This page left blank intentionally.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page i **Table of Contents Chapter**  **Page List of Acronyms**  **................................ ................................**  **................................ .................**  **v Executive Summary**  **................................ ................................**  **................................ .........**  **vi i**  **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 Anal ys is of Potential Control Scenarios for EGUs ................................ ....... 2 - 6 References ................................ ................................ ................................ ....................... 2 - 16 **3 Analysis of Selected**  **Electric Generating Units (EGUs) ................................**  **............... 3**  **- 1**  EGU Facility

Controls ................................ ................................ ................................ ....... 3 - 1 Integrated Planning Model ( IP M ® ) Anal ys is ................................ ................................ .... 3 - 2 In formation Obtained from State Agencies ................................ ................................ ....... 3 - 6 References ................................ ................................ ................................ ....................... 3 - 1 8 EGU Attachment 1 - Il lustrative Scrubber Costs (1999 $) for Representative MW and Heat Rates under the Assumptions in EPA Base Case 2004 ................................ .......... 3 - 1 9 EGU Attachment 2 - Engineering Methodology Used to Calculate $/ton Pollutant Re duction ................................ ................................ ................................ ......................... 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 Anal ys is of Potential Control Scenarios for ICI Boilers ............................... 4 - 9 References ................................ ................................ ................................ ....................... 4 - 15 **5 A**  **nalysis of Selected Industrial, Commercial, and Institutional Boilers**  **.................... 5**  **- 1**  Source Category

Description ................................ ................................ ............................. 5 - 1 In formation 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 Anal ys is of Potential Control Scenarios for Kilns ................................ ......... 6 - 9 References ................................ ................................ ................................ ....................... 6 - 13Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page ii **Table of Contents –**  **continued Chapter**  **Page 7**  **Analysis of Selected Kilns**  **................................ ................................**  **............................... 7**  **- 1**  Source Category

Description ................................ ................................ ............................. 7 - 1 In formation Obtained from State Agencies ................................ ................................ ....... 7 - 1 **8 Heating Oil**  **................................ ................................**  **................................ .......................**  **8 -**  **1** Background ................................ ................................ ................................ ....................... 8 - 1 F our Factor Anal ys is of Potential Control Scenarios for Emissions from Heating Oil Combustion ................................ ................................ ................................ ....................... 8 - 2 References ................................ ................................ ................................ ......................... 8 - 8 **9 Residential Wood Combustion**  **................................ ................................**  **....................... 9**  **- 1**  Background ................................ ................................ ................................ ....................... 9 - 1 Four Factor Anal ys is of Potential Control Scenarios for Residential Wood Combustion ................................ ................................ ................................ ....................... 9 - 9 References ................................ ................................ ................................ ....................... 9 - 1 5 **10 Residential Wood Combustion**  **– Outdoor Wood Fired Boilers**  **............................... 10**  **- 1**  Background ................................ ................................ ................................ ..................... 10 - 1 Four Factor Anal ys is of Potential Control Scenarios for Outdoor Wood - Fired Boilers ................................ ................................ ................................ ............................. 10 - 3 References ................................ ................................ ................................ ....................... 10 - 6Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page iii **Table of Contents –**  **continued Table**  **Page** Table I Summary

of Results from the Four Factor Analy sis ................................ ...................... viii Table 2.1 SO 2 Control Options for Coal - fired EGU Boilers ................................ ...................... 2 - 3 Table 2.2 Marginal Costs of Emission Reductions (Allo wance Prices) Calculated by Integrated Planning Model (IPM ® ) for the CAIR Base Case and CAIR Plus Runs ( 2006 $/ton) ..... 2 - 7 Table 2.3 NO X and SO 2 Emissions from the Electric Power Sector (Thousand Tons) ............. 2 - 8 Table 2.4 Recent Average Coal Prices from Various L ocations in the U.S. (12/2006) ($/ton) ................................ ................................ ................................ ................................ 2 - 9 Table 2. 5 Average U.S. Bituminous and Subbituminous Coal Prices ( 2006 d ollars /t on) .......... 2 - 9 Table 2.6 Estimated Cost Ranges for SO 2 Control Options for Coal - fired EGU Boilers (200 6 dollars/t on of SO 2 Reduced) ................................ ................................ ................. 2 - 13 Table 3.1 Integrated Planning Model (IPM ® version 2 .1.9) CA IR Plus Results for the Top 30 EGUs Responsible for Visibility Impairment in MANE - VU Class I Areas ........ 3 - 4 Table 3.2 Point Source Information Collected for the Top 30 EGUs Responsible for Visibility Impairment in MANE - VU Class I Areas ................................ .......................... 3 - 7 Table 3.3 Comparison of Controls Predicted by Integrated Planning Model ( IP M ® ) CAIR Plus Results versus Proposed/Planned Control Additions by the State/Facility

(b y 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 I CIBoilers ................................ .......................... 4 - 5 Table 4.2 Potential SO 2 Reductions Through Fuel Switching ................................ .................. 4 - 10 Table 4.3 Estimated Dry Sorbent Injection (DSI) Costs for I CIBoilers ................................ .. 4 - 11 Table 4.4 Estimated Flue Gas Desulfurization (FGD) Costs for IC I Boilers (2006 dollars) .... 4 - 12 Table 5.1 Point Source Information Collected from the Top 17 In dustrial Facilities Responsible for Visibility Impairment in MANE - VU Class IAreas ................................ 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 Pre heater 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 (U LS D) Desul furization Technology Costs for Individual Refineries ................................ ................................ ................................ ......... 8 - 2 Table 8.3 Average January 2007 Distillate Stocks (Million Barrels) ................................ ......... 8 - 5 Table 8.4 Distillate Production and Imports (Million Barrels per Day) ................................ ..... 8 - 5 Table 9.1 Summary

of Measures Available for RWC RACM

– PM 10 ................................ ....... 9 - 5 Table 9.2 Summary

of Measures Available for RWC BACM

– PM 10 ................................ ....... 9 - 7Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page iv **Table of Contents –**  **continued Table**  **Page** Table 9.3 Improved Technologies and Fuel Alternatives ................................ ......................... 9 - 10 Table 9.4 PM Reduction Cost Effectiveness for Replacement of Exi sting 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 - 1 2 Table 9.6 Reduction Cost Effectiveness for the Replacement of an Existing Centralized Cordwood Heating Sy stem ................................ ................................ .............................. 9 - 12 Table 9.7 Pollutant Reduction Cost Effectiveness for the Addition of a Gas L og Set or Use of Wax/Fiber Firelogs in an E xisting Fireplace 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 Day s (2000 - 2004) ................................ ................................ ................................ ....................... 1 - 2 Figure 1.2 MANE - VU 2002 Version 3 Annual Emissions Inventory Top PM 2.5 - Primary

