Mark Latham Commodity Equity Intelligence Service

Wednesday 7th December 2016
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    US Tax Front and Centre: That import tax.

    The House Republicans’ tax plan to convert the corporate income tax into something akin to a consumption tax looks superficially similar to a tariff but is quite different. Their proposal would apply a border adjustment so that U.S. products would have the tax removed at the border when exported and imports would be taxed. Under the proposal, all goods sold in the U.S. would theoretically bear the same tax, regardless of where they are made, as opposed to tariffs that burden imports selectively.

    House Republican Tax Plan

    The House GOP Task Force on Tax Reform, led by Ways and Means Chairman Kevin Brady (R-TX) and overseen by Speaker Paul Ryan (R-WI), released its “blueprint” tax reform proposal on June 24, 2016. The “blueprint” cuts individual and corporate tax rates, simplifies the tax code, and promotes economic growth.

    The proposal reduces the corporate tax rate to 20%, allows for 100% full and immediate write-off of business investments, and moves towards a purely territorial taxation system in which companies would only pay tax to the U.S. government on earnings that occur within the U.S. This is accomplished via 100 percent exemption for dividends from foreign subsidiaries; a one-time repatriation tax of 8.75 percent for cash and 3.5 percent for everything else; and border tax adjustments going forward whereby imported goods are subject to a tax (equal to the corporate tax rate of 20 percent) and revenues from exports are exempt.

    The tax code would no longer provide U.S. multinational corporations “an incentive to move production overseas because the tax burden would be based on sales within the U.S. regardless of where the goods are produced.”

    The House Ways and Means Committee, led by Chairman Kevin Brady (R-TX), will continue to work out the details of a tax reform plan pursuant to the “blueprint.” Rep. Jim Renacci (R-OH) and other members of the Ways and Means Committee have introduced alternate tax reform plans centered around a consumption tax similar to a value-added tax.

    Replace the Corporate Income and Payroll Taxes with a Consumption Tax

    On the corporate side, this plan eliminates the 35 percent corporate income tax, 12.4 percent Social Security payroll tax on the worker’s first $118,500 of wages, and the 2.9 to 3.8 percent Medicare tax on all wages. These corporate and payroll taxes are replaced with a flat 16 percent value-added tax called the “Business Flat Tax.”

    This 16 percent business tax would differ significantly from the current corporate income tax, perhaps most importantly by making capital purchases fully and immediately deductible (“full expensing”) while eliminating the deductibility of wages. It appears that the the tax would apply to all employers, including non-profits and governments, and no business tax breaks would remain in law.

    Making wages non-deductible has a huge impact on revenue, since it essentially means most wage income would be taxed twice under Sen. Cruz’s plan – once at the business level and again at the individual level. This feature, in combination with full deductibility of all non-wage business expenses (capital investments), effectively makes it a consumption tax. Both the Tax Foundation and Tax Policy Center describe Cruz’s plan as a value-added tax (VAT). Although unlike European-style VATs (Sen. Cruz’s tax would not be imposed at each stage of production nor appear as a tax to consumers), it would be paid by all businesses and passed along in the form of higher prices.

    By abolishing the corporate income tax, the plan would effectively move to a territorial system where future income earned overseas by a foreign subsidiary of a U.S. corporation would not be taxed. The plan would impose a one-time deemed repatriation tax of 10 percent on past profits held overseas, which are currently tax-deferred.

    An Internationally Competitive Corporate Tax SystemThe United States has the highest corporate tax rate in the industrialized world. Given the fact that the United Statesoperates in a global economy in which capital is highly mobile across countries, having the highest corporate tax in thedeveloped world is a recipe for slower growth, weaker investment, and reduced innovation. A high corporate tax ratediscourages foreign businesses from locating and investing in the United States and puts U.S. firms at a competitivedisadvantage with the rest of the world. For these reasons, the OECD states that the corporate tax is the most economicallyharmful type of tax.31A Better Way | 33In addition to making U.S. firms less competitive than their foreign counterparts, the corporate income tax is also a hiddentax on consumers and workers. Part of this has to do with the fact that capital is mobile and labor is relatively immobile.When the corporate tax causes capital to flee the United States in order to seek a better rate of return in a more lightlytaxed jurisdiction, workers in the United States have less capital to work with and are less productive. Over time, this slowsproductivity growth and therefore reduces wages. Moreover, when capital flees it tends to take jobs with it. And those arejust the direct effects – there are indirect effects as well. Although businesses do indeed pay taxes (and a lot of them) theyare generally able to recover those costs by passing them on to consumers through higher prices and on to their employeesthrough lower wages. These effects are so well known that the JCT, the CBO, and the Treasury Department all incorporatethem in some form in their analyses. The JCT, the CBO, and the Treasury Department all conservatively assume that about25 percent of the burden of corporate taxes is borne by labor.32 However, other academic literature finds even higherburdens on labor. For example, one study by the CBO finds that domestic labor bears 70 percent of the burden of thecorporate tax.33 Other research by Hassett and Mathur finds that a 1 percent increase in corporate taxation reduces wagesby half a percent.34 And these effects are only going to grow because the more mobile capital becomes, the more labor willbear the burden.Therefore, lowering the corporate tax rate would have significant economic benefits – faster growth and higher employment,investment, productivity, and wages. One particularly noteworthy example of the benefits of reform comes from a 2013National Bureau of Economic Research (NBER) paper that simulated the repeal of the entire corporate income tax.35 Unlikemany attempts by other economists before them, these economists made an attempt to model the rest of the world in sucha way that they could accurately depict how capital would flow into the United States as a result of corporate tax repeal.According to one of the authors, “fully eliminating the corporate income tax and replacing any loss in revenues withsomewhat higher personal income tax rates leads to a huge short-run inflow of capital, raising the United States’ capital stock(machines and buildings) by 23 percent, output by 8 percent, and the real wages of unskilled and skilled workers by 12percent.”36 Under this scenario, repealing the corporate income tax would generate so much new economic activity in theUnited States that it would finance a third of the revenue lost by repealing the corporate tax. (For perspective, the CBOprojects that the corporate tax will raise $4 trillion in revenue over the next decade).37 Although repealing the corporateincome tax is clearly a pro-growth policy, simply lowering the rate to get closer to the international average would increaseU.S. competitiveness and have similar economic benefits (albeit of a lower magnitude). Moreover, because U.S. rates are sohigh relative to our international competitors, the room for growth is significant.

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    China releases five-year plan for cleaner air, water, soil

    China's State Council has released a national plan on environmental improvements for the 13th Five-Year Plan period (2016-2020), detailing tasks to cleanse polluted air, water and soil.

    The plan set the goals of a more environmentally friendly way of living, considerable reduction of major pollutants, effective control of environmental risks, and a sounder ecological system by 2020.

    To achieve those targets, the State Council asked Beijing, Tianjin and Hebei, as well as regions along the Yangtze River Economic Belt to draw up a red line, or bottom line, for ecological protection by the end of 2017, while other areas should come up with a red line before the end of 2018.

    Consumption of coal, which is a major source of pollution in China, will be strictly controlled.

    Beijing, Tianjin, Hebei, Shandong, regions along the Pearl River and Yangtze River Delta, and the 10 cities with the worst air quality should realize negative growth in coal consumption, according to the plan.

