0226.04.020 1

MEMORANDUM 

TO: Jim Eddinger, U.S. Environmental Protection Agency, OAQPS (C439-01) 

FROM: Graham Gibson, ERG 

DATE: April 2010 

SUBJECT: New Unit Analysis Industrial, Commercial, and Institutional Boilers and Process 

Heaters National Emission Standards for Hazardous Air Pollutants – Major 

Source 

1.0 INTRODUCTION 

This memorandum describes the estimation of new major source boilers and process 

heaters projected to be built by 2013 and 2015 from the baseline year of 2008. The results of 

this analysis are used to estimate costs and impacts for new sources for a national emission 

standard for hazardous air pollutants (NESHAP) for industrial/commercial/institutional boilers 

and process heaters. The years 2013 and 2015 were selected because they are five years from 

the expected proposal and promulgation dates of the boiler NESHAP. 

This memorandum is separated into the following sections: 

1.0 Introduction 

2.0 Data Sources 

3.0 Methodology for Estimating New Units 

4.0 Results 

5.0 References 

Appendix A – Distribution of Model Units between Industrial and Commercial Sectors 
0226.04.020 2

2.0 DATA SOURCES

The existing units reported in the 2008 Combustion Survey were subcategorized into 

model units in order to project future units1. Units were subcategorized based on fuel, size 

category, and whether the facility is in the commercial or industrial sector. Specific fuels were 

categorized into one of the following categories: Coal, Bagasse, Wet Biomass, Dry Biomass, 

Heavy (Residual) Liquid, Light (Distillate) Liquid, Process Gas (Gas 2), Natural Gas and Other 

Non-Process Gases (Gas 1), Other Fuels, and Waste. The development of these fuel categories 

and the individual fuels they characterize are detailed in another memorandum2. For the purpose 

of this analysis the Biomass fuel category includes Bagasse, Wet Biomass, and Dry Biomass. It 

was assumed that all new boilers and process heaters designed to burn non-process gases would 

only burn natural gas and no other fuels associated with the Natural Gas and Other Non-Process 

Gases fuel category. To assign each facility to either the commercial or industrial sector, we 

used the three digit NAICS code that was reported for the facility in the 2008 Combustion 

Survey. Then, an average design capacity and annual hours of operation were calculated based 

on all the units within each group in order to obtain general operational estimates for each 

model. The energy consumption forecasts were provided by the Energy Information 

Administration (EIA) of the U.S. Department of Energy3

. The EIA provides forecasts of the fuel 

consumption of coal, renewable energy (including biomass), residual oil, distillate oil, and 

natural gas according to sector and source. 

3.0 METHODOLOGY FOR ESTIMATING NEW UNITS

The methodology involved in this analysis was consistent with a previous analysis 

completed for the 2004 vacated boiler NESHAP and consists of two parts: 1) Calculating the 

predicted percent changes in fuel consumption in the industrial and commercial/institutional 

sectors, and 2) Calculating the expected fuel consumption in future in boilers and heaters and 

predicting the number of new units required to fire a particular fuel4

. Since the 2008 

Combustion survey represents the inventory of affected boilers and process heaters, the base year 

for this analysis is 2008. The steps required to perform this analysis are described below. 
0226.04.020 3

3.1 Calculating Percent Change in Fuel Consumption 

Existing boilers and process heaters were grouped into one of the following fuel types: 

coal, biomass, residual liquid, distillate liquid, process gas, and natural gas. Projected fuel 

consumption by the industrial and commercial sectors for each of these fuels for 2013 and 2015 

could then be used to calculate percent differences in fuel consumption2. The EIA fuel 

consumption projections, along with calculated percent differences for 2013 and 2015, are given 

in Table 3-1. These calculations were performed as follows: 

 

 EIA data was gathered for industrial and commercial fuel use in 2008, 2013, and 2015 in 

the following fuel categories: coal (all, including Coke), residual liquids, distillate 

liquids, natural gas and renewable energy. The renewable energy definition at the EIA 

includes consumption of energy produced from hydroelectric, wood and wood waste, and 

other biomass sources, excluding ethanol blends. Renewable energy was used to project 

the future rate of increase in biomass fuels since biomass is assumed to follow the same 

growth rates of other renewable resources. Biomass energy consumption was not 

available as a distinct fuel consumption category within the EIA fuel consumption 

projections by sector data. 

