Mark Latham Commodity Equity Intelligence Service

Friday 17th March 2017
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    Trump reopens US fuel economy rules for 2022-25

    Framing the issue as a solution to US automakers moving operations overseas, President Donald Trump said Wednesday he was reopening US fuel economy standards for 2022-2025 and may ease them after a year of study.

    "We are going to restore the originally scheduled mid-term review and we are going to ensure that any regulations we have protect and defend your jobs, your factories," Trump told auto workers at the American Center for Mobility in Ypsilanti, Michigan.

    "We're going to be fair," he said. "This is an issue of deep importance to me -- for decades I've raised the alarm of unfair foreign trade practices. ... They've stolen our jobs, they've stolen our companies, and our politicians sat back and watched hopeless. Not anymore." Trump said he would also set up a task force in "every federal agency to identify and remove any regulation that undermines American auto production and any other kind of production."

    The president traveled to the Detroit area to tour auto plants and meet with CEOs to highlight job creation and auto manufacturing.

    The rules for corporate average fuel economy and greenhouse gas emissions impact automakers' decisions about vehicle body weights, engine specifications, and promotion of hybrid and electric vehicles.

    Smaller turbocharged engines used to boost fuel economy also increase demand for higher-octane gasoline. Premium gasoline accounted for 11.5% of total US motor gasoline sales in 2016, compared with 9.1% in 2009, the year the Obama administration proposed its first round of fuel economy targets, according to Energy Information Administration data.

    However, analysts do not expect a major shift in 2022-2025 gasoline demand as a result of Trump potentially rolling back the regulations.

    Related Capitol Crude podcast:Will Trump's energy policy erase Obama's climate legacy?


    PIRA Energy Group, an analytics unit of S&P Global Platts, said any changes to the CAFE targets would have minor impacts on fuel consumption by 2025, with any impacts being diluted by the fact that it takes around 10 years to turn over the entire US fleet of light vehicles.

    PIRA's current base case projects a secular decline in gasoline demand after 2020 of around 1% per year. Efficiency improvements in the gasoline-consuming fleet are part of the equation, and PIRA has also built in limited but growing electric vehicle penetration.

    Growth in the fleet size and vehicle miles traveled per vehicle remain important drivers, PIRA said. Retail gasoline prices will also matter a great deal to whether consumers favor cars with higher or lower fuel efficiency.

    Kevin Book, a managing director of ClearView Energy Partners, said freezing fuel economy standards at 2021 levels could increase US gasoline consumption by as much as 230,000 b/d -- which would only trim gasoline demand declines already expected for most of the next decade.


    To start a new review of the 2022-2025 standards, the White House is scrapping a final determination made in January by the Obama administration to keep the 2011 policy on track.

    A week before Trump's inauguration, the Environmental Protection Agency determined ahead of schedule that US automakers are meeting the targets quicker and at lower costs than expected, leaving the industry more than able to meet the 2025 goal of 54.5 mpg.

    A senior White House official who spoke to reporters on background said Obama's EPA broke its agreement with automakers by accelerating the midterm review and concluding it more than a year before the April 2018 deadline.

    He said the EPA also failed to consult with the National Highway Traffic Safety Administration and ignored a large volume of data submitted in comments during the review process.

    "We're going to get this agreement back on track," he said. "We're going to pull back the EPA's determination, because we don't think it's right.

    "And we're going to spend another year looking at the data, making sure everything is right so that we come to 2018 and we can set standards that are technological feasible, economically feasible and allow the auto industry to continue to grow and create jobs."


    Automakers have argued that adoption of hybrid and plug-in electric vehicles is not keeping pace with the CAFE standards, due in large part to the prolonged period of low gasoline prices.

    "Consumers just aren't buying those vehicles," the White House official said. "So that's a big problem. If that continues, we'll have to recalibrate" the fuel economy rules.

    The White House does not plan to revoke California's existing waiver allowing it to set tougher tailpipe standards than the national limit for cars through model year 2025, but it would work with the state to determine how to go forward after the midterm review.

    The California Air Resources Board said in January that it did not consider the waiver to be in jeopardy, despite reports of the Trump administration wanting to revoke it.

    Mitch Bainwol, president and CEO of the Auto Alliance trade group, said 18 automakers that objected to the EPA's final determination in January are pleased Trump is starting the review over from scratch.

    Automakers want to put the process back on track without pre-determining an outcome, using current data and "checking prior assumptions against new market realities," Bainwol said.

    "Now we will get back to work with EPA, NHTSA, CARB and other stakeholders in carefully determining how we can improve mileage and reduce carbon emissions while preserving vehicle safety, auto jobs and affordable new cars and trucks," he said.

    The Renewable Fuels Association, an ethanol trade group, called the first review rushed and cursory, saying it hopes the new one fully considers comments focusing on the role of fuels in enabling more efficient vehicle technologies.

    "High octane, low carbon fuels can play a significant role in helping to meet fuel economy targets in the future," RFA President Bob Dinneen said in a statement. "That is an omission that must be addressed moving forward if future vehicles can in fact help us address climate change without backsliding on other critical air quality and public health priorities."
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    New, safer U.S. rail cars gather dust even as ethanol trains grow longer

    While crossing a small wooden bridge in northwestern Iowa last Thursday, 20 rail tank cars in a mile-long train transporting ethanol flew off the tracks, sending fireballs into the sky, while thousands of gallons of the biofuel leaked into the creek below.

    No one was injured, in part because the accident occurred in a sparsely populated area. A similar derailment in the more dense Lac-Mégantic, Quebec, Canada, in 2013 killed 47 people after a train carrying crude oil crashed and exploded.

    But the incident in Iowa underscores the growing risk of another serious accident along with the increasing volume of the biofuel being moved in unit trains that are mile-long with about 100 rail cars - dubbed "rolling pipelines" - to slash freight costs.

    That is because ethanol shippers are still primarily using the type of rail cars that were deemed too unsafe to carry crude after the Quebec disaster, even though the biofuel is more explosive than oil.

    Thousands of replacement cars meant to better withstand an accident are sitting idle in rail yards around the country because the ethanol industry is not required to use them for another six years and as they cost about three time as much as the older cars, according to industry sources.

    The U.S. Pipeline and Hazardous Material Safety Administration (PHMSA) gave the ethanol industry until 2023 to employ cars with thicker shells and other safety features. Prior to the Iowa incident, PHMSA said it does not see any safety issues with relying on older cars, known as DOT 111s.

    Not everyone agrees.

    "We would like to see the shippers accelerate their schedule to get these legacy DOT-111 tank cars out of service when transporting flammable liquids — specifically crude oil and ethanol,” said Robert Sumwalt, member of the U.S. National Transportation Safety Board, an independent federal agency, at a Saturday press briefing in Iowa following the accident.

    The train in last week's accident was heading from Green Plains Inc's Superior, Iowa, terminal to the Gulf Coast. Green Plains did not comment for this story.

    The Renewable Fuels Association, which represents biofuels producers and shippers, said safety is a top priority for the industry and highlighted the rarity of these incidents.

    The NTSB has no regulatory authority to change things, Sumwalt said, adding that the power is vested with U.S. Congress.


    Ethanol production has grown sharply in the last decade thanks to government rules mandating increased use of the corn-based biofuel to reduce greenhouse gas emissions. Production is now about 1 million barrels per day.

    About 650,000 barrels of ethanol is transported by rail daily. A 2015 report by the Federal Railroad Administration estimated about 47 percent of ethanol shipments were by unit trains. But several sources interviewed, including four shippers, said their usage is increasing due to cost efficiencies.

    "Unit trains have been an increasing transportation efficiency...we are encouraged to do more unit trains," Kelly Davis, director of regulatory affairs at the Renewable Fuels Association, said at an NTSB roundtable in summer 2016.

    "Shippers want to utilize unit trains if they can to save money,” said Tom Williamson, a broker and owner of Sarasota, Florida-based Transportation Consultants. He said 11 of his 12 clients have switched to unit trains in the past two years.

    In the last two years, biofuels makers Archer Daniels Midland Co, Green Plains, and Eco-Energy Global Biofuels LLC, and terminal operator Kinder Morgan Inc have planned or built new unit train terminals.

    Eco-Energy did not respond to requests for comment, while Kinder Morgan declined comment. ADM, in a statement, said it is committed to making needed investments to meet new rail safety standards.


    Federal regulators have warned longer trains hauling hazardous materials increase the risk of disasters, particularly when using DOT 111 cars.