    Specifically, coal use in Beijing, Tianjin, Hebei, Shandong, Henan, and regions along thePearl River Delta should drop by around 10 percent during the 2016-2020 period, while consumption in Shanghai, Jiangsu, Zhejiang and Anhui should fall 5 percent.

    China's environmental protection still lags behind its economic status, and decades of breakneck growth have left the country saddled with problems such as smog and contaminated waterways and soil.

    Northern China has frequently been choked by winter smog, showing the war on pollution is an urgent and arduous task.
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    China sets 2020 target for clean air in big cities

    China aims to provide clean air in its largest cities for 80% of each year, or more than 9-1/2 months, by 2020, up from a figure of 76.7% last year, Reuters reported, citing the country's cabinet.

    Amid concern that pollution was stirring social unrest, China launched a campaign in 2014 to revitalize its tainted air, water and soil, which have been ravaged by more than three decades of breakneck industrial growth.

    The clean air goal for 338 cities was laid out in a five-year development plan on ecological and environmental protection that said China would push structural reforms to cut excess capacity in polluting industries.

    Under the plan, authorities in Beijing, the capital, its neighboring city of Tianjin and the northern province of Hebei, and those along the Yangtze River economic belt will draw up eco-protection "red lines" by the end of 2017.

    Other provinces and cities will have to draw up such "red lines" by the end of 2018, the cabinet said.

    Total coal consumption in Beijing, Tianjin, Hebei, and the eastern Shandong and central Henan provinces will be cut about a tenth during the five-year plan period.

    Consumption in the commercial capital of Shanghai, and the eastern provinces of Jiangsu, Zhejiang and Anhui will be cut by around 5% in the same timeframe.

    Coal consumption in China's Pearl River Delta region will also be cut by a tenth during the period, the plan stated.

    China aims to cut emissions of sulfur dioxide and nitrogen oxide, both gases associated with acid rain, by 15% in 2020, from 2015 levels, it said.

    Chemical oxygen demand, a measure of water quality, will be cut by 10%, while ammonia nitrogen emissions will also be reduced by 10%.

    Last week, the province of Hebei, which borders Beijing, issued its first "red alert" of the year over severe pollution. The highest level alert for smog requires suspension of work in factories, with cars being pulled off the road.
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    British power producer Drax plans to buy Opus Energy for 340 mln pounds

    British power producer Drax plans to buy Opus Energy for 340 mln pounds

    British power producer Drax Group Plc plans to buy energy supplier Opus Energy for 340 million pounds ($434 million) and will also purchase four gas power plant projects as it seeks to diversify across energy markets, it said on Tuesday.

    Drax operates Britain's biggest power station in Yorkshire, which it converted so that 70 percent of the electricity produced comes from biomass rather than coal.

    In its half-year results presentation in July it said it was looking at options to improve earnings and diversify across markets it operates in - wood pellet supply, power generation and retail.

    As part of that process the company said it "has entered into a conditional agreement" to buy Opus Energy and would also pay 18.5 million pounds to buy four open cycle gas turbine (OCGT) development projects to diversify its power generation mix.

    Opus Energy is Britain's sixth-biggest business energy supplier, providing electricity and gas to over 260,000 UK locations.

    Drax said that five of its shareholders, representing more than 45 percent of its issued share capital, have said they will support the purchase of Opus.

    In a separate deal Drax will buy four OCGT projects which have a total capacity of around 1.2 gigawatts, it said.

    "The acquisition of four OCGT development projects ... will play an important role in helping government meet their ambition of new gas generation," Drax's Chief Executive Dorothy Thompson said in a statement.

    Britain faces a supply crunch over the coming winters as nuclear reactors age and coal plants are forced to close by 2025. The government is trying to encourage new gas plants to be built to help plug the supply gap.

    Drax said it could convert more units at its plant in Yorkshire to biomass from coal "with the right conditions".

    The company said it still expects full-year EBITDA to be around the bottom of the range of current market forecasts.

    Market forecasts were for 146-185 million pounds in July.

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    China shuts small scale recycle steel furnaces.

    During a onsite survey November 24-27 in Xuzhou, Lianyungang and Suqian, Jiangsu Province,the State Council’s environmental protection team founded low-quality steel (hereinafter means low-quality steel using scrap steel as raw material, which is melt by induction furnace or rolled steel produced with such low-quality steel) and illegal steel capacity, so executed rectification on such capacities, mainly intermediate frequency furnaces. A few plants using intermediate frequency furnaces in northern Jiangsu have been dismantled. Power supply for plants using intermediate frequency furnaces in northern Jiangsu was cut off to suspend their production. Some intermediate frequency furnaces in southern Jiangsu were also forced to cease production.

    Intermediate Frequency Furnace Not Equal to Low-Quality Steel

    Intermediate frequency furnace is a type of electric induction furnace, which uses scrap steel as raw material, with low investment, low volume and simple production requirements. It is mainly used to produce rebar, or a small part of section and strip steel.

    Economic and trade industry letter 2002 (156) defined that low-quality steel means steel using scrap steel as raw material and melt with induction furnace, whose ingredient and quality is difficult to control and rolled steel produced with the former.

    Low-quality steel can be defined by quality and production requirements:

    1. Product quality is poor, and does not have the mechanical properties of ordinary steel, with low strength, stiffness and melting point, and porosity, and is easy to break 2. Chemical composition is disordered, and can not play its due role.

    Intermediate frequency furnace’s steelmaking technique and quality of scrap steel used to produce steel have improved noticeably. Some steel plants using intermediate frequency furnaces purify by oxygen and argon blowing, or using refining devices. Some plants equipped environmental protection facilities this year given strict environmental protection requirements. Low-quality steel produced by these regular steel plants using intermediate frequency furnace still differs from that produced by small workshops.

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    Oil and Gas

    Arab producers to keep Asia term crude oil, apply OPEC cut to extra supplies: sources

    Major Arab oil producing countries are looking to keep their term crude supplies into Asia at least for January loadings, while coping with OPEC's production cut agreement first with their incremental supply volumes, sources with direct knowledge of the matter said Monday.

    A number of major Arab oil producers told S&P Global Platts that producers intend to keep their term crude supply volumes with Asian customers and implement last week's OPEC agreement with their incremental supply volumes where necessary.

    The Arab producers' intended move came to light as some Asian refiners were trying to assess if OPEC's announced production cut would go beyond the tolerance flexibility clause in their term contracts with Middle East suppliers.

    While major national oil companies in the Middle East sell the majority of their crude production on a term basis, there are typically incremental volumes sold to refiners on a case by case basis.


    With OPEC looking to maintain its policy of keeping market share balanced by cutting surplus oil supplied into the market, national oil companies are seeking to minimize any impact to their key buyers across Asia, sources said.

    "Most [term] contracts [have been] renewed already [for 2017], [I] don't think the term commitments will be affected," a source at a national oil company within the Gulf Cooperation Council said.

    This was echoed by another major oil producer within the GCC. "We are still working through [the cuts] right now, we will protect the term [sales] the rest [incremental sales] will not be possible [due to the cuts]," the source said.

    A source at another GCC member state's national oil company noted that they had been preparing for the potential of an OPEC cut for a number of months and there should be no major impact on key term buyers.

