Coal News and Markets
Coal News and MarketsWeek of January 1, 2006
Coal Prices and Earnings (updated January 6, 2006) Following a break in coal spot price reporting in the week ended December 23, 2005, new movement was seen in key prices for the business week ended December 30, 2005. The Powder River Basin (PRB) average spot price for 8,8000-Btu product finished the year at an unprecedented high. In the business week ended December 30, PRB coal spot prices continued their pre-Christmas escalation, again surging higher by $2.00. Average spot prices climbed from $14.48 to $16.48 then, after the holiday break, to $18.48 per short ton. The average spot price for the Central Appalachia (CAP) 12,500-Btu rail coal tracked by the Energy Information Administration (EIA), declined to $58.25 per short ton, losing $0.75. This was in addition to the $3.00 per short ton loss 2 weeks earlier. The average spot price for 11,800-Btu Northern Appalachia (NAP) rail coal broke away from the $44.00 mark it had held since October 15, 2005, and sold for $45.00 per short ton. There were no changes in the spot prices tracked by EIA in the other coalfields. The Illinois Basin (ILB) spot price was unchanged at $36.00, and the 11,700-Btu Uinta Basin (UIB) coal average spot price is still $37.00 per short ton (all for prompt-quarter delivery, Coal Outlook, January 2, p 2).
Market Developments (updated January 6, 2006) From the week ended December 9 through the week ender December 30, the average spot price for the 8,800-Btu PRB coal tracked by EIA jumped by $4.00 per short ton. Over the past 12 months, that spot price tripled, going from an interim low of $5.75 for the week ended December 24, 2004, to $18.48 for the week ended December 30, 2005. The price rose slowly at first – it did not double until the week ended September 23, 2005 – then reached the tripled level in just another 14 weeks. For coal, and especially for PRB coal, that degree of price volatility is unusual. Once before, in 2001 during the period of extreme natural gas price spikes and the California electric power crisis, PRB prices doubled, then tripled. In that case, however, both the rise and the subsequent decline were more rapid. Moreover, they were related to sudden changes in the natural and power markets that were seen as transitory. The 2005 PRB price increases were related to more fundamental factors, such as months of diminished PRB coal shipments due to rail problems, entrenched coal inventory shortages in the consuming sectors, capacity constraints for Appalachian low-sulfur coal, sustained high oil and natural gas prices, and elevated sulfur dioxide allowance prices. The price surge in October may have been prompted by localized shortages of low-sulfur coal and by the record price inflation in sulfur dioxide (SO2) emission allowances, which some analysts feel are partly driven by hedged transactions. Those rising costs in turn were aggravated by a sudden run on coal supplies. Industrial consumers and power producers could not secure enough natural gas following widespread damage in the producing area by the late summer hurricanes in Louisiana, Mississippi, and Texas. Vacillations in the past several weeks in PRB spot prices may be related to rail capacity. There are very few new coal-haul slots the Burlington Northern and Union Pacific railroads can add in 2006 and, during October, the Union Pacific reported a decline in shipments because of flooding in Kansas, three derailments (one of which affected all three Joint Line tracks), and some remaining effects of Hurricane Rita. It has been reported that some coal buyers agreed to price increases of $5.00 to $6.00 per ton for PRB coal for 1Q06 delivery. According to one source, "I can only think the reason for that is people think they will be able to get coal delivered in Q1 of 2006, whereas now, nobody is buying because they can't get it delivered in Q4 of '05." It is not clear when the higher prices were negotiated. They may be later instances of the October price jumps reported by Platts, but there are other indications that prices will be higher in 2006. Customers are finding that in 2006 mine operators will not honor 2005 contract prices for coal that did not get shipped in 2005. Shipping contracts are generally the coal buyer's responsibility and, unlike in the past, mine operators are not willing to roll over 2005 coal and prices just because customers were unable to get it shipped in 2005. Replacement coal for 2005 short inventories will be sold at 2006 prices (December 6, pp 1-2). Further, the reality is that even the partially rebuilt southern PRB rail routes cannot ship enough PRB coal going forward to restore adequate coal inventories before the end of 2007. Data on coal sold at spot prices are company-confidential but the amounts probably vary widely and declined at the end of the year as coal consumers turn to multi-year contracts with escalation clauses. On December 20, the 8,800-Btu PRB coal passed a new milestone in the over-the-counter (OTC) markets - its price for 1Q2006 transactions exceeded $20.00 per short ton for the first time (Stifel Nicolaus, Mining report, December 21). Benchmark PRB prices