Coal News and Markets
Coal News and MarketsWeek of February 19, 2006
Coal Prices and Earnings (updated February 22, 2006) This report summarizes spot coal prices from the business weeks ended February 10 and February 17. In the business weeks ended February 10 and 17, Powder River Basin (PRB) spot prices declined for the third and fourth times in the past five weeks. Among the spot coal prices tracked by the Energy Information Administration (EIA), only the PRB price changed each week. The average spot price for 8,800-Btu PRB product lost $0.50 in the week ended February 10, then lost $0.40 the following week, declining from $17.75 to $16.85 per short ton. There were no changes in the indexed spot prices in the other coalfields in any of the previous 7 weeks. The average spot price for the Central Appalachia (CAP) 12,500-Btu rail coal tracked by EIA remained at $58.25 per short ton. The average spot price for 11,800-Btu Northern Appalachia (NAP) held at $45.00 per short ton. The Illinois Basin (ILB) spot price was unchanged at $36.00, and the 11,700-Btu Uinta Basin (UIB) coal average spot price was still $37.00 per short ton (all for prompt-quarter delivery, Coal Outlook, February 12 and 19, p 2).
The downturn in prices for PRB spot coal since the week ended January 13 and the decline in sulfur dioxide (SO2) emission allowances since early December 2005 are interrelated. Many factors have affected the coal market. PRB coal prices were dampened in part because natural gas supplies were above expectations due to mild winter weather recently in the Midwest, South, and East, and consequent natural gas price declines. Natural gas combustion emits very little SO2 , and the availability of lower-priced gas relieved some of the immediate demand for SO2 allowances as well as for low-sulfur PRB coal. Natural gas futures recently were at a 7-year low, the NYMEX near-month contract having settled at $7.134 per million Btu (MMBtu) on February 16, the same day that EIA reported underground storage of gas in the lower 48 States at 44 percent above the 5-year average for this point in the season. Many power generators and industrial plants that burn coal also own units designed to burn natural gas, or to burn either. As of end of trading on February 27, the NYMEX contracts closed even lower, at $6.780.
The Governor of West Virginia, Joe Manchin, temporarily suspended production at all of the State's coal mines Wednesday afternoon, February 1, following three accidents that resulted in two deaths. The deaths on February 1 were followed on February 16 by a fatal rock fall in Perry County Coal Corporation's HZ4-1 underground mine in eastern Kentucky, and by a machinery-related fatality in the Mettiki mine in Maryland. These deaths brought the year-to-date total to 21, just 3 fewer than in all of 2005 (MSHA, Coal Daily Fatality Report, February 22). Sixteen fatalities have occurred in West Virginia, 3 in Kentucky, 1 in Maryland, and 1 in Utah. The West Virginia "Mine Safety Stand Down" meant that "starting with the current shift, and each new shift after that, the mine companies, supervisors and the miners themselves were to engage in a thorough review of safety procedures before any work is to continue." Governor Manchin also requested additional mine safety resources from the Mine Safety and Health Administration (MSHA), which quickly agreed. In addition, he accelerated the State mine inspection agency's schedule for quarterly inspections, saying it "will immediately begin the process of inspecting every mine in the state and their equipment, conditions, engineering plans, safety procedures and safe work practices" (Platts Coal Trader, February 2, pp 1,5,6). There were instances of misinformation - that an indefinite total shutdown was in place in West Virginia - which may have grown out of radio or television coverage of a press conference in which Governor Manchin said: "Safety is going to be the foremost thing in the West Virginia mine right now and we're not going to produce another lump of coal until this is done." The phrase, "until this is done" referred to Governor Manchin's direction that all mines review their safety procedures and equipment immediately. In full context it did not imply an indefinite shutdown. (For a sample of the press conference, see National Public Radio, Morning Edition, February 2). The West Virginia call for stand-downs was followed by an MSHA call for a nationwide stand down. On February 1, Acting Assistant Secretary of Labor for Mine Safety and Health David G. Dye asked all U.S. coal mine operators to take one hour out for safety’s sake and “Stand Down for Safety,” on Monday, February 6. Mr. Dye asked that the extra time be taken “at the beginning of each shift and before the start of any mining activity, to go over the hazards involved with mining and the vital safeguards that need to be taken.”. MSHA was immediately to send out packets of safety information to stakeholders for discussion at coal mines. Further information can be found at MSHA’s “Stand Down for Safety web page. Meanwhile, United Mine Workers of America (UMWA) President Cecil E. Roberts “ordered every local union president at UMWA-represented coal mines throughout West Virginia to undertake a ‘meticulous’ inspection of their mines.” Again, these inspections would be done without major delays, although if the union believes a mine operator is not cooperating, it could order further action (Coal & Energy Price Report, February 2, pp 1-2).
