Multipollutant Efficiency Standards for Electricity Production
Schwarz, Peter M., Contemporary Economic Policy
Federal legislation for electricity emissions has become increasingly stringent, as typified by the stricter standards of the U.S. Environmental Protection Agency's (EPA) 1997 New Source Performance Standards (NSPS) as compared to the 1990 Clean Air Act Amendments (CAAA). Electric utilities are among the firms seeking greater regulatory certainty and integrated multipollutant standards in future legislation. Electric utilities support the approach of the federally proposed Clear Skies Initiative, which presents an integrated standard for sulfur dioxide (S[O.sub.2]), nitrogen oxides (N[O.sub.x]), and mercury (Hg) so as to avoid "stranded capital investments from installation of controls that later become obsolete when additional regulations are promulgated." (1)
It is generally recognized that the current "piecemeal" approach, with an uncertain timetable and ratcheting of standards applied to some pollutants without considering the relationships among pollutants, adds excessively to costs. (2) However, there is little evidence on the cost savings and net benefits from less frequent revision of standards and a more integrated multipollutant approach. This article provides such evidence of the savings to firms of crafting legislation that recognizes the relationships among multiple emissions and the advisability of foresight when emissions standards are promulgated.
In 2002, North Carolina passed the Clean Smokestacks Act, an integrated standard calling for coal-fired electric plants to reduce S[O.sub.2] by 73% by 2013 (with an interim reduction of 49% by 2009), as compared to 1998, as well as to reduce N[O.sub.x] by 79% by 2009. The act requires actual reductions, so that emissions trading cannot be used to meet the new standards. This article addresses the costs and benefits of the new North Carolina integrated standard, as compared to the 1990 and 1997 federal standards. The major findings are that firms subject to the 1990 standards that must now meet the 2002 North Carolina standard choose the lowest cost method to do so. But firms that come under the 1997 NSPS choose a different method to comply with the 2002 act that results in higher costs. Results also show that net benefits are positive for the North Carolina standards, but not for the 1997 NSPS. The approach in this article can be extended to include additional emissions, including mercury (Hg), particulate matter (PM), and carbon dioxide (C[O.sub.2]) emissions. (3)
The method used in this article is a detailed simulation of a single coal-fired electric generating plant. Electricity production uses the Integrated Environmental Control Model (IECM), developed by Rubin, Berkenpas, and others at Carnegie Mellon University (CMU) with support from the Department of Energy (DOE) and applied in a series of papers (Rubin et al., 1997, 2001, among others). The IECM is a detailed engineering model of electricity production, including the associated multiple emissions as well as the corresponding production costs.
The IECM can simulate both traditional production, aimed at reducing a single emission, and integrated methods that target multiple emissions. Utilities limiting S[O.sub.2] emissions have switched to low-sulfur coals and added flue gas desulfurization (FGD) scrubbers. To limit N[O.sub.x], utilities have incorporated low-N[O.sub.x] burners and selective catalytic removal (SCR). This article focuses on the costs of complying with environmental controls for S[O.sub.2] and N[O.sub.x], and the possibility that utilities subject to increasingly stringent controls may choose a solution with higher costs than if they had known the later standards at the time when they chose the compliance strategy to meet the initial standard. The IECM contains several integrated technologies that are under development. The most promising from a cost standpoint appears to be the fluidized bed copper oxide (CuO) process. To the extent that regulations encompassed multiple pollutants in a predictable fashion, it is likely that firms would be more willing to invest in research and development (R & D) in integrated technology, leading to earlier development.
Through the use of the IECM, Rubin and others have examined a variety of multipollutant issues. They have looked at the cost savings of a multipollutant approach attributable to the use of advanced integrated technology as compared to traditional separate technologies. For example, a fluidized bed CuO process is an advanced integrated technology under development at the DOE that can reduce both S[O.sub.2] and N[O.sub.x]. The traditional approach is FGD to meet stringent sulfur restrictions and SCR to meet N[O.sub.x] restrictions. A firm subject to one regulated emission could initially install the single emission technology and then add the second technology when it faces an additional regulated emission. If it knew both constraints at the outset, it would have an increased motivation for choosing the integrated technology.
There is relatively limited economics literature on multiple pollutants, and only a subset of that literature considers the efficiency of multipollutant standards. (4) Eskeland (1997) evaluates a package of programs to reduce multiple air pollutants in Santiago, Chile. The author uses a four-step benefit estimation approach. The steps are to measure the reduction in emissions brought about by the programs, to translate those reductions into reduced mortality and morbidity, to value those reductions in dollar terms, and to calculate those benefits on a dollar per ton basis. Finally, benefits and costs are compared, with the finding that the overall program, as well as each part of the program, passes the benefits/costs test.
Eskeland contrasts that result with Krupnick and Portney (1991), who found that for the United States, improvements in air quality mandated by the 1990 CAAA have costs that outweigh benefits on the order of 10:1. That article focused primarily on a single emission, volatile organic compounds (VOCs), and secondarily on particulates. Additional studies have challenged this finding, including the Office of Radiation Analysis (EPA). The EPA study (1999b) includes six emissions, and finds benefits outweigh costs on the order of 4:1.
Austin et al. (1998) estimate benefits to Maryland from Title IV of the 1990 CAAA, which addressed both S[O.sub.2] specifically and N[O.sub.x] more generally. The amendments introduced emissions trading for sulfur, with two phases of emission reductions. It introduced a more traditional approach for reducing N[O.sub.x] emissions. Since that time, the N[O.sub.x] state implementation plan (SIP) has introduced a separate standard during the five-month peak ozone season. Plants can meet this standard based on an average level of emissions, rather than a plant-specific level, and 22 eastern states have begun to implement N[O.sub.x] trading programs. California has a separate program, known as RECLAIM, for N[O.sub.x] control.
Burtraw et al. (2001) examine cost-effective reduction of N[O.sub.x] emissions from electricity generation, simulating reductions from a summer season regional approach to N[O.sub.x] trading, as is currently under way, an annual regional approach, and an annual national approach. While the article concentrates on a single emission, there is consideration of the extra cost to utilities if they plan for a seasonal emissions program and are then "surprised" by a change to an annual program. This sequential change of standards is another application of the "piecemeal" approach, as compared to an integrated standard where the initial requirements do not change within a period specified by the legislation.
Other studies have taken a macrolevel view of the effects of integrated standards on emissions and electric costs. A study by the Energy Information Administration (EIA, 2001) within the Department of Energy looks at how proposed multipollutant standards would affect emissions and electricity costs forecasted to 2020. They consider a variety of technologies. However, these technologies are conventional insofar as each targets a single emission, with additional technologies inserted to target additional emissions. They do not examine cost savings that could come from less frequent changing of standards, regulatory cognizance of relationships among emissions, or using integrated technologies. One of the reasons for integrated standards is that utilities will then choose integrated technologies instead of add-ons.
