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MEMORANDUM

TO:    Brian Shrager/SPPD

FROM:   Eastern Research Group, Inc.

DATE:    November 2011

SUBJECT: Revised 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 2015 from the baseline year of 2008.  The results of this

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

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

and process heaters at major sources of hazardous air pollutants.  The year 2015 was selected

because it is three years from the projected promulgation date of the boiler NESHAP

reconsideration.

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
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2.0 DATA SOURCES

The existing units reported in the 2008 Combustion Survey as well as additional units

added to the inventory as part of the reconsideration process were subcategorized into model

units in order to project future units1,2.  Units were classified based on fuel, size category, and

whether the facility is in the commercial/institutional or industrial sector.  Specific fuels were

categorized into one of the following categories:  Coal, Bagasse, Biomass (other than bagasse),

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

Other on‐spec Gases (Gas 1), and Metal Furnaces burning Natural Gas.  The development of

these fuel categories and the individual fuels they characterize are detailed in another

memorandum3

.  For the purpose of this analysis the Biomass fuel category includes Wet

Biomass (other than bagasse) and Dry Biomass.  It was assumed that all new boilers and process

heaters designed to burn gas 1 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/institutional or industrial sector, we used the three digit NAICS code that was

reported for the facility in the 2008 Combustion Survey or follow‐up data submittals.  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 Energy4

.  The 2011 Annual Energy Outlook (AEO) published by 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 through the year 2015 and beyond.

EIA divides energy use up into commercial, industrial, residential and transportation. The EIA

commercial sector includes units considered to be in the institutional sector for this rulemaking.

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 the 2010 proposal and 2011 final rule and it

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 future fuel
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consumption in boilers and process heaters and predicting the number of new units required to

fire a particular fuel5.  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.

3.1 Calculating Percent Change in Fuel Consumption

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

coal, bagasse, other 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

2015 could then be used to calculate percent differences in fuel consumption4.  The EIA fuel

consumption projections, along with calculated percent differences for 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 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 growth rates were used

as a proxy for projection of the future rate of increase in biomass fuels since biomass is

assumed to follow the same growth rates of other renewable resources.   

 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 (2015)

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

o EIA2008= Consumption of fuel from EIA data for 2008

EIA fuel consumption data were not available for process gases.  Since the definition of

process gas is exclusive to only a few specific types of gaseous fuel which are not specifically

mentioned by EIA, the natural gas consumption trends were not used to project new process

gas‐fired boilers.  EIA fuel consumption data for renewable energy were used to project new

biomass‐fired units.  However, renewable energy fuel consumption data were not used to

project new bagasse‐fired units.  The EIA does not specifically mention bagasse consumption,
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and there is only a limited amount of sugar cane being grown in the United States; it is not

expected that the sugar cane industry will experience the same growth rate as the forest

products and other biomass industries.  Natural gas consumption data were used to project

new metallurgical furnaces since natural gas is the only fuel combusted by these types of units.

Fuels with negative percent changes were assumed to have no new units projected to come

on‐line by the end of target year 2015.

Table 3‐1.  Expected Fuel Consumption Differences by Sector4

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

Fuel 2008 2015 2015

Natural Gas 6.83 8.27 21.1%

Coal 1.78 1.67  ‐6.2%

Residual oil 0.20 0.17  ‐15.0%

Distillate oil 1.27 1.16  ‐8.7%

Biomass* 1.52 1.89 24.3%

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

Fuel 2008 2015 2015

Natural Gas 3.22 3.47 7.8%

Coal 0.07 0.06  ‐14.3%

Residual oil 0.07 0.06  ‐14.3%

Distillate oil 0.37 0.28  ‐24.3%

Biomass* 0.11 0.11 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 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:

 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.  Only
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those existing units that combust 100 percent of their respective fuel category were

selected to represent a model unit since it is difficult to establish a baseline in fuel

consumption from co‐fired units.  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 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 5 MMBtu/hr

o Greater than or equal to 5 to less than 10 MMBtu/hr

o Greater than or equal to 10 to 30 MMBtu/hr

o Greater than 30 to less than 100 MMBtu/hr

o Greater than or equal to 100 to 250 MMBtu/hr

o Greater than 250 MMBtu/hr

These size thresholds were selected to be consistent with size cutoffs in the New Source

Performance Standards (NSPS) for Industrial/Commercial/Institutional boilers (40 CFR

part 60 subparts Db and Dc) in order to consider variations in compliance costs for new

units that may be subject to both this rule and the NSPS.

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

model group using Equation 2.

FC2008 = CF * DCavg * Ophours,avg * Ni Equation 2

Where:

FC2008 = Fuel consumption in 2008, MMBtu/yr

CF = Assumed capacity factor, 90%

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 year (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 (2015), MMBtu/yr

FC2008 = Fuel consumption in 2008, MMBtu/yr
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PCTY = Percent change in consumption of fuel for target year (2015)

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

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

Where:

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

FCTY = Projected fuel consumption in target year (), 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 2015 is estimated to be 1,844.  The majority of all new boilers and

process heaters are expected to be gas‐fired.  No new coal‐ or liquid‐fired boilers are projected

to come online by 2015.  However, there are 82 new biomass‐fired boilers expected to be

constructed by 2015.

