Power Measurement
What's causing price volatility, and will it last?
Coal markets have changed dramatically in the last year, but uncertainty lingers over how permanent the changes will be. After relative stability in the 1990s, coal markets, like other energy commodities, have become increasingly volatile, although high prices should not be confused with increased volatility.
We have seen coal price volatility before. As recently as late 2000 and early 2001, coal prices rose to levels as high, and in some coal supply regions even higher, than today's prices. However, those coal price spikes always receded quickly to pre-spike norms, and volatility disappeared.
What are the key drivers of these coal markets? Why have coal prices risen so much, and how long will they remain at their lofty levels? The answers to these key questions help us understand the effect that coal markets have on power markets.
Heavy Reserves
Coal reserves are abundant in the United States. Researchers estimate that the demonstrated U.S. coal reserve base exceeds 250 billion tons, which correlates to more than 200 years of supply at today's production level. Clearly, the United States will not run out of coal for a very long time, though the cost of recovery will increase as better, more easily mined reserves are depleted. Today's high prices are likely to persist for about 30 months, after which several factors are expected to contribute to a fall in coal prices: expectations of falling natural gas prices, persistent ready coal supply in excess of demand (especially in the West), and predictable high levels of competition by coal suppliers.
Natural gas prices are an important driver of coal markets. Gas prices create the opportunity for increases in coal price, but they do not push those prices one direction or the other. For example, while Eastern bituminous coal prices have been very high during this long period of high natural gas price, Powder River Basin (PRB) coal prices have remained stubbornly low. Other conditions must exist for coal prices to move. Gas prices effectively set a cap on coal prices, where the sum of the delivered coal price and the cost of other externalities associated with coal (such as any required SO2 or NOx allowances) cannot exceed the natural gas price without creating an incentive to reduce coal burn in favor of natural gas burn.
Economic conditions and weather are key price factors. Nearly 90 percent of the coal mined in the United States is burned by U.S. electric generators. (Small amounts of coal are used in steel-making, industrial plants, and in the residential and commercial sectors. Small amounts of coal are also exported to steel-making and steam-generating customers. See Figure 1.) Coal markets are clearly dependent upon the electric generation industry, which makes them dependent on the level of electric sales. As the U.S. economy improves, coal burn usually increases; the converse also is true.
Weather can be a short-term modifier of coal markets in two ways: Abnormal weather can increase or decrease the demand for electricity, depending upon the season, and adverse weather can effect coal-mining operations, creating temporary but significant coal supply shortages that can cause brief price increases.
Coal supply is the most important factor affecting coal markets. Where abundant, readily available coal exists, prices remain relatively stable in the face of natural gas price increases. Where supply is seriously constrained, coal prices react quickly to changes in natural gas prices. Where coal is abundant but not readily available, some price response to change in natural gas price should be expected over time. Note that coal is abundant and readily available in the PRB (though not always readily transportable, since railroad delivery capacity can be an issue) and that PRB prices have refused to rise in response to persistently high natural gas prices. Note also that Central Appalachian coal prices are very high now, in part because the supply is declining and barriers to new market entry exist in that region.
Put simply, if aggregate coal-mine ready capacity (not production) in a supply region is equal to or less than demand for coal from the region, then coal prices will react quickly to changes in natural gas price. If aggregate coal-supply region-ready capacity significantly exceeds demand, natural gas price will not greatly affect coal price until that ready capacity diminishes. A discussion of individual coal supply markets follows below. (.)
Eastern Coal: Prices Heading Skyward
Central Appalachia (CAPP) historically has dominated Eastern coal supply. Recently, though, CAPP has experienced production declines that will continue in the future. CAPP production is falling due to the shortage of easily mineable coal reserves (especially low-sulfur reserves), the detrimental effect on new market entry of "mountain top and valley fill" environmental regulation, and the high cost associated with mining thinner and thinner seams (as evinced by declining mine productivity in CAPP). Because of the above, generally, floor prices in CAPP are now about $32/ton to $35/ton free on board (FOB) mine (about $1.20 to $1.40/MMBtu at the mine). With ready capacity at current demand levels, prices have risen to more than $50/ton($2.00/MMBtu) FOB mine, depending on sulfur and heat content. In fact, some compliance coals sell for more than $60/ton ($2.40/MMBtu) at the mine. With CAPP coal often hundreds of miles from its markets, delivered costs of CAPP coal easily can surpass $2.00/MMBtu. In fact, in 2005, some CAPP coal delivered prices will exceed $2.50/MMBtu as existing lower-priced coal contracts and longer-term spot deals roll off and buyers are forced to write new spot or contract deals at then-current pricing.