 Equation 1 was applied to the EIA data to calculate the percent change from 2008 to the 

target years. 

o PCTY = 100 * (EIATY – EIA2008) / EIA2008 Equation 1

o Where: 

o PCTY = Percent change in consumption of fuel for target year (2013 or 2015) 

o EIATY = Consumption of fuel from EIA data for the target year (2013 or 2015) 

o EIA2008= Consumption of fuel from EIA data for 2008 

EIA fuel consumption data was not available for process gases, so it was assumed that 

the natural gas fuel consumption projections applied to all gaseous fuels. Fuels with negative 

percent changes were assumed to have no new units projected to come on-line by the end of 

target years 2013 or 2015. 

 
0226.04.020 4

Table 3-1. Expected Fuel Consumption Differences by Sector3

Industrial Sector Fuel Consumption (Quadrillion Btu per year) Percent Difference from 2008 

Fuel 2008 2013 2015 2013 2015 

Natural Gas 6.83 6.76 6.62 -1.2% -3.1% 

Coal 1.84 1.71 1.80 -7.2% -2.2% 

Residual oil 0.22 0.16 0.16 -23.4% -25.9% 

Distillate oil 1.20 1.22 1.19 1.7% -0.8% 

Biomass* 1.66 1.57 1.56 -5.9% -6.0% 

Commercial Sector Fuel Consumption (Quadrillion Btu per year) Percent Difference from 2008 

Fuel 2008 2013 2015 2013 2015 

Natural Gas 3.22 3.25 3.29 0.8% 2.1% 

Coal 0.07 0.06 0.06 -2.0% -2.0% 

Residual oil 0.07 0.08 0.08 19.1% 24.0% 

Distillate oil 0.38 0.36 0.35 -5.1% -8.9% 

Biomass* 0.12 0.12 0.12 0.0% 0.0% 

*Based on renewable energy fuel consumption. 

3.2 Fuel Consumption and New Boiler Forecasting 

To predict the number of new boilers and process heaters in operation by 2013 and 2015, 

the percent difference for each fuel calculated in Table 3-1 was applied to the fuel consumption 

represented by the generated models in the industrial and commercial sectors. This was done 

using the following steps: 
0226.04.020 5

 First, all existing boilers were determined to be at a commercial or industrial facility. 

This classification was based on the reported North American Industry Classification 

System (NAICS) code for the facility. Existing major source boilers and process heaters 

were subcategorized into model groups by sector, fuel, and size classification. Size 

classifications were based on the reported design capacity of the combustion unit. 

Categories were generated for the following sizes, based on the various size thresholds 

that would be expected to affect compliance requirements. For example, units greater 

than 100 million Btu per hour (MMBtu/hr) are required to install continuous emissions 

monitors for CO, and units greater than 250 MMBtu/hr are required to install continuous 

emission monitors for PM. The following size thresholds were used to develop model 

units: 

o Less than 10 MMBtu/hr 

o Greater than or equal to 10 to 100 MMBtu/hr 

o Greater than 100 to 250 MMBtu/hr 

o Greater than 250 MMBtu/hr 

 Next, the annual fuel consumption from 2008 (MMBtu/yr) was calculated for each model 

group using Equation 2. 

FC2008 = DCavg * Ophours,avg * Ni Equation 2

Where: 

FC2008 = Fuel consumption in 2008, MMBtu/yr 

DCavg = Average design capacity for all units in model subcategory, MMBtu/hr 

Ophours,avg = Average annual hours of operation for all units in model subcategory 

Ni = Number of existing units in model subcategory 

The fuel consumption values calculated for the model units in this step were then used as 

the 2008 basis for new unit predictions. 

 Forecasts of annual fuel consumption for each subcategory were calculated for the target 

years (2013 or 2015) by applying the percent differences calculated in Table 3-1 to the 

2008 fuel consumption calculated above using Equation 3. 

FCTY = FC2008 * [1 + (PCTY / 100)] Equation 3

Where: 

FCTY = Projected fuel consumption in target year (2013 or 2015), MMBtu/yr 

FC2008 = Fuel consumption in 2008, MMBtu/yr 

PCTY = Percent change in consumption of fuel for target year (2013 or 2015) 
0226.04.020 6

 The number of units in the target year (2013 or 2015) was calculated using Equation 4. 

NTY = [ (FCTY - FC2008) / DCavg ] / Ophours,avg Equation 4 

Where: 

NTY = Projected number of units in the target year (2013 or 2015) 

FCTY = Projected fuel consumption in target year (2013 or 2015), MMBtu/yr 

FC2008 = Fuel consumption in 2008, MMBtu/yr 

DCavg = Average design capacity for all units in model subcategory, MMBtu/hr 

Ophours,avg = Average annual hours of operation for all units in model subcategory, hr/yr 

Values were rounded up to the nearest integer because it was assumed that fractions of 

units would equate to a new unit operating at a fraction of the design capacity. If the resultant 

value was negative, it was assumed no new units for that subcategory would be in operation in 

the target year. 