The Office of Air and Radiation within the EPA (1999a) examined multiple emissions reductions that would result from controls on single emissions including S[O.sub.2], C[O.sub.2], Hg, and multiple emissions of S[O.sub.2]/C[O.sub.2] and S[O.sub.2]/C[O.sub.2]/Hg. They use a macroview to predict economy-wide costs from legislation and find savings from a multipollutant legislative approach.
Banzhaf et al. (2002) link together several models to determine efficient fees and corresponding quantities for S[O.sub.2] and N[O.sub.x] emissions at an aggregate U.S. level. They find that the levels of emissions proposed in both the Clear Skies Initiative and an alternative proposed by Jeffers are in the proximity of efficient emissions levels. Their results are based on conventional approaches and technologies aimed at single emissions, such as the use of low-sulfur coal, scrubbers, low-N[O.sub.x] burners, and catalytic converters. Their aggregate approach also considers fuel switching (from coal to natural gas) and reduced demand and conservation.
The current article focuses on a utility using a single coal-burning power plant that can use either conventional technologies aimed at a single emission or innovative technologies geared toward multiple emissions. (5) The primary purpose is to consider the circumstances where utilities will choose a technology that results in excessive costs. The secondary purpose is to compare the costs to the benefits of an increasingly stringent standard, culminating with the 2002 North Carolina Clean Smokestacks Act (NCCSA). The legislation is aimed at existing coal plants and freezes rates for five years. Thus it is possible to focus on the lowest cost technology, and it is not necessary to consider fuel switching or electricity demand and conservation.
III. IECM ANALYSIS OF S[O.sub.2] AND N[O.sub.x] EMISSIONS
Table 1 contains the IECM options directly relevant to a coal-fired electric plant subject to restrictions on S[O.sub.2] and N[O.sub.x]. Technology aimed at a single emission may increase or decrease other emissions. Rubin et al. (1997) show, for example, that low-sulfur coal reduces S[O.sub.2], but increases N[O.sub.x], PM, and Hg. These secondary effects should be considered when evaluating the desirability of a single-emissions approach. Furthermore, the cost of meeting additional requirements, such as for N[O.sub.x], depends on the previous technology decision. If a switch from medium to low-sulfur coal increases N[O.sub.x] emissions and a N[O.sub.x] requirement is added, it will be necessary to use a larger size SCR to reduce N[O.sub.x] to the required level than if there had been no secondary effect.
Options to control other emissions may be indirectly relevant. For example, a facility subject to particulate restrictions may choose a particulate control technology that affects other emissions, as well as affecting other emissions technologies. Electrostatic precipitators (ESPs) and fabric filters (FFs), among the technologies to control particulates, affect S[O.sub.2] and N[O.sub.x] emissions directly as well as indirectly through effects on S[O.sub.2] and N[O.sub.x] technologies. Also, there are options regarding the disposal of solid wastes, such as mixed with landfill or with bottom ash, that can affect other emissions.
The modern era of pollution control began with Title IV of the 1990 CAAA, which introduced sulfur emissions trading and capped sulfur emissions by approximately half, as compared to 1980. Phase I began in 1995, with the largest electric utility plants constraining sulfur emissions to 2.5 lb/MBtu ([10.sup.6] or 1 million Btu). Phase 2 expanded coverage to smaller plants in the year 2000, and a reduction to 1.2 lb/MBtu. (6) The legislation took a more conventional approach to N[O.sub.x] initially requiring plant-specific reduced emissions. While no caps were placed on N[O.sub.x], the first phase of N[O.sub.x] controls reduced emissions to 0.45 or 0.5 lb/MBtu, depending on the boiler technology in place, primarily affecting the same plants as were subject to the initial S[O.sub.2] controls. In 1999 the EPA passed the N[O.sub.x] SIP, with additional requirements for the summer ozone season for 22 eastern states, but these requirements allowed firms to meet N[O.sub.x] requirements based on average plant emissions, rather than at each plant. California and the East have begun N[O.sub.x] trading programs. An integrated approach would have established these options at the outset. The piecemeal approach to N[O.sub.x] regulations may have resulted in firms undertaking plant-specific reductions that were more costly than achieving average emissions standards, or being able to buy and sell emissions permits.
In addition to meeting Title IV of the CAAA, upgrades of plants may trigger more stringent standards as embodied in the NSPS, depending on cases now being litigated. For plants modified after July 9, 1997, that trigger NSPS, S[O.sub.2] cannot exceed 1.2 lb/MBtu and the emission limit for N[O.sub.x] is 0.15 lb/MBtu. (7) Finally, states are allowed to pass standards that are stricter than the federal standards. The North Carolina act translates to 0.16 lb/MBtu for sulfur and 0.07-0.10 lb/MBtu for N[O.sub.x]. (8)
A. Cost of Meeting the 1990 CAAA and 1997 NSPS
The conventional approach of multiple air pollution control by coal-fired power plants is to use separate technologies for each pollutant (Rubin et al., 1997). For example, utilities may use an in-furnace control (low-N[O.sub.x] burner) plus a hot-side SCR system and a wet FGD to separately control N[O.sub.x] and S[O.sub.2]. These technologies can reduce emissions by 90% or more. However, the fluidized bed CuO process currently under development at DOE can remove at least 90% of S[O.sub.2] and N[O.sub.x] emissions in a single system. The cost of a nonintegrated approach is that firms might not choose the integrated process even if it could achieve the current standard at a lower cost because they have already installed separate technologies to meet the earlier standard. They are also less likely to invest in R & D for integrated technologies. We compare these two approaches using the IECM simulation, on the premise that the cost of a commercially available CuO system will be comparable to the development model.
The basic production parameter settings for both approaches include (1) annual 500 megawatt gross (mW gross) production, (2) capacity factor set at 75% (on average, production is at 75% of plant capacity, (3) 90% removal rate for both S[O.sub.2] and N[O.sub.x] emissions, (4) the particulates control technology is required to be set at 0.03 lb/MBtu by the federal standard, (5) solid wastes are disposed of in a landfill, (6) 90% mercury removal, required to meet the 1990 CAAA, and (7) no C[O.sub.2] removal, reflecting the absence of such standards at the current time.
The IECM also provides costs corresponding to production. The cost calculations contain detailed formulas for base plant and emission control technologies (see Berkenpas et al., 1999). The model also contains parameters that would be needed in the capital asset pricing model (CAPM), such as the amount of debt and equity, including preferred versus common stock, corresponding anticipated returns to stockholders, and plant lifetime for depreciation purposes.
The results of the IECM simulation are summarized in Table 2 for the 1990 CAAA and 1997 NSPS. Simulations are presented for conventional and integrated technologies, and for two coal types--Appalachian low and medium sulfur. The base technology for all cases includes a low-N[O.sub.x] burner with over-fire air (LNB and OFA). Base particulate control is a cold-side ESP for conventional technologies and jet-pulse FF for integrated technologies. The table contains the revenue requirement needed to recover cost (on a $/mWh-net basis) and the portion attributable to emission control costs. Total cost contains the cost of the base plant plus the cost of emissions technology. Coal costs are contained in the base plant costs. (9) The unit of $/m Wh-net reflects the cost of production per net megawatt-hour of electricity produced. The net measure indicates electricity produced minus electricity used to run the technology.