Source Cate gories ................................ ................................ ................................ .......................... 1 - 3 Figure 1.3 MANE - VU 2002 Version 3 Annual Emissions Inventory Top SO 2 Source Categories ................................ ................................ ................................ .......................... 1 - 4 Figure 3.1 EGU Facilities with the Greatest Visibility Impacts in Mid - Atlantic North Eastern Class IAreas ................................ ................................ ................................ ...................... 3 - 2 Figure 6.1 Portland Cement Process Flow Diagram ................................ ................................ ... 6 - 1 Figure 6.2 Advanced Flue Gas Desulfurization Process Flow ................................ ................... 6 - 7Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

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

AF GD ................................ ................................ ................................ ................................ ...... Advanced Flue Gas Desulfurization BACM ................................ ................................ ................................ ................................ ........... Best Available Control Measure BART ................................ ................................ ................................ ................................ ...... Best Available Retrofit Technology BLM ................................ ................................ ................................ ................................ ................ Bureau of Land Management BTU ................................ ................................ ................................ ................................ ............................. Britis h Thermal Unit CAA ................................ ................................ ................................ ................................ ................................ ........ Clean Air Act CAIR ................................ ................................ ................................ ................................ ....................... Clean Air Interstate Rule CFB ................................ ................................ ................................ ................................ ..................... Circulating Fluidized Bed CHP ................................ ................................ ................................ ................................ .................... Combined Heat and Power CO 2 ................................ ................................ ................................ ................................ ................................ ....... c arbon dioxide DOE ................................ ................................ ................................ ................................ ........................... Department of Energy EGU ................................ ................................ ................................ ................................ ........................ Electric Generating Unit EIA ................................ ................................ ................................ ................................ ...... Energy Information Administration EPA ................................ ................................ ................................ ................................ ........ Environmental Protection Agency ESP ................................ ................................ ................................ ................................ ....................... Electrostatic Precipitator FGD ................................ ................................ ................................ ................................ ....................... Flue Gas Desulfurization HAP ................................ ................................ ................................ ................................ ........................ Hazardous Air Pollutant ICI ................................ ................................ ................................ ................................ ..... Industrial, Commercial, Institutional IPM ®

................................ ................................ ................................ ................................ .................... Integrated Planning Model kW ................................ ................................ ................................ ................................ ................................ ................. kilowatt kWh ................................ ................................ ................................ ................................ ................................ ......... kilowatt - hour LADCO ................................ ................................ ................................ ............................. Lake Michigan Air Dir ectors 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 Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page vi **List of Acronyms -**  **continued**

MACT ................................ ................................ ................................ .......................... Maximum Achievable Control Technology MANE - VU ................................ ................................ ................................ .......................... Mid - Atlantic/Northe ast Visibility Union MARAMA ................................ ................................ ................................ ....... Mid - Atlantic Regional Air Management Association MEL ................................ ................................ ................................ ................................ .................. Magnesium Enhanced Lime MM ................................ ................................ ................................ ................................ ................................ ................... million MMBTU ................................ ................................ ................................ ................................ .............. Million British Thermal Units MRPO ................................ ................................ ................................ ............................. Midwest Regional Planning Organization MW ................................ ................................ ................................ ................................ ................................ ............... Megawatt NESCAUM ................................ ................................ ................................ ... Northeast States for Coordinated Air Use Management NO X ................................ ................................ ................................ ................................ ................................ ...... nitrogen oxides NSPS ................................ ................................ ................................ ................................ ....... New Source Performance Standard NSR ................................ ................................ ................................ ................................ .............................. New Source Review O&M ................................ ................................ ................................ ................................ ................... Operation and Maintenance OFA ................................ ................................ ................................ ................................ ................................ ......... Over - fire Air PADD ................................ ................................ ................................ ..................... Petroleum Administration for Defense District PM ................................ ................................ ................................ ................................ ................................ .. Particulate Matter PM 10 ................................ ................................ ................................ ...... Particulate Matter with diameter 10 micrometers or less PM 2.5 ................................ ................................ ................................ ..... Particulate Matter with diameter 2.5 micrometers or less PSD ................................ ................................ ................................ ................................ . Prevention of Significant Deterioration RACM ................................ ................................ ................................ ................................ Reasonably Available Control Me asure RACT ................................ ................................ ................................ ........................... Reasonably Available Control Technology RWC ................................ ................................ ................................ ................................ .............. Residential Wood Co mbustion SACR ................................ ................................ ................................ ................................ ....... Selective Auto - catalytic Reduction SCC ................................ ................................ ................................ ................................ ................... Source Classification Code SCR ................................ ................................ ................................ ................................ ............... Selective Catalytic Reduction SIP ................................ ................................ ................................ ................................ .................... State Implementation Plan SNCR ................................ ................................ ................................ ................................ ........ Selective Non - catalytic Reduction SO 2 ................................ ................................ ................................ ................................ ................................ ........ s ulfur dioxide SOFA ................................ ................................ ................................ ................................ ......................... Separated Over - fire Air ULS D ................................ ................................ ................................ ................................ ........................ Ultra Low Sulfur DieselAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Page vii **EXECUTIVE SUMMARY** The Regional Haze regulations set forth under 40 CFR 51.308(d)(1) require S tates to achieve reasonable progress toward natural visibility conditions . The national visibility goal in Class I areas is define d in the CAA Sec tion 169A(a)(1) as “the prevention of any future, and the remedyi ng of an y existing, impairment of visibility ...”, and is expected to be satisfied by 2064 with a return to natural visibility conditions. States containing Class I areas must set Reasonable Progress Goals (RPGs) to define future visibility conditions that are expected (but not required) to be equal to, or better, than visibility conditions expected by

the uniform rate of progress at any future ye ar until natural conditions are achieved. RPGs are to be established for the final ye ar in the planning period, which in the case of the first SIP is 2018. Fo llowing draft guidance from EPA in establishing RPGs, S tates must set a baseline from which reasonable progress towards visibility improvement wi ll be measured. The MANE - VU baseline ye ar for the emission inventory is 2002 and for monitoring is 2000 - 2004 . The next task is to identify key pollutants affecting visibility impairment at each Class I area. The major pollutant contributing to visibility impairment in MANE - VU has been shown to be sulfate. In order to determine the key source regions and source ty pes affecting visibility

impairment at each Class I area, a contribution assessment was prepar ed b y NESCAUM for MANE - VU. Major contributors we re identified by ranking emissions sources, comparing Q/d (emission impact over distance), and modeling visibility impacts. Source apportionment and other anal ys e s documented in MANE - VU’s contribution assessment show ed that several source categories have impacts on visibility

at MANE - VU Class I areas. The largest contribution to visibility impairment at most sites was from burning of coal, primarily utility and industrial combustion sources in MANE - VU and nearby S tates. At forested rural sites, biogenic organics are a moderate to large contributor to visibility impairment , but other sources of secondary organics also contribute. Wood smoke and ammonium nitrate were identified as small to moderate contributors. Based on information from the contribution assessment and additional emissions inventory anal ys is , MANE - VU selected the following source categories for anal ys is in this project:

 C oal and oil - fired Electric Generating Units, (EGUs);  P oint and area source industrial, commercial and institutional boi lers;  C ement kilns;  L ime kilns;  T he use of heating oil; and  R esidential w ood combustion This document presents the results of an anal ys is of the economic and environmental impacts of potential control scenarios that could be implemented by MANE - VU S tates to reduce emissions from the above source categories in order to make reasonable progress toward meeting visibility improvement goals. The purpose of this anal ys is is to present information that can be used b y States to develop policies and implementation plans to address reasonable progress goals. Control technologies to achieve reasonable progress goals are evaluated with respect to four factors listed in the Clean Air Act (Section 169A):Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

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

 Cost,  Compliance timeframe,  Energy

and non - air quality

enviro nmental impacts, and  Remaining useful life for affected sources . T he “ four factor” anal ys is wa s applied to control options identified for each of the selected source categories . C ement kilns and lime kilns are anal yz ed together due to the similarity of the two source categories . The table below presents a summary of the four factor anal ys is for the source categories anal yz ed. Detailed information on control technologies assessed in this effort is presented in the main body

of this document. **Table I**  **Su mma**  **ry of Results from the Four Factor Analysis Source**  **Category Primary** 

**Regional Haze**  **Pollutant Average**  **Cost in** 

**2006 dollars (** **per ton of pollutant**  **reduction) Compliance** 

**Timeframe Energy and** 

**Non -** **Air Quality**  **Environmental Impacts**  **Remaining**

**Useful Life**

Electric Generating Units SO 2 IPM * v.2.1.9 p redicts $7 75 - $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 $1 3 0 - $1 1 ,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

C ement and Li me Kilns SO 2 $ 1,9 00 - $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 $55 0 - $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 Wo od 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 * I ntegrated Planning Model (IPM ® ) applic ation by ICF for MANE - VU This report also contains information on current and planned controls at 20 specific non - EGU sources and 30 specific EGU sources identified b y MANE - VU to consider control strategies already in place or planned by 2018 .Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 1: Introduction Page 1 - 1 **CHAPTER 1 INTRODUCTION**  **BACKGROUND** The Regional Haze regulations set forth under 40 CFR 51.308(d)(1) require States to achieve reasonable progress toward natural visibility conditions. The national visibility goal in Class I areas is defined in the CAA Section 1 69A(a)(1) as “the prevention of any future, and the remedyi ng of an y existing, impairment of visibility ...”, and is expected to be satisfied by 2064 with a return to natural visibility conditions. States containing Class I areas must set Reasonable Progress Goals (RPGs) to define future visibility conditions that are expected (but not required) to be equal to, or better, than visibility conditions expected by

the uniform rate of progress at any future ye ar until natural conditions are achieved. RPGs are to be established for the final ye ar in the planning period, which in the case of the first SIP is 2018. Following draft guidance from EPA in establishing RPGs, States must set a baseline from which reasonable progress towards visibility improvement will be measured. The MANE - VU baseline ye ar for the emission inventory is 2002 and for monitoring is 2000 - 2004. The next task is to identify key pollutants affecting visibility impairment at each Class I area. The major pollutant contributing to visibility

impairment in MANE - VU has been shown to be sulfate. In addition to the planned reductions that will be included as part of the S tate SIPs for regional haze, federal programs will also have significant benefits in reducing regional haze by 2018 and beyond. A list of EPA’s national and regional rules as well as voluntary programs that will assist in the reduction of fine particle pollution are as follows:

 Clean Air Interstate Rule (CAIR)  The Acid Rain Program  NO X SIP Call  20 04 Clean Air Nonroad Diesel Rule  200 7 Clean Diesel Trucks and Buses Rule  Tier 2 Vehicle Emission Standards and Gasoline Sulfur Program  Emission standards for other engines (highway and non - highway

use)  National Clean Diesel Campaign  The Great American Woodstove Changeout More information an d links to the programs listed 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 SOURCE CATEGORIES**  **AND INDIVIDUAL SOURCES**  **MOST RESPON SI**  **BLE FOR R EG** **IONAL HAZE IN MANE -** **VU CLASS I AREAS**  Particles in the PM 2.5 size range are directl y responsible for visibility reduction. F igure 1.1 generated b y NESCAUM from anal ys is of monitoring data show s the components of PM 2.5 mass at the seven Class I areas of c oncern on the 20% worst visibility day s 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 So il Se a Sa lt OC EC Nitrat e Su lf at e**M a** **s s** **( u** **g /** **m 3** **)**

NESCAUM, 2006. “2000 - 2004 Visibility Rankings and Glide Paths.ppt.” PowerPoint Presentation developed by Gary Kleiman . From F igure 1.1 , it is apparent that sulfate is the largest contributor to PM 2.5 mass at the Class I areas of concern. The second largest contributor to PM 2.5 mass is organic carbon (OC) . Nitr ates, elemental carbon (EC), soil, and sea salt also contribute to PM 2.5 mass. Source apportionment and other anal ys e s documented in MANE - VU’s c ontribution a ssessment indicated that a number of source categories have impacts on visibility at MANE - VU Class I areas. The largest contribution to visibility impairment at most sites was SO 2 from coal combustion , primarily utility and industrial sources in MANE - VU and nearby S tates. At forested rural sites, biogenic organics are a moderate to large contributor to visibility impairment but other sources of secondary organics also contribute. Wood smoke and ammonium nitrate were identified as small to moderate contributors (see Appendix B of the Contribution Assessment).Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 1: Introduction Page 1 - 3 The c ontribution a ssessment also included an analy sis of haze - associated pollutant emissions. “SO 2 is the primary

precursor pollutant for sulfate particles. Sulfate particles commonly account for more than fifty

percent of particle light extinction at northeastern Class I areas on the clearest day s and for as much as or more than eighty percent on the haziest days.” The assessment noted that point sources dominate SO 2 emissions in the MANE - VU region. Point source emissions sources primarily

consist of stationary

combustion sources for generati ng electricity, industrial power , and heat. Commercial and residential heating constitute another important source category in MANE - VU S tates. An anal ys is 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 emissions source categories of PM 2.5 and SO 2 from V ersion 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**  **Pri mary**  **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 -Wa ste Disposal, Treatment, and Recovery (5%)

