MEMORANDUM

TO: Brian Shrager, U.S. Environmental Protection Agency, OAQPS/SPPD
FROM: Amanda Singleton, and Graham Gibson, ERG
DATE: February 17, 2011
SUBJECT: Revised Methodology for Estimating Cost and Emi ssions Impacts for Industrial,

Commercial, Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants – Major Source



## 1.0 INTRODUCTION

The purpose of this memorandum is to discuss the revised meth odology used to estimate the costs, emission reductions, and secondary impacts fr om industrial, commercial, and institutional boilers at major sources of hazardous air pollutants (HAP). These impacts were calculated for existing units and new units projected to be operational by the year 2013, three years after the rule is expected to be promulgated. The re sults of the impacts analysis are presented for both the regulatory option contained in the promulgated rule and a more stringent regulatory option. The development of the maximum achieva ble control technology (MACT) floor level of control, projection of new units, and a de tailed description of the cost equations used to estimate costs for various control technologies is presented in other memoranda. 1,2,3 This memorandum is organized as follows:
1.0 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 References

## 2.0 OVERVIEW OF REGULATORY OPTIONS

Two control options were considered for existing boilers and process heaters at major sources of HAP. A description of the two options is inc luded in this section.


### 2.1 Existing Units

• The recommended option is the option presented in the pre amble and final rule. In this option, small boilers and process heaters (less than 10 mmBtu per her), limited use boilers and process heaters (operating less than 876 hours per year), and boilers burning natural gas, refinery gas, or other on-spec gaseous fuels ar e subject to work practice standards in lieu of numeric emission limitations. The work practice standard small and limited use units is a biennial tune-up and the work practice s tandard for larger natural gas, refinery gas, or other on-spec gaseous fuels is an ann ual boiler tune-up. Boilers not meeting one of those criteria are subject to numeric em ission limitations for Hg, PM, HCl, CO, and TEQ dioxins/furans. Boilers combusting at le ast 10 percent solid fuels, either coal, other fossil solids or biomass are grouped i nto a single solid fuel subcategory and are subject to identical emission limitations for the fuel-based pollutants Hg, PM, and HCl. For combustion-based pollutants CO, and TEQ dioxins/f urans separate combustor design subcategories are considered for coal/fossil solid s and biomass. Units designed to burn liquid fuels, units located in non-continental States and United States Territories designed to burn liquid fuels, and units burning off-spec gaseous fuels (other process gases) each have a single subcategory for both fuel and co mbustor-based HAP.

• The alternative option is identical to the recommended o ption except that boilers combusting at least 10 percent solid fuels are subject to s eparate numeric limits depending on the class of solid fuel combusted. Units burning c oal or other fossil solids have separate numeric emission limitations from units burning biomass or other biobased solids for Hg, PM, and HCl.



### 2.2 New Units
The same two control options for existing units were use d for new units. However, since it is projected that no new boilers combusting solid fuel (biomas s or coal) will be constructed by 2013, the results of the cost and emission impacts analys es for both options are identical.



## 3.0 ESTIMATING COST IMPACTS

For each option, the cost impacts analysis compares t he baseline emissions for each unit to the corresponding MACT floor emission limit for the unit’s subcategory. A control device was applied to the unit if its baseline emissions exceeded the ir applicable MACT floor emission limit.A comparison of the overall capital and annualized cost s of the recommended option are

presented in Table 1. The detailed equations used to estimate the control, testing, monitoring, and work practice costs are discussed in another memorandum. 2 The following logic was used to apply control, testing, and monitoring costs to each boi ler or process heater:


### 3.1 Recommended Option

The recommended option represents an option with a conso lidated subcategory for fuelbased HAP from solid fuel units, where every unit must mee t numerical emission limits and demonstrate compliance with performance stack testing, m onitoring, and fuel analysis with a few exceptions. Units in the gas 1 subcategory, small units (l ess than 10 mmBtu/hr), and limited use units (less than 876 operating hours per year), qualify for wo rk practices under Section 112(h) of the CAA and work practices consisting of an annual or bi ennial tune-up replace the traditional compliance demonstrations associated with numeric emi ssion limits.


### Control Cost Impacts
Mercury Control

• Fabric filters — a new fabric filter installation wa s expected to achieve most of the Hg emission limits in the final rule. Where baseline Hg e missions were found to be greater than the MACT floor, the cost of a fabric filter wa s estimated for an individual boiler or process heater, unless the unit already had a fabric filt er installed. A new fabric filter was estimated to be installed at 454 existing boilers and process heaters. This does not include the fabric filters installed in combination with dry inje ction to achieve HCl controls that
are discussed below.

• Activated carbon injection (ACI) — In the case of a unit with a fabric filter emitting Hg above the MACT floor emission limit, the incrementa l Hg removal efficiency required to meet the MACT floor was calculated, and then the cost s to install activated carbon injection (ACI) technology on the boiler were estima ted. Incremental ACI equipment was installed for 108 existing boilers and process heaters.

• Wet scrubbers—one of the technologies selected for the c ost analysis to reduce emissions of hydrogen chloride (HCl)—is also capable of achieving modest reductions in Hg. Literature suggests that these scrubbers can achieve a 10-perc ent reduction in Hgemissions. If a scrubber was being installed for HCl, an d 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 filte r.

Particulate Matter Control

• When baseline particulate (PM) emissions exceeded the MA CT floor, 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 estimated to be installed a t 10 existing boilers and process
heaters.

