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Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page i

Table of Contents

Chapter Page

List of Acronyms .................................................................................................................v

Executive Summary ......................................................................................................... vii

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

Background ....................................................................................................................... 1-1

Determination of Emission Source Categories and Individual Sources Most Responsible 

for Regional Haze in MANE-VU Class I Areas ............................................................... 1-2

Approach to Demonstrating Reasonable Progress............................................................ 1-6

References......................................................................................................................... 1-8

2 Source Category Analysis: Electric Generating Units (EGUs).................................. 2-1

Source Category Description............................................................................................. 2-1

Evaluation of Control Options .......................................................................................... 2-2

Four Factor Analysis of Potential Control Scenarios for EGUs ....................................... 2-6

References....................................................................................................................... 2-16

3 Analysis of Selected Electric Generating Units (EGUs)............................................... 3-1

EGU Facility Controls....................................................................................................... 3-1

Integrated Planning Model (IPM

®

) Analysis.................................................................... 3-2

Information Obtained from State Agencies....................................................................... 3-6

References....................................................................................................................... 3-18

EGU Attachment 1 - Illustrative Scrubber Costs (1999 $) for Representative MW and 

Heat Rates under the Assumptions in EPA Base Case 2004 .......................................... 3-19

EGU Attachment 2 - Engineering Methodology Used to Calculate $/ton Pollutant 

Reduction......................................................................................................................... 3-20

4 Source Category Analysis: Industrial, Commercial, and Institutional Boilers......... 4-1

Source Category Description............................................................................................. 4-1

Evaluation of Control Options .......................................................................................... 4-3

Four Factor Analysis of Potential Control Scenarios for ICI Boilers ............................... 4-9

References....................................................................................................................... 4-15

5 Analysis of Selected Industrial, Commercial, and Institutional Boilers .................... 5-1

Source Category Description............................................................................................. 5-1

Information Obtained from State Agencies....................................................................... 5-1

6 Source Category Analysis: Kilns.................................................................................... 6-1

Source Category Description............................................................................................. 6-1

Evaluation of SO2 Emission Control Options................................................................... 6-3

Four Factor Analysis of Potential Control Scenarios for Kilns......................................... 6-9

References....................................................................................................................... 6-13
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page ii

Table of Contents – continued

Chapter Page

7 Analysis of Selected Kilns............................................................................................... 7-1

Source Category Description............................................................................................. 7-1

Information Obtained from State Agencies....................................................................... 7-1

8 Heating Oil....................................................................................................................... 8-1

Background ....................................................................................................................... 8-1

Four Factor Analysis of Potential Control Scenarios for Emissions from Heating Oil 

Combustion ....................................................................................................................... 8-2

References......................................................................................................................... 8-8

9 Residential Wood Combustion....................................................................................... 9-1

Background ....................................................................................................................... 9-1

Four Factor Analysis of Potential Control Scenarios for Residential Wood

Combustion ....................................................................................................................... 9-9

References....................................................................................................................... 9-15

10 Residential Wood Combustion – Outdoor Wood Fired Boilers ............................... 10-1

Background ..................................................................................................................... 10-1

Four Factor Analysis of Potential Control Scenarios for Outdoor Wood-Fired

Boilers ............................................................................................................................. 10-3

References....................................................................................................................... 10-6
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page iii

Table of Contents – continued

Table Page

Table I Summary of Results from the Four Factor Analysis...................................................... viii

Table 2.1 SO2 Control Options for Coal-fired EGU Boilers...................................................... 2-3

Table 2.2 Marginal Costs of Emission Reductions (Allowance Prices) Calculated by Integrated

Planning Model (IPM®) for the CAIR Base Case and CAIR Plus Runs (2006 $/ton) ..... 2-7

Table 2.3 NOX and SO2 Emissions from the Electric Power Sector (Thousand Tons)............. 2-8

Table 2.4 Recent Average Coal Prices from Various Locations in the U.S. (12/2006) 

($/ton)................................................................................................................................ 2-9

Table 2.5 Average U.S. Bituminous and Subbituminous Coal Prices (2006 dollars/ton).......... 2-9

Table 2.6 Estimated Cost Ranges for SO2 Control Options for Coal-fired EGU Boilers 

(2006 dollars/ton of SO2 Reduced) ................................................................................. 2-13

Table 3.1 Integrated Planning Model (IPM®version 2.1.9) CAIR Plus Results for the 

Top 30 EGUs Responsible for Visibility Impairment in MANE-VU Class I Areas ........ 3-4

Table 3.2 Point Source Information Collected for the Top 30 EGUs Responsible for 

Visibility Impairment in MANE-VU Class I Areas.......................................................... 3-7

Table 3.3 Comparison of Controls Predicted by Integrated Planning Model (IPM

®

) CAIR 

Plus Results versus Proposed/Planned Control Additions by the State/Facility (by 2018) at 

the Top 30 EGUs Responsible for Visibility Impairment in MANE-VU Class I Areas 3-15

Table 4.1 Available SO2 Control Options for ICI Boilers.......................................................... 4-5

Table 4.2 Potential SO2 Reductions Through Fuel Switching.................................................. 4-10

Table 4.3 Estimated Dry Sorbent Injection (DSI) Costs for ICI Boilers.................................. 4-11

Table 4.4 Estimated Flue Gas Desulfurization (FGD) Costs for ICI Boilers (2006 dollars).... 4-12

Table 5.1 Point Source Information Collected from the Top 17 Industrial Facilities 

Responsible for Visibility Impairment in MANE-VU Class I Areas................................ 5-2

Table 6.1 SO2 Control Technologies for Cement Kilns ............................................................. 6-5

Table 6.2 SO2 Control Costs for AFGD Applied to Dry Kilns and Preheater Kilns

(2006 dollars) .................................................................................................................. 6-10

Table 6.3 SO2 Control Costs for Wet FGD Applied to Dry Kilns and Preheater Kilns

(2006 dollars) .................................................................................................................. 6-10

Table 6.4 SO2 Control Costs for Dry FGD Applied to Dry Kilns and Preheater Kilns

(2006 dollars) .................................................................................................................. 6-11

Table 7.1 Point Source Information Collected from the Top 3 Kilns Responsible for 

Visibility Impairment in MANE-VU Class I Areas.......................................................... 7-2

Table 8.1 State Sulfur Limits for Heating Oil............................................................................. 8-1

Table 8.2 Ultra Low Sulfur Diesel (ULSD) Desulfurization Technology Costs for

Individual Refineries......................................................................................................... 8-2

Table 8.3 Average January 2007 Distillate Stocks (Million Barrels)......................................... 8-5

Table 8.4 Distillate Production and Imports (Million Barrels per Day)..................................... 8-5

Table 9.1 Summary of Measures Available for RWC RACM – PM10....................................... 9-5

Table 9.2 Summary of Measures Available for RWC BACM – PM10....................................... 9-7
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page iv

Table of Contents – continued

Table Page

Table 9.3 Improved Technologies and Fuel Alternatives......................................................... 9-10

Table 9.4 PM Reduction Cost Effectiveness for Replacement of Existing Uncertified 

Freestanding Cordwood Stove/Insert and Cordwood Fireplace w/o Insert for 

Heating ............................................................................................................................ 9-11

Table 9.5 VOC Reduction Cost Effectiveness for Replacement of Existing Uncertified 

Freestanding Cordwood Stove/Insert and Cordwood Fireplace w/o Insert for 

Heating ............................................................................................................................ 9-12

Table 9.6 Reduction Cost Effectiveness for the Replacement of an Existing Centralized 

Cordwood Heating System.............................................................................................. 9-12

Table 9.7 Pollutant Reduction Cost Effectiveness for the Addition of a Gas Log Set or Use of 

Wax/Fiber Firelogs in an Existing Fireplace w/o Insert Used for Aesthetics................. 9-13

Figure Page

Figure 1.1 Contributions to PM2.5 Mass at 7 Sites - 20% Worst Visibility Days 

(2000-2004)....................................................................................................................... 1-2

Figure 1.2 MANE-VU 2002 Version 3 Annual Emissions Inventory Top PM2.5-Primary Source 

Categories.......................................................................................................................... 1-3

Figure 1.3 MANE-VU 2002 Version 3 Annual Emissions Inventory Top SO2 Source

Categories.......................................................................................................................... 1-4

Figure 3.1 EGU Facilities with the Greatest Visibility Impacts in Mid-Atlantic North Eastern 

Class I Areas...................................................................................................................... 3-2

Figure 6.1 Portland Cement Process Flow Diagram................................................................... 6-1

Figure 6.2 Advanced Flue Gas Desulfurization Process Flow ................................................... 6-7
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page v

List of Acronyms

AFGD ......................................................................................................................................Advanced Flue Gas Desulfurization

BACM ........................................................................................................................................... Best Available Control Measure

BART ......................................................................................................................................Best Available Retrofit Technology

BLM ................................................................................................................................................Bureau of Land Management

BTU ............................................................................................................................................................. British Thermal Unit

CAA ........................................................................................................................................................................ Clean Air Act

CAIR .......................................................................................................................................................Clean Air Interstate Rule

CFB ..................................................................................................................................................... Circulating Fluidized Bed

CHP ....................................................................................................................................................Combined Heat and Power

CO2.......................................................................................................................................................................carbon dioxide

DOE ...........................................................................................................................................................Department of Energy

EGU ........................................................................................................................................................Electric Generating Unit

EIA ...................................................................................................................................... Energy Information Administration

EPA ........................................................................................................................................ Environmental Protection Agency

ESP ....................................................................................................................................................... Electrostatic Precipitator

FGD .......................................................................................................................................................Flue Gas Desulfurization

HAP ........................................................................................................................................................Hazardous Air Pollutant

ICI .....................................................................................................................................Industrial, Commercial, Institutional

IPM®....................................................................................................................................................Integrated Planning Model

kW ................................................................................................................................................................................. kilowatt

kWh .........................................................................................................................................................................kilowatt-hour

LADCO .............................................................................................................................Lake Michigan Air Directors Consortium

LAER ........................................................................................................................................Lowest Achievable Emission Rate

LNB ...................................................................................................................................................................Low NOX Burner

LSD .............................................................................................................................. Lime Spray Drying // Low Sulfur Diesel

LSFO .................................................................................................................................................Limestone Forced Oxidation
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page vi

List of Acronyms - continued

MACT ..........................................................................................................................Maximum Achievable Control Technology

MANE-VU ..........................................................................................................................Mid-Atlantic/Northeast Visibility Union

MARAMA.......................................................................................................Mid-Atlantic Regional Air Management Association

MEL ..................................................................................................................................................Magnesium Enhanced Lime

MM ...................................................................................................................................................................................million

MMBTU..............................................................................................................................................Million British Thermal Units

MRPO .............................................................................................................................Midwest Regional Planning Organization

MW ...............................................................................................................................................................................Megawatt

NESCAUM...................................................................................................Northeast States for Coordinated Air Use Management

NOX ......................................................................................................................................................................nitrogen oxides

NSPS .......................................................................................................................................New Source Performance Standard

NSR ..............................................................................................................................................................New Source Review

O&M ...................................................................................................................................................Operation and Maintenance

OFA ......................................................................................................................................................................... Over-fire Air

PADD .....................................................................................................................Petroleum Administration for Defense District

PM ..................................................................................................................................................................Particulate Matter

PM10 ...................................................................................................... Particulate Matter with diameter 10 micrometers or less

PM2.5 ..................................................................................................... Particulate Matter with diameter 2.5 micrometers or less

PSD .................................................................................................................................Prevention of Significant Deterioration

RACM ................................................................................................................................Reasonably Available Control Measure

RACT ...........................................................................................................................Reasonably Available Control Technology

RWC ..............................................................................................................................................Residential Wood Combustion

SACR ....................................................................................................................................... Selective Auto-catalytic Reduction

SCC ................................................................................................................................................... Source Classification Code

SCR ............................................................................................................................................... Selective Catalytic Reduction

SIP .................................................................................................................................................... State Implementation Plan

SNCR ........................................................................................................................................ Selective Non-catalytic Reduction

SO2........................................................................................................................................................................ sulfur dioxide

SOFA .........................................................................................................................................................Separated Over-fire Air

ULSD ........................................................................................................................................................ Ultra Low Sulfur Diesel
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page vii

EXECUTIVE SUMMARY

The Regional Haze regulations set forth under 40 CFR 51.308(d)(1) require States to achieve

reasonable progress toward natural visibility conditions. The national visibility goal in Class I

areas is defined in the CAA Section 169A(a)(1) as “the prevention of any future, and the 

remedying of any existing, impairment of visibility...”, and is expected to be satisfied by 2064 

with a return to natural visibility conditions. States containing Class I areas must set Reasonable 

Progress Goals (RPGs) to define future visibility conditions that are expected (but not required) 

to be equal to, or better, than visibility conditions expected by the uniform rate of progress at any

future year until natural conditions are achieved. RPGs are to be established for the final year in 

the planning period, which in the case of the first SIP is 2018.

Following draft guidance from EPA in establishing RPGs, States must set a baseline from which 

reasonable progress towards visibility improvement will be measured. The MANE-VU baseline 

year for the emission inventory is 2002 and for monitoring is 2000-2004. The next task is to 

identify key pollutants affecting visibility impairment at each Class I area. The major pollutant 

contributing to visibility impairment in MANE-VU has been shown to be sulfate.

In order to determine the key source regions and source types affecting visibility impairment at 

each Class I area, a contribution assessment was prepared by NESCAUM for MANE-VU. 

Major contributors were identified by ranking emissions sources, comparing Q/d (emission 

impact over distance), and modeling visibility impacts. Source apportionment and other analyses 

documented in MANE-VU’s contribution assessment showed that several source categories have 

impacts on visibility at MANE-VU Class I areas.

The largest contribution to visibility impairment at most sites was from burning of coal, 

primarily utility and industrial combustion sources in MANE-VU and nearby States. At forested 

rural sites, biogenic organics are a moderate to large contributor to visibility impairment, but 

other sources of secondary organics also contribute. Wood smoke and ammonium nitrate were 

identified as small to moderate contributors.

Based on information from the contribution assessment and additional emissions inventory

analysis, MANE-VU selected the following source categories for analysis in this project:

 Coal and oil-fired Electric Generating Units, (EGUs);

 Point and area source industrial, commercial and institutional boilers;

 Cement kilns;

 Lime kilns;

 The use of heating oil; and

 Residential wood combustion

This document presents the results of an analysis of the economic and environmental impacts of 

potential control scenarios that could be implemented by MANE-VU States to reduce emissions 

from the above source categories in order to make reasonable progress toward meeting visibility

improvement goals. The purpose of this analysis is to present information that can be used by 

States to develop policies and implementation plans to address reasonable progress goals. 

Control technologies to achieve reasonable progress goals are evaluated with respect to four 

factors listed in the Clean Air Act (Section 169A):
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page viii

 Cost,

 Compliance timeframe,

 Energy and non-air quality environmental impacts, and

 Remaining useful life for affected sources.

The “four factor” analysis was applied to control options identified for each of the selected

source categories. Cement kilns and lime kilns are analyzed together due to the similarity of the 

two source categories.

The table below presents a summary of the four factor analysis for the source categories 

analyzed. Detailed information on control technologies assessed in this effort is presented in the 

main body of this document.

Table I Summary of Results from the Four Factor Analysis

Source 

Category

Primary 

Regional 

Haze 

Pollutant

Average Cost in 

2006 dollars

(per ton of 

pollutant 

reduction)

Compliance 

Timeframe

Energy and 

Non-Air 

Quality 

Environmental 

Impacts

Remaining 

Useful Life

Electric 

Generating Units 

SO2

IPM* v.2.1.9 predicts 

$775-$1,690

$170-$5,700 based on 

available literature

2-3 years following 

SIP submittal

Fuel supply issues, 

potential permitting 

issues, reduction in 

electricity production 

capacity, wastewater 

issues

50 years or more

Industrial, 

Commercial, 

Institutional 

Boilers

SO2

$130-$11,000 based on 

available literature

2-3 years following 

SIP submittal

Fuel supply issues, 

potential permitting 

issues, control device 

energy requirements, 

wastewater issues

10-30 years

Cement and 

Lime Kilns

SO2

$1,900-$73,000 based on 

available literature

2-3 years following 

SIP submittal

Control device energy 

requirements, 

wastewater issues

10-30 years

Heating Oil SO2

$550-$750 based on 

available literature. There 

is a high uncertainty

associated with this cost 

estimate.

Currently feasible. 

Capacity issues may 

influence timeframe 

for implementation of 

new fuel standards

Increases in 

furnace/boiler 

efficiency, Decreased 

furnace/boiler 

maintenance 

requirements

18-25 years

Residential 

Wood 

Combustion

PM and 

VOC

$0-$10,000 based on 

available literature

Several years -

dependent on 

mechanism for 

emission reduction 

Reduce greenhouse gas 

emissions, increase 

efficiency of 

combustion device

10-15 years

* Integrated Planning Model (IPM®) application by ICF for MANE-VU

This report also contains information on current and planned controls at 20 specific non-EGU 

sources and 30 specific EGU sources identified by MANE-VU to consider control strategies 

already in place or planned by 2018.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 1: Introduction Page 1-1

CHAPTER 1

INTRODUCTION

BACKGROUND

The Regional Haze regulations set forth under 40 CFR 51.308(d)(1) require States to achieve 

reasonable progress toward natural visibility conditions. The national visibility goal in Class I

areas is defined in the CAA Section 169A(a)(1) as “the prevention of any future, and the 

remedying of any existing, impairment of visibility...”, and is expected to be satisfied by 2064 

with a return to natural visibility conditions. States containing Class I areas must set Reasonable 

Progress Goals (RPGs) to define future visibility conditions that are expected (but not required) 

to be equal to, or better, than visibility conditions expected by the uniform rate of progress at any

future year until natural conditions are achieved. RPGs are to be established for the final year in 

the planning period, which in the case of the first SIP is 2018.

Following draft guidance from EPA in establishing RPGs, States must set a baseline from which 

reasonable progress towards visibility improvement will be measured. The MANE-VU baseline 

year for the emission inventory is 2002 and for monitoring is 2000-2004. The next task is to 

identify key pollutants affecting visibility impairment at each Class I area. The major pollutant 

contributing to visibility impairment in MANE-VU has been shown to be sulfate.

In addition to the planned reductions that will be included as part of the State SIPs for regional 

haze, federal programs will also have significant benefits in reducing regional haze by 2018 and 

beyond. A list of EPA’s national and regional rules as well as voluntary programs that will assist 

in the reduction of fine particle pollution are as follows:

 Clean Air Interstate Rule (CAIR)

 The Acid Rain Program

 NOX SIP Call

 2004 Clean Air Nonroad Diesel Rule

 2007 Clean Diesel Trucks and Buses Rule

 Tier 2 Vehicle Emission Standards and Gasoline Sulfur Program

 Emission standards for other engines (highway and non-highway use)

 National Clean Diesel Campaign

 The Great American Woodstove Changeout

More information and links to the programs listed above can be found on the following website: 

http://www.epa.gov/pm/reducing.html
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 1: Introduction Page 1-2

DETERMINATION OF EMISSION SOURCE CATEGORIES AND INDIVIDUAL 

SOURCES MOST RESPONSIBLE FOR REGIONAL HAZE IN MANE-VU CLASS I 

AREAS

Particles in the PM2.5 size range are directly responsible for visibility reduction. Figure 1.1

generated by NESCAUM from analysis of monitoring data shows the components of PM2.5 mass 

at the seven Class I areas of concern on the 20% worst visibility days during the period from 

2000-2004. These components of PM2.5 are directly responsible for visibility reduction.

Figure 1.1

Contributions to PM2.5 Mass at 7 Sites

20% Worst Visibility Days (2000-2004)

#

#

#

#

#

#

#

Dolly Sods

Shenandoah

Brigantine

Lye Brook

Great Gulf

Acadia

Moosehorn

0

5

10

15

20

Soil

Sea Salt

OC

EC

Nitrate

Sulfate

Mass (ug/m3)

NESCAUM, 2006. “2000-2004 Visibility Rankings and Glide Paths.ppt.” PowerPoint Presentation developed by 

Gary Kleiman.

From Figure 1.1, it is apparent that sulfate is the largest contributor to PM2.5 mass at the Class I

areas of concern. The second largest contributor to PM2.5 mass is organic carbon (OC). Nitrates, 

elemental carbon (EC), soil, and sea salt also contribute to PM2.5 mass.

Source apportionment and other analyses documented in MANE-VU’s contribution assessment 

indicated that a number of source categories have impacts on visibility at MANE-VU Class I 

areas. The largest contribution to visibility impairment at most sites was SO2 from coalcombustion, primarily utility and industrial sources in MANE-VU and nearby States. At 

forested rural sites, biogenic organics are a moderate to large contributor to visibility impairment 

but other sources of secondary organics also contribute. Wood smoke and ammonium nitrate 

were identified as small to moderate contributors (see Appendix B of the Contribution 

Assessment).
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 1: Introduction Page 1-3

The contribution assessment also included an analysis of haze-associated pollutant emissions. 

“SO2 is the primary precursor pollutant for sulfate particles. Sulfate particles commonly account 

for more than fifty percent of particle light extinction at northeastern Class I areas on the clearest 

days and for as much as or more than eighty percent on the haziest days.” The assessment noted 

that point sources dominate SO2 emissions in the MANE-VU region. Point source emissions 

sources primarily consist of stationary combustion sources for generating electricity, industrial 

power, and heat. Commercial and residential heating constitute another important source 

category in MANE-VU States. An analysis of the largest sources in the region also indicates that 

a few large kilns are among the largest SO2 sources in the region.

Figures 1.2 and 1.3 show the top emissions source categories of PM2.5 and SO2 from Version 3 

of the 2002 MANE-VU emissions inventory. The largest SO2 source categories are the largest

contributors to visibility impairment in MANE-VU.

Figure 1.2 MANE-VU 2002 Version 3 Annual Emissions Inventory

Top PM2.5 Primary Source Categories

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000

Stationary Source Fuel Combustion-Residential (28%)

Unpaved Roads (10%)

Paved Roads (8%)

Open Burning-Waste Disposal, Treatment, and Recovery (5%)

Industrial Processes-Construction: SIC 15-17 (5%)

Stationary Source Fuel Combustion-Industrial (5%)

External Combustion Boilers-Electric Generation (4%)

Off-highway Vehicle Diesel (4%)

Miscellaneous Area Sources-Agricultural Production-Crops (3%)

Industrial Processes-Food and Kindred Products: SIC 20 (3%)

Highway Vehicles-Diesel (3%)

External Combustion Boilers-Industrial (2%)

Stationary Source Fuel Combustion-Commercial/Institutional (2%)

Highway Vehicles-Gasoline (2%)

Industrial Processes-Mining and Quarrying: SIC 14 (2%)

Industrial Processes-Mineral Products (2%)

Tons/Year

On-Road

Non-Road

Point

Area
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 1: Introduction Page 1-4

Figure 1.3 MANE-VU 2002 Version 3 Annual Emissions Inventory

Top SO2 Source Categories

Description of Individual Source Identification Process and Modeling

The following discussion describes the data and procedures that were used to identify the 

individual sources with the greatest impact on regional haze in MANE-VU Class I areas. The 

individual sources included in this report (see Chapters 3, 5, and 7) were determined by

identifying the sources with the maximum predicted 24-hour sulfate ion impact.

From 2004 to 2006, the Vermont Department of Environmental Conservation (VTDEC) 

participated in MANE-VU RPO planning activities by performing regional scale screening 

modeling of pollutants known to contribute to regional haze at Class I areas in the MANE-VU 

region. The model used by VTDEC was the CALPUFF model run on a domain including most 

of the eastern United States. Both point and area sources were modeled for the entire year 2002, 

and variable hourly CEMS emission data were used for all the largest 750+ EGUs in the domain. 

Model results were primarily intended to be used in conjunction with other source/receptor 

modeling methods as part of the technical underpinning of the document, Contributions to 

Regional Haze in the Northeast and Mid-Atlantic United States: Mid-Atlantic/Northeast 

Visibility Union (MANE-VU) Contribution Assessment, prepared by NESCAUM for MANE-VU 

and dated August 2006. This document contains more detailed discussion of the approach used 

to develop inputs for the modeling platform, the model setup, and its validation. It can be found 

at the following link: http://www.manevu.org/Document.asp?fview=Reports#

0 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1,600,000 1,800,000

External Combustion Boilers-Electric

Generation (70%)

External Combustion BoilersIndustrial (7%)

Stationary Source Fuel CombustionResidential (6%)

Stationary Source Fuel CombustionCommercial/Institutional (4%)

Stationary Source Fuel CombustionIndustrial (3%)

Industrial Processes-Mineral

Products (2%)

Highway Vehicles-Gasoline (1%)

Marine Vessels, Commercial (1%)

Off-highway Vehicle Diesel (1%)

External Combustion BoilersCommercial/Institutional (1%)

Tons/Year

On-Road

Non-Road

Point

Area
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 1: Introduction Page 1-5

Starting in 2006, through its participation on two MANE-VU RPO workgroups, (the BART 

Workgroup and the Reasonable Progress Workgroup), which were charged with developing 

technical support information for regional haze plans for the MANE-VU Class I areas, VTDEC 

made available some of the EGU source modeling results previously generated during its work 

on the contribution assessment report cited above. VTDEC also performed new point source 

modeling with the same CALPUFF modeling platform for a number of additional large point 

sources identified by the workgroups, primarily non-EGUs. The new point source modeling was 

performed for sources that did not have CEMS hourly emission data. This new modeling 

performed specifically for the workgroups differed in this fundamental way from the modeling 

of large EGUs with available CEMS hourly emission data which had been done for the 

contribution assessment. All new non-EGU point source modeling performed with CALPUFF 

by VTDEC for the BART and Reasonable Progress Workgroups utilized a constant average 

hourly emission rate (annual tons/8760) for the year 2002 based on emissions provided by the 

individual States in which the sources were located. Except for a more complete set of discrete 

receptors covering each Class I area, all other inputs and settings of the CALPUFF modeling 

system, including the NWS Observation-based CALMET created wind-fields, were exactly the 

same as used in the contribution assessment modeling work.

For the Reasonable Progress Workgroup, VTDEC assembled the results of its earlier individual 

CEMS-based stack modeling of EGUs into tables which listed the maximum 24-hr (calendar 

day) sulfate ion impact predicted at any receptor in each Class I area due to the emissions from 

each individual EGU modeled (more than 750). Because the largest contributing pollutant to 

visibility impairment in all the MANE-VU Class I areas is the sulfate ion, the Reasonable 

Progress Workgroup felt that ranking point sources based on this maximum 24-hour impact 

alone would be an appropriate way to prioritize their relative potential for improving visibility

and making reasonable progress at these areas. Once the maximum 24-hr sulfate ion impacts 

modeled for 2002 were ranked from greatest to smallest by EGU, the top impacting EGUs were 

identified for each of the Class I areas.

In order to examine and prioritize potentially controllable non-EGU large point sources of SO2

located both within MANE-VU and external to MANE-VU, the Reasonable Progress Workgroup 

examined the 2002 NEI based on SIC code selections. Selected stack points for sources selected 

were modeled individually using the stack parameters and the constant annual average emission 

rate of SO2 only. VTDEC converted the annual total tons of SO2 reported by the state to the NEI 

for that stack point into an average hourly emission rate and ran the CALPUFF model for the 

194 largest points identified in three lists supplied by Delaware. The selection of points to model 

was based first on a selection of the top 100 emitting points modeled from a group of several 

hundred ICI boilers (list 1) and Cement and Lime Kilns (list 2) identified by SCC code and 

extracted from the 2002 NEI database. Later this list of 100 stack emission points to model was 

expanded by adding the top 94 stack points not previously included in the ICI and kiln lists, but 

identified by more inclusive selection criteria based on SCC codes (list 3) and ranked by annual 

SO2 emissions.

The maximum predicted 24-hour sulfate ion impact from each of the 194 non-EGUs modeled 

were combined into an ordered table showing the largest impacting non-EGU at top and the least 

impacting non-EGU at the bottom for each Class I area. A similar ordered table was created 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 1: Introduction Page 1-6

showing the annual average sulfate ion impacts of these 194 non-EGU stack points. The top 

non-EGUs impacting each Class I area were then selected from the top of each list.

The ranked listings for EGUs represent the EGUs most likely to produce the largest sulfate ion 

impact at each Class I area on a 24-hour basis. The EGU modeled results were based on variable 

hourly SO2 emissions from the CEMS data submitted by the sources themselves. For the EGUs,

the modeled stack ID for which the hourly SO2 emission was reported might be a single electric 

generating unit or it might be a combination of two or more individual electric generating units 

operating at a plant and emitting from the same stack. The CALPUFF modeling was done on the 

emission rate supplied for the particular hour of the year 2002 and did not determine whether that 

emission was from a single EGU or from a combination of several at a plant. Therefore, to 

identify which particular unit at a plant reporting multiple units emitting from a single stack is 

responsible for the specific impact due to that hourly emission, would require more information 

than was available to VTDEC. The reported impact is from the stack and the distribution among

units combined in that stack’s CEMs data cannot be determined from the modeling results.

For the non-EGU points modeled, there is a slight probability that emissions modeled may have 

been only from a particular “process” level in the NEI database structure. There may have been 

more than one process reported for the same emission point during the year 2002 so that a sum of 

two or more process annual emissions should be modeled and summed for the entire unit level 

emission control potential to be identified. The top modeled impacts are simply the top for each 

area based on the 194 separate stack points modeled with each individual annual average 

emission rate supplied from one of the three NEI selected listings VTDEC received.

APPROACH TO DEMONSTRATING REASONABLE PROGRESS

Based on the contribution assessment, including modeling and emissions inventory analysis, 

MANE-VU selected the following source categories for analysis in this project:

 Coal and oil-fired Electric Generating Units, (EGUs);

 Point and area source industrial, commercial and institutional boilers;

 Cement kilns;

 Lime kilns;

 The use of heating oil; and

 Residential wood combustion

This document presents the results of an analysis of the economic and environmental impacts of 

potential control scenarios that could be implemented by MANE-VU States to demonstrate 

reasonable progress toward meeting visibility improvement goals. The purpose of this analysis 

is to present information that can be used by States to develop policies and implementation plans 

to address reasonable progress goals. Control technologies to achieve reasonable progress goals 

are evaluated with respect to four factors listed in the Clean Air Act (Section 169A):

 Cost,

 Compliance timeframe,

 Energy and non-air quality environmental impacts, and

 Remaining useful life for affected sources.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 1: Introduction Page 1-7

The “four factor” analysis is applied to control options identified for the selected source 

categories. The analysis of cement kilns and lime kilns was combined into one section due to the 

similarity of the two sources.

Category analyses are presented for electric generating units (EGUs), industrial, commercial, and 

institutional (ICI) boilers, cement kilns, lime kilns, distillate-oil fired heating units, and 

residential wood combustion. Only sulfur dioxide (SO2) emissions are considered for the first 

five categories. The SO2 emitted from sources in these five source categories comprised 

approximately 90% of all SO2 emitted from within MANE-VU in 2002. For residential wood 

combustion, the analysis is presented for particulate matter. PM2.5 emissions from this source

were 28% of the total PM2.5 emitted from within MANE-VU in 2002. Biomass burning causes 

both direct emissions of primary particles and emissions of volatile organics which can 

contribute to the formation of secondary organic carbon particles. Organic carbon is typically 

the second-largest contributor to regional haze in the MANE-VU region.

For EGUs, ICI boilers, and kilns control options include fuel switching, fuel preparation, in-situ

modifications, and add-on controls. Because of the similarity in available control options, 

cement and lime kilns have been combined into one category. For oil-fired heating oil, the only 

control option considered is reduction in sulfur content in the fuel oil. For residential wood 

combustion and outdoor wood-fired boilers, we have included descriptions of alternative 

technologies for replacement and emission reduction.

Additionally, we have assembled current and planned controls for the 20 specific non-EGU and 

30 EGU sources based on information from State agencies and Integrated Planning Model

(IPM®). The purpose of selecting these sources is to find out whether the sources that have the 

greatest impacts on Class I areas near MANE-VU in 2002 are already controlled or will be 

controlled by 2018. In many cases, States have supplied a schedule of planned controls for these 

facilities, which we have included in tabular form in this report. In the case of EGUs, we 

obtained information from the States and from modeled projections developed using Integrated 

Planning Model (IPM®).
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 1: Introduction Page 1-8

REFERENCES

NESCAUM, 2006. 2000-2004 Visibility Rankings and Glide Paths.ppt. PowerPoint 

Presentation developed by Gary Kleiman.

EPA. Information accessed on the web April 6, 2007. http://www.epa.gov/pm/reducing.html

Vermont Air Quality Planning. Personal communications regarding description of the source 

identification and modeling process from Paul Wishinski (802-241-3862, 

paul.wishinski@state.vt.us) via E-mail on April 4, 2007.

NESCAUM, 2006. Contributions to Regional Haze in the Northeast and Mid-Atlantic United 

States. Prepared by NESCAUM for MANE-VU, August, 2006.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-1

CHAPTER 2

SOURCE CATEGORY ANALYSIS: ELECTRIC GENERATING UNITS (EGUs)

SOURCE CATEGORY DESCRIPTION

The MANE-VU contribution assessment demonstrated that the principal contributor to visibility

impairment in Class I MANE-VU areas and Class I areas affected by emissions from sources 

within MANE-VU is SO2 from EGUs. Roughly 70% of the 2.3 million tons of SO2 emissions in 

the 2002 emissions inventory (2002 MANE-VU Emissions Inventory Version 3) were from 

EGUs, making them the largest source category contributing to regional haze in terms of total 

visibility impairing emissions and in terms of number of facilities.

Boilers at EGUs burn various fuels to produce heat for steam production which is then used to 

drive turbine generators for electricity production. The primary fuel combusted in EGU boilers 

in the eastern United States is coal from mines in the Midwest and Appalachia. Coal from this 

region generally contains 2-4% sulfur. The sulfur contained in the coal is emitted as SO2 from 

the boiler. Coal obtained from western States is generally lower in sulfur, with a sulfur content 

of <1%.

Nationally, 90% of the SO2 emissions from the EGUs are from coal-fired electric utility boilers. 

These coal-fired utility boilers are also the largest sources of NOX and PM emissions, which also 

contribute to regional haze. All coal-fired electric utility power plants in the United States use 

control devices to reduce PM emissions. Additionally, many of the boilers are required to use 

controls for SO2 or NOX emissions depending on site-specific factors such as the properties of 

the coal burned, when the power plant was built, and the area where the power plant is located. 

According to the EPA Clean Air Markets Division, (Personal communication with Mr. Peter 

Kokopeli, EPA – CAMD on April 3, 2007), as of January 1, 2006, the percentage of coal-fired

EGU capacity in the United States with SO2 and/or NOX control devices (as a percentage of heat 

input), were as follows:

2% of coal-fired EGU capacity had SO2 control only;

57% of coal-fired EGU capacity had NOX control only;

32% of coal-fired EGU capacity had SO2 and NOX controls;

9% of coal-fired EGU capacity had no SO2 or NOX controls.

As 66% of coal-fired EGU capacity, (as a percentage of heat input), have no SO2 controls, there 

is room for significant reductions in emissions of SO2. There is currently a trend towards 

improving control of SO2 through installation of additional controls and making other process 

and fuel changes. The four factor analysis of potential control scenarios for EGUs contained in 

this chapter addresses the control options and costs, time requirements, energy and non-air 

impacts, and source life associated with these controls.