4.1 Changes since Final Rule

For the final rule, the 2009 version of the EIA’s Annual Energy Outlook (AEO) was used

to project energy consumption in 2013 and 20156

.  In this revised analysis, the 2011 version of

the AEO was used because the newer version is now publicly available and represents a more

accurate projection of energy usage based on recent market trends and regulations that affect

fuel usage.  The updated projections of energy usage resulted in the total number of projected

new boilers to be much higher than the projections for the final rule.  Table 4‐1 provides a

comparison of the industrial and commercial fuel consumption projections for 2015 from both
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the 2009 and 2011 AEO versions.  It also provides a comparison of the percent changes from

2008 to 2015 based on the different AEO versions.

Table 4‐1.  Comparison of 2015 Energy Consumption Projections by AEO Version4, 6

Industrial Sector Fuel Consumption in 2015 (Quadrillion Btu per year) Percent Difference from 2008

Fuel 2009 AEO 2011 AEO 2009 AEO 2011 AEO

Natural Gas 6.62 8.27 ‐3.1% 21.1%

Coal 1.80 1.67  ‐2.2%  ‐6.2%

Residual oil 0.16 0.17  ‐25.9%  ‐15.0%

Distillate oil 1.19 1.16  ‐0.8%  ‐8.7%

Biomass* 1.56 1.89 ‐6.0% 24.3%

Commercial Sector Fuel Consumption in 2015 (Quadrillion Btu per year) Percent Difference from 2008

Fuel 2009 AEO 2011 AEO 2009 AEO 2011 AEO

Natural Gas 3.29 3.47 2.1% 7.8%

Coal 0.06 0.06  ‐2.0%  ‐14.3%

Residual oil 0.08 0.06 24.0% ‐14.3%

Distillate oil 0.35 0.28  ‐8.9%  ‐24.3%

Biomass* 0.12 0.11 0.0% 0.0%

*Based on renewable energy fuel consumption.

For the final rule, no new boilers were projected to be constructed by 2015 in the

industrial sector.  However, the 2011 AEO projects industrial growth in both natural gas and

biomass consumption.  In contrast, the 2009 AEO projected a reduction in energy consumption

across all fuel categories.  The following excerpt from page 68 of the 2011 AEO discusses this

change in projected biomass consumption in the industrial sector:

“The renewable fuel share [of industrial energy consumption] expands with growth in

lumber, paper, and other industries that consume biomass‐based byproducts.”  (2011 AEO, p.

68)
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Industrial growth in natural gas consumption has also increased compared to the 2009

AEO.  The following excerpt, also from page 68 of the 2011 AEO, discusses the industrial growth

in natural gas consumption.  The excerpt also provides legitimacy to the projection of new

metallurgical furnaces.

“Natural gas use in the industrial sector grows by 27 percent from 2009 to 2035,

reflecting the recovery in industrial output and relatively low natural gas prices, which spur a

large increase in natural gas consumption for CHP generation that offsets a decline in natural

gas use for feedstock.  [...]  Metallurgical coal use drops, based on an expected decline in

smelting and increased use of electric arc furnaces in steel‐making.”  (2011 AEO, p. 68)

The final rule projected six new liquid‐fired boilers would come online by the year 2015.

This was predicated by positive growth for residual liquid fuel use in the commercial sector.  In

the 2011 AEO, residual oil fuel consumption is expected to decrease by 2015.  As a result, there

are no new liquid‐fired units projected to come online by the year 2015.  The projected

consumption of residual oil in 2015 provided by both the 2009 and 2011 AEOs are identical.  

However, the 2011 AEO provides a corrected higher amount of residual oil consumed in the

base year of 2008 which results in a net decrease in projected residual oil use by 2015.
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5.0    REFERENCES

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

Heaters, & Other Combustion Units (ICR No. 2286.01) (version 3).

2. Eastern Research Group, Inc.  Revised Handling and Processing of Corrections and New

Data in the EPA ICR Databases.  November, 2011.

3. Eastern Research Group, Inc.  Revised Development of Baseline Emission Factors for

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

November, 2011.

4. U.S. Department of Energy.  Energy Information Administration.  Annual Energy Outlook

2011. Table A2. Energy Consumption by Sector and Source. Available on‐line at:

http://www.eia.gov/forecasts/aeo/pdf/0383(2011).pdf

5. Jason Huckaby, ERG.  New Unit Analysis for Industrial, Commercial, and Institutional

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

October, 2002.

6. 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
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Appendix A

Distribution of Model Boiler Units between Industrial and Commercial Sectors

(See Excel spreadsheet)