Mark Latham Commodity Equity Intelligence Service

Tuesday 9th August 2016
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    UK Economy: Post brexit meltdown?

    Sharp Brexit slowdown in services sector signals recession, economists say.

    London and South East economy hit hardest by Brexit.

    Carney’s 'shot in the arm’ to ensure economy thrives in the 'new reality'

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    Negative Yielding Bonds at $12tn

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    China drafts new rules to curb mining pollution

    China plans to raise environmental standards in its highly-polluting mining sector, according to a policy draft circulated by the Ministry of Environmental Protection.

    Amid rising concerns about the state of its environment, China has declared war on polluters and has drawn up new laws, standards and punishments aimed at forcing firms and local governments to toe the line.

    The mining sector has been a crucial part of China's rapid economic expansion in the last three decades, but poor regulation and weak enforcement of standards has contaminated much of the country's soil and left parts of its land and water supplies unfit for human use, threatening public health.

    According to draft rules published on the website of the Ministry of Environmental Protection (MEP) ( late last week, miners will be forced to treat more than 85 percent of their wastewater, and they must put systems in place to achieve the "comprehensive utilization" of tailings and other solid waste.

    Firms will also be forced to implement measures to remediate land and minimize emissions while mines are still in operation, rather than treating soil and water long after it has been contaminated.

    Mining firms will also be pressured to implement measures to protect or even relocate valuable ecosystems. Producers of toxic heavy metals like lead or cadmium also need to make use of biological or chemical technologies to remediate contaminated soil.

    The new rules will cover metals such as tin, copper, lead and rare earths, as well as minerals like calcium carbonate, though they do not apply to the coal industry, which has separate guidelines.

    Other government bodies and state-owned mining firms like Jiangxi Copper and Yunnan Tin have been invited to submit their opinions on the draft rules before Aug. 25.

    As much as 16 percent of China's soil exceeds state pollution limits, according to environment ministry data published in 2015, and farming on 3.3 million hectares (8.15 million acres) of contaminated land across the country has been banned indefinitely.

    China published an action plan to treat soil pollution earlier this year, saying that it aimed to bring the problem under control by 2020.

    However, the cost of making China's contaminated land fit for crops or livestock could reach around 5 trillion yuan ($750 billion), according to Reuters calculations.
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    Egypt announces sharp rises in electricity prices as it aims to phase out subsidies

    Egypt will increase electricity prices by up to 40 percent for households as part of its plan to repair its finances by eliminating power subsidies entirely over the next few years, the government said on Monday.

    The latest price hikes range from 25 to 40 percent depending on consumption levels and will be applied retroactively from last month, the electricity ministry said in a statement.

    Cairo, which is in the midst of talks with the International Monetary Fund (IMF) to secure a $12 billion three-year loan programme, is trying to cut its budget deficit through a number of reforms. They include tax increases and a plan to wean the population off a decades-old subsidy regime that has often benefited the highest-earning households.

    Egypt began a five-year programme of price increases in 2014 to gradually eliminate domestic electricity subsidies.

    However, Electricity Minister Mohamed Shaker told a news conference on Monday that this year the government had raised prices more steeply than originally proposed, whilst reducing the burden on poorer households, because dwindling local production had forced the country to import more gas for power generation in recent years. A devaluation in the Egyptian pound had also made those imports more expensive, he said.

    The IMF has in the past urged Egypt to phase out its costly subsidies.

    Overconsumption of cheap electricity has in recent years exacerbated energy shortages and led to frequent power cuts in summer months.

    To ease the electricity shortages, Egypt signed an $8.9 billion deal with Siemens in June 2015 for three combined-cycle power plants with a capacity of 4,800 megawatts each as well as 12 wind farms.

    Some of the plants, which together are expected to boost electricity generation by 50 percent, are expected to go online in December this year and reach full capacity in May 2018.
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    Trump would freeze new federal regulations, revive Keystone -speech

    Trump would freeze new federal regulations, revive Keystone -speech

    Aug 8 Republican presidential candidate Donald Trump would impose a temporary moratorium on new federal regulations and revive Transcanada's Keystone pipeline project, according to an outline of an economic speech Monday obtained by Reuters.

    Trump's proposals include measures to simplify taxes for everyone and dramatically reduce the income tax and to "remove bureaucrats who only know how to kill jobs; replace them with experts who know how to create jobs," according to the outline.
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    Oil and Gas

    OPEC bullish on oil demand in H2 2016, says current price slide 'temporary'

    OPEC on Monday sounded an optimistic tone about the oil market, saying that higher demand is expected in the third and fourth quarters.

    The comments, from Qatar energy minister Mohammed bin Saleh Al-Sada, who serves as OPEC president, are likely to quell any expectations of a production freeze deal in the near future.

    The recent decline in oil prices "is only temporary," and the result of weaker refinery margins, inventory overhang and the UK's recent vote to leave the EU, Sada said, according to an OPEC news release.

    With major oil consuming countries seeing their economies improve and winter approaching in the Northern Hemisphere, oil demand will rise in the next two quarters, he continued.

    "This expectation of higher crude oil demand in [the] third and fourth quarters of 2016, coupled with decrease in availability is leading the analysts to conclude that the current bear market is only temporary and oil prices would increase during the later part of 2016," OPEC stated.

    OPEC member countries are scheduled to meet informally on the sidelines of the International Energy Forum in Algeria from September 26-28.

    The Wall Street Journal on Friday had reported that a production freeze deal could be mooted at that meeting, citing unnamed OPEC delegates, but several analysts are doubtful that such a pact could be agreed.

    "Can't help but be sceptical on the resumption of this merry-go-round again after the January-April go around," Wood Mackenzie analyst Ann-Louise Hittle said in a tweet.

    Another analyst, who spoke on condition of anonymity, said: "As things stand, we wouldn't expect OPEC to substantially change course unless there is a significant deterioration in global prices."

    The last time a production freeze agreement was on the table, several OPEC members met in Doha in April along with a handful of major non-OPEC producers, notably Russia. A deal to keep output at January levels fell apart at the 11th hour with Saudi Arabia insisting that Iran -- which did not attend-- participate in any production agreement.

    Iran has said it would not participate until its production reaches pre-sanctions levels. That could be achieved later this year, though analysts have said Iran could see difficulties in maintaining that level of output, given the lack of investment over the past few years.

    OPEC, for its part, said it continues to monitor developments closely, and is in constant deliberations with all member states on ways and means to help restore stability and order to the oil market.

    The producer group's next official meeting is November 30.
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    Venezuela says OPEC, non-OPEC countries may meet in 'coming weeks'

    A meeting between OPEC and non-OPEC countries may take place "in the coming weeks," Venezuelan Oil Minister Eulogio del Pino said on Monday, as the crisis-stricken South American nation seeks to prop up weak oil markets.

    "We are actively promoting a meeting of producers, which we estimate could take place in the coming weeks, so that OPEC and non-OPEC countries can sit down to see what the scenario for the winter looks like," Del Pino told state television.

    President Nicolas Maduro last week said his government was working to convene a meeting between of OPEC and non-OPEC countries to stabilize prices.

    Russia, the world's largest oil producer, said on Monday it does not see any ground for new talks on freezing oil output but said it was open to negotiations.

