Coal Prices and Earnings (updated February 6, 2006)

In the business week ended February 3, Powder River Basin (PRB) spot prices declined for the second time in three weeks, more than canceling out the prior week’s increase. Among the spot coal prices tracked by the Energy Information Administration (EIA), only the PRB price changed. The average spot price for 8,800-Btu PRB product lost $1.40, declining from $19.15 to $17.75 per short ton. There were no changes in the indexed spot prices in the other coalfields in any of the previous 5 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 5, p 2).

Average Weekly Coal Commodity Spot Prices Business Week Ended February 3, 2006

1 Coal prices shown are for a relatively high-Btu coal selected in each region, for delivery in the "prompt" quarter. The "prompt quarter" is the next calendar quarter, with quarters shifting forward after the 15th of the month preceding each quarter's end. Source: with permission, selected from listed prices in Platts Coal Outlook, "Weekly Price Survey." Note: the historical data file of spot prices is proprietary and cannot be released by EIA; see http://www.platts.com/Coal/. >Analytic Solutions>COALdat, or >Newsletters> Coal Outlook.

The downturn in prices for PRB spot coal since the week ended January 13 is related to the decline in sulfur dioxide (SO₂) emission allowances since early January. Many factors are affecting the coal market at this time. PRB coal prices were dampened in part because natural gas supplies are above expectations due to mild winter weather recently in the Midwest, South, and East, and consequent natural gas price declines. The availability of lower-priced natural gas, which emits very little SO₂ , lessens some of the immediate demand for SO₂ allowances as well as for low-sulfur PRB coal. Many power plants and industrial plants have units that burn coal and units that burn natural gas, or that can burn either.

Coal Mine Safety Stand-Downs
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 “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 are 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, but in full context it did not imply an indefinite shutdown. For an example of the press conference, see National Public Radio, Morning Edition, February 2).

On February 1, some energy traders reacted swiftly to rumors of a Statewide coal mining shutdown. Energy Publishing, LLC observed that: “Initially, Manchin’s call to action created concern that major production losses were likely, and the natural gas market responded with a significant surge in price.” But later, it became evident that “nothing like catastrophic work stoppages will result. The natgas upturn eased back a bit. Safety checks prior to some work shifts apparently had been completed before the end of the night, followed by production resuming.” (Coal & Energy Price Report, February 2, p 1.)

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).

The two deaths on February 1, 2006, brought the year-to-date total to 19 coal mining fatalities, just 3 fewer than in all of 2005 (MSHA, Coal Daily Fatality Report, February 2). [Please archive and link to mht file (supplied).] Sixteen fatalities have occurred in West Virginia, two in Kentucky, and one in Utah. As of February 2, Andalex Resources’ Aberdeen mine in Utah remained closed since January 29 while inspectors investigated the death, caused when coal “burst from the coal face” striking the miner (Platts Coal Trader, February 2, p 2).

Market Developments (updated February 8, 2006)

With no mass closures of coal mines across the United States, nor in West Virginia, as a result of the recent coal mine fatalities, there is no reason that the ordered safety measures should noticeably decrease overall productivity, drive up coal prices, or lessen coal supplies. The safety stand-downs themselves, if fully complied with, would 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 themselves 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.

EIA data from November 2005 show that coal inventories in the electric power sector in the Middle Atlantic Census Division (New York, New Jersey, and Pennsylvania) were at 33 days of consumption, based on most recent maximum coal burn requirements. The stockpiles had increased from 31 days’ supply in October and 28 days’ supply in September 2005. Electric power sector coal inventories were a bit less robust in the in the East South Central Census Division (Kentucky, Tennessee, Mississippi, and Alabama), where principal coals burnt comprise both Appalachian bituminous coal and western subbituminous. Those inventories equated to 31 days’ consumption in November 2005, up from 29 days of coal in October and 27 days worth in September 2005. Although plants in this region were affected by missed Powder River Basin coal deliveries in 2005, receipts of eastern bituminous cushioned the impact. Finally, by contrast, inventories at coal-fired power plants in the West South Central Division (Oklahoma, Texas, Arkansas, and Louisiana), which burn western subbituminous coal more than any other, were very low. In November 2005, coal stocks were 24 days worth of consumption, up from 22 days in both October and September.

