1 MEMORANDUM TO: Jim Eddinger, U.S. Environmental Protection Agency, OAQPS/SPPD
FROM: Eastern Research Group, Inc.
DATE: August 2012
SUBJECT: Revised (August 2012) Methodology for Estimating Co st and Emissions Impacts for Industrial, Commercial, Institutiona l Boilers and Proce ss Heaters National Emission Standards for Hazardous Air Pollutants – Major Source



## 1.0 INTRODUCTION

The purpose of this memorandum is to disc uss the revised methodology used to estimate the costs, emission reductions, and secondary impacts from industria l, commercial, and institutional boilers at major sources of hazardous air pollutants (HAP). These impacts were calculated for existing units and new units projec ted to be operational by the year 2015, three years after the rule is expected to be promulgated. The result s of the impacts analysis are presented for the regulatory opti on contained in the amended fina l rule. The development of the
maximum achievable control tec hnology (MACT) floor level of c ontrol, projection of new units, and a detailed descriptio n 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 Introduction
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 Incremental Impacts Since March, 2011 Rule Notice
7.0 References2 

## 2.0 OVERVIEW OF REGULATORY OPTIONS

Two control options were considered for ex isting boilers and pro cess heaters at major sources of HAP. A description of the tw o options is include d in this section.


### 2.1 Existing Units The recommended option is the option presented in the preamble and amended final rule. In this option, all boilers and process heaters are subject to work practice standards for dioxin/furan emissions. Small boilers and process heaters (less than 10 mmBtu per hour), limited use boilers and process heaters (operating le ss than 876 hours per yea r), and boilers burning natural gas, refinery gas, or ot her on-spec gaseous fuels are subject to work practice standards in lieu of numeric emission limitations for all pollutant s. The work practice standard for very small (less than 5 MMBtu/hr) units desi gned to burn light liquid or gase ous fuels is one tune-up every five years. The work practice standard for other small and limited use units is a biennial tune-up. The work practice standard for large units (great er than or equal to 10 mmBtu per hour) is an annual boiler tune-up. In addition to the work practice standard for dioxin/furan, large boilers and process
heaters that are not in the unit designed to burn natural gas, re finery gas, or other on-spec gaseous fuels subcategories are subject to numer ic emission limitations for Hg, PM (or a total selected non-mercury metals (TSM8, which is co mposed of the metals As, Be, Cd, Cr, Pb, Mn, Ni, and Se) alternative), HCl, and CO. Boilers co mbusting at least 10 percent solid fuels (either coal, other fossil solids, or bioma ss), or at least 10 percent liqui d fuels (either heavy liquid, light liquid, or units located in non-c ontinental States and United Stat es Territories designed to burn liquid fuels) are grouped into a single solid or liquid fuel s ubcategory, respectively, and are subject to identical emission limitations for the fuel-based pollutants Hg and HCl. For units designed to combust biomass/bio-based solids, separate combustor design subcategories are considered for the combustion-based pollutants PM (or TSM8) and CO. For units designed to combust coal/fossil solid, combustor design subcat egories are considered for CO only. Emissions of PM (and TSM8) are not expected to vary with the differing combustor designs for coal-fired boilers, and thus all units firing coal/fossil solid are grouped into a single coal subcategory for the regulation of these pollutants. For units de signed to burn liquid fuel s, separate combustor3 design subcategories are considered for PM and CO. Units burning off-spec gaseous fuels (other process gases) have a single subcategor y for both fuel and combustion-based HAP. Based on conversations with regula ted entities, it is likely th at several large units firing liquid fuels in continental states that have access to natural gas s upplies will switch to natural gas combustion in lieu of installing controls and de monstrating compliance with the emission limits for their respective subcategory. If the liquid-fired unit is in a continental state, is not a limited use unit, and reported the capability to combust na tural gas for at least 10 percent of the total reported annual operating hours for the unit, it is assumed for the purposes of this impacts analysis that the unit will c onvert to 100 percent natural ga s combustion. A total of 258 units firing liquid fuels were assumed to meet these criteria and switch to natural gas combustion. These units would be subject to the same work practice stan dards as existing units burning natural gas, refinery gas, or other on-spec gaseous fuels after making the switch to natural gas.

 The alternative option is identical to th e recommended option except that a TSM8
alternative standard is not included for the li quid subcategories under this alternative, and no liquid units are assumed to switch to natu ral gas combustion as a compliance strategy. Instead, these liquid units are assumed to inst all controls to meet the emission limits.



### 2.2 New Units
The same two control options for existing uni ts were used for new units. A total of 1,844 total new boilers are projected to be constructed by 2015. Of th ese projected new boilers, 82 are projected to combust biomass. The methods and assumptions used in projecting new units is
detailed in another memorandum. 3 No new liquid-fired boilers were projected, and thus no impacts were estimated for new liquid-fired units switching to natu ral gas in order to demonstrate compliance.



## 3.0 ESTIMATING COST IMPACTS
The cost impacts analysis compares the baseline emissions for each unit to the corresponding proposed emission limit for the un it’s subcategory. A control device was applied
to the unit if its baseline emissions exceeded their applicable proposed emission limit. A comparison of the overall capital and annualized costs of the prom ulgated option is presented in4 Table 3-5. The detailed equations used to estima te the control, testing, monitoring, and work practice costs are discusse d in another memorandum. 2 The following logic was used to apply control, testing, and monitoring costs to each boiler or process heater:


### 3.1 Recommended Option
The recommended option represents an option wi th a consolidated subcategory for fuelbased HAP from solid fuel units, where every unit must meet numeri cal emission limits and demonstrate compliance with performance stack te sting, monitoring, and fuel analysis with a few exceptions. Units in the gas 1 subcategory, small units (less than 10 mmBtu/hr), and limited use units (less than 876 operating hours per year), qualify for work pr actices under Section 112(h) of the CAA and work practices for all pollutants cons isting of an annual, biennial, or every 5 year tune-up replace the traditional compliance demons trations associated with numeric emission limits. Other units qualify for a work practice for di oxin/furan which consists of an annual tuneup, but are also subject to numerical emission limits for four pollutants. There were late changes to the Hg, HCl, PM, and CO MACT floor emission limits for several subcategories. It was determined that the non-continental liquid un its were not initially properly factored into the calcula tion of the Hg limit for liquid units, resulting in a revised Hg limit for existing liquid-fired boilers. Additionall y, it was determined that five boilers in the liquid subcategory and one boiler in the pulve rized coal subcategory were permanently shutdown. After removing the units from the MA CT floor rankings, only the HCl emission limit
for solid-fired boilers was affected. The revised limit was still more stringent than the calculated new source emission limit for the same subcategor y, and thus the revised HCl limit was used for both existing and new solid-fired boilers. Although new unit project ions are based on the counts of existing sources in each s ubcategory, the new unit projections were not changed based on the shutdown units. Further, minimum CO MACT fl oor emission levels were investigated in response to several stakeholder comments. For several subcate gories, preliminary adjustments were made to the CO emission limit based on pa ired formaldehyde tests and these adjusted
numbers were used in the estimation of cost and emission impacts. A summary of the development of minimum CO standards is provided in section 4.0 of the memorandum discussing the methods and procedures used to develop MACT floor emission limits. 1 A revision to the representative detection level (RDL) for PM also affected several of the PM emission
limits.5 Appendices to this memorandum provide summa ries of the cost, em ission, and secondary impacts calculated both prior to and following the revisions to the aforementioned emission limits. The tabular summaries in the body of th is memorandum, as well as the cost, emission, and secondary impacts sections of the preamble to the amended final rule, reflect the impacts analyses conducted following the revision of the limit. The appendices correlating to these analyses are labeled as the “Revised Recomme nded Option”. However, the results of the analyses conducted prior to the revision of the limits ar e reflected in the RIA update
memorandum and the economic and health benefits section of the preamble to the amended final rule. The appendices correlating to these an alyses are labeled as the “Old Recommended Option”. Table 3-1 provides a comparison of the old and revised MACT floor emission limitations discussed in this section. Further, the “Revised Recommended Option” is based on an inventory of 14,136 units and 1,700 facilities to acc ount for the six shutdown boilers while the “Old Recommended Option” is based on an i nventory of 14,142 units an d 1,702 facilities.

