Connecticut Regional Haze State Implementation Plan November 2009



### ATTACHMENT Y

Assessment of Reasonable Progress for Regional Haze

In MANE-VU Class I AreasThis page left blank intentionally.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page i



### Table of Contents

Chapter Page

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

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

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

Background ..................................................................................................................... .. 1-1
Determination of Emission Source Categories and Individual Sources Most Responsible for Regional Haze in MANE-VU Class I Areas ............................................................... 1-2
Approach to Demonstrating Reasonable Progress ............................................................ 1-6

References .................................................................................................................... ..... 1-8
2 Source Category Analysis: Electric Generating Units (EGUs).................................. 2-1

Source Category Description............................................................................................. 2-1
Evaluation of Control Options .......................................................................................... 2-2
Four Factor Analysis of Potent ial Control Scenarios for EGUs ....................................... 2-6

References .................................................................................................................... ... 2-16
3 Analysis of Selected Electri c 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 - Illust rative Scrubber Costs (1999 $) for Representative MW and Heat Rates under the Assumptions in EPA Base Case 2004 .......................................... 3-19
EGU Attachment 2 - Engineering Methodol ogy 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, Co mmercial, 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 SO 2 

### Emission Control Options ................................................................... 6-3
Four Factor Analysis of Potentia l Control Scenarios for Kilns......................................... 6-9

References .................................................................................................................... ... 6-13Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page ii



### Table of Contents – continued

Chapter Page

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

Source Category Description............................................................................................. 7-1
Information Obtained from State Agencies....................................................................... 7-1

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

Background .................................................................................................................... ... 8-1
Four Factor Analysis of Potential Contro l 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 .................................................................................................................... ... 10-6Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page iii



### Table of Contents – continued

Table Page

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

Table 2.1 SO 2 

### Control Options for Coal-fired EGU Boilers ...................................................... 2-3
Table 2.2 Marginal Costs of Em ission Reductions (Allowance Pric es) Calculated by Integrated Planning Model (IPM ® 

### ) for the CAIR Base Case and CA IR Plus Runs (2006 $/ton) ..... 2-7

Table 2.3 NO X 

### and SO 2 

### 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 Subbitu minous Coal Prices (2006 dollars/ton).......... 2-9
Table 2.6 Estimated Cost Ranges for SO 2 

### Control Options for Coal-fired EGU Boilers (2006 dollars/ton of SO 2 

### Reduced) ................................................................................. 2-13
Table 3.1 Integrated Planning Model (IPM ® 

### version 2.1.9) CAIR Pl us Results for the Top 30 EGUs Responsible for Visibility Im pairment 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 Pred icted 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 SO 2 

### Control Options for ICI Boilers.......................................................... 4-5

Table 4.2 Potential SO 2 

### 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 Impairme nt in MANE-VU Class I Areas................................ 5-2

Table 6.1 SO 2 

### Control Technologies for Cement Kilns ............................................................. 6-5

Table 6.2 SO 2 

### Control Costs for AFGD Applied to Dry Kilns and Preheater Kilns (2006 dollars) ................................................................................................................. . 6-10

Table 6.3 SO 2 

### Control Costs for Wet FGD Applied to Dry Kilns and Preheater Kilns (2006 dollars) ................................................................................................................. . 6-10

Table 6.4 SO 2 

### 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 (ULS D) Desulfurization Technology Costs for

Individual Refineries ......................................................................................................... 8 -2
Table 8.3 Average January 2007 Distilla te Stocks (Million Barrels)......................................... 8-5

Table 8.4 Distillate Prod uction and Imports (Milli on Barrels per Day)..................................... 8-5
Table 9.1 Summary of Measures Available for RWC RACM – PM 10 

### ....................................... 9-5
Table 9.2 Summary of Measures Available for RWC BACM – PM 10 

### ....................................... 9-7Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page iv



### Table of Contents – continued

Table Page

Table 9.3 Improved Technologies and Fuel Alternatives......................................................... 9-10
Table 9.4 PM Reduction Cost Effectiveness for Replacement of Existing Uncertified Freestanding Cordwood Stove/Insert and Cordwood Fireplace w/o Insert for Heating ........................................................................................................................ .... 9-11
Table 9.5 VOC Reduction Cost Effectiveness for Replacement of Existing Uncertified Freestanding Cordwood Stove/Insert and Cordwood Fireplace w/o Insert for Heating ........................................................................................................................ .... 9-12
Table 9.6 Reduction Cost Effectiveness for the Replacement of an Existing Centralized Cordwood Heating System.............................................................................................. 9-12

Table 9.7 Pollutant Reduction Cost Effectivenes s for the Addition of a Gas Log Set or Use of Wax/Fiber Firelogs in an Existing Firepl ace w/o Insert Used for Aesthetics................. 9-13

Figure Page

Figure 1.1 Contributions to PM 2.5 

### Mass at 7 Sites - 20% Worst Visibility Days (2000-2004).................................................................................................................... ... 1-2
Figure 1.2 MANE-VU 2002 Version 3 A nnual Emissions Inventory Top PM 2.5 

### -Primary Source Categories..................................................................................................................... ..... 1-3
Figure 1.3 MANE-VU 2002 Version 3 A nnual Emissions Inventory Top SO 2 

### Source Categories..................................................................................................................... ..... 1-4
Figure 3.1 EGU Facilities with th e Greatest Visibility Impacts in Mid-Atlantic North Eastern

Class I Areas.................................................................................................................. .... 3-2
Figure 6.1 Portland Cement Pr ocess Flow Diagram................................................................... 6-1
Figure 6.2 Advanced Flue Gas De sulfurization Process Flow ................................................... 6-7Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page v



### List of Acronyms

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

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

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

BLM ........................................................................................................................... .....................Bureau of La nd Management

BTU ........................................................................................................................... .................................. British Th ermal Unit

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

CAIR .......................................................................................................................... .............................Clean Air Inte rstate Rule

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

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

CO 2

.............................................................................................................................. .........................................carbon di oxide

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 ........................................................................................................................... ..............................................kilowa tt-hour

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

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

LNB ........................................................................................................................... ........................................Low NO X Burner

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

LSFO .......................................................................................................................... .......................Limestone Forced OxidationAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page vi



### List of Acronyms - continued

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

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

MARAMA....................................................................................................... Mid-A tlantic Regio nal 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

NO X

.............................................................................................................................. ........................................nitrogen oxides

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

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

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

OFA ........................................................................................................................... .............................................. Over-fi re Air

PADD .....................................................................................................................Petro leum Administration for Defense District

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

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

PM 2.5 ..................................................................................................... Particulate Matter with d iameter 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 Classi fication Code

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

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

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

SO 2

.............................................................................................................................. .......................................... sulfur dioxide

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

ULSD .......................................................................................................................... .............................. Ultra Low Sulfur DieselAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page vii



### EXECUTIVE SUMMARY

The Regional Haze regulations set forth under 40 CFR 51.308(d)(1) require States to achieve reasonable progress toward natural visibility conditions. The national visibili ty 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 visibili ty...”, 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 th e uniform rate of progress at any future year until natural conditions are achieved. RP Gs are to be established for the final year in the planning period, which in th e case of the fi rst SIP is 2018.

Following draft guidance from EPA in establishing RPGs, States must set a baseline from which reasonable progress towards visibility improveme nt 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 impair ment 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 visi bility impairment at each Class I area, a contribution assessment was prepared by NESCAUM for MANE-VU. Major contributors were identified by ranki ng emissions sources, comparing Q/d (emission impact over distance), and modeli ng visibility impacts. Source apportionment and other analyses

documented in MANE-VU’s contribution assessment showed that several s ource categories have impacts on visibility at MANE-VU Class I areas.

The largest contribution to visibility impairme nt at most sites was from burning of coal, primarily utility and industrial combustion source s 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 cont ribute. 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 sour ce 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 analys is of the economic and en vironmental 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 towa rd 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 addres s reasonable progress goals. Control technologies to achieve reasonable prog ress goals are evaluated with respect to four factors listed in the Clean Air Act (Section 169A):Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page viii

• 

### Cost,

• 

### Compliance timeframe,

• 

### Energy and non-air quality environmental impacts, and

• 

### Remaining useful life for affected sources.

The “four factor” analysis was applied to control options iden tified 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 technologi es assessed in this effort is presented in the main body of this document.

Table I Summary of Results fr om 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 SO 2 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 SO 2 $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 SO 2 $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 SO 2 $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 sour ces identified by MANE-VU to consider control strategies already in place or planned by 2018.Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 1: Introduction Page 1-1



### CHAPTER 1

INTRODUCTION

BACKGROUND

The Regional Haze regulations set forth under 40 CFR 51.308(d)(1) require States to achieve reasonable progress toward natural visibility conditions. The national visibili ty 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 visibili ty...”, 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 th e uniform rate of progress at any future year until natural conditions are achieved. RP Gs are to be established for the final year in the planning period, which in th e case of the fi rst SIP is 2018.

Following draft guidance from EPA in establishing RPGs, States must set a baseline from which reasonable progress towards visibility improveme nt 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 impair ment 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 volunt ary programs that will assist in the reduction of fine part icle pollution are as follows:

• 

### Clean Air Interstate Rule (CAIR)

• 

### The Acid Rain Program

• 

### NO X 

### SIP Call

• 

### 2004 Clean Air Nonroad Diesel Rule

• 

### 2007 Clean Diesel Trucks and Buses Rule

• 

### Tier 2 Vehicle Emission Standard s and Gasoline Sulfur Program

• 

### Emission standards for other engine s (highway and non-highway use)

• 

### National Clean Diesel Campaign

• 

### The Great American Woodstove Changeout

More information and links to the programs lis ted above can be found on the following website: http://www.epa.gov/pm/reducing.htmlAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 1: Introduction Page 1-2



### DETERMINATION OF EMISSION SO URCE CATEGORIES AND INDIVIDUAL

SOURCES MOST RESPONSIBLE FOR REGI ONAL HAZE IN MANE-VU CLASS I

AREAS

Particles in the PM 2.5 

### size range are directly responsible for visibility reduction. Figure 1.1 generated by NESCAUM from analysis of monitoring data shows the components of PM 2.5 

### mass at the seven Class I areas of c oncern on the 20% worst visibility days during the period from 2000-2004. These components of PM 2.5 

### are directly responsible for visibility reduction.

Figure 1.1



### Contributions to PM 2.5 

### Mass at 7 Sites

20% Worst Visibility Days (2000-2004)

# # # #

# #

#

Dolly Sods

Shenandoah Brigantine Lye Brook Great Gulf Acadia Moosehorn

0 5 10 15 20 Soil

Sea Salt

OC

EC

Nitrate

SulfateMass (ug/m3)

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



### From Figure 1.1, it is appare nt that sulfate is the largest contributor to PM 2.5 

### mass at the Class I

areas of concern. The sec ond largest contributor to PM 2.5 

### mass is organic carbon (OC). Nitrates, elemental carbon (EC), soil, and sea salt also contribute to PM 2.5 

### mass.

Source apportionment and other analyses documented in MANE -VU’s contribution assessment indicated that a number of source categories ha ve impacts on visibility at MANE-VU Class I areas. The largest contribution to visibi lity impairment at most sites was SO 2 

### from coalcombustion, primarily utility and industrial sources in MANE-VU a nd nearby States. At forested rural sites, biogenic or ganics are a moderate to large c ontributor to visibility impairment but other sources of secondary organics also contribute. W ood smoke and ammonium nitrate

were identified as small to moderate cont ributors (see Appendix B of the Contribution Assessment).Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 1: Introduction Page 1-3



### The contribution assessment also included an anal ysis of haze-associated pollutant emissions.

“SO 2 

### is the primary precursor polluta nt for sulfate particles. Su lfate particles commonly account for more than fifty percent of particle light extin ction at northeastern Class I areas on the clearest days and for as much as or more than eighty pe rcent on the haziest days.” The assessment noted that point sources dominate SO 2 

### emissions in the MANE-VU re gion. Point source emissions sources primarily consist of stationary combusti on sources for generating electricity, industrial power, and heat. Commercial and residential heating constit ute 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 SO 2 

### sources in the region.

Figures 1.2 and 1.3 show the top em issions source categories of PM 2.5 

### and SO 2 

### from Version 3

of the 2002 MANE-VU emissions inventory. The largest SO 2 

### source categories are the largest contributors to visibility impairment in MANE-VU.

Figure 1.2 MANE-VU 2002 Version 3 Annual Emissions Inventory Top PM 2.5 

### Primary Source Categories

0 20,000 40,000 60,000 80, 000 100,000 120,000 140,000 Stationary Source Fuel Combustion-Residential (28%) Unpaved Roads (10%) Paved Roads (8%) Open Burning-Waste Disposal, Treatment, and Recovery (5%) Industrial Processes-Construction: SIC 15-17 (5%) Stationary Source Fuel Combustion-Industrial (5%) External Combustion Boilers-Electric Generation (4%) Off-highway Vehicle Diesel (4%) Miscellaneous Area Sources-Agricultural Production-Crops (3%)

Industrial Processes-Food and Kindred Products: SIC 20 (3%) Highway Vehicles-Diesel (3%) External Combustion Boilers-Industrial (2%) Stationary Source Fuel Combusti on-Commercial/Institutional (2%) Highway Vehicles-Gasoline (2%) Industrial Processes-Mining and Quarrying: SIC 14 (2%) Industrial Processes-Mineral Products (2%)

Tons/Yea r On-Road

Non-Road

Point

A reaAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 1: Introduction Page 1-4



### Figure 1.3 MANE-VU 2002 Version 3 Annual Emissions Inventory Top SO 2 

### 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 gr eatest impact on regional haze in MANE-VU Class I areas. The individual sources included in this report (s ee Chapters 3, 5, and 7) were determined by identifying the sources with the maximu m predicted 24-hour sulfate ion impact.

From 2004 to 2006, the Vermont Department of Environmental Conservation (VTDEC) participated in MANE-VU RP O planning activities by perfor ming 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 CALP UFF model run on a domain including most of the eastern United States. Both point and ar ea 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 us ed in conjunction with other source/receptor modeling methods as part of the t echnical underpinning of the document, Contributions to Regional Haze in the Northeast and Mid-Atlant ic 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 va lidation. It can be found at the following link: http://www.manevu.org/Document.asp?fview=Reports# 0 200,000 400,000 600,000 800,000 1, 000,000 1,200,000 1,400, 000 1,600,000 1,800,000 External Combustion Boilers-Electric Generation (70%)External Combustion BoilersIndustrial (7%)Stationary Source Fuel CombustionResidential (6%)Stationary Source Fuel CombustionCommercial/Institutional (4%)Stationary Source Fuel CombustionIndustrial (3%) Industrial Processes-Mineral Products (2%) Highway Vehicles-Gasoline (1%) Marine Vessels, Commercial (1%)

Off-highway Vehicle Diesel (1%)

External Combustion BoilersCommercial/Institutional (1%)

Tons/Yea r On-Road

Non-Road

Point

A reaAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 1: Introduction Page 1-5



### Starting in 2006, through its participation on two MANE-VU RPO workgroups, (the BART Workgroup and the Reasonable Progress Workgr oup), 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 perfor med new point source modeling with the same CALPU FF modeling platform for a number of additional large point sources identified by the workgr oups, primarily non-EGUs. The new point source modeling was performed for sources that di d not have CEMS hourly emission data. This new modeling performed specifically for the workgroups differe d 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 poi nt source modeling performed with CALPUFF by VTDEC for the BART and Reasonable Progress Workgroups utilized a constant average hourly emission rate (annual t ons/8760) for the year 2002 based on emissions provided by the

individual States in which the sources were loca ted. 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 CA LMET created wind-fields, were exactly the same as used in the contribution assessment modeling work.

For the Reasonable Progress Workgroup, VTDEC asse mbled the results of its earlier individual CEMS-based stack modeling of EGUs into tabl es which listed the maximum 24-hr (calendar day) sulfate ion impact predicte d at any receptor in each Class I area due to the emissions from each individual EGU modeled (more than 750). Because the largest cont ributing pollutant to visibility impairment in all the MANE-VU Cl ass I areas is the sulfate ion, the Reasonable Progress Workgroup felt that ranking point s ources based on this maximum 24-hour impact alone would be an appropriate wa y to prioritize their relative pot ential 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 sm allest 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 SO 2 

### located both within MANE-VU and external to MANE-VU, the Reasona ble 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 c onstant annual average emission

rate of SO 2 

### only. VTDEC converted the annual total tons of SO 2 

### 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 thr ee lists supplied by Delaware. Th e 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 (lis t 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 se lection criteria based on SCC code s (list 3) and ranked by annual

SO 2 

### emissions.

The maximum predicted 24-hour sulfate ion im pact from each of the 194 non-EGUs modeled were combined into an ordered table showing th e 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 createdAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 1: Introduction Page 1-6



### showing the annual average sulf ate 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 SO 2 

### emissions from the CEMS data submitted by the sources themselves. For the EGUs, the modeled stack ID for which the hourly SO 2 

### emission was reported might be a single electric generating unit or it might be a combination of tw o 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 combinat ion of several at a plant. Therefore, to identify which particular unit at a plant repor ting 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 imp act is from the stack and the distribution among

units combined in that stack’s CEMs data ca nnot 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 emi ssion 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 m odeled with each individual annual average emission rate supplied from one of the thre e 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 analys is of the economic and en vironmental impacts of potential control scenarios that could be im plemented by MANE-VU States to demonstrate reasonable progress toward meeting visibility im provement goals. The purpose of this analysis is to present information that can be used by St ates to develop policies and implementation plans to address reasonable progress goals. Control te chnologies to achieve re asonable progress goals are evaluated with respect to four factor s listed in the Clean Air Act (Section 169A):

• 

### Cost,

• 

### Compliance timeframe,

• 

### Energy and non-air quality environmental impacts, and

• 

### Remaining useful life for affected sources.Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 1: Introduction Page 1-7



### The “four factor” analysis is applied to control options iden tified for the selected source categories. The analysis of cement kilns and lim e kilns was combined into one section due to the similarity of the two sources.

Category analyses are presented for electric gene rating units (EGUs), industrial, commercial, and institutional (ICI) boilers, cement kilns, lime k ilns, distillate-oil fired heating units, and

residential wood combustion. Only sulfur dioxide (SO 2 

### ) emissions are considered for the first five categories. The SO 2 

### emitted from sources in these five source categories comprised approximately 90% of all SO 2 

### emitted from within MANE-VU in 2002. For residential wood combustion, the analysis is presented for particulate matter. PM 2.5 

### emissions from this source

were 28% of the total PM 2.5 

### emitted from within MANE-VU in 2002. Biomass burning causes both direct emissions of primary particles a nd emissions of volatile organics which can contribute to the formation of secondary organi c carbon particles. Orga nic carbon is typically the second-largest contributor to regional haze in the MANE-VU region.

For EGUs, ICI boilers, and kilns control opti ons include fuel switc hing, 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 on e category. For oil-fired heating oil, the only control option considered is reduc tion in sulfur content in the fu el oil. For residential wood combustion and outdoor wood-fired boilers, we ha ve included descriptio ns of alternative technologies for replacement and emission reduction.

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

30 EGU sources based on information from St ate agencies and Integrated Planning Model (IPM ® 

### ). The purpose of selecting th ese sources is to find out whet her 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 s upplied a schedule of planned controls for these facilities, which we have included in tabular fo rm in this report. In the case of EGUs, we

obtained information from the States and from modeled projections deve loped using Integrated Planning Model (IPM ® 

### ).Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 1: Introduction Page 1-8



### REFERENCES

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

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

Vermont Air Quality Planning. Personal communi cations regarding descri ption of the source identification and modeling process from Paul Wishinski (802-241-3862, paul.wishinski@state.vt.us ) via E-mail on April 4, 2007.

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

States . Prepared by NESCAUM for MANE-VU, August, 2006.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-1



### CHAPTER 2

SOURCE CATEGORY ANALYSIS: ELECTR IC 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 Clas s I areas affected by emissions from sources

within MANE-VU is SO 2 

### from EGUs. Roughly 70% of the 2.3 million tons of SO 2 

### emissions in the 2002 emissions inventory ( 2002 MANE-VU Emissions Inventor y Version 3) were from EGUs, making them the largest source category c ontributing to regional haze in terms of total visibility impairing emissions and in terms of number of facilities.

Boilers at EGUs burn various fu els to produce heat for steam pr oduction which is then used to drive turbine generators for elect ricity 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 SO 2 

### from

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

of <1%.

Nationally, 90% of the SO 2 

### emissions from the EGUs are from coal-fired electric utility boilers. These coal-fired utility boilers ar e also the largest sources of NO X 

### and PM emissions, which also contribute to regional haze. All coal-fired electri c utility power plants in the United States use

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

controls for SO 2 

### or NO X 

### emissions depending on site-specific factors such as the properties of the coal burned, when the power plant was built, a nd the area where the power plant is located. According to the EPA Clean Air Markets Divi sion, (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 SO 2 

### and/or NO X 

### control devices (as a percentage of heat input), were as follows:

2% of coal-fired EGU capacity had SO 2 

### control only; 57% of coal-fired EGU capacity had NO X 

### control only; 32% of coal-fired EGU capacity had SO 2 

### and NO X 

### controls; 9% of coal-fired EGU capacity had no SO 2 

### or NO X 

### controls.

As 66% of coal-fired EGU capacity, (as a percentage of heat input), have no SO 2 

### controls, there is room for significant reductions in emissions of SO 2 

### . There is currently a trend towards improving control of SO 2 

### through installation of additional controls and making other process and fuel changes. The four factor analysis of potential control scenario s for EGUs contained in this chapter addresses the cont rol options and costs, time re quirements, energy and non-air impacts, and source life associated with these controls.

Although PM and NO X 

### from coal-fired utility boilers cont ribute to regional haze, the MANE-VU contribution assessment conducted by NESCAUM determined that SO 2 

### from power plants was the largest contributor to regional haze in the M ANE-VU Class I areas. Therefore, the focus of this control option analysis for coal-fired boilers is on SO 2 

### controls. Effects of the SO 2 

### controlAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-2



### options on PM and NO X 

### emissions are addressed where appli cable, 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 uni ts. Emissions of SO 2 

### from natural gas combus tion are negligible, but SO 2 

### emissions from fuel oil combustion are directly proportional to the sulfur content of the fuel. The cost of switching from a high sulfur distillate fu el oil to a lower sulfur distillate fuel oil is addressed in Chapter 8 of this report.

The SCCs applicable to coal -fired utility boilers incl ude SCCs beginning 1-01-001-XX, 1-01-002-XX, and 1-01-003-XX.

EVALUATION OF CONTROL OPTIONS

Effective post-combustion SO 2 

### controls for EGUs and particul arly coal-fired boilers are well understood and have been applied to a large numb er of sources over the years in response to regulations in the form of NSPS, PSD/NSR, St ate RACT Rules and the Title IV Acid Rain Program. Additional SO 2 

### 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 SO 2 

### from coal-fired boilers, there are other strategies that can be used to reduce emissions of SO 2



### . Examples of such strategies include switching to a fuel with a lower sulfur content, and coal cleaning prior to combustion. Methods of SO 2 

### control applicable to co al-fired boilers are listed

in Table 2.1 with a brief desc ription of the control option, applicability, and range of performance. A more detailed description of the control option and an analys is of the four factor assessment for reasonable progress follow the table.

MACTEC assembled the list of available SO 2 

### control options for the EGU source category given

in Table 2.1 from available documentation. Note th at the estimated perfor mance of each control option varies greatly and depends on a variety of site specific factors, in cluding 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 th eir specific design. Control devices designed for these types of boilers vary in terms of cost as well as estimated performance.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-3



### Table 2.1 SO 2 

### 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 SO 2 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 SO 2 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 SO 2 emissions

Flue Gas Desulfurization (FGD) - Wet SO 2 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 SO 2 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 SO 2 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 SO 2 emissions

Table references:

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

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

2006.



### Switch to Low Sulfur Coal

Fuel switching encompasses several different co ntrol options. Often it is not possible to completely switch from one type of fuel to anot her. One option is blending lower-polluting fuels

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

blend lower sulfur subbituminous coals with high sulfur bituminous coals to reduce SO 2 

### 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 difficu lty, but switching from bituminous to subbituminous coal may present great er 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 co al handling systems, boiler performance, PM

control effectiveness and ash handlin g systems. In any case, fuel switching or blending has beenAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-4



### a key strategy used by EGUs to comply with the federal Acid Rain Program. Overall SO 2 

### 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 SO 2 

### emissions, but it is currently uneconomical to consider this option fo r 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 natura l gas over the past severa l years has been several times higher than coal. According to informa tion published on the EIA website, in January 2007 the price of natural gas was a pproximately four times higher than coal according to average monthly costs of fuel delivered to el ectricity producers during that month.

Coal Cleaning

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

Particulate Matter Under the Cl ean Air Act: A Menu of Options , coal cleaning or washing is a widely practiced method of reducing impurities in co al, particularly sulfur. Reducing the sulfur

content of the fuel used in the boiler reduces the SO 2 

### emissions proportiona lly. Coal cleaning

has been shown to reduce SO 2 

### emissions by 20-25%, while incr easing the heating value of the

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

no detailed information on thes e techniques was available.

Conventional (physical) coal wash ing techniques remove ash and sulfur from coal by crushing the fuel and separating the components in a liquid ba th, 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 inorga nic sulfur in coal called pyrite is primarily in the form of ferrous sulfate (FeSO 4 

### ). 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 a nd cannot be physically washed out. Organic sulfur accounts for between 35-75% of the total sulfur in Illin ois 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 pyr ite, varying amounts of th e total sulfur can be

removed.

Although there are benefits associat ed with coal washing, there ar e limitations associated with this technology. The 20-25% SO 2 

### reduction is beneficial, but post-combustion controls have

been shown to reduce SO 2 

### emissions by greater percentages. Also, solid and liquid wastes are generated using the washing pr ocess 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 cont rol technologies titled Controlling Particulate Matter Under the Clean Air Act: A Menu of Options , EPA reports that 85% of the FGD systems in theAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-5



### United States are wet systems. Twelve percent of the FGD systems are spray dry systems, and 3% are dry systems. The operating parameters, impacts on capacity factor, and costs of each

SO 2 

### removal method are different. Capacity factor is the amount of energy a facility generates in one year divided by the total amount it co uld generate if it ran at full capacity.

SO 2 

### 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 sy stem designs (e.g., sodium carbonate, magnesium oxide, dual alkali) are used by a small per centage of the total number of boilers.

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

of SO 2 

### emissions from coal-fired electric utility boilers. Limestone sorbent is inexpensive and generally available thro ughout the United States. In a wet limestone scrubber, the flue gas containing SO 2 

### is brought into contact with limestone/water slurry. The SO 2 

### is absorbed into the slurry and reacts with limestone to form an in soluble sludge. The sludge, mostly calcium sulfite hemihydrate and gypsum, is disposed of in a pond sp ecifically 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 SO 2 

### from

coal-fired boilers that are 100 MW or larger, that combust bitu minous coal with 2% or higher sulfur content by weight. In tegrated Planning Model (IPM ® 

### ) documentation refers to the specific scrubber technology as Limestone Forced Oxidation, (LSFO), and assumes 95% SO 2 

### removal using this technology. Data and documentati on 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 SO 2 

### is contacted with hydrated lime/water slurry; the SO 2 

### is absorbed into the slurry and r eacts with hydrated lime to form an insoluble sludge. The hydrated lime provides greater alkalinity (higher pH) a nd reactivity than limestone. However, limescrubbing processes require disposal of large quan tities of waste sludge.

Another wet scrubber technology used to control emissions of SO 2 

### from EGUs is Magnesium Enhanced Lime, (MEL). This technology is av ailable 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% SO 2 

### removal.

The SO 2 

### removal efficiencies of existing wet lime stone scrubbers range from 31-97%, with an average of 78%. The SO 2 

### removal efficiencies of existing wet lime scrubbers range from 30 to 95%. For both types of wet scrubbe rs, operating parameters affecting SO 2 

### removal efficiency include liquid-to-gas ratio, pH of the scrubbing medium, and the ratio of calcium sorbent to SO 2



### . Periodic maintenance is needed because of scaling, erosion, and plugging problems. Recent advancements include the use of additives or design changes to promote SO 2 

### absorption or to reduce scaling and precipitation problems.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-6



### Flue Gas Desulfurization (FGD) – Spray Dry

A spray dryer absorber (sometimes referred to as wet-dry or semi-dry scrubber) operates by the same principle as wet lime scrubbing, except that th e flue gas is contacted with a fine mist of lime slurry instead of a bulk liquid (as in wet sc rubbing). For the spray dr yer absorber process, the combustion gas containing SO 2 

### is contacted with fine spray droplets of hydrated lime slurry in a spray dryer vessel. This ve ssel 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 SO 2 

### is absorbed in the slurry and reacts with the hydrated lime reagent to form solid calcium sulfite an d calcium sulfate sludge

as in a wet lime scrubber. The water is eva porated by the hot flue gas and forms dry, solid particles containing the reacted sulf ur. These particles are entrained in the flue gas, along with fly ash, and are collected in a PM collection device. Most of the SO 2 

### removal occurs in the spray dryer vessel itself, although some additional SO 2 

### capture has also been observed in downstream particulate collection devices, esp ecially fabric filters. This pr ocess produces dry reaction waste products for easy disposal.