    There have been at least 17 significant ethanol or crude derailments since 2006, and nearly all involved DOT 111s.

    U.S. regulators gave the ethanol industry more time to shift because getting oil producers to stop using older cars was considered more important. A 2014 Federal Railroad Administration study found ethanol cars were 1.5 times more likely to explode than oil.

    As of September, there were 35,252 tank cars hauling ethanol, and 84 percent were DOT 111s, according to the latest Association of American Railroads data. Newer DOT 117s account for just 6 percent of the ethanol fleet.

    Based on current lease rates, a shipper using 1,000 of the older cars instead of the new models would save $5.4 million annually.

    BNSF Railway Co has started offering discounts to ethanol shippers this April if they agree to use DOT 117s.

    Generally, shippers have stuck with older cars because most railcar owners would hit shippers with financial penalties if they break long-term leases.

    “While we are having some success in getting ethanol customers to upgrade to DOT 117s when their leases expire, we are not seeing a lot of demand from customers to make this switch,” said Christopher LaHurd, a spokesman with GATX Corp, a leading U.S. leaser of rail cars.

    Current lease rates for DOT 111s are roughly $200 a month, while DOT 117s are around $650 a month, brokers said.

    In addition to GATX, Wells Fargo & Co, Bank of America Corp and Greenbrier Companies Inc are among the U.S. fleet owners.

    Spokesmen for Bank of America and Greenbrier declined comment. A Wells Fargo spokeswoman said the company is working with customers to shift to newer cars.

    It would cost about billions to replace all of the older cars with 117 model cars, Davis said in a phone interview.

    "Owners paid $100,000 for these (current) cars, and you're going to melt them down like a tin can to make a new one," Davis said. "That's a lot of stranded capital."

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    Capesize freight rates hit multi-month highs on tonnage tightness

    Capesize freight rates on the key Brazil-China and South Africa-China iron ore routes hit multi-month highs Wednesday as the availability of ballasters failed to keep pace with robust cargo demand.

    The front-haul iron ore route from Tubarao in Brazil to Qingdao in China hit a 19-month high Wednesday amid a shortage of vessels in the Atlantic for the late March-early April loading window.

    The Capesize Tubarao-Qingdao 170,000 mt (plus/minus 10%) route was assessed at $15.75/wmt Wednesday, the highest since August 6, 2015, when it hit $16.40/wmt.

    The Saldanha Bay-Qingdao 170,000 mt (plus/minus 10%) route was assessed at $12.00/wmt Wednesday, the highest since December 3, 2014, when it hit $12.25/wmt.

    Another key iron ore route, from Port Hedland in Western Australia to Qingdao for 170,000 mt (plus/minus 10%), was assessed at a year-to-date high of $6.65/wmt Wednesday.

    A strong rally in the freight derivatives market was adding to the booming sentiment.

    Market participants attributed the firmness to a reduction in the number of ballasters into the Atlantic region due to weak freight levels in February, which resulted in owners not being keen to fix vessels for long voyages at rates that, at the time, offered poor returns.

    The TCE rate on the Tubarao-Qingdao route was assessed at $16,581/day Wednesday, up six-fold from a year-to-date low of $2,664/day on February 16.

    The TCE for the Saldanha Bay-Qingdao route was assessed at $17,622/day and for the Port Hedland-Qingdao at $15,038/day, both the highest since S&P Global Platts began publishing TCE assessments January 3.

    Changing market dynamics were also playing a part.

    "I would say [there is a] totally different market for iron ore and coal now compared [with] a year ago. We have seen record high volumes going from Australia to China over the last few months, largely due to the cuts in Chinese domestic coal production," said Banchero Costa research director Ralph Leszczynski, who noted global coal prices had surged 53% year on year on the back of rising Chinese import demand.

    "The Chinese economy is significantly more active than a year ago. In part this is also because 2017 is an election year in China... Authorities will be keen to stimulate the economy and show the economic situation is healthy this year," he said.

    The stronger fundamentals in China have also boosted other segments of the dry bulk freight market since the start of 2017, with rates across the board seen at healthy levels.

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    South Australia offered a new $600m energy answer

    A group of former BHP Billiton and BP executives has opened discussions with the South Australian government over a $600 million private-equity funded solution to the state's gathering energy crisis.

    The proposal involves the construction of a 350 megawatt gas-fired peaking power plant that would be fuelled by gas from a floating re-gasification plant, whose feedstock would be liquid natural gas acquired either from the North West Shelf or Singapore.

    At a high level, the importance of the pitch assembled under the auspices of Melbourne management consultancy Integrated Global Partners is not whether Jay Weatherill invites it as his solution.

    Obviously, convincing the government to go with a plan that would relieve the state of just about all of the $550 million energy investment load announced by Premier Jay Weatherill on Wednesday is the core mission for IG Partners managing partner Herman Kleynhans – an 18-year BHP veteran.

    But what is really telling here is that the investment model that Kleynhans and his team have developed says that there is a lot of money to be made by shipping gas to South Australia from as far as Singapore and using it to generate electricity during periods of peak power demand in an Australian state.

    It is a prospect that sits as obviously counter-intuitive as it does confirmative of the oddly dislocated state of affairs that has been allowed to develop in Australia's gas markets.

    There really is no avoiding the naked absurdity of the situation.

    Here we have a plan that sees potential in buying relatively small shipments of gas from Singapore's relatively new break-bulk LNG facility. It is quite likely that some of that gas could be sourced from the Gladstone LNG plants that have more than tripled Australian gas demand. Some of the gas those plants are transforming comes from South Australia.

    The only way to get your head around the craziness of the situation is to imagine that the barges that will bring the LNG to South Australia as a flexible gas hose rather than the fixed hose that would bring the gas from the Cooper Basin – if it was available.

    Just on that point, we had a chat on Thursday to Oil Search's Peter Botten. He is just back from a Houston gabfest. The view there is that the LNG price is going nowhere but south. He reckons 2017-18 could see the price hit $US4GJ. It is currently about orbiting $US7.

    Now, $US4 would be seriously tough for the Gladstone producers, whose costs are higher than most in our region. If that price was to hold, you would really have to wonder whether or not the likes of Santos – the most pressured on the Queensland operators – might be able to sustain its second Gladstone train. If that happened, some of the shorter-term supply side pressures would be relieved.

    The potential to arbitrage regional and global LNG prices that are running along at historic lows with domestic gas prices that have hit crippling peaks has been obvious to many for some time. And the opportunity has been further crystallised by South Australia's very urgent and particular need to restabilise its electricity network by adding meaningful licks of conventional base load generation.

    In a report released earlier this week McKinsey & Company identified that the floating re-gas option would be viable at a $10 gigajoule gas price. This number concurs closely with the pricing matrix that underpins the IG Partners proposition.

    McKinsey's very, very useful addition to the national gas debate observed:"FSRUs (floating re-gas) offer a flexible option for increased supply and can be activated with a relatively short lead time.

    "LNG imports via an FSRU could add as much as ~150 PJ per year (which is just less that 25 per cent of domestic gas demand). The cost of LNG imports would reflect global LNG prices, with the addition of FSRU rental fees and capital costs of onshore gas receiving facilities.

    "FSRU imports have a breakeven above the netback economics of LNG exports from Queensland. An FSRU is estimated to breakeven at ~$10 per GJ. While this is more costly than other supply options, it could serve a role in meeting regional imbalances if a substantial price premium emerges in Victoria/NSW as compared to Queensland."

    The thing about the Weatherill plan is that it would very likely result in a regional gas demand imbalance that would drive the sort of premium gas pricing that McKinsey has observed is also likely in Victoria and NSW.

    Gas supply is the missing link in the Weatherill plan. The Premier wants to build a 250MW peaking power plant but there is no indication as to where the state might secure the flexible gas supply needed to make that plan technically or financially feasible.

    The IG Partners proposal would solve both those problems and deliver a bigger electricity reserve at a significantly reduced cost to the state, which would also be relieved of the construction and operating risk. In a perfectly aligned world, the project could be ready for a final investment decision by the end of 2017 with a power plant ready for commissioning by late 2020.

    Reduced to comprehensible simplicity, the plans is to acquire 7 petajoules of gas annually (which is equivalent of about 10 per cent of Australian domestic demand) and to convert and store that gas on a floating barge that would be sit offshore Port Adelaide and be linked to a 350MW generator sites not too far from Engie's Point Pelican.

    In proof of one of LNG's new growth paradigms – that small can be good too – the gas would arrive is comparatively small 6000-tonne shipments. There would be two shipments a week and the gas would be stored on the regas barge to ensure there was ready availability when the power station was needed to support the stater grid.