Although PM and NOX from coal-fired utility boilers contribute to regional haze, the MANE-VU 

contribution assessment conducted by NESCAUM determined that SO2 from power plants was 

the largest contributor to regional haze in the MANE-VU Class I areas. Therefore, the focus of

this control option analysis for coal-fired boilers is on SO2 controls. Effects of the SO2 control 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-2

options on PM and NOX emissions are addressed where applicable, to ensure that the impact on 

emissions of these pollutants is considered for planning purposes.

In addition to coal combustion, some EGUs in MANE-VU States also burn fuel oil and/or 

natural gas. However, the EGU sources with the greatest impact on MANE-VU Class I areas 

were all coal-fired units. Emissions of SO2 from natural gas combustion are negligible, but SO2

emissions from fuel oil combustion are directly proportional to the sulfur content of the fuel. 

The cost of switching from a high sulfur distillate fuel oil to a lower sulfur distillate fuel oil is 

addressed in Chapter 8 of this report.

The SCCs applicable to coal-fired utility boilers include SCCs beginning 1-01-001-XX, 

1-01-002-XX, and 1-01-003-XX.

EVALUATION OF CONTROL OPTIONS

Effective post-combustion SO2 controls for EGUs and particularly coal-fired boilers are well 

understood and have been applied to a large number of sources over the years in response to 

regulations in the form of NSPS, PSD/NSR, State RACT Rules and the Title IV Acid Rain 

Program. Additional SO2 reductions are anticipated as a result of the Clean Air Interstate Rule 

(CAIR), which was finalized on May 12, 2005.

In addition to post-combustion controls that can be applied to reduce emissions of SO2 from 

coal-fired boilers, there are other strategies that can be used to reduce emissions of SO2. 

Examples of such strategies include switching to a fuel with a lower sulfur content, and coal 

cleaning prior to combustion. Methods of SO2 control applicable to coal-fired boilers are listed 

in Table 2.1 with a brief description of the control option, applicability, and range of 

performance. A more detailed description of the control option and an analysis of the four factor 

assessment for reasonable progress follow the table.

MACTEC assembled the list of available SO2 control options for the EGU source category given 

in Table 2.1 from available documentation. Note that the estimated performance of each control 

option varies greatly and depends on a variety of site specific factors, including the boiler type. 

Examples of three major types of coal-fired boiler include fluidized bed combustors, stoker 

boilers, and pulverized coal boilers. In addition to these three types of coal-fired boilers there are 

many subcategories of boilers, characterized by their specific design. Control devices designed 

for these types of boilers vary in terms of cost as well as estimated performance.
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-3

Table 2.1 SO2 Control Options for Coal-fired EGU Boilers

Technology Description Applicability Performance

Switch to a Low Sulfur 

Coal (generally <1% sulfur) 

Replace high-sulfur 

bituminous coal combustion 

with lower-sulfur coal

Potential control measure 

for all coal-fired EGUs 

currently using coal with 

high sulfur content

50-80% reduction in SO2

emissions by switching to a 

lower-sulfur coal

Switch to natural gas 

(virtually 0% sulfur)

Replace coal combustion 

with natural gas

Potential control measure 

for all coal-fired EGUs

Virtually eliminate SO2

emissions by switching to 

natural gas

Coal Cleaning Coal is washed to remove 

some of the sulfur and ash 

prior to combustion

Potential control measure 

for all coal-fired EGUs

20-25% reduction in SO2

emissions

Flue Gas Desulfurization 

(FGD) - Wet

SO2is removed from flue 

gas by dissolving it in a 

lime or limestone slurry. 

(Other alkaline chemicals 

are sometimes used)

Applicable to all coal-fired 

EGUs

30-95%+ reduction in SO2

emissions

Flue Gas Desulfurization 

(FGD) – Spray Dry

A fine mist containing lime 

or other suitable sorbent is 

injected directly into flue 

gas

Applicable primarily for 

boilers currently firing low 

to medium sulfur fuels

60-95%+ reduction in SO2

emissions

Flue Gas Desulfurization 

(FGD) –Dry

Powdered lime or other 

suitable sorbent is injected 

directly into flue gas

Applicable primarily for 

boilers currently firing low 

to medium sulfur fuels

40-60% reduction in SO2

emissions

Table references:

1. Assessment of Control Technology Options for BART-Eligible Sources, NESCAUM, March 2005.

2. Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options, STAPPA-ALAPCO, March

 2006.

Switch to Low Sulfur Coal

Fuel switching encompasses several different control options. Often it is not possible to 

completely switch from one type of fuel to another. One option is blending lower-polluting fuels 

with baseline fuels to reduce overall emissions. For example, many coal-fired boiler operators 

blend lower sulfur subbituminous coals with high sulfur bituminous coals to reduce SO2

emissions. In other cases, bituminous coals with a lower sulfur content can be substituted for 

high sulfur bituminous coal.

The feasibility of fuel switching depends partly on the characteristics of the plant and the 

particular type of fuel change being considered. Many plants will be able to switch from 

high-sulfur to low-sulfur bituminous coal without serious difficulty, but switching from 

bituminous to subbituminous coal may present greater challenges and costs. In some instances, 

fuel switching will require significant investment and modifications to an existing plant. 

Switching to a lower sulfur coal can affect coal handling systems, boiler performance, PM 

control effectiveness and ash handling systems. In any case, fuel switching or blending has been 
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-4

a key strategy used by EGUs to comply with the federal Acid Rain Program. Overall SO2

reductions estimated from switching to low-sulfur coal range from 50-80%.

Switch to Natural Gas

Switching from coal combustion to natural gas combustion virtually eliminates SO2 emissions, 

but it is currently uneconomical to consider this option for base load EGUs due to the fuel 

quantity necessary and the price of natural gas. The price of natural gas and coal are variable, 

but in terms of heating value, the price of natural gas over the past several years has been several 

times higher than coal. According to information published on the EIA website, in January 2007

the price of natural gas was approximately four times higher than coal according to average 

monthly costs of fuel delivered to electricity producers during that month.

Coal Cleaning

According to the 2006 STAPPA-ALAPCO document on control technologies titled Controlling 

Particulate Matter Under the Clean Air Act: A Menu of Options, coal cleaning or washing is a 

widely practiced method of reducing impurities in coal, particularly sulfur. Reducing the sulfur 

content of the fuel used in the boiler reduces the SO2 emissions proportionally. Coal cleaning 

has been shown to reduce SO2 emissions by 20-25%, while increasing the heating value of the 

fuel. Additional removal can be achieved through advanced chemical washing techniques, but 

no detailed information on these techniques was available.

Conventional (physical) coal washing techniques remove ash and sulfur from coal by crushing 

the fuel and separating the components in a liquid bath, such as water. The lighter coal particles 

float to the top of the bath for recovery, while the heavier impurities sink to the bottom for 

removal.

Coal sulfur exists in two forms, inorganic and organic. The inorganic sulfur in coal called pyrite

is primarily in the form of ferrous sulfate (FeSO4). Because it is not chemically bound within the 

coal, 40-50% of this pyrite can be removed through coal washing. The organic form of sulfur is 

chemically bound in the molecular structure of the coal itself and cannot be physically washed 

out. Organic sulfur accounts for between 35-75% of the total sulfur in Illinois Basin coals in the 

example given by STAPPA-ALAPCO. Depending on the percentage of the sulfur in a given 

coal sample which exists in the form of pyrite, varying amounts of the total sulfur can be 

removed.

Although there are benefits associated with coal washing, there are limitations associated with 

this technology. The 20-25% SO2 reduction is beneficial, but post-combustion controls have 

been shown to reduce SO2 emissions by greater percentages. Also, solid and liquid wastes are 

generated using the washing process and must be addressed.

Flue Gas Desulfurization (FGD) - Wet

There are three types of FGD scrubbers: wet, spray dry, and dry. According to the 2006 

STAPPA-ALAPCO document on control technologies titled Controlling Particulate Matter 

Under the Clean Air Act: A Menu of Options, EPA reports that 85% of the FGD systems in the 
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-5

United States are wet systems. Twelve percent of the FGD systems are spray dry systems, and 

3% are dry systems. The operating parameters, impacts on capacity factor, and costs of each 

SO2 removal method are different. Capacity factor is the amount of energy a facility generates in 

one year divided by the total amount it could generate if it ran at full capacity.

SO2 in the flue gas can be removed by reacting the sulfur compounds with a solution of water 

and an alkaline chemical to form insoluble salts that are removed in the scrubber effluent. These 

processes are called “wet FGD systems”. Most wet FGD systems are based on using either 

limestone or lime as the alkaline source. At some of these facilities, fly ash is mixed with the 

limestone or lime. Several other scrubber system designs (e.g., sodium carbonate, magnesium 

oxide, dual alkali) are used by a small percentage of the total number of boilers.

The basic wet limestone scrubbing process is simple and is the type most widely used for control 

of SO2 emissions from coal-fired electric utility boilers. Limestone sorbent is inexpensive and 

generally available throughout the United States. In a wet limestone scrubber, the flue gas 

containing SO2 is brought into contact with limestone/water slurry. The SO2 is absorbed into the 

slurry and reacts with limestone to form an insoluble sludge. The sludge, mostly calcium sulfite 

hemihydrate and gypsum, is disposed of in a pond specifically constructed for the purpose or is 

recovered as a salable byproduct. Integrated Planning Model (IPM

®

) used by EPA to predict 

future EGU control strategies assumes that this technology will be used to control SO2 from 

coal-fired boilers that are 100 MW or larger, that combust bituminous coal with 2% or higher 

sulfur content by weight. Integrated Planning Model (IPM®) documentation refers to the specific 

scrubber technology as Limestone Forced Oxidation, (LSFO), and assumes 95% SO2 removal 

using this technology. Data and documentation obtained for use in this report are from 

Integrated Planning Model (IPM®) version 2.1.9.

The wet lime scrubber operates in a similar manner to the wet limestone scrubber. In a wet lime 

scrubber, flue gas containing SO2 is contacted with hydrated lime/water slurry; the SO2 is 

absorbed into the slurry and reacts with hydrated lime to form an insoluble sludge. The hydrated 

lime provides greater alkalinity (higher pH) and reactivity than limestone. However, limescrubbing processes require disposal of large quantities of waste sludge.

Another wet scrubber technology used to control emissions of SO2 from EGUs is Magnesium 

Enhanced Lime, (MEL). This technology is available to coal-fired boilers from 100 MW to 

550 MW in capacity, that combust bituminous, sub-bituminous or lignite coal with less than 

2.5% sulfur content by weight. Integrated Planning Model (IPM®) assumes that MEL provides

96% SO2 removal.

The SO2 removal efficiencies of existing wet limestone scrubbers range from 31-97%, with an 

average of 78%. The SO2 removal efficiencies of existing wet lime scrubbers range from 30 to 

95%. For both types of wet scrubbers, operating parameters affecting SO2 removal efficiency

include liquid-to-gas ratio, pH of the scrubbing medium, and the ratio of calcium sorbent to SO2. 

Periodic maintenance is needed because of scaling, erosion, and plugging problems. Recent 

advancements include the use of additives or design changes to promote SO2 absorption or to 

reduce scaling and precipitation problems.
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Chapter 2: Source Category Analysis: Electric Generating Units Page 2-6

Flue Gas Desulfurization (FGD) – Spray Dry

A spray dryer absorber (sometimes referred to as wet-dry or semi-dry scrubber) operates by the 

same principle as wet lime scrubbing, except that the flue gas is contacted with a fine mist of 

lime slurry instead of a bulk liquid (as in wet scrubbing). For the spray dryer absorber process, 

the combustion gas containing SO2 is contacted with fine spray droplets of hydrated lime slurry

in a spray dryer vessel. This vessel is located downstream of the air heater outlet where the gas 

temperatures are in the range of 120 to 180 °C (250 to 350 °F). The SO2 is absorbed in the slurry

and reacts with the hydrated lime reagent to form solid calcium sulfite and calcium sulfate sludge

as in a wet lime scrubber. The water is evaporated by the hot flue gas and forms dry, solid 

particles containing the reacted sulfur. These particles are entrained in the flue gas, along with 

fly ash, and are collected in a PM collection device. Most of the SO2 removal occurs in the spray

dryer vessel itself, although some additional SO2 capture has also been observed in downstream 

particulate collection devices, especially fabric filters. This process produces dry reaction waste 

products for easy disposal.

The primary operating parameters affecting SO2 removal are the calcium-reagent-to-sulfur 

stoichiometric ratio and the approach to saturation in the spray dryer. To increase overall sorbent 

use, the solids collected in the spray dryer and the PM collection device may be recycled. The 

SO2 removal efficiencies of existing lime spray dryer systems range from 60-95%.

Lime Spray Drying (LSD) is a dry SO2 scrubber technology applied in Integrated Planning 

Model (IPM®) runs for coal-fired boilers 550 MW or larger that combust bituminous, 

subbituminous or lignite coal with sulfur content between 0.4% and 2% sulfur by weight. 

Integrated Planning Model (IPM®) assumes that LSD provides 90% SO2 removal.

Flue Gas Desulfurization (FGD) –Dry

For the dry injection process, dry powdered lime (or another suitable sorbent) is directly injected 

into the ductwork upstream of a PM control device. Some systems use spray humidification 

followed by dry injection. This dry process eliminates the slurry production and handling 

equipment required for wet scrubbers and spray dryers, and produces dry reaction waste products 

for easier disposal. The SO2 is adsorbed and reacts with the powdered sorbent. The dry solids 

are entrained in the combustion gas stream, along with fly ash, and collected by the PM control 

device. The SO2 removal efficiencies of existing dry injection systems range from 40-60%.

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR EGUs

Each of the control options presented in Table 2.1 is evaluated in this section according to the 

four factors for determining reasonable progress as required by Section 169A(g)(1) of the Clean 

Air Act and 40 CFR 51.308(d)(1)(i)(A). The information provided in this section is intended to 

be used by the States in setting Reasonable Progress Goals for reducing regional haze in the 

MANE-VU Class I areas.
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Chapter 2: Source Category Analysis: Electric Generating Units Page 2-7

Cost of Compliance

For EGUs, EPA used Integrated Planning Model (IPM®) to predict which units will install 

controls at what costs and which units will buy credits. Integrated Planning Model (IPM®)

predicts a least-cost solution to meet power production demands within emissions constraints. 

Emissions may be reduced by fuel-switching, use of controls or by using power from a cleaner 

unit. The RPOs made some Integrated Planning Model (IPM®) runs to determine which units 

will install controls to comply with the EPA CAIR rule. Additionally, MANE-VU investigated 

an even more stringent “CAIR Plus” strategy using Integrated Planning Model (IPM®). In 

Chapter 3, the parsed results (projections disaggregated to the unit level), available for the CAIR 

Plus strategy are used to help estimate costs for specific EGUs. It should be noted that Integrated 

Planning Model (IPM®) is an industry-wide model, and the control costs output from the model

represent the industry-wide average cost of control that can be expected based on a set industrywide emission reduction. Integrated Planning Model (IPM®

) results can also be viewed as the 

predicted cost of control at a model plant. The costs of control at individual facilities are

dependent on a number of factors and cannot be determined for any specific individual facility

from Integrated Planning Model (IPM®) results.

Table 2.2 contains the marginal costs of SO2 emission reductions, also known as the SO2

allowance price, for MANE-VU Base Case CAIR, (MARAMA_5c), and CAIR Plus, 

(MARAMA 4c), Integrated Planning Model (IPM®) runs. These costs include the capital costs 

of new investments, fuel costs, and the operation and maintenance costs of power plants. For 

both the CAIR and CAIR Plus run, Integrated Planning Model (IPM®) installed scrubbers to 

meet the demand for SO2 reduction while meeting the demand for electricity. Integrated 

Planning Model (IPM®) also installed NOX controls, but the cost of achieving the NOX emissions 

reductions was provided independently from SO2 controls. Application of SO2 controls such as 

use of cleaner and lower-sulfur coals or post combustion controls such as wet scrubbers 

generally help to reduce PM emissions in addition to SO2. SO2 controls generally do not affect

PM or NOX emissions.

Table 2.2 Marginal Costs of Emission Reductions (Allowance Prices) Calculated by 

Integrated Planning Model (IPM®) for the CAIR Base Case and CAIR Plus Runs

(2006 $/ton)

Pollutant CAIR Base Case (MARAMA_5c) CAIR Plus Policy Case (MARAMA_4c)

2008 2009 2010 2012 2015 2018 2008 2009 2010 2012 2015 2018

SO2 774 837 905 979 1,141 1,338 975 1,055 1,139 1,233 1,437 1,684

Table reference:

Final Draft Report - Comparison of CAIR and CAIR Plus Proposal Using the Integrated Planning Model (IPM®), 

ICF Resources; May 30, 2007.

Note – A conversion factor of 1.2101 was used to convert the dollar values from 1999 to 2006

www.inflationdata.com

The CAIR Plus strategy requires additional SO2 and NOX control beyond EPA’s CAIR program. 

ICF’s report on the CAIR and CAIR Plus Integrated Planning Model (IPM®) runs titled: Final 

Draft Report - Comparison of CAIR and CAIR Plus Proposal Using the Integrated Planning
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-8

Model (IPM®), states that the power sector opts for a technology strategy for complying with the 

CAIR Plus proposal requirements. In the CAIR Plus analysis, the CAIR Plus region requires the 

installation of an additional 19.5 GW of scrubbers and 77.8 GW of SCR by 2012. These controls 

represent a 30% increase in scrubbers and 185% increase in SCRs in 2012 compared to the 

Integrated Planning Model (IPM®) CAIR run. By 2018, the cumulative installation of scrubbers 

is 17% higher and the installation of SCR is 98% higher for the CAIR Plus run compared to the 

CAIR run. The resulting SO2 and NOX emissions from the CAIR and CAIR Plus Integrated 

Planning Model (IPM®) runs are listed for MANE-VU in Table 2.3.

Table 2.3 NOX and SO2 Emissions from the Electric Power Sector

(Thousand Tons)

2008

SO2| NOX

2009

SO2| NOX

2010

SO2| NOX

2012

SO2| NOX

2015

SO2| NOX

2018

SO2| NOX

CAIR Base Case (MARAMA_5c) 802 | 386 650 | 272 518 | 213 463 | 209 410 | 202 394 | 199

CAIR Plus Policy Case (MARAMA_4c) 735 | 376 556 | 228 396 | 159 376 | 162 312 | 153 271 | 146

Table reference:

Final Draft Report - Comparison of CAIR and CAIR Plus Proposal Using the Integrated Planning Model (IPM®), 

ICF Resources; May 30, 2007.

Cost of Switching to Low Sulfur Coal

Switching to a low-sulfur coal or blending a lower sulfur coal can impact cost due to the 

following two main reasons:

1. The cost of low-sulfur coal compared to higher sulfur coal

2. The cost of necessary boiler or coal handling equipment modifications

The cost of low-sulfur coal compared to higher sulfur coal is not only related to the “dollar per 

ton” cost of the coal, but also related to the heating value of the coal.

Recent data from the Energy Information Administration show the average price of coals from 

various locations together with estimated heating values and sulfur content. The prices of coal 

indicated in Tables 2.4 and 2.5 do not include the cost of delivery.

The energy-based cost of each of the coals listed in Table 2.4 is approximately the same, with the 

exception of coal from the Powder River Basin. Powder River Basin coal has a significantly 

lower heating value than the other four varieties of coal, but on an energy basis, it is still 

approximately one third the cost of the other coals listed. Since Powder River Basin coal 

contains significantly less sulfur, it would seem that this coal would be the best fuel for boilers 

trying to incorporate a lower sulfur coal. Unfortunately, due to the lower heating value of the 

coal, boilers that are configured to burn coal with a higher heating value can only use a small 

percentage of this low-sulfur coal (no higher than 15% Powder River Basin coal). The only way 

to burn higher percentages of the Powder River Basin coal would be to extensively retrofit the 

boilers or suffer from poor boiler performance and other operating difficulties. Such retrofits 

should be reviewed in light of current Prevention of Significant Deterioration (PSD) permitting 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-9

regulations to ensure that all such requirements are met and that emissions do not increase. The 

coal prices included in Table 2.4 do not reflect the cost of boiler retrofits required to combust 

low sulfur coal.

Table 2.4 Recent Average Coal Prices from Various Locations in the U.S. (12/2006)

($/ton)

Central 

Appalachia 

(Bituminous)

Northern 

Appalachia 

(Bituminous)

Illinois Basin 

(Bituminous)

Powder River 

Basin 

(Subbituminous)

Uinta Basin 

(Low-S 

Bituminous)

Coal Heating 

Value (BTU/lb)

12,500 13,000 11,000 8,800 11,700

Sulfur Content

(%)

1.2 <3 5 0.8 0.8

Cost/ton ($) $47.25 $43.00 $33.33 $9.85 $36.00

Table reference:

EIA website accessed on 2/20/07: http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html

The two types of coal used for fuel in EGU boilers in the United States are bituminous and 

subbituminous coals. Bituminous coals have varying amounts of sulfur, but the sulfur content of 

bituminous coal is generally higher than subbittuminous coal. Traditionally, many EGU boilers 

have been designed to combust bituminous coal because of the higher carbon content and heating 

value.

Table 2.5 shows the average 2005 cost data from the Energy Information Administration for 

bituminous and subbituminous coal. The purpose of this information is to demonstrate the 

difference in cost of these coals based on their heating value. Assuming a heat content for 

bituminous coal of 12,000 BTU/lb and 10,000 BTU/lb for subbituminous coal allows the 

calculation of the cost of the coal on an energy basis. The coal prices included in Table 2.5 do 

not reflect the cost of boiler retrofits required to combust low sulfur coal.

Table 2.5 Average U.S. Bituminous and Subbituminous Coal Prices

(2006 dollars/ton)

Fuel Average Price per Ton Average Price per MMBTU

Bituminous Coal $38.00 $1.58

Subbituminous Coal $8.96 $0.44

Table reference:

EIA website accessed on 2/20/07: http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html

Note – A conversion factor of 1.0323 was used to convert the dollar values from 2005 to 2006 

www.inflationdata.com

Switching to subbituminous coal can reduce SO2 emissions by up to 80%, but changes must be 

made to the boilers to compensate for the lower heating value of the subbituminous coal. Much 

of the difference in fuel price is due to the difficulty in using subbituminous coal in boilers 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-10

designed to combust bituminous coal. The 2006 STAPPA-ALAPCO document, Controlling 

Fine Particulate Matter Under the Clean Air Act, states that “fuel substitution is not feasible for 

sources where the substitution would require excessive retrofits or would entail substantial 

performance losses.”

Cost of Coal Cleaning

The World Bank reports that the cost of physically cleaning coal varies from $1 to $10 per ton of 

coal cleaned, depending on the coal quality, the cleaning process used, and the degree of 

cleaning desired. In most cases the costs were found to be between $1 and $5 per ton of coal 

cleaned. Based on the recent prices of coal from Tables 2.4 and 2.5, this cost represents a 2-15% 

increase in the cost of coal.

In addition to lowering the emissions from coal combustion, coal cleaning also increases the 

heating value of the fuel. This lowers the transportation cost of the fuel per unit of energy, 

offsetting the costs associated with the coal washing. It is not clear whether this has been taken 

into account in the cost information provided by the World Bank.

Cost of Flue Gas Desulfurization (FGD) – Wet

The cost of flue gas desulfurization varies depending on a number of factors including the size of 

the boiler, SO2 reduction requirements, boiler capacity factor, and fuel sulfur content. Taking 

these factors into account, the typical cost effectiveness of a 1,000 MMBTU/hr (~300MW) coalfired boiler equipped with wet FGD is around $410 per ton of SO2 reduced when combusting 

high-sulfur coal. This cost is based on a boiler capacity factor of 83% and SO2 removal 

efficiency of 90%. Assuming the same boiler and SO2 control efficiency, but firing low-sulfur 

coal, the cost per ton is slightly more expensive at $510 per ton of SO2 controlled. (Controlling 

Fine Particulate Matter Under the Clean Air Act: A Menu of Options, STAPPA-ALAPCO, 

March 2006) (Converted from 2003 to 2006 dollars using a conversion factor of 1.0959 

www.inflationdata.com)

A similar cost estimation from the same STAPPA-ALAPCO document provides information for 

boilers in the size range of >4,000 MMBTU/hr (~ 1,200 MW) and <4,000 MMBTU/hr achieving 

>90% SO2 removal efficiency. These cost estimates demonstrate the initial and ongoing costs of 

installing wet scrubbers. For units >1,200 MW, the capital costs are between $380-$850/MW; 

operation and maintenance costs (O&M) range from $7-$27/MW; and the ultimate cost 

effectiveness is shown to be from $230-$570/ton SO2 removed. For boilers <1,200 MW, the 

capital costs are between $850-$5,100/MW; operation and maintenance costs (O&M) range from 

$28-$68/MW; and the ultimate cost effectiveness is shown to be from $570-$5,700/ton SO2

removed. This information demonstrates a strong cost effectiveness advantage realized by

installing control devices on the larger emission units. (Converted from 2001 to 2006 dollars 

using a conversion factor of 1.1383 www.inflationdata.com)

In another independent analysis of control costs, Integrated Planning Model (IPM®) background 

documentation defines a range of control efficiencies, costs, and applicability based on unit size 

and coal type. (http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html) Two wet 

scrubber (wet FGD) control technologies are discussed in Integrated Planning Model (IPM

®

)
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-11

background documentation; (1) Limestone Forced Oxidation (LSFO), and (2) Magnesium 

Enhanced Lime (MEL). Both of the scrubber control technologies are applicable to distinct unit 

sizes and coal types, but there is no indication in the parsed Integrated Planning Model (IPM®)

results as to which type of scrubber has been applied by the model. Both scrubber technologies 

are assumed to achieve a SO2 removal percentage of 95% or greater. According to Integrated 

Planning Model (IPM®) documentation, the costs used by Integrated Planning Model (IPM®) for 

these control technologies were developed by EPA and presented in a document titled 

Emissions: A Review of Technologies, (EPA-600/R-00-093), October 2000 prepared by EPA’s 

Office of Research and Development. The cost and performance calculations were primarily a 

function of heat rate, capacity, and sulfur content. The range of various scrubber costs is 

included in Attachment 1. Using the data in Attachment 1 and applying a standard engineering 

economics analysis (Attachment 2), the costs of SO2 removal using these control technologies 

vary from approximately $300-$1,100 per ton of SO2 removal, (Converted from 1999 to 2006 

dollars using a conversion factor of 1.2101 www.inflationdata.com).

Cost of Flue Gas Desulfurization (FGD) – Spray Dry

The cost of flue gas desulfurization varies depending on a number of factors including the size of 

the boiler, SO2 reduction requirements, boiler capacity factor, and fuel sulfur content. Taking 

these factors into account, the typical cost effectiveness of a 1,000 MMBTU/hr (~300MW) coalfired boiler equipped with spray dry FGD is around $420 per ton of SO2 reduced. This cost is 

based on a boiler capacity factor of 83% and SO2 removal efficiency of 90%. (Controlling Fine 

Particulate Matter Under the Clean Air Act: A Menu of Options, STAPPA-ALAPCO, March 

2006) (Converted from 2003 to 2006 dollars using a conversion factor of 1.0959 

www.inflationdata.com)

EPA reports in a 2005 document titled Multipollutant Emission Control Technology Options for 

Coal-fired Power Plants, that conventional Spray Dry FGD systems can cost from $155-$237

per kW, have fixed operation and maintenance costs ranging from $1.55-$7.25 per kW-yr, and 

variable operation and maintenance costs from 0.2-0.7 mills/kWh. These costs are associated 

with a 300 MW plant. (Converted from 2005 to 2006 dollars using a conversion factor of 1.0322 

www.inflationdata.com)

A similar cost estimation from STAPPA-ALAPCO, 2006 provides information for boilers in the 

size range of >2,000 MMBTU/hr (~600 MW) and <2,000 MMBTU/hr achieving from 80-90% 

SO2 removal efficiency. These cost estimates provide the initial and ongoing costs of installing 

wet scrubbers. For units >600 MW, the capital costs are between $140-$510/MW; operation and 

maintenance costs range from $14-$34/MW; and the ultimate cost effectiveness is shown to be 

from $170-$340/ton SO2 removed. For boilers <600 MW per hour, the capital costs are between 

$510-$5,100/MW; operation and maintenance costs (O&M) range from $34-$1,020/MW; and 

the ultimate cost effectiveness is shown to be from $570-$4,550/ton removed. As was the case

with wet scrubbers, this information demonstrates a strong cost effectiveness advantage realized 

by installing control devices on the larger emission units. (Converted from 2001 to 2006 dollars 

using a conversion factor of 1.1383 www.inflationdata.com)

Integrated Planning Model (IPM®) background documentation defines a range of control 

efficiencies, costs, and applicability based on unit size and coal type. 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-12

(http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html) Lime Spray Dry (LSD) 

technology is one form of SO2 control applied by Integrated Planning Model (IPM®). LSD is 

assumed to achieve a SO2 removal percentage of 90%. According to Integrated Planning Model 

(IPM®) documentation, the costs used by Integrated Planning Model (IPM®) for these control 

technologies were developed by EPA and presented in a document titled Emissions: A Review of 

Technologies, (EPA-600/R-00-093), October 2000 prepared by EPA’s Office of Research and 

Development. The cost and performance calculations were primarily a function of heat rate, 

capacity, and sulfur content. The range of various scrubber costs is included in Attachment 1. 

Depending on boiler size, boiler capacity factor, and coal sulfur content, the fixed capital costs 

range from $142 to $183/kW, while fixed operation and maintenance costs (O&M) range from 

$5 to $7/kW-yr and variable O&M costs range from 1.9 to 2.4 mills/kWh. Assuming the typical 

costs in Attachment 1, an EGU rated 800 MW, a capital cost investment of $156/kW or $125 

million would be expected. Fixed O&M and variable O&M costs would be approximately

$6/kW-yr and 2.2 mills/kWh respectively and would depend on the EGU annual output. This 

cost could be expected to reduce SO2 emissions by 90%. The cost and performance calculations 

were primarily a function of heat rate, capacity, and sulfur content. Using the data in Attachment 

1 and applying a standard engineering economics analysis (Attachment 2), the costs of SO2

removal using this control technology varies from approximately $480-$600 per ton of SO2

removal, (Converted from 1999 to 2006 dollars using a conversion factor of 1.2101 

www.inflationdata.com).

Cost of Flue Gas Desulfurization (FGD) – Dry

The cost of flue gas desulfurization varies depending on a number of factors including the size of 

the boiler, SO2 reduction requirements, boiler capacity factor, and fuel sulfur content. Taking 

these factors into account, the typical cost effectiveness of a 1,000 MMBTU/hr (~300MW) coalfired boiler equipped with dry FGD is around $693 per ton of SO2 reduced when combusting 

high-sulfur coal. This cost is based on a boiler capacity factor of 83% and SO2 removal 

efficiency of 40%. Assuming the same boiler and SO2 control efficiency, but firing low-sulfur 

coal, the cost per ton is slightly higher at $764 per ton of SO2 controlled. (Controlling Fine 

Particulate Matter Under the Clean Air Act: A Menu of Options, STAPPA-ALAPCO, March 

2006) (Converted from 2003 to 2006 dollars using a conversion factor of 1.0959 

www.inflationdata.com)

The 2005 EPA document titled, Multipollutant Emission Control Technology Options for Coalfired Power Plants, shows that advanced dry FGD systems can cost from $50-$150 per kW, have 

fixed operation and maintenance costs ranging from <$1 -$3 per kW-yr, (based on 1-2% of 

capital), and variable operation and maintenance costs from 0.2-0.7 mills/kWh. Assuming an 

SO2 reduction percentage of 40%, capacity factor of 85%, coal sulfur content of 1.5%, and coal 

heat content of 12,000 BTU/lb and applying a standard engineering economics analysis 

(Attachment 2), the costs of SO2 removal using this control technology varies from 

approximately $250-$850 per ton (Converted from 2005 to 2006 dollars using a conversion 

factor of 1.0322 www.inflationdata.com)).
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-13

Summary of SO2 Reduction Costs

The cost of SO2 reductions on a per ton basis for EGUs is dependent on the cost (and 

availability) of fuels, boiler size and type, equipment retrofit costs, the desired emission

reduction, and other site specific factors. Although these factors can cause the cost of the 

reductions to be well above or below the industry average, a summary of estimated ranges for 

SO2 reductions is included in Table 2.6 for FGDs. Sufficient data were not available to calculate 

a range of costs with reasonable certainty for fuel switching or coal cleaning. Within the range 

of estimated costs for a given boiler size, the low end of the SO2 reduction cost is generally 

associated with a high boiler capacity factor. The reason for this is due to the high capital costs 

and fixed operation and maintenance costs of the control device. With higher boiler capacity

factors, the control device is able to reduce more tons of SO2, which effectively reduces the per 

ton cost of the reduction.

Table 2.6 Estimated Cost Ranges for SO2 Control Options for Coal-fired EGU Boilers

(2006 dollars/ton of SO2 Reduced)

Technology Description Performance

Cost Range

(2006 dollars/ton of 

SO2 Reduced)

Switch to a Low Sulfur 

Coal (generally <1% sulfur) 

Replace high-sulfur 

bituminous coal combustion 

with lower-sulfur coal

50-80% reduction in SO2

emissions by switching to a 

lower-sulfur coal

Potential reduction in coal 

costs, but possibly offset by

expensive retrofits and loss 

of boiler efficiency

Switch to natural gas 

(virtually 0% sulfur)

Replace coal combustion 

with natural gas

Virtually eliminate SO2

emissions by switching to 

natural gas

Unknown – cost of switch is 

currently uneconomical due 

to price of natural gas

Coal Cleaning Coal is washed to remove 

some of the sulfur and ash 

prior to combustion

20-25% reduction in SO2

emissions

2-15% increase in fuel costs 

based on current prices of 

coal

Flue Gas Desulfurization 

(FGD) – Wet

SO2is removed from flue 

gas by dissolving it in a 

lime or limestone slurry. 

(Other alkaline chemicals 

are sometimes used)

30-95%+ reduction in SO2

emissions

$570-$5,700 for EGUs 

<1,200 MW

$330-$570 for EGUs

>1,200 MW

Flue Gas Desulfurization 

(FGD) – Spray Dry

A fine mist containing lime 

or other suitable sorbent is 

injected directly into flue 

gas

60-95%+ reduction in SO2

emissions

$570-$4,550 for EGUs 

<600 MW

$170-$340 for EGUs 

>600 MW

Flue Gas Desulfurization 

(FGD) –Dry

Powdered lime or other 

suitable sorbent is injected 

directly into flue gas

40-60% reduction in SO2

emissions

$250-$850 for EGUs 

~300 MW

Table references:

1. EIA website accessed on 2/20/07: http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html

2. EIA website accessed on 2/20/07: http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html

3. STAPPA-ALAPCO. Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options; March

 2006.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-14

4. U.S. EPA. EPA-600/R-05/034; Multipollutant Emission Control Technology Options for Coal-fired Power

 Plants; March 2005.

5. U.S. EPA. Integrated Planning Model (IPM®) background documentation located on website:

 http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html

6. Final Draft Report - Comparison of CAIR and CAIR Plus Proposal Using the Integrated Planning Model

 (IPM®), ICF Resources; May 30, 2007.

