1 MEMORANDUM

From: Office of Air Qual ity Planning and Standards U.S. Environmental Protection Agency

To: EGU NSPS Docket (EPA-HQ-OAR-2011-0044)

Date: March, 2011

Subject: Incremental Control Co st, Energy, and Environmental Imp acts of Revisions to Electric Utility Steam Generating Unit NSPS under 40 CFR Part 60 subpart Da

Introduction The New Source Performance Standards (NSPS) unde r 40 CFR 60 subpart Da presently regulate the emissions of total filterable particulate matter (PM), sulfur dioxide (SO 2 ), and nitrogen oxides (NO X ) from new, modified, and reconstruc ted electric utility steam generating units (EGUs), as defined in the rule. The Clean Air Act (CAA) section 111(b)(1)( B) requires the U.S. Environmental Protection Agency (EPA) to periodically review and, if a ppropriate, revise NSPS to reflect improvements in emissions reduction methods. The EPA’s review of the NSPS for EGUs determined that revision of the existing NSPS for PM, SO 2 , and NO X emissions are appropriate to reflect the performance achievable by the best demonstrat ed technologies for controlling th ese pollutants. We have also concluded it is appropriate to cover petroleum coke-fired EGUs under subpart Da since the control costs would be similar as for coal-fired EGUs. NSPS are required under CAA section 111 to reflect the application of the best system of emissions reductions that EPA has determined to be adequately demonstrated (taking into account the cost of achieving such reductions, any non-air quality he alth and environmental impacts and energy requirements). The purpose of this memorandum is to describe the methods used for and present the results of EPA’s analysis to estimate the cost, non -air quality environmental, and energy impacts of achieving the emissions reductions that could be required under revisions to the PM, SO 2 , and NO X emission standards in the existing EGU NSPS.

