Mark Latham Commodity Equity Intelligence Service

Tuesday 23rd August 2016
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    Gold and Bonds: Unlikely cousins!

    The Gold SPDR (GLD) and the 20+ YR T-Bond ETF (TLT) are two of the best performing asset class ETFs this year and both remain in clear uptrends. GLD is up over 26% year-to-date and TLT is up around 16%. One would not expect bonds and gold to be leading at the same time. The indicator window shows the 65-day Correlation Coefficient (GLD,TLT) to confirm the positive relationship. Notice that gold and bonds have been positively correlated for most of the last ten months (since mid October). A positive correlation means they have tended to move in the same direction. It is strange to see this positive correlation, but it is what it is and this is a good time for the prayer of serenity.Image title
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    Emerging as per the Economist.

    Image titleInvestors love the promise of high returns from emerging-market equities, but there are not many of them to buy. Especially if you exclude stakes held by governments, the market capitalisation of bourses beyond the rich world is tiny. Just how tiny is apparent from the map above: in many emerging markets, the value of all the freely traded shares of firms that feature in the local MSCI share index (which typically tracks 85% of local listings) is equivalent to a single Western firm. Thus all the shares available in India are worth roughly the same as Nestlé; Egypt’s are equal to Burger King. This suggests that emerging economies need deeper, more liquid markets-and investors need more perspective.

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    German exports to Iran soar in H1 after removal of sanctions

    German exports to Iran, mostly machines and equipment, jumped in the first half of the year following the removal of international sanctions against the Islamic Republic, official trade data showed on Monday.

    Exports to Iran surged by 15 percent year-on-year in the first six months of 2016 to 1.13 billion euros ($1.3 billion), the Federal Statistics Office said.

    This compares with a rise of 1.4 percent in overall German exports in the same period and a fall of 14 percent in German exports to Iran in 2015.

    "There is a huge demand in Iran for plant and equipment", said Michael Tockuss, head of the German-Iranian Chamber of Commerce, adding that chemical products and electrical engineering were also doing well.
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    Kurdish militia launches assault to evict Syrian army from key city of Hasaka

    The Kurdish YPG militia launched a major assault on Monday to seize the last government-controlled parts of the northeastern Syrian city of Hasaka after calling on pro-government militias to surrender, Kurdish forces and residents said.

    They said Kurdish forces began the offensive after midnight to take the southern district of East Nashwa, close to where a security compound is located, near the governor's office.

    The fighting this week in Hasaka, divided into zones of Kurdish and Syrian government control, marks the most violent confrontation between the Kurdish YPG militia and Damascus in more than five years of civil war. It forms part of a broader battle for control of the long border area abutting Turkey.

    After a morning lull in fighting, fierce clashes broke out again across the city, the Syrian Observatory for Human Rights said. The powerful YPG militia has captured almost all of east Ghwairan, the only major Arab neighborhood still in government hands.

    The YPG is at the heart of a U.S.-led campaign against the Islamic State militant group in Syria and controls swaths of the north, where Kurdish groups associated with the militia have set up their own government since the Syrian war began in 2011.

    NATO member Turkey, facing a Kurdish insurgency of its own, is concerned about attempts to extend Syrian Kurdish control westward along its border. Turkey is currently allowing a rebel Syrian force under the banner of the Free Syrian Army to assemble on its soil for an attack on an Islamic State-held town, seeking to deny control to the YPG.

    The Syrian army deployed warplanes against the main armed Kurdish group for the first time during the war last week, prompting a U.S.-led coalition to scramble aircraft to protect American special operations ground forces.

    War planes were seen in the skies above Hasaka again on Monday, but did not drop bombs, the Observatory said.

    Syrian state media accused the YPG-affiliated security force known as the Asayish of violating a ceasefire and said its members had torched government buildings in Hasaka.

    It accused the Asayish of igniting the violence through escalating "provocations", including the bombing of army positions in Hasaka, and said the Asayish aimed to take control of the city.


    The YPG denied it had entered into a truce. It distributed leaflets and made loudspeaker calls across the city urging army personnel and pro-government militias to hand over their weapons.

    "To all the elements of the regime and its militias who are besieged in the city, you are targeted by our units," leaflets distributed by the YPG said.

    "This battle is decided and we will not retreat ... We call on you to give up your weapons or count yourselves dead."

    The YPG, known as the People's Protection Units and linked to Kurdish rebels who fight the Turkish state, appeared intent on leaving a nominal Syrian government presence confined to within a security zone in the heart of the city, where several key government buildings are located, Kurdish sources said.

    The complete loss of Hasaka would be a big blow to President Bashar al-Assad's government and would also dent efforts by Moscow, which had sought through a major military intervention last year to help Damascus regain lost territory and prevent new rebel gains.

    Kurdish forces have expanded their control of the city despite the bombing of several locations by Syrian jets.

    Thousands of civilians in the ethnically mixed city, including members of the Christian community, have fled to villages in the countryside as the fighting intensified, residents said.

    The confrontation appears to have undone tacit understandings between the YPG and the Syrian army that had kept the city relatively calm.

    Hasaka's governor told state media after the flare-up of violence the military had armed the YPG with weapons and tanks to fight jihadist elements but had not expected them to turn against them.

    Hasaka's population, swelled by displaced Syrians fleeing areas that fell under Islamic State control, is broadly divided along ethnic lines, with Kurds mainly in the city's eastern neighborhoods and Arabs in the southern parts.
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    China Plans to Open Up More Industries to Private Investors

    China will open sectors including oil and gas drilling to private capital to counter record-low investment growth by non-state firms.

