Mark Latham Commodity Equity Intelligence Service

Wednesday 6th July 2016
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    Glencore CEO lists mining’s mistakes after $1 trillion spree

    Glencore Plc’s billionaire Chief Executive Officer Ivan Glasenberg wants the mining industry to learn from past mistakes after a $1 trillion spending spree left the world awash with metals.

    Growth for the metals industry should mean cash flows and earnings, not digging up as many tons as possible, Glasenberg said in a presentation on Tuesday. Profit can be improved by accepting lessons from the 12 years when mining companies poured cash into boosting production of everything from copper to iron ore.

    “Accept that volume growth cannot be an end in itself,” according to Glencore’s slides from the Bank of America Merrill Lynch mining conference in Miami.

    Under a headline of “Recipe for Better Returns,” the company wrote that management incentives in the industry need to encourage “rational behaviour.”

    Years of debt-fueled investment in mining resulted in a massive oversupply of commodities at the same time that China’s economy hit the breaks. The rout in prices that followed forced mining companies to slash debt, cut costs and sell assets. In just five years, the FTSE 350 Mining Index saw more than 70% of its value disappear.

    Different Future

    Capital allocation going forward needs to be more conservative and based on cash generated, Glencore said.

    “The future can be different,” according to the presentation slides. “Doing nothing on growth is often the best outcome.”

    Glencore shares gained 1.1% by 8:10am in London. The stock has rebounded 50% this year as some commodities recovered and the company took steps to lower debt. It’s still down 74% since a $10 billion initial public offering five years ago.

    As companies lower production, spending by the world’s top five diversified miners is set to total $24 billion this year, down from a peak of $71 billion in 2012, according to Glencore. Cost cuts across the board are reaching the limits of what is possible, Andrew Mackenzie, BHP’s chief executive officer, said in a separate presentation.

    It’s not the first time Glasenberg has offered his reflections on the mining industry. Last year, he remarked that miners should understand the concept of supply and demand. In 2013, he said mining chiefs had “ screwed up” by flooding the world with raw materials.
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    Oil and Gas

    Saudi petchem firms may seek M&A as part of efficiency drive

    Saudi petrochemicals producers are looking for mergers and acquisitions to secure scale and raw materials as part of an efficiency drive to adjust their businesses to lower oil prices.

    The industry has developed substantially since the 1970s, fuelled by cheap gas feedstock provided by the Saudi government. Saudi Basic Industries Corp (SABIC), the kingdom's biggest petchems firm, is the world's fourth-largest by sales behind German BASF and Bayer and U.S. Dow Chemical.

    But a government decision in December to raise feedstock prices, has forced petchem firms to reconsider their business models, already hit by lower product prices due to cheap crude.

    Saudi companies have already invested abroad with SABIC signing a coal to chemicals project in China. Another reaction has been consideration of potential mergers and acquisitions.

    "We made a commitment at SABIC to improve our efficiency to absorb the additional cost for the feedstock and we will do that, but we still look for any other options that can position SABIC competitively for investment through acquisitions," the company's acting CEO Yousef al-Benyan, told Reuters.

    The acquisitions route could create a number of benefits, including increased scale for businesses to drive efficiencies, sourcing raw materials, and expanding into new product ranges.

    Petrochemicals are the second-largest contributor to Saudi's economy at 7-10 percent of GDP and has the potential to be a significant part of the kingdom's Vision 2030 economic plan.

    "The way forward is to crack naphtha or to grow outside, and me and everybody are looking outside. By increasing gas prices, the opposite will happen, it is definitely not going to encourage investors to go further downstream," Mutlaq al-Morished, chief executive of National Industrialization Co (Tasnee) said.


    It is the increase in feedstock prices that has jolted the Saudi petchems industry into action, as previously they could enjoy much improved margins thanks to subsidies.

    Remove the subsidies -- the Saudi government has pledged to phase out "support" over the next five years -- and high-priced oil and Saudi is competing on a level playing field.

    "What is alarming in the Saudi petrochemical industry is its obsolete fixed assets and inefficiency, where large numbers of plants today are more than 20-30 years old and do not match parameters of fuel consumption and need to be replaced," said Mohammed Alomran, a member of the Saudi Economic Association.

    Most Saudi petchem firms are now undertaking restructuring programmes to slash costs -- Tasnee said it has cut 2,000 jobs, while SABIC is reviewing some of its investments.

    It could help to switch to a more effective feedstock, but this is being inhibited by Saudi's shortage of gas.

    "I think the Saudi petchem industry is more constrained by new gas allocations than by price," said Sanjay Sharma vice President - Middle East and India at IHS Chemical Consulting.

    Aramco plans to double gas output in a decade but it is unclear just how much will go to petrochemicals.

    One alternative is deriving petrochemicals directly from crude oil, with Aramco and SABIC announcing this week they were study building an oil-to-chemicals (OTC) venture.

    OTC will open up a number of new downstream product lines to Saudi producers, which fits with the kingdom's strategic goals of creating more higher-value products.

    But the technology is still developmental and there are question marks over how it would work commercially, Sadad al-Husseini, a former top executive of Aramco, says.

    Therefore, perhaps the most promising short-term solution would be to go down the M&A route for more feedstock supply.

    Aramco has indicated it would seek opportunities in global upstream gas, while SABIC has said in May it would look to North America for gas to fuel growth.

    However, it is unlikely to result in M&A within the Saudi sector due to cumbersome rules on combining listed companies.

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    Chevron, Exxon Commit to $36.8 Billion Expansion Project in Tengiz

    Chevron Corp., Exxon Mobil Corp. and their partners on Tuesday committed to a $36.8 billion oil expansion project in Kazakhstan—the biggest investment in new barrels since oil prices collapsed two years ago.

    The investment in the expansion of the field known as Tengiz—one of the world’s largest—comes on top of around $37 billion already spent by Chevron, the operator, and its partners: state-owned energy firm KazMunaiGas, Exxon and Russia’s Lukoil.

    “This project builds on the successes of prior expansions at Tengiz and is ready to move forward,” said Jay Johnson, Chevron’s executive vice president in charge of upstream.

    “It has undergone extensive engineering and construction planning reviews and is well-timed to take advantage of lower costs of oil industry goods and services,” he said in a statement.