Table 3-1: Comparison of Emission Limits Used in Various Impacts Analyses

Pollutant Subcategory Emission Limit Used for RIA Memo and Economic and Health

Benefits Sections of Preamble (“Old Recommended Option”) Emission Limit Used in Cost, Emission, and

Secondary Impacts Sections of Preamble (“Revised Recommended Option”) Mercury (Hg) Existing – Liquid 4.9E-07 lb/MMBtu 2.0E-06 lb/MMBtu Hydrogen Chloride (HCl) Existing – Solid 0.021 lb/MMBtu 0.022 lb/MMBtu Hydrogen Chloride (HCl) New – Solid 0.021 lb/MMBtu 0.022 lb/MMBtu Carbon Monoxide (CO) Existing – Coal FB 49 ppm @ 3% O 2 240 ppm @ 3% O 2 Carbon Monoxide (CO) Existing – Coal Stoker/Other 160 ppm @ 3% O 2 350 ppm @ 3% O 2 Carbon Monoxide (CO) Existing – Heavy Liquid 12 ppm @ 3% O 2 25 ppm @ 3% O 2 Carbon Monoxide (CO) Existing – Light Liquid 6 ppm @ 3% O 2 78 ppm @ 3% O 2 Carbon Monoxide (CO) New – Coal FB 25 ppm @ 3% O 2 240 ppm @ 3% O 2 Carbon Monoxide (CO) New – Coal Stoker/Other 19 ppm @ 3% O 2 350 ppm @ 3% O 2 Carbon Monoxide (CO) Existing – Heavy Liquid 12 ppm @ 3% O 2 25 ppm @ 3% O 2 Carbon Monoxide (CO) Existing – Light Liquid 3 ppm @ 3% O 2 78 ppm @ 3% O 2 Particulate Matter (PM) Existing – Coal 3.9E-02 lb/MMBtu 4.0E-02 lb/MMBtu Particulate Matter (PM) Existing – Biomass Ducth Oven/Pile Burner 1.8E-02 lb/MMBtu 2.8E-02 lb/MMBtu6 Particulate Matter (PM) Existing – Stoker/Sloped Grate/Other Designed to Burn Wet Biomass 3.4E-02 lb/MMBtu 3.7E-02 lb/MMBtu

Particulate Matter (PM) New – Coal 1.7E-03 lb/MMBtu 1.1E-03 lb/MMBtu Particulate Matter (PM) New – Biomass Ducth Oven/Pile Burner 3.1E-03 lb/MMBtu 3.2E-03 lb/MMBtu Particulate Matter (PM) New – Biomass FB 1.0E-02 lb/MMBtu 9.8E-03 lb/MMBtu Particulate Matter (PM) New – Biomass Suspension Burner 3.0E-02 lb/MMBtu 5.1E-02 lb/MMBtu

Particulate Matter (PM) Existing – Stoker/Sloped Grate/Other Designed to Burn Wet Biomass 3.0E-02 lb/MMBtu 3.7E-02 lb/MMBtu

The preliminary adjustments to the minimu m CO emission limits shown in Table 3-1 were further refined after the impacts estimates were calculated. Thus, for certain subcategories, the CO emission limit used to calculate the imp acts differ from the emission limit in the final amended rule. Table 3-2 provi des a comparison of the CO em ission limits presented in the recommended option for the impacts estimates a nd the limits in the final amended rule.
The final amended rule CO emission limits fo r existing coal-fired fluidized bed, existing coal-fired stoker, and new coal-f ired stoker units became more stri ngent than the CO limits used in the impacts analysis. Therefore, for these unit s, the cost and emission impacts presented in the recommended option are underestimated. For the re maining affected subcategories, the cost and emission impacts are conservative overestimates.

Table 3-2: Comparison of CO Emission Limits Used in Impacts Analysis and Final Rule

Subcategory CO Emission Limit Used in Cost, Emission, and Secondary Impacts Sections of Preamble (“Revised Recommended Option”) (ppm @ 3% O2) CO Emission Limit in Final Rule (ppm @ 3% O2)

Existing – Coal FB 240 130 Existing – Coal PC 62 130 Existing – Coal Stoker/Other 350 160

Existing – Heavy Liquid 25 130 Existing – Light Liquid 78 130 Existing – Non-Continental Liquid 32 130 Existing – Process Gas 5 130 New – Coal Stoker/Other 350 1307 New – Heavy Liquid 25 130 New – Light Liquid 78 130 New – Process Gas 5 130

A final late change to the analysis concerned baseline em issions for total hydrocarbons (THC). The estimation of THC baselines were revised based on revise d methodology to account for instrumental measurement detection capabilitie s for instrumental emissions testing methods. The methods and procedures used to develop baseline emission f actors are provided in another
memorandum. 6 The methods and procedures used to account for instrumental measurement
detection limitations for instrumental emission te sting methods are also presented in another
memorandum. 23 The “Revised Recommended Option” appendices reflect the changes in the THC baseline emissions (which also had an im pact on the estimated reductions), whereas the “Old Recommended Option” appendices do not.


### Control Cost Impacts
Mercury Control

 Fabric filters — a new fabric filter installati on was expected to achieve most of the Hg emission limits in the proposal. Where baselin e Hg emissions were found to be greater than the MACT floor, the cost of a fabric fi lter was estimated for an individual boiler or process heater, unless the unit already had a fabric filter installed. A new fabric filter was projected to be installed at 325 existing boilers and process h eaters. This does not include
the fabric filters installed in combination with dry injection to achieve HCl controls that
are discussed below.

 Activated carbon injection (AC I) — in the case of a unit with a fabric filter emitting Hg above the MACT floor emission limit, the cost s to install activated carbon injection (ACI) technology on the boiler were estimate d. ACI equipment was projected to be installed for 38 existing boile rs and process heaters.

 Wet scrubbers—one of the technolo gies selected for the cost analysis to reduce emissions of hydrogen chloride (HCl)—are also capable of achieving modest reductions in Hg. Literature suggests that these scrubbers can achieve a 10 percent reduction in Hg
emissions. If a scrubber was be ing installed for HCl, and baseline Hg emissions were within 10 percent of the MACT floor, the wet scrubber was expected to achieve this level
of emission reduction without installing a fabric filter.8  Slurry additive and halogen addition systems – if a boiler already has a selective catalytic reduction (SCR) and scrubber installed, additional Hg removal is possible. Hg reductions
of 80% are achieved due to the co-benefit of the SCR and scrubber if these additive systems are installed in certain situations. If baseline Hg emissions were between 10 and 80 percent of the MACT floor and a SCR and scrubber were both installed on the boiler, the cost for additive systems was esti mated. No boilers met these criteria.

Particulate Matter and Metallic HAP Control

 When baseline particulate (PM) and TS M8 emissions both exceeded the respective emission limits for those pollutants, the cost of an ESP was estimated, unless a fabric filter had already been included in the cost analysis for Hg reduction. ESP technology was projected to be installed at 155 existing boilers and process heaters.

