Coal News and Markets
Coal News and MarketsDecember 29, 2006
Coal Prices (updated December 27, 2006) This report summarizes spot coal prices for the business weeks ended December 1, 8, and 15. No spot prices were published for the week ended December 22; the next spot price update in Platts Coal Outlook will cover the week ended December 29. Based on weekly averages in Platts Coal Outlook, spot prices fluctuated slightly in the Illinois Basin (ILB) and the Powder River Basin (PRB) in the two reported weeks since December 1. Spot prices in the other major coal supply regions were unchanged. The average spot price for the 11,800-Btu ILB coal declined from $34.00 to $33.00 per short ton during the 2-week period. The PRB spot coal average declined from $9.95 to $9.70 per short ton in the week ended December 8, but it regained most of that the next week, averaging $9.90 per short ton in the week ended December 15. The Central Appalachia (CAP) 12,500-Btu rail coal tracked by the Energy Information Administration (EIA) remained at $47.25 per short ton and the Northern Appalachia (NAP) average spot coal price for 13,000-Btu coal did not change from $43.00 per short ton. The 11,700-Btu Uinta Basin (UIB) coal commodity continued at $36.00 per short ton; it last changed in the business week ended October 6.
Flat spot coal prices are consistent with the continued weak demand for coal at this time. Bit by bit spot coal demand has slowed since early summer. A number of factors contributed to the present lull: concerted efforts that started this past spring to rebuild depleted coal consumer stockpiles with increased deliveries; the opening of shuttered and new mines following the prolonged high coal prices from mid-2004 through early 2006; a relatively mild summer in the service areas of most coal-burning electricity providers; a mild autumn in most of the eastern United States; and forecasts for mild weather in the eastern and southern United States during the remaining winter months owing to El Nino conditions in the Pacific. Coal stocks in the electric power sector equated to 49 days’ supply (133.8 MMst) as of the end of October. Coal-fired electric power generators were in a better position than in October in either of the previous two years; the most recent time that end-of-October coal stocks were as high as 49 days’ supply was in 2003 (see Coal Inventories Section, below).
Coal Production - Estimated U.S. coal production for November 2006 was 95.8 MMst (see graph below). The November EIA estimate amounts to a 2.3 percent, or 2.3 MMst, decrease from the October estimate of 98.1MMst. Estimated production in November was slightly higher than 12 months earlier – 95.8 MMst versus 95.0 MMst in November 2005. Production for the first 11 months of 2006 was at record levels, 1,069.5 MMst, or 30.9 MMst ahead of the same period in 2006.
The U.S. Monthly Coal Production graph (below) includes final production based on revised mine-level reports for all four quarters of 2005 by the Mine Safety and Health Administration (MSHA). It also shows revised production for January through September 2006 and preliminary EIA Weekly Coal Production estimates for October and November. Coal Inventories - Coal inventories are monitored at plants that generate electricity (utilities, independent power producers, and industrial and commercial plants with generation capacity). The graph data (see below) depict coal inventories and equivalent days of consumption in the Electric Power Sector. The data exclude coal stocks and days of consumption at the industrial and commercial generating plants because there is no prior knowledge as to the portion of their coal inventories that will be used to produce electricity for sale to the power grid. Further, the number of those plants is too small in many cases to ensure individual data confidentiality if their coal stocks were published. The data for the excluded plants, however, constitute only about 1 percent of coal consumed for electricity generation. Thus, the graph below depicts those power plants that comprise the majority (about 99 percent) of net electricity generation fueled by coal. The single exception is that the early-release coal consumption data in EIA’s Electric Power Flash represent consumption for the full 100 percent of electricity generation. It is not until the final data are released several weeks later that the consumption just at dedicated electric power plants can be determined and used in the graph.
