Coal News and Markets
Coal News and MarketsWeek of September 1, 2006
Coal Prices (updated September 6, 2006) This interim report summarizes spot coal prices for the business weeks ended August 18, August 25, and September 1. Text and other content beyond the following section on OTC and spot prices will be updated with the next edition. 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 last three business weeks of August, after losing $14.35 per short ton over the two weeks ended August 4 and 11(see table and graph below). In Northern Appalachia (NAP), the price for 11,800-Btu coal has been stable at $39.00 per short ton since the end of June. The spot prices of coal commodities in the other three basins published by Platts were also unchanged in the final three weeks of August. The 11,700-Btu Uinta Basin (UIB) spot coal price remains unchanged at $36.50. Powder River Basin (PRB) spot prices, reported for the 8,800-Btu commodity, remain at $10.90 per short ton. Platts spot price for 11,800-Btu, 5.0 sulfur dioxide coal from the Illinois Basin (ILB) remains at $34.00 per short ton (Coal Outlook (weekly), August 21 and 28, September 5, 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 27. 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. Until the second week in August, CAP spot coal prices reported by Platts had been remarkably stable, especially for the compliance coal product reported in the chart above, which was $64.25 per short ton at that time. During the same period, spot prices reported by some other energy reports for equivalent CAP coal were as much as $9.00 to $12.00 lower, while trending downward. Because (OTC) coal futures prices are widely followed, traders questioned how the Platts CAP spot price could be significantly above the futures prices for CAP coals over an extended period. EIA is looking into that question. In the meantime, some observations follow regarding the data. The differences could be real, they could reflect sampling error, or may indicate disparities between spot or futures prices owing to differing coal qualities or delivery periods. Price differences that are “real” would occur if price sampling among the various reports did in fact produce different results because of wide variances among prices companies paid. Part of the spread in prices for CAP coals may reflect the fact that there are six or more CAP “coals” (plural) – coal commodities with different standardized quality criteria. Comparing spot coal prices from one report to another can be problematic because the coal specifications are similar and the loading areas are highly qualified terms. For instance, there are six CAP coals reported by Platts and SNL Energy with Btu values ranging from 12,000 to 12,500 Btu per pound and SO2 ranging from 1.2 to 1.67 pounds of SO2 per million Btu (MMBtu). (Both sources report the SO2 as “SO2 lb,” which is ambiguous.) There are two defined loading districts for commoditized CAP spot coal, two different railroads, and the barge loading option. The coal specifications are apparently identical and are named nearly identically. Energy Publishing includes two nominal SO2 values that are higher than those above and one lower Btu value. There are also spot coal prices reported by Argus Energy, Bloomberg, and others. Spot coal price comparisons are complicated, but comparing spot, a.k.a. “physical market,” coals and OTC coals brings into play differences in both criteria and nomenclature. Spot and OTC coals are sold and purchased, largely, by two separate sets of commercial players. For coals listed as spot and futures transactions, even in a single report, it is clear that some of the CAP commodities are not are for strictly analogous coals. For example, SNL Energy lists a 12,500 Btu-per-pound, 1.5 pounds of SO2 per MMBtu spot coal for loading at CSX locations but its OTC prices are for a 12,500 Btu, 1.6 SO2 coal.
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 3.1 MMst in 2004 and by 2.6 MMst (to 235.8 MMst preliminary) in 2005, or about 1 percent each year. From July 2005 through June 2006, CAP production grew by a remarkable 14.6 percent. In some months CAP still produces more coal than NAP and ILB combined (see graph below). 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 - 16.0 percent in NAP and 17.2 percent in ILB. The trend lines for NAP and ILB in the graph below are flatter because it shows absolute change (tonnages) rather than percentage change.
