Coal Prices and Earnings (updated April 13, 2005)

Average spot prices for Powder River Basin (PRB) coal continue moving upward. For the week ended April 8 (see graph below) the average price for PRB 8,800-Btu coal for prompt quarter delivery gained another $0.35, up from $7.14 one week earlier. The rise in spot prices since the week ended February 18, now amounts to $1.31 per short ton -- a 21% increase over the $6.20 price 7 weeks earlier. The average spot price for the Central Appalachia (CAP) coal indexed by EIA rose in the week ended April 1, from $62.35 to $62.85 per short ton. That price remained at $62.85 last week. All other average spot prices tracked by the Energy Information Administration (EIA) were again unchanged. The average prices in Northern Appalachia (NAP) and the Illinois Basin (ILB) in the East remained at $ 57.00 and $37.00 per short ton, respectively. In the West, the Uinta Basin (UIB) average spot price held at $29.00.

Rising PRB prices in recent weeks may signal a long-expected rationalization in prices for what has become the preferred low-sulfur coal for power generators and large industrial coal boilers. The price increases follow months of conjecture by analysts over flat spot prices in the PRB while other spot coal prices rose. Argus Coal Weekly took note that “PRB prices are at their highest in a year,” stating that “The showdown between high and low-sulfur coal has begun” (April 1, p 1). By its count, as many as 24 generators tested Wyoming coal in 2004, many of which are now switching to PRB coal. Reasons cited for the price increases are numerous. They include the supply shortages of Appalachian coal and improved assurance of PRB deliveries, based on better western rail performance so far this year. Further, soaring SO₂ allowance prices (currently above $700 per short ton) increase the value of inherently low-sulfur coal, while the new Clean Air Interstate Rules (CAIR) will effectively retire one half of existing regional allowances¹ by 2010, driving up the cost of those allowances. Finally, although the Clean Air Mercury Rule issued March 15 by the Environmental Protection Agency mandates lower mercury emissions for all coal, the reductions required for bituminous coal are stricter than for lignite and subbituminous coal (such as in the PRB)².

The greatest restraint on PRB prices may be the rising rail transportation rates – not necessarily good news for coal buyers because apparently transportation costs for many are increasing faster than coal prices. Sources at coal-fired power plants report that the greater portion of their cost increases for PRB coal is in railroad costs. Some instances of doubling of rates are claimed, but rate increases of “20 to 25 percent,” on average, are said to be common. In addition, coal buyers are also paying fuel cost adjustments on all new contracts and much stricter limits on unloading time before demurrage charges kick in (U.S. Coal Review, April 4, pp 7, 21).

Until the week ended April 1, PRB coal had been the only commodity showing contango in its spot prices, the condition where forward prices exceed spot prices. In terms of supply and demand, contango is typical when supplies are adequate for demand and some analysts believe an upward trend, especially if exceeding interest rates, is a prime indicator of increases in future contract prices. CAP and UIB coals now show mixed or limited forward prices for late 2005 and for 2006. This may indicate at least some increased availability resulting from reported expansions of mine capacity in the past 4 months. The entire suite of PRB spot prices is rising – prompt quarter (see footnote 1, above), 4Q2005, 1Q2006, and calendar year 2006. For example, forward spot prices are $7.70 per short ton for 4Q2005 , $8.21 for 1Q2006, and $8.27 for calendar year 2006 delivery (Coal Outlook, April 11, p 2).

On the other hand, NAP, ILB, and discrete coal supplies in other regions, which currently show little or no change in the out quarters and calendar year 2006, may still be recovering from the coal production and/or delivery delays of 2004.

Market Developments (Updated April 13)

Demand for coal-fired generation this summer in and around the Pacific Northwest should be higher than in recent years, but not enough to cut significantly into coal supplies. A drought in that region generally results in increases in coal shipments to western power plants and in increased coal-fired generation to compensate for curtailments at the region’s many hydroelectric generators. Water normally drives more than half the electricity generated within the region, which is in its sixth consecutive year of low precipitation (see drought map below).