• Wet scrubbers are also capable of achieving a modest reduction in PM. Literature suggests that these scrubbers can achieve an 85-percent reduc tion in PM emissions. If a scrubber was being installed for HCl, and baseline PM emiss ions were within 85 percent of the MACT floor for PM, the wet scrubber was expect ed to achieve this level of emission reduction without installing an ESP.

Hydrogen Chloride Control

• When HCl baseline emissions were greater than the MAC T floor, the cost of adding a packed bed scrubber, increasing the sorbent rate on an exist ing scrubber, or installing a combination fabric filter and dry injection (DIFF) syst em was estimated. Scrubbers and
DIFF were estimated to be able to attain similar leve ls of hydrogen chloride control. Based on input received during the public comment period, many wo od product facilities are not permitted to discharge wastewater, thereby restric ting the type of controls needed to reduce emissions of HCl and other acid gases. For this a nalysis, facilities in NAICS codes 321 (wood products manufacturing) and 322 (paper manufacturing) were assumed to not be able to install a packed scrubber due to the regulati on of wastewater discharge from those industries. For the remaining units requiring con trol device installation for hydrogen chloride reduction, the less expensive control opti on between a packed scrubber
and DIFF was assumed to be the control installed. If th e boiler already reported having a scrubber installed, a DIFF was not the selected control technology, and the baseline emissions still exceeded the floor, the incremental re quired HCl removal efficiency was
calculated and the then the cost to increase the sorbe nt injection rate in the scrubber wasestimated in the cost analysis. Wet scrubbers were est imated to be necessary to control

HCl emissions at 774 existing boilers and process heaters. DIFF was identified to be necessary to control HCl emissions at 136 existing boile rs and process heaters. Incremental sorbent injection was identified to be ne cessary to control HCl emissions at 7 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 necessa ry 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 filt er was needed for mercury control,
the costs of a fabric filter were estimated.

Dioxin/Furan Control The final rule requires all units that measure dioxin dat a below the method detection level to report that congener as zero. Based on the reported dioxin/furan data and associated
detection levels available at the time of the final ru le, most units will fall below the MACT floor levels if the non-detect congeners are tre ated as zero, For coal, 17 of the 27 tests would meet the existing limits, 17 of the 22 tests fo r biomass would meet the existing limits, and all of the liquid and process gas test s would meet the existing limits.
Given these results and the fact that some units are i nstalling ACI for mercury control, which is expected to have a co-benefit of reducing dioxin/fura n emissions, the cost analysis does not estimate any control costs for achie ving the dioxin/furan emission
limits. Carbon Monoxide and Organic HAP Control

• Organic HAP and carbon monoxide can be controlled by eithe r improving the combustion efficiency of the unit, or installing an oxidati on catalyst on the exhaust of a combustion unit. The control strategy necessary to me et the MACT floor emission limit will vary depending on the magnitude between the baseline e missions and the CO MACT floor. A step function was used to delineate what type of c ontrol strategy should be analyzed in the cost impacts analysis:

o A boiler tune-up was estimated in the cost impacts analy sis if the unit’s CO baseline emissions were less than or equal to 1.5 times the applicable numeric COemission limit. Some commenters, including facilities and boiler and burner vendors, suggested that the concrete threshold of 400 ppm used i n the CO control cost analysis in the proposal was an inappropriate cutof f for determining whether or not a tune-up could achieve the CO emission limits for c ertain boiler types. Many of these commenters added that significant changes i n CO could not be
made without a tradeoff in increased NOX emissions. Base d on data in the record as well as public comment submittals, CO emissions can fluctuate widely due to operating loads and conditions. Further, most units in the database do not report dedicated combustion controls or CO oxidation catalyst s installed to reduce CO emissions. Instead of using a concrete threshold of 400 ppm i n final analysis, we estimated that tune-ups could achieve a percent reduction fr om the unit’s baseline emissions. To determine an appropriate threshold level tha t tune-ups could achieve the limits to demonstrate annual compliance with the CO stack test in the final rule, we looked at best performing units for CO that r eported paired CO CEMS emissions and boiler load data. Best performing CO unit s in the coal/fossil solid stoker, biomass/bio-based solid dutch oven/suspension b urner and hybrid suspension grate subcategories biomass had data available. No ne of these units with paired CO and load data reported having any add-on dedicated CO controls or combustion controls installed on the unit. The WVDupon tWashingtonWorks P05 unit reported a wide range of CO emissions at loads grea ter than 75 percent of its design capacity, the maximum CO value was over 9 times greater than the minimum CO value at the unit. For biomass units, the ran ge is even more pronounced, at TXDibollTemple-Inland PB-44, the maximum CO value at loads greater than 50 percent was nearly 900 times higher than th e minimum CO value, and at hybrid suspension grate burners, FLUSSugar, Boiler 8, t he maximum CO value was over 1,700 times higher than the minimum CO val ue. Despite these large ranges, the CO stack test values of these units wer e all meeting the floor values during their emission stack tests. 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 emissions. Based on data provided by best performing units, it is reasonable and a conservative estim ate that this level of control can be achieved without 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 applicable numeric CO emission lim it, the cost of a replacement low-NOx burner was estimated to achieve t he MACT floor emission limits. Since stokers, fuel cells, or fluidized bed unit do not have replaceable burners, a linkageless boiler management system (LBMS) was the technology
estimated to achieve the MACT floor when baseline CO e missions exceeded the floor in lieu of replacement low-NOx burners. A thresh old of 2.5 is still less than the reported findings from best performing boilers in the coal and biomass subcategories that demonstrate wide fluctuations in CO emiss ions 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 rec eived from public comments about underestimating the costs of CO control.

o Finally, if the baseline CO emissions were greater than 2.5 times the applicable CO emission limit, the cost impacts analysis estimate d that a CO oxidation catalyst would be required to meet MACT floor limits.