7. World Bank Organization. Information located on website:

 http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqsocc.stm

Time Necessary for Compliance

Generally, sources are given a 2-4 year phase-in period to comply with new rules. Under the 

previous Phase I of the NOX SIP Call, EPA provided a compliance date of about 31⁄2 years from 

the SIP submittal date. Most MACT standards allow a 3-year compliance period. Under Phase I 

of the NOX SIP Call, EPA provided a 2-year period after the SIP submittal date for compliance. 

States generally provided a 2-year period for compliance with RACT rules. For the purposes of 

this review, we have assumed that a maximum of 2 years after SIP submittal is adequate for precombustion controls (fuel switching or cleaning) and a maximum of 3 years is adequate for the 

installation of post combustion controls.

For post-combustion controls, site-specific information must be supplied to vendors in order to 

determine the actual time needed for installation of a given control. Large scale implementation 

of control devices within the EGU sector, particularly in a short time period, may require 

consideration of impacts on regional electricity demands. Integrated Planning Model (IPM®) has 

allowed for these and other impacts in determining the least cost approach to emission 

reductions, however, there is a great deal of uncertainty associated with modeled results in 

comparison to real-world applications of control strategies.

For BART control measures, the proposed BART guidelines require States to establish 

enforceable limits and require compliance with the BART emission limitations no later than 5 

years after EPA approves the regional haze SIP.

Energy and Non-Air Impacts

Fuel switching and cleaning may add to transportation issues and secondary environmental 

impacts from waste disposal and material handling operations (e.g. fugitive dust). Additionally, 

these SO2 control methods can create fuel supply problems if several large customers of various 

types of coal suddenly make changes in purchasing patterns. The main impact would be on the 

stability of fuel prices. It is not likely that this would be a persistent problem.

Another impact of fuel switching is that the modifications required for switching from one fuel 

to another may require a unit to be examined for major NSR permitting requirements. This is 

true even for modifications required for addition of controls since the modifications could trigger 

the definition of a “significant modification” under NSR/PSD.

Fuel switching between types and geographic sources of coal and installation of control devices 

can significantly effect mercury emissions. Data from EPA's Mercury Information Collection 

Request (ICR) revealed that many power plants have existing mercury capture as a co-benefit of 

air pollution control technologies for NOX, SO2 and PM. This includes capture of particulatebound mercury in PM control equipment and capture of soluble ionic mercury in wet FGD
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-15

systems. Additional data have also shown that the use of SCR for NOX control enhances 

oxidation of elemental mercury to the soluble ionic form, resulting in increased removal in the 

wet FGD system for units burning bituminous coal. Overall the ICR data revealed higher levels 

of Hg capture for bituminous coal-fired plants as compared to subbituminous coal-fired plants. 

Other factors that influence mercury emissions from coal combustion are chlorine content of the 

coal and fly ash composition.

FGD systems typically operate with high pressure drops across the control equipment, resulting 

in a significant amount of electricity required to operate blowers and circulation pumps. In 

addition, some combinations of FGD technology and plant configuration may require flue gas 

reheating to prevent physical damage to equipment, resulting in higher fuel usage. According to 

Integrated Planning Model (IPM®) background documentation, wet FGD systems reduce the 

capacity of the EGU by 2.1%. This means that the scrubber reduces the amount of electricity for 

sale to the grid by 2.1%. The main effect of this reduction is the increased cost of energy

production.

The primary environmental impact of FGD systems is the generation of wastewater and sludge 

from the SO2 removal process. When the exhaust gas from the boiler enters the FGD the SO2, 

metals, and other solids are removed from the exhaust and collected in the FGD liquid. The 

liquid slurry collects in the bottom of the FGD in a reaction tank. The slurry is then dewatered 

and a portion of the contaminant-laden water is removed from the system as wastewater. Waste 

from the FGD systems will increase sulfate, metals, and solids loading in a facility’s wastewater, 

potentially impacting community wastewater treatment facilities for smaller units that do not 

have self contained water treatment systems. In some cases FGD operation necessitates 

installation of a clarifier on site to remove excessive pollutants from wastewater. This places 

additional burdens on a facility or community wastewater treatment and solid waste management 

capabilities. These impacts will need to be analyzed on a site-specific basis. If lime or limestone 

scrubbing is used to produce calcium sulfite sludge, the sludge must be stabilized prior to land 

filling. If a calcium sulfate sludge is produced, dewatering alone is necessary before land filling, 

however, SO2 removal costs are higher due to increased equipment costs for this type of control 

system. In some cases calcium sulfate sludge can be sold for use in cement manufacturing.

With wet FGD technologies a significant visible plume is present from the source due to 

condensation of water vapor as it exits the smoke stack. Although the water eventually 

evaporates and the plume disappears, community impact may be significant.

Remaining Useful Life of the Source

Available information for remaining useful life estimates of EGU boilers indicates a wide range 

of operating lifetimes, depending on size of the unit, capacity factor, and level of maintenance 

performed. Typical life expectancies range to 50 years or more. Additionally, implementation 

of regulations over the years has resulted in retrofitting that has ultimately increased the expected 

life span of many EGUs. The lifetime of an EGU may be extended through repair, repowering, 

or other strategies if the unit is more economical to run than to replace with power from other 

sources. This may be particularly likely if the unit serves an area which has limited transmission 

capacity available to bring in other power.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 2: Source Category Analysis: Electric Generating Units Page 2-16

REFERENCES

2002 MANE-VU Emissions Inventory Version 3.

EPA Clean Air Markets Division, (CAMD). Personal communication regarding control at coalfired EGUs in the United States from Mr. Peter Kokopeli (202-343-9085), 

(kokopeli.peter@epa.gov) via E-mail on April 3 and April 10, 2007.

NESCAUM. Assessment of Control Technology Options for BART-Eligible Sources; March, 

2005.

Midwest RPO. Candidate Control Measures – Source Category: Electric Generating Units; 

12/09/2005.

STAPPA-ALAPCO. Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of 

Options; March 2006.

Evans, David A; Hobbs, B.F.; Oren, C.; Palmer, K.L. Modeling the Effects of Changes in New 

Source Review on National SO2 and NOX Emissions from Electricity-Generating Units.

U.S. EPA. EPA-600/R-05/034; Multipollutant Emission Control Technology Options for Coalfired Power Plants; March 2005.

U.S. EPA. Integrated Planning Model (IPM®) background documentation located on website: 

(http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html)

ICF Resources. Final Draft Report - Comparison of CAIR and CAIR Plus Proposal Using the 

Integrated Planning Model (IPM®), May 30, 2007.

GE Water & Process Technologies. Information accessed on web March 27, 2007:

http://www.zenon.com/applications/FGD_wastewater_treatment.shtml

Energy Information Administration (EIA). Information located on website: 

http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html

Energy Information Administration (EIA). Information located on website: 

http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html

Energy Information Administration (EIA). Information located on website: 

http://www.eia.doe.gov/cneaf/electricity/epm/epm_sum.html

World Bank Organization. Information located on website:

http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqsocc.stm
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-1

CHAPTER 3

ANALYSIS OF SELECTED ELECTRIC GENERATING UNITS (EGUs)

EGU FACILITY CONTROLS

The Vermont Department of Environmental Conservation (VTDEC) used the CALPUFF model 

to estimate sulfate ion impacts from large EGUs and determine the major EGUs and process 

units (boilers) at the EGUs that contribute to visibility impairment in Class I MANE-VU areas 

and Class I areas affected by emissions from sources within MANE-VU (See Chapter 1, for 

more details). Modeling was based on 2002 SO2 emissions, and the results of the modeling 

showed the SO2 emissions of the 100 highest emitting EGUs and the contribution of these 

sources toward the SO2 concentration in each of the Class I areas. Proximity of the individual 

sources to Class I areas and variations in meteorology on the 20% worst visibility days resulted 

in varying impacts from individual sources on each Class I area. In subsequent discussions with 

MARAMA and the Reasonable Progress Workgroup, MACTEC was directed to focus on the 

emissions from the top 30 individual sources for this analysis. The 30 individual sources are 

located at 23 distinct facilities. The location of the 23 EGU facilities of interest is included in 

Figure 3.1.

Since EGUs are the largest emitters of SO2 in the United States and have the greatest impact on 

haze in the MANE-VU Class I areas, it is particularly useful to determine what controls have 

recently been applied at these facilities (since the 2002 emission inventory). Also important is 

information about controls that are currently being applied at facilities, or are planned for 

addition in the future.

MACTEC gathered information from two primary sources of data for analysis of controls to be 

applied at the 30 EGUs.

1. Integrated Planning Model (IPM®) results from the MANE-VU CAIR Plus (MARAMA 

4c) run.

2. Information from State agencies with facilities in the list of the top 30 individual sources. 

We requested EGU permit information, information about SO2 controls recently 

implemented or planned at the facility and any available information on BART, consent 

decrees, or other regulations that will impact EGU control devices.

The MANE-VU CAIR Plus model results represent an estimate of the additional controls that 

might be installed under a more stringent cap and trade program in the Eastern U.S. The 

comparison of this estimate to the known planned controls for these 30 key EGUs is intended to 

give an idea of whether a stricter cap would in fact result in great controls at these sources.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-2

Figure 3.1

Note: Some facilities are too close to differentiate on the map

INTEGRATED PLANNING MODEL (IPM®) ANALYSIS

For EGUs, EPA used the Integrated Planning Model (IPM®) to estimate which units will install 

controls at what costs and which units will buy credits. The RPOs also made some Integrated 

Planning Model (IPM®) runs to determine which units will install controls to comply with the 

EPA CAIR rule. Additionally, an even more stringent “CAIR Plus” strategy was investigated 

using the Integrated Planning Model (IPM®). The parsed results which include modeled control 

scenarios for individual EGUs were used to help determine costs for EGUs, and ultimately

estimate the marginal cost of SO2 reductions for the model planning years of 2009, 2012, and 

2018.

MACTEC obtained information from the CAIR Plus Policy Case, (MARAMA_4c) for the years 

2009, 2012, and 2018 for the 30 EGUs. The information obtained included unit design capacity, 

SO2 emissions, assumed existing controls, and controls to be applied as calculated by the 

Integrated Planning Model (IPM®). The information was available for each of the individual 

years, (2009, 2012, and 2018). Also available were the resulting changes in design capacity due 

to controls, production output, or other factors from Integrated Planning Model (IPM®). The 

parsed model data do not supply specific design information pertaining to the scrubber size, 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-3

costs, or other related information for individual units. It is only possible to determine the year 

that the scrubber is due to be installed on individual process units. Information from the CAIR 

Plus Integrated Planning Model (IPM®) run is included in Table 3.1. Integrated Planning Model 

(IPM®) projections in Table 3.1 are not intended to be interpreted literally, but only as an 

example of the least-cost results from one set of inputs to the model. Also, the controls applied 

by Integrated Planning Model (IPM®) may differ from planned controls at the facility. For 

information on planned controls at these facilities, please see Table 3.2
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-4

Table 3.1 Integrated Planning Model (IPM®version 2.1.9) CAIR Plus Projections for the Top 30 EGUs Responsible for Visibility Impairment in 

MANE-VU Class I Areas

State Facility ID Facility Primary Emissions 

Point Descriptions

Point # 2002 SO2

Total 

(Tons) 1

2018 SO2

Total 

(Tons) 2

SO2 Reduction 

(2002-2018) 

(Tons/Year) 3

% SO2

Reduction 

(2002-2018)3

Design 

Capacity4

Existing Control4 MANE_VU 

CAIR Plus 

Projection5

TN D03406C10 Johnsonville Coal - wall fired; dry 

bottom boiler 10 108,789 46,000 63,000 58% 15,688 MMBTU Cold-side ESP; LNB SCR by 2012

OH D028404 Conesville Coal - tangential; dry 

bottom boiler 4 92,340 7,000 85,000 92% 764 MW Cold-side ESP; LNB + OFA + BOOS

SCR and Scrubber 

by 2009

PA D031361 Keystone Coal - tangential; dry 

bottom boiler 1 87,709 5,000 83,000 94% 8,010 MMBTU

Cold-side ESP + SCR; LNB; 

OFA Scrubber by 2009

OH D02872C04 Muskingum 

River

Coal - cyclone; wet 

bottom boiler 4 24,484 1,000 23,000 96%

205 MW to 

201 MW by 

2012

Cold-side ESP; OFA SCR and Scrubber 

by 2012

PA D03179C01 Hatfield’s Ferry Coal - wall fired; dry 

bottom boiler 1 55,695 13,000 43,000 77% 5,766 MMBTU Cold-side ESP + SNCR; LNB None

OH D02876C01 Kyger Creek Coal - wall fired; wet 

bottom boiler 1 13,789 1,000 13,000 93% 13,789 MMBTU Cold-side ESP + SCR; OFA Scrubber by 2012

WV D03935C02 John E. Amos

Coal - wall fired; dry 

bottom boiler 2 31,465 6,000 25,000 81% 7,020 MMBTU Cold-side ESP + SCR; LNB Scrubber

PA D031362 Keystone Coal - tangential; dry 2 62,890 4,000 59,000 94% 8,010 

MMBTU

Cold-side ESP + SCR; LNB; 

OFA Scrubber by 2009

IN D01010C05 Wabash River Coal - wall fired; dry 

bottom boiler 5 9,380 1,000 8,000 89% 95 MW Cold-side ESP + Cyclone; LNB + OFA SNCR by 2009

PA D031491 Montour Coal - tangential; dry 

bottom boiler 1 61,005 4,000 57,000 93% 744 MW Cold-side ESP + SCR; LNB + OFA Scrubber by 2009

NC D080421 Belews Creek Coal - wall fired; dry 

bottom boiler 1 57,848 3,000 55,000 95% 1,096 MW Cold-side ESP + SCR; LNB Mercury control

WV D03948C02 Mitchell Coal - wall fired; dry 

bottom boiler 2 29,532 6,000 24,000 80% 7,020 MMBTU

Cold-side ESP + SCR + Wet 

Scrubber; LNB None

PA D031222 Homer City Coal - wall fired; dry 

bottom boiler 2 55,346 3,000 52,000 95% 6,792 MMBTU

Cold-side ESP + SCR; LNB + 

OFA Scrubber by 2009

PA D031492 Montour Coal - tangential; dry 

bottom boiler 2 50,441 4,000 46,000 92% 729 MW Cold-side ESP + SCR; LNB + OFA Scrubber by 2009

MD D01571CE2 Chalk Point Coal - wall fired; dry 

bottom boiler 2 23,537 2,000 22,000 92% 335 MW Cold-side ESP; LNB SCR and Scrubber by 2009

MI D01733C12 Monroe Coal - cell fired; dry 

bottom boilers 1 & 2 48,563 28,000 21,000 42% 770, 785 MW Cold-side ESP + SCR; LNB None

PA D031221 Homer City Coal - wall fired; dry 

bottom boiler 1 45,745 3,000 43,000 93% 607 MW Cold-side ESP + SCR; LNB + OFA Scrubber by 2009

NC D080422 Belews Creek Coal - wall fired; dry 

bottom boiler 2 45,236 3,000 42,000 93% 1,096 MW Cold-side ESP + SCR; LNB Mercury control

WV D039432 Fort Martin Coal - wall fired; dry 

bottom boiler 2 45,890 5,000 41,000 89% 4,634 MMBTU

Cold-side ESP + SNCR; LNB 

+ OFA Scrubber by 2012

WV D039431 Fort Martin Coal - tangential; dry 

bottom boiler 1 45,228 5,000 40,000 89% 4,460 MMBTU

Cold-side ESP + SNCR; LNB 

+ OFA Scrubber by 2012

WV D039353 John E. Amos Coal - wall fired; dry 

bottom boiler 3 44,030 9,000 35,000 80% 11,900 MMBTU Cold-side ESP + SCR; LNB Scrubber
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-5

Table 3.1 Integrated Planning Model (IPM®version 2.1.9) CAIR Plus Projections for the Top 30 EGUs Responsible for Visibility Impairment in 

MANE-VU Class I Areas

State Facility ID Facility Primary Emissions 

Point Descriptions

Point # 2002 SO2

Total 

(Tons) 1

2018 SO2

Total 

(Tons) 2

SO2 Reduction 

(2002-2018) 

(Tons/Year) 3

% SO2

Reduction 

(2002-2018)3

Design 

Capacity4

Existing Control4 MANE_VU 

CAIR Plus 

Projection5

OH D0283612 Avon Lake Coal - wall fired; dry 

bottom boiler 12 41,872 6,000 36,000 86% 6,040 MMBTU Cold-side ESP Scrubber by 2009; SCR by 2012

VA D037976 Chesterfield Coal - tangential; dry 

bottom boiler 6 40,923 4,000 37,000 90% 6,650MMBTU Cold-side ESP; LNB + OFA SCR and Scrubber by 2012

PA D082261 Cheswick Coal - tangential; dry 

bottom boiler 1 42,018 5,000 37,000 88% 550 MW Cold-side ESP + SCR ; LNB + OFA Scrubber by 2009

OH D028281 Cardinal Coal - cell fired; dry 

bottom boilers 1 39,894 2,000 38,000 95%

600 MW to 

587 MW in 

2012

Cold-side ESP + SCR; LNB Scrubber by 2012

MD D015731 Morgantown Coal - tangential; dry 

bottom boiler 1 37,757 3,000 35,000 92% 570 MW Cold-side ESP; LNB +OFA SCR and Scrubber by 2009

OH D028667 W H Sammis

Coal - wall fired; dry 

bottom boiler 7 33,720 3,000 31,000 91%

593 MW to 

818 MW in 

2012

Cold-side ESP + SNCR; LNB

Scrubber in 2009; 

Coal to IGCC in 

2012

MD D015732 Morgantown Coal - tangential; dry 

bottom boiler 2 32,587 3,000 30,000 91% 570 MW Cold-side ESP; LNB +OFA SCR and Scrubber by 2009

MA D016193 Brayton Point Coal - wall fired; dry 

bottom boiler 3 19,451 3,000 16,000 85% 5,800 MMBTU Cold-side ESP; LNB + OFA

SCR, Scrubber, 

Mercury Control 

by 2009

NJ D023781 B L England Coal - cyclone; wet 

bottom boiler 1 10,080 1,000 9,000 90% 129 MW Cold-side ESP; + SNCR; OFA None

Note: CEMS hourly data was used in the modeling of the emission units, not annual emissions. Also, a single emission unit at a generating plant may represent two 

or more emission units at that plant emitting from the same stack point. (Refer to the detailed explanation in the Introduction section of this report).

Table references:

1. 2002 SO2 total for the emission point from RPO emission inventory

2. Integrated Planning Model (IPM®) CAIR Plus projected 2018 SO2 total for the emission point (rounded to nearest 1,000 tons)

3. Approximate reduction in SO2 emissions for 2018 Integrated Planning Model (IPM®) versus 2002 RPO emission inventory (rounded to nearest 1,000 tons)

4. Information from Integrated Planning Model (IPM®) and RPO emission inventories

5. Information from Integrated Planning Model (IPM®) CAIR Plus Scenario
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-6

Integrated Planning Model (IPM®) background documentation defines a range of control 

efficiencies, costs, and applicability based on unit size and coal type. 

(http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html) Three scrubber control 

technologies are discussed briefly in Integrated Planning Model (IPM®) background 

documentation; 1. Limestone Forced Oxidation (LSFO), 2. Magnesium Enhanced Lime (MEL) 

and 3. Lime Spray Dryer (LSD). Each of the three scrubber control technologies are applicable 

for distinct unit sizes and coal types, but there is no indication in the parsed Integrated Planning 

Model (IPM®) results as to which type of scrubber has been applied by the model. All three 

scrubber technologies are assumed to achieve a SO2 removal percentage of 90% or greater. The 

range of various scrubber costs is included in Attachment 1. Depending on boiler size, boiler 

capacity factor, and coal sulfur content, the fixed capital costs range from $140 to $580/kW, 

while fixed operation and maintenance costs (O&M) range from $5 to $24/kW-yr and variable 

O&M costs range from 1.0 to 2.4 mills/kWh. Assuming the typical costs in Attachment 1, an 

EGU rated 500 MW, (the approximate average of the 30 units included in this analysis), a capital 

cost investment of $216/kW or $110 million would be expected. Fixed O&M and variable O&M 

costs would be approximately $11/kW-yr and 2.0 mills/kWh, respectively and would depend on 

the EGU annual output. This cost could be expected to reduce SO2 emissions by greater than 

90%. A typical SO2 reduction from a 500 MW unit (assuming a minimum of 90% reduction), 

based on the 30 units included in this analysis would be from 4,000 to 40,000 tons annually. 

(Converted from 1999 to 2006 dollars using a conversion factor of 1.2101 

www.inflationdata.com)

INFORMATION OBTAINED FROM STATE AGENCIES

The 30 EGUs analyzed here are already subject to a variety of existing emission control 

requirements, including CAIR, BART, mercury controls, the NOX SIP call, and EPA’s acid rain 

control program. Therefore, it is expected that at least some of the 30 EGUs will already be 

adding control by 2018.

To investigate this possibility, MACTEC contacted State agencies with facilities in the list of the 

top 30 individual sources. We requested EGU permit information, information about SO2

controls recently implemented or planned at the facility, and any available information on 

BART, consent decrees, or other regulations that will impact EGU control devices. The 

information we have obtained is included in Table 3.2.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-7

Table 3.2 Point Source Information for the Top 30 EGUs Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)a

Primary Emissions Point 

Description

Point 

ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Johnsonville1, 2, 3 TN 108,789 Coal-fired Boilers 01-10

for steam & electricity 

generation. The units are 

pulverized coal, dry-bottom

boilers without fly ash 

reinjection. Units 1-6 are 

Combustion Engineering 

tangentially-fired boilers. 

Units 7-10 are Foster 

Wheeler wall fired boilers. 

All boilers exhaust through 

a common stack.

43-

0011-

01-10

15,688 

MMBTU/hr

ESP Combustion 

of low-sulfur 

fuel (since 

2002)

SCR by 2018

2018 SO2 emissions 

will be approximately 

51,000 tpy

Conesville4 OH 92,340 Unit 4 Main Boiler -

Combustion Engineering 

model 7868 pulverized 

coal-fired, dry-bottom

boiler

B004 7,960 MMBTU/hr ESP FGD and SCR 

by 8/18/09

N/A

Keystone (aka 

Reliant Energy 

Northeast 

Mgmt/Keystone 

Power Plant)5

PA 87,709 Boiler 1 w/low NOX

burner

1 (031) 8,717 MMBTU/hr Cold-side ESP

SCR

FGD Alternate operation: 

SCR System Boiler 1

Muskingum 

River6

OH 24,484 Unit 3 Main Boiler -

Babcock and Wilcox 

model RB-248 (custom) 

coal-fired, cyclone boiler

B004 2,150 MMBTU/hr ESP None planned N/A
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-8

Table 3.2 Point Source Information for the Top 30 EGUs Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)a

Primary Emissions Point 

Description

Point 

ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Hatfield’s Ferry5PA 55,695 Babcock & Wilcox Boiler 

#1 that burns bituminous 

coal (227 tons/hr) and No. 

2 fuel oil (1,384 gal/hr)

1 (031) 5,766 MMBTU/hr Cold-side ESP FGD N/A

Kyger Creek6 OH 13,789 Unit #1 Boiler- Babcock 

and Wilcox pulverized 

coal-fired, wet-bottom 

boiler

B001 1,850 MMBTU/hr ESP SCR, FGD 

operational by 

1/01/09

N/A

John E. Amos7,8 WV 31,465 Dry-bottom wall-fired coal 

boiler

2 800 MW,

7,020 MMBTU/hr

ESP

Low NOX

burners

SCR

FGD 

(12/2008)

Vents through CS012

Keystone (aka 

Reliant Energy 

Northeast 

Mgmt/Keystone 

Power Plant)5

PA 62,890 Boiler 2 w/low NOX

burner

2 (032) 8,717 MMBTU/hr Cold-side ESP

SCR

FGD Alternate operation: 

SCR System Boiler 2

Wabash (aka 

Duke Energy 

Indiana, Inc. -

Wabash River 

Generating 

Station)9, 10

IN 9,380 Wall fired coal electric 

utility boiler (pulverized –

dry bottom) constructed in 

1956 using No. 2 fuel oil 

as ignition fuel

5 1,096.2 

MMBTU/hr

Low- NOX

burner (NOX)

ESP (PM)

None Stack is equipped with 

CEM for SO2
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-9

Table 3.2 Point Source Information for the Top 30 EGUs Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)a

Primary Emissions Point 

Description

Point 

ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Montour (aka 

PPL Montour, 

LLC – Montour 

Steam Electric 

Station)5

PA 61,005 CE Boiler – Unit #1 that 

burns bituminous coal and 

No. 2 fuel oil

1 (031) 7,317 MMBTU/hr Cold-side ESP

SCR

FGD N/A

Belews Creek 

(aka Duke 

Power’s Belews 

Creek Plant)11

NC 57,848 Coal-fired electric utility 

boiler constructed in 1974

1 1,120 MW None Scrubbers 

(2008)

Expected rate under 

their compliance plan 

for the Clean 

Smokestacks Act is 

0.150 lbs 

SO2/MMBTU. 

Expected emissions 

SO2 for 2013 and later 

is 5,512 tpy.

Mitchell7, 12 WV 29,532 Dry-bottom wall-fired coal 

boiler

2 800 MW,

7,020 MMBTU/hr

ESP

Low NOX

burners

FGD 

(1/2007);

SCR (4/2007)

Vents through CS012

Homer City (aka 

Homer City 

OL/Homer City 

Generation 

Station13

PA 55,346 Boiler No. 2 (Unit 2) 2 (032) 6,792 MMBTU/hr Cold-side ESP

SCR

FGD N/A

Montour (aka 

PPL Montour, 

LLC – Montour 

Steam Electric 

Station)5

PA 50,441 CE Boiler – Unit #2 that 

burns bituminous coal and 

No. 2 fuel oil

2 (032) 1,239 MMBTU/hr Cold-side ESP

SCR

FGD N/A
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-10

Table 3.2 Point Source Information for the Top 30 EGUs Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)a

Primary Emissions Point 

Description

Point 

ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Chalk Point15, 16 MD 23,537 Steam Unit 2 is a wall 

fired, dry bottom, 

supercritical boiler base 

loaded unit. The primary 

fuel is coal with natural 

gas and No. 2 oil used for 

ignition.

2 342 MW Low NOX

burners

ESP

SACR

LNBs & 

SOFA (NOX)

SCR and FGD 

(2009/2010 

timeframe)

Unit covered under the 

MD Healthy Air Act

Monroe (aka 

Detroit Edison –

Monroe Power 

Plant)16

MI 48,563 4 cell burner boilers 

(Boiler Unit Nos. 1, 2, 3, 

and 4) constructed in the 

late 1960s (1968-1969) 

and modified in 1994

EG01

EG02

EG03

EG04

3,000 MW (total) Dry wire ESP 

(SO3)

FGD (Units 3 

& 4) @ 97% 

CE

May put 

scrubbers on 

Units 1 & 2 

later

If additional scrubbers 

are added, a SO2

reduction of 97% is 

anticipated

Homer City (aka 

Homer City 

OL/Homer City 

Generation 

Station13

PA 45,745 Boiler No. 1 (Unit 1) 1 (031) 6,792 MMBTU/hr Cold-side ESP

SCR

FGD N/A

Belews Creek 

(aka Duke 

Power’s Belews

Creek Plant)11

NC 45,236 Coal-fired electric utility 

boiler constructed in 1975

2 1,120 MW None Scrubbers 

(2008)

Expected rate under 

their compliance plan 

for the Clean 

Smokestacks Act is 

0.150 lbs 

SO2/MMBTU. 

Expected emissions 

SO2 for 2013 and later 

is 4,639 tpy.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-11

Table 3.2 Point Source Information for the Top 30 EGUs Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)a

Primary Emissions Point 

Description

Point 

ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Fort Martin7, 8 WV 45,228 Tangentially-fired coal 

boiler

1 552 MW,

4,460 MMBTU/hr

ESP

Low NOX

burners

SNCR Trim

FGD (4Q

2009)

N/A

Fort Martin7, 8 WV 45,890 Wall-fired coal boiler 2 55 MW,

4,634 MMBTU/hr

ESP

Low NOX

burners

SNCR Trim

FGD (1Q

2010)

N/A

John E. Amos7, 8 WV 44,030 Dry-bottom wall-fired coal 

boiler

3 1,300 MW,

11,900 

MMBTU/hr

ESP

Low NOX

burners

SCR

FGD 

(12/2007)

N/A

Avon Lake6 OH 41,872 Boiler #12 - Pulverized 

coal-fired, dry bottom, 

boiler

B012 6,040 MMBTU/hr ESP SCR and FGD 

operational by 

2010

N/A

Chesterfield (aka 

Chesterfield 

Power Station)17

VA 40,923 Combustion Engineering 

tangentially-fired coal 

boiler equipped with 

startup burners

6 (ES6A)6,650 MMBTU/hr SCR

ESP

Stage 

combustion 

coal burners

FGD (95% 

CE under 

construction, 

operational 

2008)

The unit is restricted to 

burn 2,330,160 tons/yr 

of coal at an annual 

average heating value 

of 12,500 BTU/lbs

Cheswick (aka 

Cheswick Power 

Station)18

PA 42,018 Tangentially-fired “main” 

boiler that burns 

bituminous coal (primary 

fuel), natural gas, and 

synfuel

1 5,500 MMBTU/hr 

(coal & synfuel)

1,000 MMBTU/hr 

(NG)

Low NOX

burners

SCR

ESP w/flue 

gas 

conditioning 

(PM) 

FGD (98% 

CE planned)

N/A
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-12

Table 3.2 Point Source Information for the Top 30 EGUs Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)a

Primary Emissions Point 

Description

Point 

ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Cardinal6, 12 OH 39,894 Unit 1 Main Boiler -

Babcock and Wilcox, 

pulverized coal-fired, dry 

bottom, cell burner boiler

B001 527 MMBTU/hr ESP FGD (2/2008) N/A

Morgantown14, 15 MD 37,757 Combustion Engineering, 

Inc., Unit Boiler No. 1 -

steam generating coalfired utility boiler installed 

in 1967 which primarily 

combusts Eastern 

Bituminous coal 

containing no more than 

2% sulfur by weight and 

secondary fuel is No. 6 oil 

containing no more than 

2% sulfur by weight

1 (F-1) 5,317 MMBTU/hr ESP

SO3 injection

Low NOX

burners

SCR and FGD 

(2009/2010 

timeframe)

Stacks equipped with 

SO2, NOX, CO2, and 

ultrasonic flow 

monitors. Unit covered 

under the MD Healthy 

Air Act.

W H Sammis6 OH 33,720 Coal Fired Boiler No.1 -

Foster-Wheeler pulverized 

coal-fired, dry-bottom

boiler

B007 1,822 MMBTU/hr Fabric filter ESP

FGD 

operational 

12/31/09

SNCR 

Operational 

06/06

N/A
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-13

Table 3.2 Point Source Information for the Top 30 EGUs Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)a

Primary Emissions Point 

Description

Point 

ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Morgantown14, 15 MD 32,587 Combustion Engineering, 

Inc., Unit Boiler No. 2 -

steam generating coalfired utility boiler installed 

in 1967 primarily 

combusts Eastern 

Bituminous coal w/ no 

more than 2% sulfur by 

weight and secondary fuel 

is No. 6 oil w/ no more 

than 2% sulfur by weight

1 (F-2) 5,317 MMBTU/hr ESP

SO3 injection

Low NOX

burners

SCR and FGD 

(2009/2010 

timeframe)

Stacks equipped with 

SO2, NOX, CO2, and 

ultrasonic flow 

monitors. Unit covered 

under the MD Healthy 

Air Act.

Brayton Point19 MA 19,451 Water tube boiler 3 (EU3) 5,655 MMBTU/hr ESP w/flue 

gas 

conditioning 

(PCD-3)

Fuel sulfur 

content 

(2011)

FGD (2011)

BART recommended 

controls for SO2 are 

95% control or 0.15 

lb/MMBTU (coal), 

0.33 lb/MMBTU (0.3% 

fuel sulfur limit) (oil)

B L England20, 21 NJ 10,080 Wet-bottom, cyclone coal 

boiler

1 129 MW ESP

SNCR

None The facility will either 

close by 2012 or install 

scrubbers on all coalfired units. One 

scrubber is already 

installed and the other 

unit would get a 95% 

CE –minimum, but 

unclear if this unit is 

already controlled.

a

2002 SO2 total for the emission point from RPO emission inventory.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-14

1 Tennessee Department of Environment and Conservation, Division of Air Pollution Control. Personal communication regarding Johnsonville facility from Ms. Julie Aslinger 

(615-532-0587, Julie.Aslinger@state.tn.us) via E-mail on March 1, 2007.

2 MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid-Atlantic North Eastern Class I Areas”, March 8, 2007. 

Comment regarding Johnsonville facility received from Ms. Julie Aslinger (615-532-0587, Julie.Aslinger@state.tn.us) via E-mail on March 30, 2007.

3 MACTEC, Inc., “Documentation of the Base G 2002 Base Year, 2009 and 2018 Emission Inventories for VISTAS”, January, 2007.

4 Ohio Environmental Protection Agency, Division of Air Pollution Control. Personal communications regarding Conesville facility from Mr. William Spires (614-644-3618, 

bill.spires@epa.state.oh.us) via E-mail on February 20 and 21, 2007.

5

Pennsylvania Department of Environmental Protection, Bureau of Air Quality. Personal communications regarding Keystone, Hatfield’s Ferry, and Montour facilities from Ms. 

Nancy Herb (717-783-9269, nherb@state.pa.us) via E-mail on January 31 and February 7, 2007.

6 Ohio Environmental Protection Agency, Division of Air Pollution Control. Personal communication regarding Muskingum, Kyger Creek, Avon Lake, Cardinal, and WH Sammis 

facilities from Mr. William Spires (614-644-3618, bill.spires@epa.state.oh.us) via E-mail on February 20, 2007.

7 West Virginia Division of Air Quality. Personal communication regarding John. E. Amos, Mitchell, and Fort Martin facilities from Ms. Laura Crowder (304-926-0499 Ext. 1247, 

LCROWDER@wvdep.org) via E-mail on February 17, 2007.

8 MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid-Atlantic North Eastern Class I Areas”, March 8, 2007. 

Comments regarding John E. Amos, Mitchell, and Fort Martin and facilities received from Ms. Laura Crowder (304-926-0499 Ext. 1247, LCROWDER@wvdep.org) via E-mail 

on March 30, 2007.

9

Indiana Department of Environmental Management, Office of Air Quality. Personal communication regarding Wabash facility between Mr. Jay Koch (317-233-0581, 

JKOCH@idem.IN.gov) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007.

10 Indiana Department of Environmental Management, Office of Air Quality. Personal communications regarding Wabash facility from Mr. Jay Koch (317-233-0581, 

JKOCH@idem.IN.gov) via E-mail on February 1 and 5, 2007.

11 North Carolina Department of Environment and Natural Resources, Division of Air Quality. Personal communications regarding Belews Creek facility from Ms. Sheila Holman 

(919-715-0971, shelia.holman@ncmail.net) via E-mail on February 1 and 2, 2007.

