1 MEMORANDUM

TO: Jim Eddinger, U.S. Environmental Protection Agency, OAQPS /SPPD

FROM: Graham Gibson, Susan McClutchey, and Amanda Singleton, ERG

DATE: April 2010

SUBJECT: DRAFT Methodology for Estimating Impacts from Industrial, Commercial, Insti tutional Boilers at Area Sources of Hazardous Air Pollutant Emissions



## 1.0 INTRODUCTION
The purpose of this memorandum is to discuss the methodology used to estimate the costs, emission reductions, and secondary impacts from industrial, commercial, and institutional boilers at area sources of hazardous air pollutants (HAP). These impacts were calculated for existing units and new units projected to be operational by the year 2013, three years after the rule is expected to be promulgated. The results of the impacts analysis are presented for both the most stringent regulatory option evaluated and the regulatory option contained in the proposed
rule. The development of the maximum achievable control technology (MACT) floor and Generally Achievable Contro l Technology (GACT) level of control, projection of new units, and a detailed description of the cost equations used to estimate costs for various control technologies is presented in other memoranda. 1,2,3 This memorandum is organized as follows:
1.0 Introduct ion
2.0 Overview of Regulatory Options
3.0 Estimating Cost Impacts
4.0 Methodology for Estimating Emission Reductions
5.0 Methodology for Estimating Secondary Impacts
6.0 References2 

## 2.0 OVERVIEW OF REGULATORY OPTIONS

Three control options were considered for existing boiler s at area sources of HAP. A description of the three options is described below.



### 2.1 **Existing Units**

**•** Option 1E represents the option where all boilers, regardless of fuel type or size, must meet mercury and CO numerical emission limits based on MACT and PM n umerical emission limits based on GACT . PM GACT was identified to be a multiclone for existing units.

**•** Option 2E represents the same emission limits as discussed in 1E above for large units (equal to or greater than 10 mmBtu/hr). Small units are exempt fro m numerical limits and instead are required to meet a work practice standard of a bienni al tune

- up. All facilities are required to conduct an energy audit.

**•** Option 3E represents the primary proposed option discussed in the preamble. In this option, all c oal boilers equal to or greater than 10 mmBtu/hr must meet mercury and CO numeric emission limits based on MACT . All biomass and liquid boilers equal to or greater than 10 mmBtu/hr must meet a CO numerical emission limit , based on MACT

. All facilities wi th a large boiler are required to conduct an energy audit. Small boilers are exempt from numeric emission limits for all pollutants, but are required to meet a work practice standard of a biennial tune

- up. There are no numerical emission limits for PM und er this option for any size or type of unit.


### 2.2 **New Units**

Three control options were considered for new boilers at area sources of HAP. A detailed description of the three options is described below.

**•** Option 1N represents the option where all boilers, regard less of fuel type or size, must meet mercury and CO limits based on MACT and PM numerical emission limits based on GACT

. GACT for new units is based on PM limits in the New Source Performance Standards (NSPS) for Industrial, Commercial, and Institutional B oilers (40 CFR part 60 subparts Db, Dc).

**•** Option 2 N represents the same emission limits as discussed in 1N above for large units (equal to or greater than 10 mmBtu/hr). Small units are exempt from numerical emission limits and instead are required to meet a work practice standard of a biennial tune

- up.

**•** Option 3N represents the primary proposed option discussed in the preamble. In this3 option, all coal boilers, regardless of size, must meet mercury and CO limits based on MACT and PM numerical emission li mits based on GACT . All biomass and liquid boilers, regardless of size, must meet CO limits based on MACT and PM numerical emission limits based on GACT

.


## 3 .0 ESTIMATING COST IMPACTS

For each option, a percentage of units in each model unit were assumed to require control
devices in order to meet the limit when the baseline emissions for the model unit exceeded the MACT floor emission limit applicable to each model. A detailed description of the three options is described below. A summary table comparing the overall capital and annualized costs of option 3E for existing units and option 3N for new units is presented in Table 1. The equations used to estimate the control, testing, monitoring, and work practice costs are discussed in another
memorandum. 3 Th e following logic was used to apply control, testing, and monitoring costs to
each boiler:



### 3.1 **Option 1E**

Control Cost Impacts

Mercury Control A new fabric filter installation was expected to achieve the mercury emission limits in the proposed rule. Where baseline mercury emissions were found to be greater than the MACT floor, the cost of a fabric filter was estimated for a portion of the boilers represented by the model unit.
Based on the data used in the MACT floor analysis, a fraction of units in each su bcategory meeting the MACT floor for Hg was estimated

. For boilers designed to burn biomass one of the boilers was meeting the floor and the other unit was not meeting the floor. In the cost impacts analysis, 50 percent of the biomass units were estimated to install a fabric filter to meet the floor

. For boilers designed to burn coal, 44 percent of units were achieving the proposed MACT floor emission limit for coal, so a new fabric filter was estimated to be installed at 56 percent of the existing coal

- fir ed boilers. For liquid fuel units, there were no area source boilers with emission test data available for mercury. In the absence of other information about the distribution of units that would require a fabric filter to be installed, this cost impacts an alysis assumes that 504 percent of the liquid fuel units would install a fabric filter to meet the mercury limit.