for calendar year 2006 delivery rose about $2.00 per short ton, to approximately $21.00 (Stifel Nicolaus, Coal Supply and Demand Indicators, December 29). An explanation from trading market observers is that some traders' positions are currently short or flat for early 2006 coal because they sold short when the OTC price for that PRB coal dipped nearly to $14.00 a few months earlier, with expectations to cover their positions later. PRB producers, however, are selling their unobligated coal in the term market, under at least 2- or 3-year contracts. Because most 1Q2006 positions are covered, traders noted that OTC prices in early 2006 are subject to a wide range of plausible prices and could settle as low as $15.00 or as high as $25.00 per short ton (Coal & Energy Price Report, December 21, pp 2, 3). On December 31, at midnight, the only remaining coal-fired power plant owned by Southern California Edison (SCE) will cease operations. Whether the shutdown of SCE’s Mohave Generating Station is permanent or temporary remains to be seen. The circumstances are complex. Ostensibly, the shutdown is being triggered by the failure of SCE to install court-ordered pollution control equipment – flue gas scrubbers, fabric filters, and low-NOx burners that would cost $1.2 billion according to SCE spokesman, Don Hendren (The Laughlin Nevada Times, “It’s Official: Generating Station to Close,” by Stacey Bonnar, December 14). The equipment installation deadline was December 31, 2005. In reality, SCE has not refused to comply: back in 1999, the power plant agreed to make the changes. At that time it operated as a deregulated merchant power generator, but subsequently ownership of the plant changed and it was re-regulated by the California Public Utility Commission (CPC). When the CPC became the regulating authority, it refused to approve the installation of the scrubbers agreed to by the plant, because the coal supply for the plant is itself in doubt. The Mohave Station receives all its coal from the Black Mesa coal mine in northeastern Arizona, which is operated by Peabody Coal Company on lands leased from the Navajo and Hopi Indian Nations. Normally, shopping around for a new coal vendor is a resolvable problem, but not in this case. The Mohave plant burns coal slurry – a finely ground coal and water mixture - that has been transported the 273 miles from mine to power plant ever since 1970 via the Nation’s only operating coal slurry pipeline. The Mohave plant has all the equipment needed to receive, dewater, and feed coal slurry to its boilers. It is not equipped to receive or process coal delivered by other transportation modes. The reason that relationship is now an issue is that the Hopi Nation is no longer agreeable to the mining terms, recently under renegotiations, that supply make-up water for the coal slurry from deep groundwater wells drilled into the “N” aquifer. This is the same aquifer from which both Hopi and Navajo people draw most of their water for domestic and municipal uses. Further, the Hopi and Navajo Nations do not share equally in the terms of the original agreement permitting the coal mining. The Hopi, because of their geographic location on traditional agricultural lands, may be differently dependent on the groundwater from that aquifer than are the Navajo, and both Nations dispute some of the conditions and parceling within that and earlier agreements, originally set forth by the Bureau of Indian Affairs. Peabody Coal, the Navajo, and the Hopi have actions pending that could change the water source and/or the conditions for mining. Meanwhile, as local citizens are aware, Navajo and Hopi employees of Peabody stand to forfeit millions of dollars now going into the local economy and workers at the Mohave Plant would also lose their employment after mothballing of the plant. While these changes are ongoing, the U.S. Senate, under S.1003, The Navajo Hopi Land Settlement Act of 1974 Amendments, may be moving toward a resolution of terms of the 1974 Act. That sensitive, much-delayed resolution would require the relocation of thousands of Navajo and Hopi people. They have resisted relocation for 30 years and they contend that the “new lands” were contaminated in the 1970’s by radioactive wastes from failed mining impoundments. Until the final form of the S.1003 amendments is law, it is unclear how they will be received by the affected indigenous people of northeastern Arizona. Arch Coal said on November 14 its West Elk mine would be off line for at least six more weeks due to an unexpected increase in detected combustion gases. Previously, the company had estimated a shorter outage. One analyst estimates that Arch will have lost 1.1 million tons of coal production from the West Elk outage by the end of this year. CONSOL Energy said, also on November 14, that repairs at the Buchanan mine will not be completed until mid to late December, rather than mid November as originally thought. The skip hoist damage of September 16 will require full replacement instead of repairs only (Legg-Mason, Mining advisory, November 15). Buchanan normally produces 350,000 to 400,000 short tons per month of low volatile metallurgical coal. This