Mark Latham Commodity Equity Intelligence Service

Thursday 18th August 2016
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    Too Much Stuff: Hedgehog Houses

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    A Look at the Symbolic Meaning of the Hedgehog

    It's true, big things really do come in small packages and the animal symbolism of the hedgehog proves it.

    Those with the hedgehog as their animal totem know how to take care of themselves and do so with grace and style. We make this association by observing the hedgehog when it is threatened. It packs itself tightly in a neat little ball, exposing some lethal looking quills. Any predator who takes a bite of this prickly morsel will spit it right back out.

    Same goes with those who honor the hedgehog as their totem - these people always land on their feet and go through challenges with the same calm, cool practicality as the hedgehog does.

    This little creature packs a powerful symbolic punch with animal symbolism including, and connecting with the deeper meaning of the hedgehog will restore your own power supply.
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    Too much capital: negative rates.

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    Too much labour: migration poses problems.

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    Shipping traffic suspended in Turkey's Bosphorus after collision -shipping agent

    Traffic in Turkey's Bosphorus Strait, a key international shipping lane for oil and grain, was suspended on Wednesday after a bulk carrier collided with a coast guard boat, shipping agent GAC said.

    Six people were rescued and taken to hospital, a spokesman at the office of the Istanbul governor said.

    The coast Guard in Istanbul said it was unable to provide information on the accident.

    The collision occurred at 8:40 a.m. (0540 GMT) at the southern end of the strait, forcing the capsize of the coast guard vessel, GAC said.

    GAC identified the cargo ship as the M/V Tolunay, a Cook Island-flagged bulk carrier headed north to the Black Sea.

    More than 3 percent of the global crude supply - mainly from Russia and the Caspian Sea - pass through the 17-mile Bosphorus that connects the Black Sea to the Mediterranean.
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    China police crack down on $30 billion in underground banking

    Chinese police have busted underground banks that handled 200 billion yuan ($30.2 billion) in illegal money transfers this year, the Ministry of Public Security (MPS) said on Wednesday.

    Police said they arrested 450 suspects involved in 158 cases of underground banking and money laundering, according to a notice posted on the MPS official website.

    Beijing has been fighting illegal cross-border outflows in an attempt to slow capital flight as its yuan currency weakens to near six-year lows.

    A special task force, jointly launched by the MPS, the central bank, and the foreign exchange regulator, uncovered illicit banking services in 192 locations this year, the notice said.

    On Wednesday, China state broadcaster CCTV separately reported that police in the southern city of Shenzhen recently busted an underground bank that handled 30 billion yuan in transactions over a six-year period.

    Police arrested 26 major suspects in four different cities, the report said. The underground bank was disguised as a trade company.

    "The key (problem) is that underground banks have become channels for drug dealers, smugglers, and economic criminals to transfer funds,” Shu Jianping, head of the anti-money laundering unit at the Ministry of Public Security, told CCTV.

    Beijing started a campaign against illegal banking in April last year and uncovered over 170 cases of money laundering and illegal fund transfers involving more than 800 billion yuan as of last November.

    The crackdown included an investigation into the country's biggest underground banking case involving $64 billion worth of illegal transactions.

    Although the crackdown has curbed underground banking to some extent, illegal activities using those "grey capital" networks are still spreading and becoming more elusive as collusion between banks in different regions is rife, the notice said.

    Underground banks are channels for transferring money obtained through illegal activity, including public funds embezzled by corrupt officials, an earlier Xinhua news agency report on the crackdown said.
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    Oil and Gas

    Iran's crude oil exports above 2.1 mln bpd in July - SHANA

    Iran's crude oil exports in July were more than 2.1 million barrels per day, the oil ministry's news agency SHANA cited a senior Iranian oil official as saying on Wednesday.

    Director of the International Affairs Department at National Iranian Oil Company (NIOC) Mohsen Ghamsari told SHANA the total amount of crude and gas condensate exports by Iran reached 2.740 million bpd in July. He said 600,000 bpd out of that figure were condensate exports.

    "Exports of crude are now at a good level but ... have not yet touched that of the pre-sanction level," he said, adding that Iran used to export 2.350 million barrels of crude per day before international sanctions were imposed.

    Ghamsari did not give a figure for Iran's oil exports in June but a source with knowledge of the country's crude lifting plans had told Reuters exports that month were about 2.31 million bpd.
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    OPEC’s Former Head Says Conditions Are Right for Oil-Freeze Deal

    OPEC is on course to strike an output-freeze deal with fellow oil producers in Algiers next month because its biggest members are already pumping flat-out, the group’s former president said.

    While a similar initiative failed in April, an agreement can now be reached as Saudi Arabia, Iran, Iraq and non-member Russia are producing at, or close to, maximum capacity, Chakib Khelil said in a Bloomberg Television interview. Khelil steered OPEC in 2008, the last time it implemented an output cut, which was announced in Algeria in December of that year.

    “All the conditions are set for an agreement,” Khelil said from Washington. “Probably this is the time because most of the big countries like Russia, Iran, Iraq and Saudi Arabia are reaching their top production level. They have gained all the market share they could gain.”

    While oil prices have advanced since OPEC announced it would hold informal talks in the Algerian capital next month, analysts from UBS Group AG to Commerzbank AG doubt any freeze deal will be completed, and comments from Saudi Arabia and Nigeria have kept expectations low. Talks collapsed in April as Saudi Arabia insisted Iran would have to limit its production, a condition the country rejected as it ramped up exports previously curbed by sanctions.

    As producers are almost pumping at full-tilt, the impact of any accord to prevent further increases would essentially be “psychological,” Khelil said. That would nonetheless have a benefit for the market, according to the Algerian, who was also the country’s energy minister from 1999 to 2010.

    The global crude oversupply is already diminishing, and markets will probably reach “complete equilibrium” next year, Khelil said.
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    Too Big to Frack? Oil Giants Try Again to Master Technology That Revolutionized Drilling

    The oil-and-gas well BP PLC is drilling here in the Texas Panhandle looks ordinary enough from the surface. Yet a mile-and-a-half underground, horizontal pipes shoot off for at least a mile in three directions, like a chicken’s foot.

    The idea, part of an experiment by BP executive David Lawler, is to make three wells from one. It also is designed to help turn the London-based energy giant into a shale-oil innovator that can better compete with the entrepreneurial outfits that pioneered the business of hydraulic fracturing, or fracking.

    Big oil companies like BP are in need of a jolt. The multibillion-dollar projects they specialize in—giant offshore oil rigs and gas-export projects—are often prohibitively expensive in a world of $45-a-barrel oil. U.S. wells are a tempting option, but major oil companies have yet to prove they can master the techniques pioneered by shale drillers, whose innovations fueled a rebirth in U.S. energy production.