 Wet scrubbers are also capable of achiev ing a modest reduction in PM and TSM. Literature suggests that these scrubbers can achieve an 85-percent reduction in PM
emissions. If a scrubber was be ing installed for HCl, and baseline PM emissions were within 85 percent of the MACT floor for PM , the wet scrubber was expected to achieve
this level of emission reducti on without installing an ESP.

Hydrogen Chloride Control

 When HCl baseline emissions were greater than the MACT floor, the cost of adding a packed bed scrubber, increasi ng the sorbent rate on an exis ting scrubber, or installing a
combination fabric filter a nd dry injection (DIFF) system was estimated. Scrubbers and
DIFF were estimated to be able to attain similar levels of hydrogen chloride control. Based on input received duri ng the public comment period, many wood product facilities are not permitted to discharge wastewater, thereby re stricting the type of controls needed to reduce emissions of HCl and other acid gase s. For this analysis, facilities in NAICS codes 321 (wood products manufacturing) and 3 22 (paper manufacturing) were assumed
to not be able to install a packed scrubber due to the regul ation of wastewater discharge from those industries. For the remaining un its requiring control de vice installation for hydrogen chloride reduction, the less expensive control option between a packed scrubber
and DIFF was assumed to be the control installe d. If the boiler already reported having a9 scrubber installed, a DIFF was not the sele cted control technology, and the baseline emissions still exceeded the floor, the incremen tal required HCl removal efficiency was
calculated and the then the cost to increase the sorb ent injection rate in the scrubber was estimated in the cost analysis. Wet scrubbers were estimated to be necessary to control HCl emissions at 678 existing boilers and pr ocess heaters. DIFF was identified to be necessary to control HCl emissions at 104 existing boilers an d process heaters. Incremental sorbent injection was identified to be necessary to control HCl emissions at 8 existing boilers and process heaters.

 Since the fabric filter portion of a DIFF will achieve reductions in both HCl and Hg, the analysis first checked for whether a DIFF was necessary to achieve HCl reductions, and if so, this DIFF was assumed to achieve the MACT floor limits for both HCl and Hg. If a DIFF was not needed for HCl control, but a fabric filter was needed for mercury control,
the costs of a fabric filter were estimated.

Carbon Monoxide and Organic HAP Control

 Organic HAP and carbon monoxide can be controlled by either improving the combustion efficiency of the unit, or instal ling an oxidation catalyst on the exhaust of a combustion unit. The control strategy necessa ry to meet the MACT floor emission limit will vary depending on the magnitude between the baseline emissions and the CO MACT floor. A step function was used to delineat e what type of control strategy should be analyzed in the cost impacts analysis:

o A boiler tune-up was estimated in the co st impacts analysis if the unit’s CO
baseline emissions were less than or equal to 1.5 times the applicable numeric CO emission limit. We estimated that tune-ups could achieve a percent reduction from
the unit’s baseline emissions. To determin e an appropriate threshold level that tune-ups could achieve the limits to de monstrate annual compliance with the CO stack test in this proposal, we looked at best performing units for CO that reported paired CO CEMS emissions and boiler load data. Details of this analysis are discussed in a previous ve rsion of this memorandum. 21 We settled on a modest threshold condition of assuming that a tune-up would meet the limit if the floor
value was within 150% of the baseline em issions. Based on data provided by best10 performing units, it is reasonable and a c onservative estimate that this level of
control can be achieved wit hout capital installations.

o If the unit’s baseline CO emissions were greater than 1.5 times but less than or equal to 2.5 times the app licable numeric CO emissi on limit, the cost of a replacement low-NOx burner was estimated to achieve the MACT floor emission limits. Since stokers, fuel cells, or fluidized bed units do not have replaceable burners, a linkageless boiler management system (LBMS) was the technology
estimated to achieve the MACT floor when baseline CO emissions exceeded the floor in lieu of replacement low-NOx burne rs. A threshold of 2.5 is still less than the reported findings from best perfor ming boilers in the coal and biomass subcategories that demonstrate wide fluc tuations in CO emissions without any added CO controls, as discussed above. However, since we do not have similar data available for the liquid and process gas subcategories, we opted to select a conservatively low threshold to address some concerns received from public comments about underestimating th e costs of CO control.

o Finally, if the baseline CO emissions we re greater than 2.5 times the applicable CO emission limit, the cost impacts an alysis estimated that a CO oxidation catalyst would be required to meet MACT floor limits.

Work Practice Costs

 All boilers and process heater s are subject to a work pr actice standard. Large units (greater than or equal to 10 mmBtu per hour) are required to conduct an annual tune-up. All liquid-fired units that were identified as capable to switching to natural gas consumption are large units, and are thus subj ect to an annual tune-up. All small boilers (less than 10 mmBtu per hour) combusting any fuel, and limited use boilers (less than 876 hours of operation per year) are required to conduct a biennial boiler tune-up. Very small units designed to burn gaseous fuels or light liquid fuels (less than 5 mmBtu per hour) are required to conduct a tune-up every 5 years. The cost to conduct an annual tune-up is based on the cost estimate provide d in a report by the Industrial Extension
Service 16 . This report indicated that the initial set-up fo r boiler tune-up was $3,000 to $7,000 per boiler; thereafter, annual tuning costs $1,000 per bo iler. An average of $5,000 per boiler in initial set-up co sts was annualized over 5 years at a 7 percent rate and added11 to the subsequent year tune-up costs. Alt hough the proposal allows a biennial or every 5- year tune-up in some circumstances the cost impacts analysis show the tune-up costs on an annual basis since these repr esent the first year costs when the rule is implemented.
The resultant annualized cost for an annua l tune-up is $2,875 per boiler, as shown in Equation 1.

Annual Tune-up Cost ($2008) = {[C $2004 * (X 2008 / X 2004 ) * i * (1+ i ) y ] / [(1+ i ) y – 1)]} + [Z $2004 * (X 2008 / X 2004 )] = $2,875 (Equation 1) Where: C $2004 = Average set-up cost, $5,000 (from 2004) X 2008 = 2008 cost index, 575.4 X 2004 = 2004 cost index, 442.2 i = interest rate, 7% y = length of annuity, 5 years Z $2004 = annual tuning cost, $1,000 (from 2004)

 All existing facilities ar e expected to conduct a one-time energy audit. An annual cost of $854 per audit was used for commercial or institutional facilitie s and $18,292 per audit
was used for industrial faciliti es, and these costs are the same as the estimates included in the March 2011 final rule and the December 2011 proposed reconsideration of the rule. 2 For the cost impacts analysis, 1,702 facilities are expected to c onduct an audit under the “Old Recommended Option” discussed in S ection 3.1, 204 facilities are commercial or institutional and 1,498 facilities are industrial. There are 1,700 facilities expected to
conduct an audit under the “Rev ised Recommended Option” discussed in Section 3.1.



### Testing and Monitoring Cost Impacts
Testing and monitoring requirements varied depending on the equipment installed on the unit to control emissions, the de sign capacity of the unit, and th e fuel category the unit was assigned to.