    "Political barriers" for private investment will be removed to offer a fair playing field and encourage non-state companies to take part in 165 projects outlined in the country’s 13th five-year plan, said Hu Zucai, vice chairman of China’s National Development and Reform Commission, the government’s top economic planning body.

    The remarks follow a government plan announced Monday to lower corporate costs and raise profitability. China’s leaders are seeking to rev up faltering fixed-asset investment growth by the private sector to keep this year’s economic expansion target of at least 6.5 percent in sight.

    "The government needs money, because they have to restructure a huge state sector," said Alicia Garcia Herrero, chief economist for Asia Pacific at Natixis SA in Hong Kong. "But it’s still not clear where they will give up control."

    For strategic sectors such as telecommunications, energy and nuclear power, Herrero said there might be some private investment, but not "deep involvement."

    Hu reiterated the government’s pledge to ease burdens on companies and create a fair investment environment for private investors. "The most important thing is to grant maximum market access, and the State Council has made it clear it will roll out a negative list regarding market access," he said. A negative list would specify which areas are off limits, leaving all others theoretically open to private firms.

    "We need to generate more channels for private investment to take part in major projects more swiftly and smoothly," Hu said. "There must be a clear and predictable investment environment for private investors."
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    Oil and Gas

    Petronas Posts 96% Quarterly Profit Decline on Lower Oil Prices

    Petroliam Nasional Bhd., Malaysia’s state oil company, said profit dropped 96 percent last quarter after it was hit by oil prices that remained sharply lower than a year earlier.

    Net income fell to 348 million ringgit ($86 million) in the three months through June, from 9.1 billion ringgit a year ago, the company said Monday. Revenue slid 21 percent to 48.4 billion ringgit.

    “The first half of 2016 remained difficult for Petronas,” Chief Executive Officer Wan Zulkiflee Wan Ariffin told reporters in Kuala Lumpur. “The continuous volatility of oil prices means that we cannot let up, but instead continue to grow on the back of better operational efficiencies, more controllable" spending on operations, he said.

    Petronas, as the company is known, said earlier this year a change in its business structure will result in the loss of about 1,000 jobs as it joined global oil majors including Royal Dutch Shell Plc in cutting spending as crude prices fell. The company had about 51,000 workers at the end of 2014. The company will focus on non-performers for any further headcount reductions, without aiming for a specific target, Wan Zulkiflee said.

    No Debt-Raising

    Petronas is planning to lower capital and operating expenditures by as much as 20 billion ringgit in 2016, with a planned reduction of 50 billion ringgit over four years, Wan Zulkiflee said in February. While Petronas has said that it may need to raise debtand tap its cash reserves to cover spending and dividend payments to the government, no debt-raising has been planned so far, Chief Financial Officer George Ratilal said Monday.

    Brent crude, the global benchmark, averaged almost $47 a barrel in the second quarter, compared with about $63 during the same period last year. Petronas is sticking with its expectation for Brent to average $30 a barrel in 2016, Wan Zulkiflee said. The average oil price this year is still lower than 2015, he said.

    Petronas will make a total review of its liquefied natural gas development in Canada after the government there finishes its own assessment of the project around September or October, Wan Zulkiflee said Monday. The company plans to revisit the cost, schedule and market conditions for the project before making a final investment decision with its partners after delays in securing regulatory approvals, he said.

    The Canadian government is evaluating the company’s final submission for the C$36 billion Pacific NorthWest LNG projectbefore deciding if the company can proceed with its planto ship gas from the country’s Pacific Coast. Construction was originally scheduled to start in 2015, but the approval has been mired over concerns about the impact on fish, wildlife and the traditional ways of life of First Nation tribes in the region.
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    ‘Well-Timed’ OPEC Talk Forces Oil Bears Into Record Reversal

     OPEC has done it again.

    Talk of a potential deal to freeze output helped push oil close to $50 a barrel and prompted money managers to cut bets on falling prices by the most ever. West Texas Intermediate, the U.S. benchmark, went from a bear to a bull market in less than three weeks.

    OPEC is on course to agree to a production freeze because its biggest members are pumping flat-out, said Chakib Khelil, the group’s former president. Saudi Energy Minister Khalid Al-Falih said that the talks may lead to action to stabilize the market.

    "This is all courtesy of some very well-timed comments from the Saudi oil minister," said John Kilduff, partner at Again Capital LLC, a New York hedge fund focused on energy. "They’ve been successful over the last year in jawboning the market, and this is the latest example."

    Hedge funds trimmed their short position in WTI by 56,907 futures and options during the week ended Aug. 16, the most in data going back to 2006, according to the Commodity Futures Trading Commission. Futures rose 8.9 percent to $46.58 a barrel in the report week and traded at $47.41 as of 11:16 a.m. in London on Monday. WTI is up 20 percent from its Aug. 2 low, meeting the common definition of a bull market.

    "This was a very short market so we were bound to get some covering," said Stephen Schork, president of the Schork Group Inc., a consulting company in Villanova, Pennsylvania. "You probably won’t hear a lot from OPEC with prices up here, but if we get down to where we were a few weeks ago we can expect to hear more."

    Informal Talks

    The Organization of Petroleum Exporting Countries plans to hold informal talks to discuss the market at the International Energy Forum next month in Algiers. Russian Energy Minister Alexander Novak said that the nation -- not an OPEC member -- was open to discussing a freeze.

    Talks to implement a production cap collapsed in April when Saudi Arabia said it wouldn’t take part without Iranian participation. Iran was restoring exports after sanctions over its nuclear program were lifted in January.  

    Saudi Arabia, Iran, Iraq and Russia are producing at, or close to, maximum capacity, Khelil said in a Bloomberg Televisioninterview on Aug. 17. Saudi Arabia told OPEC that its production rose to an all-time high of 10.67 million barrels a day in July, according to a report from the group.