Work Practice Costs

• All small boilers (less than 10 mmBtu per hour), limite d use boilers (less than 876 hours of operation per year), are required to conduct a biennial boi ler tune-up. All large boilers burning natural gas, refinery gas, or other on-spec gaseous fue ls are required to conduct an annual tune-up. The cost to conduct an annual tune-up is ba sed on the cost estimate provided in a report by the Industrial Extension Service 16 . This report indicated that the initial set-up for boiler tune-up was $3,000 to $7,000 per boile r; thereafter, annual tuning costs $1,000 per boiler. An average of $5,000 per boiler initial set-up costs was annualized over 5 years at a 7 percent rate, and added to the subsequent year tune-up costs. The resultant annualized cost for an annual tune-up i s $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)
Biennial tune-up costs would provide some cost savings, although t he costs of the initial tune-up set-up must be factored into both of the work practi ce frequencies, so this analysis used a single tune-up cost, which is based on an a nnual frequency. The annualized cost for a biennial tune-up is $2,228 per boiler, as s hown in Equation 2.

Biennial Tune-up Cost ($2008) = {[C $2004 * (X 2008 /X 2004 ) * i * (1+ i ) y ] / [(1+ i ) y – 1)]} +

[(Z $2004 / 2) * (X 2008 /X 2004 )] = $2,228 (Equation 2) 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)

A total of 12,266 boilers and process heaters meet one of t he above criteria and are subject to a tune-up work practice in lieu of add-on controls

.

• All facilities are expected to conduct a one-time energy audit. An annual cost of $854 per audit was used for commercial facilities and $18,292 per audit w as used for industrial facilities, and these costs are the same as the esti mates included in the proposal. Although
some commenters indicated EPA underestimated the costs of the assessment, in the final rule EPA has reduced the scope of the assessment in the final rule to an assessment that does not exceed one to three days in length for units cons uming less than 1 trillion Btu/year of energy. For larger units, the audit is reduce d in scope to assess for at least 20 percent of the energy output of the boiler system. As discussed in the memorandum for Estimating Control Costs from Major Source Boilers an d Process Heaters, the cost of an energy audit ranges from $75,000 for industrial-scale energy audits to between $2,000 and $5,000 per energy audit for institutional and commercial- scale audits. 2 This larget estimate is based on costs presented to the 2009 Boiler Sm all Business Regulatory Flexibility Act panel by an affected small entity, Port Townsend Paper Company. The cost of each type of audit was annualized over 5 years at 7 percent to obtain anannualized cost estimate. For the cost impacts analysis, 1,639 facilities are expected to

conduct an audit, 197 facilities are commercial or instit utional and 1,442 facilities are
industrial.



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

Testing Costs All boilers and process heaters designed to burn solid an d gaseous fuels were expected to conduct an annual compliance test for PM, HCl, Hg, D/F, and CO. The cost to conduct stack tests for these five pollutants was estimated to be $44,000 pe r year for boilers combusting solid or other gaseous fuels. Based on comments received about t esting under worst-case conditions, many solid fuel boilers which fire multiple fuel stream s or types of fuel are expected to conduct repeated testing for mercury and HCl at a cost of $18,000 per y ear. Boilers and process heaters designed to burn liquid fuels were expected to conduct an annual compliance test for PM, D/F, and CO. In lieu of a stack test boilers designed to burn liquid fuels were expected to conduct fuel analysis, or rep ort fuel analyses received from a fuel supplier for chlorine and Hg. Conducting stack tests for PM, D/F, and CO and fuel analysis for chlorine and Hg was estimated to be $16,000 per year. Although othe r fuels are eligible to comply with the promulgated rule through fuel analysis in lieu of stack testing, this cost estimate conservatively assumed that only units designed to fire liqui d fuels would use this compliance
alternative. The methods and data sources used to estimate testing and monitoring costs are
discussed in other memoranda. 2 The final rule includes a provision for gaseous fuels other than natural gas and refinery gas to demonstrate that they meet the specifications ou tlined in the rule for mercury and hydrogen sulfide. We reviewed the database for facilities 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 45 facilities would need to conduct monthly fuel analysis, at a cost of $600 per month, or $7200 per year. The methods and costs associated with demonstratingthat the gas meets the specifications for mercury and hydr ogen sulfide are discussed in another

memorandum. 4 Because the fuel spec can be conducted upstream of the combustion equipment, EPA determined that one specification per month, per faci lity, would be the likely compliance mechanism for units opting to demonstrate that their gaseous fuels meet the specification.
Small boilers often exhaust to small diameter stacks that do not have any test ports or test platforms installed. Similarly, based on the public comm ents received limited use units often do not have test ports or test platforms installed. For th ese units, we estimated the additional costs to these costs to construct or rent scaffolding and install t est ports. The costs include installation of 4 test ports, 90 degrees opposed to each other, and five weeks rental of temporary scaffolding.
EPA estimates that these small sources would incur an a dditional $196 million to install test ports and rent temporary scaffolding. Many establishments i n each industry, commercial, or institutional sector are associated with multiple (as many as a 700) small units. A summary of the costs by fuel category is shown in Table 3-1 below.