Some coal prices recently seemed to be unaffected, or barely affected, by movements in other energy markets. Coal prices may appear to be in relative balance with natural gas or oil prices one week but be virtually unphased by their significant fluctuations the next. This primarily applies to spot prices. Except for PRB coal, few changes in spot coal prices have been reported since the New Year. Compared with petroleum and natural gas markets, spot and futures coal prices generally react to world events more tentatively and, until late 2004, were relatively insulated from international markets. For oil, NYMEX futures that had previously dipped to a few dollars above $50.00 per barrel (during intraday trading) resurged recently on the troubling news of violence and well shut-ins in Nigeria. Settle prices that bottomed at $57.55 on February 15 closed at $61.10 on February 21. If changes of that sort affect coal markets, they do so indirectly, either in consideration of price changes for natural gas, which tends to be more sensitive to oil price changes, or through lagged changes in mining or coal transportation costs as oil price changes are eventually passed through via diesel prices, supplier costs, or coal transporters' fuel surcharges. A stronger direct influence on coal prices would likely result if traded natural gas prices stay low for another week or two. Analyst Spencer Jakab noted that with natural gas prices in decline, "some of the least-efficient and most heavily polluting coal plants are nearly as expensive to run as the most-efficient gas plants" and such coal plants "may be taken off line." Meanwhile, SO2 emission allowance prices for 2006 and 2007 vintages have leveled off around $920 to $950 per ton (see below). Oil prices and output levels will be on the agenda when the Organization of Oil Exporting Countries (OPEC) meets on March 8. Historically high oil prices in past months have raised costs for U.S. coal producers - for the diesel fuel used heavily at surface mines - and for their customers - paying fuel surcharges to transport the coal to their boilers and power stations. Fears of sudden coal shortages and higher prices because of the recent rash of coal miner fatalities were unfounded. With no mass closures of coal mines across the United States, nor in West Virginia, as a result of the coal mine fatalities, there was no reason that the ordered safety measures should on their own noticeably decrease overall productivity, drive up coal prices, or lessen coal supplies. The safety stand-downs, if fully complied with, did not require enough time to have a measurable effect on coal supplies over the course of a month or a year. In fact, net productivity may benefit in some cases by correction of hazardous situations or identification of inefficiencies. Undoubtedly, individual mines that suffer miner fatalities could be harmed by loss of production, by fines and investigations, by damaged reputation, and possibly by diminished trust among their employees. In general, however, the tragic fatalities and temporary mine closures are not of a magnitude to affect overall availability or near-term prices of coal. On the other hand, if perceptions arise that Appalachian - or U.S. - coal production may slow and productivity decline, that would be a contributing factor toward higher temporary spot prices. Bituminous coal spot prices - Appalachian, Illinois Basin, and Colorado/Utah Uinta Basin - have been high, but most of them moderated late last summer from earlier peak prices, and stagnated. Those markets have been less active recently because consumer stockpiles at eastern power producers, that almost exclusively burn Appalachian bituminous coal, are at least at acceptable levels. Eastern U.S. coal production capacity is rising and complaints during 2005 about missed coal deliveries due to rail or barge problems were not systemic. The fundamentals, in other words, are good. An exception to the low direct impacts described above may be the lost coal production from Massey's Aracoma Alma mine Number 1, which was shut down on January 19. It is still closed during continued investigations, repairs, and improvements and, as of February 23, no date for reopening had been set. Alma No.1 