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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<PHONE_NUMBER>,   HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<PHONE_NUMBER><EMAIL_ADDRESS>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<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<PHONE_NUMBER>,
HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<PHONE_NUMBER> Ext. 1247,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<PHONE_NUMBER>,   HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<PHONE_NUMBER>,   HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<PHONE_NUMBER>,   HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>)
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<PHONE_NUMBER>,
HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>) via
E-mail on February 9, 2007.

18	Allegheny County Health Department.  Personal communications
regarding Cheswick facility from Ms. Jayme Graham<PHONE_NUMBER>,
HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<EMAIL_ADDRESS><EMAIL_ADDRESS>) 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<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>)
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<PHONE_NUMBER>,   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>)
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