    Since the plunge in oil prices in 2014, Venezuela has repeatedly tried to broker deals to freeze production and reduce a supply glut, with limited success. OPEC members and other producers including Russia did not manage to reach an agreement on freezing supply at a meeting held in Doha in April.

    OPEC members are scheduled to meet informally in September.

    Venezuela, which receives almost all of its foreign exchange from oil, is struggling with the world's highest inflation, a severe recession and chronic shortages of food and medicine. Maduro says his government is the victim of an "economic war" led by political adversaries with the support of Washington.
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    ExxonMobil buys stake in Eni’s Mozambique LNG development

    Italian oil and gas company Eni has reportedly sold a multi-billion dollar stake in its planned Mozambique LNG development to U.S.-based energy giant ExxonMobil. The deal is completed but it will not be announced for several months due to ExxonMobil’s request.

    According to the report, the deal could give ExxonMobil its desired operating stake in the onshore LNG export plant while Eni would retain control over Mozambique’s Area 4 gas fields feeding it.

    The gas reserves already discovered by Eni in Area 4 in the offshore Rovuma basin are large enough to feed a giant land-based LNG export plant. Eni, that is the operator of the Area 4 with a 50 percent stake, has discovered about 85 trillion cubic feet of gas in the offshore block.

    The Coral field will remain outside the scope of the deal with ExxonMobil, and Eni has earmarked LNG from the Phase I development of Coral to the UK-based energy giant BP, the report said.

    LNG World News has contacted Eni regarding the stake sale. An Eni spokesperson declined to comment.

    To remind, the Mozambique government in February approved the plan of development for Eni’sCoral FLNG project. The approval relates to the first phase of development of 5 trillion cubic feet of gas in the Coral discovery, located in the Area 4 permit.

    The plan of development, the very first one to be approved in the Rovuma Basin, foresees the drilling and completion of 6 subsea wells and the construction and installation of a floating LNG facility, with the capacity of around 3.4 MTPA.
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    Argentina’s Enarsa purchases eight LNG cargoes

    Enarsa – the Argentinian state-run energy company – has purchased eight LNG cargoes as part of its latest tender.

    The cargoes have been purchased from companies including Petrobras, Gas Natural, BP, Royal Dutch Shell and Trafigura. Reuters claims that the cargoes will be delivered in September and October 2016.

    Shell and Trafigura will reportedly both provide two cargoes each.
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    Pemex Has Imported Exactly Zero Barrels of U.S. Crude Oil

    Ten months after Mexico won special dispensation to import U.S. crude oil, it has yet to take in a single barrel.

    Petroleos Mexicanos successfully petitioned the U.S. Commerce Department in October for permission to swap its own heavy oil for the lighter crude produced in shale formations. The effort was part of the state-owned oil company’s plan to increase fuel quality at its refineries, and came months before the government removed all prohibitions on U.S. oil exports.

    But the oil hasn’t come, according to the latest reports from the U.S. Census Bureau and Mexico’s Energy Ministry. Pemex says it doesn’t make economic sense to bring in U.S. crude at current prices. Even if the potential for profits improves, though, the question remains whether Mexico’s infrastructure would be able to handle the imports and if its ailing refineries would be able to take it. Roberto Montes, Pemex’s operational manager for refining, said in an interview last year that the necessary infrastructure wasn’t in place to import U.S. crude by large tankers.

    The aim to produce better-quality gasoline and diesel by blending Mexican heavy crude with U.S. light oil has run into a snag at a time when Pemex’s refineries are struggling with continued operating losses, reduced investment and frequent outages. Mexico, which for years requested supplies from the U.S., has had to cut 162 billion pesos ($8.7 billion) from Pemex’s budget in the past two years to weather an oil market rout, compromising the efficiency of units that would process the imported crude.

    “It wouldn’t surprise me if the refineries were not in a condition to receive the shipments,” John Padilla, Managing Director of IPD Latin America, said in a phone interview. “The company is in a full-blown liquidity crisis, which means less and less money can be dedicated to refining and crude processing."

    Refining Woes

    When Pemex received a license from the U.S. last October to import as much as 75,000 barrels a day in exchange for heavy Mexican crude, the state-owned producer said it would begin welcoming U.S. light oil to lower the sulfur content of its fuel. But Mexico’s six refineries are running at about 60 percent of capacity and had 35 unscheduled stoppages in the first quarter, prompting the country to boost fuel imports. The units have amassed annual losses of more than 100 billion pesos as refining fell last year to the lowest since at least 1990.

    Pemex said it would reevaluate the purchases if potential margins improved, and that the company already has the proper infrastructure in place. The imports have been postponed because they would no longer be as profitable, the company said in an e-mailed response to questions. The producer is continuing to use its own light crude to mix with heavier oil, according to the statement.

    ‘Economic Attractiveness’

    At the time of the approval of the U.S.-Mexico crude swap, replacing some local Maya oil with imported West Texas Intermediate would provide good returns, but the broader lifting of U.S. crude trade restrictions in December elevated WTI prices and diminished the potential profits from imports, Pemex said.

    "Due to the reduction of its economic attractiveness, it was decided to postpone crude imports until the economic and operating conditions merit reconsideration,” Pemex said.

    The import of U.S. light crude was deemed "very positive for our crude oil processing operations" and said to "generate additional value for the company," Pemex Treasurer Rodolfo Campos said on the day of the announcement.

    Since lifting the international trade limits on Dec. 18, the U.S. shipped its crude to 16 countries through May, including Colombia, Nicaragua, Panama and Peru in Latin America, according to 2016 data from the U.S. Census Bureau. WTI futures have gained more than $8, or about 24 percent, since then and is hovering around $43 a barrel.
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    Britons will decide how to spend $1.3 bln shale gas fund

    Britons living near "fracking" developments will be able to decide how a 1 billion pound ($1.3 billion) shale gas wealth fund should be spent, either by accepting direct personal payments or supporting projects such as railways or flood defences, the government said on Monday.

    Prime Minister Theresa May announced on Sunday that some tax proceeds from new shale gas developments could go directly into local residents' pockets, showing her support for the nascent industry that she hopes can ease Britain's growing reliance on imported gas.

    In a consultation published on Monday outlining how the shale wealth fund should be run, the government said payments to individual communities, where residents could decide what to do with the money, should not exceed 10 million pounds over the 25-year lifespan of the fund.

    Residents would be given the choice of receiving payments directly or picking a project that would help their community.

    "Local communities should be the first to benefit from the Shale Wealth Fund, and they should get to decide how a proportion of the funding is used," the government said in its consultation document.

    Britain is estimated to have plenty of shale gas resources in place, enough to cover the country's annual gas needs for hundreds of years.

    But shale gas extraction -- so called fracking -- has been slow because of local residents' and green campaigners' concerns over environmental impact and the fall in energy prices.

    In the U.S., where abundant shale gas production has started to turn the country into an exporter, landowners have directly benefited from the shale gas boom because they have rights to mineral resources.

    Payouts to communities from the wealth fund will come on top of shale gas operator payments of 100,000 pounds per exploration well and a one percent share of shale gas site revenues.

    INEOS, which controls Britain's largest shale gas sites, has pledged to increase the percentage of its revenue it would pay to communities to 6 percent. It said these payments could add up to 2.5 billion pounds.

    Shale gas developers welcomed the government's proposal.

