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A severe coal shortage has forced power cuts in many regions in China as demand surged due to a cold snap across large swathes of the nation over the past week, state media reported.

In the northern province of Shaanxi, 14 major thermal power stations only had four days worth of coal stocks left, with reserves at two power stations already running out, the Global Times said on Monday.

Many plants and residents in Shaanxi had received notice of impending blackouts, with a 12,000-household compound in the provincial capital of Xian facing power cuts for the next 10 days, it added.

Similar shortages have also gripped other provinces including coal-rich Shanxi in the north and Henan in central China, as well as the southwestern mega-city of Chongqing, the report said.

China, which overtook Japan in the second quarter to be the world's second largest economy, relies on coal for 70 per cent of its fast-growing energy needs and coal combustion has become one of the main sources of its air pollution.

Experts have blamed the shortages on soaring coal prices, insufficient logistics facilities and increasing transportation costs, the Global Times said.

Some power cuts may be unrelated to the coal shortages, as local governments struggle to meet the annual energy efficiency targets set by Beijing, the China Daily said on Monday.

China has sought to reduce energy consumption per unit of gross domestic product -- so-called carbon intensity -- by 20 per cent by year's end from 2005 levels.

A 15.6 per cent reduction was realised from 2006 to 2009, officials said previously.

But the figure increased 0.09 per cent in the first half of 2010 year-on-year, signalling the difficulties in meeting the 2010 target.

At global climate talks in Copenhagen last year, China pledged that it would reduce carbon intensity by 40-45 per cent by 2020 based on 2005 levels.




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Jan. 6 (Bloomberg) -- Steelmakers in Asia may be forced to pay as much as 33 percent more for hard coking coal after the worst floods in 50 years in AustraliaÃÆâ€â„¢ÃƒÆ’ƒâہ¡ÃƒÆ’‚¢ÃƒÆ’¢Ã¢Ã¢Ã¢Ã¢â€š¬Ã…¡Ãƒâ€šÃ‚¬ÃƒÆ’…¡Ãƒâہ¡ÃƒÆ’‚¬ÃƒÆ’¢Ã¢Ã¢Ã¢Ã¢â€š¬Ã…¡Ãƒâ€šÃ‚¬ÃƒÆ’…¾Ãƒâہ¡ÃƒÆ’‚¢s Queensland state disrupted output from the worldÃÆâ€â„¢ÃƒÆ’ƒâہ¡ÃƒÆ’‚¢ÃƒÆ’¢Ã¢Ã¢Ã¢Ã¢â€š¬Ã…¡Ãƒâ€šÃ‚¬ÃƒÆ’…¡Ãƒâہ¡ÃƒÆ’‚¬ÃƒÆ’¢Ã¢Ã¢Ã¢Ã¢â€š¬Ã…¡Ãƒâ€šÃ‚¬ÃƒÆ’…¾Ãƒâہ¡ÃƒÆ’‚¢s biggest shipper of the fuel.


Prices may increase to $270 a metric ton for three-month contracts starting April 1 as the floods threaten to take as much as 10 million tons of metallurgical coal out of the market, Colin Hamilton, a London-based analyst at Macquarie Group Ltd., said in an e-mailed response to questions. Daiwa Capital Markets analyst David Brennan said prices may jump to $300 a ton. Mills agreed to pay $225 a ton for the three months starting Jan. 1, Bank of America Merrill Lynch analysts wrote in a report last month.





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Anglo American and Posco have signed quarterly contracts for Q3 at a premium to Q2 prices. The new benchmark price of US$225/t for the premium German Creek brand of hard coking coal represents a 7.1% increase on the Q2 price of US$210/t FOB Australia. The new benchmark price for PCI coal increased by 5.7% to US$162/t. The price increases are in line with market expectations given the tightness for premium coking coal grades.


The industrial dispute at BMA continues to disrupt production volumes at the world's largest supplier of hard coking coal (HCC) to the seaborne market. These disruptions have largely offset weak demand and provided support for HCC prices. The Q3 benchmark price is in line with the current spot price of US$223.50/t for Peak Downs product. At the lower end of the product range, prices for semi-soft coking coal have declined in the year to date, and the relative discount to HCC has increased.


Nevertheless, an increase in benchmark prices stands out in the current market where downward pressure on commodity prices is widespread.

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The weakness in the global steel sector continues to weigh on steel raw material prices such as Iron ore and coking coal. The combination of demand weakness and consistent supply numbers has led to a downward price trend. Buyers of these commodities are sitting on the sidelines waiting for the current price decline to run its course before stepping back into the market.



Since the price peak during the beginning of 2011, iron ore has been the best performing (down 31%), followed by thermal coal (down 38%) and premium metallurgical coal (down 54%).


Iron ore and thermal coal remain our top picks


Goldman Sachs (GS) likes iron ore and thermal coal given the fact that both commodities have good cost support from high cost domestic iron ore production in China and from marginal thermal coal producers in Australia, Indonesia, Russia, and the US. Therefore, GS has the view that price risk for these two commodities is skewed to the upside with a medium-term horizon.