    "At least for the core countries...[those within the] GCC - have been preparing [for a cut] for quite a while...[the cuts] should be factored in for those countries," the source said.

    "[We will] work on the tolerance it should be ok [it] won't affect any term volume" the source added

    A source at another GCC national oil company said: "Each member has to do his own way [implement the cuts]... we haven't decided anything [yet] it's too soon."


    Sources at refiners in Asia said Monday the companies do not see any impact on their term crude loading volumes with Middle Eastern suppliers so far in January.

    "We have been told that our term allocation for January will be executed as contracted," said an Asian refiner source but added that it would still need to keep an eye on a possible 5% cut in its operational tolerance supply volumes.

    Another Asian refiner source said the refiner does not see any immediate impact from OPEC's cut on its term and spot crude procurements for January.

    "We have not got received any notice on a term supply cut," the source said.

    OPEC's decision on November 30 to hold production at 32.5 million b/d starting January 1, 2017 -- the first coordinated cut since the depths of the global financial crisis in 2008 -- amounts to an approximate 1.2 million b/d cut from the producer group's current output levels. The deal exempts Libya and Nigeria and is contingent on key non-OPEC producers also agreeing to cut 600,000 b/d in total.
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    Saudi Arabia cuts Jan oil price to Asia to 4-month low to keep market share

    Saudi Aramco has cut the January price for its Arab Light crude for Asian customers to the lowest in four months as it holds to a strategy of preserving market share in the world's fastest-growing demand centre.

    The price cuts are meant to ensure that Aramco can still sell more oil into Asia even after going along with the Opec-Russia deal to cut output. The Saudis have been struggling over the last two years to fight off increased competition from other producers in the Middle East, Russia and the Atlantic Basin.

    Saudi Aramco said on Tuesday it cut the price of Arab Light crude sales to Asia by US$1.20 a barrel versus December to a discount of US$0.75 a barrel to the Oman/Dubai average.

    January's price cuts of US$0.60-US$1.50 across all Saudi crude grades are small compared with a near US$10 a barrel gain in global benchmark Brent futures in the past week. Brent hit 16-month high on Monday after Opec and Russia struck a deal last week to cut production from January.

    "Ahead of the Opec cut, producers are pumping at maximum output, so they must price to sell," said a trader with a North Asian refiner who declined to be named due to company policy.

    Russian oil production hit an all time high in November, according to official energy ministry data, while a Reuters survey found that output from the Organization of the Petroleum Exporting Countries (Opec) was also at a record for the month.

    Prior to the Opec output deal, Saudi Aramco agreed to supply some customers in Asia with additional oil that will load in January to help them meet winter demand.


    The company raised its Arab Light OSP to Northwest Europe by US$0.30 a barrel for January from the previous month at a discount of US$4.20 a barrel to the Brent Weighted Average (Bwave).

    The Arab Light OSP to the United States was set at a premium of US$0.05 a barrel to the Argus Sour Crude Index (ASCI) for January, down US$0.30 a barrel from the previous month.

    Because the Brent to Dubai Arab Light prompt month spread rose to US$3.15 a barrel from US$2.55 after the Opec deal, Saudi Arabia had more leeway to raise their OSPs to Europe and remain competitive, said Jeff Quigley, Energy Markets Director at Stratas Advisors, a Houston-based consultancy.

    "They are trying to capitalise on the Opec deal-driven price increase in Europe while not losing market share in Asia," Mr Quigley said.
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    Iran floating storage



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    India pushes Nigeria for more oil term contract volumes

    Indian state-run oil refiners have called for Nigeria to increase its total term contract volumes next year by more than 20% as demand from the South Asian country climbs, an official from Nigeria's state-owned Nigerian National Petroleum Corporation said.

    This request comes a few weeks before Nigeria's crude oil term lifting contracts for 2017 are finalized, which will be decided by mid-December.

    India as the largest buyer of Nigerian crude, has always said it should have a longer-term arrangement with NNPC to ensure security of supply.

    "Three Indian companies mentioned that they are looking for a combined total of 11 million mt [in 2017] from 9 million mt [this year]," Anibor O. Kragha, group executive director at NNPC, told S&P Global Platts in an interview on the sidelines of the Petrotech conference in New Delhi late Monday.

    "Now what they will get is a balance between term contracts and [spot] sales contracts," he added.

    The Nigerian crude oil term contracts involve the export of around 1.17 million b/d of Nigerian crude, out of the 2.2 million b/d the country can theoretically produce. They are then sold by contract holders to end-users, refiners and other buyers.

    But with Nigerian oil output sharply down due to renewed militancy, the term volumes could be much lower for 2017 if output does not rebound.

    Nigerian oil output had recovered sharply after it fell to a 30-year low in early summer but renewed attacks on oil infrastructure in the Niger Delta have shut in production of popular export grade Forcados in the past month.

    Total oil and condensate production was around 1.9 million b/d, including 300,000 b/d of condensates, oil minister Emmanuel Kachikwu said last week.

    He said output could reach 2.2 million b/d if the militancy issues were resolved by early next year. NEGOTIATIONS ONGOING

    Kragha said that negotiations are ongoing and that he was not sure if the deal would materialize, but he added that once Nigerian output recovers, it will "increasingly look towards India" as the major buyer of its crude.

    "Indian demand is very positive for us. A vibrant Indian economy is good for us," he said.

    The two countries have been working on a memorandum of understanding in the past month to enable the participation of Indian companies in Nigeria's upstream and downstream oil and gas sectors.

    The deal being negotiated by Nigeria will also have the Indian government make an upfront payment for the purchase of Nigeria's crude on a long-term basis as well as Indian public sector companies investing in Nigerian refineries.

    Indian state-owned refiners tend to buy most of their crude on term contracts while their remaining requirements are sought via tenders.

    "We just came out of a meeting with key Indian oil companies and they are pushing to get incremental allocations for the term contracts," said Kragha. "We explained to them that there needs to be a balance." INDIA'S RELIANCE ON NIGERIAN CRUDE

    India is a significant buyer of Nigerian crude, which is largely light and sweet, rich in gasoline and diesel and low in sulfur, and meets the needs of Indian refiners.

    State-owned refiners like Indian Oil Corp, Bharat Petroleum Corp Ltd and Hindustan Petroleum Corp Ltd are major regular buyers of Nigerian crudes like Qua Iboe, Bonny Light, Escravos, EA Blend, Erha, Usan and Agbami.

    A source from an Indian refiner told Platts that Nigerian crude is a must for most of its refineries, especially the older ones, which have been designed to run light sweet crudes.

    "Despite all the militancy issues, we still buy Nigerian crude, as our refineries need it. We will continue to buy Nigerian crude, but we want them to supply us with more," he said.

    India, which is currently among the world's fastest growing economies, has seen its gasoline and gasoil demand climb sharply over the past few years. This has encouraged Indian refineries to buy more Nigerian crudes.

    In 2015-16, India imported nearly 23.7 million mt of Nigerian crude, nearly 12% of India's overall oil imports, according to official Indian data.

    The South Asian country also imports some 2 million mt/year of LNG from Nigeria.

    Every month almost 20-25% of total Nigerian crude exports travel to India, particularly to IOC, which is the main recipient of Nigerian crude.

