- 1 - Date: March 27, 2013

Subject: National Emission Standards for Haza rdous Air Pollutants (NESHAP) Beyond the
Maximum Achievable Control Technol ogy (MACT) Floor (‘Beyond-the-Floor’) Analysis for Revised Emission Standards fo r New Source Coal-and Oil-fired Electric Utility Steam Generating Units

From: Nick Hutson, U.S. EPA Of fice of Air and Radiation

To: Docket No. EPA-HQ-OAR-2009-0234

Introduction

The purpose of this memorandum is to present the data, methodology and assumptions used to conduct a beyond-the-floor (BTF) analysis for the emission limits that the Agency is finalizing in the
reconsideration of certain new sour ce standards established in the fi nal National Emission Standards for Hazardous Air Pollutants (NESHAP) for Coal- and O il-fired Electric Utility Steam Generating Units (EGUs). This memorandum presents the estimates of the incremental pollutant emission reduction and cost that would be achieved by im plementing a BTF option to control hazardous air pollutant (HAP) and HAP surrogate emissions from new and reconstructe d sources and discusses any anticipated non-air quality health and environmental impacts and energy requirements.

The MACT floor level of control for new EGUs is based on the emission control that is achieved in practice by the best controlled similar source for each HAP or HAP surrogate in the different categories or subcategories. After EPA establishes MACT fl oor levels, CAA section 112(d)(2) requires EPA to consider whether more stringent BTF standards should be established. Pursuant to that section of the CAA, the Agency must consider “the cost of ach ieving such emission reduc tion, and any non-air quality health and environmental impacts and energy requiremen ts...” before it may estab lish a standard that is
based on a BTF level of control.

As mentioned, the new source MACT floor emission limits were set based on the performance of the best controlled similar source within that category or s ubcategory. In most of thes e cases, it is reasonable to expect that the very best performing source is ac hieving that level of cont rol through the application of well-performing control technologies, by followi ng a disciplined and routine maintenance schedule, and by operating in an efficient manner. For most of the new source standards addressed in the reconsideration proposal, we have not identified additional technologies or HAP emission reduction approaches that would achieve HAP reductions greater than the new source floors for the subcategories – other than multiple controls in se ries (e.g., multiple scrubbers in seri es or multiple particulate matter (PM) controls in series), which we consider to be unreasonable from a cost perspective. We are therefore finalizing the floor level of control in all but tw o instances. We are finalizing a BTF standard for hydrogen chloride (HCl) a nd sulfur dioxide (SO 2 ) emissions from coal-fired EGUs. Details of the EPA’s
BTF evaluations for the new source standards in the final reconsider ation notice are provided below.

Beyond-the-floor analysis fo r PM from coal-fired EGUs

It is commonly accepted that a baghouse fabric filter (FF) is the technology that provides the best level of PM emission reduction for coal-fired EGUs. Newly constructed coal-fired EGUs will be expected to install a baghouse FF to meet the new source NE SHAP PM limit and the applicable New Source- 2 - Performance Standard (NSPS). We have considered av ailable options that woul d allow a new source to achieve greater emission reductions than those achieve d in practice by the best controlled source. The
EPA is aware that some EGUs have installed downs tream secondary PM contro l devices to provide for incremental PM reductions beyond what is achieved by the primary PM control device. However, those secondary “polishing” PM control devices are most often installed for one of two purposes: (1) to augment the control of an underperforming or undersiz ed primary control device, or (2) to allow for injection of activated carbon or other powdered sorbent so that th e fly ash and the sorbent remain separated for eventual storage, di sposal, or re-use. A wet ESP (WESP) may also be installed in a new coal-fired EGU (usually downstream of a wet-flue gas desulfurization (WFG D) scrubber). Although the primary purpose of the WESP would be to control emissi ons of condensible PM (e specially sulfuric acid mist), it would be expected to also provide some small incremental reduction in filterable PM (fPM) emissions. We have conducted a BTF analysis on a hypothetical new 500 MW pl ant burning coal with an ash content of approximately 10% and operating at an 85% capacity factor. The calculation assumed that the primary PM control device is a fabric filter with an air-to- cloth ratio of 4.0, and that it is designed to meet a fPM emission level of 75% of the final emission limit of 0.09 lb/MWh. 1 Although a relatively small percentage of the coal ash would be expected to partition to the bottom ash, we assumed all of the coal ash content would exit the system as fly ash.