    London-based BP is moving into shale-oil drilling with wells such as the King Harry 1H in the Texas Panhandle, which descends 8,000 feet before splitting into three shafts. 

    If BP, Exxon Mobil Corp. and others can figure out how to coax enough oil out of fracked wells cheaply enough to make it profitable, it could help them maintain production levels. Failure could make it harder to replace the oil from declining older megaprojects, and leave them further behind on innovations transforming the industry.

    Six years after the Deepwater Horizon accident in the Gulf of Mexico caused the worst offshore spill in U.S. history, BP is turning again to America. Mr. Lawler, a former college football linebacker turned engineer, is in charge of the push into shale oil and gas. If the Perryton well succeeds, Mr. Lawler could try the same thing with drilling leases BP has in Oklahoma, Texas and beyond, potentially yielding oil and gas on a large scale.

    He isn’t the only Lawler in the fracking business. His older brother, Robert, known as Doug, is chief executive of Chesapeake Energy Corp., the trailblazer founded by fracking pioneer Aubrey McClendon, who died in a car crash in March.

    The Lawler brothers are part of the second wave of the fracking revolution: a move away from debt-fueled drilling mania to what they hope will be a more financially sustainable future.

    Doug’s challenge is to take debt-laden Chesapeake and its attractive drilling leases and turn it into a profitable business. David’s mission is to crack the code of shale drilling for BP, something that the world’s biggest energy companies haven’t been good at.

    Processes designed for huge offshore platforms are a poor fit for fracking, which requires endless tinkering to be successful. Frackers must also develop a substantial tolerance for failure. They often must drill dozens of wells to figure out the best techniques for particular locations.

    So far, big oil companies have compiled a poor record in U.S. fracking. Their fracked wells don’t produce as much as those of industry leaders because they haven’t mastered the technology. They have taken more than $20 billion in write-downs, some stemming from top-of-the-market acquisitions of fracking companies, and the plunge in crude prices has made things worse. Exxon has lost money in its U.S. drilling business for six straight quarters.

    In 2014 and 2015, shale wells drilled by BP, Royal Dutch Shell PLC, Exxon and Chevron Corp. were one-third less productive, on average, than the top 10 operators, according to data from analytics firm NavPort. Their wells have improved each year, but so have those of the top operators. Many big companies—often called “integrated” firms because they have production and refining operations—say they are getting better and have drilled some profitable wells.

    “You have to be quick, you have to be nimble, you have to be flexible,” says shale pioneer Mark Papa, former chief executive ofEOG Resources Inc. “The track records of the integrateds is really not very pretty.”

    David Lawler, 48 years old, acknowledges the challenges BP faces trying to go small. Exxon, Shell and Total SA all notched losses or write-downs from their shale businesses, even before oil prices began falling two years ago.

    Yet Mr. Lawler says he is optimistic that BP can make shale profitable at today’s prices, even if it isn’t blessed with what others in the industry see as good rock—land in the country’s most prized oil-and-gas basins. “It’s about how fast we can change,” he says.
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    South Korea LNG imports down 15.2 pct in July

    Imports of liquefied natural gas (LNG) by South Korea, the world’s second-largest buyer of the chilled fuel, dropped 15.2 percent year-on-year in July, according to the customs data.

    South Korea imported 1.92 million mt of LNG in July, as compared to 2.26 million mt in the corresponding period in 2015.

    The country paid US$584 million for July imports, down 44 percent on year, the data showed.

    Most of the LNG imports in July came from Qatar (822,265 tonnes), down 25.8 percent as compared to July in 2015.

    The rest of South Korea’s LNG imports in July were sourced from Indonesia, Oman, Malaysia, Australia, Angola, Brunei, and Russia.

    To remind, state-owned Kogas that handles almost all of the LNG imports into South Korea saidlast week its sales volume dropped 2.8 percent in the first half of this year to 16.75 million mt of LNG.

    The company’s sales into the power sector dropped down 8.2 percent in January-June as South Korea used more coal and nuclear for power generation.

    Kogas sold 2.19 million tonnes of LNG in July,  a rise of 15.2 percent on year.
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    China drafts rules to lower natural gas transportation costs

    China's state planner has proposed new rules regulating the cost of transporting natural gas by pipeline that analysts say will lower prices in order to boost consumption of the cleaner-burning fuel.

    The government will use an "allowed cost plus reasonable margin" scheme in setting the transportation cost for natural gas, the National Development and Reform Commission (NDRC) said on Wednesday on its website.

    Under the proposal, natural gas pipeline operators will fix their transportation prices by compiling the cost of their fixed assets such as pipelines and storage, operating costs and depreciation, and then adding a fixed 8-percent margin to those costs, the NDRC said.

    However, the 8 percent margin only applies to pipelines with a capacity utilization higher than 75 percent, the NDRC said, without stating what the margin would be for pipelines using less than 75 percent of their capacity.

    The lower margin should lower the gas costs for consumers as the current margin pipelines are making is believed to be higher than the 8 percent proposed by the NDRC.

    Analysts said the changes underscore Beijing's plan to lift sagging demand growth for natural gas, seen as the most efficient fuel to cut greenhouse gas emissions in the world's largest emitter and tackle air pollution. China is the world's third-largest gas consumer.

    "The new regulation should help reducing the cost of natural gas," said Diao Zhouwei, a Beijing-based analyst with IHS. "China's reform of its natural gas pipeline is moving toward its planned direction. Focusing on tightening pricing regulations as well as lowering the cost through better transparency."

    Previously, transportation cost were set by the NDRC based on the individual pipeline projects. This new proposal would apply across companies rather than by specific pipeline.
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    Fed-up east coast Aus gas buyers hatch LNG import plan

    Industrial gas buyers have been forced to consider importing LNG at a Sydney or Melbourne port to ensure a competitive supply of gas due to what they say is a major failing of energy policy that has left manufacturers stranded and put jobs on the line.

    Manufacturing Australia chairman Mark Chellew said initial studies showed gas could be imported from the US at a price of about $6 a gigajoule, about a third less than prices some industrial users are facing by 2018.

    "If we got to that stage it would be a major fundamental policy flaw of all governments," Mr Chellew said. "It is a flaw that we've got to the stage of having to seriously consider it."

    Mr Chellew partly blames the "over-zealous" drive into renewable energy by some state governments for contributing to the energy difficulties that erupted in South Australia in June and which he says risk spreading across the eastern states.

    At the same time, the onshore gas ban in Victoria, difficulties with NSW gas and a tripling in demand for gas on the east coast due to the new Queensland LNG export industry have squeezed supplies for manufacturers, chemical producers and power generators.

    "We jumped off a cliff around 15 years ago and we haven't yet invented the parachute," Mr Chellew said of the policy failings that led to the current fix, which has left local gas buyers short of supplies at the same time as Australia is set to become the world's biggest LNG exporter by 2019.