    The numbers suggest that the new plant would need a power price of about $100 a megawatt hour to justify pumping power. Based on the 2016 numbers, that means the new plant would have been in the system for 16 per cent of the generating year. It would have been in the money for 33 per cent of the opening months of 2017.

    The obvious challenge for IG Partners is to convince government that it has the financial capacity and functional expertise to deliver on the promise of what presently sits a classic example of the way markets work to find innovative and remunerative ways to solve problems.

    The best way to convince the government that it has the nous will be to gather financial backing and leadership of credibility known to the state government. That process is in train. Having worked on its plan for more than eight months, IG Partners is in meaningful discussions with private equity over funding and with a preferred chairman of deep experience and some considerable regional standing.

    With the chairman confirmed IG Partners will appoint a chief executive, who we understand is a former South Australian bureaucrat, and formalise the equity and organisation structure of their operating vehicle, to be called SEA LNG.

    Fiscal and functional credibility will be critical given that the venture requires one very particular gift from the state government.  SEA LNG will not sail without the security of a firm power supply contract from the South Australian government.

    The people working to secure that contract, and others, include two former BP executives, Kerrie Benham and Kellie Larson. Both worked in commercial roles at BP for more than 15 years. And they have been joined by Peter Monkhouse, who is an electrical engineer by training but who spent a working life in project management at BHP.  

    The size of the power station SEA LNG might operate suggests an ambitious level of capacity latency. It would seem very clear, not least because of the pedigree of the people involved here, that there are broader commercial possibilities here. South Australia is Australia's emerging copper super province with big expansions planned for BHP's Olympic Dam and for the nearby Oz Minerals fleet of prospects. The state could be producing 400,000 tonnes of copper in the relatively near future. But the security of power supply has become one of the missing links for miners.

    Whatever happens from here, it is plain that South Australia is in the grip of a market failure that requires some level of temporary state intervention. The plan Premier Weatherill revealed on Wednesday announces that reality. What SEA LNG announces is that there might be other more efficient, less risky and more complete ways of skinning this cat of crisis.

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    Datang Int'l Power 2016 loss at 2.6 bln yuan

    Datang International Power Generation Co., Ltd, a listed arm of China Datang Group, announced a loss of 2.62 billion yuan ($380.3 million) in 2016, plunging 193.39% from a net profit of 2.81 billion yuan in 2015, said the company in its annual report on March 16.

    The company realized 59.1 billion of operating revenue in 2016, a year-on-year drop of 4.47%. Its operating cost stood at 43.6 billion yuan, up 2.85% from a year earlier, according to the report.

    By December 31 last year, its assets totaled 233.2 billion yuan, 23.12% lower than the start of 2016.

    Total debts stood at 174.6 billion yuan last year during the same period, down 27.24% from the start of the year. Its asset-liability ratio was 74.88%.

    The company produced 172.47 TWh of electricity last year, up 1.62% from a year ago. The on-grid electricity reached 163.5 TWh, rising 1.67% year on year.

    By end of 2016, it had 44.3 GW of installed power capacity. Power projects totaling 1.58 GW gained approval last year, with 0.75 GW of photovoltaic capacity, 0.21 GW of hydropower capacity and 0.62 GW of wind power capacity.
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    Oil and Gas

    Halfway into 2017's oil supply cut, Asia remains awash with fuel

    Halfway into an OPEC-led oil supply cut, Asia remains awash with fuel in a sign that the group's efforts to rein in a global glut have so far had little effect.

    The Organization of the Petroleum Exporting Countries (OPEC) and other suppliers including Russia have pledged to cut production by almost 1.8 million barrels per day (bpd) during the first half of this year to rein in oversupply and prop up prices.

    Yet almost three months into the announced cuts, oil flows to Asia, the world's biggest and fastest growing market, have risen to near record highs.

    The Asian surplus will pressure global oil prices and weigh on the budgets of major oil producing nations but may also help spur growth in demand needed to soak up the excess.

    Thomson Reuters Oil Research and Forecasts data shows around 714 million barrels of oil are being shipped to Asia this month, up 3 percent since December when the cuts were announced.

    Responding to rising production, benchmark crude prices are down 10 percent since January, and analysts warn that more falls could follow.

    "Cuts are not enough to re-absorb the world's excess supply. So, unless oil demand growth rebounds to record levels in 2017, oil prices could head for another substantial fall," said Leonardo Maugeri, senior fellow at the Harvard Kennedy School's Belfer Center for Science and International Affairs.

    Not only are supplies from the Middle East and Russia to Asia still high despite the pledge to cut, but record volumes are flooding into Asia from the Americas and Europe.

    The result is a market awash with fuel. More than 30 supertankers are sitting off the coasts of Singapore and southern Malaysia filled with oil, despite a price structure that makes it unattractive to buy oil now and store it for sale at a later date. Crude for delivery in January 2018 is only 70 cents more expensive than that for delivery next May, making those floating storage vessels unprofitable.


    The ongoing glut poses a predicament for OPEC. Its members need higher oil prices to balance government budgets, but cutting back production to prop up prices means losing market share as other suppliers step in to fill the gap.

    OPEC's cuts early in the year pushed up Middle East Dubai crude price against the international benchmark Brent, allowing oil from outside the Middle East to head to Asia.

    Traders are shipping competitively priced crudes such as Russian Urals, Kazakhstan's CPC Blend, North Sea Forties and U.S. West Texas Intermediate to replace Middle East staples from Oman to Abu Dhabi.

    A record 10.5 million barrels of Russian Urals will arrive in Asia between April and June, Eikon data shows.

    Oil from Kazakhstan, the North Sea, Brazil, and the United States arriving in Asia in March is expected to reach 45 million barrels, double the volume in the same month a year ago.

    "The uptick in arbitrage has not gone unnoticed by the large Middle Eastern (OPEC) producers," analysts from consultancy JBC Energy said in a note to clients this week.

    In a move to beat off competition but which contradicts the announced cuts, OPEC's de-facto leader Saudi Arabia unexpectedly cut light crude prices last week.

    State-owned Saudi Aramco has also given additional supplies to Asian customers in April, trade sources said.

    Stiff competition and ample supplies have depressed prices for Middle East and Asia-Pacific grades, some of them to multi-month lows.

    May-loading for Qatar Marine crude sold at discounts to its official selling price for the first time in four months while spot premiums for Russian and Malaysia's flagship Kimanis crude have also hit lows.

    With few signs that producers will cut supplies deeply enough to end the glut, and indicators that output is rising in the United States, traders say only strong demand can eventually rein in the surplus.

    "Demand growth in Asia is about 700,000 bpd, so the glut will eventually clear," said Oystein Berentsen, managing director for oil trading company Strong Petroleum in Singapore.

    Not all are as confident.

    "Enduring excess supply could be eased by a robust demand growth," said Maugeri of the Belfer Center. "But preliminary data and analyses do not portend such a development, especially because of a significant slowdown in demand growth in China and India - the two major engines of world oil consumption growth."

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    Iraqi KRG faces obstacles to maintain crude oil export quality

    The regional government of semi-autonomous Iraqi Kurdistan appears to be struggling to maintain the quality of its oil exports, just as it has signed a landmark supply agreement with Rosneft aimed at opening up new markets for Kurdish crude.

    The problem surfaced last month in a regulatory filing by Gulf Keystone Petroleum, which produces heavy crude from Kurdistan's giant Shaikan field, disclosing a Kurdistan Regional Government decision to stop accepting Shaikan crude for blending into pipeline exports of Kurdish crude for delivery to the Turkish Mediterranean oil terminal at Ceyhan.

    Instead, the KRG has agreed to shoulder the cost of transporting Shaikan crude by truck for onward export as a stand-alone product and to continue paying Gulf Keystone a flat $15 million/month for current and past exports, the company said.

    Kurdish officials said the action was taken to preserve the quality of the crude exported by pipeline.

    The main problem for the KRG, however, is unlikely to be solely the low API and relatively high sulfur content of Shaikan crude, which so far has been pumped in limited quantities -- recently at a rate reported by Gulf Keystone of about 37,000 b/d.

    More likely, the KRG's unexpected decision to exclude Shaikan crude from the export pipeline reflects much bigger problems for the regional government in coping with a large drop in output from one of Kurdistan's major producing fields, compounded by delays in bringing new fields onstream.

    Taq Taq, a field operated by a joint venture between Genel Energy and Sinopec, is one of two major fields that for the past several years have been the mainstays of Kurdish light crude oil production. The other is DNO-operated Tawke.