Table 3-1: Cost Estimate for Renting Scaffolding and Const ructing Test Ports at Limited Use and Small Boilers and Process Heaters

Fuel Category Number of Limited Use and

Small Boilers and Process

Heaters Port Costs ($2008) Renting Temporary Scaffolding ($2008) Total Costs

($2008)
Coal 15 164,722 210,000 374,722

Biomass 21 230,610 294,000 524,610

Gas 1 7433 81,624,999 104,062,000 185,686,999

Gas 2 51 560,053 714,000 1,274,053

Liquid 358 3,931,353 5,012,000 8,943,353
Total 7,878 86,511,737 110,292,000 196,803,737

Monitoring Costs Various monitor configurations were installed based on the size of the unit and the pollution control devices expected to be installed to achieve the MACT floor emission limits. For units expected to install packed bed wet scrubbers, an annualize d cost of $5,600 for a scrubber parametric monitor was included in the cost analysis. If a unit was expected to install DIFF, thecost to monitor sorbent injection rate and add a bag leak det ection monitor was included in the

analysis, based on the unit’s hours of operation. For unit s expected to install a fabric filter, an annualized cost of $9,700 for a bag leak detection monitor was included in the cost analysis. If a unit was expected to install ACI, the cost to monitor the carbon injection rate was included in the analysis, based on the unit’s hours of operation. For unit s that did not install a PM CEMS and did not install a scrubber to meet HCl limits, an annualize d cost of $14,660 for an opacity monitor was included in the cost analysis. While the final rule includes a cutoff of greater than 250 mmBtu/hr, in order to be consistent with the thresholds in the boiler NSPS (40 CFR 60, Subparts Db and Dc) the cost analysis includes the cost of a PM CEMS for units with a heat input capacity of 250 mmBtu/hr or more. Oxygen monitors were required for al l boilers and process heaters subject to CO emission limits, these monitors were assu med to be extractive type monitors with an annualized cost of $1,436. Although several units are expecte d to have O2 monitors installed on the units for other reasons, such as to monitor combust ion efficiency, since the number of units with monitors installed and calibrated according to EPA performance specifications is unknown, this analysis applies the cost of an O2 monitor to all units subject to a CO emission limit. No PM CEMS or opacity monitors were assumed for boilers and process heaters designed to gaseous fuels.


### Fuel Savings Impacts This cost analysis includes an estimate of energy saving s of one percent for every unit that is expected to install controls to improve combust ion, or conduct an annual tune-up or energy audit. Further, documents from the Sustainable Ene rgy Authority of Ireland have charted efficiency gains as a function of boiler fuel type and ti me elapsed since the previous tune-up. 8 Many best practices are considered pollution prevention b ecause they reduce the amount of fuel combusted which results in a corresponding reduction in e missions from the fuel combustion. Further boiler tune-ups have been shown to improve the e fficiency 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 burners and insta llation of an LBMS are also expected to improve the efficiency of the unit, thus reduci ng fuel consumption. This cost analysis assumes an annual fuel savings of 1 percent. The energy sa vings is estimated using the Equation
3:Annual Fuel Savings (mmBtu/yr) = DC * CF * Op hours * EG (Equation 3)

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%
After the fuel savings for each boiler and process heate r was calculated, the both industrial and commercial prices for coal, #2 distillate f uel oil, #6 residual fuel oil, and natural gas were obtain from the EIA. 5 The EIA data reported fuel prices as $/ton for coal, $/t housand cubic feet for natural gas, and cents per gallon for fuel o il. The higher heating values were obtained from Table C-1 of the EPA Mandatory Reporting R ule (40 CFR part 98 subpart C) and the higher heating values were used to convert the fuel pri ces to a standard unit of measure, $ per mmBtu. Using the NAICS code reported by each facility and the fuel category assigned to each combustion unit, the appropriate fuel price was multiplie d by the calculated fuel savings. Table 3-2 below shows the distribution of reported NAICS codes considered as industrial versus commercial in terms of fuel pricing.

Table 3-2: 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, 921, & 928

This cost analysis only estimates the fuel savings from units in the coal, liquid and natural gas and other gaseous fuel categories. A fuel savings was no t estimated for units in the biomass fuel category since the price of biomass fuels is variable, and often biomass is an on-site industrial byproduct instead of a purchased fuel. The logic behind the costs analysis for new units were identical to that of existing units for the rec ommended option with the exception of the energy audit. Energy audits are a recommended beyon d-the-floor option for existing units only and therefore no costs for an audit were included in t he new source floor analysis.


### 3.2 Alternative Option The alternative option includes control device and testin g/monitoring cost estimation logic identical to the Recommended Option outlined above, except that units combustingbiomass and coal must meet separate numeric emission li mitations for Hg, PM, and HCl. All

other aspects of the options are identical. As a result of this modified option and its computed MACT floors, the number of solid fuel units estimated t o install controls to meet the limits were adjusted as follows:

• A new fabric filter was estimated to be installed at 451 existing boilers and process heaters to control Hg emissions. This does not include th e fabric filters installed in combination with dry injection to achieve HCl control. A new fabric filter is required to be installed on 3 fewer boilers and process heaters under this option when compared to the recommended option.

• Incremental ACI equipment was estimated to be installed at 11 existing boilers and process heaters for the controlling Hg. Incremental ACI equipment is required to be installed on 97 fewer boilers and process heaters compared to the recommended option.

