Supplementary Information for

Four-Factor Analyses

for Selected Individual Facilities in Wyoming

May 6, 2009

Revised Draft Report

Prepared by:

William Battye

Janet Hou

Brad Nelson

EC/R Incorporated

501 Eastowne Drive, Suite 250

Chapel Hill, North Carolina 27514

Prepared for:

Lee Gribovicz, Project Manager

Western Regional Air Partnership (WRAP) and

Western Governors’ Association (WGA)

1600 Broadway, Suite 1700

Denver, Colorado 80202
Scope of Document

This document provides an initial analysis of the four factors which must be 

considered in establishing a reasonable progress goal toward achieving natural 

visibility conditions in mandatory Class I areas. These factors were examined for 

several candidate control measures for priority pollutants and emission sources. 

The results of this report are intended to inform policymakers in setting 

reasonable progress goals for the Class I areas in the Western Regional Air 

Partnership (WRAP) region. 

This document does not address policy issues, set reasonable progress goals, or 

recommend a long-term strategy for regional haze. Separate documents will be 

prepared by the States which address the reasonable progress goals, each state's 

share of emission reductions, and coordinated emission control strategies. 

Disclaimer

The analysis described in this document has been funded by the Western 

Governors’ Association. It has been subject to review by the WGA and the 

WRAP. However, the report does not necessarily reflect the views of the 

sponsoring and participating organizations, and no official endorsement should be 

inferred.
iii

Contents

1. Introduction ...........................................................................................................................................................1-1

2. Methodology..........................................................................................................................................................2-1

2.1 Factor 1 – Costs............................................................................................................................................2-1

2.2 Factor 2 – Time Necessary for Compliance .................................................................................................2-2

2.3 Factor 3 – Energy and Other Impacts...........................................................................................................2-2

2.4 Factor 4 – Remaining Equipment Life .........................................................................................................2-3

2.5 References for Section 2...............................................................................................................................2-4

3. Boilers....................................................................................................................................................................3-1

3.1 Factor 1 – Costs............................................................................................................................................3-2

3.2 Factor 2 – Time Necessary for Compliance .................................................................................................3-2

3.3 Factor 3 – Energy and Other Impacts...........................................................................................................3-3

3.4 Factor 4 – Remaining Equipment Life .........................................................................................................3-3

3.5 References for Section 3...............................................................................................................................3-5

4. Cement Manufacturing ..........................................................................................................................................4-1

4.1 Factor 1 – Costs............................................................................................................................................4-4

4.2 Factor 2 – Time Necessary for Compliance .................................................................................................4-4

4.3 Factor 3 – Energy and Other Impacts...........................................................................................................4-4

4.4 Factor 4 – Remaining Equipment Life .........................................................................................................4-5

4.5 References for Section 4...............................................................................................................................4-8
iv

Abbreviations

BART Best Available Retrofit Technology

EC Elemental Carbon

EDMS Emissions Data Management System

EPA Environmental Protection Agency 

ESP Electrostatic Precipitator

ICAC Institute of Clean Air Companies

LNB Low-NOx Burners

MRPO Midwest Regional Planning Organization

MW Megawatt

NACAA National Association of Clean Air Agencies

NEI National Emissions Inventory

NOx Nitrogen Oxides

OC Organic Carbon

OFA Overfire Air

PM Particulate Matter

PM10 Particulate Matter Particles of 10 Micrometers or Less

PM2.5 Particulate Matter Particles of 2.5 Micrometers or Less

SCR Selective Catalytic Reduction

SNCR Selective Noncatalytic Reduction

SO2 Sulfur Dioxide

WRAP Western Regional Air Partnership
1-1

1. Introduction

The Regional Haze Rule requires States to set reasonable progress goals toward meeting 

a national goal of natural visibility conditions in Class I areas by the year 2064. The first 

reasonable progress goals will be established for the planning period 2008 to 2018. The Western 

Regional Air Partnership (WRAP), along with its member states, tribal governments, and federal 

agencies, are working to address visibility impairment due to regional haze in Class I areas. The 

Regional Haze Rule identifies four factors which should be considered in evaluating potential 

emission control measures to meet visibility goals. These are as follows:

1. Cost of compliance

2. Time necessary for compliance

3. Energy and non-air quality environmental impacts of compliance

4. Remaining useful life of any existing source subject to such requirements

This report has been prepared as part of a project to evaluate the above factors for 

possible control strategies intended to improve visibility in the WRAP region. We have 

identified control measures for emissions of nitrogen oxides (NOX), which can react in the 

atmosphere to produce visibility-obscuring particulate matter (PM) on a regional scale, and also 

for direct emissions of particulate matter. By request from the Wyoming state representative, 

SO2 has not been analyzed as SO2 emissions have been addressed through the back stop trading 

program. For direct particulate matter emissions, we have evaluated the impacts of control 

measures on various particulate matter components, including PM2.5, PM10, elemental carbon 