CO/Organic HAP Control Organic HAP and carbon monoxide can be controlled by either improving the combustion efficiency of the unit, or insta lling an oxidation catalyst on the exhaust of a combustion unit. The control strategy necessary to meet the MACT floor emission limit will vary depending on the magnitude between the baseline emissions and the CO MACT floor. Most boilers (other than Dutch ovens and PC

- coal boilers) are designed to operate with CO emissions at or near 400 parts per million (ppm). A boiler tune

- up was estimated in the cost impacts analysis if the unit’s baseline emissions exceeded the floor for carbon monoxide (CO),
but were less than or equal to 400 ppm @ 3% O 2 . The combustor design of the boilers in the area source inventory is not known and this impacts analysis assumes that all areas source boilers firing solid fuels have a stoker combustor design since this is the predom inant combustor design in the major source boiler inventory. The baseline emissions for area source boilers in all fuel categories are less than 400 ppm, and so it is assumed that combustion controls, either a basic

tune

- up or a more advanced burner replac ement or installation of a linkageless boiler management system, can achieve the proposed MACT floor emission limits. No oxidation catalysts are estimated to be required to meet the MACT floor emission limits.
Based on the emission test data used to calcul ate the MACT floor for CO , 29 percent of units burning coal are meeting the MACT floor and these units would be expected to install a linkageless boiler management system to comply with the CO limits. For units burning biomass, 72 percent of the units are exceeding the MACT floor emission limits, and so 72 percent of the units are estimated to install a linkageless boiler management system. For units burning liquids, 86 percent of the units are exceeding the floor and this cost impacts analysis assumes thes e units will install a new low NOx replacement burner in order to meet the CO limits. The units not expected to install these advanced controls are expected to conduct an annual tune

- up to maintain in compliance with the proposed CO limit overtime.

Partic ulate Matter Control
For all units that were not expected to install a fabric filter for mercury control, th e cost impacts analysis for this option assumes that the unit would install a multiclone to achieve the5 GACT emission limits for PM. Based on the c urrent MACT floor analysis, 44 percent of coal units and 50 percent of liquid units would install a multiclone. Existing biomass units not expected to install a fabric filter would also install a multiclone. Base on the current MACT floor analysis, 50 pe rcent of existing biomass units would install a multiclone.


### Testing and Monitoring Cost Impacts

Testing and monitoring requirements varied depending on the equipment installed on the unit to control emissions, the design capacity of the model unit, and t he fuel category of the
model unit

.

Testing Costs
All boilers designed to burn solid fuels were expected to conduct an annual compliance test for PM, Hg, and CO. The cost to conduct stack tests for these three pollutants was estimated to be $ 15 ,000 per ye ar. Boilers greater than 100 mmBtu/hr were expected to install CO CEMS in lieu of conducting a CO stack test and t he cost to conduct tests on PM and Hg was estimated to be $ 12 ,000 per year. Boilers designed to burn liquid fuels were expected to conduct a n annual compliance test
for PM and CO. In lieu of a stack test boilers designed to burn liquid fuels were expected to conduct fuel analysis, or report fuel analyses received from a fuel supplier for chlorine and Hg. Conducting stack tests for PM and CO wa s estimated to be $13,000 per year and the cost to
conduct fuel analysis for Hg was estimated to be $600 per year. Combustion units greater than 100 mmBtu/hr were expected to install CO CEMS in lieu of conducting a CO stack test and the
cost to conduct tes ts on PM and fuel analysis for Hg was estimated to be $ 8
, 6 00 per year. Although solid fuels are eligible to comply with the proposed rule through fuel analysis in lieu of stack testing, when the mercury content of the fuel is below the MACT floor emission limit, this cost estimate conservatively assumed that only units designed to fire liquid fuels would use this compliance alternative. The methods and data sources used to estimate testing and monitoring
costs are discussed in other memoranda. 36 Monitoring Costs Various monitor configurations were installed based on the size of the unit and the pollution control devices expected to be installed to achieve the MACT floor emission limits. For units expected to install a fabric filter, an annualized cost of $9 ,700 for a bag leak detection monitor was included in the cost analysis. For units greater than 100 mmBtu/hr, an annualized cost of $53,300 for a CO CEMS was included in the cost analysis. For units that did not install a bag leak detector, an annualized c ost of $14,660 for an opacity monitor was included in the cost analysis.


### Fuel Savings Impacts This cost analysis includes an estimate of energy savings for every unit that is expected to install controls to improve combustion, or conduct an annual tune

- u p or energy audit. The Department of Energy has conducted energy assessments at selected manufacturing facilities and reports that facilities can reduce fuel/energy use by 10 to 15 percent by using best practices to increase their energy efficiency. Many best practices are considered pollution prevention because they reduce the amount of fuel combusted which results in a corresponding reduction in
emissions from the fuel combustion. Further boiler tune

- ups have been shown to improve the efficiency of a b oiler between 1 and 5 percent, depending on the age of the unit and the time lapse since the previous tune

- up. Other combustion controls such as upgrading burners and installation of an LBMS are also expected to improve the efficiency of the unit, thus red ucing fuel consumption. This cost analysis assumes an annual fuel savings of 1 percent. The energy savings is estimated using Equation 1:

Annual Fuel Savings (mmBtu/yr) = DC * CF * Op hours * EG (Equation 1) Where: DC = unit design capacity (mmBtu/hr) Op hours = annual operating hours, assumed 8400 (hours/year) EG = Efficiency gain, estimated to be 1% CF = annual average capacity factor, 0.5 for liquid and 0.65 for coal and biomass

After the fuel savings for each boiler was calculated, the both industri al and commercial prices for coal, #2 distillate fuel oil, and #6 residual fuel oil were obtain ed from the EIA. 3 The EIA data reported fuel prices as $/ton for coal, and cents per gallon for fuel oil. The higher heating values were obtained from Tabl e C

- 1 of the EPA Mandatory Reporting Rule (40 CFR7 part 98 subpart C) and the higher heating values were used to convert the fuel prices to a standard unit of measure, $ per mmBtu. Using the distribution of SIC code s reported in the 13

- state boiler inspector inve ntory, the model units were distributed to an industrial or commercial sector, and the n the appropriate fuel price was multiplied by the calculated fuel savings. This cost analysis only estimates the fuel savings from units in the coal and liquid fuel cate gories. A fuel savings was not estimated for units in the biomass fuel category since the price of biomass fuels is variable, and often biomass is an on

- site industrial byproduct instead of a purchased fuel.