We then calculated the BTF incremen tal cost effectiveness for installa tion of a downstream “polishing” secondary PM control device. In this case, we as sumed the downstream FF would have an air-to-cloth ratio of 6.0 and that it would provide incremental fPM control to achieve an emi ssion that is 50% of the final emission limit of 0.09 lb/MWh. In this case the pol ishing PM device would remove a much smaller amount of fPM, but at a similar (though lower) overal l cost than the primary PM control device. The
incremental cost effectiveness wa s calculated to be greater than $75,000 per ton of fPM. We do not

believe that this is a reasonable cost per ton removal and it does not justify the installation of the downstream secondary PM control device and, therefore, we are not finalizing a BTF fPM emission limit. We also considered non-air quality health and environmental impacts and energy requirements. We found no significant non-air quality health and environmental impact s; but we acknowledge a likely increase in energy requirements with the installa tion of a downstream polishi ng baghouse fabric filter (due to increased pressure drop across the filter).

Beyond-the-floor analysis for Hg from EGUs firing non-low rank virgin coal

The final new source mercury (Hg) emission limit for EGUs firing non-low rank virgin coal is based on
the use of the three times the re presentative detection level (3xRDL) approach and, thus, a more stringent BTF limit would be impractical due to measurement frequency issues described in the preamble to the proposed rule. As explained in th e preamble and in the associated technical support memo (“Determination of Representative Detection Level (RDL) and 3xRDL Values for Mercury Measured Using Sorbent Trap Technologies,” whic h is available in the rulemaking docket EPA-HQOAR-2009-0234), we do not have informa tion available to determine at this time whether a lower Hg emission limit could be reliably measured with su fficient frequency to allow consistent and timely compliance. For this reason, we have determined that it is not reasonable to establish a BTF level of control for Hg from this subcategory. We also co nsidered non-air quality health and environmental

1 In petitions for reconsideration, petitioners stated th at operators usually target emissions that are 50 – 75% of the emission limitation to provide for margin of error.- 3 - impacts and energy requirements. We found no signifi cant non-air quality hea lth and environmental impacts or significant energy requirements a ssociated with a BTF level of control.

Beyond-the-floor analysis for Hg from EGUs firing low rank virgin coal 2

The final new source Hg emission limit for EGUs firing low rank virgin coal is based on the performance of an existing EGU that is equipp ed with advanced air pollution cont rol technology, including injection of brominated activated carbon upstream of a FF for the control of Hg. Although it is reasonable to assume that an increase in the inje ction rate of the bromin ated activated carbon would result in better performance and, thus, lower emissi ons, we do not have enough information to determine
whether or not the increase in sorbent would result in a reduction in emissions th at is cost-effective.

The sorbent performance curve (i.e., the percent of Hg reduction versus sorbent injection rate – see Figure 1 for an illustrative example) tends to have a steep area where small incr eases in sorbent result in large increases in Hg removal. Ho wever, as the sorbent injection ap proaches its performance limitation, the curve becomes flat and larg e increases in sorbent are requ ired for only small incremental improvements in Hg control.

The sorbent injection curve tends to be very site specific and we have no way to know exactly how the sorbent injection curve for a new low rank coal-burning source would lo ok. We believe that it is likely that the performance needed to achieve a BTF level of control would require a considerable increase in activated sorbent injection. Such a significant increase would result in higher levels of sorbent mixed with the fly ash, which may affect th e viability of the resulting fly ash- sorbent mixture to be recycled for beneficial use (e.g., in concrete manu facture or in road construction) a nd, thus, its salabili ty. Fly ash that cannot be beneficially recycled must be land-filled at considerable cost.