Industrial Processes - Construction: SIC 15 - 17 (5%) Sta tionary Source Fuel Combustion - Industrial (5%) External Combustion Boilers - Electric Generation (4%)

Off - highway Vehicle Diesel (4%) Miscellaneous Area Sources -Agricultural Production - Crops (3%) Industrial Processes - Food and Kindred Products: SIC 20 (3% ) Highway Vehicles - Diesel (3%) External Combustion Boilers - Industrial (2%) Stationary Source Fuel Combustion - Commercial/Institutional (2%) Highway Vehicles - Gasoline (2%) Industrial Processes - Mi ning and Quarrying: SIC 14 (2%)

Industrial Processes - Mi ne ral Products (2%)

**Tons/Year** On - Road Non - Road Point AreaAssessment 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** 

**D escription of**  **Individual Sourc**  **e Identification**  **Process and Modeling** The following discussion describes the data and procedures that were used to identify the individual sources with the greatest impact on regional haze in MANE - VU Class Iareas. The indiv idual sources included in this report (see Chapters 3, 5, and 7) were determined by identifying the sources with the maximum predicted 24 - hour sulfate ion impact. From 2004 to 2006, the Vermont Department of Environmental Conservation (VT DEC) participated in MANE - VU RPO planning activities by performing regional scale screening modeling of pollutants known to contribute to regional haze at Class Iareas in the MANE - VU region. The model used by VTDEC was the CALPUFF model run on a domain including most of the eastern United S tates . Both point and area sources were modeled for the entire ye ar 2002, and variable hourl y CEMS emission data were used for all the largest 750+ EGUs in the domain. Model results were primarily intended to be used in conjunction wi th other source/receptor modeling methods as part of the technical underpinning of the document, Contributions to Regional Haze in the Northeast and Mid - Atlantic United States: Mid - Atlantic/Northeast Visibility Union (MANE- VU) Contribution Assessment , prepared b y NESCAUM for MANE - VU and dated August 2006. This document contains more detailed discussion of the approach used to develop inputs for the modeling platform, the model setup, and its validation. It can b e 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%) Ext ernal Combustion Boilers Industrial (7%) Stationary Source Fuel Combustion Residential (6%) Stationary Source Fuel Combustion Commercial/Institutional (4%) Stationary Source Fuel Combustion Industrial (3%) Industrial Processes - Mi neral Products (2%) Highway Vehicles - Gasoline (1%) Marine Vessels, Commercial (1%) Off - highway Vehicle Diesel (1%) External Combustion Boilers Commercial/Institutional (1%)

**Tons/Year** On - Road Non - Road Point AreaAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 1: Introduction Page 1 - 5 Starting in 2006, through its participation on two MANE - VU RPO workgroups , (the BART Workgroup and the Reasonable Progress Workgroup) , which were charged with developing technical support information for regional haze plans for the MANE - VU Class Iareas, VTDEC made available some of the EGU source modeling results previously ge nerated during its work on the contribution assessment report cited above. VTDEC also performed new point source modeling with the same CALPUFF modeling platform for a number of additional large point sources identified b y the workgroups, primaril y non - EGUs. The new point source modeling was performed for sources that did not have CEMS hourly emission data. This new modeling performed specifically

for the workgroups differed in this fundamental way from the modeling of large EGUs with available CEMS hourly emission data which had been done for the contribution assessment. All n ew non - EGU point source modeling performed with CALPUFF by VTDEC for the BART and Reasonable Progress Workgroups utilized a constant average hourly emission rate (annual tons/8760) for the year 2002 based on emissions provided by the individual S tates in which the sources were located. Except for a more complete set of discrete receptors covering each Class Iarea, all other inputs and settings of the CALPUFF modeling sy stem, including the NWS Observation - based CALMET created wind - fields, were exactl y the same as used in the contribution assessment modeling work. For the Reasonable Progress Workgroup, VTDEC assembled the results of its earlier individual CEMS - based stack modeling of EGUs into tables which listed the maximum 24 - hr (calendar day) sulfate ion impact predicted at any receptor in each C lass I area due to the emissions from each individual EGU modeled (more than 750). Because the largest contributing pollutant to visibility impairment in all the MANE - VU Class I areas is the sulfate ion, the Reas onable Progress W orkgroup felt that ranking point sources based on this maximum 24 - hour impact alone would be an appropriate way to prioritize their relative potential for improving visibility and making reasonable progress at these areas. Once the maximum 24 - hr sulfate ion impacts modeled for 2002 were rank ed from great est to smallest by EGU, the top impacting EGUs were identified for each of the Class Iareas. 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 Reasonable Progress Workgroup examine d the 2002 N EIbased on SI C code selections. Selected stack points for sources selected were modeled individually using the stack parameters and the constant 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 hourl y emission rate and ran the CALPUFF model for the 194 largest points identified in three lists supplied by Delaware. The selection of points to model was based first on a selection of the top 100 emitting points modeled from a group of several hundred ICI boilers (list 1) and Cement and Lime Kilns (list 2) identified by SCC code and extracted from the 2002 NEI database. Later this list of 100 stack emission points to model was expanded by

adding the top 94 stack points not previously included in the ICIand kiln lists, but identified by

more inclusive selection criteria based on SCC codes (list 3) and ranked b y annual SO 2 emissions. The maximum predicted 24 - hour sulfate ion impact from each of the 194 non - EGUs modeled were combined into an ordered table showing the largest impacting non - EGU at top and the least impacting non - EGU at the bottom for e ach 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 sulfate ion impacts of these 194 non - EGU stack points. The top non - EGUs impacting each Class Iarea were then selected from the top of each list. The ranked listings for EGUs represent the EGU s 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 hourl y SO 2 emission was reported might be a single electric generating unit or it might be a combination of two or more individual electric generating units operating at a plant and emitting from the same stack. The CALPUFF modeling was done on the emission rate supplied for the particular hour of the year 2002 and did not determine whether that emission was from a single EGU or from a combination of several at a plant. Therefore, to identify which particular unit at a plant reporting multiple units emitting from a single stack is responsible for the specific impact due to that hourly emission, would require more information than was available to VTDEC. The reported impact is from the stack and the distribution among un its combined in that stack’s CEMs data cannot be determined from the modeling results. For the non - EGU points modeled, there is a slight probability that emissions modeled may have been onl y from a particular “process” level in the NEI database structure. There may have been more than one process reported for the same emission point during the year 2002 so that a sum of two or more process annual emissions should be modeled and summed for the entire unit level emission control potential to be identified. The top modeled impacts are simply the top for each area based on the 194 separate stack points modeled with each individual annual average emission rate supplied from one of the three NEI selected listings VTDEC received. **APPROACH TO DEMONSTRATING REASO NABLE PROGRESS**  Based on the contribution assessment, including modeling and emissions inventory anal ys is, MANE - VU selected the following source categories for analy sis in this project:

 C oal and oil - fired Electric Generating Units, (EGUs);  P oint and area source industrial, commercial and institutional boilers;  C ement kilns;  L ime kilns;  T he use of heating oil; and  R esidential wood combustion This document presents the results of an anal ys is of the economic and environmental impacts of potential control scenarios that could be implemented by MANE - VU S tates to demonstrate reasonable progress toward meeting visibility improvement goals. The purpose of this anal ys is is to present information that can be used b y S tate s to develop policies and implementation plans to address reasonable progress goals. Control technologies to achieve reasonable progress goals are evaluated with respect to four factors listed in the Clean Air Act (Section 169A) :

 Cost,  Compliance timeframe,  Energy

and non - air quality

environment al 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 T he “ four factor” anal ys is is applied to control options identified for the selected source categories. T he analy sis of cement kilns and lime kilns was combined into one section due to the simil arity of the two sources. Category anal ys es are presented for electric generating units (EGUs), industrial, commercial, and institutional (I CI ) boilers, cement kilns, lime kilns, distillate - oil fired heating units, and residential wood combustion. O nly s ulfur 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 anal ys is is presented for particulate matter . PM 2.5 emissions from th is source w ere 2 8 % of the total PM 2.5 emitted from within MANE - VU in 2002. Biomass burning causes both direct emissions of primary particles and emissions of volatile organics which can contribute to the formation of secondary organic carbon particles. Organic carbon is typically the second - largest contributor to regional haze in the MANE - VU region. For EGUs, IC I boilers, and kilns control options include fuel switching, fuel preparation, in -situ modifications, and add - on controls. Because of the similarity in available control option s, cement and lime kilns have been combined into one category . For oil - fired heating oil, the onl y control option considered is reduction in sulfur content i n the fuel oil. For residential wood combustion and outdoor wood - fired boilers , we have included descriptions of alternative technologies for replacement and emission reduction. Additionally , w e have assembled current and planned controls for the 20 spec ific non - EGU and 30 EGU sources based on information from S tate agencies an d Integrated Planning Model (IPM ® ) . The purpose of selecting these sources is to find out whether the sources that have the greatest impacts on C lass Iareas near MANE - VU in 2002 are already controlled or will be controlled by

2018. In many

cases , S tates have supplied a schedule of planned controls for these facilities, which we have included in tabular form in this report. In the case of EGUs, we obtained information from the S tates and from modeled projections developed 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 Ap ril 6, 2007. http://www.epa.gov/pm/reducing.html Vermont Air Quality Planning. Personal communications regarding description of the source identification and modeling process from Paul Wishinski (802 - 241 - 3862, paul.wishinski@state.vt.us ) via E - mail on April 4, 2007. NESCAUM, 2006. Contributions to Regional Haze in the Northeast and Mid - Atlantic United States . Prepared b y NESCAUM for MANE - VU, August, 2006 .Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 1 **CHAPTER 2 SOURCE CATEGORY ANALYSIS:**  **ELECTRIC GENERATING UNITS (EGUs )**  **SOURCE CATEGORY DESCRIPTION** The MANE - VU contribution assessment demonstrated that the principal contributor to visibility impairment in Class I

MANE - VU areas and Class Iarea s affected by emissions from sources within MANE - VU is SO 2 from EGUs. Roughl y 70% of the 2.3 million tons of SO 2 emissions in the 2002 emissions inventory (2002 MANE - VU Emissions Inventory Version 3) were from EGUs, making them the largest source category contributing to regional haze in terms of total visibility impairing emissions and in terms of number of facilities. Boilers at EGUs burn various fuels to produce heat for steam production which is then used to drive turbine generators for electricity production. The primary fuel combusted in EGU boilers in the eastern United States is coal from mines in the Midwest and Appalachia. C oal from this region generall y contains 2 - 4% sulfur. The sulfur contained in the coal is emitted as SO 2 from the boiler. Coal obtained from western S tates is generall y 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 are also the largest sources of NO X and PM emissions, which also contribute to regional haze. All coal - fired electric utility power plants in the United States use control devices to reduce PM emissions. Additionally , man y of the boilers are required to use controls for SO 2 or NO X e missions depending on site - specific factors such as the properties of the coal burned, when the power plant was built, and the area where the power plant is located. According to the EPA Clean Air Markets Division, ( Personal communication with Mr. Peter Kokopeli, EPA

– CAMD on April 3, 2007 ), as of January 1, 2006 , the percentage of coal - fired EGU capacity in the United States with 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 currentl y a trend towards improving control of SO 2 through installation of additional controls and making other process and fuel changes. The four factor anal ys is of po tential control scenarios for EGUs contained in this chapter ad dresses the control options and costs, time requirements, energy and non - air impacts, and source life associated with these controls. Although PM and NO X from coal - fired utility boilers contribute to regional haze, the MANE - VU contribution assessment conducted b y NESCAUM determined that SO 2 from power plants was the largest contributor to regional haze in the MANE - VU Class I areas. Therefore, the focus of this control option analy sis for coal - fired boilers is on SO 2 controls. Effects of the SO 2 controlAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 2 options on PM and NO X emissions are addressed where applicable, to ensure that the impact on emissions of these pollutants is considered for planning purposes. In addition to coal combustion, s ome EGUs in MANE - VU S tates also burn fuel oil and/or natural gas. However, the EGU sources with the greatest impact on MANE - VU Class I areas were all coal - fired units. Emissions of SO 2 from natural gas combustion are negligible, but SO 2 emissions from fu el oil combustion are directl y proportional to the sulfur content of the fuel. The cost of switching from a high sulfur distillate fuel oil to a lower sulfur distillate fuel oil is addressed in Chapter 8 of this report. The SCCs applicable to coal - fired utility boilers include SCCs beginning 1 - 01 - 001 - XX, 1 - 01 - 002 - XX, and 1 - 01 - 003 - XX. **EVALUATION OF CONTROL OPTIONS** Effective post - combustion SO 2 controls for EGUs and particularly coal - fired boilers are well understood and have been applied to a large number of sources over the ye ars in response to regulations in the form of NSPS, PSD/NSR, State 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 coal - fired boilers are listed in Table 2. 1 with a brief description of the control option, applicability , and range of performance. A more detailed description of the control option and an analysis of the four factor assessment for reas onable 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 documentatio n . Note that the estimated performance of each control option varies greatl y and depends on a v arie ty of site specific factors, including the boiler type . Examples of three major ty pes of coal - fired boiler include fluidized bed combustors, stoker boilers , and pulverized coal boilers. In addition to these three typ es of coal - fired boilers there are many subcategories of boilers, characterized by their specific design. Control devices designed for these types of boilers vary in terms of cost as well as es timated performance.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: 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 Po tential 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 (virtuall y 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% reduc tion 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 Desu lfurization (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 Te chnology Options for BART -Eligible Sources , NESCAUM, March 2005. 2. Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options, STAPPA - ALAPCO , March 2006. **Switch to Low Sulfur Coal** Fuel switching encompasses several different co ntrol options. Often it is not possible to completely