    "The onshore oil and gas industry in the UK continues to believe that local people should share in the success of our industry and be rewarded for hosting sites on behalf of others in the country," said Ken Cronin, chief executive of the UK Onshore Oil and Gas body.

    Environmental campaigners said cash sweeteners would not convince Britons about shale gas.

    "You can't put a price on the quality of the air you breathe, the water you drink, and the beauty of our countryside," said Doug Parr, Greenpeace UK's chief scientist.
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    BP Suit Over Supply Deal Spurs Claim of Oil-Market Rigging

    A firm owned by two Wall Street commodity market veterans has accused oil giant BP PLC of manipulating the crude market on a single day in 2014 to get a better price on a deal it was negotiating with them.

    The company, controlled by Kaushik Amin and Neal Shear, pioneers of Wall Street’s foray into commodity markets, claims BP rigged market prices on a day it was using to value a two-year crude-supply agreement, costing the firm $33 million. BP denies the allegations. The pair’s investment partnership, SilverRange Capital Partners LLC, lodged the charges through a subsidiary called NARL Refining Limited Partnership as part of a legal fight over the contract between BP and a refinery it owns in Canada.

    The price-rigging allegations, which surfaced in documents filed in New York federal court, haven’t been reported previously.

    SilverRange hasn’t yet produced evidence to support its claim that BP rigged the market. BP has previously been sanctioned in the U.S. for natural gas and propane-market manipulation. Pinning price movements in global markets on a single player will be a tough task for them, an analyst said.

    "There have been very few manipulation cases proved," said Rosa M. Abrantes-Metz, a New York University professor and market-manipulation expert who has testified in enforcement cases, including the natural gas case against BP. "The requirements are high, they’re difficult to establish.”

    BP Denial

    The claims by Amin’s and Shear’s firm "are completely without merit and have been made solely as a tactical move" in the dispute, BP said in a prepared statement. The company said it couldn’t comment further because of confidentiality rules covering the private arbitration proceeding in which the claim was originally raised. The claims were entered into public court records as part of the New York lawsuit.

    There are hundreds of traders involved in the roughly $275 billion market for the world’s two main crude contracts, making it too big to manipulate over long periods. But larger dealers can influence it at the margins, causing incremental moves by putting on significant positions when trading is thin.

    Earlier Troubles

    It’s not the first time BP’s energy-trading unit has been accused of market manipulation. Last month, BP was fined $20 million by U.S. pipeline regulators for gaming the Texas natural gas market in 2008. BP has said it plans to appeal. In 2007, the company agreed to pay $303 million to the U.S. Justice Department and the U.S. Commodity Futures Trading Commission to resolve an investigation into propane market manipulation. The company neither admitted nor denied the allegations.

    That same year, a BP trader paid $400,000 to settle CFTC civil charges that he tried to manipulate gasoline futures. He neither admitted nor denied the claims.

    Now, Amin’s and Shear’s firm is raising similar complaints in the arbitration. BP launched the arbitration case against SilverRange last year, claiming the refinery failed to produce the required amount of fuels under the contract. SilverRange sued in New York federal court in January, accusing BP of supplying inferior crude that caused damage to refining equipment.

    A judge has already denied SilverRange’s effort to force BP to continue supplying crude to the refinery, as SilverRange sought. The lawsuit has been suspended while the dispute, including the manipulation claim, remains in arbitration. SilverRange could demand that BP produce its trading records, internal communications and other evidence in an effort to back up its claim.

    Lead Traders

    Shear built the commodity franchise at Morgan Stanley, long considered one of the top-tier firms in the market, while Amin did so at Lehman Bros. Their Wall Street careers were damaged in the financial crisis. Shear, who had risen to a more senior role overseeing trading at Morgan Stanley, was demoted in 2007 following its $3.7 billion loss on mortgage securities, and left the firm soon after. Amin was cited in the Lehman bankruptcy examiner’s report as being a key figure in the use of the so-called Repo 105 accounting maneuver that the examiner said helped the firm conceal its deteriorating finances.

    After a handful of other ventures, including a stint at UBS Securities LLC where they first worked together, the two teamed up in 2013 to pursue direct ownership of energy facilities such as refineries and delivery terminals.

    Supply Deal

    They bought the Come by Chance refinery in Newfoundland and Labrador in 2014 after negotiating a two-year agreement with BP, under which the oil company would sell them crude and then buy the finished fuels. The price tag on the supply deal was tied to the closing prices of the U.S. and global Brent crude benchmarks on Aug. 1, 2014.

    As that day approached, the gap between the two benchmarks reached its highest level in a month, which benefited SilverRange, according to court records. But on Aug. 1, a Friday, it lurched in the other direction, contracting 7.5 percent over the course of the trading session, with global Brent prices dropping more sharply than their U.S. counterparts.

    According to SilverRange’s court filing, much of the move came in the final half hour of trading before the market closed for the weekend. Traders sometimes use such tactics at day’s end to drive the market in their favor, in a strategy known as "banging the close."

    SilverRange asserts the ripple sliced 50 cents-a-barrel off the value of their deal, or $32.9 million over the life of the contract.

    "BP appears to have engaged in manipulation of the crude oil markets" to force prices down and reduce their cost in the deal, the firm claimed in a court filing.

    Weak Demand

    At the time, traders and analysts attributed the market’s move to evidence of weakening demand amid the start of a burgeoning supply glut that would ultimately prompt a two-year collapse.

    But executives at SilverRange were immediately suspicious and called BP that day to ask if their trading was behind the move, according to the court records. BP assured them, according to one SilverRange filing, that "it was not responsible for the movement and reaffirmed that it would be a good partner in the relationship."

    Evidence of market manipulation has to document intent and show that the price change was directly caused by the tactic. Both private litigation and regulatory enforcement actions have often fallen short. In the CFTC’s most high-profile oil-market-manipulation case in recent years, the agency wound up settling with the defendants for $13 million -- much less than the $50 million they allegedly reaped from the scheme.

    Class Action

    A class-action lawsuit claiming BP, Royal Dutch Shell PLC, trading house Trafigura Beheer BV and others conspired to manipulate global oil benchmarks has dragged on in New York federal court for three years, through three different versions of the lawsuit and with some co-defendants being dismissed from the case. The companies deny wrongdoing.

    BP was among companies raided in 2013 and subpoenaed by European Union antitrust officials investigating rigging in the crude oil markets, but the probe ended without charges being filed.

    The case is NARL Refining Ltd. Partnership v. BP Products North America Inc., 16-cv-00404, U.S. District Court, Southern District of New York (Manhattan).

    Attached Files
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    Ending $4 Billion U.S. Oil Subsidy Seen Having Minimal Impact

    Eliminating $4 billion of petroleum subsidies in the U.S. would have only a minor affect on oil production and demand and boost the country’s influence in advocating global climate change action, according to a report for the Council on Foreign Relations.

    Withdrawing oil-drilling subsidies could cut domestic production by 5 percent by 2030, which could increase international oil prices by just 1 percent, Gilbert Metcalf, a professor of economics at Tufts University, said in the report. Local natural gas prices could rise as much as 10 percent, while both production and consumption would probably fall as much as 4 percent, according to the report.

    The viability of the three main oil and gas subsidies in the U.S. has been debated for years. Environmental groups argue that eliminating state support would not only increase government revenue but also push the country toward mitigating climate change. The industry says any changes would lead to large declines in domestic production and cut many jobs. The oil price crash over the last two years has made the U.S. oil industry more vulnerable, enhancing its argument for keeping the subsidies.