    Ample Stockpiles

    Declining crude and gasoline stockpiles in the U.S. also bolstered the market last week. Crude supplies dropped by 2.51 million barrels as of Aug. 12, Energy Information Administration data show. Gasoline inventories slipped 2.72 million barrels during the period. Stockpiles of both crude and gasoline remain at the highest seasonal levels in decades even after the declines.

    "There’s a high level of uncertainty right now, so fairly small news can move the market a lot," said Michael Lynch, president of Strategic Energy & Economic Research in Winchester, Massachusetts. "It still remains the case that we have a huge surplus of supply and aren’t going to see it disappear anytime soon."

    Money managers’ short position in WTI dropped to 163,232 futures and options. Longs, or bets on rising prices, increased 0.1 percent, while net longs advanced 56 percent, the most since July 2010.

    In other markets, net-bearish bets on gasoline climbed 54 percent to 1,970 contracts. Gasoline futures rose 5.7 percent in the report week. Net-long wagers on U.S. ultra low sulfur diesel increased more than fivefold to 10,835 contracts. Futures advanced 9.8 percent.

    More Rigs

    A backlog of drilled but uncompleted wells, or DUCs, helps support the bearish case, said Ed Morse, head of commodities research at Citigroup Inc. in New York. There’s also been an upsurge in drilling as prices have climbed. U.S. producers added oil rigs for an eighth week, the longest run since April 2014, according to Baker Hughes Inc. data on Aug. 19.

    The EIA increased its domestic output forecast for 2017 to 8.31 million barrels a day from 8.2 million projected in July, according to its monthly Short-Term Energy Outlook released Aug. 10.

    "In the U.S., DUC completion and the drilling of new wells are changing the production outlook," Morse said. "We might see U.S. production rise next year instead of falling."

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    China's Biggest Oil Firms May Calm Investors With Post-Crash Payouts

    Cnooc Ltd., the country’s largest offshore producer, may consider a special dividend even as it’s forecast to report on Wednesday that it lost 8 billion yuan ($1.2 billion) in the first half of the year, according to China International Capital Corp. and Morgan Stanley. PetroChina Co., the country’s biggest oil and gas company, may pass on to investors the proceeds from selling stakes in Central Asia pipelines, according to Nomura Holdings Inc.

    “At current oil prices, China’s big oil companies have basically nothing but reasonable dividend payouts to keep current investors and attract new ones,” Tian Miao, a Beijing-based analyst at North Square Blue Oak Ltd., said by phone. Payouts will add extra stress to cash flow, but they’re necessary for the companies to stay attractive or meaningful to financial and strategic investors, Tian said.

    Oil companies have stayed committed to dividends in the face of the energy crash, with some of the biggest selling billions of dollars of bonds this year to sustain payouts. Exxon Mobil Corp. and Royal Dutch Shell Plc maintained dividends despite posting the lowest quarterly profits since 1999 and 2005, respectively. Chevron Corp. reported its longest earnings slump in 27 years, while BP Plc posted its lowest refining margin in six years and still kept the shareholder payout intact.

    ‘More Generous’

    While shares of China’s so-called Big Three oil companies -- which includes China Petroleum & Chemical Corp., the world’s biggest refiner -- have recovered this year amid a rebound in oil prices, they’re all still down more than 30 percent since their peak in 2014.

    PetroChina may break even in the first half of the year on the back of one-off gains, according to a July 15 research note by Citigroup Inc. analysts including Graham Cunningham, who has a sell rating on the company. The company may see a gain of at least 20 billion yuan from the sale of 50 percent in Trans-Asia Gas Pipeline Co. in November, according to Citigroup and Nomura.

    “The improved balance sheet means that PetroChina has the capacity potentially to pay a special divided to reward investors,” Gordon Kwan, Nomura’s Hong Kong-based head of Asia oil and gas research, who has a buy rating on the stock, said in a report earlier this month. “We think PetroChina could become more generous in rewarding investors amid depressed oil prices and trigger out-performance for the stock. ”

    Cnooc said in July that it expects a loss for the first six months of the year, compared with profit of 14.7 billion yuan in the same period in 2015, on the back of falling oil prices and an impairment on assets including its Canadian oil sands project. It would the first time the company reported a half-year loss since it began trading in 2000, according to data compiled by Bloomberg.

    “Thanks to Cnooc’s competitive cash cost and strategy to reward shareholders, we think the company is highly likely to pay special dividend in first half of 2016 despite the loss,” Morgan Stanley analysts including Andy Meng, wrote after it announced the profit warning. He has an overweight rating on the stock, similar to a buy recommendation.

    The exploration and production units of China’s energy giants will be hit by both the decline in oil prices as well as the slide in the country’s production due to an estimated 10 percent reduction in capital spending during the first half of the year, Neil Beveridge, a Hong Kong-based analyst at Sanford C. Bernstein & Co., wrote in an Aug. 1 report.

    The country’s crude output in July tumbled to the lowest since October 2011 and has slipped 5.1 percent in the first seven months of the year, according to data from the National Bureau of Statistics. The drop contrasts with a 3.1 percent increase in natural gas output over the same period.

    Profit at China Petroleum, known as Sinopec, is expected to drop about 40 percent to roughly 15 billion yuan -- compared with less than 200 million yuan for PetroChina -- as losses on its oil production units will be countered by its refining business, according to Bernstein’s Beveridge. The company’s domestic crude output, which makes up more than 80 percent of its production, dropped nearly 13 percent in the first half of the year, it said in a statement last month.

    China’s oil production has a break-even price between $37 and $50 a barrel, Beveridge wrote in the report. Brent crude, the global benchmark, averaged about $41 a barrel during the first half of the year, compared with more than $59 during the same period in 2015.