    Indian refiners like IOC, HPCL and BPCL are currently on crude oil term lifting contracts for 2016 with NNPC.
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    Frigstad exits deepwater rig market

    Offshore drilling contractor Frigstad Offshore has decided to exit from an investment in Frigstad Deepwater’s newbuilds to position itself for the industry recovery, the company said on Tuesday.

    Frigstad Deepwater Holding Ltd, a subsidiary of Frigstad Offshore Group, has decided to sell all of its shares in Frigstad Deepwater Ltd to a subsidiary of China International Maritime Containers Group (CIMC) with effect from December 6, 2016.

    Frigstad Deepwater Ltd, which has been jointly owned by Frigstad Offshore Group and CIMC since 2012, has two 7th generation ultra deepwater drilling units of the Frigstad D90 design under construction at the Yantai CIMC Raffles shipyard in Shandong, China. The units, Frigstad Shekou and Frigstad Kristiansand, are scheduled for delivery in 1Q 2017 and 3Q 2017, respectively.

    As a consequence of Frigstad Offshore’s exit, Frigstad Deepwater will become a wholly owned subsidiary of CIMC and be renamed “CIMC Bluewhale Rig Ltd”. The operational management of the rigs will be taken over by Bluewhale Offshore Pte Ltd, also a subsidiary of CIMC, and the rigs will be renamed Bluewhale I and Bluewhale II. A team from Frigstad Offshore, the current manager of the rigs, will continue to supervise the construction of the two rigs until completion, the company said.

    Challenging market

    Harald Frigstad, Chairman and founder of the Frigstad Group, says in a comment: “The ultra deepwater market has been extremely challenging for a while and we have agreed with CIMC that it is in the best interests of both parties that our group exit from the investment in Frigstad Deepwater Ltd at this moment. We are doing this on friendly terms and will remain a close partner of CIMC also in the future. Our exit from Frigstad Deepwater Ltd gives us a good foundation to position the Frigstad Group for the industry recovery which we believe will come.

    “As part of this, we are reorganizing the group and strengthening the organization in key areas, which includes expansion at our office in Kristiansand, Norway. We are investing heavily in research and development, and will be launching the next generation of our ultra deep‐water semi‐submersible rig design in 2017 to keep up with industry requirements for new technology and higher efficiency. We strongly believe that offshore oil and gas will still play a very important role in the global energy supply for a long time, and we will be a part of this promising industry in the years to come, both as rig designer and drilling contractor.”
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    Indonesia cuts gas prices for some companies from 2017 - energy ministry

    Indonesia on Tuesday told energy companies to cut natural gas prices for fertilizer, steel and petrochemical industries starting Jan. 1, 2017, in a renewed effort to bring down domestic gas prices.

    Earlier this year, the government had introduced regulations to cut domestic gas prices to help to spur economic growth and improve the competitiveness of domestic industry.

    But some contractors have continued to sell natural gas above the price the government had planned for, according to government data.

    New rules from the energy ministry published on its official website on Tuesday, require gas contractors like PT Pertamina EP and Kangean Energy Indonesia Ltd, among others, to use new price formulas for contracts with PT Krakatau Steel Tbk, PT Petrokimia Gresik and several fertilizer makers.

    Based on the new formulas, gas buyers would only pay around $6 per million British thermal units (mmBtu), compared to a range of prices they currently pay of between $5.73 to $7.54.

    There will be no change for companies with contract terms already below $6 per mmBtu.

    Suryaningsih, a senior official at the ministry's directorate general of oil and gas, said the new formulas would mean less revenue for gas producers as well as the government, but "all contractors have agreed."

    There were no more details available on how much revenue gas companies and the government could expect to lose.

    "(Gas) contractors are asked to make their operational costs more efficient in order to maintain their businesses' viability and their return of investment," the energy ministry's spokesman Sujatmiko said.

    In addition to cheaper gas prices, Krakatau Steel and Petrokimia Gresik will also get a reduction in transport fees for their gas purchase.
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    India to get three more LNG terminals on east coast

    New Delhi: India expects to build three more liquefied natural gas (LNG) terminals on its east coast, a senior oil ministry official said on Tuesday, as the country tries to increase consumption of the cleaner-burning fuel.

    A.P. Sawhney of the Oil and Natural Gas Corporation (ONGC), said the three new terminals will be located at Ennore, Kakinada and Dhamra ports on the east coast. Sawhney was speaking at the Petrotech energy conference in New Delhi.

    The country was also looking at reviving stranded gas-based power generation capacity, Sawhney said.
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    RasGas says seeing preference for short term LNG contracts in India

    Qatar's RasGas is seeing preference for short-term LNG contracts from customers in India, its chief executive said on Tuesday at the Petrotech energy conference in New Delhi.

    Hamad Mubarak Al Muhannadi also said that India needs more LNG terminals to unlock demand. Asia's third-largest economy will become the world's second-largest spot and long-term LNG buyer this year, Muhannadi said.
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    Venezuela says Shell to provide $400 million financing for oil venture

    Royal Dutch Shell Plc will provide some $400 million in financing to boost oil output at Venezuela's Petroregional del Lago, a joint venture with state-run PDVSA, the South American country announced on Tuesday.

    Petroregional, which operates the Urdaneta oilfield in Venezuela's western Maracaibo Lake, produces between 30,000 barrels per day and 35,000 bpd, according to Shell's website. Shell holds a 40 percent stake in the venture.

    The agreement aims to increase total production to 344 million barrels between the 2017 and 2035 period, PDVSA said in a statement, or an average of around 52,400 bpd.

    "As a minority partner, (Shell) has decided to start a financing of $400 million for the joint venture we have in the lake," Venezuela's oil minister and PDVSA president, Eulogio Del Pino, said in an interview broadcast over PDVSA's radio station.

    Shell did not immediately respond to a request for details on the financing arrangement.

    Recession-hit OPEC nation Venezuela is seeking to recover its oil production after a nearly 10 percent tumble in output this year. Operations have been crimped by a lack of investment, shortages of equipment and spare parts, a brain drain, and crime.
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    Glencore raises money for Kurdish oil deal, likely short of target: sources

    Glencore will likely fall short of its target of raising $550 million to pre-finance the purchase of Kurdish oil, with investors exercising caution despite the offer of a 12 percent bond yield, industry sources told Reuters.

    Two sources familiar with the plans said that commodities giant Glencore will price the bond at 12 percent on Tuesday, having received investor commitments for between $200 million and $400 million. Glencore would have to cover the rest itself, though there is no obligation to hit the full $550 million.

    European traders contending with a protracted oil industry downturn have targeted Kurdish oil since the government of the autonomous Kurdish region in Erbil began selling independently from Baghdad.

    The oil has been relatively cheap because of potential supply disruptions and the opposition of Iraq's central government to independent Kurdish oil sales, though Baghdad has softened its tone on Erbil in recent months.

    Rivals such as Vitol, Petraco and Trafigura have lent Erbil about $2 billion in total, to be repaid in oil. The traders have borrowed from banks and lent it to Erbil at their own risk.

    Glencore also loaned $300 million to Erbil this year, with the money repaid by way of one mid-sized oil cargo a month, worth about $25 million.

    The new bond should allow Glencore to split the risks by selling debt notes to a small number of investors and hedge funds who specialize in high-risk, high-yield investments and emerging markets.