• ESP technology was estimated to be installed at 34 exis ting boilers and process heaters to control PM. ESP technology is required to be installed on an additional 24 boilers and process heaters under this option when compared to the rec ommended option.

• Wet scrubbers were estimated to be necessary to contro l HCl emissions at 774 existing boilers and process heaters. This is identical to the n umber of sources estimated to install a scrubber for HCl control under the recommended option.

• DIFF was identified to be necessary to control HCl emi ssions at 390 existing boilers and process heaters. DIFF is estimated to be installed on a n additional 254 boilers and process heaters under this option when compared to the recommended o ption.

• Incremental sorbent injection was identified to be ne cessary to control HCl emissions at 23 existing boilers and process heaters. Incremental sorb ent injection is estimated to be installed on an additional 16 boilers and process heaters under this option compared to the recommended option.


### 3.3 New Unit Options The recommended option for new units follows the same log ic for estimating control costs as the recommended option for existing units outline d above with one exception. For boilers with a rated heat capacity less than 500,000 Btu per hour, a tune-up cost of $200 was selected. This value was based on research of tune-up cost s for similarly sized home boiler programs, which suggested the costs of a tune-up ranged from $60 to $150. 19,20 The alternativeoption for new units is also identical to the alternat ive option for existing units. However, no new

boilers or process heaters combusting solid fuels are expected to be constructed by 2013. Since the differences in the recommended and alternative optio ns are focused only on boilers and process heaters combusting solid fuel, there are no diff erences in the recommended and alternative options for new units. The new unit analysis also projects new gaseous fuels, but based on the EIA data used for the new unit projections al l of these new boilers are estimated to be natural gas so no cost for a gas specification is in cluded in the new unit analysis.



### 3.4 Summary of Cost Impacts
The recommended option is the promulgated option for exist ing and new boilers and process heaters. Tables 3-3 and 3-4 summarize the costs of the promulgated option for new and existing units. Appendix A of this memorandum provides a detail ed summary of the costs according to unit size, subcategory, and individual control de vice costs. Appendix A also includes a summary of the costs on existing units under th e alternative option considered in development of the final rule.

Table 3-3: Summary of Costs of Promulgated Options Costs shown in $10 6 (2008) with capital recovery estimated at 7%
Type of Unit Option Number of Units TAC TAC considering fuel savings Testing &

Monitoring TAC Control

TAC Control

TCI New Recommended 47 $6.3 $6.1 $0.3 $5.9 $20.9 Existing Recommended 13,840 $1,804 $1,376 $135 $1,669 $5,082

Table 3-4: Summary of Total Annual Costs by Control Type fo r Existing Units under Recommended Option Costs shown in $10 6 (2008) with capital recovery estimated at 7%

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 13,840 391 3.5 578 423 2.0 219 17.5 35.1 26.5

## 4.0 METHODOLOGY FOR ESTIMATING EMISSION REDUCTIONS This section discusses the methodology used to estimate e mission reductions from boilers and process heaters at both existing and new facilities a nd it presents a summary of the results for the recommended regulatory options.



### 4.1 Emission Reductions from Existing Boilers and P rocess Heaters
The emission reductions analysis for existing combustion u nits was done for each boiler and process heater in the major source inventory. There are a total of 13,840 boilers and process heaters at major sources that reported data in the 2008 ques tionnaire (ICR No. 2286.01). Each combustion unit was assigned a unit-specific or average baseline emission factor, depending on the availability of emission data reported for the unit . A detailed discussion of the procedures and results of the baseline emissions analysis is present ed in another memorandum. 6

Emission Reductions for Recommended Option Emission reductions for PM, HCl, Hg, CO, and dioxins/furan s were calculated on a ton per year basis by subtracting the baseline emissions ass igned to each unit from the MACT floor emission limits corresponding to each unit’s subcategory . A detailed discussion of the procedures and results of the MACT floor analysis is pre sented in another memorandum. 1 A percent reduction was calculated for CO. It was assume d that each combustion unit would achieve an identical percent reduction from baseline emi ssions 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 percent reduction from baseline emissions for HF as
was achieved for HCl. A combustion unit is assumed to in stall 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 was assumed that the control will achieve a reduction from baseline for SO2 equivalent to the reduction in HCl. The logic for estimating SO2 reductions is a change since the proposal o f the rule, to address public comments concerned with overestimating SO2 reductions. At proposal we had estimated that all units installing control for HCl removal would achieve a 95 percen t reduction in SO2; by reducing the removal efficiency for SO2 to be equivalent to the reduc tion efficiency for HCl the revisedemission reductions are more in line with the capability of the control devices estimated to be installed. A percent reduction in PM was also calculated in order to estimate total non-Hg metals
reductions. It was assumed that each combustion unit would achieve an identical percent reduction from baseline emissions for each non-Hg metal lic HAP as was achieved for PM.
PM2.5 emissions were assumed to be a fraction of total filterable PM emissions based on fuel and control device configuration installed on the unit. The methods used to derive the contribution of PM2.5 to overall filterable PM are prese nted in other memoranda. 4 To calculate emission reductions for PM2.5, the emission reductions fo r PM were multiplied by the applicable PM2.5 fraction. Emission reductions for all pol lutants for which there was no floor value were calculated on a ton per year basis.
To convert emission reductions from an emission rate on a heat input basis to an annual emission rate, Equation 4 was used:

Annual Emission Rate (tpy) = ER HI * 0.0005 * Op hours (Equation 4) 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 concentration bas is to an annual emission rate, Equations 5 and 6 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 5) 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 pollutant, 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 standardized emission concentrati on for promulgated 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 6) Where: ER C = emission concentration (ng/dscm @ 7% O 2 ) 0.0283 = conversion factor, dry standard cubic meter per dry s td. 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 emission concentratio n for promulgated rule.