The primary operating parameters affecting SO 2 

### removal are the calcium-reagent-to-sulfur stoichiometric ratio and the appro ach to saturation in the spray dr yer. To increase overall sorbent use, the solids collected in th e spray dryer and the PM collection device may be recycled. The

SO 2 

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

Lime Spray Drying (LSD) is a dry SO 2 

### 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 c ontent between 0.4% and 2% sulfur by weight. Integrated Planning Model (IPM ® 

### ) assumes that LSD provides 90% SO 2 

### 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 SO 2 

### is adsorbed and reacts with the powdered sorbent. The dry solids are entrained in the combustion gas stream, alon g with fly ash, and collected by the PM control

device. The SO 2 

### 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 presen ted in Table 2.1 is evaluated in this section according to the four factors for determining reas onable progress as required by Section 169A(g)(1) of the Clean Air Act and 40 CFR 51.308(d)(1)(i)(A). The informa tion provided in this section is intended to be used by the States in setting Reasonable Pr ogress Goals for reducing regional haze in the

MANE-VU Class I areas.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-7



### Cost of Compliance

For EGUs, EPA used Integrated Planning Model (IPM ® 

### ) to predict which units will install

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

### ) predicts a least-cost solution to meet power pr oduction 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” stra tegy using Integrated Planning Model (IPM ® 

### ). In Chapter 3, the parsed results (pro jections disaggregated to the un it level), available for the CAIR Plus strategy are used to help estimate costs for sp ecific EGUs. It should be noted that Integrated Planning Model (IPM ® 

### ) is an industry-wide model, and th e control costs output from the model represent the industry-wide averag e cost of control that can be expected based on a set industrywide emission reduction. In tegrated Planning Model (IPM ® 

### ) results can also be viewed as the predicted cost of contro l at a model plant. The costs of c ontrol at individual facilities are dependent on a number of factors and cannot be de termined for any specific individual facility from Integrated Planning Model (IPM ® 

### ) results.

Table 2.2 contains the marginal costs of SO 2 

### emission reductions, also known as the SO 2 

### 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 operati on 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 SO 2 

### reduction while meeting the demand for electricity. Integrated Planning Model (IPM ® 

### ) also installed NO X 

### controls, but the cost of achieving the NO X 

### emissions reductions was provided independently from SO 2 

### controls. Application of SO 2 

### controls such as use of cleaner and lower-sulfur coals or pos t combustion controls such as wet scrubbers generally help to reduce PM emissions in addition to SO 2 

### . SO 2 

### controls generally do not affect

PM or NO X 

### emissions.

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

Integrated Planning Model (IPM ® 

### ) for the CAIR Base Case and CAIR Plus Runs (2006 $/ton)

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

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

SO 2 774 837 905 979 1,141 1,338 975 1,055 1,139 1,233 1,437 1,684

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

ICF Resources ; May 30, 2007.

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

www.inflationdata.com



### The CAIR Plus strategy requires additional SO 2 

### and NO X 

### control beyond EPA’s CAIR program. ICF’s report on the CAIR and CAIR Pl us Integrated Planning Model (IPM ® 

### ) runs titled: Final Draft Report - Comparison of CAIR and CAIR Pl us Proposal Using the Integrated PlanningAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-8



### Model (IPM ® 

### ) , states that the power sector opts for a technology strategy fo r complying with the CAIR Plus proposal requirements. In the CAIR Plus analysis, th e 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 sc rubbers and 185% increase in S CRs in 2012 compared to the Integrated Planning Model (IPM ® 

### ) CAIR run. By 2018, the cumula tive installation of scrubbers is 17% higher and the installati on of SCR is 98% higher for the CAIR Plus run compared to the CAIR run. The resulting SO 2 

### and NO X 

### emissions from the CAIR and CAIR Plus Integrated Planning Model (IPM ® 

### ) runs are listed for MANE-VU in Table 2.3.

Table 2.3 NO X 

### and SO 2 

### Emissions from the Electric Power Sector (Thousand Tons)

2008

SO 2 | NO X 2009

SO 2 | NO X 2010

SO 2 | NO X 2012

SO 2 | NO X 2015

SO 2 | NO X 2018

SO 2 | NO X

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

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

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

ICF Resources ; May 30, 2007.



### Cost of Switching to Low Sulfur Coal

Switching to a low-sulfur coal or blending a lower sulfur coal can impact cost due to the following two main reasons:

1. The cost of low-sulfur coal co mpared to higher sulfur coal

2. The cost of necessary boiler or co al handling equipment modifications

The cost of low-sulfur coal compared to higher su lfur coal is not only related to the “dollar per ton” cost of the coal, but also rela ted to the heating value of the coal.

Recent data from the Energy Information Administ ration show the average price of coals from various locations together with es timated 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 approximat ely the same, with the exception of coal from the Powder River Basin. Powder River Basin coal has a significantly lower heating value than the othe r 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 w ould be the best fuel for boilers trying to incorporate a lower sulfur coal. Unfo rtunately, 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 Ba sin coal would be to ex tensively retrofit the boilers or suffer from poor boiler performance a nd other operating difficulties. Such retrofits should be reviewed in light of current Preven tion of Significant Deteri oration (PSD) permittingAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-9



### regulations to ensure that all such requirements are met and that emissions do not increase. The coal prices included in Table 2.4 do not reflect the cost of boiler retrofits required to combust

low sulfur coal.

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

Central Appalachia (Bituminous) Northern Appalachia (Bituminous) Illinois Basin (Bituminous) Powder River

Basin (Subbituminous) Uinta Basin (Low-S Bituminous)

Coal Heating Value (BTU/lb) 12,500 13,000 11,000 8,800 11,700

Sulfur Content (%) 1.2 <3 5 0.8 0.8

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

Table reference:

EIA website accessed on 2/20/07: http://www.eia.doe.gov/cneaf/coa l/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 varyi ng amounts of sulfur, but the sulfur content of bituminous coal is generally higher than subbitt uminous 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 thei r 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 co al on an energy basis. The co al prices included in Table 2.5 do

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

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

Fuel Average Price per Ton Average Price per MMBTU

Bituminous Coal $38.00 $1.58

Subbituminous Coal $8.96 $0.44

Table reference:

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

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

www.inflationdata.com



### Switching to subbituminous coal can reduce SO 2 

### emissions by up to 80%, but changes must be made to the boilers to compensate for the lowe r heating value of the subbituminous coal. Much of the difference in fuel price is due to the difficulty in using subbituminous coal in boilersAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-10



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

Fine Particulate Matter Under the Clean Air Act , states that “fuel substitution is not feasible for sources where the substitution would require exce ssive 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, th e cleaning process use d, 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 tr ansportation 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 info rmation provided by the World Bank.

Cost of Flue Gas Desulfurization (FGD) – Wet

The cost of flue gas desulfurization varies depe nding on a number of fact ors including the size of the boiler, SO 2 

### reduction requirements, boiler capacity fa ctor, and fuel sulfur content. Taking these factors into account, the typical cost effectiveness of a 1,000 MMBTU/hr (~300MW) coalfired boiler equipped with wet FGD is around $410 per ton of SO 2 

### reduced when combusting high-sulfur coal. This cost is based on a boiler capacity factor of 83% and SO 2 

### removal efficiency of 90%. Assuming the same boiler and SO 2 

### control efficiency, but firing low-sulfur coal, the cost per ton is slightly more expensive at $510 per ton of SO 2 

### controlled. ( Controlling

Fine Particulate Matter Under th e Clean Air Act: A Menu of Options , STAPPA-ALAPCO, March 2006) (Converted from 2003 to 2006 dol lars using a conversion factor of 1.0959

www.inflationdata.com )

A similar cost estimation from the same ST APPA-ALAPCO document pr ovides information for boilers in the size range of >4,000 MMBTU/hr (~ 1,200 MW) and <4,000 MMBTU/hr achieving

>90% SO 2 

### 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 SO 2 

### 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 SO 2 

### removed. This information demonstrates a stro ng cost effectiveness advantage realized by installing control devices on the larger emissi on units. (Converted from 2001 to 2006 dollars using a conversion factor of 1.1383 www.inflationdata.com )

In another independent analysis of cont rol costs, Integrated Planning Model (IPM ® 

### ) background documentation defines a range of control efficienci es, costs, and applicability based on unit size and coal type. (http://www.epa.gov/airmarkets/pro gsregs/epa-ipm/past-modeling.html) Two wet scrubber (wet FGD) control t echnologies are discussed in Integrated Planning Model (IPM ® 

### )Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-11



### background documentation; (1) Limestone Forc ed Oxidation (LSFO), and (2) Magnesium Enhanced Lime (MEL). Both of the scrubber control technologies are applicable to distinct unit sizes and coal types, but ther e is no indication in the parsed Integrated Planning Model (IPM ® 

### ) results as to which type of sc rubber has been applied by the mode l. Both scrubber technologies

are assumed to achieve a SO 2 

### removal percentage of 95% or gr eater. Accordi ng 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 Developmen t. The cost and performance calculations were primarily a function of heat rate, capacity, and sulfur cont ent. The range of va rious scrubber costs is included in Attachment 1. Using the data in At tachment 1 and applying a standard engineering economics analysis (Attachment 2), the costs of SO 2 

### removal using these control technologies vary from approximately $300-$1,100 per ton of SO 2 

### removal, (Converted from 1999 to 2006 dollars using a conve rsion factor of 1.2101 www.inflationdata.com ).

Cost of Flue Gas Desulfur ization (FGD) – Spray Dry

The cost of flue gas desulfurization varies depe nding on a number of fact ors including the size of the boiler, SO 2 

### reduction requirements, boiler capacity fa ctor, and fuel sulfur content. Taking these factors into account, the typical cost effectiveness of a 1,000 MMBTU/hr (~300MW) coalfired boiler equipped with spray dry FGD is around $420 per ton of SO 2 

### reduced. This cost is based on a boiler capacity factor of 83% and SO 2 

### removal efficiency of 90%. ( Controlling Fine

Particulate Matter Under the Cl ean Air Act: A Menu of Options , STAPPA-ALAPCO, March 2006) (Converted from 2003 to 2006 dollars using a conversion factor of 1.0959

www.inflationdata.com )

EPA reports in a 2005 document titled Multipollutant Emission Cont rol Technology Options for Coal-fired Power Plants , that conventional Spray Dry F GD systems can cost from $155-$237 per kW, have fixed operation and maintenan ce costs ranging from $1.55-$7.25 per kW-yr, and variable operation and maintenance costs from 0.2-0.7 mills/kWh. These costs are associated with a 300 MW plant. (Converted from 2005 to 2006 dollars using a conversion factor of 1.0322

www.inflationdata.com )

A similar cost estimation from STAPPA-ALAPCO, 2006 provides information for boilers in the size range of >2,000 MMBTU/hr (~600 MW) a nd <2,000 MMBTU/hr achieving from 80-90%

SO 2 

### removal efficiency. These cost estimates pr ovide the initial and ongoing costs of installing

wet scrubbers. For units > 600 MW, the capital costs are be tween $140-$510/MW; operation and maintenance costs range from $14-$34/MW; and the ul timate cost effectiveness is shown to be from $170-$340/ton SO 2 

### removed. For boilers <600 MW per hour, the capital costs are between $510-$5,100/MW; operation and maintenance cost s (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 effectiven ess advantage realized by installing control devices on the larger emission units. (C onverted from 2001 to 2006 dollars using a conversion factor of 1.1383 www.inflationdata.com )

Integrated Planning Model (IPM ® 

### ) background documentation defines a range of control efficiencies, costs, and applicability based on unit size and coal type.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-12



### (http://www.epa.gov/airmarkets/progsregs/epa-ipm /past-modeling.html) Lime Spray Dry (LSD) technology is one form of SO 2 

### control applied by Integr ated Planning Model (IPM ® 

### ). LSD is

assumed to achieve a SO 2 

### removal percentage of 90%. Acco rding 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 perf ormance calculations were prim arily a function of heat rate, capacity, and sulfur content. The range of variou s 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 operati on and maintenance costs (O&M) range from $5 to $7/kW-yr and variable O&M costs range fr om 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 va riable 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 SO 2 

### emissions by 90%. The cost and performance calculations were primarily a function of heat rate, capacity, a nd sulfur content. Using the data in Attachment 1 and applying a standard engineering economic s analysis (Attachment 2), the costs of SO 2 

### removal using this control technology vari es from approximately $480-$600 per ton of SO 2 

### removal, (Converted from 1999 to 2006 dolla rs using a conversion factor of 1.2101

www.inflationdata.com ).

Cost of Flue Gas Desu lfurization (FGD) – Dry

The cost of flue gas desulfurization varies depe nding on a number of fact ors including the size of the boiler, SO 2 

### reduction requirements, boiler capacity fa ctor, and fuel sulfur content. Taking these factors into account, the typical cost effectiveness of a 1,000 MMBTU/hr (~300MW) coalfired boiler equipped with dry FGD is around $693 per ton of SO 2 

### reduced when combusting high-sulfur coal. This cost is based on a boiler capacity factor of 83% and SO 2 

### removal efficiency of 40%. Assuming the same boiler and SO 2 

### control efficiency, but firing low-sulfur coal, the cost per ton is sli ghtly higher at $764 per ton of SO 2 

### controlled. ( Controlling Fine

Particulate Matter Under the Cl ean Air Act: A Menu of Options , STAPPA-ALAPCO, March 2006) (Converted from 2003 to 2006 dollars using a conversion factor of 1.0959

www.inflationdata.com )

The 2005 EPA document titled, Multipollutant Emission Control Technology Options for Coalfired Power Plants , shows that advanced dry FGD systems can cost from $50-$150 per kW, have fixed operation and maintenance costs ranging fr om <$1 -$3 per kW-yr, (based on 1-2% of capital), and variable operation and maintena nce costs from 0.2-0.7 mills/kWh. Assuming an

SO 2 

### reduction percentage of 40%, cap acity factor of 85%, coal sulf ur 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 SO 2 

### removal using this control technology varies from approximately $250-$850 per ton (Converted fr om 2005 to 2006 dollars using a conversion

factor of 1.0322 www.inflationdata.com )).Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-13



### Summary of SO 2 

### Reduction Costs

The cost of SO 2 

### reductions on a per ton basis for E GUs 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 factor s can cause the cost of the

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

SO 2 

### reductions is included in Table 2.6 for FGDs. Sufficient data were not available to calculate a range of costs with reasonable certainty for fu el switching or coal clean ing. Within the range of estimated costs for a given boi ler size, the low end of the SO 2 

### 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 SO 2 

### , which effectively reduces the per

ton cost of the reduction.

Table 2.6 Estimated Cost Ranges for SO 2 

### Control Options for Coal-fired EGU Boilers (2006 dollars/ton of SO 2 

### Reduced)

Technology Description Performance Cost Range

(2006 dollars/ton of

SO 2 

### Reduced)

Switch to a Low Sulfur Coal (generally <1% sulfur) Replace high-sulfur

bituminous coal combustion

with lower-sulfur coal 50-80% reduction in SO 2 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 SO 2 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 SO 2 emissions 2-15% increase in fuel costs based on current prices of

coal

Flue Gas Desulfurization (FGD) – Wet SO 2 is removed from flue gas by dissolving it in a lime or limestone slurry. (Other alkaline chemicals are sometimes used) 30-95%+ reduction in SO 2 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 SO 2 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 SO 2 emissions $250-$850 for EGUs

~300 MW

Table references:

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

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

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

2006.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-14

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

Plants ; March 2005. 5. U.S. EPA. Integrated Planning Model (IPM ® ) background documentation located on website: http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html

6. Final Draft Report - Comparison of CAIR and CAIR Plus Proposal Using the Integrated Planning Model (IPM ® ), ICF Resources ; May 30, 2007. 7. World Bank Organization. Information located on website: http://www.worldbank.org/html/fpd/em /power/EA/mitigatn/aqsocc.stm



### Time Necessary for Compliance

Generally, sources are given a 2-4 year phase-in period to comply with new rules. Under the previous Phase I of the NO X 

### SIP Call, EPA provided a complianc e date of about 31⁄2 years from

the SIP submittal date. Most MACT standards a llow a 3-year compliance period. Under Phase I

of the NO X 

### SIP Call, EPA provided a 2-year period afte r the SIP submittal date for compliance. States generally provided a 2-yearperiod for compliance with RACT rules. For the purposes of this review, we have assumed th at a maximum of 2 years after SIP submittal is adequate for precombustion controls (fuel switchi ng 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, part icularly in a short time period, may require consideration of impacts on re gional electricity demands. In tegrated Planning Model (IPM ® 

### ) has allowed for these and other impacts in determ ining the least cost approach to emission reductions, however, there is a gr eat deal of uncertainty associ ated with modeled results in comparison to real-world applic ations of control strategies.

For BART control measures, the proposed BA RT 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 trans portation issues and secondary environmental impacts from waste disposal and material handl ing operations (e.g. fugitive dust). Additionally,

these SO 2 

### control methods can create fuel supply probl ems if several large customers of various types of coal suddenly make changes in purchasin g patterns. The main impact would be on the stability of fuel prices. It is not likely that this woul d be a persistent problem.

Another impact of fuel switching is that the modi fications required for sw itching from one fuel to another may require a unit to be examined for major NSR permitting requirements. This is true even for modifications requi red for addition of controls since the modifications could trigger the definition of a “significan t modification” under NSR/PSD.

Fuel switching between types and geographic sources of coal and installation of control devices can significantly effect mercury emissions. Da ta from EPA's Mercury Information Collection Request (ICR) revealed that many power plants have existing merc ury capture as a co-benefit of air pollution contro l technologies for NO X 

### , SO 2 

### and PM. This includes capture of particulatebound mercury in PM control equipment and captu re of soluble ionic mercury in wet FGDAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-15



### systems. Additional data have also shown that the use of SCR for NO X 

### control enhances oxidation of elemental mercury to the soluble ionic form, resulti ng 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 fr om coal combustion are ch lorine content of the coal and fly ash composition.

FGD systems typically operate w ith high pressure drops across th e control equipment, resulting in a significant amount of electri city required to operate blower s and circulation pumps. In addition, some combinations of FGD technology and plant confi guration may require flue gas reheating to prevent physical damage to equipment, resulting in hi gher 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 th e scrubber reduces the am ount 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 system s is the generation of wastewater and sludge

from the SO 2 

### removal process. When the exhaust gas from the boiler enters the FGD the SO 2 

### , metals, and other solids are removed from the exhaust and collected in the FGD liquid. The liquid slurry collects in the botto m 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 trea tment 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 exces sive pollutants from wastewater. This places additional burdens on a facility or community wa stewater treatment and solid waste management capabilities. These impacts will need to be analyz ed on a site-specific basis. If lime or limestone scrubbing is used to produce calci um sulfite sludge, the sludge mu st be stabilized prior to land filling. If a calcium sulfate sludge is produced, dewatering alone is necessary before land filling, however, SO 2 

### removal costs are higher due to increased equipment costs for this type of control system. In some cases calcium sulfate sludg e 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 th e 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 remaini ng useful life estimates of EGU boilers indicates a wide range of operating lifetimes, depending on size of the un it, 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 retrof itting that has ultimately increased the expected life span of many EGUs. The lifetime of an EGU may be extended thro ugh 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 th e unit serves an area which has limited transmission capacity available to br ing in other power.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analys is: Electric Generating Units Page 2-16



### REFERENCES

2002 MANE-VU Emissions Inventory Version 3.

EPA Clean Air Markets Division, (CAMD). Pers onal communication regarding control at coalfired EGUs in the United States from Mr. Peter Kokopeli (202-343-9085), (kokopeli.peter@epa.gov) via E-ma il 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 Ca tegory: 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 SO 2 

### and NO X 

### Emissions from Electricity-Generating Units

.

U.S. EPA. EPA-600/R-05/034; Multipollutant Emission Control Technology Options for Coalfired Power Plants ; March 2005.

U.S. EPA. Integrated Planning Model (IPM ® 

### ) background documentati on located on website: ( http://www.epa.gov/airmarkets/progs regs/epa-ipm/past-modeling.html )

ICF Resources. Final Draft Report - Comparison of CA IR and CAIR Plus Proposal Using the Integrated Planning Model (IPM ® 

### ), May 30, 2007.

GE Water & Process Technologies. In formation accessed on web March 27, 2007: http://www.zenon.com/applications/F GD_wastewater_treatment.shtml

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

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

Energy Information Administration (EIA). Information located on website: http://www.eia.doe.gov/cneaf/e lectricity/epm/epm_sum.html

World Bank Organization. Information located on website: http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqsocc.stmAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-1



### CHAPTER 3

ANALYSIS OF SELECTED ELECTRIC GENERATING UNITS (EGUs)

EGU FACILITY CONTROLS

The Vermont Department of Environmental C onservation (VTDEC) used the CALPUFF model to estimate sulfate ion impacts from large E GUs 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 SO 2 

### emissions, and the results of the modeling

showed the SO 2 

### emissions of the 100 highest emitting EGUs and the contribution of these

sources toward the SO 2 

### concentration in each of the Class I areas. Proximity of the individual

sources to Class I areas and variations in mete orology 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 Pr ogress Workgroup, MACTEC was directed to focus on the emissions from the top 30 indivi dual sources for this analysis . The 30 individual sources are

located at 23 distinct facilities. The location of the 23 EGU faciliti es of interest is included in Figure 3.1.

Since EGUs are the largest emitters of SO 2 

### in the United States and have the greatest impact on haze in the MANE-VU Class I areas, it is particular ly useful to determine what controls have recently been applied at these f acilities (since the 2002 emission inventory). Also important is

information about controls that are currently being a pplied at facilities, or are planned for

addition in the future.

MACTEC gathered information from two primary sour ces of data for analysis of controls to be applied at the 30 EGUs.

1. Integrated Planning Model (IPM ® 

### ) results from the MANE-VU CAIR Plus (MARAMA 4c) run.

2. Information from State agencies with facilities in the list of the top 30 individual sources. We requested EGU permit information, information about SO 2 

### controls recently implemented or planned at the facility a nd 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 addi tional 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 planne d controls for these 30 key EGUs is intended to give an idea of whether a strict er cap would in fact result in great controls at these sources.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-2



### Figure 3.1

Note: Some facilities are too close to differentiate on the map



### INTEGRATED PLANNING MODEL (IPM ® 

### ) ANALYSIS

For EGUs, EPA used the Integrated Planning Model (IPM ® 

### ) to estimate which units will install

controls at what costs and whic h units will buy credits. The RP Os 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 st ringent “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 he lp determine costs for EGUs, and ultimately estimate the marginal cost of SO 2 

### reductions for the model pl anning years of 2009, 2012, and

2018.

MACTEC obtained information from the CAIR Plus Policy Ca se, (MARAMA_4c) for the years 2009, 2012, and 2018 for the 30 EGUs. The information obtained included unit design capacity,

SO 2 

### emissions, assumed existing controls, and co ntrols to be applied as calculated by the Integrated Planning Model (IPM ® 

### ). The information was availa ble 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 In tegrated Planning Model (IPM ® 

### ). The parsed model data do not supply specific design information pertaining to the scrubber size,Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-3



### costs, or other related information for individual units. It is only possible to determine the year

that the scrubber is due to be installed on individual process un its. 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 lite rally, but only as an example of the least-cost results from one set of inputs to the mode l. 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 3.2Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 3: Analysis of Selected Electric Generating Units (EGUs) Page3-4Table 3.1 Integrated Planning Model (IPM®version 2.1.9) CAIR Plus Projections for the Top30 EGUs Responsible for Visibility Impairment inMANE-VU Class I AreasState Facility ID Facility Primary EmissionsPoint DescriptionsPoint # 2002 SO2Total(Tons)12018 SO2Total(Tons)2SO2Reduction(2002-2018)(Tons/Year)3% SO2Reduction(2002-2018)3DesignCapacity4Existing Control4MANE_VUCAIR PlusProjection5TN D03406C10 JohnsonvilleCoal - wall fired; drybottom boiler10 108,789 46,000 63,000 58%15,688MMBTUCold-side ESP; LNB SCR by 2012OH D028404 ConesvilleCoal - tangential; drybottom boiler4 92,340 7,000 85,000 92% 764 MWCold-side ESP; LNB + OFA +BOOSSCR and Scrubberby 2009PA D031361 KeystoneCoal - tangential; drybottom boiler1 87,709 5,000 83,000 94%8,010MMBTUCold-side ESP + SCR; LNB;OFAScrubber by 2009OH D02872C04MuskingumRiverCoal - cyclone; wetbottom boiler4 24,484 1,000 23,000 96%205 MW to201 MW by2012Cold-side ESP; OFASCR and Scrubberby 2012PA D03179C01 Hatfield’s FerryCoal - wall fired; drybottom boiler1 55,695 13,000 43,000 77%5,766MMBTUCold-side ESP + SNCR; LNB NoneOH D02876C01 Kyger CreekCoal - wall fired; wetbottom boiler1 13,789 1,000 13,000 93%13,789MMBTUCold-side ESP + SCR; OFA Scrubber by 2012WV D03935C02 John E. AmosCoal - wall fired; drybottom boiler2 31,465 6,000 25,000 81%7,020MMBTUCold-side ESP + SCR; LNB ScrubberPA D031362 Keystone Coal - tangential; dry 2 62,890 4,000 59,000 94%8,010MMBTUCold-side ESP + SCR; LNB;OFAScrubber by 2009IN D01010C05 Wabash RiverCoal - wall fired; drybottom boiler5 9,380 1,000 8,000 89% 95 MWCold-side ESP + Cyclone;LNB + OFASNCR by 2009PA D031491 MontourCoal - tangential; drybottom boiler1 61,005 4,000 57,000 93% 744 MWCold-side ESP + SCR; LNB +OFAScrubber by 2009NC D080421 Belews CreekCoal - wall fired; drybottom boiler1 57,848 3,000 55,000 95% 1,096 MW Cold-side ESP + SCR; LNB Mercury controlWV D03948C02 MitchellCoal - wall fired; drybottom boiler2 29,532 6,000 24,000 80%7,020MMBTUCold-side ESP + SCR + WetScrubber; LNBNonePA D031222 Homer CityCoal - wall fired; drybottom boiler2 55,346 3,000 52,000 95%6,792MMBTUCold-side ESP + SCR; LNB +OFAScrubber by 2009PA D031492 MontourCoal - tangential; drybottom boiler2 50,441 4,000 46,000 92% 729 MWCold-side ESP + SCR; LNB +OFAScrubber by 2009MD D01571CE2 Chalk PointCoal - wall fired; drybottom boiler2 23,537 2,000 22,000 92% 335 MW Cold-side ESP; LNBSCR and Scrubberby 2009MI D01733C12 MonroeCoal - cell fired; drybottom boilers1 & 2 48,563 28,000 21,000 42% 770, 785 MW Cold-side ESP + SCR; LNB NonePA D031221 Homer CityCoal - wall fired; drybottom boiler1 45,745 3,000 43,000 93% 607 MWCold-side ESP + SCR; LNB +OFAScrubber by 2009NC D080422 Belews CreekCoal - wall fired; drybottom boiler2 45,236 3,000 42,000 93% 1,096 MW Cold-side ESP + SCR; LNB Mercury controlWV D039432 Fort MartinCoal - wall fired; drybottom boiler2 45,890 5,000 41,000 89%4,634MMBTUCold-side ESP + SNCR; LNB+ OFAScrubber by 2012WV D039431 Fort MartinCoal - tangential; drybottom boiler1 45,228 5,000 40,000 89%4,460MMBTUCold-side ESP + SNCR; LNB+ OFAScrubber by 2012WV D039353 John E. AmosCoal - wall fired; drybottom boiler3 44,030 9,000 35,000 80%11,900MMBTUCold-side ESP + SCR; LNB ScrubberAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 3: Analysis of Selected Electric Generating Units (EGUs) Page3-5Table 3.1 Integrated Planning Model (IPM®version 2.1.9) CAIR Plus Projections for the Top30 EGUs Responsible for Visibility Impairment inMANE-VU Class I AreasState Facility ID Facility Primary EmissionsPoint DescriptionsPoint # 2002 SO2Total(Tons)12018 SO2Total(Tons)2SO2Reduction(2002-2018)(Tons/Year)3% SO2Reduction(2002-2018)3DesignCapacity4Existing Control4MANE_VUCAIR PlusProjection5OH D0283612 Avon LakeCoal - wall fired; drybottom boiler12 41,872 6,000 36,000 86%6,040MMBTUCold-side ESPScrubber by 2009;SCR by 2012VA D037976 ChesterfieldCoal - tangential; drybottom boiler6 40,923 4,000 37,000 90%6,650MMBTUCold-side ESP; LNB + OFASCR and Scrubberby 2012PA D082261 CheswickCoal - tangential; drybottom boiler1 42,018 5,000 37,000 88% 550 MWCold-side ESP + SCR ; LNB+ OFAScrubber by 2009OH D028281 CardinalCoal - cell fired; drybottom boilers1 39,894 2,000 38,000 95%600 MW to587 MW in2012Cold-side ESP + SCR; LNB Scrubber by 2012MD D015731 MorgantownCoal - tangential; drybottom boiler1 37,757 3,000 35,000 92% 570 MW Cold-side ESP; LNB +OFASCR and Scrubberby 2009OH D028667 W H SammisCoal - wall fired; drybottom boiler7 33,720 3,000 31,000 91%593 MW to818 MW in2012Cold-side ESP + SNCR; LNBScrubber in 2009;Coal to IGCC in2012MD D015732 MorgantownCoal - tangential; drybottom boiler2 32,587 3,000 30,000 91% 570 MW Cold-side ESP; LNB +OFASCR and Scrubberby 2009MA D016193 Brayton PointCoal - wall fired; drybottom boiler3 19,451 3,000 16,000 85%5,800MMBTUCold-side ESP; LNB + OFASCR, Scrubber,Mercury Controlby 2009NJ D023781 B L EnglandCoal - cyclone; wetbottom boiler1 10,080 1,000 9,000 90% 129 MWCold-side ESP; + SNCR;OFANoneNote: CEMS hourly data was used in the modeling of the emission units, not annual emissions. Also, a single emission unit ata generating plant may represent twoor 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 SO2total for the emission point from RPO emission inventory2. Integrated Planning Model (IPM®) CAIR Plus projected 2018 SO2total for the emission point (rounded to nearest 1,000 tons)3. Approximate reduction in SO2emissions 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 inventories5. Information from Integrated Planning Model (IPM®) CAIR Plus ScenarioAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-6



### Integrated Planning Model (IPM ® 

### ) background documentation defines a range of control efficiencies, costs, and applicability based on unit size and coal type. (http://www.epa.gov/airmarkets/progsregs/epa-ipm /past-modeling.html) Three scrubber control technologies are discussed briefly in Integrated Planning Model (IPM ® 

### ) background documentation; 1. Limestone Forced Oxidation (LSFO), 2. Magnesium Enhanced Lime (MEL) and 3. Lime Spray Dryer (LSD). Each of the th ree scrubber control techno logies are applicable for distinct unit sizes and coal types, but there is no indication in the pa rsed Integrated Planning Model (IPM ® 

### ) results as to which type of scrubber ha s been applied by the model. All three scrubber technologies are assumed to achieve a SO 2 

### removal percentage of 90% or greater. The range of various scrubber costs is included in Attachment 1. Dependi ng on boiler size, boiler capacity factor, and coal sulfur content, th e fixed capital costs range from $140 to $580/kW, while fixed operation and mainte nance costs (O&M) range from $5 to $24/kW-yr and variable O&M costs range from 1.0 to 2.4 mills/kWh. Assu ming the typical costs in Attachment 1, an EGU rated 500 MW, (the approximate average of the 30 units included in th is 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 SO 2 

### emissions by greater than 90%. A typical SO 2 

### reduction from a 500 MW unit (assu ming a minimum of 90% reduction), based on the 30 units included in this analysis would be from 4,000 to 40,000 tons annually. (Converted from 1999 to 2006 dollars using a conversion factor of 1.2101

www.inflationdata.com )

INFORMATION OBTAINED FROM STATE AGENCIES

The 30 EGUs analyzed here are already subjec t to a variety of ex isting emission control requirements, including CAIR, BART, mercury controls, the NO X 

### SIP call, and EPA’s acid rain control program. Therefore, it is expected th at at least some of the 30 EGUs will already be adding control by 2018.