    Metcalf concluded that “U.S. energy security would neither increase nor decrease substantially” if the three subsidies were repealed. The effect on oil consumption would be “even less noticeable,” implying “emissions of greenhouse gases that cause climate change would not change substantially,” he said.
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    SM Energy Announces Permian Basin Acquisition

    SM Energy Company today announced that it has entered into a definitive purchase agreement to acquire 24,783 net acres in Howard County, West Texas, expanding the Company’s Midland Basin footprint to approximately 46,750 net acres. The acquired acreage position is largely contiguous and includes approximately 4,900 Boe per day net production (with two new wells coming on-line August 2016) and 6 MMBoe of proved developed producing reserves. The purchase price is $980 million and the seller is Rock Oil Holdings LLC.

    “Continued portfolio management, concentrating capital allocation to highest return programs and operating at peer leading performance levels will allow us to generate higher company-wide margins, cash flow growth and value creation for our shareholders going forward.”

    President and Chief Executive Officer Jay Ottoson comments: “We are demonstrated leaders in operational performance in the Midland Basin, and we have been looking for some time to expand our asset base, in the right location under the right terms. This is a negotiated transaction for assets in Howard County, a region of the Midland Basin that is emerging as a top tier area for well performance.

    “Our operational expertise in the region can be immediately applied to the acquisition assets. We expect that the implementation of pad drilling, reservoir modeling, zipper frac’s, and leading edge completion technologies will add value from the start. We anticipate running one rig in the area in the fourth quarter of 2016 and two rigs throughout 2017. As a result, we are increasing our estimate of total capital spend for 2016 by approximately $15-20 million.

    “Continued portfolio management, concentrating capital allocation to highest return programs and operating at peer leading performance levels will allow us to generate higher company-wide margins, cash flow growth and value creation for our shareholders going forward.”

    The transaction is expected to close on October 4, 2016, with an effective date of September 1, 2016 and will be subject to customary purchase price adjustments. The closing of the transaction is subject to the satisfaction of customary closing conditions, and there can be no assurance that the transaction will close on the expected closing date or at all.

    As provided above, average production represents the July 2016 average, on a 3-stream basis, and proved developed producing reserves are estimated by SM Energy and have not been verified by a third party.

    Jefferies served as lead financial advisor to Rock Oil LLC. Petrie Partners also acted as a financial advisor to Rock Oil.
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    Oil’s ‘hottest ZIP codes’ see bids soar on SM deal

    SM Energy Co.’s $980 million purchase of drilling rights in the biggest U.S. crude field indicates producers are willing to pay a premium for access to one of the few spots where oil exploration still turns a profit.

    SM, which extracts oil and natural gas from the Rocky Mountains to the Gulf Coast, agreed to pay the equivalent of $39,543 an acre for drilling rights across 24,783 acres in the Permian Basin, almost doubling the Denver-based company’s holdings in the region, according to a statement on Monday. SM plans to deploy a rig as soon as October to drill the acquired acreage, which Chief Executive Officer Jay Ottoson called “top tier.”

    After decades of neglect by international oil producers, the Permian Basin that lies beneath West Texas and New Mexico has seen a rejuvenation in the past eight years as intensive drilling and fracking techniques honed in other oil- and gas-producing regions were brought to bear on the Permian’s multi-layered stack of crude-soaked rocks. As low energy prices made other areas unprofitable to drill, explorers as diverse as Apache Corp., Cimarex Energy Co. and Occidental Petroleum Corp. have been touting plans to expand Permian investments.

    The Permian’s got “the hottest ZIP codes in the industry,” Concho Resources Inc. CEO Tim Leach told analysts on an Aug. 3 call. The Midland, Texas-based company focuses solely on the Permian and announced more drilling plans last week.

    Higher Price

    SM jumped 7.4 percent to $31.46 at 11:15 a.m. in New York trading, after earlier reaching $31.68, the highest intraday price in two months. The shares have risen 60 percent this year.

    SM’s agreement “demonstrates continued high acreage values” in the Permian and “validates” recent acquisitions in the region by Diamondback Energy and Callon Petroleum, Jeff Grampp, an analyst at Northland Securities, said in a note to clients. It’s also a positive development for other Permian drillers such as Earthstone Energy, Parsley Energy and RSP Permian, he said.

    The per-acre price SM is paying exceeds the $25,000 to $35,000 range that acreage in the Permian’s Midland Basin section had been fetching as recently as May, according to estimates by Mike Wichterich, president of Three Rivers Operating Co., a private equity-backed explorer. QEP Resources forked over about $60,000 an acre to unnamed sellers for a tranche of Permian drilling rights in June, a signal that deal values in the region are at “an all-time high,” Eli Kantor, an analyst at Iberia Capital Partners said in a July 26 note to clients.

    Acquisition “deal values remain high and incrementally trending up, which bodes well for operators with established acreage positions,” Northland’s Grampp wrote.

    SM is acquiring the Permian drilling rights through an outright purchase of Riverstone Holdings LLC’s Rock Oil Holdings LLC, the London-based private equity giant said in a separate statement. Denver-based Rock Oil was created in 2014 and has been amassing drilling rights ever since, Riverstone said.

    Patty Errico, an SM spokeswoman, didn’t immediately return a telephone message seeking comment.

    Permian Basin

    The Permian Basin, an active oil-producing region for almost a century, fell out of fashion as major explorers abandoned onshore U.S. drilling to search in deep waters and overseas. Smaller domestic companies revitalized the region by adapting sideways drilling and high-pressure hydraulic fracturing to open up layers of rock that had been previously been shunned as too dense or expensive to be worth exploiting.

    U.S. drillers spent last week’s earnings conference calls talking up their acreage in the Permian and Oklahoma’s Scoop and Stack regions, areas where companies say they can still make a profit despite depressed oil prices.

    The Permian generated Apache Corp.’s highest profit margins in North America — about $17 per barrel, more than double the return of other regions, CEO John Christmann told analysts on Aug. 4. The Houston company’s only active drilling rigs were in the Permian last quarter and its only other wells to start producing oil were in the Scoop, he said.
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    Sanchez Energy announces second quarter 2016 results

    Sanchez Energy Corporation, today announced operating and financial results for the second quarter 2016.

