Coal News and Markets
Coal News and MarketsWeek of October 15, 2006
Coal Prices (updated October 16, 2006) This report summarizes spot coal prices for the business weeks ended September 1 through October 13, 2006. Based on weekly averages in Platts Coal Outlook, the Central Appalachia (CAP) 12,500-Btu rail coal tracked by the Energy Information Administration (EIA) remained at $49.90 per short ton in the business weeks ended September 1 and 8. The average spot price declined to $49.25 in the week ended September 15 and stayed at that level through the end of September. In the week ended October 6 the average spot price lost an additional $0.25, ending at $49.00 per short ton. Platts average spot prices in all five regions remained unchanged in the week ended October 13 for the coals tracked in the table and graph below. In Northern Appalachia (NAP), the price for 11,800-Btu coal had been stable at $39.00 per short ton since the end of June before inching down to $38.75 in the week ended September 15, where it remained through the end of the month. In the first week of October, the NAP average price gained $0.50 and ended at $39.25 per short ton. Following a pattern similar to CAP coal, in the week ended September 15 the 11,700-Btu Uinta Basin (UIB) average spot coal price inched down by $0.25 from the $36.50 level it reached 2 months earlier. It remained at $36.25 per short ton through the end of September, then lost $0.25 in the first week of October, ending at $36.00 (see table and graph below). Powder River Basin (PRB) coal continued to sell for spot prices below $10.00 through the month of September. Prices reported for the 8,800-Btu commodity fell from $10.90 to $9.95 per short ton in the week ended September 8. Over the next three weeks they declined to $9.70 then to $9.45, but the average spot price rebounded to $10.15 per short in the week ended October 6. In the Illinois Basin (ILB), the Platts spot price for 11,800-Btu, 5.0-pound sulfur dioxide coal lost $1.00, from $34.00 to $33.00 per short ton in the week ended September 15 but it rose and attained an average price of $33.50 during the weeks ended September 29 and October 6. As noted above, all average prices recorded in the table and graph below were unchanged in the week ended October 13 (Coal Outlook (weekly), September 5 through October 16, p 2).
OTC Prices versus Spot Prices – The trend of recent NYMEX Central Appalachian barge coal futures prices is indicative of CAP over-the-counter (OTC) prices in general. After declining steadily since mid-February, the NYMEX futures turned upward for several days starting July 24. Traders attributed the rise in near-month and later delivery coals to prevailing high heat in the Midwest and East, some burn-off of coal inventories, and increases in sulfur dioxide allowance prices. After the July surge, the NYMEX price resumed its decline but from a higher level. On September 22 the price went below the previous low of $45.20 on July 20. On the other hand, as noted last month CAP spot coal prices reported by Platts had been remarkably stable until the second week in August, especially for the compliance coal product reported in the chart above, which was $64.25 per short ton at that time. EIA confirmed through Platts that the spot prices reported during that period, and their sources, were rechecked and found to be correct. The experience of those principals polled by Platts was that the compliance coal commodity in question, with 12,500 Btu per lb and 1.2 lbs of SO2 per MMBtu, was in short supply and sellers were able to obtain relatively high prices during that period.
Coal Production - Estimated U.S. coal production for September 2006 was 95.3 MMst (see graph below). The September EIA estimate amounts to a 6.7 percent, or 6.9 MMst, decrease from the August estimate of 102.2 MMst. Estimated production in September was also lower than 12 months earlier – the first month that has been the case since March 2006 (compare to blue 2005 line on the graph). Those 6 months of higher shipped production have helped raise average coal stockpiles at electric power producers (see graph, Coal Stocks at Electric Power Plants, in this section). Production for the first 9 months of 2006 was at record levels, 875.6 MMst, or 25.7 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 June 2006 and preliminary EIA Weekly Coal Production estimates for June through September.