Pollutants Emitted Emissions from EGUs contain, among othe r things, substantial amounts of PM, SO 2 , NO X , and carbon monoxide (CO). PM is associated with premat ure mortality and a number of serious adverse respiratory and cardiovascular effects, especially in children, the elderly, and people with existing heart or lung disease. PM also reduces visibi lity and damages building materials. SO 2 is a criteria pollutant and is considered harmful to public health and the environment. It c ontributes to respiratory illness, particularly in children and the elderly, and aggravates existing h eart and lung diseases. It also contributes to acid deposition and damage to forests, aquatic ecosyst ems, crops, and building materials. SO 2 undergoes chemical reactions in the atmosphere to form sulfate PM. NO 2 (measured collectively along with other nitrogen oxide co mpounds as the surrogate compound NO X ) is a criteria pollutant and is regulated due to its co ntribution to ozone formati on. Exposure to ozone ha s been linked to negative health and welfare impacts and incl udes impaired respiratory functi on, eye irritation, de terioration of materials such as rubber, and necrosis of plant tissue. NO X is also a major precursor for nitrate PM. NO X can cause irritation of the lungs and can also reduce resistance to respiratory infection. Because of its contribution to tropospheric ozone, NO X is also an indirect greenhouse gas (GHG). However, like tropospheric ozone, NO X increases hydroxyl (OH) abundance, which in turn decreases the2 atmospheric lifetime of potent GHGs like methane. CO is a criteria pollutant and is considered harmful to public health and the environment. It ha s been linked to increased risk to heart disease, reduced visual perception, cognitive functions and aerobic ca pacity, and possible feta l effects. CO is a weak GHG on its own. However, CO reacts with at mospheric OH to function as an indirect GHG, because decreased concentrations of OH in the atmosphere increase the atmospheric lifetime of stronger GHGs like methane. Impacts Estimate General Approach Control technologies for steam ge nerating units are based on pre-combustion controls, combustion controls, post-combustion c ontrols, or a combination of approach es. Pre-combustion controls remove contaminants from the fuel before it is bur ned, and combustion controls reduce the amount of pollutants formed during combustion. Post-combusti on controls remove pollutants from the flue gases before the gases are released to the atmosphere. To comply with the existing EGU NSPS, affected owners/operators of new coal-fired EGUs need to install air pollution controls to meet the emission standards for filterable PM, SO 2 , and NO X . The specific control configura tions used for an individual EGU will depend on site-specific factors including type and characteristics of the coal burned and the type of boiler used to burn the co al. The costs to install and operat e these controls will be incurred regardless of any revisions to the emission standards. Consequently, the contro l configuration used for a new coal-fired EGU to meet the existing EGU N SPS represents the referen ce point or “regulatory baseline” from which the additional control costs and associated non-ai r quality and energy impacts of complying with any alternative emission standards are determined. Revisions to the existing EGU NSPS would require furt her reductions in the amounts of total PM, SO 2 , and NO X emitted from coalfired EGUs subject to rule that begin c onstruction, modification, or reconstruction. Cost, non-air quality environmental, and energy impacts estimates were prepared for hypothetical “model plants” representative of the coal-fired EGUs and associated control system configurations that may build in the United States in the foreseeable future. The basis for the control system cost estimates (with one exception described later in this memorandum) are control algorithms and procedures developed by the EPA Clean Air Mark ets Division (CAMD). The cost estimates were prepared applying the applicable control system costing models used for the EPA Base Case v4.10_PTox analysis using the EPA’s Integr ated Planning Model (IPM (available at: http://www.epa.gov/airmarkt/p rogsregs/epa-ipm/toxics.html ) to the model plant configurations selected for this analysis. The cap ital costs for the all control systems were a nnualized using a capital recovery factor that assumes an inte rest rate of 7% and a period of 20 years. All costs are expressed as 2009 dollars. In addition, since the IPM cost procedures are primarily intended to estimate costs of retrofitting controls to existing un its, the costs estimated by the IPM are reduced a retr ofit factor of 0.77 to account for the controls being installed at model plants representing new EGUs. The costing algorithms and procedures used for this impact analysis are in tended to provide “study estimate” costs. Cost values obtained by this type of cost estimation method are on the order of ± 30% of the presumed actual costs for the control system being modeled. The model plant EGUs selected for this impact analysis do not represent specific actual coal-fired electric util ity power plant currently operating or under construction in th e United States. Furthermore, th e control costs estimated by this analysis are not intended to be directly applied to a specific coal-fired elec tric utility power plant location. Actual control costs for a given coal-fired EGU project will be determined by the detailed site-specific factors, and theref ore can be higher or lower than the costs presented in this memorandum. However, the cost and impact values derived from a model plant analysis provide reasonable estimates for the purpose of evaluating the impacts of revisions to the existing EGU NSPS. Model Plant EGU Descriptions3 Costs for installing and operating the air pollution contro ls were estimated by assigning specific air pollution control configurations to an array of seven model plants representing EGUs varying in characteristics of the coal burned, boiler types, and generating capacit y. Five of the model plant EGUs represent pulverized coal -fired (PC-fired) boiler s burning either bituminous coal, subbituminous coal, or lignite. The coal types were selected for these model plant EGUs to represent a typical low-sulfur, medium-sulfur, and high-sulfur content coal that would be burned in a ne w EGU. Two additional model plant EGUs represent boilers that use fluidized-bed combustion (FBC) technology and burn lignite or coal refuse. The boiler sizes were selected to approximately span the range of typical coalfired EGUs expected to be built in the United States. Boiler sizes are expressed in terms of the model plant EGU’s gross electricity output in megawatts electric (MWe). The model plant EGU configurations defined for the im pact analysis are descri bed in Table 1. All of the model plant EGUs with the exception of the 1 00 MW size boilers are projected to have a gross efficiency of 38% (8,979 Btu/kWh) and assumed to be operated as base load units with an annual capacity factor of 85%. Supercri tical steam turbines are not available below approximately 200 MW and coal refuse-fired EGUs tend to be less efficien t that EGUs burning higher rank coals. To account for this, the 100 MW subbituminous and coal refuse -fired boiler were pr ojected to have gross efficiencies of 36% (9,478 Btu/ kWh) and 34% (10,035 Btu/kWh) re spectively and annual capacity factors of 85%.