switch from one ty

pe of fuel to another. One option is blending lower - polluting fuels with baseline fuels to reduce overall emissions. For example, many coal - fired boiler operators blend lower sulfur subbituminous coals with high sulfur bituminous coals to reduce 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 partl y on the chara cteristics of the plant and the particular type of fuel change being considered. Many plants will be able to switch from high - sulfur to low - sulfur bituminous coal without serious difficulty , but switching from bituminous to subbituminous coal may present greater challenges and costs. In some instances, fuel switching will require significant investment and modifications to an existing plant. Switching to a lower sulfur coal can affect coal handling s ys tems, boiler performance, PM control effectiveness an d ash handling s ys tems . In any case, fuel switching or blending has beenAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 4 a key strategy used by EGUs to comply

with the federal Acid Rain P rogram. Overall SO 2 reductions estimated from switching to low - sulfur coal range from 50 - 80%. **Switch to Natural Ga**  **s** Switching from coal combustion to natural gas combustion virtually eliminates SO 2 emissions, but it is currently un economical to consider this option for base load EGUs due to the fuel quantity necessary

and the price of natural gas. The price of natural gas and coal are variable, but in terms of heating value, the price of natural gas over the past several years has been several times higher than coal. According to information published on the EIA website, i n January 2007 the price of natural gas was approximately four times higher than coal according to average monthly costs of fuel delivered to electricity producers during that month. **Coal Cleaning** According to the 2006 STAPPA - ALAPCO document on control technologies titled Controlling Particulate M

atter Under the Clean Air Act: A Menu of Options , coal cleaning or washing is a widely practiced method of reducing impurities in coal, particularly sulfur. Reducing the sulfur content of the fuel used in the boiler reduces the SO 2 emissions proportionall y. Coal cleaning has been shown to reduce SO 2 emissions by 20 - 25%, while increasing the heating value of the fuel. Additional removal can be achieved through advanced chemical washing techniques, but no detailed information on these techniques was availa ble. Conventional (phy sical) coal washing techniques remove ash and sulfur from coal by crushing the fuel and separating the components in a liquid bath, such as water. The lighter coal particles float to the top of the bath for recovery , while the heavi er impurities sink to the bottom for removal. Coal sulfur exists in two forms, inorganic and organic. The inorganic sulfur in coal called p yr ite is primarily

in the form of ferrous sulfate (FeSO 4 ). Because it is not chemically bound within the coal , 40 - 50% of this py

rite can be removed through coal washing . The organic form of sulfur is chemicall y bound in the molecular structure of the coal itself and cannot be physically washed out. Organic sulfur accounts for between 35 - 75% of the total sulfur in I l linois Basin coals in the example given b y STAPPA - ALAPCO. Depending on the percentage of the sulfur in a given coal sample which exists in the form of p yrite, varying amounts of the total sulfur can be removed. Although there are benefits associated with coal washing, there are limitations associated with this technology . The 20 - 25% 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 process and must be addressed. **Flue Gas Desulfurization (FGD) -**  **Wet** There are three types of FGD scrubbers: wet, spray dry, and dry . According to the 2006 STAPPA - ALAPCO document on control t echnologies titled Controlling Particulate Matter Un der the Clean Air Act: A Menu of Options , EPA reports that 85% of the FGD sy stems in theAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 5 United States are wet sy stems. Twelve percent of the FGD s ys tems are spray dry s ys tems, and 3% are dry

s ys tems. 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 could generate if it ran at full capacity . SO 2 in the flue gas can be removed b y reacting the sul fur 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 s ys tems”. Most wet FGD s ys tems are based on using either limestone or lime as the alkal ine source. At some of these facilities, fly ash is mixed with the limestone or lime. Several other scrubber s ys tem designs (e.g., sodium carbonate, magnesium oxide, dual alkali) are used by a small percentage of the total number of boilers. The basic w et limestone scrubbing process is simple and is the ty pe most widely

used for control of SO 2 emissions from coal - fired electric utility boilers. L imestone sorbent is inexpensive and generall y available throughout the United States. In a wet limestone scr ubber, 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 insoluble sludge. The sludge, mostly calcium sulfite hemihydrate and gy

psum, is disposed of in a pond specificall y constructed for the purpose or is recovered as a salable b yproduct. Integrated Planning Model ( IP M ® ) 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 bituminous coal with 2% or higher sulfur content b y weight. Integrated Planning Model (IPM ® ) documentation refers to the specific scrubber technology

as Limestone Forced Oxidation, (L SFO), and assumes 95% SO 2 removal using this technology . Data and documentation obtained for use in this report are from Integrated Planning Model (IPM ® ) version 2.1.9. The wet lime scrubber operates in a similar manner to the wet limestone scrubber. In a wet lime scrubber, flue gas c ontaining SO 2 is contacted with hydrated lime/water slurry ; the SO 2 is absorbed into the slurry

and reacts with h ydrated lime to form an insoluble sludge. The hydrated lime provides greater alkalinity (higher pH) and reactivity than limestone. However, lim e scrubbing processes require disposal of large quantities of waste sludge. Another wet scrubber technology used to control emissions of SO 2 from EGUs is Magnesium Enhanced Lime, (MEL). This technology is available to coal - fired boilers from 100 MW to 55 0 MW in capacity , that combust bituminous, sub - bituminous or lignite coal with less than 2.5% sulfur content b y weight. Integrated Planning Model (IPM ® ) assumes that MEL provide s 96% SO 2 removal. The SO 2 removal efficiencies of existing wet limestone scr ubbers 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 scrubbers, 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 Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 6 **Flue Gas Desulfurization (FGD) –**  **Spray Dry** A spray dryer absorber (sometimes referred to as wet - dry or semi - dry

scrubber) operates b y the same principle as wet lime scrubbing, except that the flue gas is contacted with a fine mist of lime slurry

