1 MEMORANDUM

TO: Jim Eddinger, U.S. Environmental Protection Agency, OAQPS (C439

- 01)

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

DATE: 24 March 2010

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



## 1.0 INTRODUCTION
The purpose of this memorandum is to discuss the methodology used to estimate cost, emission reductions, and secondary impacts from industrial, commercial, and i nstitutional boilers at area sources of hazardous air pollutant (HAP) emissions. These impacts were calculated for existing units and projected new boilers expected to be operational by the year 2013, three years after the rule is expected to be promulgat ed.
The cost, emission reductions , and secondary impacts analyse s for existing and new area
source boilers were conducted on model boilers

. Twenty

- seven general model boilers were developed based on the sized of the combustion unit and fuel combusted. There are a total of 182,671 existing boilers nationwide, according to the extrapolated boiler inspector inventory.
These boilers were divided into the 2 7 model units in order to assess the impacts of the proposed regulatory options. An estimated 6,779 new boilers at area sources are expected to be installed by 2013, and most of these units are expected to fir e fuel oil. Given the current fuel oil prices, and the fact that gas

- fired boilers are not part of the area source industrial, commercial and
institut ional boiler source category, these projections may overestimate the number of new sources expected to come on

- line by 2013. Instead, these new boilers projected to fire fuel oil may be configured to fire natural gas in order to avoid the compliance costs associated with the area source rulemaking. The project new units were distributed among 12 model boilers, five models representing units at industrial facilities and the remaining 77 model boilers representing2 boilers at commercial and institutional faci lities. The methodology used to develop model units and estimate the number of affected units are presented in other memoranda

. (Projecting new area source

boilers, developing model units) The results of the impacts analysis are presented for the most strin gent regulatory option evaluated and the regulatory option contained in the proposed rule. The development of the MACT floor level of control and a detailed description of the cost equations used to estimate costs for various control technologies is prese nted in other memoranda. 1,2 ,3 This memorandum is separated into the following sections:

1.0 Introduction
2.0 Regulatory Options and Estimating Cost Impacts
3.0 Methodology for Estimating Emission Reductions
4.0 Methodology for Estimating Secondary Impacts [under develop ment]
5.0 References [under development]


## 2.0 REGULATORY OPTIONS AND ESTIMATING COST IMPACTS

Three control options were considered for boilers at area sources of HAP. For each option, a percentage of units in each model unit were assumed to require control de vices 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 four options is described below. A summary table comparing the overall capital an d annualized costs of option 1 and option 2a is presented in Table 1. The equations used to estimate the control, testing, monitoring, and work practice costs are discussed in another memorandum. 2,3



### 2.1 **Existing Units** Option 1 Option 1 requires boilers of al l sizes to meet numerical emission limits for CO, PM, and Hg. To estimate the number of units required to install controls to meet the emission limits, the baseline emissions for each model unit is compared to the corresponding MACT floor for CO and Hg, an d generally achievable control technology (GACT) limit for PM. T he following logic3 is used to select which control devices are included in the cost analysis for each existing boiler :

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 i n the MACT floor analysis, a fraction of units in each subcategory 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 estimat ed to be installed at 56 percent of the existing coal

- fired 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 requ ire a fabric filter to be installed, this cost impacts analysis assumes that 50 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 installing 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 emissio ns 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 emiss ions 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 fue ls have a stoker combustor design since this is the predominant 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 control s, either a basic

tune

- up or a more advanced burner replacement or installation of a linkageless boiler4 management system, can achieve the proposed MACT floor emission limits. No oxidation catalysts are estimated to be required to meet the MACT floor emiss ion limits.
Based on the emission test data used to calculate 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 limit s. 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 excee ding the floor and this cost impacts analysis assumes these 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.

Particulate Matter Control

For all units that were not expected to install a fabric filter for mercury control, this cost impacts analysis assumes that the unit would install a multiclone to achieve the GACT emission limits for PM. Based on the current MACT floor analysis, 44 percent of coal units and 50 percent of biomass and liquid units would install a multiclone.