Testing Costs All boilers and process heaters designed to burn solid and gaseous fuels were expected to conduct an annual compliance test for PM, HCl, H g, and CO. The cost to conduct stack tests for12 these four pollutants was estimated to be $28,000 pe r year for boilers combusting solid or other gaseous fuels. Based on comments received abou t testing under worst-case conditions, many solid fuel boilers which fire multiple fuel streams or types of fuel are expected to conduct repeated testing for mercury and HCl at a cost of $18,000 per year. Boilers and process heaters 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 analyses received from a fuel supplier, for chlorine and Hg. Conducting stack tests for PM and CO was estimated to be $11,000 per year, and fuel analysis for chlorine and Hg was estimated at $400 per month. Although other fuels are eligible to comply with the proposal through fuel analysis in lieu of stack testing, this cost estimate conservatively assumed that only units designed to fire liquid fuels would use this compliance alternative. Th e methods and data sources used to estimate testing and monitoring costs are discussed in other memoranda. 2 The proposal includes a provision for gaseous fuels other than natural gas and refinery gas to demonstrate that they meet the specifications outlined in the rule for mercury. We
reviewed the database for facil ities that had boilers with heat input capacities of at least 10 mmBtu/hr that are firing gaseous fuels other than natural gas or refinery gas, and we estimated
that these 385 combustion units would need to conduct monthly fuel anal ysis, at a cost of $200 per month, or $2,400 per year. The methods and costs associated with demons trating that the gas meets the specifications for mercury are discussed in another memorandum. 2 In the March 2011 final rule cost estimates, we had estimated gas specification costs at one per month, per facility. However, because certain gas streams are not used in all combustion units, and different units may combust different blends of gases, we increas ed the cost to one spec ification per month, per
unit in order to be conservative.

Monitoring Costs Various monitor configurations were inst alled based on the size of the unit and the pollution control devices expected to be installe d to achieve the MACT floor emission limits. For units expected to install pack ed bed wet scrubbers, an annualized cost of $5,600 for a scrubber parametric monitor was included in the cost analysis. If a unit wa s expected to install DIFF, the cost to monitor sorbent injecti on rate and add a bag leak detec tion monitor was included in the analysis, based on the unit’s hours of operation. For units expected to insta ll a fabric filter, an13 annualized cost of $9,700 for a bag l eak detection monitor was include d in the cost analysis. If a unit was expected to install ACI, the cost to m onitor the carbon injection rate was included in the analysis, based on the unit’s hours of operation. For units that did not inst all a PM CPMS and did
not install a scrubber to meet HCl limits, an annualized cost of $14,660 for an opacity monitor was included in the cost analysis. The cost anal ysis includes the cost of a PM CPMS for units with an average heat input rate of 250 mmBtu/hr or more from coal, fossil solid or liquid fuel. Oxygen monitors were required for all boilers an d process heaters subject to CO emission limits; these monitors were assumed to be extractive ty pe monitors with an annualized cost of $1,436. Although several units are expected to have O2 m onitors installed on the units for other reasons, such as to monitor combustion efficiency, since the number of units with monitors installed and calibrated is unknown, this analysis a pplies the cost of an O2 monito r to all units subject to a CO emission limit. No PM CPMS or opacity monitors were assumed for boile rs and process heaters designed to burn gaseous fuels.


### Fuel Savings Impacts This cost analysis includes an estimated energy savings of one percent for every existing unit that is expected to instal l controls to improve combustion, or conduct an annual tune-up or energy audit. Further, documents from the Sustai nable Energy Authority of Ireland have charted efficiency gains as a function of boiler fuel t ype and time elapsed sin ce the previous tune-up. 8 Many best practices are consider ed pollution prevention because they reduce the amount of fuel combusted which results in a corresponding reduc tion in emissions from the fuel combustion. Further boiler tune-ups have b een shown to improve the efficien cy of a boiler between 1 and 5 percent, depending on the age of the unit and the time lapse since the previous tune-up 10-15, 17-19

. Other combustion controls such as upgrading bu rners and installation of an LBMS are also expected to improve the efficiency of the unit, th us reducing fuel consumption. This cost analysis assumes an annual fuel savings of 1 percent. Th e energy savings are estimated using Equation 2:

Annual Fuel Savings (mmBtu/yr) = DC * CF * Op hours * EG (Equation 2) Where: DC = unit design capacity (mmBtu/hr) CF = capacity factor, 90% of design capacity Op hours = annual operating hours reported in 2008 survey (hours/year) EG = Efficiency gain, estimated to be 1%14 After the fuel savings for each boiler and pro cess heater was calculated, the industrial and commercial prices for coal, #2 dist illate fuel oil, #6 residual fu el oil, and natural gas were
obtained from both the 2008 and 2012 EIA in order to get a potential ra nge of fuel savings. 5, 22 This is a change since the propos ed reconsideration of the rule, for which the cost analysis utilized fuel prices from the 2008 EIA only. 5 The EIA data reported fuel prices as $/ton for coal, $/thousand cubic feet for natural gas, and cents per gallon for fuel oil. A comparison of the 2008 and 2012 EIA fuel prices is provided in Table 3-3 below. The 2008 EIA data are presented in year 2008$ while the data for th e 2012 EIA are presented in 2012$.

Table 3-3: Comparison of Fuel Prices from 2008 and 2012 EIA

Fuel Type Industrial Costs ($/MMBtu) Commercial/Institutional Costs ($/MMBtu) 2008 EIA 2012 EIA 2008 EIA 2012 EIA
Coal 2.43 3.06 2.43 3.06
Natural Gas 9.32 3.06 11.66 9.09
Distillate Oil 23.23 18.7 22.66 18.69
Residual Oil 12.96 14.06 12.96 12.03

The revised EIA 2012 data highli ght the trends towards subs tantially lower natural gas fuel prices since previous iterati ons of this impacts analysis. This new data results in lower fuel savings estimates. The higher heating values were obtained from Table 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 NAICS code reported by each facility and the fuel category as signed to each combustion unit, the appropriate fuel price was multiplied by the calculated fuel savings. Table 3-4 below shows the distribution of reported NAICS codes considered as industrial versus commercial in te rms of fuel pricing.

Table 3-4: Summary of NAICS Code Distribution by Sector Sector NAICS Codes Industrial 221, 311, 312, 313, 314, 316, 321, 322, 323, 324, 325, 326, 327, 331, 332, 333, 334, 335, 336, 337, & 339 Commercial 111, 113, 115, 211, 212, 423, 424, 441, 481, 482, 486, 488, 493, 531, 541, 561, 562, 611, 622, 623, 811, 813, 921, & 92815 This cost analysis only estimates the fuel sa vings from units in the coal, liquid and natural gas fuel categories. A fuel savings range was not estimated for units in the biomass or other process gas fuel categories since the price of these fuels is vari able, and often biomass is an onsite industrial byproduct inst ead of a purchased fuel.


### Fuel Switching Impacts No costs were estimated for liquid units as sumed to switch to natural gas combustion.
The units identified as candidates for fuel switc hing reported the ability to combust both liquid fuels and natural gas, and thus unit’s fuel ha ndling and firing equipment were not assumed to need modification. The only changes required to these units would be to cease the purchase of liquid fuels and replace it with the purchase of natural gas. Additionally, as shown in the 2008 and 2012 EIA, natural gas prices are historically lower than both dist illate and residual oil prices on a dollar per unit of heat input basis. 5, 22


### 3.2 Alternative Option The alternative option includes control devi ce and testing/monitoring cost estimation logic identical to the Recomm ended Option outlined above, excep t that the alternative TSM8 emission limit option is removed from consider ation for liquid units, and no liquid units are assumed to switch to natural ga s combustion in lieu of demons trating compliance with emission limits. All other aspects of the options are identica l. As a result of this modified option and its computed MACT floors, the number of units estimated to install controls to meet the limits were adjusted as follows:

 A new fabric filter was estimated to be in stalled at 555 existing boilers and process heaters to control Hg emissions. This does not include the fabric filters installed in combination with dry injection to achieve HCl co ntrol. A new fabric filter is required to
be installed on an additional 230 boilers a nd process heaters under this option when compared to the recommended option.

 ACI equipment was estimated to be installed at 40 existing boilers and process heaters for controlling Hg. ACI equipment is required to be installed on an additional two boilers and process heaters compared to the recommended option.

 ESP technology was estimated to be installed at 155 existing boilers and process heaters to control PM. ESP technology is required to be installed on the same number of boilers16 and process heaters compared to the recommended option.