    The $36.8 billion includes $27.1 billion for facilities, $3.5 billion for wells and $6.2 billion for contingencies. It will take Tengiz production up to 1 million barrels of oil equivalent a day from around 800,000 barrels of oil equivalent a day currently. First production from the expansion is due in 2022.

    Tengiz is one of the most profitable fields in the history of the modern oil era. Some analysts estimate that it has brought Chevron more than $70 billion in revenue, and $40 billion in profits, since 1993, when the U.S. company became the first foreign oil company to strike a deal with the former Soviet republic.

    The decision, which has been on hold since last year, is a signal of the industry’s growing confidence that oil prices have stabilized and are set to move higher. Oil prices collapsed from around $115 a barrel in mid-2014 to a low of $27 in January, but have hovered near $50 a barrel in recent weeks.
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    Brazil 2017 subsalt oil rights sale to unlock stalled fields

    Brazil on Tuesday said it will sell four areas in its prolific subsalt region by mid-2017 to speed up development of offshore oil and gas discoveries blocked by nationalist energy policies and state-run Petrobras' debt and financial woes.

    One of the areas will abut the giant Carcará prospect in the BM-S-8 block in Brazil's offshore Santos Basin south of Rio de Janeiro, Marcio Felix, the energy ministry's oil and gas secretary designate, told reporters in Rio de Janeiro.

    "Without this sale, Carcará can't be developed," said a senior official with a company that owns Carcará resources.

    While there is no official estimate for the size of Carcará, partners in the group, including state-led Petroleo Brasileiro SA, or Petrobras, Portugal's Galp Energia SPGS SA, and Brazil's Barra Energia and QGEP Participações SA, have said it rivals Brazil's 8-billion-barrel Lula field.

    With enough oil to supply all the world's needs for nearly three months, Lula is one of the world's largest discoveries in four decades. The subsalt is a region near Rio where about 100 billion barrels of oil are trapped deep beneath the seabed by a layer of mineral salts.

    Petrobras owns 66 percent of BM-S-8 where Carcará was discovered, and is lead partner or "operator". Galp owns 14 percent and Barra and QGEP each own 10 percent.

    In addition to areas abutting BM-S-8, Felix said the auction will sell blocks adjacent to Petrobras' Tartaruga field; the Sapinhoa field owned by Petrobras, Royal Dutch Shell Plc, Spain's Repsol SA and China's Sinopec; and the Gato do Mato prospect owned by Shell and France's Total SA.

    Changes made in 2010 by a previous government to Brazil's oil law were designed to increase government control of the giant subsalt discoveries and channel an expected bonanza to health care, education and economic development.

    Instead they stalled investment and put development into regulatory limbo. They've since combined with a Petrobras corruption scandal, the company's $126 billion of debt, the world oil industry's largest, and a plunge in oil prices, to hobble a once-booming oil industry.

    Carcará partners have invested more than $2 billion to date but will have to wait until at least 2020 for a return, two decades after rights to the area were first sold.

    Brazilian law also requires fields to be developed as a single unit, meaning parts of Carcará extending into unleased areas must be sold to another company and "unitized" with Carcará resources in BM-S-8.

    About 55 percent of Carcará is outside BM-S-8, the Carcará partner and a governmentsource said.

    The 2010 law, though, required all unleased areas in Brazil's subsalt to be operated and at least 30 percent owned by Petrobras. New subsalt areas must also be sold under production sharing contracts, where the government earns both oil and royalties. Older areas such as BM-S-8 are concessions that pay only royalties.

    Short of cash, though, Petrobras can no longer afford new subsalt areas it is legally obligated to lead.

    "Petrobras is broke, the rules a mess. Without change we're stuck," the Carcará partner said.

    A bill ending Petrobras' obligation to lead all new subsalt development should pass Congress within weeks, opening the 2017 subsalt auction to new bidders, Felix said.

    Rules clarifying unitization of concessions and production-sharing contracts will be complete by year end, he added.

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    Noble Energy sells 3% interest in Tamar field for $369 million

    Noble Energy, Inc. today announced that it signed a definitive agreement to divest a 3 percent working interest in the Tamar field, offshore Israel, to the Harel Group, a leading insurance provider and pension manager in Israel, in partnership with Israel Infrastructure Fund ('IIF'), Israel's largest infrastructure private equity fund. The transaction value of $369 million is based upon a gross pre-tax Tamar valuation of approximately $12 billion and is subject to purchase price adjustments between January 1, 2016 and the closing date. Closing for the transaction is anticipated in the third quarter of 2016, subject to customary terms and conditions, with after-tax proceeds received expected to be approximately $275 million. Under terms of the agreement, Harel and IIF have the option to elect, before closing, to purchase an additional 1 percent working interest from Noble Energy at the same valuation.

    Gary W. Willingham, the Company's Executive Vice President of Operations, commented, 'This transaction reflects the inherent value of our producing Tamar asset, which reliably fuels more than half of Israel's electricity generation today. It also highlights the potential of our other undeveloped Levant Basin discoveries, which share similar reservoir and well deliverability characteristics and are poised to bring needed energy to a region which is fundamentally short natural gas. We are excited about partnering with Harel and IIF, which bring additional leading Israeli investors into the project. These proceeds further bolster our balance sheet in the near-term and will contribute to our upcoming capital investments in Israel, including our initial investment in the Leviathan project.'

    Noble Energy and partners are planning to drill and complete an additional development well at the Tamar field in response to the continued increasing demand and outlook for natural gas usage within Israel, as Israel displaces coal for clean-burning natural gas. Drilling is anticipated to commence in the fourth quarter of 2016. The additional producing well will further enhance redundancy while meeting maximum deliverability for extended peak demand periods. There is no material change to the Company's overall 2016 capital program.

    Prior to the announced working interest sale, Noble Energy operated the Tamar field with a 36 percent working interest. The Company is carrying out an 11 percent sell-down of its interest in the Tamar field in accordance with Israel's approved Natural Gas Regulatory Framework. Noble Energy anticipates the sale of the remaining 7 to 8 percent working interest over the next 36 months. Following completion of this sell-down process, Noble Energy will retain a 25 percent working interest and operatorship in the Tamar field, which has recoverable gross mean natural gas resources of 10 trillion cubic feet (Tcf).

    The Tamar field sold 252 million cubic feet per day, net, of natural gas and generated net pre-tax income of $318 million for Noble Energy in 2015.

