Supplementary Information for Four-Factor

Analyses for Selected Individual Facilities in 

South Dakota

May 19, 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 .........................................................................................................3-4

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...........................................................................................................4-6

4.4 Factor 4 – Remaining Equipment Life .........................................................................................................4-7

4.5 References for Section 4...............................................................................................................................4-9
iv

Abbreviations

BART Best Available Retrofit Technology

CAIR Clean Air Interstate Rule

CO2 Carbon Dioxide 

EC Elemental Carbon

EDMS Emissions Data Management System

EPA Environmental Protection Agency 

ESP Electrostatic Precipitator

FGD Flue Gas Desulfurization

ICAC Institute of Clean Air Companies

LNB Low-NOx Burners

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

VOC Volatile Organic Compounds

WRAP Western Regional Air Partnership
11

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) and sulfur dioxide (SO2), 

which can react in the atmosphere to produce visibility-obscuring particulate matter on a regional 

scale, and also for direct emissions of particulate matter. For direct particulate matter (PM) 

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.” 
12

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

measures for selected emission sources including one electric generating unit and two cement 

kilns at one cement manufacturing plants in South Dakota. The emission sources addressed in 

this current report were selected by the South Dakota Department of Environment and Natural 

Resources. Section 2 presents the methodology employed for the analyses, Section 3 presents 

the results of the four-factor analysis for boilers and Section 4 presents the results for cement 

kilns. 
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, wastewater discharged, acid deposition, nitrogen deposition, and climate impacts 

(e.g., generation and mitigation of greenhouse gas emissions).

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 
2-3

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

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

Additional carbon dioxide (CO2) produced

Reduced acid deposition

Reduced nitrogen deposition

Benefits from reductions in PM2.5 and ozone, where available

Impacts Not Included

Impacts of control measures on boiler efficiency

Energy required to produce lower sulfate fuels

Secondary environmental impacts to produce additional energy (except 

CO2) 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 
2-4

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

annualized cost-effectiveness.

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.
2-1

3. Boilers

A four-factor analysis was performed on a single coal-fired boiler at Black Hill Power 

and Light Company – Ben French Station. This boiler is used to produce steam from the 

combustion of sub-bituminous coal to generate electricity in a steam turbine. The unit at BEN 

French Station is rated at 25 megawatts (MW). Pollutant emissions from the boilers include: 

nitrogen oxides (NOX), sulfur dioxide (SO2), and particulate matter (PM). 

Table 2-1 summarizes the NOX and SO2 emissions from the boiler, as well as the control 

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

2-1 were obtained from the WRAP 2002 emission inventory.2 Emissions of EC and OC can be

estimated using speciation factors from EPA’s SPECIATE database.3The 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)

S O2 Annual 

Emissions 

(tons/yr)

Annual 

Emission Date

Black Hills Power and 

Light Co. Ben French Station Unit 1

Sub-bituminous coalfired boiler 25 907.5 785.0 2002

Table 3-1. Emissions from Selected Boilers - South Dakota

Currently, the boiler at the Ben French Station is uncontrolled. The facility does utilize a 

low sulfur coal (0.33 wt %) to minimize the formation of SO2 during the combustion process. A 

list of potential NOX and SO2 control strategies are presented in Table 2-2. The table provides a 

range of pollutant reductions and presents the potential emission reductions from the baseline 

emissions by applying the listed control options.4,5 These control options have been applied to 

many electrical generating unit boilers in the U.S. to reduce emissions of NOX and SO2.
2-2

Facility Name Source Type

Pollutant 

controlled Control Technology

Baseline 

emissions1 

(tons/yr)

Estimated 

control 

efficiency (%)

Potential 

controlled 

emissions2 

(tons/yr)

LNB 907 30 - 75 681

LNB w/OFA 50 - 65 590

SNCR 30 - 75 681

SCR 40 - 90 817

Dry sorbent injection 785 10 - 40 314

Spray dryer absorber 90 706

Wet FGD 90 706

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 - South Dakota

Ben French Station - 

Unit 1

Sub-bitiminous coalfired boilerN OX

S O2

3.1 Factor 1 – Costs

Table 2-3 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.