Figure 1. Example sorbent injection performance curve

A BTF analysis was performed on a hypothetical new 500 MW plant burning low rank virgin coal and operating at an 85% capacity factor. It was assumed that the fuel used in the EGU has an average Hg 0 10 20 30 40 50 60 70 80 90 100MercuryControl,%

Increasing Sorbent Injection ‐‐‐‐‐‐ >- 4 - content of 26.2 lb/TBtu (which was the average Hg c ontent of low rank virgin coal from the 2010 Utility information collection request (ICR)). Based on data from U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL) fiel d tests, we estimate that such a facility should be able to achieve a targeted emission of 75% of the fi nal emission limit of 0.03 lb/GWh (or 0.0225 lb/GWh, which is an approximately 92% reduction, coal-to-st ack for the average coal) by injecting 2 lb/MMacf (pounds of sorbent per million actual cubic feet of flue gas) of br ominated activated carbon sorbent upstream of a well-performing FF. 3 We have also assumed that the EGU would need to increase the sorbent injection – to 5 lb/MMacf – to achieve a BTF emission of 50% of the final emission limit (or 0.015 lb/GWh, which is an approximately 95% reduction, coal-to-stack).

The increase in sorbent injection needed to achie ve the BTF emission may render the captured fly ash (or spray dryer absorber (SDA)/FF byproduct) unfit for be neficial reuse. If the fl y ash cannot be sold (or given away in the case of SDA/FF byproduct) for bene ficial reuse, then the operator must landfill the resulting byproduct-sorbent mixture at considerable cost. In the DOE /NETL study (cited earlier), this
tended to increase incremental cost s ($ per pound of Hg) by approximate ly three-fold for plants firing
low rank coal.

In the cost analysis for the hypothetical new plant, we calculated incrementa l BTF costs ranging from $61,000 per incremental pound of Hg (assuming no bypr oduct effects) to $183,500 per incremental pound of Hg (assuming the sorbent rende rs the byproducts unusable). We do not believe that this range of potential incremental cost effec tiveness is reasonable, therefore, we are not finalizing a BTF Hg emission limit for new EGUs designed for and burning low rank virgin coal.

Beyond-the-floor analysis for SO 2 emissions from coal-fired EGUs

The best performing source for SO 2 emissions from a coal-fired EGU is a conventional tangential-fired pulverized coal-fired boiler with a dry flue gas desulfurization (FGD) spray dryer for SO 2 control. This is expected to be a common and well-performing c ontrol configuration for new EGUs. Other generation technologies (i.e., circulating fluidized bed combusto rs, CFB) will be expected to utilize limestone injection and/or downstream circul ating dry scrubbers (CDS) for SO 2 control. Other PC EGUs may also be expected to install advanced FGD technology such as spray drier absorber (SDA) for lower sulfur coal or a wet-FGD scrubber (WFGD) for EGUs bur ning medium-to-high sulfur coals. In this final action, the EPA used the same statistical analyses us ed in the proposed rule (i.e., 99% upper predictive limit (UPL)), and the resulting MACT floor emis sion limit is 1.3 pounds per megawatt-hour (lb/MWh). An EGU burning high-sulfur coal (e.g., coal mined in the Illinois basin) would need to reduce potential emissions by greater than 97% in order to meet th e MACT floor emissions limit. However, a state-ofthe-art wet FGD can reduce the potential SO 2 emissions rate by 98%. This level of control would result in an emissions rate of 1.0 lb/MWh, and EPA determin ed this level of control is cost effective based on an evaluation of the potential co sts for 7 model EGUs. See Appendi x to this Memorandum. The only technology for a high-sulfur coal-fired EGU to reduce emission below this level would be to install a