To investigate this possibility, MA CTEC contacted State agencies with facilities in the list of the top 30 individual sources. We requested EGU permit information, information about SO 2 

### controls recently implemented or planned at the facility, and any av ailable information on BART, consent decrees, or other regulations th at will impact EGU control devices. The

information we have obtained is included in Table 3.2.Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 3: Analysis of Selected Electric Generating Units (EGUs) Page3-7Table 3.2 Point Source Information for the Top 30 EGUs Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)aPrimary Emissions PointDescriptionPointID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationJohnsonville1, 2, 3TN 108,789 Coal-fired Boilers 01-10for steam & electricitygeneration. The units arepulverized coal, dry-bottomboilers without fly ashreinjection. Units 1-6 areCombustion Engineeringtangentially-fired boilers.Units 7-10 are FosterWheeler wall fired boilers.All boilers exhaust througha common stack.43-0011-01-1015,688MMBTU/hrESP Combustionof low-sulfurfuel (since2002)SCR by 20182018 SO2emissionswill be approximately51,000 tpyConesville4OH 92,340 Unit 4 Main Boiler -Combustion Engineeringmodel 7868 pulverizedcoal-fired, dry-bottomboilerB004 7,960 MMBTU/hr ESP FGD and SCRby 8/18/09N/AKeystone (akaReliant EnergyNortheastMgmt/KeystonePower Plant)5PA 87,709 Boiler 1 w/low NOXburner1 (031) 8,717 MMBTU/hr Cold-side ESPSCRFGD Alternate operation:SCR System Boiler 1MuskingumRiver6OH 24,484 Unit 3 Main Boiler -Babcock and Wilcoxmodel RB-248 (custom)coal-fired, cyclone boilerB004 2,150 MMBTU/hr ESP None planned N/AAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 3: Analysis of Selected Electric Generating Units (EGUs) Page3-8Table 3.2 Point Source Information for the Top 30 EGUs Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)aPrimary Emissions PointDescriptionPointID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationHatfield’s Ferry5PA 55,695 Babcock & Wilcox Boiler#1 that burns bituminouscoal (227 tons/hr) and No.2 fuel oil (1,384 gal/hr)1 (031) 5,766 MMBTU/hr Cold-side ESP FGD N/AKyger Creek6OH 13,789 Unit #1 Boiler- Babcockand Wilcox pulverizedcoal-fired, wet-bottomboilerB001 1,850 MMBTU/hr ESP SCR, FGDoperational by1/01/09N/AJohn E. Amos7,8WV 31,465 Dry-bottom wall-fired coalboiler2 800 MW,7,020 MMBTU/hrESPLow NOXburnersSCRFGD(12/2008)Vents through CS012Keystone (akaReliant EnergyNortheastMgmt/KeystonePower Plant)5PA 62,890 Boiler 2 w/low NOXburner2 (032) 8,717 MMBTU/hr Cold-side ESPSCRFGD Alternate operation:SCR System Boiler 2Wabash (akaDuke EnergyIndiana, Inc. -Wabash RiverGeneratingStation)9, 10IN 9,380 Wall fired coal electricutility boiler (pulverized –dry bottom) constructed in1956 using No. 2 fuel oilas ignition fuel5 1,096.2MMBTU/hrLow- NOXburner (NOX)ESP (PM)None Stack is equipped withCEM for SO2Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 3: Analysis of Selected Electric Generating Units (EGUs) Page3-9Table 3.2 Point Source Information for the Top 30 EGUs Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)aPrimary Emissions PointDescriptionPointID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationMontour (akaPPL Montour,LLC – MontourSteam ElectricStation)5PA 61,005 CE Boiler – Unit #1 thatburns bituminous coal andNo. 2 fuel oil1 (031) 7,317 MMBTU/hr Cold-side ESPSCRFGD N/ABelews Creek(aka DukePower’s BelewsCreek Plant)11NC 57,848 Coal-fired electric utilityboiler constructed in 19741 1,120 MW None Scrubbers(2008)Expected rate undertheir compliance planfor the CleanSmokestacks Act is0.150 lbsSO2/MMBTU.Expected emissionsSO2for 2013 and lateris 5,512 tpy.Mitchell7, 12WV 29,532 Dry-bottom wall-fired coalboiler2 800 MW,7,020 MMBTU/hrESPLow NOXburnersFGD(1/2007);SCR (4/2007)Vents through CS012Homer City (akaHomer CityOL/Homer CityGenerationStation13PA 55,346 Boiler No. 2 (Unit 2) 2 (032) 6,792 MMBTU/hr Cold-side ESPSCRFGD N/AMontour (akaPPL Montour,LLC – MontourSteam ElectricStation)5PA 50,441 CE Boiler – Unit #2 thatburns bituminous coal andNo. 2 fuel oil2 (032) 1,239 MMBTU/hr Cold-side ESPSCRFGD N/AAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 3: Analysis of Selected Electric Generating Units (EGUs) Page3-10Table 3.2 Point Source Information for the Top 30 EGUs Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)aPrimary Emissions PointDescriptionPointID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationChalk Point15, 16MD 23,537 Steam Unit 2 is a wallfired, dry bottom,supercritical boiler baseloaded unit. The primaryfuel is coal with naturalgas and No. 2 oil used forignition.2 342 MW Low NOXburnersESPSACRLNBs &SOFA (NOX)SCR and FGD(2009/2010timeframe)Unit covered under theMD Healthy Air ActMonroe (akaDetroit Edison –Monroe PowerPlant)16MI 48,563 4 cell burner boilers(Boiler Unit Nos. 1, 2, 3,and 4) constructed in thelate 1960s (1968-1969)and modified in 1994EG01EG02EG03EG043,000 MW (total) Dry wire ESP(SO3)FGD (Units 3& 4) @ 97%CEMay putscrubbers onUnits 1 & 2laterIf additional scrubbersare added, a SO2reduction of 97% isanticipatedHomer City (akaHomer CityOL/Homer CityGenerationStation13PA 45,745 Boiler No. 1 (Unit 1) 1 (031) 6,792 MMBTU/hr Cold-side ESPSCRFGD N/ABelews Creek(aka DukePower’s BelewsCreek Plant)11NC 45,236 Coal-fired electric utilityboiler constructed in 19752 1,120 MW None Scrubbers(2008)Expected rate undertheir compliance planfor the CleanSmokestacks Act is0.150 lbsSO2/MMBTU.Expected emissionsSO2for 2013 and lateris 4,639 tpy.Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 3: Analysis of Selected Electric Generating Units (EGUs) Page3-11Table 3.2 Point Source Information for the Top 30 EGUs Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)aPrimary Emissions PointDescriptionPointID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationFort Martin7, 8WV 45,228 Tangentially-fired coalboiler1 552 MW,4,460 MMBTU/hrESPLow NOXburnersSNCR TrimFGD (4Q2009)N/AFort Martin7, 8WV 45,890 Wall-fired coal boiler 2 55 MW,4,634 MMBTU/hrESPLow NOXburnersSNCR TrimFGD (1Q2010)N/AJohn E. Amos7, 8WV 44,030 Dry-bottom wall-fired coalboiler3 1,300 MW,11,900MMBTU/hrESPLow NOXburnersSCRFGD(12/2007)N/AAvon Lake6OH 41,872 Boiler #12 - Pulverizedcoal-fired, dry bottom,boilerB012 6,040 MMBTU/hr ESP SCR and FGDoperational by2010N/AChesterfield (akaChesterfieldPower Station)17VA 40,923 Combustion Engineeringtangentially-fired coalboiler equipped withstartup burners6 (ES6A)6,650 MMBTU/hr SCRESPStagecombustioncoal burnersFGD (95%CE underconstruction,operational2008)The unit is restricted toburn 2,330,160 tons/yrof coal at an annualaverage heating valueof 12,500 BTU/lbsCheswick (akaCheswick PowerStation)18PA 42,018 Tangentially-fired “main”boiler that burnsbituminous coal (primaryfuel), natural gas, andsynfuel1 5,500 MMBTU/hr(coal & synfuel)1,000 MMBTU/hr(NG)Low NOXburnersSCRESP w/fluegasconditioning(PM)FGD (98%CE planned)N/AAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 3: Analysis of Selected Electric Generating Units (EGUs) Page3-12Table 3.2 Point Source Information for the Top 30 EGUs Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)aPrimary Emissions PointDescriptionPointID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationCardinal6, 12OH 39,894 Unit 1 Main Boiler -Babcock and Wilcox,pulverized coal-fired, drybottom, cell burner boilerB001 527 MMBTU/hr ESP FGD (2/2008) N/AMorgantown14, 15MD 37,757 Combustion Engineering,Inc., Unit Boiler No. 1 -steam generating coalfired utility boiler installedin 1967 which primarilycombusts EasternBituminous coalcontaining no more than2% sulfur by weight andsecondary fuel is No. 6 oilcontaining no more than2% sulfur by weight1 (F-1) 5,317 MMBTU/hr ESPSO3injectionLow NOXburnersSCR and FGD(2009/2010timeframe)Stacks equipped withSO2, NOX, CO2, andultrasonic flowmonitors. Unit coveredunder the MD HealthyAir Act.W H Sammis6OH 33,720Coal Fired Boiler No.1 -Foster-Wheeler pulverizedcoal-fired, dry-bottomboilerB007 1,822 MMBTU/hr Fabric filterESPFGDoperational12/31/09SNCROperational06/06N/AAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 3: Analysis of Selected Electric Generating Units (EGUs) Page3-13Table 3.2 Point Source Information for the Top 30 EGUs Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)aPrimary Emissions PointDescriptionPointID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationMorgantown14, 15MD 32,587 Combustion Engineering,Inc., Unit Boiler No. 2 -steam generating coalfired utility boiler installedin 1967 primarilycombusts EasternBituminous coal w/ nomore than 2% sulfur byweight and secondary fuelis No. 6 oil w/ no morethan 2% sulfur by weight1 (F-2) 5,317 MMBTU/hr ESPSO3injectionLow NOXburnersSCR and FGD(2009/2010timeframe)Stacks equipped withSO2, NOX, CO2, andultrasonic flowmonitors. Unit coveredunder the MD HealthyAir Act.Brayton Point19MA 19,451 Water tube boiler 3 (EU3) 5,655 MMBTU/hr ESP w/fluegasconditioning(PCD-3)Fuel sulfurcontent(2011)FGD (2011)BART recommendedcontrols for SO2are95% control or 0.15lb/MMBTU (coal),0.33 lb/MMBTU (0.3%fuel sulfur limit) (oil)B L England20, 21NJ 10,080 Wet-bottom, cyclone coalboiler1 129 MW ESPSNCRNone The facility will eitherclose by 2012 or installscrubbers on all coalfired units. Onescrubber is alreadyinstalled and the otherunit would get a 95%CE –minimum, butunclear if this unit isalready controlled.a2002 SO2total for the emission point from RPO emission inventory.Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 3: Analysis of Selected Electric Generating Units (EGUs) Page3-141Tennessee Department of Environment and Conservation, Division of Air Pollution Control. Personal communication regarding Johnsonville facility from Ms. Julie Aslinger(615-532-0587,Julie.Aslinger@state.tn.us) via E-mail on March 1, 2007.2MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid-Atlantic NorthEastern Class I Areas”, March 8, 2007.Comment regarding Johnsonvillefacility received from Ms.Julie Aslinger (615-532-0587,Julie.Aslinger@state.tn.us) via E-mail on March 30, 2007.3MACTEC, Inc., “Documentation of the Base G 2002 Base Year, 2009 and 2018 Emission Inventories for VISTAS”, January, 2007.4Ohio Environmental Protection Agency, Division of Air PollutionControl. Personal communications regarding Conesville facilityfrom Mr. William Spires (614-644-3618,bill.spires@epa.state.oh.us) via E-mail on February 20 and 21, 2007.5Pennsylvania Department of Environmental Protection, Bureau ofAir Quality. Personal communications regarding Keystone, Hatfield’s Ferry, and Montour facilities from Ms.Nancy Herb (717-783-9269,nherb@state.pa.us) via E-mail on January 31 and February 7, 2007.6Ohio Environmental Protection Agency, Division of Air Pollution Control. Personal communication regarding Muskingum, Kyger Creek, Avon Lake, Cardinal, and WH Sammisfacilities from Mr. William Spires (614-644-3618,bill.spires@epa.state.oh.us) via E-mail on February 20, 2007.7West Virginia Division of Air Quality.Personal communication regardingJohn. E. Amos, Mitchell, and Fort Martin facilities from Ms. Laura Crowder (304-926-0499 Ext. 1247,LCROWDER@wvdep.org) via E-mail on February 17, 2007.8MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid-Atlantic NorthEastern Class I Areas”, March 8, 2007.Comments regarding John E. Amos, Mitchell,and Fort Martin and facilities receivedfrom Ms. Laura Crowder (304-926-0499 Ext. 1247,LCROWDER@wvdep.org) via E-mailon March 30, 2007.9Indiana Department of Environmental Management, Office of Air Quality.Personal communication regarding Wabash facility between Mr. Jay Koch (317-233-0581,JKOCH@idem.IN.gov) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007.10Indiana Department of Environmental Management, Office of Air Quality.Personal communications regarding Wabash facility fromMr. Jay Koch (317-233-0581,JKOCH@idem.IN.gov) via E-mail on February 1 and 5, 2007.11North Carolina Department of Environment and Natural Resources,Division of Air Quality. Personal communications regarding Belews Creek facility from Ms. Sheila Holman(919-715-0971,shelia.holman@ncmail.net) via E-mail on February 1 and 2, 2007.12MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid-Atlantic NorthEastern Class I Areas”, March 8, 2007.Comments regarding Mitchell and Cardinal facilities received from Mr. David J. Long, P.E. of American Electric Power (614-716-1245,djlong@aep.com) via E-mail on March29, 2007.13Pennsylvania Department of Environmental Protection, Bureau ofAir Quality. Personal communications regarding Homer City facility from Ms. Nancy Herb (717-783-9269,nherb@state.pa.us) via E-mail on January 31 and February 7 and 8, 2007.14Maryland Department of the Environment.Personal communication regarding Chalk Point and Morgantown facilities from Mr. Andy Heltibridle (410-537-4218,aheltibridle@mde.state.md.us) via U.S. mail on February 9, 2007.15MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid-Atlantic NorthEastern Class I Areas”, March 8, 2007.Comments regarding Chalk Point and Morgantown facilities received from Mr. Brian Hug (410-537-4125,bhug@mde.state.md.us) via E-mail on March 14, 2007.16Michigan Department of Environmental Quality, Air Quality Division. Personal communication regarding Monroe facility from Ms.Teresa Walker (517-335-2247,walkertr@michigan.gov) via E-mail on February 7, 2007.17Virginia Department of Environmental Quality, Division of Air Quality. Personalcommunication regarding Chesterfield facilityfrom Ms. Doris McLeod (504-698-4197,damcleod@deq.virginia.gov) via E-mail on February 9, 2007.18Allegheny County Health Department. Personal communications regarding Cheswick facility from Ms. Jayme Graham (412-578-8129,JGraham@achd.net) via E-mail onFebruary 2, 2007.19Massachusetts Department of EnvironmentalProtection. Personal communications regarding Brayton Point facility from Mr. DonaldSquires (617-292-5618,Donald.Squires@state.ma.us) via E-mail on February 2 and 7, 2007.20New Jersey Department of Environmental Protection, Division of Air Quality. Personal communicationsregarding B.L. England facility between Mr. Ray Papalski (609-633-7225,Ray.Papalski@dep.state.nj.us) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007.21New Jersey Department of Environmental Protection, Division of Air Quality. Personal communicationsregarding B.L. England facility from Mr. Ray Papalski (609-633-7225,Ray.Papalski@dep.state.nj.us) via E-mail on February 1, 2007.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-15



### Table 3.3 presents a side by side comparison of the predicted control information from Tables 3.1 and 3.2. The existing control information av ailable from Integrated Planning Model (IPM ® 

### ) data was in disagreement with the informati on reported by the States for many of the EGUs. Since controls at the EGUs may have changed recently [since Integrat ed Planning Model (IPM ®


### v.2.1.9)], Table 3.3 reports existing c ontrol information obtained from the States for this report. The information on proposed or pl anned controls obtained from the States reflects that 26 of the 30 EGUs included in this study plan to install SO 2 

### control (FGD/scrubber), or switch to a lower sulfur coal prior to 2018. SO 2 

### reduction estimates from the States were only available for some of the EGUs, but reflect a significant reduction in SO 2 

### for those units for which an estimate was supplied.

Regarding the control information fr om Integrated Planning Model (IPM ® 

### ) CAIR Plus results, Integrated Planning Model (IPM ® 

### ) predicts that 21 of the 30 EGUs will install SO 2 

### in the CAIR Plus scenario. Additionally, Integrated Planning Model (IPM ® 

### ) predicts a reduction in SO 2 

### at all 30 EGUs included in this study, including the 9 units for which no SO 2 

### control is added. The

SO 2 

### 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 in formation on all Integrated Planning Model (IPM ® 

### ) compliance strategies and well as information on NO X 

### reductions are available in Integrated Planning Model (IPM ® 

### ) documentation available on EPA’s webs ite and in the ICF report titled: Final Draft Report – Comparison of CAIR and CAIR Plus Proposal Us ing the Integrated Planning Model (IPM ® 

### )

.

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

### ) CAIR Plus

Results versus Proposed/Planned Control Addition s by the State/Facility (by 2018) at the Top 30 EGUs Responsible for Visibility Im pairment in MANE-VU Class I Areas

Facility

Name State Point

# 2002

SO 2 

### (tons) Existing

Controls

(based on

information from State) 

### Facility/State Proposed/Planned

Controls

{% SO 2 

### reduction} IPM ® 

### Predicted Controls (CAIR Plus)

{% SO 2 

### reduction}

Johnsonville TN 10 108,789 ESP Low sulfur fuel since 2002; SCR by 2018

{53% reduction in SO 2 } SCR by 2012

{58% reduction in SO 2 }

Conesville OH 4 92,340 ESP FGD and SCR by 8/18/09

{SO 2 reduction unavailable} SCR and Scrubber by 2009

{92% reduction in SO 2 }

Keystone PA 1 87,709 Cold-side ESP; SCR FGD

{SO 2 reduction unavailable} Scrubber by 2009

{94% reduction in SO 2 }

Muskingum

River OH 4 24,484 ESP None planned

{SO 2 reduction assumed 0%} SCR and Scrubber by 2012

{96% reduction in SO 2 }

Hatfield’s Ferry PA 1 55,695 Cold-side ESP FGD

{SO 2 reduction unavailable} None

{77% reduction in SO 2 }

Kyger Creek OH 1 13,789 ESP SCR, FGD operational by

1/01/09

{SO 2 reduction unavailable} Scrubber by 2012

{93% reduction in SO 2 }

John E. Amos WV 2 31,465 ESP; Low NO X burners;

SCR FGD by 12/2008

{SO 2 reduction unavailable} Scrubber

{81% reduction in SO 2 }Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-16



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

### ) CAIR Plus

Results versus Proposed/Planned Control Addition s by the State/Facility (by 2018) at the Top 30 EGUs Responsible for Visibility Im pairment in MANE-VU Class I Areas

Facility

Name State Point

# 2002

SO 2 

### (tons) Existing

Controls

(based on

information from State) 

### Facility/State Proposed/Planned

Controls

{% SO 2 

### reduction} IPM ® 

### Predicted Controls (CAIR Plus)

{% SO 2 

### reduction}

Keystone PA 2 62,890 Cold-side ESP; SCR FGD

{SO 2 reduction unavailable} Scrubber by 2009

{94% reduction in SO 2 }

Wabash River IN 5 9,380 Low NOX burners; ESP None planned

{SO 2 reduction assumed 0%} SNCR by 2009

{89% reduction in SO 2 }

Montour PA 1 61,005 Cold-side ESP; SCR FGD

{SO 2 reduction unavailable} Scrubber by 2009

{93% reduction in SO 2 }

Belews Creek NC 1 57,848 None Scrubbers (2008)

{90% reduction in SO 2 } Mercury control

{95% reduction in SO 2 }

Mitchell WV 2 29,532 ESP; Low NO X burners FGD (1/2007); SCR (4/2007)

{SO 2 reduction unavailable} None

{80% reduction in SO 2 }

Homer City PA 2 55,346 Cold-side ESP; SCR FGD

{SO 2 reduction unavailable} Scrubber by 2009

{95% reduction in SO 2 }

Montour PA 2 50,441 Cold-side ESP; SCR FGD

{SO 2 reduction unavailable} Scrubber by 2009

{92% reduction in SO 2 }

Chalk Point MD 2 23,537 Low NO X burners; ESP;

SACR LNBs & SOFA SCR and FGD (2009/2010 timeframe)

{SO 2 reduction unavailable} SCR and Scrubber by 2009

{92% reduction in SO 2 }

Monroe MI 1 & 2 48,563 Dry wire ESP; FGD Possible addition of scrubbers

{97% SO 2 reduction if controlled} None

{42% reduction in SO 2 }

Homer City PA 1 45,745 Cold-side ESP; SCR FGD

{SO 2 reduction unavailable} Scrubber by 2009

{93% reduction in SO 2 }

Belews Creek NC 2 45,236 None Scrubbers (2008)

{90% reduction in SO 2 } Mercury control

{93% reduction in SO 2 }

Fort Martin WV 2 45,890 ESP, Low NO X burners;

SNCR Trim FGD (4Q 2009)

{SO 2 reduction unavailable} Scrubber by 2012

{89% reduction in SO 2 }

Fort Martin WV 1 45,228 ESP, Low NO X burners;

SNCR Trim FGD (1Q 2010)

{SO 2 reduction unavailable} Scrubber by 2012

{89% reduction in SO 2 }

John E. Amos WV 3 44,030 ESP, Low NO X burners;

SCR FGD (12/2007)

{SO 2 reduction unavailable} Scrubber

{80% reduction in SO 2 }

Avon Lake OH 12 41,872 ESP SCR and FGD operational by

2010

{SO 2 reduction unavailable} Scrubber by 2009; SCR by

2012

{86% reduction in SO 2 }

Chesterfield VA 6 40,923 SCR; ESP; Stage

combustion burners FGD operational 2008

{95% reduction in SO 2 } SCR and Scrubber by 2012

{90% reduction in SO 2 }

Cheswick PA 1 42,018 Low NOX burners; SCR; ESP w/flue gas conditioning None

{SO 2 reduction assumed 0%} Scrubber by 2009

{88% reduction in SO 2 }

Cardinal OH 1 39,894 ESP FGD (2/2008)

{SO 2 reduction unavailable} Scrubber by 2012

{95% reduction in SO 2 }Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-17



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

### ) CAIR Plus

Results versus Proposed/Planned Control Addition s by the State/Facility (by 2018) at the Top 30 EGUs Responsible for Visibility Im pairment in MANE-VU Class I Areas

Facility

Name State Point

# 2002

SO 2 

### (tons) Existing

Controls

(based on

information from State) 

### Facility/State Proposed/Planned

Controls

{% SO 2 

### reduction} IPM ® 

### Predicted Controls (CAIR Plus)

{% SO 2 

### reduction}

Morgantown MD 1 37,757 ESP; SO 3 injection; Low

NO X burners SCR and FGD (2009/2010 timeframe)

{SO 2 reduction unavailable} SCR and Scrubber by 2009

{92% reduction in SO 2 }

W H Sammis OH 7 33,720 Fabric filter ESP and FGD operational 12/31/09; SNCR operational

6/06

{SO 2 reduction unavailable} Scrubber in 2009; Coal to

IGCC in 2012

{91% reduction in SO 2 }

Morgantown MD 2 32,587 ESP; SO 3 injection; Low

NO X burners SCR and FGD (2009/2010 timeframe)

{SO 2 reduction unavailable} SCR and Scrubber by 2009

{91% reduction in SO 2 }

Brayton Point MA 3 19,451 ESP w/flue gas conditioning (PCD-3) Fuel sulfur content (2011);

FGD 2011

{95% reduction in SO 2 } SCR, Scrubber, Mercury Control by 2009

{85% reduction in SO 2 }

B L England NJ 1 10,080 ESP;SNCR Facility will either close or install scrubbers by 2012

{95% reduction in SO 2 } None

{90% reduction in SO 2 }

Table Reference: See full reference info rmation for Integrated Planning Model (IPM ® ) and State agency contacts associated with

Tables 3.1 and 3.2.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-18



### REFERENCES

2002 MANE-VU Emissions Inventory Version 3.

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

2005.

Midwest RPO. Candidate Control Measures – Source Ca tegory: 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 SO 2 

### and NO X 

### Emissions from Electricity-Generating Units

.

ICF Resources. Final Draft Report - Comparison of CA IR and CAIR Plus Proposal Using the Integrated Planning Model (IPM ® 

### ), May 30, 2007.

U.S. EPA. EPA-600/R-05/034; Multipollutant Emission Control Technology Options for Coalfired Power Plants ; March 2005.

U.S. EPA. Integrated Planning Model (IPM ® 

### ) background documentati on located on website: ( http://www.epa.gov/airmarkets/progs regs/epa-ipm/past-modeling.html )

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

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

World Bank Organization. Information located on website: http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqsocc.stmAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-19



### Attachment 1. Illustrative Scrubber Costs (199 9 $) for Representative MW and Heat Rates under the Assumptions in EPA Base Case 2004

Heat Rate (BTU/kWh) Scrubber Type Capacity (MW) 9,000 10,000 11,000 Cost

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 LSFO

Min. Cutoff: >= 100 MW

Max. Cutoff: None

Assuming 3.0% Sulfur Content Coal (by weight) with Heating Value of 11,900

BTU/lb

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

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 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

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

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 LSD

Min. Cutoff: >= 550 MW

Max. Cutoff: None

Assuming 1.5% Sulfur Content Coal (by weight) with Heating Value of 11,900

BTU/lb

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 fr om EPA Integrated Planning Model (IPM ® ) documentation ( http://www.epa.gov/airmarkets/progsregs/epaipm/docs/bc5emission.pdf ). (Note: To adjust cost data from 1999 to 2006, multiply by 1.2101 www.inflationdata.comAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3-20



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

Calculation of Cost per ton of SO2 of scrubbing First, calculate annual cost of a scrubber ($/kW/yr)

Cost data Cap Fix O&M Var O&M

469 19 1.7 $/Kw $/KW-yr $/kWh

Assume Cap Rec Factor CapacFact

0.15 0.85 1/yr dimensionless 8760 h/yr

TOTAL
Implies 70.35 19 12.6582 102.01 This is the annual cost per kW for a scrubber $/KW-yr $/KW-yr $/KW-yr $/KW-yr

Then calculation annual emissions reduction from the scrubber Calculate emissions rate (lb/MBTU) based on coal S content

Fraction S SO2/S Heat Content SO2 Emissions rate
3% 2 divided by 0.012 = 5

dimensls dimesnlss MBTU/lb lb/MBTU

Use emissions rate and assumed plant efficiency/operating hours to get emissions/kw/yr

UnconSO 2 Reduction Heat Rate Cap Facto r Hr/yr tons/lb

5 0.9 0.01 0.85 8760 0.0005 = 0.167535

lb/MBTU dimensionl e MBTU/kWh dimensls hr/yr tons/lb tons/kw-yr

Check of units:

lb mbtu hr ton

mbtu kW - hr yr lb

Result: Get $/ton of reduction
divide cost/kw/yr by ton/kw/yr = 608.877 = 102.01 divided by 0.167535 $/KW-yr tons/kw-yrAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-1



### CHAPTER 4

SOURCE CATEGORY ANALYSIS: INDUSTRIAL, COMMERCIAL, AND

INSTITUTIONAL BOILERS

SOURCE CATEGORY DESCRIPTION

The MANE-VU contribution assessment has demonstrated that SO 2 

### emissions are the principal contributor to visibility impairm ent 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 th at contribute to SO 2 

### emissions. Typical industr ial applications include chemical, refining, manufacturing, metals, paper, petroleum, food producti on and a wide variety

of other small industries and co mmercial heating applications. Commercial and institutional boilers are normally used to produce steam and hot water for space heating in office buildings, hotels, apartment buildings, hospita ls, universities, and similar facilities. Most commercial and

institutional boilers are sma ll, with 80% of the population smaller than 15 million British Thermal Units per hour (MMBTU/hr). A fairly wide range of fuels ar e used by ICI boilers, ranging from coal, petroleum coke, distillate and residual fuel oils, natura l gas, wood waste or other class of waste products. Boilers aggreg ated under the ICI classi fication are generally

smaller than boilers in the electric power industry, and typica lly 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 bo iler 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 a nd paper processing may use biomass as a fuel, resulting in high PM emissions. Units with shor t duty cycles may utilize oil or natural gas as a fuel. The use of a wide variety of fuels is an im portant 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 co mbustion 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-firi ng configuration is a second major identifier of boiler design for solid fuels. St oker boilers are the oldest technology and are still widely used for solid-fueled boilers. Pulveri zed coal boilers succeeded stokers as a more efficient method of burning coal a nd are used in larger boiler desi gns. 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 va riety 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 produ ce electricity and steam or hot water from a single unit. Some ICI boilers are used only in the colder months for space heating, while others have high capacity utilization year round.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-2



### Clean Air Act Regulations Controlling ICI Boilers

Emissions from ICI boilers ar e 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 pollu tants by requiring local governments to adopt State Implementation Plan s (SIPs) that set fo rth their strategy for achieving reductions in the particul ar criteria pollutant(s) for whic h they are out of attainment. The SIP requirements includes Reasonably Availa ble Control Technology (RACT) requirements, but more stringent requirements may be imposed depending on the locale's degree of nonattainment with ambient air standards.