(EC) particulate matter, and organic carbon (OC) particulate matter. A number of emission 

source categories have been addressed, including:

1. Reciprocating internal combustion engines and turbines

2. Oil and natural gas exploration and production field operations

3. Natural gas processing plants

4. Industrial boilers

5. Cement manufacturing plants

6. Sulfuric acid manufacturing plants

7. Pulp and paper plant lime kilns

8. Petroleum refinery process heaters

The four-factor analyses for these emission categories are documented in a separate report, 

entitled “Assessing Reasonable Progress for Regional Haze in the WRAP Region – Source 

Category Analysis.” 
1-2

The current report presents the results of a four-factor analysis of potential control 

measures for selected emission sources and includes two electric generating units and one 

cement kiln in Wyoming. The emission sources addressed in this current report were selected by 

the Wyoming Department of Environmental Quality. Section 2 discusses the methodology 

employed in these analyses. Section 3 presents the results of the four-factor analysis for 

emission sources from boilers and Section 4 presents the results of the four-factor analysis for 

emission sources from the kiln at the cement manufacturing plant. 
2-1

2. Methodology

The first step in the technical evaluation of control measures for a source category was to 

identify the major sources of emissions from the category. Emissions assessments were initially 

based on 2002 emissions inventory in the WRAP Emissions Data Management System

(EDMS),

1 which consists of data submitted by the WRAP states in 2004. The states then 

reviewed the emissions data and parameters from the EDMS used for this analysis and provided 

updated data when applicable. In some cases, detailed data on PM10 and PM2.5 emissions were 

not available from the WRAP inventory. Therefore, PM10 and PM2.5 data from the U.S. 

Environmental Protection Agency’s (EPA) 2002 National Emissions Inventory (NEI) were used 

to supplement the WRAP inventory where necessary.

Once the important emission sources were identified within a given emission source 

category, a list of potential additional control technologies was compiled from a variety of 

sources, including control techniques guidelines published by the EPA, emission control cost 

models such as AirControlNET2and CUECost,

3 Best Available Retrofit Technology (BART) 

analyses, White Papers prepared by the Midwest Regional Planning Organization (MRPO),

4

and 

a menu of control options developed by the National Association of Clean Air Agencies 

(NACAA).5The options for each source category were then narrowed to a set of technologies 

that would achieve the emission reduction target under consideration. The following sections 

discuss the methodology used to analyze each of the regional haze factors for the selected 

technologies.

2.1 Factor 1 – Costs

Control costs include both the capital costs associated with the purchase and installation 

of retrofit and new control systems, and the net annual costs (which are the annual reoccurring 

costs) associated with system operation. The basic components of total capital costs are direct 

capital costs, which includes purchased equipment and installation costs, and indirect capital 

expenses. Direct capital costs consist of such items as purchased equipment cost, 

instrumentation and process controls, ductwork and piping, electrical components, and structural 

and foundation costs. Labor costs associated with construction and installation are also included 

in this category. Indirect capital expenses are comprised of engineering and design costs, 

contractor fees, supervisory expenses, and startup and performance testing. Contingency costs, 

which represent such costs as construction delays, increased labor and equipment costs, and 

design modification, are an additional component of indirect capital expenses. Capital costs also 

include the cost of process modifications. Annual costs include amortized costs of capital 

investment, as well as costs of operating labor, utilities, and waste disposal. For fuel switching 

options, annual costs include the cost differential between the current fuel and the alternate fuel.
2-2

The U.S. EPA’s Guidance for Setting Reasonable Progress Goals under the Regional 

Haze Program6indicates that the four-factor analyses should conform to the methodologies 

given in the EPA Air Pollution Control Cost Manual.

7

This study draws on cost analyses which 

have followed the protocols set forth in the Cost Manual. Where possible, we have used the 

primary references for cost data. Cost estimates have been updated to 2007 dollars using the 

Marshall & Swift Equipment Cost Index or the Chemical Engineering Plant Cost Index, both of

which are published in the journal, Chemical Engineering.

For Factor 1, results of the cost analysis are expressed in terms of total cost-effectiveness, 

in dollars per ton of emissions reduced. A relevant consideration in a cost-effectiveness 

calculation is the economic condition of the industry (or individual facility if the analysis is 

performed on that basis). Even though a given cost-effectiveness value may, in general, be 

considered “acceptable,” certain industries may find such a cost to be overly burdensome. This 

is particularly true for well-established industries with low profit margins. Industries with a poor 

economic condition may not be able to install controls to the same extent as more robust 

industries. A thorough economic review of the source categories selected for the factor analysis 

is beyond the scope of this project.

2.2 Factor 2 – Time Necessary for Compliance

For Factor 2, we evaluated the amount of time needed for full implementation of the 

different control strategies. The time for compliance was defined to include the time needed to 

develop and implement the regulations, as well as the time needed to install the necessary control 

equipment. The time required to install a retrofit control device includes time for capital 

procurement, device design, fabrication, and installation. The Factor 2 analysis also included the 

time required for staging the installation of multiple control devices at a given facility.