Table 1. Coal-fired EGU “Model Plant” Configurations

Model Plant Boiler Type Coal Burned Gross Generating

Capacity (MWe) Gross Heat Rate (Btu/kWh) Uncontrolled SO 2 Emissions Rate (lb/MMBtu) Annual Capacity

Factor

A PC Low sulfur Subbituminous 100 9,478 0.90 85%

B PC Low sulfur Subbituminous 500 8,979 0.90 85%

C PC Medium sulfur Bituminous 500 8,979 3.44 85%

D PC High sulfur Bituminous 500 8,979 6.89 85%

E PC Lignite (Gulf Coast) 500 8,979 2.07 85%

F FB Lignite (North Dakota) 400 8,979 2.50 85%

G FB Coal refuse 100 10,035 5.46 85%

The regulatory baseline defined for each model plan t used for the incremental impact analysis is presented in Table 2. The regulator y baseline PM emissions rate is the controlled emissions rate assuming the use of a fabric filter for PM c ontrol for all units. Th e regulatory baseline SO 2 emissions rate depends upon the potential SO 2 emissions rate based on assuming all of the sulfur in the coal is converted to SO 2 when burned. In all cases flue gas desulf urization (FGD) is assumed. The regulatory baseline NO X emission rate for PC-fired boilers assumes th at new PC-fired boilers are installed with low NO X burners as standard equipment plus selec tive catalytic reduction (SCR). The regulatory baseline NO X emission rate for FBC boilers assumes good combustion plus sele ctive non-catalytic reduction (SNCR).4 Table 2. Coal-fired EGU “Model Plant” Regulatory Baseline Emissions Levels

Model Plant Particulate Matter Sulfur Dioxide (SO 2 ) Nitrogen Oxides (NO X )

Emissions Rate (lb/MMBtu) PM Controls Assumption Emissions Rate (lb/MWh) SO 2 Controls Assumption Emissions Rate (lb/MWh) NO X Controls Assumption

A 0.034 Fabric Filter 1.4 FGD 1.0 LNB + SCR

B 0.034 Fabric Filter 1.4 FGD 1.0 LNB + SCR

C 0.034 Fabric Filter 1.5 FGD 1.0 LNB + SCR

D 0.034 Fabric Filter 3.1 FGD 1.0 LNB + SCR

E 0.034 Fabric Filter 1.4 FGD 1.0 LNB + SCR

F 0.034 Fabric Filter 1.4 FGD 1.0 SNCR

G 0.034 Fabric Filter 2.7 FGD 1.0 SNCR

PM Emissions Control Impacts
Controls for filterable PM are well established, a nd the PM control that would be used by any new coal-fired EGU would be use of a fa bric filter (i.e., baghous e) or an electrostatic precipitator (ESP). Either of control devices can achie ve the high control efficiencies n eed to meet the existing limit and control both coarse and fine filterable PM. For the impact analysis, the PM emissions regulatory baseline is assumed to be 0.034 lb/MMBtu and is define d to be installation of fabric filters on all units. It is assumed that to meet any revised PM emissi ons limit, this fabric filter would be used in combination with additiona l PM control devices.

The revised PM emissions limit would be a total PM emissions limit that includes both filterable PM and condensable PM. To meet this total PM emissi ons limit, it is assumed that the addition of dry sorbent injection (DSI) upstream of the fabric filt er and a wet electrostati c precipitator (WESP) downstream of the fabric filter would be necessary to achieve the higher performance level needed to achieve the limit. The DSI system would reduce the sulfuric acid mist portion of the condensable PM. The WESP would further reduce condens able PM and additional filterable PM that is not collected by the fabric filter. The controlled total PM emissi ons rate for this PM control system configuration (addition of DSI and a WESP to the baseline fabric filter ) as applied to all of the model plants is set at 0.055 lb/MWh. The DSI costs are estimated by adapting the cost algorithms developed for the IPM (available at: http://www.epa.gov/airmarkets/p rogsregs/epa-ipm/docs/append5_4.pdf ) for control of SO 2 emissions to control of sulfur trioxide (SO 3 ) emissions. The algorithms estimate total project capital costs, fixed operating and maintenance (fixed O&M) costs, a nd variable operating and maintenance (variable O&M). The DSI cost algorithms require the user inputs: EGU unit size, EGU gross heat rate, particulate control device t ype, sorbent characteristics, SO 2 rate, and coal type. To estimate the DSI costs, the following assumptions were made:

 Sorbent reacts with and removes acid gas emissions from the flue gas stream preferentially in the following order: SO 3 , HCl, and SO 2
.

 1.5% of potential SO 2 emissions are converted to SO 3 in the PC-fired EGUs and 1.0% in the CFB EGUs. This is based on assuming 1.0% conver sion in the boiler and 0.5% in the SCR. The5 CFB boilers install SNCR systems instead of S CR systems, so the additional 0.5% conversion is not associated with the CFB boilers.

 Trona is the sorbent used.

 Control system provides 90% removal of SO 3
.

 IPM DSI cost algorithms are valid when substituting SO 3 potential emissions rate for the SO 2 potential emissions rate.

 Reaction of each ton of trona with SO 3 chemically generates 0.39 tons of carbon dioxide (CO 2 ).

The current version of the IPM doe s not include a costing model for WESPs. Therefore, the WESP costs are estimated using the results from an EPA sensitivity analysis for the Clean Air Interstate Rule (CAIR) (available at: http://www.epa.gov/cair/pdfs/0053-2263.pdf ). The EPA estimated the cost impacts for CAIR using the IPM. The cost met hod provided capital, fixed O&M, and variable O&M costs as a function of EGU size. A scaling factor was provided, as the base unit of the method was a 500 MW unit. Electricity use for the WESP is assu med to be 0.5 % of the EGU gross output. The WESP costs from the CAIR analysis were in 2002 dollars. To calculate 2 009 dollars, the Chemical Engineering Price Costing Index (CEPCI) was used for the capital cost, and an inflation rate of 2.5% per year was used for the variable O&M and fixed O&M costs.

For those coal-fired EGUs us ing wet scrubber systems for SO 2 emissions control to meet the existing EGU NSPS, it is assumed that the wa stewater from the WESP would be recycled to the wet scrubber. Coal-fired EGUs without an exis ting wastewater treatment system capable of handling the additional wastewater stream from the WESP would need to build and operate a suitable wastewater treatment system. Costs for such a system are not included in the analysis. The capital, variable operation and maintenance (O&M), and fixed O&M costs were estimated individually for each model plant for the DSI syst em and the WESP. All costs were summed to calculate total capital, total variable O&M, and total fixed O&M costs for both the DSI and WESP systems. Then, the annual costs for DSI and WESP systems were summed to provide total annual cost for the DSI and WESP system. The cost effectiveness is the total annual cost per ton of PM reduction. Table 3 presents the estimated incremental impact s of revising the EGU NSPS PM emissions limit for all of the model plant EGUs relative to impacts of using only a fabric filter to meet the existing PM emissions limit. The PM control system confi guration (addition of both DSI and a WESP to the baseline fabric filter) used to estimate the impact s presented in Table 3 is a conservative assumption (i.e., likely overstates the control costs) with respect to estima ting the total PM emissions reduction cost impacts for the model plant EGUs. Any new EGU using a spray dryer absorber for SO 2 emissions control would not require the additional cost of DSI because the sorbent used for SO 2 control would also control SO 3 emissions. In addition, the cost impact analysis for all model plant EGUs does not account for the benefit of additional SO 2 emissions reduction that would occur with the use of the WESP.6 Table 3. DSI with WESP Control System Annual Incremental Impacts