 Wet scrubbers were estimated to be necessa ry to control HCl emissions at 902 existing boilers and process heaters. A new wet sc rubber is required to be installed on an additional 224 boilers and process heaters under this option when compared to the recommended option.

 DIFF was identified to be necessary to cont rol HCl emissions at 129 existing boilers and process heaters. DIFF is estimated to be in stalled on an additional 25 boilers and process heaters under this option when comp ared to the recommended option.

 Incremental sorbent injection was identified to be necessary to control HCl emissions at 12 existing boilers and process heaters. Increm ental sorbent injection is estimated to be
installed on the same number of boilers and process heaters under this option compared to the recommended option.


### 3.3 New Unit Options The recommended option for new units follows similar logic for estimating control costs as the recommended option for existing units outl ined above with two exceptions: (1) Since new boilers are not subject to energy assessment re quirements under the proposed rule, no costs for these audits have been included; and (2) since these boilers are new, fuel savings from these boilers was not estimated since the savings are e xpected to be minimal given that a new boiler will operating optimally in the first year they are installed regardless of any of the requirements of this rule. The new unit analysis also projec ts new gaseous fuels, but based on the EIA data used for the new unit projections all of these ne w boilers are estimated to be natural gas so no cost for a gas specification is included in the new unit analysis. Table 3-5 summarizes the costs for the recommended option for new sources. The alternative option for new units follows similar logic as the alternative option for existing units. Similar to the assumptions noted earlier in Section 3.3, estimated fuel savings and costs for energy audits were not applied to ne w units. However, since no new liquid units are projected, the results of both the promulgated and alternative options are the same for both options.17 

### 3.4 Summary of Cost Impacts
The recommended option is the promulgated option for existing and new boilers and process heaters. Tables 3-5 and 3-6 summarize th e costs of the promulgated for new and existing units. Appendix A of this memorandum provides a detailed summary of the promulgated option for existing and new sources cost s according to unit size, subcat egory, and individual control device costs. Note that Appendix A-1a represen ts the “Old Recommended Option” that was used in the RIA, while Appendix A-1b represents the “Revised Recommended Option” after accounting for later data submittals and edits to the analysis.

Table 3-5: Summary of Costs of Proposed Promulgated Options Costs shown in $10 6 (2008) with capital recovery estimated at 7%

Type of Unit Option Number of Units TAC Minimum TAC considering fuel savings Maximum TAC considering fuel savings Testing & Monitoring TAC Control TAC Control TCI New Recommended 1,844 $104 N/A $104 $5.6 $98.5 $393 Existing Recommended (Old) 14,142 $1,702 $1,355 $1, 558 $89.4 $1,612 $5,028
Existing Recommended (Revised) 14,136 $1,661 $1,247 $1, 489 $88.9 $1,544 $4,877

Table 3-6: Summary of Total Annual Costs by Contro l Type for Existing Units under Promulgated Option Costs shown in $10 6 (2008) with capital recovery estimated at 7%

Option Number of Boilers Fabric Filter ESP Wet Scrubber DIFF Increased Caustic

Rate Combustion Controls

and Oxidation Catalysts Activated Carbon Injection Work Practices(Tuneup) Energy Audit Recommended (Old) 14,142 $327 $54.6 $667 $337 $2 $168 $15.8 $40.7 $27.6
Recommended (Revised) 14,136 $355 $54.6 $643 $337 $2 $98.9 $13.5 $40.6 $27.5



## 4.0 METHODOLOGY FOR ESTIMATING EMISSION REDUCTIONS

This section discusses the methodology used to estimate emission reductions from boilers and process heaters at both exis ting and new facilities and it pr esents a summary of the results for the recommended regulatory options.

The emission reductions analysis for existi ng combustion units was done for each boiler and process heater in the major source inventory. There are a to tal of 14,142 boilers and process18 heaters at major sources that reported data in the 2008 questionnair e (ICR No. 2286.01) or subsequent requests for or s ubmissions of data (or 14,136 units in the revised inventory discussed in Section 3.1 of this memoranda). E ach combustion unit was assigned a unit-specific or average baseline emission fact or, depending on the availability of emission data reported for
the unit. A detailed discussion of the procedures and results of th e baseline emissions analysis is presented in another memorandum. 6



### 4.1 Emission Reductions for Recommended Option
Emission reductions followed three steps: Firs t, emission reductions were estimated for units subject to emission limits for PM (or TSM8 ), HCl, Hg, and CO. These emission reductions were calculated on a ton per year basis by subtra cting the baseline emi ssions assigned to each unit from the emission limits corresponding to each unit’s subcategory. A detailed discussion of the procedures and results of the MACT floor analysis is presented in another memorandum. 1 A percent reduction was calculated for CO. It was assumed that each combustion unit would achieve an identical percent reduction from baseline emissions for THC and VOC as was achieved for CO. A percent reduction was also calculated for HCl. It was assumed that each combustion unit would achieve an identical percen t reduction from baseline emissions for HF as
was achieved for HCl. A combustion unit is a ssumed to install a scrubber or DIFF for HCl control if it is not currently meeting the HCl floor limit, and if it doesn’t already have a scrubber installed. For units required to install a scrubber or DIFF, it wa s assumed that the control will
achieve a reduction from baseline for SO2 equivalent to the reduction in HCl. This analysis assumed that each combustion unit would comply with either the PM or TSM8 numeric emission limit that required the lowest percent reduction from the respective baseline emissions. The minimum percent reducti on required for PM or TSM8 was chosen, and
baselines for both PM and TSM8 were reduced by that same percentage. The reductions in individual non-Hg metallic HAP (antimony, arsenic, berylliu m, cadmium, chromium, cobalt, lead, manganese, nickel, and sele nium) were based on the same po llutant removal efficiencies
estimated for PM or TSM8 above. The reduction s for each of the individual 10 metallic HAP were summed in order to get reductions fo r TSM10. PM2.5 emissions were assumed to be a
fraction of total filterable PM emissions based on fuel and control device configuration installed19 on the unit. The methods used to derive the c ontribution of PM2.5 to overall filterable PM are presented in other memoranda. 6 To calculate emission reductions for PM2.5, the emission reductions for PM were multiplied by the applicable PM2.5 fraction. Although baseline emissions of dioxin/furans are shown in Appendix B, this estimated
baseline is based on data that include detec tion limit-based values, which overestimates the amount of dioxin/furans by an unknown amount since most of the data were reported to be measured below detection levels and the vast majo rity of the data that were above the detection limit were still lower than the amount that the EPA has determined can be accurately measured. No reductions were estimated for dioxins/furans because any estimates would be highly
uncertain.
To convert emission reductions from an emissi on rate on a heat input basis to an annual emission rate, Equation 3 was used:

Annual Emission Rate (tpy) = ER HI * 0.0005 * Op hours (Equation 3)

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)

To convert emission reductions from a concen tration basis to an annual emission rate, Equations 4 and 5 were used:

Annual Emission Rate (tpy) = ER C * 0.000001 * Q S * 60 * Op hours * MW * 0.0026 * 0.0005 * (20.946 – O 2 ) / (20.946 – Std O 2 ) (Equation 4)

Where: ER C = emission concentration (ppm @ 3% O 2 ) 0.000001 = conversion factor, ppm to parts Q S = exhaust flowrate (dscfm) 60 = conversion factor, minutes to hours Op hours = annual operating hours reported in 2008 survey (hours/year) MW = molecular weight of po llutant, in lb per lb-mole 0.0026 = conversion factor, lb-mole per dry standard cubic foot of gas 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 percent oxygen in standard ized emission concentration.20 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 5)

Where: ER C = emission concentration (ng/dscm @ 7% O 2 ) 0.0283 = conversion factor, dry standard cubic meter per dry std. cubic foot Q S = exhaust flowrate (dscfm) 60 = conversion factor, minutes per hour 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 emi ssion concentration for promulgated rule.