Focus on thermal coal


A recovery from negative thermal coal price is dependant on a supply response to low prices and incremental demand from China. The outlook for the third quarter of this year appears challenging however things should turn around in the following quarter.



's ability to support the seaborne price is constrained


High inventory levels and weak electricity demand growth in China has limited the nation's power utilities from increasing imports even when they are competitively priced against domestic coal. Most recently we have seen the weakest periods in power demand growth, although we are uncertain as to the role played by energy efficiency (a shift towards newer buildings, factories, etc), structural changes in the economy (a shift away from heavy industry towards services) and statistical errors.



supply response to lower prices was short lived


Signs of a supply response to ease the oversupply in the seaborne thermal coal market remain non existent. Shipments have recovered from the recent 4-week decline and are now running at close to full capacity. Therefore, GS believes that a supply side response from Australia to bring the market back into balance is yet to eventuate.


US coal demand remains under pressure


Cheap shale gas prices in the US have encouraged coal/gas substitution on a larger scale, further enhanced by new environmental regulations. Given the growing preference for shale gas, US coal producers will remain under pressure to find export markets as a substitute for domestic demand according to GS.


Upside risk in India?


The negativity surrounding seaborne thermal coal demand is balanced by upside risks for seaborne demand in India. The Indian economy is short of energy and coal; however the seaborne demand to date has been constrained by the fact that power prices are regulated. Coal-fired power plants which do not operate on fuel pass-through mechanisms are exposed to the volatility of seaborne coal prices. One solution proposed by the Indian government is the creation of a basket price for domestic and imported coal, whereby all power utilities would pay Coal India a standard price regardless of where the coal comes from. This would result in lower fuel costs for plants supplied by imported coal, at the expense of higher fuel costs for power plants supplied by domestic mines. If implemented, this framework would enable any idle coal fired plant to operate at a profit, and would be very positive for seaborne coal demand.

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Have US Coal Prices Bottomed?

By Hadaf Zubi | Sat, 24 November 2012 00:00 | 0. Definitely maybe. While the juryÃÆâ€â„¢ÃƒÆ’ƒâہ¡ÃƒÆ’‚¢ÃƒÆ’¢Ã¢Ã¢Ã¢Ã¢â€š¬Ã…¡Ãƒâ€šÃ‚¬ÃƒÆ’…¡Ãƒâہ¡ÃƒÆ’‚¬ÃƒÆ’¢Ã¢Ã¢Ã¢Ã¢â€š¬Ã…¡Ãƒâ€šÃ‚¬ÃƒÆ’…¾Ãƒâہ¡ÃƒÆ’‚¢s still out on the Uinta Basin, prices for Appalachian and Illinois/Powder River Basin coal look to have begun recovering after dropping to long-term support levels following the achievement of post-2009 highs in October 2011. The interesting point about this price movement is that of the 5 major US coal categories, all but Uinta basin coal have set 2012 lows that are higher than their 2009 lows. http://oilprice.com/js/common/tinymce/jscripts/tiny_mce/plugins/imagemanager/files/AE1014.png


None of this indicates that coal prices canÃÆâ€â„¢ÃƒÆ’ƒâہ¡ÃƒÆ’‚¢ÃƒÆ’¢Ã¢Ã¢Ã¢Ã¢â€š¬Ã…¡Ãƒâ€šÃ‚¬ÃƒÆ’…¡Ãƒâہ¡ÃƒÆ’‚¬ÃƒÆ’¢Ã¢Ã¢Ã¢Ã¢â€š¬Ã…¡Ãƒâ€šÃ‚¬ÃƒÆ’…¾Ãƒâہ¡ÃƒÆ’‚¢t go lower in the future, but recent price action is accompanied by fundamental support that would suggest some price stability or appreciation in the future. Firstly, US coal production has declined 5.4% in the past 52 weeks, which has helped to stabilise prices through reduction of supply. Coal stocks, which began to decline in Q2 2009, rose more than 15% from Q3 to Q4 2011. This oversupply contributed to price weakness in the first quarter of 2012, but from Q1 to Q2 2012 stocks have only risen 0.78%. Exacerbating the effect of oversupply on price was the fact that natural gas prices, a substitute for coal in many cases, dropped 57% in the five quarters from January 2011 to April 2012. Natural gas is 19% higher than it was in April, and producer shut-ins and seasonality have made a return to $2 very unlikely in the near-term.


Related Article: Pakistan Continue with Controversial Plan to Turn Coal into Diesel


Total domestic coal consumption in the USA is projected by the EIA to be 11% lower in 2012 from 2011, and to increase 6% from 2012 to 2013. This would suggest that lower domestic demand has largely already been priced-in. Finally, the NOAA is forecasting 3806 heating degree days in 2012. When compared with 4238 in 2011 (10% lower) or the projected 4341 in 2013 (14% year-over-year gain), climate conditions seem favourable for coal price support purely in the form of increased domestic demand moving forward. Even if coal exports (a bit over 12% of annual production) remain static in 2013, domestic demand should support prices.