12 MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid-Atlantic North Eastern Class I Areas”, March 8, 2007. 

Comments regarding Mitchell and Cardinal facilities received from Mr. David J. Long, P.E. of American Electric Power (614-716-1245, djlong@aep.com) via E-mail on March 

29, 2007.

13

Pennsylvania Department of Environmental Protection, Bureau of Air Quality. Personal communications regarding Homer City facility from Ms. Nancy Herb (717-783-9269, 

nherb@state.pa.us) via E-mail on January 31 and February 7 and 8, 2007.

14 Maryland Department of the Environment. Personal communication regarding Chalk Point and Morgantown facilities from Mr. Andy Heltibridle (410-537-4218, 

aheltibridle@mde.state.md.us) via U.S. mail on February 9, 2007.

15 MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid-Atlantic North Eastern Class I Areas”, March 8, 2007. 

Comments regarding Chalk Point and Morgantown facilities received from Mr. Brian Hug (410-537-4125, bhug@mde.state.md.us) via E-mail on March 14, 2007.

16 Michigan Department of Environmental Quality, Air Quality Division. Personal communication regarding Monroe facility from Ms. Teresa Walker (517-335-2247, 

walkertr@michigan.gov) via E-mail on February 7, 2007.

17 Virginia Department of Environmental Quality, Division of Air Quality. Personal communication regarding Chesterfield facility from Ms. Doris McLeod (504-698-4197, 

damcleod@deq.virginia.gov) via E-mail on February 9, 2007.

18 Allegheny County Health Department. Personal communications regarding Cheswick facility from Ms. Jayme Graham (412-578-8129, JGraham@achd.net) via E-mail on 

February 2, 2007.

19 Massachusetts Department of Environmental Protection. Personal communications regarding Brayton Point facility from Mr. Donald Squires (617-292-5618, 

Donald.Squires@state.ma.us) via E-mail on February 2 and 7, 2007.

20 New Jersey Department of Environmental Protection, Division of Air Quality. Personal communications regarding B.L. England facility between Mr. Ray Papalski (609-633-

7225, Ray.Papalski@dep.state.nj.us) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007.

21 New Jersey Department of Environmental Protection, Division of Air Quality. Personal communications regarding B.L. England facility from Mr. Ray Papalski (609-633-7225, 

Ray.Papalski@dep.state.nj.us) via E-mail on February 1, 2007.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-15

Table 3.3 presents a side by side comparison of the predicted control information from Tables 

3.1 and 3.2. The existing control information available from Integrated Planning Model (IPM®)

data was in disagreement with the information reported by the States for many of the EGUs. 

Since controls at the EGUs may have changed recently [since Integrated Planning Model (IPM®

v.2.1.9)], Table 3.3 reports existing control information obtained from the States for this report. 

The information on proposed or planned controls obtained from the States reflects that 26 of the 

30 EGUs included in this study plan to install SO2 control (FGD/scrubber), or switch to a lower 

sulfur coal prior to 2018. SO2 reduction estimates from the States were only available for some 

of the EGUs, but reflect a significant reduction in SO2 for those units for which an estimate was 

supplied.

Regarding the control information from Integrated Planning Model (IPM®) CAIR Plus results, 

Integrated Planning Model (IPM®) predicts that 21 of the 30 EGUs will install SO2 in the CAIR 

Plus scenario. Additionally, Integrated Planning Model (IPM®) predicts a reduction in SO2 at all 

30 EGUs included in this study, including the 9 units for which no SO2 control is added. The 

SO2 reductions estimated by Integrated Planning Model (IPM®) are said to be achieved through a 

number of compliance strategies in addition to control, such as fuel switching, plant retirements, 

plant dispatch, and new builds. Additional information on all Integrated Planning Model (IPM®)

compliance strategies and well as information on NOX reductions are available in Integrated 

Planning Model (IPM®) documentation available on EPA’s website and in the ICF report titled: 

Final Draft Report – Comparison of CAIR and CAIR Plus Proposal Using the Integrated 

Planning Model (IPM®).

Table 3.3 Comparison of Controls Predicted by Integrated Planning Model (IPM®) CAIR Plus 

Results versus Proposed/Planned Control Additions by the State/Facility (by 2018) at the Top 

30 EGUs Responsible for Visibility Impairment in MANE-VU Class I Areas

Facility 

Name

State Point 

#

2002 

SO2

(tons)

Existing 

Controls

(based on 

information from

State)

Facility/State 

Proposed/Planned 

Controls

{% SO2

reduction}

IPM®Predicted 

Controls (CAIR 

Plus)

{% SO2

reduction}

Johnsonville TN 10 108,789 ESP

Low sulfur fuel since 2002; 

SCR by 2018

{53% reduction in SO2}

SCR by 2012

{58% reduction in SO2}

Conesville OH 4 92,340 ESP

FGD and SCR by 8/18/09

{SO2 reduction unavailable}

SCR and Scrubber by 2009

{92% reduction in SO2}

Keystone PA 1 87,709 Cold-side ESP; SCR

FGD

{SO2 reduction unavailable}

Scrubber by 2009

{94% reduction in SO2}

Muskingum 

River OH 4 24,484 ESP

None planned

{SO2 reduction assumed 0%}

SCR and Scrubber by 2012

{96% reduction in SO2}

Hatfield’s Ferry PA 1 55,695 Cold-side ESP

FGD

{SO2 reduction unavailable}

None

{77% reduction in SO2}

Kyger Creek OH 1 13,789 ESP

SCR, FGD operational by 

1/01/09

{SO2 reduction unavailable}

Scrubber by 2012

{93% reduction in SO2}

John E. Amos WV 2 31,465 ESP; Low NOX burners; 

SCR

FGD by 12/2008

{SO2 reduction unavailable}

Scrubber

{81% reduction in SO2}
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-16

Table 3.3 Comparison of Controls Predicted by Integrated Planning Model (IPM®) CAIR Plus 

Results versus Proposed/Planned Control Additions by the State/Facility (by 2018) at the Top 

30 EGUs Responsible for Visibility Impairment in MANE-VU Class I Areas

Facility 

Name

State Point 

#

2002 

SO2

(tons)

Existing 

Controls

(based on 

information from

State)

Facility/State 

Proposed/Planned 

Controls

{% SO2

reduction}

IPM®Predicted 

Controls (CAIR 

Plus)

{% SO2

reduction}

Keystone PA 2 62,890 Cold-side ESP; SCR

FGD

{SO2 reduction unavailable}

Scrubber by 2009

{94% reduction in SO2}

Wabash River IN 5 9,380 Low NOX burners; ESP

None planned

{SO2 reduction assumed 0%}

SNCR by 2009

{89% reduction in SO2}

Montour PA 1 61,005 Cold-side ESP; SCR

FGD

{SO2 reduction unavailable}

Scrubber by 2009

{93% reduction in SO2}

Belews Creek NC 1 57,848 None

Scrubbers (2008)

{90% reduction in SO2}

Mercury control

{95% reduction in SO2}

Mitchell WV 2 29,532 ESP; Low NOX burners

FGD (1/2007); SCR (4/2007)

{SO2 reduction unavailable}

None

{80% reduction in SO2}

Homer City PA 2 55,346 Cold-side ESP; SCR

FGD

{SO2 reduction unavailable}

Scrubber by 2009

{95% reduction in SO2}

Montour PA 2 50,441 Cold-side ESP; SCR

FGD

{SO2 reduction unavailable}

Scrubber by 2009

{92% reduction in SO2}

Chalk Point MD 2 23,537 Low NOX burners; ESP; 

SACR LNBs & SOFA

SCR and FGD (2009/2010 

timeframe)

{SO2 reduction unavailable}

SCR and Scrubber by 2009

{92% reduction in SO2}

Monroe MI 1 & 2 48,563 Dry wire ESP; FGD

Possible addition of scrubbers

{97% SO2 reduction if 

controlled}

None

{42% reduction in SO2}

Homer City PA 1 45,745 Cold-side ESP; SCR

FGD

{SO2 reduction unavailable}

Scrubber by 2009

{93% reduction in SO2}

Belews Creek NC 2 45,236 None

Scrubbers (2008)

{90% reduction in SO2 }

Mercury control

{93% reduction in SO2}

Fort Martin WV 2 45,890 ESP, Low NOX burners; 

SNCR Trim

FGD (4Q 2009)

{SO2 reduction unavailable}

Scrubber by 2012

{89% reduction in SO2}

Fort Martin WV 1 45,228 ESP, Low NOX burners; 

SNCR Trim

FGD (1Q 2010)

{SO2 reduction unavailable}

Scrubber by 2012

{89% reduction in SO2}

John E. Amos WV 3 44,030 ESP, Low NOX burners; 

SCR

FGD (12/2007)

{SO2 reduction unavailable}

Scrubber

{80% reduction in SO2}

Avon Lake OH 12 41,872 ESP

SCR and FGD operational by 

2010

{SO2 reduction unavailable}

Scrubber by 2009; SCR by 

2012

{86% reduction in SO2}

Chesterfield VA 6 40,923 SCR; ESP; Stage 

combustion burners

FGD operational 2008

{95% reduction in SO2}

SCR and Scrubber by 2012

{90% reduction in SO2}

Cheswick PA 1 42,018

Low NOX burners; 

SCR; ESP w/flue gas 

conditioning

None

{SO2 reduction assumed 0%}

Scrubber by 2009

{88% reduction in SO2}

Cardinal OH 1 39,894 ESP

FGD (2/2008)

{SO2 reduction unavailable}

Scrubber by 2012

{95% reduction in SO2}
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-17

Table 3.3 Comparison of Controls Predicted by Integrated Planning Model (IPM®) CAIR Plus 

Results versus Proposed/Planned Control Additions by the State/Facility (by 2018) at the Top 

30 EGUs Responsible for Visibility Impairment in MANE-VU Class I Areas

Facility 

Name

State Point 

#

2002 

SO2

(tons)

Existing 

Controls

(based on 

information from

State)

Facility/State 

Proposed/Planned 

Controls

{% SO2

reduction}

IPM®Predicted 

Controls (CAIR 

Plus)

{% SO2

reduction}

Morgantown MD 1 37,757 ESP; SO3 injection; Low 

NOX burners

SCR and FGD (2009/2010 

timeframe)

{SO2 reduction unavailable}

SCR and Scrubber by 2009

{92% reduction in SO2}

W H Sammis OH 7 33,720 Fabric filter

ESP and FGD operational 

12/31/09; SNCR operational 

6/06

{SO2 reduction unavailable}

Scrubber in 2009; Coal to 

IGCC in 2012

{91% reduction in SO2}

Morgantown MD 2 32,587 ESP; SO3 injection; Low 

NOX burners

SCR and FGD (2009/2010 

timeframe)

{SO2 reduction unavailable}

SCR and Scrubber by 2009

{91% reduction in SO2}

Brayton Point MA 3 19,451 ESP w/flue gas 

conditioning (PCD-3)

Fuel sulfur content (2011); 

FGD 2011

{95% reduction in SO2}

SCR, Scrubber, Mercury 

Control by 2009

{85% reduction in SO2}

B L England NJ 1 10,080 ESP;SNCR

Facility will either close or 

install scrubbers by 2012

{95% reduction in SO2}

None

{90% reduction in SO2}

Table Reference: See full reference information for Integrated Planning Model (IPM®) and State agency contacts associated with 

Tables 3.1 and 3.2.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-18

REFERENCES

2002 MANE-VU Emissions Inventory Version 3.

NESCAUM. Assessment of Control Technology Options for BART-Eligible Sources; March, 

2005.

Midwest RPO. Candidate Control Measures – Source Category: Electric Generating Units; 

12/09/2005.

STAPPA-ALAPCO. Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of 

Options; March 2006.

Evans, David A; Hobbs, B.F.; Oren, C.; Palmer, K.L. Modeling the Effects of Changes in New 

Source Review on National SO2 and NOX Emissions from Electricity-Generating Units.

ICF Resources. Final Draft Report - Comparison of CAIR and CAIR Plus Proposal Using the 

Integrated Planning Model (IPM®), May 30, 2007.

U.S. EPA. EPA-600/R-05/034; Multipollutant Emission Control Technology Options for Coalfired Power Plants; March 2005.

U.S. EPA. Integrated Planning Model (IPM®) background documentation located on website: 

(http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html)

Energy Information Administration (EIA). Information located on website: 

http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html

Energy Information Administration (EIA). Information located on website: 

http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html

World Bank Organization. Information located on website:

http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqsocc.stm
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-19

Attachment 1. Illustrative Scrubber Costs (1999 $) for Representative MW and Heat Rates 

under the Assumptions in EPA Base Case 2004

Scrubber Type Capacity 

(MW)

Heat Rate (BTU/kWh)

Cost

9,000 10,000 11,000

LSFO

Min. Cutoff: >= 100 MW

Max. Cutoff: None

Assuming 3.0% Sulfur 

Content Coal (by weight) 

with Heating Value of 11,900 

BTU/lb

100 456

19

1.6

469

19

1.7

481

20

1.9

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

300 225

11

1.6

234

11

1.7

243

20

1.9

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

500 173

9

1.6

180

9

1.7

187

9

1.9

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

700 142

8

1.6

149

8

1.7

155

8

1.9

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

1,000 157

7

1.6

166

8

1.7

174

8

1.9

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

MEL

Min. Cutoff: >= 100 MW

Max. Cutoff: <500 MW

Assuming 1.5% Sulfur 

Content Coal (by weight) 

with Heating Value of 11,900 

BTU/lb

100 340

17

0.8

351

17

0.9

362

17

1

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

200 224

12

0.8

233

12

0.9

241

12

1

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

300 224

11

0.8

235

11

0.9

245

12

1

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

400 200

10

0.8

210

10

0.9

220

10

1

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

500 178

9

0.8

187

9

0.9

196

9

1

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

LSD

Min. Cutoff: >= 550 MW

Max. Cutoff: None

Assuming 1.5% Sulfur 

Content Coal (by weight) 

with Heating Value of 11,900 

BTU/lb

600 137

5

1.6

144

5

1.8

151

6

2

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

700 127

5

1.6

134

5

1.8

140

5

2

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

800 124

5

1.6

130

5

1.8

135

5

2

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

900 125

4

1.6

131

4

1.8

137

4

2

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

1,000 118

4

1.6

124

4

1.8

130

4

2

Cap.Cost ($/kW)

Fix. O&M $/kW-yr

Var. O&M mills/kWh

Table reference:Copy of Table 5.3 from EPA Integrated Planning Model (IPM®) documentation (http://www.epa.gov/airmarkets/progsregs/epaipm/docs/bc5emission.pdf). (Note: To adjust cost data from 1999 to 2006, multiply by 1.2101 www.inflationdata.com
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-20

Attachment 2. Engineering Methodology Used to Calculate $/ton Pollutant Reduction

Calculation of Cost per ton of SO2 of scrubbing

First, calculate annual cost of a scrubber ($/kW/yr)

Cost data

Cap Fix O&M Var O&M

469 19 1.7

 $/Kw $/KW-yr $/kWh

Assume Cap Rec Factor CapacFact

0.15 0.85

 1/yr dimensionless

8760 h/yr

TOTAL

Implies 70.35 19 12.6582 102.01 This is the annual cost per kW for a scrubber

 $/KW-yr $/KW-yr $/KW-yr $/KW-yr

Then calculation annual emissions reduction from the scrubber

Calculate emissions rate (lb/MBTU) based on coal S content

Fraction S SO2/S Heat Content SO2 Emissions rate

3% 2 divided by 0.012 = 5

dimensls dimesnlss MBTU/lb lb/MBTU

Use emissions rate and assumed plant efficiency/operating hours to get emissions/kw/yr

UnconSO2 Reduction Heat Rate Cap FactorHr/yr tons/lb

5 0.9 0.01 0.85 8760 0.0005 = 0.167535

lb/MBTU dimensionless MBTU/kWh dimensls hr/yr tons/lb tons/kw-yr

Check of units:

lb mbtu hr ton

mbtu kW -hr yr lb

Result: Get $/ton of reduction

divide cost/kw/yr by ton/kw/yr = 608.877 = 102.01 divided by 0.167535

$/KW-yr tons/kw-yr
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4-1

CHAPTER 4

SOURCE CATEGORY ANALYSIS: INDUSTRIAL, COMMERCIAL, AND 

INSTITUTIONAL BOILERS

SOURCE CATEGORY DESCRIPTION

The MANE-VU contribution assessment has demonstrated that SO2 emissions are the principal 

contributor to visibility impairment in Class I areas in the northeast. After electric generation 

units, Industrial, Commercial, and Institutional (ICI) boilers and heaters are the next largest class 

of pollution sources that contribute to SO2 emissions. Typical industrial applications include 

chemical, refining, manufacturing, metals, paper, petroleum, food production and a wide variety 

of other small industries and commercial heating applications. Commercial and institutional 

boilers are normally used to produce steam and hot water for space heating in office buildings, 

hotels, apartment buildings, hospitals, universities, and similar facilities. Most commercial and 

institutional boilers are small, with 80% of the population smaller than 15 million British 

Thermal Units per hour (MMBTU/hr). A fairly wide range of fuels are used by ICI boilers, 

ranging from coal, petroleum coke, distillate and residual fuel oils, natural gas, wood waste or 

other class of waste products. Boilers aggregated under the ICI classification are generally

smaller than boilers in the electric power industry, and typically have a heat input in the 10 to 

250 MMBTU/hr range; however, industrial boilers can be as large as 1,000 MMBTU/hr or as 

small as 0.5 MMBTU/hour.

The process that a particular unit serves strongly influences the boiler fuel choice. For example, 

the iron and steel industry uses coal to generate blast furnace gas or coke oven gas that is used in 

boilers, resulting in sulfur emissions. Pulp and paper processing may use biomass as a fuel, 

resulting in high PM emissions. Units with short duty cycles may utilize oil or natural gas as a 

fuel. The use of a wide variety of fuels is an important characteristic of the ICI boiler category. 

While many boilers are capable of co-firing liquid or gaseous fuels in conjunction with solid 

fuels, boilers are usually designed for optimum combustion of a single specific, fuel. Changes to 

the fuel type may, therefore, reduce the capacity, duty cycle, or efficiency of the boiler.

Boiler design also plays a role in the uncontrolled emission rate. Most ICI boilers are of three 

basic designs: water tube, fire tube, or cast iron. The fuel-firing configuration is a second major 

identifier of boiler design for solid fuels. Stoker boilers are the oldest technology and are still 

widely used for solid-fueled boilers. Pulverized coal boilers succeeded stokers as a more 

efficient method of burning coal and are used in larger boiler designs. Circulating fluidized bed 

(CFB) boilers are the most recent type of boiler for solid fuel combustion and are becoming more 

commonplace. CFB boilers are capable of burning a variety of fuels, and are more efficient and 

less polluting than stoker or pulverized coal boilers. Combined heat and power (CHP) or 

cogeneration technologies are also used to produce electricity and steam or hot water from a 

single unit. Some ICI boilers are used only in the colder months for space heating, while others 

have high capacity utilization year round.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4-2

Clean Air Act Regulations Controlling ICI Boilers

Emissions from ICI boilers are currently governed by multiple State and federal regulations 

under the Titles I, III, and IV of the Clean Air Act. Each of these regulatory programs is 

discussed in the following paragraphs. Title I regulates criteria pollutants by requiring local 

governments to adopt State Implementation Plans (SIPs) that set forth their strategy for 

achieving reductions in the particular criteria pollutant(s) for which they are out of attainment. 

The SIP requirements includes Reasonably Available Control Technology (RACT) requirements, 

but more stringent requirements may be imposed depending on the locale's degree of nonattainment with ambient air standards. 

Title I also imposes New Source Performance Standards (NSPS) on certain specified categories 

of new and modified large stationary sources. In 1986, EPA codified the NSPS for industrial 

boilers (40 CFR part 60, subparts Db and Dc) and revised portions of them in 1998 to reflect 

improvements in control methods for the reduction of NOX emissions. Subpart Db applies to 

fossil fuel-fired ICI units greater than 100 MMBTU per hour that were constructed or modified 

after June 19, 1984. Subpart Dc applies to fossil fuel-fired ICI units from 10 to 100 MMBTU per 

hour that were constructed or modified after June 9, 1989. 

In addition, Title I subjects new and modified large stationary sources that increase their 

emissions to permitting requirements that impose control technologies of varying levels of 

stringency (known as New Source Review, or NSR). NSR prescribes control technologies for 

new plants and for plant modifications that result in a significant increase in emissions,

subjecting them to Best Available Control Technology (BACT) in attainment areas and to the 

Lowest Achievable Emission Rate (LAER) in non attainment areas. Control strategies that 

constitute BACT and LAER evolve over time and are reviewed on a case by case basis in State 

permitting proceedings.

On September 13, 2004, EPA published a final rule under Title III of the CAA to substantially

reduce emissions of toxic air pollutants from ICI boilers. These Maximum Achievable Control 

Technology (MACT) standards apply to ICI boilers located at major sources of hazardous air 

pollutants (HAPs). There are many options for complying with the MACT standards, ranging 

from continued use of existing control systems to fuel switching to the installation of a fabric 

filter and wet scrubber technologies. Thus, the control technologies used to reduce the level of 

HAP emitted from affected sources are also expected to reduce emissions of PM, and to a lesser 

extent, SO2 emissions.

Title IV of the CAA addresses acid rain by focusing primarily on power plant emissions of SO2. 

Title IV includes an Opt-in Program that allows sources not required to participate in the Acid 

Rain Program the opportunity to enter the program on a voluntary basis and receive their own 

acid rain allowances. The Opt-in Program offers sources such as ICI boilers a financial incentive 

to voluntarily reduce its SO2 emissions. By reducing emissions below allowance allocation, an 

opt-in source will have unused allowances, which it can sell in the SO2 allowance market.

The regulation of ICI boilers by various CAA programs has resulted in a variety of unit level 

emission limits resulting from SIP, NSPS, NSR, or MACT requirements. Overlaid on these unit 

level requirements are system-wide allowances of the NOX SIP call and the Acid Rain SO2 opt-in 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4-3

program. Thus, the specific emission limits and control requirements for a given ICI boiler vary

and depend on boiler age, size, and geographic location.

EVALUATION OF CONTROL OPTIONS

An undesirable by-product of the combustion of sulfur, SO2 is associated with the combustion of 

most fossil fuels. Coal deposits contain sulfur in amounts ranging from trace quantities to as high 

as 8% or more. Distillate oils typically have sulfur contents less than 0.5% while residual oil can 

have 1-2% sulfur by weight. Petroleum coke, a byproduct of the oil refining process, may have 

as much as 6% sulfur. Pipeline quality natural gas contains virtually no sulfur, while landfill gas 

may contain varying amounts of sulfur depending on the materials contained in the landfill. A 

variety of air pollution control technologies are employed to meet requirements for sulfur 

dioxide control and are dependant on a number of factors to determine which technique is 

utilized for a given facility.

Air pollution reduction and control technologies for ICI boilers have advanced substantially over 

the past 25 years. In addition, advances in power generation technologies, renewable energy, 

and energy efficiency have the potential to further reduce emissions from these facilities. The 

focus of this evaluation is on the first category mentioned above - emission control technologies. 

The timing and magnitude of reductions from the other strategies – improved technologies, 

demand reduction/energy efficiency, and clean power should be considered as part of a longerterm solution.

Control techniques may be classified into three broad categories: fuel treatment/substitution, 

combustion modification, and post-combustion control. Fuel treatment primarily reduces SO2

and includes coal cleaning using physical, chemical, or biological processes. Fuel substitution 

involves burning a cleaner fuel or renewable fuel. Combustion modification includes any 

physical or operational change in the furnace or boiler and is sometimes discussed in conjunction 

with post-combustion control technologies. Post-combustion control employs a device after the 

combustion of the fuel and is applied to control emissions of SO2. It should be noted that 

physical or operational changes to a furnace or boiler may require that the unit be examined for 

applicability under the Prevention of Significant Deterioration (PSD) program.

There are a wide variety of proven control technologies for reducing SO2 emissions from ICI

boilers. The method of SO2 control appropriate for any individual ICI boiler is dependent upon 

the type of boiler, type of fuel, capacity utilization, and the types and staging of other air 

pollution control devices. However, cost effective emissions reduction technologies for SO2 are 

available and are effective in reducing emissions from the exhaust gas stream of ICI boilers. 

Effective post-combustion SO2 controls for boilers, and particularly coal-fired boilers, are well 

understood and have been applied to a number of sources over the years in response to 

regulations in the form of NSPS, PSD/NSR, State RACT Rules and the Title IV SO2 program. 

Additional SO2 reductions are anticipated as a result of regional pollution control initiatives 

prompted by the Clean Air Interstate Rule (CAIR), which was passed on May 12, 2005.

In addition to post-combustion controls that can be applied to reduce emissions of SO2 from 

fossil fuel fired boilers, there are other strategies that can be used to reduce emissions of SO2. 
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Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4-4

Examples of such strategies include switching to a fuel with a lower sulfur content, or coal 

cleaning prior to combustion. Methods of SO2 control applicable to ICI boilers are listed in 

Table 4.1 with a brief description of the control option, applicability, and range of performance. 

After the table, a more detailed description of the control option and an analysis of the four factor 

assessment for reasonable progress is presented.

SO2 Control Option Descriptions

Almost all SO2 emission control technologies fall in the category of reducing SO2 after its 

formation, as opposed to minimizing its formation during combustion. The exception to the 

nearly universal use of post-combustion controls is found in fuel switching and, more 

significantly, in fluidized bed boilers, in which limestone is added to the fuel in the combustion 

chamber.

Post-combustion SO2 control is accomplished by reacting the SO2 in the gas with a reagent 

(usually calcium- or sodium-based) and removing the resulting product (a sulfate/sulfite) for 

disposal or commercial use depending on the technology used. SO2 reduction technologies are 

commonly referred to as Flue Gas Desulfurization (FGD) and are usually described in terms of 

the process conditions (wet versus dry), byproduct utilization (throwaway versus saleable) and 

reagent utilization (once-through versus regenerable).

Within each technology category, multiple variations are possible and typically involve the type 

and preparation of the reagent, the temperature of the reaction (for dry processes), the use of 

enhancing additives, etc. Because these variations mostly involve complex process chemistry, 

but are fundamentally similar, this summary focuses on the major categories of SO2 control 

technologies, their applicability, performance and cost. Descriptions of available SO2 control 

technology options are in Table 4.1. A brief discussion of these techniques follows.
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Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4-5

Table 4.1 Available SO2 Control Options For ICI Boilers

Technology Description Applicability Performance

Switch to a Low Sulfur 

Coal (generally <1% sulfur) 

Replace high-sulfur 

bituminous coal combustion 

with lower-sulfur coal

Potential control measure 

for all coal-fired ICIs 

currently using coal with 

high sulfur content

50-80% reduction in SO2

emissions by switching to a 

lower-sulfur coal

Switch to Natural Gas 

(virtually 0% sulfur)

Replace coal combustion 

with natural gas

Potential control measure 

for all coal-fired ICIs

Virtually eliminate SO2

emissions by switching to 

natural gas

Switch to a Lower Sulfur 

Oil

Replace higher-sulfur 

residual oil with lowersulfur distillate oil. 

Alternatively, replace 

medium sulfur distillate oil 

with ultra-low sulfur 

distillate oil

Potential control measure 

for all oil-fired ICIs 

currently using higher 

sulfur content residual or 

distillate oils

50-80% reduction in SO2

emissions by switching to 

a lower-sulfur oil

Coal Cleaning Coal is washed to remove 

some of the sulfur and ash 

prior to combustion

Potential control measure 

for all coal-fired ICI 

boilers

20-25% reduction in SO2

emissions

Combustion Control A reactive material, such 

as limestone or bicarbonate, is introduced 

into the combustion 

chamber along with the 

fuel

Applicable to pulverized 

coal-fired boilers and 

circulating fluidized bed 

boilers

40%-85% reductions in 

SO2 emissions

Flue Gas Desulfurization 

(FGD) - Wet

SO2 is removed from flue 

gas by dissolving it in a 

lime or limestone slurry. 

(Other alkaline chemicals 

are sometimes used)

Applicable to all coal-fired 

ICI boilers

30-95%+ reduction in SO2

emissions

Flue Gas Desulfurization 

(FGD) – Spray Dry

A fine mist containing 

lime or other suitable 

sorbent is injected directly 

into flue gas

Applicable primarily for 

boilers currently firing low 

to medium sulfur fuels

60-95%+ reduction in SO2

emissions

Flue Gas Desulfurization 

(FGD) –Dry

Powdered lime or other 

suitable sorbent is injected 

directly into flue gas

Applicable primarily for 

boilers currently firing low 

to medium sulfur fuels

40-60% reduction in SO2

emissions

Table references:

1. Assessment of Control Technology Options for BART-Eligible Sources, NESCAUM, March 2005.

2. Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options, STAPPA-ALAPCO, March 

2006.
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Switch to Coal with Lower Sulfur Content

Switching from a high sulfur fuel to one with sufficiently low sulfur content is the first option 

available for SO2 reduction in this category for pre-combustion control of SO2. Fuels naturally 

low in sulfur content are readily available for solid (coal) and liquid (oil) fired boilers. For coalfired boilers, low-sulfur fuels may be obtained directly or, alternatively, the sulfur content of coal 

fired in the boiler may be lowered first by cleaning the coal or blending coals obtained from 

several sources. 

However, burning low-sulfur fuel may not be a technically feasible or economically practical 

SO2 control alternative for all boilers. In some cases, a fuel with the required sulfur content to 

meet the applicable emission reduction may not be available or cannot be fired satisfactorily in a 

given boiler unit design. Even if such a fuel is available, use of the lower-sulfur fuel that must 

be transported long distances from the supplier may not be cost competitive with burning higher 

sulfur fuel supplied by near-by suppliers and using a post-combustion control device. The 

feasibility of fuel switching depends partly on the characteristics of the plant and the particular 

type of fuel change being considered. Many plants will be able to switch from high-sulfur to 

low-sulfur bituminous coal without serious difficulty, but switching from bituminous to subbituminous coal may present greater challenges and costs. In some instances, fuel switching will 

require significant investment and modifications to an existing plant. Switching to a lower sulfur 

fuel, either coal or oil, can affect fuel handling systems, boiler performance, PM control 

effectiveness and ash handling systems. Overall SO2 reductions estimated from switching to 

low-sulfur fuels range from 50-80%.

Switch to Natural Gas

Switching from coal combustion to natural gas combustion virtually eliminates SO2 emissions. 

It is technically feasible to switch from coal to natural gas, but it is currently uneconomical to 

consider this option for large ICIs due to the fuel quantity necessary and the price of natural gas. 

The price of natural gas is roughly seven times the price of coal in terms of heating value.

Reduced Sulfur Oil

Oil-fired boilers may opt for lower sulfur distillate fuels or, if available, ultra-low sulfur distillate 

fuel. Number 2 distillate fuel oil, heating oil, and highway diesel fuel oil are the same refineryproduced liquid, and are only differentiated for tax purposes. This differentiation is 

accomplished through addition of a red dye in the fuels supplied for non-transportation related 

use. Currently, the sulfur content in Number 2 oil varies between 15 and 20,000 ppm. 

Beginning in 2006, the permissible level of sulfur in highway diesel fuel (ultra low sulfur diesel, 

or ULSD) was reduced to15 ppm. Prior to that, highway low sulfur diesel fuel was refined to 

contain 500 ppm sulfur (Low Sulfur Diesel, or LSD). Consequently, refineries have already 

performed the capital investments required for the production of LSD and ULSD fuel oil. Based 

on EIA data for the week of Feb 23, 2007 domestic production of ULSD fuel oil accounted for 

about 45% of all distillate oil in the United States and LSD fuel oil accounted for slightly over 

17% of domestic production (See Chapter 8).
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Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4-7

Coal Cleaning

According to the 2006 STAPPA-ALAPCO document on control technologies titled Controlling 

Particulate Matter Under the Clean Air Act: A Menu of Options, coal cleaning or washing is a 

widely practiced method of reducing impurities in coal, particularly sulfur. Reducing the sulfur 

content of the fuel used in the boiler reduces the SO2 emissions proportionally. Coal cleaning 

has been shown to reduce SO2 emissions by 20-25%, while increasing the heating value of the 

fuel. Additional removal can be achieved through advanced chemical washing techniques, but 

no detailed information on these techniques was available.

Conventional (physical) coal washing techniques remove ash and sulfur from coal by crushing 

the fuel and separating the components in a liquid bath, such as water. The lighter coal particles 

float to the top of the bath for recovery, while the heavier impurities sink to the bottom for 

removal.

Although there are benefits associated with coal washing, there are limitations associated with 

this technology. The 20-25% SO2 reduction is beneficial, but post-combustion controls have 

been shown to reduce SO2 emissions by greater percentages. Also, solid and liquid wastes are 

generated using the washing process and must be addressed.

Combustion Control

SO2 reduction is also possible through combustion related control technologies. One such 

technology that has been demonstrated and is currently available is the use of fluidized bed 

boilers.

Fluidized bed boilers generally operate at lower temperatures than other combustion systems, 

800° to 870° C (1500° F to 1600° F). The lower temperatures allow the use of limestone or 

dolomite to be added to the bed to capture sulfur. Limestone (CaCO3) is converted to CaO at 

approximately 800° C (1500° F). SO2 released from the fuel reacts with CaO to form CaSO4, 

which is thermodynamically stable at bed temperatures. By recycling some of the solids leaving 

the bed up to 90% removal of SO2 can be achieved with Ca/S molar ratios of 2 to 2.5 in 

circulating fluidized beds. Higher Ca/S ratios are required in bubbling beds. In either case, the 

sorbent is removed with the ash from the bed and sent to disposal.

Flue Gas Desulfurization (FGD)

There are three types of FGD scrubbers: wet, spray dry, and dry. According to the 2006 

STAPPA-ALAPCO document on control technologies titled Controlling Particulate Matter 

Under the Clean Air Act: A Menu of Options, EPA reports that 85% of the FGD systems in use 

in the United States are wet systems. Twelve percent of the FGD systems are spray dry systems, 

and 3% are dry systems. The operating parameters, efficiency, and costs of each SO2 removal 

method are different.

SO2 in the flue gas can be removed by reacting the sulfur compounds with a solution of water 

and an alkaline chemical to form insoluble salts that are removed in the scrubber effluent. These 

processes are called “wet FGD systems”. Most wet FGD systems for control of SO2 emissions 
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are based on using either limestone or lime as the alkaline source. At some of these facilities, fly

ash is mixed with the limestone or lime. Several other scrubber system designs (e.g., sodium 

carbonate, magnesium oxide, dual alkali) are used by a small number of boilers.

The basic wet limestone scrubbing process is simple and is the type most widely used for control 

of SO2 emissions from coal-fired electric utility boilers. Limestone sorbent is inexpensive and 

generally available throughout the United States. In a wet limestone scrubber, the flue gas 

containing SO2 is brought into contact with limestone/water slurry. The SO2 is absorbed into the 

slurry and reacts with limestone to form an insoluble sludge. The sludge, mostly calcium sulfite 

hemi-hydrate and gypsum, is disposed of in a pond specifically constructed for the purpose or is 

recovered as a salable byproduct.

