Document ID: EPA-HQ-OAR-2009-0734-0025
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2014-02-03T05:00Z

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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

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

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

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

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

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

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):



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.

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:    HYPERLINK
"http://www.epa.gov/pm/reducing.html" 
http://www.epa.gov/pm/reducing.html 

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

 

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
coal-combustion, 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).

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

 



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:    HYPERLINK
"http://www.manevu.org/Document.asp?fview=Reports#" 
http://www.manevu.org/Document.asp?fview=Reports# 

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 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.

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®).

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.    HYPERLINK
"http://www.epa.gov/pm/reducing.html" 
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,   HYPERLINK "mailto:paul.wishinski@state.vt.us"
 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.

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 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.



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	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 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 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 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, lime-scrubbing 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.

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.

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 industry-wide 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   HYPERLINK "http://www.inflationdata.com" 
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
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:

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

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 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:    HYPERLINK
"http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html" 
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:    HYPERLINK
"http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html" 
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   HYPERLINK "http://www.inflationdata.com" 
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
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) coal-fired 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  
HYPERLINK "http://www.inflationdata.com"  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   HYPERLINK "http://www.inflationdata.com" 
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®) 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   HYPERLINK "http://www.inflationdata.com" 
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) coal-fired 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   HYPERLINK "http://www.inflationdata.com"  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   HYPERLINK
"http://www.inflationdata.com"  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  
HYPERLINK "http://www.inflationdata.com"  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.
(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  
HYPERLINK "http://www.inflationdata.com"  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) coal-fired 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   HYPERLINK
"http://www.inflationdata.com"  www.inflationdata.com )

The 2005 EPA document titled, Multipollutant Emission Control Technology
Options for Coal-fired 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   HYPERLINK
"http://www.inflationdata.com"  www.inflationdata.com )).

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

	SO2 is 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:    HYPERLINK
"http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html" 
http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html 

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

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:

       HYPERLINK
"http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html" 
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:

        HYPERLINK
"http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqsocc.stm" 
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 3½ 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
pre-combustion 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 particulate-bound mercury in PM control
equipment and capture of soluble ionic mercury in wet FGD 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.

REFERENCES

2002 MANE-VU Emissions Inventory Version 3.

EPA Clean Air Markets Division, (CAMD).  Personal communication
regarding control at coal-fired 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 Coal-fired Power Plants; March 2005.

U.S. EPA.  Integrated Planning Model (IPM®) background documentation
located on website: (  HYPERLINK
"http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html" 
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:

  HYPERLINK
"http://www.zenon.com/applications/FGD_wastewater_treatment.shtml" 
http://www.zenon.com/applications/FGD_wastewater_treatment.shtml 

Energy Information Administration (EIA).  Information located on
website:    HYPERLINK
"http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html" 
http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html 

Energy Information Administration (EIA).  Information located on
website:    HYPERLINK
"http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html" 
http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html 

Energy Information Administration (EIA).  Information located on
website:  

  HYPERLINK "http://www.eia.doe.gov/cneaf/electricity/epm/epm_sum.html" 
http://www.eia.doe.gov/cneaf/electricity/epm/epm_sum.html 

World Bank Organization.  Information located on website:

  HYPERLINK
"http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqsocc.stm" 
http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqsocc.stm 

 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.

Integrated Planning Model (IPM®) results from the MANE-VU CAIR Plus
(MARAMA 4c) run.

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.

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, 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



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

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%	6,650 MMBTU	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

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   HYPERLINK
"http://www.inflationdata.com"  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.

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

Hatfield’s Ferry5	PA	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

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

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.

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 (ES-6A)	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

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 coal-fired 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

Morgantown14, 15	MD	32,587	Combustion Engineering, Inc., Unit Boiler No.
2 - steam generating coal-fired 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 coal-fired 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.

