to cost $1-billion, including contingency.

    The PEA calculated an after-tax NPV, at an 8% discount rate, of $4.7-billion, which is an increase of 382% compared with the after-tax NPV of $986-million estimated in the 2016 Kamoa PFS. The after-tax IRR of 34.6% is more than double the IRR of the 2016 Kamoa PFS, and will have a payback period of 3.5 years.

    Average mine-site cash cost is estimated at $0.42/lb of copper during the first ten years.

    Australian consultancy OreWin, Amec Foster Wheeler E&C Services and SRK Consulting prepared the PEA.

    The Kamoa-Kakula deposits boast combined indicated mineral resources of 944-million tonnes, grading 2.83% copper and contain 58.9-billion pounds of 1% copper cutoff grade ore, as well as a minimum thickness of 3 m.

    Kamoa-Kakula also has inferred mineral resources of 286-million tonnes, grading 2.31% copper and containing 14.6-billion pounds of copper.


    Ivanhoe stated that it had tasked Ivanhoe’s senior miningadviser, former president and co-founder of McIntosh Engineering Michael Gray to undertake a subsequent PEA to examine a doubling of the proposed mining rate at Kakula Phase 1 to eight-million tonnes a year, plus expanded output options of up to 16-million tonnes a year from two mines.

    Ivanhoe expects the follow-on PEA, now under way, to have “substantial advantages” over the development of two mines to achieve the same production rate. Planned studies also will assess higher mining rates of up to 16-million tonnes a year, which would use high-grade copper ore from the Kakula, Kansoko Sud and Kansoko Centrale deposits of the adjacent Kamoa deposit.

    The company expects to publish the results of the follow-on PEA by February next year.

    Meanwhile, Ivanhoe confirmed that strategic discussions regarding the company and its projects are intensifying, revealing that several significant mining companies and investors across Asia, Europe, Africa and elsewhere have expressed interest while setting no limit on providing capital.

    Attached Files
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    Aurubis confident of better year ahead after 2015/16 profit tumbles

    Europe's biggest copper smelter, Aurubis AG, said it expected profit to rebound in the current financial year after reporting a near 40 percent drop in 2015/16 earnings on Wednesday, partly due to smelter repairs in Bulgaria.

    The German company, which processes copper concentrate into metal, said it was now benefiting from high supplies of copper ore in the market and that it expected "significantly higher" operating earnings from the sector this financial year.

    "We assess the expected treatment and level of refining charges as relatively high in light of the current market situation," it said.

    It reported operating earnings (EBT) for the year ended September of 213 million euros ($227 million), down from 343 million euros in the previous year and below a Reuters poll forecast for 217 million euros. Aurubis had previously warned that it would not repeat last year's record results.

    "Overall, we expect significantly higher operating EBT and slightly higher operating ROCE (operating return on capital employed) for the group in the fiscal year 2016/17 compared to the (2015/16) reporting year," new CEO Juergen Schachler said.

    Schachler, who took over as CEO in July, said Aurubis is likely to seek deals to process more complex copper concentrate in coming months after a surprisingly low deal on fees to process standard ores.

    Benchmark annual copper ore treatment and refining charges (TC/RCs) for 2017 reportedly agreed in November by smelter FreeportMcMoRan are too low and some negotiations are still being carried out above the benchmark level, Schachler told a news conference to present the results.

    Freeport will reportedly pay $92.50 per tonne and 9.25 cents per pound for 2017 treatment and refining charges (TC/RCs), the second annual benchmark cut in a row and down from $97.5 per tonne for term contracts this year.

    "Negotiations are still going on above this level," Schachler said. "I still regard the level as too low in view of rising costs, an uncertain sulphuric acid market and strong mine production."

    Sulphuric acid is an important by-product of copper. When mine production is high, mines and other concentrate owners have to compete to gain smelter capacity and so TC/RCs are likely to be firm.

    "The upshot of this level could be that we will seek agreements to process more complex concentrate grades instead of the standard grades in the benchmark agreement," Schachler said.

    Some spot TC/RC deals for standard grades were currently being made below the expected benchmark level, he said.