    Highlights include:

    Sanchez Energy plans to increase its 2016 upstream capital spending by up to $50 million, to a range of between $250 million to $300 million, which positions the Company to be able to deliver total production growth of between 5% and 8% in 2017;
    Total production of 5.1 million barrels of oil equivalent ('MMBoe') during the second quarter 2016, up approximately 4% over the second quarter 2015;
    Average production of approximately 55,900 barrels of oil equivalent per day ('Boe/d'), which exceeded the high end of the Company's guidance of 48,000 to 52,000 Boe/d for the second quarter 2016 by over 7%;
    Sanchez Energy's development focus remains on Catarina, where the Company has met its 50 well annual drilling commitment for the period July 2015 through June 2016 and has banked 20 wells toward the 50 well annual drilling commitment for the period July 2016 through June 2017;
    South-Central Catarina wells continue to exceed expectations, with the 30-day initial production rates of most recent wells, including the best well drilled to date at Catarina, averaging 1,600 to 1,900 Boe/d;
    Average drilling and completion costs during the second quarter 2016 at Catarina and Cotulla were $3.3 million per well, with the Company's best wells coming in below $3.0 million per well in both areas;
    Revenues of approximately $111 million (exclusive of hedge settlements) were up approximately 39% when compared to the first quarter 2016 due to improvements in realized commodity prices during the second quarter 2016;
    Commodity price realization during the second quarter 2016 includes natural gas liquids ('NGL') realization of $14.47 per barrel, up from $8.91 per barrel in the first quarter 2016, after total production was impacted by 2,000 to 3,000 barrels per day ('Bbls/d') as a result of significant ethane rejection;
    Inclusive of hedge settlements, revenues totaled approximately $146 million during the second quarter 2016;
    Adjusted EBITDA (a non-GAAP financial measure) of approximately $79.6 million, up approximately 23% when compared to the first quarter 2016;
    Total liquidity of approximately $624 million as of June 30, 2016, which consisted of $324 million in cash and cash equivalents and an undrawn bank credit facility with an elected commitment amount of $300 million; and
    The planned increase in capital spending is expected to be largely offset by the Company's July 2016 sale of its interest in Carnero Gathering, LLC ('Carnero Gathering'), a joint venture that is 50% owned by Targa Resources Corp. ('Targa'), to Sanchez Production Partners LP (NYSE MKT:SPP) ('SPP') for approximately $44 million in total consideration (the 'Carnero Gathering Transaction').

    MANAGEMENT COMMENTS'We are encouraged by our strong operating and financial results in the first half of 2016,' said Tony Sanchez, III, Chief Executive Officer of Sanchez Energy. 'As previously reported, we achieved excellent production results in the second quarter 2016, exceeding the high end of our guidance by over 7%. Process improvements and efficiency gains continue to drive our operating performance, with several wells coming in below $3.0 million. This combination of strong production and lower costs has allowed us to achieve positive returns on our capital program, which provides us with a key competitive advantage in responding to current industry conditions.'

    'Our development focus remains on Catarina and further delineation of the South-Central region of the lease as results in this region, including the exceptional results from the E33 Pad that we reported in July 2016, continue to meet or exceed our expectations. The E33 Pad consisted of four wells that had average 30-day initial production rates that ranged from 1,600 to 1,900 Boe/d, representing some of the most productive results drilled at Catarina to date. We continue to test northern extensions in South-Central Catarina and remain impressed with this area of the lease. As of June 30, 2016, we successfully completed our 50 well annual drilling commitment at Catarina for the period July 2015 through June 2016 and banked 20 wells toward the 50 well annual drilling commitment for the period July 2016 through June 2017.'
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    Williams Cos, Williams Partners to sell Canadian operations

    Pipeline company Williams Cos Inc and its master limited partnership agreed on Monday to sell their Canadian natural gas liquids midstream businesses to Inter Pipeline Ltd for total cash proceeds of C$1.35 billion ($1.03 billion).

    This is the first major deal by Williams Cos since Energy Transfer Equity walked away from its more than $20 billion takeover of the company in June.

    Williams Partners LP will get a net consideration of about $817 million, while Williams Cos will get about $209 million after a waiver of $150 million of incentive distribution rights in the quarter.

    Both companies said they planned to use the proceeds to reduce borrowings on credit facilities.

    The assets include two liquids extraction plants located near Fort McMurray, Alberta; a fractionator near Redwater, Alberta and a pipeline system that connects these facilities.

    Fort McMurray in northern Alberta, the heart of Canada's oil sands region, was affected by an uncontrollable wildfire in May.

    The Canadian unit had attracted at least seven bidders, including Enbridge Inc, and pension funds, such as Canada Pension Plan Investment Board and Ontario Teachers' Pension Plan, Reuters reported last month, citing sources.

    Inter Pipeline said it would also assume responsibility for the potential construction of a C$1.85 billion propane dehydrogenation facility in Alberta.

    The deal, which is expected to immediately add to funds from operations per share, is estimated to reduce Inter Pipeline's annual cash taxes by about $70 million in 2017 through 2019.

    Inter Pipeline said it expected to fund the deal by proceeds from the issuance of 22.43 million subscription receipts, new term debt and available capacity on its credit facility.
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    Sempra: FID on Cameron LNG expansion project could be postponed

    San Diego-based energy company and LNG operator Sempra Energy said that a final investment decision on the proposed Cameron LNG expansion project could be delayed beyond the first half of 2017.

    Sempra and its partners in the Cameron LNG export project are currently building the first three liquefaction trains with a nameplate capacity of 13.9 million tonnes per annum (Mtpa) in Hackberry, Louisiana.

    The Cameron expansion project, which would include up to two additional liquefaction trains raising the project’s capacity to 24.92 Mtpa, has received approvals from both the U.S. FERC and the Department of Energy.

    However, the final investment decision could be postponed as one the partners “indicated to Sempra Energy and the other partners that it currently does not want to invest additional capital in Cameron LNG JV with respect to the expansion,” Sempra said in a 10-Q filing with the U.S. Securities and Exchange Commission.

    Cameron LNG is a joint venture owned by affiliates of Sempra Energy, Engie, Mitsui & Co. and Japan LNG Investment, a joint venture formed by affiliates of Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha.

    “As a result, alternatives are being developed and negotiated with all partners to allocate the required equity, commitments and guarantees to the remaining three partners that are supportive of the development of the expansion and to secure the consent of all of the partners to allow the expansion to proceed,” Sempra said.

    These activities have contributed to delays in developing firm pricing information and securing customer commitments, Sempra said, adding that failure to obtain the unanimous consent of all Cameron LNG partners to move forward on the expansion project or to obtain the necessary customer commitments could further delay this project.

    Sempra expects the first three trains of the LNG export project to achieve commercial operation in 2018, and have the first year of full operations in 2019.

    The total cost of the facility, including the cost of the original import facility, is estimated to be approximately $10 billion.
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    Alternative Energy

    Apple approved to enter power market

    Apple has won permission from federal regulators to sell excess electricity that is generated by three of its major solar projects.

    The Federal Energy Regulatory Commission, or FERC, on Thursday approved an application from Apple’s energy subsidiary to sell electricity in six regional power markets around the country at market rates.

    The move into outright selling of energy follows on from the company’s efforts in recent years to supply its data centers with renewable power. One example of that is the $850m spent last year on a 130 MW solar farm near San Francisco.

    Apple also owns 20 MW of generation in the Nevada Power Company service area and 50 MW in the Salt River Project service area in Arizona, according to the FERC order. All of Apple’s data centers are now powered by renewables.

    In granting approval, the commission determined the company did not raise the risk of being able to unfairly hike up power prices.

    The iPhone maker is among a group of companies investing in energy projects in a bid to tackle global warming and cut electric bills. Google, Microsoft Corp. and Inc. are backing wind turbines and solar farms to power their operations and lower their carbon footprint.
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    Affordable solar schemes light way to energy for all in Zimbabwe

    Innovative ways to pay for solar power systems could make clean energy affordable for many of Zimbabwe's 1.5 million households that lack electricity, campaigners say.

    Zimbabwe produces only around 60 percent of the electricity it needs when demand is highest, and relies on costly imports to make up some of the shortage, particularly when drought hits hydropower facilities, as happened this year.