Model Plant Annual Costs ($1,000) PM Emission Reduction

(tons) Incremental Cost Effectiveness

($/ton PM) Electricity Use (MWh) Trona Use (tons) Chemically Created

CO 2 (tons) DSI WESP Total

A $767 $806 $1,573 99 $15,900 8,563 0.15 0.1

B $2,314 $2,579 $4,893 475 $10,300 42,815 0.71 0.3

C $3,319 $2,579 $5,898 475 $12,400 42,815 2.7 1.1

D $4,335 $2,579 $6,914 475 $14,600 42,815 5.4 2.1

E $2,744 $2,579 $5,323 475 $11,200 42,815 1.6 0.6

F $2,178 $2,193 $4,371 380 $11,500 34,252 1.0 0.4

G $1,094 $806 $1,900 106 $17,900 8,563 0.64 0.2

SO 2 Emissions Control Impacts For the incremental impact analysis it is assumed th at in general the same t ype of FGD controls for SO 2 would be installed on a given model plant EGU to comply with either the existing NSPS SO 2 emissions limit or the revised limit under considerat ion. Therefore, there would be an incremental increase in the capital and annual costs for the app licable FGD control system to achieve the higher performance levels (i.e., higher SO 2 emissions control efficiency) n eeded to meet a more stringent revised limit due to design modifications and operati ng changes to the controls . Because of the unique environmental benefits that coal refuse-fired power plants provide, EPA concluded it is appropriate to maintain the existing EGU NSPS SO 2 emissions limits as applied to owners/operators of affected facilities burning 75% or mo re coal refuse on an annual basis. Therefore, there would no incremental SO 2 emissions control impacts for model plant G from the NSPS SO 2 emissions limit revisions under consideration.

The SO 2 control system configuration used for a give n model plant EGU depends on the type of coal burned. The model plant EGUs representing PC–fired boilers firing either bitu minous coal or lignite are assumed to use limestone-based wet scrubbers (Model plants C, D, E). The model plant EGUs representing PC–fired boilers fi ring subbituminous coal are assumed to use a lime-based spray dryer adsorber (SDA) system (Model plants A, B). Th e model plant EGUs representing a FBC boiler firing lignite (Model plant F) is assumed to use limesto ne injection for primary control followed by lime injection into the ductwork prior to the fabric filter for additional control. To estimate costs for model plant F, it is assumed that 80% SO 2 control in the fluidized-bed followed by the post-combustion control to achieve the additional required SO 2 removal. To be conservative the incremental costs were modeled using the SDA costing assumptions. The capital costs values for both the limestone-based wet FGD and the lime-based dry FGD systems are based on 98% and 95% control efficiency respec tively. However, the capital and variable costs do not vary with changes in design control efficiency. Factors were added to acc ount for these changes to more accurately reflect the increm ental impacts of the revised limit under consideration. The capital cost values were adjusted using the relative capital cost values calculated from the Integrated Environmental Control Model (IEC M) version 6.2.4 developed by Carn egie Mellon University with support from the National Energy Tec hnology Laboratory (NETL) (available at:7 http://www.cmu.edu/epp/iecm/download_current.html ). The IECM has signifi cantly lower capital cost projections, but the default me dium sulfur Appal achian bituminous and Powder River Basin subbituminous IECM coals were used to develop rela tive cost curves for the wet scrubber and SDA at various design efficiencies. The adjustment f actors use for wet scrubber and SDA systems are presented in Equations 1 and 2 respectively where %R represents the percentage of SO 2 reduction. These factors were then applied to the IP M costs at different control efficiencies.

7.622 כ ሺ %ܴ ሻ ଶ െ 14.011 כ ሺ %ܴ ሻ ൅ 7.4102 [Equation 1]

0.2544 כ ሺ %ܴ ሻ ଶ െ 0.3314 כ ሺ %ܴ ሻ ൅ 1.0841 [Equation 2]

The lime injection rate for model plant F and corr esponding waste generation rate were adjusted using the reagent ratio developed for IECM and relative percent control, compared to the base of 95% control. The adjustment fact or is shown in Equation 3.