    PetroChina shares dropped 1.1 percent to HK$5.25 in Hong Kong as of 10:13 a.m., while Sinopec fell 0.7 percent to HK$5.56 and Cnooc slid 2 percent to HK$9.55. The city’s benchmark Hang Seng Index declined 0.4 percent.

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    UK gas supply worries ease as storage site to open more wells for withdrawals

    Twenty wells at Britain's Rough gas storage site should be available for withdrawals from Nov. 1, Centrica Storage Limited (CSL) said on Monday, above the operator's previous estimate and easing concerns about record low gas stocks this winter.

    Centrica, which owns British Gas, one of Britain's largest energy suppliers, imposed restrictions in March last year on how much gas could be stored at Rough as a safety precaution after identifying potential issues with well integrity.

    Following investigations, Centrica shut down the facility for injections and withdrawals of gas in June this year and then said the outage would be extended until March or April next year.

    However, it also said it hoped to be able to re-open at least four wells for withdrawals only by Nov. 1, 2016.

    Britain depends on stored reserves to help manage winter demand spikes and to ensure security of supply. The Rough site accounts for more than 70 percent of the country's storage capacity, National Grid data shows.

    There were fears Britain could go into next winter with very low levels of gas stocks, because if only four wells returned to service, the site would have a maximum withdrawal rate of around 5 million cubic metres (mcm) per day.

    If 20 wells are available for withdrawals, the maximum withdrawal rate is around 35 mcm/d, based on CSL data earlier this month.

    "It certainly eases concerns (about stocks). It has had an impact on the first quarter price and beyond and hopefully it will mitigate future issues if Centrica can address problems now," said Nick Campbell, an analyst at Inspired Energy.

    The British gas prices for delivery this winter fell by 0.90 pence to 40.90 p/therm at 1122 GMT, having previously traded at a high of 42.20 p/therm earlier on Monday.

    The Q1 2017 contract was down 0.40 pence at 43.70 p/therm.

    However, CSL added it could not increase the reservoir pressure at Rough while it was doing its well testing programme, so no wells were currently available for injection.
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    China receives U.S. LNG cargo

    World’s largest energy consumer, China has on Monday received the first cargo of LNG from Cheniere’s Sabine Pass liquefaction and export terminal in the United States.

    The cargo was brought onboard the 161,870-cbm Maran Gas Apollonia, chartered by the Hague-based LNG giant Shell, that was the first LNG tanker to transit the newly expanded Panama Canal connecting the Atlantic and Pacific oceans.

    Maran Gas Apollonia is currently unloading the U.S. LNG cargo produced from shale gas at the CNOOC-owned Guangdong Dapeng LNG terminal in Shenzhen Dapeng Bay, according to AIS data provided by the vessel tracking website, MarineTraffic.

    Cheniere’s Sabine Pass plant in Louisiana, first of its kind to ship U.S. shale gas overseas, started shipping the chilled fuel from Train 1 in February this year.

    The majority of these exports went to South America, followed by the Middle East, Asia, and Europe.

    Cheniere previously said it expects first cargo from Sabine Pass Train 2 in mid-August with substantial completion to be achieved in late September.
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    Genscape Cushing inventory

    Genscape Cushing inventory: -187,197 bbls in week ended Aug.19

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    Future U.S. tight oil and shale gas production depends on resources, technology, markets.

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    Based on projections in the U.S. Energy Information Administration's Annual Energy Outlook 2016 (AEO2016), U.S. tight oil production is expected to reach 7.08 million barrels per day (b/d), and shale gas production is expected to reach 79 billion cubic feet per day (Bcf/d) in 2040. These values reflect Reference case projections, while several side cases with different assumptions of oil prices, technological advances, and resource availability have different levels of tight oil and shale gas production.

    U.S. production of tight oil and shale gas has increased significantly from 2010 to 2015, driven by technological improvements that have reduced drilling costs and improved drilling efficiency in major shale plays, such as the Bakken, Marcellus, and Eagle Ford.

    Production from tight oil in 2015 was 4.89 million barrels per day, or 52% of total U.S. crude oil production. From 2015 to 2017, tight oil production is projected to decrease by 700,000 barrels per day in the Reference case, mainly attributed to low oil prices and the resulting cuts in investment. However, production declines will continue to be mitigated by reductions in cost and improvements in drilling techniques. The use of more efficient hydraulic fracturing techniques and the application of multiwell-pad drilling, as well as changes in well completion designs, will allow producers to recover greater volumes from a single well.

    As oil prices recover, oil production from tight formations is expected to increase. By 2019, Bakken oil production is projected to reach 1.3 million b/d, surpassing the Eagle Ford to become the largest tight oil-producing formation in the United States. The Bakken, which spans 37,000 square miles in North Dakota and Montana, has a technically recoverable resource of 23 billion barrels of tight oil that can be produced based on current technology, industry practice, and geologic knowledge. Bakken production is projected to reach 2.3 million barrels per day by 2040, almost a third of the projected U.S. total tight oil production.

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    Source: U.S. Energy Information Administration, Annual Energy Outlook 2016

    Natural gas production from shale gas plays in 2015 accounted for 37.4 billion cubic feet per day (Bcf/d), or 50% of total U.S. natural gas production. Unlike production from tight oil, which declines in the near term before increasing later in the forecast period, natural gas production from shale gas plays is expected to increase through 2040 in the AEO2016 Reference case.

    The two Appalachian shale gas plays, the Marcellus and Utica, have factors favorable for production: shallower geologic formation depths and proximity to consuming markets. Both Appalachian shale gas plays have remained resilient to the low natural gas prices and are projected to continue to drive total U.S. production in the long term. Shale gas production in these plays is expected to reach more than 40 Bcf/d by 2040, providing just over half of U.S. total shale gas production.