6,7

 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 2-3 also estimates the 

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

Recent literature8has indicated that the cost of SCR for electric generating can vary from $120 to 

$170 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, and approximately 30 

months to design, build, and install SO2 scrubbing technology.

9

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

reductions for industrial boilers is estimated at a total of 51⁄2 years for NOX strategies, and 61⁄2 

years for SO2 strategies.
2-3

Facility Name

Pollutant 

controlled Control Technology

Estimated 

control 

efficiency (%)

Estimated capital 

cost ($1000)

Estimated 

annual cost 

($1000/yr)

Cost 

effectiveness 

($/ton)

LNB 51 1,250 195 421

LNB w/OFA 65 1,780 298 505

SNCR 40 1,290 770 2,121

SCR 80 3,000 - 4,250 754 - 1,068 1,039 - 1,471

Dry sorbent injection 40 4,300 1,700 5,414

Spray dryer absorber 90 11,600 2,670 3,779

Wet FGD 90 14,600 2,760 3,907

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.

NOX

SO2

Table 3-3. Estimated Costs of Control for Selected Boilers - South Dakota

Ben French 

Station - Unit 1

3.3 Factor 3 – Energy and Other Impacts

Table 2-4 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.

10,11

 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. 

This would produce a small increase in CO2 emissions to generate electricity; however the 

technology itself does not produce additional CO2 emissions. 

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

However additional energy is required to operate the SCR, which will produce an increase in 

CO2 emissions to generate the electricity. 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.

Retrofitting of the SO2 control options increase the usage of electricity, and produce both 

a solid waste and wastewater stream. In addition, increases of CO2 emissions will occur due to 

the increased energy usage for material preparation (e.g., grinding), materials handling (e.g., 

pumps/blowers), flue gas pressure loss, and steam requirements. Power consumption is also 

affected by the reagent utilization of the control technology, which also affects the control 

efficiency of the control technology.
2-4

Source Type Control Technology

Pollutant 

controlled

Electricity 

requirement 

(kW)

Steam 

requirement 

(lb/hr)

Solid waste 

produced 

(ton/hr)

Wastewater 

produced 

(gal/min)

Additional CO2 

emitted 

(tons/yr)

LNB N OX 1.2 0.0012

LNB w/OFA N OX 1.2 0.0012

SNCR N OX 7 170 0.007

SCR N OX 181 204 0.18

Dry sorbent injection S O2 265 1.5 18.3 0.3

Spray dryer absorber S O2 183 1.8 14.7 0.18

Wet FGD S O2 524 1.5 33 0.5

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 - South Dakota

Energy and non-air pollution impacts

Ben French 

Station - Unit 1

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.
2-5

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. EPA (2006), SPECIATE version 4, U.S. EPA, RTP, NC. 

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

4. 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/

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

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

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

Controls Cost Estimates for Industrial Boilers.

7. Khan, Sikander (2003), Methodology, Assumptions, and References: Preliminary SO2 

Controls Cost Estimates for Industrial Boilers.

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

http://www.powermag.com/instrumentation_and_controls/Estimating-SCR-installationcosts_506_p3.html

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

Control Technologies on Industrial Sources.

10. Reference 6.

11. Reference 7.
4-1

4. Cement Manufacturing

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

Dakota cement manufacturing plant. The following facility and emission sources have been 

evaluated:

 GCC Dacotah, Rapid City Plant – Cement Kilns #4 and #5

Table 3-1 outlines the baseline levels of emissions and potential additional control 

measures that could be adopted to further reduce emissions. The table also gives the estimated 

control efficiency and annual emission reduction for each potential future control measure.

Baseline emissions of NOX and SO2 for the refineries were obtained from the WRAP 

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

EPA NEI and from the state of South Dakota.