    Until last year, the two fields had similar prospects, with reserves in each case estimated at over half a billion barrels and long-term prospects of expanding production to 200,0000 b/d.

    But their fortunes diverged sharply in late February 2016, when Genel stunned investors by slashing its estimate of Taq Taq's initial proven and probable reserves by nearly half, to 356 million barrels from 683 million, with gross remaining 2P reserves as at December 2015 of only 172 million barrels.

    The company also indicated output from the field could shrink to as little as 50,000 b/d by 2018 from the then-expected average for 2016 of 80,000 b/d.

    Last year, Tawke's output averaging 107,000 b/d easily outstripped Taq Taq's actual average output of only 60,000 b/d. As at December 31, 2016, Tawke still had 504 million b of proven and probable reserves.

    Tawke production continues to trend upwards but only gradually, and certainly not by enough to offset the big decline from Taq Taq. It averaged 110,000 b/d in December 2016, DNO reported.

    The other main source of crude contributions to the KRG's piped export stream is northern Iraq's major Kirkuk field, which lies in territory disputed between Eribil and Baghdad.

    In practice, the administration of the huge field's three oil domes has long been partitioned between the KRG and Iraq's federal government, with the KRG opportunistically strengthening its position following the major Islamic State group insurgency in mid-2014.

    But the Kirkuk field, which gave its name to northern Iraq's Kirkuk export crude grade long before the underdeveloped Kurdistan region started its own oil exports, is a source of medium-heavy crude.

    Beginning in the era of late Iraqi dictator Saddam Hussein, Kirkuk's crude has been made heavier by the injection of large volumes of excess heavy fuel oil into the reservoir -- an unwanted by-product from ageing Iraqi refineries.


    All this adds up to a ton of trouble for the KRG, which has struggled to pay its oil contractors and staff following Baghdad's suspension of federal budget transfers to the region in early 2014, and the crash in oil prices and major IS group insurgency later that year.

    The big question now is whether sufficient new sources of Kurdish light crude can be developed fast enough to offset Taq Taq's decline, allowing the KRG to shore up its reputation as a reliable exporter of a crude blend with Kirkuk grade specs.

    Only that, paired with better relations with Baghdad, could help the KRG substantially reduce the hefty discount to other regionally traded crudes at which it currently sells its oil to international buyers.

    Certainly there are other Kurdish fields with light crude waiting in the wings. One is Atrush, operated by Abu Dhabi National Energy Co., or Taqa. Another is Gazprom-operated Sarqala, and a third is Kurdamir, on a block operated by Repsol adjacent to Gazprom's license.

    Early-stage production has already begun at Atrush and Sarqala, while the partners in Kurdamir plan to file a revised development plan for their field by the end of this year.

    With a state-controlled or large international producer leading each development, production from all three fields could in theory be ramped up quickly.

    But even major producers and government-backed companies such as Taqa and Gazprom are currently balking at investing heavily in drilling campaigns while they remain deeply uncertain of the KRG's ability to pay for future crude exports.

    Even DNO, long entrenched in Kurdistan as an oil producer and currently the biggest producer of the region's crude, has said its investment in further drilling to bring Tawke's output capacity to 135,000 b/d is "contingent on regular and predictable export payments" from the KRG.

    After pledging early last year to make prompt and regular monthly payments for contractual volumes of oil delivered for export, the KRG is still running behind on such payments.

    DNO and Genel last week reported the receipt from the KRG of $36.73 million for gross December 2016 exports from Tawke and $17.46 million for gross exports from Taq Taq that month. They also received about $10 million in aggregate toward recovery of amounts owed for earlier exports.

    The one sliver of good news to emerge recently on the KRG's situation is that the regional government has not hung Gulf Keystone out to dry.

    The company last week reported receiving its standard $15 million payment for December exports, indicating the KRG has not yet been squeezed into giving up on prospects for Shaikan's vast store of heavy crude to become a future money-spinner.

    But for that to happen in anything sooner than the distant future, the KRG would probably have to build a new pipeline dedicated to heavy crude exports.

    Gulf Keystone's previous disclosures on the high cost of transporting Shaikan crude by truck to the Turkish Mediterranean port of Dortyol, as happened until May 2016, mean that any near-term profits from trucked exports of Kurdish heavy crude to the Turkish coast are likely to be marginal.

    Still, with Gulf Keystone's cash position standing at just $121.6 million as of last week, the KRG continues to treat the revenue-poor oil developer as a special case, ensuring it just about stays afloat.

    Kurdistan's known petroleum resources also include meaningful volumes of condensate in the Khor Mor and Chemchemal fields, for which the Pearl Petroleum consortium, led by UAE affiliates Crescent Petroleum and Dana Gas, hold development contracts.

    Much to the partners' disappointment, as indicated in Dana's regulatory filings related to an international arbitration case against the KRG, negotiations with the regional government to start development of Chemchemal, which holds major condensate reserves, have not yet reached fruition.

    Pearl currently produces gas from Khor Mor, used as feedstock for two Kurdish power plants, along with LNG and condensate. But those operations, too, are included in the arbitration case, in which Pearl partners also including OMV and MOL have already won a partial settlement award of about $2 billion.


    Nonetheless, officials at Iraq's federally-controlled North Oil Co. last week told S&P Global Platts gas condensate had been added to the Kirkuk export mix. One official said Khor Mor condensate was being added.

    Another official, who did not comment on the source of the condensate, said 10,000 b/d of condensate was being injected into gathering stations, swelling the 168,000 b/d flow of crude being sent for export from northern Iraqi oil fields under NOC control to 178,000 b/d.

    Since repeated IS group attacks on Iraq's federal export pipeline put the line permanently out of action three years ago, NOC has been sending limited volumes of crude from Kirkuk and smaller northern Iraqi fields for export through the KRG's pipeline under successive makeshift agreements between Baghdad and Erbil.

    While the use of Khor Mor condensate to thin Kirkuk and even Shaikan crude might seem an obvious way for the KRG to control the quality of the crude passing through its export pipeline, the regional government previously suspended that practice over a dispute with Pearl over payments for condensate.

    Given the continuing bad blood between the KRG and Pearl over the subsequent arbitration case, the reintroduction of Khor Mor condensate into the export stream points to growing KRG desperation.

    Adding to KRG woes is growing anti-government activism by supporters of the opposition Patriotic Union of Kurdistan party, which earlier this month briefly interrupted crude flows from NOC fields when a security force loyal to the PUK took over and temporarily halted operations at a pumping station.

    The activists' main complaint was that not enough Kirkuk crude was reaching a refinery near Kurdistan's Sulimaniyah province, where a large majority of voters support the PUK.

    Yet another potential problem is a recently signed energy cooperation agreement between Iraq's federal government and Iran, which includes a plan to build a 150 km crude oil pipeline from Kirkuk to Kaneqin, on the the Iranian border, to feed refineries in northwestern Iran.

    That pipeline, if built, would bypass the KRG export system and reduce exports from Ceyhan by Iraq's federal State Oil Marketing Organization, thereby lessening KRG political leverage in negotiations with Baghdad.

    Unless the KRG could compensate with higher output from the Kirkuk domes under its control, it might suddenly need to accelerate Shaikan's development to avoid deviating too far in the lighter direction from Kirkuk blend specs.

    How this will all pan out is far from obvious. The biggest hope on the near horizon for the KRG may be Atrush, which could be developed quickly with the help of Abu Dhabi government resources.

    Last week, in an operating and financial statement, junior Atrush partner Shamaran reported that construction of the 30,000 b/d Atrush phase 1 production facility was complete, with final commissioning in progress.

    Four production wells had been completed and connected to the production facility, ready for start-up, and work on pipelines to connect the field to the KRG export pipeline was well underway, with completion expected in Q2, the company added.
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    Venezuela's cash-strapped PDVSA offers Rosneft oil stake - sources

    Venezuelan state oil company PDVSA has offered Russian counterpart Rosneft a stake in a joint venture in the country's Orinoco Belt extra-heavy crude area, five industry sources said, in a sign of the Latin American nation's dire economic situation and Moscow's growing muscle there.

    Rosneft, Russia's top oil producer, has been offered a 10 percent stake in the Petropiar joint venture.

    PDVSA, as Petróleos de Venezuela SA is known, has a 70 percent share, and U.S. oil company Chevron Corp (CVX.N) holds 30 percent of the venture, which includes an oil field and a 210,000 barrel-per-day oil upgrader.