Emissions trading - Sulfur dioxide (SO2) allowance prices, with which low-sulfur coal prices (especially PRB) tend to correlate, had declined consistently since their large drop in January. By early February, prices for 2006 allowances had passed through the $1100 level and continued declining to $585 by June 2, close to the 2005 low. The turnaround followed a heat wave in the U.S. interior region and coincided with a rapid price increase in natural gas futures the second week in July. SO2 prices climbed steadily through June to close out the month at $625. By July 24, allowance prices were on the rise again as record heat in western and interior States again ate into coal inventories at power plants, touching the $750 mark by month’s end. August 1 trading ended with 2006 SO2 allowance prices at $735. There were no trades in 2007 vintage allowances after July 28, but they had been trading in roughly the same range as the 2006 allowances. For July overall, however, there was significant activity in future vintage allowances, especially for 2007-2009. Some market analysts have expressed the opinion that many utilities with surplus inventory may have been trying to bank additional 2009 vintage allowances to carry into the first phase of the Environmental Protection Agency’s Clean Air Interstate Rules program, or that a once-anticipated surplus of SO2 allowances owing to announced scrubber installations for 2008 and 2009 may now not occur until 2010 or later.
Average mine size - Coal companies continue to open new mines. Even though some of the new mines are simply replacing mines being closed, the total number in operation has increased. Mine Safety and Health Administration (MSHA) mine production records indicate that 2003 was a turning point. The number of U.S. coal mines had been declining steadily since the early 1970’s – reaching numbers not seen since the late 1800’s – but the 1,316 mines operating in 2003 was a new low for the post-1970 period (see table below).
From 2003 through 2005 (preliminary data) there was a net increase of 99 producing mines, or 7.5 percent. Of those, 95 reported annual production levels over 10,000 short tons and only four were smaller sites that produced less than 10,000 tons per year. Total coal production from 2003 through 2005 (including refuse recovery sites) increased by 5.7 percent while the average mine size in 2004 decreased for the first time since 1984, and decreased again in 2005. Even though average mine size has been decreasing over the past 2 years, State totals currently complete (through 2004) reveal that mine size in major producing areas contracted in CAP, southern Appalachia, and the lignite fields in the Gulf States and North Dakota. Average mine size continued to increase in NAP, the PRB, and other parts of the Western Region. This information appears to confirm that remaining CAP coal reserves are mostly in thinner, deeper beds that are harder and costlier to mine. Those conditions tend to yield fewer tons of coal on the ground, even with more expensive innovative, mining techniques. A further contributing factor may be that, with the extended period of strong pricing for CAP coal, some marginally profitable small mines without access to costly technology, have been able to open or reopen. These trends will be reexamined when the detailed 2005 statistics are released. That year saw major delays in processing of new Federal fill permits in watersheds that are essential for large surface mines and mountaintop removal mines and disruptions to some established mines due to individual lawsuits, permit violations, and adverse mining conditions. In southern Appalachia, where all active mines are located in Alabama, the decline in mine size was caused by additional surface mines, which tend to be small owing to the topography. Such mines are sustainable and relatively easy to open for small operators with basic equipment. In both the Gulf Coast and North Dakota there were no changes in the number of mines, but production was down. Since these mines are all dedicated to minemouth power plants, they are more affected than most by lower demand from their sole customers, some of whom supplement lignite with PRB shipments. Recent announcements of new mines - Black Beauty Coal’s new Wildcat Hills mine is up and running in southern Illinois, according to parent company, Peabody Energy. The mine will eventually produce 1 MMst per year. Peabody reports strong demand coming from power plants investing in technologies to burn high-sulfur coal cleanly. Peabody subsidiaries own 10 MMst to 20 MMst new productive capacity planned in ILB over the next 5 years, including the Lively Grove underground mine to serve Peabody’s planned Prairie State Energy Campus in Washington County, Illinois (Coal Trader, July 17, p 1). The Illinois Office of Mines and Minerals expects Drummond Company to submit a permit application soon for a new underground mine in the State. This would be the first mine in Illinois for Alabama-based Drummond. The company owns coal reserves in several counties and has also done some drilling in Fayette County, where Clean Coal Power Resources has proposed a 2,400 MW coal gasification plant (Coal Trader, July 14, pp 1, 5). In West Virginia, mining permit applications have been received from Frasure Creek Mining, Consol of Kentucky, and D&L Coal Company. The most recent application from Frasure Creek covers the proposed Peerless underground mine, for a location near Kincaid, WV. Frasure Creek has permits already pending for two surface mines, one in Fayette and one in Mingo County, and for the Glenco Conveyor deep mine in Fayette County. The Consol application was close to final approval and would cover the 572-acre MT-500 surface mine in Mingo County. That mine would join Consol’s Miller Creek complex, which mined 1.2 MMst in 2005. D&L Coal’s application is to permit a remining project, called the Jones Remine in Mineral County. The 115-acre surface mine would recover coal from four coal seams (SNL Coal Report, July 17, pp 4-5).