    Technically, the money would be raised by a special-purpose vehicle and the debt will be non-recourse, meaning that Glencore will not be liable should problems occur.

    Glencore has told investors it expects to enter a new five-year agreement with the government of Kurdistan to buy its crude, with deliveries rising from one cargo in January, to two in February-March, four in April and six from May onwards.

    Six cargoes a month would represent a quarter of overall exports from Kurdistan. Industry sources have said that Kurdistan has yet to finalize its export plans for 2017.

    Glencore declined to comment.

    Kurdistan exports its oil via the Turkish Mediterranean port of Ceyhan. Flows have been running at more than 600,000 barrels per day since September after being occasionally disrupted in 2015 and at the start of this year by militant attacks in Turkey and Kurdistan.
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    New Spot Market Aims to Make Trading Gas More Like Oil

    Two U.S. exchanges plan to launch derivatives that could make it easier to trade shipped gas, potentially revolutionising this market in the way that the Brent and West Texas Intermediate benchmarks did for crude oil, according to people familiar with the matter.

    The moves by CME Group Inc. and Intercontinental Exchange Inc.come as increasing shipments of liquefied natural gas from the U.S. and elsewhere have helped create a spot, or short term market, for this commodity, which is transported on ships in liquid form.

    Having a spot market makes it easier to launch futures contracts, which will attract a wider pool of investors while offering the sort of real-time prices currently available in oil, gold and many other major commodities. Companies and investors use commodities-futures markets to speculate on the price of a commodity and to hedge its risk against turns in the market.

    Currently, buyers and sellers mainly agree to yearslong LNG contracts priced off oil, gas that is piped, and price reporting agencies’ data. There is no global price benchmark for LNG.

    Since the late 1990s, the majority of the world’s oil has been priced off Brent, the international benchmark, and WTI, its U.S. equivalent. There are already several benchmarks for pipeline gas including the U.S.’s Henry Hub and Europe’s NBP and TTF markets.

    In LNG, “you’re seeing an evolution toward more market-based pricing, but there hasn’t been that real consolidation around a couple of benchmarks yet,“ said Jason Feer, head of business intelligence at consultancy Poten & Partners. ”Oil was a fragmented market and then over time it consolidated around Brent and it consolidated around WTI,” he said.

    To be sure, companies have already tried before to create LNG pricing benchmarks with limited success, including Japan OTC Exchange and the Singapore Exchange, better known as SGX.

    But industry analysts say that the chance of success is greater with an increasingly large spot market underpinning the futures contract—an agreement to buy or sell an underlying asset.

    The CME wants to launch a futures contract next year underpinned by U.S. Gulf Coast LNG exports, two people familiar with the matter said. ICE is also working on a U.S. Gulf Coast LNG futures contract, one of the people said.

    Peter Keavey, managing director of energy products at CME Group, declined to comment on specific plans, but said the exchange is constantly talking to its customers about new products.

    "There’s definitely an interest in creating a liquid and transparent spot market and then further down the road, from an exchange standpoint, a liquid futures contract would have to follow that liquid spot market,” Mr. Keavey said.

    That spot market is being driven by a number of factors.

    For a start, there is just more gas being consumed. Gas is expected to make up around one quarter of the world’s primary energy mix by 2040, up from around a fifth, according to the International Energy Agency. New buyers, including Jordan, Egypt and Pakistan emerged in 2015. Meanwhile, supply has exploded, mainly due to the U.S. shale boom and through new projects in Australia.

    Earlier this year, Cheniere Energy Inc. exported the first U.S. LNG in decades through a terminal it converted for this purpose in Louisiana.

    At least another four LNG export terminals are expected to start up on the U.S. Gulf coast in the next three years. That would bring U.S. capacity to over 60 million metric tons annually, compared with the world’s top exporter Qatar’s 77 million metric tons a year.

    Energy major BP PLC predicts LNG will overtake pipeline gas as the dominant form of traded gas within the next two decades.

    “The market will need to evolve and come up with different pricing mechanisms,” said Anatol Feygin, Cheniere’s chief commercial officer.

    The new pool of gas and people to buy it has created a more actively traded spot market.

    The spot market, defined as cargoes delivered within 90 days of a sale being agreed, made up around 15% of LNG trade in 2015, according to the International Group of Liquefied Natural Gas Importers.

    There are signs that spot trades rose sharply this year. Bookings of LNG ships for less than a year—one indicator of spot market activity—have risen by 60% for the January-August period, compared with the same period last year, according to data from gas-shipping company GasLog Ltd.

    Another factor boosting the LNG spot market is the growing participation of large trade houses. These giant commodities traders also helped create a global spot market in oil in the 1980s, earning U.S. trader Marc Rich the title ’the king of oil.’

    Trade houses, including Trafigura Group Pte., Vitol Group and Gunvor Group, are buying and selling LNG in the spot market, adding liquidity.

    “Traders have made a difference in boosting liquidity, we’re not the only factor but we’ve played a role,” said Hadi Hallouche, head of LNG at Trafigura.
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    Investors Are Pricing Junk-Energy Bonds Like $80 Per-Barrel Oil Is Back

    Investors are treating high-yield bonds issued by energy firms like it's the good old days for black gold. Yields on the securities have have dropped to 6.73 percent, a level last seen at the end of 2014 when oil was trading around $80 a barrel.

    "The market seems to be pricing in perfection for a number of reasons," according to Bloomberg Intelligence Senior Credit Analyst Spencer Cutter. "Part of it has just been the reach for yield throughout the entire fixed-income market, so even bonds from distressed credits get bid up," he said. Add to that the fact that drilling costs are falling, and the sustained (if modest) recovery in oil prices is causing some to bet that the worst is over.  

    "There was a view back in the first quarter when it felt like the world was going to end, and that given how much carnage there had been in the sector eventually things would bounce back, and being long energy bonds was at some point going to be the play of a career," Cutter said. Companies including Halcon Resources Corp. and Linn Energy LLC went bankrupt in the first half of 2016 and were removed from the index, he said, meaning their bonds are no longer dragging the index down.

    Investors' embrace of riskier energy debt is likely to make life easier for oil and gas companies that had found themselves shut out of markets when oil prices plummeted — but they might want to hurry and get those deals done.

    "There are a lot of things that have to go right to justify the market being where it is today," Cutter said. "If those expectations or assumptions don't come to pass, then there could be another wave of restructuring in a year or two," he concluded.
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    In mammoth task, BP sends almost 3 million barrels of U.S. oil to Asia

    Oil major BP is shipping almost 3 million barrels of U.S. crude to customers across Asia, pioneering a lengthy and complex operation likely to become more popular after OPEC last week announced deep production cuts.

    BP's efforts, involving one of the world's longest sea routes, seven tankers and a series of ship-to-ship transfers, underscore a desire among oil traders to develop new routes to sell swelling supplies of cheap U.S. shale oil to Asia, the world's biggest consumer region.

    While exports of U.S. crude have been allowed since a 40-year ban was lifted a year ago, the distance, cost and complexity of shipping to Asia has so far kept the flow to a trickle.

    Now, using its global shipping and trading network, BP was able to grapple with U.S. port limitations and the need to transfer oil between ships off Malaysia to split cargoes for customers across Asia, according to trade sources and shipping data in Thomson Reuters Eikon.