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 below excludes industrial and commercial plants because their coal inventories are not published. The number of plants is too small in many cases to ensure individual data confidentiality but, depending on timing, the excluded plants constitute only 1 percent to 5 percent of coal-fueled net electricity generation. Thus, the graph depicts those power plants that comprise the majority (95 to 99 percent) of net electricity generation fueled by coal. In every month from December 2005 through June 2006, those inventories increased from prior month levels. Coal inventories were increased by nearly 34 MMst during the 6-month period (see graph below).
In July 2006 coal inventories declined by 7.7 MMst as the heat of another above average summer began to set in. Nonetheless, as of the end of July, customer stocks of both subbituminous coal, mined in western States, primarily in the PRB, and of bituminous coal, mined principally in eastern States, were in considerably better shape, by 21.9 MMst, than in July 2005. That is the month when average coal stockpiles at electric power plants were near their nadir, especially for PRB coal customers, owing to last summer’s rail disruptions. In recent months, coal stocks at electric power plants have returned to levels closer to historic norms. Both subbituminous and bituminous coal stocks have been rebuilt. Mining capacity - CAP mines in recent years have been moving into reserves with more difficult mining conditions and 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). In the first 9 months of 2006, CAP production was up 2.5 percent over the same period in 2005. Preliminary production for September declined, perhaps confirming company reports of lowered third quarter production and fourth quarter projections. Future mining capacity In NAP and ILB is not as constrained as in CAP because 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, albeit deeper on average than mined in the past. Additional coal production growth is expected between now and 2011, as numerous 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 9 months of 2006, NAP production was 3.4 percent ahead of the same period in 2005 and ILB production was up 3.2 percent. Like CAP production, NAP and ILB production dipped in September.
Coal Technology (updated October 16, 2006 ) Integrated Gasification Combined Cycle (IGCC) - American Electric Power (AEP) filed for environmental permits for two 600-megawatt IGCC power plants, one in Ohio and one in West Virginia. Indicating that the permits could take as much as a year to obtain, AEP projected that construction likely could not start before late 2007 and that the first plant would not be online before 2012. The Ohio plant is slated first currently but the order could change depending on permitting progress and a court appeal in Ohio (Coal Outlook, October 9, pp 4,5). Coal-to-Liquids Project Financing - Even though the prices of crude oil and petroleum products have declined, the growing coal-to-liquids (CTL) industry is apparently not concerned. Spot prices for West Texas Intermediate have been on the decline since early August, falling form $77.05 to as low as $56.74 on October 23. Industry analysts believe that CTL plants will be able to operate profitably as long as crude oil prices remain above $40 per barrel, according to Mark Koenig of Rentech, Incorporated. Arch Coal spokeswoman, Kim Link, stated that “The price of crude would have to fall significantly further to eliminate the commercial viability of CTL.” Arch purchased 25 percent equity in the Houston-based CTL company, DKRW Energy, and would supply 2 MMst per year of coal to the planned $1 billion to $1.5 billion Medicine Bow CTL plant. Peabody Coal participates in a joint development agreement with Rentech to build CTL plants to use 160 MMst of Peabody coal reserves in Montana and 4.2 billion short tons of its coal in the Midwest. In Illinois, Governor Rod Blagojevich backs a $1.2 billion energy independence plan that would use Illinois coal reserves to build coal gasification plants and to produce alternative fuels (Coal Outlook, October 16, pp 1,14). In Montana, Governor Brian Schweitzer has been a proponent of coal gasification, CTL, and carbon sequestration. Although the State has not had funding to contribute, according to industry partners, the Governor was “instrumental in bringing the coal-to-liquids concept before the American people and has caused the financial community to recognize that Montana is a good place to invest in future-oriented, clean energy technologies” (Bull Mountain Land Company, News Release October 2). There is also additional Federal legislation pending that may benefit CTL projects. In May, Illinois Representative John Shimkus and Virginia Representative Rick Boucher introduced