2.3 Factor 3 – Energy and Other Impacts

Table 2-1 summarizes the energy and environmental impacts analyzed under Factor 3. 

We evaluated the direct energy consumption of the emission control device, solid waste 

generated and wastewater discharged.

In general, the data needed to estimate these energy and other non-air pollution impacts 

were obtained from the cost studies which were evaluated under Factor 1. These analyses 

generally quantify electricity requirements, steam requirements, increased fuel requirements, and 

other impacts as part of the analysis of annual operation and maintenance costs.

Costs of disposal of solid waste or otherwise complying with regulations associated with 

waste streams were included under the cost estimates developed under Factor 1, and were 

evaluated as to whether they could be cost-prohibitive or otherwise negatively affect the facility. 

Energy needs and non-air quality impacts of identified control technologies were aggregated to 

estimate the energy impacts for the specified industry sectors. However, indirect energy impacts 
2-3

were not considered, such as the different energy requirements to produce a given amount of coal 

versus the energy required to produce an equivalent amount of natural gas. 

Table 2-1 Summary of Energy and Environmental Impacts 

Evaluated Under Factor 3 

Energy Impacts

Electricity requirement for control equipment and associated fans

Steam required

Fuel required

Environmental Impacts

Waste generated

Wastewater generated

Impacts Not Included

Impacts of control measures on boiler efficiency

Energy required to produce lower sulfate fuels

Secondary environmental impacts to produce additional energy 

produced

2.4 Factor 4 – Remaining Equipment Life

Factor 4 accounts for the impact of the remaining equipment life on the cost of control. 

Such an impact will occur when the remaining expected life of a particular emission source is 

less than the lifetime of the pollution control device (such as a scrubber) that is being considered. 

In this case, the capital cost of the pollution control device can only be amortized for the 

remaining lifetime of the emission source. Thus, if a scrubber with a service life of 15 years is 

being evaluated for a boiler with an expected remaining life of 10 years, the shortened 

amortization schedule will increase the annual cost of the scrubber.

The ages of major pieces of equipment were determined where possible, and compared 

with the service life of pollution control equipment. The impact of a limited useful life on the 

amortization period for control equipment was then evaluated, along with the impact on 

annualized cost-effectiveness.
2-4

2.5 References for Section 2

1. WRAP (2008), Emissions Data Management System, Western Regional Air Partnership, 

Denver, CO, http://www.wrapedms.org/app_main_dashboard.asp.

2. E.H. Pechan & Associates (2005), AirControlNET, Version 4.1 - Documentation Report, 

U.S. EPA, RTP, NC, http://www.epa.gov/ttnecas1/AirControlNET.htm.

3. Coal Utility Environmental Cost (CUECost) Model Version 1.0, U.S. EPA, RTP, NC, 

http://www.epa.gov/ttn/catc/products.html.

4. MRPO (2006), Interim White Papers-- Midwest RPO Candidate Control Measures, 

Midwest Regional Planning Organization and Lake Michigan Air Directors Consortium, 

Des Plaines, IL, www.ladco.org/reports/control/white_papers/.

5. NACAA (formerly STAPPA and ALAPCO) (2006), Controlling Fine Particulate Matter

Under the Clean Air Act: A Menu of Options, National Association of Clean Air 

Agencies, www.4cleanair.org/ PM25Menu-Final.pdf.

6 EPA (2007), Guidance for Setting Reasonable Progress Goals under the Regional Haze

Program, 

http://www.epa.gov/ttncaaa1/t1/memoranda/reasonable_progress_guid071307.pdf.

7. EPA (2002), EPA Air Pollution Control Cost Manual, 6th ed., EPA/452/B-02-001, U.S. 

EPA, Office of Air Quality Planning and Standards, RTP, NC, Section 5 - SO2 and Acid 

Gas Controls, pp 1-30 through 1-42, http://www.epa.gov/ttncatc1/products.html#cccinfo.
3-1

3. Boilers

A four-factor analysis was performed on two coal-fired boilers (Units BW41 & BW42) at 

the Pacificorp Dave Johnston electric generating station. These boilers are used to produce 

steam from the combustion of sub-bituminous coal to generate electricity in a steam turbine. 

Each of the boilers is rated to be able to generate 114 megawatts (MW). Pollutant emissions 

from the boilers include: nitrogen oxides (NOX) and particulate matter (PM). The emissions of 

SO2 emissions have not been addressed in this analysis, because the emissions have already been 

addressed through a back stop trading program.

Table 3-1 summarizes the NOX emissions from each of the boilers, as well as the control 

measures used to reduce these emissions.1 The pollutant emission rates shown in Table 3-1 were 

obtained from the WRAP 2002 emission inventory.2 Emissions of elemental carbon (EC) and 

organic carbon (OC) were estimated using speciation factors from EPA’s SPECIATE database.3

The EC and OC components are estimated to comprise 0.021% and 0.012% of PM10 emissions 

from coal-fired boilers, respectively. 