Coal-to-Liquids Project Financing - John Warzel, vice president government affairs at Syntoleum Corporation, recently told Coal Outlook that despite $2.7 million in loan guarantees that have been promised to promote coal-to-liquids (CTL) plants under the Energy Policy Act of 2005 (EPACT2005), his and some other CTL projects will use private financing. Mr. Warzel felt that operational delays in the loan guarantee program and some of the language in EPACT2005 puts limits on loan guarantees that make private financing a better alternative (Coal Outlook, July 17, pp 1, 12, 13). Even though loan guarantees are very helpful because CTL projects are new and untested in this country, some of the technologies companies are planning to use may not qualify for Federal loan guarantees. Oklahoma-based Syntroleum is contracted to deliver 100,000 gallons of synthesized liquid fuel for testing in U.S. military turbines. Warzel stated that success in endeavors like that will make it easier to fund CTL projects. Sherry Tucker of Colorado-based Rentech Corporation noted that even though loan guarantees must be repaid, a major benefit is that having them makes it much easier to get financing for the remaining capital needed, and at better rates. Rentech is converting a natural gas-fed ammonia plant to a clean liquid fuels plant based on coal gasification. Ms Tucker said Rentech will move ahead whether or not it wins loan guarantees. Rentech also has projects in development that use natural gas to develop liquid fuels and other products in Colorado, Mississippi, and Wyoming (Coal Outlook, July 17, p 12; and Correction, July 24, p 6). CTL Private initiative - An agreement between Peabody Energy and Rentech is seen by investment analysts as a positive advance toward developing the CTL industry in the United States. On July 18, the largest U.S. coal producer and Denver-based Rentech revealed their agreement jointly to develop two CTL projects to produce diesel and jet fuel. Because CTL technology is untested in the U.S. on a commercial scale, the companies will spend the next year on feasibility plans. According to Hunt Ramsbottom, Rentech president and CEO, fuels from CTL technology can be produced and finished for $36 to $42 per barrel (Coal Trader, July 24, pp 3-4). The CTL plants will be located near Peabody coal reserves in Montana and the Midwest.
New coal-fired generation projects are moving forward. They may end up needing 6 to 10 years to complete, as is the start-to-finish standard, but their numbers are growing. The wave of projects is expected to increase coal-fired baseload noticeably starting around 2011. News of recent projects - Tampa-based Seminole Electric Cooperative is on the fast track for a third coal-fired generating unit at its Seminole Generating Station. The Florida Public Service Commission approved Seminole’s March 2006 application. The 750-megawatt (MW) unit would increase the station’s generating capacity by 60 percent and employ $440 million in advanced environmental control technologies. The entire project is expected to cost $1.4 billion and be in service in 2012 (Coal Outlook, July 17, p 4; Seminole Electric Cooperative, Fact Sheet, updated June 27). Planning for a new 500 MW coal-fired generating unit at Lakeland General Electric’s Lakeland power plant got a boost when Southern Company responded to its solicitation to co-develop the unit. The Lakeland City Commission selected the Southern Company proposal. Southern Company would own 60 percent (300 MW) of the new $900 million unit and Lakeland would own the remaining portion. The projected date of service is 2012 (Coal Outlook, July 17, p 4). Oklahoma Gas and Electric Company (OG&E), American Electric Power’s Public Service Company of Okalahoma, and the Oklahoma Municipal Power Authority indicated they will partner to build one new 950-MW coal-fired generating unit at OG&E’s Sooner plant. Steve Moore, Chairman, President, and CEO of OG&E’s parent company, OGE Energy, said the large “highly efficient unit” was proposed in lieu of two smaller plants, that would both eventually be needed, because the $1.8 billion project would create long-term savings. “By building one unit instead of two, we anticipate saving Oklahoma customers at least $200 million in construction costs alone. We also reduce the environmental impact associated with multiple units spread across the state,” Moore said (SNL Coal Report, July 24, p 1). Tax credits advance clean coal projects - A new entity in the field, Mountain Island Energy (MIE), proposed a 400 MW integrated-gasification combined-cycle (IGCC) coal-fired generator, for location possibly at an undisclosed southeastern Idaho site. The location near Soda Springs, ID, is confidential while feasibility is being assessed but it adjoins a brownfield industrial area and has Union Pacific rail access. Preliminary environmental studies are done and the permitting process has just begun. The project is contingent on its winning Federal advanced coal project tax credits, under Section XIII of the Energy Policy Act of 2005. Further evaluation concluded that IGCC technology is not practicable at the proposed site because of altitude, so MIE has amended its plans and will use pressurized fluidized bed combustion (PFBC), which could also qualify for Section XIII tax credits (Coal Outlook, July 17, p 5; SNL Coal Report, July 17, p 9).