2

 Emissions of EC and OC were estimated using 

speciation factors from EPA’s SPECIATE database.3 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).4

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.5 SO2 emissions are created from sulfur compounds in the raw materials used (i.e., 

limestone, clay, sand and iron ore) and to a smaller extent in the fuel.4PM emissions are also 

generated by cement kilns.
Company Source Pollutant

Baseline 

emissions 

(tons/yr)

Existing Control 

Technology

Potential Control 

Technology

Estimated 

control 

efficiency (%)

Potential 

emission 

reduction 

(tons/year) References

LNB (indirect) 30-40 212 - 283 5,11,15,19

LNB (direct) 40 283 5,11,15,19

Biosolid Injection 23 163 5,11,15,19

CemSTAR 20-60 14 - 424 5,11,15,19

Mid-Kiln 20-50 14 - 353 5,11,15,19

SCR 80 565 10,11,14,15

SO2 26 None Wet FGD 90-99 24 - 26 10,11,14,15

 PM10 136 Dry ESP Fabric Filter 99 134 10,11,14,15

PM2.5 67 Dry ESP Fabric Filter 99 67 10,11,14,15

EC 10 Dry ESP Fabric Filter 99 9.38 10,11,14,15

OC 2 Dry ESP Fabric Filter 99 1.876 10,11,14,15

LNB (indirect) 30-40 116 - 155 5,11,15,19

LNB (direct) 40 155 5,11,15,19

Biosolid Injection 23 89 5,11,15,19

CemSTAR 20-60 78 - 233 5,11,15,19

Mid-Kiln 20-50 78 - 194 5,11,15,19

SCR 80 310 10,11,14,15

SO2 431 None Wet FGD 90-99 388 - 427 10,11,14,15

 PM10, PM2.5, 

EC, OC 45 Dry ESP Fabric Filter 82 37

2, 10,11,14,15

NOX

None

None

Table 4-1. Existing Control Measures and Potential Additional Control Options for Selected Cement Manufacturing Operations 

Long Wet Kiln 

# 4

Long Wet Kiln 

# 5

NOX

707

388

GCC Dacotah, 

Rapid City Plant
4-3

The GCC Dacotah Rapid City Plant cement kilns analyzed in this report are all long wet 

kilns. Kilns #4 and #5 have capacities of 550 tons of clinker per day each; assuming the kilns 

run 365 days of the year the result is 200,750 tons of clinker per year (tpy) per kiln. NOX and 

SO2 emissions from the Kiln #4 are 707 tpy and 27 tpy, respectively. NOX and SO2 emissions 

from the Kiln #5 are 388 tpy and 431 tpy, respectively. 

1

Combustion control options for NOX include:

 Direct and indirect-fired low NOX burners, 

 The CemStar process, and

 Mid-kiln firing.

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.5The CemStar process adds a small amount of steel slag to the raw kiln feed and 

lower the temperature required to operate the kiln. Mid-kiln firing uses an additional feed 

injection mechanism and injects solid fuel into the calcining zone of a rotating kiln, thus 

lowering the temperature to produce clinker.

NOX removal control options 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.6,15 Both 

CemStar and biosolid injection are most feasible when there are nearby sources of steel slag or 

biowaste, respectively, that the cement plant can easily procure without incurring large 

transportation costs.

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. 

The catalytic reactions can take place only in certain temperature ranges which are often higher 

than typical cement kiln flue gas temperatures. Process reconfigurations, such as an 

automatically activated bypass duct placed around the SCR reactor to control temperature 

fluctuations or installing equipment to maintain the desired temperature, can successfully deal 
4-4

with temperature issues.6 Due to potential fouling problems of the catalyst the SCR system must 

be installed after the particulate collection device.

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 and as such SNCR is not applicable to long wet and dry kills.