1	Tennessee Department of Environment and Conservation, Division of Air
Pollution Control.  Personal communication regarding Johnsonville
facility from Ms. Julie Aslinger (615-532-0587,   HYPERLINK
"mailto:Julie.Aslinger@state.tn.us"  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,   HYPERLINK
"mailto:Julie.Aslinger@state.tn.us"  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,   HYPERLINK
"mailto:bill.spires@epa.state.oh.us"  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,  
HYPERLINK "mailto:nherb@state.pa.us"  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,   HYPERLINK "mailto:bill.spires@epa.state.oh.us" 
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,   HYPERLINK
"mailto:LCROWDER@wvdep.org"  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,   HYPERLINK "mailto:LCROWDER@wvdep.org" 
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,   HYPERLINK "mailto:JKOCH@idem.IN.gov"  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,   HYPERLINK "mailto:JKOCH@idem.IN.gov" 
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,   HYPERLINK
"mailto:shelia.holman@ncmail.net"  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,   HYPERLINK "mailto:djlong@aep.com" 
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,   HYPERLINK "mailto:nherb@state.pa.us" 
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,   HYPERLINK
"mailto:aheltibridle@mde.state.md.us"  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,  
HYPERLINK "mailto:bhug@mde.state.md.us"  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,   HYPERLINK "mailto:walkertr@michigan.gov" 
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,   HYPERLINK
"mailto:damcleod@deq.virginia.gov"  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,  
HYPERLINK "mailto:JGraham@achd.net"  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,   HYPERLINK "mailto:Donald.Squires@state.ma.us" 
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,   HYPERLINK
"mailto:Ray.Papalski@dep.state.nj.us"  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,   HYPERLINK
"mailto:Ray.Papalski@dep.state.nj.us"  Ray.Papalski@dep.state.nj.us )
via E-mail on February 1, 2007.

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}

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}

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.

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 Coal-fired Power Plants; March 2005.

U.S. EPA.  Integrated Planning Model (IPM®) background documentation
located on website: (  HYPERLINK
"http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html" 
http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html )

Energy Information Administration (EIA).  Information located on
website:    HYPERLINK
"http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html" 
http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html 

Energy Information Administration (EIA).  Information located on
website:    HYPERLINK
"http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html" 
http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html 

World Bank Organization.  Information located on website:

  HYPERLINK
"http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqsocc.stm" 
http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqsocc.stm
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 (  HYPERLINK
"http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/bc5emission.pdf" 
http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/bc5emission.pdf ). 
(Note:  To adjust cost data from 1999 to 2006, multiply by 1.2101   
HYPERLINK "http://www.inflationdata.com"  www.inflationdata.com  

Attachment 2.  Engineering Methodology Used to Calculate $/ton
Pollutant Reduction

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.

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 non-attainment 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
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 longer-term 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.  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.



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
lower-sulfur 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
bi-carbonate, 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.

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 coal-fired 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 sub-bituminous 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
refinery-produced 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).

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 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, lime-scrubbing 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 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:

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

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.

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   HYPERLINK "http://www.inflationdata.com" 
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.

Cost of Combustion Control

Dry sorbent injection, (DSI), systems have lower capital and operation
costs than post-combustion 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
Coal-fired Power Plants

(Converted from 2005 to 2006 dollars using a conversion factor of 1.0322
  HYPERLINK "http://www.inflationdata.com"  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.

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

Oilc	FGD (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
  HYPERLINK "http://www.inflationdata.com"  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 3½ 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 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. 

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,
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.

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  
HYPERLINK "http://www.eia.doe.gov/cneaf/coal/coal_trans/epact2000.html" 
http://www.eia.doe.gov/cneaf/coal/coal_trans/epact2000.html 

GE Water & Process Technologies.  Information accessed on web March 27,
2007:

  HYPERLINK
"http://www.zenon.com/applications/FGD_wastewater_treatment.shtml" 
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   HYPERLINK
"http://tonto.eia.doe.gov/dnav/pet/pet_pri_dist_dcu_R1X_m.htm" 
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   HYPERLINK
"http://tonto.eia.doe.gov/dnav/pet/pet_pnp_wiup_dcu_r10_w.htm" 
http://tonto.eia.doe.gov/dnav/pet/pet_pnp_wiup_dcu_r10_w.htm 



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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.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

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 (EP-031B-1):

1

2

3

4

13

14

Boilers (EP-031B-2):

11

12

15

16

Boilers (EP-321B-3):

41

42

Boilers (EP-321B-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

MW Custom Papers LLC – Chillicothe Mill4	OH	23,216	No.5 Coal Boiler -
wet bottom, pulverized coal-fired 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 coal-fired 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 coal-fired 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

Eastman Chemical Company5, 6	TN	22,882	Two fuel burning installations
(B-83-1 & B-253-1) 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
B-253-1 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 fired-cyclone
boiler	1	590 MMBTU/hr maximum heat input	SNCR (NOX)

ESP (PM)	Baghouse (PM)	Not BART eligible due to age

	Boiler 25 is a coal fired-tangential boiler	2	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

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 oil-fired boiler constructed in 1976	10	Boilers A
& B:  242 MMBTU/hr

Boiler C:

330 MMBTU/hr

Boiler D:

195 MMBTU/hr	Boilers A & B:  Multi-cyclone

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).