may be the most important source for minus-1 percent (less than 1 percent) sulfur, 12,500-Btu coal in the CSX rail originations area for the over-the-counter (OTC) market. This premium coal can be sold straight or blended with higher-sulfur 11,500 Btu coals from the area to produce other 12,000- and 12,500-Btu coal commodities traded in the OTC. A shortfall in that premium coal creates major problems for traders whose positions are due while Alma No.1 is idle (U.S. Coal Review, January 30, p 12). Somewhere they will have to find or buy back coal with the specifications in their contracts. At the same time - and possibly for some of the same needs - mega-utilities such as the Southern Company, Duke Energy, and Tennessee Valley Authority are looking for sources of at least 2 mmst of comparable low-sulfur coal. As of February 16, Andalex Resources' Aberdeen mine in Utah was reopened. The mine had been closed since January 29 following a fatality when coal burst from the longwall face, 2,700 feet beneath the surface, crushing a miner (Argus Coal Daily, February 16, p 6; February 17, p 6). The loss of over 2 weeks' production compounds the effects of several outages and disruptions in the Uinta region. Production problems daunt miners at Arch's West Elk mine, following a fire in late 2005, at Oxbow's Elk Creek mine because of a recent roof cave-in, and at Bowie Resources Number 2 mine - all in the Somerset mining area of the Uinta region in Colorado. Union Pacific noted lower coal carloadings in the area in January. The disruptions have affected some deliveries, forcing a few utilities into the spot market, and keeping spot prices firm despite modest coal demand nationally (Argus Coal Daily, February 17, pp 5-6). For each major coal-burning generator or industrial plant the decision - whether to burn coal, to switch to gas-burning generators or boilers if available, to purchase power, or to follow other options - depends on individual circumstances, but for many the rationale for conserving coal stockpiles for a while is better than at any time in 2005. The average spot price for PRB 8,800 Btu coal dropped by 18.4 percent from the week ended January 13 through the week ended February 17. In a number of regions, day-ahead and forward prices for power purchases have declined recently. Whether power producers with coal-fired capacity opt to buy power off the grid depends on complex individual assessments of each one's mix of generating technologies, coal stocks, supply contracts, transportation options, access to other generation energy sources, and - in rapidly changing power markets - on timing. Some power generators, with retrofit scrubbers that will not be operational for another 2 years or more, have been locking in supplies of higher-sulfur NAP and ILB coal due to concerns that supplies may not be plentiful and prices may be higher in the future. The higher-sulfur coal will generally be supplied under multi-year contracts and the prices being agreed to are high enough to persuade producers to price some of the future production earlier than usual. Some market watchers have reported seeing higher prices for eastern spot coal as well but, except for one CAP barge coal, Platts Coal Outlook had not reported increases as of February 3. The market for Appalachian coal affects both operators who burn that coal exclusively and those whose boilers were converted to use PRB coal. In the Midwest and South Central regions of the United States a sizable number of managers at power plants that burn PRB coal also purchase low-sulfur and high-Btu Appalachian coals. Those plants blend Appalachian coal, especially CAP, with PRB coal to boost Btu and meet their sulfur emission budgets. At current emission allowance prices the quality of the high-Btu blend coal has become just as important as the low sulfur in the PRB coal. The impacts so far are limited because 80 percent or more of Appalachian coal sales are under existing contracts, at prices the customers can still tolerate in conjunction with emission allowance costs. If SO2 allowance prices remain high, however, the costs could price more CAP and NAP coal out of the market at a time when their Btu's are needed (Coal & Energy Price Report, January 9, p 2).