    That means solar panels and other clean energy sources not connected to the southern African nation's power grid are likely the cheapest and fastest way to bring electricity to those without it, say sustainable energy experts.

    “Only focusing on grid extension and increasing generation capacity will not allow us to attain energy access for all by 2030,” said Chiedza Maizaiwana, manager of the Power for All Zimbabwe Campaign.

    To meet the internationally agreed goal, so-called “decentralised” renewable energy is “a critically needed solution”, she told the Thomson Reuters Foundation.

    “It is imperative that we create the opportunity for families and businesses to access (these) services rapidly and affordably,” she said.

    Getting connected to the grid in a rural area can cost thousands of dollars, a huge obstacle when many people earn between $20 and $100 a month, said Ngaatendwe Murimba, a program officer for Ruzivo Trust, a non-governmental organization (NGO) working to improve rural energy access.

    But families without electricity do pay for energy, buying firewood or charcoal – which drive deforestation – batteries, or polluting fuels such as paraffin.

    A 2012 study by SNV, a Dutch anti-poverty NGO, found that a rural household in Zimbabwe spends on average $26 a month on lighting, communication and entertainment, including $8 to $15 on kerosene and candles alone.

    A home solar system that can produce enough power to run lights, a radio and a television costs about $500, said Honour Mutambara, a renewable energy manager with SNV in Zimbabwe.

    That’s one reason only a fifth of households in Zimbabwe use solar energy, he said.


    Simba Mangwende, a renewable energy director with the Ministry of Energy and Power Development, told a workshop in June the market for decentralised renewable energy is “abundant but it is being curtailed by deprivation of cheap sources of finance”.

    Zimbabwe lacks clear-cut policies and targets for renewable energy, and is still developing a feed-in tariff, deemed key to attracting investor participation in the sector.

    If families are to afford clean energy in the short term, innovative business models are needed, such as pay-as-you-go or rent-to-buy solar systems, experts say.

    Jonathan Njerere, head of programs in Zimbabwe for charity Oxfam, said that in Gutu district, 230 km east of Harare, his organization and others had helped set up a community-owned, self-financing solar energy scheme.

    It has enabled more than 270 farmers to irrigate about 16 hectares (39.5 acres) of crops.

    Oxfam gave the community solar equipment for irrigation and an initial batch of solar lanterns, which were sold to members. The proceeds were pooled in a savings and lending scheme, allowing others to join and buy solar products for home and business use.

    Community funds are used to purchase solar equipment for sale to the public through energy kiosks, and the revenue is kept for repairs and relief in natural disasters.

    Njerere said the program, assisted by 2 million euros ($2.22 million) from the European Union, had helped chicken farms, fisheries, tailors and shopkeepers acquire hire-purchase solar panels, so they can work in the evening as well as during the day.

    Other entrepreneurs use the solar panels to sell mobile phone charging services for $0.20 a time.


    Jeffreti Chara operates his sewing business with a $700 home solar system bought on credit from the community scheme, which powers a sewing machine and lights his three-bedroom house.

    He paid $50 upfront, and is now paying $20 each month, covering $290 of the loan so far.

    “Production has improved dramatically since I started using a solar-powered machine, boosting my income from around $50 to $90 a month,” said Chara, who mostly sews uniforms.

    “Solar energy has improved my family’s quality of life such that there is not much difference between us and people in the urban areas,” he added.

    Servious Murikitiko, an energy kiosk chairperson, said the solar scheme had brought clean, affordable energy to the community, allowing children to read at night and schools to introduce computer lessons, while providing entertainment and extra income to homes and businesses.

    Households purchase what they can afford, he added, with some paying just $4 a month to acquire solar lanterns.

    More than 32,000 people have benefited from solar power across the district.


    SNV’s Mutambara estimates Zimbabwe's potential market for solar lanterns at $33.7 million and that for solar home systems at $235 million.

    But few lenders and solar companies have tried their luck in rural areas due to a perception of limited customers, as well as high transaction costs and risk, he said.

    Providing subsidized solar equipment would hugely improve uptake, Ruzivo Trust’s Murimba said.

    Communities are asking for free installation of solar systems, zero taxes on solar equipment, and government-accredited dealers who can provide them with quality solar equipment and technical support, he added.

    One local company had to discontinue a popular package including a mobile phone and a $45 solar lamp. It sold some 400,000 lights to around a third of the country’s households, but they were poor quality, and many developed problems with no mechanism for repair or return.

    In Harare, vegetable vendor Regina Meki, 40, uses a solar lamp she bought on credit to hawk her wares well into the night.

    Under a payment plan offered by a local solar company, she pays $1 a day for the $50 rented lamp, which has helped boost her monthly earnings from $70 to $120.

    “Solar energy has brought nothing but happiness to me, increasing my income. Besides payment for the equipment was easy on the pocket,” she said.
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    Centrex advances Oxley to prefeasibility stage

    ASX-listed junior Centrex Metals is advancing its Oxley project, in Western Australia, to the prefeasibility study (PFS) stage, after receiving positive results from a scoping study on a start-up potassium nitrate fertiliser (NOP) operation.

    The scoping study, prepared by Amec Foster Wheeler, shows that the start-up operation has the economic potential to be globally competitive, with upside for large-scale expansion, the company reported in a statement on Monday.

    The start-up NOP operation is based on an inferred mineral resource of 38-million tonnes at 10% potassium oxide (K2O), from a total of 155-million tonnes at 8.3% (K2O). Theresources to date cover only 3 km of the overall 32 km striking area that forms the basis of the project.

    Centrex will now proceed to a PFS, which will not only consider a start-up NOP operation, but also second stage expansion in to the bulk potassium fertiliser market.

    The PFS is expected to be complete by the end of 2017. The company will also start with preliminary engineering studies.
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    Precious Metals

    Franco-Nevada hits new production, revenue records; boldly beats expectations

    Precious metals streaming firm Franco-Nevada Corp has doubled net income for the quarter ended June 30, hitting new gold-equivalent ounce (GEO) output and revenue records.

    The Toronto-based firm reported a 75% year-on-year surge in adjusted earnings to $40-million, or $0.22 a share, beating Wall street analyst forecasts of earning $0.19 a share.

    Revenue rose 38% year-on-year to $150.9-million, resulting in adjusted earnings before interest, taxes, depreciation and amortisation to rise 45% to $118.9-million.

    "Franco-Nevada's diversified portfolio continues to perform very well. With record GEO and revenue results, we are now expecting to be close to the top end of our previously provided guidance ranges for 2016. Even more exciting for the future, we are seeing renewed activity and good news at many of our non-producing advanced and exploration assets. In addition, our investment opportunity pipeline remains very full,” CEO David Harquail stated Monday.

    Gold equivalent output rose 36% in the second quarter to 112 787 oz, boosted by new gold and silver stream acquisitions and oil and gas. According to Franco-Nevada, revenue was sourced 94% from precious metals (72% gold, 16% silver and 6% platinum-group metals) and 84% from the Americas (14% US, 19% Canada and 51% Latin America.

    During the period, the company provided $37.7-million of funding to First Quantum Minerals’ Cobre Panama projectduring the quarter. It now expected its portion of total funding to range between $120-million and $140-million this year, down slightly from previous estimates of $130-million to $150-million.