The lowest cost method to meet the scenario of reducing both S[O.sub.2] and N[O.sub.x] by 90% while meeting the 1990 CAAA particulates standard of 0.03 lb/MBtu is the base case with low-sulfur coal. Low-sulfur coal is sufficient to meet the emissions constraint of 2.5 lb/MBtu, while a low-N[O.sub.x] burner reduces N[O.sub.x] enough to meet 0.45 lb/MBtu. The use of medium-sulfur coal resulted in 3.1 lb/MBtu in the base case, exceeding the emissions constraint. For the 1990 CAAA, Appalachian low-sulfur coal produced a lower cost than any of the other six coal options. In scenarios reflecting more stringent standards, Appalachian low-sulfur and medium-sulfur coal were the options considered.
An asterisk next to a subtotal indicates that the emissions technology reduced sulfur emissions considerably below the required level. Had the firm known with certainty that S[O.sub.2] or N[O.sub.x] standards would be further reduced at a future time, the firm could have evaluated whether to adopt the more expensive technology then rather than alter the lower cost, higher emitting technology when a new regulation begins. The second integrated technology under development at DOE, simply called N[O.sub.x]SO, allows the firm to exceed the standard by a considerable margin.
In order to meet the more stringent NSPS restrictions, the lowest cost solution is to add N[O.sub.x] catalytic control (SCR) while continuing to use low-sulfur coal. It is no longer possible to achieve the emissions constraint using low-sulfur coal and the base case configuration. The incremental cost of meeting the more stringent NSPS is $1.53/mWh-net ($39.74-$38.21).
Again, if a firm knew that sulfur emissions would be further constrained in the future, the firm would consider adopting an integrated technology. By making the decision to use the N[O.sub.x] technology, the firm will be more likely to add a scrubber (wet FGD) to reduce sulfur in response to a tighter sulfur constraint in the future, such as the standard of the NCCSA. The results suggest that the integrated CuO technology is likely to be able to control both N[O.sub.x] and S[O.sub.2] at a lower cost.
B. Cost of Meeting the NCCSA
North Carolina coal-fired electric plants are now evaluating technologies to achieve the more stringent requirements of the NCCSA. The North Carolina legislation translates to reduced S[O.sub.2] emissions of 0.16 lb/MBtu by 2013 and reduced N[O.sub.x] emissions of 0.07/lb/MBtu by 2009.
Before considering the simultaneous tightening of both S[O.sub.2] and N[O.sub.x], suppose North Carolina had tightened one standard, while leaving the other unchanged. Consider a firm that initially met the NSPS, but now must meet the tighter NCCSA standard for either S[O.sub.2] or N[O.sub.x]. Table 3 shows the costs for the tighter N[O.sub.x] standard first, while not changing the NSPS S[O.sub.2] standard, followed by the NCCSA S[O.sub.2] standard, while maintaining the NSPS N[O.sub.x] standard. Finally, the table shows the costs if both standards are tightened.
If the NCCSA tightened N[O.sub.x] emissions only, as compared to NSPS, the lowest cost technology is SCR with low-sulfur coal, which was also the lowest cost technology to meet NSPS. The additional cost of meeting the tighter N[O.sub.x] constraint is $0.34/mWh ($40.08-$39.74). As was the case if a firm had to adapt to NSPS from CAAA, the lowest cost solution is to install SCR.
Alternatively, if only sulfur emissions are tightened, the firm cannot meet the new emissions standard without sulfur technology. The only feasible solutions are to install FGD as well as SCR, or use an integrated technology. A firm building a new plant would find the integrated CuO technology to be the lowest cost.
A firm meeting the 1990 CAAA, but not required to meet NSPS, would also install CuO technology, since it had not previously installed any emissions technology. But a firm that was subject to NSPS would have already installed SCR. For this firm, adding FGD would be cheaper than the integrated solution. Cost increases by $5.23/mWh ($44.97-$39.74), as compared to scrapping SCR and installing CuO technology at a cost of approximately $6.00.
Similarly, if North Carolina had tightened N[O.sub.x] first, followed by S[O.sub.2], a utility would find it costs less to add FGD than to scrap SCR and install CuO technology. Yet the lowest cost method of achieving the dual standards is CuO technology. Had North Carolina tightened the S[O.sub.2] standard first, followed by N[O.sub.x], there would be no such conflict. The integrated CuO technology is the lowest cost solution for both of these cases. Again, it should be noted that a firm subject to the 1990 CAAA standards would also choose CuO technology, while a firm that complied with the 1997 NSPS by installing SCR would find it less costly to add FGD to meet the 2002 standard, even though CuO technology would be the lowest cost solution if the firm had not installed an SCR.
In the United States, firms needing to meet stringent S[O.sub.2] requirements have looked toward scrubbers (FGDs). To meet stringent N[O.sub.x] standards, they have generally considered the installation of catalytic converters (SCRs). (10) This technology combination is denoted by "separated" technology. Typically firms installed FGD to meet the year 2000 sulfur standard of the 1990 CAAA. For firms that were subject to the NSPS, they have also added an SCR. For this sequential technology, costs are lower with Appalachian medium-sulfur coal than with low-sulfur coal.
Cost figures for the fluidized bed CuO process are from DOE research, which developed the process at its Federal Energy Technology Center in conjunction with, among others, Carnegie Mellon University. The cost difference, including the base plant (coal, boiler, ash disposal, etc.), is approximately $2.50, approximately 6% of the total cost of producing 1 mWh. The emission control cost of the CuO system is $7.10, considerably lower than the separate controls. Compared to separate controls with low-sulfur coal, the difference is $1.73, more than 20% less.
Proponents of long-term, multipollutant legislation use this argument to suggest the savings from a multipollutant approach. In order for firms to use the lowest cost technology, controls will have to be long term and stable. Environmental legislation needs to consider that in complying with one standard there are changes in other effluents, as well as changes in the cost of complying with future standards.
One additional consideration is how the technologies compare in their effects on other emissions, such as mercury, particulates, and carbon. In the Table 3 scenarios, solutions were required to meet the EPA PM standard of 0.03 lb/MBtu. The PM control used with conventional technologies is the ESP, while the lowest cost PM control for integrated technology is the pulse-jet FF. The two alternatives led to similar costs for PM control, ranging from about $1.10/mWh-net to $1.45/m Wh-net. The amounts were generally higher for low-sulfur coal. However, this cost was included in the subtotal of emissions control costs, so that despite this secondary effect, low-sulfur coal with integrated technology was the most cost-effective solution. But a more complete analysis should consider secondary effects on mercury and possibly carbon. From an efficiency standpoint, all effects, not just direct effects, should be included.