    "We are supportive of the federal renewable energy target but we need to make sure that the energy grid in Australia is stable and able to supply electricity continuously to industry. The stability of the grid is dependent on sufficient coal or gas-fired power stations."

    Seeking solutions

    Mr Chellew's comments come ahead of Friday's meeting of federal and state energy ministers in Canberra which will cover potential solutions to the energy supply problems evident in South Australia in June, including new inter-state power interconnectors and boosting gas supply.

    Manufacturing Australia, whose members include Brickworks sand BlueScope Steel, wants LNG imports to be among options under discussion, given government would need to take a lead in aggregating demand and making it happen. It has raised the idea with Federal Energy and Resources Minister Joel Frydenberg and the energy ministers in NSW and South Australia.

    "They are aware that the level of frustration in industry has got to the point where this is on the table," said executive director Ben Eade.

    The concept is based on a project in Lithuania, which started LNG imports in late 2014 to gain independence from Russian gas giant Gazprom. A re-designed LNG carrier, moored permanently at the the coastal city of Klaipeda, is refuelled by LNG tanker and turns the super-chilled fuel back into gas and feeds it into the pipeline network.

    According to consultancy Gaffney Cline, gas could be supplied using a similar vessel at a port in Brisbane, Sydney or Melbourne for as little as $6 a gigajoule assuming demand of at least 100 petajoules a year. That compares to $8-$10 a gigajoule that some manufacturers face in 2018.

    The analysis assumes current low US gas prices and includes processing into LNG, shipping and regasification. The cost of offloading gas from the vessel into the network and piping it to the user would add about $1 a gigajoule.

    "It is something we really do not want to do," Mr Chellew said. "But maybe they've got to seriously look at that as an alternative to where we're at. We would hope there is a lifting of the ban on onshore gas development around Australia. We think that's a better solution."

    The concept is similar to one raised cynically by Shell Australia chairman Andrew Smith in an address in June when he suggested importing LNG into Port Botany could be the only answer to onshore gas moratoria. But he cautioned the benefits were unlikely to outweigh the costs.

    Weak spot prices

    EnergyQuest consultant Graeme Bethune said the outlook for several years of weak LNG spot prices meant the idea was "certainly worth pursuing".

    "The way to do it would be a floating regasification terminal; they can be put in place pretty quickly and pretty cheaply and then it would be a matter of looking at different points and the connections to infrastructure. One of the challenges would be aggregating enough willing buyers."

    In early July spot prices for gas on the east cost approached $45 a gigajoule as an extended cold snap across the eastern states combined with the impact of intermittent renewables generation in South Australia and rising demand for gas from the Gladstone LNG industry. That pushed Adelaide spot prices up to average $13.90 a gigajoule in July, about 65 per cent more than the raw Japanese LNG import price. Prices to Japanese industrial users would be about 30 per cent more than the import price, Dr Bethune said.

    "Gas prices are substantially higher in Australia than they are abroad," Mr Eade said. "You don't just sit back and accept that: if there are other ways you can access the true international price for gas then they need to be looked at."

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    Floating storage eyed for European naphtha on oversupply

    A few charterers such as Koch are looking to put naphtha on Long Range 2 tankers as floating storage in the Mediterranean region because Europe has been bursting at the seems with naphtha over the last two quarters against the background of a closed arbitrage to the Far East, sources said Wednesday.

    "Koch was asking questions to put a LR2 tanker as floating storage on Tuesday, but I am not too sure if that was naphtha. Nonetheless, we declined as we don't want to lock-in the prices at such low levels given that market is very weak. But, we expect the markets to bounce back after the summer," a shipowner said.

    According to market participants, there are two options for charterers to deploy a ship as floating storage. Firstly, is by putting it on time-charterer, and secondly by putting the ship on a demurrage.

    The cost of putting a ship on a time-charter is around $18,000-$19,000 a day for a year, while if it goes on demurrage it's around $20,000-$21,000/day.

    A few shipbrokers said Koch was looking to put naphtha into floating storage, and it's likely to get a ship on demurrage.

    Sources said one LR2 loaded with naphtha was being used as floating storage in Gibraltar, while another LR2 carrying naphtha was heard on its way from the Russian Black Sea port of Tuapse to Gibraltar. This second LR2 was expected to be used as floating storage because the current contango as well as the physical discount -- CIF NWE naphtha physical cargoes were assessed Tuesday at a $6/mt discount to the September swap -- could offset the cost of demurrage.

    The naphtha market has remained bearish, the September crack was trading at minus $5.70/b at noon London time Wednesday, up from minus $5.85/b at market close Tuesday, while the September/October swap spread was seen trading at minus $5.00/mt, versus minus $5.25/mt at market close Tuesday.

    "We need to see the August/September spread weaken for that to be economic," a trader said when asked about the logic for keeping naphtha in floating storage.

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    BP to Halliburton in ‘Barroom Brawl’ as Drillers Slash Costs

    Mad Dog, BP Plc’s drilling project deep in the Gulf of Mexico, could be Exhibit A in the oil industry’s war on cost.

    When the British oil giant announced the project’s second phase in 2011, it put the price at $20 billion. Last month, after simplifying plans and benefiting from a sharp drop in everything from steel to drilling services, Chief Executive Officer Bob Dudley said he could do the job for $9 billion.

    Across the industry, companies have taken a chainsaw to expenses, slashing spending for the 2015-to-2020 period by $1 trillion through cutting staff, delaying projects, changing drilling techniques and squeezing outside contractors, according to consulting firm Wood Mackenzie Ltd. That’s cushioned businesses as oil prices plunged 60 percent since 2014. Now producers seek to show they can make the savings stick, while service providers try to reverse their losses.

    Industry costs “may be the defining issue of the next six to 12 months," said J. David Anderson, a Barclays analyst in New York. “As you start ramping up, the fact is you’re going to need more services and they’re going to have to come in at a higher price."

    London-based BP expects 75 percent of its reductions to hold even if oil rebounds, Dudley told investors in July. In earnings reports over the last month, U.S. shale drillers said at least half of their savings are permanent improvements in efficiency. But service providers such as Schlumberger Ltd. and Halliburton Co., which perform much of the drilling and hydraulic fracturing around the globe, tell a different tale: They may have cut rates to keep business during the oil rout, but those discounts were temporary.

    “Price negotiations have been a barroom brawl," Jeff Miller, president of Houston-based Halliburton, said on a July 20 conference call. “But we believe prices will recover."

    Who’s right could have big implications for the oil industry and the broader economy.

    U.S. benchmark oil has climbed about 18 percent since closing below $40 a barrel and slipping into a bear market this month. The grade traded at $46.77 a barrel at 12:51 p.m. Singapore time.

    “A lot of the actions that we’ve taken are what we would call self-help type of things, changing the way we work,” said Stephen Riney, chief financial officer of Houston-based Apache Corp., an oil explorer. “These are things that are not dependent upon the pricing from third parties.”