is the second time this year that the mine is out of commission; "no meaningful inventories" were available from Buchanan at the time of the mishap (Coal Trader, October 28, p 4). Lower current coal demand in Europe has given South American and, now, Russian low-sulfur coal producers incentives to offer more coal and competitive prices for the U.S. import market (U.S. Coal Review, November 7, p 4; Coal Outlook, November 14, p 8). Russian producers are offering coal at a delivered price of about $60 per metric tonne CIF US and some sales reportedly have been made. Platts assessed a sample of Russian coal as 11,500 Btu per pound, 1 percent sulfur, and 16 percent ash. Public Service Electric & Gas of New Jersey has purchased "one lot each" of Russian and Polish coal, described as high-Btu coal, for presumable test burns at its Mercer plant (Coal Trader, December 9, p 3). In metallurgical coal markets, after the Pinnacle mine encountered a rock offset at the longwall, a company official said on November 8 that the low roof area had reduced production to 80 percent of capacity. The longwall plow is expected to have mined through the rock intrusion after only two or three shield widths, which meant that mining should be through it "pretty soon." The official said that shipments of its low-volatile met coal had not been delayed and that stockpiles were sufficient to sell off some end-of-year "opportunity tons" (U.S. Coal Review, November 14, p 18). CONSOL Energy said on November 14 that repairs at the Buchanan mine will not be completed until mid to late December, rather than mid November as originally thought. The skip hoist damage of September 16 will require full replacement instead of repairs only (Legg-Mason, Mining advisory, November 15). The skip hoist lifts the coal 1,780 feet from underground to the surface, equal to the height of a 148-story building. Buchanan, which normally produces 350,000 to 400,000 short tons per month of low volatile metallurgical coal, has invoked force majeure provisions while the mine is idle (U.S. Coal Review, November 21, p 3). This is the second time this year that the mine is out of commission; "no meaningful inventories" were available from Buchanan at the time the mine was idled (Coal Trader, October 28, p 4). In international markets metallurgical coal demand expectations are varied and mixed. The core issue is that 2005 domestic steel production in China has been well above projections, resulting in a glut of steel despite China’s current position as the world’s largest consumer of steel. 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. Summer coal inventories at electricity generating plants generally reach their low point in August or September each year. In 2005 that low point was in September, which ended with 98.1 mmst, or 33 days' supply (see graph below). That was slightly above the winter low point of 97.9-mmst this past January, also a 33-day supply. In terms of number of days’ consumption though, the summer low point occurred in August, which fell to 31 days’ of coal. Even though September coal inventories were 1.4 percent lower, the days’-supply low point occurred in August because the rate of coal consumption in August was 9.9 percent higher than in September.  Trade reports in August estimated that coal-fired generator stocks had reached 30 days' supply on average (which was close), and around 10 days' supply in isolated cases. Stockpiles usually decline through September. This year they were expected to have declined more than usual based on above-normal cooling degree-days and high power generation rates. During the shoulder months of October and November, power producers rebuild coal inventories as much as possible. The ongoing need to replenish inventories is expected to keep spot and new contract prices firm through at least 2006. When the price of SO2 emission allowances rose to a new record high of $1,630 per ton on December 9, Platts Coal Trader observed that the price reached a level that long-term forecasters had projected for 2010 (December 12, p 5). By close of business December 13, the last settled price for 2005 SO2 allowances had retreated slightly to $1,615 per ton. Still, that was $245 higher than the price as recently as c.o.b. November 28 (Evolution Markets, December 14). Trading was moderate to light. Bids and offers for 2006 and 2007 allowances were discounted only $2 to $10 below 2005 vintage values. Year 2005 emission allowances of nitrogen oxide (NOx), by contrast, have trended down in price throughout 2005. The 2006 and 2007 allowances traded relatively level, and generally below 2005-vintage prices. NOx gases are formed primarily from combustion air and from subsequent chemical reactions in the atmosphere. Virtually no precursor free radicals of nitrogen are normally derived from the fossil fuels combusted, unlike SO2 emissions, for which the sulfur is contributed by the fuel and oxidized during combustion. NOx allowance prices offer a meaningful contrast with the behavior of the SO2 market during a year when low-sulfur coals were in short supply. Most of the new crop of flue gas desulfurization units currently under construction or