### 3.2 **Option 2 E**  Option 2 E follows the same logic for estimating control costs as option 1 E outlined above, with the exception of small units (less than 10 mmBtu/hr). In option 2 E , the only cost
estimated for small units is the cost of a n a nn u al tune

- up for each boiler. No testing and monitoring costs wer e included in option 2 E for small units

. Option 2E also includes the cost of an energy audit at every area source facility, approximately 91,339 facilities

. As discussed in the memorandum for Estimating Control Costs from Major Source Boilers and Process heaters, the cost of an energy audit ranges from $75,000 for industrial

- scale energy audits to between $2,000 and $5,000 per energy audit for institutional and commercial

- scale audits. 4 The facility’s
classification of either an industrial or commercial facility was assigned using the distribution of
SIC codes in the 13

- state boiler inspector inventory. The cost of each type of audit was annualized over 5 years at 7 percent to obtain an annualized cost estimate.



### 3.3 **Option 3E**  The proposed o ption 3E incl udes control device and testing/monitoring cost estimation for mercury and CO from large coal units. As mentioned in option 1E, 56 percent of large coal units, or 321 boilers are expected to install a fabric filter in order to meet the mercury limit. In
ad dition, 29 percent of large coal units are expected to install advanced combustion controls in order to meet the CO limit. This analysis uses the cost of a linkageless boiler management system to estimate the costs of advanced combustion control. The remai ning 71 percent of large coal units are expected to meet the CO limit with a tune

- up. The testing and monitoring costs for large coal units include a test for CO and mercury, as well as a bag leak detection system for the 321 boilers that are expected to i nstall a fabric filter. There are no proposed numerical PM8 em ission limits under this option, and so no additional testing costs for PM or opacity monitoring costs were assessed in the cost impacts analysis for this option. Under option 3E liquid and bioma ss boilers are not subject to numerical emission limits for mercury and there are no costs included in the impacts analysis to install fabric filters or conduct mercury fuel analysis or stack testing. Large liquid and biomass boilers are subject to
numeric al emission limits for CO. This cost impacts analysis estimates that all the biomass and liquid fuel units can meet the CO emission limits by conducting an annual tune

- up. These large units must also conduct testing and monitoring activities for CO to demo nstrate compliance with
the numerical emission limits. Option 3E exempts small boilers from numerical emission limits. Instead these units must conduct a work practice standard of a biennial tune

- up. The cost impacts analysis does not include any additiona l testing and monitoring requirements for these small boilers. Finally, option 3E proposes that all facilities with large boilers conduct an energy audit. For this cost impacts analysis one large boiler per facility was assumed, or 13,268 facilities
estima ted to conduct an audit . Similar to the discussion under option 2E, the cost of the audit ranged from $ 75,000 for industrial

- scale energy audits to between $2,000 and $5,000 per energy
audit for institutional and commercial

- scale audits. 2



### 3.4 

### Option **1 N**  New area source boilers are subject to an NSPS (40 CFR part 60 subparts Db, Dc) to regulate emissions of PM, NOx and SO2. The cost impacts analysis considered controls that would likely be installed to comply with the NSPS and includes an estimate of any a dditional control, testing and monitoring costs that would not be already conducted to meet the requirements of the NSPS. Based on a review of the NSPS, this analysis assumes all biomass boilers greater than 30 mmBtu/hr will have an ESP control installed a s the baseline to meet the NSPS PM limits; all coal boilers greater than 75 will have an FF and wet scrubber installed to meet PM and SO2 limits; all coal boilers between 30 and 75 will have a Fabric Filter and use low
sulfur coal to meet PM and SO2 limits , and all liquid boilers greater than 30 will have an FF installed to meet PM limits. The NSPS does not regulate PM for units less than 30 mmBtu/hr.

Mercury Control A new fabric filter installation was expected to achieve the mercury emission limits in t he9 proposed rule. Where baseline mercury emissions were found to be greater than the MACT floor, the cost of a fabric filter was estimated for a portion of the boilers represented by the model unit. All new boilers, regardless of size or fuel, were expecte d to install a fabric filter in order to meet the mercury limits under this option. Comparing the s e mercury control requirement to the expected controls under the NSPS, all biomass boilers are expected to install a fabric filter to meet the mercury limit and all liquid and coal boilers less than or equal to 30 mmBtu/hr are expected to install a fabric filter to meet the mercury limit.

CO/Organic HAP Control New boilers are expected to be equipped with new and efficient burners, and it was
assumed that an annual tune

- up c ould achieve the CO numeric emission limit for all sizes and types of boilers. Other advanced combustion controls were not considered as a control alternative
for new boilers. As mentioned under 1E, t he control strategy necessary to meet th e MACT floor emission limit will vary depending on the magnitude between the baseline emissions and the CO
MACT floor.

Particulate Matter Control Under this option all units are expected to install a fabric filter for mercury control, which
has a co

- bene fit of reducing PM emissions, as well as other non

- mercury metallic HAP. No
additional control costs were estimated for PM control at new boilers.


### Testing and Monitoring Cost Impacts

Testing and monitoring requirements varied depending on the equipment in stalled on the unit to control emissions, the design capacity of the model unit, and the fuel category of the
model unit.