By. Hadaf Zubi



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Coal price recovery to continue but upside is capped - Goldman Sachs

The seaborne coal market is still in recovery modeÃÆâ€â„¢ÃƒÆ’ƒâہ¡ÃƒÆ’‚¢ÃƒÆ’¢Ã¢Ã¢Ã¢Ã¢â€š¬Ã…¡Ãƒâ€šÃ‚¬ÃƒÆ’…¡Ãƒâہ¡ÃƒÆ’‚¬ÃƒÆ’â€Å¡Ãƒƒâہ¡ÃƒÆ’‚¦


Seaborne thermal and metallurgical coal prices have declined by 23% and 27% ytd respectively, but prices have recovered from the trough of 2H 2012 (by 12% and 15% respectively) and we expect further upside in 2013.


ÃÆâ€â„¢ÃƒÆ’ƒâہ¡ÃƒÆ’‚¢ÃƒÆ’¢Ã¢Ã¢Ã¢Ã¢â€š¬Ã…¡Ãƒâ€šÃ‚¬ÃƒÆ’…¡Ãƒâہ¡ÃƒÆ’‚¬ÃƒÆ’â€Å¡Ãƒƒâہ¡ÃƒÆ’‚¦ but the upside for thermal coal is capped by China


We believe that seaborne thermal coal prices usually trade within a range set by marginal production costs at one end and by the China domestic price equivalent at the high end. Trends in domestic coal supply in China lead us to expect relatively flat prices, and as a result we now expect the price upside for thermal coal to be lower than we had previously expected. On that basis we downgrade our forecasts to US$100/t for the period 2013-15 but we still expect spot prices to increase by 15%.


Slower demand growth will moderate metallurgical coal recovery


Metallurgical coal prices will gradually recover and move above cost support during 2013. However, a greater rate of self-sufficiency in China and continued softness in other markets for metallurgical coal lead us to expect a lower rate of seaborne demand growth in the period 2013-16 from 4.1% to 2.4%. We downgrade our forecasts for the period 2013-16 accordingly.

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Weak global coal market threatens Australian mines - SMH


Thermal coal producers around the world face the prospect of mine closures as oversupply and weak demand drive down prices towards unprofitable levels.


European and South African physical coal prices have fallen back below $US90 a tonne and analysts say that the low prices will hit Australian mines in particular, where miners are also contending with a strong Australian dollar and high costs.


Traders said that prices have dropped back to levels that may cause some low-revenue mines to close because they can't generate profits at such low prices.


"There's just too much coal around and too little demand, so at some point the mines with the lowest profit margins will have to shut," one physical coal trader said.


Ivan Glasenberg, chief executive of commodities trader Glencore, said that a lack of "capital discipline" among resources companies had contributed to gluts of major commodities including coal.



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The Japanese government is moving to speed up the environmental assessment process for new coal-fired power plants as its power sector struggles with a surging energy bill in the wake of the forced idling of much of the country's nuclear power plants following the Fukushima power plant meltdown in 2011. At present, it can take up to four years for approvals for new plants to be processed.


According to Japanese media reports, the government intends to make 12 months the maximum period for assessing and approving new coal-fired power plants as its utilities seek to develop more power stations to stem surging energy supply bills.


The closure of much of the country's nuclear power capacity following Fukushima has forced the utilities to restart idled oil-fired power plants, which has pushed up energy bills significantly since oil is the most expensive fuel source.


Of Japan's 50 nuclear power plants, just two are in operation at the moment. All were shut for a review of operating procedures after the Fukushima accident. And with the government considering the closure of much of the installed nuclear capacity over the medium term, the spotlight is back on coal as the cheapest energy source, notwithstanding plans to cut carbon emissions.


A commitment to slice 2020 carbon emissions by 25 per cent from their 1990 level will be revised by October, according to Japanese newspaper reports.


Tokyo Electric, which operated the Fukushima complex, is adding an estimated 2.6 gigawatts a year of coal-fired generation capacity from two new plants that started operation this month.


It is also sourcing electricity from two coal-fired plants operated by Tohoku Electric Power Co that have been restarted after being repaired following the devastating March 2011 earthquake and tsunami.


The No.2 unit at Tokyo Electric's Hitachinaka plant, with 1000 megawatts of capacity, began operating this month, along with the 600MW No. 6 unit at its Hirono power station. The utility is also purchasing half of the output from the No. 1 and No. 2 units at Tohoku Electric's Haramachi plant in northern Japan, each of which can generate 1000MW.


In total, these coal-fired power plants are expected to consume about 11.5 million tonnes of coal in a full year of operation.


The government's move to speed up the assessment process coincides with Tokyo Electric's call for tenders for the construction of new coal-fired power stations with 2600MW of capacity, which it wants to have in operation by the end of the decade, to replace lost nuclear capacity.


Read more: http://www.smh.com.au/business/japan-turns...l#ixzz2RW1w0kkF

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