    Noble Energy also operates the Leviathan field, offshore Israel, with a 39.66 percent working interest and the Aphrodite field, offshore Cyprus, with a 35 percent working interest. The Leviathan field has an estimated 22 Tcf of recoverable gross natural gas resources, while Aphrodite holds an estimated 4 Tcf of recoverable gross natural gas resources.
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    Colombia's peace deal could spur oil sector turnaround

    Is a peace dividend in the form of more investment-and ultimately more production and jobs-coming to Colombia's beleaguered oil and gas sector?

    That's been the hope of executives and analysts since the government signed a permanent cease fire on June 23 with the Revolutionary Armed Forces of Colombia, or FARC, the country's largest rebel group. If a comprehensive peace deal is signed later this summer as expected, the warring sides could end 52 years of armed aggression.

    An end to hostilities, assuming one takes hold in the mostly rural areas where oil is pumped, would be welcome news for E&P and oil field services firms. Their employees have been regular victims over the decades of FARC kidnappings, bombings, extortion and murders.

    From 2001 through 2015, Colombian national police reported 219 oil company employees were kidnapped for ransom by FARC guerrillas and other groups, according to figures compiled by Agora Consultorias, a risk analysis firm in Bogota. Oil firms have paid untold millions in extortion payments to armed groups as well.

    Over that same 15-year period, there were 1,814 reported bombings of Colombian pipelines, the vast majority by suspected FARC rebels. According to El Tiempo newspaper, as many as 4.1 million barrels of oil have been lost to the bombings since the mid-1980s, or more than twice the oil spilled by the Exxon Valdez after it ran aground in Alaska in 1989.

    Naturally, those statistics have had a chilling effect on Colombia's oil patch, especially in recent years as lower global prices have made the Andean country a tougher sell to oil companies' investment committees. Added to the country's challenging logistics and higher lifting costs associated with heavy oil, security issues have driven many companies to more inviting conditions in Mexico, Peru and Argentina.

    Three years of investment declines are coming home to roost, contributing to a precipitous decline in Colombia's crude output this year. After averaging 1,005,000 b/d in 2015, Colombia pumped only 904,000 b/d in May, down a shocking 11.8% from what was pumped in the year-ago month.

    Adding to the gloom is that Colombia's proven oil reserves took a major hit last year, falling to 2 billion barrels as of December 31, down from 2.308 billion barrels at the end of 2014, a 13% decline.

    The drop follows a 5.6% decline reported at the end of 2014.

    Others step in where FAR C left

    President Juan Manuel Santos insists the improved security resulting from a peace deal, which if signed would go before Colombian voters later this year, could be a turning point, making Colombia more appealing to investors in energy and other sectors.

    But analysts caution that benefits from a peace accord will take time to materialize. Moreover, investors are weighing factors other than security in their Colombian investment decisions, including a looming tax reform package that goes before Congress later this year that could place a higher fiscal burden on oil companies.

    Orlando Hernandez, president of Agora Consultorias, notes that Colombian armed forces are still at war with other rebel and criminal groups that dominate some areas of rural Colombia, making the Colombian oil patch still a risky environment.

    Hernandez notes that as the FARC has wound down its violent activities since declaring a provisional cease-fire a year ago, the National Liberation Army, another rebel group known by its Spanish initials ELN, had moved in. The ELN has carried out 15 pipeline attacks so far this year, up from its year-ago total of five, he said.

    The Colombian government and the ELN are not currently in peace talks.

    Another problem that oil companies face that won't be helped by a FARC peace deal is the rising occurrence of blockades by peasants and indigenous groups of oil and gas installations. Executives complain that the blockades have been more damaging to production in recent years than the rebels. Some groups have environmental complaints against E&P projects, others do it to extract labor or royalty concessions from the government.

    Currently, a month-long blockade by indigenous groups of a natural gas processing plant in the town of Gibraltar in northeast Colombia has caused a 30% increase in gas prices for residents of nearby Bucaramanga. Last year, groups blocked repair crews from fixing the 220,000-b/d Cano Limon pipeline for two months, costing the country millions in oil revenue, Hernandez said.

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    Indonesia's Pertamina eyes SPR storage facility for 25 mil barrels of crude

    Indonesia's state-owned oil and gas company Pertamina will seek partners to build a strategic petroleum reserve of about 25 million barrels to ensure energy security, a senior official said Tuesday.

    "The third party will provide the crude. We plan to select partners after Eid al-Fitr," Pertamina's processing director Rahmad Hardadi said.

    About 60% of the crude for the SPR storage was expected to come from domestic production and the rest from other sources, he added.

    The SPR storage facility was expected to be built in 1 1/2 to two years, Hardadi said.

    The company also plans to build storage capacity for 7.3 million kiloliters of oil products by 2020 from 4.8 million kl currently, S&P Global Platts reported earlier.

    President Joko Widodo has committed to build upstream and downstream infrastructure, such as new refineries, pumping stations and storage tanks in a bid to cut Indonesia's dependency on imported fuels.

    The government also plans to provide incentives to private companies to participate in building the infrastructure.

    Indonesia is already in talks with Oman, Kuwait, Iran and Saudi Arabia to lease storage tanks to hold buffer stocks of crude and oil products equivalent to 30 days of consumption.
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    Grade-Grubbing Oil Producers Are Threatening to Boost U.S. Output Yet Again

    Shale producers are tapping their crown jewel assets in response to the latest oil price rally, according to Morgan Stanley.

    The recovery in crude to close to $50 per barrel has encouraged shale producers to double down on their most profitable fields — a process known in oil country as high grading.

    This new trend threatens to force analysts to revisit calls for declining U.S. production, warned Morgan Stanley Commodity Strategist Adam Longson, and thereby constitutes a downside risk for prompt prices.

    "The rig count in the highest initial production counties of the Permian Midland continues to march higher and is not far from its 2015 peak," writes a Morgan Stanley team led by Longson. "Since May 6, the Midland has added 13 horizontal rigs in top tier counties versus only eight for the entire play."

    In other words, capital is returning to the oil patch, and it's being invested in new projects that will allow firms to boost production in an expeditious manner once the taps are turned on.

    The collapse in headline oil rig count, as such, continues to provide only a partial picture of the outlook for U.S. production.

    If this trend towards new fertile plays continues, it could alter the downwards trajectory for U.S. production in about four to six months, said Longson.

    "It’s also important to consider that the rigs are going into the most prolific areas, the decline curve for shale wells is flattening, and completing drilled-but-uncompleted wells could slow declines in as short as one to two months," he added.

