Coal occupies an unenviable position in the fossil fuel hierarchy.
With its use concentrated in large power stations in most countries, it is a prime candidate for carbon capture and storage, even though technologies for this are not yet commercial – they face enormous cost hurdles and use vast amounts of energy in such steps as concentrating oxygen prior to combustion and separating CO2, not to mention a host of geo-engineering and institutional issues associated with sequestration.
Technology development now requires large-scale demonstrations – a critical stage on the path to commercial development – and further innovations are sought.
This places carbon capture and storage on a timeline where the technology response in the best of worlds may lag society’s desire to curb emissions.
Opposition to coal (along with extraordinary escalation of capital costs) came to a peak in 2007, stalling or derailing some 50 gigawatts (GW) of once-proposed plants in the United States.
At present, about 50 plants totaling 30 GW are either under construction (50 percent of the total) or in early stages of development, and thus not assured of completion in the 2008-16 period. This compares to about 70 GW of gas-fired plants (80 percent combined cycles and 20 percent combustion turbines) and 40 GW of wind capacity.1
Notably, the lead in new generation has now been taken up by natural gas and renewables. In fact, natural gas is experiencing a development boom, albeit smaller than the 2000-04 merchant plant boom (see figure 1). A turn to gas at the expense of coal will intensify after enactment of legislation to curb greenhouse gases.
Analysts have reached remarkably different conclusions about how much natural gas can replace existing coal-fired generation (a range from 0 to 284 GW of natural gas capacity additions by 2030 in response to stringent, early cutbacks in CO2 emissions), but all conclude that obstacles to nuclear capacity, delays in mastering carbon capture and sequestration – or achievement of only moderate levels of renewables – would translate into greater natural gas use. 2
Early indications are that gas impacts would be far from uniform, with demand surging regionally, perhaps first in the Southeast. 3
So much for the long run. In the short run, natural gas-fired generation is viewed as the likely “default” choice, and this was before the financial crisis turned lenders against both capital cost and technology risk. 4
The implications for both coal and natural gas markets are considerable – arresting coal demand growth (unless associated with carbon capture and storage) and establishing new gas demands of about 0.5 trillion cubic feet per year (1.4 billion cubic feet per day) for every 10 GW of coal capacity replaced by gas generation. If there is a moose in the room, this is it. 5
Power sector demand growth will not materialize in time to prevent the looming oversupply from gas shales/Rockies production, but it certainly appears capable of stressing supplies (and widening the door to LNG imports) in the post-2015 period.
While coal’s future is uncertain and insecure, the exact opposite is true of its present role – both domestically (it provides 49 percent of U.S. power generation) and internationally (see our eye-opening comments on China below).
Volatility and globalization are the two watchwords that best describe the current market.
During 2008 U.S. coal prices were buffeted as never before by international forces. Between the summers of 2007 and 2008 prices at the three principal export hubs of Newcastle, Australia (principally to Asian markets), Richards Bay, South Africa (principally to Amsterdam-Rotterdam-Antwerp or ARA) and Colombia (to ARA and the United States) rose from about $60/metric ton to $160. This is astonishing.
It was accompanied by the added burden of unprecedented hikes in dry bulk shipping costs (e.g., from a norm of $15-20/metric ton to $50 for Richards Bay to ARA), it had very little to do with oil’s coincident price escalation and, among other things, it led to expansion of the United States’ usually very modest role as a coal exporter (to ARA) and a wave of price escalation in U.S. coal prices.
Metallurgical coal prices experienced a similar but even more extreme rise (e.g., the annual settlement of Japanese high quality hard coking coal went from $100/metric ton in 2007 to $300 in April 2008).
The journey of U.S. spot coal prices is summarized in EIA’s price chart (figure 2). Northern and Central Appalachian prices went from $45/short ton to $140-150 between summers of 2007 and 2008.
Illinois Basin prices, not directly participating in the export market and slightly lagging Appalachian movements, climbed from $30/short ton to an equally astonishing $90.
The principal question in U.S. and international markets now is “how hard will these prices fall?”
Hard times to come are indicated in the stock values of coal producers, which have dropped sharply since July, preceding by several months the emergence of the global financial crisis.
No comments about coal, however cursory, would be complete without a few words about China, for two reasons:
China’s industrialization has brought about nearly incomprehensible changes in its infrastructure. In 2006, 102 GW of new generating capacity was added in China, and the pace of development over the past three years has been estimated as equivalent to adding three to four 500-megawatt power plants per week. 7
About half of the coal produced in China is used to make electricity, and about 80 percent of the country’s electric generation is derived from coal. 8
Power sector growth has been the primary engine behind China’s growing coal consumption and production. Production doubled between 2001 and 2006. It is this phenomenon that is behind BP’s observation when releasing its 2008 Statistical Review that “coal was again the fastest growing fuel in 2007.”
And it also is behind growing recognition by world policymakers that development in China is the trump card in controlling CO2 emissions.
Discussions about coal as an energy resource often turn to its reserves, resources and global distribution. For those concerned with world energy developments, it makes sense to focus on countries that are most important in the world coal trade. This is done in the following table (figure 3), which ranks countries by their combined exports of thermal and metallurgical coal.
While Australia is at the top, Indonesia is the fastest growing exporter – and by 2006 it was the world leader among exporters of thermal coal, 50 percent greater than Australia.
Indonesia’s electricity needs also have been rapidly growing, which is leading to policies to assure sufficient supplies to serve its domestic markets.
Rather than attempt to answer the many questions a table such as this may raise, we leave it as a portrayal of some of the features of the global coal industry.
Jeremy Platt is chair of the EMD Economics Committee.
William A. Ambrose is chair of the EMD Coal Committee.
AAPG’s Energy Minerals Division (EMD) and Division of Professional Affairs (DPA) offer professional certification in coal geology.
With certification in coal geology, professionals have the opportunity to network with a dedicated group of individuals recognized as leaders in the field of coal science.
Geologists and engineers dedicated to the profession of coal science and who are interested in learning more about coal certification should visit the EMD Web site.
The Energy Minerals Division (EMD), a division of AAPG, is dedicated to addressing the special concerns of energy resource geologists working with energy resources other than conventional oil and gas, providing a vehicle to keep abreast of the latest developments in the geosciences and associated technology. EMD works in concert with the DEG to serve energy resource and environmental geologists.