Testing Costs All boilers designed to burn solid fuels were expected to conduct an annual compliance test for PM, Hg, and CO. The co st to conduct stack tests for these three pollutants was estimated to be $15,000 per year. Combustion units greater than 100 mmBtu/hr were expected to install CO CEMS in lieu of conducting a CO stack test and the cost to conduct tests on PM and Hg was10 esti mated to be $12,000 per year. Boilers designed to burn liquid fuels were expected to conduct an annual compliance test for PM and CO. In lieu of a stack test boilers designed to burn liquid fuels were expected to conduct fuel analysis, or report fuel anal yses received from a fuel supplier for chlorine and Hg. Conducting stack tests for PM and CO was estimated to be $13,000 per year and the cost to conduct fuel analysis for Hg was estimated to be $600 per year. Combustion units greater than
100 mmBtu/hr wer e expected to install CO CEMS in lieu of conducting a CO stack test and the cost to conduct tests on PM and fuel analysis for Hg was estimated to be $8,600 per year. Although solid fuels are eligible to comply with the proposed rule through fuel analysis i n lieu of stack testing, when the mercury content of the fuel is below the MACT floor emission limit, this cost estimate conservatively assumed that only units designed to fire liquid fuels would use this compliance alternative. The methods and data source s used to estimate testing and monitoring
costs are discussed in other memoranda. 3

Monitoring Costs Various monitor configurations were installed based on the size of the unit and the pollution control devices expected to be installed to achieve the MACT floor emission limits. For units expected to install a fabric filter, an annualized cost of $9,700 for a bag leak detection monitor was included in the cost analysis. For units greater than 100 mmBtu/hr, an annualized cost of $53,300 for a CO CEMS was incl uded in the cost analysis. For units that did not install a bag leak detector, an annualized cost of $14,660 for an opacity monitor was included in the cost analysis.



### 3.4 

### Option **2N** Option 2N follows the same logic for estimating control costs as option 1N outlined above, with the exception of small units (less than 10 mmBtu/hr). In option 2N, the only cost
estimated for small units is the cost of a n a nn u al tune

- up for each boiler. No testing and monitoring costs were included in option 2N for small units



### 3.5 **Option 3N**  The proposed option 3N includes identical requirement for coal units as outlined under option 1N. Under option 3N liquid and biomass boilers are not subject to numerical emission11 limits for mercury and there are no costs included in the impac ts analysis to install fabric filters for mercury control or conduct mercury fuel analysis or stack testing. L iquid and biomass boilers are subject to numerical emission limits for CO. This cost impacts analysis estimates that all the biomass and liquid fu el units can meet the CO emission limits by conducting an annual tune

- up. T hese units must also conduct testing and monitoring activities for CO to demonstrate compliance with the numerical emission limits. Option 3 N also includes a numerical PM emission l imit for coal, biomass, and liquid boilers, based on the NSPS limits applicable to each of these categories. Since all coal units are subject to mercury emission limits, they are expected to meet a PM GACT limit of 0.051 lb/mmBtu without any additional con trol requirements. The NSPS PM limit for biomass is 0.1 lb/mmBtu, which is based on the performance of an electrostatic precipitator (ESP). Since biomass units greater than 30 mmBtu/hr are already subject to this limit under the NSPS, this cost analysis ap plies the costs for an ESP to units less than or equal to 30 mmBtu/hr. The NSPS
PM limit for liquids is also 0.051 lb/mmBtu. Based on the calculated average baseline emission
factors analysis distillate liquids are expected to meet that limit without any a dditional control. 5 However residual liquid units are expected to install a fabric filter to meet the PM emission limit.
Under o ption 3N , all boilers less than or equal to 30 mmBtu/hr are estimated to incur
costs to test for PM and CO , at an estimate cost of $14,000 per year

. Boilers greater than 30 mmBtu/hr will incur PM stack testing costs under the NSPS. Coal boilers are estimated to incur additional costs to test for mercury and the cost to conduct tests for PM, CO, and Hg is estimated to be $19,000 per year

.


### 3.6 **Summary of Cost Impacts** Option 3E is the proposed option for existing boilers and option 3N is the proposed option for new boilers. Since new boilers and their exhaust stacks can be designed to allow for stack testing, the tune

- up work practi ce standard does not apply to new small units. Table 1
summarize s the costs of the proposed option for new and existing boilers at area sources of HAP. Appendix A of this memorandum provides a detailed summary of the costs for each model unit

.12 Table 1 : Summary of Costs of Proposed Option s Costs shown in $10 6 (2008) with capital recovery estimated at 7%

Type of

Unit Option Number of Boilers TAC TAC considering fuel savings Testing & Monitoring TAC Control TAC Control TCI
New 3N 6,779 $ 311 $ 260 $ 193 $ 11 7 $ 343
Existing 3E 182,67 1 $ 696 $279 $ 94 $ 550 $ 1, 792



## 4 .0 METHODOLOGY FOR ESTIMATING EMISSION REDUCTIONS

This section discusses the methodology used to estimate emission reductions from boilers at both existing and new facilities and it presents a summ ary of the results for the regulatory option s 1 E/ 1 N and 3E/3N

.