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    U.S. shale firms' first-quarter hedging rush may squeeze margins, spur output

    As oil prices began recovering from 13-year lows early this year, U.S. shale producers ramped up their hedges against another slump on a scale unseen for at least a year, a Reuters analysis of company disclosures shows.

    A review of disclosures by the largest 30 U.S. shale firms showed 17 of them increased their hedge books in the first quarter, the most at least since early 2015.

    Several, including EOG Resources Inc and Devon Energy Corp, two of the biggest shale companies, secured significant protection of future earnings for the first time in at least six months.

    A greater volume of hedged production typically indicates more drilling activity ahead as producers that locked in prices for a sizeable part of their output ensure enough cash flow to sustain or increase production.

    What makes the outlook more complicated this time is the fact that oil companies, fearing the rally could fizzle, locked in sales at levels around $10 a barrel below both current prices and break even levels for some producers.

    For those producers the concern is that their margins will suffer if service costs rise as activity picks up.

    It is less clear how it will affect production, though most analysts expect more supply.

    Michael Cohen, head of energy commodities research at Barclays in New York, believes hedges allow producers to plan better even if they secured prices below present levels just below $50 a barrel.

    "I think (the hedging) gives producers more security to lock in a capex plan," Cohen said, predicting shale production will edge up in the second half of the year.

    The 17 companies locked in prices for nearly 55 million barrels of future production, the highest volume in at least a year and some 45 percent more than hedges added by eight companies in the fourth quarter.

    The spike in hedging came as crude recovered from February's 13-year lows around $26 a barrel CLc1 later in the first quarter, a rally that continued into the second quarter.

    That recovery stalled, however, in the final weeks of last month amid heightened uncertainty about the impact of Britain's vote to leave the European Union and crude prices slipped back below $50 a barrel. (Graphic:


    Sometime in the first quarter, Marathon Oil Corp (MRO.N), for example, hedged at an average price of $39.25 for the second quarter, when prices averaged just below $46 a barrel. Denbury Resources Inc (DNR.N) locked in first-quarter 2017 U.S. crude production at just over $42 a barrel; those futures CLF7 this week were trading at about $52 a barrel.

    While those deals may look problematic now, analysts point out that they did make more sense three or four months ago.

    Michael Tran, director of commodity strategy at RBC Capital Markets in New York, said that at the time market players had expected oil prices to average at or below $40 this year.

    "You have to remember that sentiment in this market is still so fragile," he said. "Producers ended up locking in something in case we did a double dip."

    For those that have enough money, the hedges may now act as an incentive to crank up production for the spot market to average up how much they fetch per barrel, said John Saucer, vice president of research and analysis at Mobius Risk Group in Houston.

    For a number of oil producers hedges were more of a necessity than a strategic choice as they needed them to get bank loans, said Thomas McNulty, a director at consultancy Navigant, who advises producers on valuation, transactions and risk management such a hedging.

    "Banks have been working very hard with their clients to continue or extend financing, and that requires producers to hedge more," McNulty said, adding that he saw limited appetite for hedging that went beyond what banks required.
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    Bakken multi-well pads getting bigger

    Oil well pads are getting bigger in western North Dakota as companies figure out how to get the most oil out of the Bakken.

    Hess Corp. has the Bakken’s largest well pad with 18 wells on a single location, but the state’s top oil regulator says he expects to see mega-pads get even larger.

    “At any time in the not too distant future, their record is going to be eclipsed,” said Lynn Helms, director of the Department of Mineral Resources.

    Regulators already have permitted a few larger multi-well pads, including one from Continental Resources that will have 25 wells on one location.

    Many landowners prefer consolidating more wells onto one location rather than having several smaller pads, said Troy Coons, chairman of the Northwest Landowners Association.

    “For the most part, people want things to be the most efficient so they can farm around them with the least amount of impact on the land,” Coons said.

    On average, a single-well pad takes up 3.35 acres, Helms said.

    But consolidating 18 or more wells on on pad can shrink that impact to less than 1 acre per well, Helms said.

    “That’s an enormous reduction in use of the landscape,” Helms said. “I think we’re going to see a lot of 16-plus well pads.”

    In addition to reducing the footprint of oil production, companies are finding other benefits.

    Hess recently increased the amount of oil the company expects to recover from its Bakken and Three Forks wells from 1.4 billion barrels to 1.6 billion barrels. The increase in production is in large part due to spacing the wells closer together, as well as optimizing hydraulic fracturing techniques, said Gerbert Schoonman, a Hess vice president who oversees the company’s Bakken assets.

    “All of a sudden, essentially you add another 200 million barrels of recoverable reserves to your business,” Schoonman said. “There aren’t many fields in the world that have got 200 million barrels. This is big.”

    Oil companies are experimenting with different well densities to optimize how much oil they can recover from the Bakken and Three Forks formations.

    For Hess, drilling nine middle Bakken wells and eight Three Forks wells in a single location is showing good results, Schoonman said, though the company is doing other field studies.

    These multi-well pads are unique to the Bakken, Helms said.

    “In my experience, our multi-well pads are larger and have a lot more wells on them,” he said.

    The largest locations will be concentrated in the core of the Bakken in McKenzie, Dunn and Mountrail counties. In those areas, Helms estimates it will take 32 wells in a single 1,280-acre spacing unit to fully develop the Bakken.

    The areas on the fringe of the Bakken, such as parts of Stark and Divide counties, will likely have four to six wells in a single area, Helms said.

    At the Hess 18-well pad in Mountrail County, the location has nine pump jacks lined up on one side and nine on the other, with horizontal wells extending two miles in opposite directions. Pipelines transport the oil, natural gas and produced water - a waste byproduct of oil production - to nearby facilities for further processing. The 20-acre pad, which looks like a gravel parking lot, is surrounded by a containment berm in case of a spill.

    Steve McNally, general manager for Hess in North Dakota, said multi-well pads make the entire process of developing a well more efficient, from acquiring the land to drilling and fracking the well to monitoring wells once they’re complete.

    “It reduces the amount of time through every single step,” McNally said.

    Consolidating wells also allows pipelines to be installed to one location, rather than several smaller ones, eliminating truck traffic and reducing natural gas flaring.

    One potential downside to multi-well pads is that by consolidating the drilling, it could also concentrate the waste, Helms said.