planned (EIA identified 21.6 gigawatts planned as of late 2004) will be operational by 2011. Their influence could constrain high volatility in future SO2 emission prices. Unless market participants suddenly sell off SO2 allowances to generate end-of-year revenue, Evolution Markets sees the logical cap occurring 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). Dialogue between Platts and market players attributes the unprecedented price spikes to speculative trading by banks and hedge funds, which have at least doubled market activity since 2004. Traders also noted that although a large number of electric power producers intend to install flue gas scrubbers, many in that group may be scrambling to acquire needed allowances before the year-end compliance deadline (Coal Trader, December 12, p 5). 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 1, September 19). As a result, exports year to date at the end of June were nearly the same as in the same period of 2004: 24.93 versus 24.94 mmst. U.S. coal exports continue to be led by metallurgical coal, but the year-to-date totals are also very similar for met coal (15.25 versus 15.21 mmst in 2004) and for steam coal exports (9.68 versus 9.73 mmst in 2004). On the other hand, coal imports are up appreciably for the first 6 months of 2005: 14.84 versus 12.18 mmst in 1H2004, an increase of 21.8 percent. The graph below, and its downloadable data file include data available through September 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. 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, traditional 12-month contracts, and not just spot shipments, variances are less extreme than in some spot price reports.
Coal Production (updated December 22, 2005) Estimated monthly coal production for November 2005 was 92.5 mmst (see graph below). The November EIA estimate amounts to a 1.6 percent, or 1.5 mmst, increase from October’s 91.0 mmst. The November production estimate is within 50,000 short tons of the November 2004 production, for no significant difference. Year-to-date production maintains a 8.2 mmst, 0.8 percent, lead over January through November 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), 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.
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 has increased in 2005. In West Virginia, eight State permit applications are up for review, with comments due in early- to mid-December. The Corps of Engineers has seven coal-mining-related Section 404 permit applications - to deposit fill material in surface streams or drainage areas - pending for early December action. Four are in West Virginia, one in eastern Kentucky, one in Ohio, and one in the western Kentucky (Illinois Basin) field. The Section 404 permitting process became backlogged in 2004 following a legal decision that halted permitting under streamlined "national" guidelines and forced resumption of individual environmental assessments. Tonnage projections are not available, but the 15 projects include underground, surface, mountaintop, and highwall/auger mines. Most are new, but three of the applications seek renewal, reissue, or expansion of existing permits (Coal Outlook, November 28, pp 4-5). On the bright side (for coal producers), most observers feel that the decision by of the Fourth Circuit Court of Appeals will clear away the backlog. On November 28, the Court reversed a lower court's restrictions on those "national" guidelines, known as the Nationwide Permit 21 (NWP 21). The decision is seen as an endorsement of the Corps' historical use of NWP 21 and as providing confidence in the future of the program (Coal Outlook, December 5, pp 1,16). Although most surface mines and some underground mines involve fill activity and require Section 404 permitting, mountaintop removal mining is the greatest beneficiary of the decision. In the mid-term, Massey Coal and the Eagle Ridge Development Group submitted State permit applications for a new deep mine and for a 36-acre surface mine, respectively, in southern West Virginia. The permits will require 6 to 12 months to process. In the near term, in eastern Kentucky, Quest Minerals and Mining will reopen its rehabilitated Slater’s Branch mine in early December and its joint-venture deep/surface Apollo mine by June 2006. The Slater’s Branch mine will mine about 600,000 short tons per year (tpy) and the Apollo operation is planned at 1.2 million tpy (SNL Coal Report, November 28, p 7). On November 17, Foundation Senior Vice President and CFO Frank Wood reported that there are plans to replace the Emerald longwall mine in Pennsylvania, when it runs out of coal in a few years. Emerald produced nearly 5.8 million tons in 2004. A new Pittsburgh-seam mine, will be developed in Northern Appalachia with capacity of 6 or 7 mmst per year and several hundred mmst of reserves. The new mine would probably be a more productive mine than Emerald. There are also plans in the area, if markets develop, for a conventional deep mine in the Freeport seam, with 2 mmst per year productive capacity and over 70 mmst available reserves. That mine could serve both steam and metallurgical coal markets, Wood noted. In