Title I also imposes New Source Performance St andards (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 met hods for the reduction of NO X 

### emissions. Subpart Db applies to fossil fuel-fired ICI units great er 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 NS R). NSR prescribes cont rol technologies for new plants and for plant modifications that result in a significant increase in emissions, subjecting them to Best Available Control Tech nology (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 po llutants from ICI boilers. Thes e 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, SO 2 

### emissions.

Title IV of the CAA addresses acid rain by fo cusing primarily on power plant emissions of SO 2



### . Title IV includes an Opt-in Program that allows sources not required to participate in the Acid Rain Program the opportunity to enter the prog ram on a voluntary basis and receive their own acid rain allowances. The Opt-in Program offers s ources such as ICI boilers a financial incentive to voluntarily reduce its SO 2 

### emissions. By reducing emissions below allowance allocation, an opt-in source will have unused allowances, which it can sell in the SO 2 

### allowance market.

The regulation of ICI boilers by various CAA progr ams has resulted in a variety of unit level emission limits resulting from SI P, NSPS, NSR, or MACT requireme nts. Overlaid on these unit level requirements are system-wide allowances of the NO X 

### SIP call and the Acid Rain SO 2 

### opt-inAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-3



### program. Thus, the specific emission limits and control requirements for a given ICI boiler vary and depend on boiler age, si ze, and geographic location.

EVALUATION OF CONTROL OPTIONS

An undesirable by-product of the combustion of sulfur, SO 2 

### 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 su lfur 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 advan ced substantially over the past 25 years. In additi on, advances in power generati on technologies, renewable energy, and energy efficiency have the pot ential to further reduce emissions from these facilities. The focus of this evaluation is on the first category mentioned above - emissi on control technologies. The timing and magnitude of reductions from th e other strategies – improved technologies, demand reduction/energy efficiency, and clean powe r should be considered as part of a longerterm solution.

Control techniques may be classi fied into three broad categorie s: fuel treatment/substitution, combustion modification, and post-combustion cont rol. Fuel treatment primarily reduces SO 2 

### and includes coal cleaning using physical, chemical , or biological processes. Fuel substitution involves burning a cleaner fuel or renewable fuel. Combus tion modification includes any physical or operational change in the furnace or boiler and is sometimes discussed in conjunction with post-combustion cont rol technologies. Post-combustion control employs a device after the combustion of the fuel and is applied to control emissions of SO 2 

### . 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 Si gnificant Deterioration (PSD) program.

There are a wide variety of proven control technologies for reducing SO 2 

### emissions from ICI

boilers. The method of SO 2 

### control appropriate for any indi vidual ICI boiler is dependent upon the type of boiler, type of fuel, capacity util ization, and the types a nd staging of other air pollution control devices. However, cost e ffective emissions reduction technologies for SO 2 

### are available and are effective in reducing emissions from the exhaust gas stream of ICI boilers.

Effective post-combustion SO 2 

### controls for boilers, and particul arly 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/NS R, State RACT Rules and the Title IV SO 2 

### program. Additional SO 2 

### reductions are anticipated as a result of regional pollution control initiatives prompted by the Clean Air Interstate Ru le (CAIR), which was passed on May 12, 2005.

In addition to post-combustion controls that can be applied to reduce emissions of SO 2 

### from fossil fuel fired boilers, there are other strategies that can be used to reduce emissions of SO 2



### .Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-4



### Examples of such strategies include switching to a fuel with a lower sulfur content, or coal cleaning prior to combustion. Methods of SO 2 

### control applicable to ICI boilers are listed in Table 4.1 with a brief description of the control option, applicability, and ra nge of performance. After the table, a more detailed description of the control option and an analys is of the four factor assessment for reasonable progress is presented.

SO 2 

### Control Option Descriptions

Almost all SO 2 

### emission control technologies fall in the category of reducing SO 2 

### after its formation, as opposed to minimizing its forma tion during combustion. The exception to the nearly universal use of post-combustion cont rols is found in fuel switching and, more significantly, in fluidized bed boile rs, in which limestone is added to the fuel in the combustion

chamber.

Post-combustion SO 2 

### control is accomplishe d by reacting the SO 2 

### in the gas with a reagent (usually calcium- or sodium-b ased) and removing the resulting product (a sulfate/sulfite) for disposal or commercial use de pending on the technology used. SO 2 

### reduction technologies are commonly referred to as Flue Gas Desulfurizatio n (FGD) and are usually described in terms of the process conditions (wet vers us dry), byproduct utilization (thr owaway versus saleable) and reagent utilization (once-th rough versus regenerable).

Within each technology category, multiple variations are possible and typically involve the type and preparation of the reagent, the temperature of the reaction (for dry processes), the use of enhancing additives, etc. Because these variati ons mostly involve complex process chemistry, but are fundamentally similar, this summ ary focuses on the major categories of SO 2 

### control technologies, their applicabil ity, performance and cost. Descriptions of available SO 2 

### control technology options are in Table 4.1. A brie f discussion of these techniques follows.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-5



### Table 4.1 Available SO 2 

### Control Options For ICI Boilers

Technology Description Applicability Performance

Switch to a Low Sulfur Coal (generally <1% sulfur) Replace high-sulfur

bituminous coal combustion

with lower-sulfur coal Potential control measure

for all coal-fired ICIs currently using coal with high sulfur content 50-80% reduction in SO 2 emissions by switching to a

lower-sulfur coal

Switch to Natural Gas (virtually 0% sulfur) Replace coal combustion with natural gas Potential control measure

for all coal-fired ICIs Virtually eliminate SO 2 emissions by switching to natural gas

Switch to a Lower Sulfur

Oil Replace higher-sulfur

residual oil with lowersulfur distillate oil. Alternatively, replace

medium sulfur distillate oil

with ultra-low sulfur

distillate oil Potential control measure

for all oil-fired ICIs currently using higher

sulfur content residual or

distillate oils 50-80% reduction in SO 2 emissions by switching to

a lower-sulfur oil

Coal Cleaning Coal is washed to remove

some of the sulfur and ash prior to combustion Potential control measure

for all coal-fired ICI

boilers 20-25% reduction in SO 2 emissions

Combustion Control A reactive material, such

as limestone or bicarbonate, is introduced

into the combustion chamber along with the

fuel Applicable to pulverized

coal-fired boilers and circulating fluidized bed

boilers 40%-85% reductions in

SO 2 emissions

Flue Gas Desulfurization (FGD) - Wet SO 2 is removed from flue gas by dissolving it in a lime or limestone slurry. (Other alkaline chemicals are sometimes used) Applicable to all coal-fired

ICI boilers 30-95%+ reduction in SO 2 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 SO 2 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 SO 2 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.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-6



### Switch to Coal with Lower Sulfur Content

Switching from a high sulfur fuel to one with suffi ciently low sulfur content is the first option

available for SO 2 

### reduction in this category fo r pre-combustion control of SO 2 

### . Fuels naturally low in sulfur content are readily available for solid (coal) and liqui d (oil) fired boilers. For coalfired boilers, low-sulfur fuels may be obtained directly or, alternativ ely, the sulfur content of coal fired in the boiler may be lowered first by clean ing the coal or blendi ng coals obtained from

several sources.

However, burning low-sulfur fuel may not be a technically feasible or economically practical

SO 2 

### control alternative for all boilers . In some cases, a fuel with the required sulf ur content to meet the applicable emission reduction may not be av ailable or cannot be fire d satisfactorily in a given boiler unit design. Even if such a fuel is av ailable, use of the lower-sulfur fuel that must be transported long distances from the supplier may not be cost competitive with burning higher sulfur fuel supplied by near-by suppliers and using a post-combustion control device. The feasibility of fuel switching depends partly on the characteristics of the pl ant and the particular type of fuel change being considered. Many plants will be able to switch from high-sulfur to

low-sulfur bituminous coal wit hout serious difficulty, but switc hing from bituminous to subbituminous coal may present greater challenges and costs. In some instances, fuel switching will require significant investment and modifications to an existing plant. Switching to a lower sulfur fuel, either coal or oil, can affect fuel ha ndling systems, boiler performance, PM control effectiveness and ash handling systems. Overall SO 2 

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

Switch to Natural Gas

Switching from coal combustion to natural gas combustion virtually eliminates SO 2 

### emissions. It is technically feasible to switch from coal to natural gas, but it is currently uneconomical to consider this option for large ICIs due to the fuel quantity necessary and the price of natural gas. The price of natural gas is roughly seven times th e price of coal in terms of heating value.

Reduced Sulfur Oil

Oil-fired boilers may opt for lower su lfur distillate fuels or, if availa ble, ultra-low sulfur distillate fuel. Number 2 distillate fuel oil, heating oil, and highway diesel fuel oil are the same refineryproduced liquid, and are only differentiated for tax purposes. This differentiation is accomplished through addition of a red dye in the fuels supplied for non-transportation related use. Currently, the sulfur content in Number 2 oil vari es between 15 and 20,000 ppm. Beginning in 2006, the permissible level of sulfur in highway diesel fuel (ultra low sulfur diesel, or ULSD) was reduced to15 ppm. Prior to that, highway low sulfur diesel fuel was refined to contain 500 ppm sulfur (Low Sulf ur Diesel, or LSD). Conseque ntly, refineries have already performed the capital investments required for the production of LS D and ULSD fuel oil. Based on EIA data for the week of Feb 23, 2007 domest ic production of ULSD fuel oil accounted for

about 45% of all distillate oil in the United States and LSD fuel oil accounted for slightly over 17% of domestic production (See Chapter 8).Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-7



### Coal Cleaning

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

Particulate Matter Under the Cl ean Air Act: A Menu of Options , coal cleaning or washing is a widely practiced method of reducing impurities in co al, particularly sulfur. Reducing the sulfur

content of the fuel used in the boiler reduces the SO 2 

### emissions proportiona lly. Coal cleaning

has been shown to reduce SO 2 

### emissions by 20-25%, while incr easing the heating value of the

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

no detailed information on thes e techniques was available.

Conventional (physical) coal wash ing techniques remove ash and sulfur from coal by crushing the fuel and separating the components in a liquid ba th, such as water. The lighter coal particles float to the top of the bath for recovery, while the heavier impurities sink to the bottom for

removal.

Although there are benefits associat ed with coal washing, there ar e limitations associated with this technology. The 20-25% SO 2 

### reduction is beneficial, but post-combustion controls have

been shown to reduce SO 2 

### emissions by greater percentages. Also, solid and liquid wastes are generated using the washing pr ocess and must be addressed.

Combustion Control

SO 2 

### reduction is also possible th rough combustion related contro l technologies. One such technology that has been demonstrated and is cu rrently available is th e use of fluidized bed

boilers.

Fluidized bed boilers generally operate at lowe r temperatures than other combustion systems, 800° to 870° C (1500° F to 1600° F). The lower te mperatures allow the use of limestone or

dolomite to be added to the bed to capture sulfur. Limestone (CaCO 3 

### ) is converted to CaO at approximately 800° C (1500° F). SO 2 

### released from the fuel reacts with CaO to form CaSO 4 

### , which is thermodynamically stable at bed temperat ures. By recycling some of the solids leaving the bed up to 90% removal of SO 2 

### can be achieved with Ca/S molar ratios of 2 to 2.5 in circulating fluidized beds. Higher Ca/S ratios are required in bubb ling beds. In either case, the

sorbent is removed with the ash fr om the bed and sent to disposal.

Flue Gas Desulfurization (FGD)

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

STAPPA-ALAPCO document on cont rol technologies titled Controlling Particulate Matter Under the Clean Air Act: A Menu of Options , EPA reports that 85% of the FGD systems in use in the United States are wet systems. Twelve percent of the FGD systems are spray dry systems, and 3% are dry systems. The operating pa rameters, efficiency, and costs of each SO 2 

### removal

method are different.

SO 2 

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

and an alkaline chemical to form insoluble salts that are removed in the scrubber effluent. These processes are called “wet FGD systems”. Most wet FGD systems for control of SO 2 

### emissionsAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-8



### are based on using either limestone or lime as the al kaline source. At some of these facilities, fly

ash is mixed with the limestone or lime. Seve ral other scrubber system designs (e.g., sodium carbonate, magnesium oxide, dual alkali) ar e used by a small number of boilers.

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

of SO 2 

### emissions from coal-fired electric utility boilers. Limestone sorbent is inexpensive and generally available thro ughout the United States. In a wet limestone scrubber, the flue gas containing SO 2 

### is brought into contact with limestone/water slurry. The SO 2 

### is absorbed into the slurry and reacts with limestone to form an in soluble sludge. The sludge, mostly calcium sulfite hemi-hydrate and gypsum, is disposed of in a pond specifically constructed for the purpose or is recovered as a salable byproduct.

The wet lime scrubber operates in a similar manner to the wet limestone scrubber. In a wet lime scrubber, flue gas containing SO 2 

### is contacted with hydrated lime/water slurry; the SO 2 

### is absorbed into the slurry and r eacts with hydrated lime to form an insoluble sludge. The hydrated lime provides greater alkalinity (higher pH) a nd reactivity than limestone. However, limescrubbing processes require disposal of large quan tities of waste sludge.

The SO 2 

### removal efficiencies of existing wet lime stone scrubbers range from 31-97%, with an average of 78%. The SO 2 

### removal efficiencies of existing wet lime scrubbers range from 30 to 95%. For both types of wet scrubbe rs, operating parameters affecting SO 2 

### removal efficiency include liquid-to-gas ratio, pH of the scrubbing medium, and the ratio of calcium sorbent to SO 2



### . Periodic maintenance is needed because of scaling, erosion, and plugging problems. Recent advancements include the use of additives or design changes to promote SO 2 

### absorption or to reduce scaling and precipitation problems.

A spray dryer absorber (sometimes referred to as wet-dry or semi-dry scrubbers) operates by the same principle as wet lime scrubbing, except that th e flue gas is contacted with a fine mist of lime slurry instead of a bulk liquid (as in wet sc rubbing). For the spray dr yer absorber process, the combustion gas containing SO 2 

### is contacted with fine spray droplets of hydrated lime slurry in a spray dryer vessel. This ve ssel 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 SO 2 

### is absorbed in the slurry and reacts with the hydrated lime reagent to form solid calcium sulfite and calcium sulfate as in a wet lime scrubber. The water is evaporated by the hot flue gas and forms dry, solid particles containing the reacted sulfur. These particles ar e entrained in the flue gas, along with fly ash,

and are collected in a PM collection device. Most of the SO 2 

### removal occurs in the spray dryer vessel itself, although some additional SO 2 

### capture has also been observed in downstream particulate collection devices, esp ecially fabric filters. This pr ocess produces dry reaction waste products for easy disposal.

The primary operating parameters affecting SO 2 

### removal are the calcium-reagent-to-sulfur stoichiometric ratio and the appro ach to saturation in the spray dr yer. To increase overall sorbent use, the solids collected in th e spray dryer and the PM collection device may be recycled. The

SO 2 

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

For the dry injection process, dr y powdered lime (or another suitable sorbent such as trona) is directly injected into the ductwork upstream of a PM control device. Some systems use sprayAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-9



### humidification followed by dry injection. This dr y 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 SO 2 

### is adsorbed and reacts with the powdered sorbent. The dry solids are entrained in the combustion gas str eam, along with fly ash, and collected by the PM

control device. The SO 2 

### removal efficiencies of existing dr y injection systems range from 40 to

60%.

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR ICI

BOILERS

Each of the control options presen ted in Table 4.1 is reviewed in this section utilizing a four factor analysis approach for determining reas onable progress as requi red by Section 169A(g)(1)

of the Clean Air Act and Section 51.308(d)(1)(i)(A). The informati on provided in this section is intended to be used by the States in setti ng Reasonable Progress Goal s (RPGs) for reducing regional haze in Class I areas in MANE-VU Class I areas.

Cost of Compliance

To compare the various control options, information has been co mpiled on the cost-effectiveness of retrofitting controls. In genera l, cost-effectiveness increases as boiler size and capacity factor (a measure of boiler utilization) increases.

Cost of Switching to Low Sulfur Coal , Distillate Oil, or Natural Gas

Switching to a low-sulfur coal or blending a lower sulfur coal can impact cost due to the following two main reasons:

1. The cost of low-sulfur coal co mpared to higher sulfur coal.

2. The cost of boiler or coal handli ng equipment modifications necessary

The cost of low-sulfur coal compared to higher su lfur coal is not only related to the “dollar per ton” cost of the coal, but the heating value of the coal also impacts the cost analysis.

Table 4.2 reflects the pote ntial sulfur reduction po ssible by switching fuels:

Table 4.3 shows the average 2004 and 2005 cost data from the Energy Information

Administration for various fuels.

Refineries were required to ma ke significant capital investments to meet the LSD and ULSD highway fuel sulfur requirement. To achieve the LSD and ULSD sulfur goals, refineries were required to implement diesel de sulfurization te chnologies. Estimates for the capital costs were developed in 2001 by the Energy Information Ad ministration (EIA) and are based on calendar year 1999. Table 4.4 presents the capital costs for desulfurizati on technologies presented by the EIA. The EIA developed estimates for new a nd revamped desulfurization technologies at existing refineries.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-10



### Table 4.2 Potential SO 2 

### Reductions Through Fuel Switching

Original Fuel Sub-bituminous Coal

(% Reduction) Distillate oil

(% Reduction) Natural Gas

(% Reduction)

Bituminous Coal 72.9 91.2 99.9

Sub-bituminous coal - 69.5 99.9

Residual Oil - 91.5 99.9

Distillate Oil - - 99.7

Calculations based on typical fuel sulfur content listed in Department of Energy EIA analysis for 2000. Energy Policy Act Transportation Rate Study: Final Report on Coal Transportation



### In its highway diesel fuel rulemaking, EPA also developed cost estimates for the deployment and implementation of desulfurization technologies at refine ries. EPA estimated that it would cost existing refineries an estimated $50 million per refi nery to install desulfurization technologies. No estimates were made for the costs associated with new refineries as none are currently being

constructed in the United States. The EPA anal ysis spread the investment cost over a 2-year period. Consequently, it was estimated that the US refinery-wide investment for calendar year 2004 was $2.45 billion and $2.83 billion for calenda r year 2005 (EIA 2001) (Converted from 2001 to 2006 dollars using a conversion factor of 1.1383 www.inflationdata.com ).

Using the most recently available EIA price information for 2006 No. 2 Distillate oil for industrial, commercial, and institu tional facilities in the northeas t (excluding taxes), a cost per

ton of SO 2 

### removed was calculated to be $734/ton SO 2 

### by switching to 500 ppm LSD and $554/ton SO 2 

### by switching to ULSD fuel oils. (See the di scussion of fuel oil prices in Chapter 7 – Heating Oil.)

Cost of Coal Cleaning

The World Bank, an organization which assist s with economic and technological needs in developing countries reports that the cost of physically cleaning co al 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.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-11



### Cost of Combustion Control

Dry sorbent injection, (DSI), systems have lower capital a nd operation costs than postcombustion FGD systems due to: simplicity of de sign, lower water use requirements, and smaller land use requirements. Table 4.3 presents the estimated costs of adding DSI based SO 2 

### controls to ICI boilers based on boiler size, fuel type, and capacity factor. Capacity factor is the amount of energy a boiler generates in one year divided by the total amount it could generate if it ran at full capacity.

Table 4.3 Estimated Dry Sorbent Injection (DSI) Costs For ICI Boilers (2006 dollars)

Cost Effectiveness ($/Ton of SO 2 )

Fuel SO 2 Reduction (%) Capacity Factor (%) 100

MMBTU/hr 250

MMBTU/hr 1,000

MMBTU/hr

14 4,686 3793 2,979

50 1,312 1062 834 2%-sulfur

coal 40

83 772 624 490

14 2,732 2,212 1,737

50 765 619 486 3.43%-sulfur

coal 40

83 450 364 286

14 2,205 1,786 1,402

50 617 500 392 2%-sulfur

coal 85

83 363 294 231

14 1,286 1,040 818

50 360 291 229 3.43%-sulfur

coal 85

83 212 171 134

Calculations based on information available from EPA Publications, EPA-452/F-03-034, Air Pollution Control Technology Fact Sheet , and EPA-600/R-05-034, Multipollutant Emission Control Technology Options for Coalfired Power Plants (Converted from 2005 to 2006 dollars using a conversion factor of 1.0322 www.inflationdata.com )



### Cost of FGD

Installation of post-combustion SO 2 

### control in the form of FGD has several impacts on facility operation, maintenance, and waste handling. FGD systems typically require significant area for construction of the absorber towers, sorbent tanks , and waste handling. The facility costs are, therefore, variable and dependent on the ava ilability of space for construction of the FGD system. Solid waste handling is a nother factor that infl uences the cost of FGD control systems. Significant waste material may be generated that requires disposal. This cost may be mitigated, however, by utilization of a forced oxidation FGD process that produ ces commercial quality gypsum, which may be sold as a raw mate rial for other commercial processes.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-12



### Table 4.4 presents the total estimated co st effectiveness of adding FGD based SO 2 

### controls to ICI boilers based on boiler size, fuel type, and capacity factor. There is no indication that these cost data include revenue from gypsum sales. Reve nue from gypsum sales would reduce the cost of

these controls.

Table 4.4 Estimated Flue Gas Desulfurizatio n (FGD) Costs For ICI Boilers (2006 dollars)

Cost Effectiveness ($/Ton of SO 2 )

Fuel Technology SO 2 Reduction (%) Capacity Factor (%) 100

MMBTU/hr 250

MMBTU/hr 1,000

MMBTU/hr

14 3,781 2,637 1,817

50 1,379 1,059 828 High-sulfur

coal a FGD (Dry) 40

83 1,006 814 676

14 4,571 3,150 2,119

50 1,605 1,207 928 Lower-sulfur

coal b FGD (Dry) 40

83 1,147 906 744

14 4,183 2,786 1,601

50 1,290 899 567 Coal FGD (Spray

dry) 90

83 843 607 407

14 3,642 2,890 1,909

50 1,116 875 601 High-sulfur

coal a FGD (Wet) 90

83 709 563 398

14 4,797 3,693 2,426

50 1,415 1,106 751 Lower-sulfur

coal b FGD (Wet) 90

83 892 705 492

14 10,843 8,325 5,424

50 2,269 1,765 1,184 Oil c FGD (Wet) 90

83 1,371 1,079 740

a. Assumes sulfur content = 3.43% and ash content = 12.71%.

b. Assumes sulfur content = 2.0% and ash content = 13.2%. c. Sulfur content of oil is not specified. Table references:

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

2006. Primary Reference: Khan, S. Methodology, Assumptions, and References—Preliminary SO 2 Controls Cost Estimates for Industrial Boilers (EPA-HQ-OAR-2003-0053-166), October-November 2003. (Converted from 2004 to 2006 dollars using a conversion factor of 1.0672 www.inflationdata.com )



### Time Necessary for Compliance

Generally, sources are given a 2-4 year phase-in period to comply with new rules. Under the previous Phase I of the NO X 

### SIP Call, EPA provided a complianc e date of about 31⁄2 years from

the SIP submittal date. Most MACT standards a llow a 3-year compliance period. Under Phase IIAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-13



### of the NO X 

### SIP Call, EPA provided a 2-year period after the SIP submittal date for compliance. States generally provided a 2-yearperiod for compliance with RACT rules. For the purposes of this review, we have assumed that a 2-year period after SIP submittal is adequate for precombustion controls (fuel switchi ng or cleaning) and a three year period for the installation of post combustion controls.

For BART control measures, the proposed BA RT guidelines require States to establish enforceable limits and require compliance with the BART emission limitations no later than 5 years after EPA approves the regional haze SIP.

Refiners in the United States are already pr oducing low sulfur diesel fuel which may be

marketed as distillate oil. Th ere is a potential that offshore re finers may not be able to produce enough 15 ppm sulfur for export to the Northeast United States to meet peak demand, but so far

this has not occurred.

ICI boilers would not have to retrofit or inst all expensive control t echnology to burn ULSD distillate fuel oil, therefore, compliance with th e standard is driven by supply and demand of the

lower sulfur distillate oils.

For combustion based and post-combustion based engineering and construction leads times will vary between 2 and 5 years depend ing on the size of th e facility and specif ic control technology

selected.

Energy and Non-Air Impacts

Fuel switching and cleaning do not significantly affect the efficiency of the boiler but may add to transportation issues and secondary environmenta l impacts from waste disposal and material handling operations (e.g. fugitive dust). FGD systems typically operate with high pressure drops across the control equipment, resu lting 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 ga s reheating to preven t physical damage to equipment, resulting in higher fuel usage.

The primary environmental impact of FGD system s is the generation of wastewater and sludge

from the SO 2 

### removal process. When the exhaust gas from the boiler enters the FGD the SO 2 

### , metals, and other solids are removed from the exhaust and collected in the FGD liquid. The liquid slurry collects in the botto m 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 trea tment 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 exces sive pollutants from wastewater. This places additional burdens on a facility or community wa stewater treatment and solid waste management capabilities. These impacts will need to be analyz ed on a site-specific basis. If lime or limestone scrubbing is used to produce calci um sulfite sludge, the sludge mu st be stabilized prior to land filling. If a calcium sulfate sludge is produced, dewatering alone is necessary before land filling,Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-14



### however, SO 2 

### removal costs are higher due to increased equipment costs for this type of control system. In some cases calcium sulfate sludg e can be sold for use in cement manufacturing.

With wet FGD technologies a significant visibl e plume is present from the source due to condensation of water vapor as it exits th e smoke stack. Although the water eventually evaporates and the plume disappears, community impact may be significant.

Reducing the sulfur contents of di stillate fuel oil has a variety of beneficial consequences for ICI

boilers. Low sulfur distillate fuel is cleaner burning and emits less particulate matter which reduces the rate of fouling of heating units substantially a nd permits longer time intervals between cleanings. According to a study conducte d by the New York State Energy Research and Development Authority, (NYSER DA), boiler deposits are reduced by a factor of two by lowering the fuel sulfur content from 1,400 ppm to 500 ppm. These reductions in buildup of deposits result in longer servic e intervals between cleanings. (Batey a nd McDonald 2005)

Remaining Useful Life of the Source

Available information for remaining useful life estim ates of ICI boilers indi cates a wide range of operating time, depending on size of the unit, ca pacity factor, and level of maintenance performed. Typical life exp ectancies range from about 10 years up to over 30 years.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Indus trial, Commercial, and Institutional Boilers Page 4-15



### REFERENCES

Batey, J.E. and R. McDonald, 2005. Low Sulfur Home Heating Oil Demonstration Project Summary Report . Project funded by The New York Sate Energy Research and Development Authority. Contr act No. 6204-IABR-BR-00.

U.S. EPA, 2005, Multipoint Emission Control Technology Options for Coal-fired Power Plants

, Washington, DC, EPA-600/R-05/034.

U.S. EPA, 2003, Air Pollution Control Technology Fact Sheet , Washington, DC, EPA-425/F-03-

034.

STAPPA ALAPCO, 2006, Controlling Fine Particulate Matte r Under the Clean Air Act: A Menu of Options

.

The Lake Michigan Air Directors Consortium, Midwest Regional Planning Organization Boiler Best Available Retrofit T echnology Engineering Analysis , March 30, 2005

U.S. EPA, 1993, PM-10 Innovative Strategies: A Sour cebook for PM-10 Control Programs

, Research Triangle Par k, NC, EPA-452/R-93-016.

U.S. Energy Information Administration, October 2000, Energy Policy Act Transportation Rate Study: Final Report on Coal Transportation , Publication downloaded from World Wide Web in February, 2007 at http://www.eia.doe.gov/cneaf/coa l/coal_trans/epact2000.html

GE Water & Process Technologies. In formation accessed on web March 27, 2007: http://www.zenon.com/applications/F GD_wastewater_treatment.shtml

U.S. Energy Information Administration, 2007. :”N o. 2 Distillate Prices By Sales Type”, Information downloaded from the World Wide Web on March 7, 2007, at http://tonto.eia.doe.gov/dnav/pe t/pet_pri_dist_dcu_R1X_m.htm

U.S. Energy Information Administration, 2007. :” weekly Inputs, Utiliz ation and Production”, Information downloaded from the World Wide Web on March 7, 2007, at http://tonto.eia.doe.gov/dna v/pet/pet_pnp_wiup_dcu_r10_w.htmThis page left blank intentionally.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5-1



### CHAPTER 5

ANALYSIS OF SELECTED INDUSTRIAL , COMMERCIAL, AND INSTITUTIONAL

BOILERS

SOURCE CATEGORY DESCRIPTION

Modeling of visibility impacts on Class I regi ons was conducted by the Vermont Department of Environmental Conservation (VTDEC) and M ANE-VU to identify the major ICI sources contributing to visibility impairment in the northe ast. Table 5.1 lists the ICI sources identified to contribute significant levels of SO 2 

### to the MANE-VU region. MACTEC was directed by

MARAMA and the Reasonable Pr ogress Workgroup to focus on the 17 major sources listed in

Table 5.1.