Source Name Facility Name Unit ID Unit Type

Boiler Size 

(MW)

NOX Annual 

Emissions 

(tons/yr)

Annual 

Emission Date

BW41

Sub-bituminous coalfired boiler equipped 

with ESP

114 2,341.4 2002

BW42

Sub-bituminous coalfired boiler equipped 

with ESP

114 2,298.0 2002

Pacificorp Dave Johnston

Table 3-1. Emissions from Selected Boilers - Wyoming

Currently, each of the boilers is equipped with a cold-side electrostatic precipitator (ESP) 

used to reduce particulate emissions from the boiler exhaust gas. This control technology is 

comparable to other PM control options; therefore PM control options for these boilers will not 

be explored. A list of potential NOX control strategies are presented in Table 3-2. The table 

provides a range of pollutant reductions and presents the potential emission reductions from the 

baseline emissions by applying the listed control options.3,4 These control options have been 

applied to many electrical generating unit boilers in the U.S. to reduce emissions of NOX.
3-2

Facility Name Source Type

Pollutant 

controlled Control Technology

Baseline 

emissions1 

(tons/yr)

Estimated 

control 

efficiency (%)

Potential 

controlled 

emissions2 

(tons/yr)

LNB 2,341 30 - 75 1,756

LNB w/OFA 50 - 65 1,522

SNCR 30 - 75 1,756

SCR 40 - 90 2,107

LNB 2,298 30 - 75 1,724

LNB w/OFA 50 - 65 1,494

SNCR 30 - 75 1,724

SCR 40 - 90 2,068

1

 Baseline emissions obtained from 2002 EDMS database.

2

 Potential emission reductions calculated using the highest percentage in the estimated control efficiency range.

Table 3-2. Control Options for Selected Boilers - Wyoming

Dave Johnston - BW41 Sub-bituminous coalfired boiler equipped 

with ESP

N OX

Dave Johnston - BW42 Sub-bituminous coalfired boiler equipped 

with ESP

N OX

3.1 Factor 1 – Costs

Table 3-3 provides cost estimates for the emission control options which have been 

identified for each of the electrical generating unit boilers. For each option, the table gives an 

estimate of the capital cost to install the necessary equipment, and the total annual cost of 

control, including the amortized cost associated with the capital equipment cost. The capital cost 

values are expressed in terms of the cost per MW size of the boiler using EPA cost information.

5

 

The capital cost data was extrapolated to determine the capital cost for the larger sized boilers. 

The annual cost was calculated by amortizing the capital cost over 30 years at an interest rate of 

7% and multiplying that value by an O&M factor. Table 3-3 also estimates the cost 

effectiveness for each control measure, in terms of the cost per ton of emission reduction. 

Recent literature6has indicated that the cost of SCR for electric generating can vary from $150 to 

$300 per kilowatt, therefore due to this variability, the capital and annual costs for SCR are 

presented as a range. 

3.2 Factor 2 – Time Necessary for Compliance

Once a State decides to adopt a particular control strategy, up to 2 years will be needed to 

develop the necessary rules to implement the strategy. We have estimated that sources may then 

require up to a year to procure the necessary capital to purchase control equipment. The Institute 

of Clean Air Companies (ICAC) has estimated that approximately 18 months is required to 

design, fabricate, and install SCR or SNCR technology for NOX control.

7

 Additional time of up 

to 12 months may be required for staging the installation process if multiple boilers are to be 

controlled at a single facility. For a complete system, the typical deployment of LNB or LNB + 

OFA takes between 24-32 weeks (6 – 8 months) on a typical industrial boiler covering the bid 

evaluation through the startup of the technology. Based on these figures, the total time required 

to achieve emission reductions for boilers is estimated at a total of 51⁄2 years for NOX strategies.
3-3

Facility Name

Pollutant 

controlled Control Technology

Estimated 

control 

efficiency (%)

Estimated capital 

cost ($1000)

Estimated 

annual cost 

($1000/yr)

Cost 

effectiveness 

($/ton) References

LNB 51 4,030 631 528 5

LNB w/OFA 65 5,760 962 632 5

SNCR 40 4,160 2,490 2,659 5

SCR 80 17,100 - 34,200 4,298 - 8,596 2,295 - 4,589 6

LNB 51 4,030 631 538 5

LNB w/OFA 65 5,760 962 644 5

SNCR 40 4,160 2,490 2,709 5

SCR 80 17,100 - 34,200 4,298 - 8,596 2,338 - 4,676 6

1

 The annual cost was calculated using a 30-year equipment life and 7% interest.

2

 Cost effectiveness calculated from baseline emissions using the estimated control efficiency.