    Franco-Nevada ended the quarter with $225.8-million in cash at and no debt.
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    Richmont Mines Reports Strong Second Quarter Financial Results; On Track to Meet or Exceed Guidance Estimates

    Richmont Mines Inc. announces operating and financial results for the three and six months ended June 30, 2016, driven by solid results from the Island Gold Mine. The Corporation will host a conference call and webcast on Monday, August 8, 2016 , beginning at 8:30 a.m. Eastern Time (details below). (All amounts are in Canadian dollars, unless otherwise indicated.)

    Second Quarter Highlights

    Company-wide production was 23,320 ounces for the quarter, an 11% decrease over Q2 2015, primarily due to the depletion of the Monique stockpile earlier this year. The Island Gold Mine produced 18,617 ounces of gold in the second quarter, a 24% increase over Q2 2015, driven by record underground and mill productivity of 911 tonnes per day and 878 tonnes per day, respectively, as well as a positive reconciliation (mined vs. reserves) of 19%.
    Gold sold during the quarter was 24,888 ounces, a decrease of 10% over Q2 2015, at an average realized price of $1,628 (US$1,263) per ounce.
    Revenues for the quarter were $40.6 million ( US$31.5 million ), consistent with Q2 2015.
    Company-wide cash costs1 for the quarter were $903 per ounce ( US$701 per ounce), a decrease of 7% over Q2 2015 and below current guidance estimates. Cash costs for the Island Gold Mine were $766 per ounce ( US$595 per ounce), a 20% decrease over Q2 2015 and significantly below current guidance estimates.
    Company-wide All-in-Sustaining Costs1 ("AISC") for the quarter were $1,330 per ounce ( US$1,032 per ounce), in-line with Q2 2015 and within current guidance estimates. AISC for the Island Gold Mine were $1,038 per ounce ( US$806 per ounce), a 21% decrease over Q2 2015 and significantly below current guidance estimates.
    Earnings were $2.7 million , 8% lower than Q2 2015, or $0.04 per share ( US$2.1 million , or US$0.03 per share).
    Operating cash flow (after changes in non-cash working capital) of $14.9 million ( US$11.5 million ), or $0.25 per share ( US$0.19 per share), both in-line with Q2 2015.
    Richmont ended the quarter with an increased cash balance of $95.5 million ( US$73.4 million ), which includes net proceeds of $29.1 million ( US$22.7 million ) related to a bought-deal prospectus financing completed on June 7, 2016 and $3.0 million of net free cash flow1.
    Based on the success of the Phase 1 exploration program at the Island Gold Mine, the Corporation launched an aggressive 18 to 24 month Phase 2 drilling program of up to 142,000 metres, with an estimated 39,000 metres to be completed in the second half of 2016.
    Based on the strong operational and cost performance in the first six months of the year, Richmont expects to meet, or exceed, the high end of production guidance and the low end of cash cost and AISC guidance. The Corporation will determine whether a revision to 2016 guidance estimates is warranted following the completion of a scheduled 3-week electrical upgrade at the Island Gold mill and the commencement of stope mining in the Q Zone of the Beaufor Mine, both expected in August. It is anticipated that any update to guidance estimates would be released by mid-September.

    "Positive grade and tonne reconciliations, as well as record mining and milling productivities at the Island Gold Mine have driven better than expected production and cost performance in the first half of the year. For the remainder of the year, we expect Island Gold to continue its strong performance as well as see improved performance from the Beaufor Mine as stope mining from the higher grade Q Zone commences." stated Renaud Adams , CEO. He continued, "Our solid cash position and cash flow generation is expected to fully fund both our accelerated development activities and the Phase 2 exploration program that are currently underway at the Island Gold Mine, both of which could position this core asset for significant production growth and mine life extension."
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    AuRico Metals Reports 2016 Second Quarter Results

    AuRico Metals Inc. today reported its financial results for the quarter ended June 30, 2016.  The Company also announced increased guidance on royalty revenue and an expanded exploration program at Kemess East.  For complete details of the Financial Statements and associated Management's Discussion and Analysis for the quarter ended June 30, 2016, please see the Company's filings on SEDAR ( or the Company's website ( All amounts are in US dollars unless otherwise indicated.

    Recent Highlights

    On August 2, 2016, the Company announced a C$10.0 million bought deal equity financing whereby the Company will issue 10,000,000 common shares at C$1.00 per share.  The Company has granted the underwriters an over-allotment option to purchase up to an additional 1,500,000 common shares under the same terms;

    On August 8, 2016, the Company announced that Alamos Gold Inc. ("Alamos") has exercised its participation right with respect to the bought deal announced above.  As a result, the Company will issue up to an additional 1,273,000 common shares through a private placement at C$1.00 per share;

    During Q2 2016, recognized royalty revenue of $2.0 million, comprised of $0.9 million from the Fosterville royalty, $0.8 million from the Young-Davidson royalty, and $0.3 million from the Hemlo, Eagle River and Stawell royalties;

    On July 29, 2016, Newmarket Gold Inc. ("Newmarket") announced that it has increased guidance at Fosterville to 130,000 to 140,000 ounces for 2016, up from previous guidance of 110,000 to 120,000 ounces;

    On July 27, 2016, Barrick Gold Corporation ("Barrick") announced that it has increased guidance at Hemlo to 215,000 to 230,000 ounces for 2016, up from previous guidance of 200,000 to 220,000 ounces;

    The Company has increased its royalty revenue guidance to between $7.7 million to $8.1 million from its original guidance of $6.6 million to $7.1 million;

    The Company has expanded its Kemess East exploration program to $4.4 million this year with a focus on further expanding and infilling the previously announced resource.  The increased program has been funded by CEE ("Canadian Exploration Expenses") flow-through financings for $2.7 million completed subsequent to June 30th;

    On May 12, 2016, the Company announced that the Company's application for an Environmental Assessment ("EA") Certificate for the Kemess Underground Project entered the 180-day review period; and

    On May 6, 2016, the Company announced that it had filed the National Instrument 43-101 technical report for the Kemess Underground Project and the Kemess East Resource Estimate.

    Commenting on the results, Chris Richter, President and CEO stated, "We are pleased to report a fourth consecutive quarter of higher royalty revenue and to be increasing our annual royalty revenue guidance.  At Kemess we are advancing through the EA review process and are keen to accelerate permitting efforts over the remainder of the year.  We are particularly excited about our expanded exploration program at Kemess East and look forward to the results from three drills currently in operation."
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    Steel, Iron Ore and Coal

    Shanxi coal loans are 400 bln yuan ($60 bln)

    China’s coal-rich Shanxi province has extended the maturity on over 400 billion yuan ($60 billion) in loans for seven of its largest coal miners in a move to easing pressure on coal miners, state media reported.

    The Shanxi branch of the China Banking Regulatory Commission will allow the province’s seven biggest coal companies to restructure short-term debt into medium and long-term loans, the state-run Xinhua news agency reported.

    The move comes after the deputy provincial government led the seven coal miners on a road show to Beijing this summer in an attempt to convince investors to subscribe to their bonds.

    These seven key state-owned coal enterprises included Shanxi Coking Coal Group, Datong Coal Mine Group, Yangquan Coal Industry Group, Jincheng Anthracite Group, Shanxi Coal Imp.& Exp. Group, Lu'an Group and Jinneng Group.