Central Appalachia (CAP) the major project pending is in the 63.8-mmst “Harts Creek reserve,” which could support a 2 mmst per year operation. Asked whether production increases being planned by Foundation and other producers would lead to oversupplies of coal and resulting lower coal prices, Mr. Wood said that incremental expansions such as he outlined are not adding major new net capacity. He noted that in CAP, with dwindling reserve base and difficult permitting problems, “if you can just stay even, you’re doing pretty well.” On balance, he felt that CAP production is still likely to diminish (SNL Coal Report, November 28, pp 3-4). Five new mines are in various stages of development in Indiana. Solar Sources is preparing for a new 1 million-tpy surface mine and is in the planning stages for a new underground mine, to replace one that was closed in 2005. Sunrise Coal LLC opened the new Howesville underground mine in Clay County, which will produce less than 1 million tpy, and is planning to develop a slightly larger one in Sullivan County. Little Sandy Coal is considering reentering the coal mining business. It is preparing a permit application to open a new surface mine in Pike County. It is too early to project capacity of the mine or whether it would open in 2006 or later (Coal Outlook, November 28, p 5). In addition, Foundation Coal expects to increase production at its nearby Wabash deep mine in Illinois by about 300,000 short tons, to 2.1 mmst per year (SNL Coal Report, November 28, p 3). 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 growing 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 say 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 December 8, 2005)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. On November 18, Union Pacific Railroad (UP) Vice President Doug Glass announced that UP would lift force majeure restrictions on southern PRB Joint Line coal movements on November 24 if this year’s work is completed “as currently planned.” The embargo on new customers, however, declared last July 18, will remain indefinitely to protect existing customers. Since the track failures in May 2005 and the subsequent rebuilding program, the two PRB railroads – UP and Burlington Northern Santa Fe – have not been able to meet PRB coal demand. UP has estimated that is has shipped about 85 percent of scheduled coal trains since May. Extensive repair work is planned to continue in 2006. Based on customer declarations, Mr. Glass said that 2006 demand is more than 18 percent over projected 2005 shipments (SNL Coal Report, November 28, pp 1, 22). Great Lakes coal shipments are up by 9.2 percent through the end of October, compared with the same period last year. The January-October shipments of 35.0 mmst comprise the best running total since 2001 and are 4.8 percent ahead of the prior 5 years’ average (Lake Carriers Association, October Great Lakes Coal Report). 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). Keystone Industries LLC announced plans to build a new dry bulk import terminal in Jacksonville, Florida. The goal is to import as much as 6 mmst of Venezuelan coal per year. The purchase of the site is scheduled for February 2006. Plans call for one Panamax-capable berth to be operating 18 to 24 months later, and a second berth could be added if warranted. Plans include a rail loop capable of loading 100-car unit trains. Rail carriers include Norfolk Southern, CSX, and Florida East Coast Railroad. The terminal would handle coal, petroleum coke, and possibly other commodities (SNL Coal Report, October 24, p 11). Burlington Northern Santa Fe (BNSF) will convert its fuel surcharges for coal and agricultural hauls to a mileage basis on Janurary 1, 2006. BNSF executive John Lanigan characterized the new program as “more fair and equitable than the current percentage-based program (U.S. Coal Review, October 24, p 18). In testimony at the October 19 hearing to review the 1980 Staggers Act, the Surface Transportation Board (STB) heard strong complaints from groups representing captive shippers. Many electric coops are captive to a single rail provider and “have unreasonably high rates and non-negotiable terms of service dictated to them on a ‘take-it-or-leave-it’ basis,” according to Glenn English, CEO of the National Rural Electric Cooperative Association. Mr. English said that better rail service and greater capacity should not “be accomplished on the backs of captive rail shippers.” Calling STB’s “rate reasonableness” review procedure arbitrary and prohibitively expensive to shippers, Mr. English concluded, “ Our membership asks in the strongest possible terms that the board take corrective action to implement the clearly expressed intent of Congress that mandated protections against monopoly power and transportation rate fairness. . .” The statement of the Alliance for Competition said implementation of the Staggers Act “has resulted in less competition due to Class I mergers and regulatory approval of paper barriers neutralizing the ability of smaller railroads to compete with the Class I railroads . . .”