4.0 RESULTS

The results of the new boiler analysis by model and year for the industrial and 

commercial sectors are presented in Appendices A-1 and A-2, respectively. The combined total 

number of new boilers for 2013 is expected to be 46. Likewise, the total number of new 

industrial, commercial, and institutional boilers for 2015 is 86. The majority of all new boilers 

and process heaters are expected to be gas-fired, which is true for both target years. No new coal 

or biomass fired boilers are projected to come online by 2015.
0226.04.020 7

5.0 REFERENCES

1. Survey Database containing Results of the 2008 Questionnaire for Boilers, Process 

Heaters, & Other Combustion Units (ICR No. 2286.01). 

2. Amanda Singleton and Graham Gibson, ERG. Memorandum to Jim Eddinger, U.S. 

Environmental Protection Agency, OAQPS. Development of Baseline Emission Factors 

for Boilers and Process Heaters at Commercial, Industrial, and Institutional Facilities. 

April, 2010.

3. U.S. Department of Energy. Energy Information Administration. Annual Energy 

Outlook 2009. Table 2. Energy Consumption by Sector and Source. Available on-line 

at: http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html 

4. Jason Huckaby, ERG. Memorandum to Jim Eddinger, U.S. Environmental Protection 

Agency, OAQPS. New Unit Analysis for Industrial, Commercial, and Institutional 

Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants.

 October, 2002.
Appendix A-1: Calculation of Projected Number of New Industrial Boilers and Process Heaters in 2013 and 2015

Annual Energy 

Consumption 

(MMBtu/yr)

Number of 

Existing Units

Projected 

Annual Energy 

Consumption 

(MMBtu/yr)

Estimated 

Number of New 

Units

IndBagasseBlr1 Industrial Biomass 3,903 229.0 >100 to 250 8.94E+05 1 8.41E+05 - 

IndBagasseBlr2 Industrial Biomass 4,668 478.9 >250 3.35E+07 15 3.16E+07 - 

IndCoalBlr2 Industrial Coal 5,946 68.4 10 to 100 3.82E+07 94 3.55E+07 - 

IndCoalBlr3 Industrial Coal 6,753 187.6 >100 to 250 2.71E+08 214 2.52E+08 - 

IndCoalBlr4 Industrial Coal 7,721 545.3 >250 7.37E+08 175 6.83E+08 - 

IndDryBmassBlr1 Industrial Biomass 7,319 3.8 <10 3.63E+05 13 3.42E+05 - 

IndDryBmassBlr2 Industrial Biomass 7,187 47.3 10 to 100 4.82E+07 142 4.54E+07 - 

IndDryBmassBlr3 Industrial Biomass 7,646 166.5 >100 to 250 6.11E+07 48 5.75E+07 - 

IndDryBmassBlr4 Industrial Biomass 8,421 491.5 >250 1.24E+08 30 1.17E+08 - 

IndGas1Blr1 Industrial Natural Gas 8,196 5.1 <10 1.67E+08 4,011 1.65E+08 - 

IndGas1Blr2 Industrial Natural Gas 6,955 43.7 10 to 100 8.35E+08 2,748 8.25E+08 - 

IndGas1Blr3 Industrial Natural Gas 6,855 167.8 >100 to 250 9.31E+08 809 9.20E+08 - 

IndGas1Blr4 Industrial Natural Gas 7,695 423.6 >250 1.21E+09 370 1.19E+09 - 

IndGas2Blr1 Industrial Process Gas 4,469 8.1 <10 3.64E+04 1 3.60E+04 - 

IndGas2Blr2 Industrial Process Gas 6,650 45.5 10 to 100 2.03E+07 67 2.00E+07 - 

IndGas2Blr3 Industrial Process Gas 7,202 177.7 >100 to 250 6.14E+07 48 6.07E+07 - 

IndGas2Blr4 Industrial Process Gas 8,094 434.4 >250 2.50E+08 71 2.47E+08 - 

IndHvyLiqBlr1 Industrial Residual Liquid 5,133 5.3 <10 8.21E+04 3 6.29E+04 - 

IndHvyLiqBlr2 Industrial Residual Liquid 6,325 49.3 10 to 100 4.21E+07 135 3.23E+07 - 

IndHvyLiqBlr3 Industrial Residual Liquid 5,296 174.1 >100 to 250 7.01E+07 76 5.37E+07 - 