    "Keeping regional price differentials, different tanker rates, and the forward price curve in mind while considering the delivery needs and schedules of your counterparties is not something many oil trading firms can do," said a shipping source in Singapore, who had knowledge of the operations.

    "BP is one of perhaps half a dozen firms capable of doing so," he added, speaking on condition of anonymity as he was not authorised to publicly discuss operations.

    BP declined to comment.


    While BP's operations are currently the most sophisticated, others have also begun developing U.S./Asia trade.

    China's Unipec, the trading arm of Asia's largest refiner Sinopec, is shipping about 2 million barrels of WTI to China this month, while trading house Trafigura is also exporting some 2 million barrels of U.S. oil to Asia.

    Incentives to bring U.S. crude into Asia have risen after the Middle East-led producer club of the Organization of the Petroleum Exporting Countries (OPEC) and Russia agreed to cut output, encouraging refiners across the region to seek alternatives to offset potential supply shortfalls.

    "OPEC is putting U.S. shale oil to the test... (and) we will truly see what it can deliver," said Bjarne Schieldrop, chief commodity analyst at SEB. He predicted 2017 would be a "shale oil party" with a surge in U.S. exports after the OPEC production cuts.


    BP's operations to Asia kicked off in mid-September, when it chartered the large Suezmax-class tanker Felicity to load crude from the smaller Aframax-class vessel Eagle Stavanger in the Galveston Offshore Lightering Area (GOLA) off Texas.

    Days later, also at GOLA, BP transferred oil from three Aframax-class tankers to the C. Excellency, a Very Large Crude Carrier (VLCC).

    The transfers were necessary as American ports cannot load oil on the biggest tankers.

    A VLCC can carry 2 million barrels of oil, enough to meet two days' worth of Britain's consumption, while a Suezmax and an Aframax can load 1 million barrels and 800,000 barrels, respectively.

    Too big for the Panama Canal, the Felicity and C. Excellency sailed around South Africa to the Linggi International Transhipment Hub in Malaysia where their cargoes were split up again for delivery across Asia-Pacific.

    In late October, the Felicity transferred part of its oil to the smaller Aframax Taurus Sun, which then delivered 300,000 barrels of WTI Midland crude to Thailand, according to shipping data.

    The C. Excellency received the rest of the Felicity's cargo in Malaysia, then transferred oil to Aframax-class British Gannet in November.

    On Wednesday, shipping data shows that the British Gannet docked at BP's Kwinana refinery in Perth, Australia to make its final delivery. The cargo will have travelled more than 16,000 nautical miles (30,000 km) from GOLA.

    Meanwhile, C. Excellency received some fuel from another super-tanker, the Gener8 Andriotis, and this week headed to Sriracha in Thailand to deliver 300,000 barrels of WTI, shipping data showed. Sources involved with the shipment said some of that oil would likely proceed to Japan.

    While BP's operation stands out size and complexity, more long-haul trades are likely.

    "As Middle East producers and Russia are due to cut their output, large crude buyers (in Asia)... will likely import an incremental amount from longer-haul sources," said Erik Nikolai Stavseth from Norway's Arctic Securities.
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    US EIA lowers expected 2017 gas marketed output to 79.94 Bcf/d

    The US Energy Information Administration Tuesday lowered its natural gas marketed production estimate for 2017 by 310 MMcf/d to an average 79.94 Bcf/d.

    Gas production is forecast to average 77.5 Bcf/d in 2016, a 1.3 Bcf/d decline from the 2015 level, marking the first annual decline since 2005, the agency said in its December Short-Term Energy Outlook. But EIA expected production to pick up starting in November because of drilling activity increases and new infrastructure coming online to bring gas to demand centers.

    "In 2017, forecast natural gas production increases by an average of 2.5 Bcf/d from the 2016 level," the agency said.

    The agency raised its projections for gas marketed production for the fourth quarter by 450 MMcf/d to 76.89 Bcf/d, and raised its full 2016 estimate 150 MMcf/d to average of 77.48 Bcf/d.

    For the Q4, EIA lowered its estimate for US natural gas consumption by 1.33 Bcf/d to 75.57 Bcf/d.

    The agency said that demand for US gas for 2016 is expected to average 75.22 Bcf/d -- 44 MMcf/d below last month's estimate -- compared with 74.65 Bcf/d in 2015.

    The report noted, however, that natural gas consumption for December 2016 through March 2017 is likely to be 4% above the same time last year, driven by temperatures projected to be 3% higher than normal but still 13% below the same period a year earlier.

    Turning to prices, EIA raised its Q1 2017 Henry Hub spot natural gas price forecast to $3.36/MMBtu, 11 cents above its estimate in November, even as it lowered its Q4 estimate 6 cents to $2.93/MMBtu.

    The agency noted that warmer-than-normal weather in the first half of November helped push inventories to near-record levels. Spot prices "were more greatly affected by the record-high inventories and fell by a larger percentage than the futures price," the report said.

    "US natural gas inventories were at their highest level ever at the beginning of the current heating season, but stronger gas demand this winter and increased exports are expected to reduce natural gas inventories to more normal levels by the end of winter in late March," EIA Administrator Adam Sieminski said in a statement.

    The report reflected upon price volatility in the futures market in November, and it attributed the wide range of prices seen in November to market players balancing the current high inventory "with expectations of narrowing supply and demand fundamentals going forward."

    EIA said Henry Hub prices are projected to average $2.49/MMBtu in 2016 and $3.27/MMBtu in 2017. The 2016 projection was down 1 cent from the estimate in last month's report, while the 2017 projection was up 15 cents.

    "Growing domestic natural gas consumption, along with higher pipeline exports to Mexico and liquefied natural gas exports, contribute to the Henry Hub natural gas spot price rising from an average of $2.49[/MMBtu] in 2016 to $3.27/MMBtu in 2017," the report said.

    On the power side, Sieminski noted that more US electricity is expected to be generated from coal than gas this winter, but he said the share of total annual generation from gas is forecast to exceed coal during 2016 and 2017.

    The report projected that gas will continue to make up an average of 34% of total US utility-scale power generation this year, while the share from coal will average 30%. In 2017, EIA estimates that gas and coal will generate 33% and 31% of electricity, respectively.

    In all, the agency predicted power from utility-scale plants in the US will tick up 0.2% this year from 2015, to reach 11.2 TWh in full-year 2016.
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    Suncor Energy successfully resolves $1.3 billion tax dispute with Canada Revenue Agency

    Suncor today reports that the Tax Court of Canada has issued a favourable Order resolving the previously disclosed dispute with the Canada Revenue Agency (CRA). The dispute was in regards to the income tax treatment of realized losses in 2007 on the settlement of certain derivative contracts.

    The Tax Court Order confirms the successful resolution of this matter between Suncor and the CRA, resulting in no additional taxes, interest or penalties. Suncor's original filing position on this issue is therefore maintained and all taxation matters related to this issue are now closed.

    As is customary in disputes of this nature, Suncor had provided security to the CRA and the Provinces of Quebec and Ontario for approximately $657 million in respect of this issue. The company is taking steps for the return of this security.
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    New England natural gas pipeline capacity increases for the first time since 2010

    Spectra Energy Corporation has almost completed the first two natural gas pipeline projects in New England since 2010. On November 1, Spectra placed part of the Algonquin Incremental Market (AIM) project into service, following the late-October approval from the Federal Energy Regulatory Commission (FERC). The remainder of the project is expected to be completed this month. Spectra placed another pipeline project—Salem Lateral—into service on October 28, according to PointLogic Energy, but it is not expected to be used until June 2017.