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.5

The clinker production process controls SO2 to a significant degree.7,8The interior of the 

kiln is highly alkaline absorbs up to 95 percent of the SO2 emissions generated, although this can 

vary depending on the kiln feed.9The option to control SO2 is limited to flue gas desulfurization 

(FGD).10 Flue gas is the primary source of SO2 and volatile organic carbons (VOCs) – the fuel 

and raw materials dictate the amount of SO2 emissions generated. Wet scrubbers have 80-99 

percent control efficiency, although the generation of sludge and particulate build-up necessitates 

the FGD be installed downstream of a fabric filter.11,1213 PM emissions are often controlled by 

fabric filters or wet or dry Electrostatic Precipitators (ESPs).14,15 Kilns #4 and #5 at the GCC 

facility already have dry ESPs installed and thus only fabric filters are analyzed for further PM 

control.

4.1 Factor 1 – Costs

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

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

estimate of the capital cost to install the necessary equipment (including any required

instrumentation and equipment and all piping and ductwork), 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 South Dakota, 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 
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) Refer-ences

LNB (indirect) NOX 30-40 212 - 283 526 129 3,092 - 1,859 5,14,15

LNB (direct) NOX 40 283 1,873 331 7,788 5,14,15

Biosolid Injection NOX 23 163 - - 421.41 5,14,15

CemSTAR NOX 20-60 14 - 424 1,599 299 4,476 - 13,459 5,14,15

Mid-Kiln NOX 20-50 14 - 353 2,758 -315 6,922 - 17,328 5,14,15

LoTOxTM NOX 80-90 565 - 636 3155 - 3891 6,15

SCR NOX 80 565 14,813 4,137 34 5,14,15

Wet FGD SO2 90-99 24 - 26 9,133 1,370 403,942 - 437,604 10,11,15

Fabric Filter

 PM10, EC, OC 99 134 1,357 1,148 18,699 10,11,15

Fabric Filter PM2.5 99 67 1,235 1,045 37,399 10,11,15

LNB (indirect) NOX 30-40 116 - 155 526 129 4,229 - 5,651 5,14,15

LNB (direct) NOX 40 155 1,873 331 14220 5,14,15

Biosolid Injection NOX 23 89 - - 0 5,14,15

CemSTAR NOX 20-60 78 - 233 1,599 299 8,144 - 24,330 5,14,15

LoTOxTM NOX 80-90 310 - 349 3155 - 3891 6,15

Mid-Kiln NOX 20-50 78 - 194 2,758 -315 12,594 - 31,324 5,14,15

SCR NOX 80 310 14,813 4,137 61 5,14,15

Wet FGD SO2 90-99 388 - 427 9,133 1,370 27,068 10,11,15

Fabric Filter

 PM10, PM2.5, 

EC, OC

82 37 1,235 1,045 110,421 2,10,11,15

a 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).

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

Long Wet 

Kiln # 4

Long Wet 

Kiln # 5

GCC 

Dacotah, 

Rapid City 

Plant

Unknowna

Unknowna
4-6

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

fabricate, and install SCR or SNCR technology for NOX control.16 However, state regulators’ 

experience indicates that closer to 18 months is required to install this technology.17 In the Clean 

Air Interstate Rule (CAIR) analysis, EPA estimated that approximately 30 months is required to 

design, build, and install SO2 scrubbing technology for a single emission source.

18

 The analysis 

also estimated that up to an additional 12 months may be required for staging the installation 

process if multiple sources are to be controlled at a single facility. 

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

cement kilns would be up to 61⁄2 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. CO2 emissions associated with the generation of the 

additional electricity and steam are also estimated in the table. 

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, 

although it may be possible to use heat recovery systems to reheat and achieve the required 

temperature.

5

 However, it is possible to use heat recovery systems to reheat the exhaust and 

avoid generating 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.