Converting concentrations to an annual emission rate re quired an oxygen concentration and exhaust flowrate estimated for each specific fuel t ype. The development of these assumptions and estimates is presented in other memoranda

. 2 All conversions required the annual operating hours for each combustion unit reported in the 2008 survey. If no operating hours were reported, the unit was assumed to operate for 8,400 hours per year (two weeks of downtime). For units not subject to emission limitations, the emiss ion 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 a ir pollutants. A one percent reduction in all types of emissions was estimated by multiplying th e baseline emissions for each unit by a
factor of 0.01.

Emission Reductions for Alternative Option The same calculations discussed for estimating emissi on reductions for the recommended option were applied to all units except that boilers an d process heaters combusting biomass and coal were subject to separate numeric emission limits for Hg, PM, and HCl. In these cases the adjusted MACT floors under this alternative option were s ubtracted from baseline emissions and
then the remainder of the above calculations for the r ecommended option was performed.

### 4.2 Emission Reductions from New Boilers and Proces s Heaters

Based on industrial and commercial fuel consumption projec tions from the EIA, there are 47 new boilers and process heaters expected to come on-line by 2013. 5 a discussion of the methodology used to project new boilers and process heate rs is discussed in another
memorandum. 3 The New Source Performance Standards for Industrial, Comm ercial and Institutional Boilers (40 CFR part 60, subparts Db, Dc) (NSPS), was revie wed 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 establish the PM NSPS limit for biomass boilers. New coal units larger than 75 mmBtu/hr would have a fabric fi lter and wet scrubber installed, while new coal units between 30 and 75 mmBtu/hr would only have a f abric filter installed and would
meet the SO 2 limits in the NSPS by using coals with low sulfur con tent. New units larger than 30 mmBtu/hr and combusting liquid fuel would have a fabric filt er installed. All new units less than 30 mmBtu/hr would have no add-on controls and liquid fuels we re expected to meet the NSPS
SO 2 limits using low sulfur fuel oils. Gas-fired units of all sizes were not expected to install controls to meet any of the NSPS limits. For this impa cts 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 install ed as a baseline control, regardless of
fuel. After an appropriate baseline level of control was deter mined for each model unit, an average baseline emission factor calculated for existin g units within the same fuel category and having the same level of control was assigned to each mode l 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 constructed to m eet 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 corres ponding to each unit’s subcategory. The
same calculations discussed in Section 3.1 of this memo were used to estimate the reductions for
new units.
Similar to the methods discussed in Section 4.1 of this me morandum, the emission reductions for new units were calculated by subtracting th e baseline emissions assigned to eachunit from the MACT floor emission limits corresponding to each unit’s subcategory, except for

units not subject to numeric emission limits. For units n ot subject to emission limitations, the emission reductions were based on a one percent gain in efficiency expected from the tune-up work practice standard. A summary of the estimated emi ssion reductions at existing units for both the recommended and alternative options are locate d in Appendix B-1.



## 5.0 METHODOLOGY FOR ESTIMATING SECONDARY IMPACTS

Secondary impacts include the solid waste, water, wastew ater, electricity required to operate air pollution control devices and the resultant gr eenhouse gas emissions, as well as the additional energy savings resulting from improved combus tion controls or work practices required by the NESHAP. This section documents the inputs a nd equations used to estimate these secondary impacts, and it summarizes the impacts at existing units under promulgated regulatory option 4 and new units under promulgated regulatory op tion 1. Table 5-1 summarizes the cost, emission, and secondary impacts of this pro mulgated NESHAP. Appendices C-1 and C2 present a detailed breakdown of the secondary waste, wat er, and energy impacts from each subcategory of new and existing boilers and process heaters , respectively.

Table 5-1: Summary of Secondary Impacts

Impact New Units (recommended option) Existing Units (recommended option)

Water (gal/yr) 242,000 671 million
Wastewater (gal/yr) 193,900 266 million Solid Waste (tons/yr) 580 100,500 Purchased Electricity (kW-hr/yr) 6.2 million 1.4 billion CO2 Emissions from Purchased

Electricity (tons/yr) 4,100 910,000 Energy Savings* (trillion Btu/yr) 0.01 44.5 * Energy savings is calculated for units in the coa l, liquid and gas subcategories.The secondary impacts were calculated using algorithms and assumptions described in