The wet lime scrubber operates in a similar manner to the wet limestone scrubber. In a wet lime 

scrubber, flue gas containing SO2 is contacted with hydrated lime/water slurry; the SO2 is 

absorbed into the slurry and reacts with hydrated lime to form an insoluble sludge. The hydrated

lime provides greater alkalinity (higher pH) and reactivity than limestone. However, limescrubbing processes require disposal of large quantities of waste sludge.

The SO2 removal efficiencies of existing wet limestone scrubbers range from 31-97%, with an 

average of 78%. The SO2 removal efficiencies of existing wet lime scrubbers range from 30 to 

95%. For both types of wet scrubbers, operating parameters affecting SO2 removal efficiency

include liquid-to-gas ratio, pH of the scrubbing medium, and the ratio of calcium sorbent to SO2. 

Periodic maintenance is needed because of scaling, erosion, and plugging problems. Recent 

advancements include the use of additives or design changes to promote SO2 absorption or to 

reduce scaling and precipitation problems.

A spray dryer absorber (sometimes referred to as wet-dry or semi-dry scrubbers) operates by the 

same principle as wet lime scrubbing, except that the flue gas is contacted with a fine mist of 

lime slurry instead of a bulk liquid (as in wet scrubbing). For the spray dryer absorber process, 

the combustion gas containing SO2 is contacted with fine spray droplets of hydrated lime slurry

in a spray dryer vessel. This vessel is located downstream of the air heater outlet where the gas 

temperatures are in the range of 120 to 180 °C (250 to 350 °F). The SO2 is absorbed in the slurry

and reacts with the hydrated lime reagent to form solid calcium sulfite and calcium sulfate as in a 

wet lime scrubber. The water is evaporated by the hot flue gas and forms dry, solid particles 

containing the reacted sulfur. These particles are entrained in the flue gas, along with fly ash, 

and are collected in a PM collection device. Most of the SO2 removal occurs in the spray dryer 

vessel itself, although some additional SO2 capture has also been observed in downstream 

particulate collection devices, especially fabric filters. This process produces dry reaction waste 

products for easy disposal.

The primary operating parameters affecting SO2 removal are the calcium-reagent-to-sulfur 

stoichiometric ratio and the approach to saturation in the spray dryer. To increase overall sorbent 

use, the solids collected in the spray dryer and the PM collection device may be recycled. The 

SO2 removal efficiencies of existing lime spray dryer systems range from 60-95%.

For the dry injection process, dry powdered lime (or another suitable sorbent such as trona) is 

directly injected into the ductwork upstream of a PM control device. Some systems use spray
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humidification followed by dry injection. This dry process eliminates the slurry production and 

handling equipment required for wet scrubbers and spray dryers, and produces dry reaction waste 

products for easier disposal. The SO2 is adsorbed and reacts with the powdered sorbent. The dry

solids are entrained in the combustion gas stream, along with fly ash, and collected by the PM 

control device. The SO2 removal efficiencies of existing dry injection systems range from 40 to 

60%.

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR ICI 

BOILERS

Each of the control options presented in Table 4.1 is reviewed in this section utilizing a four 

factor analysis approach for determining reasonable progress as required by Section 169A(g)(1) 

of the Clean Air Act and Section 51.308(d)(1)(i)(A). The information provided in this section is 

intended to be used by the States in setting Reasonable Progress Goals (RPGs) for reducing 

regional haze in Class I areas in MANE-VU Class I areas.

Cost of Compliance

To compare the various control options, information has been compiled on the cost-effectiveness 

of retrofitting controls. In general, cost-effectiveness increases as boiler size and capacity factor 

(a measure of boiler utilization) increases.

Cost of Switching to Low Sulfur Coal, Distillate Oil, or Natural Gas

Switching to a low-sulfur coal or blending a lower sulfur coal can impact cost due to the 

following two main reasons:

1. The cost of low-sulfur coal compared to higher sulfur coal.

2. The cost of boiler or coal handling equipment modifications necessary

The cost of low-sulfur coal compared to higher sulfur coal is not only related to the “dollar per 

ton” cost of the coal, but the heating value of the coal also impacts the cost analysis.

Table 4.2 reflects the potential sulfur reduction possible by switching fuels:

Table 4.3 shows the average 2004 and 2005 cost data from the Energy Information 

Administration for various fuels.

Refineries were required to make significant capital investments to meet the LSD and ULSD 

highway fuel sulfur requirement. To achieve the LSD and ULSD sulfur goals, refineries were 

required to implement diesel desulfurization technologies. Estimates for the capital costs were 

developed in 2001 by the Energy Information Administration (EIA) and are based on calendar 

year 1999. Table 4.4 presents the capital costs for desulfurization technologies presented by the 

EIA. The EIA developed estimates for new and revamped desulfurization technologies at 

existing refineries.
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Table 4.2 Potential SO2 Reductions Through Fuel Switching

Original Fuel

Sub-bituminous Coal

(% Reduction)

Distillate oil

(% Reduction)

Natural Gas

(% Reduction)

Bituminous Coal 72.9 91.2 99.9

Sub-bituminous coal - 69.5 99.9

Residual Oil - 91.5 99.9

Distillate Oil - - 99.7

Calculations based on typical fuel sulfur content listed in Department of Energy EIA analysis for 2000. Energy 

Policy Act Transportation Rate Study: Final Report on Coal Transportation

In its highway diesel fuel rulemaking, EPA also developed cost estimates for the deployment and 

implementation of desulfurization technologies at refineries. EPA estimated that it would cost 

existing refineries an estimated $50 million per refinery to install desulfurization technologies. 

No estimates were made for the costs associated with new refineries as none are currently being 

constructed in the United States. The EPA analysis spread the investment cost over a 2-year 

period. Consequently, it was estimated that the US refinery-wide investment for calendar year 

2004 was $2.45 billion and $2.83 billion for calendar year 2005 (EIA 2001) (Converted from 

2001 to 2006 dollars using a conversion factor of 1.1383 www.inflationdata.com).

Using the most recently available EIA price information for 2006 No. 2 Distillate oil for 

industrial, commercial, and institutional facilities in the northeast (excluding taxes), a cost per 

ton of SO2 removed was calculated to be $734/ton SO2 by switching to 500 ppm LSD and 

$554/ton SO2 by switching to ULSD fuel oils. (See the discussion of fuel oil prices in Chapter 7 

– Heating Oil.)

Cost of Coal Cleaning

The World Bank, an organization which assists with economic and technological needs in 

developing countries reports that the cost of physically cleaning coal varies from $1 to $10 per 

ton of coal cleaned, depending on the coal quality, the cleaning process used, and the degree of 

cleaning desired. In most cases the costs were found to be between $1 and $5 per ton of coal 

cleaned.
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Cost of Combustion Control

Dry sorbent injection, (DSI), systems have lower capital and operation costs than postcombustion FGD systems due to: simplicity of design, lower water use requirements, and smaller 

land use requirements. Table 4.3 presents the estimated costs of adding DSI based SO2 controls 

to ICI boilers based on boiler size, fuel type, and capacity factor. Capacity factor is the amount 

of energy a boiler generates in one year divided by the total amount it could generate if it ran at 

full capacity.

Table 4.3 Estimated Dry Sorbent Injection (DSI) Costs For ICI Boilers (2006 dollars)

Fuel

SO2

Reduction 

(%)

Capacity 

Factor (%)

Cost Effectiveness ($/Ton of SO2)

100 

MMBTU/hr

250 

MMBTU/hr

1,000 

MMBTU/hr

2%-sulfur

coal

40 14 4,686 3793 2,979

50 1,312 1062 834

83 772 624 490

3.43%-sulfur

coal

40 14 2,732 2,212 1,737

50 765 619 486

83 450 364 286

2%-sulfur

coal

85 14 2,205 1,786 1,402

50 617 500 392

83 363 294 231

3.43%-sulfur

coal

85 14 1,286 1,040 818

50 360 291 229

83 212 171 134

Calculations based on information available from EPA Publications, EPA-452/F-03-034, Air Pollution Control 

Technology Fact Sheet, and EPA-600/R-05-034, Multipollutant Emission Control Technology Options for Coalfired Power Plants

(Converted from 2005 to 2006 dollars using a conversion factor of 1.0322 www.inflationdata.com)

Cost of FGD

Installation of post-combustion SO2 control in the form of FGD has several impacts on facility 

operation, maintenance, and waste handling. FGD systems typically require significant area for 

construction of the absorber towers, sorbent tanks, and waste handling. The facility costs are,

therefore, variable and dependent on the availability of space for construction of the FGD 

system. Solid waste handling is another factor that influences the cost of FGD control systems. 

Significant waste material may be generated that requires disposal. This cost may be mitigated, 

however, by utilization of a forced oxidation FGD process that produces commercial quality

gypsum, which may be sold as a raw material for other commercial processes.
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Table 4.4 presents the total estimated cost effectiveness of adding FGD based SO2 controls to ICI

boilers based on boiler size, fuel type, and capacity factor. There is no indication that these cost 

data include revenue from gypsum sales. Revenue from gypsum sales would reduce the cost of 

these controls.

Table 4.4 Estimated Flue Gas Desulfurization (FGD) Costs For ICI Boilers (2006 dollars)

Fuel Technology

SO2

Reduction 

(%)

Capacity 

Factor (%)

Cost Effectiveness ($/Ton of SO2)

100 

MMBTU/hr

250 

MMBTU/hr

1,000 

MMBTU/hr

High-sulfur

coala

FGD (Dry) 40 14 3,781 2,637 1,817

50 1,379 1,059 828

83 1,006 814 676

Lower-sulfur

coalb

FGD (Dry) 40 14 4,571 3,150 2,119

50 1,605 1,207 928

83 1,147 906 744

Coal FGD (Spray

dry)

90 14 4,183 2,786 1,601

50 1,290 899 567

83 843 607 407

High-sulfur

coala

FGD (Wet) 90 14 3,642 2,890 1,909

50 1,116 875 601

83 709 563 398

Lower-sulfur

coalb

FGD (Wet) 90 14 4,797 3,693 2,426

50 1,415 1,106 751

83 892 705 492

OilcFGD (Wet) 90 14 10,843 8,325 5,424

50 2,269 1,765 1,184

83 1,371 1,079 740

a. Assumes sulfur content = 3.43% and ash content = 12.71%.

b. Assumes sulfur content = 2.0% and ash content = 13.2%.

c. Sulfur content of oil is not specified.

Table references:

Source: Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options, STAPPA-ALAPCO, 

2006.

Primary Reference: Khan, S. Methodology, Assumptions, and References—Preliminary SO2 Controls Cost 

Estimates for Industrial Boilers (EPA-HQ-OAR-2003-0053-166), October-November 2003.

(Converted from 2004 to 2006 dollars using a conversion factor of 1.0672 www.inflationdata.com)

Time Necessary for Compliance

Generally, sources are given a 2-4 year phase-in period to comply with new rules. Under the 

previous Phase I of the NOX SIP Call, EPA provided a compliance date of about 31⁄2 years from 

the SIP submittal date. Most MACT standards allow a 3-year compliance period. Under Phase II 
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of the NOX SIP Call, EPA provided a 2-year period after the SIP submittal date for compliance. 

States generally provided a 2-year period for compliance with RACT rules. For the purposes of 

this review, we have assumed that a 2-year period after SIP submittal is adequate for precombustion controls (fuel switching or cleaning) and a three year period for the installation of 

post combustion controls. 

For BART control measures, the proposed BART guidelines require States to establish 

enforceable limits and require compliance with the BART emission limitations no later than 5 

years after EPA approves the regional haze SIP.

Refiners in the United States are already producing low sulfur diesel fuel which may be 

marketed as distillate oil. There is a potential that offshore refiners may not be able to produce 

enough 15 ppm sulfur for export to the Northeast United States to meet peak demand, but so far 

this has not occurred.

ICI boilers would not have to retrofit or install expensive control technology to burn ULSD 

distillate fuel oil, therefore, compliance with the standard is driven by supply and demand of the 

lower sulfur distillate oils.

For combustion based and post-combustion based engineering and construction leads times will 

vary between 2 and 5 years depending on the size of the facility and specific control technology

selected.

Energy and Non-Air Impacts

Fuel switching and cleaning do not significantly affect the efficiency of the boiler but may add to 

transportation issues and secondary environmental impacts from waste disposal and material 

handling operations (e.g. fugitive dust). FGD systems typically operate with high pressure drops 

across the control equipment, resulting in a significant amount of electricity required to operate 

blowers and circulation pumps. In addition, some combinations of FGD technology and plant 

configuration may require flue gas reheating to prevent physical damage to equipment, resulting 

in higher fuel usage.

The primary environmental impact of FGD systems is the generation of wastewater and sludge 

from the SO2 removal process. When the exhaust gas from the boiler enters the FGD the SO2, 

metals, and other solids are removed from the exhaust and collected in the FGD liquid. The 

liquid slurry collects in the bottom of the FGD in a reaction tank. The slurry is then dewatered 

and a portion of the contaminant-laden water is removed from the system as wastewater. Waste 

from the FGD systems will increase sulfate, metals, and solids loading in a facility’s wastewater, 

potentially impacting community wastewater treatment facilities for smaller units that do not 

have self contained water treatment systems. In some cases FGD operation necessitates 

installation of a clarifier on site to remove excessive pollutants from wastewater. This places 

additional burdens on a facility or community wastewater treatment and solid waste management 

capabilities. These impacts will need to be analyzed on a site-specific basis. If lime or limestone 

scrubbing is used to produce calcium sulfite sludge, the sludge must be stabilized prior to land 

filling. If a calcium sulfate sludge is produced, dewatering alone is necessary before land filling, 
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however, SO2 removal costs are higher due to increased equipment costs for this type of control 

system. In some cases calcium sulfate sludge can be sold for use in cement manufacturing.

With wet FGD technologies a significant visible plume is present from the source due to 

condensation of water vapor as it exits the smoke stack. Although the water eventually 

evaporates and the plume disappears, community impact may be significant.

Reducing the sulfur contents of distillate fuel oil has a variety of beneficial consequences for ICI

boilers. Low sulfur distillate fuel is cleaner burning and emits less particulate matter which 

reduces the rate of fouling of heating units substantially and permits longer time intervals 

between cleanings. According to a study conducted by the New York State Energy Research and 

Development Authority, (NYSERDA), boiler deposits are reduced by a factor of two by 

lowering the fuel sulfur content from 1,400 ppm to 500 ppm. These reductions in buildup of 

deposits result in longer service intervals between cleanings. (Batey and McDonald 2005)

Remaining Useful Life of the Source

Available information for remaining useful life estimates of ICI boilers indicates a wide range of 

operating time, depending on size of the unit, capacity factor, and level of maintenance 

performed. Typical life expectancies range from about 10 years up to over 30 years.
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REFERENCES

Batey, J.E. and R. McDonald, 2005. Low Sulfur Home Heating Oil Demonstration Project 

Summary Report. Project funded by The New York Sate Energy Research and Development 

Authority. Contract No. 6204-IABR-BR-00.

U.S. EPA, 2005, Multipoint Emission Control Technology Options for Coal-fired Power Plants, 

Washington, DC, EPA-600/R-05/034.

U.S. EPA, 2003, Air Pollution Control Technology Fact Sheet, Washington, DC, EPA-425/F-03-

034.

STAPPA ALAPCO, 2006, Controlling Fine Particulate Matter Under the Clean Air Act: A 

Menu of Options.

The Lake Michigan Air Directors Consortium, Midwest Regional Planning Organization Boiler 

Best Available Retrofit Technology Engineering Analysis, March 30, 2005

U.S. EPA, 1993, PM-10 Innovative Strategies: A Sourcebook for PM-10 Control Programs, 

Research Triangle Park, NC, EPA-452/R-93-016.

U.S. Energy Information Administration, October 2000, Energy Policy Act Transportation Rate 

Study: Final Report on Coal Transportation, Publication downloaded from World Wide Web in 

February, 2007 at http://www.eia.doe.gov/cneaf/coal/coal_trans/epact2000.html

GE Water & Process Technologies. Information accessed on web March 27, 2007:

http://www.zenon.com/applications/FGD_wastewater_treatment.shtml

U.S. Energy Information Administration, 2007. :”No. 2 Distillate Prices By Sales Type”, 

Information downloaded from the World Wide Web on March 7, 2007, at 

http://tonto.eia.doe.gov/dnav/pet/pet_pri_dist_dcu_R1X_m.htm

U.S. Energy Information Administration, 2007. :”weekly Inputs, Utilization and Production”, 

Information downloaded from the World Wide Web on March 7, 2007, at 

http://tonto.eia.doe.gov/dnav/pet/pet_pnp_wiup_dcu_r10_w.htm
This page left blank intentionally.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-1

CHAPTER 5

ANALYSIS OF SELECTED INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL 

BOILERS

SOURCE CATEGORY DESCRIPTION

Modeling of visibility impacts on Class I regions was conducted by the Vermont Department of 

Environmental Conservation (VTDEC) and MANE-VU to identify the major ICI sources 

contributing to visibility impairment in the northeast. Table 5.1 lists the ICI sources identified to 

contribute significant levels of SO2 to the MANE-VU region. MACTEC was directed by 

MARAMA and the Reasonable Progress Workgroup to focus on the 17 major sources listed in 

Table 5.1.

As explained in the previous chapter, there are a wide variety of proven control technologies for 

reducing SO2 emissions from ICI boilers and specifically the control method for SO2 applied to 

any individual ICI boiler is dependent upon the type of boiler, type of fuel, capacity utilization, 

and the types and staging of other air pollution control devices. However, cost effective 

emissions reduction technologies for SO2 are available and are effective in reducing emissions 

from the exhaust gas stream of ICI boilers.

INFORMATION OBTAINED FROM STATE AGENCIES

For the selected ICI boilers, MACTEC contacted State and or regional regulatory agencies to 

evaluate the status of each unit and determine if additional pollution controls had been mandated 

as a part of regulatory actions taken since the data used for the visibility impairment modeling 

were collected. Table 5.1 presents the information obtained from the States.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-2

Table 5.1 Point Source Information Collected from the Top 17 Industrial Facilities Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)

Primary Emissions Point 

Description

Point ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Motiva 

Enterprises 

LLC –

Delaware 

City1

DE 29,747 Fluid Coking Unit (FCU) 

and FCU Carbon Monoxide 

Boiler

002 57,199 barrels 

per day of total 

feed

None Cansolv 

Regenerative 

Wet Gas 

Scrubber and 

SNCR

Data from Permit 

APC-82/0829 

Amendment 5 SO2

permit limit is 174 tpy

Fluid Catalytic Cracking 

Unit (FCCU) and FCCU 

Carbon Monoxide Boiler

012 FCCU coke burn 

rate limit is 

56,000 lbs/hr

None Cansolv 

Regenerative 

Wet Gas 

Scrubber

Data from Permit 

APC-82/0981 

Amendment 6 SO2

permit limit is 361 tpy
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-3

Table 5.1 Point Source Information Collected from the Top 17 Industrial Facilities Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)

Primary Emissions Point 

Description

Point ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Kodak Park 

Division2, 3

NY 23,508 Building 31 and 321 

stationary combustion 

installations, including 

package ABD built up 

boilers used for the 

generation of process steam 

and electricity

Boilers:

1 – Package boiler, No. 6

2 – Package boiler, No. 6

3 – Package boiler, No. 6

4 – Package boiler, No. 6

13 – Underfed stoker, coal

14 – Underfed stoker, coal

11 – Underfed stoker, coal

12 – Underfed stoker, coal

15 – Wet bottom cyclone, 

coal/No. 6

16 – Wall-fired, coal/No. 6

41 – Wet bottom cyclone, 

coal/No. 6

42 – Wet bottom cyclone, 

coal/No. 6

43 – Wet bottom cyclone, 

coal/No. 6

44 – Tangential-fired 

pulverized coal, coal/No. 2

U0015

Boilers (EP031B-1):

1

2

3

4

13

14

Boilers (EP031B-2):

11

12

15

16

Boilers (EP321B-3):

41

42

Boilers (EP321B-4):

43

44

98 MMBTU/hr

98 MMBTU/hr

98 MMBTU/hr

98 MMBTU/hr

265 MMBTU/hr

265 MMBTU/hr

197 MMBTU/hr

222 MMBTU/hr

478 MMBTU/hr

544 MMBTU/hr

500 MMBTU/hr

500 MMBTU/hr

640 MMBTU/hr

670 MMBTU/hr

None BART 

analysis - NOX

& SO2 controls 

affordable on 

Boilers 41, 42, 

& 43

Wet scrubber 

(90% 

reduction) 

would be 

~$2,150/ton

Dry scrubber 

(40% 

reduction) 

would be 

~$1,850/ton

Process K07 (Bldg 31) is 

No. 6 fuel oil combustion 

in package boilers

Process K09 (Bldg 31) is 

bituminous coal 

combustion in built up 

Boilers 13 and 14

Process K10 (Bldg 31) is 

No. 6 fuel oil combustion 

in built up Boilers 15 and 

16

Process K11 (Bldg 31) is 

bituminous coal 

combustion for built up 

Boiler 15

Process K12 (Bldg 321) 

is No. 6 fuel oil 

combustion for built up 

Boilers 41, 42 and 43

Process K13 (Bldg 321) 

is bituminous coal 

combustion for built up 

Boilers 41, 42 and 43

Process K14 (Bldg 321) 

is No. 2 fuel oil 

combustion with NSPS 

applicability in Boiler 44

Process K15 (Bldg 321) 

is bituminous low sulfur 

coal combustion
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-4

Table 5.1 Point Source Information Collected from the Top 17 Industrial Facilities Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)

Primary Emissions Point 

Description

Point ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

MW Custom 

Papers LLC –

Chillicothe 

Mill4

OH 23,216 No.5 Coal Boiler - wet 

bottom, pulverized coalfired boiler (C. E. model 

VU-40), capable of running 

on #2 fuel oil as backup fuel

B001 380 MMBTU/hr 

maximum heat 

input

Cyclone/

multi-clone

ESP

None 9.9 lbs of sulfur dioxide 

per MMBTU actual heat 

input

No.7 Coal Boiler - wet 

bottom, pulverized coalfired boiler (C. E. model 

VU-405), capable of 

running on #2 fuel oil as 

backup fuel

B002 422 MMBTU/hr 

maximum heat 

input

Cyclone/

multi-clone

ESP

None 9.9 lbs of sulfur 

dioxide per MMBTU

actual heat input

No.8 Coal Boiler - wet 

bottom, pulverized coalfired boiler (C. E. model 

VU-40), capable of running 

on #2 fuel oil as backup 

fuel.

B003 505 MMBTU/hr 

maximum heat 

input

Cyclone/

multi-clone

ESP

None 9.9 lbs of sulfur 

dioxide per MMBTU

actual heat input
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-5

Table 5.1 Point Source Information Collected from the Top 17 Industrial Facilities Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)

Primary Emissions Point 

Description

Point ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Eastman 

Chemical 

Company5, 6

TN 22,882 Two fuel burning 

installations (B-83-1 & B253-1) w/a total of 19 coal 

fired boilers of which 14 

units (#18-#24) are located at 

Powerhouse B-83-1 & 5 

units (#25-#29) are located at 

Powerhouse B-253-1. The 

primary fuel is coal. In 

addition, wood, waste solids, 

waste liquids, & biosludge 

may be burned in these 

Powerhouses, while NG & 

process gas may also be 

burned in the Powerhouse B253-1 boilers.

82-0003-01-

19

(020101, 

021520)

6,625 Million 

BTU/hr nominal 

heat input

ESP Scubbers 

potentially

The five boilers in 

Powerhouse B-253-1 

are subject to BART.

The State does not 

have confirmation yet, 

but they believe that 

the boilers will be 

controlled by 

scrubbers of some sort.

Units #11-#17, that 

were located at 

Powerhouse B-83-1, 

have been removed 

Coal-Fired Boilers 30 and 

31

PES

B-325-1or 

82-1010-15 

(261501)

Heat input is 

limited to 780 

and 880 

MMBTU/hr, 

respectively, on 

a 30 calendar 

day rolling 

average basis

None None

Westvaco Fine 

Papers7, 8

MD 19,083 Boiler 24 is a coal firedcyclone boiler1 590 MMBTU/hr 

maximum heat 

input

SNCR 

(NOX)

ESP (PM)

Baghouse 

(PM)

Not BART eligible 

due to age
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-6

Table 5.1 Point Source Information Collected from the Top 17 Industrial Facilities Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)

Primary Emissions Point 

Description

Point ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Boiler 25 is a coal firedtangential boiler2 785 MMBTU/hr 

maximum heat 

input

Low NOX

burners/

overfired air 

(NOX)

ESP (PM)

Scrubber 

(FGD in 

design)

SNCR (NOX)

Baghouse to 

replace ESP 

(PM)

BART eligible

PPG Industries 

Inc.9

WV 12,678 Boiler 3 is a coal-fired 

boiler installed in 1942 and 

modified in 1981

R011 (002) 

or S076

243 MMBTU/hr Fabric filter

Low NOX

burners

None Not BART eligible

Boiler 4 is a coal-fired and 

natural gas-fired boiler 

installed in 1952

R015 (001) 

or S076

496 MMBTU/hr ESP

Low NOX

burners

None Not BART eligible

Boiler 5 is a coal-fired 

boiler installed in 1966

R072 (003) 

or S482

878 MMBTU/hr ESP

Low NOX

burners

None BART eligible, facility 

to decrease emissions 

by using low-sulfur 

coal and taking an 

emission limit of 

1,478.8 lb SO2/hr
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-7

Table 5.1 Point Source Information Collected from the Top 17 Industrial Facilities Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)

Primary Emissions Point 

Description

Point ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Williams 

Ethanol 

Services

Inc.10, 11

IL 12,244 4 boilers

Boiler A & B are coal-fired 

boilers constructed in 1944

Boiler C is a coal/oil 

supplemental-fired boiler 

constructed in 1958

Boiler D is a NG/No. 2 oilfired boiler constructed in 

1976

10 Boilers A & B: 

242 MMBTU/hr

Boiler C:

330 MMBTU/hr

Boiler D:

195 MMBTU/hr

Boilers A & 

B: Multicyclone

Boiler C:

ESP

Boiler D:

None

None Not BART eligible.

There is also a steep 

acid preparation 

system (Unit 2) that 

converts sulfur into 

sulfurous acid that will 

be used for the 

steeping process. 

Total sulfur usage for 

this unit is limited to 

961,750 lbs/yr (at least 

48% of the sulfur 

added to steepwater 

shall be retained in the 

products shipped from 

the plant).
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-8

Table 5.1 Point Source Information Collected from the Top 17 Industrial Facilities Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)

Primary Emissions Point 

Description

Point ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Corn Products 

International 

Inc.10, 11

IL 9,281 Utilities:

Coal fired Boilers #1, #2, & 

#3 (pre 1972)

Natural gas-fired Boilers #4 

& #5 (pre 1972)

Natural gas-fired Boiler #6 

constructed in 1992

2 natural gas-fired turbines 

constructed in 1995

Group 9 Boilers #1, #2, & 

#3:

250 MMBTU/hr

Boilers #4 & #5:

312.5 

MMBTU/hr

Boiler #6:

600 MMBTU/hr

Turbines:

65 MMBTU/hr

Boilers #1, 

#2, & #3:

ESP

Boilers #4 & 

#5: None

Boiler #6:

low-NOX

burner & 

flue gas 

recirculation

Turbines:

None

None Not BART eligible

Mead

Westvaco 

Packaging 

Resource 

Group12

VA 8,552 Four (4) boilers

#6 – primarily coal-fired

#7 – coal/bark/wood-fired

#8 - coal/bark/wood-fired

#9 – primarily coal-fired

25 550 MMBTU/hr

440 MMBTU/hr

580 MMBTU/hr

807 MMBTU/hr

ESP

Scrubbers

FGR

LNB

None

PH Glatfelter 

Co./Spring 

Grove13, 14

PA 7,855 #4 Power Boiler that burns 

bituminous coal (13 

tons/hr), #6 oil (751 gal/hr), 

& #2 oil (108 gal/hr)

034 363.7 

MMBTU/hr

Cyclone 

dust 

collector

ESP

None Not BART eligible
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-9

Table 5.1 Point Source Information Collected from the Top 17 Industrial Facilities Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)

Primary Emissions Point 

Description

Point ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

#5 Power Boiler that burns 

bituminous coal (10.3 

tons/hr), #6 oil (300 gal/hr), 

“as fired” wood (12.2 

tons/hr), & #2 oil (451.2 

gal/hr)

035 262.3 

MMBTU/hr

Cyclone 

dust 

collector

ESP

None BART eligible

Goodyear Tire 

& Rubber Co.4

OH 5,903 "A" Boiler, which is a coalfired boilerB101 301 MMBTU/hr ESP None 4.64 lbs of sulfur 

dioxide per MMBTU

actual heat input for 

B101, B102, and B103 

exiting through

Stack 4

"B" Boiler, which is a coalfired boilerB102 301 MMBTU/hr ESP None 4.64 lbs of sulfur 

dioxide per MMBTU

actual heat input for 

B101, B102, and B103 

exiting through

Stack 4

"C" Boiler, which is a coalfired boiler B103 174 MMBTU/hr ESP None 4.64 lbs of sulfur 

dioxide per MMBTU

actual heat input for 

B101, B102, and B103 

exiting through

Stack 4
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-10

Table 5.1 Point Source Information Collected from the Top 17 Industrial Facilities Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)

Primary Emissions Point 

Description

Point ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Sunoco Inc. 

(R&M)15, 16

PA 3,645 Plt. 10-4 FCC Unit 101 4,792.000 bbl/hr 

fresh feed

None SCR and a wet 

gas scrubber 

installed in 

2010. At the 

latest, 

compliance is 

required by 

2013.

SO2 limit of 9.8 

lbs/1000 lbs of coke 

burn-off in the catalyst 

regenerator determined 

daily on a 7-day

rolling average basis

Valero 

Refining Co. –

NJ17, 18

NJ 3,597 FCCU Regenerator with InLine HeaterE21 or U1 102 MMBTU/hr WGS None Per Consent Decree, 

SO2 concentration 

emission limits at the 

point of emission to 

the atmosphere of no 

greater than 25 ppmvd, 

measured as a 365-day 

rolling average, and 50

ppmvd, measured as a 

7-day rolling average, 

both at 0% O2.

Stone 

Container 

Corp. (dba 

Smurfit-Stone 

Contain)19

VA 3,379 #8 Power Boiler that burns 

bituminous coal

2 1,056 

MMBTU/hr

None Wet gas 

scrubber 

(2007)

Consent Decree dated 

11/2004 which states 

that SO2 emission rate 

will not exceed 0.26 

lb/MMBTU on a 30-

day rolling average 

basis.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-11

Table 5.1 Point Source Information Collected from the Top 17 Industrial Facilities Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)

Primary Emissions Point 

Description

Point ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

Great Northern 

Paper Inc. Mill 

West20, 21

ME 1,842 Power Boilers #4 (RileyStoker))004 (WB4) 740 MMBTU/hr None None Unit to be shut down 

so BART not an issue 

(only BART eligible 

source at this facility)

NRG Energy 

Center Dover 

LLC1, 22, 23

DE 1,836 Riley Stoker Boiler fired on 

pulverized bituminous coal 

(primary fuel) and natural 

gas (for startup/ignition).

C-1 (001) 243 MMBTU/hr Four (4) DB 

Riley Low 

NOX burners

Cyclonic 

Combustion 

Venturi 

burner 

assemblies

Low excess 

air

ESP 

w/23,000 ft2

collecting 

electrode 

area

None Not BART eligible

SappiSomerset20, 21ME 1,734 Power Boiler #1 (Babcock 

& Wilcox)

001 (PB#1) 848 MMBTU/hr 

(all fuels) &

250 MMBTU/hr 

(fossil fuels)

None None CEMS for SO2

Facility to reduce SO2

emissions by 50% by 

2013 (BART deadline)

1 MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid-Atlantic North Eastern Class I Areas”, March 8, 2007. 

Comments regarding Motiva Enterprises LLC – Delaware City and NRG Energy Center Dover LLC facilities received from Mr. John Sipple (302-739-9435, 

John.Sipple@state.de.us) via E-mail on March 13, 2007.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-12

2 New York State Department of Environmental Conservation, Division of Air Resources. Personal communications regarding Kodak Park Division facility between Mr. Mike 

Cronin, P.E. (518-402-8403, mpcronin@gw.dec.state.ny.us) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on February 1 and 9, 2007.

3 New York State Department of Environmental Conservation, Division of Air Resources. Personal communications regarding Kodak Park Division facility from Mr. Mike 

Cronin, P.E. (518-402-8403, mpcronin@gw.dec.state.ny.us) via E-mail on February 12, 2007.

4 Ohio Environmental Protection Agency, Division of Air Pollution Control. Personal communication regarding MW Custom Papers LLC – Chillicothe Mill and Goodyear Tire 

and Rubber Company facilities from Mr. William Spires (614-644-3618, bill.spires@epa.state.oh.us) via E-mails on February 20, 2007.

5 Tennessee Department of Environment and Conservation, Division of Air Pollution Control. Personal communication regarding Eastman Chemical Company facility from Ms. 

Julie Aslinger (615-532-0587, Julie.Aslinger@state.tn.us) via E-mail on March 1, 2007.

6 MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid-Atlantic North Eastern Class I Areas”, March 8, 2007. 

Comments regarding Eastman Chemical Company facility received from Ms. Julie Aslinger (615-532-0587, Julie.Aslinger@state.tn.us) via E-mail on March 30, 2007.

7 Maryland Department of the Environment. Personal communication regarding Westvaco Fine Papers facility between Mr. Andy Heltibridle (410-537-4218, 

aheltibridle@mde.state.md.us) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007.

8 Maryland Department of the Environment. Personal communication regarding Westvaco Fine Papers facility from Mr. Andy Heltibridle (410-537-4218, 

aheltibridle@mde.state.md.us) via E-mail on January 31, 2007.

9 West Virginia Division of Air Quality. Personal communications regarding PPG, Industries, Inc. facility between Ms. Laura Crowder (304-926-0499 Ext. 1247, 

LCROWDER@wvdep.org) and Mr. Steve Pursley (304-926-0499 Ext. 1218) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on March 14, 2007.

10 Virginia Department of Environmental Quality, Division of Air Quality. Personal communication regarding Mead Westvaco Packaging Resource Group facility between Ms. 

Doris McLeod (504-698-4197, damcleod@deq.virginia.gov) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on February 20, 2007.

11 Pennsylvania Department of Environmental Protection, Bureau of Air Quality. Personal communication regarding PH Glatfelter Company/Spring Grove facility between Ms. 

Nancy Herb (717-783-9269, nherb@state.pa.us) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007.

12 Pennsylvania Department of Environmental Protection, Bureau of Air Quality. Personal communications regarding PH Glatfelter Company/Spring Grove facility from Ms. 

Nancy Herb (717-783-9269, nherb@state.pa.us) via E-mail on January 31 and February 7, 2007.

13 Illinois Environmental Protection Agency, Bureau of Air. Personal communication regarding Williams Ethanol Services Incorporated and Corn Products International 

Incorporated facilities between Mr. Rob Kaleel (217-524-4387, Rob.Kaleel@illinois.gov) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on February 2, 2007.

14 Illinois Environmental Protection Agency, Bureau of Air. Personal communication regarding Williams Ethanol Services Incorporated and Corn Products International 

Incorporated facilities from Mr. Rob Kaleel (217-524-4387, Rob.Kaleel@illinois.gov) via E-mail on February 2, 2007.