H.R. 5453 to extend the $0.50 per gallon alternative fuel tax credit from 2009 to 2020. In June, Kentucky Senator Jim Bunning and Illinois Senator Barack Obama sponsored S. 3325 which would provide up to $20 million in matching funds for planning, permitting, and engineering a CTL facility (Coal Outlook, October 16, p 14). Senator Richard Lugar introduced S. 4000 on September 29, which would establish incentives and requirements to increase use of non-petroleum fuels. The bill would establish a fuel tax credit to support growth of alternative fuel production, such as CTL and cellulosic ethanol, and set goals for increased ethanol availability and higher vehicle fuel economy standards. CTL Private initiative – After lengthy negotiations, companies controlling the Bull Mountain coal mine near Roundup, Montana, and DKRW reached an agreement on financing and constructing a CTL facility on site. The plant would produce 22,000 barrels per day of diesel fuel, along with 300 megawatts of generated electricity. It would consume at least 12 million tons per year (Mtpy) of coal from the Bull Mountain mine. The projected $1.3 billion complex would include a new rail link and employ 4,264 people when in operation (nearly 10,000 during construction) and add $34.2 million in annual tax revenues (News Release, Big Sky Economic Development Authority, October 2, 2006) DKRW and Arch Coal previously announced plans to locate a CTL facility in Wyoming at the Medicine Bow Mine (Coal Outlook, October 9, pp 3,4). Site selection is completed for the first CTL plant in Oregon. Summit Power Group identified a site along the Columbia River for the 336-megawatt plant, which would also produce 56,000 MMBtu/day of synthetic natural gas (syngas). Construction is expected to start in 2008 and the plant would be operational in 2011. The plant is expected to serve as a “reference plant” for Summit Power Group – a design it would replicate at other sites, in other markets (Coal Outlook, October 9, p 5).
The graph below, and its downloadable data file include data available through July 2006. They 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 include the costs of transporting the coal to the coke plants or export districts.
The latest quarterly average price at coke plants shows a small increase of $1.63 per short ton in delivered price of metallurgical coal, from $91.09 to $92.72. The monthly average prices for coking coal transported to export docks have stayed within a range of $85 to $94 in 2006. In April, the price was $85.48 per short ton, 90.27 in May, $93.67 in June, and down to $90.58 in July. 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, the extent to which movement in the delivered prices reflects actual changes in coal priced at the mine versus changes in eastern U.S. rail transportation rates. NOTE: the graph and data file contain minor corrections to quarterly average prices for coal received at coke plants: in 2005, Q2 and Q3, and in 2006, Q1 and Q2, ranging from $0.49 to $1.51 per ton. The previous prices for those quarters were inadvertently calculated using data files in which some coke plant data had not yet been received. The new, revised prices and the previous, superseded prices are clearly identified in the linked data file. Metallurgical coal prices have clearly continued to strengthen since September 2003. Prices in 2004 were forced higher when exports of Chinese steam coal and metallurgical coke were curtailed and redirected to domestic uses. Even though the shock to international coal supplies that occurred in 2004 could happen only once, met coal prices continued to be high in 2005 because of Australian mining and shipping problems and limits on the capacity to produce alternatively sourced met coal in Canada and the United States. In 2006, so far, met prices have reached new average highs amid reports that shortages of steam coal in China are under control but that met coal demand still exceeds supplies. In testimony in support of a Nova Scotia Power rate filing, Emily Medine of Energy Ventures Analysis cited unsettled conditions in international coal markets because China currently is expected to be a net exporter of steam coal and a net importer of metallurgical coal. Ms. Medine also noted that “Labor could become a major issue in many of the exporting countries and could cause short-term disruptions.” A month-long strike ended recently at Drummond’s mine in Colombia. Elk Valley Coal in British Columbia narrowly averted a strike recently over stagnant wages during a period of rising company profits (SNL Coal Report, October 16, 2006). The largest union contract with United Mine Workers in the United States expires at the end of 2006. There is much interest in how new contract negotiations are progressing.
Contact(s):
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
