Eastern spot prices for coal have risen 25 percent since the start of 2004, reaching their highest levels in more than 25 years. This spike represents the second time in four years that coal prices have risen to more than double their pre- 2000 price levels. Years of famine (from a coal producer’s point of view) have been replaced by periods of plenty, with increasing consequences for coal’s customers. How long will hits spike last?


The roots of today’s coal crisis lie in the counterintuitive events that occurred in the aftermath of the 2000-2001price spikes. When spot prices rose, coal companies were quick to respond with additional production through the first quarter of 2002. But the costs to labor and materials also rose, and the combination of a mild summer, 9/11, and a slowing economy caused prices to collapse before coal producers’ earnings-which were effectively shielded by long-term contracts-could benefit.

However, unlike the 200-2001 price spike, the current spike has moved prices to much higher levels than many vintage coal contracts call for and has caused prices in new long-term contracts to increase as well. It has boosted the revenues of coal producers and raised expectations on Wall Street and coal company boardrooms that, this time, higher prices could actually by good news for coal producers.

To understand the factors behind coal price volatility, EPRI has conducted periodic analyses of changing conditions in this market since the beginning of the 200-2001 price spike. One of EPRI’s investigators for these studies, Jerry Eyster- a managing consultant with PA Consulting’s Global Energy Practice in Washington, D.C- observes: `At present, there is reluctance among both coal companies and power generators to sign long-term contracts, and that is stalling badly needed investments in new mine development. Both parties are proceeding cautiously, seeking to avoid mistakes of the past, In some ways, the current tightness of the coal market reflects a classic standoff between entities with different views of the market.’

What’s Up or Down?
Before attempting to identify a solution to any imbalance in the coal market, it’s important to understand what created it. `We now know that the 200-2001 price spike was primarily a result of heightened demand,’ Eyster explains. That spike occurred at the end of the `go-go’ 1990s and coincided with a plateau in nuclear generation, a shortfall in hydro capacity, and- like now-skyrocketing natural gas prices. In addition, there were aggravating mine disruptions in each major producing region.

`Now,’ says Eyster, `the situation is quite different, The current prolonged spike in Eastern spot prices is primarily due to insufficient supply, since demand for Eastern coal has grown very little.’ The obvious solutions is more supply. Today’s coal environment in the U.S is similar to that of natural gas: The nation is in the midst of a prolonged supply shortage, and demand growth has (temporarily) stalled. In natural gas’s power generation niche, demand has actually fallen to levels of five years ago,

Four Reasons Why Prices are High
The volatility of today’s spot market prices is partly attributable to recent changes in the coal industry’s structure. Those changes were driven by the quest for survival during the doldrums of the 1990s, when coal prices flattened and even declined in nominal terms, The survivors of those lean years have emerged bigger, stronger, and better able to dictate their immediate future. EPRI’s insights into the following four critical coal market factors have been derived from analysis of market statistics and from interviews of electric utility fuel managers.

Consolidation
The coal industry has consolidated significantly over the past 15 years and continues to consolidate. In 1989 the top 10 US coal producers controlled 30 percent of national coal production. That share rose to 41 percent by 1994, to 60 percent by 1999, and to 64 percent 2003. On a regional basis, the impact of consolidation has been even greater. Three companies now control 60 percent to 75 percent of Powder River Basing, and Colorado/ Utah, consolidation has contributed to the volatility of spot coal prices by accelerating the elimination of excess mining capacity and-of course- by reducing the number of competitors.

New Mining Technologies
With some new technologies- such as draglines for surface mining and longwalls for underground mining (although their number has decreased dramatically over the past 10 years)- economies of scale are needed to minimize costs. Today, capacity is added less frequently and in larger chunks, Coal producers have a strong financial incentive to avoid building unneeded capacity. It makes sense for them to defer spending several million dollars on a new and large mining complex for as long as possible, because doing so tightens the market and drive spot coal prices up.