    While the industry has gotten more efficient, it’s likely to give back most of the gains, said Pritesh Patel, upstream director at research firm IHS Markit Ltd. About half the decline came as a strong U.S. dollar reduced the relative price of materials and labor, Patel said. Contractor discounts accounted for much of the rest, he said.

    Sustaining Cuts

    Producers will be lucky to sustain a third of the cost reductions, Patel predicted.

    One example of a cut that may soon be lost is in the Eagle Ford Shale in south Texas, where the price to lease a drilling rig with a crew tumbled by almost a quarter in the two-year downturn to $18,208 a day, according to a Bloomberg Intelligence estimate.

    Service providers say they’re getting to a point where they may no longer be able to offer such a discount. Schlumberger, Halliburton and Baker Hughes Inc., the top service companies, all reported losses in North America in the first three months of 2016.

    “A large wave of cost inflation from every part of the supplier industry is now building," Schlumberger CEO Paal Kibsgaard said on a July 22 call. Profit margins, he said, are “deeply negative."

    Permanent Changes

    Oil explorers insist they’ve made lasting changes. In the North Sea, producers such as BP are standardizing everything from drilling equipment to the light bulbs and paint used on offshore rigs. In the U.S., companies have built out infrastructure in shale plays, installing pipelines to transport crude and wastewater rather than paying to truck it away.

    In the Permian Basin in west Texas, Devon Energy Corp. has extended electricity to its well sites, allowing it to eliminate 300 rented generators, Chief Operating Officer Tony Vaughn said on an Aug. 3 call. Occidental Petroleum Corp. CEO Vicki Hollub said her company has improved well designs and can drill more quickly, accounting for about 80 percent of cost reductions.

    Apache has renegotiated power, water and chemical-handling contracts and cut lease-operating expenses, a measure of drilling efficiency, by 17 percent, CEO John Christmann told analysts on Aug. 4.

    Producers such as Apache and Devon are going to have to accept “the reality” of the service companies’ situation, Halliburton CEO Dave Lesar said last month.

    “Some of the efficiency gains we have made with customers are in fact sustainable and will continue, but others including deep uneconomic pricing cuts are unsustainable and will have to be reversed,” he said.

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    Tight gas output triples in Argentina’s Neuquen basin, but costs still vary

    A large shift to tight gas production in Argentina’s Neuquen basin is being driven by pricing incentives and lower costs vs. shale gas wells. However, at current costs, only the best tight gas wells break even at the incentivized $7.50/MMbtu gas price, according to analysis from research and consultancy firm Wood Mackenzie Ltd.

    Tight gas production from the basin almost tripled over a 2-year period to 565 MMcfd during the first quarter, representing one quarter of the basin’s overall output, WoodMac notes, but well performance has been variable across all formations. Of the six tight gas formations studied, the median well in the Neuquen basin has a 90-day initial production (IP) rate of 2 MMcfd, with top quartile wells performing about five times higher than the bottom quartile.

    Horizontal wells targeting the Mulichinco formation show the highest estimated ultimate recovery (EUR) at more than 5 bcf. The best wells in Punta Rosada are expected to achieve similar results with a vertical construction. Representative wells in the Lajas formation, meanwhile, are expected to recover a third of that volume.

    “The large variability indicates that tight gas in Neuquen will continue to require a statistical development approach,” said Horacio Cuenca, WoodMac director of Latin America upstream research. “This means that large, multiwell development programs will be used to spread the productivity risk among a large number of wells. This approach is more similar to shale than to conventional developments.”

    High costs, high output

    WoodMac notes that longer laterals, more fracture stages, and increased water and propant usage are all factors that have been shown to enhance production but also increase well cost. Different sections of the same play also require unique considerations given variance in rock quality and thickness, pressure, and temperature.

    “What is critically important is the relationship between the cost of these wells and the productivity they can achieve,” said Cuenca. “Our analysis shows that the tight gas wells with the highest costs also have the highest EURs and IP rates.”

    Using type-well EURs and WoodMac’s current well-cost estimates, Mulichinco horizontal wells and Punta Rosada vertical wells, the most expensive in the basin on average, are profitable at or below the government’s $7.50/MMbtu incentivized gas price. These costs reflect a 15% reduction versus 2015 levels driven by the strong peso devaluation at the beginning of 2016. However, considerable additional reductions are still needed for type wells in these and other formations to be economic at the $5.20/MMbtu average gas price without incentives.

    “Beyond discovering and focusing on the best producing sweet spots in each formation, enhancing EURs through more expensive wells—i.e. horizontal sections or targeting deep, thick formations with a high number of frac stages—seems a more plausible path for improving tight gas well economics in the short term rather than the drastic costs reductions needed with current EURs,” said Cuenca.

    Capital efficiencies on IP rates in the Neuquen basin ranged $9,340-20,000/boe/d while EUR capital efficiencies ranged $13.70-29/boe. In comparison, WoodMac’s recently estimated capital efficiencies for unconventional wells within the Karnes Trough and Edwards Condensate subplays of the south Texas Eagle Ford shale showed capital efficiencies on IP rates ranging $8,000-15,000/boe/d and EUR capital efficiencies ranging $16-31/boe.
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    Diesels splutter as new petrol engine emerges

    Nissan’s new petrol engine could make advanced diesel engines obsolete.

    The new engine – called a Variable Compression-Turbo (VC-T), has 27% better fuel economy than previous models but provides comparable power and torque.

    It’s also cheaper than today’s advanced turbo-charged diesel engines and should meet emissions rules in most countries without requiring costly treatment systems.

    “We believe this new engine of ours is an ultimate petrol engine that could over time replace the advanced diesel engine of today,” Kinichi Tanuma, a senior Nissan engineer said.

    James Chao, Asia-Pacific Managing Director at consultant IHS said: “Increasing the fuel efficiency of internal combustion engines is critical to automakers. Not all consumers will accept a battery electric vehicle solution. But significant challenges remain, such as increased complexity and cost, as well as potential vibration issues.”

    The VC-T powertrain is expected to be officially unveiled at next month’s Paris motor show.
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    Pay dispute, not terrorism behind Malaysian tanker ‘hijacking’

    A “hijacked” Malaysian oil tanker is thought to have been taken in a commercial dispute, a news report said.

    The MT Vier Harmoni vessel was believed to be sailing from the Malaysian port of Tanjung Pelepas when it went missing earlier this week.

    The ship, whose cargo of 900,000 litres of diesel is estimated to be worth £300,000, is now thought to be off the Indonesian island of Batam.

    A Malaysian Maritime Enforcement Agency (MMEA) spokesman told Reuters that there was “no element of terrorism involved in the tanker’s disappearance”.