Three fatalities in three separate incidents in Kentucky during July brought the total coal mining fatalities for 2006 to 36. One of the most recent deaths occurred inside a coal preparation plant when a worker on a man lift came in contact with an overhanging structure. The other two fatalities were at surface mines – one due to use of machinery and the other from rock fall from the highwall face.
A broader front - Dallas mayor, Laura Miller, seeks to organize about 50 other Texas mayors to form a united front, called the Texas Cities for Climate Protection, to examine the cumulative environmental impacts of 17 proposed coal-fired power plants. The group is not seeking to halt new coal-fired developments, according to Ms. Miller, but to persuade those planning the plants to take another look at coal gasification-based generation. She noted that “17 of 124 coal-fired plant planned in the US propose to use gasification,” with none proposing gasification in Texas. Scrubbers for Hatsfields Ferry - Allegheny Energy won praise from the citizens groups that had filed suit against it when it agreed to build on new scrubbers at the Hatsfields Ferry coal-fired power plant. “Allegheny’s willingness to make a big investment in scrubbing this plant will mitigate all the issues that were raised” in the lawsuit, said Eric Schaeffer, Director of Environmental Integrity Project, one of the litigants. The project will reduce SO2 emissions by 95 percent compared with 2002 levels, and will significantly lower mercury emissions. In addition to Hatfields Ferry, Allegheny agreed to reduce SO2 at its Fort Martin and Pleasants plants, for a total projected reduction of 250,000 tons per year (SNL Coal Report, July 17, pp 1, 18-19). “without a customer. . . without a future” - On June 19, the operators of Southern California Edison’s (SoCal) Mohave Generating Station in Laughlin, Nevada, announced itheir decision not to invest in air emission controls needed if the plant were to reopen. Its two generating units have been shut down since January 1, 2006, the deadline by which SoCal was required under a court order to meet specified air emissions pollution limits or to cease operations. The shutdown also halted mining at Peabody Energy’s Black Mesa mine in Arizona and its 275-mile coal slurry pipeline, because all its production and the pipeline were dedicated solely to the Mohave plant. Owing to the mine’s remote desert location and limited transportation options, no other customers were found for its 4 to 5 MMst productive capacity, leaving the Black Mesa mine “without a customer and seemingly without a future” (SNL Coal Report, July 3, p 1). Peabody has for years been embroiled in difficult negotiations with the Hopi and Navajo tribes, on whose land the mine and slurry pumping plant are located, to tap into additional groundwater sources needed for the slurry. Recently, Peabody considered siting an environmentally friendly integrated gasification combined-cycle power plant near the mine to take its future output – an alternative, however, that would require major new electricity transmission infrastructure. The company is now seriously considering siting a coal gasification plant near the mine. Instead of using the synthetic gas for integrated power generation, Peabody would sell the gas via a nearby existing natural gas pipeline. A lot of negotiations and permitting lie ahead if Peabody decides on this course, but it has the advantages of using existing (pipeline) infrastructure and avoiding the need to mine more groundwater. The coal from Peabody’s soon-to-open El Segundo mine in nearby northwestern New Mexico is now also expected to be gasified. The coal was to be dedicated to the Mustang Generating Station being developed by Peabody and several partners, but the Mustang plant was put on hold when the State declined to issue an air permit for the plant’s standard pulverized coal boiler technology. In order to achieve the carbon dioxide limits that the State would prefer, Peabody would turn to integrated gasification combined cycle (IGCC) technology with carbon sequestration, but Peabody is also considering directing El Segundo coal to pipeline gas or coal liquefaction, either of which would start with gasification.