N OX

N OX

Dave Johnston - 

BW41

Dave Johnston - 

BW42

Table 3-3. Estimated Costs of Control for Selected Boilers - Wyoming

3.3 Factor 3 – Energy and Other Impacts

Table 3-4 shows the estimated energy and non-air pollution impacts of control measures 

for industrial boilers. The values were obtained from an EPA report listing the performance 

impacts of each of the control technology options.

8

 In general, the combustion modification 

technologies (LNB, OFA) do not require steam or generate solid waste, or wastewater. They 

also do not require additional fuel to operate, and, in some cases, may decrease fuel usage 

because of the optimized combustion of the fuel.

Retrofitting of a SNCR requires energy for compressor power and steam for mixing. 

Installation of SCR on an industrial boiler is not expected to increase fuel consumption. 

However additional energy is required to operate the SCR. In addition, spent catalyst would 

have to be changed periodically, producing an increase in solid waste disposal. However, many 

catalyst companies accept the return of spent catalyst material.

3.4 Factor 4 – Remaining Equipment Life

Electric generating units do not have a set equipment life. Since many of the strategies 

are market-based reductions applied to geographic regions, it is assumed that control 

technologies will not be applied to units that are expected to be retired prior to the amortization 

period for the specific control equipment. Therefore, the remaining life of an industrial boiler is 

not expected to affect the cost of control technologies for industrial boilers.
3-4

Source Type Control Technology

Pollutant 

controlled

Electricity 

requirement 

(kW)

Steam 

requirement 

(lb/hr)

Solid waste 

produced 

(ton/hr)

Wastewater 

produced 

(gal/min) References

LNB N OX 5.4 5

LNB w/OFA N OX 5.4 5

SNCR N OX 3 1 439 5

SCR N OX 825 527 5

LNB N OX 5.4 5

LNB w/ OFA N OX 5.4 5

SNCR N OX 3 1 431 5

SCR N OX 825 517 5

NOTES:

A blank cell indicates no impact is expected.

Table 3-4. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Selected 

Boilers - Wyoming

Energy and non-air pollution impacts

Dave Johnston - 

BW41

Dave Johnston - 

BW42
3-5

3.5 References for Section 3

1. NEEDS 2006.

2. WRAP(2008), Emissions Data Management System, Western Regional Air Partnership, 

Denver, CO. http://www.wrapedms.org/app_main_dashboard.asp

3. MRPO (2006), Interim White Paper - Midwest RPO Candidate Control Measures Source

Category: Industrial, Commercial, and Institutional (ICI) Boilers.

http://www.ladco.org/reports/control/white_papers/

4. NESCAUM (2009), Applicability and Feasibility of NOX, SO2, and PM Emission 

Control Technologies for Industrial, Commercial, and Institutional (ICI) Boilers.

5. Khan, Sikander (2003), Methodology, Assumptions, and References: Preliminary NOX

Controls Cost Estimates for Industrial Boilers.

6. Power Magazine (2006), Estimating SCR Installation Costs.

http://www.powermag.com/instrumentation_and_controls/Estimating-SCRinstallationcosts_506_p3.html

7. Institute of Clean Air Companies (2006), Typical Installation Timelines for NOX

Emissions Control Technologies on Industrial Sources.

8. Reference 5.
4-1

4. Cement Manufacturing

Four-factor analyses have been conducted for selected emission sources at one Wyoming 

cement manufacturing plant. The following facility and emission source has been evaluated:

 Mountain Cement Company, Laramie Plant – Cement Kiln #2

Table 4-1 outlines the baseline levels of emissions and potential control measures that 

could be adopted to reduce these emissions. The table also gives the estimated control efficiency 

and annual emission reduction for each potential control measure.

Baseline emissions of NOX for the kiln were obtained from the WRAP 2002 emissions 

inventory.1 Emissions of PM2.5 and PM10 were obtained from the 2002 U.S. EPA NEI. 

Emissions of EC and OC were estimated using speciation factors from EPA’s SPECIATE 

database.2 EC and OC are estimated to comprise 0.07% and 0.014% of PM10 emissions from 

cement kilns, respectively. 

The primary source of emissions from cement manufacturing plants is the cement kiln. 

There are four types – long wet kilns, long dry kilns, preheater kilns, and preheater/precalciner 

kilns. Fuels used in cement kilns include coal, natural gas, and waste-derived fuels (primarily 

scrap tires, but also motor oils, surplus printing inks, and sludge from the petroleum industry).

3

Wet, long dry, and most preheater kilns have one fuel combustion zone; newer 

preheater/precalciner kilns have two fuel combustion zones and some may even have three. NOX

emissions are generated due to oxidation of molecular nitrogen present in the combustion air 

(i.e., thermal NOX formation) or oxidation of nitrogen compounds within the combustion fuel 

(i.e., fuel NOX formation). The temperature within the combustion zone(s) dictate, in part, the 

amount of NOX formed during the production of clinker. The energy efficiency also dictates the 

formation of emissions, as the efficiency influences the amount of heat input required to produce

cement.4 PM emissions are also generated by cement kilns.