IV. BENEFITS VERSUS COSTS OF TIGHTER STANDARDS FOR S[O.sub.2] AND N[O.sub.x]
As new scientific evidence shows harm from ever smaller amounts of emissions, environmental legislation continues to reduce the amount of allowable emissions of S[O.sub.2] and N[O.sub.x]. Society experiences benefits, primarily from reduced mortality and morbidity, as well as secondary benefits such as increased agricultural production and greater visibility. While federal standards proposed by the EPA are not required to meet a benefit/cost test, it is desirable to compare benefits to costs. For states that propose standards more stringent than the federal standard, as in the case of the NCCSA, it is certainly appropriate to consider the benefits and costs of a more stringent standard.
[FIGURE 1 OMITTED]
Consider the three sets of standards: 1990 CAAA, 1997 NSPS, and the NCCSA. We consider the annual benefits and costs of moving from the CAAA to NSPS to NCCSA, as well as NSPS to NCCSA. According to Banzhaf et al. (2002), a reasonable range for benefits from reducing S[O.sub.2] is between $1700/ton to $4700/ton. For N[O.sub.x], the value is between $700/ton and $1200/ton. (11)
Figure 1 shows annual net benefits among the three standards for the two coal types and for the high and low benefit estimates, based on the plant considered in the earlier tables. Appendix A contains three tables, each determining net benefits from more stringent standards. Table A1 is a comparison of CAAA to NSPS, Table A2 compares NSPS to NCCSA, and Table A3 compares CAAA to NSCS. The tables include calculations based on the change in total cost, and alternatively, the change in the emissions cost. The use of emissions cost affects the magnitude, but not the sign, of the net benefits measure.
The IECM calculates the annual change in emissions, measured in tons, for the two pollutants. Total benefit adds the benefit from sulfur and N[O.sub.x] emissions. The separate benefits are the dollar per ton benefit, multiplied by the change in tons. The cost is the addition to cost from the more stringent standard, using the revenue requirement from the previous tables. Note that reductions in sulfur and N[O.sub.x] emissions are a joint good, so that with multiple emissions, costs cannot be separated.
For both the high and low benefit cases, there is a negative net benefit when firms that meet CAAA are required to meet the NSPS. The lowest cost method to meet the more stringent standard is to add an SCR. The annualized cost of the SCR, even allowing for the use of lower cost medium-sulfur coal, outweighs the benefit of lower sulfur and N[O.sub.x].
The usual convexity assumptions would predict that if the more stringent NSPS falls short on benefit/cost grounds, then even more stringent controls will be inefficient. In contrast, Figure 1 shows benefits exceed costs for moving from CAAA or NSPS to NCCSA. The net benefits are larger when the firm adapts from CAAA to NCCSA. Net benefits are in excess of $45 million for the high benefit case and in excess of $10 million for the low benefit case.
The primary explanation is the nonconvexity of marginal cost. The incremental cost of moving to the most stringent standard, as compared to the intermediate standard, is relatively small. Another factor is that marginal benefit is being held constant. If marginal benefit decreased with the more stringent standard, the net benefit to NCCSA would decrease. As the emphasis in this article is on determining costs, it is left to future research to reconsider benefits when there is a more detailed estimation of marginal benefits. (12)
V. UNCERTAINTY CONSIDERATIONS
Given the initial assumptions of the simulation, the lowest cost method for achieving the NCCSA standards is to adopt a CuO process along with low-sulfur coal. Embedded in the simulation is a set of default assumptions, including some parameters specified with probability distributions. Figure 2 shows a probabilistic distribution of costs for CuO with low-sulfur coal. Appendix B summarizes uncertainty parameter settings.
The lowest cost alternative was combining SCR and FGD. The expected cost of this technology is $45.12, considerably above the mean for CuO of $41.67. However, there is some overlap of the probability distributions, so that the cost of CuO could exceed that of SCR plus FGD. (13)
[FIGURE 2 OMITTED]
Finally, there is a sensitivity analysis that allows the financial assumptions regarding interest rates to increase or decrease. Table 4 shows a cost comparison for the original default case, as well as higher and lower costs of capital.
Copper oxide with low-sulfur coal remains the lowest cost option for all cases. Low interest rates do reduce the cost savings from CuO compared to SCR plus FGD. Were interest rates to continue to decline, it would be appropriate to make sure that CuO still has a cost advantage.
There has been increasing attention paid to multiple pollutants in environmental legislation. The motivation for the multipollutant approach is to reduce the cost to electric utilities of meeting emissions constraints. The "piecemeal" approach, whereby regulations do not consider the interactions among emissions, results in the possibility that firms will choose technologies that result in excessive costs when regulations are later tightened. With the availability of integrated technologies that can reduce more than one pollutant at a time, a potential benefit of multipollutant legislation is to encourage R & D as well as adoption of integrated technology when it minimizes costs.
In the scenarios considered in this article, the lowest cost technology to meet the 1990 CAAA required basic technologies, but not the use of scrubbers or catalytic converters to meet S[O.sub.2] or N[O.sub.x] standards. Firms with plants subject to the 1997 NSPS had to consider catalytic devices such as SCRs in order to meet tougher N[O.sub.x] restrictions. Although NSPS tightened sulfur restrictions as well, it was still possible to minimize the cost of meeting NSPS without a scrubber (FGD).
The coal-fired facilities of North Carolina electric utilities will be subject to still more stringent controls on sulfur and N[O.sub.x] emissions than those in NSPS. These firms will not be able to meet the new standards with N[O.sub.x] control alone. They must either add more technology such as a scrubber (FGD) to reduce sulfur further, or use integrated technology such as the CuO process.
According to the simulation, firms that were formerly subject to the 1990 CAAA standards would find it most cost effective to install the integrated CuO process under development at the DOE. In that case, the firms choose the lowest cost technology. But firms that were subject to the 1997 NSPS that had already installed a catalytic device (SCR) will find it less costly to add a scrubber (FGD) rather than to scrap the catalytic device and replace it with an integrated technology, even though the cost to a new firm would be lower with integrated technology.
Requiring firms that meet the 1990 CAAA to meet the more stringent 1997 NSPS has costs in excess of benefits. The usual convexity assumptions lead to the expectation that costs will exceed benefits for the still more stringent standards of the NCCSA legislation. However, that legislation has positive net benefits, whether the producer is moving from the CAAA or the NSPS. The IECM model that simulates engineering production costs allows for nonconvexity of costs; the increase in costs from NSPS to NCCSA is relatively small as compared to the increase in benefits, as the firm takes advantage of integrated technology to meet the most stringent standard. Results are robust with respect to simulations that allow for uncertainty in parameters, as well as a sensitivity analysis that considers an increase or a decrease in financing costs. In order for firms to choose the technology that is most cost effective, emissions standards should be chosen that recognize the relationship between emissions and the choices of technology. Today's regulations must consider the impact on future compliance costs, given the historic trend toward ever more stringent standards.