IndHvyLiqBlr4 Industrial Residual Liquid 5,367 629.4 >250 1.45E+08 43 1.11E+08 - 

IndLtLiqBlr1 Industrial Distillate Liquid 4,554 4.3 <10 8.83E+05 45 8.98E+05 1 

IndLtLiqBlr2 Industrial Distillate Liquid 4,864 45.4 10 to 100 2.83E+07 128 2.88E+07 3 

IndLtLiqBlr3 Industrial Distillate Liquid 3,578 177.7 >100 to 250 3.88E+07 61 3.94E+07 2 

IndLtLiqBlr4 Industrial Distillate Liquid 5,246 430.5 >250 6.77E+07 30 6.89E+07 1 

IndWetBmassBlr1 Industrial Biomass 6,486 4.4 <10 1.14E+05 4 1.07E+05 - 

IndWetBmassBlr2 Industrial Biomass 8,205 53.3 10 to 100 3.24E+07 74 3.05E+07 - 

IndWetBmassBlr3 Industrial Biomass 7,829 186.6 >100 to 250 4.68E+07 32 4.40E+07 - 

IndWetBmassBlr4 Industrial Biomass 8,218 585.9 >250 2.99E+08 62 2.81E+08 - 

Total 5.56E+09 9,550 5.34E+09 7 

2008 2013 

Model Indentifier Sector

Standard Fuel 

Category

Average 

Annual 

Operation 

Hours

Average Design 

Capacity 

(mmBtu/hr)

Design Capacity 

Size Category 

(mmBtu/hr)

Page 1 of 2
Appendix A-2: Calculation of Projected Number of New Commercial Boilers and Process Heaters in 2013 and 2015

Annual Energy 

Consumption 

(MMBtu/yr)

Number of 

Existing Units

Projected 

Annual Energy 

Consumption 

(MMBtu/yr)

Estimated 

Number of New 

Units

ComCoalBlr1 Commercial Coal 5,162 79.0 10 to 100 1.26E+07 31 1.24E+07 - 

ComCoalBlr2 Commercial Coal 5,994 163.7 >100 to 250 4.51E+07 46 4.42E+07 - 

ComCoalBlr3 Commercial Coal 7,832 439.0 >250 6.19E+07 18 6.07E+07 - 

ComGas1Blr1 Commercial Natural Gas 7,910 4.9 <10 1.21E+08 3,131 1.22E+08 27 ComGas1Blr2 Commercial Natural Gas 5,064 34.7 10 to 100 6.51E+07 371 6.57E+07 4 

ComGas1Blr3 Commercial Natural Gas 4,291 158.0 >100 to 250 5.49E+07 81 5.54E+07 1 

ComGas1Blr4 Commercial Natural Gas 1,732 318.2 >250 4.96E+06 9 5.00E+06 1 

ComGas2Blr1 Commercial Process Gas 7,591 37.8 10 to 100 2.58E+06 9 2.60E+06 1 

ComGas2Blr2 Commercial Process Gas 5,334 146.3 >100 to 250 2.34E+06 3 2.36E+06 1 

ComHvyLiqBlr1 Commercial Residual Liquid 500 6.0 <10 3.00E+03 1 3.57E+03 1 

ComHvyLiqBlr2 Commercial Residual Liquid 4,736 51.3 10 to 100 2.43E+06 10 2.89E+06 2 

ComHvyLiqBlr3 Commercial Residual Liquid 2,980 196.0 >100 to 250 2.92E+06 5 3.48E+06 1 

ComLtLiqBlr1 Commercial Distillate Liquid 5,145 2.3 <10 2.37E+06 196 2.25E+06 - 

ComLtLiqBlr2 Commercial Distillate Liquid 5,132 37.1 10 to 100 1.46E+07 77 1.39E+07 - 

ComLtLiqBlr3 Commercial Distillate Liquid 5,150 184.2 >100 to 250 1.23E+07 13 1.17E+07 - 

ComLtLiqBlr4 Commercial Distillate Liquid 4,652 776.4 >250 1.08E+07 3 1.03E+07 - 

ComBmassBlr1 Commercial Biomass 8,760 60.0 10 to 100 5.26E+05 1 5.26E+05 - 

Total 4.16E+08 4,005 4.15E+08 39 

2008 2013 

Model Indentifier Sector

Standard Fuel 

Category

Average 

Annual 

Operation 

Hours

Average Design 

Capacity 

(mmBtu/hr)

Design Capacity 

Size Category 

(mmBtu/hr)

Page 2 of 2