    Two sources said the offer was part of a larger package offered to Rosneft as PDVSA seeks to raise money to pay suppliers and bond holders.

    It is unclear if Rosneft will accept the offer. Financial details of the potential transaction were not immediately available.

    PDVSA and Venezuela's Oil Ministry did not respond to requests for comments. Chevron and Rosneft declined to comment.

    A deal would see California-based Chevron working alongside state-owned Rosneft, which has been affected by U.S. sanctions against Russia.

    But Chevron's main concern is that accounting and transparency laws are less strict in Russia than in the United States, a source close to the matter said.

    The proposal highlights Venezuela's need for cash after the nation's oil output fell about 10 percent last year, according to the Organization of the Petroleum Exporting Countries. This has worsened a recession that has millions of Venezuelans skipping meals amid food shortages and spiraling inflation.

    The opposition-controlled National Assembly says President Nicolas Maduro's unpopular government is resorting to surreptitiously selling strategic assets to weather the unprecedented crisis.

    "Any deal of national interest must be approved by the National Assembly," tweeted lawmaker Jose Guerra, head of congress' finance commission, in reaction to Reuters' article. "If PDVSA sells 10 (percent) of Petropiar to Rosneft, that sale is null and void."


    Rosneft has already been gaining ground in Venezuela, an OPEC member.

    Last year, the company paid $500 million to increase its stake in the Petromonagas joint venture from 16.7 percent to 40 percent, the maximum foreign partners are allowed to have under oil sector regulations created under late leader Hugo Chavez.

    "The ballpark value of the two projects (Petromonagas and Petropiar) probably isn't that different," said Francisco Monaldi, fellow in Latin American energy policy at the Baker Institute in Houston.

    The Petromonagas sale also raised the ire of the National Assembly, which said the purchase was illegal because Congress did not approve it. Critics have also said the stake was sold too cheaply.

    In another controversial move, PDVSA last year used 49.9 percent of its shares in coveted U.S. subsidiary Citgo as collateral for loan financing from Rosneft.

    PDVSA said this month it had received $1.985 billion from an unnamed client in return for future oil shipments, with Citgo shares used as a guarantee.

    In total, Rosneft has lent PDVSA between $4 billion and $5 billion, but the details of those deals have not been disclosed.

    "We must thank life that Russia and the world have a Vladimir Putin," Maduro said at a deal-signing event with Rosneft head Igor Sechin last year.

    "I wanted to be here at this event because of how important relations with the new Russia are."
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    BP appoints new heads of production, drilling as output set to jump

    The chief of the production, exploration and development unit or upstream division, Bernard Looney, has appointed several executives including a new head of production and a new head of drilling, BP told Reuters.

    Gordon Birrell, who previously headed BP in Azerbaijan, will become chief operating officer for production, transformation and carbon in the BP upstream segment, reporting to Looney.

    Based in London, he will be responsible for global operations, global wells, global procurement, supply chain management and upstream engineering.

    He will also be accountable for upstream modernization and lead the development of the upstream approach to a low-carbon future, BP said.

    Andy Krieger will become the new head of drilling. Krieger, previously vice-president for drilling in the Gulf of Mexico, will report to Birrell.

    The previous head of drilling, Gary Jones, will lead operations in Azerbaijan. The country is a key global growth area where the company wants to expand the giant ACG oilfields and the Shah Deniz gas development.

    Jones will report to Andy Hopwood, chief operating officer for strategy and regions in BP's upstream segment.

    "Project execution followed by an underlying cashflow inflection will be the key steps (for BP) combined

    arguably with oil above rather than below $50 per barrel," analysts from JP Morgan wrote this week after meeting BP's chief financial officer, Brian Gilvary.

    They said BP's production growth was due to accelerate through 2017/18, pause thereafter and then see another step-up in 2020/21.

    The key start-ups this year are the Zohr gas field in Egypt, Juniper in Trinidad, Khazzan in Oman, Quad 204 in Britain and Persephone in Australia, JP Morgan said.

    Attached Files
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    India's IOC buys its first Hibernia crude from Canada's Suncor

    Indian Oil Corp (IOC.NS) became India's first refiner to buy light sweet Hibernia crude from Canada's largest oil company, doing the deal after the opening of the arbitrage for Canadian oil to flow to Asia.

    A decision by the Organization of the Petroleum Exporting Countries (OPEC) to cut output strengthened Middle East benchmark Dubai against other regional markers, allowing oil from the Americas and Europe to be shipped to Asia at competitive prices.

    Production in North America, led by U.S. shale output, is increasing after supply cuts by OPEC and non-OPEC countries pushed oil prices to above $50 a barrel.

    This was also the first time that Suncor Energy (SU.TO) has sold a cargo of offshore Canadian crude to IOC, a Suncor spokeswoman Sneh Seetal said on Wednesday.

    Seetal declined to say how big the cargo was or when it would load, but confirmed Canada's biggest oil company had won an Indian Oil Corp tender.

    "We do market our offshore crude production globally on an opportunistic basis," she said.

    Trade sources said Suncor sold the 1 million barrel cargo of Hibernia crude to IOC on a free on board basis. Separately, IOC has also bought its first Russian Urals crude cargo in about a year in another tender.

    IOC previously bought a cargo of Canadian White Rose oil in November 2013. State-refiners like IOC were last year given the freedom to draw up the crude import strategies that would allow them to make swift gains from changing market dynamics.

    News of the Suncor cargo comes after market sources this week said two other vessels carrying Atlantic Canadian crude are on their way to China.

    The Stena Suede and the Jag Lalit, both Suezmaxes, loaded at Whiffen Head terminal, Newfoundland, according to Reuters ship tracking data. At least one of them was sold by Husky Energy (HSE.TO) to buyer PetroChina (601857.SS), two sources said.

    Husky had said in February it sold its first one-million-barrel cargo of offshore Atlantic Canada crude bound for China from its White Rose field.

    At the time a Husky spokesman said low shipping rates helped make the transaction worthwhile.
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    Petrobras’ domestic output down on FPSO stoppage

    Brazil’s Petrobras saw its oil and natural gas production in February totaling 2.82 million barrels of oil equivalent per day (boed), with 2.703 million boed produced in Brazil and 113,000 boed abroad.

    Average domestic oil output stood at 2.20 million barrels per day (bpd), 1% down on the January figure. This was mainly due to a scheduled stoppage on FPSO Cidade de Paraty in the Santos Basin’s Lula Nordeste pre-salt field, and termination of the Anticipated Production System (SPA) test phase in the Búzios field under the Rights Transfer Agreement.

    The SPA was designed to gather information about the behavior of the reservoirs in the oilfield.

    In February, production of natural gas in Brazil (excluding liquefied gas) stood at 80.2 million m³/d, 1% down on the previous month, mainly because of a scheduled stoppage on the FPSO Cidade de Paraty.

    Pre-salt Production

    In February, oil and natural gas production managed by Petrobras (own and third party output) in the pre-salt layer was 1.53 million boed, showing growth of 41% against the February 2016 figure. However, compared to January this year, this figure is represents a 3% drop, which was due to a scheduled stoppage on FPSO Cidade de Paraty in the Santos Basin’s Lula Nordeste pre-salt field, and termination of the SPA test phase in the Búzios field.

    Gas and oil production abroad

    In February, oil output from oilfields abroad stood at 63.5 million bpd, 8% down on the previous month. Natural gas production amounted to 8.4 million m³/d, 3% down on the January 2017 figure. This was mainly due to operational stoppages in the Lucius and Hadrian South fields in the U.S. because of limitations in the distribution capacity of third-party facilities.
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    India approves use of LNG as fuel for transport

    India’s ministry of the road, transport and highways has given the green light for the use of liquefied natural gas (LNG) as fuel for road vehicles.

    Minister Nitin Gadkari told reporters that the LNG has been approved as fuel for vehicles with fueling stations expected to be made available across the country, Press Trust of India reports.

    Speaking after an agreement with India’s largest importer of liquefied natural gas, Petronet LNG, Gadkari said the standard for the use of LNG as fuel will be defined by a number of ministries including the ministry of Petroleum.

    He added that the wider use of LNG as fuel will reduce the cost of road transport.

    Prior to the agreement with the ministry, Petronet LNG signed an agreement with the Inland Waterway Authority of India to set up LNG stations along the inland waterways that will provide fuel for LNG-fueled barges.