Source: http://www.cpc.ncep.noaa.gov/products/expert_assessment/seasonal_drought.html

The winter of 2004/2005 created the lowest cumulative runoff on record (Bonneville Power Administration, Press Release, March 24). Because of heavy rains in parts of the region in March along with continued deficits in mountain snowpack, however, there is no longer a consensus among drought forecasters, whether this summer will be the driest on record or merely dryer than normal (National Weather Service, Climate Prediction Center, http://www.cpc.ncep.noaa.gov/products/expert_assessment/DOD.html ). In either case, stream and lake levels are expected to be as low or lower than in 2001, the year when the electricity crisis in California was attributed in part to low regional hydroelectric generation and reduced cross-border power sales were contributing factors.

The graph below shows electricity generation from 1990 through 2004 in the hydroelectric, coal-fired, and natural gas sectors. Note that coal-fired generation is included for the Pacific Northwest and California hydroelectric-rich States and for four adjacent States that are the primary sources for supplemental coal-fired electricity sales. The year 2001 marked the end of a 3-year, 88 Megawatthour decline in hydroelectric generation and illustrates a clear relationship between natural gas-fired and hydroelectric generation. When hydropower is plentiful, natural gas generation is taken off line, but when hydropower is constrained, natural gas generators are pressed into service throughout the service area, which is expected this year. Natural gas-fired generators are generally smaller and more disbursed than most coal-fired units, and can more quickly dispatch. The Bonneville Power Administration notes that “Although the addition of gas-fired turbine generators in the region since the drought of 2001 has helped beef up supply, reliance on gas-fueled combustion turbines at a time when natural gas prices are extremely high increases costs” (Bonneville Power Administration, Press Release, March 24).

Coal-fired generation has trended higher in recent years, but it responds only weakly to the annual fluctuations in hydro. EIA long-range forecasts do project steady growth of coal-fired generation continuing in western States. Coal-fired generation has been increasing at about the rate of overall electricity demand in western States. It shows only limited response (roughly 5 million Megawatthours, equivalent to 2.7 million tons of western coal) to yearly hydroelectric fluctuations. That amount of coal equates to 0.6% of PRB coal production in 2004.

An analysis of 10-K filings with the Securities and Exchange Commission, by Argus Coal Weekly, reveals that even before the end of March, most 2005 U.S. coal production has been committed and priced. Companies in the study include most of the majors: Alliance Resource Partners, Alpha Natural Resources, Arch Coal, Consol Energy, Foundation Coal, Massey Energy, Peabody Energy, and Westmoreland Coal (Argus Coal Weekly, March 24, p 3). The highest percentage of 2005 production still uncommitted was 10%, or 16 to 18 mmst.

The NAP coalfield is well positioned to respond to increased demand for high-sulfur coal. In that region, more capacity could be opened or reopened more readily as spot and contract prices rose. This would especially benefit established customers in nearby States in the Northeast, where CSX Railroad is the predominant rail carrier. In the latter months of 2004, CSX improved its carloadings of coal after more than a year of service problems. This fact has apparently encouraged both power producers and other industrial coal customers to reenter the NAP market. According to Energy Publishing's interviews, however, the CSX improvements have taken concerted efforts and the railroad's capacity problems are far from resolved, so there it is likely that added coal deliveries in 2005 could again surpass CSX capacities (U.S. Coal Review, December 27, pp 4, 13).

Analysts believe that hoped-for improvements in 2005 in rail equipment and personnel will help in rebuilding consumer stockpiles, although not enough to reach their targeted levels. On the other hand, with service improvements on CSX lines, buyers reported that some suppliers did not in fact had coal on hand when trains arrived at mines or loadouts. It is likely that the highly publicized problems that the eastern railroads had keeping up with demand in 2004 masked the reality that some producers were still not able to produce coal at levels for which they had contracted.

At the EUCI conference, “Coal: Volatile Markets & New Fuel Supply Patterns,” on February 23 and 24, the audience was primarily fuels buyers, engineers, and executives from major electric power producers and industrial plants. This demand-side audience was receptive to several speakers who recognized that coal prices during 2004 were driven up in part by coal supplier contract abrogations and bankruptcy filings. Panel discussions and Q&A largely involved strategies better to secure reliable supply contracts at assured prices. Jerry Eyster of PA Energy Consulting said that supplier credit worthiness a new reality that coal customers must contend with. He noted that even dealing with financially stable, well capitalized coal suppliers may not alleviate buyer risk. In the low-profit coal markets still typical in 2000 through 2003, a number of conservative, well-run companies divested themselves of coal properties and some new owners used highly leveraged financial instruments or risky business practices.