    State regulations allow companies to bury drill cuttings – a waste byproduct of oil development – on the drilling site after mixing them with a stabilizing material. Cuttings pits at multi-well pads will be larger with the waste more concentrated in one place, Helms said.

    But companies can also choose to dispose of the cuttings by hauling them to a special waste landfill, which is how Hess handles the waste.

    Another downside of the larger locations is they can have a major impact on a single landowner, Coons said.
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    Unexpected Cushing Build

    Genscape reported an unexpected 230k barrel build at Cushing

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    Cabot Oil & Gas In New Long-Term Sales Deal To Supply Lackawanna Energy Center

    Cabot Oil & Gas Corp. reported Tuesday that it has executed a 10-year sales agreement to be the exclusive provider of natural gas supplies to Invenergy LLC's Lackawanna Energy Center power plant.

    Additionally, South Jersey Industries (SJI) , the energy holding company for South Jersey Resources Group, LLC, will become a counterparty to both entities through an exclusive supply fuel management service agreement.

    The company noted that confidential pricing terms under the deal guarantee Cabot attractive rates of return while providing fuel costs directly linked to power prices, eliminating risks for each of the parties involved in the transaction.

    The proposed facility is a natural-gas fueled 1,500 megawatt combined-cycle generating station located in Lackawanna County, Pennsylvania and is expected to be one of the most efficient power plants in the United States.

    Commercial operations are expected to begin in mid-2018 and to reach full-scale operations by year-end 2018. The facility, at maximum capacity, will burn up to 240,000 dekatherms of natural gas per day.

    Dan O. Dinges, Chairman, President and Chief Executive Officer, said, "Together with our previously announced agreement with SJI to supply natural gas to the Caithness Moxie Freedom project, Cabot will be providing more than 400,000 dekatherms of natural gas per day for power generation directly in our backyard."
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    Alternative Energy

    Germany to limit offshore wind power

    Germany plans to cap the expansion of offshore wind power at the start of the next decade to ensure the future growth of renewables keeps step with the construction of new power lines, according to a revision to a new energy law seen by Reuters.

    Between 2021 and 2025 the government plans to limit offshore wind installations to 3.1 gigawatts (GW) of capacity since high-voltage power lines needed to carry green energy from the windy north to the industrial south will not be ready.

    The reforms to the energy law are aimed at bringing down the costs of Germany's shift towards renewables sources of energy and away from nuclear power and fossil fuels known as the Energiewende.

    The rapid expansion of green energy, which now makes up more than 30 percent of the power mix, has pushed up electricity costs in Europe's biggest economy and placed a strain on its grids.

    In 2021, new offshore wind capacity should be built exclusively in the Baltic Sea since power lines on the mainland there are already available, according to the agreement between the Economy Ministry and government parties.

    From 2026, there will be annual new capacity of 840 megawatts (MW) in order to reach the target of having 15 GW of offshore wind capacity in 2030.

    The revision to the new law also set out the size of tenders for new offshore projects. For 2017, 1.7 GW will be auctioned, while in 2018 this will be cut to 1.4 GW.

    In addition, energy-intensive companies that were exempt from paying green energy surcharges until 2014 will only have to pay 20 percent of the surcharge in future, according to the agreement.

    The new law, which must still be examined and approved by the European Union, is due to come into force at the start of 2017.
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    Wind power plant in Atacama Desert fills Chile's clean-energy sails

    Deep in northern Chile's Atacama Desert, a remote community of 6,000 people is preparing to host the country's largest wind power plant.

    The residents of Freirina commune, on the coast of Huasco province, 700 km (435 miles) from the capital Santiago, have traditionally made a living from mining, olive farming, fishing and collecting seaweed.

    The new wind project marks a turning point for all Freirina’s families, according to 35-year-old mayor Cesar Orellana, a clean-energy enthusiast.

    “Having an important wind plant so close to us inspires everyone with positive expectations,” said the Socialist Party politician, who was born and raised in the isolated commune. “The energy Freirina wants is clean.”

    Near Huasco port, a privately run coal-fired thermoelectric power plant spills pollution into the air - which the mayor referred to as a “nuisance”.

    The Atacama Desert is one of the driest, sunniest and least populated places on Earth, offering economic opportunities to harness renewable energy resources.

    The San Juan wind project, located in Chañaral de Aceituno, 60 km south of Huasco port, is being developed by Latin America Power, a Chilean company, backed by Brazilian investment.

    The first wind turbines are due to start functioning in October, with an initial capacity of 10 megawatts (MW).

    Company spokesman Giovanni Vinciprova said all 56 turbines should be operating by February 2017, generating 185 MW - enough to power a city of 900,000 inhabitants. If all goes to plan, the $81-million wind plant will be Chile’s largest.

    Construction work began on the plant in March 2015, but engineers, biologists and social workers started to make contact with community leaders and hundreds of households in early 2014.

    “There are rural communities (here) who live in precarious conditions without access to energy, water or any means of transport,” said Vinciprova.

    And Freirina’s history of resistance against large companies meant residents were initially suspicious of the new wind power initiative.


    A few years ago, they mobilized against a pig farm and pork plant, one of Latin America's biggest meat-processing sites, owned by Chilean farm Agrosuper, due to the unpleasant smells it emitted.

    In May 2012, authorities declared a health alert in the area and ordered the plant, which kept half a million pigs, to close temporarily. It then shut down permanently, leaving behind hundreds of rotten dead animals that caused health and environmental problems.

    The experience left residents fiercely opposed to similar large-scale investments in their town, mayor Orellana said. So the wind power company had to make a careful effort to overcome negative sentiment towards investors.

    Gradually, the prospect of job creation and funding for community projects such as paving roads and bringing solar power to isolated fishing villages started changing local minds.

    A fund set up by the wind developer has already invested $60,000 in projects for Freirina, with a further $100,000 due to be spent in the second half of the year.

    “At the beginning it was a challenge, but we’ve had a positive experience with local communities,” said Vinciprova. “We’re taking into account (their) demands on water and telecommunications. The families are the ones who know their needs.”


    Chile currently relies on fossil fuels - coal, petroleum and natural gas - for almost half its electrical power generation.

    The other half comes from hydropower plants that have suffered from a lack of rainfall linked to the El Niño weather phenomenon which ended in May. This has highlighted the economic advantages of investing in alternative clean energy sources, including wind and solar.