The Mountain Cement Company Laramie Plant cement kiln is a long dry kiln with a 

capacity of 1,500 tons of clinker per day; assuming the plant runs 365 days of the year the result

is 547,500 tons per year (tpy).

5

 NOX emissions from the Laramie preheater kiln are 524 tpy.

1
Company Source Pollutant

Baseline 

emissions 

(tons/yr) Control Technology

Estimated 

control 

efficiency (%)

Potential emission 

reduction (1000 

tons/year) References

LNB (indirect) 30-40 157 - 210 4, 5,7,8,13

LNB (direct) 40 210 4, 5,7,8,13

Biosolid Injection 50 262 4, 5,7,8,13

NOXOUT 35 183 4, 5,7,8,13

CemSTAR 20-60 105 - 314 4, 5,7,8,13

LoTOxTM 80-90 5, 6

SCR 80 419 4, 5,7,8,13

SNCR (urea) 35 183 13

SNCR (ammonia) 35 183 13

PM10 37.42 37 7, 9

PM2.5 15.11 15 7, 9

EC 2.6 2.59 7, 9

OC 0.21 0.52 7, 9

PM10 37.42 36 - 37 7, 9

PM2.5 15.11 14 - 15 7, 9

EC 2.6 2.52 - 2.59 7, 9

OC 0.21 0.20 - .021 7, 9

Table 4-1. Potential Control Options for Selected Cement Manufacturing Operations in Wyoming

Mountain Cement 

Company

Long Dry Kiln #2 NOX 523.95

Fabric Filter

Dry ESP

99

95-98
4-3

Combustion control options for NOX include:

 Direct and indirect-fired low NOX burners, and the

 CemStarTM process.

Kilns can be considered either direct- or indirect-fired kilns. Direct-fired kilns use more 

than 10% of primary air (i.e., air that is used for conveying the pulverized coal from the coal mill 

to the kiln). Indirect-fired kilns use less than 10% of primary air. Low NOX burners can be used 

on either direct- or indirect-fired kilns. Low NOX burners reduce flame turbulence, delay fuel/air 

mixing, and establish fuel-rich zones for initial combustion, thus reducing thermal NOX

formation.4The CemStar process adds a small amount of steel slag to the raw kiln feed and 

lower the temperature required to operate the kiln.

 NOX removal controls include:

 Biosolid injection,

 LoTOxTM,

 SCR,

 SNCR, and

 NOXOUT 

Biosolid injection uses biosolids from wastewater treatment plants to lower the kiln 

heating temperature required to produce clinker (biosolid tipping fees are such that often the 

annualized cost is negative, i.e., the plant receives a credit for using the technology). In the 

LoTOxTM system, ozone is injected into the kiln which oxidizes NOX. The resulting higher 

oxides of nitrogen can then be removed by a wet scrubber.6 LoTOx is licensed by the BOC 

Group and is currently being used on the Midlothian cement wet kilns in Texas.6,7

SCR uses an ammonia catalyst (such as a titanium dioxide or vanadium pentoxide 

mixture) to selectively reduce NOX emissions from exhaust gases by converting NOX to nitrate. 

SNCR also reduces NOX formation by ammonia or urea but does not use a catalyst. Instead the 

ammonia or urea is injected into the kiln. Similar to SCR, there is an ideal temperature range at 

which these reactions optimally occur. Long wet and dry kilns have the ideal temperature for 

SNCR reactions in the middle of the kiln, whereas preheater/precalciner kilns have the ideal 

temperature at the lower end of the preheater tower or at the cooler end of the kiln, i.e., not in the 

middle. Thus preheater/precalciner kilns are much more conducive to the SNCR technology 

although SNCR has been used in both long wet and dry kilns.

NOXOUT is similar to the SNCR process and uses urea to complete the chemical 

conversion of NO to nitrate and oxygen. The temperature window is somewhat wider than 

typical SNCR systems due to an additive developed by the proprietors of the NOXOUT 

technology.4PM emissions are often controlled by fabric filters or ESPs.

8,9
4-4

4.1 Factor 1 – Costs

Table 4-2 provides cost estimates for the emission control options which have been 

identified for the Wyoming cement manufacturing plant. For each option, the table gives an 

estimate of the capital cost to install the necessary equipment, and the total annual cost of 

control, including the amortized cost associated with the capital equipment cost. The table also 

shows the estimated cost effectiveness for each control measure, in terms of the cost per ton of 

emission reduction. 

4.2 Factor 2 – Time Necessary for Compliance

Once the regional haze control strategy is formulated for Wyoming, up to 2 years will be 

needed for the state to develop the necessary rules to implement the strategy. We have estimated 

that sources may then require up to a year to procure the necessary capital to purchase control 

equipment. The ICAC has estimated that approximately 13 months is required to design, 

fabricate, and install SCR or SNCR technology for NOX control.10 However, state regulators’ 

experience indicates that closer to 18 months is required to install this technology.11 Installation 

of a single NOX system on cement kilns typically takes less than 18 months. However, LoTOx 

requires a scrubber, which will take approximately 26 months to procure the necessary capital, 

plan, and construct the system. It is assumed that the time for compliance for installing PM 

controls also falls within the range of 13-18 months.