    The authority said the ship may have been taken following a financial dispute between the vessel’s management and crew, which suggests a mutiny has taken place, not a hijacking.
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    Origin Energy suspends dividend as annual profit slumps

    Australia's Origin Energy suspended its final dividend as it scrambles to cut debt and trimmed its guidance, after weak oil prices and spending on the A$26 billion ($20 billion) Australia Pacific LNG project nearly halved its underlying annual profit.

    Australia's top power and gas retailer, whose Australia Pacific liquefied natural gas project started exporting this year just as oil and LNG prices slumped, said on Thursday it expects to cut net debt to below A$9 billion by next June.

    Underlying profit fell to A$365 million ($280 million) for the year to June 2016 from A$682 million a year earlier, in line with analysts' forecasts around A$370 million.

    "While the Board will review each dividend decision in light of the prevailing circumstances, the Board's view is that suspension of the dividend is in the best overall interest of shareholders," Chairman Gordon Cairns said in a statement.

    The second unit of two units at the 9 million tonnes a year APLNG project is on track to start producing in the December quarter, Origin said.

    The ramp up has been a bit slower than expected while the oil price slump has persisted, delaying the benefits of the massive project, one of three LNG plants that have started up side by side in Queensland since early 2015.

    Origin has previously said 2015 and 2016 would be transitional years for the company, but has now pushed that out to include 2017.

    "In FY2018 and beyond, as APLNG completes the transition from development to production of its LNG project, Origin expects to see significant growth in earnings and returns, strong cash flow and continuing reduction in debt," Origin Chief Executive Grant King said in a statement.

    With both APLNG units operating, the company said it expects underlying earnings before interest, tax, depreciation and amortization to rise by at least 45 percent to between A$2.37 billion and A$2.6 billion in the year to June 2017, roughly matching market forecasts.

    But excluding LNG, the 2017 guidance worked out to $1.8 billion to $1.95 billion, which was lower than the company flagged in February.

    "We anticipate a negative reaction to the guidance downgrade," Royal Bank of Canada analyst Ben Wilson said in a note, who added that the suspension of the dividend was expected.

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    US oil production surges

                                                 Last Week   Week Before  Last Year
    Domestic Production   '000...... 8,597            8,445          9,348
    Alaska '000................................. 477               425             438
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    Summary of Weekly Petroleum Data for the Week Ending August 12, 2016

     U.S. crude oil refinery inputs averaged about 16.9 million barrels per day during the week ending August 12, 2016, 268,000 barrels per day more than the previous week’s average. Refineries operated at 93.5% of their operable capacity last week. Gasoline production increased last week, averaging 10.3 million barrels per day. Distillate fuel production increased last week, averaging over 4.9 million barrels per day.

    U.S. crude oil imports averaged 8.2 million barrels per day last week, down by 211,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged over 8.4 million barrels per day, 11.3% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 610,000 barrels per day. Distillate fuel imports averaged 92,000 barrels per day last week.

    U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 2.5 million barrels from the previous week. At 521.1 million barrels, U.S. crude oil inventories are at historically high levels for this time of year. Total motor gasoline inventories decreased by 2.7 million barrels last week, but are well above the upper limit of the average range. Finished gasoline inventories increased while blending components inventories decreased last week. Distillate fuel inventories increased by 1.9 million barrels last week and are near the upper limit of the average range for this time of year.

    Propane/propylene inventories rose 1.8 million barrels last week and are at the upper limit of the average range. Total commercial petroleum inventories increased by 1.3 million barrels last week. Total products supplied over the last four-week period averaged about 20.8 million barrels per day, up by 1.4% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged about 9.8 million barrels per day, up by 1.7% from the same period last year. Distillate fuel product supplied averaged over 3.7 million barrels per day over the last four weeks, up by 0.3% from the same period last year. Jet fuel product supplied is up 6.0% compared to the same four-week period last year.

    Cushing down 800,000 Bbl

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    Eagle Ford rig productivity doubles

    Eagle Ford rig productivity has doubled in 18 months, from 550 to 1,100 B/d per rig. Better than Moore’s law!

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    US Methanol Confirms MDN Rumor – 2 (or More) Plants Coming to WV

    Last week MDN was the first to share the news that the California-based US Methanol is building at least two, rumoured up to five, methanol plants in the Mountain State.

    MDN shared a rumour (based on a source) that until we disclosed it, was not public knowledge: The first methanol plant they will build will be in Institute, WV, and the second in Belle, WV–both in the Charleston region.

    We now have confirmation of that rumour via several news accounts. We also told you that both plants were being disassembled in other countries and brought here.

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    FERC terminates Downeast LNG applications

    The United States Federal Energy Regulatory Commission on Wednesday issued an order dismissing and terminating Downeast LNG’s applications to build an LNG import/export terminal and associated facilities in Washington County, Maine.

    The project has been plagued with delays and hold-ups, with Downeast LNG requesting the commission to hold the pre-filing process in abeyance several times, first in November 2015, with the latest request filed on June 2 asking for the extension of the hold on the proceeding until September 30, 2016.

    According to the FERC order, Downeast LNG requested the latest extension while it “pursued discussions with existing and potential investors to optimize the Downeast LNG project.”

    Prior to the last request to hold the pre-filing process, Downeast LNG, with its majority shareholder, a private equity manager Yorktown Partners, put the company up for sale.

    “We have reviewed our strategy and decided that an industrial player or a specialized investor such as an infrastructure fund is better suited to continue the permitting process and eventual build-out of the project,” George Petrides, Chairman of the Board of Downeast LNG, said at the time.

    However, the commission noted that its “pre-filing process in Downeast has resulted in no significant recent progress toward the development of the bi-directional import/export project application or in stakeholder engagement.”

    In the past nine months, Downeast LNG made no progress and presented nothing to persuade the commission that its situation is likely to change, FERC said, declining the latest request to hold the proceedings in abeyance until September 30.

    In addition, because the project has not made progress in the pre-filing review process towards a single proposal, “its pending import application and bidirectional import/export pre-filing proceedings have become stale”, FERC said.

    The proposed project was planned to have the capacity to export up to 3 million tons of liquefied natural gas per year (450 mmcf/Day) and regasify up to 100 mmcf/d.
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    Exxon's Baton Rouge refinery puts off shutdown: sources

    ExxonMobil Corp on Wednesday put off plans to shut its Baton Rouge, Louisiana refinery after it managed to start a liquefied petroleum gas (LPG) processing unit in the adjoining chemical plant, sources familiar with plant operations said.

    An Exxon spokesman declined to discuss operations on specific units at the Baton Rouge refinery.

    "Contrary to some reports, the ExxonMobil Baton Rouge Complex is operating," company spokesman Todd Spitler said in an email. "It is our practice not to comment on specific unit operations at our facilities. We do expect to meet contractual commitments."