(SNL Coal Report, October 24, pp 12, 13). The view of the rail industry, enunciated in the Association of American Railroad’s (AAR) September 2005 position paper, “Destructive Railroad Deregulation,” states that calls like those above for changes to the Staggers Act would lead to less competition and higher rates. For example, the AAR asserts that the railroads’ use of “’differential pricing’. . . is the fairest, most-pro-efficiency, and most pro-competitive pricing system consistent with the continued viability of freight railroads. All shippers, including those who pay a higher markup, benefit from the differential pricing because it maximizes the number of shippers who contribute to railroads’ huge fixed and common costs.” The AAR concludes that, because of railroads’ enormous infrastructure costs, “If shippers with the greatest demand for rail service paid less because of regulation . . . costs would not be covered, and private capital would flee the industry,” with the result that taxpayers would eventually have to make up the revenue shortfall. With the cooling of growth in the Chinese steel industry earlier this year, ocean bulk carrier rates declined. In August, however, China’s crude steel output hit a new record, up by 30 percent year-on-year to 30.5 million (Metric) tonnes. In September, the crude steel output nearly matched the record high, reaching 30.4 million tonnes. These compare with 29.2 million tonnes in July and correspond with intentional drawdowns of iron ore stockpiles (Simpson, Spence & Young, October 19, Website News). The use of iron ore stocks meant that China’s demand for bulk carriers had not yet affected rates. Logically, however, that ore would need to be replaced in 2006. Further, European steel prices have increased slightly in the second half of 2006 after most large steel companies cut production. U.S. steel prices are currently the highest in the world, but increased ocean shipments of low-cost steel from Asia are expected to reach the United States in coming months (Business Day, November 21). Indeed, international ocean shipping rates had begun to rise. Since July 30, when coal shipping rates from U.S. Gulf ports to the ARA (Amsterdam/Rotterdam/Antwerp) European gateway reached $11 per tonne, they had risen to over $18.00 by mid-October. Similarly, averaged rates from Hampton Roads to Japan, via 150,000-tonne Capesize vessels, having fallen to $22.50 in late July, rebounded to $42 per tonne by mid-October. More recently, however, rates have moderated, reaching about $16.00 for U.S. Gulf to ARA and about $33.00 for Hampton Roads to Japan, as of November 25 (Simpson, Spence & Young, Resources, Free Charts, accessed November 30). Chinese coke batteries have been producing excess coke again and have lowered prices by $100 cumulatively in 2005. Non-premium Chinese coke was recently available for $125 per tonne, f.o.b. dockside. Even with ocean shipping costs, coke at that price is less expensive currently than domestic coke, according to some U.S. buyers, and may spur more coke imports by U.S. customers (U.S. Coal Review, October 24, pp 5, 15). Environment (updated December 7, 2005)Secretary of Energy Samuel W. Bodman announced on December 6 that the Department of Energy signed an agreement with the FutureGen Industrial Alliance to build “FutureGen,” a prototype of the coal-fueled power plant of the future. The nearly $1 billion government-industry project is designed to produce electricity and hydrogen and to produce no emissions, including no carbon dioxide, a greenhouse gas. Possible site nominations will be solicited in early 2006, final site selection in 2007, and operations are planned for 2012, using cutting-edge technologies, including advance carbon capture and sequestration. The FutureGen Industrial Alliance will contribute $250 million to the project. Alliance members are: American Electric Power; BHP Billiton (Melbourne, Australia); CONSOL Energy; Foundation Coal; China Huaneng Group (Beijing, China); Kennecott Energy; Peabody Energy; and Southern Company (U.S. Department of Energy, Press Release, December 6). The December 12, 2005, edition of Business Week magazine highlighted climate change and how U.S. and foreign companies are addressing the issue. The lead article – one of 13 features on the climate change subject – finds that a “surprising number of companies in old industries such as oil and materials as well as high tech are . . . moving swiftly to measure and slash their greenhouse gas emissions,” even though current U.S. law does not require mandatory curbs. American companies following that approach are not just trying to win the approval of environmental proponents; they are doing so out of good business sense, with an eye on the bottom line. Bankers, insurers, and institutional investors have determined that the financial risks associated with climate change are too high not to start preparing. And, based on an informal poll, many technology and energy industry CEO’s expect the United States to impose mandatory curbs on carbon dioxide and other greenhouse gases (GHG), eventually. The rationale for cutting back on GHG production turns out to be sound economics, according to business leaders. Many measures taken achieve the GHG reductions in part by