In 2009, unconventional shale gas emerged as the dominant driver in North American natural gas markets. Rapid increases in shale gas production and shale-driven upward revisions to the U.S....
Coal No More: What If?
An analysis of what risks would have to be taken to significantly reduce carbon emissions by using natural gas in the short run.
global warming. It also deals with the feasibility of increasing projected U.S. gas-fired combined-cycle capacity operating at 50 percent load factor. If wholesale natural-gas prices in 2006 and 2007 return to NYMEX (Henry Hub) Natural Gas Futures of $11.30/million Btu , this simply would not be economical with coal delivered to power plants at 1.5/million Btu from 2004 to 2025 (2030 in the latest projection).
In late May and early June, NYMEX gas prices dropped slightly below $6/MMBtu after recovery of Gulf production from hurricanes Katrina and Rita, as well as a great deal of excess storage. Based on May 25-28, 2006, trading dates, gas prices may stay competitive at $5.90 to $11.30/million Btu . As shown in Table 1, the DOE’s Energy Information Administration (EIA) data confirm that the trend of declining total U.S. gas supply (including imports) and increasing natural-gas-fired combined-cycle capacity is continuing, although at a slower pace, making increased natural-gas-fired combined-cycle capacity (in addition to high gas prices) a less likely solution to the greenhouse-gas emission problem. However, a 2000 estimate of an investment cost of $1,642/kW  for the modified IGCC power generation that incorporates a catalytic water gas shift step—which converts the carbon monoxide in the raw synthesis gas into more hydrogen and CO 2, followed by CO 2 separation and sequestration—now appears far too low in the light of recent information. Moreover, this cost estimate excludes the cost of CO 2 sequestration.
The natural-gas requirements to replace the 311 GW of coal-fired steam-electric plants with gas-fired combined-cycle plants at 70 percent load factor and a heat rate of 6,300 Btu/kWh would be 11.7 Tcf/yr. In addition, at the projected net increase of 170 GW of combined-cycle capacity from 2001 to 2025 at 50 percent load factor and a heat rate of 6,300 Btu/kWh, it would require another 4.6 Tcf/yr (Tables 1 and 2). Moreover, coal-fired steam-electric capacity would continue to increase from 311 GW in 2001 to 412 GW in 2025 in spite of the environmental problems caused by the resulting increase in CO 2 emissions.
This increase in CO 2 emissions may be reduced if a significant portion of the new capacity uses the modified IGCC technology in which carbon monoxide in the original synthesis gas is converted to hydrogen and CO 2 by catalytic water-gas shift (CO+H 2O $ CO 2+H2) and the CO 2 is removed and sequestered in suitable underground formations. Moreover, the existing 311 GW of coal-fired capacity in 2001-2002, already emitted 516.5 mmt of carbon in the form of CO 2 of the total of 1,609 mmt of U.S. carbon emissions in 2004 , or nearly one-third. In the Reference Case for 2004 , gas consumption for power generation from 2001-2025 increases 3.0 Tcf, so that the net increase of gas consumption from 2001-2025 including replacement of the existing 311 GW of coal-fired capacity would be 11.7 + 4.6-3.0 Tcf, or 13.3 Tcf. Or, a total projected gas consumption in 2025 of 31.3 + 13.3, or 44.6 Tcf, far in excess of what is