Testing and Monitoring Cost Impacts

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

. 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 year. Combustion units 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 w as estimated 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 f uel analyses received from a fuel supplier for chlorine and Hg.5 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 mmBt u/hr were 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
, 6 00 per year. Although solid fuels are eligible to comply with the proposed rule through fuel an alysis 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 dat a sources used to estimate testing and monitoring
costs are discussed in other memoranda. 2 ,3 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 e mission 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 i n 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. Fuel Savings Impacts This cost analysis includes an estimate of energy savings for every uni t that is expected to install controls to improve combustion, or conduct an annual tune

- up or energy audit. The Department of Energy has conducted energy assessments at selected manufacturing facilities and reports that facilities can reduce fuel/energy u se 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 f uel combustion. Further boiler tune

- ups have been shown to improve the efficiency of a boiler 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 reducing fuel consumption. This cost analysis assumes an annual fuel savings of 1 percent. The energy savings is estimated using the Equation 1:

Annual Fuel Savings (mm Btu/yr) = DC * CF * Op hours (Equation 1) Where:6 DC = unit design capacity (mmBtu/hr) CF = capacity factor, 90% of design capacity Op hours = annual operating hours, assumed 8400 (hours/year)
After the fuel savings for each boiler was calculated, the both industrial and commercial prices for coal, #2 distillate fuel oil, #6 residual fuel oil, and natural gas were obtain from the
EIA. 3 The EIA data reported fuel prices as $/ton for coal, $/thousand cubic feet for natural gas, and cents per gallon for fuel o il. The higher heating values were obtained from Tabl e C

- 1 of the EPA Mandatory Reporting Rule (40 CFR 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 inventory, 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 t he fuel savings from units in the coal
and liquid fuel categories. 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 purch ased fuel.


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

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


### Option 2a Option 2a includes control device and testing/monitoring cost estimation logic identical to Option 2 outlined above, except for the addition of the estima ted cost of one facility

- wide energy audit for each facility, annualized over 5 years, as discussed in option 2. As discussed in the memorandum for Estimating Control Costs from Major Source Boilers and Process heaters, the cost of an energy audit ranges f rom $75,000 for industrial

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

- scale audits. 2 The facility’s classification of either an industrial or commercial facility was assigned using the distribution o f
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. For the cost impacts7 analysis, 91,339 facilities are expected to conduct an audit, 87,507 facilities are commercial or
institutional and 3,832 facilities are industrial.



### 2.2 **Regulatory Options for New Units** The same three regulatory options 1, 2, and 2a were evaluated for the 6,779 new boilers expected to come online through 2013. However, the distribution of new units expected to install fabric filters for mercury control or advanced combustion controls for CO control were adjusted to account for other regulatory requirements including New Source Performance Standards and local air quality sta ndards that may require new boilers to install low NOx burners.


### Option 1 Mercury and PM Control
To meet the PM GACT floor limit of 0.0 3 lb/mmBtu, and the proposed mercury limits for coal, biomass, and liquid units, the cost to install a fabric filter was applied to all new boilers, regardless of size.

CO Control Since new boilers are estimated to install new low NOx burners as part of their installation, the work practice estimated to achieve the proposed CO limits is a tune

- up. The
costs for a tune

- up w ere applied to all new boilers expected to come online through 2013.

Testing and Monitoring The same testing and monitoring costs des c ribed for option 1 for existing units in section 2.1 was applied to all new units.

Fuel Savings
Since all new boilers are expected to conduct a tune

- up to meet the CO limit, an estimate of fuel savings was calculated for all new boilers firing coal and liquid fuels. The calculations used to estimate fuel savings are described in Section 2.1.


### Option 2 Similar to option 2 d iscussed in Section 2.1, under this option new units less than 10 mmBtu/hr will demonstrate compliance with the rule using a tune

- up and the cost of an annual8 tune

- up was applied to every new boiler with a design capacity of less than 10 mmBtu/hr. For larg er units, the regulatory option is the same as Option 1, that is all units >10 will install a fabric
filter and conduct a tune

- up in order to achieve the proposed MACT floor emission limits for mercury and CO and the GACT emission limit for PM.