### 4 **.1 Emission Reductions from Existing Boilers** 

Each model area source boiler was assigned baseline emissions based on the calculated baseline averages for existing major source combustion unit s in the same size and fuel subcategory. The development of area source model units and the procedures and results of the
baseline emiss ions analysis is presented in other memoranda

. 5

- 6

Emission Reductions for Option 1 E
E mission reductions for all pollut ants were calculated on a ton per year basis. Emission
reductions of Hg and CO were calculated by subtracting the baseline emissions assigned to each
model unit from the MACT floor (or GACT) emission limits corresponding to the subcategory
for each model b oiler

. A detailed discussion of the procedures and results of the MACT floor analysis is prese nted in an other memorand um

. 1
For all units expected to install a fabric filter to meet the mercury MACT floor emission limits, this fabric filter achieves a co

- b enefit of reducing emissions of PM and non

- mercury metallic HAP . To calculate the PM emission reductions from units expected to install a fabric13 filter, the baseline emissions assigned to each model boiler were subtracted from the calculated

average baseli ne emission factor corresponding to a fabric filter level of control in the same fuel category. For example, the PM baseline emission factor for uncontrolled or multiclone

- equipped
biomass boilers is 0.26 lb/mmBtu , and the calculated baseline emission fac tors for biomass boilers equipped with a fabric filter is 0.01 lb/mmBtu . The emission reductions were estimated using the difference of these two factors, or 0.25 lb/mmBtu. The methodology used to calculate average baseline emission factors for different f uel and control configurations is discussed in
another memorandum. 5 It was assumed that the remaining boilers that did not install a fabric filter will install a cyclone or multiclone to reduce PM emissions. Multiclones were identified as
a GACT level of control for PM

. Emission reductions for units expected to install a multiclone were estimated by multiplying the baseline emissions of each model unit by the expected PM control efficiency of a multiclone, a 75 percent reduction. These control efficiencie s for various
control devices are detailed in another memorandum. 5 Model units with a design capacity greater than 10 mmBtu/hr were expected to already have a multiclone installed as a baseline level of control, so no additional PM emission reductions wer e estimated from these units, unless the unit installed a fabric filter for mercury control.
To estimate the reductions in other non

- mercury metallic HAP, the percent reduction in
filterable PM was calculated for each model boiler expected to install a f abric filter for mercury
control. This percent reduction was multiplied by the baseline emissions for each of the non

mercury metallic HAP. Since fabric filters capture fine particulate, t his analysis assume s that
each model boiler would achieve an identic al percent reduction from baseline emissions for each

non

- mercury metallic HAP as was achieved for PM. For model boilers that were expected to install a multiclone to meet the PM GACT limit, a 10 percent reduction was estimated for non

mercury metallic HA P.
PM2.5 emissions comprise a fraction of total filterable PM emissions depending on the
fuel combusted and control device configuration installed on the unit. The methods used to derive the contribution of PM2.5 to overall filterable PM are presented in other memor anda. 5 To
calculate emission reductions for PM2.5 for each model boiler , the emis sion reductions for PM were multiplied by the applicable PM2.5 fraction. For any boiler conducting a tune

- up or installing advanced combustion controls such as a replacement burner or linkageless boiler management system , a one percent gain in combustion14 efficiency was estimated, resulting in an estimated one percent emissions reduction of all pollutants . Efficiency gains reduce fuel use, and in turn, emissions o f hazardous air pollutants. 8 A one percent reduction in emissions for these pollutants was estimated by multiplying the baseline emissions for each unit by a factor of 0.01.

To convert emission reductions from an emission rate on a heat input basis to an annual emission rate, Equation 2 was used:

Annual Emission Rate (tpy) = ER HI * 0.0005 * Op hours * CF (Equation 2) Where: ER HI = emission rate (lb/mmBtu) 0.0005 = conversion factor, lbs per ton Op hours = annual operating hours , assumed 8760 (adjusted using capacity factor) CF = annual average capacity factor, 0.5 for liquid and 0.65 for coal and biomass
To convert emission reductions from a concentration basis to an annual emission rate, Equations 3 and 4 were used:

Annual Emission Rate (tp y) = ER C * 0.000001 * ρ air * Q S * 60 * Op hours * 0.0005 * (20.946

– O 2 ) / (20.946

– Std O 2 ) * CF (Equation 3) Where: ER C = emission concentration (ppm @ 3% O 2 ) 0.000001 = conversion factor, ppm to parts ρ air = density of air, 0.0749 lb/dscf Q S = exhaust flowrate (dscfm) 6 0 = conversion factor, minutes to hours Op hours = annual operating hours reported in 2008 survey (hours/year) 0.0005 = conversion factor, lb per ton 20.946 = percentage of oxygen in ambient air O 2 = percentage of oxygen assumed in exhaust gas Std. O 2 = 3 p ercent oxygen in standardized emission concentration for proposed rule. CF = annual average capacity factor, 0.5 for liquid and 0.65 for coal and biomass
Annual Emission Rate (tpy) = ER C * 0.0283 * Q S * 60 * Op hours * 0.000000001 * 0.0022 * 0.0005 * (20. 946

– O 2 ) / (20.946

– Std O 2 ) * CF (Equation 4) Where: ER C = emission concentration (ng/dscm @ 7% O 2 ) 0.0283 = conversion factor, dscm to dscf Q S = exhaust flowrate (dscfm) 60 = conversion factor, minutes to hours Op hours = annual operating ho urs reported in 2008 survey (hours/year)15 0.000000001 = conversion factor, ng to g 0.0022 = conversion factor, g per lb 0.0005 = conversion factor, lb per ton 20.946 = percentage of oxygen in ambient air O 2 = percentage of oxygen assumed in exhaust gas Std O 2 = 7 percent oxygen in standardized emission concentration for proposed rule. CF = annual average capacity factor, 0.5 for liquid and 0.65 for coal and biomass

Converting concentrations to an annual emission rate required an oxygen concentration
and exh aust flowrate estimated for each specific fuel type. The development of these assumptions and estimates is presented in an other memorand um. 4