Vintage 2006 SO2 allowance prices fell from their December 9, 2005, settle price record of $1,630 to as low as $1,050 on February 3. The settle price on February 6 had moved up to $1,075 before falling again: to $1,000 by February 9 and to $920 on February 16 and 17 (Evolution Markets, February 6 and 17). The precipitous 44 percent drop in prices since December 9 was more than enough to improve prospects for the use of higher-sulfur coals that could not be sold a month earlier. A few of the new crop of flue gas desulfurization units are starting to phase in. The influence of these retrofit scrubbers could eventually constrain high volatility in future SO2 emission prices. Although NAP and ILB coals, and off-spec CAP coal (with Btu below specified levels or with sulfur content above specified levels) are expected to gain market share because of the addition of flue-gas scrubbers at scores of generating units, it should to take until 2011 for all the first wave of anticipated scrubbers to be built and installed. Consol Coal, with the highest holdings of available reserves in NAP, expects the scrubbed coal-fired capacity to double between now and 2011 (Argus Coal Daily, January 11, p 4). EIA's AEO2006 forecasts project 90.6 gigawatts of coal-fired generation retrofitted with new scrubbers by the end of 2011. The total then would be nearly 2 times the 102 gigawatts of scrubbed coal-fired capacity on line in 2004. (EIA projects continuing retrofits beyond 2011, reaching 132.7 gigawatts of cumulative retrofits by 2020 and 140.6 gigawatts by 2030.) Coal Supplies (updated February 23, 2006) Coal inventories are monitored at plants that generate electricity (utilities, independent power producers, and industrial and commercial plants with generation capacity). In December 2005 those inventories decreased from November levels by 5.5 MMst (see graph below). In the same month, those generators consumed 10.3 MMst of coal, more than half of which would appear to have been taken from stocks. It is surprising, therefore, to find that estimated shipped coal production in December increased by 9.4 MMst without raising stockpiles in the prime coal consuming sector. Some of the difference may have gone to industrial consumers. Coal exports increased by 1.7 MMst, November to December, but coal imports increased by 1.1MMst during the same period, yielding only 0.6 MMst of net exports (National Mining Association, International Coal Review, January and February 2006). Some of the discrepancy may be related to irregular shipping patterns that could put production versus receipts of the same coal into different reporting months, or unusual amounts of coal temporarily stored at transfer or blending facilities. Coal on hand decreased from 106.5 (revised November stocks) to101.0 MMst through the end of December based on EIA's early-release "Electric Power Flash" estimates. Statistics prior to December are based on revised or final data from EIA's latest Electric Power Monthly. By historical standards, coal stockpiles continue to be low: they totaled 106.7 MMst in December 2004 and 121.6 MMst in December 2003. Calculated days of consumption represented by coal stocks decreased from 39 days to 34 days from end of November to end of December. By comparison, ending December coal stocks in 2004 equated to 36 days' consumption and in 2003 to 42 days'. Days of consumption levels normally decrease between December and February because of heavy consumption before the spring "shoulder months," when weather and planning encourage rebuilding inventories for summer consumption. Compared with the same period in 2004, coal consumption for January through December 2005 was up by 2.5 percent, based on higher-than-usual consumption from June through October.  After unusual growth in coal exports in 2004 (5.0 mmst over 2003), 1Q2005 exports were ahead of 1Q2004, but that pattern reversed in 2Q2005. (EIA, Quarterly Coal Report, Table 7, December 21, 2005). Since then, coal exports were roughly equivalent to those of 2004, with the result that exports year to date at the end of September were nearly the same as in the same period of 2004: 37.6 versus 37.2 mmst. U.S. coal exports continue to be led by metallurgical coal, but the year-to-date totals are also very similar to the prior year for met coal (21.7 versus 21.4 mmst in 2004) and for steam coal exports (15.8 mmst in both years). On the other hand, coal imports are up by 13.5 percent for the first 3 quarters of 2005: 22.7 versus 20.0 mmst in 2004.