Converting concentrations to an annual em ission 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. 2 All conversions required the annual operating hours for each combustion unit re ported in the 2008 survey or in subsequent data submittals. If no operating hours were re ported, the unit was assu med to operate for 8,400 hours per year (two weeks of downtime). The second step was to estimate emission redu ctions based on a one percent gain in efficiency expected from the initial tune-up work practice standard required for all units. Efficiency gains reduce fuel use, and in tur n, emissions of hazardous air pollutants. A one percent reduction in all types of emissions wa s estimated by multiplying the baseline emissions for each unit by a factor of 0.01. All units, regardless of size or fuel, must conduct an initial tuneup. A one percent gain in efficiency is thus expe cted for all types of un its based on this tune-up requirement. The third and final step consisted of taki ng the maximum emission reduction value from the two steps outlined above. Even if a unit’s reported baseline emissions were below its respective emission limits, the unit was still exp ected to achieve nominal emission reductions of one percent through combustion efficiency and fu el savings resulting from the tune-up work practice. However, if additional emission reductions were needed in order to meet the emission limits the reductions resulting from improved efficien cy were expected to be factored into the overall engineering strategy and control devi ce design to achieve each emission limit. This21 approach ensures that every uni t in the inventory achieves at least a 1 percent reduction in
emissions.

Reductions for Liquid Units Switch ing to Natural Gas Combustion For the continental liquid units identified to have the capability to switch to natural gas combustion, emission reductions were calculated by subtracting the current liquid baseline emissions from the expected emissions when firi ng natural gas. For the fuel-based pollutants (i.e., Hg, PM, HCl, HF, SO2, PM2.5, and metallic HAP) it was assumed that the same level of control currently in use for the liquid unit would be retained for the natural gas combustion. As an example, if a liquid unit with a fabric filter was expected to convert to natural gas combustion, emission reductions were calculated by subtra cting the liquid baseline emissions from the expected natural gas emissions for a fabric filter level of control for the respective pollutant. For the organic combustor-based pollutants (i.e., CO, THC, and VOC) a similar comparison was done, except using the reported baseline presence or absence of low NOx burners in lieu of the level of control. As an example, if a liquid unit with low NOx burners was expected to convert to natural gas combustion, emission re ductions were calculated by s ubtracting the liquid baseline emissions from the expected natural gas em issions for units with low NOx burners for the respective pollutant. Based on the available data, emission fact ors for CO, THC, VOC, and HF from natural gas combustion were higher than the correspond ing liquid baseline emissions, and emissions for these pollutants increased after assuming that the 258 large, rou tine-use liquid uni ts would switch to natural gas combustion. Natural gas emissions for the remaining pollutants were lower than the corresponding liquid baseline emissions, a nd the natural gas switch provided additional emissions reductions. Table 4-1 compares the em ission reductions expected from liquid units both with and without the assump tion that the 258 units would sw itch to natural gas combustion.

Table 4-1: Comparison of Emission Reductions (tons per year) from Liquid Units With and Without Units Switching to Natural Gas Combustion Subcategory Hg PM HCl CO THC VOC HF SO2 PM2.5 Metals

No Liquid

Units Switching to Natural Gas 1.13 5,562 2,155 12,448 3,404 1,954 71 89,152 2,346 1,63322 258 Liquid Units Switching to Natural Gas 1.14 9,522 2,160 8,632 2,940 1,688 (538) 97,520 4,800 2,325

Incremental

Emissions Reductions 0.01 3,960 5 (3,816) (464) (266) (609) 8,368 2,454 692

Emission Reduction Range for Mercury Given that some survey res pondents reported non-detect fracti ons of mercury differently than others, a second method of estimating emissi on reductions for mercury was used in order to establish a range of possible reductions for me rcury. For each subcategory, the average (mean) emissions of the top performing units were calculated and compared to three times the representative detection level (3x RDL) for the same subcat egory; the higher value of the two was determined to be the lower bound of emissions for each subcategory. Details and methods used to compute the mean of the top performi ng units and each 3x RDL value can be found in
other memoranda. 4,20 Table 4-2 shows the computed emission limits, mean of the top performers, and the 3x RDL value for each subcategory. For th e solid and process ga s subcategories, the average emissions or 3x RDL value was lower th an the actual numeri c emission limit. For liquids, the 3x RDL was the basis of the emissi on limit, and thus the values are equal.

Table 4-2: Comparison of Hg Emission Limits , Top Performer Averages (Mean), and 3x RDL by Subcategory

Fuel Subcategory Emission Limit (lb/MMBtu) Mean Emissions of Top Performers (lb/MMBtu) 3x RDL (lb/MMBtu)

Solid 5.7E-06 4.1E-07 7.2E-07
Liquid 4.7E-07 3.7E-07 4.7E-07

Process Gas 7.9E-06 6.2E-06 4.4E-07

As an added constraint to the lower bound on estimated emission levels that could reasonably be achieved, it was assumed that units expected to install air pollution control devices for compliance with a numeric emission limit for Hg, or units expected to install control devices to meet PM (or TSM), or HCl limits that have a co-benefit of reducing mercury, would achieve a minimum amount of reductions based on the type of control installed. For units installing a fabric23 filter, ACI, or DIFF for Hg or HCl control, the representative control efficiency was assumed to be 70 percent. For units installing an ESP fo r PM, it was assumed that the maximum control efficiency for Hg removal would be 25 percent. For units installing a wet scrubber, or units with a pre-existing scrubber that are required to incrementally in crease the sorbent injection rate, it was assumed that the maximum control efficiency for Hg removal would be 10 percent. These selected percentages are within the ranges of pollutant removal e fficiencies discussed in another
memorandum. 6 Emission reductions were then calculated by de termining the percent reduction needed to
reduce baseline emissions to th e level of the average emissions of the top performers (or 3x RDL, whichever was higher). This value was comp ared with the estimated removal efficiency of the control device expected to be installed on the unit. The baseline emissions were then multiplied by the minimum of these two percenta ges. However, if the percent reduction required to comply with the actual numeric emission limit was higher than this minimum value, then the percent reduction needed was defaulted to the per centage needed to meet the floor since all units will be required to meet their respective numer ic emission limit. This alternative method for estimating mercury emission reductions was used to estimate the upper end of the range for mercury reductions.


### 4.2 Emission Reductions for Alternative Option

The same calculations discussed for estima ting emission reductions for the recommended option were applied to all units except that th e alternative numeric TSM8 emission limits for liquid units were removed, and that no liquid units were assu med to switch to natural gas
combustion. It was assumed that each combusti on unit would achieve an identical percent
reduction in TSM emissions as was achieved for compliance with the numeric PM emission limits. The remainder of the above methodology and calculations for the recommended option were performed for all other pollutants.