    Luis Vargas, director of the Department of Electrical Engineering at Chile University, said the country’s private sector is now investing aggressively in renewables.

    The volume of wind capacity under construction jumped from 168 MW in late 2014 to around 400 MW in early 2016, for example.

    “We took advantage of learning from technology advances worldwide that now have highly competitive prices,” the researcher said. “Investing in renewables has become profitable in Chile.”

    Wind still generates only 4 percent of the nation's electricity, but that could rise to one third by mid-century, Vargas predicted.

    Chile has pledged to achieve at least a 70 percent share of renewables in its electrical power generation by 2050.

    The country’s new long-term energy policy includes hydropower but puts more emphasis on solar and wind, complemented by geothermal, biomass and ocean energy.

    While solar is still considered a non-conventional source of energy, at the beginning of the year Chile was generating 1,103 MW of solar power, according to the National Centre for Innovation and Promotion of Sustainable Energy (CIFES).

    The Atacama Desert will also be home to the Copiapó solar thermal power project, which is expected to cost $2 billion and begin operating in 2019 with a capacity of 260 MW.

    “Some researchers believe that around 2050 the country might be 100 percent renewable. Fossil fuels are gradually reducing their share,” Vargas said.

    Projections point to wind potential in Chile of 15,000 MW, equivalent to the country’s entire electrical power generation capacity today, he noted.

    “Wind potential could be even higher - we could harness this resource not only on the coastline but also along the Andes (mountains),” he said.
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    New Heat Pump Water Heater Changes the Game

    Today, A. O. Smith, the largest manufacturer and marketer of water heaters in North America, introduced a dramatically efficient new model of heat pump water heater.

    “Contractors can confidently recommend a Voltex heat pump water heater to their customers across the Northwest as a way for them to save money and energy, while still delivering the same reliable hot water.”

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    Already three times more efficient than a standard electric water heater, A. O. Smith engineers refreshed the Voltex line to improve energy efficiency benefits and performance for homes in all climates, including homes that routinely deal with cold weather.

    These improvements qualify the Voltex for the highest tier of efficiency under the Advanced Water Heater Specification. This specification was developed by an alliance of Northwest utilities, energy efficiency organizations and market partners under the umbrella of Hot Water Solutions, a program facilitated by the Northwest Energy Efficiency Alliance (NEEA). The goal of this program is to advance higher performing electric heat pump water heaters.

    Tremendous energy savings

    “The new Voltex Hybrid Electric Heat Pump can reduce electric water heating costs by as much as 71 percent for some homeowners,” according to David Chisolm, vice president of marketing for A.O. Smith. “Contractors can confidently recommend a Voltex heat pump water heater to their customers across the Northwest as a way for them to save money and energy, while still delivering the same reliable hot water.”

    Over the past three years, Northwest utilities and the Hot Water Solutions program have supported increased energy efficiency performance and influenced the sale of over 13,000 electric heat pump water heaters, paving the way for this technology.

    Heat pump water heaters have the potential to bring about enormous energy savings to the Northwest region. Currently 55 percent of Northwest homes have electric water heaters. If all of those homes used high-efficiency heat pump water heaters, the region could save nearly 300 average megawatts by 2025 – the equivalent to powering all the homes in Spokane and Boise annually.

    “We know that heat pump technology has a tremendous potential to save energy. That’s why we’re working as a region to spread the word, and with manufacturers to keep improving the efficiency and performance of these products.” said Jill Reynolds, program manager at NEEA.
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    Dong wins Borssele tender at €72.70/MWh

    Dong Energy has placed a winning bid of €72.70/MWh to build the 700MW Borssele I and II offshore wind projects in the Netherlands following a competitive tender.

    The bid, which excludes transmission costs, is among the lowest offshore prices to date.

    Dong will receive the €72.70/MWh support prices for the project's first 15 years of operation, after which it will be subject to market prices.

    Dong has up to five years to build the two 350MW projects, 22km from the Dutch coast. It is expected both will use approximately 100 turbines in total, meaning turbines of at least 7MW capacity will be used.

    "With Borssele 1 and 2, we are crossing the levelised cost of electricity mark of €100/MWh for the first time, and are reaching a critical industry milestone more than three years ahead of time," said Dong head of wind Samuel Leupold.

    The Dutch government has supported the development stages of the project, easing project costs. After consultation with the industry, the Dutch authorities tried to remove many of the cost and time barriers for developers looking to bid to build and operate the projects.

    The government took on the burden of preparing all the site data required to help with bids, including the environmental impact assessment. The final project and site description for the Borssele sites was placed online at the Netherlands Enterprise Agency website.

    Dutch offshore grid operator Tennet is responsible for construction, operation and ownership of the projects' substations and export cables.

    The Netherlands has approximately 520MW of offshore wind capacity installed in the North Sea.

    The previous lowest winning bid for an offshore project had been Vattenfall's €103.1/MWh for the 400MW Horns Rev 3 site in Denmark, which also excludes connections costs.
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    Precious Metals

    Centerra Gold to buy Thompson Creek Metals for $1.1 billion including debt

    Canadian mining company Centerra Gold agreed on Tuesday to buy U.S. –based miner Thompson Creek Metals for around $1.1 billion in shares and cash, including paying off nearly $900 million of debt, to expand its operations in North America.

    Centerra, whose main asset is the Kumtor gold mine in Kyrgyzstan, has wanted to reduce its exposure to the impoverished Asian nation, which has in recent months escalated its rhetoric against the miner as it guns for a bigger slice of its profits.

    Denver, Colorado-based Thompson Creek's main asset is the Mount Milligan copper and gold mine in British Columbia.

    "Half of the value of all our assets will now be domiciled in Canada. I really think we have absolutely transformed the company in a very favorable way," Centerra Chief Executive Scott Perry said in an interview.

    Thompson Creek last November hired Moelis & Co and BMO Capital Markets to look at alternatives, including debt refinancing and restructuring and asset sales, after the company's debt ballooned following the 2010 purchase of Mount Milligan and the cost of developing it into a mine.

    In December, Deutsche Bank analyst Jorge Beristain described Thompson Creek's debt as "unsustainable" in a note to clients and said the company was "quickly approaching an end-game". The company was also hit by weaker gold and copper prices.


    In terms of the deal, Centerra will redeem all of Thompson Creek's secured and unsecured notes at their call price plus accrued and unpaid interest for $889 million.