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

	#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 coal-fired
boiler	B101	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 coal-fired boiler	B102	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 coal-fired 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

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 In-Line
Heater	E21 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.

Great Northern Paper Inc. Mill West20, 21	ME	1,842	Power Boilers #4
(Riley-Stoker))	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

Sappi- Somerset20, 21	ME	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,   HYPERLINK
"mailto:John.Sipple@state.de.us"  John.Sipple@state.de.us ) via E-mail
on March 13, 2007.

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,   HYPERLINK
"mailto:mpcronin@gw.dec.state.ny.us"  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,   HYPERLINK
"mailto:mpcronin@gw.dec.state.ny.us"  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,   HYPERLINK
"mailto:bill.spires@epa.state.oh.us"  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,   HYPERLINK
"mailto:Julie.Aslinger@state.tn.us"  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,  
HYPERLINK "mailto:Julie.Aslinger@state.tn.us" 
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,   HYPERLINK "mailto:aheltibridle@mde.state.md.us" 
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,   HYPERLINK "mailto:aheltibridle@mde.state.md.us" 
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,   HYPERLINK "mailto:LCROWDER@wvdep.org" 
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,  
HYPERLINK "mailto:damcleod@deq.virginia.gov"  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,   HYPERLINK
"mailto:nherb@state.pa.us"  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,   HYPERLINK
"mailto:nherb@state.pa.us"  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,   HYPERLINK "mailto:Rob.Kaleel@illinois.gov" 
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,   HYPERLINK "mailto:Rob.Kaleel@illinois.gov" 
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,   HYPERLINK
"mailto:nherb@state.pa.us"  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,   HYPERLINK
"mailto:nherb@state.pa.us"  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,   HYPERLINK
"mailto:Ray.Papalski@dep.state.nj.us"  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,   HYPERLINK
"mailto:Ray.Papalski@dep.state.nj.us"  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,   HYPERLINK
"mailto:damcleod@deq.virginia.gov"  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,   HYPERLINK "mailto:Lynn.Ross@maine.gov" 
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,   HYPERLINK "mailto:Lynn.Ross@maine.gov" 
Lynn.Ross@maine.gov ) via E-mail on February 2, 2007.

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,   HYPERLINK "mailto:Tammy.Henry@state.de.us" 
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,
  HYPERLINK "mailto:Tammy.Henry@state.de.us"  Tammy.Henry@state.de.us )
via E-mail on March 5, 2007.



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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 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 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 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.

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 site-specific.	All Kilns	Depends on availability of low-sulfur
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)	SO2 is 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 Scrubber™ 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.

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-to-gas 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 flue-gas 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) 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

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.

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.

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

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:    HYPERLINK
"http://www.ladco.org/reports/rpo/Regional%20Air%20Quality/BART/Cement_B
ART_Engineering%20Analysis%20%2B%20Appendix%20A1.pdf" 
http://www.ladco.org/reports/rpo/Regional%20Air%20Quality/BART/Cement_BA
RT_Engineering%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 3½ 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 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 (  HYPERLINK
"http://www.secbd.org/prosmcldopr.html" 
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 (  HYPERLINK
"http://www.epa.gov/epaoswer/other/ckd/rtc/chap-4.pdf" 
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.

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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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.

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,
non-hazardous 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.

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,   HYPERLINK
"mailto:walkertr@michigan.gov"  walkertr@michigan.gov ) via E-mail on
February 7, 2007.



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HEATING OIL

BACKGROUND

Number 2 distillate fuel oil, heating oil, and diesel fuel oil are
essentially the same refinery-produced 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 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.

bSource 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   HYPERLINK "http://www.inflationdata.com" 
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 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.  
HYPERLINK "http://www.inflationdata.com"  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
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.

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 Distillate

Stocks

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

aSource 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

aSource 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
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 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.

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:    HYPERLINK "http://www.marathonpetroleum.com/" 
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:   HYPERLINK "http://www.redorbit.com" 
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:    HYPERLINK
"http://www.eia.doe.gov/oiaf/servicerpt/ulsd" 
www.eia.doe.gov/oiaf/servicerpt/ulsd 

US Energy Information Administration, 2007.  Information downloaded from
the World Wide Web on March 8, 2007.at:   HYPERLINK
"http://tonto.eia.doe.gov/dnav/pet/pet_pri_dist_dcu_R1X_m.htm" 
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.

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 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 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).

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.

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.



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.