3 Jones, A.P.; Hoffman, J.W.; Smith, D.N.; Feele y, J.; Murphy, J.T.; “DOE/NETL’s Phase II Mercury Control Technology Field Testing Program: Prelim inary Economic Analysis of Activated Carbon Injection,” Environ. Sci. Technol. , 41, 1365 (2007) (Docket ID EPA-HQ-OAR-2009-0234-20074); and Sjostrom, S.; Durham, M.; Bustard, C.J.; Martin, C.; “Activated Car bon Injection for Mercury Control: Overview,” Fuel , 89, 1320 (2010) (Docket ID EPA-HQ-OAR-2009-0234-20072).- 5 - downstream “polishing” scrubber. We have concluded th at this incremental level of control is not cost
effective.

As part of the BTF analysis, the EPA evaluate d a hypothetical new 500 MW plant burning high-sulfur coal. See Appendix to this Memorandum. The calcula tion first assumed that the primary wet FGD is capable of meeting an SO 2 emission level of 1.0 lb/MWh from 1.3 lb/MWh. We determined that the incremental cost effectiveness for that BTF level of control is less than $1,100/ton of SO 2 removed,
which is reasonable cost for SO 2 removal. The remaining model EGUs’ cost effectiveness numbers were less than the cost per ton of SO 2 removal for the high-sulfur coal, a nd, thus, the costs are reasonable. Id. The EPA conducted a similar cost analysis for the revised Utility NSPS and established a 1.0 lb/MWh
for coal-fired EGUs. 4 The Agency has also evaluated the non -air quality health and environmental impacts and energy requirements of complying with a BTF level of control of 1.0 lb/MWh for all coalfired EGUs. The most significant non- air quality impact is the increased waste that may be generated and the increased water requirements. Going BTF to 1.0 lb/MWh may increase the volume of coal combustion residuals (CCRs) and water requirements by up to 3% for facilities using a wet FGD and 20% for facilities using a SDA. However, many faciliti es are able to sell (for approximately $20/ton) or give away their CCR for beneficial reuse. Facilitie s that do not sell their CCRs for beneficial reuse would have to dispose of the additional material in appropriately designed landfills. Disposal of regular CCR is generally less than $20/ton. However, the cost of disposal of contaminated CCR in a specially designed landfill (if necessary) can be as much as $100/ton. Whether sold or deposited in an appropriately landfill, the additional solid waste should have minimal health or environmental impacts if disposal is properly addressed. We also maintain that the incremental increase in water requirements are reasonable and unlikely to cause adverse health or environmental impacts. Concerning the energy requirements, because sources will use the same cont rols to comply with the BTF level as would have been utilized based on the MACT floor, the additiona l energy requirements to run the pollution controls will be less than 1% for facilities using a SDA an d less than 10% for facilities using a wet FGD. For these reasons, we conclude that these impacts ar e minor compared to the baseline requirements. Therefore, since the costs of going beyond the fl oor to 1.0 lb/MWh are reasonable and the non-air quality health and environmental impacts and ener gy requirements are not significant, we find that 1.0
lb/MWh is achievable for new coal-fired EGUs as a BTF level of control.

We then calculated the BTF incremen tal cost effectiveness for installa tion of a downstream “polishing” secondary scrubber to achieve an additional level of control beyond 1.0 lb/MWh. See Appendix to this
Memorandum. We assumed the downstream scrubber would provide incremental SO 2 control to achieve
an emission limit of 0.70 lb/MWh. The calculated increm ental cost effectivene ss is greater than $31,000 per ton of SO 2 removed. We have concluded that the cost of going to 0.70 lb/MWh is not reasonable. We also considered non-air quali ty health and environmental im pacts and energy requirements of establishing an SO 2 standard of 0.70 lb/MWh. Installation of a polishing scrubber would result in
increased scrubber solids that would e ither be sold, given away, or be disposed of in a coal combustion residuals landfill. Operation of a polishing scrubber would also result in an increase in energy requirements for operation of the facility. While these impacts are not significant, the incremental cost

4 Arguably the cost of going to 1.0 lb/MWh is zero because the Utility NSPS requires compliance with that number. Nevertheless, the Agency conducted an independent cost analysis. Similarly, the non-air quality health and environmental impacts and en ergy requirements that result from achieving an SO 2 emission level of 1.0 lb/MWh result from the NSPS.- 6 - of establishing a MACT BTF standard of 0.70 lb/MWh is not reasonable; therefor e, we are finalizing a
MACT limit for SO 2 emission at the BTF level of 1.0 lb/MWh.