another memorandum. 2 These algorithms and assumptions were applied to the exist ing boiler and process heaters, where the baseline emissions for each unit exceeded the promulgated MACT floor emission limit except for small units (les s than 10 mmBtu/hr), limited use units, and units firing natural gas, refinery gas, or other on-spec gaseous fuels. A one percent energy savings was calculated for all units, including the small, limited use and gas-fired units since these units are expected to conduct a tune-up. For new units, the algorithms and assumptions were applied to model units representing units expected to com e online between 2010 and 2013, when the baseline emissions for each model exceeded the pr omulgated MACT floor emission limit for new units except for small units and units firing n atural gas, refinery gas, or other onspec gaseous fuels. Similar to existing units these small an d gas-fired units are not required to meet a numerical emission limit, and therefore not ex pected to incur any secondary waste, water, or electricity impacts from these controls. A one per cent energy savings from small units and units burning natural gas, refinery gas, or other on-spec gaseo us fuels are included in the energy savings estimate in Table 5-1 since these units are expecte d to conduct a tune-up. The methodology used to assign baseline emission factors to n ew 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 fo r every unit expected to install a scrubber to meet the HCl limits in the promulgated rule. B oth the water and wastewater calculations required the use of several constants and var iables. The constants including the density of gas, moles of salt needed per mole of hydrogen chlo ride 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 sour ces for these constants are provided in
another memorandum. 2 The variables used to estimate the quantity of water requi red and wastewater generated were calculated based on characteri stics reported for each existing unit in the 2008 survey and for the characteristics assigned to ea ch new model unit. The variables
included: exhaust flow rate from the combustion unit to the control device in actual cubic feet per minute, the inlet loading of hydrogen chloride to the cont rol device (mole fraction), and theefficiency of the control device in removing hydrogen chloride from the exhaust gas (percent

reduction). The calculations used to estimate each varia ble are provided in another
memorandum. 2 The total national water and wastewater amounts in Ta ble 5-1 were determined by adding the per unit water and wastewater estimates for a ll new and existing units, respectively.



### 5.2 Solid Waste Impacts
Solid waste is generated from collecting dust and fly ash i n fabric filters or ESP control devices, spent carbon associated with ACI, or spent caustic from increasing the caustic injection rate. Solid waste impacts were estimated for every unit expected to install a fabric filter for mercury control or a DIFF for HCl control, ACI for m ercury emission limits, or install an ESP to
meet PM emission limits. The total national solid was te amounts in Table 5-1 were determined by adding the per unit solid waste estimates for all new an d existing units, respectively. To
estimate the solid waste contribution from each of th ese control devices, the variables were calculated based on characteristics reported for each existing unit in the 2008 survey and for the characteristics assigned to each new model unit. The calc ulations used to estimate each variable and the quantity of solid waste generated are provided in ano ther memorandum. 2 The solid waste (dust, fly ash) generated by the use of an electrostatic precipitator was calculated when an electrostatic precipitator was dete rmined to be necessary to meet the
NESHAP emission limits for PM. Estimates of the sol id waste collected in an ESP was based on several variables including: exhaust flow rate from the com bustion unit to the control device (acfm); the inlet loading of particulate matter to the control device (gr/acfm); operating hours (hr/year) and the efficiency of the control device requ ired to meet the PM emission limits in the promulgated NESHAP. The solid waste generated from the collection of dust an d fly ash in a fabric filter was
calculated when a fabric filter was determined to be nec essary to meet the promulgated NESHAP emission limits for particulate matter and/or mercury . The calculation required the use of three variables, including: exhaust flow rate from the combustion u nit to the control device (dscfm); operating hours (hr/year) and the inlet loading of particu late matter to the control device (gr/acfm).For this analysis, the spent carbon collected from units with ACI is assumed to be

disposed of instead of being re-generated. The amount of spen t carbon created from ACI was calculated when ACI was expected to be necessary to mee t the promulgated NESHAP emission limits for mercury or dioxin/furan. The calculation require d the use of six variables, including:
exhaust flow rate from the combustion unit to the cont rol device (dscfm); operating hours (hr/year), required removal efficiency for mercury and dioxin/furan, and an adjustment factor based required removal efficiency of mercury or dioxin /f uran. The solid waste generated by the use of increased caustic was calculated for those units where additional caustic was expected to achieve the promu lgated NESHAP emission limits for HCl. The calculation required the use of three variable s, including: exhaust flow rate from the combustion unit to the control device (dscfm); operating h ours (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, D IFF, CO oxidation catalyst and the fans for the ductwork associated with this equipment. These impacts we re assessed for every unit that was estimated to require hydrogen chloride and/or particulate mat ter control. Electricity requirements are one output of the cost algorithms used in the analyse s, so no additional calculations were necessary. For some units, an electrical demand from mu ltiple control devices was estimated. The total national electricity demand in Table 5-1 was de termined by adding the per unit solid waste estimates for all new and existing units, respectiv ely. To estimate the electricity demand from each of these control devices, a set of variables were calculated based on characteristics reported for each existing unit in the 2008 survey and for the characteristics assigned to each new model unit. The constants, variables, and calculations used to estimate each variable and the electricity demand to operate the control devices are pro vided in another memorandum. 2



### 5.4 Greenhouse Gas Emissions from Electricity Usage Since greenhouse gases are generated from electricity produc tion, an estimate of carbon dioxide emissions was generated for the electricity impac ts of the add-on air pollution control devices. The total electricity usage from all control de vices was multiplied by the nationalaverage carbon dioxide emission factor for carbon dioxi de emissions from EPA’s 2005 e-GRID

to obtain the expected annual carbon dioxide emissions. 9 No carbon dioxide emissions were estimated for boilers or process heaters conducting a boiler tune-up since no electricity impacts
were estimated for those units.


### 5.5 Energy Savings Impacts
The energy savings from combustion controls such as low N Ox burners or linkageless boiler management systems, and work practice standards, including a tune-up, and implementing the energy audit findings with a short-term payback can im provements in efficiency, thereby reducing fuel consumption. This secondary impacts analysis only estimates a one percent efficiency gain from tune-up work practices and installat ion of combustion 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 assessment i n this analysis. Quantifying the exact gains in efficiency from each of these work practice st andards is difficult, and may depend on the baseline operating efficiency of each unit. Section 3.1 discusses the fuel savings impacts in terms of annualized cost savings to each boiler or process heater, and the national energy savi ngs presented in Table 4.1 of this section follows the same methodology as was discussed in Sectio n 3.1 and reflect the savings from boilers in the coal, gas, and liquid fuel categories only.