Alternatives to CAP coal was a major topic. Mr. Eyster noted that contract prices for buyers of CAP compliance coal increased by 34% between 2000 and the third quarter of 2004, compared with 12% for ILB coal and 1% for PRB coal consumers (SNL Energy Coal Report, February 28, p 20). Jay Lindgren of RW Beck stated that recent spot coal price volatility has been as high 56%, following many years of low volatility, typically around 7%. In panel discussions on coal procurement strategies it was noted that PRB coal is making further inroads in Appalachia itself: Allegheny Energy recently bought and marketed 1 mmst of PRB coal in Pennsylvania, “right in Consol’s backyard.” According to Trygve Gaalaas of PACE Global Energy Services, as many as 20 power plants that have always used Eastern coals are currently planning to test PRB coal. For PRB coal the procurement process usually involves significant changes at the plant – 40% or so more rail car or barge capacity; longer shipping times; additional storage space for the coal; higher capacity handling, moving, and grinding equipment; new dust suppression equipment; possible boiler modifications and control system changes; and even a different type of fly ash to market or dispose of.

Coal exports for 2004 were up by 4.6 mmst over 2003, most of which was bituminous coal from the eastern U.S. (National Mining Association, International Coal Review Monthly, February 2005). Considering that production east of the Mississippi increased by 17.1 mmst (see Coal Production below) most of that increase was sold in the United States. Steam coal exports actually declined slightly, as metallurgical coal exports increased by 4.7 mmst over 2003. That 4.7 mmst increase in met coal exports left primarily via Hampton Roads and Baltimore and put severe strains on the rail distribution of domestic coal, partly because of the extra trainloads but largely because the railroads had not been prepared for the change in shipping patterns. The demand for met coal exports is greater in 2005 but at least this year there has been more advance notification.

Market analysts consistently predicted that international metallurgical coal prices would remain high in 2005, but the disruption at the Buchanan mine has sent a few buyers into the spot market with offers similar to those below. Two producers of premium U.S. met coal recently confirmed that their orders were again increasing and that buyers were bidding prices higher. Officials from both Drummond Coal Sales and PinnOak Resources noted that much of their 2005 production is becoming committed. Walter Schrage, Executive Vice President for Sales and Marketing, noted in reference to PinnOak's low-volatility product, “I'd say it wouldn't be lower than ($125 per short ton)” in 2005 (Coal Outlook, November 1, p 15). Jim Walter Resources in Alabama has announced major investments in its Blue Creek Number 7 mine to increase met coal production by 2.7 mmst by mid-2008 (Argus Coal Daily, December 16, p 1) and Quest Minerals and Mining is reopening its high-quality metallurgical sections at its Slater's Branch mine in eastern Kentucky, projecting 20,000 ton per month production by July 2005 (Coal Trader, December 17, p 1).

International met coal price speculation subsided some after Grand Cache and Western Canadian Coal Corporation announced contracts in South Korea, China, and Japan for 1.3 mmst of hard coking coal in 2005, priced at $125 Canadian per metric tonne (Coal Trader, December 17, p 1). Expectations for 2005 had been mixed because of the many unknowns, including: the impact of announced low coal and met coke exports from China; recent longwall problems and a continuation of infrastructure constraints affecting Australian met coal mines; broad and severe coal shortages that may, it is feared, reach “crisis” proportions in India, mostly for steam coal; uncertainty as to how much new met coal from U.S. production and new Canadian mines will be available; and the potential for escalation of U.S. exports because of the lowest U.S.$ exchange rate in 9 years.