    A scheduled shutdown at Aurubis's Pirdop smelter in Bulgaria hurt its 2015/16 earnings. The company said its first-quarter earnings for the current financial year will be affected by a three-week maintenance shutdown in October-November at its Hamburg smelter, which is legally mandated every three years.

    Schachler said the company was considering acquisitions although it had no firm targets in view.

    "We could go towards acquisitions when they strengthen Aurubis' core business," he said.

    Aurubis' last takeover was its purchase of Luvata group's rolled copper operations in 2011.

    "We currently have no concrete projects although we are naturally always in discussions," Schachler said. "We are financially in a rather strong position and have the potential."

    More details about the company's strategy could be announced at the annual shareholders' meeting in March, he said.

    Attached Files
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    World refined zinc market in 277,000 mt deficit in Jan-Oct

    The global market for refined zinc metal was in deficit by 277,000 mt from January to October 2016, with total reported inventories falling by 53,000 mt over the same period, according to preliminary data released Wednesday by the International Lead and Zinc Study Group.

    For the first 10 months of last year, the market was in surplus by 201,000 mt, according to ILZSG data.

    A rise in global usage of refined zinc metal of 3.7% year on year to 11.599 million mt was primarily influenced by an increase in Chinese apparent demand of 9.3%, which more than offset a 14% reduction in the US, the ILZSG noted. Usage in Europe rose by 0.9% year on year.

    Chinese imports of zinc contained in zinc concentrates fell by 44.5% to 631,000 mt in January-October, but the country's net imports of refined zinc metal increased by 26% to 359,000 mt.

    Despite rises in output in China and the Republic of Korea, world refined zinc metal output declined by 0.6% over the period to 11.322 million mt, mainly as a consequence of reductions in Australia, India, Mexico and the US.

    Global zinc mine production of 10.887 million mt was down by 1.8% compared to the corresponding 10 months of 2015.

    "This was mainly due to reductions in Australia, India, Ireland and Peru that more than offset increases in Bolivia, China and the Russian Federation," the ILZSG said.
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    Steel, Iron Ore and Coal

    Coal demand growth to stall as appetite wanes, according to IEA

    Growth in global coal demand will stall over the next five years as the appetite for the fuel wanes and other energy sources gain ground, according to the latest coal forecast from the International Energy Agency.

    The share of coal in the power generation mix will drop to 36% by 2021, down from 41% in 2014, the IEA said in the latest Medium-Term Coal Market Report,driven by lower demand from China and the United States, along with fast growth of renewables and strong focus on energy efficiency.

    But in a sign of coal’s paradoxical position, the world is still highly dependent on coal. While coal demand dropped in 2015 for the first time this century, the IEA forecasts that demand will not reach 2014 levels again until 2021. However such a path would depend greatly on the trajectory of China’s demand, which accounts for 50% of global coal demand – and almost half of coal production – and more than any other country influences global coal prices.

    The new report highlights the continuation of a major geographic shift in the global coal market towards Asia. In 2000, about half of coal demand was in Europe and North America, while Asia accounted for less than half. By 2015, Asia accounted for almost three-quarters of coal demand, while coal consumption in Europe and North America had declined sharply below one quarter. This shift will accelerate in the next years, according to the IEA.

    Because it is relatively affordable and widely available, coal remains the world’s number one fuel for generating electricity, producing steel and making cement. It provides almost 30% of the world’s primary energy, declining to 27% by 2021. However it is also responsible for 45% of all energy-related carbon emissions and is a significant contributor to other types of pollution.

    “Because of the implications for air quality and carbon emissions, coal has come under fire in recent years, but it is too early to say that this is the end for coal,” said Keisuke Sadamori, the director of the IEA’s energy markets and security directorate, who launched the report in Beijing, China.

    “Coal demand is moving to Asia, where emerging economies with growing populations are seeking affordable and secure energy sources to power their economies. This is the contradiction of coal — while it can provide essential new power generation, it can also lock-in large amounts of carbon emissions for decades to come.”