    Two oil price side cases illustrate the effect of higher or lower global crude oil prices on production from tight formations. By 2040, the global benchmark Brent crude oil spot price averages $73/b in the Low Oil Price case, $136/b in the Reference case, and $230/b in the High Oil Price case. In the High Oil Price case, drilling activities increase tight oil production through 2026, after which it begins to decline. The opposite is true in the Low Oil Price case, where tight oil production declines slightly before increasing after 2026. Production of shale gas increases in both the High and Low Oil Price cases.

    In the resource and technology side cases, the estimated ultimate recovery for shale gas and tight oil wells in the United States is 50% higher or 50% lower than in the Reference case. Rates of technological improvement that reduce costs and increase productivity in the United States are also 50% higher or 50% lower than in the Reference case. By 2040, these cases result in the greater differences from Reference case production values than do the alternative oil price cases.

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    Source: U.S. Energy Information Administration, Annual Energy Outlook 2016

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    EIA: U.S. shale oil production to fall sharply through 2017

    The flow of oil from U.S. shale fields is projected by government analysts to fall 14 percent by 2017, as the reverberations of the recent crash in crude prices are felt.

    Production from those shale fields had increased exponentially over the past decade as hydraulic fracturing and horizontal drilling techniques were improved. Shale oil now accounts for more than half of the nation’s crude output.

    But according to a report Monday by the U.S. Energy Information Administration, shale oil output – which peaked in 2015 at 4.9 million barrels a day – will fall to 4.2 million barrels by the end of next year.

    The fall is “mainly attributed to low oil prices and the resulting cuts in investment. However, production declines will continue to be mitigated by reductions in cost and improvements in drilling techniques,” the report reads.

    After 2017 government analyst are more bullish, predicting that by 2040 shale oil production will increase 45 percent from 2015 levels to 7.1 million barrels a day. U.S. natural gas production from shale would more than double to 79 billion cubic feet a day – with no drop off in production in the short-term.

    Those predictions are predicated on analysts ability to predict future oil prices. In the report, EIA explains that fluctuations in oil prices could cause wild production swings. In the event of high prices, shale oil would reach more than 12 million barrels a day by 2040. If prices were low, production could fall close to 3 million barrels a day.

    The EIA also predicts that by 2019 the Bakken formation, which spans North Dakota and Montana, will be the country’s largest oil field, surpassing the Eagle Ford field in South Texas. By 2040, analysts predict, the Bakken will produce 2.3 million barrels per day, almost a third of the nation’s shale oil output.
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    Alternative Energy

    Record hot summer, not much growth in electricity consumed.

    U.S. Power Generators Get Flattened by PJM's Summer Peak: BNEF

    • PJM capacity prices to 2020 are all below 2014 prices
    • AEP, Exelon, Dominion, NRG are top firm capacity owners

    By Nathaniel Bullard

    (Bloomberg) -- 

    Hot weather isn’t what it used to be, at least not for some U.S. utilities.

    Record heat has been smothering the states of PJM Interconnection, the regional transmission operator serving the U.S. Mid-Atlantic and Midwest. August 13, Washington D.C. tied its all-time high temperature for the day, arecord set in 1881 - but even such extreme temperatures might not bring the knock-on effect for revenue that utilities could once plan on. Heat waves are often a boon for PJM power companies like American Electric Power, Exelon,Dominion Resource, and NRG Energy - but the PJM capacity market suggests that link may be broken.

    Why is heat such a boon? Hot weather can strain the power grid by summoning ‘peak’ electricity demand from hard-working air-conditioning units. Really hot days threaten blackouts, if demand for power were to eclipse supply (measured as fleet-aggregate power plant capacity). In fact, grid operators like PJM design their entire power fleets specifically to address peak load from summer heat waves like those seen a week ago.

    PJM right-sizes its power plant fleet by awarding stand-by ‘capacity payments’ to generators, to ensure that in a given year, there are enough power plants in existence to keep air conditioning units running through the hottest summer days. These capacity payments are a material source of revenue for generators in the Mid-Atlantic and Midwest.

    Expectations for high peak demand in future years can cause capacity prices to rise; lower peak demand forecasts can cause capacity payments to fall. As such, generators pray for record-breaking hot weather, not just because it temporarily boosts wholesale energy prices, but because it can make grid operators nervous, causing them to revise upward their expectations for peak load in future years, ultimately leading to higher standby capacity payments.

    The problem with this narrative is that August 13, record heat did not deliver record electricity demand. This development may actually be bad news for generators, lending more evidence of the broad decoupling of electric load from weather and economic activity. This decoupling has profound long-term implications for the entire power sector.

    First: PJM summer peak demand has declined slightly, and so have the regional transmission operator’s 10-year average summer peak-load growth forecasts. Five years ago, PJM forecast 1.3 percent average summer peak load growth for the next decade; this year, it predicts only 0.6 percent. Since 2011, the delta between expected growth rates and actual summer peaks is real, and it is widening.

    PJM summer peak load growth projections 2011 - 2016, and actual peak load (PJM Interconnection annual forecasts)

    Second: capacity payment prices established in forward auctions to 2020 are all below 2014 levels. Turning that capacity payment trend upward would require creating relative tightness in capacity supply and summer peak demand. Creating that tightness means either a higher growth rate in PJM summer peak load, or a major retirement of generation assets in the region.

    The region retired nearly 10 gigawatts last year, as a clutch of coal plants succumbed to the effects of old age, cheap gas and environmental regulations. This was expected to promise some upside for capacity price, but the most recent auction surprised low, and now with peak load failing to materialize, the market is left to question how much more needs to come offline.