Emission Reductions for Option 3E The same calculations discussed for estimating emission reductions for option 1 E were applied to all large coal boilers

. For small model boilers , the emission reductions were based on a one percent gain in efficiency expected from the biennial tune

- up work practice standard. For large biomass and liquid units no add

- on controls for PM or mercury are expected since these units are not subject to numerical emission limits for PM or Hg. Instead, a similar one percent gain in efficiency is expected to occur as a result of conducting an annual tune

- up or installing
advanced combustion con trols necessary to meet the CO numerical limit in each category. Efficiency gains reduce fuel use, and in turn, emissions of hazardous air pollutants. A one percent reduction in all types of emissions was estimated by multiplying the baseline emissions
fo r each unit by a factor of 0.01. A summary of the estimated emission reductions at existing units for both option 1 and option 2a are located in Appendix B

- 1

.


### 4 **.2 Emission Reductions from New Boilers**

Based on industrial and commercial fuel consumption p rojections from the EIA and a history of boiler installation dates in the boiler inspector inventory , there are 6,779 new area source boilers expected to come on

- line by 2013. 7 These new projected boilers are expected to fire biomass, coal, and liquid fue ls

. An average (mean) design capacity of area source boilers firing similar fuel type, in the same size category , and in the same sector (industrial or commercial) was estimated to develop new model units representative of the existing boiler inventory. New model units were assigned baseline emissions in the same manner as existing16 area source model units. The projection of new model area source boilers and the procedures
and results of the baseline emiss ions analysis is presented in other memoranda

. 2

As discussed in Section 3.4, t he NSPS for Industrial, Commercial and Institutional Boilers (40 CFR part 60, subparts Db, Dc) ( NSPS ) w ere reviewed to identify the expected baseline level of control for projected new units. Then, the average baseline emission factor corresponding to the expected level of control and fuel category was assigned to each new model
boiler. N ew biomass boilers larger than 30 mmBtu/hr w ere expected to install an ESP ; n ew coal boilers larger than 75 mmBtu/hr were expected to install a fabric filter and wet scrubber ; new coal boilers between 30 and 75 mmBtu/hr would only have a fabric filter installed and w ere expected to meet the SO2 limits in the NSPS by using coals with a low sulfur content ; n ew boilers larger than 30 mmBtu/hr and co mbusting liquid fuel s were expected to install a fabric
filter. All new boilers less than 30 mmBtu/hr would have no add

- on controls

. For this impacts analysis, it was assumed that all new solid fuel units would be stokers, since stoker boilers are
the mos t common type of solid fuel boilers and all new units would have NOx control installed as a baseline control, regardless of fuel. Based on the EIA fuel projections, all new coal boilers are projected to be less than 10 mmBtu/hr and the only 49 model boiler s firing biomass are expected to exceed 30 mmBtu/hr.

Emission Reductions for Option 1N After an appropriate baseline level of control was determined for each model unit, an

average baseline emission factor was calculated for existing units within the sam e fuel category and having the same level of control was assigned to each model boiler. The NSPS specifies PM
and SO2 limits for new solid

- and liquid

- fired combustion units based on heat input. It was assumed that all new solid and liquid units would be c onstructed to meet these limits and those
limits were used as baseline emission values
, where applicable. For units less than 30 mmBtu/hr, the baseline emissions for PM were estimated assuming the unit was uncontrolled and the target
PM emission limit f rom the NSPS was used as the GACT level of control. The baseline emissions for each unit were subtracted from the new source MACT floor for Hg and CO and GACT emission limit for PM corresponding to each unit’s subcategory. The same calculations
discussed in Section 4.1 of this memo were used to estimate the reductions for new units.17 Emission Reductions for Option 3N For new coal boilers, the emission reductions were calculated using the same methods discussed for Option 1N above. For new biomass boilers l ess than 30 mmBtu/hr, emission reductions for PM were calculated by subtracting the PM NSPS emission limits from a baseline emission factor representing uncontrolled units. Since an ESP is not expected to be very effective at capturing mercury emissions, m ercury emissions reductions from all biomass units were estimated based on a one percent efficiency improvement, resulting from annual tune

- ups or other combustion controls expected to occur in order to demonstrate compliance with CO
emission limits. For n ew biomass boilers greater than or equal to 30 mmBtu/hr, there were no
estimated additional PM or non

- Hg metallic HAP emission reductions since these larger biomass boilers are already expected to be in compliance with a PM NSPS limit using an ESP.
New re sidual liquid boilers less than 30 mmBtu/hr were expected to install a fabric filter to meet the PM emission limit. Since a fabric filter is effective at capturing fine particulate, additional emission reductions for mercury were calculated by subtracting the average baseline emission factor for heavy liquid boilers equipped with a fabric filter from the average baseline emission factor corresponding to an uncontrolled heavy liquid unit. The average baseline emission factor for PM at uncontrolled distillat e liquid units is less than the NSPS emission limit for liquid units. As a result, no additional PM, Hg, or non

- Hg metallic HAP emission reductions were estimated from installing additional PM controls. Instead, these reductions were estimated based on a one percent efficiency improvement, resulting from annual tune

- ups or other combustion controls expected to occur in order to demonstrate compliance with CO emission limits. Under this proposed option, new small units do not qualify for the same tune

- up work practice standards that apply to existing units since it is expected that new units can be designed to allow for stack test diameters that would be compatible with EPA test methods. As a result, new A summary of the estimated emission reductions at existing units for both option 1N and the proposed option 3N are located in Appendix B

- 2

.

