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.
currently considered feasible (see Tables 1 and 2). Even with the reduced gas requirements of 3.3 Tcf/yr to fuel the smaller increase in combined-cycle capacity from 2002 to 2025 of 123.5 GW  (Tables 1 and 3), it still would require 11.7 Tcf/yr to replace 311 GW of U.S. coal-fired steam-electric capacity plus 3.3 Tcf/yr for the 123.5 GW of increased 2002-2025 combined-cycle capacity, less 3.8 Tcf projected increase in total electric power consumption, or 11.7+3.3-3.8 = 11.2 Tcf/yr for a total of 41.8 Tcf/yr, well above what appears achievable.
Moreover, coal-fired capacity would increase to 394 GW in 2025. Finally, the net increase of combined-cycle capacity from 2003 to 2030 of 88.5 GW  (Tables 1 and 4) would require only 2.4 Tcf/yr at 50 percent load factor and a higher heating value heat rate of 6,300 Btu/kWh. The increase in projected demand for power generation would drop to 1.3 Tcf/yr, but this still would lead to total gas requirements of 11.7 + 2.4-1.3 = 12.8 Tcf/yr, or a total projected consumption in 2030 of 39.3 Tcf. Again, this is far in excess of what appears feasible. Moreover, total coal-fired capacity still is projected to increase to a whopping 457 GW by 2030, without any indication how much of this would come through essentially CO 2-emission-free IGCC plants using CO 2 removal and sequestration.
LNG and Future U.S. Gas Demands
As shown in Table 5, the expectations of ever increasing U.S. imports of LNG rising further above the 6.37 Tcf in 2025  are not materializing. This is because of global competition reflected in higher net-back prices in Europe and Asia, as well as the use of stranded natural-gas resources for the production of premium distillate petroleum fuels by the catalytic Fischer-Tropsch Process—so-called Gas-to-Liquids (GTL) Plants. As a result, the steady rise in LNG imports from 6.2 percent to 20.8 percent of total supply shown in Table 5 for EIA’s Annual Energy Report (AEO) 2003, AEO2004, and AEO2005 reverses in the projections of AEO2006  to a mere 15.5 percent. The projected level of U.S. LNG imports in 2030, according to AEO2006, is 4.36 Tcf. There currently are only four on-shore U.S. LNG import terminals: Everett, Mass., Cove Point, Md., Elba Island, Ga., and Lake Charles, La. Terminals also are being built in Mexico and Canada, in close proximity to U.S. markets.
Numerous IGCC projects are in the advanced planning stage in spite of investment costs on the order of $2,000/kW and remaining uncertainties about CO 2 sequestration. With coal at $1.50/MMBtu and natural gas currently at about $7.00/MMBtu with likely major escalations during the 2006/2007 winter, IGCC may become competitive with natural gas-fired combined-cycle generation with an investment cost of only about $500/kW and a heat rate (higher heating value) of 6,300 Btu/kWh.
The April 2006 to Oct. 30, 2007, working gas-storage season began with a record 1,700 Tcf in storage—well over 400 Tcf above last year, and about 660 Tcf above the five-year average . This upward trend of working gas volumes continued into May 2006