instead of a bulk liquid (as in wet scrubbing). For the spray dryer absorber process, the combustion gas containing SO 2 is contacted with fine spray droplets of hydrated lime slurry in a spray dryer vessel. This vessel is located downstream of the air heater outlet where the gas temperatures are in the range of 120 to 180 °C (250 to 350 °F). The SO 2 is absorbed in the slurry and reacts with the h ydrated lime reagent to form solid calcium sulfite and calcium sulfate sludge as in a wet lime scrubber. The water is evaporated by the hot flue gas and forms dry , solid particles containing the reacted sulfur. These particles are entrained in the flue gas, along with fly ash, and are collected in a PM collection device. Most of the 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, especially fabric filters. This process produces dry reaction waste products for eas y disposal. Th e primary

operating parameters affecting SO 2 removal are the calcium - reagent - to - sulfur stoichiometric ratio and the approach to saturation in the spray dryer. To increase overall sorbent use, the solids collected in the spray dryer and the PM collection d evice may be recycled. The SO 2 removal efficiencies of existing lime spray dryer sy stems 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 content between 0.4% and 2% sulfur by weight. Integrated Planning Model (IPM ® ) assumes that LSD provide s 90% SO 2 removal. **Flue Gas Desulfurization (FGD) –** **Dry** For the dry

injection proces s, dry

powdered lime (or another suitable sorbent) is directly injected into the ductwork upstream of a PM control device. Some sy stems use spray humidification followed b y 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, along with fly ash, and collected by

the PM control device. The SO 2 removal efficiencies of existing dry injection sy stems range from 40 - 60%. **FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR EGUs** Each of the control options presented in Table 2. 1 is evaluated in this s ection according to the four factors for determining reasonable progress as required b y Section 169A(g)(1) of the Clean Air Act and 40 CFR 51.308(d)(1)(i)(A). The information provided in this section is intended to be used b y the S tates in setting Reasona ble Progress Goals for reducing regional haze in the MANE - VU Class I areas.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 7 **Cost of Compliance** For EGUs, EPA used Integrated Planning Model (IPM ® ) to predict which units will install controls at what costs and which units will buy credits. Integrated Pl anning Model (IPM ® ) predicts a least - cost solution to meet power production demands within emissions constraints. Emissions may

be reduced by

fuel - switching, use of controls or by using power from a cleaner unit. The RPOs made some Integrated Planning Mo del (IPM ® ) runs to determine which units will install controls to comply with the EPA CAIR rule. Additionally , MANE - VU investigated an even more stringent “CAIR Plus” strategy using Integrated Planning Model (IPM ® ) . In Chapter 3, the parsed results (proj ections disaggregated to the unit level), available for the CAIR Plus strategy

are used to help estimate costs for specific EGUs. It should be noted that Integrated Planning Model (IPM ® ) is an industry- wide model , and the control costs output from the mod el represent the industry- wide average cost of control that can be expected based on a set industrywide emission reduction. Integrated Planning Model (IPM ® ) results can also be viewed as the predicted cost of control at a model plant. The cost s of control at individual facilities are dependent on a number of factors and cannot be determined for any specific indiv idual facility from Integrated Planning Model (IPM ® ) results. T able 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 ® ) run s . These costs include the capital costs of new investment s, fuel costs, and the operation and maintenance costs of power plants. For both the CAIR and CAIR Plus run, Integrated Planning Model (IPM ® ) installed scrubbers to meet the demand for SO 2 reduction while meeting the demand for electricity. Integrated Planning Model (IPM ® ) also installed NO X controls, but the cost of ach ieving the NO X emissions reductions was provided independentl y from SO 2 controls. Application of SO 2 controls such as use of cleaner and lower - sulfur coals or post combustion controls such as wet scrubbers generall y help to reduce PM emissions in addition to SO 2 . SO 2 controls generall y do not affect PM or NO X emissions. **Table 2.**  **2 Marginal Costs**  **of Emission Reductions (Allowance Prices)**  **Calculated by Integrated Planning Model (IPM**  **® )**  **f or the CAIR Base Case and CAIR Plus Runs**  **( 2006**  **$/ton) Pollutant**  **CAIR B ase Case (MARAMA_5c)**  **CAIR Plus Policy Case (MARAMA_4c)**

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 r eference : 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 Plu s strategy

requires additional SO 2 and NO X control beyond EPA’s CAIR program. IC F’s report on the CAIR and CAIR Plus Integrated Planning Model (IPM ® ) runs titled: Final Draft Report - Comparison of CAIR and CAIR Plus Proposal Using the Integrated PlanningAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 8 Model (IPM

® ) , states that the power sector opts for a technology strategy for complying with the CAIR Plus proposal requirements. In the CAIR Plus analy sis, the CAIR Plus region requires the installation of an additional 19.5 GW of scrubbers and 77.8 GW of SCR by 2012. These controls represent a 30% increase in scrubbers and 18 5 % increase in SCRs in 2012 compared to the Integrated Planning Model (IPM ® ) CAIR run. By 2018, the cumulative installation of scrubbers is 1 7 % higher and the installation of SCR is 9 8 % 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 Po**  **wer 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 r eference : 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 L ow Sulfur Coal Switching to a lo w - sulfur coal or blending a lower sulfur coal can impact cost due to the following two main reasons: 1. The cost of low - sulfur coal compared to higher sulfur coal 2. The cost of necessary boiler or coal handling equipment modifications The cost of low - sulfur c oal compared to higher sulfur coal is not only related to the “dollar per ton” cost of the coal, but also related to the heating value of the coal. Recent data from the Energy Information Administration show the average price of coals from various locatio ns together with estimated heating v alues and sulfur content. The prices of coal indicated in Table s 2. 4 and 2.5 do not include the cost of delivery . The energy- based cost of each of the coals listed in Table 2. 4 is approximately the same, with the excep tion of coal from the Powder River Basin. Powder River Basin coal has a significantl y lower heating value than the other four varieties of coal, but on an energy basis, it is still approximately

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

less sulfur, i t would seem that this coal would be the best fuel for boilers trying to incorporate a lower sulfur coal. Unfortunately , due to the lower heating value of the coal, boilers that are configured to burn coal with a higher heating value can only use a small percentage of this low - sulfur coal (no higher than 15% Powder River Basin coal). The onl y way to burn higher percentages of the Powder River Basin coal would be to extensive ly retrofit the boilers or s uffer from poor boiler performance and other operating difficulties. Such retrofits should be reviewed in light of current Prevention of Signific ant Deterioration (PSD) permittingAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 9 regulations to ensure that all such requirements are met and that emissions do not increase. The coal prices included in Table 2.4 do not reflect the cost of boiler retrofits required to combust low sulfur coal. **Table 2.**  **4 Recent Average Coal Prices from Various Locations in the U.S.**  **(12/2006) ($/ton)**  **Central Appalachia**  **(Bitu mi**  **nous) Northern** 