APPENDIX A: NET BENEFITS FROM MORE STRINGENT S[O.sub.2] AND NOX CONTROLS
TABLE A1 Annual Benefit and Cost Analysis (CAAA to NSPS) Constraint CAAA NSPS SO2 (lb/Mbtu) 2.5 1.2 NOX (lb/Mbtu) 0.45 0.15 Pollutant Control Base case NOx Control (SCR) Coal L/S L/S [DELTA] Benefit CAAA (Total Benefits) NSPS (Benefit Change) High Benefit SO2 ($4,700/ton) $64,290,078 $432,306 NOX ($1,200/ton) $3,851,334 $2,107,393 subtotal $68,141,412 $2,539,699 Low Benefit SO2 ($1,800/ton) $24,621,732 $165,564 NOX ($700/ton) $2,246,612 $1,229,313 subtotal $26,868,344 $1,394,877 [DELTA] Costs CAAA (Total Cost) NSPS (Cost Change) Revenue Requirement $117,700,000 $3,500,000 ($/yr) Emission cost ($/yr) $5,829,000 $4,077,000 Revenue Requirement $38.21 $1.53 ($/MWh) Emission cost ($/MWh) $1.89 $1.34 [DELTA](Benefit--Cost) CAAA NSPS High Benefit base case $(960,300.80) Low Benefit base case $(2,105,123.30) TABLE A2 Annual Benefit and Cost Analysis (NSPS to NCCSA) Regulation NSPS NCCSA NCCSA Technology N[O.sub.x] SCR + FGD SCR + FGD control (SCR) Coal LS MS LS S[O.sub.2] (lb/MBtu) 1.2 0.16 0.16 N[O.sub.x] (lb/MBtu) 0.15 0.07 0.07 [DELTA]Benefit NSPS NCCSA NCCSA (Total B) ([DELTA]B) ([DELTA]B) High Benefit S[O.sub.2] $63,857,772 $53,025,419 $53,056,298 ($4,700/ton) N[O.sub.x] $1,743,941 $927,947 $930,312 ($1,200/ton) [DELTA]Benefit NSPS NCCSA NCCSA (Total B) ([DELTA]B) ([DELTA]B) Subtotal $65,601,713 $53,953,366 $53,986,610 Low Benefit S[O.sub.2] $24,456,168 $20,307,607 $20,319,433 ($1,800/ton) N[O.sub.x] ($700/ton) $1,017,299 $541,302 $542,682 Subtotal $25,473,467 $20,848,910 $20,862,115 [DELTA]Costs NSPS NCCSA NCCSA (Total Cost) ([DELTA]C) ([DELTA]C) Rev Req ($/yr) $121,200,000 $9,200,000 $13,400,000 Emission Cost ($/yr) $9,906,000 $19,004,000 $16,624,000 Rev Req ($/MWh) $40 $6 $7 Emission Cost ($/MWh) $3 $6 $6 [DELTA]Benefit vs. NSPS NCCSA NCCSA [DELTA] Cost High Benefit Baseline $44,753,366 $40,586,610 Low Benefit Baseline $11,648,910 $7,462,115 Regulation NCCSA NCCSA Technology CuO CuO Coal MS LS S[O.sub.2] (lb/MBtu) 0.16 0.16 N[O.sub.x] (lb/MBtu) 0.07 0.07 [DELTA]Benefit NCCSA ([DELTA]B) NCCSA ([DELTA]B) High Benefit S[O.sub.2] $53,028,507 $53,062,474 ($4,700/ton) N[O.sub.x] $927,947 $930,312 ($1,200/ton) [DELTA]Benefit NCCSA ([DELTA]B) NCCSA ([DELTA]B) Subtotal $53,956,454 $53,992,786 Low Benefit S[O.sub.2] $20,308,790 $20,321,798 ($1,800/ton) N[O.sub.x] ($700/ton) $541,302 $542,682 Subtotal $20,850,092 $20,864,480 [DELTA]Costs NCCSA ([DELTA]C) NCCSA ([DELTA]C) Rev Req ($/yr) $12,500,000 $9,700,000 Emission Cost ($/yr) $16,704,000 $8,594,000 Rev Req ($/MWh) $4 $3 Emission Cost ($/MWh) $5 $4 [DELTA]Benefit vs. NCCSA NCCSA [DELTA] Cost High Benefit $41,456,454 $44,292,786 Low Benefit $8,350,092 $11,164,480 TABLE A3 Annual Benefit and Cost Analysis (CAAA to NCCSA) Regulation CAAA NCCSA NCCSA S[O.sub.2] (lb/MBtu) 2.5 0.16 0.16 N[O.sub.x] (lb/MBtu) 0.45 0.07 0.07 Pollutant Control Base Case SCR + FGD SCR + FGD (ton/yr) Coal L/S M/S L/S CAAA NCCSA NCCSA Benefits Change (Total B) (Change) (Change) High Benefit S[O.sub.2] ($4700/ton) $64,290,078 $53,457,725 $53,488,604 N[O.sub.x] ($1200/ton) $3,851,334 $3,035,340 $3,037,705 Subtotal $68,141,412 $56,493,065 $56,526,309 Low Benefit S[O.sub.2] ($1800/ton) $24,621,732 $20,473,171 $20,484,997 N[O.sub.x] ($700/ton) $2,246,612 $1,770,615 $1,771,995 Subtotal $26,868,344 $22,243,786 $22,256,992 CAAA NCCSA NCCSA Cost Change (Total C) (Change) (Change) Rev Req ($/yr) $117,700,000 $12,700,000 $13,400,000 Emission Cost ($/yr) $5,829,000 $23,081,000 $16,624,000 Rev Req ($/MWh) $38 $7 $7 Emission Cost $2 $8 $6 ($/MWh) (Benefits--Costs) Change CAAA NCCSA NCCSA High Benefit Base case $43,793,065 $43,126,309 Low Benefit Base Case $9,543,786 $8,856,992 Regulation NCCSA NCCSA S[O.sub.2] (lb/MBtu) 0.16 0.16 N[O.sub.x] (lb/MBtu) 0.07 0.07 Pollutant Control CuO CuO (ton/yr) Coal M/S L/S NCCSA NCCSA Benefits Change (Change) (Change) High Benefit S[O.sub.2] ($4700/ton) $53,460,813 $53,494,780 N[O.sub.x] ($1200/ton) $3,035,340 $3,037,705 Subtotal $56,496,153 $56,532,485 Low Benefit S[O.sub.2] ($1800/ton) $20,474,354 $20,487,362 N[O.sub.x] ($700/ton) $1,770,615 $1,771,995 Subtotal $22,244,969 $22,259,357 Cost Change NCCSA NCCSA (Change) (Change) Rev Req ($/yr) $12,500,000 $9,700,000 Emission Cost ($/yr) $16,704,000 $8,594,000 Rev Req ($/MWh) $4 $3 Emission Cost $5 $4 ($/MWh) (Benefits--Costs) NCCSA NCCSA Change High Benefit $43,996,153 $46,832,485 Low Benefit $9,744,969 $12,559,357 TABLE B1 Default Uncertainty Assumptions in the IECM Model Control Technology Parameters Nominal Value Common Base Plant/Perf Gross Cycle Heat 7880 Rate Base Plant/Perf Capacity Factor 75 Base Plant/Perf Excess Air to 20 Boiler Base Plant/Perf Leakage Across 19 Air Preheater Base Plant/Finn Fixed Charge 0.1034 Factor (FCF) Base Plant/Finn Real Return on 4.60 Debt Base Plant/Finn Real Return on 8.70 Common Stock Base Plant/Finn Real Return on 5.20 Preferred Stock Mercury Control Furnace Removal 7.00 PM control/Perf Specific 384.00 Collection