As explained in the previous chapter, there are a wide variety of proven control technologies for reducing SO 2 

### emissions from ICI boilers and specifically the control method for SO 2 

### applied to any individual ICI boiler is depe ndent upon the type of boiler, type of fuel, capacity utilization, and the types and staging of ot her air pollution control devices. However, cost effective emissions reduction technologies for SO 2 

### are available and are eff ective in reducing emissions from the exhaust gas stream of ICI boilers.

INFORMATION OBTAINED FROM STATE AGENCIES

For the selected ICI boilers, MACTEC contacted State and or regional regulatory agencies to evaluate the status of each unit and determine if additional pollution controls had been mandated as a part of regulatory actions taken since the da ta used for the visibility impairment modeling were collected. Table 5.1 presents th e information obtained from the States.Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page5-2Table 5.1 Point Source InformationCollected from the Top 17 Industrial Facilities Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)Primary Emissions PointDescriptionPoint ID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationFluid Coking Unit (FCU)and FCU Carbon MonoxideBoiler002 57,199 barrelsper day of totalfeedNone CansolvRegenerativeWet GasScrubber andSNCRData from PermitAPC-82/0829Amendment 5 SO2permit limit is 174 tpyMotivaEnterprisesLLC –DelawareCity1DE 29,747Fluid Catalytic CrackingUnit (FCCU) and FCCUCarbon Monoxide Boiler012 FCCU coke burnrate limit is56,000 lbs/hrNone CansolvRegenerativeWet GasScrubberData from PermitAPC-82/0981Amendment 6 SO2permit limit is 361 tpyAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page5-3Table 5.1 Point Source InformationCollected from the Top 17 Industrial Facilities Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)Primary Emissions PointDescriptionPoint ID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationKodak ParkDivision2, 3NY 23,508 Building 31 and 321stationary combustioninstallations, includingpackage ABD built upboilers used for thegeneration of process steamand electricityBoilers:1 – Package boiler, No. 62 – Package boiler, No. 63 – Package boiler, No. 64 – Package boiler, No. 613 – Underfed stoker, coal14 – Underfed stoker, coal11 – Underfed stoker, coal12 – Underfed stoker, coal15 – Wet bottom cyclone,coal/No. 616 – Wall-fired, coal/No. 641 – Wet bottom cyclone,coal/No. 642 – Wet bottom cyclone,coal/No. 643 – Wet bottom cyclone,coal/No. 644 – Tangential-firedpulverized coal, coal/No. 2U0015Boilers (EP031B-1):12341314Boilers (EP031B-2):11121516Boilers (EP321B-3):4142Boilers (EP321B-4):434498 MMBTU/hr98 MMBTU/hr98 MMBTU/hr98 MMBTU/hr265 MMBTU/hr265 MMBTU/hr197 MMBTU/hr222 MMBTU/hr478 MMBTU/hr544 MMBTU/hr500 MMBTU/hr500 MMBTU/hr640 MMBTU/hr670 MMBTU/hrNone BARTanalysis - NOX& SO2controlsaffordable onBoilers 41, 42,& 43Wet scrubber(90%reduction)would be~$2,150/tonDry scrubber(40%reduction)would be~$1,850/tonProcess K07 (Bldg 31) isNo. 6 fuel oil combustionin package boilersProcess K09 (Bldg 31) isbituminous coalcombustion in built upBoilers 13 and 14Process K10 (Bldg 31) isNo. 6 fuel oil combustionin built up Boilers 15 and16Process K11 (Bldg 31) isbituminous coalcombustion for built upBoiler 15Process K12 (Bldg 321)is No. 6 fuel oilcombustion for built upBoilers 41, 42 and 43Process K13 (Bldg 321)is bituminous coalcombustion for built upBoilers 41, 42 and 43Process K14 (Bldg 321)is No. 2 fuel oilcombustion with NSPSapplicability in Boiler 44Process K15 (Bldg 321)is bituminous low sulfurcoal combustionAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page5-4Table 5.1 Point Source InformationCollected from the Top 17 Industrial Facilities Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)Primary Emissions PointDescriptionPoint ID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationNo.5 Coal Boiler - wetbottom, pulverized coalfired boiler (C. E. modelVU-40), capable of runningon #2 fuel oil as backup fuelB001 380 MMBTU/hrmaximum heatinputCyclone/multi-cloneESPNone9.9 lbs of sulfur dioxideper MMBTU actual heatinputNo.7 Coal Boiler - wetbottom, pulverized coalfired boiler (C. E. modelVU-405), capable ofrunning on #2 fuel oil asbackup fuelB002 422 MMBTU/hrmaximum heatinputCyclone/multi-cloneESPNone 9.9 lbs of sulfurdioxide per MMBTUactual heat inputMW CustomPapers LLC –ChillicotheMill4OH 23,216No.8 Coal Boiler - wetbottom, pulverized coalfired boiler (C. E. modelVU-40), capable of runningon #2 fuel oil as backupfuel.B003 505 MMBTU/hrmaximum heatinputCyclone/multi-cloneESPNone 9.9 lbs of sulfurdioxide per MMBTUactual heat inputAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page5-5Table 5.1 Point Source InformationCollected from the Top 17 Industrial Facilities Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)Primary Emissions PointDescriptionPoint ID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationTwo fuel burninginstallations (B-83-1 & B253-1) w/a total of 19 coalfired boilers of which 14units (#18-#24) are located atPowerhouse B-83-1 & 5units (#25-#29) are located atPowerhouse B-253-1. Theprimary fuel is coal. Inaddition, wood, waste solids,waste liquids, & biosludgemay be burned in thesePowerhouses, while NG &process gas may also beburned in the Powerhouse B253-1 boilers.82-0003-01-19(020101,021520)6,625 MillionBTU/hr nominalheat inputESP ScubberspotentiallyThe five boilers inPowerhouse B-253-1are subject to BART.The State does nothave confirmation yet,but they believe thatthe boilers will becontrolled byscrubbers of some sort.Units #11-#17, thatwere located atPowerhouse B-83-1,have been removedEastmanChemicalCompany5, 6TN 22,882Coal-Fired Boilers 30 and31PESB-325-1or82-1010-15(261501)Heat input islimited to 780and 880MMBTU/hr,respectively, ona 30 calendarday rollingaverage basisNone NoneWestvaco FinePapers7, 8MD 19,083 Boiler 24 is a coal firedcyclone boiler1 590 MMBTU/hrmaximum heatinputSNCR(NOX)ESP (PM)Baghouse(PM)Not BART eligibledue to ageAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page5-6Table 5.1 Point Source InformationCollected from the Top 17 Industrial Facilities Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)Primary Emissions PointDescriptionPoint ID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationBoiler 25 is a coal firedtangential boiler2 785 MMBTU/hrmaximum heatinputLow NOXburners/overfired air(NOX)ESP (PM)Scrubber(FGD indesign)SNCR (NOX)Baghouse toreplace ESP(PM)BART eligibleBoiler 3 is a coal-firedboiler installed in 1942 andmodified in 1981R011 (002)or S076243 MMBTU/hr Fabric filterLow NOXburnersNone Not BART eligibleBoiler 4 is a coal-fired andnatural gas-fired boilerinstalled in 1952R015 (001)or S076496 MMBTU/hr ESPLow NOXburnersNone Not BART eligiblePPG IndustriesInc.9WV 12,678Boiler 5 is a coal-firedboiler installed in 1966R072 (003)or S482878 MMBTU/hr ESPLow NOXburnersNone BART eligible, facilityto decrease emissionsby using low-sulfurcoal and taking anemission limit of1,478.8 lb SO2/hrAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page5-7Table 5.1 Point Source InformationCollected from the Top 17 Industrial Facilities Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)Primary Emissions PointDescriptionPoint ID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationWilliamsEthanolServicesInc.10, 11IL 12,244 4 boilersBoiler A & B are coal-firedboilers constructed in 1944Boiler C is a coal/oilsupplemental-fired boilerconstructed in 1958Boiler D is a NG/No. 2 oilfired boiler constructed in197610 Boilers A & B:242 MMBTU/hrBoiler C:330 MMBTU/hrBoiler D:195 MMBTU/hrBoilers A &B: MulticycloneBoiler C:ESPBoiler D:NoneNone Not BART eligible.There is also a steepacid preparationsystem (Unit 2) thatconverts sulfur intosulfurous acid that willbe used for thesteeping process.Total sulfur usage forthis unit is limited to961,750 lbs/yr (at least48% of the sulfuradded to steepwatershall be retained in theproducts shipped fromthe plant).Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page5-8Table 5.1 Point Source InformationCollected from the Top 17 Industrial Facilities Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)Primary Emissions PointDescriptionPoint ID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationCorn ProductsInternationalInc.10, 11IL 9,281 Utilities:Coal fired Boilers #1, #2,  (pre 1972)Natural gas-fired Boilers #4& #5 (pre 1972)Natural gas-fired Boiler #6constructed in 19922 natural gas-fired turbinesconstructed in 1995Group 9 Boilers #1, #2, :250 MMBTU/hrBoilers #4 & #5:312.5MMBTU/hrBoiler #6:600 MMBTU/hrTurbines:65 MMBTU/hrBoilers #1,#2, & #3:ESPBoilers #4 : NoneBoiler #6:low-NOXburner &flue gasrecirculationTurbines:NoneNone Not BART eligibleMeadWestvacoPackagingResourceGroup12VA 8,552 Four (4) boilers#6 – primarily coal-fired#7 – coal/bark/wood-fired#8 - coal/bark/wood-fired#9 – primarily coal-fired25 550 MMBTU/hr440 MMBTU/hr580 MMBTU/hr807 MMBTU/hrESPScrubbersFGRLNBNonePH GlatfelterCo./SpringGrove13, 14PA 7,855 #4 Power Boiler that burnsbituminous coal (13tons/hr), #6 oil (751 gal/hr),& #2 oil (108 gal/hr)034 363.7MMBTU/hrCyclonedustcollectorESPNone Not BART eligibleAssessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page5-9Table 5.1 Point Source InformationCollected from the Top 17 Industrial Facilities Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)Primary Emissions PointDescriptionPoint ID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformation#5 Power Boiler that burnsbituminous coal (10.3tons/hr), #6 oil (300 gal/hr),“as fired” wood (12.2tons/hr), & #2 oil (451.2gal/hr)035 262.3MMBTU/hrCyclonedustcollectorESPNone BART eligible"A" Boiler, which is a coalfired boilerB101 301 MMBTU/hr ESP None 4.64 lbs of sulfurdioxide per MMBTUactual heat input forB101, B102, and B103exiting throughStack 4"B" Boiler, which is a coalfired boilerB102 301 MMBTU/hr ESP None 4.64 lbs of sulfurdioxide per MMBTUactual heat input forB101, B102, and B103exiting throughStack 4Goodyear Tire& Rubber Co.4OH 5,903"C" Boiler, which is a coalfired boilerB103 174 MMBTU/hr ESP None 4.64 lbs of sulfurdioxide per MMBTUactual heat input forB101, B102, and B103exiting throughStack 4Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page5-10Table 5.1 Point Source InformationCollected from the Top 17 Industrial Facilities Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)Primary Emissions PointDescriptionPoint ID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationSunoco Inc.(R&M)15, 16PA 3,645 Plt. 10-4 FCC Unit 101 4,792.000 bbl/hrfresh feedNone SCR and a wetgas scrubberinstalled in2010. At thelatest,compliance isrequired by2013.SO2limit of 9.8lbs/1000 lbs of cokeburn-off in the catalystregenerator determineddaily on a 7-dayrolling average basisValeroRefining Co. –NJ17, 18NJ 3,597 FCCU Regenerator with InLine HeaterE21 or U1 102 MMBTU/hr WGS None Per Consent Decree,SO2concentrationemission limits at thepoint of emission tothe atmosphere of nogreater than 25 ppmvd,measured as a 365-dayrolling average, and 50ppmvd, measured as a7-day rolling average,both at 0% O2.StoneContainerCorp. (dbaSmurfit-StoneContain)19VA 3,379 #8 Power Boiler that burnsbituminous coal2 1,056MMBTU/hrNone Wet gasscrubber(2007)Consent Decree dated11/2004 which statesthat SO2emission ratewill not exceed 0.26lb/MMBTU on a 30-day rolling averagebasis.Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page5-11Table 5.1 Point Source InformationCollected from the Top 17 Industrial Facilities Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)Primary Emissions PointDescriptionPoint ID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationGreat NorthernPaper Inc. MillWest20, 21ME 1,842 Power Boilers #4 (RileyStoker))004 (WB4) 740 MMBTU/hr None None Unit to be shut downso BART not an issue(only BART eligiblesource at this facility)NRG EnergyCenter DoverLLC1, 22, 23DE 1,836 Riley Stoker Boiler fired onpulverized bituminous coal(primary fuel) and naturalgas (for startup/ignition).C-1 (001) 243 MMBTU/hr Four (4) DBRiley LowNOXburnersCyclonicCombustionVenturiburnerassembliesLow excessairESPw/23,000 ft2collectingelectrodeareaNone Not BART eligibleSappiSomerset20, 21ME 1,734 Power Boiler #1 (Babcock& Wilcox)001 (PB#1) 848 MMBTU/hr(all fuels) &250 MMBTU/hr(fossil fuels)None None CEMS for SO2Facility to reduce SO2emissions by 50% by2013 (BART deadline)1MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid-Atlantic NorthEastern Class I Areas”, March 8, 2007.Comments regarding Motiva Enterprises LLC – Delaware City and NRG Energy CenterDover LLC facilities received from Mr. John Sipple (302-739-9435,John.Sipple@state.de.us) via E-mail on March 13, 2007.Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page5-122New York State Department of Environmental Conservation, Division of Air Resources.Personal communicationsregarding Kodak Park Division facility between Mr. MikeCronin, P.E. (518-402-8403,mpcronin@gw.dec.state.ny.us) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on February 1 and 9, 2007.3New York State Department of Environmental Conservation, Division of Air Resources.Personal communicationsregarding Kodak Park Division facility from Mr. MikeCronin, P.E. (518-402-8403,mpcronin@gw.dec.state.ny.us) via E-mail on February 12, 2007.4Ohio Environmental Protection Agency, Division of Air Pollution Control. Personal communication regarding MW Custom Papers LLC– Chillicothe Mill and Goodyear Tireand Rubber Company facilities from Mr. William Spires (614-644-3618,bill.spires@epa.state.oh.us) via E-mails on February 20, 2007.5Tennessee Department of Environment and Conservation, Division of Air Pollution Control. Personal communication regarding Eastman Chemical Company facility from Ms.Julie Aslinger (615-532-0587,Julie.Aslinger@state.tn.us) via E-mail on March 1, 2007.6MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid-Atlantic NorthEastern Class I Areas”, March 8, 2007.Comments regarding Eastman Chemical Company facility received from Ms. Julie Aslinger (615-532-0587,Julie.Aslinger@state.tn.us) via E-mail on March 30, 2007.7Maryland Department of the Environment. Personal communication regarding Westvaco Fine Papers facility between Mr. Andy Heltibridle (410-537-4218,aheltibridle@mde.state.md.us) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007.8Maryland Department of the Environment.Personal communication regarding Westvaco FinePapers facility from Mr. Andy Heltibridle (410-537-4218,aheltibridle@mde.state.md.us) via E-mail on January 31, 2007.9West Virginia Division of Air Quality.Personal communications regarding PPG, Industries, Inc. facility between Ms. Laura Crowder (304-926-0499 Ext. 1247,LCROWDER@wvdep.org) and Mr. Steve Pursley (304-926-0499 Ext. 1218) and Ms. LoriCress, MACTEC Federal Programs, Inc., on March 14, 2007.10Virginia Department of Environmental Quality, Division of Air Quality. Personal communication regarding Mead Westvaco Packaging Resource Group facility between Ms.Doris McLeod (504-698-4197,damcleod@deq.virginia.gov) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on February 20, 2007.11Pennsylvania Department of Environmental Protection, Bureau ofAir Quality. Personal communication regarding PH Glatfelter Company/Spring Grove facility between Ms.Nancy Herb (717-783-9269,nherb@state.pa.us) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007.12Pennsylvania Department of Environmental Protection, Bureau ofAir Quality. Personal communications regarding PH Glatfelter Company/Spring Grove facility from Ms.Nancy Herb (717-783-9269,nherb@state.pa.us) via E-mail on January 31 and February 7, 2007.13Illinois Environmental Protection Agency, Bureau of Air. Personal communication regarding Williams Ethanol Services Incorporated and Corn Products InternationalIncorporated facilities between Mr. Rob Kaleel (217-524-4387,Rob.Kaleel@illinois.gov) and Ms. Lori Cress, MACTEC FederalPrograms, Inc. on February 2, 2007.14Illinois Environmental Protection Agency, Bureau of Air. Personal communication regarding Williams Ethanol Services Incorporated and Corn Products InternationalIncorporated facilities from Mr. Rob Kaleel (217-524-4387,Rob.Kaleel@illinois.gov) via E-mail on February 2, 2007.15Pennsylvania Department of Environmental Protection, Bureau ofAir Quality. Personal communications regarding Sunoco Inc. (R&M) facility between Ms.Nancy Herb (717-783-9269,nherb@state.pa.us) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007.16Pennsylvania Department of Environmental Protection, Bureau ofAir Quality. Personal communications regarding Sunoco Inc. (R&M) facility from Ms. Nancy Herb (717-783-9269,nherb@state.pa.us) via E-mail on February 22, 2007.17New Jersey Department of Environmental Protection, Division of Air Quality. Personal communications regarding Valero RefiningCompany facility between Mr. Ray Papalski(609-633-7225,Ray.Papalski@dep.state.nj.us) and Ms. Lori Cress, MACTEC Federal Programs,Inc. on January 31 and February 2, 2007.18New Jersey Department of Environmental Protection, Division of Air Quality. Personal communication regarding Valero Refining Company facility from Mr. Ray Papalski(609-633-7225,Ray.Papalski@dep.state.nj.us) via E-mail on February 21, 2007.19Virginia Department of Environmental Quality, Division of Air Quality. Personal communication regarding Stone Container Corporation facility fromMs. Doris McLeod (504-698-4197,damcleod@deq.virginia.gov) via E-mail on February 9, 2007.20Maine Department of Environmental Protection Agency, Bureau of Air Quality. Personal communications regarding Great Northern Paper Incorporated Mill West and Sappi -Somerset facilities between Ms. Lynn Ross (207-287-8106,Lynn.Ross@maine.gov) and Mr. Marc Cone (207-287-2437) and Ms. LoriCress, MACTEC Federal Programs, Inc.on February 2, 2007.21Maine Department of Environmental Protection Agency, Bureau of Air Quality. Personal communication regarding Great Northern Paper Incorporated Mill West and Sappi -Somerset facilities between Ms. Lynn Ross (207-287-8106,Lynn.Ross@maine.gov) via E-mail on February 2, 2007.Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page5-1322Delaware Department of Natural Resources and Environmental Control, Divisionof Air and Waste Management. Personal communications regarding NRG Energy CenterDover LLC facility between Ms. Tammy Henry (302-323-4542,Tammy.Henry@state.de.us) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on March 5, 2007.23Delaware Department of Natural Resources and Environmental Control, Divisionof Air and Waste Management. Personal communications regarding NRG Energy CenterDover LLC facility from Ms.Tammy Henry (302-323-4542,Tammy.Henry@state.de.us) via E-mail on March 5, 2007.This page left blank intentionally.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6-1



### CHAPTER 6

SOURCE CATEGORY ANALYSIS: KILNS

SOURCE CATEGORY DESCRIPTION

Portland cement is a main ingredient for c oncrete and other common building materials. Portland cement is mainly composed of clinke r, a material formed by heating limestone and other ingredients to temperatures over 1,400 o 

### C (2,650 o 

### F). High combustion temperatures require large amounts of fuel and can re sult in significant emissions of SO 2 

### and NO X 

### . Crushing of ingredients and finished clinker can release dust and particles. Ammonia is sometimes produced during the heating of limestone.

Figure 6.1 shows a process flow diagram of a Portland cement facilit y. The process flow diagram (taken from AP-42) shows both wet and dry Portland cement processes.

Figure 6.1 Portland Cement Process Flow Diagram

EPA. January, 1995. AP42 Section 11.6 – “Portland Cement Manufacturing”.



### Figure 6.1 shows that the Portland cement pro cess can generally be broken down into the following steps: raw materials handling, ra w material preparation, dry mixing, optionalAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6-2



### preheating and/or precalcining, kiln treatment (pyroprocessing step), clinker handling and storage, and finishing operati ons (finishing, storage and shipme nt). The pyroprocessing step transforms the raw mix into clinkers, which are gr ay, glass-hard, sphericall y shaped nodules that range from 0.125 to 2.0 inches in diameter.

The pyroprocessing step is the predominant source of gaseous pollutant emissions. In general, there are five different processes used in the Portland cement industry to accomplish the pyroprocessing step: the wet proce ss, the dry process (long dry pro cess), the semidry process, the dry process with a preheater, and the dr y process with a preh eater/precalciner.

Each of the pyroprocessing types vary with re spect to equipment design, method of operation, and fuel consumption. Generally, fuel consumpti on decreases in the order of the processes listed due to the heat required to evaporate water presen t in the raw material sl urry (e.g., wet processes use the most fuel).

In the long dry process, all of the pyroprocessing activity occurs in the rotary kiln. Dry process pyroprocessing systems have been improved in thermal efficiency and productive capacity through the addition of one or more cyclone-type preheater vessels in th e gas stream exiting the rotary kiln. This system is called the preheater process. The vessels ar e arranged vertically, in series, and are supported by a stru cture known as the preheater towe r. Hot exhaust gases from the rotary kiln pass counterc urrently through the downward-moving raw materials in the preheater vessels. Compared to th e simple rotary kiln (long dry pro cess), the heat tr ansfer rate is significantly increased, the degree of heat utilizati on is greater, and the process time is markedly reduced by the intimate contact of the solid par ticles with the hot gases. The improved heat transfer allows the length of the rotary kiln to be reduced. An added benefit of the preheater operation is that hot gases from th e preheater tower are used to he lp dry raw materials in the raw

mill. Because the catch from the mechanical co llectors, fabric filters, and/or electrostatic precipitators (ESP) that follow the raw mill is retu rned to the process, these devices can also be considered to be production machines as well as pollution control devices.

Additional thermal efficiencies and productivity gains have been achieved by diverting some of

the fuel to a calciner vessel at the base of th e preheater tower. This system is called the preheater/precalciner process.

Regardless of the type of pyroprocess used, the last component of the pyroprocessing system is

the clinker cooler. The clinker cooler serves two main pur poses. First, this portion of the

process:

• recoups up to 30% of the heat input to the kiln system;

• locks in desirable product qualiti es by freezing mineralogy; and

• makes it possible to handle th e cooled clinker w ith conventional conveying equipment.

The more common types of clinker coolers are re ciprocating grate, plan etary, and rotary. In these coolers, the clinker is cooled from a bout 1,100°C to 90°C (2000°F to 200°F) by ambient air that passes through the clinker and into the rotary kiln for use as combustion air. However, in the reciprocating grate cooler, lower clinker discharge temperat ures are achieved by passing anAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6-3



### additional quantity of air through the clinker. Be cause this additional air cannot be used in the kiln for efficient combustion, it is vented to the atmosphere, used for drying coal or raw materials, or used as a combustion air source for the precalciner.

The second portion of the clinker process, a se ries of blending and grinding operations, completes the transformation of clinker into fi nished cement. Up to 5% gypsum or natural anhydrite is added to the clinke r during grinding to control the cement setting time, and other specialty chemicals are added as needed to impa rt specific product prope rties. This finish milling is accomplished almost exclusively in ball or tube mills. Typically, finishing is conducted in a closed-circuit system, with product sizing by air separation.

Coal is the fuel of choice in cement kilns, prim arily because of its low cost, but also because the coal ash contributes to the produc t. The current fuel usage in cement kilns is about 82% coal; 4% natural gas; and 14% other fuels, mainly co mbustible waste (industrial waste, tires, sewage sludge, etc.). In addition to conventional fuel s, many Portland cement facilities are employing the use of petroleum derived coke (petc oke) blended with coal to fire kilns.

Lime kilns are similar to cement kilns. The kiln is the heart of the lime manufacturing plant, where various fossil fuels (such as coal, petroleum coke, natural gas, and fu el oil) are combusted to produce the heat needed for calcination. There are five different types of kilns used in lime manufacturing: rotary, vertical, doub le-shaft vertical, rotary heart h, and fluidized bed. The most popular is the rotary ki ln, however the double-shaf t vertical kiln is an emerging new kiln technology gaining in acceptance primarily due to its energy efficiency. Similar to cement plants, rotary kilns at lime manufacturing plants may also have preheaters to improve energy efficiency. Additionally, energy efficiency is improved by routing exhaust from the lime cooler

to the kiln. SO 2 

### emissions from lime predominately originate from compounds in the limestone

feed material and fuels and are formed from th e combustion of fuels and the heating of feed

material in the kiln.

All types of kilns at lime manufacturing plants use external equipment to cool the lime product, except vertical (including double-shaft) kilns, wh ere the cooling zone is part of the kiln.

Ambient air is most often used to cool the lime (although a few us e water as the heat transfer medium), and typically all of the heated air stream exiting the cooler goes to the kiln to be used as combustion air for the kiln. The exception to th is is the grate cooler, where more airflow is generated than is needed for kiln combustion, and consequently a portion (about 40%) of the grate cooler exhaust is vented to the atmosphere. EPA has estimated that there are about five to

ten kilns in the United States th at use grate coolers. The emi ssions from grate coolers include lime dust (PM) and trace metallic HAPs found in the lime dust, but not typically SO 2



### .

For cement and lime kilns, add-on control technology options identified for SO 2 

### include advanced flue gas desulfurizati on (AFGD), dry FGD, and wet FGD.

EVALUATION OF SO 2 

### EMISSION CONTROL OPTIONS

Sulfur dioxide may be generated both from the su lfur compounds in the raw materials and from

sulfur in the fuel. The sulfur content of both raw materials and fu els varies from plant to plant and with geographic location. However, the alka line nature of the cement provides for directAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6-4



### absorption of SO 2 

### into the product, thereby reducing the quantity of SO 2 

### emissions in the exhaust stream. Depending on the process an d the source of the sulfur, SO 2 

### absorption ranges from

about 70% to more than 95%.

In contrast to electric utility and industrial boilers, SO 2 

### emissions from rotary cement kilns are not strongly dependent on fuel sulfur content. Instead, SO 2 

### emissions are more closely related to the amount of sulfide (e.g. pyrite) in kiln feedstocks and to the mola r ratio of total sulfur to total alkali input to the system. In cement kilns SO 2 

### emissions generally depend on:

• Inherent SO 2 

### removal efficiency of kiln system during processing,

• Form of sulfur (e.g. pyritic) and sulf ur concentrations in raw material,

• Molecular ratio between sulfur and alkalis,

• Prevailing conditions (oxidizi ng or reducing) and their lo cation within the kiln, and

• Temperature profile in the kiln system.

SO 2 

### emission reductions may also result from a ttempts to reduce other pollutants (primarily

NO X 

### ), typically due to changes in the flame char acteristics of combustion. For example, staged combustion with mid-kiln injection of a low-su lfur fuel may be considered for reducing SO 2



### . Similarly, including high pressure air injection at a mid-kiln firing site can limit oxygen in the kiln and suppress SO 2 

### formation (Hansen, 2002). Since these techniques are primarily used to

reduce NO X 

### and because their efficiencies are typical ly more limited than other techniques they

are not considered in additional detail here.

Other more specific SO 2 

### control technologies applicable to ce ment kilns are listed below. A summary of controls evaluated for this work is provided in Table 6.1. Details of each of the control technologies follow Table 6.1. Additional information on this source category and

associated controls can be found in the 2005 NESCAUM document titled: Assessment of Control Technology Options for BART-Eligible Sources.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6-5



### Table 6.1 SO 2 

### Control Technologies for Cement Kilns

Technology Description Applicability Performance

Fuel Switching Limiting the sulfur content of both

raw materials and fuels can reduce

releases of SO 2 . Availability ofthese materials is highly sitespecific. All Kilns Depends onavailability of lowsulfur raw materials

Dry Flue Gas

Desulfurization - Spray Dryer Absorption (FGD) Addition of absorbents such as slaked lime (Ca(OH)2), quicklime (CaO) or activated fly ash with high CaO content to the exhaust gas of

the kiln can absorb some of the SO 2

. All Kilns 60-80% reduction

Wet Flue Gas

Desulfurization (FGD) SO 2 is absorbed by a liquid/slurry sprayed in a spray tower or is bubbled through the liquid/slurry.

Wet scrubbers also significantly reduce the HCl, re sidual dust, metal

and NH 3 emissions. All Kilns 90-99.9% reduction

Advanced Flue Gas

Desulfurization (FGD) DOE demonstrated a retrofit Passamaquoddy Technology Recovery ScrubberTM using cement kiln dust (CKD), an alkaline-rich (potassium) waste, to react with the acidic flue gas. All Kilns 95-99.5% reduction

Table References:

1. Assessment of Control Technology Options for BART-Eligible Sources , NESCAUM, March 2005. 2. Miller, F.M. et. al. Formation and Techniques of Control of Sulfur Dioxide and Other Sulfur Compounds in Portland Cement Kiln Systems . Portland Cement Association R&D Serial No. 2460, 2001.