Beyond-the-floor analysis for PM fr om solid oil-derived fuel-fired EGUs

This analysis is very similar to that which was pres ented earlier for PM emissions from coal-fired EGUs. We believe that the incremental costs would be very similar to those presented for coal-fired EGUs. As with the coal-fired source, such a device would add considerable costs to the project, and the incremental cost effectiveness (i.e., the $/ton for th e incremental PM reduction – which was calculated at > $75,000 per ton of fPM for new coal EGUs) would not be reasonable. We al so considered non-air quality health and environmental impacts and en ergy requirements. We f ound no significant non-air quality health and environmental impacts; but we acknowledge a likely increase in energy requirements
with the installation of a downstream polishing baghouse fabric filt er (due to increased pressure drop across the filter).

Beyond-the-floor analysis for SO 2 from solid oil-derived fuel-fired EGUs

The best performing source for SO 2 emissions from solid oil-derived fuel-fired EGUs is a CFB combustor with limestone injection for SO 2 control. Solid oil-derived fuel is most often fired in CFB boilers; and, as mentioned earlier, this limestone injection control configur ation will be the most commonly used for CFB boilers. The final new source emission limit for SO 2 is the same as for the coalfired EGU subcategory (1.0 lb/MWh) and the same ar guments present earlier for why we do not believe
that installation of a downstream scru bber is cost effective can also be made here. For coal-fired EGUs,
we calculated that the incremental cost effectiveness would be >$31,000 per ton of SO 2 removed and we believe that the costs would be the same or very similar for solid oil-derived fuel EGUs. We do not believe that the cost of going BT F is reasonable, and, therefore, we are not finalizing a BTF SO 2 emission limit. Non-air quality health and enviro nmental impacts and energy requirements would be
similar as for a coal-fired EGU.

Beyond-the-floor analysis for PM from continental liquid oil fuel-fired EGUs

The final new source fPM emission limit for continenta l liquid oil-fired EGUs is based on an EGU that uses an electrostatic precipitator (ESP). Distillate oil-fired facilitie s do not need add-on PM controls (their emissions are inherently lo w) and residual oil-fired EGUs cannot use FFs for PM control due to concerns about bag contamination a nd fire safety. Therefore ESPs ar e the best fPM control technology for liquid oil fuel-fired EGUs. The final new sour ce emission limit is 0.4 lb/MWh. The performance of an ESP is based on the properties of the ash (particle size, particle resistivity, etc.). We do not have the necessary information to determine if a BTF level of performance can be obtained at liquid oil-fired EGUs and therefore, we are not finalizing a BTF emission limit.

Beyond-the-floor analysis for a ll HAP emissions from IGCC EGUs

We have no data upon which to assess whether any other technology would provide additional control, in a cost effective manner, beyond the final new source emission limits for HAP emissions from new IGCC EGUs. Accordingly, we are not finalizing BTF emission limitations for these pollutants for new

IGCC EGUs.- 7 - Beyond-the-floor analysis for HC l emissions from coal-fired EGUs

For HCl, the EPA’s revised floor analysis for co al EGUs resulted in a revised MACT floor of 0.020
lb/MWh. We have estimated that a new coal-fired EGU would need to remove HCl in the range of 81.0 to 96.6% (depending upon the in itial chlorine (Cl) content of the fu el) in order to meet this revised
MACT floor emission standard. We also note that it is reasonable to expect that in most, if not all, cases, advanced FGD control technology (such as a WFGD scrubber or a high effici ency SDA) would be required as a result of other federal requirements – specifically a prevention of significant deterioration (PSD) best available control technology (BACT) analysis.