    The largest owners of firm capacity in PJM are all publicly listed utility holding companies:

    Top firm capacity owners in PJM, as of August 2016 (BNEF)

    Historically, ever-hotter summers increased electricity prices and capacity payments. PJM’s forward capacity payments are heading down, not up - despite record heat in the Mid-Atlantic.

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    Wind, solar can supply bulk of South Africa’s power at least cost, CSIR model shows

    There has been much discussion in recent months about the work done by the Council for Scientific and IndustrialResearch Energy Centre into the role thatrenewable energy could play in South Africa’s future electricity mix. In an extensive interview with Engineering News Online, Dr Tobias Bischof-Niemz outlines the key findings of the research and unpacks the possible implications. The article follows:
    The dramatic fall in the cost of supplying power from wind and solar photovoltaic (PV) plants has moved the globalelectricity supply industry beyond a critical “tipping point”, which leading energy scientist Dr Tobias Bischof-Niemzsays is irreversibly altering the operating model, with significant implications for sun-drenched and wind-richSouth Africa.

    Instead of renewable energy playing only a modest and supportive role in the future supply mix, research conducted by the Council for Scientific and Industrial Research (CSIR)Energy Centre shows that, having the bulk of the country’s generation arising from wind and solar is not only technically feasibly, but also the lowest-cost option.

    “The notion of baseload is changing,” Bischof-Niemz tellsEngineering News Online. Over a relatively short period, renewables have become cost competitive with alternative new-build options in South Africa, dramatically altering the investment case.

    Until the large-scale global adoption of wind and solar PV, a phenomenon that has only really taken hold over the last ten years, generation technologies were not dispatched by nature. The objective was, thus, to use the assets as often as possible in order to reduce unit costs. Under such conditions, it made sense to first build baseload, such as coal and nuclearplants, and use these as much as possible, before deploying the more expensive mid-merit plants and the peakers, which acted as the ultimate safety net.

    With the large-scale adoption of renewables (in 2015 a record 120 GW of wind and solar PV were added globally, more than any other technologies combined), the model is being turned on its head, particularly as costs have fallen, making them competitive when compared with alternative new-build options in many countries, including South Africa.

    CSIR Energy Centre research goes so far as to suggest that it now makes sense, for cost reasons, to favour renewables generation over traditional baseload sources, and to supply any “residual” demand using “flexible” technologies able to respond to the demand profile created when the sun sets and/or the wind stops blowing.

    This has been stress tested using a simulated time-synchronous model, integrating wind and solar data from the Wind Atlas South Africa and the Solar Radiation Data respectively. The outcome is reflective of South Africa’s impressive wind and solar resource base, with a capacity factor of 35% found to be achievable anywhere in the country – far superior to the 25% actually achieved in Spain and the 20% in Germany.

    “On almost 70% of suitable land area in South Africa a 35% capacity factor or higher can be achieved,” Bischof-Niemz says, noting that a key finding is that South Africa’s wind resource is far better than first assumed.

    “The wind resource in South Africa is actually on par withsolar, with more than 80% of the country’s land mass having enough wind potential to achieve a 30% capacity factor or more. In addition, on a portfolio level, 15-minute gradients are very low, which makes the integration of wind power into the electricity system easier compared to countries with smaller interconnected areas. On average, wind power inSouth Africa is available around the clock, but with higher output in the evenings and at night.”


    The unit’s research has gone further, though, testing the technical feasibility of supplying a theoretical baseload of 8 GW resulting in a yearly electricity demand of 70 TWh using a mix of solar PV (6 GW) and wind (16 GW), backed up by 8 GW of flexible power, which could be natural gas, biogas,coal, pumped hydro, hydro, concentrated solar power, or demand-side interventions. In such a mix, 83% of the totalelectricity demand is supplied by solar PV and wind, and the flexible power generators make up the 17% residual demand. The carbon dioxide emissions of this mix per kilowatt hour are only 10% of what a coal-fired power station would emit.

    The economic feasibility, meanwhile, has been tested using the 69c/kWh achieved for wind in the fourth bid window of the Renewable Energy Independent Power Producer Procurement Programme (REIPPPP) and the 87c/kWh achieved for solar. The flexible solutions to fill the gaps are assumed, “pessimistically”, to carry a cost of 200c/kWh.

    Bischof-Niemz notes that 200c/kWh for flexible generation is a “worst-case” assumption, as is the assumption that anyexcess energy produced when solar PV and wind supply more than the assumed load is simply discarded and, thus, has no economic value.

    The outcome shows that it is technically feasible for such a 30 GW mix to supply the 8 GW baseload in as reliable a manner as conventional baseload generators, while the economic analysis suggests that such a mix will deliver electricity at a blended cost of 100c/kWh. “Does it make sense to supply 8 GW baseload with an installed capacity of 30 GW? Yes, because it’s about energy, not capacity,” Bischof-Niemz avers.

    In reality, customer demand is never “pure baseload”. The CSIR unit has, therefore, also extended the model to the supply of the actual South African electricity-demand profile  – picking up in the morning, varying throughout the day, peaking in the evening and then falling again. This modelling is scaled to a 40 GW peak demand, or 261 TWh a year, which is about 10% more than South Africa’s current demand. Using the same cost assumptions, the 100c/kWh outcome is sustained, as is the technical feasibility.

    “So now the cost-optimal mix is a completely different mix than was traditionally the case,” Bischof-Niemz explains.

    The competitiveness of wind and solar PV, he adds, is likely to continue to improve, owing to the fact that the costs of the technologies are derived from manufacturing processes that are being continuously improved as production is upscaled. By contrast, traditional fossil-fuel plants rely on finite fossilresources, where it becomes increasingly expensive as more primary energy is consumed.