Fewer Small Mines
In 1989 there were 1,162 small mines in Central Appalachia that collectively produced 80.2 million tons of coal (or 31 percent of the region’s total that year). By 2003 the number of small mines had dropped to 367, and they produced only 26.8 million tons (or 12 percent of the region’s total production). This represents a loss of `surge capacity.’

More Public Coal Companies
Companies responsible for more than half of total U.S coal production have gone public since 1999. Six of the top 10 coal producers in the U.S. (Peabody Energy, Arch Coal Consol Energy, Massey Energy, Westmoreland, and Foundation Coal) are now publicly traded. These six companies controlled about 43 percent of U.S. coal production in 2003. Before July 1997, only two of them were publicly traded Going public wouldn’t have been an option had coal prices remained low. What impact does this trend have on coal supply and prices? Publicly traded companies tend to be more focused on short-term earnings and profits than on investing in incremental production for the future.

Aggravating Spot Market
EPRI’s studies have also identified the following market factors as contributors to today’s volatile coal prices.

Demand
Between 1999 and 2003, coal use for electricity generation grew by about 63 million tons. However, that growth was partially offset by slight declines in coal use at domestic coke plants and other industrial plants and by a significant decline in net coal exports. As a result, the total growth in demand for U.S. coal between 1999 and 2003 was only 24 million tons, or o.6 percent per year.

Miners’ Productivity
With the exception of Northern Appalachia, all the major coal-producing regions have experienced significant declines in coal miner productivity since 1999, just prior to the first price spike, The size of the declines ranges from 1.7 percent year in the Wyoming portion of the Powder River Basin to 3.5 percent year for surface mines in Central Appalachia. In these regions, more labor is now required to produce a given quantity of coal, and that both increases costs and constrains supply.

Coal Stockpiles
The average size of the coal stockpile at a U.S. power plant has diminished significantly over the past two decades- from a high of 112 days’ supply at the end of 1979 to 36 days’ supply at the end of 3004. For generators dependent on Central Appalachian coal, some stockpiles are low because of supply problems, including problematic rail transport. Urgency to build stockpiles or obtain needed supplies adds to the pressures on the spot market. Figure 3 shows the declining stock levels and days’ supply at U.S coal-fired power plants.

Coal Delivery
The number of large or Class I railroads in the U.S. fell from 71 in 1970 to only 9 in 1996. Of those, only five were considered mega-carries (now four, with the splitting and takeover of Conrail). Most railroad companies have substantially underperformed over the past 10 years and are under tremendous pressure to increase revenues. Though average rail rates have remained flat, important exceptions are occurring. An early sign of a new trend in the rail industry business is movement by the tow western carriers toward posted rates and shorter-term contracts. Rail has become a central focus of EPRI’s fuel research in 2005.

Exports Squeezing Supply
US domestic and export coal markets have become much more closely linked than in the past. One example of the consequences of the linkage occurred a year ago, when escalating Chinese demand and a cutback in the country’s coal exports contributed to a worldwide shortage of metallurgical coal. In response, the price of Central Appalachian met coal rose to $100/ton, which drew some steam coal into the met market and further aggravated the steam coal supply crisis.

Weathering the Crisis
With respect to Central Appalachian coal supplies-which are at the heart of the crisis-EPRI estimates that an increase in production of just 10 million tons could bring great relief. Such and expansion would need to take place as part of a national increase in coal production of about 40 million tons.

According to the Platts COALdat database, in 2004, Central Appalachian production increased only slightly, from 230.6 million tons to 231.1 million tons. The last sizable jump was in 2001 (during the 200-2001 price spike), when suppliers produced 269 million tons-6.4 million tons more than the year before. Accordingly any production increase of 10 million tons now should be measured against the 40 million-ton contraction of supplies over the past two years. The coal industry would likely have to make a capital investment of about $300 million to fund such a capacity expansion.

One cause of the investment impasse is that coal producers are reluctant to add capacity based on spot prices alone. At the same time. generation are wary of signing traditional long-term base-price contracts, or contracts with escalation or cost-plus clauses, because in the past many of these contracts did not serve them well. The `chicken and egg’ problem here is that these types of agreements historically have provided the financial underpinning for major new mine developments.