Area PM control/Perf Energy Requirement 0.2185 (Penalty) PM control/Capital General Facilities 1.00 Capital PM control/Capital Engineering & Home 5.00 Office Fees PM control/Capital Process 20.00 Contingency Cost PM control/Capital Project 0.00 Contingency Cost PM control/O & M Waste Disposal 11.3 Cost Conventional SO2 control/Addi. Dibasic Acid 20 (Wet FGD) Makeup SO2 control/Perf Molar Stoichiometry 1.03 SO2 control/Capital General Facilities 10 Capital SO2 control/Capital Engineering & Home 10 Office Fees SO2 control/Capital Project Contingency 15 Cost SO2 control/Capital Process Contingency 2 Cost SO2 control/O & M Limestone Cost 16.21 SO2 control/O & M Disposal Cost 8.809 SO2 control/O & M Dibasic Acid Cost 389.1 Conventional NoX control/Perf Min Activity 0.5 (SCR) NoX control/Perf Activity at 0.85 Reference Time NoX control/Perf Total Pressure Drop 9 NoX control/Perf Ammonia Slip 5 NoX control/Perf Energy Requirement 0.5183 (Penalty) NoX control/Capital General Facilities 10 Capital NoX control/Capital Engineering & Home 10 Office Fees NoX control/Capital Project Contingency 10 Cost NoX control/Capital Process Contingency 5.054 Cost NoX control/Capital Misc. Capital Costs 2 NoX control/Capital Inventory Capital 0.5 NoX control/O & M Ammonia Cost 204.9 NoX control/O & M Catalyst Cost 324.2 NoX control/O & M Total Maintenance 2 Cost NoX control/O & M Admin & Support 30 Cost Integrated CuO control/Perf Sorbent 1.387 Stoichiometry Copper CuO control/Perf Ammonia 0.7887 Oxide Stoichiometry CuO control/Perf Absorbers 2.00E-02 CuO control/Perf Circulation System 4.70E-02 CuO control/Absor. Sprbent Fluidized 26.6 Bed Density CuO control/Rege. CuSO3 Regeneration 80 Efficiency CuO control/Capital General Facilities 10 Capital CuO control/Capital Engineering & Home 15 Office Fees CuO control/Capital Project Contingency 20 Cost CuO control/Capital Process Contingency 14.10 Cost CuO control/Capital Misc. Capital Costs 2 CuO control/Capital Inventory Capital 0.5 CuO control/O & M Sorbent Cost 5.38 CuO control/O & M Ammonia Cost 204.9 CuO control/O & M Natural Gas Cost 3.783 CuO control/O & M Total Maintenance 4.5 Cost Prob Control Technology Unit Dist Common Base Plant/Perf Btu/kWh -1/2 N Base Plant/Perf % N Base Plant/Perf % N Base Plant/Perf % N Base Plant/Finn Fraction U Base Plant/Finn % N Base Plant/Finn % N Base Plant/Finn % N Mercury Control % T PM control/Perf acfm/ft2 N PM control/Perf %MWg N PM control/Capital %PFC N PM control/Capital %PFC N PM control/Capital %PFC N PM control/Capital %PFC N PM control/O & M $/ton T Conventional SO2 control/Addi. n of SO2 rem N (Wet FGD) SO2 control/Perf mol Ca/S T SO2 control/Capital %PFC L SO2 control/Capital %PFC 1/2 N SO2 control/Capital %PFC U SO2 control/Capital %PFC 1/2 N SO2 control/O & M $/ton U SO2 control/O & M $/ton T SO2 control/O & M $/ton N Conventional NoX control/Perf U (SCR) NoX control/Perf N NoX control/Perf in H2O gauge N NoX control/Perf ppmv T NoX control/Perf %MWg N NoX control/Capital %PFC N NoX control/Capital %PFC T NoX control/Capital %PFC N NoX control/Capital %PFC N NoX control/Capital %TPI N NoX control/Capital %TPC N NoX control/O & M $/ton U NoX control/O & M $/ton T NoX control/O & M %TPC N NoX control/O & M %total labor N Integrated CuO control/Perf total Cu/mol N Copper CuO control/Perf nol N/mol NO N Oxide CuO control/Perf % of bed inven T CuO control/Perf % of circulati T CuO control/Absor. lb/cu ft T CuO control/Rege. % U CuO control/Capital %PFC N CuO control/Capital %PFC N CuO control/Capital %PFC N CuO control/Capital %PFC N CuO control/Capital %TPI N CuO control/Capital %TPC N CuO control/O & M $/lb T CuO control/O & M $/ton U CuO control/O & M $/mscf T CuO control/O & M %TPC N Normalized Control Technology Values Note Common Base Plant/Perf (1.0, 0.018) N-Normal Base Plant/Perf (1.0, 0.07) 1/2 N-Half Normal Base Plant/Perf (1.0, 0.025) -1/2 N-Neg Half Normal Base Plant/Perf (1.0, 0.025) U-Uniform Base Plant/Finn (0.7, 1.3) T-Triangular Base Plant/Finn (1.0, 0.1) Base Plant/Finn (1.0, 0.1) Base Plant/Finn (1.0, 0.1) Mercury Control (0, 1.0, 1.429) PM control/Perf (1.0, 0.05) PM control/Perf (1.0, 0.1) PM control/Capital (1.0, 0.1) PM control/Capital (1.0, 0.1) PM control/Capital (1.0, 0.1) PM control/Capital (1.0, 0.1) PM control/O & M (0.8X, 1.0X, 1.2X) Conventional SO2 control/Addi. (1.0, 0.08) (Wet FGD) SO2 control/Perf (1.02, 1.03, 1.05) SO2 control/Capital (1.0, 0.013) SO2 control/Capital (1.0, 0.17) SO2 control/Capital (0.67X, 1.33X) SO2 control/Capital (1.0, 0.50) SO2 control/O & M (0.7X, 1.3X) SO2 control/O & M (0.61X, 1X, 1.84X) SO2 control/O & M (1.0, 0.05) Conventional NoX control/Perf (1X, 1.5X) (SCR) NoX control/Perf (1.0, 0.03) NoX control/Perf (1.0, 0.05) NoX control/Perf (1X, 1.001X, 2X) NoX control/Perf (1.0, 0.05) NoX control/Capital (1.0, 0.1) NoX control/Capital (0.7X, 1X, 1.5X) NoX control/Capital (1.0, 0.1) NoX control/Capital (1.0, 0.1) NoX control/Capital (1.0, 0.1) NoX control/Capital (1.0, 0.1) NoX