In each month from December 2005 through June 2006, coal inventories at electric power plants had increased from prior month levels. Coal inventories increased by nearly 34 MMst during the 6-month period. On June 30, inventories started the summer 16.3 MMst higher than one year earlier. Further, during the relatively mild summer that followed, the net drawdown in coal inventories was only 11.9 MMst, in contrast to the summer of 2005 when the net drawdown was 21.7 MMst. During the summer, coal inventories declined in July by 7.7 MMst and by 4.1 MMst in August 2006, but by the end of September coal stockpiles were already showing net gains, up 2.3 MMst over August levels and they gained another 12.2 MMst in October. Inventories at the end of October were 32.6 MMst, or 32 percent, above those of a year earlier when coal stockpiles at electric power plants were affected by last summer’s rail disruptions. Inventories were widely acknowledged to be at comfortable margins at most power plants as winter approached. The exception may be some PRB coal customers that had been unable to rebuild to preferred levels, although recent railroad and coal mine reports indicate shipments of PRB coal were still being shipped to power plants at high rates during December. As an indication of PRB inventories, see subbituminous coal in Figure 6.4 of the EIA Flash report. Eastern mining capacity – Because CAP mines in recent years have been moving into more difficult mining conditions, mine operators have not been able to expand production significantly. Nonetheless, CAP is still the highest producing coalfield in Appalachia. After reaching a high of 281.8 MMst in 1997, CAP annual production decreased as far as 230.1 MMst in 2003. Production increased, however, by 2.4 MMst in 2004 and by 2.8 MMst (to 235.3 MMst) in 2005, or about 1 percent each year. In some months CAP still produces more coal than NAP and ILB combined (see graph below). Production in the eastern U.S. was up for the first 6 or 7months of 2006, but by the end of November, year-to-date production was declining. CAP production was down by 1.3 MMst, or 1.0 percent from the same period in 2005. Production estimates for the months of September, October, and November had each declined, confirming company reports of lowered third quarter production and fourth quarter projections. CAP production declined more severely than NAP production and ILB actually grew by 2.1 percent, or 1.8 MMst. This validated reports that retreating coal demand and prices were cutting into already slim margins at those CAP mines with difficult mining conditions and high operating costs. Numerous temporary mine closures were announced.
Future mining capacity in NAP and ILB is less constrained than in CAP. Deep but relatively thick longwall-minable coal is still accessible in NAP. Large reserves of relatively thick and flat-lying coal are available in ILB, although deeper on average than mined in the past. Additional coal production growth is expected between now and 2011, as many retrofit scrubbers become operational and mines begin burning more high-sulfur coals. Nonetheless, production in those two coalfields has been growing at impressive rates – 3.7 percent in NAP from 2004 to 2005 and 2.8 percent in ILB over the same period. For the first 11 months of 2006, NAP production was 2.0 percent ahead of the same period in 2005 and ILB production was up 3.3 percent. Like CAP production, NAP and ILB production dipped in September and again in November, but the combined production of NAP and ILB exceeded CAP production in both October and November, for the first time since December 2005. Future Coal Demand – Discussions at the December 14 Coal Trading Conference in New York reflected growing concerns over the adequacy of coal supplies and the economics of new coal-fired power plants. Speaking at the conference, Gary Hunt, President of Global Energy Decisions, stated that “The coal supply chain is pretty poorly positioned for sustained growth,” and that substantial investment is needed to meet projected coal demand from the electric power sector. Daniel Gabaldan, a principal at Booz Allen Hamilton warned, “The ‘70s and “80s saw a lot of coal and nuclear plants being built,” only to find out, in the case of the nuclear plants, that the costs of regulations would become a major factor in their economic viability. Mr. Gabaldan drew a parallel with the electric power industry today, which is struggling with the uncertainties of which coal-fired technologies will make economic sense, even as the costs of the new technologies keep growing. With the changes in Congress following the 2006 elections, industry decision makers expect that carbon emission reductions are coming, but do not know whether they will be implemented by a cap or a tax program. “The industry is skeptical that IGCC [integrated gasification combined cycle] may not meet the carbon sequestration needs.” Mr. Gabaldan continued: “A tax allows for easier sharing of the burden among all industries. A cap and trade system is harder to move across industries and distribution of allocations would be difficult . . . But the bigger question is how much carbon [mandates are] going to cost . . . The way these two unfold is critical to where the industry is headed and we think it’s the reason why many in the industry are on the cusp of making practical decisions about what to do” (Platts Coal Outlook, December 18, pp 1,12).