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 and has not reopened. 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.

The Alma mine’s 2005 production, which declined from 2004 levels, projects to about 1.5 million short tons (mmst), or 125,000 short tons per month (tpm) based on 3 quarters of production reports. Its production had returned to the 200,000- tpm level that was typical in 2004 according to U.S. Coal Review (January 30, p 4). How much longer the mine will be out is unknown and the subject of much speculation, but given the current safety climate, outsider estimates are for total downtime of 1 to 3 months.

Vintage 2006 SO₂ allowance prices have fallen from their December 9, 2005, settle price record of $1,630 to as low as $1,050 on February 3. The last settle price on February 6 moved up to $1,075 (Evolution Markets, February 6). They are still costly but the precipitous 35 percent drop in prices is enough to improve prospects for the use of higher-sulfur coals that could not be sold a month earlier.

Evolution Markets previously suggested the logical cap would occur when the market sees coal plus allowance prices becoming more expensive than natural gas prices on a Btu basis, or when market players on the margin start to sell allowances and buy power on the open market (Evolution Markets, SO₂ Markets November 2005). By that reasoning, it is logical to see a correlation between lower prices for SO₂ allowances and steadily declining natural gas prices in the face of the widespread mild weather since mid-December. Working gas in storage was 2,406 Billion cubic feet (Bcf) as of Friday, January 27, according to EIA estimates. Stocks were 296 Bcf higher than last year at this time and 529 Bcf above the 5-year average of 1,877 Bcf After one of the mildest Januaries on record, some market analysts are predicting record high working gas storage by the end of the winter season.

Since the Wednesday-to-Wednesday week ended December 13, 2005, the natural gas spot price at the Henry Hub declined by 42.6 percent , from $14.80 per million Btu (MMBtu) to $8.50 per MmBtu. On February 7 gas traded at prices averaging $7.80 per MMBtu (Dow Jones Newswires, 02-07-06 1626ET). Lower spot and futures prices, paired up with unusually good supplies of natural gas is encouraging for power producers with natural gas generators as well as for some industrial gas consumers, who have begun to resume use of gas.

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.

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 14.1 percent from the week ended January 13 through the week ended February 3. 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.

The recent record high prices for PRB spot coal contrasted with prices for CAP coal and NAP coal, which declined in 4Q2005. The explanation is that coal suppliers are essentially selling two commodities in 2006 – Btu’s and sulfur. The higher the Btu, the higher the value of the coal itself, but the higher the sulfur entrained in the coal, the more it must be discounted. In the past, one reported rule of thumb would discount the price by $0.30 per short ton for each 0.1 percent of sulfur in the coal (Coal & Energy Price Report, January 9, pp 1-2). By that approach, a 1.5 percent sulfur CAP coal would be discounted $1.50 per short ton below the price of a 1.0 percent coal of similar Btu. In 2006, however, with the prices of SO₂ emission allowances topping $1,500 per ton, boiler operators have been demanding discounts of $15 to $16 per ton of coal carrying an extra 0.5 percent sulfur. By the same token, the heat content of the coal has become more critical because the amount of sulfur converted ultimately to SO₂ emissions is inversely proportional to the Btu value of the coal. The lower the Btu content, the more coal and attendant sulfur must be combusted to produce the heat or power needed. As a result 11,500-Btu coal with 1.5 percent sulfur may be at the margin of the market, but 11,000-Btu coal with 1.5 percent sulfur may have to be discounted below its cost of production. Of more concern, much of the “off-spec” coal (with Btu below specified levels or with sulfur content above specified levels) is not being bought at any price (Coal & Energy Price Report, January 9, p 2).

If this selective buying were to become widespread it could indirectly result in a broad loss of productive capacity for coal. For example, some of the extra Appalachian capacity in 2005 was produced at new or expanded surface mines, in part because of the shortage in trained underground miners. Further, the decision by the Fourth Circuit Court of Appeals in late November 2005 on Section 404 permitting (see below) will ease permitting delays for surface mines and, especially, mountaintop removal mines in CAP. The dilemma is that economically feasible surface mines tend to recover multiple beds of coal, of which only a minor percentage will have the desired Btu/sulfur properties. The other coal must also be salable for at least a modest profit for these mines to stay in business, but currently in the spot market those off-spec coals are being mined at a loss.