### 4.3 Emission Reductions from New Boilers and Process Heaters

Based on industrial and commercial fuel cons umption projections from the Department of Energy’s 2011 Annual Energy Outlook, there are 1,844 new boilers and process heaters24 expected to come on-line by 2015. 7 A discussion of the methodology used to project new boilers and process heaters is disc ussed in another memorandum. 3
The New Source Performance Standards for Industrial, Commercial and Institutional Boilers (40 CFR part 60, subparts Db, Dc) (NSPS) , was reviewed to identify the expected baseline level of control for projected new units. It was determined that new boilers and process heaters larger than 30 mmBtu/hr and combusting biomass would install an ESP. This technology selection is based on the analysis used to es tablish the PM NSPS limit for biomass boilers. New coal units larger than 75 mmBtu/h r would have a fabric filter and wet scrubber installed, while
new coal units between 30 and 75 mmBtu/hr would only have a fabric filt er installed and would
meet the SO 2 limits in the NSPS by using coals with low sulfur content. New units larger than 30 mmBtu/hr and combusting liquid fuel would have a fabr ic filter installed. All new units less than
30 mmBtu/hr would have no add-on controls and li quid fuels were expected to meet the NSPS
SO 2 limits using low sulfur fuel oils. Gas-fired units of all sizes were no t expected to install controls to meet any of the NSPS limits. For this impacts analysis, it was assumed that all new
solid fuel units would be stokers , since stoker boilers are the mo st common type of solid fuel
boilers and all new units would have NOx control installed as a baseline control, regardless of
fuel. After an appropriate baseline level of control was determined for each model unit, an average baseline emission factor calculated for ex isting 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 combus tion units based on heat input. It was assumed that all new solid and liquid units would be constructed to meet thes e limits, so they were used as baseline emission values where applicable. The ba seline emissions for each unit were subtracted
from the new source MACT floor emission limit corresponding to each unit’s subcategory. Similar to the methods discussed in Section 4.1 of this memorandum, the emission reductions for new units were calculated by subtracting the baseline emissions assigned to each
unit from the MACT floor emission limits corr esponding to each unit’s subcategory, except for units not subject to numeric emission limits. Pollu tants which received re ductions in emissions based on the percent reduction in a regulated pol lutant for existing sources were calculated identically for reductions from new sources. Howe ver, new sources are not expected to achieve substantial fuel savings as a result of a tune-up, since the unit is expected to be installed tuned and ready to operate efficien tly, the one percent reduction in emissions for all pollutants25 expected from the efficiency gain of the boiler tune-up was not estimated. The method for estimating an upper range of Hg reductions used for existing sources, which involved comparing baseline emissions to the average emissions of the top performers, was also calculated for new sources. However, this did not re sult in a range of Hg emissi on reductions for new sources. New source baseline emissions of Hg at each of th e model units were below the mean of the top performing unit in each subcategory except for th e industrial biomass units. However, for this subcategory, since the MACT floor was based on the 3x RDL, no further reductions could be
estimated. Summaries of the estimated emission reductions from existing and new units for both the recommended and alternative options are loca ted in Appendix B. Note that Appendix B-1a represents the “Old Recommended Option” that was used in the RIA, while Appendix B-1b represents the “Revised Recommended Option” after accounting for late r data submittals and edits to the analysis.



## 5.0 METHODOLOGY FOR ESTIMATING SECONDARY IMPACTS

Secondary impacts include the solid waste, wa ter, wastewater, elec tricity required to operate air pollution control devices and the resu ltant greenhouse gas emissions, as well as the additional energy savings resulting from impr oved 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 new and existing units under the recommended option. Table 5-1 summarizes the co st, emission, and secondary impacts of this promulgated NESHAP. Appendices C-1 and C-2 present a detailed breakdown of the secondary waste, water, and energy impacts from each subc ategory of existing and new boilers and process heaters, respectively.

Table 5-1: Summary of Secondary Impacts
Impact New Units (recommended option) Existing Units (Old Recommended option) Existing Units (Revised Recommended option)
Water (gal/yr) 0 1.2 billion 1.2 billion
Wastewater (gal/yr) 0 432 million 426 million26 Solid Waste (tons/yr) 1,700 238,600 238,000Purchased Electricity (kWhr/ y r ) 120 million 1.3 billion 1.3 billion CO2 Emissions from Purchased Electricit y 79,700 896,800 859,200 Energy Savings* (trillion Btu/ y r ) 0 46.8 48.5 * Energy savings is calculated for units in the coal, liquid and gas (1) subcategories.

The secondary impacts were calculated using algorithms and assumptions described in
another memorandum. 2 These algorithms and assumptions were applied to the existing boiler and process heaters, where the baseline emissions for each unit exceeded the promulgated MACT floor emission limit except for small units (less than 10 mmBtu/hr), limited use units, and units firing natural gas, refine ry gas, or other on-spec gase ous fuels. A one percent energy savings was calculated for all existin g units except those firing biom ass or process gas, those that are otherwise already meeting th e appropriate numeric emission lim itation for CO, or those that require the installation of an oxi dation catalyst for CO control. Fo r new units, the algorithms and assumptions were applied to model units repres enting units expected to come online between 2012 and 2015, when the baseline emissions for each model exceeded the promulgated MACT floor emission limit for new units except for small uni ts and units firing natura l gas, refinery gas, or other on-spec gaseous fuels. Similar to existing units these sm all and gas-fired units are not required to meet a numerical emission limit, and therefore not expected to incur any secondary waste, water, or electricity impacts from these controls. A one percent en ergy savings from small units and units burning natural gas, refinery gas, or other on-spec gaseous fuels are included in the energy savings estimate in Table 5-1 since th ese units are expected to conduct a tune-up. The methodology used to assign baseline emission factor s to new and existing units are discussed in
another memorandum. 6



### 5.1 Wastewater and Water Impacts
The water required to create a slurry in the packed scrubber and the wastewater generated by the effluent of a packed bed scrubber were calculated for every unit expected to install a scrubber to meet the HCl limits in the proposal. Both the water and wastewater calculations required the use of several constants and variable s. The constants including the density of gas,27 moles of salt needed per mole of hydrogen chloride in the exhaust gas, the molecular weight of the salt used, the fraction of the waste stream treated, operating hours per year and the molecular weight of the gas. The data sources for thes e constants are provided in another memorandum. 2 The variables used to estimate the quantity of water required and wast ewater generated were
calculated based on characteristic s reported for each existing unit in the 2008 survey and subsequent data gathering activit ies and for the characteristics assigned to each new model unit.
The variables included: exhaust flow rate from the combus tion unit to the control device in actual cubic feet per minute, the inlet loading of hydrogen chlori de to the control device (mole fraction), and the efficiency of the control device in removing hydrogen chloride from the exhaust gas (percent reduction). The calculations used to estimate each variable are provided in
another memorandum. 2 The total national water and wast ewater amounts in Table 5-1 were determined by adding the per unit water and wastew ater estimates for all new and existing units, respectively.



### 5.2 Solid Waste Impacts
Solid waste is generated from collecting dust an d fly ash in fabric filters or ESP control devices, spent carbon associated with ACI, or spen t caustic from increasing the caustic injection rate. Solid waste impacts were estimated for ever y unit expected to install a fabric filter for mercury control or a DIFF for HCl control, ACI fo r 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 adding the per unit solid waste estimates for all new and existing unit s, respectively. To
estimate the solid waste contribution from each of these control devices, the variables were
calculated based on characteristic s reported for each existing unit in the 2008 survey and subsequent data gathering activit ies and for the characteristics assigned to each new model unit.
The calculations used to estimate each variable and the quantity of solid waste generated are provided in another memorandum. 2 The solid waste (dust, fly ash) generated by the use of an electrostatic precipitator was calculated when an electrostatic precipitator wa s determined to be necessary to meet the
NESHAP emission limits for PM. Estimates of the solid waste collected in an ESP were based on several variables, including: Exhaust flow rate from the com bustion unit to the control device (acfm); the inlet loading of pa rticulate matter to the contro l device (gr/acfm); operating hours28 (hr/year) and the efficiency of the control device required to meet the PM emission limits in the promulgated 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 promulgated NESHAP emission limits for particulate matter and/or me rcury. 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). For this analysis, the spent carbon collected from units w ith ACI is assumed to be disposed of instead of being re-generated. The amount of spent carbon created from ACI was calculated when ACI was expected to be necessary to meet the promulgated NESHAP emission limits for mercury. The calculation required the use of six variables, incl uding: Exhaust flow
rate from the combustion unit to the control de vice (dscfm); operating hours (hr/year), required removal efficiency for mercury, and an adjustment factor based required removal efficiency of

mercury. The solid waste generated by the use of incr eased caustic was calculated for those units where additional caustic was expected to achie ve the promulgated NESHAP emission limits for HCl. The calculation required the use of three va riables, including: exhaust flow rate from the combustion unit to the control device (dscfm); operating hours (hr/year), and the required removal efficiency for HCl.