ሺሺ1.495 െ LN ሺ 1 െ %ܴ ሻ ሻ 4.4907 ⁄ ሻ *(%R/0.95) [Equation 3]

The limestone addition rate and waste generation rate for the wet scrubbing system was scaled directly with the percent control relative to the 98% base control efficiency. The makeup water rates for both the SDA and we t scrubbing systems and the auxiliary power requirements for the SDA were scaled using the values calculated by the IPM equa tions at a zero sulfur inlet rate and the relative control efficiencies, co mpared to the base control efficiency. The wet scrubber auxiliary power requirements were scaled using factors developed from the IECM model similar to the capital costs. Equation 4 lists th e factor that was applie d to the auxiliary power requirements are varyin g percent removals.

124.32 כ ሺ %ܴ ሻ ଶ െ 231.65 כ ሺ %ܴ ሻ ൅ 108.62 [Equation 4]

The use of this factor can result in relatively low auxiliary power requirements, but since the purpose of this analysis is to estimate the incremental impacts of revised standards compared to existing standards it was concluded the results are sufficien t to account for the increased pumping requirements due to the increased liquid to gas rati os at higher rem oval efficiencies. Using adjustment factors based on the EPA’s Coal Utility Environmental Cost (CUECost) model was considered (available at: http://www.epa.gov/nrmrl/pubs/600r09131/600r09131.pdf ). However, the CUECost model does not vary auxilia ry power requirements and it was c oncluded that it was therefore more appropriate to use IECM for the adjustment values. Table 4 presents the estimated incremental impacts of revising the EGU NSPS SO 2 emissions limit for the model plant EGUs representing PC–fired boilers firing either bituminous coal or lignite (Model plants C, D, E) based on the assumption that thes e facilities would use limestone-based wet scrubbers to meet the existing SO 2 emissions limit. Table 5 presents the estimated incremental impacts of revising the EGU NSPS SO 2 emissions limit for the model plant EGUs representing PC–fired boilers firing subbituminous coal (Model plants A, B) and FBC boiler firing lignite (Model plant F) based on the assumption that these facilities would use a lime-based SDA system to meet the existing SO 2 emissions limit.8 Table 4. Limestone-Based Wet FGD Annual Incremental Impacts

Model Plant Annual Costs ($1,000) SO 2 Emissions Reduction

(tons) Incremental Cost Effectiveness ($/ton) Electricity Use (MWh) Water Use (1,000 gal) Limestone Use (tons) Solid Waste Generated (tons) Chemicall y Created

CO 2 (tons)
C 875 1,006 870 7,050 6,374 344 1,799 691

D 1,671 2,303 725 14,390 14,610 787 4,118 1,582

E 341 744 456 990 4,597 272 1,330 511

Table 5. Lime-base Dry FGD System Annual Incremental Impacts

Model Plant Annual Costs ($1,000) SO 2 Emissions Reduction

(tons) Incremental Cost Effectiveness

($/ton SO 2 ) Electricity Use (MWh) Water Use (1,000 gal) Lime Use (tons) Waste Generated (tons)
A 105 149 703 2 21 473 1,077

B 450 737 611 11 104 2,230 5,074

F 229 595 385 9 83 1,073 2,464

NO X Emissions Control Impacts For the incremental impact analysis it is assumed that in general the same type of post-combustion NO X emissions controls would be in stalled on a given model plant EGU to comply with either the existing NSPS NO X emissions limit or the revised limit under consideration. Therefore, there would be an incremental increase in the capital and annual costs for the applicable NO X reduction system to achieve the higher performan ce levels (i.e., higher NO X emissions control efficiency) needed to meet a more stringent revised limit due to design modifi cations and operating cha nges to the controls.