A high efficiency SDA is less costly than a WFGD, a nd we think it likely that some new sources will be able to comply with PSD/BACT requirements usi ng that less expensive op tion. For this reason, we
believe that it is reasonable to assume the minimu m level of performance for HCl control from a new EGU will be equivalent to that of a well-perfo rming SDA for purposes of the BTF analysis. We examined the level of HCl control achieved by t hose EGUs from the 2010 Utility ICR database that were equipped with SDA and we determined that t hose EGUs achieved HCl cont rol in a range of 90 to 98% (coal-to-stack, depending on the coal Cl content).

In addition, because we have determ ined that no additional controls wi ll be required to comply with a BTF level of control for HCl, we do not believ e that there are any non-air quality health or environmental impacts or additional energy requirement s associated with establishing a limit based on a
BTF level of control.

We therefore are finalizing a BT F HCl emission limit for new coal-fired EGUs at 0.010 lb/MWh. We believe that a new EGU firing lowe r Cl-content coal would need to achieve a minimum of 90% control to meet this final limit and that a new EGU firing a higher Cl-content coal would need to achieve a
minimum of 98% control to meet the limit. We belie ve that this BTF emission limit is cost-effective because it does not involve additional cost as we exp ect that any new EGU will ne ed to install at least a high efficiency SDA to comply with other CAA requirements.

We also considered a BTF emission limit by a ssuming installation of a WFGD scrubber, which generally achieves greater HCl redu ctions, but at somewhat greater co st, than a high efficiency SDA.
We understand that some new coal-fired EGUs will like ly be required to install this type of advanced FGD technology for SO 2 control. However, if the EGU is not required to install a WFGD scrubber as a
result of the PSD BACT determination for SO 2 , then the additional costs beyond those for a high efficiency SDA would be attributable only to th e achievement of additional HCl emission reductions. For cost assumptions, we used information in Table 5-4 (Illustrative Scrubber Costs (2007$) for Representative Sizes and Heat Rates under the Assu mptions in EPA Base Case v.4.10) from Chapter 5 (Emission Control Technologies) of the Integrated Planning Mode l (IPM) v 4.10 documentation. We
calculated the incremental cost for the WFGD scrubber to be $11,404 per ton of HCl removed. We do not find this to be cost effective and, thus , we are finalizing a BTF value of 0.010 lb/MWh.- 8 - APPENDIX – Detailed BTF SO 2 Cost Analysis

Impacts Estimate General Approach

Cost estimates of establishing MACT based on a beyond the floor (BTF) level of control were prepared for hypothetical “model plants” representative of the coal-fired EGUs and associated control system configurations that may be built in the United States in the foreseeable future. The basis for the control system cost estimates are control algorithms and procedures developed by the EPA Clean Air Markets Division (CAMD). The cost estimates were prepared applying the applicable control system costing models used for the EPA Base Case v4.10_PTox anal ysis using the EPA’s In tegrated Planning Model (IPM (available at: http://www.epa.gov/ airmarkt/progsregs/epa-ipm/toxics.html ) to the model plant configurations selected for this analysis. The capital costs for all the control systems were annualized using a capital recovery factor that assumes an interest rate of 7% a nd a period of 20 years. All costs are expressed as 2009 dollars. In addition, since the IPM co st procedures are primar ily intended to estimate costs of retrofitting controls to existing units, the co sts estimated by the IPM are reduced a retrofit factor of 0.77 to account for the controls being installed at model plants representing new EGUs. For retrofit applications on reconstructed facili ties, both the baseline and analyzed costs would be higher. Capital costs generally represent between 1/2 and 2/3 of the annual costs of a SO 2 scrubber application. Therefore, the incremental cost effectiveness for reconstructed facilities w ould be between 10% and 15% higher than for new facilities. Since the costs ar e similar, we determined the same conclusions are appropriate for both new and reconstructed facilities.