There are now signs that, in the long term, the dilemma may be resolved. 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).

Although NAP and ILB coals, and off-spec CAP coal, 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 2006 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 inventories are monitored at plants that generate electricity (utilities, independent power producers, and industrial and commercial plants with generation capacity). Those inventories increased in November 2005, as they usually do in autumn, and had a small but noteworthy impact on the overall downward trend in coal stocks (see graph below).

Coal on hand increased from 101.1 to 109.5 mmst from the end of October through the end of November based on EIA's early-release "Electric Power Flash" estimates. Earlier statistics are based on revised or final data from EIA's latest Electric Power Monthly. By historical standards, though, coal stockpiles continue to be low: they totaled 113.3 mmst in November 2004 and 126.7 mmst in November 2003. Calculated days of consumption represented by coal stocks increased from 37 days to 40 days from end of October to end of November. That marks the first month since January 2005 that days of coal consumption increased to within 1 day of the coal on hand a year earlier. By comparison, ending November coal stocks in 2004 equated to 41 days' consumption and in 2003 to 46 days'. Days of consumption levels normally increase in October and November because inventories increase and because the rate of consumption tends to be lower in those months than in any of the previous four or five months.

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.

Metallurgical Coal (updated January 27, 2006)

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.

Download Met Coal data files. (Excel Format)

Coal Production (updated January 12, 2006)

Estimated monthly coal production for December 2005 was 90.3 mmst (see graph below). The December EIA estimate amounts to a 2.3 percent, or 2.1 mmst, decrease from November’s 92.5 mmst. The December production estimate is a hefty 5.1 mmst below that of December 2004. Preliminary estimates of the year’s production totals 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 final mine-level reports for 2004 by the Mine Safety and Health Administration (MSHA), EIA Weekly Coal Production estimates through the end of 2005, and revisions to EIA estimates based on initial MSHA mine-level surveys for 1Q2005 through 3Q2005. 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.

Note: This graph is based on MSHA-based revisions for all quarters of 2004, for the first through third quarters of 2005, and on preliminary EIA production estimates through December 2005.

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.

In the PRB, Basin Electric Cooperative expects to submit a siting permit in January for a 375-megawatt coal-fired minemouth plant north of Gillette, Wyoming. The plant would burn an estimated million tpy of subbituminous coal from the nearby Dry Creek mine and transmit the generated power to the western part of its service area (Coal Outlook, November 28, p 6).

The fact that rising prices of basic mining materials - steel, diesel fuel, explosives, for example - have helped swell coal prices was noted here in the past. A greater concern, however, is the unavailability of key materials, especially steel and rubber. The biggest impact may be experienced in severely delayed or incomplete deliveries of new equipment. Slowed specialty steel deliveries delay assembly of new equipment. Mine trucks and other rubber-tired equipment have been delivered without tires, which may not be available until 2006 or 2007.

An informal search found that a critical scarcity of the enormous tires needed for mine trucks has been an issue at least since early 2005. On March 18, Argus Coal Daily (p 3) noted that PRB mines' capital costs were increasing as a result of "heavier equipment to mine through thicker overburden (and) of the increased cost of steel, rubber and other commodities." Further, mine operators were finding that key equipment was becoming unavailable regardless of cost: "The tires needed for the extremely large surface-mining equipment and trucks are proving to be difficult to acquire not only in Wyoming but globally, with Asian miners saying they, too, are having trouble keeping their trucks shod." Mine operators in the PRB and Appalachia had become accustomed to delays in delivery of new tires and to having old tires repaired or retreaded. Because it is remote from most suppliers, the 30-million-tpy Cerrejon mine in Colombia employs 1/3 of its 3,600 blue-collar labor force repairing and rebuilding equipment. That includes retreading their own mine truck tires, the number of which doubled to 280 in 2005 (U.S. Coal Review, March 21, pp 18,19). By May, ILB mine operators wanted to increase production to meet growing demand but "they can't find rubber tires, they can't find equipment, and they can't find people. They're robbing from one another," according to one source. And, it was reported that "It's gotten so crazy, I've heard of people taking delivery on pieces of equipment that don't even have tires on them" and tire dealers were offering to buy used tires from idle or inoperable equipment (Coal Outlook, May 30, p 1).