### Fuel Switching

As with any fuel-fired SO 2 

### emission source, reduction of sulfur levels in the fuel itself typically results in lowered emissions. However, this technique is less effective in cement-making systems, where SO 2 

### emissions are not strongly dependent on fuel sulfur content. Depending upon the level of sulfur in a plant’s limestone, and more specifically the pyrite content, compared to the sulfur content of its heating fuel, fu el switching may not be sufficient to reduce SO 2 

### emissions (Tanna and Schipholt, 2004). Howeve r, when fuel sulfur levels are high, fuel switching may have a significant benefit in SO 2 

### levels.

Flue Gas Desulfurization (FGD)

Both wet and dry flue gas desulfurization (FGD) systems have been used effectively to control

SO 2 

### emissions from cement kilns. FGD systems at cement facilities typically are, 1) dry flue gas desulfurization (spray dryer abso rption) 2) wet flue gas desulfur ization, and 3) advanced flue gas desulfurization (AFGD). A brief descriptio n of each of these technologies is provided

below.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6-6



### Dry Flue Gas Desulfurizati on (Spray Dryer Absorption)

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO 2 

### is absorbed by the slurry, forming a mixture of calci um sulfite and calcium sulfate. The liquid-togas ratio is such that the water evaporates before the droplets reach the bo ttom of the tower. The dry solids are carried out with the gas and collected with a fabric filter or ESP. When used to specifically control SO 2 

### , the term dry flue-gas desulfurizatio n (dry FGD) may also be used. As with other types of dry scrubbing systems (such as lime/limestone injection) exhaust gases that exit at or near the adiabatic saturation temperatures can create problems with this control technology by causing the baghouse filter cake to beco me saturated with moisture and plug both

the filters and the dust re moval system. In addition, the lime slurry would not dry properly and would plug up the dust collection system. Howe ver there is some argument in the control community that indicates that some of the SO 2 

### removal actually occurs on the filter cake. Therefore, dry FGD (spray dryer absorption) may not be technically feasible if exit gas temperatures are not substantially above the ad iabatic saturation temper atures. For Portland cement facilities, these temperatures are likely to be above the adiabatic saturation temperatures.

Most of the spray dryer type SO 2 

### control technologies in the cement industry are applied to preheater or preheater/precalciner kilns. Exhaus t gases from long dry kilns are cooled by either spray water introduced into the f eed end of the kiln or by dilu tion air-cooling after the gases leave the kiln. Adding a conditioning tower to replace wet suppression or dilution air enables the alkaline slurry system to be used to reduce SO 2 

### emissions (the equivalent of a spray dryer). The use of an alkaline slurry spray dryer type scrubber should be app lied to long wet kilns with care because the addition of the lime slurry may drop the exhaust gases temperature below the acid adiabatic saturation temperatures, creating si gnificant plugging and co rrosion problems in the downstream particulate c ontrol device, duct work, and induced draft fan.

Wet Flue Gas Desulfurization (FGD)

Wet scrubbing processes used to control SO 2 

### and particulate emissions are generally termed fluegas desulfurization (FGD). FGD utilizes gas absorption technology, the se lective transfer of materials from a gas to a c ontacting liquid, to remove SO 2 

### in the waste gas. Caustic, crushed limestone, or lime are used as scrubbing agents. Our screening evaluation assumes that lime is the scrubbing agent.

Caustic scrubbing produces a liqui d waste, and minimal equipment is needed. When lime or limestone is used as the reagent for SO 2 

### removal, additional equipment is needed for preparing the lime/limestone slurry and collecting and concen trating the resultant sludge. Calcium sulfite sludge is watery and is typically stabilized with fly ash for land filling. Calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air injecti on blower is needed to supply the oxygen for the second reaction to occur. The normal SO 2 

### control efficiency range for

SO 2 

### scrubbers is 80-90% for low efficiency scrubbers and 90-99.9% for high efficiency

scrubbers.

While wet scrubbers have been used successfully in the utility industry, they require more care when used for a Portland cement facility. Calcium sulfate scaling and cementitious buildup when a wet scrubber is used for acid gas control (applied to the exhaust gas from a cement kiln)Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6-7



### can be avoided if these systems are installed dow nstream of a high efficiency particulate control device (e.g., fabric filter). Failure of the pa rticulate control device can pose difficult problems

for a downstream wet scrubber.

Advanced Flue Gas Desulfurization (FGD)

The AFGD process accomplishes SO 2 

### removal in a single absorber which performs three functions: prequenching the flue gas, absorbing SO 2 

### , and oxidizing the resu lting calcium sulfite to wallboard-grade gypsum. Figure 6.2 show s the process flow for an AFGD system.

Incoming flue gas is cooled and humidified w ith process wet suppression before passing to the absorber. In the absorber, two ti ers of fountain-like sprays distri bute reagent slu rry over polymer grid packing that provides a large surface area for gas/liquid contact. The gas then enters a large gas/liquid disengagement zone above the slurry re servoir in the bottom of the absorber and exits through a horizontal mist eliminator.

Figure 6.2 Advanced Flue Gas De sulfurization Process Flow

As the flue gas contacts the sl urry, the sulfur diox ide is absorbed, neutralized, and partially

oxidized to calcium sulfite and calcium sulfate. The overall reactions are shown in the following equations:

CaCO 3 

### + SO 2 

### → CaSO 3 

### • 1/2 H 2 

### O + CO 2Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6-8



### CaSO 3 

### •1/2 H 2 

### O + 3H 2 

### O + O 2 

### → 2 CaSO 4 

### • 2 H 2 

### O

After contacting the flue gas, sl urry falls into the slurry rese rvoir where any unreacted acids are neutralized by limestone injected in dry powder form into the re servoir. The primary reaction product, calcium sulfite, is oxidized to gypsum by the air rotary sparge rs, which both mix the slurry in the reservoir and inject air into it. Fixed air spargers assist in completing the oxidation. Slurry from the reservoir is ci rculated to the absorber grid.

A slurry stream is drawn from the tank, dewate red, and washed to remove chlorides and produce wallboard quality gypsum. The resultant gypsum cake contains less than 10% water and 20 ppm chlorides. The clarified liquid is returned to th e reservoir, with a slipst ream being withdrawn and sent to the wastewater evaporation system for injection into the hot flue gas ahead of the electrostatic precipitator. Wate r evaporates and dissolved soli ds are collected along with the flyash for disposal or sale.

The production of gypsum may actually be benefici al for Portland cement as gypsum is added to Portland cement in the final gri nding process to regulate the se tting time of the concrete. However, to date there are no known installa tions of AFGD at Portland cement facilities.

Inherent Removal

Removal of SO 2 

### in the cement manufacturing process is inherent to that process. The raw materials used in the process, primarily limest one, are preheated in th e cement-making process either in the preheater tower or in the rotary k iln. In either case, the limestone comes in contact

with hot combustion exhaust gases generating a free lime, which then reacts with SO 2 

### in the gas stream, providing in-process removal of sulfur in the kiln system. Removal efficiencies in rotary kiln systems range between 38% and 99% of sulf ur input, and 50% to 70% of the remaining SO 2 

### is removed from exhaust gases when passing thro ugh an in-line raw mill system (Miller et al., 2001). The overall effectiveness and costs associ ated with this method are highly variable and are related primarily to the type of kiln operati on and the ability of the facility to change raw material feeds. These costs can be difficult to quantify.

Process Alterations

The following methods to remove and prevent formation of SO 2 

### by modifying or controlling conditions in the system are available due to th e nature of the Portla nd cement manufacturing

process:

• Change in the oxygen concentration in the flam e/exhaust gas area. The concentrations of oxygen and (more importantly) carbon monoxide strongly influence the stability of alkali and calcium sulfates in the burning zone. By ensuring that sufficient oxygen is present to stabilize these compounds, SO 2 

### emissions can be controlled. Control of burning-zone O 2 

### and CO concentrations is a widely used industrial practice, a nd a control technique applicable to all rotary cement kilns. The downside of this technique is the more

favorable conditions crea ted for generation of NO X 

### in the rotary kiln.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6-9



### • Burning-zone flame shape can be modified to ensure that reducing conditions in the flame are minimized. Flame impingement in the hot zone has a major effect on SO 2 

### emissions from the kiln, even if total oxygen is sufficient to fully combust all fuel. Avoiding flame impingement in the burning zone minimizes SO 2 

### formation. Avoiding flame impingement on the clinker, a techniqu e applicable to all rotary kilns producing cement clinker, requires prope r solid fuel preparation and proper flame shaping and

control.

• Changes in raw materials to alter the alkali/sul fur molar ratio can also be used to control

SO 2 

### emissions. SO 2 

### concentrations in kiln exit gases vary with the molar ratio of alkali to

sulfur. When there are sufficient alkalis in excess of sulfur, SO 2 

### emissions are typically low, due to more sulfur being retained as al kali sulfates in the clinker. Cement plants may also change their raw materials to reduce SO 2 

### emissions. Typically this is accomplished by substituting a raw material cont aining pyritic sulfur or organic sulfur with one containing lesser amounts of these compounds, leading to reduced SO 2 

### emissions. Replacement of raw materials, however, is often constrained by economic considerations, while alkali input increase may also be limited by cement product quality specifications on total alkali in cement.

• 

### Alterations to system can influence SO 2 

### emissions. It has been found that an improved distribution of kiln feed may equalize temper atures in bottom stage cyclones and reduce

SO 2 

### emission by as much as 20% (Miller, 2001).

As with inherent removal, the overall effectiven ess and costs associated with this method are highly variable and are related primarily to the type of kiln operation and the ability of the facility to change raw material feeds. These costs can be difficult to quantify.

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR KILNS

Cost of Compliance

To compare the various control options, information has been co mpiled on the cost-effectiveness of retrofitting controls. In ge neral, cost-effectiveness increas es with the amount of cement produced by the facility.

In a study performed for LADCO for a BART an alysis, MACTEC developed control costs for

SO 2 

### for a “model” cement plant for SO 2 

### . For the wet scrubber, the control cost estimates were prepared using lime as the base in the scr ubbing liquor. Caustic (NaOH) and limestone are potential alternatives for a scrubber and coul d change the costs slightly. While lime and limestone require additional equipment for slurry preparation and for so lids separation from the sludge generated in the scrubber, lime scrubbers are the most commonly used since lime is plentiful and relatively cheap. Materials of constr uction must also be made suitable for caustic, lime, or limestone if existing equipmen t is modified for wet scrubbing of SO 2



### .

AFGD systems require additional capital costs for the spargers and blowers necessary to oxidize the waste product to gypsum and for equipment to dewater the product (e.g., centrifuge). However if the commercial grade gypsum can be sold or used by the cement facility, some of

these costs can be offset.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6-10



### Dry FGD costs were calculated based on the low and high control efficien cies typical for these systems. For dry scrubbers, the flue gas must be cooled to a temperat ure 10 to 20 degrees above adiabatic saturation. This is typically accomplishe d using a heat recovery boiler, an evaporative cooler or a heat exchanger. In addition, if th e facility does not have one, a particulate removal device is required for removal of th e dry materials used to absorb SO 2



### .

For all scrubbers, costs for an additional or upgraded induced air draft fan to make up for pressure drops within the system may be requi red. In addition, for wet systems, flue gas reheating may be required, thus a reheater may be necessary.

Tables 6.2 – 6.4 present estimated SO 2 

### control costs for AFGD, Wet FGD, and Dry FGD applied to dry kilns and preheater kilns. The range of costs for these systems vary depending on the size of the kiln and control efficiency, so costs are presented for three size ra nges of kilns. Although the capital and annual operating co sts of these three types of c ontrol vary widely depending on kiln size and control efficiency, the ultimate cost in terms of $/ton of SO 2 

### reduction are estimated to be from $2,000 - $7,000 for dry kilns and $9,000 to $73,000 for preheater kilns.

Table 6.2 SO 2 

### Control Costs for AFGD Applied to Dry Kilns and Preheater Kilns (2006 dollars)

Dry Kiln Preheater Kiln

Unit Relative

Size Capital Costs (10 6 $) Annual Operating Costs (10 6 $) SO 2 Cost

Effectiveness

($/ton SO 2 reduction) Capital Costs (10 6 $) Annual Operating Costs (10 6 $) SO 2 Cost

Effectiveness

($/ton SO 2 reduction)

Small $7.03 – $22.9 $3 - $6 $4.5 - $14.5

Medium $14.1 - $45.9 $6.1 - $11.9 $8.9 - $29.0

Large $28.1 - $91.6 $12.1 – $23.7 $2,000 - $4,000

$17.8 - $58.0 $1.2 – $11.8 $13,600- $38,000



### Table 6.3 SO 2 

### Control Costs for Wet FGD Applie d to Dry Kilns and Preheater Kilns (2006 dollars)

Dry Kiln Preheater Kiln

Unit Relative

Size Capital Costs (10 6 $) Annual Operating Costs (10 6 $) SO 2 Cost

Effectiveness

($/ton SO 2 reduction) Capital Costs (10 6 $) Annual Operating Costs (10 6 $) SO 2 Cost

Effectiveness

($/ton SO 2 reduction)

Small $2.43 – $36.5 $3 - $9 $1.5 - $23.1

Medium $4.9 - $73.0 $6.0 - $18.4 $3.1 - $46.3

Large $9.5 - $142.5 $11.9 – $36.8 $2,000 - $6,200

$6.2 - $92.5 $0.9 – $18.9 $9,700- $64,600Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6-11



### Table 6.4 SO 2 

### Control Costs for Dry FGD Applie d to Dry Kilns and Preheater Kilns (2006 dollars)

Dry Kiln Preheater Kiln

Unit Relative

Size Capital Costs (10 6 $) Annual Operating Costs (10 6 $) SO 2 Cost

Effectiveness

($/ton SO 2 reduction) Capital Costs (10 6 $) Annual Operating Costs (10 6 $) SO 2 Cost

Effectiveness

($/ton SO 2 reduction)

Small $1.45 – $37.0 $3 - $9 $0.9 - $26.3

Medium $2.9 - $84.9 $5.5 - $20.0 $1.8 - $52.6

Large $5.6 - $165.5 $10.7 – $38.9 $1,900 - $7,000

$3.6 - $105.2 $0.9 – $21.0 $10,000- $72,800



### The LADCO region had no wet kilns so cost estimates were not available for those type kilns. For the purposes of this study, wet kiln cost effec tiveness is assumed to be similar to that for long dry kilns.

Additional details concerning the calc ulation of cost effectiveness of controls for kilns is located in a document developed by MACTEC for LADCO titled: Cement Best Available Retrofit Technology (BART) Engineering Analysis . This document can be downloaded from the web at the following location: http://www.ladco.org/reports/rpo/Regional%20A ir%20Quality/BART/Cement_BART_Engineeri ng%20Analysis%20%2B%20Appendix%20A1.pdf

.

Time Necessary for Compliance

Generally, sources are given a 2-4 year phase-in period to comply with new rules. Under the

NO X 

### SIP Call for Phase I sources, EPA provided a compliance date of about 31⁄2 years from the SIP submittal date. Most MACT standards allow a 3-year compliance period. Under Phase II of

the NO X 

### SIP Call, EPA provided a 2-year period after the SIP submittal date for compliance. States generally provided a 2-year period for co mpliance with RACT rules. For BART control measures, the proposed BART guidelines require States to establish enforceable limits and require compliance with the BART emission limitat ions no later than 5 ye ars after EPA approves the regional haze SIP.

For the purposes of this review, we have assumed that a 2-year period after SIP submittal is adequate for pre-combustion controls (fuel switchi ng or cleaning) and a three year period for the installation of post combustion controls.

Energy and Non-Air Impacts

Fuel switching and cleaning and process changes do not significantly impact efficiency of the cement operation, but may add to transportation issues and secondary environmental impacts from waste disposal and material handling opera tions (e.g. fugitive dust). FGD systems typically operate with high pressure drops across the cont rol equipment, resulting in a significant amount of electricity required to operate blowers and circulation pumps. In addition, some combinationsAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6-12



### of FGD technology and plant config uration may require flue gas reheating to prevent physical damage to equipment, resulting in higher fuel usage.

Environmental Impacts

The primary environmental impact of AFGD is the generation of byproduct gypsum. While gypsum is generated as a byproduct, the intent of the AFGD system is to produce gypsum that is commercial grade that can be sold. In the cas e of cement kilns, production of gypsum would result in some cost offsets since gypsum is a component of Portland cement. Thus the gypsum produced could be used to offset gypsum purchases.

The primary environmental impact of wet scrubbers is the generation of wastewater and sludge.

Waste from wet scrubbers will increase the su lfate and solids loading in the facility’s wastewater. This places additi onal burdens on a facility’s wastew ater 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, th e sludge is water-laden,

and it must be stabilized for la nd filling. If lime or limestone scrubbing is used to produce calcium sulfate sludge, it is stable and easy to de water. However, control costs will be higher because additional equipment is required. Scrubber exhaust gases are saturated with water, thus creating a visible plume. Plume visibility may be a local/community con cern. Once the exhaust mixes with sufficient air, the moisture droplets evaporate, and the plume is no longer visible.

Disposal of removed material from dry FGD syst ems is also required and will result in landfill impacts.

Energy Impacts

A scrubber operates with a high pr essure drop, resulting in a si gnificant amount of electricity required to operate the blower and pump. In addi tion for some technologies, a flue gas reheater may be required resulting in s lightly increased fuel usage.

Remaining Useful Life of the Source

MACTEC could find little information on the typical lifetime of a cement pl ant. In a Security and Exchange filing ( http://www.secbd.org/prosmcldopr.html ) for a facility in India, typical lifetimes of various components of the plant ra nge between 20-50 years. In an evaluation of waste management of cement kiln dust (CKD), re maining useful lifetimes of waste management units were around 20 years ( http://www.epa.gov/epaoswer/other/ckd/rtc/chap-4.pdf ). Thus we found nothing to suggest that the amortization of capital costs or calculation of annual operating costs would be affected by the remaining useful life.

For the purposes of this analysis, we assumed that the remaining useful life of each emission unit was a minimum of at least 10 years and that it was likely that some units would continue to operate for at least 20-30 more year s with proper maintenance and upkeep.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6-13



### REFERENCES

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

2005.

EPA. January, 1995. AP42 Section 11.6 – “Portland Cement Manufacturing”.

Hansen, Eric R. Staged Combustion for NO X 

### Reduction Using High Pressure Air Injection

, IEEE-IAS/PCA 43rd Cement Industry Technica l Conference; Jacks onville, FL: May 2002.

Miller, F.M. et. al. Formation and Techniques of Control of Sulfur Dioxide and Other Sulfur Compounds in Portland Cement Kiln Systems . Portland Cement Associ ation R&D Serial No. 2460, 2001.

Tanna, B. and B. Schipholt. Waste-Derived Fuel Use in Cement Kilns ERAtech Group, LLC http://www.eratech.com/papers/wdf.htm , accessed September, 2004.This page left blank intentionally.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 7: Analysis of Selected Kilns Page 7-1



### CHAPTER 7

ANALYSIS OF SELECTED KILNS

SOURCE CATEGORY DESCRIPTION

Emission control regulations for cem ent kilns have historically fo cused on particulate emissions. Over the past several years, regulations for the control of NO X 

### and hazardous air pollutant (HAP) emissions have also been adopted. SO 2 

### emission controls are largel y non-existent. Some States have mandated emission limits as part of the Title V requirements but no national regulatory program for SO 2 

### controls for cement kilns exists. The only exceptions to this is for sources subject to New Source Review under Title I of th e Clean Air Act and for sources subject to the

Best Available Retrofit Tec hnology (BART) requirements of th e regional haze regulations.

Title I subjects new and modified large stati onary sources that increase their emissions to permitting requirements that impose control technologi es 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 attain ment areas and to the Lowest Achievable Emission Rate (LAER) in nonattainment areas. Th e control strategies that constitute BACT and

LAER evolve over time and are reviewed on a case-by-case basis in State permitting proceedings.

INFORMATION OBTAINED FROM STATE AGENCIES

MACTEC contacted State agencies to obtain information on kilns from those facilities in the list of the top 20 individual non-EGU sources. We requested permit information, information about

SO 2 

### controls recently implemented or planned at the facility and any available information on BART, consent decrees, or other regulations that will impact control devices at the facilities.

The information we obtained is included in Table 7.1.Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 7: Analysis of Selected Kilns Page7-2Table 7.1 Point Source Information Collected from the Top 3 Kilns Responsible forVisibility Impairment inMANE-VU Class I AreasFacility Name State2002SO2Total(tons)Primary Emissions PointDescriptionPoint ID(PermitID No.)DesignCapacityExistingControl(s)Proposed/PlannedControl(s)AdditionalInformationLaFargeBuildingMaterials Inc.1NY 14,800 Two rotary, wet processkilns (Kiln 1 & 2) and twoclinker coolers (ClinkerCooler 1 & 2). There arebuildings at either end of thekilns; the discharge endbuilding where the clinkercoolers are located, and thefeed end building.041000 Unknown Fabric filterdust collectoron clinkercoolers (PM)ESP (PM)NoneSt. LawrenceCement Corp.– CatskillQuarry2, 3NY 3,562 Cement kiln permitted toburn coal, oil, tires, wasteoil, natural gas, nonhazardous fuels, and coke.This is a wet kiln built in1964.U00K18 Unknown ESP Low-sulfurfuelConsent Decree dated1/9/91 limits burningsolid fuel with a maxsulfur content of 3.8lbs/MMBTU/hr.BART analysis has notbeen completed.LafargeMidwest, Inc.,Alpena Plant4MI 16,576 Five rotary dry kilns, clinkercoolers and associatedmaterials handlingoperations. Kilns fire withcoal, coke or waste derivedfuelEU-Kiln19EU-Kiln20EU-Kiln21EU-Kiln22EU-Kiln23Unknown Baghouses onkiln dust returnsystemsUnknown as ofdate of report -these units aresubject toBARTSO2Emission limitson all five kilns:EUKiln19 = 2,088 tonsEUKiln20 = 2,065 tonsEUKiln21 = 2,056 tonsEUKiln22 = 9,685 tonsEUKiln23 = 9,728 tons1New York State Department of Environmental Conservation, Division of Air Resources.Personal communication regarding LaFarge Building Materials Incorporated facilitybetween Mr. Rick Leone (518-402-8403) and Ms. Lori Cress,MACTEC Federal Programs, Inc., on February 2, 2007.2New York State Department of Environmental Conservation, Division of Air Resources.Personal communication regarding St. Lawrence Cement Corporation – Catskill Quarryfacility between Mr. Rick Leone (518-402-8403) and Ms. Lori Cress, MACTEC Federal Programs,Inc., on February 9, 2007.Assessment of Reasonable Progress for Regional Haze In MANE-VU Class I AreasMethodology for Source Selection, Evaluation of Control Options, and Four Factor AnalysisChapter 7: Analysis of Selected Kilns Page7-33New York State Department of Environmental Conservation, Division of Air Resources.Personal communication regarding St. Lawrence Cement Corporation – Catskill Quarryfacility from Mr. Rick Leone (518-402-8403) via E-mail on February 9, 2007.4Michigan Department of Environmental Quality, Air Quality Division. Personal communication regarding LaFarge Midwest, Incorporated Alpena Plant from Ms. Teresa Walker(517-335-2247,walkertr@michigan.gov) via E-mail on February 7, 2007.This page left blank intentionally.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8-1



### CHAPTER 8

HEATING OIL

BACKGROUND

Number 2 distillate fuel oil, he ating oil, and diesel fuel oil ar e essentially the same refineryproduced liquid. In the Northeast United States, home heating accounts for 54% of distillate fuel oil demand. In comparison, highway diesel accounts for 38% (NESCAUM, 2005). Annually, home heating oil use generates an esti mated 100,000 tons of sulfur dioxide (SO 2 

### ) emissions in the Northeast (NESCAUM, 2005). C limate and seasonality play im portant roles in the use of heating oil, and therefore the emissions from com bustion of heating oil. While it is important to consider the emissions from heating oil in the Northeast United States, emissions from heating

oil combustion in other areas of the United States such as the VISTAS States are not significant in comparison to other emission sources.

SO 2 

### emissions are proportional to fuel oil sulfur content. It is not feasible to control SO 2 

### emissions from homes using control devices; theref ore, the most efficient method for controlling

SO 2 

### emissions from home heating is by lowering the amount of sulfur in the fuel. Currently, the sulfur limits in heating oil vary between 2,000 to 20,000 ppm. Table 8.1 provides information on the range of sulfur in heati ng oils throughout the Northeast.

Table 8.1 State Sulfur Li mits for Heating Oil

State Sulfur Limit in Percent Sulfur Limit in parts per million (ppm)

Connecticut 0.3 3,000

Maine 0.3 to 0.5 3,000 to 5,000

Massachusetts 0.3 3,000

New Hampshire 0.4 4,000

New Jersey 0.2 to 0.3 2,000 to 3,000

New York Upstate 1.0 to 1.5 10,000 to 15,000

New York Downstate 0.2 to 0.37 2,000 to 3,700

Rhode Island 0.5 5,000

Vermont 2.0 20,000

Source: NESCAUM, 2005



### Beginning in 2006, the permissible level of sulfur in highway diesel fuel (ultra low sulfur diesel, or ULSD) was 15 ppm. Prior to that, highway low sulfur diesel fuel wa s refined to contain 500 ppm sulfur (Low Sulfur Diesel, or LSD). Cons equently, refineries have already performed the capital investments required for the production of LS D and ULSD fuel oil. The Northeast States are considering adopting consistent low sulfur heating oil requirements, and a memorandum

titled DRAFT Memorandum of Understanding for Regi onal Fuel Sulfur Content Standards forAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8-2



### Distillate Number 2 Heating Oil , the Northeast States proposed to reduce the sulfur content to 500 ppm. A reduction of sulfur in heating oils from the current levels to 500 ppm would reduce

SO 2 

### emissions by approximately 75% per year on a nationwide basis (Batey and McDonald, 2005). There has also been some discussion regard ing the reduction of hea ting oil sulfur content to 15 ppm.

This memorandum presents the four factor analys is that was applied to the heating oil sulfur reduction proposal. The four fact ors are: cost of compliance, time necessary for compliance, energy and non-air impacts, and re maining useful life of the sources. This document primarily focuses on reducing the sulfur content of heatin g oil to 500 ppm. Information on reducing the sulfur content of heating oil to 15 ppm is presented wherever data were available.

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR

EMISSIONS FROM HEATING OIL COMBUSTION

Cost of Compliance

Refinery Retrofit Costs

Refineries were required to ma ke significant capital investme nts to meet the LSD and ULSD highway fuel sulfur requirement. To achieve the LSD and ULSD sulfur goals, refineries were required to implement diesel de sulfurization te chnologies. Estimates for the capital costs were developed in 2001 by the Energy Information Ad ministration (EIA) and are based on calendar year 1999. Table 8.2 presents the capital costs for desulfurizati on technologies developed by the EIA, which were converted from a calendar y ear 1999 dollar basis to 2006 dollars. The EIA developed estimates for new and revamped desulf urization technologies at existing refineries.

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

Individual Refineries a,b

Desulfurization Unit Type Throughput (Barrels per Day) Capital Costs (2006 Dollars per Daily Barrel

Produced) Total Capital Cost per Unit (Million 2006 Dollars)

New 50,000 1,204 60.3

New 10,000 2,187 21.9

Revamp 50,000 716 35.8

Revamp 10,000 1,464 14.6

a Based on cost estimates for hydrotreaters to produce ULSD.

b Source for this information is the Energy Information Administration

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

www.inflationdata.com



### In its highway diesel fuel rulemaking, EPA also developed cost estimates for the deployment and implementation of desulfurization technologies at refine ries. EPA estimated that it would cost existing refineries an estimated $56 million (2006 do llars) per refinery to install desulfurizationAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8-3



### technologies, and that this effo rt would be spread out over a 2- year time period. EPA based its conclusions on the assumption that refineries would revamp thei r hydrotreating technologies. It

further estimated that 80% of th e hydrotreaters at the refineries would be revamped. The EPA also estimated that the cost of a new hydrotre ater would be $91 million (2006 dollars), and that roughly 25 refineries nationwide woul d have to make this investme nt. No estimates were made

for the costs associated with new refineries as none are currently being constructed in the United States. The EPA analysis spread the investment cost over a 2-y ear period. Consequently, it was

estimated that the US refine ry-wide investment for cale ndar year 2004 was $2.45 billion and $2.83 billion for calendar year 2005 (EIA 2001) (Converted from 2001 to 2006 dollars using a

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

In the August 9, 2006 edition of This Week in Petroleum , EIA reported that total ULSD production progress has been good and that ULSD is currently being produced in all Petroleum

Administration for Defense District s (PADDs). Stocks of ULSD in the United States in January 2007 were approximately equal to distillate oil c ontaining greater than 500 ppm sulfur. However on the East Coast, stocks of ULSD were approximat ely one-third the size of distillate oil stocks containing more than 500 ppm sulfur (EIA). Another independent source, The Marathon Petroleum Company, LLC, found that 90% of refine ries in the continental United States that were included in a survey had designed units capable of producing ULSD. Also, Marathon determined that the planned US capacity for UL SD would be in excess of 2.5 million barrels per day in 2006 (Marathon Petrol eum Corporation 2007).

Heating Oil Cost Increases

It is assumed that the costs for retrofitting refi neries will be passed on to consumers. In its December 2005 study, NESCAUM estimated that th e average price increment for the lower sulfur product (500 ppm) would be $0.16 per gall on. In December 2005, this represented a 1% increase of the average oil price.

To update these costs we compared the costs of low-sulfur diesel fuel (15 – 500 ppm) with regular diesel fuel (2,000 ppm) for 2006. These data were gathered from DOE EIA Web site on March 8, 2007. We used the difference in diesel fuel prices because the cost for low sulfur heating oil is currently not reported and because diesel fuel and numb er 2 distillate are essentially the same product. It is therefore reasonable to assume that the cost differential between low sulfur and regular diesel fuel shoul d reflect the potential co st differential between low sulfur and regular heating o il. All cost comparisons are be fore taxes. EIA only reports a low-sulfur diesel fuel category which includes both low sulfur (500 ppm) and ultra low sulfur diesel (15 ppm). For the first two months on 20 07, EIA reports that stocks of 15 ppm sulfur oil were roughly twice that of 500 pp m sulfur oil. We averaged monthly costs to compute annual average costs for PADD 1A (C T, ME, MA, NH, RI, VT) and PADD 1B (DE, DC, MD, NJ, NY, PA) for low sulfur and regular diesel fuel from January to December 2006. For PADD 1A, the cost of low sulfur diesel fuel ranged from $1.954 to $2.433 per gallon and the cost of regular diesel fuel ranged from $1.963 to $2.429 per gallon. The monthly difference between low sulfur and regular diesel fuel ranged fr om -1.1 cents per gallon to 0.5 cents per gallon with an annual average of -0.8 cents per gallon. That is, low-su lfur diesel fuel was on average less expensive that regular diesel fuel in PADD 1A in 2006. Similarly in PADD 1B, the cost of low sulfur diesel fuel ranged from $1.894 to $2.358 per gallon a nd the cost of regular diesel fuel rangedAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8-4



### from $1.894 to $2.321 per gallon. The monthly differe nce between low sulfur and regular diesel fuel ranged from -1.3 cents per gallon to 4.7 cents per gallon with an annual average of 1.6 cents per gallon. In both regions fuel costs were highe st in the summer and the difference in cost between low sulfur and regular diesel fuel was al so highest in summer. To calculate an average cost differential, we weighed the PADD 1A and PA DD 1B cost differentials by residential fuel use in each PADD for 2005 (the latest date data are available from EIA). In 2005, PADD 1A States used 1.9 million gallons and PADD 1B St ates used 2.5 million gallons. Therefore, on average low sulfur distillate oil would be exp ected cost 0.8 cents per ga llon more than regular heating oil in MANE-VU States. This average pr ice differential translates in to $734/ton of

sulfur removed if it assumed that the low sulfur diesel has a c oncentration of 500 ppm sulfur or $554/ton of sulfur removed for ultra low 15 ppm sulfur diesel.