    However, what does the research mean for South Africa’sreal-world electricity supply industry, where the contestation of ideas and technologies has never been more robust?

    For Bischof-Niemz it means that energy planners can move with greater confidence in factoring in higher levels of renewables in the generation plan, as the model proves that the resources have the technical wherewithal to meet demand, while the tariffs achieved through the REIPPPP underpin their financial robustness.

    “It does require an acknowledgment that wind and solar PV have now passed a cost-competitiveness tipping point. Once one accepts that, things become far less complicated.”

    The issue then is for South African planners to set targets for the transition from the current coal-heavy mix, where conventional baseload generation remains the most cost optimal, to one that relies increasingly on renewables, supported by flexible load-followers.

    That is likely to translate into far higher allocations of wind and solar PV than is currently the case in the Integrated Resource Plan, which, in turn, could have material industrialpolicy implications.

    The CSIR unit is aiming to add further evidence for its thesis by implementing what has been dubbed CSIR’s ‘Energy-Autonomous Campus’, which is being rolled out across the science council’s 170 ha complex in Pretoria and all CSIR sites in the country. Interestingly, Eskom is a partner in this endeavour.

    It has already invested in a 558 kW ground-mounted solar PV plant and is currently adding two more facilities with a combined 450 kW. It has plans for the large-scale deployment of roof-top solar across many of the 52 buildings on site, as well as a wind turbine and a biogas plant, using municipal waste.

    Ultimately, the expectation is that the CSIR will meet its full 30 GWh-a-year demand and have surplus energy to balance load at other CSIR sites in a ‘virtual power plant”, to fuel a fleet of electric cars, as well as to produce hydrogen formobile and stationary fuel-cell applications.

    “Our vision is having a real-world research platform for cost-efficient future energy systems based on renewables,” Bischof-Niemz concludes.
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    China to more than triple geothermal power consumption by 2020

    China is expected to more than triple geothermal power consumption by 2020 to 72.1 million tonnes of coal equivalent from the current level, Xinhua News Agency reported, citing an expert as saying.

    China consumed about 20 million tonnes of coal equivalent of geothermal resources for heating, power generation and other uses in 2015, said Cao Yaofeng, an academician of the China Engineering Academy, at a summit on sustainable development on August 22.

    By 2020, geothermal power will likely account for about 1.5% of the country's total energy consumption, Cao said, helping to reduce carbon dioxide emissions by 177 million tonnes.

    In 2014, the amount of hot dry rock, the most abundant source of geothermal energy on the Chinese mainland, was estimated to be the equivalent of 860 trillion tonnes of standard coal, or 260,000 times China's annual energy consumption that year.
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    Base Metals

    Too much copper

    In New York trade on Monday copper for delivery in September suffered another down day as new supply coming on stream coupled with fewer than usual mining disruptions upset the fundamentals for the metal.

    Copper dipped almost 2% to $2.1270 per pound ($4,690 a tonne), a six week low. While other industrial metals and steelmaking raw materials have jumped in value this year, industry bellwether copper has been underperforming badly. The red metal is now trading flat year to date following a 26% decline in 2015.

    Demand has held up well. China,  responsible for more than 45% of the seaborne trade, imported 9.4 million tonnes of concentrate during the first seven months of the year, a 36% jump on 2015.  For the first seven months refined imports are up by nearly one-fifth at 3.1 million tonnes.

    But the market is set stay in surplus despite some curtailment by top producers Freeport McMoran and Glencore as new mines and expansions, particularly in Peru, ramp up to capacity.

    If this low rate of disruption continues through the second half, mine supply will exceed our initial forecast by around 230,000 tonnes in 2016

    While top producer Chile settled into a gentle decline, Peruvian copper production  surged by more than 50% to just under 741,000 tonnes in the first half of the year.

    Additional supply includes increased production from Freeport’s Cerro Verde mine and the ramp-up of the Chinese-backed Las Bambas mine, both in Peru. Cerro Verde pumped out 260,000 tonnes during the first half of the year after Freeport completed a project to add 270,000 tonnes annual capacity at the mine.

    Operator MMG's Las Bambas ramp-up is ahead of schedule and the new mine is expected to produce 250,000 – 300,000 tonnes this year and 400,000 in 2017. Hudbay's Constantia is also hitting its stride with 63,800 tonnes unearthed so far this year while Glencore's Antamina and Antapaccay mines both upped output substantially.

    Add to Peru's success increased output at Vale's Salobo mine and the ramping up of Southern Copper Corp’s Buenavista mine in Mexico. BHP Billiton last week also announced increased guidance at Escondida, the world's largest copper mine by some margin.

    Further out Canada's First Quantum Minerals is also continuing to proceed with the development of the Cobre Panama project, with full production expected in 2018, while NGEx Resources Constellation copper project could fill any gaps opening up some time in the next decade.

    A rule of thumb for many industry forecasters is to allow for a 5%–6% swing in global annual output of 22 million tonnes due to mine level disruptions, be it from bad weather, labour problems or technical difficulties.

    According to a Morgan Stanley report quoted by CNBC, this year disruptions are tracking at 1.8%:

    "If this low rate of disruption continues through the second half, mine supply will exceed our initial forecast by around 230,000 tonnes in 2016 – bearish for copper's price."
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    Glencore ‘vindicated’ on zinc supply cuts, Morgan Stanley says

    Glencore’s decision to cut zinc output to fight a rout in prices last year has been vindicated as the metal has rallied in 2016, according to Morgan Stanley, which held out the possibility that the commodity trader may order restarts.

    “It turns out, cutting/waiting was a good plan,” Morgan Stanley said in a note, which contained the heading “Glencore, vindicated".