5

 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.19
4-7

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
Source Type Control Technology Pollutant controlled

Electricity 

requirement (kWhr)Steam requirement 

(tons steam)

Solid waste 

produced (tons 

waste)

Wastewater 

produced (1000 

gallons)

Additional CO2 

emitted (tons)

LNB (indirect) NOX 212 - 283 a 182

LNB (direct) NOX 283 a 182

Biosolid Injection NOX 163 a

NOXOUT NOX 247 b

CemSTAR NOX 14 - 424 a

Mid-Kiln NOX 14 - 353 a

LoTOxTM NOX 565 - 636 c b b c

SCR NOX 565 9.8 57 b

Wet FGD SO2 24 - 26 1,100 3 3 3.7 2.6

Fabric Filter PM10, EC, OC 134 b 1

Fabric Filter PM2.5 67 b 1

Dry ESP PM10, EC, OC 44 b 1

Dry ESP PM2.5 21 b 1

LNB (indirect) NOX 116 - 155 a

LNB (direct) NOX 155 a

Biosolid Injection NOX 89 a

NOXOUT NOX 136 b

CemSTAR NOX 78 - 233 a

Mid-Kiln NOX 78 - 194 a

LoTOxTM NOX 310 - 349 c b b c

SCR NOX 310 9.8 57 b

Wet FGD SO2 388 - 427 1,100 3 3 3.7 2.6

Fabric Filter PM10, EC, OC 45 b 1 b

Fabric Filter PM2.5 22 b 1

Dry ESP PM10, EC, OC 45.17 a b 1

Dry ESP PM2.5 22.34214973 0.5 b 1 0.0

NOTES:

GCC Dacotah, 

Rapid City Plant

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

Additional fuel 

requirement (%)

a - The measure is expected to improve fuel efficiency.

Potential emission 

reduction ( 

tons/year)

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

blank indicates no impact is expected.

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

Long Wet Kiln # 4

Long Wet Kiln # 5

c - According to the ERG Report (reference 5) "electricity and oxygen costs are reported to be high" although there is no quantification given.
4-9

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 Boddicker, Rick (2009), Personal Communication, Potential Reduction of Particulate 

Matter by Dry ESP, South Dakota Department of Environment & Natural Resources, 

May 5.

3. EPA (2006), SPECIATE version 4, U.S. EPA, RTP, NC,

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

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

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

5 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.

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 Davis, W. (2000) Air Pollution Engineering Manual: Second Edition, Air & Waste 

Management Association.

8 Sumter Cement Company (2005), Application to Construct New Portland Cement Plant, 

NSR/PSD Construction Permit for Center Hill Plant, submitted to Florida Department of 

Environmental Protection, 

www.dep.state.fl.us/Air/permitting/construction/sumter/APPLICATION.zip

9 U.S. Environmental Protection Agency (1995), Chapter 11: Mineral Products Industry: 

Portland Cement Manufacturing” in AP 42, Fifth Edition, Volume I, 

http://www.epa.gov/ttn/chief/ap42/ch11/final/cs11s06.pdf.

10 U.S. Department of Energy, National Energy Technology Laboratory (2001), Cement 

Kiln Flue Gas Recovery Scrubber Project: A DOE Assessment, DOE/NETL-2002/1163, 

http://www.epa.gov/ttn/chief/ap42/ch11/final/cs11s06.pdf.

11 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.
4-10

12 Miller, F.M., G.L. Young, M. von Seebach (2001), Formation and Techniques for 

Control of Sulfur Dioxide4 and Other Sulfur Compounds in Portland Cement Kiln 

Systems, Portland Cement Association, PCA R&D Serial No. 2460, pp.37-48.

13 NESCAUM (2005), Assessment of Control Technology Options for BART-Eligible 

Sources: Steam Electric Boilers, Industrial Boilers, Cement Plants and Paper and Pulp 

Facilities, U.S. EPA Grant XA-983799-01-2, pp. 59-78, 

http://www.nescaum.org/documents/bart-control-assessment.pdf/

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

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

15 NACCA (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.

16 . 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.

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

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

18. EPA (2005), Boilermaker Labor Analysis and Installation Timing – Technical Support 

Document for the Final Clean Air Interstate Rule. OAR-2003-0053, U.S. EPA, 

Washington, DC. www.epa.gov/cair/technical.html#final

19 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.