    Perry said Centerra opted to pay off all the noteholders to ensure "deal certainty".

    All of Thompson Creek's common shares will be exchanged for Centerra shares at a ratio that implies a value of 79 Canadian cents per Thompson Creek share - a premium of 32 percent on the stock's closing price on July 4 for a value of $140 million.

    Both company's shares were halted before the deal was announced.

    To fund the transaction, Centerra said it would raise C$170 million ($130.76 million) through a bought deal, pay $460 million from cash on hand at Thompson Creek and Centerra, and raise $300 million from a new debt facility.

    Centerra also has a commitment from mining financier Royal Gold Inc (RGLD.O) to restructure Royal's so-called streaming finance deal with Thompson Creek.

    Royal had helped finance the construction of Mount Milligan in exchange for 52.25 percent of its future annual gold output. That will now be amended to 35 percent of annual gold output plus 18.75 percent of copper production.

    Thompson Creek shareholders will vote on the transaction in September.
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    Tahoe expands presence in Canada, to acquire Whitney JV from Goldcorp

    Latin America-focused Canadian miner Tahoe Resources is expanding its presence home by acquiring Goldcorp's  2% net smelter return royalty for production at Bell Creek Mine for $12.5 million.

    The parties have also signed a letter of intent that would increase Tahoe’s ownership interest in their Whitney joint venture to 100%. Goldcorp’s current interest of 30% would be reduced to a 2% net smelter royalty, Tahoesaid in a statement.

    The move follows Tahoe’s deal with Lake Shore Gold in February, which added two low-cost mines in Northern Ontario to its portfolio.

    The Bell Creek Complex, located about 20 km northeast of Timmins, Ontario, consists of an underground mine and processing facility and is 100%-owned by Tahoe. It is very close to the Whitney Project, currently a 70% (Tahoe) – 30% (Goldcorp) joint venture with Tahoe as the operator.

    The move follows the company’s deal with Lake Shore Gold (TSX:LSG) in February, which added two low-cost mines in Northern Ontario to its portfolio.

    Tahoe’s chair and chief executive, Kevin McArthur, said Bell Creek and Whitney were two key components of the company’s strategy to grow gold production in Timmins to over 250,000 ounces per year by 2020.

    The Vancouver-based miner, which was spun out of Goldcorp in 2010, has been one of the most aggressive buyers in the industry. It bought Rio Alto Mining last year to expand into Peru, and in February this year, after the deal with Lake Shore, it hinted it could be interested in Goldcorp's Porcupine operation, also located in Timmins, Ontario.
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    Steel, Iron Ore and Coal

    World’s Biggest Coal Producer Exploring Exports to Trim Glut

     The state-run miner, which produces the bulk of the country’s coal, is “exploring avenues to export” amid record production, Coal Secretary Anil Swarup wrote on Twitter on Tuesday. Demand from power producers, the company’s biggest customers, has lagged output, leading to rising stockpiles at plants and the company’s own mines. The country has exported the equivalent of 0.2 percent of total production, according to the latest available data.

    “We don’t want inventories to build up,” said S.N. Prasad, director of marketing at Coal India. “That is why we are looking at all possible opportunities to sell coal.”

    Coal producers from Australia to the U.S. have been punished by a growing glut of the fuel as countries seek cleaner forms of energy and as ample supplies of natural gas make it a cost-competitive alternative. Thermal coal at Australia’s port of Newcastle, a benchmark in Asia, has rebounded since hitting the lowest since 2006 in January and prices are on pace to halt five years of declines.

    Coal India rose as much as 0.8 percent to 320.50 rupees, headed for the highest level since March, and traded 0.4 percent higher as of 12:33 p.m. in Mumbai. The benchmark S&P BSE Sensex fell 0.3 percent.

    Record Production

    Coal India boosted output 8.5 percent to 536 million metric tons in the year ended March 31, a record annual haul. Production in June was 10 percent higher from the same month last year, though it still missed output and off-take targets.

    The company increased prices of lower-grade coal, a staple for Indian power plants, by as much as 19 percent in May, at a time when cash-strapped regional power retailers are curtailing purchases because they can’t afford the cost of electricity.

    Tepid demand from cash-strapped regional power retailers has left Coal India with 45 million to 50 million tons stockpiled at its mines, said Abhishek Jain, an analyst at India Nivesh Securities Ltd.

    “The company might be looking at exports to nearby countries like Nepal and Bangladesh,” he said. “But it won’t be more than 5 million to 10 million in a year.”

    Coal India is in talks to supply fuel to NTPC Ltd.’s 1,320 megawatt power plant being built in Bangladesh, Prasad said.

    India’s total coal imports reached 212.1 million tons in the year to March 2015, up 27 percent from the previous year and dwarfing exports of 1.24 million tons, according to government statistics. Total production of coal, from private and public companies, rose to 612.4 million tons, according to the data.

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    Anglo American settles Q3 premium low vol below mid-vol: sources

    Mining company Anglo American has settled third-quarter premium low vol hard coking coal contracts with North Asian steelmakers at $92/mt FOB Australia, 50 cents/mt lower than settlements for Australian prime hard mid-vol material, according to sources.

    This was the first time in about a decade that quarterly term prices of premium mid-vol coal have surpassed that of low-vol, according to two sources.

    "It's strange that mid-vol is [priced] higher than low-vol, but the supply situation is more difficult for mid-vol supply," according to a North Asian steelmaker.

    Sources said there were ongoing production issues in at least two Australian premium mid-vol mines producing high fluidity coals.

    Anglo American's contract settlement applies to premium low-vol hard coking coal brand German Creek.

    Sources from at least three steelmakers told Platts they had concluded settlements for the coal brand since late last week.

    It was still unclear whether other premium low-vol suppliers like Canada's Teck Resources had attained a similar Q3 price. There was also doubt among market participants about whether the premium mid-vol settlement of $92.50/mt FOB Australian reached at the end of June between Nippon Steel & Sumitomo Metal Corporation and Glencore PLC was truly representative.

    The Q3 premium mid-vol price was $8.50/mt higher than the previous quarter's settlement.

    "We find it hard to [recognize] a benchmark coming from a package deal reached between one steelmaker and one producer in which semi-soft is included," one steelmaker said.

    Meanwhile, two Asian steelmakers told Platts that they had agreed July-September price for Australian semi-soft coal at $74/mt FOB Australia.

    A London spokesman for Anglo American declined to comment on the company's commercial agreements.