reducing fossil fuel consumption, often using low-tech, common-sense changes. For example, in 2002 International Paper increased the use of wood waste in its fuel mix (from 13 percent to 20 percent), with the result that carbon dioxide output went down, as well as energy costs. Alcoa, Incorporated, reduced GHG emissions by 25 percent and saved on energy costs by improving a key step in its aluminum production process (Business Week Online, “The Race Against Climate Change,” accessed December 7). Jim Rogers, the CEO of Ohio-based utility, Cinergy, supports mandatory national limits on carbon dioxide even though 95 percent of Cinergy’s electricity is produced by burning coal. He believes the political momentum in Congress to limit GHG is “unstoppable.” Further, the consensus of Mr. Rogers and his advisors at Cinergy is that global warming is real, is hastened by GHG’s from human activities, and that the science indicating that is unlikely to be refuted. Accordingly, Cinergy is making changes “actively and quickly.” Mr. Rogers said that a proactive approach can give a major GHG producer credibility, engender public good will, improve Cinergy’s negotiation position on spreading GHG reduction burdens to other industries, and decrease expensive lawsuits (Business Week Online, “Cinergy Answers Burning Questions,” accessed December 7). On November 22, Goldman Sachs called for the Federal Government to issue rules for a viable U.S. market in greenhouse gas (GHG) emissions. In its new environmental policy, the global investment bank and securities firm said, “Markets are particularly efficient at allocating capital and determining the appropriate prices for goods and services we purchase. The government can help the markets in this regard by establishing a strong policy framework that creates long-term value for greenhouse gas emissions reductions and consistently supports and incentives the development of new technologies that lead to a less carbon-intensive economy.” Goldman Sachs’ policy states that voluntary actions to cut emissions are inadequate and that the firm “will work to develop partnerships with other organizations to help identify and promote effective and efficient regulatory/policy approaches to reducing [GHG] emissions” (Coal Outlook, November 28, pp 10-11). The Department of Energy and the Environmental Protection Agency (EPA) encourage voluntary reporting and reductions of GHG. More than 70 U.S. companies have registered with the EPA’s Climate Leaders program, set corporate GHG reduction goals, and are measuring their progress through emissions inventories. In addition, more than one third of the State governments have enacted GHG reporting systems or expressed interest in GHG regulation or markets. Currently, U.S. policies on climate change are based on development of technologies to control GHG emissions or to avoid producing GHG’s in the first place. In June 2004, Then Secretary of Energy Spencer Abraham stated that because “the United States has a Gross Domestic Product of $11 trillion, with a desired rate of growth of at least three to four percent . . . we will unavoidably continue to generate substantial greenhouse gas emissions—despite pursuing greater energy efficiency and the use of alternative fuels—so long as we use traditional or conventional technological approaches.” Consequently, U.S. policy reasons: “the only possible path to offset these likely GHG increases is by developing truly transformational technologies that will bring us into an entirely new energy age. This is true, because no nation is prepared to trade economic growth, to mortgage its prosperity, for cuts in greenhouse gas emissions” ("U.S. Climate Policy: Toward a Sensible Center,” Conference, Brookings Institution). Secretary Abraham explained that the technologies developed under the U.S. approach would be even more beneficial “in many developing countries, which are moving toward an explosive burst in energy demand, but lack many of the efficiency measures we have deployed here in the United States.” The Chicago Climate Exchange (CCX) is North America’s only multi-sector market for reducing and trading greenhouse gas emissions credits. Members of CCX make legally binding commitments to establish a rules-based market for reducing greenhouse gases and include a cross-section of North American corporations, municipalities and other institutions. The CCX market gives members a way to receive credit for reductions, to buy and sell credits, and thereby to determine the most cost-effective means to achieve emission reductions. Its members include Ford Motor Company, International Paper, and American Electric Power, the country’s largest coal-burning utility. On November 21, the Ohio Air Quality Development Authority joined CCX as an associate member. The authority is the first major state-funded coal research and development organization to join the CCX program. Associate members produce small or no direct emissions; they commit to comply with CCX rules by offsetting the greenhouse gases associated with certain business-related activities (SNL Coal Report, November 28, pp 18-19).
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