15 Pennsylvania Department of Environmental Protection, Bureau of Air Quality. Personal communications regarding Sunoco Inc. (R&M) facility between Ms. Nancy Herb (717-

783-9269, nherb@state.pa.us) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007.

16 Pennsylvania Department of Environmental Protection, Bureau of Air Quality. Personal communications regarding Sunoco Inc. (R&M) facility from Ms. Nancy Herb (717-

783-9269, nherb@state.pa.us) via E-mail on February 22, 2007.

17 New Jersey Department of Environmental Protection, Division of Air Quality. Personal communications regarding Valero Refining Company facility between Mr. Ray Papalski 

(609-633-7225, Ray.Papalski@dep.state.nj.us) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31 and February 2, 2007.

18 New Jersey Department of Environmental Protection, Division of Air Quality. Personal communication regarding Valero Refining Company facility from Mr. Ray Papalski 

(609-633-7225, Ray.Papalski@dep.state.nj.us) via E-mail on February 21, 2007.

19 Virginia Department of Environmental Quality, Division of Air Quality. Personal communication regarding Stone Container Corporation facility from Ms. Doris McLeod (504-

698-4197, damcleod@deq.virginia.gov) via E-mail on February 9, 2007.

20 Maine Department of Environmental Protection Agency, Bureau of Air Quality. Personal communications regarding Great Northern Paper Incorporated Mill West and Sappi -

Somerset facilities between Ms. Lynn Ross (207-287-8106, Lynn.Ross@maine.gov) and Mr. Marc Cone (207-287-2437) and Ms. Lori Cress, MACTEC Federal Programs, Inc. 

on February 2, 2007.

21 Maine Department of Environmental Protection Agency, Bureau of Air Quality. Personal communication regarding Great Northern Paper Incorporated Mill West and Sappi -

Somerset facilities between Ms. Lynn Ross (207-287-8106, Lynn.Ross@maine.gov) via E-mail on February 2, 2007.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-13

22 Delaware Department of Natural Resources and Environmental Control, Division of Air and Waste Management. Personal communications regarding NRG Energy Center 

Dover LLC facility between Ms. Tammy Henry (302-323-4542, Tammy.Henry@state.de.us) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on March 5, 2007.

23 Delaware Department of Natural Resources and Environmental Control, Division of Air and Waste Management. Personal communications regarding NRG Energy Center 

Dover LLC facility from Ms. Tammy Henry (302-323-4542, Tammy.Henry@state.de.us) via E-mail on March 5, 2007.
This page left blank intentionally.
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 6: Source Category Analysis: Kilns Page 6-1

CHAPTER 6

SOURCE CATEGORY ANALYSIS: KILNS

SOURCE CATEGORY DESCRIPTION

Portland cement is a main ingredient for concrete and other common building materials. 

Portland cement is mainly composed of clinker, a material formed by heating limestone and 

other ingredients to temperatures over 1,400oC (2,650oF). High combustion temperatures require 

large amounts of fuel and can result in significant emissions of SO2 and NOX. Crushing of 

ingredients and finished clinker can release dust and particles. Ammonia is sometimes produced 

during the heating of limestone.

Figure 6.1 shows a process flow diagram of a Portland cement facility. The process flow 

diagram (taken from AP-42) shows both wet and dry Portland cement processes.

Figure 6.1 Portland Cement Process Flow Diagram

EPA. January, 1995. AP42 Section 11.6 – “Portland Cement Manufacturing”.

Figure 6.1 shows that the Portland cement process can generally be broken down into the 

following steps: raw materials handling, raw material preparation, dry mixing, optional 
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 6: Source Category Analysis: Kilns Page 6-2

preheating and/or precalcining, kiln treatment (pyroprocessing step), clinker handling and 

storage, and finishing operations (finishing, storage and shipment). The pyroprocessing step 

transforms the raw mix into clinkers, which are gray, glass-hard, spherically shaped nodules that 

range from 0.125 to 2.0 inches in diameter.

The pyroprocessing step is the predominant source of gaseous pollutant emissions. In general, 

there are five different processes used in the Portland cement industry to accomplish the 

pyroprocessing step: the wet process, the dry process (long dry process), the semidry process, the 

dry process with a preheater, and the dry process with a preheater/precalciner.

Each of the pyroprocessing types vary with respect to equipment design, method of operation, 

and fuel consumption. Generally, fuel consumption decreases in the order of the processes listed 

due to the heat required to evaporate water present in the raw material slurry (e.g., wet processes 

use the most fuel).

In the long dry process, all of the pyroprocessing activity occurs in the rotary kiln. Dry process 

pyroprocessing systems have been improved in thermal efficiency and productive capacity

through the addition of one or more cyclone-type preheater vessels in the gas stream exiting the 

rotary kiln. This system is called the preheater process. The vessels are arranged vertically, in 

series, and are supported by a structure known as the preheater tower. Hot exhaust gases from 

the rotary kiln pass countercurrently through the downward-moving raw materials in the 

preheater vessels. Compared to the simple rotary kiln (long dry process), the heat transfer rate is 

significantly increased, the degree of heat utilization is greater, and the process time is markedly 

reduced by the intimate contact of the solid particles with the hot gases. The improved heat 

transfer allows the length of the rotary kiln to be reduced. An added benefit of the preheater 

operation is that hot gases from the preheater tower are used to help dry raw materials in the raw 

mill. Because the catch from the mechanical collectors, fabric filters, and/or electrostatic 

precipitators (ESP) that follow the raw mill is returned to the process, these devices can also be 

considered to be production machines as well as pollution control devices. 

Additional thermal efficiencies and productivity gains have been achieved by diverting some of 

the fuel to a calciner vessel at the base of the preheater tower. This system is called the 

preheater/precalciner process. 

Regardless of the type of pyroprocess used, the last component of the pyroprocessing system is 

the clinker cooler. The clinker cooler serves two main purposes. First, this portion of the 

process:

 recoups up to 30% of the heat input to the kiln system;

 locks in desirable product qualities by freezing mineralogy; and

 makes it possible to handle the cooled clinker with conventional conveying equipment.

The more common types of clinker coolers are reciprocating grate, planetary, and rotary. In 

these coolers, the clinker is cooled from about 1,100°C to 90°C (2000°F to 200°F) by ambient 

air that passes through the clinker and into the rotary kiln for use as combustion air. However, in 

the reciprocating grate cooler, lower clinker discharge temperatures are achieved by passing an 
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 6: Source Category Analysis: Kilns Page 6-3

additional quantity of air through the clinker. Because this additional air cannot be used in the 

kiln for efficient combustion, it is vented to the atmosphere, used for drying coal or raw 

materials, or used as a combustion air source for the precalciner. 

The second portion of the clinker process, a series of blending and grinding operations, 

completes the transformation of clinker into finished cement. Up to 5% gypsum or natural 

anhydrite is added to the clinker during grinding to control the cement setting time, and other 

specialty chemicals are added as needed to impart specific product properties. This finish 

milling is accomplished almost exclusively in ball or tube mills. Typically, finishing is 

conducted in a closed-circuit system, with product sizing by air separation.

Coal is the fuel of choice in cement kilns, primarily because of its low cost, but also because the 

coal ash contributes to the product. The current fuel usage in cement kilns is about 82% coal; 

4% natural gas; and 14% other fuels, mainly combustible waste (industrial waste, tires, sewage 

sludge, etc.). In addition to conventional fuels, many Portland cement facilities are employing 

the use of petroleum derived coke (petcoke) blended with coal to fire kilns.

Lime kilns are similar to cement kilns. The kiln is the heart of the lime manufacturing plant, 

where various fossil fuels (such as coal, petroleum coke, natural gas, and fuel oil) are combusted 

to produce the heat needed for calcination. There are five different types of kilns used in lime 

manufacturing: rotary, vertical, double-shaft vertical, rotary hearth, and fluidized bed. The most 

popular is the rotary kiln, however the double-shaft vertical kiln is an emerging new kiln 

technology gaining in acceptance primarily due to its energy efficiency. Similar to cement 

plants, rotary kilns at lime manufacturing plants may also have preheaters to improve energy

efficiency. Additionally, energy efficiency is improved by routing exhaust from the lime cooler 

to the kiln. SO2 emissions from lime predominately originate from compounds in the limestone 

feed material and fuels and are formed from the combustion of fuels and the heating of feed 

material in the kiln.

All types of kilns at lime manufacturing plants use external equipment to cool the lime product, 

except vertical (including double-shaft) kilns, where the cooling zone is part of the kiln. 

Ambient air is most often used to cool the lime (although a few use water as the heat transfer 

medium), and typically all of the heated air stream exiting the cooler goes to the kiln to be used 

as combustion air for the kiln. The exception to this is the grate cooler, where more airflow is 

generated than is needed for kiln combustion, and consequently a portion (about 40%) of the 

grate cooler exhaust is vented to the atmosphere. EPA has estimated that there are about five to 

ten kilns in the United States that use grate coolers. The emissions from grate coolers include 

lime dust (PM) and trace metallic HAPs found in the lime dust, but not typically SO2.

For cement and lime kilns, add-on control technology options identified for SO2 include 

advanced flue gas desulfurization (AFGD), dry FGD, and wet FGD.

EVALUATION OF SO2 EMISSION CONTROL OPTIONS

Sulfur dioxide may be generated both from the sulfur compounds in the raw materials and from 

sulfur in the fuel. The sulfur content of both raw materials and fuels varies from plant to plant 

and with geographic location. However, the alkaline nature of the cement provides for direct 
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 6: Source Category Analysis: Kilns Page 6-4

absorption of SO2 into the product, thereby reducing the quantity of SO2 emissions in the exhaust 

stream. Depending on the process and the source of the sulfur, SO2 absorption ranges from 

about 70% to more than 95%.

In contrast to electric utility and industrial boilers, SO2 emissions from rotary cement kilns are 

not strongly dependent on fuel sulfur content. Instead, SO2 emissions are more closely related to 

the amount of sulfide (e.g. pyrite) in kiln feedstocks and to the molar ratio of total sulfur to total 

alkali input to the system. In cement kilns SO2 emissions generally depend on:

 Inherent SO2 removal efficiency of kiln system during processing,

 Form of sulfur (e.g. pyritic) and sulfur concentrations in raw material,

 Molecular ratio between sulfur and alkalis,

 Prevailing conditions (oxidizing or reducing) and their location within the kiln, and

 Temperature profile in the kiln system.

SO2 emission reductions may also result from attempts to reduce other pollutants (primarily 

NOX), typically due to changes in the flame characteristics of combustion. For example, staged 

combustion with mid-kiln injection of a low-sulfur fuel may be considered for reducing SO2. 

Similarly, including high pressure air injection at a mid-kiln firing site can limit oxygen in the 

kiln and suppress SO2 formation (Hansen, 2002). Since these techniques are primarily used to 

reduce NOX and because their efficiencies are typically more limited than other techniques they

are not considered in additional detail here.

Other more specific SO2 control technologies applicable to cement kilns are listed below. A 

summary of controls evaluated for this work is provided in Table 6.1. Details of each of the 

control technologies follow Table 6.1. Additional information on this source category and 

associated controls can be found in the 2005 NESCAUM document titled: Assessment of Control 

Technology Options for BART-Eligible Sources.
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 6: Source Category Analysis: Kilns Page 6-5

Table 6.1 SO2 Control Technologies for Cement Kilns

Technology Description Applicability Performance

Fuel Switching Limiting the sulfur content of both 

raw materials and fuels can reduce 

releases of SO2. Availability of 

these materials is highly sitespecific.

All Kilns Depends on 

availability of lowsulfur raw materials

Dry Flue Gas 

Desulfurization -

Spray Dryer 

Absorption (FGD)

Addition of absorbents such as 

slaked lime (Ca(OH)2), quicklime 

(CaO) or activated fly ash with high 

CaO content to the exhaust gas of 

the kiln can absorb some of the SO2.

All Kilns 60-80% reduction

Wet Flue Gas 

Desulfurization 

(FGD)

SO2is absorbed by a liquid/slurry 

sprayed in a spray tower or is 

bubbled through the liquid/slurry. 

Wet scrubbers also significantly 

reduce the HCl, residual dust, metal 

and NH3 emissions. 

All Kilns 90-99.9% reduction

Advanced Flue Gas 

Desulfurization 

(FGD)

DOE demonstrated a retrofit 

Passamaquoddy Technology 

Recovery ScrubberTM using cement 

kiln dust (CKD), an alkaline-rich 

(potassium) waste, to react with the 

acidic flue gas.

All Kilns 95-99.5% reduction

Table References:

1. Assessment of Control Technology Options for BART-Eligible Sources, NESCAUM, March 2005.

2. Miller, F.M. et. al. Formation and Techniques of Control of Sulfur Dioxide and Other Sulfur Compounds in 

Portland Cement Kiln Systems. Portland Cement Association R&D Serial No. 2460, 2001.

Fuel Switching

As with any fuel-fired SO2 emission source, reduction of sulfur levels in the fuel itself typically 

results in lowered emissions. However, this technique is less effective in cement-making 

systems, where SO2 emissions are not strongly dependent on fuel sulfur content. Depending 

upon the level of sulfur in a plant’s limestone, and more specifically the pyrite content, compared 

to the sulfur content of its heating fuel, fuel switching may not be sufficient to reduce SO2

emissions (Tanna and Schipholt, 2004). However, when fuel sulfur levels are high, fuel 

switching may have a significant benefit in SO2 levels.

Flue Gas Desulfurization (FGD)

Both wet and dry flue gas desulfurization (FGD) systems have been used effectively to control 

SO2 emissions from cement kilns. FGD systems at cement facilities typically are, 1) dry flue gas 

desulfurization (spray dryer absorption) 2) wet flue gas desulfurization, and 3) advanced flue 

gas desulfurization (AFGD). A brief description of each of these technologies is provided 

below.
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 6: Source Category Analysis: Kilns Page 6-6

Dry Flue Gas Desulfurization (Spray Dryer Absorption)

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO2 is 

absorbed by the slurry, forming a mixture of calcium sulfite and calcium sulfate. The liquid-togas ratio is such that the water evaporates before the droplets reach the bottom of the tower. The 

dry solids are carried out with the gas and collected with a fabric filter or ESP. When used to 

specifically control SO2, the term dry flue-gas desulfurization (dry FGD) may also be used. As 

with other types of dry scrubbing systems (such as lime/limestone injection) exhaust gases that 

exit at or near the adiabatic saturation temperatures can create problems with this control 

technology by causing the baghouse filter cake to become saturated with moisture and plug both 

the filters and the dust removal system. In addition, the lime slurry would not dry properly and 

would plug up the dust collection system. However there is some argument in the control 

community that indicates that some of the SO2 removal actually occurs on the filter cake. 

Therefore, dry FGD (spray dryer absorption) may not be technically feasible if exit gas 

temperatures are not substantially above the adiabatic saturation temperatures. For Portland 

cement facilities, these temperatures are likely to be above the adiabatic saturation temperatures.

Most of the spray dryer type SO2 control technologies in the cement industry are applied to 

preheater or preheater/precalciner kilns. Exhaust gases from long dry kilns are cooled by either 

spray water introduced into the feed end of the kiln or by dilution air-cooling after the gases 

leave the kiln. Adding a conditioning tower to replace wet suppression or dilution air enables the 

alkaline slurry system to be used to reduce SO2 emissions (the equivalent of a spray dryer). The 

use of an alkaline slurry spray dryer type scrubber should be applied to long wet kilns with care 

because the addition of the lime slurry may drop the exhaust gases temperature below the acid 

adiabatic saturation temperatures, creating significant plugging and corrosion problems in the 

downstream particulate control device, duct work, and induced draft fan.

Wet Flue Gas Desulfurization (FGD)

Wet scrubbing processes used to control SO2 and particulate emissions are generally termed fluegas desulfurization (FGD). FGD utilizes gas absorption technology, the selective transfer of 

materials from a gas to a contacting liquid, to remove SO2 in the waste gas. Caustic, crushed 

limestone, or lime are used as scrubbing agents. Our screening evaluation assumes that lime is 

the scrubbing agent.

Caustic scrubbing produces a liquid waste, and minimal equipment is needed. When lime or 

limestone is used as the reagent for SO2 removal, additional equipment is needed for preparing 

the lime/limestone slurry and collecting and concentrating the resultant sludge. Calcium sulfite 

sludge is watery and is typically stabilized with fly ash for land filling. Calcium sulfate sludge is 

stable and easy to dewater. To produce calcium sulfate, an air injection blower is needed to 

supply the oxygen for the second reaction to occur. The normal SO2 control efficiency range for 

SO2 scrubbers is 80-90% for low efficiency scrubbers and 90-99.9% for high efficiency

scrubbers.

While wet scrubbers have been used successfully in the utility industry, they require more care 

when used for a Portland cement facility. Calcium sulfate scaling and cementitious buildup 

when a wet scrubber is used for acid gas control (applied to the exhaust gas from a cement kiln) 
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 6: Source Category Analysis: Kilns Page 6-7

can be avoided if these systems are installed downstream of a high efficiency particulate control 

device (e.g., fabric filter). Failure of the particulate control device can pose difficult problems 

for a downstream wet scrubber.

Advanced Flue Gas Desulfurization (FGD)

The AFGD process accomplishes SO2 removal in a single absorber which performs three 

functions: prequenching the flue gas, absorbing SO2, and oxidizing the resulting calcium sulfite 

to wallboard-grade gypsum. Figure 6.2 shows the process flow for an AFGD system.

Incoming flue gas is cooled and humidified with process wet suppression before passing to the 

absorber. In the absorber, two tiers of fountain-like sprays distribute reagent slurry over polymer 

grid packing that provides a large surface area for gas/liquid contact. The gas then enters a large 

gas/liquid disengagement zone above the slurry reservoir in the bottom of the absorber and exits 

through a horizontal mist eliminator.

Figure 6.2 Advanced Flue Gas Desulfurization Process Flow

As the flue gas contacts the slurry, the sulfur dioxide is absorbed, neutralized, and partially 

oxidized to calcium sulfite and calcium sulfate. The overall reactions are shown in the following 

equations:

CaCO3 + SO2  CaSO3 • 1/2 H2O + CO2
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 6: Source Category Analysis: Kilns Page 6-8

CaSO3 •1/2 H2O + 3H2O + O2  2 CaSO4 • 2 H2O

After contacting the flue gas, slurry falls into the slurry reservoir where any unreacted acids are 

neutralized by limestone injected in dry powder form into the reservoir. The primary reaction 

product, calcium sulfite, is oxidized to gypsum by the air rotary spargers, which both mix the 

slurry in the reservoir and inject air into it. Fixed air spargers assist in completing the oxidation. 

Slurry from the reservoir is circulated to the absorber grid.

A slurry stream is drawn from the tank, dewatered, and washed to remove chlorides and produce 

wallboard quality gypsum. The resultant gypsum cake contains less than 10% water and 20 ppm 

chlorides. The clarified liquid is returned to the reservoir, with a slipstream being withdrawn and 

sent to the wastewater evaporation system for injection into the hot flue gas ahead of the 

electrostatic precipitator. Water evaporates and dissolved solids are collected along with the 

flyash for disposal or sale.

The production of gypsum may actually be beneficial for Portland cement as gypsum is added to

Portland cement in the final grinding process to regulate the setting time of the concrete. 

However, to date there are no known installations of AFGD at Portland cement facilities.

Inherent Removal

Removal of SO2 in the cement manufacturing process is inherent to that process. The raw 

materials used in the process, primarily limestone, are preheated in the cement-making process 

either in the preheater tower or in the rotary kiln. In either case, the limestone comes in contact 

with hot combustion exhaust gases generating a free lime, which then reacts with SO2 in the gas 

stream, providing in-process removal of sulfur in the kiln system. Removal efficiencies in rotary

kiln systems range between 38% and 99% of sulfur input, and 50% to 70% of the remaining SO2

is removed from exhaust gases when passing through an in-line raw mill system (Miller et al., 

2001). The overall effectiveness and costs associated with this method are highly variable and 

are related primarily to the type of kiln operation and the ability of the facility to change raw 

material feeds. These costs can be difficult to quantify.

Process Alterations

The following methods to remove and prevent formation of SO2 by modifying or controlling 

conditions in the system are available due to the nature of the Portland cement manufacturing 

process:

 Change in the oxygen concentration in the flame/exhaust gas area. The concentrations of 

oxygen and (more importantly) carbon monoxide strongly influence the stability of alkali 

and calcium sulfates in the burning zone. By ensuring that sufficient oxygen is present to 

stabilize these compounds, SO2 emissions can be controlled. Control of burning-zone O2 

and CO concentrations is a widely used industrial practice, and a control technique 

applicable to all rotary cement kilns. The downside of this technique is the more 

favorable conditions created for generation of NOX in the rotary kiln.
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 6: Source Category Analysis: Kilns Page 6-9

 Burning-zone flame shape can be modified to ensure that reducing conditions in the 

flame are minimized. Flame impingement in the hot zone has a major effect on SO2

emissions from the kiln, even if total oxygen is sufficient to fully combust all fuel. 

Avoiding flame impingement in the burning zone minimizes SO2 formation. Avoiding 

flame impingement on the clinker, a technique applicable to all rotary kilns producing 

cement clinker, requires proper solid fuel preparation and proper flame shaping and 

control.

 Changes in raw materials to alter the alkali/sulfur molar ratio can also be used to control 

SO2 emissions. SO2 concentrations in kiln exit gases vary with the molar ratio of alkali to 

sulfur. When there are sufficient alkalis in excess of sulfur, SO2 emissions are typically 

low, due to more sulfur being retained as alkali sulfates in the clinker. Cement plants 

may also change their raw materials to reduce SO2 emissions. Typically this is 

accomplished by substituting a raw material containing pyritic sulfur or organic sulfur 

with one containing lesser amounts of these compounds, leading to reduced SO2

emissions. Replacement of raw materials, however, is often constrained by economic 

considerations, while alkali input increase may also be limited by cement product quality

specifications on total alkali in cement.

 Alterations to system can influence SO2 emissions. It has been found that an improved 

distribution of kiln feed may equalize temperatures in bottom stage cyclones and reduce 

SO2 emission by as much as 20% (Miller, 2001).

As with inherent removal, the overall effectiveness and costs associated with this method are 

highly variable and are related primarily to the type of kiln operation and the ability of the 

facility to change raw material feeds. These costs can be difficult to quantify.

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR KILNS

Cost of Compliance

To compare the various control options, information has been compiled on the cost-effectiveness 

of retrofitting controls. In general, cost-effectiveness increases with the amount of cement 

produced by the facility.

In a study performed for LADCO for a BART analysis, MACTEC developed control costs for

SO2 for a “model” cement plant for SO2. For the wet scrubber, the control cost estimates were 

prepared using lime as the base in the scrubbing liquor. Caustic (NaOH) and limestone are 

potential alternatives for a scrubber and could change the costs slightly. While lime and 

limestone require additional equipment for slurry preparation and for solids separation from the 

sludge generated in the scrubber, lime scrubbers are the most commonly used since lime is 

plentiful and relatively cheap. Materials of construction must also be made suitable for caustic, 

lime, or limestone if existing equipment is modified for wet scrubbing of SO2. 

AFGD systems require additional capital costs for the spargers and blowers necessary to oxidize 

the waste product to gypsum and for equipment to dewater the product (e.g., centrifuge). 

However if the commercial grade gypsum can be sold or used by the cement facility, some of 

these costs can be offset.
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 6: Source Category Analysis: Kilns Page 6-10

Dry FGD costs were calculated based on the low and high control efficiencies typical for these 

systems. For dry scrubbers, the flue gas must be cooled to a temperature 10 to 20 degrees above 

adiabatic saturation. This is typically accomplished using a heat recovery boiler, an evaporative 

cooler or a heat exchanger. In addition, if the facility does not have one, a particulate removal 

device is required for removal of the dry materials used to absorb SO2.

For all scrubbers, costs for an additional or upgraded induced air draft fan to make up for 

pressure drops within the system may be required. In addition, for wet systems, flue gas 

reheating may be required, thus a reheater may be necessary.

Tables 6.2 – 6.4 present estimated SO2 control costs for AFGD, Wet FGD, and Dry FGD applied 

to dry kilns and preheater kilns. The range of costs for these systems vary depending on the size 

of the kiln and control efficiency, so costs are presented for three size ranges of kilns. Although 

the capital and annual operating costs of these three types of control vary widely depending on 

kiln size and control efficiency, the ultimate cost in terms of $/ton of SO2 reduction are estimated 

to be from $2,000 - $7,000 for dry kilns and $9,000 to $73,000 for preheater kilns.

Table 6.2 SO2 Control Costs for AFGD Applied to Dry Kilns and Preheater Kilns

(2006 dollars)

Dry Kiln Preheater Kiln

Unit Relative 

Size

Capital Costs 

(106$)

Annual 

Operating 

Costs (106 $)

SO2 Cost 

Effectiveness 

($/ton SO2

reduction)

Capital Costs 

(106$)

Annual 

Operating 

Costs (106 $)

SO2 Cost 

Effectiveness 

($/ton SO2

reduction)

Small $7.03 – $22.9 $3 - $6

$2,000 - $4,000

$4.5 - $14.5

$1.2 – $11.8 $13,600-

$38,000 Medium $14.1 - $45.9 $6.1 - $11.9 $8.9 - $29.0

Large $28.1 - $91.6 $12.1 – $23.7 $17.8 - $58.0

Table 6.3 SO2 Control Costs for Wet FGD Applied to Dry Kilns and Preheater Kilns 

(2006 dollars)

Dry Kiln Preheater Kiln

Unit Relative 

Size

Capital Costs 

(106$)

Annual 

Operating 

Costs (106 $)

SO2 Cost 

Effectiveness 

($/ton SO2

reduction)

Capital Costs 

(106$)

Annual 

Operating 

Costs (106 $)

SO2 Cost 

Effectiveness 

($/ton SO2

reduction)

Small $2.43 – $36.5 $3 - $9

$2,000 - $6,200

$1.5 - $23.1

$0.9 – $18.9 $9,700-

$64,600 Medium $4.9 - $73.0 $6.0 - $18.4 $3.1 - $46.3

Large $9.5 - $142.5 $11.9 – $36.8 $6.2 - $92.5
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 6: Source Category Analysis: Kilns Page 6-11

Table 6.4 SO2 Control Costs for Dry FGD Applied to Dry Kilns and Preheater Kilns 

(2006 dollars)

Dry Kiln Preheater Kiln

Unit Relative 

Size

Capital Costs 

(106$)

Annual 

Operating 

Costs (106 $)

SO2 Cost 

Effectiveness 

($/ton SO2

reduction)

Capital Costs 

(106$)

Annual 

Operating 

Costs (106 $)

SO2 Cost 

Effectiveness 

($/ton SO2

reduction)

Small $1.45 – $37.0 $3 - $9

$1,900 - $7,000

$0.9 - $26.3

$0.9 – $21.0 $10,000-

$72,800 Medium $2.9 - $84.9 $5.5 - $20.0 $1.8 - $52.6

Large $5.6 - $165.5 $10.7 – $38.9 $3.6 - $105.2

The LADCO region had no wet kilns so cost estimates were not available for those type kilns. 

For the purposes of this study, wet kiln cost effectiveness is assumed to be similar to that for 

long dry kilns.

Additional details concerning the calculation of cost effectiveness of controls for kilns is located 

in a document developed by MACTEC for LADCO titled: Cement Best Available Retrofit 

Technology (BART) Engineering Analysis. This document can be downloaded from the web at 

the following location: 

http://www.ladco.org/reports/rpo/Regional%20Air%20Quality/BART/Cement_BART_Engineeri

ng%20Analysis%20%2B%20Appendix%20A1.pdf.

Time Necessary for Compliance

Generally, sources are given a 2-4 year phase-in period to comply with new rules. Under the 

NOX SIP Call for Phase I sources, EPA provided a compliance date of about 31⁄2 years from the 

SIP submittal date. Most MACT standards allow a 3-year compliance period. Under Phase II of 

the NOX SIP Call, EPA provided a 2-year period after the SIP submittal date for compliance. 

States generally provided a 2-year period for compliance with RACT rules. For BART control 

measures, the proposed BART guidelines require States to establish enforceable limits and 

require compliance with the BART emission limitations no later than 5 years after EPA approves 

the regional haze SIP.

For the purposes of this review, we have assumed that a 2-year period after SIP submittal is 

adequate for pre-combustion controls (fuel switching or cleaning) and a three year period for the 

installation of post combustion controls.

Energy and Non-Air Impacts

Fuel switching and cleaning and process changes do not significantly impact efficiency of the 

cement operation, but may add to transportation issues and secondary environmental impacts 

from waste disposal and material handling operations (e.g. fugitive dust). FGD systems typically 

operate with high pressure drops across the control equipment, resulting in a significant amount 

of electricity required to operate blowers and circulation pumps. In addition, some combinations 
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 6: Source Category Analysis: Kilns Page 6-12

of FGD technology and plant configuration may require flue gas reheating to prevent physical 

damage to equipment, resulting in higher fuel usage.

Environmental Impacts

The primary environmental impact of AFGD is the generation of byproduct gypsum. While 

gypsum is generated as a byproduct, the intent of the AFGD system is to produce gypsum that is 

commercial grade that can be sold. In the case of cement kilns, production of gypsum would 

result in some cost offsets since gypsum is a component of Portland cement. Thus the gypsum 

produced could be used to offset gypsum purchases.

The primary environmental impact of wet scrubbers is the generation of wastewater and sludge. 

Waste from wet scrubbers will increase the sulfate and solids loading in the facility’s 

wastewater. This places additional burdens on a facility’s wastewater treatment and solid waste 

management capabilities. These impacts will need to be analyzed on a site-specific basis. If 

lime or limestone scrubbing is used to produce calcium sulfite sludge, the sludge is water-laden, 

and it must be stabilized for land filling. If lime or limestone scrubbing is used to produce 

calcium sulfate sludge, it is stable and easy to dewater. However, control costs will be higher 

because additional equipment is required. Scrubber exhaust gases are saturated with water, thus 

creating a visible plume. Plume visibility may be a local/community concern. Once the exhaust 

mixes with sufficient air, the moisture droplets evaporate, and the plume is no longer visible.

Disposal of removed material from dry FGD systems is also required and will result in landfill 

impacts.

Energy Impacts

A scrubber operates with a high pressure drop, resulting in a significant amount of electricity 

required to operate the blower and pump. In addition for some technologies, a flue gas reheater 

may be required resulting in slightly increased fuel usage.

Remaining Useful Life of the Source

MACTEC could find little information on the typical lifetime of a cement plant. In a Security 

and Exchange filing (http://www.secbd.org/prosmcldopr.html) for a facility in India, typical 

lifetimes of various components of the plant range between 20-50 years. In an evaluation of 

waste management of cement kiln dust (CKD), remaining useful lifetimes of waste management 

units were around 20 years (http://www.epa.gov/epaoswer/other/ckd/rtc/chap-4.pdf). Thus we 

found nothing to suggest that the amortization of capital costs or calculation of annual operating 

costs would be affected by the remaining useful life.

For the purposes of this analysis, we assumed that the remaining useful life of each emission unit

was a minimum of at least 10 years and that it was likely that some units would continue to 

operate for at least 20-30 more years with proper maintenance and upkeep.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 6: Source Category Analysis: Kilns Page 6-13

REFERENCES

Assessment of Control Technology Options for BART-Eligible Sources, NESCAUM, March 

2005.

EPA. January, 1995. AP42 Section 11.6 – “Portland Cement Manufacturing”.

Hansen, Eric R. Staged Combustion for NOX Reduction Using High Pressure Air Injection,

IEEE-IAS/PCA 43rd Cement Industry Technical Conference; Jacksonville, FL: May 2002.

Miller, F.M. et. al. Formation and Techniques of Control of Sulfur Dioxide and Other Sulfur 

Compounds in Portland Cement Kiln Systems. Portland Cement Association R&D Serial No. 

2460, 2001.

Tanna, B. and B. Schipholt. Waste-Derived Fuel Use in Cement Kilns ERAtech Group, LLC 

http://www.eratech.com/papers/wdf.htm, accessed September, 2004.
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Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 7: Analysis of Selected Kilns Page 7-1

CHAPTER 7

ANALYSIS OF SELECTED KILNS

SOURCE CATEGORY DESCRIPTION

Emission control regulations for cement kilns have historically focused on particulate emissions. 

Over the past several years, regulations for the control of NOX and hazardous air pollutant (HAP) 

emissions have also been adopted. SO2 emission controls are largely non-existent. Some States 

have mandated emission limits as part of the Title V requirements but no national regulatory

program for SO2 controls for cement kilns exists. The only exceptions to this is for sources 

subject to New Source Review under Title I of the Clean Air Act and for sources subject to the 

Best Available Retrofit Technology (BART) requirements of the regional haze regulations.

Title I subjects new and modified large stationary sources that increase their emissions to 

permitting requirements that impose control technologies of varying levels of stringency (known 

as New Source Review, or NSR). NSR prescribes control technologies for new plants and for 

plant modifications that result in a significant increase in emissions, subjecting them to Best 

Available Control Technology (BACT) in attainment areas and to the Lowest Achievable 

Emission Rate (LAER) in nonattainment areas. The control strategies that constitute BACT and 

LAER evolve over time and are reviewed on a case-by-case basis in State permitting 

proceedings.

INFORMATION OBTAINED FROM STATE AGENCIES

MACTEC contacted State agencies to obtain information on kilns from those facilities in the list 

of the top 20 individual non-EGU sources. We requested permit information, information about 

SO2 controls recently implemented or planned at the facility and any available information on 

BART, consent decrees, or other regulations that will impact control devices at the facilities. 

The information we obtained is included in Table 7.1.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 7: Analysis of Selected Kilns Page 7-2

Table 7.1 Point Source Information Collected from the Top 3 Kilns Responsible for

Visibility Impairment in MANE-VU Class I Areas

Facility Name State

2002

SO2

Total

(tons)

Primary Emissions Point 

Description

Point ID

(Permit

ID No.)

Design

Capacity

Existing

Control(s)

Proposed/

Planned

Control(s)

Additional 

Information

LaFarge 

Building 

Materials Inc.1

NY 14,800 Two rotary, wet process 

kilns (Kiln 1 & 2) and two 

clinker coolers (Clinker 

Cooler 1 & 2). There are 

buildings at either end of the 

kilns; the discharge end 

building where the clinker 

coolers are located, and the 

feed end building.

041000 Unknown Fabric filter 

dust collector 

on clinker 

coolers (PM)

ESP (PM)

None

St. Lawrence 

Cement Corp. 

– Catskill 

Quarry2, 3

NY 3,562 Cement kiln permitted to 

burn coal, oil, tires, waste 

oil, natural gas, nonhazardous fuels, and coke. 

This is a wet kiln built in 

1964.

U00K18 Unknown ESP Low-sulfur 

fuel

Consent Decree dated 

1/9/91 limits burning 

solid fuel with a max 

sulfur content of 3.8 

lbs/MMBTU/hr. 

BART analysis has not 

been completed.