Supplies have been further stressed by intractable shipping delays at Dalrymple Bay in Queensland, Australia, which may have worsened in recent months. The number of ships waiting to load has increased to more than 50 during the past month. It is not clear whether that confirms worsening delays in loading or simply the fact that customers are sending empty ships earlier to get better queue positions. The port at Dalrymple Bay receives coal by train from mines in central Queensland and ships metallurgical coal, principally to Asian ports. “Nearly five percent of all global coking coal trade is handled through Dalrymple, according to Bloomberg, and nearly 25 percent of the coal shipped from Australia” (U.S. Coal Review, March 28, p 14). The port owner, Prime Infrastructure, confirms that Dalrymple shipments were 11.3% behind contracted tonnage for the 6 months of July through December, 2004, (Company newsletter, “Prime Site,” December 2004, released January 11, 2005). At that rate, the shortfall in deliveries would amount to 6 to 7 mm tonnes per annum (tpa). The current port capacity of 53.6 mm tpa should increase to 60 mm tpa by January 2006 under ongoing improvements.

Western Canadian Coal Corporation announced on April 5 that it just concluded an export contract for low-volatile coal for pulverized coal injection (PCI) at Asian steel mills, covering the 12 months starting in April 2005 (SNL Energy Coal Report, April 11, p 19). The price, at over US$100 per metric tonne ($90 per short ton) is said to be in line with other recent coal contracts with Asian steelmakers, but is considerably higher than metallurgical coke prices of 18 months ago. Considering that the reason PCI coal is injected into blast furnaces, as a supplementary heat and carbon source, is to permit reductions in the requirements for more costly metallurgical coke, the current prices of PCI coal underscore the scale of coal and coke price volatility in the past year and a half. Earlier, at the annual met coal negotiations with Japanese steelmakers, Australian and Canadian suppliers were expected to receive $115 to $120 per metric tonne, F.O.B. dock, for 2005 deliveries, despite producer targets around $130 (Coal & Energy Price Report, December 2, p 3). At the ICCC Forum in Budapest in the second week in December, U.S. met coal producers and western European and South American steel mills reportedly negotiated “major” tonnage deals for prices exceeding $130 per tonne for fiscal year 2005 (U.S. Coal Review, December 13, p 2).

Coal Production (updated April 14, 2005)

The U.S. Monthly Coal Production (graph below) includes production based on mine surveys of 2004 Quarters 1 through 4 by the Mine Safety and Health Administration (MSHA). EIA estimates 2004 coal production of 1,111.4 million short tons (mmst), based on January through December production allocations. That is 39.7 mmst, or 3.7 percent, more than in 2003. Of the net increase, 22.6 mmst are attributable to production west of the Mississippi River. Annual 2004 production East of the Mississippi finished 17.1 mmst ahead of that in 2003.

The latest monthly production , for March 2005 was 96.1 mmst (see below). That is 3.9 mmst more tons, or 4.3 percent higher, than in March 2004. EIA estimates that year-to-date 2005 coal production (through April 2, 2005, versus April 2, 2004) is 282.2 mmst, versus 282.7 mmst in 2004. The lower production so far this year, at 0.5 mmst, represents impressive gains since February, when year-to-date production was 2.8 mmst less than for January through February 2004. Of the net difference, 5.3 mmst were attributable to less production east of the Mississippi River. West of the Mississippi, year-to-date production was 4.7 mmst higher than in the same period of 2004.

Note: This graph is based on MSHA-based revisions for quarters 1 through 3 of 2004 and preliminary EIA production estimates for October through December 2004 and January through March 2005.

Transportation (updated March 28)

Union Pacific (UP) is off to a much improved start in 2005, following a year of declining operational efficiency in 2004. Chief Financial Officer, Rob Knight, reported on March 22 that February was a record month for the average number of trains per day leaving the southern PRB -- 37 per day, compared with the previous month-long record of nearly 35 per day (Argus Coal Weekly, March 24, p 9). Both UP and Burlington Northern Santa Fe (BNSF) are shipping PRB coal at a faster rate than last year and are making trackage improvements in older roadbeds.

Railroads continued to deliver more coal than in the same period last year even though it is taking a bit longer for some of that coal to arrive. In the 4-week period ended March 12, 2005, the four Class I U.S. railroads loaded 9,684 more carloads than in the same period of 2004. More than 74% of the additional carloads were originated by the two western carriers, UP and BNSF. The increase in the West confirms greater activity at western mines but also reflects the lower-than-anticipated demand early last year, when large consumers of PRB coal reportedly felt that prices would soften further and delayed new purchases. BNSF average coal train velocity slowed by 4.5% compared with the previous 4 weeks and NS coal trains slowed by 1.3%. UP increased velocity by 1.3% while continuing to limit new PRB coal hauls. CSX improved slightly, by 0.6%, from 15.9 to 16.0 mph (Argus Coal Weekly, March 18, p 9).