    Petronet is in the process of preparing a detailed feasibility report for setting up LNG facilities at Haldia, Sahibganj, Patna and Ghazipur on NW-I (river Ganges).
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    India says producers can sell coal bed methane at market rate

    India has permitted coal bed methane (CBM) producers to sell gas at the market rate, a government statement said on Wednesday, a move that could help companies such as Oil and Natural Gas Corp and Reliance Industries.

    The producers can also now sell CBM gas to their affiliates if they are unable to find any other buyer, the government statement said.

    The government will announced a price for CBM gas, which will be used as a floor for calculating its royalty and other charges.

    But CBM producers will pay royalties and other dues to the government on the basis of sale or market prices, if it is higher than the official rate, the statement added.
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    Trump Weighing Eni Bid to Drill in Arctic Waters After Obama Ban

    The Interior Department is weighing Eni SpA’s request to explore for oil in waters north of Alaska, giving the Trump administration a chance to reverse course from former President Barack Obama’s attempt to curtail Arctic drilling.

    Eni’s exploration well would be in an area it previously leased from the federal government, and so it isn’t covered by the executive order Obama issued in December to block the sale of new drilling rights within huge swaths of the Chukchi and Beaufort seas. As the Trump administration considers ways it could reverse Obama’s directive, approving this plan could encourage more oil companies to consider Arctic exploration.

    Although some oil companies have abandoned plans to launch expensive quests for crude off Alaska’s coast, recent discoveries have fanned interest in waters near the shoreline that can be drilled at a lower cost.

    The Bureau of Ocean Energy Management is conducting an initial, 15-day review of the broad drilling blueprint filed by Italy’s Eni, which is aiming to sink a well in the federal waters of the Beaufort Sea before its leases expire at the end of the year.

    If the bureau deems Eni’s broad exploration blueprint complete, it would publish the document online and subject it to public comment while scrutinizing the plan’s details in a 30-day review.

    "By the end of the 30-day period BOEM will either approve the exploration plan, require modifications to the exploration plan or disapprove the exploration plan," bureau spokeswoman Connie Gillette said in an email. Before it could launch operations on its proposed Nikaitchuq North well, Eni also would have to win a drilling permit from the Bureau of Safety and Environmental Enforcement and secure other government approvals.

    Eni already uses a man-made gravel island to extract oil from leases in state waters hugging Alaska’s coast. Under its plan, the company would would use that same site -- known as Spy Island -- as a launching pad for extended-reach drilling that would target a potential oil reservoir in nearby federal waters.

    Eni, the lead operator on the project, owns 40 percent of the 13 leases set to be affected by the plan. Its partners are Royal Dutch Shell Plc, which also has a 40 percent share, and Spain’s Repsol SA, which claims the remaining 20 percent.

    In an emailed statement, Eni said it was planning to begin drilling by the end of the year. Eni could cite its proposed oil exploration in trying to convince federal regulators to issue a "suspension of operations" that would effectively extend its leases there.

    In February, the safety bureau approved Eni’s bid to consolidate 13 of its federal leases in a single unit -- a decision that could make it easier to prolong the life of all of them if drilling began in any one of those tracts.

    Still, U.S. law is designed to push oil companies to diligently develop their holdings -- and it sets a relatively high bar for granting time-outs. Eni’s targeted leases have already been suspended before -- some for roughly four years. Federal law does not give the Interior Department authority to issue blanket extensions and requires companies to lay out a specific plan for developing leased acreage in order to get more time.

    Environmental Opposition

    "Eni and the federal government must be cautious and responsible," said Michael LeVine, Pacific senior counsel for the conservation group Oceana, which closely monitors Arctic development. "The leases Eni owns have sat dormant for more than a decade and have already had their expiration dates extended in the past. There is no compelling reason to extend the leases again or to rush to grant last minute approvals."

    Under Obama, the Interior Department rejected bids by Shell and ConocoPhillips to extend the life of other Arctic leases. Shell initially appealed the decision but later dropped the effort after a challenge from environmentalists.

    Environmentalists argue the risks of Arctic drilling are too high -- potentially imperiling the seals, whales and walruses that live in the region as well as the Alaska Natives who live off those resources. Government auditors have warned that icy conditions, dark days and sparse infrastructure could make it impossible to adequately sop up a spill in the region.

    27 Billion Barrels

    Obama cut Arctic tracts from a five-year leasing plan issued last year, and issued a sweeping order that withdrew almost all U.S. Arctic waters from future sales. Neither action affects existing leases, such as that held by Eni. Trump is weighing how to reverse both of Obama’s moves, according to Alaska Senator Lisa Murkowski.

    The U.S. Arctic is estimated to hold 27 billion barrels of oil and 132 trillion cubic feet of natural gas, but energy companies have struggled to tap resources buried below the remote, icy waters at the top of the globe. Shell spent more than seven years and roughly $8 billion trying to find a large stash of crude in the Chukchi Sea, but it abandoned that quest in 2015 after a series of embarrassing mishaps and a test well yielded disappointing results.

    A different scenario is playing out closer to the coast, where recent discoveries -- and the prospect of far lower development costs -- may be luring oil companies. Caelus Energy Corp. claimed to have found at least 2 billion barrels of recoverable oil far beneath northwestern Alaska’s Smith Bay in 2016. And Repsol just announced a 1.2 billion-barrel discovery on Alaska’s North Slope.
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    Fire at Syncrude oil sands site extinguished after two days

    The fire at Syncrude Canada's oil sands plant in northern Alberta was extinguished on Thursday morning, the company said in a statement, as parts of the mining and upgrading facility ran at reduced rates.

    Syncrude said crews were still working to fully isolate the affected area of the Mildred Lake upgrader to allow safe entry to assess damage and development a repair strategy. The upgrader processes mined bitumen into refinery-ready synthetic crude

    Other operations remained stable at the 350,000 barrel per day mining and upgrading facility, roughly 40 kilometres north of the oil sands hub of Fort McMurray.

    Several upgrader units were shut down or running at reduced rates, while mining and extraction were being paced to balance lower bitumen demand, the company said.

    Syncrude spokesman Will Gibson said he did not have details of the impact on production volumes.

    The fire broke out on Tuesday afternoon after a line failure caused a treated naphtha leak, prompting an evacuation of the Syncrude site. One worker was injured and was at an Edmonton hospital, in stable condition.

    Syncrude is majority-owned by Suncor Energy, while Imperial Oil provides operational, technical and business management support.
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    China's biggest nuclear power plant goes online

    Yangjiang nuclear power plant, China's biggest nuclear power plant located in southeastern Guangdong province, was put into operation on March 15, according to its operator China General Nuclear Power Corp (CGN).

    With construction beginning in November 2012, Unit 4 of the Yangjiang nuclear power plant, has had a good safety record, said CGN, which is the country's biggest nuclear operator with 19 nuclear power units in operation and an installed capacity of 20.38 GW at the end of 2016.

    The grid connection of Yangjiang's Unit 4 brings its total number of operational power reactors in operation to 20, with a combined installed capacity of more than 21.46 GW, said the company.

    Six units are planned for the Yangjiang plant, with Unit 1 entering commercial operation in March 2014, Unit 2 and Unit 3 in June 2015 and January 2016, respectively. And all six reactors will be put into operation by 2019, said the company.

    CGN's total annual nuclear on-grid power generation was roughly 115.58 GWh in 2016, a year-on-year increase of 30.8%, which is equivalent to a reduction in coal consumption of 37 million tonnes and carbon dioxide emissions of 90 million tonnes and sulfur dioxide emissions of 880,000 tonnes, it said.

    After the Fukushima disaster, nuclear power unit construction was suspended in China and all nuclear plants under planning or construction were reviewed.

    China's nuclear energy developers will be commissioning many more reactors during the 13th Five-Year Plan (2016-20) as nuclear power is a key source of clean energy along with hydropower.

    Installed nuclear capacity already more than doubled to 27.17 GW in the 12th Five-Year Plan (2011-15) and should double again by 2020 to 58 GW.
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    Precious Metals

    Chile’s Supreme Court casts shadow over Barrick’s plans to restart Pascua-Lama

    Plans by Barrick Gold to revive its Pascua Lama gold, silver and copper project straddling the border between Chile and Argentina may once again be postponed after Chile’s Supreme Court revoked this week a temporary closure permit granted by the country’s mining regulator Sernageomin in 2015.

    Such decision sought to relax certain requirements for Barrick to obtain a new environmental licence for the project, which the top court qualified as an irresponsible measure.

    “It authorizes the temporary closure of Pascua-Lama mining operations, without having the necessary measures in place to ensure the physical and chemical stability of the water sources affected by the project,” the judge said according to local paper Diario Financiero (in Spanish). “[Sernageomin also failed to previously determine] the extent of the damage caused by the project through its innumerable environmental violations,” it added.