    The metal “may be supported/lifted, if China’s steel-production rate remains at around 800-million tons per year into 2017. Conversely, the most likely short-term price cap for zinc is the reactivation of Glencore’s dormant mining capability,” it said.

    Zinc has led gains in metals this year after the shutdown of depleted mines coupled with Glencore’s cutbacks. GlencoreCEO Ivan Glasenberg has repeatedly argued the case for miners not producing materials into oversupplied markets, saying in May that volume growth can’t be an end in itself. Morgan Stanley said zinc is its top commodity pick, while Goldman Sachs has dubbed it the “bullish exception” among metals.

    “We’re zinc bulls,” Morgan Stanley said. “But its 2016 price performance has surprised even us. Any upside from here depends on China’s steel production rate and Glencore’s willingness to re-fire some of its mine supply.”

    Zinc for delivery in three months traded 0.5% lower at $2 275.50 on the London Metal Exchange at 4:06 p.m. inSingapore, 42% higher in 2016. That performance has made it the top performer on the Bloomberg Commodity Index year-to-date.
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    Steel, Iron Ore and Coal

    China July thermal coal imports up 30.9pct on year

    China's import of thermal coal, including bituminous and sub-bituminous coal, stood at 9.32 million tonnes in July, rising 30.9% on year and up 23.44% from June, showed the latest data released by the General Administration of Customs.

    The value of the imports totaled $463.22 million, translating to an average import price of $49.7/t, falling $9.58/t from a year ago and down $1.84/t from the month prior.

    Over January-July, China imported 49.8 million tonnes of thermal coal, edging up 0.61% from the same period in 2015. Total value stood at $2.39 billion, down 22.11% year on year.

    Meanwhile, China imported 5.13 million tonnes of lignite in July, up 3.64% year on year but down 16.86% on month. That valued $171.58 million, down 15.5% year on year.

    Total lignite imports over January-July reached 33.48 million tonnes, up 16.66% year on year, with value at $1.11 billion, down 12.1% year on year.

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    Will there be a shortage of US coal in 2017?

    Image title
    Even as summer heat is bolstering air conditioning load and, consequently, power and coal demand, high coal stockpiles are muting the upside for coal prices. With coal prices subdued and gas prices climbing, coal producers may not receive the proper price signals to increase supply to match higher levels of demand. As a result, coal shortages are possible, perhaps even likely next year.

    Displacement of coal-fired generation by lower cost combined cycle units has driven a dramatic decline in US coal production. Indeed, coal output through June 2016 is off a staggering 33% compared to the same period just two years ago.

    Coal producers have responded to slackening demand in various ways: mine closures, employee lay-offs, cutting back on hours worked and prolonged periods of low capital expenditures. According to the Mine Safety and Health Administration (MSHA) reporting, the number of employees at Powder River Basin (PRB) mines – the largest producing US coal basin - has declined by more than 15%, dropping from about 6,500 to 5,500 over the last two quarters.

    Consequently, quarterly production has fallen from about 100 Mst to about 75 Mst for the PRB. Based on the current level of employment – assuming productivity can return to historic norms – we forecast 85 Mst of quarterly PRB production. At that rate, PRB production in 2016 and 2017 would end at about 310 Mst and 340 Mst, respectively; compared to over 400 Mst in 2015.

    Low gas prices in 2015 and 2016 have had a similar impact on gas producers; the number of active drilling rigs have fallen 65% since the beginning of 2015. We project that the bottom of the gas market is behind us and gas prices will rise to cover the marginal cost of drilling new wells, at a minimum. Our forecast also shows that natural gas prices will average nearly US$3.60/mmBtu in 2017, and with higher gas prices, we expect coal consumption to increase considerably in 2017. In fact, annual coal demand in 2017 will be more than 400 Mst, even considering a historic 50 Mst draw down in coal inventories.

    In our H1 2016 base case, we assume that significant latent capacity exists and production rates similar to 2015 are achievable. In that case, the market should balance nicely. Prices will strengthen slightly, with new contract prices continuing to be settled in the US$12-13/st range, and bloated stockpiles will shrink to more normal levels, from over 60 full burn days to around 40 full burn days. However, our base case assumptions are reasonable only if coal producers can increase production quickly. Higher mine output requires bringing thousands of miners back to work, repositioning and re-starting idled equipment and adjusting mine plans. We do not doubt that miners have the ability to expand production over time, but the question is: how quickly can they ramp back up to take advantage of improved market conditions?

    Unfortunately, coal producers are receiving little if any encouragement to prepare for an increase in demand. Year-to-date in 2016, the amount of coal delivered classified as ‘"contract"’ is 27% lower than in 2015. The percentage of coal under long-dated contracts is running about 10% lower than average over the previous four years. The result could be a severe shortage of coal with the potential to spike coal prices. Based on the our estimates for natural gas prices, PRB prices as high as US$17/st could be justified.

    Attached Files
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    Anhui to cut iron & steel capacity of 8.9 Mtpa over 2016-20

    Anhui province pledged to cut steel-making capacity of 5.06 million tonnes per annum (Mtpa) and iron-making capacity of 3.84 Mtpa over 2016-2020, said the provincial government in a notice released days earlier.

    A total of 29,000 laid-off staff will be resettled by end-2018, according to the notice.

    Half of the money used for resettlement will come from central and provincial governments, and the rest will be paid jointly by municipal governments and steel enterprises, said the notice.

    Meanwhile, the provincial government required steel makers to further lower production and operating costs and asset-liability ratio by 2020. Annual steel production per capita is expected to reach 1,000 tonnes over the same period.

    The government said it will give sound support for the capacity cuts, regrouping of enterprises and the development of those promising steel makers by corresponding financial policies.

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