The NO X emissions regulatory baseline is 1.0 lb/MWh and is defined to be installation of SCR controls on the model plant EGUs using PC-fir ed boilers (Model plant EGUs A, B, D, E, F) and SNCR controls on the model plant with an inherently lower amount of NO X formed during combustions, specifically the EGUs using FBC boilers (Model plant EGUs F, G). Design modificati ons and operating changes to the SCR and SNCR systems would be required to achieve the higher performance level needed to comply with an emissions standard of 0.70 lb/MWh. The auxiliary electrical power requi rement is the only variable in the IPM costing equations for SCR and SNCR that does not vary with either inlet NO X concentrations or percent removal. This value is generally not a significant factor in overall costs of either control technology. However, to account for the incremental impacts the auxiliary power requi rements for SCR were adjusted by assuming a 5% change in auxiliary power from the baseline calcul ated using the IPM equation for doubling or halving either the percent reduction require ment or inlet concentration. The baseline used in IPM is 0.21 lb/MMBtu and a 70% reduction. To account for impr oved design in a new EGU compared to a retrofit EGU the minimum urea utilization was increased from 25% to 30% for the SNCR used in a FBC boiler. The auxiliary powe r requirements were also scaled relative to the urea flow rates listed in the IPM’s example calculation. The example calculation aux iliary power requirement is 0.05% for a 300 MW EGU with a urea flow rate of 245 lb/hr.9 Table 6 presents the estimated incremen tal impacts of revising the EGU NSPS NO X emissions limit for the model plant EGUs using either FBC boilers a nd assumed to be using SN CR to meet the existing NO X emissions limit (Model plant EGUs F, G). Table 7 presents the estimated incremental impacts of revising the EGU NSPS NO X emissions limit for the model plant EGUs using PC-fired boilers and assumed to be using SCR to meet the existing NO X emissions limit (Model plant EGUs A, B, C, D, E).

Table 6. Selective Non-Catalytic Reduction (SNCR) Annual Incremental Impacts

Model Plant Annual Costs NO x Emissions Reduction

(tons) Incremental Cost Effectiveness ($/ton of NO
x ) Electricity Use (MWh) Urea Use (tons) Water Use (1,000 gal) F $644,900 443 1,460 1,200 2,100 960

G $186,400 112 1,670 300 530 240

Table 7. Selective Catalytic Reducti on (SCR) Annual Incremental Impacts

Model Plant Annual Costs NO x Emissions Reduction

(tons) Incremental Cost Effectiveness ($/ton of NO
x ) Electricity Use (MWh) Urea Use (tons) Steam Use (1,000 lb) A $141,600 110 1,290 37 77 170

B $679,000 564 1,200 200 400 890

C $489,800 544 900 130 380 860

D $489,800 544 900 130 380 860

E $693,200 564 1,230 200 400 890

Secondary Air Pollutant Emissions Impacts Secondary air pollutant emissions from the generati on of the electricity requi red to operate that air pollution control equipment used to meet the re vised emissions limits under consideration are estimated assuming that the electricity is generated at the facility site by a coal-fired EGU that is operated to achieve the fo llowing emission levels.

PM = 0.055 lb/MWh
SO 2 = 1.0 lb/MWh
NO X = 0.70 lb/MWh Carbon monoxide (C O) = 0.40 lb/MWh Mercury = 0.000010 lb/GWh (all coals exce pt lignite); 0.040 lb/GWh (lignite)
CO 2 = 1,860 lb/MWh
The estimated annual incremental se condary air pollutant emissions fo r each model plant are presented in Table 8.10 Table 8. Secondary Air Emissions Annual Incremental Impacts

Model Plant Total Control Equipment Electricity Use (MWh/yr) Annual Incremental Increase in Secondary Air Emissions from Control Equipment Operations

PM (ton/yr) SO 2 (ton/yr) NO X (ton/yr) CO (ton/yr) Mercury (lb/yr) CO 2 (ton/yr)

A 8,602 0.2 4.3 3.0 1.7 < 0.0001 8,000

B 43,026 1.2 21.5 15.1 8.6 0.0004 40,000

C 42,952 1.2 21.5 15.0 8.6 0.0004 40,000

D 57,335 1.6 28.7 20.1 11.5 0.006 53,000

E 44,005 1.2 22.0 15.4 8.8 1.8 41,000

F 35,461 1.0 17.7 12.4 7.1 1.4 33,000

G 8,863 0.2 4.4 3.1 1.8 < 0.0001 8,000