### Option 2a O ption 2a is the same as option 2 above, except for the addition of a facility

- wide energy audit. As discussed for option 2a for existing boilers under Section 2.1, the cost of an audit depends on whether the facility is an industrial or commercial facility . The cost of each type of audit was annualized over 5 years at 7 percent to obtain an annualized cost estimate. The facility’s classification of either an industrial or commercial facility was assigned using EIA fuel projection estimates for 2013 in the i ndustrial and commercial sectors. Based on these projections, and an average of 2 boilers per facility, this cost impacts analysis estimates that 3,035 facilities with new boilers are at commercial or institutional facilities and the remaining
354 faciliti es with new boilers are at industrial facilities.



### 2. **5 Summary of Cost Impacts** 

Option 2a is the proposed option for existing boilers and option 1 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 practice 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 t he costs for each model unit.

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 Cont rol TCI New 1 6,779 $ 2,233 $ 2,145 $177 $ 2,056 $ 5,952 Existing 2a 182,677 $5, 324 $ 4
, 751 $357 $ 4
, 967 $ 15,5969 

## 3 .0 METHODOLOGY FOR ESTIMATING EMISSION REDUCTIONS

This section discusses the methodology used to estimate emission reductions from boilers

a t both existing and new facilities and it presents a summary of the results for the regulatory option s 1 and 2a

.



### 3.1 **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 units 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

. 1

- 2

Emission Reductions for Option 1
E mission reductions for all pollutants 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 emission limits correspond ing to the subcategory for each
model boiler

. A detailed discussion of the procedures and results of the MACT floor analysis is

prese nted in an other memorand um

. ( cite MACT floor analysis )
For all units expected to install a fabric filter to meet the merc ury MACT floor emission limits, this fabric filter achieves a co

- benefit of reducing emissions of PM and non

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

average baseline 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 factors 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 u sed to calculate average baseline emission factors for different fuel and control configurations is discussed in
another memorandum. (Baseline) It was assumed that the remaining boilers that did not install a fabric filter will install a cyclone or multicl one to reduce PM emissions. Multiclones were10 identified as a GACT level of control for solid fuel units. 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
efficiencies for various control devices are detailed in another memorandum. (cite baseline memo) Model units with a design capacity greater than 10 mmBtu/hr were expected to al ready have a
multiclone installed as a baseline level of control, so no additional PM emission reductions were estimated from these units, unless the unit installed a fabric filter for mercury control.
To estimate the reductions in other non

- mercury meta llic HAP, the percent reduction in
filterable PM was calculated for each model unit, depending whether a multiclone of fabric filter was projected to be installed on the boiler. This percent reduction was multiplied by the baseline
emissions for each of th e non

- mercury metallic HAP. T his analysis assume s that each model
boiler would achieve an identical percent reduction from baseline emissions for each non

mercury metallic HAP as was achieved for PM.
PM2.5 emissions comprise a fraction of total filterabl e 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 memoranda. (cite

baseline memo) To calculate emissi on reductions for PM2.5 for each model boiler , the emission reductions for PM were multiplied by the applicable PM2.5 fraction. For any boiler conducting a tune

- up, a one percent gain in combustion efficiency was estimated, resulting in an estimated one percent emissions reduction of HCl, HF, SO2, THC, VOC, and dioxins/furans. Efficiency gains reduce fuel use, and in turn, emissions of hazardous air pollutants. A one percent reduction in emissions for these pollutants was estimated by multiplying the ba seline 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 (Equation 2) Where: ER HI = emission rate (lb/mmBtu) 0.0005 = conversion factor, lbs per ton Op hours = annual operating hours reported in 2008 survey (hours/year)11 To convert emission reductions from a concentration basis to an annual emission rate, Equations 3 and 4 were used:

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

– O 2 ) / (20.946

– Std O 2 ) (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) 60 = 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 perce nt oxygen in standardized emission concentration for proposed rule.
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 ) (Equation 4) Where: ER C = emission concent ration (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 hours reported in 2008 survey (hours/year) 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.