Incremental Emission Reductions if Energy Audit Findings are Implemented We evaluated the potential additional reductions and fuel savings that could occur as a

resu lt of implementing certain cost

- effective energy efficiency improvements identified during18 the audit. Using the Department of Energy references of a 10 to 15 percent improvement in efficiency, a range of incremental emission reductions was estimated consid ering efficiency gains between 5 and 10 percent. We applied the control efficiency ranges of 5 and 10 percent reduction to the emissions remaining after MACT level of controls were installed on the unit to identify the potential for additional emission red uctions if the findings of an energy audit were implemented. Table 3 summarizes the potential additional emission reductions that could occur under a beyond the floor option of implementing any findings in the audit with a short term payback. The fuel savi ngs were estimated using Equation 1 described in 3.1 of this memo that was used to estimate fuel savings. In this case the efficiency gain term was modified to be between 5 and 10 percent. A summary of the estimated incremental emission reduction and fuel savings is shown in Table 3. A summary of the estimated emission reductions at existing area source boilers for options 1E , 2E, and the proposed option 3E are located in Appendix B

- 1

. A summary of the
estimated emission reductions at new area source boil ers for options 1N, 2N, and the proposed option 3N are located in Appendix B

- 2

.19 Table 3 Emission Reductions and Energy Savings Resulting from Implementing Cost Effective Findings of an Energy Audit at Facilities with Large ( ≥10 mmBtu/hr) Boilers

Assuming a Five Percent Efficiency Gain From Implementing Audit Findings

Emission Reductions and Energy Savings Per Facility HCl Emission Reductions (tpy) Filterable PM Emission Reductions (tpy) Non

- Hg Metals Emission Reductions ( tpy) Hg Emission Reductions (tpy) VOC Emission Reductions (tpy) Energy Saved (mmBtu/yr) Annual Fuel Savings ($/yr)

Min 3.92E

- 03 3.01E

- 02 1.12E

- 03 9.21E

- 07 3.59E

- 04 3.85E+03 $0

Max 2.40E

- 01 3.11E+00 1.64E

- 01 3.28E

- 05 2.93E

- 02 3.80E+04 $860,704

Average 1. 73E

- 02 1.74E

- 01 1.98E

- 02 4.64E

- 06 1.86E

- 03 6.15E+03 $95,279

Median 3.92E

- 03 3.01E

- 02 2.39E

- 02 3.45E

- 06 4.20E

- 04 5.54E+03 $125,613

TOTAL ( 13,268 facilities with a large boiler ) 2.29E+02 2.31E+03 2.63E+02 6.16E

- 02 2.47E+01 8.16E+07 $1,264,161,683

Assumi ng a 10 Percent Efficiency Gain From Implementing Audit Findings

Emission Reductions and Energy Savings Per Facility HCl Emission Reductions (tpy) Filterable PM Emission Reductions (tpy) Non

- Hg Metals Emission Reductions (tpy) Hg Emission Reductions (tpy) VOC Emission Reductions (tpy) Energy Saved (mmBtu/yr) Annual Fuel Savings ($/yr)

Min 7.84E

- 03 6.02E

- 02 2.25E

- 03 1.84E

- 06 7.18E

- 04 7.69E+03 $0

Max 4.80E

- 01 6.23E+00 3.28E

- 01 6.56E

- 05 5.87E

- 02 7.60E+04 $1,721,408

Average 3.45E

- 02 3.48E

- 01 3.96E

- 02 9.28E

- 06 3.73E

- 03 1.23E+04 $190,558

Median 7.84E

- 03 6.02E

- 02 4.79E

- 02 6.89E

- 06 8.40E

- 04 1.11E+04 $251,226

TOTAL ( 13,268 facilities with a large boiler ) 4.58E+02 4.62E+03 5.26E+02 1.23E

- 01 4.94E+01 1.63E+08 $2,528,323,367

* Although the energy savings in mmBtu /yr are calculated for all fuels, a dditional fuel savings in $/yr consider only units in the coal and liquid categories . Biomass is often an industrial byproducts and w as not assigned a purchase price.


## 5 .0 METHODOLOGY FOR ESTIMATING SECONDARY IMPACTS

Sec ondary impacts include the solid waste and electricity required to operate air pollution control devices, as well as the additional energy savings resulting from improved combustion controls or work practices required by the NESHAP. This section documents the inputs and equations used to estimate these secondary impacts, and it summarizes the impacts at existing units under proposed regulatory option 3E and new units under proposed regulatory option 3N

.20 Table 5

- 1 summarizes the secondary impacts of this pr oposed NESHAP. Appendices C

- 1 and
C

- 2 present a detailed breakdown of the secondary waste and energy impacts from each subcategory of existing and new boilers , respectively.

Table 5

- 1: . Summary of Secondary Impacts
Impact New Units (proposed regulatory Option 4N ) Existing Units (proposed regulatory Option 4E )

Solid Waste (tons/yr) 1,800 14,300
Purchased Electricity (kW

- hr/yr) 22 million 206 million Energy Savings* ( t Btu/yr) 2

. 3 4 19

. 6 * Energy savings is calculated for units in the coal and liquid su bcategories. The secondary impacts were calculated using algorithms and assumptions described in
another memorandum. 3 These algorithms and assumptions were applied to the existing boiler s , where the baseline emissions for each unit exceeded the proposed MACT floor emission limit. For new units, the algorithms and assumptions were applied to model units representing units expected to come online between 2010 and 2013, when the baseline emissions for each model exceeded the proposed MACT floor or GACT emiss ion limit for new units. The methodology used to assign baseline emission factors to new and existing units are discussed in another
memorandum. 5