    The IEA’s report acknowledges China’s continued dominance in global coal markets. Coal-fired power generation in China dropped in 2015 due to sluggish power demand and a diversification policy that led to the development of new renewable and nuclear power generation capacity. The IEA forecast for Chinese coal demand shows a very slow decline, with chemicals being the only sector in which coal demand will grow, reaching 2,816 Mtce by 2021, around 100 Mtce less than the 2013 peak.

    In the United States, coal consumption dropped by 15% in 2015, precipitated by competition from cheap natural gas, cheaper renewable power – notably wind – and regulations to reduce air pollutants that led to coal plant retirements. This was the largest annual decline ever, reaching levels not seen in more than three decades. Another substantial decline is expected in 2016. Looking ahead, the IEA forecasts a 1.6% per year decline, much slower than 6.2% decline over the past five years, as higher gas prices result in less coal-to-gas switching.

    The brightest sign for coal was a recent unexpected boost in prices that provided relief to the industry. After a sustained four-year long decline, coal prices rebounded in 2016, mostly because of policy changes in China to cut capacity and curb oversupply. This was another example of the strong influence of macroeconomic developments and policies in China in shaping the global coal market.

    The report also points out that despite the Paris Agreement there is no major impetus to promote the development of carbon capture and storage technology.
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    Coal India Q2 net profit plunges to the lowest level

    Coal India (CIL) registered its lowest quarterly profit for the second quarter of fiscal year 2016-17 (April-March) since its listing, revealed company presentation submitted to Bombay Stock Exchange.

    CIL, the world's largest coal producer, saw its net profit plunged 77.4% to Rs 600.4 crore ($89.01 million) for the period against Rs 2,654.34 crore in the previous corresponding period.

    The company's net income from operations has gone down by 7.8% to 16,212.5 crore in 2016 from 17,489.8 crore in 2015.

    The presentation also revealed that the company's production during the same period fell 3.5% to 104.41 million tonnes and the offtake fell 5% to 115.93 million tonnes.

    Coal India, which produces around 84% of India's total coal, posted a 6.8% drop in net sale to 3,3441.1 crore during July to September from 35,913.34 crore in the same quarter of 2015-16.

    On December 14, CIL's stock slumped to a six-month low, closing at Rs 292.25 ($4.33) per share, down 4.42%.
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    China iron ore falls for second day as rally loses steam

    Chinese iron ore futures dropped for a second session on Thursday as investors pared bullish bets after lifting it, along with steel, to multi-year highs.

    Improved steel supply in parts of China prompted some traders to cut price offers, dragging down rates on raw material iron ore that had piggybacked on the strength in the steel market.

    The most-active rebar on the Shanghai Futures Exchange closed flat at 3,413 yuan ($492) a tonne. Earlier in the session, it fell as low as 3,304 yuan. The construction steel product touched 3,557 yuan on Monday, its highest since April 2014.

    Iron ore on the Dalian Commodity Exchange slipped 1.1 percent to end at 608.50 yuan per tonne. It climbed to a near three-year high of 657 yuan on Monday.

    Both commodities fell on Wednesday despite data suggesting that Chinese banks looked set to lend a record amount this year as Beijing boosts the economy to meet economic growth targets.

    The decline indicates that "investors felt the price had surged too high, too fast," ANZ analysts said in a note.

    China's efforts to curb overcapacity in its steel sector and stimulate economic growth with increased infrastructure spending had fueled an 88-percent rally in Shanghai rebar futures this year.

    But data released on Tuesday showed China's crude steel output rose for a ninth straight month in November, suggesting that Beijing's closure of excess capacity has not stopped mills from producing more to chase rising prices.

    The retreat in futures again pulled back spot iron ore below $80 a tonne after staying above that level for five days.

    Iron ore for delivery to China's Qingdao port .IO62-CNO=MB slid 5.1 percent to $79.18 a tonne on Wednesday, according to Metal Bulletin. The spot benchmark peaked at $83.58 on Monday, its strongest since October 2014.

    An increase in the supply of billet in Tangshan led to prices for the semi-finished steel product dropping late on Tuesday, said Metal Bulletin which tracks Chinese trades.

    Rebar futures followed on Wednesday, which resulted in buyers delaying their procurement plans, it said.
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