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.4	2. Upgrade offset. 4

3. All new stove installations EPA-certified, 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.

	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, in-large 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).

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.

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.

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 Non-Catalytic

Cordwood

Stove	Certified

NSPS 

Catalytic

Cordwood Stove	Pellet

Stove	Gas

Stove-NG,

B Vent	Gas

Stove-NG,

Direct

Vent	Gas

Stove-LPG,

B Vent	Gas

Stove-LPG,

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.

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 Non-Catalytic

Cordwood

Stove	Certified

NSPS 

Catalytic

Cordwood Stove	Pellet

Stove	Gas

Stove-NG,

B Vent	Gas

Stove-NG,

Direct

Vent	Gas

Stove-LPG,

B Vent	Gas

Stove-LPG,

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 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 Log-LPG	Wax/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
Change-out/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).

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.

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.

This page left blank intentionally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 wood-fired 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 wood-fired 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
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).

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:    HYPERLINK
"http://www.vtwoodsmoke.org"  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 -
$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 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 wood-fired 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.

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:    HYPERLINK
"http://www.boston.com"  www.boston.com 

Michigan Department of Environmental Quality 2007.  Outdoor Wood Boiler
and Air Quality Factsheet.  Document obtained from the World Wide Web
at:    HYPERLINK "http://www.michigan.gov/deqair" 
www.michigan.gov/deqair  

NESCAUM, 2006.  Assessment of Outdoor Wood-fired Boilers.  Document
obtained from the World Wide Web at:    HYPERLINK
"http://burningissues.org/outdoor-wood-boilers.htm" 
http://burningissues.org/outdoor-wood-boilers.htm 

NESCAUM, 2007.  Outdoor Hydronic Heater Model Regulation.  Document
obtained from the World Wide Web at:    HYPERLINK
"http://burningissues.org/outdoor-wood-boilers.htm" 
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.

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:  HYPERLINK
"http://www.alpinehomeair.com"  www.alpinehomeair.com ;   HYPERLINK
"http://www.hud-son.com/woodfurnaces.htm" 
www.hud-son.com/woodfurnaces.htm ;   HYPERLINK
"http://www.woodmaster.com/web.htm"  www.woodmaster.com/web.htm 

Draft Final Assessment of Reasonable Progress for Regional Haze In the
Mid-Atlantic North Eastern Class I Areas

		Page   PAGE  ii 

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   PAGE  vii 

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-  PAGE  8 

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-
 PAGE  8 

Assessment of Reasonable Progress for Regional Haze In the Mid-Atlantic
North Eastern Class I Areas

Source Category Analysis:  Electric Generating Units		Page   PAGE  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 3:  Analysis of Selected Electric Generating Units (EGUs)	Page
3-  PAGE  3 

Technical Memorandum:  Methods for Evaluating Statutory Factors

February 6, 2007

Page   PAGE  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 3:  Analysis of Selected Electric Generating Units (EGUs)					
Page 3-  PAGE  5 

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-  PAGE  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

Chapter 3:  Analysis of Selected Electric Generating Units (EGUs)					
Page 3-  PAGE  14 

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-  PAGE  18 

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-  PAGE  20 

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-  PAGE  1 

Technical Memorandum:  Methods for Evaluating Statutory Factors

February 6, 2007

Page   PAGE  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 5:  Analysis of Selected Industrial, Commercial, and
Institutional Boilers	Page 5-  PAGE  1 

Technical Memorandum:  Methods for Evaluating Statutory Factors

February 6, 2007

Page   PAGE  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 5:  Analysis of Selected Industrial, Commercial, and
Institutional Boilers				Page 5-  PAGE  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

Chapter 6:  Source Category Analysis: Kilns		Page 6-  PAGE  5 

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-  PAGE  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-  PAGE  3 

 PAGE   

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-  PAGE  8 

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-  PAGE  11 

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 10:  Residential Wood Combustion – Outdoor Wood-Fired Boilers
Page 10-  PAGE  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

Chapter 10:  Open Burning		Page 10-  PAGE  7 

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 Boilers-

Industrial (7%)

Stationary Source Fuel Combustion-

Residential (6%)

Stationary Source Fuel Combustion-

Commercial/Institutional (4%)

Stationary Source Fuel Combustion-

Industrial (3%)

Industrial Processes-Mineral

Products (2%)

Highway Vehicles-Gasoline (1%)

Marine Vessels, Commercial (1%)

Off-highway Vehicle Diesel (1%)

External Combustion Boilers-

Commercial/Institutional (1%)

Tons/Year

On-Road

Non-Road

Point

Area

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