By October, the wait for new equipment, such as an earth scraper, which had previously been 8 or 10 weeks, was up to 52 weeks. This was not "a new story" and - although sudden increases in coal demand was a factor - it was rumored in the coalfields that Chinese industrial expansion had taken all the equipment. New haul trucks were still being delivered without tires, and steel in the form of spare parts and replacement engines were unavailable (U.S. Coal Review, October 24, pp 1, 15). There has been no change as the year-end nears. "One major coal producer is parking its big trucks on rainy days to preserve tires" another hopes to reduce wear and tear by putting chains on its big tires and "carefully monitoring maintenance." The shortages in tires and steel products extend beyond the coal industry, of course, but the fact that the problems are widespread apparently is not enough to improve their prospects. The outlook for tires is reportedly that Goodyear is sold out through 2006 and Michelin through mid-2007, even though Michelin is constructing a new tire plant in Brazil and planning one in South Carolina. Bridgestone says it will expand three "big-tire" plants in Japan. Even with those efforts, industry sources expect the global shortage not to be totally resolved until 2010 (Coal & Energy Price Report, December 14, p 3).

Transportation (updated January 13, 2006)

At the McCloskey U.S. Coal Imports Conference 2005, in Baltimore on November 30 and December 1, coal terminal operators confirmed plans to add more coal import capacity along the U.S. Gulf and Atlantic coasts. Kinder Morgan is expanding terminals along both coasts. The most imminent is the expanded Fairless Hills terminal on the Delaware River in Pennsylvania. Final permits are expected in time for a January 2006 restart of the 2 million short tons per year (tpy) capacity, double its previous size. McDuffie Terminal in Mobile, Alabama, is increasing its capacity during 2006 from 16 million to 18 million tpy, along with adding a new loading and unloading berth, additional stackers/reclaimers, a third barge unloader, and unit train loading. For 2007-2008, McDuffie plans include a new blending belt between two of its yards and attracting additional rail carriers. Dominion Terminal Associates (DTA) in Newport News, Virginia, expects construction or installation to begin in spring 2006 on transfer towers, conveyors, belts, two additional cranes, and a 600-foot pier lengthening. The project in-service date is mid-2007 with new capacity at 7 million tpy, up from 5.2 million tpy in 2003. The Point Tupper terminal in Nova Scotia added a Belgian E-crane in 2005 and was improved to permit docking of cape-size vessels. The terminal does not have loading, transfer, or vessel-to-vessel transloading capabilities, but the facility management firm, Savage Industries, indicated willingness to expand in those areas to meet demand. At least one coal-fired power plant in Massachusetts has been known to import Indonesian coal by way of a Nova Scotia port and stored it there. Smaller transshipments are made to the power plant as needed.

The Dakota, Minnesota & Eastern Railroad (DM&E), along with its sister railroad, the Iowa, Chicago & Eastern, applied for a $2.5 billion loan from the Federal Railroad Administration to build a third railroad into the Powder River Basin. The loan would virtually guarantee the fruition of the DM&E’s years of effort, which started in 1998. 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. In April, the Surface Transportation Board reaffirmed its approval of the DM&E project to build a third PRB line. DM&E is filing for the loan under a provision authored by Senator John Thune, R-SD, that was part of the $286 billion Transportation Reauthorization bill enacted earlier this year. Senator Thune stated, “This project could transform South Dakota’s economy for generations” (Coal Outlook, November 14, pp 10-11).

Previous Coal News and Markets Reports

Contact(s):

Rich Bonskowski
Phone: 202-287-1725
Fax: 202-287-1934
e-mail: Richard Bonskowski

Bill Watson
Phone: 202-287-1971
Fax: 202-287-1934
e-mail: William Watson