### 5.3 Electricity Impacts
The amount of electricity required to operate a control device was calculated for a packed scrubber, electrostatic precipitator, fabric filter, DIFF, CO oxidati on catalyst and the fans for the ductwork associated with this equipment. These impacts were assessed for every unit that was estimated to require hydrogen chloride and/or partic ulate matter control. Electricity requirements are one output of the cost algo rithms used in the analyses, so no additional calculations 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, respectively. To estimate the electricity demand from each of these control devices, a set of va riables were calculated based on characteristics29 reported for each existing unit in the 2008 survey and subsequent data gathering activities and for the characteristics assigned to each new model unit. The constants, variables, and calculations
used to estimate each variable and the electr icity demand to operate the control devices are provided in another memorandum. 2



### 5.4 Greenhouse Gas Emissions from Electricity Usage Since greenhouse gases are generated from electricity production, an estimate of carbon dioxide emissions was generated for the electrici ty impacts of the add- on air pollution control devices. The total electricity usage from all control devices was multiplied by the national average carbon dioxide emission factor for carbon dioxide emi ssions from EPA’s 2005 e-GRID to obtain the expected annua l carbon dioxide emissions. 9 Carbon dioxide emissions were only estimated for boilers required to install a fabric filter, electrostatic pr ecipitator, wet scrubber, oxidation catalyst, or DIFF system, since those controls generate an increased electricity
demand.



### 5.5 Energy Savings Impacts
The energy savings from combustion controls such as low NOx burners or linkageless boiler management systems, and work practice standards, including a tune-up, and implementing the energy audit findings with a short-term pa yback can improvements in efficiency, thereby reducing fuel consumption. This secondary im pacts analysis only estimates a one percent efficiency gain from tune-up work practices and installation of com bustion controls to be conservative and consistent with the assumptions made in Section 3.1 of this memorandum. No energy savings are attributed to the energy asse ssment in this analys is. Quantifying the exact gains in efficiency from each of these work pr actice standards is difficult, and may depend on the baseline operating efficiency of each unit.
Section 3.1 discusses the fuel sa vings impacts in terms of annu alized cost savings to each boiler or process heater, and th e national energy savings presente d 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, gas, a nd liquid fuel categories only.30 

### 5.6 Estimating Secondary Impacts for Existing and New Units
Appendices C-1 and C-2 present a detailed br eakdown of the secondary waste, water, and energy impacts from each subcategory of existing and new boilers and process heaters, respectively. The differences presented between the recommended and alternative regulatory options are based on the number of controls estimated to be installed to meet the floor limits associated with each option, which in turn aff ects the amount of waste, wastewater, water, and energy consumed by the control devices installed for PM, HCl, and Hg.



## 6.0 INCREMENTAL IMPACTS SINCE MARCH, 2011 RULE NOTICE

Appendix D presents the incremental costs, emission reductions, and secondary impacts of the amended final rule when compared to the March, 2011 final rule notice (76 FR 15608). This appendix shows the incremental impacts due to changes in the major source inventory of boilers and process heaters. The amended fina l rule contains an additional 336 boilers and process heaters compared to the inventory us ed to estimate impacts for the March, 2011 final rule. Appendix D also shows the incremental impacts due to changes in regulatory provisions (e.g., changes in emission limits, subcategories, or revised emission data submittals).31 

## 7.0 REFERENCES

1. Eastern Research Group, Inc. Revised MA CT Floor Analysis (August 2012) for the Industrial, Commercial Institutional Boile rs and Process Heaters national Emission Standards for Hazardous Air Pollutants – Major Source. August 2012.

2. Eastern Research Group, Inc. Re vised (November 2011) Methodology for Estimating Control Costs for Industrial, Commercial, Institutional Boilers and Process Heaters National Emission Standa rds for Hazardous Air Pollutants – Major Source. November 2011.

3. Eastern Research Group, Inc. Revised (November 2011) New Unit Analysis for Industrial, Commercial, a nd Institutional Boilers and Process Heaters at Major Sources. November 2011.

4. Singleton, A. and B. Lange, ERG. Gas Sp ecification for Industrial, Commercial, Institutional Boilers and Process Heater s National Emission Standards for Hazardous Air Pollutants – Major Source. January 2011.

5. U.S. Department of Energy, EIA. 2008 Deliv ered Fuel Prices to Industrial and Commercial Clients. http://www.eia.doe.gov/

6. Eastern Research Group, Inc. Revise d August 2012 Development of Baseline Emission Factors for Boilers and Process Heaters at Commercial, Industrial, and Institutional Faci lities. August 2012.

7. U.S. Department of Energy. Energy In formation Administration. Annual Energy Outlook 2011. Table A2. Energy Consumption by Sector and Source. http://www.eia.gov/forecasts/aeo/pdf/0383(2011).pdf

8. “Servicing Your Boiler by Sustainable En ergy Authority of Ireland.” Previously available on-line at http://www.seai.ie/ . Docketed in National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters.

9. Environmental Protection Agency. eGRI D. “eGRID Year 2005 Summary Tables” December 2008. http://www.epa.gov/cleanenergy/docume nts/egridzips/eGRID2007V1_1_year05_Su mmaryTables.pdf

10. Milmore, P. and S. Winkleman. Climate Wise Boiler and Steam Efficiency Wise Rules: Proceedings from the Twentie th National Industry Energy Technology Conference. April 1998. Docketed in Nati onal Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial , Commercial, and Institutional Boilers and Process Heaters.32 11. DTE Energy. “Your Energy Savings Bu siness Program: Boiler Tune-ups.” Previously available on-line at http://YourEnergySavings.com/ . Docketed in National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters.

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14. CenterPoint Energy. Energy Efficiency Check list (Minnesota). Pr eviously available on-line at http://centerpointenergy.com/ . Docketed in National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters.

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18. Wright, A., M. Martin, and S. Nimbalkar, Oak Ridge National Laboratory, and J. Quinn, S. Glatt, and B. Orthwein, DOE Industrial Technologies Program. Results from the U.S. DOE 2007 Save Energy Now Assessment Initiative: DOE’s Partnership with U.S. Industry to Redu ce Energy Consumption, Energy Costs, and Carbon Dioxide Emissions, Detailed A ssessment Opportunity Data Report. ORNL/TM-2009/074. April 2009.

19. Five State Heating and Cooling, Charlotte, NC. http://www.fivestarheatingandcooling.com/33 20. Eastern Research Group, Inc. Analys is of Dioxin/Furan Data and Minimum Detection Levels from Industrial, Commer cial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants – Major Sources. November 2011.

21. Singleton, A., and Gibson, G., ERG. Revi sed Methodology for Estimating Cost and Emissions Impacts for industrial, Commer cial, Institutional Boilers and Process heaters National Emission Standards for Hazardous Air Pollutants – Major Source. February 2011.

22. U.S. Department of Energy, EIA. 2012 Deliv ered Fuel Prices to Industrial and Commercial Clients. http://www.eia.doe.gov/

23. Eastern Research Group, Inc. Incorporat ing Measurement Error in Reported Carbon Monoxide (CO) and Total Hydrocarbon (THC) Data (Revised August 2012). August 2012.