    The giant gold, silver and copper project has been shut since 2013, when a court ordered Barrick to halt construction over environmental concerns. Later that year, the firm officially shelved the project.

    The regulator will have now to issue a new closure plan that includes comments from other government offices including the environmental watchdog (SMA), which is expected to rule on two pending cases against the Canadian miner by mid-year.

    The giant project in the Andes has been shuttered since 2013, when a court ordered the company to halt construction over environmental concerns. Later that year, Barrick shelved the project citing massive cost overruns and nose-diving metal prices.

    Ahead with the Lama portion

    When gold prices began their long-awaited recovery last year, Barrick announced the beginning of a “drastic revision” of Pascua-Lama. A few months later, it agreed to pay $140 million to resolve a US class-action lawsuit that accused the company of distorting facts related to the project.

    In September, the world’s No.1 gold producer by market value appointed a new executive, George Bee, to lead the development of the Argentine side of the mothballed project (the Lama portion).

    The company said at the time it would develop a “modest, scalable starter project” on that side using underground mining methods. If successful, the miner said it could use cash flow from Lama to fund additional development on both sides of the border over time.

    A few months later, it decided to strengthen its position in Latin America by hiring a new director for the region — Pablo Marcet — with decades of mining experience in the geographic area.

    Argentina has been an enthusiastic supporter of the project – while only around a fifth of the deposit is located in that country, many of the above-ground facilities will be built on that side of the border.

    If it ever comes into production, Pascua-Lama would generate about 800,000 to 850,000 ounces of gold and 35 million ounces of silver per year in the first full five years of its 25-year life.
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    Base Metals

    Strikers at BHP's Escondida mine in Chile block restart attempt at port

    Striking workers at BHP Billiton's Escondida copper mine in Chile, the world's largest, are blocking attempts by the company to renew operations at a key port nearby, BHP and an umbrella union said on Thursday, as the stoppage enters its sixth week.

    The company said on Tuesday it was gradually resuming operations at Escondida after the 2,500-member Escondida No. 1 Union, which has been on strike since Feb. 9, turned down three offers to return to the negotiating table.

    The company would at first restart operations unrelated to the negotiations, it said, before beginning some maintenance operations, and finally resuming copper production, which has been halted since workers walked off.

    But the striking workers blocked access to Coloso, a BHP-controlled port near the city of Antofagasta used to export copper, when replacement workers tried to enter it on Wednesday. The blockade continued on Thursday.

    "We roundly reject the various actions that the Escondida mine is taking to break the unity demonstrated by the members of the union," Gustavo Tapia, president of Chile's FMC mining umbrella union, said in a statement.

    The president of Escondida, a BHP representative, told a local newspaper that the company would insist on accessing the port, and later the mine itself, which is 170 miles southeast in Chile's high desert.

    He said if the company could not restart all of its operations, a partial resumption was possible.

    Under Chilean law, BHP was allowed to hire temporary workers 15 days after the strike started but said it would wait for 30 days to show its commitment to dialogue. Thursday marked day 36 of the strike.

    The strike at Escondida, as well as stoppages at Freeport-McMoran Inc's Grasberg mine in Indonesia and its Cerro Verde mine in Peru have pushed up global copper prices amid supply concerns.

    The union repeatedly has said it will not return to the table until BHP agrees not to trim benefits in the existing contract, not to make shift patterns more taxing, and to offer the same benefits to new workers as those already at the mine.

    Attached Files
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    Rusal's Q4 core earnings jump 35 pct, beat forecasts

    Rusal's Q4 core earnings jump 35 pct, beat forecasts

    Russian aluminium giant Rusal said on Friday its fourth-quarter core earnings jumped by more than a third on recovery in metal prices, and forecast the market to remain in good shape this year.

    Quarterly earnings before interest tax and amortisation (EBITDA) rose 35 percent from a year earlier to $412 million, beating analyst expectations for a 31 percent rise to $400 million.

    Hong Kong-listed Rusal was overtaken by China's Hongqiao as the world's top aluminium producer several years ago as it reduced its production capacity due to a fall in prices for aluminium, used in transport and packaging.

    "We saw improved market conditions in the second half of the year," CEO Vladislav Soloviev said in a statement.

    "Solid results were down to our dedication to cost management, production discipline, and a stronger focus on innovation and value added products development."

    Full-year aluminium production edged up by 1.1 percent to 3.685 million tonnes, while costs per tonne fell 4.7 percent to $1,344 in the fourth quarter.

    Rusal said it expects the aluminium market to remain in "good shape" in 2017, with demand growing by 5 percent and a global market deficit widening to 1.1 million tonnes.

    It sees China's plans to constrict production next winter and help improve air quality tightening supply by around 1.2 million tonnes, while an anti-dumping case in the United States is likely to curb exports of semi-manufactured shapes of metal.

    Aluminium prices rose 12 percent in London since the start of 2017, to $1900 on Friday, on expectations of less supply from China.

    "In 2017, Chinese supply will be under pressure by significant cost inflation, environmental regulations as well as continuation of supply side reform," Chief Financial Officer Alexandra Bouriko told reporters on a conference call.

    The company sees demand for global aluminium growing by 5 percent to 62.7 million tonnes this year, driven by 6.7 percent demand growth in China to 33.5 million tonnes.

    Global aluminium supply will increase by 4.3 percent to 61.6 million tonnes, tempered by slower output growth in China, which is still seen up by 6 percent to 34.3 million tonnes.

    Russia's VTB said rising prices and a recovery in volumes "might drive 1Q17F EBITDA closer to $500 million."

    The company also said it had placed the first 1 billion yuan ($145 million) tranche of a Chinese yuan-denominated bond, known as a Panda bond, with a 5.5 percent per year coupon rate.
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    Steel, Iron Ore and Coal

    South Korea Feb thermal coal imports up 31.4% YoY

    South Korea imported 9.33 million tonnes thermal coal (including bituminous and sub-bituminous coal) in February, surging 31.4% from the year prior but down 4.01% month on month, showed the data from South Korea Customs.

    Of this, bituminous coal imports posted a year-on year increase of 29.03% but a month-on-month decrease of 6.64% to 8.53 million tonnes.

    South Korea mainly imported thermal coal from Indonesia, Australia and South Africa in February. Indonesia supplied the largest volumes to South Korea, totaling 2.5 million tonnes, up 7.21% from the year-ago level but sliding 27.99% from the month before.

    This was followed by Australia with a shipment of 2.22 million tonnes, falling 16.78% from a year ago but up 3.24% from the previous month; South Africa at 1.28 million tonnes, surging 63.48% on the year.

    The country imported 797,100 tonnes of sub-bituminous coal in February, soaring 63.51% from the year prior and 37.55% month on month. During the same period, Shipments from Indonesia surged 109.17% year on year and 39.34% from January to 709,100 tonnes.

    Imports value of bituminous coal totaled $681 million in February, a decrease of 2.08% from the preceding month. That translated into an average import price of $79.77/t, up 57.69% compared to the year-ago level and 4.89% from the previous month.

    Import value of sub-bituminous coal witnessed a month-on-month increase of 64.14% to $51.30 million in February, which translated into an average price of $64.36/t, rising 43.14% from the year-ago level and 19.33% from January, breaking the record of import price averaged since December, 2014.

    Meanwhile, South Korea's anthracite coal imports rose 6.59% from the same period last year but down 24.45% from January to 435,000 tonnes in February.
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    Hebei deputy suggests supportive policies for competitive coal firms

    Government authorities should roll out more supportive policies for competitive coal firms to facilitate the de-capacity move, said one deputy from Hebei at the just-concluded parliamentary sessions.

    "The aim of shedding insufficient surplus capacity is to spare room for advanced capacity by shutting outdated capacity," said Wang Chang, director of Hebei State-owned Assets Supervision and Administration Commission.

    Wang suggested financial institutions to implement differentiated credit policies while prioritizing loans to competitive coal firms.

    Attached Files
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    Daqin spring maintenance may postpone to late April

    The routine spring maintenance of coal-dedicated Daqin railway may postpone to late April or even early May this year, in order to meet restocking demand from utilities, sources said.

    Last year, the maintenance of Daqin, connecting Datong, Shanxi to Qinhuangdao port, started on April 6 and lasted for 25 days.

    Presently, coal burns at power plants under the six coastal utilities stayed at a relatively high level of 650,000 tonnns, due to robust industrial activities and low hydropower output.