STAPPA-ALAPCO (2006) estimates that the annua l fuel oil consumption per household is 865 gallons per year. Using the price differential data presented above, th e average household would spend about $7 per year additional on home heating costs by using low or ultra low sulfur fuel.

The use of LSD/ULSD will also result in cost savi ngs to owners/operators of residential furnaces

and boilers due to reduced maintenance costs. When the existing heating oil sulfur content is 2,000 ppm and 500 ppm sulfur is substituted, the serv ice interval can be extended by a factor of three or more (e.g., cleaning at th ree year intervals rath er than annually). Vacuums are used to remove deposition caused by SO 2 

### from furnaces and boilers.

The potential vacuum cleaning costs savings for the United States, for a starting fuel sulfur content of 2,000 ppm ranges from approximately $200 million a year to $390 million a year for service costs of $50 to $100 per hour. Therefore, if all oil heated homes switched to 500 ppm sulfur heating oil, more than $200 million a y ear could be saved, which would significantly lower the overall operating costs of fuel oil mark eters. Given the dominant share of the U.S. heating oil market represented by the Northeast States, a large percentage of the projected national benefits would accrue in the region (N ESCAUM 2005). In a brochure distributed by

EIA titled Residential Heating Oil Prices : What Consumers Should Know, EIA reports that 6.3 million of the 8.1 million households using heating oil in the United States (78%) are in the Northeast Region. This region includes the New England and Central Atlantic States.

Heating Oil Supply

EPA addressed the issue of using ULSD for heating oil purposes in its regulatory impact analysis for Heavy-Duty Engine and Vehicle Standard s and Highway Diesel Fuel Sulfur Control Requirements (2000). EPA found that refiners in the Mid-Atlantic and Northeast (PADD 1) could produce more of this fuel and reduce the need for imports.

EIA reports that in 2004, 5,975,966,000 gallons of hea ting oil were sold in the United States. This decreased to 5,548,827,000 gallons in 2005. The EIA publishes weekly updates on the availability of heating oil. Information was retrieved for January 2007 and is summarized in

Table 8.3 below.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8-5



### Table 8.3 Average January 2007 Distillate Stocks (Million Barrels) a

Location 15 ppm and

Under Stocks 15 ppm -- 500 ppm Stocks >500 ppm Stocks Total Distillate

Stocks

US (Total) 57.2 25.0 59.7 141.8

East Coast 14.7 21.9 44.5 66.5

Average Days of Supply of

Distillate Fuel Oil b 34.4 34.4 34.4 34.4

a Source for this information is the Energy Information Administration.

b The sulfur content of distillate stocks is not distinguished by the EIA for this data point.



### The EIA also makes available information regardi ng the production and imports of heating oil. This information is summarized in Table 8.4, an d includes specific data for the East Coast.

The information presented in Table 8.4 indicate s that on a nationwide basis, more ULSD is produced than both LSD and high sulfur fuel. This is due to the predominant use of ULSD in highway diesel vehicles. This information also supports the c onclusion that the United States has the infrastructure to produce ad equate stocks of LSD and ULSD.

Table 8.4 Distillate Production and Imports (Million Barrels per Day) a,b

Location 15 ppm and

Under Production 15 ppm - 500 ppm

Production >500 ppm

Production Total Distillate

Production

US 2.659 0.624 0.970 4.253

East Coast 0.248 0.024 0.277 0.549

Imports 0.204 0.018 0.115 0.392

a Source for this information is the Energy Information Administration.

b Based on the four week average ending January 12, 2007.



### Currently, the 15 ppm fuel is sold for highway us e diesel, whereas the >500 ppm stocks are sold for heating oil. The 15-500 ppm fuel can still be used until 2010 under the hardship provisions of the heavy duty highway diesel program (EPA 2004). Under these prov isions of the heavy duty highway diesel program, if there is a shor tage of 15 ppm fuel, the 15 -500 ppm fuel could be used to relieve the shortage. With this flexib ility, the likelihood of a fuel shortage in the short term, due to usage of ULSD for heating oil is reduced.

Time Necessary for Compliance

Refiners in the United States are already produci ng low sulfur highway diesel fuel. This same fuel can be marketed as heating oil since it is the same refinery product as highway diesel except with dye added to the fuel to differentiate it for tax purposes. Some time may be required toAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8-6



### allow petroleum marketers to adjust to distribu ting ULSD to heating oil customers, however, the

distribution network for motor fuels a nd heating oil are already in place.

NESCAUM (2005) estimated that during peak pe riods of demand, up to 20% of the required heating oil is imported. This analysis does not a ddress whether offshore refineries should be able to produce 15 ppm sulfur for export to the Northeas t United States. In case of a shortage of 15 ppm fuel during the transition period from LSD to ULSD, the heavy duty highway diesel program allows the use of 15-500 ppm sulfur fuel.

Existing residential furnaces and boilers do not n eed to be retrofitted or modified to combust 15 ppm sulfur. The capacity for producing LSD a nd ULSD already exists among US refiners. Consequently, the time necessary for co mpliance does not hinge on the heating oil

furnace/boiler.

Energy and Non-Air Impacts

Reducing the sulfur contents of heating oil ha s a variety of benefici al consequences for

residential furnaces and boilers. Low sulfur di stillate fuel is cleaner burning and emits less particulate matter which reduces th e rate of fouling of heating units substantially and permits longer time intervals between clean ings. According to a study conducted by the New York State Energy Research and Development Authority, (NYSERDA), boiler deposits are reduced by a factor of two by lowering the fuel sulfur c ontent from 1,400 ppm to 500 ppm. These reductions in buildup of deposits result in longer service intervals between cleanings. (Batey and McDonald 2005). Batey and McDonald (2005) estimated that the potential cost sa vings from decreased vacuum cleanings ranges from $200 million per y ear to $390 million per year. The decreased deposits would also enable a more efficient transf er of heat, thereby reducing the fuel usage. Further reducing the heating oil sulfur from 500 to 15 ppm would increase the cost savings from decreased maintenance needs due to heat exchanger fouling.

The decreased sulfur levels would enable manufac turers to develop more efficient furnaces and boilers by using more advanced condensing furna ces and boilers. These boilers recoup energy that is normally lost to the heating of water vapo r in the exhaust gases. Historically, the use of high sulfur fuels prevented this due to the corr osion of the furnace/boiler due to the creation of sulfuric acid in the exhaust gases. The increased efficiency results in a decrease in the amount of heating oil a heating unit uses, th erefore, this would make a switc h to lower sulfur heating oils

more attractive and cost effective.

Remaining Useful Life of the Source

Residential furnaces and boilers have finite life ti mes, but they do not need to be replaced to burn low or ultra low sulfur fuel. The Energy Rese arch Center estimates that the average life expectancy of a residential heating oil furnace is approximately 18 years, and that the average life expectancy of a residential heating oil boi ler is 20-25 years (Personal communication with Mr. John Batey, Energy Research Center on February 6, 2007).

Finally, the number of homes that are bei ng heated with heati ng oil is declining by approximately 100,000/year (RedOrbit 2007). No geographical distribution was available forAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8-7



### this estimate, but since heating o il is predominantly used in the Northeast, most of the changes will be occurring there. Consequently, emissions from heating oil combustion will become less significant of a source of SO 2 

### emissions in the future.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8-8



### REFERENCES

Batey, J.E. and R. McDonald, 2005. Low Sulfur Home Heating Oil Demonstration Project Summary Report . Project funded by The New York Sate Energy Research and Development Authority. Contr act No. 6204-IABR-BR-00.

Energy Research Center. Pers onal communication on February 6, 2007 with Mr. John Batey and

Mr. Bernd Haneke of MACTEC Federal Programs, Inc.

EPA, 2004. Overview of EPA’s Low Sulfu r Diesel Fuel Programs . Presented at the Ultra-Low Sulfur Diesel Fuel Implementation Workshop by the EPA’s Office of Transportation and Air Quality, New Orleans, L ouisiana, November 15, 2004.

Marathon Petroleum Company, LLC. Ultra Low Sulfur Diesel. PowerPoint Presentation downloaded from the World Wide Web on January 31, 2007 from: http://www.marathonpetroleum.com/

NESCAUM, 2005. Low Sulfur Heating Oil in the Northeast States: An Overview of Benefits, Costs and Implementation Issues

.

RedOrbit, 2007. Refiners Have Many Options to Conver t High-Aromatic Streams into ULSD

. Article downloaded from the Worl d Wide Web on January 31, 2007 at: http://www.redorbit.com

STAPPA ALAPCO, 2006. Controlling Fine Particulate Matte r Under the Clean Air Act: A Menu of Options

.

US Energy Information Administration, August 9, 2006. This Week in Petroleum.

US Energy Information Admini stration, 2001. Brochure titled Residential Heating Oil Prices:

What Consumers Should Know.

US Energy Information Administration, 2001. The Tr ansition to Ultra-Low –S ulfur Diesel Fuel: Effects on Prices and Supply. Publication dow nloaded from the World Wide Web on January 31, 2007 at: www.eia.doe.gov/oiaf/servicerpt/ulsd

US Energy Information Administration, 2007. In formation downloaded from the World Wide Web on March 8, 2007.at: http://tonto.eia.doe.gov/dnav/pe t/pet_pri_dist_dcu_R1X_m.htm

US EPA, 2000. Regulatory Impact Analysis: Heavy Duty Engine and Vehicle Standards and Highway Diesel Fuel Su lfur Control Requirements . EPA Publication Number EPA420-R-00-

026.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-1



### CHAPTER 9

RESIDENTIAL WOOD COMBUSTION

BACKGROUND

The MANE-VU Contribution Assessment and ot her MANE-VU reports have documented that visibility impairment in this region is primarily due to regional secondary sulfate. However, in the MANE-VU Class I areas, biomass combustion al so has been identified as a contributor to visibility impairment. Biomass combustion emi ssions due to human activ ity primarily derive

from residential wood combusti on. While some biomass burni ng occurs throughout the year, residential wood combustion occurs predominantly in the winter months, potentially contributing to wintertime peaks in PM concentrations.

In the document, Control Analysis and Documentation fo r Residential Wood Combustion in the MANE-VU Region , OMNI Environmental Services, Inc. (OMNI) conducted a control analysis

and documentation of residential wood combustion (RWC) in the 11 States and the District of Columbia that make up the MANE-VU region. In formation for the OMNI analysis was obtained from: (1) The MANE-VU Residential Wood Combustion Emission Inventory published by MARAMA (July 2004 report), (2) Residential Energy Consump tion Surveys published by the EIA, (3) the National Emission Inventory publ ished by the EPA, (4) Simmons Marketing Research reports, and (5) Ameri can Housing Surveys for the Unite d States published by the U.S. Department of Commerce and the U.S. Departme nt of Housing and Urban Development. In addition, the results of three RWC surveys at the State-level have been published in the last decade for the Mid-Atlantic and New England area, which allow for comparison of data extrapolated from the national- and regional-scale surveys to the State level for three States. These were the: (1) 1995 Delaware Fuelwood Survey, (2) Residential Fuelwood Use in Maine, Results of 1998/1999 Fuelwood Survey, and (3) Ve rmont Residential Fuel Wood Assessment for

1997-1998.

To facilitate understanding of the cost effectiveness analyses done by OMNI, descriptions of the various appliances used, as well as a brief discussion of efficiency, are provided from the OMNI

report.

Cordwood-Fired Stoves and Fireplace Inserts

Uncertified, certified catalytic, and certified non- catalytic cordwood stoves and fireplace inserts together are considered cordwood heaters. They are designed to burn bulk cordwood and are room space heaters, i.e., they prim arily rely on radiant and convection heat transfer, in contrast to centralized heating systems such as warm-air fu rnaces or boilers which utilize heat distribution systems to heat multiple rooms. Fireplace inserts are essentially wood stoves that are designed to be inserted into an existing fire place cavity. Because of the heat transfer shielding effect of the fireplace cavity and the fact the majority of existing firepl ace chimneys are against an outside wall, their heating efficiency is less than a similar freestanding woodstove. Many fireplace

inserts have fans to facilitate transfer of heat fr om the portion that is insi de the fireplace cavity. Both freestanding cordwood stoves and fireplace inse rts rely on a natural draft using room air for combustion and the venting of exhaust through the chimney to the atmosphere. Though theAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-2



### majority of cordwood heaters use room air for co mbustion, some insert inst allations, such as in mobile homes, require the use of outside air for combustion.

Uncertified Conventional Cordwood-F ired Stoves and Fireplace Inserts

Uncertified cordwood fired stoves and fireplace inserts include units manufactured before the 40 CFR Part 60, Subpart AAA Ne w Source Performance Standard (NSPS) July 1, 1990 certification requirement, and curr ently or recently manufactured exempt units which operate similarly to some old pr e-EPA certification units.

NSPS Certified Catalytic Cordwood-F ired Stoves and Fireplace Inserts Certified catalytic units pass the exhaust through a catalyst to achieve emission reductions. Generally, a coated ceramic honeycomb catalys t is located inside the stove where the incompletely combusted gases and particles ign ite and are combusted fu rther, thus reducing air emissions and increasing co mbustion overall efficiency.

NSPS Certified Non-Catalytic Cordw ood-Fired Stoves and Fireplace Inserts Certified non-catalytic stoves and fireplace in serts rely on design f eatures to reduce air emission and increase efficiency. They ge nerally rely on the in troduction of heated secondary air to improve combustion, as well as firebox insulation, and baffles to produce a longer, hotter gas flow path, as well as othe r design features to ach ieve low emissions and higher efficiency.

Pellet Stoves and Fireplace Inserts

Analogous to cordwood stoves and fireplace insert s, pellet stoves and fireplace inserts are considered room heaters. They burn pellets generally made from sawdust, although there has been, and continues to be, research into uti lizing other biomass fuels to make pellets.

Combustion air is drawn from the room for most models, and exhaust is vented outdoors. Some pellet appliances use outside air for combusti on. Pellet stoves and inserts require the use of electric motors to power the combustion air and h eat transfer fans and th e pellet-feeding auger. Modern pellet units use electronic sensors and controls. Pellets are introduced into the hopper, and the auger continuously feeds a consistent amount of pellets into the firebox. The feed rate is controlled electronically by a feed rate setting selected by the user . There are two basic designs: bottom-feed and top-feed models. Pellet units ha ve a high efficiency and low emissions due to the use of the electric auger and fan that pr oduce uniform and controlled combustion conditions. Some units are certified by the NSPS process and some are not. The performance of the certified

and uncertified models are similar. What is considered by most as a “loop-hole” in the NSPS regulations essentially allows certification to be bypassed.

Wood-burning Fireplaces without Inserts

Fireplaces without inserts incl ude manufactured units (often referred to as “zero-clearance” fireplaces) and site-built masonr y units operated both with and without glass doors. Combustion

air is drawn from the natural dr aft created by fire, and that same draft vents the exhaust gases through the chimney. Fireplaces wi thout inserts have low efficienci es due to the large amount of

heated room air that is exhauste d out of the chimney from the dr aft. Many fireplaces without inserts are not used in a given year, some are used for aesthetic purposes and some are used forAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-3



### heating. Those that are used for heating are al most always used for secondary heating purposes and not primary heating due to th eir low efficiency and lack of heat transfer capabilities. Manufactured wax/fiber firelogs ar e often used as a fuel in them with about 30% of fireplace users nationwide claiming that they use wax/fiber firelogs some of the time. Most fireplaces are wall-mounted, however, this category also includes some free-standing models.

Direct Vent Gas Stoves and Fireplace Inserts (LPG and Natural Gas)

Direct vent gas stoves a nd inserts are sealed units that draw their combustion air from, and vent their exhaust to, the outside air. Venting can be extended vertically or horizontally out of the home. A common type of venting is coaxial, whic h has the exhaust pipe c ontained within the air inlet pipe, so the temperature of the combustion ai r is raised, and the temperature of the exhaust is lowered, creating more efficient combustion. It should be noted that natural gas is not readily available in all locations, however LPG may be available for use.

Vent-Free Gas Stoves and Fireplace Inserts (LPG and Natural Gas)

Vent-free gas stoves and inserts re ceive their combustion air from the room in which the unit is placed, and all of the products of combustion are exhausted into the room as well. The high efficiency of vent free units is due to the fact th at the heat produced is kept in the room. Vent free gas stoves and inserts have a maximum heat input in order to avoid emitting excess CO,

CO 2 

### , or NO X 

### into the room, and the units also have an O 2 

### depletion sensor or other device to shut the unit down if oxygen levels become too low. It is important to note that vent-free natural gas and LPG stoves, inserts and log sets should not be considered options for primary or even significant secondary heating use. There is considerable concern regarding indoor air quality and damage to homes by moisture created from their use, as combustion gases are not vented to the atmosphere. If the devices are used prudentl y, these problems are reduced. Their appropriate role is for aesthetics and minor secondary heatin g. Just as with direct vent gas stoves and fireplace inserts, LPG can be used as an altern ative where natural gas is not readily available.

B-Vent Gas Stoves and Fireplace Inserts (LPG and Natural Gas)

B-vent gas stoves and inserts draw their combus tion air from the room, and exhaust is vented outdoors. These units use a draft hood for the prop er venting of exhaust. B-vent gas stoves and inserts have lower efficiency than direct vent due to the fact that already heated room air is used as combustion air, which is then exhausted to the outdoors, taking heat away from the room.

OMNI Study Summary

In the OMNI study, the amount of fuel consumed by RWC devices was c onsidered the measure of activity. Activity data were provided by indi vidual appliance type by State and for the total MANE-VU region. The activity study conduc ted by OMNI showed that there were approximately 6.4 million tons of fuel burne d in 2002 by RWC devices in the MANE-VU region. The majority of RWC combustion was lo cated in New York (1.9 million tons of fuel burned) and Pennsylvania (1.4 m illion tons of fuel burned).Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-4



### OMNI then compiled an emissions inventory by county, by State, and fo r the entire MANE-VU region for the 2002 base year. The dry mass of fuel (activity) for cordwood, pellets, and manufactured wax/fiber firelogs compiled in th e activity task was multiplied by the applicable

emission factor in the units of mass air pollutant per mass of dry fuel. The emission factors were obtained by reviewing and averaging (if multiple sources were available) data obtained from available reports and publicati ons. PM and VOC (an ozone precu rsor) are the main criteria pollutants of concern for RWC and non attainme nt areas. The OMNI emissions inventory reported that there were 92,470 tons of total PM emissions and 87,741 tons of VOC generated from RWC devices in the MANE-VU region during the base year (2002). It should be noted that this analysis assumed that PM 10 

### was equivalent to PM. The onl y emissions control efficiency,

and control device information available is for PM 10 

### . We have therefore assumed that data for

PM 10 

### are applicable to PM 2.5



### .

Table 9.1 from the OMNI report summarizes meas ures for RWC RACM developed by EPA in EPA-450/2-89-015. OMNI reported the RACM fa ll in three primary categories: (1) improvement of performance, (2) reducing the use of RWC devices , and (3) episodic curtailment. The effectiveness in reducing RW C emissions and a relate d discussion of each of the various activities are also pr ovided in Table 9.1. In additio n to the three primary categories for RWC RACM, the RACM document emphasizes the importance of public awareness in many RWC emission control programs and provides considerable information on the subject.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-5



### Table 9.1 Summary of Measures Available for RWC RACM – PM 10

Program Elements Estimated

Effectiveness (%) Discussion

IMPROVEMENT OF PERFORMANCE

State implementation of NSPS 0 States are not expected to adopt this program element at levels that would affect program effectiveness significantly.

Ban on resale of uncertified

devices 0 No credit recognized because requirement is largely unenforceable: other elements will be required to include disabling of

retired used devices.

Installer Training Certification or Inspection Program ~ 5 Reduction in emissions from each new

certified RWC device where either the

installer is trained/certified or the installation is inspected.

90 Reduction in emissions from each new or existing conventional, uncertified RWC device replaced with a pellet stove. Pellet stoves

75 Reduction in emissions from each new or existing Phase II EPA certified RWC device replaced with a pellet stove.

EPA Phase II certified RWC

devices ~50 Reduction in emissions from each new or existing conventional, uncertified RWC device replaced with an EPA Phase II

certified RWC device.

Retrofit requirement <5 Reduction in emissions from each existing conventional, uncertified RWC device equipped with a retrofit catalyst or pellet hopper (to maximum when all existing

uncertified RWC devices have retrofit devices installed).

~50 Reduction in emissions from each existing conventional, uncertified RWC device replaced with Phase II certified device. Accelerated changeover requirement

100 Reduction in emissions from each existing conventional, uncertified RWC device removed and not replaced: requires existing

device to be disabled and not resold.

~50 Reduction in emissions from each existing conventional, uncertified RWC device replaced with Phase II certified device. Accelerated changeover

inducement

100 Reduction in emissions from each existing conventional, uncertified RWC device removed and not replaced: requires existing

device to be disabled and not resold.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-6



### Table 9.1 Summary of Measures Available for RWC RACM – PM 10

Program Elements Estimated

Effectiveness (%) Discussion

Require fireplace inserts 0 No cred it recognized for fireplace inserts, since inserts change use of fireplace from aesthetic to primary heat source, resulting

in an increase in amount of wood combusted and higher overall emissions.

Wood moisture <5 Reduction in total emissions from all RWC devices in the community/airshed.

Trash burning prohibition 0 No credit recognized for eliminating trash burning in RWC devices.

Weatherization of residences <5 Reduction in total emissions from all RWC devices in the community/airshed.

Opacity limits <5 Reduction in total emissions from all RWC devices in the community/airshed.

REDUCING USE OF RWC DEVICES

Availability of alternative fuels 10 0 Reduction in emissions from each RWC device removed from service and replaced with device using natural gas: recognize no more than 10% of RWC devices replaced under program with no additional

incentives.

Emission trading Computation required For a 2:1 trading ratio, the reduction in

emissions from each new stove would be

calculated as the difference between

emissions of a new RWC device and 2 times the average emissions per stove in the community:

multiplier would change for other trading

ratios.

Taxes on RWC devices Variable Emission reduction credit would vary with utility or tax rate structure adopted and

extent to which this structure resulted in

reduction in number of RWC devices in the community versus reduction in use of RWC

devices.

Regulatory ban on RWC devices in new dwellings 100 Reduction in emissions from new RWC devices purchased for installation in new dwellings.

Regulatory ban on

existing RWC devices 100 Reduction in emissions from each RWC

device removed.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-7



### Table 9.1 Summary of Measures Available for RWC RACM – PM 10

Program Elements Estimated

Effectiveness (%) Discussion

EPISODIC CURTAILMENT

Voluntary 10 Reduction in emissions for all RWC devices not exempted.

Mandatory 60% fireplace

50% woodstoves Reduction in emissions for all RWC devices not exempted.

Table Reference: U.S. EPA, 1992, Technical Information Document for Residential Wood Combustion Best

Available Control Measures , Research Triangle Park, NC, EPA-450/2-92-002.



### Table 9.2 from the OMNI report summarizes meas ures for RWC BACM developed by EPA in EPA-450/2-92-002. As shown in Table 9.2, the BACM fall into two primary categories: (1) integral measures which are necessary for the success of a long-term RWC pollutant reduction programs but, by themselves, are not adequate to provide long-term reducti ons and (2) flexible (long-term) measures to reduce, eliminate, or prevent increases in pollutant emissions for existing and/or new installations. With the ex ceptions of the device and upgrade offsets, the specific elements of the BACM are essentially those described in the RACM document with the

various efficiencies listed in Table 9.1 being applicable.

Table 9.2 Summary of Measures Available for RWC BACM – PM 10

Integral Measures 1 Flexible Measures that

Reduce or Eliminate

Emissions from Existing Installations 2 Flexible Measures that

Reduce Emissions or

Prevent Emission

Increases from New

Installations 2 Flexible Measures

that Reduce

Emissions from New and Existing

Installations 2

1. Public awareness and

education. 1. Conversion of existing wood-burning fireplaces to gas logs. 1. Gas fireplaces or gas logs in new wood burning fireplace

installations. 1. Device offset. 4

2. Mandatory curtailment during predicted periods of high PM 10 concentrations. 2. Changeover to EPA certified,

Phase II stoves or equivalent. 2. Upgrade offset. 4 2. Upgrade offset. 4

3. All new stove

installations EPAcertified, Phase II stoves or equivalent. 3. Changeover to low emitting device. 3 3. Restriction on number and density of new wood-burning stove and/or fireplace

installations.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-8



### Table 9.2 Summary of Measures Available for RWC BACM – PM 10

Integral Measures 1 Flexible Measures that

Reduce or Eliminate

Emissions from Existing Installations 2 Flexible Measures that

Reduce Emissions or

Prevent Emission

Increases from New

Installations 2 Flexible Measures

that Reduce

Emissions from New and Existing

Installations 2

4. Measures to improve wood burning performance:

-control of wood

moisture content

-weatherization of

homes with wood stoves -educational opacity

program 4. Requirement that new

stove installations be low emitting.

1 Integral measures are regarded as critical for the succes s of a RWC control program, but by themselves are not

intended to result in long-term attainment of the PM 10 NAAQS for serious PM 10 nonattainment areas.

2 Flexible measures are designed for permanent control of RWC emissions and thus long-term attainment of the

PM 10 NAAQS.

3 This measure is virtually identical to item 2, except that the changeover is recommended to a “low-emitting”

device that can document “in-home” field test emissions less than the emission factor averages of “in-home” field

test emissions data for EPA-certified stoves. This can include classes of devices that are demonstrated to be capable as a class of producing lower field emissions, as well as, specific m odel units that perform better in the field than the class collectively (an example might includ e masonry heaters, uncertified pellet-fueled devices, and wood fired gasification centralized heating systems).

4 Offsets are intended to achieve emissi on reductions, when retiring (device offs et) or changing-out (upgrade offset) conventional stoves, greater than the emissions increase resulting from new stove installations. Table Reference: U.S. EPA, 1992, Technical Information Document for Residential Wood Combustion Best

Available Control Measures , Research Triangle Park, NC, EPA-450/2-92-002.



### OMNI reported that the RWC RACM a nd BACM have been the basis for PM 10 

### innovative strategies implemented in various west ern States and in local jurisdictions and have also been, inlarge part, the basis for a number of western State and their loca l RWC regulations. As part of these strategies, strict particulate emission standa rds have been developed which will take effect

in 2008.

The OMNI report states that the Washington St ate standard is notable among State and local regulations for residential wood burning devices . Washington State has implemented more stringent standards for reside ntial wood burning devices, so de vices installed in Washington State must be certified to the more stringent st andard. This has affected the stove market because many U.S. certified stove manufacturers choos e to have their appliances certified to the more stringent Washington State standard, unless the manufacturer can not or does not choose to test to the tighter standard. Discussions with EPA indicate that most manufacturers are choosing to design and sell units that meet the Washingt on State standards of 4.5 g/hr for non catalytic wood stoves and 2.5 g/hr for catalytic wood st oves (personal communication with Mr. John Dupree of the U.S. EPA).Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-9



### FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR

RESIDENTIAL WOOD COMBUSTION

Cost of Compliance

OMNI analyzed the cost effec tiveness of five categories of widely existing, older technology wood-burning devices. These are: (1) freesta nding cordwood stoves, (2) cordwood-fueled fireplace inserts, (3) cordwood fireplaces (with out inserts) used for heating purposes, (4) centralized cordwood heating systems and (5) co rdwood fireplaces used for aesthetic purposes. Table 9.3 lists these five categories with the available, improved technology replacement, installation scenarios, and fuel switching altern atives that would reduc e particulate and VOC

emissions.

OMNI noted that wood resources are abundant a nd widely utilized as fuel, and heating is

essential due to the climate of the region. The cost to households of any regulatory program mandating acceptable heating practices is an impo rtant consideration. Likewise, the cost to households of any voluntary program is paramount for its success. The cost effectiveness of all reasonable scenarios for the replacement, modificat ion or alternative fuel use for older existing, high emission wood-burning appliances was provid ed in the OMNI report for regulators and policy makers charged with the task of speci fically lowering particulate and VOC emissions

from residential wood combustion.

The tables provided in this chapter based on th e OMNI report allow for a direct comparison of the cost burden for each realistic mitigation option that would be shouldered by residential users. As an example, for an average resident in the MANE-VU region with an existing older technology centralized cordwood heating system, th e best current option in terms of cost among the pellet, natural gas, and LPG options, is na tural gas (assuming natural gas is available). Similarly, for wood-burning fireplaces used for aest hetics, manufactured wax/ fiber firelogs offer the lowest cost per unit mass of air pollutant redu ction. The cost effectiveness of each option is dependent on the costs of the new equipment and th e cost of required fuels. The costs presented in the tables in this chapter were the most curre nt information available as of the date of the OMNI report.