### 5.1 Solid Waste Impacts Solid waste is generated from collecting dust and fly ash in fabric filters or ESP con trol
devices. Solid waste impacts were estimated for every unit expected to install a fabric filter to meet mercury emission limits, or install an ESP to meet PM emission limits. The total national
solid waste amounts in Table 5

- 1 were determined by addin g the per unit solid waste estimates for all new and existing units, respectively. To estimate the solid waste contribution from each of these control devices, t he variables were calculated based on characteristics reported for each
model unit. The calcul ations used to estimate each variable and the quantity of solid waste generated are provided in another memorandum. 3 The solid waste (dust, fly ash) generated by the use of an electrostatic precipitator was calculated when an electrostatic precipitator was determined to be necessary to meet the GACT21 emission limits for PM. Estimates of the solid waste collected in an ESP was based on several variables including: exhaust flow rate from the combustion unit to the control device (acfm); the inlet loading of particulate matter to the control device (gr/acfm); operating hours (hr/year) and the efficiency of the control device required to meet the PM emission limits in the proposed
NESHAP. The solid waste generated from the collection of dust and fly ash in a fabric filter was calculated when a fabric filter was determined to be necessary to meet the proposed NESHAP emission limits for particulate matter and/or mercury. The calculation required the use of three variables, including: exhaust flow rate from the combustion unit to the control device (dscfm); operating hours (hr/year) and the inlet loading of particulate matter to the control device (gr/acfm).


### 5.2 Electricity Impacts The amount of electricity required to operate a control device was calculated for an electrostatic precipitator and fabric filter. These impacts were assessed for every unit that was estimated to require particulate matter control. Electricity requirements are one output of the cost algorithms used in the analyses, so no additional ca lculations were necessary. For some units, an electrical demand from multiple control devices was estimated. The total national electricity demand in Table 5

- 1 was determined by adding the per unit solid waste estimates for all new and existing units, res pectively. To estimate the electricity demand from each of these control devices, a set of variables were calculated based on characteristics assigned to each model unit. The constants, variables, and calculations used to estimate each variable and the
el ectricity demand to operate the control devices are provided in another memorandum. 3


### 5.3 Energy Savings Impacts The energy savings from combustion controls such as low NOx burners or linkageless boiler management systems, and work practice standards, inc luding a tune

- up, and implementing the energy audit findings with a short

- term payback can improvements in efficiency, thereby reducing fuel consumption. Although these combustion improvements have been documented to achieve efficiency gains between 5 and 10 percent from the baseline operating conditions, this secondary impacts analysis estimates a 1 percent efficiency gain, to be conservative and consistent with the assumptions made in Section 3.1 of this memorandum. Quantifying the exact22 gains in efficien cy from each of these work practice standards is difficult, and may depend on the baseline operating efficiency of each unit. Section 3.1 discusses the fuel savings impacts in terms of annualized cost savings to each boiler, and the national energ y saving s presented in Table 5

- 1 of this section follows the same methodology as was discussed in Section 3.1 and reflect the savings from boilers in the coal and liquid fuel categories only

. 

### 5.4 Estimating Secondary Impacts for Regulatory Options 3E/3N Regulatory Options 3E for existing and 3 N for new units are both described in detail in
Section 2 of this memorandum. For the secondary impacts analysis at existing units under option
3 E , the waste and electricity impacts wer e only assessed for large units ( those gr eater than or equal to 10 mmBtu/hr ) that are in the coal subcategor y . Secondary impacts of solid waste and electricity were not assessed for the liquid and biomass subcategor ies because these boilers were not subject to PM or Hg numerical emission limits a nd were not expected to install add

- on controls . Energy savings were estimated for all units firing anything other than biomass since all units were expected to conduct a tune

- up or install combustion controls.

. For new units under option 3 N, the solid wa ste and electricity impacts were assessed for any size unit firing coal
, liquid , or biomass . A one percent energy savings was estimated for all units firing coal or liquids that were estimated to require a tune

- up to meet the CO limits from
new boilers. B oth tune

- ups and combustion controls improve the efficiency of the unit, thereby reducing energy consumption.



## 6 .0 REFERENCES

1. Singleton, A., ERG. MACT Floor Analysis for the Industrial, Commercial, Institutional Boilers National Emission Standards for Haz ardous Air Pollutants

– Area Source . April, 2010

.
2. Singleton, A., ERG. New Unit Analysis Industrial, Commercial, and Institutional Boilers National Emission Standards for Hazardous Air Pollutants

– Area Source . April, 2010.

3. Singleton, A., ERG. Methodo logy for Estimating Control Costs for Industrial, Commercial, Institutional Boilers National Emission Standards for Hazardous Air Pollutants

– Area Source . April, 2010.23 4. Singleton, A., ERG. Methodology for Estimating Control Costs for Industrial, Commerci al, Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants

– Major Source. April, 2010.

5. Gibson, G. and A. Singleton, ERG. Development of Baseline Emission Factors for Boilers and Process Heaters at Commercial, Industrial and Institutional Facilities . April, 2010.

6. Singleton, A., ERG. Methodology for Developing Model Units for Industrial, Commercial, and Institutional Boilers National Emission Standards for Hazardous Air Pollutants

– Area Source . April, 2010.

7. U.S. Department of Energy. Energy Information Administration. Annual Energy Outlook 2006 (Early Release) with Projections to 2030. Figure 3. Energy Consumption by Fuel, 1980

- 2030 (quadrillion Btu)

.
8. Delta Institute. Sector

- Based Based Pollution Prevention: Toxic Reductions through Energy Efficiency and Conservation Among Industrial Boilers. July 2002. Located online at http://www.delta

- institut e.org/publications/boilers/SectorBasedP2.pdf