Based on these figures, the total time required to achieve emission reductions for the 

cement kilns would be up to 7 years. This includes 2 years for regulatory development, 1 year 

for capital acquisition, and 21⁄2 years for designing, building and installing a scrubber, if this 

option is selected. If catalyst additives are used, time will be required to select and test the 

appropriate additives, and to determine the optimum feed rate for the additive.

4.3 Factor 3 – Energy and Other Impacts

Table 4-3 shows the estimated energy and non-air pollution impacts of control measures 

for sources at the Wyoming cement manufacturing plant. The table shows the additional fuel, 

electricity, and steam requirements needed to operate the control equipment; and the additional 

solid waste that would be produced. 

A LoTOxTM scrubbing system or wet scrubbing system applied to the fluidized catalytic 

cracking unit would require electricity to operate fans and other auxiliary equipment, and would 

produce a wastewater stream which would require treatment. In addition, sludge from the 

scrubber would require disposal as solid waste. SCR and SNCR systems would also require 

electricity for fans, and SCR may require additional heat input as the temperature at which the 

catalytic reactions occur can be higher than the typical cement kiln flue gas temperatures. 

However, it is possible to use heat recovery systems to reheat the exhaust and avoid generating 
4-5

additional heat input. There is also the additional burden of getting rid of fouled or deactivated 

catalyst from the system – often the PM control device in the form of a fabric filter or 

electrostatic precipitator can achieve this goal.

4

 SCR systems would produce additional solid 

waste because of spent catalyst disposal. Dust captured by an ESP or fabric filter would also 

require disposal as a solid waste. The presence of catalyst fines in the dust may require treatment 

as a hazardous waste.12

4.4 Factor 4 – Remaining Equipment Life

Information was not available on the age of the cement kilns. However, industrial 

processes often refurbish cement kilns to extend their lifetimes. Therefore, the remaining 

lifetime of most equipment is expected to be longer than the projected lifetime of pollution 

control technologies which have been analyzed for these sources. 

If the remaining life of an emission source is less than the projected lifetime of a 

pollution control device, then the capital cost of the control device would have to be amortized 

over a shorter period of time, corresponding to the remaining lifetime of the emission source. 

This would cause an increase in the amortized capital cost of the pollution control option, and a 

corresponding increase in the total annual cost of control. This increased cost can be quantified 

as follows:

where:

A1 = the annual cost of control for the shorter equipment lifetime ($)

A0 = the original annual cost estimate ($)

C = the capital cost of installing the control equipment ($)

r = the interest rate (0.07)

m = the expected remaining life of the emission source (years)

n = the projected lifetime of the pollution control equipment
Company Source Control option Pollutant Estimated 

control 

efficiency (%)

Potential 

emission 

reduction 

(tons/year)

Estimated capital 

cost ($1000)

Estimated 

annual cost 

($1000/year)

Cost effectiveness 

($/ton)

References

LNB (indirect) NOX 30-40 157 - 210 826 205 6,568 - 4,910 4, 5,7,8,13

LNB (direct) NOX 40 210 2,460 449 13,853 4, 5,7,8,13

Biosolid Injection NOX 50 262 474 -127c 1,324 4, 5,7,8,13

NOXOUT NOX 35 183 960 507 8,023 4, 5,7,8,13

CemStar NOX 20-60 105 - 314 Unknowna

UnknownaUnknowna 4, 5,7,8,13

LoTOxTM NOX 80-90 419 - 472 Unknownd 5, 6

SCR NOX 80 419 27,042 7,553 82,535 4, 5,7,8,13

SNCR (urea) NOX 50 183 Unknownb

Unknownb 1,223 8, 13

SNCR (ammonia) NOX 50 183 Unknownb

Unknownb 1,223 8, 13

PM10, EC, OC 99 37 5,261 4,451 262,489 7, 9

PM2.5 99 15 5,261 4,451 647,472 7, 9

PM10, EC, OC 95-98 36 - 37 10,926 6,475 483,356 - 470,292 7, 9

PM2.5 95-98 14 - 15 10,926 6,475 1,242,915 - 1,160,054 7, 9

d Cost effectiveness figures for LoTOx were not determined for dry kilns or preheater kilns, but only for wet kilns (the kilns that currently use the system) and 

precalciner kilns (developed from vendor information).

b Capital and annual costs for SNCR has only been costed for preheater and precalcnier kilns. Only cost effectiveness figures were available for dry kilns.

c A negative annual cost is given because cement kilns receive a credit for the biosolids tipping fee paid by facilities providing the biosolids to the cement plant. For the 

purposes of this analysis the tipping fee is $5.00/ton.