    The $972 million AIM project will bring additional natural gas from the Appalachian Basin into New England. The project is the largest pipeline project since 2007 to transport natural gas into New England from outside the region. The pipeline will provide an additional 342 million cubic feet per day (MMcf/d) of pipeline capacity to the New England market.

    The $63 million Salem Lateral Project will provide capacity for the Salem Harbor Power Plant, a converted coal-to-gas electric power plant due to be in service in June 2017. Once completed, the 674 megawatt power plant will use up to 115 MMcf/d of natural gas to generate electricity for New England consumers.

    The AIM project entered commercial service in November 2016 and added capacity to a constrained New England pipeline infrastructure system ahead of upcoming winter demand and ahead of the anticipated increase in demand from the Salem Lateral project.

    The increase in pipeline capacity is expected to continue offsetting decreasing natural gas imports into New England. Liquefied natural gas (LNG) imports into New England have typically met a significant portion of natural gas demand, but they have declined because of a variety of market conditions, including demand for LNG from other markets, and the expiration of previous long-term LNG contracts. LNG shipments to the Algonquin Northeast Gateway Lateral project (built in 2007 to deliver regasified LNG into the metropolitan Boston and New England market) and shipments to the LNG terminal in Everett, Massachusetts (built in 1971) have decreased over the past several years.

    For many years, some points along the natural gas pipelines in New England have reached full capacity utilization rates during the winter months. The Algonquin Gas Transmission pipeline is the major pipeline delivering Appalachian gas into New England. Even as capacity has remained relatively flat, deliveries have been growing since 2010 because the pipeline has been operating at capacity for a longer portion of the winter season and higher levels of summer use. Over the past several years, natural gas flows through the Stony Point compressor station—a key entry point for natural gas destined for New England—have reached their operating capacity throughout the year, even in non-winter months.

    New England natural gas pipeline constraints have contributed to relatively volatile natural gas spot prices. Average monthly natural gas prices at the Algonquin Citygate, a trading hub indicative of Boston wholesale natural gas prices, reached $15 per million British thermal units (MMBtu) during the winters of 2013 and 2015 and $25/MMBtu during the winter of 2014.

    For the nation as a whole, 10 U.S. natural gas pipeline projects have been completed or are expected to be completed before the end of 2016. In all, nearly 5.9 Bcf/d of additional pipeline capacity will be placed in service throughout 2016. More information about existing natural gas pipeline infrastructure is available in EIA's spreadsheet of State-to-State Capacity. Projects that are planned or under construction are listed in the Pipeline Projects spreadsheet.
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    Alternative Energy

    Japan's CO2 emissions drop 3pct to 5-yr low in FY2015

    Japan's greenhouse gas emissions fell 3% to a five-year low in the financial year through March due to lower power demand, growing renewable energy and the restart of nuclear power plants, government figures showed on December 6.

    Emissions fell for a second straight year to 1.321 billion tonnes of CO2 equivalent, hitting the lowest since fiscal 2010, according to Ministry of Environment preliminary data.

    Japan's emissions rose after the March 2011 Fukushima disaster that led to the closure of nuclear power plants and an increased reliance on coal.

    The world's fifth-biggest carbon emitter, Japan, has set a goal to cut its emissions by 26% from 2013 levels by 2030, and last month ratified the 2015 Paris Climate Change Agreement to prevent climate change.

    The 2015 figure was down 6.0% from 2013, due to power saving and a cooler summer and warmer 2015/2016 winter.

    Wider use of renewable energy in the wake of Fukushima and the restart of Kyushu Electric Power's two reactors at Sendai nuclear power station also lent support, said Madoka Konishi, chief official at the ministry's low carbon society promotion office.

    Two of Japan's 43 reactors were restarted during the year through March 2016, marking the nation's first nuclear power generation since September 2013.

    Currently, only two reactors are generating power and the pace of restarts has been slower than many expected as all units need to be relicensed after being idled in the wake of the meltdown at Tokyo Electric Power's Fukushima Daiichi nuclear plant in March 2011.
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    Precious Metals

    Barrick Gold says Latam key to growth as it adds director

    Latin America will play an increasingly important role in Barrick Gold's growth strategy, the world's biggest gold miner said on Tuesday as it named a new director with decades of mining experience in that region.

    The company said it had appointed Pablo Marcet to its board.

    Marcet worked for 15 years for global miner BHP Billiton and was president of Northern Orion Resources' South American operations before the company was acquired by Yamana Gold.

    "Mr. Marcet's deep operational and geopolitical experience in Latin America will be a vital asset as the company evaluates new investments in the region," Toronto-based Barrick said.

    Several of Barrick's biggest gold projects are in Argentina and Chile, including the large, stalled Pascua-Lama venture, its more recent Alturas discovery and the Cerro Casale deposit. The projects are located along the gold-rich El Indio belt, where Barrick's existing Veladero mine is located.

    Barrick said in September that it planned to work on a scaled-back development plan for Pascua-Lama, an $8.5 billion project that was put on hold in 2013 in response to a slump in gold prices, political opposition to the project, environmental issues and labor unrest.
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    Environment group takes De Beers Canada to court over mercury

    An environmental group said on Tuesday it filed a lawsuit against De Beers Canada, accusing the diamond producer of failing to report toxic levels of mercury and methylmercury at its Victor diamond mine in northern Ontario.

    The Wildlands League alleged that De Beers Canada failed to report mercury levels from five of nine surface water monitoring stations for the creeks next to its open pit mine between 2009 and 2016.

    This was an offense under the Ontario Water Resources Act, the group said in a statement. It said it had alerted the province of Ontario and De Beers Canada to the failures more than 18 months ago.

    The remote fly-in/fly-out Victor mine in the James Bay Lowlands of Ontario is about 90 km (56 miles) west of the Attawapiskat First Nation.

    "After months and months of silence from Ontario, we felt we had no choice but to file charges," said Trevor Hesselink, Wildlands League's director of policy and research.

    De Beers Canada said in a statement that while it could not comment specifically on the allegations while they were before the courts, the suggestions that its environmental reporting had not been appropriate for seven years were inaccurate.

    "Our reporting requirements were expanded to a more robust and comprehensive program when the mine began operations in mid‐2008," the Calgary-based company said.

    The miner also said that mercury was naturally occurring and had been present in the region long before mine construction. Mercury is not used in the mining process, it added.

    Ontario's ministry of environment and climate change said it had previously "provided direction" to De Beers Canada regarding monitoring and reporting requirements at the mine.

    "As a result, improvements were made to the 2016 reporting process," the ministry said in an emailed statement. It added that it has remained in close contact with De Beers to ensure the company follows all the conditions of its permits.

    California EPA says settled with Apple on hazardous waste claims

    Methylmercury is created when mercury, a metal that poses health risks, is dissolved in freshwater and seawater.

    The Victor mine is set to close in 2018 unless De Beers Canada, a unit of global diamond producer De Beers, proceeds with an expansion.

    De Beers is 85 percent owned by miner Anglo American Plc.