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    Russia H1 coal output up 6.4pct on year

    Coal-rich Russia produced 186 million tonnes of coal in the first six months this year, rising 6.4% year on year, showed the latest data from the Energy Ministry of Russian Federation.

    Of this, coal output in June stood at 29.13 million tonnes, up 5.3% from a year prior.

    During January to June, the country exported 78.98 million tonnes of coal, climbing 7.94% from the year-ago level.

    The coal export in June was 13.84 million tonnes, rising 7.5% on year.
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    Indian coal blocks go a-begging

    In a sign of times of surplus, neither India’s Ministry of Coal or  Ministry of Power was willing to take charge of seven coal mines, lying idle for the last nine months.

    The Coal Ministry was seeking to hand over the seven coalmines with aggregate production capacity of close to 46-million tons a year to the Power Ministry, but the latter was not willing to take over the mines unless each mine came bundled with all government mandatory approvals like environmental and forest clearances.

    While the Power Ministry was insisting that the nine coalmines be handed over “ready for production with all mandatory approvals built in with the assets”, the CoalMinistry had taken a stance that “onus of securing all mandatory approvals rested on the  companies which were finally allocated the assets”, a senior government official has said.

    Off the record, officials acknowledged that the tussle over handing over the nine coal mines was indicative of a lack of appetite among investors to buy coal mines during a coal over supply.

    They conceded that the Power Ministry’s stance on not taking charge of the mines stemmed from the belief that it would be difficult to find takers of the assets unless they were made “plug and play” as few miners would be willing to spend time an prolong gestation period of the assets in seeking all mandatory approvals to turn them into producing mines.

    However, it was pointed out that  current rules governing coalblocks did not have any clarity on  allocating “ready-made assets” to miners or end users and until now, the responsibility of securing mandatory approvals invariably had vested with the company securing the mine.

    In the case of the seven coal blocks, the Coal Ministry was to hand over the blocks to the Power Ministry based on the recommendation of a technical committee, which had identified the blocks as suitable for  the power sector.

    The delay in operationalising the coal blocks was also attributed to lack of clarity on who to allocate these blocks to. While the technical committee had recommended allocation to the power sector and the Power Ministry favoured handing them over to provincial power distributions companies, a section within the government maintained that these companies did not have the financial muscle required to bring the coal blocks back to production.
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    Guinea says Rio bound to $20bn mine as CEO flags delay

    Guinea said Rio Tinto Group must honour its commitment to develop the world’s largest untapped iron-oredeposit, after the company’s CEO signalled it may delay building the $20-billion mine and related infrastructure because of low prices.

    Guinea is counting on Rio and other investors, including Aluminium Corporation of China and International Finance, to meet their funding commitments for the Simandou project, the Mining Ministry said in an e-mailed statement.

    The government is “convinced” that a financing solution will be found.

    Rio, which owns 47% of the project, is being squeezed by iron-ore prices that have plunged by about 70% since 2011 as China’s slowdown left the world awash with supply. Jean-Sebastien Jacques, CEO of the second-biggest mining company, told the Times newspaper this week that he doesn’t see a way forward for Simandou.

    “It’s not the right time to develop this project from a Rio standpoint,” the Times cited Jacques as saying. “The other stakeholders might have different perspectives on this one.”

    A spokesman for Rio declined to comment beyond Jacques’ remarks in the newspaper. The company submitted a bank feasibility study to the government in May.

    Guinea is keen to develop Simandou, which could double the size of the West African nation’s economy and provide an additional 45 000 jobs, the government, Rio, Chinalco and IFC said in 2014. Jacques’ predecessor Sam Walsh said last year that the project, which includes a 650-km railway, is “very complex.”

    Separately, Sundance Resources, based in Perth, Australia, said it’s committed to the 436-million metric ton Mbalam-Nabeba iron-ore project on the border between Cameroon and the Republic of Congo, even after prices dropped.

    “There is no question of abandoning such an important project, especially with the constant support of the highest authorities of Cameroon and Congo,” CEO Giulio Casello said in an e-mailed statement.

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    Steel industry still choppy under half-year de-capacity efforts

    China’s steel and coal sectors have been implementing 276-workday reform at coal mines, layoffs and regroupings at steel enterprises, in response to the capacity cut policy for two industries rolled out by central government before the Chinese Lunar New Year holidays.

    However, the result of steel sector was not as satisfactory as expected, compared with the reported 8.4% year-on-year drop of coal output over January-May this year.

    National Bureau of Statistics (NBS) data showed that China’s crude steel output dipped only 1.4% on year to 329.9 million tonnes between January and May.

    Hebei, Jiangsu and Shandong, major steel-making provinces that are also entrusted with de-capacity tasks, witnessed coal production up 0.3%, 2.19% and 5.47% on year during the same period, instead of anticipated declines.

    Under the national de-capacity requirement of 100-150 million tonnes per annum (Mtpa) over next five years, Hebei government vowed to decrease 49.89 Mtpa iron-making capacity and 49.13 Mtpa steel capacity during the same period, and to firstly realize iron and steel capacity elimination of 17.26 Mtpa and 14.22 Mtpa this year.

    While Shandong province promised to cut pig iron and crude steel capacity of 9.7 Mtpa and 15 Mtpa in next five years, respectively.

    However, the ferrous metal market came to boom over March-May out of the previous slackness, bringing about as much as 74.8% profit in the first five months and 160% year-on-year profit in May.

    Steel sector also benefited much, with steel profit as much as 800-1,000 yuan/t in April and May. China Iron & Steel Association (CISA) data showed that CISA member steel makers realized 8.74 billion yuan ($1.31 billion) of profit in the first five months, soaring 738% on year.

    "China's suspended capacity reached 110 Mtpa last year, and over 60 Mtpa capacity was eliminated, yet 51% of the suspended plants resumed production this year," said steel analyst, adding that "the crude steel output probably decreases in the wake of peak over April-May, as difficulties remains for those still suspended capacity to recover operation."

    Meanwhile, de-stocking measures at steel industry are rewarding. The average steel stocks declined 24.2% on year in the first half of this year. The social stock of steel products dropped more than 5% on month and down 30% on year this week.

    CISA data showed that the average weekly steel stockpiles of medium and large steel makers decreased 16.36% on year to 13.3 million tonnes in the first half of the year, indicating enhanced efforts of those enterprises in de-stocking.

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