Table 4-2. Estimated Costs of Control for Selected Cement Manufacturing Operations in Wyoming

Mountain 

Cement 

Company

Long Dry 

Kiln #2

Fabric Filter

Dry ESP

a The CemStar process has been costed for long wet kilns only although the process is currently being used in long dry kilns at two facilities, one in Texas and one in 

California.

Unknownd
Source Type Control Technology

Pollutant 

controlled

Electricity 

requirement 

(kW-hr)

Steam 

requirement 

(tons steam)

Solid waste 

produced 

(tons waste)

Wastewater 

produced (1000 

gallons)

LNB (indirect) NOX 157 - 210 a 182

LNB (direct) NOX 210 a

182

Biosolid Injection NOX 262 a

NOXOUT NOX 183

CemSTAR NOX 105 - 314 a

LoTOxTM NOX 419 - 472 c b b

SCR NOX 419

SNCR (urea) NOX 183 b

SNCR (ammonia) NOX 183 b

PM10, EC, OC 37 b 1

PM2.5 15 b 1

PM10, EC, OC 36 - 37 b 1

PM2.5 14 - 15 b 1

NOTES:

a - The measure is expected to improve fuel efficiency.

Potential 

emission 

reduction (1000 

tons/year)

blank indicates no impact is expected.

b - Some impact is expected but insufficient information is available to evaluate the impact.

c - According to the ERG Report (reference 6) "electricity and oxygen costs are reported to be high" although there is no quantification given.

Energy and non-air pollution impacts (per ton of emission 

reduced)

Table 4-3. Estimated Energy and Non-Air Environmental Impacts of Potential Control Measures for Selected Cement Manufacturing 

Operations in Wyoming

Mountain Cement 

Company

Long Dry Kiln #2

Fabric Filter

Dry ESP

Additional fuel 

requirement 

(%)
4-8

4.5 References for Section 4

1. WRAP (2008), Emissions Data Management System, Western Regional Air Partnership, 

Denver, CO, http://www.wrapedms.org/app_main_dashboard.asp

2. U.S. Environmental Protection Agency (2006), SPECIATE version 4, U.S. EPA, RTP, 

NC., http://www.epa.gov/ttn/chief/software/speciate/index.html

3 Lake Michigan Air Directors Consortium, Interim White Paper – Midwest RPO 

Candidate Control Measures, http://www.ladco.org/reports/control/white_papers/.

4 EC/R Incorporated (2000), NOX Control Technologies for the Cement Industry, Prepared 

for OAQPS/OPSP/AQSSD, EPA Contract No, 68-D98-026, 

http://www.epa.gov/ttn/naaqs/ozone/rto/fip/data/cement.pdf.

5 Wyoming Department of Environmental Quality (2007), WAQSR Chapter 6, Section 3 

Operating Permit, Mountain Cement Company, Permit No. 3-1-098-1, 

http://deq.state.wy.us/aqd/TitleVPermitsIssued.asp.

6 ERG, Inc. (2005), Assessment of NOX Emissions Reduction Strategies for Cement Kilns -

Ellis County, Chapter 4, TCEQ Contract No. 582-04-65589, Work Order No. 05-06, 

http://www.tceq.state.tx.us/assets/public/implementation/air/sip/agreements/BSA/CEME

NT_FINAL_REPORT_70514_final.pdf.

7 NACAA (formerly STAPPA and ALAPCO) (2006), Controlling Fine Particulate Matter

Under the Clean Air Act: a Menu of Options, Prepared by the State and Territorial Air 

Pollution Program Administrators and Association of Local Air Pollution Control 

Officials, www.4cleanair.org/ PM25Menu-Final.pdf.

8 E.H. Pechan & Associates (2005), AirControlNET, Version 4.1 - Documentation Report, 

U.S. EPA, RTP, NC, http://www.epa.gov/ttnecas1/AirControlNET.htm.

9 Lake Michigan Air Directors Consortium (LADCO) (2005), Midwest Regional Planning

Organization (RPO) Cement Best Available Retrofit Technology (BART) Engineering 

Analysis, Prepared by MACTEC Federal Programs/MACTEC Engineering and 

Consulting, Inc., http://www.ladco.org/reports/control/bart/cement_plants.pdf

10 . Institute of Clean Air Companies (2006), Typical Installation Timelines for NOX 

Emissions Control Technologies on Industrial Sources, 

http://www.icac.com/files/public/ICAC_NOx_Control_Installation_Timing_120406.pdf..
4-9

11 . Ghoreishi, Farrokh (2007), Personal communication, Time required to install add-on 

control measures for NOX, , Wisconsin Department of Natural Resources, April 27.

12 US Environmental Protection Agency/Office of Air Quality Planning and Standards 

(1994), Alternative Control Techniques Document - NOX Emissions from Cement 

Manufacturing, EPA-453/R-94-004, Chapter 7, 

http://www.epa.gov/ttn/catc/dir1/cement.pdf.