    Normally, the 502,500 bpd Baton Rouge refinery sends LPG to the Sorrento, Louisiana Storage Facility where it is kept underground in salt dome caverns until needed. Flooding forced the closure of the facility over the weekend, said the sources, who requested anonymity because they were not authorized to speak publicly about the matter.

    The floods, centered on the Baton Rouge area, have claimed at least 11 lives and forced thousands of people from their homes.

    On Tuesday, Exxon shut a 110,000 bpd crude distillation unit at the refinery to reduce LPG production and the company was prepared on Wednesday to shut the refinery if the chemical plant unit could not be started, the sources said.

    The chemical plant unit will process the LPG produced by the refinery, the sources said. The refinery's production level is down to about 60 percent of capacity.

    In addition to the chemical plant unit shut on Tuesday, Exxon cut production on a 210,000 bpd CDU in half for maintenance planned prior to the floods, the sources said.

    Two other CDUs at the refinery have a combined capacity of 180,000 bpd. The CDUs do the initial refining of crude oil coming into a refinery and provide feedstock for all other units.

    Motiva Enterprises LLC's 235,000 bpd Convent, Louisiana refinery continues to operate with only essential personnel due to flooding in the area, said sources familiar with the company's operations. They requested anonymity because they were not authorized to speak publicly about the matter.

    A Motiva spokeswoman did not immediately respond to requests for comment.

    Production at the refinery has been reduced since Thursday when a 45,000 bpd heavy oil hydrocracker was shut by a large fire.

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    Louisiana’s Sinking Coast Is a $100 Billion Nightmare for Big Oil

    The state can’t pay, so someone has to. And the water keeps rising.

    From 5,000 feet up, it’s difficult to make out where Louisiana’s coastline used to be. But follow the skeletal remains of decades-old oil canals, and you get an idea. Once, these lanes sliced through thick marshland, clearing a path for pipelines or ships. Now they’re surrounded by open water, green borders still visible as the sea swallows up the shore.

    The canals tell a story about the industry’s ubiquity in Louisiana history, but they also signal a grave future: $100 billion of energy infrastructure threatened by rising sea levels and erosion. As the coastline recedes, tangles of pipeline are exposed to corrosive seawater; refineries, tank farms and ports are at risk.

    “All of the pipelines, all of the things put in place in the ’50s and ’60s and ’70s were designed to be protected by marsh,” said Ted Falgout, an energy consultant and former director of Port Fourchon.

    Louisiana has an ambitious -- and expensive -- plan to protect both its backbone industry and its citizens from this threat but, with a $2 billion deficit looming next year, the cash-poor state can only do so much to shore up its sinking coasts. That means the oil and gas industry is facing new pressures to bankroll critical environmental projects -- whether by choice or by force.

    “The industry down there has relied on the natural environment to protect its infrastructure, and that environment is now unraveling,” said Kai Midboe, the director of policy research at the Water Institute of the Gulf. “They need to step up.”

    Every year in Louisiana, more than 20 square miles of land is swallowed by the Gulf. At Port Fourchon, which services 90 percent of deepwater oil production, the shoreline recedes by three feet every month. Statewide, more than 610 miles of pipeline could be exposed over the next 25 years, according to one study by Louisiana State University and the Rand Corporation. Private industry owns more than 80 percent of Louisiana’s coast.

    The land loss exacerbates another natural threat: storm-related flooding, like that affecting Baton Rouge now. About 40,000 homes in southeastern Louisiana have been affected by devastating flooding, and at least 8 people have died. The flooding occurred after some areas received more than 26 inches of rain over a three-day period, causing water to overrun levees along several tributaries.

    Barrier islands, marshes and swamps reduce storm surge and soak up rainfall like a sponge. But as the land erodes, storms advance without a buffer, and Louisiana's flood protection systems become less effective. The state estimates that damage from flooding could increase by $20 billion in coming years, if the coastline isn't reinforced.

    Lots More:
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    Precious Metals

    Capital Drilling sees signs of recovery in mining sector

    The under-pressure mining sector might be seeing flickers of life, services company Capital Drilling has said, after reporting a rise in revenue for the first time in four years.

    The London-listed company, which provides drilling rigs primarily to gold mining companies across Africa and South America, said the industry was enjoying “increasing interest” on the back of a gradual recovery in metal prices this year.

    “The increasing interest from the mining industry, particularly over the last few months, to invest in assets combined with the firming of selected metal pricing, has injected some momentum in tendering for new contracts as well as higher demand from existing clients for the group's drilling services,” said Mark Parsons, chief executive.

    Capital Drilling reported a 7pc rise in revenue to $41.7m in the six months to June 30, while pre-tax profits rose to $748,000. It slipped to a net loss of $840,000 on the back of a one-off tax charge, although this was an improvement on the $3.2m it lost in the same period a year ago.

    The rising gold price, which has been buoyed by investors seeking safe havens in the wake of the Brexit vote, has been a boon to some of Capital’s clients, which include AngloGold Ashanti and Centamin. As a sign of its confidence in its outlook, Capital raised its interim dividend 36pc to 1.5 US cents a share.

    Capital works mainly with gold miners

    Capital, which listed on the LSE in 2010, has been on the turnaround trail since being hit hard by the downturn in the mining industry that sent its share price tumbling in 2012.

    It has cut costs and paid down debt, and today reported a jump in its rig utilisation rate – the percentage of its 94 drilling rigs that are actually in use – from 34pc to 40pc. However, this remains some way off the 90pc rate it enjoyed in the boom times.

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    Royal Gold Announces Fourth Quarter Dividend

    Royal Gold, Inc., today announced that its Board of Directors has declared its fourth quarter dividend of US$0.23 per share of common stock. The dividend is payable on October 14, 2016 to shareholders of record at the close of business on September 30, 2016.

    Royal Gold is a precious metals royalty and stream company engaged in the acquisition and management of precious metal royalties, streams, and similar production based interests. The Company owns interests on 193 properties on six continents, including interests on 38 producing mines and 24 development stage projects.
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    Base Metals

    China must import more ore

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    China is the leader in extracting gold, zinc, lead, molybdenum, coal, tin, tungsten, rare earths, graphite, vanadium, antimony and phosphate, and holds second place in mine production of copper, silver, cobalt, bauxite and manganese.

    A new report from BMI Research shows the country's domestic mining output growth has slowed dramatically and will average far below levels attained in the last decade. Reasons for the slowdown are plentiful.

    Besides lower prices, increasing costs, depleting grades and low reserves, Beijing's drive to consolidate the country's mining industry as part of its sharpened environmental policies has played an important role in curbing new capacity and forcing production cuts says BMI.

    So far this year domestic copper, nickel, bauxite, iron ore and lead mining output have been curtailed (of course coal too). Tin and zinc mining supply have reacted to higher prices, but production growth is coming off a low base after two years of declines.

