3. Data and Analysis Uncertainties

As with any long-term projection, there are considerable uncertainties. It is impossible to predict future fuel prices and how existing generation or emissions control technologies might evolve in cost and performance or what currently unknown technologies might emerge to play unexpectedly important roles in the market. Of particular concern in this analysis are future natural gas prices and the availability and market acceptance of low- or zero-carbon generation technologies, including new nuclear, renewable, and fossil plants with carbon capture and sequestration equipment.

Another key uncertainty is the cost and performance of technologies designed to remove mercury. In recent years, substantial information has been gathered on the factors influencing mercury emissions at existing plants, i.e., the mercury content of coal, coal rank, coal chlorine content, power plant particulate, SO₂ and NO_x control systems, etc., but significant uncertainty remains. Experts at the EPA and the U.S. Department of Energy have different views on the mercury removal rates that should be assigned to particular plant configurations using various coals. Often their analyses use the same data sources, but because of variability in the data and their interpretation, they reach different conclusions. The understanding of what contributes to mercury emissions will likely improve in coming years as research efforts continue, but the outcome of these efforts is unknown.

One particular area of uncertainty with respect to mercury control concerns the role that NO_x control devices, or SCRs, play in removing mercury from lower-rank coals (subbituminous and lignite). Evidence suggests that when combined with a wet scrubber for SO₂ removal, they do enhance mercury removal in plants using bituminous coals. The same has not been found to be true for the lower-rank coals, but research is ongoing. In this analysis, SCRs are not assumed to enhance mercury removal at plants using subbituminous or lignite coals. The outcome of this research will be important because power plants are expected to invest in SCRs to meet the NO_x emissions caps in the Inhofe, Carper, and Jeffords bills. If these investments also contribute to removing mercury emissions, they could lower the incremental costs of meeting the mercury emissions caps.

Another area of uncertainty is the cost and performance of mercury removal systems. Supplemental fabric filter systems using activated carbon injection (ACI) are expected to be a key technology in removing mercury. Tests of such systems have demonstrated their ability to remove mercury from bituminous coals, but full-scale tests on subbituminous and lignite coals are only now being evaluated. This analysis assumes these systems will be equally effective on the lower-rank coals and be able to achieve removal rates up to 90 percent. However, experts at the Department of Energy believe that the lower chlorine content typically found in subbituminous and lignite coals may limit the ability of ACI fabric filter systems to remove mercury from them. There is also uncertainty on the cost of these systems. Based on information from the National Energy Technology Laboratory, this analysis assumes these systems will typically cost just over $50 per kilowatt of capacity on a 500-megawatt unit. Experts at the Department of Energy have indicated that the test units from which these costs were developed may have been undersized, presenting unacceptable maintenance problems. Their current estimate of the cost of an appropriately-sized system is nearly $80 per kilowatt for a 500-megawatt unit, a 60-percent increase from earlier estimates. Again, more research is needed to confirm these findings. The cost and performance of mercury control systems are particularly important in the analysis of the Jeffords bill. As discussed, the Jeffords bill calls for facility-specific mercury reductions that generally require more than 90 percent of the mercury in the coal to be removed. It is unclear whether the technologies in development will be able to achieve removal rates this high for all plants and coal types.

There is also uncertainty about the cost of SCR systems. In the 1990s various estimates typically put the costs of these systems at $70 to $90 per kilowatt of capacity.¹⁹ However, many power companies are now installing these systems to comply with summer NO_x emission limits that take affect in 2004. Reported costs for these retrofits are higher than the previously estimated costs, ranging from $80 per kilowatt to $160 per kilowatt.²⁰ This analysis assumes that retrofitting a SCR on a 500-megawatt unit will cost just under $100 per kilowatt. This is within the range of the recent costs, but a higher cost may be justified if reported costs continue to exceed them.

The potential availability and cost of CO₂ offsets are also very uncertain. There is uncertainty in what offsets might actually cost and what rules and regulations the independent review board (IRB) called for in the Carper bill might establish for acceptable international trading programs and offset projects. The marginal abatement curves used here were developed by the EPA using engineering cost analysis. The curves suggest that there are many low-cost opportunities for reducing greenhouse gas emissions, some actually with negative costs (i.e., a company could increase its profits by taking the actions).²¹ More work is needed to determine whether these curves accurately reflect the costs faced by the various industries studied, especially those where the curves suggest a large number of profitable investments are being overlooked. While beyond the scope of this report, there is substantial debate about the existence of a large amount of “negative-cost” greenhouse gas reduction options.²² These curves likely oversimplify the invention, innovation, and market diffusion process that new technologies generally follow and may understate the costs involved in achieving the reductions.

The IRB established in the Carper bill will have to establish measurement, verification, and enforcement procedures for acceptable international programs and offset projects. The procedures established will impact the availability and cost of offsets. For example, if the IRB requires strict measurement and verification procedures, many projects such as those in agriculture and forestry may find the costs of compliance make their projects uneconomical. The actual greenhouse gas savings from projects in these areas are difficult to measure and verify. On the other hand, the IRB could establish simple protocols for such projects, making it relatively easy to submit estimated savings and receive extra CO₂ allowances. However, in this case program regulators would never accurately know how much greenhouse gases were actually being reduced.

With respect to natural gas prices, one only has to look at their volatility in recent years to understand their uncertainty. Recent data appear to suggest declining well productivity, but it is unclear whether this will continue to be seen in the future or whether technological advances will moderate the recent price increases.

Sensitivity cases assuming slower rates of progress in oil and natural gas supply technologies were prepared to assess the sensitivity of the results to higher natural gas prices.²³ In addition, since it has been more than 25 years since a nuclear plant has been ordered, a Jeffords case with higher natural gas prices without new nuclear plants was also prepared. In a case without any of the proposed legislation, the slower technology progress rates resulted in a natural gas wellhead price of $4.99 per thousand cubic feet in 2025, $0.56 per thousand cubic feet higher than in the reference case.

The key results in these cases are that higher natural gas prices will increase the resource costs of complying with the three bill provisions and change the mix of generating capacity built to meet consumers’ needs (Figure 38). The impact on resource costs is small in the Inhofe case because fuel switching was not a very important compliance option in that case. Higher natural gas prices have a bigger impact in the Carper Cases and Jeffords cases where fuel switching is more important. In the Carper Domestic High Gas Price case, higher natural gas prices lead to a 10 percent ($7 billion) increase in the discounted industry costs of compliance. In the Jeffords High Gas Price case, higher natural gas prices increase the discounted industry costs of compliance by 4 percent ($11 billion). In the Jeffords High Gas Price/No Nuclear case, the cost of compliance rises still further.

As might be expected, higher natural gas prices cause the industry to reduce its dependence on natural gas technologies and turn to increased use of coal, renewables, and, in the Jeffords cases, coal plants with carbon capture and sequestration equipment (Figure 39). In the reference and Inhofe cases, higher natural gas prices primarily lead to greater dependence on new coal plants. In the Carper cases, higher natural gas prices lead to increased dependence on new renewable and coal plants. In the Jeffords cases, higher natural gas prices lead to increased dependence on new coal plants with carbon capture and sequestration equipment, particularly when new nuclear plants can not be built.

Notes and Sources