    At the end of last year, Shanxi’s seven largest coal groups had 1.189 trillion in debt, almost as much as the province’s 2015 GDP of 1.28 trillion yuan, according to Everbright Securities.

    Datong Coal Mine Group saw its debt rank the first at 219.21 billion yuan, followed by Shanxi Coking Coal Group and Jinneng Group with liabilities at 205.58 billion and 108.86 billion yuan, respectively.

    Some 21% of all bank lending in Shanxi has gone to the province’s seven top coal companies, Zhang Anshun, the head of the province’s CBRC, was quoted as saying by Xinhua.

    Also, average asset-liability ratio in these companies climbed to 82.51% in 2015, up from 81.16% in 2014. Among them, Yangquan Coal Industry Group ranked the first at 85.84%, followed by Shanxi Coal Imp.& Exp. Group and Datong Coal Mine Group with ratio at 84.97% and 84.95%.

    Under heavy debt, all these enterprises posted losses in 2015, totaling 5.585 billion yuan. Datong Coal Mine Group witnessed the largest loss of 1.085 billion yuan, compared with Shanxi Coking Coal’s least loss of 465 million yuan.

    Official figures put China’s bad debt at 4.6 trillion yuan as of end-March, or 1.75% of total commercial banking debt in the system. Analysts say the real ratio could be as high as 15%.

    The central government last year launched a 4 trillion yuan-and-counting programme that pushed banks to swap debt from many local government businesses for longer-maturity bonds.

    This year, Beijing announced a plan in which banks would trade corporate debt for equity in companies.

    Corporate debt is a concern across China but the situation is particularly desperate in Shanxi. A four-year slump in coal prices has left miners in the red and private companies unable to repay high-interest-rate shadow-banking loans that date back to a boom in coal prices a decade ago.
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    Coal miners in N China gets resource charge extension to ease financial strains

    Authorities in the northern province of Shanxi postponed resource exploitation charges for mining firms during the first half (H1) this year, to alleviate the financial strain on firms saddled with overcapacity.

    The province's land and resources department allowed 504 coal-mining firms and four other mining firms to delay paying their prospecting and mining charges for the first six months, totaling 16.1 billion yuan (2.42 billion U.S. dollars).

    Coal mining must tackle overcapacity as part of the government's wider structural reforms.

    The State Council, China's cabinet, said earlier this year that it aimed to cut 500 million tonnes of coal production capacity over the next three to five years.

    Coal production in Shanxi has dropped by more than 60 million tonnes year on year during H1.

    China's banking regulator has also asked banks to continue to support mining and steel firms' "reasonable funding needs" to ensure that they have the necessary financial support to press ahead with capacity reduction and structural reforms.
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    Dalrymple Bay's coal exports down 16pct on month in July

    Coal exports from Australia's Dalrymple Bay Coal Terminal (DBCT) reached 5.40 million tonnes in July, fell 16% from June, sources said.

    Dalrymple Bay is located within Hay Point port in central Queensland. The facility operating at an annualized rate of 63.75 Mtpa during the month, which is 21.25 Mtpa lower than its 85 Mtpa nameplate capacity.

    In the first seven months this year, the terminal was seen operating at an annualized rate of 66.81 Mtpa.

    Anglo American, BHP Billiton, Glencore, Peabody Energy and Rio Tinto are the coal producers that ship product through DBCT.

    For fiscal year 2015-16 ended June 30, DBCT exported 67.35 million tonnes of coal, the source said, down 5.6% from the year-ago level.

    In this period, shipments to China totalled 13.94 million tonnes, Japan received 14.70 million tonnes and exports to South Korea were 11.22 million tonnes, statistics from the port showed.

    All of DBCT's capacity is currently contracted to coal producers located in the Bowen Basin coalfields in Queensland, according to DBCT management.

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    Favourable response to CIL’s forward auction sales

    State-controlled Coal India Limited (CIL) has received a “highly favourable response” to its forward e-auction programme, which it hopes will attract sales of at least 120-million tonnes ofcoal in the current financial year.

    According to a CIL official, the response to its forward e-auction, against a backdrop of oversupply, is a “good” indication of the miner’s ability to maintain production, while efficiently managing its stockpiles, which were estimated at 53-million tons at the end of last month.

    The company plans to continue to offer an estimated 60-million tons for sale on e-auction over the next six months topower and non-power bulk consumers, potentially increasing to 120-million tons for the full financial year, the official added.

    In the latest round of forward e-auction exclusively for thepower sector, which started early this month, CIL was able to secure bookings of around 18-million tons. This is said to be a significant achievement for the coal miner considering that data from the Central Electricity Authority shows thataggregate coal stocks with all thermal power plants in the country stand at 31-million tons, or the equivalent of about 23 days consumption, which is one of the highest stocks in the last eight months.

    In another past forward auction held in April, the entire four-million tonnes on offer was booked by thermal power plants which had lost captive coal mines following a Supreme Court order, or where the plants’ existing fuel supply agreement with CIL expired in July 2016.

    In a further drive to auction volumes, CIL has decided to offer blended coal, a mix of high and low gross calorific value (GCV) fuel, as an appropriate import substitution for imported coal-based coastal thermal power plants.

    With the government putting in place restrictions and directing thermal power plants to progressively reduce coalimports, auction sales of blended coal will cater for the coastal thermal power plants, which are largely designed to use a mix of high GCV fuel as feedstock along with high-ash content coal to achieve a lower electricity generating cost of production.

    Despite a 42-million-ton stockpile, the Coal Ministry has set a production target for CIL of 598.62-million tons for 2016/17, up from 538.75-million tons achieved in 2015/16.
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    Iron ore price soars past $61 per tonne to fresh 3-month high

    Iron ore prices built on Friday’s gain hitting almost $62 per tonne Monday, a fresh three-month high, after figures released by the Pilbara Ports Authority showed a significant increase of shipments from Australia in July through Port Hedland, the world’s largest iron ore loading terminal.

    Iron ore has spent much of this year defying analysts’ predictions for a sustained slump triggered by oversupply. Beijing’s stimulus plans, restocking by Chinese steel mills and historically low port stockpiles have supported prices.

    The import price for 62% iron content fines at the port of Qingdao added nearly a dollar to $61.56 a tonne, data from The Metal Bulletin Index shows, taking the commodity’s monthly price average to $61.28.

    Today’s price rally coincides with the release of Port Hedland’s export figures, which rose 9.6% last month to 38.72 million tonnes, compared with 35.3 million tonnes shipped in July last year.

    While the numbers were lower than the record high of 41.81 million tonnes reached in June, most of it went to China, which accounted for 32.52 million tonnes of iron ore shipments from the port last month, up from 29.48 million tonnes in the same month last year.

    Shipments to South Korea fell 12% year-on-year to 2.54 million tonnes last month, while those to Japan totalled 1.88 million tonnes, marginally lower than the 1.9 million tonnes shipped a year earlier.

    Iron ore’s resilience in recent months has defied many analysts’ forecasts, as Beijing’s stimulus plans, restocking by Chinese steel mills and historically low port stockpiles have supported prices.

    Major miners had rushed to cut costs in recent years as the steel-making ingredient tumbled into an extended bear market, with low prices that pushed high-cost companies out of the market.

    New supply from Roy Hill in Australia, Anglo American’s Minas Rio and Vale’s S11D in Brazil, however, is now expected to outpace demand for some time.
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