    China's of consumption of metals and minerals far outstrip domestic supply – in iron ore its imports constitute nearly 80% of  use and in copper it’s approaching 50% and for nickel it’s already above that.

    Chinese imports of metals and minerals, particularly ores, have hit records recently with bauxite imports jumping nearly 18% year on year, already all-time high levels of iron ore cargoes have continued to grow while copper concentrate shipments are up more than a third.

    Falling domestic production could only accelerate this trend and provide support for seaborne prices.

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    China's MMG posts third straight loss amid shift to copper

    MMG, the miner owned by China's top state-owned metals trader, posted a third straight half-yearly loss as revenue dropped 47 per cent due to lower prices and the closure of a zinc mine in Australia. Its shares fell.

    Its net loss widened to $US93 million ($127.7 million) in the first six months, from $US48 million a year earlier, according to a statement Tuesday. Revenue sank to $US586 million from $US1.1 billion. The closure of the company's Century zinc mine, lower copper output in Laos, and declining metals prices all hit sales. The firm, controlled by China Minmetals, is ramping up its Las Bambas mine in Peru, one of the world's biggest new sources of copper.

    "The challenging global economic conditions we experienced in 2015 continued into 2016, driving persistent commodity-price volatility and low growth rates," chairman Jiao Jian said in the statement. Las Bambas, set to produce between 250,000 and 350,000 tonnes of copper this year, will contribute to earnings from July 1, the company said.

    Zinc has surged 40 per cent this year, reaching its highest in more than a year in August, after mine closures and production cuts curbed supply. Still, average prices remain below last year's levels after a downturn in demand growth in China, the world's biggest buyer. The shuttering of Century after 16 years of operation contributed to a 73 per cent slump in zinc revenue to $US108 million. Copper sales dropped 36 per cent to $US360 million.

    The rally in zinc prices had helped push MMG's shares in Hong Kong to their highest in about a year on Tuesday at $HK2.05 (34?), before it released earnings. They fell as much as 4.4 per cent Wednesday and traded 2.9 per cent lower at $HK1.99 a share by 11:49 a.m.

    MMG's planned Dugald River zinc mine in Australia will start output in 2018 amid a "widely anticipated zinc deficit" that's expected to hit the global market next year, Jiao said. MMG is seeking zinc resources in Peru and elsewhere, chief executive officer Andrew Michelmore said last month.

    Growth in global copper supply will fall significantly short of demand for the remainder of this decade, according to Citigroup in a note Tuesday. Many planned projects won't come to fruition after spending cuts and tighter project financing, it said. The bank's view contrasts with Barclays, which has argued that the copper market faces a surplus up to 2020, which will weigh on prices.

    MMG runs mines in Australia, Peru, Laos and the Democratic Republic of Congo.
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    Aus Tin becomes Australia’s second ASX-listed tin producer

    ASX-listed Aus Tin has started concentrate production at the Granville project, inTasmania, elevating the company to tin producer status.

    Aus Tin, which bought the Granville project less than four months ago, is now the second Australian company listed on the ASX to produce tin, the other being Metals X.

    The milestone was achieved against the backdrop of an improving tin price and declining global tin stocks.

    “The tin price is up 25% year-to-date and we believe the best leverage an investor can have to the increasing tin price is through operating assets. Having now commenced production at Granville, it is our intention to ramp-up production and in due course exploit the high tin grades in the openpit generated from our 2015 drilling programme,” said CEO Peter Williams on Wednesday.

    Aus Tin plans to use the cash flow generated by the Granvillproject to advance its other projects, including the Taronga tin project, in New South Wales, and Mt Cobalt, inQueensland.
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    Steel, Iron Ore and Coal

    After years of pain, coal becomes one of the hottest commodities of 2016

    Less than a year after the coal industry was declared to be in terminal decline, the fossil fuel has staged its steepest price rally in over half a decade, making it one of the hottest major commodities.

    Cargo prices for Australian thermal coal from its Newcastle terminal, seen as the Asian benchmark, have soared over 35 percent since mid-June to more than one-year highs of almost $70 a ton, pushed by surprise increases in Chinese imports.

    "Chinese regulators have assumed the role that markets traditionally play in bringing oversupplied commodities back to balance," Goldman Sachs said in a note to clients late on Tuesday, reversing a gloomy outlook it issued last September.

    "Restrictions on domestic production introduced earlier this year have lifted prices globally and turned coal into one of the best performing commodities so far this year."

    Global mining majors like Glencore and Anglo American, but also regional Asian players like Thailand's Banpu, are reaping the benefits.

    All three have seen their shares rise sharply this year, particularly in recent months after China in April cut mine operating days by 16 percent in a bid to help meet its target of reducing capacity by 250 million tonnes this year.

    Banpu, which operates several export mines across Asia-Pacific, said this week that it expects to sell its 2016 coal supplies at an average price of over $50 a ton, up from a previous target of $47 to $48 per ton, thanks to the recent rally.

    The price recovery is an unexpected boon for miners, who were hit hard by a years-long downturn, and stands in sharp contrast to previous calls by Goldman and the International Energy Agency (IEA), who said last year that coal was in terminal decline.

    As a result of China's surprise move, Goldman said there was now "support (for) global prices for the foreseeable future."

    The bank raised its three, six and 12 month price forecasts to $65/$62/$60 per ton for Newcastle coal, up as much as 38 percent from its previous outlook.


    Coal has also been garnering support from Asian industrial powerhouses Japan and South Korea, while demand remains firm in India, Vietnam and the Philippines.

    Japan is burning record amounts of the fossil fuel for electricity generation after the 2011 Fukushima disaster shuttered its nuclear sector, while Korea plans to build 20 new power plants using the cheapest fuel source by 2022.

    China's power consumption has also risen against expectations, jumping 8.2 percent from a year ago in July to reach 552.3 billion kilowatt hours.

    "The biggest improvement in the industrial sector (in China) was power generation,... helping demand for coal over the past month," Australia's Macquarie bank said this week.

    While almost all thermal coal miners were hit by the previous price decline, and most shut or sold assets, those left with the best assets now stand to benefit from the rebound.

    The biggest winners are those with mines in Australia, thanks to the high average quality of its coal.

    Shares of Anglo American, a major thermal coal miner in Australia, have recovered from record lows earlier this year of around 2.2 pounds to around 8.7 pounds.

    Commodity merchant and miner Glencore, the world's biggest thermal coal exporter with huge Australian operations, has also seen its shares soar from around 70 pence early this year to nearly 2 pounds.

    Glencore was not available for comment ahead of reporting its half-year results on Aug. 24. Anglo American in its half-year results in late June pointed to consistent Indian demand and the unexpected pickup in China.

    Other miners, however, have not been able to benefit from coal's 2016 boom.

    Indonesia, the world's biggest exporter of thermal coal, has seen its output fall during the lull, and its miners are unable to raise production due to debt constraints.