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 EGUs selected for this impact analysis do not represen t specific actual coal-fired EGUs currently operating or under construction in the United States. Furthermore, th e control costs estimated by this analysis are not intended to be directly applied to a specific coal-fired EGU plant locat ion. Actual control costs for a given coal-fired EGU project will be determined by th e detailed site-specific f actors, and therefore can be higher or lower than the costs presented in this memorandum. Howeve r, the cost and impact values derived from a model plant analys is provide reasonable estimates for the purpose of evaluating the impacts of establishing a MACT standard based on a BTF level of control for SO 2 emissions from

EGUs.

Model Plant EGU Descriptions

Costs for installing and operating th e air pollution controls were estimated by assigning specific air pollution control configurations to an array of seven model plants representing EGUs varying in
characteristics of the coal burne d, boiler types, and generating cap acity. Five of the model EGUs represent pulverized coal-f ired (PC-fired) boilers bur ning either bituminous coal, subbituminous coal, or lignite. The coal types were selected for these mo del plant EGUs to represent a typical low-sulfur, medium-sulfur, and high-sulfur content coal that would be burned in a new EGU. Two additional model plant EGUs represent boilers that use fluidized-bed combustion (F BC) technology and burn lignite or coal refuse. The boiler sizes were selected to approxi mately span the range of typical conventional coalfired EGUs expected to be built in the United States. Boiler sizes ar e expressed in terms of the model plant EGU’s gross electricity output in megawatts electric (MWe).- 9 - The model plant EGU configurations defined for the im pact analysis are describe d in Figure 1. All of the model plant EGUs with the excep tion of the 100 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%. Supercriti cal steam turbines are not available below a pproximately 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 boi ler were projected to have gross efficiencies of 36% (9,478 Btu/kWh) and 34% (10,035 Btu/kWh) respectively and annu al capacity factors of 85%. However, at these high levels of control the im pact of the efficiency assumption is minimal.

Figure 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) Acid Gas
Control

A PC Low-sulfur Subbituminous 100 9,478 0.90 SDA

B PC Low-sulfur Subbituminous 500 8,979 0.90 SDA

C PC Medium-sulfur Bituminous 500 8,979 3.44 WFGD

D PC High-sulfur Bituminous 500 8,979 6.89 WFGD

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

F FB Lignite (North Dakota) 400 8,979 2.50 CFB + SDA

G FB Coal refuse 100 10,035 5.46 CFB + SDA

The regulatory baseline acid gas em issions rate is the calculated MA CT floor emissions rate of 1.3 lb

SO 2 /MWh of gross output.

SO 2 Emissions Control Costs Impacts

For the incremental impact analysis, it is assumed that in general when it has been demonstrated to be achievable the same type of FGD controls for SO 2 would be installed on a given model plant EGU to comply with either the floor SO 2 emissions limit or the BTF limits under consideration. Therefore, there would be an incremental increase in the capital an d annual costs for the applicable FGD control system to achieve the higher performance levels (i.e., higher SO 2 emissions control efficiency) needed to meet a more stringent BTF limit due to design modifi cations and operating changes to the controls.

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 bo ilers firing either bitumi nous 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). The model plant EGUs representing FBC boilers firing lignite and coal refuse (Model plants F and G) ar e assumed to use limestone injection for primary- 10 - control followed by lime injection into the ductwork prio r to the fabric filter for additional control. To estimate costs for model plants F and G, 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 us ing the SDA costing assumptions. A circulating dry scrubber (CDS) has the potential to offer cost savings, but we do not have a cost model for this technology.