Lafarge 

Midwest, Inc., 

Alpena Plant4

MI 16,576 Five rotary dry kilns, clinker 

coolers and associated 

materials handling 

operations. Kilns fire with 

coal, coke or waste derived 

fuel

EU-Kiln19

EU-Kiln20

EU-Kiln21

EU-Kiln22

EU-Kiln23

Unknown Baghouses on 

kiln dust return 

systems

Unknown as of 

date of report -

these units are 

subject to 

BART

SO2 Emission limits 

on all five kilns:

EUKiln19 = 2,088 tons

EUKiln20 = 2,065 tons

EUKiln21 = 2,056 tons

EUKiln22 = 9,685 tons

EUKiln23 = 9,728 tons

1 New York State Department of Environmental Conservation, Division of Air Resources. Personal communication regarding LaFarge Building Materials Incorporated facility 

between Mr. Rick Leone (518-402-8403) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on February 2, 2007.

2 New York State Department of Environmental Conservation, Division of Air Resources. Personal communication regarding St. Lawrence Cement Corporation – Catskill Quarry 

facility between Mr. Rick Leone (518-402-8403) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on February 9, 2007.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 7: Analysis of Selected Kilns Page 7-3

3 New York State Department of Environmental Conservation, Division of Air Resources. Personal communication regarding St. Lawrence Cement Corporation – Catskill Quarry 

facility from Mr. Rick Leone (518-402-8403) via E-mail on February 9, 2007.

4 Michigan Department of Environmental Quality, Air Quality Division. Personal communication regarding LaFarge Midwest, Incorporated Alpena Plant from Ms. Teresa Walker 

(517-335-2247, walkertr@michigan.gov) via E-mail on February 7, 2007.
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Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 8: Heating Oil Page 8-1

CHAPTER 8

HEATING OIL

BACKGROUND

Number 2 distillate fuel oil, heating oil, and diesel fuel oil are essentially the same refineryproduced liquid. In the Northeast United States, home heating accounts for 54% of distillate fuel 

oil demand. In comparison, highway diesel accounts for 38% (NESCAUM, 2005). Annually,

home heating oil use generates an estimated 100,000 tons of sulfur dioxide (SO2) emissions in 

the Northeast (NESCAUM, 2005). Climate and seasonality play important roles in the use of 

heating oil, and therefore the emissions from combustion of heating oil. While it is important to 

consider the emissions from heating oil in the Northeast United States, emissions from heating 

oil combustion in other areas of the United States such as the VISTAS States are not significant 

in comparison to other emission sources.

SO2 emissions are proportional to fuel oil sulfur content. It is not feasible to control SO2

emissions from homes using control devices; therefore, the most efficient method for controlling 

SO2 emissions from home heating is by lowering the amount of sulfur in the fuel. Currently, the 

sulfur limits in heating oil vary between 2,000 to 20,000 ppm. Table 8.1 provides information on 

the range of sulfur in heating oils throughout the Northeast.

Table 8.1 State Sulfur Limits for Heating Oil

State Sulfur Limit in Percent Sulfur Limit in parts per 

million (ppm)

Connecticut 0.3 3,000

Maine 0.3 to 0.5 3,000 to 5,000

Massachusetts 0.3 3,000

New Hampshire 0.4 4,000

New Jersey 0.2 to 0.3 2,000 to 3,000

New York Upstate 1.0 to 1.5 10,000 to 15,000

New York Downstate 0.2 to 0.37 2,000 to 3,700

Rhode Island 0.5 5,000

Vermont 2.0 20,000

Source: NESCAUM, 2005

Beginning in 2006, the permissible level of sulfur in highway diesel fuel (ultra low sulfur diesel, 

or ULSD) was 15 ppm. Prior to that, highway low sulfur diesel fuel was refined to contain 500 

ppm sulfur (Low Sulfur Diesel, or LSD). Consequently, refineries have already performed the 

capital investments required for the production of LSD and ULSD fuel oil. The Northeast States 

are considering adopting consistent low sulfur heating oil requirements, and a memorandum 

titled DRAFT Memorandum of Understanding for Regional Fuel Sulfur Content Standards for 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 8: Heating Oil Page 8-2

Distillate Number 2 Heating Oil, the Northeast States proposed to reduce the sulfur content to 

500 ppm. A reduction of sulfur in heating oils from the current levels to 500 ppm would reduce 

SO2 emissions by approximately 75% per year on a nationwide basis (Batey and McDonald, 

2005). There has also been some discussion regarding the reduction of heating oil sulfur content 

to 15 ppm.

This memorandum presents the four factor analysis that was applied to the heating oil sulfur 

reduction proposal. The four factors are: cost of compliance, time necessary for compliance, 

energy and non-air impacts, and remaining useful life of the sources. This document primarily 

focuses on reducing the sulfur content of heating oil to 500 ppm. Information on reducing the 

sulfur content of heating oil to 15 ppm is presented wherever data were available.

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR 

EMISSIONS FROM HEATING OIL COMBUSTION

Cost of Compliance

Refinery Retrofit Costs

Refineries were required to make significant capital investments to meet the LSD and ULSD 

highway fuel sulfur requirement. To achieve the LSD and ULSD sulfur goals, refineries were 

required to implement diesel desulfurization technologies. Estimates for the capital costs were 

developed in 2001 by the Energy Information Administration (EIA) and are based on calendar 

year 1999. Table 8.2 presents the capital costs for desulfurization technologies developed by the 

EIA, which were converted from a calendar year 1999 dollar basis to 2006 dollars. The EIA 

developed estimates for new and revamped desulfurization technologies at existing refineries.

Table 8.2 Ultra Low Sulfur Diesel (ULSD) Desulfurization Technology Costs for 

Individual Refineriesa,b

Desulfurization 

Unit Type

Throughput 

(Barrels per Day)

Capital Costs 

(2006 Dollars per 

Daily Barrel 

Produced)

Total Capital 

Cost per Unit 

(Million 2006

Dollars)

New 50,000 1,204 60.3

New 10,000 2,187 21.9

Revamp 50,000 716 35.8

Revamp 10,000 1,464 14.6

aBased on cost estimates for hydrotreaters to produce ULSD.

b

Source for this information is the Energy Information Administration

Note – A conversion factor of 1.2101 was used to convert the dollar values from 1999 to 2006 

www.inflationdata.com

In its highway diesel fuel rulemaking, EPA also developed cost estimates for the deployment and 

implementation of desulfurization technologies at refineries. EPA estimated that it would cost 

existing refineries an estimated $56 million (2006 dollars) per refinery to install desulfurization 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 8: Heating Oil Page 8-3

technologies, and that this effort would be spread out over a 2-year time period. EPA based its 

conclusions on the assumption that refineries would revamp their hydrotreating technologies. It

further estimated that 80% of the hydrotreaters at the refineries would be revamped. The EPA 

also estimated that the cost of a new hydrotreater would be $91 million (2006 dollars), and that 

roughly 25 refineries nationwide would have to make this investment. No estimates were made 

for the costs associated with new refineries as none are currently being constructed in the United 

States. The EPA analysis spread the investment cost over a 2-year period. Consequently, it was 

estimated that the US refinery-wide investment for calendar year 2004 was $2.45 billion and 

$2.83 billion for calendar year 2005 (EIA 2001) (Converted from 2001 to 2006 dollars using a 

conversion factor of 1.1383. www.inflationdata.com).

In the August 9, 2006 edition of This Week in Petroleum, EIA reported that total ULSD 

production progress has been good and that ULSD is currently being produced in all Petroleum 

Administration for Defense Districts (PADDs). Stocks of ULSD in the United States in January

2007 were approximately equal to distillate oil containing greater than 500 ppm sulfur. However 

on the East Coast, stocks of ULSD were approximately one-third the size of distillate oil stocks 

containing more than 500 ppm sulfur (EIA). Another independent source, The Marathon 

Petroleum Company, LLC, found that 90% of refineries in the continental United States that 

were included in a survey had designed units capable of producing ULSD. Also, Marathon 

determined that the planned US capacity for ULSD would be in excess of 2.5 million barrels per 

day in 2006 (Marathon Petroleum Corporation 2007).

Heating Oil Cost Increases

It is assumed that the costs for retrofitting refineries will be passed on to consumers. In its 

December 2005 study, NESCAUM estimated that the average price increment for the lower 

sulfur product (500 ppm) would be $0.16 per gallon. In December 2005, this represented a 1%

increase of the average oil price.

To update these costs we compared the costs of low-sulfur diesel fuel (15 – 500 ppm) with 

regular diesel fuel (2,000 ppm) for 2006. These data were gathered from DOE EIA Web site on 

March 8, 2007. We used the difference in diesel fuel prices because the cost for low sulfur 

heating oil is currently not reported and because diesel fuel and number 2 distillate are 

essentially the same product. It is therefore reasonable to assume that the cost differential 

between low sulfur and regular diesel fuel should reflect the potential cost differential between 

low sulfur and regular heating oil. All cost comparisons are before taxes. EIA only reports a 

low-sulfur diesel fuel category which includes both low sulfur (500 ppm) and ultra low sulfur 

diesel (15 ppm). For the first two months on 2007, EIA reports that stocks of 15 ppm sulfur oil 

were roughly twice that of 500 ppm sulfur oil. We averaged monthly costs to compute annual 

average costs for PADD 1A (CT, ME, MA, NH, RI, VT) and PADD 1B (DE, DC, MD, NJ, NY, 

PA) for low sulfur and regular diesel fuel from January to December 2006. For PADD 1A, the 

cost of low sulfur diesel fuel ranged from $1.954 to $2.433 per gallon and the cost of regular 

diesel fuel ranged from $1.963 to $2.429 per gallon. The monthly difference between low sulfur 

and regular diesel fuel ranged from -1.1 cents per gallon to 0.5 cents per gallon with an annual 

average of -0.8 cents per gallon. That is, low-sulfur diesel fuel was on average less expensive 

that regular diesel fuel in PADD 1A in 2006. Similarly in PADD 1B, the cost of low sulfur 

diesel fuel ranged from $1.894 to $2.358 per gallon and the cost of regular diesel fuel ranged 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 8: Heating Oil Page 8-4

from $1.894 to $2.321 per gallon. The monthly difference between low sulfur and regular diesel 

fuel ranged from -1.3 cents per gallon to 4.7 cents per gallon with an annual average of 1.6 cents 

per gallon. In both regions fuel costs were highest in the summer and the difference in cost 

between low sulfur and regular diesel fuel was also highest in summer. To calculate an average 

cost differential, we weighed the PADD 1A and PADD 1B cost differentials by residential fuel 

use in each PADD for 2005 (the latest date data are available from EIA). In 2005, PADD 1A 

States used 1.9 million gallons and PADD 1B States used 2.5 million gallons. Therefore, on 

average low sulfur distillate oil would be expected cost 0.8 cents per gallon more than regular 

heating oil in MANE-VU States. This average price differential translates in to $734/ton of 

sulfur removed if it assumed that the low sulfur diesel has a concentration of 500 ppm sulfur or 

$554/ton of sulfur removed for ultra low 15 ppm sulfur diesel.

STAPPA-ALAPCO (2006) estimates that the annual fuel oil consumption per household is 865 

gallons per year. Using the price differential data presented above, the average household would 

spend about $7 per year additional on home heating costs by using low or ultra low sulfur fuel.

The use of LSD/ULSD will also result in cost savings to owners/operators of residential furnaces 

and boilers due to reduced maintenance costs. When the existing heating oil sulfur content is 

2,000 ppm and 500 ppm sulfur is substituted, the service interval can be extended by a factor of 

three or more (e.g., cleaning at three year intervals rather than annually). Vacuums are used to 

remove deposition caused by SO2 from furnaces and boilers.

The potential vacuum cleaning costs savings for the United States, for a starting fuel sulfur 

content of 2,000 ppm ranges from approximately $200 million a year to $390 million a year for 

service costs of $50 to $100 per hour. Therefore, if all oil heated homes switched to 500 ppm 

sulfur heating oil, more than $200 million a year could be saved, which would significantly 

lower the overall operating costs of fuel oil marketers. Given the dominant share of the U.S. 

heating oil market represented by the Northeast States, a large percentage of the projected 

national benefits would accrue in the region (NESCAUM 2005). In a brochure distributed by

EIA titled Residential Heating Oil Prices: What Consumers Should Know, EIA reports that 6.3 

million of the 8.1 million households using heating oil in the United States (78%) are in the 

Northeast Region. This region includes the New England and Central Atlantic States.

Heating Oil Supply

EPA addressed the issue of using ULSD for heating oil purposes in its regulatory impact analysis 

for Heavy-Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control 

Requirements (2000). EPA found that refiners in the Mid-Atlantic and Northeast (PADD 1) 

could produce more of this fuel and reduce the need for imports.

EIA reports that in 2004, 5,975,966,000 gallons of heating oil were sold in the United States. 

This decreased to 5,548,827,000 gallons in 2005. The EIA publishes weekly updates on the 

availability of heating oil. Information was retrieved for January 2007 and is summarized in 

Table 8.3 below.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 8: Heating Oil Page 8-5

Table 8.3 Average January 2007 Distillate Stocks 

(Million Barrels)a

Location 15 ppm and

Under Stocks

15 ppm --

500 ppm Stocks >500 ppm Stocks Total DistillateStocks

US (Total) 57.2 25.0 59.7 141.8

East Coast 14.7 21.9 44.5 66.5

Average Days of 

Supply of 

Distillate Fuel Oilb

34.4 34.4 34.4 34.4

a

Source for this information is the Energy Information Administration.

bThe sulfur content of distillate stocks is not distinguished by the EIA for this data point.

The EIA also makes available information regarding the production and imports of heating oil. 

This information is summarized in Table 8.4, and includes specific data for the East Coast.

The information presented in Table 8.4 indicates that on a nationwide basis, more ULSD is 

produced than both LSD and high sulfur fuel. This is due to the predominant use of ULSD in 

highway diesel vehicles. This information also supports the conclusion that the United States 

has the infrastructure to produce adequate stocks of LSD and ULSD.

Table 8.4 Distillate Production and Imports

(Million Barrels per Day)a,b

Location 15 ppm and

Under Production

15 ppm -

500 ppm

Production

>500 ppm

Production

Total Distillate

Production

US 2.659 0.624 0.970 4.253

East Coast 0.248 0.024 0.277 0.549

Imports 0.204 0.018 0.115 0.392

a

Source for this information is the Energy Information Administration.

bBased on the four week average ending January 12, 2007.

Currently, the 15 ppm fuel is sold for highway use diesel, whereas the >500 ppm stocks are sold 

for heating oil. The 15-500 ppm fuel can still be used until 2010 under the hardship provisions 

of the heavy duty highway diesel program (EPA 2004). Under these provisions of the heavy 

duty highway diesel program, if there is a shortage of 15 ppm fuel, the 15 -500 ppm fuel could 

be used to relieve the shortage. With this flexibility, the likelihood of a fuel shortage in the short 

term, due to usage of ULSD for heating oil is reduced.

Time Necessary for Compliance

Refiners in the United States are already producing low sulfur highway diesel fuel. This same 

fuel can be marketed as heating oil since it is the same refinery product as highway diesel except 

with dye added to the fuel to differentiate it for tax purposes. Some time may be required to 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 8: Heating Oil Page 8-6

allow petroleum marketers to adjust to distributing ULSD to heating oil customers, however, the 

distribution network for motor fuels and heating oil are already in place.

NESCAUM (2005) estimated that during peak periods of demand, up to 20% of the required 

heating oil is imported. This analysis does not address whether offshore refineries should be able 

to produce 15 ppm sulfur for export to the Northeast United States. In case of a shortage of 15 

ppm fuel during the transition period from LSD to ULSD, the heavy duty highway diesel 

program allows the use of 15-500 ppm sulfur fuel.

Existing residential furnaces and boilers do not need to be retrofitted or modified to combust 15 

ppm sulfur. The capacity for producing LSD and ULSD already exists among US refiners. 

Consequently, the time necessary for compliance does not hinge on the heating oil 

furnace/boiler.

Energy and Non-Air Impacts

Reducing the sulfur contents of heating oil has a variety of beneficial consequences for 

residential furnaces and boilers. Low sulfur distillate fuel is cleaner burning and emits less 

particulate matter which reduces the rate of fouling of heating units substantially and permits 

longer time intervals between cleanings. According to a study conducted by the New York State 

Energy Research and Development Authority, (NYSERDA), boiler deposits are reduced by a 

factor of two by lowering the fuel sulfur content from 1,400 ppm to 500 ppm. These reductions 

in buildup of deposits result in longer service intervals between cleanings. (Batey and McDonald

2005). Batey and McDonald (2005) estimated that the potential cost savings from decreased 

vacuum cleanings ranges from $200 million per year to $390 million per year. The decreased 

deposits would also enable a more efficient transfer of heat, thereby reducing the fuel usage. 

Further reducing the heating oil sulfur from 500 to 15 ppm would increase the cost savings from 

decreased maintenance needs due to heat exchanger fouling.

The decreased sulfur levels would enable manufacturers to develop more efficient furnaces and 

boilers by using more advanced condensing furnaces and boilers. These boilers recoup energy

that is normally lost to the heating of water vapor in the exhaust gases. Historically, the use of 

high sulfur fuels prevented this due to the corrosion of the furnace/boiler due to the creation of 

sulfuric acid in the exhaust gases. The increased efficiency results in a decrease in the amount of 

heating oil a heating unit uses, therefore, this would make a switch to lower sulfur heating oils 

more attractive and cost effective.

Remaining Useful Life of the Source

Residential furnaces and boilers have finite life times, but they do not need to be replaced to burn 

low or ultra low sulfur fuel. The Energy Research Center estimates that the average life 

expectancy of a residential heating oil furnace is approximately 18 years, and that the average 

life expectancy of a residential heating oil boiler is 20-25 years (Personal communication with 

Mr. John Batey, Energy Research Center on February 6, 2007).

Finally, the number of homes that are being heated with heating oil is declining by

approximately 100,000/year (RedOrbit 2007). No geographical distribution was available for 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 8: Heating Oil Page 8-7

this estimate, but since heating oil is predominantly used in the Northeast, most of the changes 

will be occurring there. Consequently, emissions from heating oil combustion will become less 

significant of a source of SO2 emissions in the future.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 8: Heating Oil Page 8-8

REFERENCES

Batey, J.E. and R. McDonald, 2005. Low Sulfur Home Heating Oil Demonstration Project 

Summary Report. Project funded by The New York Sate Energy Research and Development 

Authority. Contract No. 6204-IABR-BR-00.

Energy Research Center. Personal communication on February 6, 2007 with Mr. John Batey and 

Mr. Bernd Haneke of MACTEC Federal Programs, Inc.

EPA, 2004. Overview of EPA’s Low Sulfur Diesel Fuel Programs. Presented at the Ultra-Low 

Sulfur Diesel Fuel Implementation Workshop by the EPA’s Office of Transportation and Air 

Quality, New Orleans, Louisiana, November 15, 2004.

Marathon Petroleum Company, LLC. Ultra Low Sulfur Diesel. PowerPoint Presentation 

downloaded from the World Wide Web on January 31, 2007 from: 

http://www.marathonpetroleum.com/

NESCAUM, 2005. Low Sulfur Heating Oil in the Northeast States: An Overview of Benefits, 

Costs and Implementation Issues.

RedOrbit, 2007. Refiners Have Many Options to Convert High-Aromatic Streams into ULSD. 

Article downloaded from the World Wide Web on January 31, 2007 at: http://www.redorbit.com

STAPPA ALAPCO, 2006. Controlling Fine Particulate Matter Under the Clean Air Act: A 

Menu of Options.

US Energy Information Administration, August 9, 2006. This Week in Petroleum.

US Energy Information Administration, 2001. Brochure titled Residential Heating Oil Prices: 

What Consumers Should Know.

US Energy Information Administration, 2001. The Transition to Ultra-Low –Sulfur Diesel Fuel: 

Effects on Prices and Supply. Publication downloaded from the World Wide Web on January

31, 2007 at: www.eia.doe.gov/oiaf/servicerpt/ulsd

US Energy Information Administration, 2007. Information downloaded from the World Wide 

Web on March 8, 2007.at: http://tonto.eia.doe.gov/dnav/pet/pet_pri_dist_dcu_R1X_m.htm

US EPA, 2000. Regulatory Impact Analysis: Heavy Duty Engine and Vehicle Standards and 

Highway Diesel Fuel Sulfur Control Requirements. EPA Publication Number EPA420-R-00-

026.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-1

CHAPTER 9

RESIDENTIAL WOOD COMBUSTION

BACKGROUND

The MANE-VU Contribution Assessment and other MANE-VU reports have documented that 

visibility impairment in this region is primarily due to regional secondary sulfate. However, in 

the MANE-VU Class I areas, biomass combustion also has been identified as a contributor to 

visibility impairment. Biomass combustion emissions due to human activity primarily derive 

from residential wood combustion. While some biomass burning occurs throughout the year, 

residential wood combustion occurs predominantly in the winter months, potentially contributing 

to wintertime peaks in PM concentrations.

In the document, Control Analysis and Documentation for Residential Wood Combustion in the 

MANE-VU Region, OMNI Environmental Services, Inc. (OMNI) conducted a control analysis 

and documentation of residential wood combustion (RWC) in the 11 States and the District of 

Columbia that make up the MANE-VU region. Information for the OMNI analysis was obtained 

from: (1) The MANE-VU Residential Wood Combustion Emission Inventory published by

MARAMA (July 2004 report), (2) Residential Energy Consumption Surveys published by the 

EIA, (3) the National Emission Inventory published by the EPA, (4) Simmons Marketing 

Research reports, and (5) American Housing Surveys for the United States published by the U.S. 

Department of Commerce and the U.S. Department of Housing and Urban Development. In 

addition, the results of three RWC surveys at the State-level have been published in the last 

decade for the Mid-Atlantic and New England area, which allow for comparison of data 

extrapolated from the national- and regional-scale surveys to the State level for three States. 

These were the: (1) 1995 Delaware Fuelwood Survey, (2) Residential Fuelwood Use in Maine, 

Results of 1998/1999 Fuelwood Survey, and (3) Vermont Residential Fuel Wood Assessment for 

1997-1998.

To facilitate understanding of the cost effectiveness analyses done by OMNI, descriptions of the 

various appliances used, as well as a brief discussion of efficiency, are provided from the OMNI 

report.

Cordwood-Fired Stoves and Fireplace Inserts

Uncertified, certified catalytic, and certified non-catalytic cordwood stoves and fireplace inserts 

together are considered cordwood heaters. They are designed to burn bulk cordwood and are 

room space heaters, i.e., they primarily rely on radiant and convection heat transfer, in contrast to 

centralized heating systems such as warm-air furnaces or boilers which utilize heat distribution 

systems to heat multiple rooms. Fireplace inserts are essentially wood stoves that are designed to 

be inserted into an existing fireplace cavity. Because of the heat transfer shielding effect of the 

fireplace cavity and the fact the majority of existing fireplace chimneys are against an outside 

wall, their heating efficiency is less than a similar freestanding woodstove. Many fireplace 

inserts have fans to facilitate transfer of heat from the portion that is inside the fireplace cavity. 

Both freestanding cordwood stoves and fireplace inserts rely on a natural draft using room air for 

combustion and the venting of exhaust through the chimney to the atmosphere. Though the 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-2

majority of cordwood heaters use room air for combustion, some insert installations, such as in 

mobile homes, require the use of outside air for combustion.

Uncertified Conventional Cordwood-Fired Stoves and Fireplace Inserts

Uncertified cordwood fired stoves and fireplace inserts include units manufactured before the 

40 CFR Part 60, Subpart AAA New Source Performance Standard (NSPS) July 1, 1990 

certification requirement, and currently or recently manufactured exempt units which operate 

similarly to some old pre-EPA certification units.

NSPS Certified Catalytic Cordwood-Fired Stoves and Fireplace Inserts

Certified catalytic units pass the exhaust through a catalyst to achieve emission reductions. 

Generally, a coated ceramic honeycomb catalyst is located inside the stove where the 

incompletely combusted gases and particles ignite and are combusted further, thus reducing 

air emissions and increasing combustion overall efficiency.

NSPS Certified Non-Catalytic Cordwood-Fired Stoves and Fireplace Inserts

Certified non-catalytic stoves and fireplace inserts rely on design features to reduce air 

emission and increase efficiency. They generally rely on the introduction of heated 

secondary air to improve combustion, as well as firebox insulation, and baffles to produce a 

longer, hotter gas flow path, as well as other design features to achieve low emissions and 

higher efficiency.

Pellet Stoves and Fireplace Inserts

Analogous to cordwood stoves and fireplace inserts, pellet stoves and fireplace inserts are 

considered room heaters. They burn pellets generally made from sawdust, although there has 

been, and continues to be, research into utilizing other biomass fuels to make pellets. 

Combustion air is drawn from the room for most models, and exhaust is vented outdoors. Some 

pellet appliances use outside air for combustion. Pellet stoves and inserts require the use of 

electric motors to power the combustion air and heat transfer fans and the pellet-feeding auger. 

Modern pellet units use electronic sensors and controls. Pellets are introduced into the hopper, 

and the auger continuously feeds a consistent amount of pellets into the firebox. The feed rate is 

controlled electronically by a feed rate setting selected by the user. There are two basic designs: 

bottom-feed and top-feed models. Pellet units have a high efficiency and low emissions due to 

the use of the electric auger and fan that produce uniform and controlled combustion conditions. 

Some units are certified by the NSPS process and some are not. The performance of the certified 

and uncertified models are similar. What is considered by most as a “loop-hole” in the NSPS 

regulations essentially allows certification to be bypassed.

Wood-burning Fireplaces without Inserts

Fireplaces without inserts include manufactured units (often referred to as “zero-clearance” 

fireplaces) and site-built masonry units operated both with and without glass doors. Combustion 

air is drawn from the natural draft created by fire, and that same draft vents the exhaust gases 

through the chimney. Fireplaces without inserts have low efficiencies due to the large amount of 

heated room air that is exhausted out of the chimney from the draft. Many fireplaces without 

inserts are not used in a given year, some are used for aesthetic purposes and some are used for 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-3

heating. Those that are used for heating are almost always used for secondary heating purposes 

and not primary heating due to their low efficiency and lack of heat transfer capabilities. 

Manufactured wax/fiber firelogs are often used as a fuel in them with about 30% of fireplace 

users nationwide claiming that they use wax/fiber firelogs some of the time. Most fireplaces are 

wall-mounted, however, this category also includes some free-standing models.

Direct Vent Gas Stoves and Fireplace Inserts (LPG and Natural Gas)

Direct vent gas stoves and inserts are sealed units that draw their combustion air from, and vent 

their exhaust to, the outside air. Venting can be extended vertically or horizontally out of the 

home. A common type of venting is coaxial, which has the exhaust pipe contained within the air 

inlet pipe, so the temperature of the combustion air is raised, and the temperature of the exhaust 

is lowered, creating more efficient combustion. It should be noted that natural gas is not readily 

available in all locations, however LPG may be available for use.

Vent-Free Gas Stoves and Fireplace Inserts (LPG and Natural Gas)

Vent-free gas stoves and inserts receive their combustion air from the room in which the unit is 

placed, and all of the products of combustion are exhausted into the room as well. The high 

efficiency of vent free units is due to the fact that the heat produced is kept in the room. Vent 

free gas stoves and inserts have a maximum heat input in order to avoid emitting excess CO, 

CO2, or NOX into the room, and the units also have an O2 depletion sensor or other device to shut 

the unit down if oxygen levels become too low. It is important to note that vent-free natural gas 

and LPG stoves, inserts and log sets should not be considered options for primary or even 

significant secondary heating use. There is considerable concern regarding indoor air quality and 

damage to homes by moisture created from their use, as combustion gases are not vented to the 

atmosphere. If the devices are used prudently, these problems are reduced. Their appropriate 

role is for aesthetics and minor secondary heating. Just as with direct vent gas stoves and 

fireplace inserts, LPG can be used as an alternative where natural gas is not readily available.

B-Vent Gas Stoves and Fireplace Inserts (LPG and Natural Gas)

B-vent gas stoves and inserts draw their combustion air from the room, and exhaust is vented 

outdoors. These units use a draft hood for the proper venting of exhaust. B-vent gas stoves and 

inserts have lower efficiency than direct vent due to the fact that already heated room air is used 

as combustion air, which is then exhausted to the outdoors, taking heat away from the room.

OMNI Study Summary

In the OMNI study, the amount of fuel consumed by RWC devices was considered the measure 

of activity. Activity data were provided by individual appliance type by State and for the total 

MANE-VU region. The activity study conducted by OMNI showed that there were 

approximately 6.4 million tons of fuel burned in 2002 by RWC devices in the MANE-VU 

region. The majority of RWC combustion was located in New York (1.9 million tons of fuel 

burned) and Pennsylvania (1.4 million tons of fuel burned).
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-4

OMNI then compiled an emissions inventory by county, by State, and for the entire MANE-VU 

region for the 2002 base year. The dry mass of fuel (activity) for cordwood, pellets, and 

manufactured wax/fiber firelogs compiled in the activity task was multiplied by the applicable 

emission factor in the units of mass air pollutant per mass of dry fuel. The emission factors were 

obtained by reviewing and averaging (if multiple sources were available) data obtained from 

available reports and publications. PM and VOC (an ozone precursor) are the main criteria 

pollutants of concern for RWC and non attainment areas. The OMNI emissions inventory

reported that there were 92,470 tons of total PM emissions and 87,741 tons of VOC generated 

from RWC devices in the MANE-VU region during the base year (2002). It should be noted that 

this analysis assumed that PM10 was equivalent to PM. The only emissions control efficiency, 

and control device information available is for PM10. We have therefore assumed that data for 

PM10 are applicable to PM2.5.

Table 9.1 from the OMNI report summarizes measures for RWC RACM developed by EPA in 

EPA-450/2-89-015. OMNI reported the RACM fall in three primary categories: (1) 

improvement of performance, (2) reducing the use of RWC devices, and (3) episodic 

curtailment. The effectiveness in reducing RWC emissions and a related discussion of each of 

the various activities are also provided in Table 9.1. In addition to the three primary categories 

for RWC RACM, the RACM document emphasizes the importance of public awareness in many 

RWC emission control programs and provides considerable information on the subject.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-5

Table 9.1 Summary of Measures Available for RWC RACM – PM10

Program Elements

Estimated 

Effectiveness

(%) Discussion

IMPROVEMENT OF PERFORMANCE

State implementation of NSPS 0 States are not expected to adopt this 

program element at levels that would affect 

program effectiveness significantly.

Ban on resale of uncertified 

devices

0 No credit recognized because requirement 

is largely unenforceable: other elements 

will be required to include disabling of 

retired used devices.

Installer Training Certification or 

Inspection Program

~ 5 Reduction in emissions from each new 

certified RWC device where either the 

installer is trained/certified or the 

installation is inspected.

Pellet stoves 90 Reduction in emissions from each new or 

existing conventional, uncertified RWC 

device replaced with a pellet stove.

75 Reduction in emissions from each new or 

existing Phase II EPA certified RWC 

device replaced with a pellet stove.

EPA Phase II certified RWC 

devices

~50 Reduction in emissions from each new or 

existing conventional, uncertified RWC 

device replaced with an EPA Phase II 

certified RWC device.

Retrofit requirement <5 Reduction in emissions from each existing 

conventional, uncertified RWC device 

equipped with a retrofit catalyst or pellet 

hopper (to maximum when all existing 

uncertified RWC devices have retrofit 

devices installed).

Accelerated changeover 

requirement

~50 Reduction in emissions from each existing 

conventional, uncertified RWC device 

replaced with Phase II certified device.

100 Reduction in emissions from each existing 

conventional, uncertified RWC device 

removed and not replaced: requires existing 

device to be disabled and not resold.

Accelerated changeover 

inducement

~50 Reduction in emissions from each existing 

conventional, uncertified RWC device 

replaced with Phase II certified device.

100 Reduction in emissions from each existing 

conventional, uncertified RWC device 

removed and not replaced: requires existing 

device to be disabled and not resold.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-6

Table 9.1 Summary of Measures Available for RWC RACM – PM10

Program Elements

Estimated 

Effectiveness

(%) Discussion

Require fireplace inserts 0 No credit recognized for fireplace inserts, 

since inserts change use of fireplace from 

aesthetic to primary heat source, resulting 

in an increase in amount of wood 

combusted and higher overall emissions.

Wood moisture <5 Reduction in total emissions from all RWC 

devices in the community/airshed.

Trash burning prohibition 0 No credit recognized for eliminating trash 

burning in RWC devices.

Weatherization of residences <5 Reduction in total emissions from all RWC 

devices in the community/airshed. 

Opacity limits <5 Reduction in total emissions from all RWC 

devices in the community/airshed.

REDUCING USE OF RWC DEVICES

Availability of alternative fuels 100 Reduction in emissions from each RWC 

device removed from service and replaced 

with device using natural gas: recognize no 

more than 10% of RWC devices replaced 

under program with no additional 

incentives.

Emission trading Computation 

required

For a 2:1 trading ratio, the reduction in 

emissions from each new stove would be 

calculated as the difference between 

emissions of a new RWC device and 2 

times the average emissions per stove in the 

community:

multiplier would change for other trading 

ratios.

Taxes on RWC devices Variable Emission reduction credit would vary with 

utility or tax rate structure adopted and 

extent to which this structure resulted in 

reduction in number of RWC devices in the 

community versus reduction in use of RWC 

devices.

Regulatory ban on RWC devices 

in new dwellings

100 Reduction in emissions from new RWC 

devices purchased for installation in new 

dwellings.

Regulatory ban on

existing RWC devices

100 Reduction in emissions from each RWC 

device removed.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-7

Table 9.1 Summary of Measures Available for RWC RACM – PM10

Program Elements

Estimated 

Effectiveness

(%) Discussion

EPISODIC CURTAILMENT

Voluntary 10 Reduction in emissions for all RWC 

devices not exempted.

Mandatory 60% fireplace

50% woodstoves

Reduction in emissions for all RWC 

devices not exempted.

Table Reference: U.S. EPA, 1992, Technical Information Document for Residential Wood Combustion Best 

Available Control Measures, Research Triangle Park, NC, EPA-450/2-92-002.

Table 9.2 from the OMNI report summarizes measures for RWC BACM developed by EPA in 

EPA-450/2-92-002. As shown in Table 9.2, the BACM fall into two primary categories: (1) 

integral measures which are necessary for the success of a long-term RWC pollutant reduction 

programs but, by themselves, are not adequate to provide long-term reductions and (2) flexible 

(long-term) measures to reduce, eliminate, or prevent increases in pollutant emissions for 

existing and/or new installations. With the exceptions of the device and upgrade offsets, the 

specific elements of the BACM are essentially those described in the RACM document with the 

various efficiencies listed in Table 9.1 being applicable.

Table 9.2 Summary of Measures Available for RWC BACM – PM10

Integral Measures1

Flexible Measures that 

Reduce or Eliminate

Emissions from

Existing Installations2

Flexible Measures that 

Reduce Emissions or

Prevent Emission

Increases from New

Installations2

Flexible Measures

that Reduce

Emissions from

New and Existing

Installations2

1. Public awareness and

education.

1. Conversion of 

existing wood-burning 

fireplaces to gas logs. 

1. Gas fireplaces or gas 

logs in new wood 

burning fireplace 

installations.

1. Device offset.4

2. Mandatory 

curtailment during 

predicted periods of 

high PM10

concentrations.

2. Changeover to EPA 

certified,

Phase II stoves or 

equivalent.

2. Upgrade offset.42. Upgrade offset. 4

3. All new stove 

installations EPAcertified, Phase II stoves 

or equivalent.