### 5.6 Estimating Secondary Impacts for Existing and N ew Units
Appendices C-1 and C-2 present a detailed breakdown of the secondary waste, water, and energy impacts from each subcategory of new and existing boilers and process heaters, respectively. The differences presented between the rec ommended 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 affects the amount of waste, wastewater, water, and energy consumed by the control devices installed for PM, HCl, and Hg.

## 6.0 REFERENCES

1. Singleton, A., ERG. Revised MACT Floor Analysis for t he Industrial, Commercial Institutional Boilers and Process Heaters national Em ission Standards for Hazardous Air Pollutants – Major Source. January 2011.

2. Singleton, A. and S. McClutchey, ERG. Revised Methodology for Estimating Control Costs for Industrial, Commercial, Institutiona l Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants – Major Source. January 2011.

3. Gibson, G., Singleton, A. and L. Stanulis, ERG. Revis ed New Unit Analysis for Industrial, Commercial, and Institutional Boilers and Pr ocess Heaters at Major Sources. January 2011.

4. Singleton, A. and B. Lange, ERG. Gas Specification for Industrial, Commercial, Institutional Boilers and Process Heaters National Em ission Standards for Hazardous Air Pollutants – Major Source. January 2011.

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

6. Singleton, A. and G. Gibson, ERG. Revised Development o f Baseline Emission Factors for Boilers and Process Heaters at Commercia l, Industrial, and Institutional Facilities. January 2011.

7. U.S. Department of Energy, EIA. Annual Energy Outlook 2009. Table 2. Energy Consumption by Sector and Source. http://www.eia.doe.gov/

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

9. Environmental Protection Agency. eGRID. “eGRID Year 2005 Summ ary Tables” December 2008. http://www.epa.gov/cleanenergy/documents/egridzips/eGRID2007V1_1_ year05_Su mmaryTables.pdf

10. Milmore, P. and S. Winkleman. Climate Wise Boiler an d Steam Efficiency Wise Rules: Proceedings from the Twentieth National Industry Energy Technology Conference. April 1998. Docketed in National Emission Stan dards for Hazardous Air Pollutants for Major Sources: Industrial, Commercia l, and Institutional Boilers and Process Heaters.11. DTE Energy. “Your Energy Savings Business 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 Pr ocess Heaters.

12. U.S. Department of Energy. Energy Assessment Helps K aiser Aluminum Save Energy and Improve Productivity. DOE/GO-102008-2561. July 2008. Docketed in National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Pr ocess Heaters.

13. Sathyanathan, V. T., Ph.D. Running a Coal Fired Boiler at the Best Efficiency. April 2010. Docketed in National Emission Standards for Hazardous A ir Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters.

14. CenterPoint Energy. Energy Efficiency Checklist (Minne sota). Previously available on-line at http://centerpointenergy.com/ . Docketed in National Emission Standards for Hazardous Air Pollutants for Major Sources: Industria l, Commercial, and Institutional Boilers and Process Heaters.

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16. Eckerlin, H.M., Ph.D., and E.W. Soderberg, Industrial Exte nsion Service. USI Boiler Efficiency Program. A Report Summarizing the Findings and R ecommendations of an Evaluation of Boilers in State-Owned Facilities. F ebruary 2004. http://www.energync.net/programs/docs/usi/om/boilers/ss r.pdf

17. Wright, A. and M. Martin, Oak Ridge National Laboratory, and B. Gemmer, P. Scheihing, and J. Quinn, DOE Industrial Technologies Progra m. Results from the U.S. DOE 2006 Save Energy Now Assessment Initiative: D OE’s Partnership with U.S. Industry to Reduce Energy Consumption, Energy Costs , and Carbon Dioxide Emissions, Detailed Assessment Opportunity Data Report. O RNL/TM-2007/138. September, 2007.

18. Wright, A., M. Martin, and S. Nimbalkar, Oak Ridge Natio nal Laboratory, and J. Quinn, S. Glatt, and B. Orthwein, DOE Industrial Technol ogies Program. Results from the U.S. DOE 2007 Save Energy Now Assessment Init iative: DOE’s Partnership with U.S. Industry to Reduce Energy Consumption , Energy Costs, and Carbon Dioxide Emissions, Detailed Assessment Opportunity D ata Report. ORNL/TM-2009/074. April 2009.

19. Wright, A., M. Martin, and S. Nimbalkar, Oak Ridge Natio nal Laboratory, and J. Quinn, S. Glatt, and B. Orthwein, DOE Industrial Technol ogies Program. Resultsfrom the U.S. DOE 2008 Save Energy Now Assessment Init iative: DOE’s

Partnership with U.S. Industry to Reduce Energy Consumption , Energy Costs, and Carbon Dioxide Emissions, Detailed Assessment Opportunity D ata Report. ORNL/TM-2010/146. July 2010.

20. Ed’s Heating and Air, Inc. 1099 Pelto Path Woodbury, MN, 55129. http://www.merchantcircle.com/blogs/Eds.Heating.And.Air. Inc..Woodbury.MN.651 -775-7490/2008/10/Furnace-Tune-Up-Cost/126531

21. Five State Heating and Cooling, Charlotte, NC. http://www.fivestarheatingandcooling.com/