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    Indian state ports' thermal coal imports drop in July

    India's 12 major government-owned ports handled 7.34 million tonnes of imported thermal coal in July, sliding 22.65% from 9.49 million tonnes in the same month last year, and dropping 18.5% from June's 9.00 million tonnes, according to latest data released by the Indian Ports Association (IPA).

    However, coking coal shipments received by the 12 ports during the month rose 14.13% on the year to 4.27 million tonnes, from 3.74 million tonnes, the data showed.

    Paradip port on east coast handled the highest volume of thermal coal in July at 2.58 million tonnes, falling 6.29% from 2.75 million tonnes a year ago.

    Kolkata port, also on the east coast, received the highest coking coal shipments in July at 1.24 million tonnes, compared to 532,000 tonnes in July of 2015, showing a rise of 132.9%.

    The 12 ports referred to are Kolkata, Paradip, Visakhapatnam, Ennore, Chennai, VO Chidambaranar (Tuticorin), Cochin, New Mangalore, Mormugao, Mumbai, Jawaharlal Nehru Port Trust, or JNPT, and Kandla.

    Cochin port, JNPT and Chennai didn't receive any coal cargoes in July.

    As of the end of July, Indian imports of thermal coal totaled 34.51 million tonnes in the fiscal year of 2016-17 (April-March), slipping 3.2% compared to the corresponding period last year.

    Meanwhile, the Asian country imported 17.32 million tonnes of coking coal, rising slightly by 0.62% on year.

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    Australia's Whitehaven beats profit forecast amid coal resurgence

    Australia's Whitehaven Coal Ltd on Thursday reported a bigger-than-expected annual profit on the back of higher coal sales in Asia.

    Net profit by the producer of coal used in power generation and to make steel, whose customers are predominantly in Japan and India, reached A$20.5 million ($15.7 million) in fiscal 2016 against forecasts by analysts of around A$14.6 million, according to Thomson Reuters data. The company recorded a A$10.7 million loss in fiscal 2015.

    Whitehaven has seen a dramatic rise in its stock from just A$0.70 in January to Wednesday's close of A$2.04 amid an expansion by the company in eastern Australia.

    Production of coal increased by 30 percent in the year ended June 30, allowing Whitehaven to improve sales margins despite average lower selling prices over the year.

    Whitehaven said buyers of its thermal coal were adding more coal-fired power station capacity.

    After five years of declining prices, coal markets appear to have found a bottom in the current quarter, it said.

    Japan is burning record amounts of the fossil fuel for electricity generation after the 2011 Fukushima disaster shuttered its nuclear sector, while South Korea plans to build 20 new power plants using the cheapest fuel source by 2022.

    Cargo prices for Australian thermal coal from its Newcastle terminal, seen as the Asian benchmark, have soared over 35 percent since mid-June to more than one-year highs of almost $70 a tonne.

    Prices for metallurgical coal, a smaller component of Whitehaven's sales, have also firmed over the last year, according to the company.
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    Top steel firms' debt level totals record $150 billion: EY

    Debt in the world's top 30 steel companies totals a record $150 billion, international accountancy firm EY said on Thursday, adding governments' action to support the sector would work only if matched with more radical industry restructuring.

    Overcapacity and weak steel prices have piled pressure on firms such as Tata Steel, which is in merger talks with German conglomerate Thyssenkrupp.

    EY said in a report published on Thursday steel firms took on debt as they fought for market share, notably the Chinese steel sector has added about a billion tonnes of capacity since 2000, helping to take global excess capacity to about 700 million tonnes.

    The debt of the top 30 companies is dwarfed by China's steel sector debt, estimated at $500 billion.

    "Many steelmakers are in some form of distress with some teetering on the verge of bankruptcy," Anjani Agrawal, EY global steel leader, said, adding government efforts would only work if the industry had viable business models.

    Reforms are underway.

    Thyssenkrupp, the world's 16th largest steel producer by tonnage, has announced the sale of real estate assets as well as embarking on merger talks with Tata.

    At the end of June, the firm had gearing of 175 percent, versus 124 percent a year earlier, and debt of 4.77 billion euros compared with 4.39 billion the previous year.

    It aims to reduce its gearing to less than 150 percent by the end of September and told an analysts' call last week it should meet that target.

    The world's largest steelmaker ArcelorMittal has tackled its debt with a $3 billion rights issue.

    It also sold a $1 billion stake in a Spanish automotive steel group Gestamp in April. Net debt was $12.7 billion at the end of the first half of 2016, down from $17.3 after the first quarter. The group guides for positive cash flow in 2016.

    China has promised to reduce steel capacity by 45 million tonnes this year, but cuts in the first seven months were only 47 percent of the annual target.

    To protect Western firms from Chinese steel, which the United States and Europe says is sold at less than cost price, Washington and Brussels have imposed duties, prompting criticism from China.

    European steel representatives say Chinese firms should carry out most of the restructuring, given the size of their debts, but they are not assuming that will happen and all measures will be needed for the sector to survive.

    "For the next 5 to 10 years there will be substantial pain. It should be principally in China, but it will be principally here unless we have effective trade measures," Brussels-based lawyer Laurent Ruessmann, a partner at Fieldfisher, said by telephone. He represents steel firms and is specialized in China and trade law.
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    U.S. ITC backs steel pipe and tube import duties

    The U.S. International Trade Commission on Wednesday backed duties on imports of certain carbon steel pipes and tubes from South Korea, Mexico and Turkey, saying the imports were harming domestic producers.

    The Commerce Department had already slapped anti-dumping duties of up to 35.66 percent on imports of heavy-walled rectangular welded carbon steel pipes and tubes from the three countries, as well as anti-subsidy duties of up to 23.37 percent on the products from Turkey.

    The ITC's finding, which finalizes those duties, marks the last step in an investigation launched last year after a complaint from Atlas Tube, a division of JMC Steel Group; Bull Moose Tube Co; EXLTUBE; Hannibal Industries, Inc; Independence Tube Corp; Maruichi American Corp, a subsidiary of Maruichi Steel Tube Ltd; Searing Industries; Southland Tube and Vest Inc.
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    Sinosteel debt swap near complete

    Sinosteel Corp, which became one of the first State-owned companies to encounter bond repayment problems in 2015, is in the final stages of completing a debt-to-equity swap plan, financial magazine Caixin reported on Tuesday.

    The plan has been submitted to the State Council for approval and will soon begin in earnest, Caixin said, citing anonymous industry sources.

    Sinosteel may be permitted to swap half of its debt into equity, Caixin noted. The magazine estimates Sinosteel and its subsidiaries had 100 billion yuan ($15 billion) of debt at the end of 2014.

    In October 2015, Sinosteel asked bondholders not to exercise an early redemption option on one of its bonds maturing in 2017 as it would not be able to make full payment.
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