The graph below, and its downloadable data file include available data through September 2006. The fourth quarter price data for receipts at coke plants are not yet available. The data show quarterly average values based on coal cost data EIA collects from coke plants. They also depict monthly average values declared for met coal brought to ocean terminals for export, from U.S. Customs data. The values reported do include the costs of transporting the coal to the coke plants or export points.
The third quarter average price at coke plants showed a small increase of $0.77 per short ton in delivered price of metallurgical coal, from $92.72 to $93.49. The monthly average prices for coking coal transported to export docks have stayed within a range of $85 to $94 throughout 2006, and leveling out between $89 and $92 from July through September. Unlike many prices reported in coal newsletters, the values below are based on surveys of actual shipments. These prices are about 2 months old, however, when they are first available. Because the prices are averaged and include met coal shipments from multi-year contracts and traditional 12-month contracts - and not just spot shipments - variances are less extreme than in some spot price reports. Further, it cannot be known from the price data how much of any movement in delivered prices may reflect actual changes in coal priced at the mine versus changes in eastern U.S. rail transportation rates. Metallurgical coal prices have continued to strengthen since September 2003 and the shock to international coal supplies that occurred in 2004 when exports of Chinese steam coal and metallurgical coke were curtailed. In 2006, met prices have climbed at a slower rate but have reached new average highs amid reports of shortages of steam coal and high met coal demand in China, India, growing coal demand in other East Asia industrial economies. Accounts of actual individual transactions are relatively few in October and November as the first quarter, January through March, is the period traditionally when most iron and steel producers contract for met coal for the next year or two. Reports that have been seen are mixed for recent met coal price agreements. Jim Walter Resources, reporting on its third quarter sales of Alabama met coal, sold 1.6 MMst of met coal at an average price of $105.48 per short ton, priced at the mine area. That volume is a substantial increase over the 0.7 MMst it sold in 3Q2005, when the coal fetched $108.28 per short ton (Platts Coal Outlook, November 13, p 8.) Third quarter 2006 sales figures for metallurgical coal released by Alberta-based Grand Cache Coal cited 0.3 MM tonnes metric sold for an average $C103, or about $US106 per short ton at the mine (Platts Coal Outlook, November 20, p 9). On the other hand, CRU Monitor, which advises commodity dealers, buyers, and investors, reported in November that U.S. met coal producers that have concluded supply agreements for 2007 purchased premium high–volatile met coal for $69 to $73 per short ton, mid-volatile met coal for about $80 per short ton, and low-volatile met coal for $74 to $82 per short ton (CRU Monitor, Steelmaking Raw Materials, November 2006, p 3).
A Bear Stearns survey of more than 1,000 shippers confirmed what coal-fueled power plant operators believe and the railroad industry says is necessary – that rail transportation rates are rising and expected to continue. Railroad customers, including utilities and coal producers, were surveyed by Bear Stearns analysts and said they expect “strong” rate increases continuing into 2007, driven by “ongoing tight rail capacity and expectations for continued strong rail freight demand.” The survey is done quarterly and encompasses a cross section of freight shippers (not only coal). At the time of the survey, third quarter operating costs were not complete but respondents were expecting average rail rate increases of 4.2 percent for the quarter. The second quarter expectations had been for 4.4 percent increases. Rail customers also noted that railroad service improved in the third quarter, especially for CSX customers (Coal Outlook, November 27, pp 8-9.)
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