control/O & M (1X, 1.5X) NoX control/O & M (0.67X, 1X, 1.33X) NoX control/O & M (1.0, 0.1) NoX control/O & M (1.0, 0.1) Integrated CuO control/Perf (1.0, 0.05) Copper CuO control/Perf (1.0, 0.0625) Oxide CuO control/Perf (0.5X, 0.55X, 1X) CuO control/Perf (0.43X, 1X, 1X) CuO control/Absor. (0.92X, 1X, 1.08X) CuO control/Rege. (0.5, 1.0) CuO control/Capital (1.0, 0.1) CuO control/Capital (1.0, 0.1) CuO control/Capital (1.0, 0.2) CuO control/Capital (1.0, 0.3) CuO control/Capital (1.0, 0.1) CuO control/Capital (1.0, 0.1) CuO control/O & M (0.5X, 1X, 1X) CuO control/O & M (1X, 1.5X) CuO control/O & M (0.5X, 1X, 1X) CuO control/O & M (1.0, 0.1) TABLE 1 Selected IECM S[O.sub.2] and N[O.sub.x] Control Options for a Coal-Fired Plant Targeted Emission Pollutant Control Sulfur (SO2) Nitrogen (NOx) Precombustion Coal type (i.e., low-sulfur coal) Combustion In-furnace control (i.e., low-NOx burner (LNB)) Postcombustion Scrubber (i.e., flue gas Catalytic desulfurization (FGD)) converter (i.e., hot-side selective catalytic removal (SCR)) Integrated technology (i.e., fluidized bed copper oxide (CuO) process) TABLE 2 Cost of Production Alternatives to Comply with 1990 CAAA and 1997 NSPS Emission Coal Type (LS, MS) + Technology Revenue Requirement Cost (FGD, SCR, CuO, N[O.sub.x]SO) ($/mWh) ($/mWh) MS (Base Case) 1990 CAAA N/A (S > 2.5 lb/MBtu) 1997 NSPS N/A (S, N[O.sub.x] > lb/MBtu) LS (Base Case)# 1990 CAAA# $38.21# $1.888# 1997 NSPS N/A (N[O.sub.x] > 0.15 lb/ MBtu) MS + FGD 1990 CAAA $42.33 $7.085 1997 NSPS N/A (N[O.sub.x] > 0.15 lb/ MBtu) LS + FGD 1990 CAAA $45.81 $7.923* 1997 NSPS $47.37 $9.304 MS + SCR 1990 CAAA $42.33 $7.085 1997 NSPS N/A (S > 2.5 lb/MBtu) LS + SCR# 1990 CAAA $39.68 $3.165 1997 NSPS# $39.74# $3.226# MS + SCR + FGD 1990 CAAA $43.96 $8.517 1997 NSPS $44.31 $8.868 LS + SCR + FGD 1990 CAAA $47.31 $9.248* 1997 NSPS $47.37 $9.304 MS + CuO 1990 CAAA $39.53 $5.048 1997 NSPS $41.83 $7.311 LS + CuO 1990 CAAA N/A (floating point error) 1997 NSPS N/A (floating point error) MS + N[O.sub.x]SO 1990 CAAA N/A (floating point error) 1997 NSPS $46.53 $11.55 LS + N[O.sub.x]SO 1990 CAAA $45.62 $8.502* Production method with lowest total cost is in bold. Asterisk (*) indicates that method exceeds emissions standard. Amounts are in constant 1999 dollars. Revenue requirement is amount needed per mWh to recoup cost. CAAA emissions standards are 2.5 lb/MBtu S[O.sub.2] and 0.45 lb/MBtu N[O.sub.x]. NSPS 1997 emissions standards are 1.2 lb/MBtu S[O.sub.2] and 0.15 lb/MBtu N[O.sub.x]. A floating point error occurs when a calculation involves dividing by zero. Note: Production method with lowest total cost indicated with #. TABLE 3 Tightening Either N[O.sub.x], S[O.sub.2], or Both Emissions: 2002 NCCSA Standard Emission Coal Type (LS, MS) + Technology Revenue Requirement Cost (FGD, SCR, CuO, N[O.sub.x]SO) ($/mWh) ($/mWh) LS + SCR# N[O.sub.x] lower# $40.08# $3.560# S[O.sub.2] lower N/A (S > 0.16 lb/MBtu) N[O.sub.x] lower, N/A (S, N[O.sub.x] > S[O.sub.2] lower allowed lb/MBtu) MS + SCR + FGD N[O.sub.x] lower $44.46 $9.215 S[O.sub.2] lower $44.97 $9.406 N[O.sub.x] lower, $45.26 $9.716 S[O.sub.2] lower LS + SCR + FGD N[O.sub.x] lower $47.65 $9.613 S[O.sub.2] lower $46.07 $8.545 N[O.sub.x] lower, $46.41 $8.883 S[O.sub.2] lower MS + CuO N[O.sub.x] lower $41.86 $7.349 S[O.sub.2] lower $43.32 $8.588 N[O.sub.x] lower, $43.34 $8.610 S[O.sub.2] lower LS + CuO# N[O.sub.x] lower N/A (floating point error) S[O.sub.2] lower# $42.73# $6.002# N[O.sub.x] lower, $42.75# $7.097# S[O.sub.2] lower# Only technologies that can achieve emissions constraints are shown. N[O.sub.x]SO is omitted because it is higher cost than CuO. The lowest cost method is in bold. Amounts are in constant 1999 dollars. NCCSA 2002 emissions standards are 0.16 lb/MBtu S[O.sub.2] and 0.07 lb/ MBtu N[O.sub.x]. Revenue requirement is the amount needed per mWh to recoup cost. A floating point error occurs when a calculation involves dividing by zero. Note: The lowest cost method indicated with #. TABLE 4 Sensitivity of Technology Costs to Capital Cost Assumptions Coal Type (LS, MS) + Technology (FGD, SCR, CuO, Revenue Requirement Emission Cost N[O.sub.x]SO) ($/mWh) ($/mWh) MS + SCR + FGD Base $45.26 $9.72 Increase $46.63 $8.93 Decrease $39.89 $8.84 LS + SCR + FGD Base $46.41 $8.88 Increase $45.49 $9.77 Decrease $41.08 $7.76 MS + CuO Base $43.34 $8.61 Increase $43.53 $8.63 Decrease $38.86 $8.18 LS + CuO Base $42.75# $7.10# Increase $42.94# $6.05# Decrease $38.25# $5.62# MS + N[O.sub.x]SO Base $47.70 $12.29 Increase $47.93 $12.34 Decrease $42.27 $11.03 LS + N[O.sub.x]SO Base $48.11 $10.48 Increase $48.55 $10.67 Decrease $42.95 $9.49 (a) The default assumptions for return on debt, common, and preferred stock are 4.6%, 5.2%, 8.7%. (b) Assumptions for the "increase" case are 5.52%, 6.24%, 10.44% (a 20% increase in rates). (c) Assumptions for the "decrease" case are 3.68%, 4.16%, 6.96% (a 20% decrease in rates). The lowest cost case is in bold. Note: The lowest cost case indicated with #.