Coal inventories are monitored at plants that generate electricity (utilities, independent power producers, and industrial and commercial plants with generation capacity). In every month since December 2005 those inventories increased from prior month levels (see graph below). Coal inventories in May 2006, at 133.2 MMst, reached the highest level seen since July 2003. May coal inventories are based on EIA's early-release "Electric Power Flash" estimates. Statistics prior to May incorporate revised or final data from EIA's latest Electric Power Monthly. By historical standards, coal stockpiles in May represented the mid-level of expected ranges, - prior to the onslaught of extended heat waves in most parts of the country that rely on coal-fired generation.
Calculated days of consumption represented by coal stocks increased from 41 days at the end of March to 51 days in both April and May. By comparison, ending March coal stocks in 2005 equated to 39 days' consumption and April and May were 47 and 46 days' consumption respectively (see graph). The 51 days of consumption represented by May coal stockpiles were fractionally lower than in April, even though stockpile tonnages increased, because the demand for coal in May was 8.1 MMst higher than in April. Days of consumption levels normally decrease from June through August because of heavy winter consumption during the hottest summer months. Compared with the same period in 2005, coal consumption from January through May 2006 was down by 5.4 MMst, or 1.3 percent, based on milder late winter weather in 2006 in the coal-burning areas. Coal exports continue to grow. After significant growth in 2004, to 48.0 MMst, the trend carried over through 2005, which ended with 49.9 MMst (EIA, Quarterly Coal Report, Table 7, August 2, 2006). U.S. coal exports continue to be led by metallurgical coal, with 28.7 MMst in 2005, which comprised 57.4 percent of total coal exports. This was 6.8 percent higher than the 26.8 MMst exported in 2004. On the other hand, coal imports were also up in 2005, with 30.5 MMst, surpassing the 27.3 MMst imported in 2004 by 11.7 percent. Bituminous coal exports in April decreased by 0.3 MMst from March levels. Bituminous exports for the first 4 months of 2006 totaled 13.9 MMst, compared with 14.2 MMst for January through April 2005. During the same period, coal imports increased by 2.0 MMst compared with 2005, reaching 12.0 MMst of coal exports from January through April 2006. The net exports of coal equated to 1.9 MMst for January through April 2006 (National Mining Association, International Coal Review, June 2006).
The graph below, and its downloadable data file include data available through 2Q 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 data collected from coke plants show an average increase of $4.01 per short ton in delivered price of metallurgical coal. The data for coking coal transported to export docks reflect an $8.24 per short ton decline in average declared value from March to April and a gain in May of $4.80, to $90.27 per short ton. Unlike most 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 and do not address future prices. Because the prices below 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.
Estimated monthly coal production for June 2006 was 99.6 MMst (see graph below). The June EIA estimate amounts to a 2.9 percent, or 3.0 MMst, decrease from May’s 102.6 MMst. The June production was, however, 4.1 MMst greater than in June 2005. Production for the first 6 months of 2006 was at record levels, 589.0 MMst, or 23.4 MMst ahead of the same period in 2006. Revised estimates of year-end production total 1,133.3 MMst for 2005, which is 21.2 MMst, or 1.9 percent, greater than the final production for 2004. The U.S. Monthly Coal Production graph (below) includes 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 March 2006 and preliminary EIA Weekly Coal Production estimates for April through June.
Ohio River system needs $2.5 billion in rehab work – A draft report of a 10-year Army Corps of Engineers study finds that $2.5 billion over 20 years are needed to re-engineer, rebuild, repair, and maintain the high priority facilities along the 981 miles of the Ohio River and along its tributaries used for barge traffic. After that, the 60-year plan identifies other probable priorities over the remaining 40 years for the Ohio River System (ORS). Forty-five percent of the locks on the ORS are more than 50 years old and almost 50 percent are 25 to 50 years old. The study also identified environmental improvements needed to mitigate damage done by development along the banks, lost wetlands, and “damaging effects of locks, dams, and commercial river traffic” (Coal Outlook, July 17, pp 1, 13). The highest priority for lock upgrades was assigned to locks in the Pittsburgh area: Emsworth, Dahields, and Montgomery. During the next several years, major rehabilitation of the main locks will be needed at: Markland, Meldahl, Hannibal, and Pike Island.
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