    Attached Files
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    Steel, Iron Ore and Coal

    China's coke price hits record high in late Nov, NBS

    China's Grade II met coke price rose 72.9 yuan/t from ten days ago to 2,019.8 yuan/t in late November, hitting record high entering 2016, showed data from the National Bureau of Statistics (NBS) released on December 5.

    China's coke prices have been rising since March of the year, especially during the third quarter, as coke supply fell short of demand affected by low operating rate amid environmental checks and constrained coking coal supply under 276-working day regulation.

    In October, China produced 39.93 million tonnes of coke, up 1.63% from September and 7.3% year on year; total coke output over January-October dipped 0.8% on year to 371.76 million tonnes, the NBS data showed.

    Coke prices in the country may be steady in the short run considering stabilizing coal prices.

    Separately, the price of 1/3 coking coal stood at 1,170 yuan/t during November 21-30, up 60 yuan/t from November 11-20; and the rebar price also increased 23.9 yuan/t to 3,056.8 yuan/t, the data showed.
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    Indonesia's Dec HBA thermal coal price hits record high since 2012

    Indonesia's Ministry of Energy and Mineral Resources has set its December thermal coal reference price, also known as Harga Batubara Acuan or HBA, at $101.69/t, up nearly 20% from the HBA in the preceding month.

    It is now at its highest level since May 2012, with record high year-on-year growth at 90.04%. Moreover, price growth between November and December was the steepest monthly rise ever in the history of the HBA.

    The rally in HBA prices since May this year has been largely driven by a mix of supply cuts and strong demand from China. However, analysts predicted the soar of HBA to be out of steam soon, amid bearish international coal market.

    China now is determined to curb rapid rise of coal prices by allowing all coal mines to operate 330 working days a year till the end of the heating season in late March or early April, boosting thermal coal rail transport, as well as pushing for term contracts between coal producers and utilities.

    By doing so, coal stocks at the country's ports climbed notably. As of December 2, the inventory at six ports of the Bohai Rim totaled 19.57 million tonnes, a gain of 4.95 million tonnes compared to a year prior.

    Meanwhile, China's newly-implemented 2017 coal contract price effective on December 1 has been set at around 585 yuan/t, FOB basis, lower than spot prices, which will result in falling back of the alternative Indonesia material.

    The offer for Indonesian 6000 Kcal/kg NAR coal was heard to be $94/t in the beginning of December, down $12/t from a month ago. The downward was predicted to remain in the rest of 2016 affected by falling Chinese coal prices, thus impacting on HBA prices.

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

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

    It is based on 6,322 kcal/kg GAR coal, with 8% total moisture content, 15% ash as received and 0.8% sulfur as received.

    In 2016, the HBA coal price averaged $61.84/t, slightly higher compared to the average of $60.13/t in 2015.
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    Shenshuo rail line's coal transport exceeds 2016 target

    Shenshuo rail line, which starts from Daliuta in Shaanxi province and ends in Shuozhou in neighboring Shanxi province, hauled 225.08 million tonnes of coal as of December 2, exceeding its target of 224.35 million tonnes for 2016, said operator China Shenhua Group on December 5.

    This is the fifth consecutive year for its coal transport to stay above 200 million tonnes, after reaching 207 million tonnes in 2012.

    Since 2016, the rail line has reduceed coal transport time between Daliuta and Shuozhou from 0.83 day to 0.78 day, releasing tight transport capacity.

    The 266-km line, the second largest coal dedicated railway after Daqin line transporting coal from western production areas to eastern consumption areas, mainly delivers coal from Shenfu and Dongsheng coal fields owned by Shenhua Group.
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    Beijing cuts 2.5 mln of coal consumption in 2016

    Beijing has cut coal burning by more than 2.5 million tonnes of this year, reducing the proportion of coal in the city's total energy consumption to around 14%, the municipal environmental protection bureau announced on December 5.

    Beijing used around 10 million tonnes of coal this year, and the number is expected to be reduced to nine million tonnes by 2020, according to the bureau.

    Beijing has made great efforts to replace rural coal use with cleaner fuels and residential coal-burning management this year, which is estimated to have reduced 39,000 tonnes of soot, 21,000 tonnes of sulfur dioxide and 10,000 tonnes of nitrogen oxide from the atmosphere, according to the bureau.

    Beijing has almost closed all coal-fired boilers in its six core districts as of the end of 2015, and plans to make all of its seven districts in the plain area coal-free by 2017.

    In Beijing, coal is mainly used in industrial facilities and large heating boilers. The capital started to convert coal-fired boilers to clean-energy boilers from 1998.
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    India’s coal export plans heading for the backburner

    India’s nascent plans to export its way out of a domestic coal glut may be heading for the backburner.

    Domestic coal miners, primarily Coal India Limited (CIL), are failing to make much headway with plans to export their coal, with few buyers in neighbouring countries for the low-grade, high-ash content coal that is on offer.

    At the same time, the Coal Ministry is reconsidering its position on exports and is looking to back off from pushing too fast into it export markets, on the grounds that the current coal glut may be a short-term trend.

    Some government policy makers have expressed their views that, should there be a sudden revival of demand from the domestic thermal power sector, there could be sharp drawdown on the surplus, placing commitments to international markets at risk.

    Media reports in Bangladesh have stated that that country’s Energy Minister had ruled out any coal purchases from CIL.

    Bangladesh, which is planning to float global tenders for coal, is keen to clinch deals with miners in South Africa, where it will secure higher grade coal than what is available from India, the Minister has been quoted as saying.

    India’s Coal Ministry has interpreted the comments as Bangladesh voicing its disinterest in sourcing Indian coal for a proposed 1 320 MW thermal power plant, which is being constructed under a bilateral agreement between the two countries.

    In statement last month, CIL said it had achieved coal production of 50-million tons, or about 93% of its target for the month, and off-take agreements of 48-million tons, or about 97% of its monthly target.

    During the April to November period, the miner produced 323.57-million tons, achieving 90%  of the target set by the Coal Ministry with offtake of 340.32-million tons.

    Among the triggers for optimism in the Ministry that the glut might be easing was the fact that pithead stocks with CIL was down 39-million tons in November, from 53.9-million tons in April.
    At the same time, coal stocks with thermal power plants too were on a downward curve and an indication that their off-take from the miner would rise over the next few months.

    Government data indicated that in November coal stocks with thermal power plants were down to 19-million tons, against an estimated demand of 30-million tons, which would prompt these  power plants to make fresh off-takes from CIL.

    Attached Files
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    Jiangxi slashes 4.33 Mtpa steel capacity this year

    Jiangxi province in southeastern China has slashed 4.33 million tonnes per annum (Mtpa) of crude steel making capacity and 0.5 Mtpa of pig iron making capacity so far this year, local media reported.

    This means the province has completed its de-capacity target set for the 13th Five-Year Plan period (2016-2020) four years earlier, thanks to great efforts made by the provincial government and steel makers.

    The provincial government provided a series of financial support, including special funds and subsidies, to seven steel makers in the province to cut capacity.

    Jiangxi province also vowed to eliminate 12.79 Mtpa of coal capacity in 2016 by shutting down 205 coal mines.

    More than 283 coal mines in the province will be shut over 2016-2020, slashing over 18.68 Mtpa of coal capacity.

    Attached Files
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