New coal contracts will need to avoid the excesses of the 1979s, when buyers entered into cost-plus agreements with few controls, or into long-term contracts that were divorced from the market price for decades. Instead, linger-term agreements might be developed with some price adjustment and re-pricing mechanisms. The development and general availability of coal price and emission allowance indices may help in the crafting of agreements that are sensitive to market prices. Another possible solution that is appealing to both parties is to shorten the terms of coal contracts. Sellers are trying to extend the benefits of high prices as far into the future as possible. Buyers do not want to find themselves in a few years with contracts that are far above prevailing market prices. Contracts with three- to five-year terms are becoming the norm.

Finding Common Ground
Federal environmental requirements may have become clearer with the arrivals of the Clean Air Interstate Rule and Clean Air Mercury Rule, but the cost of burning coal cleanly remains a challenge. for example, how does a mine developer determine coal demand for newly scrubbed units in eastern states when generators want to maintain the flexibility to burn a 7-1b or a 3.5-1b SO2/ MMBtu Illinois Basin coal? Some generators can defer their capital costs by burning (now high-priced) compliance coal. Upgrades to other coals are inevitable, but when will the money be spent?

Another dimension of the problem is legislative and regulatory uncertainty. EPRI’s last (December 2004) review of power plan status considered 16.000 MW of new coal capacity `likely’ to be built between 2005 and 2012. Out of 32 new plants, almost all would be pulverized coalfired units. But what would happen to coal demand and the EPRI prediction if integrated gas combined-cycle (IGCC) technology were to be designated a Best Available Control Technology? That is the intention of the March 3, 2005, court case appealing the approval for the air permit for Peabody Energy’s Prairie State coal plant.

Partnering for Future
To quantify the consequences of different economic and policy drivers on the outlook for coal, EPRI analyzed different coal-capacity expansion scenarios and how coal consumption might change in response to changes in air-quality regulations, electricity demand, natural gas pricing, and the introductions of IGCC.

Not surprisingly, the analysis generated a wide range of possible outcomes. The highest level of new coal plant construction occurs in the high-gas-price/high-generation-growth scenario, with nearly 75 GW being built by 2020, However, the most probable scenarios call for significantly lower build levels. One scenario posits that IGCC units will be built before 2020 only if tow things happen: natural gas prices remain elevated, coupled with high load growth, or a national cap on CO2 emissions is put in place

One thing that may be keeping some parties apart is the math that high natural gas prices are driving up coal demand. This myth can be debunked by a glance at the table, which shows that the growth of gas0fired generation (over 7 percent) far exceeded that of coal-fired generation (essentially flat) last year even though natural gas prices topped $6/MMBtu for most of the year. Nevertheless, the EPRI analysis predicts that persistently high natural gas prices will increase reliance on coal generation for the sake of fuel diversity.

To bring parties together, where environmental uncertainties are simply too great for the comfort of a coal producer and a coal buyer to bear the risk, commercial value might be winnowed from a converging of energy policy vision at more overarching level. Jamie Heller, president of Hellerworx and an EPRI investigator on coal contracting options, suggests, `A point of agreement might be a vision of fuel diversity and its value. Once a need for expanded Illinois Basin coal production is established, for example, it may be easier for parties to promote financing even if the production is not sold out in entirety to participants at the start. Entities more suited to taking on risk may be emboldened by this vision. As another example, it may be possible to complete the financing for the DM&E [Dakota Minnesota & Eastern] railroad even though the market and contracts have not fully materialized.’

This is not to promote a rosy view that all is possible with `common vision,’ but rather to suggest that data, analysis, and suitable information exchange need to occur at all levels. The fruits of such convergence over a vision are already emerging in power/industry consortia aimed at advancing coal technology (for example, EPRI’s coalFleet initiative), and we are suggesting that this can extend to additional parts of the mine-rail-power infrastructure.

Source: EPRI