Convertin g concentrations to an annual emission rate required an oxygen concentration and exhaust flowrate estimated for each specific fuel type. The development of these assumptions and estimates is presented in other memoranda SEE Control Cost Memo . All conversi ons required the annual operating hours for each model unit, which were assumed to be 8,400 hours

per year for all model units (two weeks of downtime).

Emission Reductions for Option 2a12 The same calculations discussed for estimating emission reductions fo r option 1 were applied to all boilers except small model boilers (less than 10 mmBtu/hr). For small model
boilers , the emission reductions were based on a one percent gain in efficiency expected from the
annual tune

- up work practice standard. 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 for each unit by a factor of 0.01. A summary of the estimated
emission reduc tions at existing units for both option 1 and option 2a are located in Appendix B

1

.



### 3.2 Emission Reductions from New Boilers

Based on industrial and commercial fuel consumption projections 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. (cite EIA source) These new projected boilers are expected to fire biomass, coal, and liquid fuels

. An average (mean) design capacity of area source boil ers 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 sa me manner as existing area source model units. The development of area source model units and the procedures and results of the baseline emiss ions analysis is presented in other memoranda

. 1

- 2

The New Source Performance Standards for Industrial, Commercial and Institutional Boilers (40 CFR part 60, subparts Db, Dc) ( NSPS ) w as reviewed to identify the expected baseline level of control for projected new units. It was determined that new boilers larger than 30 mmBtu/hr and combusting biomass would install an ESP. This technology selection is based on the analysis used to establish the PM NSPS limit for biomass boilers. New coal boilers larger than 75 mmBtu/hr would have a fabric filter and wet scrubber installed, while new coal boilers
between 30 and 75 mmBt u/hr would only have a fabric filter installed and would meet the SO2 limits in the NSPS by using coals with a low sulfur content. New boilers larger than 30 mmBtu/hr and combusting liquid fuel would have a fabric filter installed. All new boilers less

t han 30 mmBtu/hr would have no add

- on controls and liquid fuels were expected to meet the13 NSPS SO2 limits using low sulfur fuel oils. For this impacts analysis, it was assumed that all new solid fuel units would be stokers, since stoker boilers are the most 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 boilers firing biomass are expected to exceed 30 mmBtu/hr.

Emission Reductions for Option 1 After an appropriate baseline level of control was determined for each model unit, an average baseline emission factor calculated for existing units within the same 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 const ructed to meet these limits, so they were used as baseline emission values where applicable. The baseline emissions for each unit were subtracted from the new source MACT floor emission limit corresponding to each unit’s subcategory. The
same calculation s discussed in Section 3.1 of this memo were used to estimate the reductions for
new units.

Emission Reductions for Option 2a The emission reductions for new units under regulatory option 2a were calculated using
the same methods discussed in Section 3.1 of this memo to compare with the reductions achieved under regulatory option 1. Under the proposed rule, 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 d esigned to allow for stack test diameters that would be compatible with EPA test methods

. A summary of the estimated emission reductions at existing units for both option 1 and option 2a
are located in Appendix B

- 2

.



## 4.0 METHODOLOGY FOR ESTIMATING SECONDA RY IMPACTS [under development] 

## 5.0 REFERENCES [under development]14 1. Area source model units memo

2. B aseline emission factor memo

3. Eddinger, J. April 2009. Technical Memorandum: “MACT Floor Analysis for the Industrial, Commercial, and Institutional Area S ource Boilers”.

4. MACT floor memo

5. Roy Oommen, Eastern Research Group (ERG). Memorandum to Jim Eddinger, U.S. Environmental Protection Agency, OAQPS. Methodology for Estimating Cost and Emissions Impacts for Industrial, Commercial, Institutional Boilers a nd Process Heaters National Emission Standards for Hazardous Air Pollutants. October, 2002.15 Appendix A

– Emission Reductions Spreadsheet