For many years, especially in foreign production centers, direct reduction iron (DRI) has been a useful intermediate product. DRI is made using crushed natural ore, possibly small amounts of fluxes, great amounts of natural gas to heat the ore, and mo coke. The result is 97 percent pure iron, as compared with blast furnace hot metal, which is only 93 percent pure. The DRI - either granular or pelletized, depending on whether it is used on site or shipped - is used in mini-mills and melt furnaces to produce various type of finished steel. When the DRI is shipped, the steel can be produced in small, lower-cost facilities, near where the finished product is needed. Research has been ongoing for years on processes that would eliminate the need to consume vast amounts of natural gas and would incorporate coal. Most results have been only partly successful and have not advanced beyond bench scale or pilot plant set-ups, but now a company in Minnesota, Mesabi Nuggets, LLC, plans to have such a plant operating by 3Q2007. The iron-rich "nuggets," including powdered coal largely as a carbon source, will be produced at a location about 4 miles north of Aurora, Minnesota, and will be shipped to a Steel Dynamics, Incorporated mill near Butler, Indiana. The manufacture will use the Kobe Steel ITmk3 process co-developed with Midrex International. In international markets metallurgical coal demand expectations are varied and mixed. A Wall Street Journal article predicts that met coal prices will decline by about $10.00 per metric tonne in 2006, from prices in 2005 ranging from $78 to $125 per tonne (depending on quality) in world markets (WSJ, January 13, p A2) The core issue affecting met coal is that 2005 domestic steel production in China was well above projections, resulting in a glut of steel despite China's current position as the world's largest consumer of steel. The Chinese State Council released new regulations to reduce unneeded steel capacity by shutting down blast furnaces with less than 300 cubic meters capacity by the end of 2007, and also to shut down small converters and arc furnaces by the end of 2006 (Metals Place, January 10). China's largest steel producer, Baosteel cut prices by at least 10 percent November 22, after cutting prices by 15 percent in August (Financial Times (FT.com), November 22). As noted in the Transportation section (below), Chinese steel producers have been drawing down iron ore supplies. It appears the same is true of metallurgical coke. To deal with slow domestic sales of met coke, producers in China were reported offering coke for $130 per metric tonne at Chinese ports (U.S. Coal Review, November 21, p 5). Prices in that range for coke, if they persist in steady volumes, would deter further sales of metallurgical coal above $100 per tonne ($90-$91 per short ton). Much depends on location and timing. Some producers, especially those with new contracts, are confident that demand will remain high over the next several years, just not greater than $100 per short ton. The graph below, and its downloadable data file include data available through October 2005. They show quarterly average values based on coal cost data EIA collects from coke plants. It also depicts 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 October data reflect a $4.83 per short ton rise over September in average declared value of coking coal transported to export docks. 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 January 2006 was 99.7 mmst (see graph below). The January EIA estimate amounts to a 10.3 percent, or 9.3 mmst, increase from December's 90.3 mmst. The January production estimate is a hefty 6.0 mmst above that of January 2005. Preliminary estimates of the 2005 production total 1,119.9 mmst for 2005, which is 7.8 mmst, or 0.7 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 the first three quarters of 2005 by the Mine Safety and Health Administration (MSHA) and also shows preliminary EIA Weekly Coal Production estimates for all of 2005 and January 2006. The revised coal production through the first three quarters of 2005 was 845.9 mmst, based on completed MSHA data. That is 14.8 mmst, or 1.8 percent, more than in the first three quarters of 2004.
If future coal demand is on the rise, as many believe, future coal supplies will require additional production from mines currently in planning and permitting stages. The number of coal mines announced, planned, or reopening increased in 2005.
After 4 years of dialogue, revisions, and court hearings, plans for a third railroad to serve the PRB moved one large step closer to reality on February 15 when the Surface Transportation Board (STB) once again approved the Dakota, Minnesota & Eastern (DM&E) Railroad's application. The STB decision grants DM&E final approval to build 280 miles of new rail line in South Dakota and Wyoming that would connect with DM&E's existing rail line in Minnesota to the east and, through its co-owned partner, the Iowa, Chicago & Eastern Railroad (IC&E), into the Chicago area. The existing line will also require numerous upgrades and rebuilds. DM&E filed its application in February 1998 and received STB approval in January 2002. The STB's 5,000-page environmental impact statement, released in 2000, met with widespread opposition. In April 2005, the Surface Transportation Board reaffirmed its approval of the DM&E but it became final after the 8th Federal Circuit Court of Appeals remanded the case back to the board and STB issued its latest ruling (Coal Trader, February 17, pp 1, 4-5). In November 2005, the DM&E and IC&E applied for a $2.5 billion loan from the Federal Railroad Administration (FRA) to finance the expansion. The loan would virtually guarantee the fruition of the DM&E's years of effort and construction on the 3-year project could start in late 2006 if the loan is approved, according to Kevin Schieffer, president and CEO of Cedar American Rail Holdings, Incorporated, which owns both railroads. DM&E expects to haul 100 MMst of PRB coal per year when the line is built. The FRA loan application was filed under a provision authored by Senator John Thune (R-SD) that was part of the $286 billion Transportation Reauthorization bill enacted in 2005. A new hurdle for DM&E appeared, however, last week when the Department of Transportation's fiscal year 2007 budget proposed to eliminate the FRA program that would provide the $2.5 billion loan. The final outcome is unclear at this time.
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