Prohibiting this transfer of market share is the fact that many NAMR mines must be recapitalized. That is, the large NAMR and NAPP producers have sufficient coal reserves to accommodate new markets, but insufficient additional ready capacity. NAMR producers are addressing this with new production potential. In the meantime, NAPP prices are very high, with many prices now at or above the $45/ton ($1.73/MMBtu) FOB mine range for 2-percent sulfur coal. As in CAPP, these prices will not moderate until natural gas prices fall or ready capacity increases. Unlike CAPP, ready capacity is likely to increase significantly in NAPP, and this should help moderate out-year NAPP pricing.
Southern Appalachia coals are produced and consumed regionally. This niche market has always been high-priced ($35/ton to $40/ton, $1.40/MMBtu to $1.55/MMBtu FOB mine), and has not reacted as dramatically to high prices in CAPP and NAPP. Even so, when CAPP and NAPP prices moderate, the price for better SAPP coals will not fall below $35/ton at the mine.
Interior Coal: Will It Take Eastern Coal's Place?
The largest of interior U.S. coal supply regions is the Illinois Basin (ILLB). Long a victim of the effects of the 1990 Clean Air Act Amendments, a result of which was a decline in the use of ILLB coal, the region is experiencing a production rebound in response to increased overall demand and expected new scrubbed coal plants. In fact, should NAPP falter as a replacement for CAPP coal, the ILLB could supply coal into those Eastern coal markets where sulfur is not a great issue, such as into scrubbed Eastern power plants.
Many of the newly announced planned coal-fired power plants in the United States will use ILLB coal for fuel. This is due primarily to its abundance, but also to its better price and location. Still, ILLB prices have followed CAPP prices upward but not to CAPP price levels, because more ready capacity exists in ILLB and its coal quality is poorer. ILLB prices at the mine are likely to range from $30/ton ($1.30/MMBtu) to more than $40/ton ($1.65/MMBtu) at the mine for the next two years before giving ground in a more gas-abundant climate.
Western Coal: If All Else Fails
Should ILLB or NAPP coal fail to capture the anticipated CAPP production decline, or should Eastern bituminous coal prices stay high for an extended period while PRB prices remain low, then the PRB will be examined carefully by Eastern generators. If Eastern generators are locked into low sulfur or compliance coals, or if SO2 allowance prices continue to rise, then PRB coal will be examined even more closely, since alternative coals to CAPP in the East are all higher in sulfur. Of course, a switch to PRB coal could involve plant modification and a possible de-rate.
Its great abundance, ease of mining, and suitability to quickly adding production capability without considerably adding to unit-mining cost make PRB coal less likely to react to changes in natural gas price. Rather, PRB prices likely will increase over time at a regular, predictable pace as PRB mines develop into regions with higher and higher stripping ratios. These cost increases will not be dramatic, as they are in the eastern United States. From a level of about $5.50/ton ($0.32/MMBtu) today, expect higher heat content PRB coal price to grow steadily at about $0.25/ton to $0.50/ton per year nominal. Lower heat content PRB coal (8,400 Btu per pound of coal) will grow at the same rate but from a level today of about $4.50/ton ($0.28/MMBtu).
While it is relatively simple to add new production capacity in the PRB, moving that new production to market will require significant railroad investment. One reason PRB coal prices have remained low during the otherwise national run-up in price is because although PRB mines can produce more coal, it can't easily be moved to market. This creates an unusual kind of "supply surplus" in the PRB where supply-side transportation constraints keep prices low, which is the opposite effect usually seen in demand-side transportation constraint situations. How new railroad infrastructure development costs will be dispersed in the marketplace is a subject of much discussion. It is safe to assume that suppliers, transporters, and consumers all will bear some of the cost in one way or another. But reducing transportation congestion out of the PRB may be a necessary precursor for permanent PRB price increase.
Production of bituminous coal in the West occurs in the insular Northwest and Four Corners supply regions and in the more nationally important Rockies regions (Colorado, Utah, and southern Wyoming). Rockies coal is abundant, but not readily available, except in Colorado. New development, especially in Utah, will be needed to decouple Utah coal prices from those of natural gas. Even in the Colorado region, coal prices react somewhat in concert with CAPP coals; though Colorado mines can produce more, the process can take longer than in CAPP owing partly to the fact that there are only a few mines in Colorado while there are hundreds in CAPP.
Rockies coal prices at the mine are in the $21/ton ($0.91/MMBtu) to $26/ton ($1.12/MMBtu) range at this time, with the higher-priced coal coming from high-heat content Utah and Colorado mines. These prices are not expected to moderate for two years. Additional coal production may be added in Utah, which would create downward pressure on Rockies prices.
Natural gas prices effectively set the ceiling for coal prices, but mining costs set the floor. In all cases, coal prices will no longer fall below full production costs for any length of time, as they did during the 1990s, regardless of the price of natural gas. The long period of sub-full-cost pricing in the 1990s caused great rationalization in the coal industry, leaving a much healthier and sensible market. One consequence of this is that the floor price for coal in most regions has risen about 25 percent in the last few years. With natural gas prices expected to remain high for some time, those coal markets where ready capacity is at current demand levels will see steadily high prices.
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