3. Changeover to low

emitting device.3

3. Restriction on number 

and density of new 

wood-burning stove 

and/or fireplace 

installations.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-8

Table 9.2 Summary of Measures Available for RWC BACM – PM10

Integral Measures1

Flexible Measures that 

Reduce or Eliminate

Emissions from

Existing Installations2

Flexible Measures that 

Reduce Emissions or

Prevent Emission

Increases from New

Installations2

Flexible Measures

that Reduce

Emissions from

New and Existing

Installations2

4. Measures to improve 

wood burning 

performance:

-control of wood 

moisture content

-weatherization of 

homes with wood stoves 

-educational opacity 

program

4. Requirement that new 

stove installations be 

low emitting.

1

Integral measures are regarded as critical for the success of a RWC control program, but by themselves are not 

intended to result in long-term attainment of the PM10 NAAQS for serious PM10 nonattainment areas.

2

Flexible measures are designed for permanent control of RWC emissions and thus long-term attainment of the 

PM10 NAAQS.

3 This measure is virtually identical to item 2, except that the changeover is recommended to a “low-emitting” 

device that can document “in-home” field test emissions less than the emission factor averages of “in-home” field 

test emissions data for EPA-certified stoves. This can include classes of devices that are demonstrated to be 

capable as a class of producing lower field emissions, as well as, specific model units that perform better in the 

field than the class collectively (an example might include masonry heaters, uncertified pellet-fueled devices, and 

wood fired gasification centralized heating systems).

4 Offsets are intended to achieve emission reductions, when retiring (device offset) or changing-out (upgrade offset) 

conventional stoves, greater than the emissions increase resulting from new stove installations.

Table Reference: U.S. EPA, 1992, Technical Information Document for Residential Wood Combustion Best 

Available Control Measures, Research Triangle Park, NC, EPA-450/2-92-002.

OMNI reported that the RWC RACM and BACM have been the basis for PM10 innovative 

strategies implemented in various western States and in local jurisdictions and have also been, inlarge part, the basis for a number of western State and their local RWC regulations. As part of 

these strategies, strict particulate emission standards have been developed which will take effect 

in 2008.

The OMNI report states that the Washington State standard is notable among State and local 

regulations for residential wood burning devices. Washington State has implemented more 

stringent standards for residential wood burning devices, so devices installed in Washington 

State must be certified to the more stringent standard. This has affected the stove market 

because many U.S. certified stove manufacturers choose to have their appliances certified to the 

more stringent Washington State standard, unless the manufacturer can not or does not choose to 

test to the tighter standard. Discussions with EPA indicate that most manufacturers are choosing 

to design and sell units that meet the Washington State standards of 4.5 g/hr for non catalytic 

wood stoves and 2.5 g/hr for catalytic wood stoves (personal communication with Mr. John 

Dupree of the U.S. EPA).
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-9

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR 

RESIDENTIAL WOOD COMBUSTION

Cost of Compliance

OMNI analyzed the cost effectiveness of five categories of widely existing, older technology

wood-burning devices. These are: (1) freestanding cordwood stoves, (2) cordwood-fueled 

fireplace inserts, (3) cordwood fireplaces (without inserts) used for heating purposes, (4) 

centralized cordwood heating systems and (5) cordwood fireplaces used for aesthetic purposes. 

Table 9.3 lists these five categories with the available, improved technology replacement, 

installation scenarios, and fuel switching alternatives that would reduce particulate and VOC 

emissions.

OMNI noted that wood resources are abundant and widely utilized as fuel, and heating is 

essential due to the climate of the region. The cost to households of any regulatory program 

mandating acceptable heating practices is an important consideration. Likewise, the cost to 

households of any voluntary program is paramount for its success. The cost effectiveness of all 

reasonable scenarios for the replacement, modification or alternative fuel use for older existing, 

high emission wood-burning appliances was provided in the OMNI report for regulators and 

policy makers charged with the task of specifically lowering particulate and VOC emissions 

from residential wood combustion.

The tables provided in this chapter based on the OMNI report allow for a direct comparison of 

the cost burden for each realistic mitigation option that would be shouldered by residential users. 

As an example, for an average resident in the MANE-VU region with an existing older 

technology centralized cordwood heating system, the best current option in terms of cost among 

the pellet, natural gas, and LPG options, is natural gas (assuming natural gas is available). 

Similarly, for wood-burning fireplaces used for aesthetics, manufactured wax/fiber firelogs offer 

the lowest cost per unit mass of air pollutant reduction. The cost effectiveness of each option is 

dependent on the costs of the new equipment and the cost of required fuels. The costs presented 

in the tables in this chapter were the most current information available as of the date of the 

OMNI report.

Estimates of costs per ton of reductions in the tables in this chapter are specific to the 

MANE-VU region because they reflect the estimated usage of various devices in this region.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-10

Table 9.3 Improved Technologies and Fuel Alternatives

Existing Cordwood Device

High Technology Replacement, Installation or 

Alternative Fuel

Uncertified Freestanding Cordwood

Stove

Replacement with Certified NSPS Non-Catalytic 

Cordwood Stove

Replacement with Certified NSPS Catalytic 

Cordwood Stove

Replacement with Pellet Stove

Replacement with Gas Stove – natural gas (B vent, 

direct vent)

Replacement with Gas Stove – LPG

(B vent, direct vent)

Uncertified Cordwood Fireplace

Insert

Replacement with Certified NSPS Non-Catalytic 

Cordwood Insert

Replacement with Certified NSPS Catalytic 

Cordwood 

Replacement with Pellet Insert

Replacement with Gas Insert – natural gas (B vent, 

direct vent)

Replacement with Gas Insert – LPG

(B vent, direct vent)

Cordwood Fireplace without Insert

Used for Heating

Installation of Certified NSPS Non-Catalytic 

Cordwood Insert

Installation of Certified NSPS Catalytic Cordwood 

Insert

Installation of Pellet Insert

Installation of Gas Insert – natural gas

(B-vent, direct vent)

Installation of Gas Insert – LPG

(B-vent, direct vent)

Cordwood Fireplace Used for

Aesthetic Purposes

Installation of Gas Log Set – natural gas (vented 

and vent free)

Installation of Gas Lo g Set – LPG (vented and vent 

free)

Wax/Fiber Firelog Fuel

Centralized Cordwood Heating

System

Pellet Furnace or Boiler

Gas Furnace or Boiler – natural gas

Gas Furnace or Boiler – LPG

OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and

Documentation for Residential Wood Combustion in the MANE-VU Region. Project funded by Mid-Atlantic 

Regional Air Management Association, Inc., December 19, 2006.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-11

Table 9.4 from the OMNI report demonstrates the cost effectiveness of replacing three types of 

cordwood stoves and fireplaces with devices that emit less PM. Table 9.5 from the OMNI report

demonstrates the impact on cost effectiveness of the same replacements on VOC reductions. 

The cost effectiveness tables are in reference to the replacement of an existing RWC device, and 

do not include new construction.

In Tables 9.4 and 9.5, if the total annual cost of the improved technology and alternative fuel 

replacement or installation is less than the total annual cost of the existing device, and there is 

corresponding pollutant reduction after installation or replacement, then there is no cost for the 

pollution reduction, and the cell is marked as “**”. The replacement options for which there is 

no cost may actually represent cost savings, and thus are the most cost effective options for 

replacement.

Table 9.4 PM Reduction Cost Effectiveness for Replacement of Existing Uncertified 

Freestanding Cordwood Stove/Insert and Cordwood Fireplace w/o Insert for Heating

Existing

Cordwood

Device

Certified

NSPS NonCatalytic

Cordwood

Stove

Certified

NSPS 

Catalytic

Cordwood 

Stove

Pellet

Stove

Gas

StoveNG,

B Vent

Gas

StoveNG,

Direct

Vent

Gas

StoveLPG,

B Vent

Gas

StoveLPG,

Direct

Vent

PM Reduction Cost Effectiveness ($/ton)

Uncertified 

Freestanding 

Cordwood

Stove

1,170 3,300 8,960 5,350 3,530 12,600 9,760

Uncertified 

Cordwood 

Fireplace 

Insert

  5,180 1,910 **  8,980 6,040

Cordwood 

Fireplace 

w/o Insert 

for Heating

3,880 5,670 8,330 ** ** 1,880 695

OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and 

Documentation for Residential Wood Combustion in the MANE-VU Region. Project funded by Mid-Atlantic 

Regional Air Management Association, Inc., December 19, 2006.

**No cost for the pollution reduction.

Tables 9.4 and 9.5 indicate that OMNI estimated that in the MANE-VU region there are several 

options for reducing emissions from two of the above types of fireplaces that would reduce 

emissions at essentially no cost, due to fuel cost savings.
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-12

Table 9.5 VOC Reduction Cost Effectiveness for Replacement of Existing Uncertified 

Freestanding Cordwood Stove/Insert and Cordwood Fireplace w/o Insert for Heating

Existing

Cordwood

Device

Certified

NSPS NonCatalytic

Cordwood

Stove

Certified

NSPS 

Catalytic

Cordwood 

Stove

Pellet

Stove

Gas

StoveNG,

B Vent

Gas

StoveNG,

Direct

Vent

Gas

StoveLPG,

B Vent

Gas

StoveLPG,

Direct

Vent

VOC Reduction Cost Effectiveness ($/ton)

Uncertified 

Freestanding 

Cordwood 

Stove

1,260 2,960 7,740 4,940 3,260 11,800 9,130

Uncertified 

Cordwood 

Fireplace 

Insert

  4,480 1,760 **  8,410 5,640

Cordwood 

Fireplace 

w/o Insert 

for Heating

7,900 10,400 13,200 ** ** 3,090 1,140

OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and 

Documentation for Residential Wood Combustion in the MANE-VU Region. Project funded by Mid-Atlantic 

Regional Air Management Association, Inc., December 19, 2006.

**No cost for the pollution reduction.

Table 9.6 presents the cost effectiveness in terms of dollars per ton of PM reduction and VOC 

reduction for replacement of an existing centralized cordwood heating system with three 

available technologies. The cost effectiveness tables are in reference to the replacement of an 

existing RWC device, and do not include new construction. The most cost effective option is 

replacing the existing system with a natural gas furnace or boiler. This option is not feasible in 

areas that do not have access to natural gas, and the increase in costs associated with using LPG 

is significant.

Table 9.6 Reduction Cost Effectiveness for the Replacement of an Existing Centralized 

Cordwood Heating System

High Technology 

Replacement, Installation or 

Alternative Fuel

PM Reduction

Cost Effectiveness

($/ton)

VOC Reduction

Cost Effectiveness

($/ton)

Pellet Furnaces and Boilers 7,810 17,200

Gas Furnaces and Boilers–

Natural Gas 3,030 7,150

Gas Furnaces and Boilers-LPG 9,370 23,100

OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and 

Documentation for Residential Wood Combustion in the MANE-VU Region. Project funded by Mid-Atlantic 

Regional Air Management Association, Inc., December 19, 2006.

Table 9.7 presents the cost effectiveness in terms of dollars per ton of PM reduction and VOC 

reduction for the addition of a gas log set or use of wax/fiber firelogs in an existing fireplace with 
Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-13

no insert. Burning wax/fiber firelogs in the existing fireplace is, by far, the most cost effective 

option for reducing emissions of PM and VOC.

Table 9.7 Pollutant Reduction Cost Effectiveness for the Addition of a Gas Log Set or Use 

of Wax/Fiber Firelogs in an Existing Fireplace w/o Insert Used for Aesthetics

Pollutant

Pollutant Reduction Cost Effectiveness ($/ton)

Vent-Free Gas

Log Set-NG

Vented Gas

Log Set-NG

Vent-Free Gas

Log Set-LPG

Vented

Gas LogLPGWax/Fiber

Firelog Fuel

PM 27,100 29,900 29,400 34,100 2,530

VOC 43,900 48,500 48,300 56,600 5,110

OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and 

Documentation for Residential Wood Combustion in the MANE-VU Region. Project funded by Mid-Atlantic 

Regional Air Management Association, Inc., December 19, 2006.

OMNI presented no cost-effectiveness summary for other RWC control measures such as 

described in EPA’s PM10 RACM/BACM guideline documents. Costs associated with these 

measures are predominantly organizational and administrative associated with the 

implementation of regulations.

Time Necessary For Compliance

Because the control methods discussed in the previous section for RWC are existing technology, 

the time necessary for compliance would depend on the amount of time it would take to regulate 

the sources and establish compliance deadlines. The Feasibility Assessment of a Changeout/Education Program for Residential Wood Combustion from the Canadian Council of 

Ministers of the Environment suggests a phased approach for national implementation. A phased 

approach will enable the program to evolve over time and benefit from lessons learned in the 

early stages of the program. Phasing also reflects the reality that building awareness and 

changing behavior is a long-term investment. The approach that this report proposed had two 

phases. The first phase (2005-2006) focused on building a base for support and understanding 

around RWC in a single province. The second phase (2007 and beyond) and full roll-out 

involved the realization of independent, arms length management of public education and 

outreach by all stakeholders throughout Canada. The main steps for this phase included:

 Implementation of national regulation as soon as possible (i.e. 2008-2009);

 Full operational capacity across Canada;

 Funding to come from multiple sources (i.e. nationwide partnerships with the insurance, 

financial, and utilities industries);

 Movement of various groups from being target audiences to becoming key players in 

designing and delivering woodstove change-out/public education campaigns; and

 Multi-stakeholder involvement and shared leadership (governments together with 

business and industry, communities, and non-governmental organizations).
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-14

Energy and Non-Air Impacts

Other factors beyond PM2.5 and regional haze (i.e., VOC and fine particles) should also influence 

RWC regulatory policy. The greenhouse gas benefits of biomass combustion and the minimal 

acid gas emissions (acid precipitation impacts) from wood combustion are strong environmental 

advantages. Further, the fact that wood is a domestic renewable energy source and the fact that 

the cost of natural gas, propane, and fuel oil have a history of rising together have been 

responsible for the increase in the use of RWC. For example, several States are encouraging the 

use of renewable energy sources such as wood for heating purposes.

The Canadian Council of Ministers of the Environment study estimated that the increase in 

combustion efficiency associated with a switch out to a more efficient stove would save on 

average more than one cord of wood per stove per heating season.

Any mandatory change out program should be mindful that even with assistance, woodstove 

change out programs will impact families that are least able to bear the burden of additional 

costs. Voluntary programs do not impose this economic burden on families less able to bear 

associated costs.

Remaining Useful Life Of The Source

From information obtained from a scoping study that was prepared for Environment Canada in 

1997, (Gulland Associates Inc., 1997) the durability of low emission stoves has improved 

considerably. Premature stove degradation is not viewed as a problem. In most new stoves 

today, vulnerable parts can be replaced, and manufacturers now use more heat-resistant materials 

such as ceramics and stainless steel. The performance and durability of catalytic stoves has also 

improved through better design and use of materials. The useful life of a wood stove catalytic 

element is estimated to be 9,000 to 12,000 hours, or three to five years of use, depending on 

heating demand, user skill, and degree of maintenance provided.

The best mechanism by which to lower smoke emissions from residential wood burning 

appliances is to replace conventional equipment with certified low emission stoves. Given the 

minimum useful life span of a wood stove of 10-15 years (per industry references), over which 

time the incremental cost of advanced technologies is spread, the cost impacts did not seem 

unreasonable to Environment Canada. It is also possible that the price of the least expensive 

advanced technology stove would come down after a regulation were established as 

manufacturers seek to fill the low cost market niche formerly filled by conventional stoves; that 

is, plain, unadorned styling and lacking additional features such as ash pan and large glass door 

panel. (Gulland Associates Inc., 1997) Many woodstove manufacturers have chosen to 

manufacture products at a reasonable cost that meet more stringent emissions standards such as 

those in Washington State (personal communication with Mr. John Dupree of EPA). 

Implementation of stricter emissions standards in additional states or regions will likely increase 

the competition to produce these woodstoves at even more reasonable prices.
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 9: Residential Wood Combustion Page 9-15

REFERENCES

OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control 

Analysis and Documentation for Residential Wood Combustion in the MANE-VU Region. 

Project funded by Mid-Atlantic Regional Air Management Association, Inc., December 19, 

2006.

Headquarters, U.S. EPA. Personal communication regarding the number of new residential 

wood burning devices meeting the Washington State standards from Mr. John Dupree 

(202) 564-5950, (Dupree.john@epa.gov) via telephone on April 12, 2007.

U.S. EPA, 1989, Guideline Series, Guidance Document for Residential Wood Combustion 

Emission Control Measures, Research Triangle Park, NC, EPA-450/2-89-015.

U.S. EPA, 1992, Technical Information Document for Residential Wood Combustion Best 

Available Control Measures, Research Triangle Park, NC, EPA-450/2-92-002.

U.S. EPA, 1993, PM-10 Innovative Strategies: A Sourcebook for PM-10 Control Programs, 

Research Triangle Park, NC, EPA-452/R-93-016.

The Canadian Centre for Pollution Prevention, CULLBRIDG Marketing and Communications 

and Action-Environment, Feasibility Assessment of a Change-out/Education Program for 

Residential Wood Combustion, A Step-by-Step Approach to a National Program Aimed at 

Reducing Emissions from Residential Wood Combustion. September 20, 2004.

Gulland Associates Inc., Scoping Study: Reducing Smoke Emissions From Home Heating With 

Wood. Prepared for Environment Canada, March 31, 1997.

Environment Australia (2002). Technical Report No. 4: Review of Literature on Residential 

Firewood Use, Wood-Smoke and Air Toxics. 49p. Report available on the Environment 

Australia website

http://ea.gov.au/atmosphere/airtoxics/report 4/exec-summary.html.
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Chapter 10: Residential Wood Combustion – Outdoor Wood-Fired Boilers Page 10-1

CHAPTER 10

RESIDENTIAL WOOD COMBUSTION - OUTDOOR WOOD-FIRED BOILERS

BACKGROUND

Outdoor wood-fired boilers are used in the Northeast United States, and their use is increasing as 

more traditional heating fuels (heating oil, natural gas) are becoming more expensive. 

NESCAUM (2007) estimates that the sale of outdoor wood-fired boilers is increasing by 25-50% 

annually. Nationwide there are between 155,000 and 200,000 boilers in service (Personal 

communication with Lisa Rector, NESCAUM). If the sales trends continue, NESCAUM 

estimates that there may be up to 500,000 boilers nationally by 2010.

Outdoor wood-fired boilers are used for heating and providing hot water for both individual 

homes and for “mini-district heating” (Woodheat.org 2007). Additional uses of outdoor woodfired boilers include heating swimming pools and greenhouses. Outdoor wood-fired boilers are 

typically located in sheds that are located near buildings. Heated water is conveyed through 

underground or insulated pipes.

Even though outdoor wood-fired boilers may be economical solutions to home heating and hot 

water production, they contribute significantly to air pollution. Outdoor boilers emit so much 

smoke they have been banned by some local jurisdictions (Woodheat.org 2007). NESCAUM 

(2007) estimates that the average fine particulate emissions from one outdoor wood-fired boiler 

are equivalent to the emissions from 22 US Environmental Protection Agency (EPA) certified 

wood stoves, 205 oil-fired furnaces, or 8,000 natural gas-fired furnaces.

On the basis of heat input, NESCAUM (2007) estimated that outdoor wood-fired boilers emit 

from 1.5 to 3.1 pounds of PM per MMBTU heat input. This information was calculated by

NESCAUM using data from tests conducted on outdoor wood-fired boilers for EPA (EPA 

1998a). (Guldberg 2007) used data from 56 outdoor wood-fired boilers tests conducted by EPA 

in 1995 and 1999, and estimated that outdoor wood-fired boilers emit 1.44 pounds of PM per 

MMBTU heat input. In comparison, the EPA estimate (EPA 1998b) for PM from residential 

fuel oil combustion is 0.4 pounds of PM per thousand gallons of fuel combusted. Assuming a 

heating value of 140 MMBTU per thousand gallons of fuel oil, the PM emission factor is 0.003 

pounds of PM per MMBTU heat input for residential fuel oil combustion. Similarly, for 

residential natural gas combustion, (EPA 1998c) assuming a natural gas heating value of 1,020 

BTU per standard cubic foot, the PM emission factor is 0.002 pounds per MMBTU heat input. 

Based on these emission factor estimates, and strictly on the basis of heat input, outdoor woodfired boilers emit roughly 500 times as much PM as oil-fired residential furnaces and 750 times 

as much PM as natural gas-fired residential furnaces based on the low-range estimate of PM 

emissions from outdoor wood-fired boilers. Based on the upper range of the PM emissions

estimate from outdoor wood-fired boilers, they emit roughly 1,000 times as much PM as oil-fired 

residential furnaces and 1,500 times as much PM as natural gas-fired furnaces.

Heavy emissions from outdoor wood-fired boilers can be attributed to their designs. For 

example, most outdoor wood-fired boilers have fireboxes that are surrounded by a water jacket. 

The water jacket makes complete combustion of the wood nearly impossible due to the cooling 
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Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis

Chapter 10: Residential Wood Combustion – Outdoor Wood-Fired Boilers Page 10-2

effect that the jacket has on the firebox. The flaming combustion of wood cannot occur below 

about 540 C (1,000 F), so the steel surfaces of the water jacket backed up by water at 

approximately 65 C (150 F) chill and quench the flames well before complete combustion can 

occur.

In addition outdoor wood-fired boilers smoke heavily due to their cyclical operating pattern. 

When the temperature of the water within the boiler falls below a set point, its combustion air 

damper opens and/or a small fan forces combustion air into the firebox. Once the water is heated 

back to the upper set point, the fan is turned off and/or the combustion air damper closes. During 

the off cycles the fire smolders and much of the smoke condenses as creosote on the cold steel 

internal surfaces. When the thermostat again calls for heat and incoming combustion air 

rekindles the fire, the heat ignites the creosote clinging to the boiler walls. This leads to an 

increase in emissions that accompanies the poor combustion in the firebox.

Outdoor wood-fired boilers are also sometimes not sized appropriately for the house that they are 

intended to heat. For example, an oversized boiler will tend to run in the smoldering phase 

longer than in the full out burn phase, thereby producing more smoke.

It has been suggested that excessive production of emissions by outdoor wood-fired boilers is 

associated improper installation of the boiler or the use of fuels not designed to be combusted in 

the boiler (personal communication with Peter Guldberg, Tech Environmental). Additionally, 

Guldberg, 2007 suggests that emissions from outdoor wood-fired boilers are comparable to other 

wood-fired combustion devices in terms of lbs/MMBTU heat generated. In any case, Guldberg, 

2007 indicates that outdoor wood-fired boiler manufacturers have worked with EPA to develop a 

voluntary Outdoor Wood-fired Heater Program with a Phase I emission target of 0.6 

lb/MMBTU. According to Guldberg, 2007 manufacturers will offer the outdoor wood-fired 

heaters qualified to achieve the Phase I standard later in 2007.

NESCAUM’s Model Rule

On January 29, 2007, NESCAUM made available its “Outdoor Hydronic Heater Model 

Regulation.” The model rule is designed to serve as a template to assist State and local agencies 

in adopting requirements that will reduce air pollution from outdoor wood-fired boilers. The 

model rule was developed in cooperation with a number of States and EPA. The model rule has 

provisions for:

 Critical definitions,

 Emission standards,

 Test method procedures,

 Certification process, and

 Labeling requirements.

The model rule contains a single method for regulating new units with respect to the critical 

elements and contemplates that States may propose alternative approaches for other provisions. 

It also provides alternatives for states to consider for regulating previously installed units 

(NESCAUM 2007).
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NESCAUM’s model rule sets standards for particulate matter (PM) emissions by phases for 

residential and commercial boilers. The PM standards for both boiler types are identical. Phase 

I calls for a PM emission limit or 0.44 pounds per million BTU heat input. This standard would 

have to be met by March 31, 2008. Phase II calls for a PM emission standard of 0.32 

lb/MMBTU which is to be met by March 31, 2010.

Vermont’s Rule on Outdoor Wood-fired Boilers

On April 12, 2007 Vermont filed a regulation on outdoor wood-fired boilers with the Secretary

of State and the Legislative Committee on Administrative Rules. The rule legally went into 

effect on April 27, 2007, and adopts NESCAUM’s model rule Phase 1 PM emission standard of 

0.44 lb/MMBTU. As of March 31, 2008, outdoor wood-fired boilers not meeting the standard of 

0.44 lb/MMBTU cannot be sold in Vermont. Additional information on Vermont’s final rule on 

outdoor wood-fired boilers can be found on the following web site: 

http://www.vtwoodsmoke.org. (Etter, personal communication)

This section of this document addresses the four factor analysis which includes the following 

elements: cost of compliance, time necessary for compliance, energy and non-air impacts, and 

remaining useful life of the source.

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR 

OUTDOOR WOOD-FIRED BOILERS

Cost of Compliance

Outdoor wood-fired boilers are priced according to their size (heat output). For example, 

Northwest Manufacturing sells a line of outdoor wood-fired boilers that ranges in price from 

$4,295 for a boiler that will heat a 2,000 square foot house to $12,995 for a boiler that can heat 

up to 20,000 square feet. Similarly, Hud-Son Forest Equipment has a line of outdoor wood-fired 

boilers that range in price from $6,095 for boiler that can heat a 2,000 square foot house to 

$7,795 for a boiler that can heat up to 10,000 square feet.

There are currently only a few outdoor wood-fired boiler manufacturers whose products would 

meet the 2008 NESCAUM phase I standard of 0.44 lb/MMBTU. NESCAUM estimates that 

there are “several units currently on the market that can meet this standard.” In addition, 

NESCAUM estimates that more stringent air standards that it proposed should come into 

compliance in 2010 would currently only be met by one unit. Consequently, manufacturers of 

outdoor wood-fired boilers would have to invest money into research and development in order 

to manufacture boilers that would meet NESCAUM’s model standards. MACTEC contacted an 

outdoor wood-fired boiler manufacturer to determine cost increases due to the NESCAUM rule. 

The boiler manufacturer was not able to provide estimated cost increases necessary to 

manufacture boilers meeting the NESCAUM model rule standards (personal communication 

with Central Boiler, Inc.).

MACTEC also investigated the costs of replacing the outdoor wood-fired boilers with heating 

oil-fired furnaces and boilers. We determined that the capital cost of oil-fired water boilers 

ranged from $2,800 - $3,825. Similarly, the capital cost of oil-fired furnaces range from $1,560 -
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Chapter 10: Residential Wood Combustion – Outdoor Wood-Fired Boilers Page 10-4

$1,800 (Alpine Home Air 2007). Therefore, oil-fired boilers and furnaces can be substantially 

less expensive than outdoor wood-fired boilers.

In a previous section, information was presented on the average amount of distillate fuel oil used 

on an annual basis by households in the Northeast. It was estimated that households use 

approximately 865 gal/yr of fuel oil (STAPPA-ALAPCO 2006). Therefore, the annual average 

heating cost using fuel would currently be approximately $2,100 (assuming a fuel oil price of 

$2.40/gal). The University of Wisconsin Solid and Hazardous Waste Education Center (2007) 

estimates that it would take only 4 full cords of oak firewood to heat a house per year. At 

approximately $200/cord (Boston.com 2004), this equates to an annual fuel cost of $800/year. 

Consequently, the annual cost for firewood is $1,300 less than the cost of distillate fuel oil. 

Additionally, many operators of outdoor wood boilers have access to a free supply of firewood 

for the boiler, thus the only fuel cost to these operators is the time, effort, and expense associated 

with gathering the wood and cutting it for use in the outdoor wood-fired boiler.

Assuming the average household use of 865 gal/yr of fuel oil, and a fuel oil heating value of 140 

MMBTU per thousand gallons, the annual heat input required is 121.1 MMBTU. The emission 

factors for residential fuel oil combustion, natural gas combustion, and wood combustion in 

outdoor wood-fired boilers are 0.003, 0.002, and 1.5 to 3.1 pounds of PM per MMBTU heat 

input respectively. Using the annual heat input requirement of 121.1 MMBTU, the annual

emissions from an oil-fired furnace would be 0.4 pounds, the emissions from a natural gas-fired 

furnace would be 0.2 pounds, and the emissions from the outdoor wood-fired boiler would be 

from 180 to 380 pounds. The cost of replacing an outdoor wood-fired boiler with an oil-fired 

furnace or boiler is estimated to be from $1,560 to $3,825 (Alpine Home Air 2007). If the 

capital cost of the oil-fired furnace or boiler is spread over ten years, the annualized capital cost 

is between $156 and $383. Additionally, the cost of fuel oil is estimated to be from $0 to $2,100 

more than the outdoor wood-fired boiler fuel costs depending on whether the operator has access 

to a free wood supply, or must purchase the wood by the cord. Based on these estimates, the PM 

cost effectiveness of replacing an outdoor wood-fired boiler with an oil-fired furnace or boiler 

would be from $1,700 to $13,000 per ton of PM reduced. The costs for replacement of outdoor 

wood-fired boilers with natural gas-fired furnaces or boilers have not been quantified.

Time Necessary for Compliance

Outdoor wood-fired boilers have been in operation for approximately the last 15 years (personal 

communication with P. Etter from Vermont Air Pollution Control). Consequently, the average 

age of outdoor wood-fired boilers is not known. On at least one occasion, a boiler vendor opted 

to go out of business rather than honor 5-year warranties (personal communication with J. 

Gulland from OutdoorHeat.org). If States pass a rule similar to NESCAUM’s and existing 

boilers are grandfathered, only new boilers would be required to meet the more stringent 

standards. In the section on residential heating, it was estimated that the average useful life of a 

residential boiler is between 18-25 years. Well manufactured outdoor wood-fired boilers may

have similar useful lives. Therefore, new boilers meeting more stringent PM emissions 

standards would be phased in slowly as older boilers are replaced.

Replacement of wood-fired boilers with oil-fired furnaces or boilers could occur on a very quick 

schedule. The number of residential boiler/furnace manufacturers in the United States is 
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Chapter 10: Residential Wood Combustion – Outdoor Wood-Fired Boilers Page 10-5

indicative of the fact that there is an ample supply of manufacturers. Although it is possible for 

outdoor wood-fired boilers to be replaced quickly, realistically, most of these units have been 

installed within the past 15 years. Since they are designed to last for approximately 20 years, 

operators of the outdoor wood-fired boilers would likely be reluctant to replace them 

immediately.

Energy and Non-Air Impacts

Wood is a renewable resource that is plentiful in the United States Northeast. The increased use 

of outdoor wood-fired boilers would lead to an increase in the amount of firewood that is 

combusted in the US Northeast on an annual basis. Alternatively, tighter rules regarding the PM 

emissions from outdoor wood-fired boilers may lead to a decrease in their use, which would 

make more firewood available for use in wood stoves and fire places. A move away from woodfired boilers would increase the demand on heating fuels such as heating oil, propane, and 

potentially coal or natural gas. 

The increased use of outdoor wood-fired boilers may have a variety of non-air impacts on the 

environment, especially on forest and water resources. The potential impacts are outlined below.

Nuisance Smoke: Outdoor wood-fired boilers typically have very short stacks, and are prone to 

smoke. The short stacks oftentimes prevent proper mixing of the smoke and soot with the 

surrounding air, thereby creating nuisance smoke problems for surrounding houses or 

communities (Michigan DEQ 2007).

Water: Increased logging to satisfy the demand for firewood may increase runoff of silts and 

sediments into adjacent creeks and rivers. This increased sediment load in rivers can affect 

aquatic ecosystems that are integral to rivers and streams.

Soils: Increased logging may impact soils in many ways. For example, heavy machinery used to 

fell and process trees may lead to rutting and compaction of the soil, which in turn leads to 

higher erosion and/or altered vegetative regrowth.

Wildlife: Increased logging may put pressure on existing wildlife populations in the US 

Northeast by altering their critical habitat.

Threatened and Endangered Species: Increased logging in Northeast may impact threatened and 

endangered species through habitat destruction or alteration.

Remaining Useful Life of the Source

The useful life of outdoor wood-fired boilers is approximately 20 years, which is also very close 

to the useful life of other residential boilers (Etter, personal communication). In addition, Mr. 

Etter indicated that outdoor wood-fired boilers have only been around for approximately 15 

years, therefore, most of the boilers that have been put into service are likely to remain there for 

at least the next five years.
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Chapter 10: Residential Wood Combustion – Outdoor Wood-Fired Boilers Page 10-6

REFERENCES

EPA, 1998a. Emissions from Outdoor Wood-Burning Residential Hot Water Furnaces. EPA 

Publication Number EPA-600/R-98-017.

EPA, 1998b. AP-42 section 1.3. Fuel Oil Combustion.

EPA, 1998c. AP-42 section 1.4. Natural Gas Combustion.

Etter, P., Vermont Department of Environmental Conservation, Air Pollution Control Division. 

Personal communication with Mr. Bernd Haneke, MACTEC Federal Programs, Inc., on March 

9, 2007.

Etter, P., Vermont Department of Environmental Conservation, Air Pollution Control Division. 

Personal communication with Mr. William Hodan, MACTEC Federal Programs, Inc., on July 3, 

2007.

Gulland, J., OutdoorHeat.org. Personal communication with Mr. Bernd Haneke, MACTEC 

Federal Programs, Inc., via E-mail on March 9, 2007.

Guldberg, P., Tech Environmental, Inc. Personal communication with Mr. William Hodan, 

MACTEC Federal Programs, Inc. via E-mail on May 17, 2007.

Guldberg, P. 2007. Outdoor Wood Boilers – New Emissions Test Data and Future Trends. 

Presented at the 16th Annual International Emission Inventory Conference - Emission 

Inventories: “Integration, Analysis, and Communications”

Killeen, W. 2004. Firewood Shortage Reflected in Prices. Document obtained from the World 

Wide Web at: www.boston.com

Michigan Department of Environmental Quality 2007. Outdoor Wood Boiler and Air Quality 

Factsheet. Document obtained from the World Wide Web at: www.michigan.gov/deqair

NESCAUM, 2006. Assessment of Outdoor Wood-fired Boilers. Document obtained from the 

World Wide Web at: http://burningissues.org/outdoor-wood-boilers.htm

NESCAUM, 2007. Outdoor Hydronic Heater Model Regulation. Document obtained from the 

World Wide Web at: http://burningissues.org/outdoor-wood-boilers.htm

NESCAUM. Personal communication between Ms. Lisa Rector and Dr. Art Werner, MACTEC 

Federal Programs, Inc., on June 6, 2007.

STAPPA ALAPCO, 2006. Controlling Fine Particulate Matter Under the Clean Air Act: A 

Menu of Options.

Central Boiler, Inc. Personal communication between Mr. Rodney Tollefson and Mr. Bernd 

Haneke, MACTEC Federal Programs, Inc., on March 8, 2007.
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Chapter 10: Residential Wood Combustion – Outdoor Wood-Fired Boilers Page 10-7

University of Wisconsin 2005. Using Wood as a Residential Heating Fuel: Issues and Options. 

Published by the University of Wisconsin Solid and Hazardous Waste Education Center, and 

downloaded from the World Wide Web at: 

uwm.edu/Dept/shwec/publications/cabinet/p2/outdoorwoodfiredboilers.pdf

Information on prices of furnaces and boilers were obtained from the World Wide Web using the 

following URLs:www.alpinehomeair.com; www.hud-son.com/woodfurnaces.htm; 

www.woodmaster.com/web.htm