CAAA: Clean Air Act
NSPS: New Source Performance Standards
NCCS: North Carolina Clean Smokestacks
S[O.sub.2]: Sulfur Dioxide
N[O.sub.x]: Nitrous Oxide
PM: Particulate Matter
C[O.sub.2]: Carbon Dioxide
EPA: United States Environmental Protection Agency
DOE: Department of Energy
IECM: Integrated Environmental Control Model
CMU: Carnegie Mellon University
FGD: Flue Gas Desulfurization
SCR: Selective Catalytic Removal
CuO: Copper Oxide
LNB: Low-NOx Burner
OFA: Overfire Air
SIP: State Implementation Plan
ESP: Electrostatic Precipitator
FF: Fabric Filter
LS: Low Sulfur
MS: Medium Sulfur
1. This statement is one of several in favor of a flexible, integrated approach to environmental legislation contained in the executive summary of the Clean Skies Initiative at http://www.whitehouse.gov/news/releases/2002/02/clearskies.html. Environmentalists seek the inclusion of carbon emissions as a fourth standard, whereas the Bush administration and the electric utility industry favor restricting standards to three emissions. See Burtraw (2002) for a discussion of this debate.
2. For a recent statement of this suggested policy reform, see Burtraw and Palmer (2004).
3. Were the North Carolina legislation to allow emissions trading, firms could attain the more stringent goals at a lower cost. Trading would give the option of not upgrading to meet the more stringent standard, while firms that can meet the new standard at a lower cost could reduce emissions and sell permits. Even so, overall cost would not necessarily be minimized, as firm decisions would depend on their existing technologies to meet earlier standards. This article does not consider trading, given that firms cannot use emissions trading to achieve the North Carolina goal.
4. Other articles with multipollutant aspects include a paper by Montero (2001) that models marketable permit systems for multipollutant markets by introducing an exchange rate between permits. Two articles correct for multiple emissions in measuring electric utility productivity [see Faere et al. (1989) and Yaisawarng and Klein (1994)]. A book by Dhanda et al. (1999) develops a network approach to modeling markets with single and multiple emissions. They use simulations to evaluate how emissions affect emissions trading prices and quantities, as well as output prices and quantities. Maranas and Gupta (2003) are developing a simulation of electricity production that includes emissions trading.
5. There is a dissertation in progress by Echeverri that uses the IECM along with decision techniques to measure the cost of regulatory uncertainty for a coal-fired power plant by estimating the value of having perfect information.
6. There are a variety of units used to express constraints, including tons per year and pounds per megawatt (lb/mW). The IECM expresses emissions constraints in pound per million Btu, which relates emissions to the fuel input, in this case the input of coal. This article uses the notation MBtu throughout. Equivalent notations that are used elsewhere are mmBTU and MMBtu.
Using lb/mW relates emissions to the electricity output. There is discussion that constraints in pounds per megawatt-hour (lb/m Wh) of electricity output would lead to more efficient behavior than lb/mmBtu of fuel input. Currently firms have an incentive to minimize emissions per unit of fuel input, but not necessarily to minimize fuel input use. Defining the constraint in units of output would provide an incentive to minimize fuel inputs.
7. As of May 2004, the N[O.sub.x] standard for the eastern states participating in N[O.sub.x] trading is 0.15 lb/MBtu.
8. These numbers were provided as general guidelines by Mike Stroben, Manager, EHS Technical Analysis, Corporate Environmental Health and Safety, Duke Energy Company. The lower N[O.sub.x] figure is for a tangentially fired boiler, the default option for the IECM. The higher figure is for a wall-fired boiler. The actual number will be different at every facility, depending upon facility type, boiler technology, and coal type.
9. There are cases where the utility chooses a higher-cost emissions technology, yet the revenue requirement increases by less than the emissions cost. These two figures can increase by different amounts when the base plant costs decrease while emissions costs increase. One reason is that the firm has switched to a lower-cost coal, a part of base plant costs, while switching to a more expensive emissions technology. A second reason, mentioned earlier in the article, is that the size of the needed technology can change.
10. For example, Duke Energy has eight coal-fired electric plants. They have installed an SCR on one unit of their Cliffside plant and they expect to complete shortly the installation of two SCRs on both units of Belews Creek. Another technology is known as selective noncatalytic reduction (SNCR).
11. The ranges are from a 90% confidence interval Monte Carlo simulation to reflect uncertainty. The extreme values also encompass a sensitivity analysis that allows for differing values for the concentration response function for mortality effects and for the statistical value of human life. For example, the Monte Carlo simulation uses $2.25 million for the value of a statistical life, which yields a most likely estimate of $3500/ton for the marginal benefit of reducing S[O.sub.2] and $1100/ton for N[O.sub.x]. If the value-of-life estimate is $6.1 million, the marginal benefit of reducing S[O.sub.2] and N[O.sub.x] more than doubles, and the efficient caps for the two emissions are closer to the 90% end of the initial Monte Carlo estimates. All values are in 1999 dollars, consistent with costs.
12. However, Banzhaf et al. (2002) find marginal benefit on the national level to be relatively constant, so the assumption in this article appears reasonable. That article also notes the importance of nonconvexity on the benefit side.
13. A future version of the IECM will have the ability to compare two probability distributions, so as to provide a distribution for the cost difference. It would then be possible to conclude, for example, that there is a 15% probability that CuO is more costly than the alternative and an 85% probability that CuO is the lowest cost alternative.
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PETER M. SCHWARZ*
*This article is a revised version of a paper prepared for the Western Economics Association (WEA), Contemporary Economic Policy invited session, organized by Darwin Hall, California State University, Long Beach, July 12, 2003, in Denver, Colorado. The paper was also presented at the University of Colorado Environmental and Resource Economics Workshop, July 18, 2003, Boulder, Colorado. I wish to acknowledge the exceptional assistance of Hsiao-Wei Hsu, a former graduate student in economics, as well as from Alex Hanning, a current graduate student. I also wish to acknowledge funding received from the Global Institute of Energy and Environmental Systems (GIEES) and Duke Energy, as well as a university research grant from the University of North Carolina Charlotte Foundation. I thank Hilary Inyang, Director of GIEES, for being instrumental in bringing this topic to my attention, Mike Stroben at Duke Energy, and Norwood Davis, formerly at Duke Energy, for discussions and clarifications, Ed Rubin and Mike Berkenpas of Carnegie Mellon for assistance in using the Integrated Environmental Control Model (IECM), and