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 respectivel y. However, the capital and variable costs do not vary with changes in design control efficiency. As explained below, factors we re added to account for these changes to more accurately reflect the incremental impacts of the revised limit under consideration. The capital cost values were adjust ed using the relative capital cost values calculated from the Integrated Environmental Control Mode l (IECM) version 6.2.4 developed by Carnegie Mellon University with support from the National Ener gy Technology Laboratory (NETL) (available at: http://www.cmu.edu/epp/iecm/download_current.html ). The IECM has significantly lower capital cost projections, but the default medium-sulfur A ppalachian 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 fact ors used 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 percen t control, compared to the base of 95% control. The adjustment factor 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, comp ared to the base control efficiency. The wet scrubber auxiliary power requirements were scaled using fact ors developed from the IECM model similar to the capital costs. Equation 4 lists the factor that was a pplied to the auxiliary power requirements are varying 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 re quirements, but sinc e the purpose of this analysis is to estimate the incremental impacts of revised standards compared to existing standards it- 11 - was concluded that the results are sufficient to acc ount for the increased pumping requirements due to the increased liquid to gas ratios at higher removal 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.

Figure 2 presents the estimated incremental impa cts of going BTF acid gas emissions rate of 1.0
lb/MWh to the limit of 1.0 lb SO 2 /MWh for model plants C, D, and E based on the assumption that these facilities would use improved limestone-bas ed wet scrubbers to meet the lower SO 2 emissions limit. Figure 3 presents the estimated incremen tal impacts of going BTF to 1.0 lb/MWh SO 2 emissions limit for the model plants A and B and FBC boilers firing lignite and coal refuse (model plants F and G) based on the assumption that these facilities would us e an improved lime-based SDA system to meet the
lower SO 2 emissions limit. A significant distinction between this analysis and the NSPS analysis is the baseline control technology for the co al refuse-fired EGU. The floor leve l of control requi res the use of a secondary polishing scrubber and the costs are base d on incremental improvement in that polishing
scrubber.

Figure 2. Limestone-Based Wet FG D Annual Incremental Impacts

Model

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

(tons) Incremental
Cost
Effectiveness ($/ton) Electricity Use (MWh) Solid

Waste
Generated (tons) Water Use (1,000 gal) Limestone Use (tons) Chemicall y Created
CO 2 (tons)

C 526 551 954 4,426 3,507 188 986 379

D 620 576 1,077 6,326 3,734 197 1,029 396

E 301 552 545 1,305 3,419 202 986 379

Figure 3. Lime-base Dry FGD Syst em Annual Incremental Impacts

Model

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

(tons) Incremental
Cost
Effectiveness

($/ton SO 2 ) Electricity Use (MWh) Waste
Generated (tons) Water Use (1,000 gal) Lime Use (tons)

A 82 112 726 2 838 16 368

B 350 555 631 9 3,944 78 1,733

F 181 445 408 7 1,906 62 830

G 95 114 838 2 1,059 16 467

We also evaluated the incremental cost of going fr om 1.0 lb/MWh to an emissions limit of 0.70 lb/MWh gross output. The model plant burn ing high-sulfur bituminous coal (model plant D) would be unable to- 12 - achieve an emissions rate of less than 1.0 lb/MWh with the emissions reductions that have been currently demonstrated for wet scrubbers. Therefore, the facility would have to install a polishing spray dryer in addition to a wet scrubber. To estimate thes e costs, we modeled a wet scrubber to achieve the
initial 95% reduction in SO 2 emissions. The flue gases would th en enter a SDA for an additional 77% reduction for an overall reduction of 99%. Figure 4 s hows the incremental impacts of adding a polishing scrubber to model plant D.

Figure 4. Polishing SDA Annual Incremental Impacts

Model

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

(tons) Incremental
Cost
Effectiveness ($/ton) Electricity Use (MWh) Solid

Waste
Generated (tons) Water Use (1,000 gal) Limestone
& Lime Use (tons) Chemicall y Created
CO 2 (tons)

D 17,087 540 31,669 13,018 (15,222) 183,460 (2,751) (2,692)

We conclude that it is not reasonable to establis h a MACT standard based on a BTF level of control below 1.0 lb/MWh due to the high incremental costs of achieving the additional reductions. .