Despite uneven service, resulting in unfulfilled expectations for many coal consumers, railroad freight volumes overall were up last year. For example, railroad files at EIA show that Union Pacific (UP) loaded 828,000 more tons of coal from March 2004 through February 2005 than in the previous 12-month period. UP loaded 1.9 mmst more coal in Wyoming and 1.7 mmst more coal in Colorado. At the same time, Utah coal loadings were down 2.0 mmst and Illinois down 0.8 mmst, period to period.

The additional 828,000 tons of coal were carried using 4,870 fewer carloads than 12 months earlier, owing to the drops in Utah and Illinois loadings, which average fewer tons per carload, while loadings increased in Colorado and, especially, Wyoming, which account for more tons per carload. Wyoming-originated coal averaged 117.0 tons per carload, up by 0.8 tons year over year. By contrast, Illinois-origin coal averaged 106.7 and Utah 108.4 tons per carload.

Following delayed CSX deliveries during 2004, Morgan Stanley upgraded the company’s investment rating on March 4, stating that “CSX is unlikely to under-perform” going forward, based on “robust demand,” favorable decisions in two recent rate cases, and an outlook for “strong customer pricing again in 2005” (SNL Energy Coal Report, March 14, p 14). In the West, southern Powder River Basin rail capacity is projected by the railroads and coal producers to reach full capacity in 2005, estimated at 350 mmst. During the 4 weeks ended March 5, BNSF coal carloadings were up by 9.7% while UP coal carloadings were 11.3% above the same period last year (Argus Coal Weekly, March 11, p 9).

The Tennessee Valley Authority (TVA) will consider increasing its fleet of coal cars by nearly 45% in 2005 in an attempt to improve transportation efficiency and decrease costs. TVA feels the anticipated lease of 1,375 additional coal cars would help it move various tonnages and types of coal to its plants more efficiently (Argus Coal Daily, March 17, p 4).

Meanwhile, despite widely noted concerns over aging waterways infrastructure and the aging and declining barge fleet, coal traffic on U.S. internal waterways was also higher in 2004 versus 2003. The Army Corps of Engineers (ACE) posts "tonnage indicators" for coal and coke, which are preliminary statistics extrapolated from usual routings and waterborne traffic patterns. The tonnage indicators are 144.0 units for coal and coke passed through ACE locks and tally points, up from 136.9 units in 2003 (http://www.iwr.usace.army.mil/ndc/wcsc/wcmcoal.htm). Those statistics are related to millions of short tons but they appear in dimensionless units because the monthly data on which they are based cannot detect double counting or directional progress of barges, and are not accumulative over time. Data include barges going to transfer docks or Great Lakes or tidewater piers for export. The 7.5 unit difference, year over year, equates to a 4.5% increase.  The percentage of increase year over year is useful and valid information, but ACE statistics should not simply be equated with validated distribution data for U.S. coal to final destination. Besides their preliminary nature, the ACE statistics include minor unknown tonnages of coke and of coal shipped to intermediate storage or blending facilities before final delivery .

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¹ Under CAIR, the calculated regional budget for SO₂ emissions applies specially-designed allowance retirement ratios of 2:1 to existing Acid Rain Program allowances beginning in 2010, increasing to 2.86:1in 2015 and beyond. These ratios were developed to cut the allowance emission levels by half beginning in 2010 and by 65 percent beginning in 2015. (Environmental Protection Agency, Technical Support Document for the Clean Air Interstate Rule, Notice of Final Rulemaking, “Regional and State SO₂ and NOx Emissions Budgets” (Washington, DC, March 2005)).

² Under the Clean Air Mercury Rule (40 CFR Part 60, subpart Da [Amended], §60.45a), the new source standards are 145 for lignite-fired units, 42 to 78 for subbituminous-fired units, and 21 for bituminous-fired units (all expressed as 10^-6 lb Hg/MWh).

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Rich Bonskowski
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