    However, coal stockpiles at these power plants fell 5.5% from the previous week to 9.79 million tonnes on March 15, which could last for 15.2 days of consumption, down from 15.8 days a week ago.

    Utilities may start a new round of restock in April, as coal stocks were not enough to meet consumption.

    The spring maintenance usually lasts for 20-25 days. Total rail coal transport during the maintenance may reduce 16.6%, with daily transport falling from 1.2 million tonnes to 1-1.05 million tonnes.
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    Peabody eyes bankruptcy exit in April

    Peabody Energy Corp, the world's largest private sector coal producer, said on Thursday it expects to exit its Chapter 11 bankruptcy in early April after a U.S. judge said he would approve its plan to slash over $5 billion of debt.

    U.S. Bankruptcy Judge Barry Schermer said he was ready to sign an order to approve Peabody's bankruptcy emergence once language regarding a late settlement of certain U.S. Department of Justice complaints had been finalized.

    St. Louis-based Peabody will leave bankruptcy amid dramatically improved short-term prospects for its business compared to a year ago, when it sought Chapter 11 protection.

    "Peabody has accomplished the goals set out nearly a year ago, against an industry backdrop that has strengthened," Chief Executive Officer Glenn Kellow said in a statement.

    The reorganization plan, which will repay secured lenders in full, received overwhelming support from its creditors.

    Peabody plans to re-list on the stock market, coinciding with increased demand from Asia and anticipation of eased regulation under U.S. President Donald Trump that has fueled investor enthusiasm for coal.

    Coal producer Ramaco Resources Inc recently completed an initial public offering and Warrior Met Coal has filed to sell shares in an IPO.

    Peabody's plan is being financed through a $1.5 billion sale of stock, consisting of a $750 million rights offering available to bondholders and a $750 million private placement of preferred equity for institutional investors.

    A small group of asset managers opposed the plan because they said it was proposed in bad faith and attacked the private placement for enriching the select funds that helped negotiate the company's bankruptcy plan.

    "The value of the private placement is truly extraordinary," said Andrew Leblanc, a lawyer who represented the opponents to the plan. He said they would appeal the bankruptcy confirmation.

    The opponents argued in court papers that the main funds backing the plan stood to reap hundreds of millions of dollars in profits because the plan underestimated Peabody's potential.

    Hedge funds Elliott Management and Aurelius Capital Management played a key role in crafting the reorganization plan by urging Peabody to use an accounting change to weaken the position of the company's lenders.

    The dispute went into mediation and eventually formed the basis for the reorganization plan.

    Peabody reached last-minute settlements on a number of objections to the plan, including one from individual investors who said they were wrongly blocked from the private stock sale.

    Peabody, which owns prime assets in Australia and coal-rich Wyoming in the United States, also recently settled objections over its environmental liability policy and a mine workers union retirement plan.

    Schermer overruled other objections, including from shareholders whose stock will be wiped out in the reorganization.

    The plan also includes a stock bonus plan for employees and executives, including about $15 million for CEO Kellow and $3 million to $5 million for five other top executives.
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    Vale to get $733m by month-end from Moatize stake sale to Mitsui

    Brazilian mining company Vale said on Wednesday it is nearing conclusion of a deal to sell a stake in Mozambique's Moatize coal project to Japan's Mitsui & Co.

    Vale said it expects to receive by the end of this month an initial payment of $733-million from Mitsui from the equity sale. The company said it would receive $2.7-billion more after the financing for the project of the mine and the transportation system is concluded.

    Vale has been in talks with Mitsui over the Moatize project for almost three years. But the firms previously had said that any payments or the conclusion of the deal would only take place once financing was sealed. Now, the two processes are being handled separately.

    Mitsui will have an option to transfer back to Vale the stake in the project if financing is not completed by December, the statement said.

    The Japanese company is buying 15% of Vale's 95% share in the coal mine. It is also acquiring 50% of Vale's 70% stake in the Nacala logistics corridor, a railway system connecting production at the mine to the Nacala port, in Mozambique.
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    China bulls kick iron ore price back above $90

    Renewed optimism about the strength of Chinese demand saw iron ore and steel prices spike on Wednesday after statistics showed the economic rebound in the world's top commodities consumer accelerating into 2017.

    The Northern China import price of 62% Fe content ore rose 4.2% to trade at $92.1 per dry metric tonne according to data supplied by The Steel Index after the world's most traded steel futures contract – Shanghai rebar – jumped to the highest since February 2014. Volatile trading on the Dalian Commodities Exchange saw domestic iron ore price surge 5.5% to triple digits on Wednesday.

    The Statistics Bureau of China said yesterday industrial production led by the construction industry jumped 6.3% in January and February of 2017 (released together to smooth out distortions in the data caused by the Chinese new year).

    Beijing's policies to clean up and consolidate the domestic steel industry is also playing into the hands of iron ore miners
    Fixed asset investment shot up by 8.9% compared to 8.1% for 2016 as a whole thanks to strong private sector investment.

    After a 85% rise in 2016, the price of iron ore is up another 16%  this year and has more than doubled in value since hitting near-decade lows at the end of 2015.

    China forges as much steel as the rest of the world combined and completely dominates the 1.3 billion tonne seaborne iron ore market.

    Beijing's policies to clean up and consolidate the domestic steel industry is also playing into the hands of iron ore miners with low grade furnaces – particularly those that use scrap – being forced out of business. Authorities are also clamping down on pollution from sintering plants, a necessary extra step when using low grade ore (domestic Chinese iron content averages only about 20%) to make steel.

    Import, import, import

    While worries about supply and  stockpiles at record highs have plagued the market, imports by China continued to strengthen in 2017 after hitting an all-time high last year.

    The all-time record in terms of dollar value was set in January 2014, when the country imported $11.3 billion worth of iron ore back when prices were firmly in triple digits

    Trade figures released last week showed China imported 83.5 million tonnes of ore in February, up 13% compared to last year.

    Total imports for January-February climbed 12.6% to 175.3 million. Iron ore is averaging $84.90 a tonne in 2017, compared to less than $45 during the first two months last year.

    The all-time record for monthly Chinese imports in terms of volume was in December 2015 with shipments totalling 96.3 million tonnes. But the price of iron ore fell to below $40 a tonne pushing the value of shipments below $5 billion.

    The all-time record in terms of dollar value was set in January 2014, when the country imported $11.3 billion worth of iron ore back when prices were firmly in triple digit territory. Chinese imports of iron ore for the full year 2016 topped one billion tonnes for the first time.

    The 1.024 billion tonnes constitute a 7.5% increase over the annual total in 2015 and is indicative to what extent exporters from Brazil and Australia has been able to displace high-cost domestic producers.

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    China's late Feb key mills daily output up 3.5% MoM

    Daily crude steed of China's key mills stood at 1.74 million tonnes over February 21-28, increasing 3.48% to 58,400 tonnes from previous ten days, according to data released by the China Iron and Steel Association (CISA).

    During the same period, the country's total crude steel output was estimated to climb 69,800 tonnes or 3.15% from ten days ago to 2.29 million tonnes each day on average, the CISA said.

    As of February 28, stocks of steel products at key steel mills stood at 13.09 million tonnes, down 1.18 million tonnes or 8.26% from ten days ago, the CISA data showed.
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    Anyang Iron and Steel swings to profit in 2016

    Anyang Iron and Steel Co., Ltd, the largest steel maker in China's Henan province, swung to profit last year, with net profit of 123 million yuan ($17.8 million), announced the company in its annual report late March 15.

    It realized 22.04 billion yuan of operating revenue in 2016, a year-on-year increase of 8.25%, according to the report.

    The company produced 8.18 million tonnes of pig iron last year, down 3.54% from the year prior; its output of crude steel and steel products stood at 8.08 million and 8.09 million tonnes during the period, down 2.42% and 6.26% year on year, respectively.

    It believed that a downward adjustment of China's GDP to 6.5% from last year's 6.7% would lead to further slowdown of domestic economy, which will not bolster up steel demand.

    China will continue to implement the supply-side structural reform to optimize the industrial structure this year. The country's consumption of crude steel is expected to drop to 650 million-700 million tonnes or so during the 13th Five-Year Plan period (2016-2020), and crude steel capacity will reduce 100-150 million tonnes per annum (Mtpa).

    In 2017, the company plans to produce 8.48 million tonnes of pig iron, 8.46 million tonnes of crude steel and 8.39 million tonnes of steel products. The sales revenue is expected to reach 25.4 billion yuan.

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