Estimates of costs per ton of re ductions in the tables in this chapter are specific to the MANE-VU region because they reflect the estima ted usage of various de vices in this region.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-10



### Table 9.3 Improved Technologies and Fuel Alternatives

Existing Cordwood Device High Technology Replacement, Installation or

Alternative Fuel

Replacement with Certifie d NSPS Non-Catalytic

Cordwood Stove

Replacement with Certif ied NSPS Catalytic

Cordwood Stove

Replacement with Pellet Stove

Replacement with Gas Stove – natural gas (B vent, direct vent) Uncertified Freestanding Cordwood

Stove

Replacement with Gas Stove – LPG

(B vent, direct vent)

Replacement with Certifie d NSPS Non-Catalytic

Cordwood Insert

Replacement with Certif ied NSPS Catalytic

Cordwood

Replacement with Pellet Insert

Replacement with Gas Insert – natural gas (B vent, direct vent) Uncertified Cordwood Fireplace

Insert

Replacement with Gas Insert – LPG

(B vent, direct vent)

Installation of Certified NSPS Non-Catalytic

Cordwood Insert

Installation of Certified NSPS Catalytic Cordwood

Insert

Installation of Pellet Insert

Installation of Gas Insert – natural gas

(B-vent, direct vent) Cordwood Fireplace without Insert

Used for Heating

Installation of Gas Insert – LPG

(B-vent, direct vent)

Installation of Gas Log Set – natural gas (vented and vent free)

Installation of Gas Lo g Set – LPG (vented and vent free) Cordwood Fireplace Used for

Aesthetic Purposes

Wax/Fiber Firelog Fuel

Pellet Furnace or Boiler

Gas Furnace or Boiler – natural gas Centralized Cordwood Heating

System

Gas Furnace or Boiler – LPG

OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and Documentation for Residential Wood Combustion in the MANE-VU Region . Project funded by Mid-Atlantic Regional Air Management Associ ation, Inc., December 19, 2006.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-11



### Table 9.4 from the OMNI report demonstrates the co st effectiveness of re placing three types of cordwood stoves and fireplaces with devices that emit less PM. Table 9.5 from the OMNI report demonstrates the impact on cost effectiveness of the same replacements on VOC reductions.

The cost effectiveness tables ar e in reference to the replacement of an existing RWC device, and

do not include new construction.

In Tables 9.4 and 9.5, if the total annual cost of the improved technology and alternative fuel replacement or installation is less than the total annual cost of the existing device, and there is corresponding pollutant reduction afte r installation or replacement, then there is no cost for the pollution reduction, and the cell is marked as “**” . The replacement options for which there is no cost may actually represent cost savings, and thus are the most cost effective options for replacement.

Table 9.4 PM Reduction Cost Effectiveness for Replacement of Existing Uncertified Freestanding Cordwood Stove/Insert and Co rdwood Fireplace w/o Insert for Heating

Certified

NSPS NonCatalytic

Cordwood

Stove Certified

NSPS Catalytic

Cordwood

Stove Pellet

Stove Gas

StoveNG,

B Vent Gas

StoveNG,

Direct

Vent Gas

StoveLPG,

B Vent Gas

StoveLPG,

Direct

Vent Existing

Cordwood

Device PM Reduction Cost Ef fectiveness ($/ton)

Uncertified Freestanding

Cordwood

Stove 1,170 3,300 8,960 5,350 3,530 12,600 9,760

Uncertified

Cordwood Fireplace

Insert   5,180 1,910 **  8,980 6,040

Cordwood Fireplace

w/o Insert for Heating 3,880 5,670 8,330 ** ** 1,880 695

OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and Documentation for Residential Wood Combustion in the MANE-VU Region . Project funded by Mid-Atlantic Regional Air Management Associ ation, Inc., December 19, 2006.

**No cost for the pollution reduction.



### Tables 9.4 and 9.5 indicate that OMNI estimated that in the MANE-VU region there are several options for reducing emissions from two of th e above types of fireplaces that would reduce emissions at essentially no cost , due to fuel cost savings.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-12



### Table 9.5 VOC Reduction Cost Effectiveness for Replacement of Existing Uncertified Freestanding Cordwood Stove/Insert and Co rdwood Fireplace w/o Insert for Heating

Certified

NSPS NonCatalytic

Cordwood

Stove Certified

NSPS Catalytic

Cordwood

Stove Pellet

Stove Gas

StoveNG,

B Vent Gas

StoveNG,

Direct

Vent Gas

StoveLPG,

B Vent Gas

StoveLPG,

Direct

Vent Existing

Cordwood

Device VOC Reduction Cost Effectiveness ($/ton)

Uncertified Freestanding

Cordwood

Stove 1,260 2,960 7,740 4,940 3,260 11,800 9,130

Uncertified

Cordwood Fireplace

Insert   4,480 1,760 **  8,410 5,640

Cordwood Fireplace

w/o Insert for Heating 7,900 10,400 13,200 ** ** 3,090 1,140

OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and Documentation for Residential Wood Combustion in the MANE-VU Region . Project funded by Mid-Atlantic Regional Air Management Associ ation, Inc., December 19, 2006.

**No cost for the pollution reduction.



### Table 9.6 presents the cost eff ectiveness in terms of dollars per ton of PM reduction and VOC reduction for replacement of an existing central ized cordwood heating system with three available technologies. The cost effectiveness ta bles are in reference to the replacement of an existing RWC device, and do not include new cons truction. The most cost effective option is replacing the existing system with a natural gas fu rnace or boiler. This option is not feasible in areas that do not have access to natural gas, a nd the increase in costs as sociated with using LPG is significant.

Table 9.6 Reduction Cost Effectiveness for th e Replacement of an Existing Centralized Cordwood Heating System

High Technology Replacement, Installation or

Alternative Fuel PM Reduction

Cost Effectiveness ($/ton) VOC Reduction

Cost Effectiveness ($/ton)

Pellet Furnaces and Boilers 7,810 17,200

Gas Furnaces and Boilers–

Natural Gas 3,030 7,150

Gas Furnaces and Boilers-LPG 9,370 23,100

OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and Documentation for Residential Wood Combustion in the MANE-VU Region . Project funded by Mid-Atlantic Regional Air Management Associ ation, Inc., December 19, 2006.



### Table 9.7 presents the cost eff ectiveness in terms of dollars per ton of PM reduction and VOC reduction for the addition of a gas log set or use of wax/fiber firelogs in an existing fireplace withAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-13



### no insert. Burning wax/fiber firelogs in the exis ting fireplace is, by far, the most cost effective option for reducing emissions of PM and VOC.

Table 9.7 Pollutant Reduction Cost Effectivene ss for the Addition of a Gas Log Set or Use of Wax/Fiber Firelogs in an Existing Fi replace w/o Insert Used for Aesthetics

Pollutant Reduction Cost Effectiveness ($/ton)

Pollutant Vent-Free Gas Log Set-NG Vented Gas Log Set-NG Vent-Free Gas Log Set-LPG VentedGas LogLPG Wax/Fiber Firelog Fuel

PM 27,100 29,900 29,400 34,100 2,530

VOC 43,900 48,500 48,300 56,600 5,110

OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and Documentation for Residential Wood Combustion in the MANE-VU Region . Project funded by Mid-Atlantic Regional Air Management Associ ation, Inc., December 19, 2006.



### OMNI presented no cost-effectiveness summary for other RWC control measures such as

described in EPA’s PM 10 

### RACM/BACM guideline documents. Costs associated with these measures are predominantly organizational and administrative associated with the implementation of regulations.

Time Necessary For Compliance

Because the control methods discussed in the previous section for RW C are existing technology, the time necessary for compliance would depend on the amount of time it would take to regulate the sources and establish compliance deadlines. The Feasibility Assessment of a Changeout/Education Program for Residential Wood Combustion from the Canadian Council of

Ministers of the Environment s uggests a phased approach for nati onal implementation. A phased approach will enable the program to evolve ove r time and benefit from lessons learned in the early stages of the program. Phasing also re flects the reality that building awareness and changing behavior is a long-term investment. Th e approach that this report proposed had two phases. The first phase ( 2005-2006) focused on building a ba se for support and understanding around RWC in a single province. The sec ond phase (2007 and beyond) and full roll-out

involved the realization of i ndependent, arms length management of public education and outreach by all stakeholders th roughout Canada. The main st eps for this phase included:

• Implementation of national regulation as soon as possible (i.e. 2008-2009);

• Full operational capacity across Canada;

• Funding to come from multiple sources (i.e. na tionwide partnerships with the insurance, financial, and utilities industries);

• Movement of various groups from being ta rget audiences to becoming key players in designing and delivering woodstove change -out/public education campaigns; and

• Multi-stakeholder involvement and shared leadership (governments together with business and industry, communities, a nd non-governmental organizations).Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-14



### Energy and Non-Air Impacts

Other factors beyond PM 2.5 

### and regional haze (i.e., VOC and fine particles) should also influence RWC regulatory policy. The greenhouse gas bene fits of biomass combustion and the minimal acid gas emissions (acid precip itation impacts) from wood combustion are strong environmental advantages. Further, the fact that wood is a domestic renewable energy source and the fact that the cost of natural gas, propane, and fuel oil have a history of risi ng together have been responsible for the increase in th e use of RWC. For example, se veral States are encouraging the use of renewable energy sources su ch as wood for heating purposes.

The Canadian Council of Ministers of the Envi ronment study estimated that the increase in combustion efficiency associated with a switch out to a more efficient stove would save on average more than one cord of wood per stove per heating season.

Any mandatory change out program should be mindful that even with assistance, woodstove change out programs will impact families that ar e least able to bear the burden of additional costs. Voluntary programs do not impose this economic burden on families less able to bear

associated costs.

Remaining Useful Life Of The Source

From information obtained from a scoping study th at was prepared for Environment Canada in 1997, (Gulland Associates Inc., 1997) the durability of low emission stoves has improved considerably. Premature stove degradation is not viewed as a problem. In most new stoves today, vulnerable parts can be replaced, and manuf acturers now use more heat-resistant materials

such as ceramics and stainless st eel. The performance and durability of catalytic stoves has also improved through better design and use of material s. The useful life of a wood stove catalytic element is estimated to be 9,000 to 12,000 hours, or three to five years of use, depending on heating demand, user skill, and de gree of maintenance provided.

The best mechanism by which to lower smoke emissions from residential wood burning appliances is to replace conventional equipment with certified low emission stoves. Given the minimum useful life span of a wood stove of 10- 15 years (per industry references), over which time the incremental cost of advanced technolog ies is spread, the cost impacts did not seem

unreasonable to Environment Canada. It is also possible that the price of the least expensive advanced technology stove would come down after a regulation were established as

manufacturers seek to fill the low cost market niche formerly filled by conventional stoves; that is, plain, unadorned styling and l acking additional features such as ash pan and large glass door panel. (Gulland Associates Inc., 1997) Ma ny woodstove manufacturers have chosen to manufacture products at a reasonab le cost that meet more stringent emissions standards such as those in Washington State (personal co mmunication with Mr. John Dupree of EPA)

. Implementation of stricter emissions standards in additional states or regions will likely increase the competition to produce these woodst oves at even more reasonable prices.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9-15



### REFERENCES

OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and Documentation for Resident ial Wood Combustion in the MANE-VU Region

. Project funded by Mid-Atlantic Regional Air Management Association, Inc., December 19,

2006.

Headquarters, U.S. EPA. Personal communicat ion regarding the number of new residential wood burning devices meeting the Washington State standards from Mr. John Dupree (202) 564-5950, (Dupree.john@epa.gov) via telephone on April 12, 2007.

U.S. EPA, 1989, Guideline Series, Guidance Document for Residential Wood Combustion

Emission Control Measures , Research Triangle Park, NC, EPA-450/2-89-015.

U.S. EPA, 1992, Technical Information Document fo r Residential Wood Combustion Best

Available Control Measures , Research Triangle Pa rk, NC, EPA-450/2-92-002.

U.S. EPA, 1993, PM-10 Innovative Strategies: A Sour cebook for PM-10 Control Programs

, Research Triangle Par k, NC, EPA-452/R-93-016.

The Canadian Centre for Pollution Preventi on, CULLBRIDG Marketing and Communications and Action-Environment, Feasibility Assessment of a C hange-out/Education Program for Residential Wood Combustion, A Step-by-Step Approach to a National Program Aimed at Reducing Emissions from Residential Wood Combustion . September 20, 2004.

Gulland Associates Inc., Scoping Study: Reducing Smoke Emi ssions From Home Heating With

Wood . Prepared for Environment Canada, March 31, 1997.

Environment Australia (2002). Technical Report No. 4: Review of Literature on Residential Firewood Use, Wood-Smoke and Air Toxics . 49p. Report available on the Environment

Australia website http://ea.gov.au/atmosphere/airt oxics/report 4/exec-summary.html.This page left blank intentionallyAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion – Outdoor Wood-Fired Boilers Page 10-1



### CHAPTER 10

RESIDENTIAL WOOD COMBUSTION - OUTDOOR WOOD-FIRED BOILERS

BACKGROUND

Outdoor wood-fired boilers are used in the Northeas t United States, and thei r use is increasing as more traditional heating fuels (heating oil, na tural gas) are becoming more expensive. NESCAUM (2007) estimates that the sale of out door wood-fired boilers is increasing by 25-50% annually. Nationwide there are between 155,000 and 200,000 boilers in service (Personal communication with Lisa Rector, NESCAUM). If the sales trends continue, NESCAUM estimates that there may be up to 500,000 boilers nationally by 2010.

Outdoor wood-fired boilers are used for heati ng and providing hot water for both individual homes and for “mini-district heating” (Woodhe at.org 2007). Additional uses of outdoor woodfired boilers include heating swimming pools an d greenhouses. Outdoor wood-fired boilers are typically located in sheds that are located near buildings. Heated water is conveyed through underground or insulated pipes.

Even though outdoor wood-fired boilers may be ec onomical solutions to home heating and hot water production, they contribute significantly to air pollution. Outdoor boilers emit so much smoke they have been banned by some local jurisdictions (Woodheat.org 2007). NESCAUM (2007) estimates that the averag e fine particulate emissions fr om one outdoor wood-fired boiler are equivalent to the emissions from 22 US E nvironmental Protection Agency (EPA) certified wood stoves, 205 oil-fired furnaces, or 8,000 natural gas-fired furnaces.

On the basis of heat input, NESCAUM (2007) estimated that outdoor wood-fired boilers emit from 1.5 to 3.1 pounds of PM per MMBTU heat input. This information was calculated by NESCAUM using data from tests conducted on outdoor wood-fired boilers for EPA (EPA 1998a). (Guldberg 2007) used data from 56 out door wood-fired boilers tests conducted by EPA in 1995 and 1999, and estimated that outdoor w ood-fired boilers emit 1.44 pounds of PM per MMBTU heat input. In comparison, the EPA es timate (EPA 1998b) for PM from residential fuel oil combustion is 0.4 pounds of PM per t housand gallons of fuel combusted. Assuming a heating value of 140 MMBTU per thousand gallons of fuel oil, the PM emission factor is 0.003 pounds of PM per MMBTU heat input for reside ntial fuel oil combustion. Similarly, for residential natural gas combustion, (EPA 1998c) assuming a natural gas heating value of 1,020 BTU per standard cubic foot, the PM emission factor is 0.002 pounds per MMBTU heat input.

Based on these emission factor estimates, and strictly on the ba sis of heat input, outdoor woodfired boilers emit roughly 500 times as much PM as oil-fired residential furnaces and 750 times as much PM as natural gas-fired residential fu rnaces based on the low-range estimate of PM

emissions from outdoor wood-fired boilers. Ba sed on the upper range of the PM emissions estimate from outdoor wood-fired boilers, they em it roughly 1,000 times as much PM as oil-fired residential furnaces and 1,500 times as much PM as natural gas-fired furnaces.

Heavy emissions from outdoor wood-fired boilers can be attributed to their designs. For example, most outdoor wood-fired boilers have fireboxes that are surrounded by a water jacket. The water jacket makes complete combustion of the wood nearly impossible due to the coolingAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion – Outdoor Wood-Fired Boilers Page 10-2



### effect that the jacket has on the firebox. Th e flaming combustion of wood cannot occur below about 540 C (1,000 F), so the steel surfaces of the water jacket backed up by water at approximately 65 C (150 F) chill and quench the flames well before complete combustion can

occur.

In addition outdoor wood-fired boilers smoke heav ily due to their cyclical operating pattern. When the temperature of the water within the bo iler falls below a set point, its combustion air damper opens and/or a small fan forces combusti on air into the firebox. Once the water is heated back to the upper set point, the fan is turned off and/or the co mbustion air damper closes. During the off cycles the fire smolders and much of th e smoke condenses as creosote on the cold steel internal surfaces. When the thermostat again calls for heat and incoming combustion air rekindles the fire, the heat ignites the creosote clinging to the boiler walls. This leads to an increase in emissions that accompanie s the poor combustion in the firebox.

Outdoor wood-fired boilers are also sometimes not sized appropriately for the house that they are intended to heat. For example, an oversized boiler will tend to run in the smoldering phase longer than in the full out burn pha se, thereby producing more smoke.

It has been suggested that ex cessive production of emissions by outdoor wood-fired boilers is associated improper installation of the boiler or the use of fuels not designed to be combusted in the boiler (personal communicati on with Peter Guldberg, Tech Environmental). Additionally, Guldberg, 2007 suggests that emissions from outdoor wood-fired boilers are comparable to other

wood-fired combustion devices in terms of lbs/MMB TU heat generated. In any case, Guldberg,

2007 indicates that outdoor wood-fired boiler manuf acturers have worked with EPA to develop a voluntary Outdoor Wood-fired Heater Program with a Phase I emission target of 0.6 lb/MMBTU. According to Guldberg, 2007 manuf acturers will offer the outdoor wood-fired heaters qualified to achieve the Phase I standard later in 2007.

NESCAUM’s Model Rule

On January 29, 2007, NESCAUM made availabl e its “Outdoor Hydr onic Heater Model Regulation.” The model rule is designed to serve as a template to assist State and local agencies in adopting requirements that will reduce air po llution from outdoor wood-fired boilers. The model rule was developed in cooperation with a nu mber of States and EPA. The model rule has provisions for:

• 

### Critical definitions,

• 

### Emission standards,

• 

### Test method procedures,

• 

### Certification process, and

• 

### Labeling requirements.

The model rule contains a single method for regul ating new units with respect to the critical elements and contemplates that States may propose alternative approaches for other provisions. It also provides alternatives for states to c onsider for regulating previously installed units (NESCAUM 2007).Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion – Outdoor Wood-Fired Boilers Page 10-3



### NESCAUM’s model rule sets standards for pa rticulate matter (PM) emissions by phases for

residential and commercial boilers. The PM standards for both boile r types are identical. Phase I calls for a PM emission limit or 0.44 pounds per m illion BTU heat input. This standard would have to be met by March 31, 2008. Phase II calls for a PM emission standard of 0.32 lb/MMBTU which is to be met by March 31, 2010.

Vermont’s Rule on Outdoor Wood-fired Boilers

On April 12, 2007 Vermont filed a regulation on outdoor wood-fired boilers with the Secretary of State and the Legislative Co mmittee on Administrative Rules. The rule legally went into effect on April 27, 2007, and adopts NESCAUM’s m odel rule Phase 1 PM emission standard of 0.44 lb/MMBTU. As of March 31, 2008, outdoor wood- fired boilers not meeting the standard of

0.44 lb/MMBTU cannot be sold in Vermont. Additional information on Vermont’s final rule on

outdoor wood-fired boilers can be found on the following web site: http://www.vtwoodsmoke.org . (Etter, personal communication)

This section of this document addresses the f our factor analysis wh ich includes the following elements: cost of compliance, time necessary for compliance, energy and non-air impacts, and remaining useful life of the source.

FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR

OUTDOOR WOOD-FIRED BOILERS

Cost of Compliance

Outdoor wood-fired boilers are priced according to their size (heat output). For example, Northwest Manufacturing sells a li ne of outdoor wood-fired boilers that ranges in price from $4,295 for a boiler that will heat a 2,000 square foot house to $12,995 for a boiler that can heat up to 20,000 square feet. Similarly, Hud-Son Fore st Equipment has a line of outdoor wood-fired boilers that range in price from $6,095 for boile r that can heat a 2,000 square foot house to $7,795 for a boiler that can heat up to 10,000 square feet.

There are currently only a few outdoor wood-fire d boiler manufacturers whose products would meet the 2008 NESCAUM phase I standard of 0.44 lb/MMBTU. NESCAUM estimates that there are “several units currently on the market that can meet this standard.” In addition, NESCAUM estimates that more stringent air st andards that it proposed should come into compliance in 2010 would currently only be met by one unit. Consequently, manufacturers of

outdoor wood-fired boilers would have to invest money into research and development in order

to manufacture boilers that would meet NESCAU M’s model standards. MACTEC contacted an

outdoor wood-fired boiler manufacturer to determin e cost increases due to the NESCAUM rule. The boiler manufacturer was not able to provi de estimated cost increases necessary to manufacture boilers meeting th e NESCAUM model rule standa rds (personal communication with Central Boiler, Inc.).

MACTEC also investigated the costs of replacing the outdoor w ood-fired boilers with heating

oil-fired furnaces and boilers. We determined th at the capital cost of oil-fired water boilers ranged from $2,800 - $3,825. Similarly, the capital cost of oil-fired furnaces range from $1,560 -Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion – Outdoor Wood-Fired Boilers Page 10-4



### $1,800 (Alpine Home Air 2007). Therefore, oil-fire d boilers and furnaces can be substantially less expensive than outdoor wood-fired boilers.

In a previous section, information was presented on the average amount of distillate fuel oil used on an annual basis by households in the North east. It was estimated that households use approximately 865 gal/yr of fuel oil (STAPPA- ALAPCO 2006). Therefore, the annual average heating cost using fuel would currently be approximately $2,100 (assuming a fuel oil price of $2.40/gal). The University of Wisconsin Solid and Hazardous Waste Education Center (2007) estimates that it would take only 4 full cords of oak firewood to heat a house per year. At approximately $200/cord (Boston.com 2004), this e quates to an annual fuel cost of $800/year. Consequently, the annual cost for firewood is $1,300 le ss than the cost of distillate fuel oil. Additionally, many operators of outdoor wood boilers have acce ss to a free supply of firewood for the boiler, thus the only fuel cost to these ope rators is the time, effort , and expense associated with gathering the wood and cutting it fo r use in the outdoor wood-fired boiler.

Assuming the average household use of 865 gal/yr of fuel oil, and a fuel oil heating value of 140 MMBTU per thousand gallons, the annual heat i nput required is 121.1 MMBTU. The emission factors for residential fuel oil combustion, natural gas combustion, and wood combustion in outdoor wood-fired boilers are 0.003, 0.002, and 1.5 to 3.1 pounds of PM per MMBTU heat input respectively. Using the annual heat input requirement of 121.1 MMBTU, the annual

emissions from an oil-fired furnace would be 0.4 pounds, the emissions from a natural gas-fired furnace would be 0.2 pounds, and the emissions from the outdoor wood-fired boiler would be from 180 to 380 pounds. The cost of replacing an outdoor wood-fired boile r with an oil-fired

furnace or boiler is estimated to be from $1,560 to $3,825 (Alpine Home Air 2007). If the capital cost of the oil-fired furnace or boiler is spread over ten years, th e annualized capital cost is between $156 and $383. Additionally, the cost of fuel oil is estimated to be from $0 to $2,100

more than the outdoor wood-fired boiler fuel co sts depending on whether the operator has access to a free wood supply, or must purchase the wood by the cord. Based on these estimates, the PM cost effectiveness of replacing an outdoor wood- fired boiler with an oil-fired furnace or boiler would be from $1,700 to $13,000 per ton of PM redu ced. The costs for replacement of outdoor wood-fired boilers with natural gas-fired furn aces or boilers have not been quantified.

Time Necessary for Compliance

Outdoor wood-fired boilers have been in operatio n for approximately the last 15 years (personal

communication with P. Etter from Vermont Air Pollution Control). Cons equently, the average age of outdoor wood-fired boilers is not known. On at least one occasion, a boiler vendor opted to go out of business rather than honor 5-ye ar warranties (personal communication with J. Gulland from OutdoorHeat.org). If States pass a rule simila r to NESCAUM’s and existing boilers are grandfathered, only new boilers w ould be required to meet the more stringent standards. In the section on residential heating, it was estimated that the average useful life of a residential boiler is between 18-25 years. We ll manufactured outdoor wood-fired boilers may

have similar useful lives. Th erefore, new boilers meeting more stringent PM emissions standards would be phased in slow ly as older boilers are replaced.

Replacement of wood-fired boilers with oil-fired furnaces or boilers could occur on a very quick

schedule. The number of residential boiler/fu rnace manufacturers in the United States isAssessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion – Outdoor Wood-Fired Boilers Page 10-5



### indicative of the fact that there is an ample supply of manufacturer s. Although it is possible for outdoor wood-fired boilers to be replaced quickly, realistically, most of these units have been installed within the past 15 years. Since they are designed to last for approximately 20 years, operators of the outdoor wood-fi red boilers would likely be reluctant to replace them immediately.

Energy and Non-Air Impacts

Wood is a renewable resour ce that is plentiful in the United St ates Northeast. The increased use

of outdoor wood-fired boilers would lead to an increase in the amount of firewood that is

combusted in the US Northeast on an annual basis. Alternatively, tighter rules regarding the PM emissions from outdoor wood-fired boilers may l ead to a decrease in their use, which would

make more firewood available for use in wood st oves and fire places. A move away from woodfired boilers would increase th e demand on heating fuels such as heating oil, propane, and potentially coal or natural gas.

The increased use of outdoor wood-fired boilers may have a variety of non-air impacts on the environment, especially on forest and water reso urces. The potential imp acts are outlined below.

Nuisance Smoke : Outdoor wood-fired boilers typically ha ve very short stacks, and are prone to smoke. The short stacks oftentimes prevent proper mixing of the smoke and soot with the surrounding air, thereby creating nuisance smoke problems for surrounding houses or communities (Michigan DEQ 2007).

Water : Increased logging to satisfy the demand for firewood may increase runoff of silts and sediments into adjacent creeks and rivers. This increased sediment load in rivers can affect aquatic ecosystems that are integral to rivers and streams.

Soils : Increased logging may impact soils in many ways. For example, heavy machinery used to fell and process trees may lead to rutting and co mpaction of the soil, which in turn leads to higher erosion and/or alte red vegetative regrowth.

Wildlife : Increased logging may put pressure on existing wildlife populations in the US Northeast by altering their critical habitat.

Threatened and Endangered Species : Increased logging in Northeas t may impact threatened and endangered species through habita t destruction or alteration.

Remaining Useful Life of the Source

The useful life of outdoor wood-fi red boilers is approximately 20 y ears, which is also very close

to the useful life of other resi dential boilers (Etter, personal communication). In addition, Mr.

Etter indicated that outdoor wood-fired boile rs have only been around for approximately 15 years, therefore, most of the boilers that have b een put into service are likely to remain there for at least the next five years.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion – Outdoor Wood-Fired Boilers Page 10-6



### REFERENCES

EPA, 1998a. Emissions from Outdoor Wood-Burni ng Residential Hot Water Furnaces . EPA

Publication Numb er EPA-600/R-98-017.

EPA, 1998b. AP-42 section 1.3. Fuel Oil Combustion

.

EPA, 1998c. AP-42 section 1.4. Natural Gas Combustion

.

Etter, P., Vermont Department of Environmenta l Conservation, Air Pollu tion Control Division.

Personal communication with Mr. Bernd Haneke , MACTEC Federal Programs, Inc., on March 9, 2007.

Etter, P., Vermont Department of Environmenta l Conservation, Air Pollu tion Control Division. Personal communication with Mr. William Hodan, MACTEC Federal Programs, Inc., on July 3,

2007.

Gulland, J., OutdoorHeat.org. Personal commun ication with Mr. Bernd Haneke, MACTEC Federal Programs, Inc., via E-mail on March 9, 2007.

Guldberg, P., Tech Environmental, Inc. Personal communication with Mr. William Hodan, MACTEC Federal Programs, Inc. via E-mail on May 17, 2007.

Guldberg, P. 2007. Outdoor Wood Boilers – New Emissions Test Data and Future Trends

. Presented at the 16th Annual Internationa l Emission Inventory Conference - Emission Inventories: “Integ ration, Analysis, a nd Communications”

Killeen, W. 2004. Firewood Shortage Reflected in Prices . Document obtained from the World

Wide Web at: www.boston.com

Michigan Department of Environmental Quality 2007. Outdoor Wood Boiler and Air Quality

Factsheet . Document obtained from the World Wide Web at: www.michigan.gov/deqair

NESCAUM, 2006. Assessment of Outdoor Wood-fired Boilers . Document obtained from the

World Wide Web at: http://burningissues.org/outdoor-wood-boilers.htm

NESCAUM, 2007. Outdoor Hydronic Heater Model Regulation . Document obtained from the

World Wide Web at: http://burningissues.org/outdoor-wood-boilers.htm

NESCAUM. Personal communicati on between Ms. Lisa Rector and Dr. Art Werner, MACTEC Federal Programs, Inc., on June 6, 2007.

STAPPA ALAPCO, 2006. Controlling Fine Particulate Matte r Under the Clean Air Act: A Menu of Options

.

Central Boiler, Inc. Personal communicati on between Mr. Rodney Tollefson and Mr. Bernd Haneke, MACTEC Federal Prog rams, Inc., on March 8, 2007.Assessment of Reasonable Progress for Re gional Haze In MANE-VU Class I Areas Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion – Outdoor Wood-Fired Boilers Page 10-7



### University of Wisconsin 2005. Using Wood as a Residential Hea ting Fuel: Issues and Options

. Published by the University of Wisconsin So lid and Hazardous Waste Education Center, and

downloaded from the World Wide Web at: uwm.edu/Dept/shwec/public ations/cabinet/p2/out doorwoodfiredboilers.pdf

Information on prices of furnaces and boilers we re obtained from the World Wide Web using the following URLs: www.alpinehomeair.com 

### ; www.hud-son.com/woodfurnaces.htm 

### ;
www.woodmaster.com/web.htm