**Appalachia (Bitum** **inous) Illinois Basin** 

**(Bitum inous)**  **Powder River**

**Basin (Subbituminous)**  **Uinta Basin (Low**  **- S**  **Bitum inous)**  Coal H eating V alue (BTU/lb ) 12,500 13,000 11,000 8,800 11,700 Sulfur Content (%) 1.2 <3 5 0.8 0.8 Cost /ton ($) $47.25 $43.00 $33.33 $9.85 $36.00 Table reference: EIA website accessed on 2/20/07 : http://www.eia.doe.gov/cneaf/coal/page/coalne ws/coalmar.html The two ty

pes of coal used for fuel i n EGU boilers in the United States are bituminous and subbituminous coals. Bituminous coals have varying amounts of sulfur, but the sulfur content of bituminous coal is generally higher than subbittuminous coal. Traditionally , man y EGU boilers have been designed to combust bituminous coal because of the higher carbon content and heating value. T able 2. 5 shows the average 2005 cost data from the Energy Information Administration for bituminous and subbituminous coal. The purpose of this information is to demonstrate the difference in cost of these coals based on their heating value. Assuming a heat content for bituminous coal of 12,000 BTU/lb and 10,000 BTU/lb for subbituminous coal allows the calculation of the cost of the coal on an energy basis. The coal prices included in Table 2.5 do not reflect the cost of boiler retrofits required to combust low sulfur coal.

**Table 2.**  **5 Average**  **U.S. Bituminous and Subbituminous Coal Prices (2006 dollars**  **/ton) Fuel**  **Average Price per Ton Average Price per MMBTU**  Bit uminous Coal $3 8.00 $1.5 8 Subbituminous Coal $8. 96 $0.4 4 Table reference: EIA website accessed on 2/20/07 : http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html Note

– A conversi on factor of 1.0323 wa s 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 lower 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 Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 10 designed to combust bituminous coal. Th e 2006 STAPPA - ALAPCO document, Controlling Fine Particulate Matter Under the Clean Air Act , states that “fuel substitution is not feasible for sources where the substitution would require excessive retrofits or would entail substantial performance losses.” Cost of Coal Cleaning The World Bank reports that the cost of physically cleaning coal varies from $1 to $10 per ton of coal cleaned, depending on the coal quality, the cleaning process used, and the degree of cleaning desired. In most cases the costs were found to be between $1 and $5 per ton of coal cleaned. Based on the recent prices of coal from Tables 2. 4 and 2. 5 , this cost represents a 2 - 15% increase in the cost of coal. In addition to lowering the emissions from coal combustion, coal cleaning also increases the heating value of the fuel. This lowers the transportation cost of the fuel per unit of energy , offsetting the costs associated with the coal washing. It is not clear whether this has been taken into account in the cost information provided b y the World Bank. Cost of Flue Gas Desu lfurization (FGD)

– Wet The cost of flue gas desulfurization varies depending on a number of factors including the size of the boiler, SO 2 reduction requirements, boiler capacity factor, and fuel sulfur content. Taking these factors into account, the ty p ical cost effectiveness of a 1,000 MMBTU/hr (~300MW) coal fired boiler equipped with wet FGD is around $4 10 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 $5 10 per ton of SO 2 controlled. ( Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options , STAPPA - ALAPC O, March 2006) (Converted from 2003 to 2006 dollars using a conversion factor of 1.0959 www.inflationdata.com ) A similar cost estimation from the same STAPPA - ALAPCO document provides information for boilers i n 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 c osts of installing wet scrubbers . For units > 1,200 MW , the capital costs are between $ 3 8 0 - $ 850 /M W ; operation and maintenance costs (O&M) range from $ 7 - $ 2 7 /M W ; 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 $ 8 50 - $ 5 , 1 00 /M W ; operation and maintenance costs (O&M) range from $ 28 - $ 68 /M W ; and the ultimate cost effectiveness is shown to be from $ 5 70 - $ 5,7 00 /ton SO 2 removed. This information demonstrates a strong cost effectiveness advantage realized by installing control devices on the larger emission units. (Co nverted from 2001 to 2006 dollars using a conversion factor of 1.1383 www.inflationdata.com) In another independent analy sis of control costs, Integrated Planning Model (IPM ® ) background documentation defines a range of control efficiencies, costs, and applicability based on unit size and coal type. (http://www.epa.gov/airmarkets/progsregs/epa - ipm/past - modeling.html ) Two wet scrubber (wet FGD) control technologies are discussed in Integrated Planning Model (IP M ® )Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 11 background documentation; ( 1 ) Li mestone Forced Oxidatio n (LSFO), and ( 2 ) Magnesium Enhanced Lime (MEL). Both of the scrubber control technologies are applicable to distinct unit sizes and coal ty

pes, but there is no indication in the parsed Integrated Planning Model (IPM ® ) results as to which ty

pe of scrubber has been applied by the model. Both scrubber technologies are assumed to achieve a SO 2 removal percentage of 95% or greater. According to Integrated Planning Model (IPM ® ) documentation, the cost s used by Integrated Planning Model (IPM ® ) for these control technologies were developed b y EP A and presented in a document titled Emissions: A Review of Technologie s , (EPA - 600/R - 00 - 093), October 2000 prepared b y EPA’s Office of Research and Development. The cost and performance calculations were primarily a function of heat rate, capacity , and sulfur content. The range of various scrubber costs is inc luded in Attachment 1. Using the data in Attachment 1 and appl yi ng a standard engineering economics anal ys is (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 conversion factor of 1.2101 www.inflationdata.com). Cost of Flue Gas Desulfurization (FGD)

– Spray Dry The cost of flue gas desulfurization varies depending on a number of factors including the size of the boiler, SO 2 reduction requirements, boiler capacity factor, and fuel sulfur content. Taking these factors into account, the ty pical cost effectiveness of a 1,000 MMBTU/hr (~300MW) coal fired 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 Clean Air Act: A Menu of Options , STAPPA - ALAPCO, March 2006) (Converted from 2003 to 2006 dollars using a conversion factor of 1.0959 www.inflationdata.com ) EPA rep orts in a 2005 document titled Multipollutant Emission Control Technology Options for Coal- fired Power Plants , that conventional Spray Dry FGD s ys tems can cost from $15 5 - $23 7 per kW, have fixed operation and maintenance costs ranging from $1.5 5 - $7. 25 per kW - yr , and variable operation and maintenance costs from 0.2 - 0.7 mills/kWh. These costs are associated with a 300 MW plant. (Converted from 2005 to 2006 dollars using a conversion factor of 1.0322 www.inflationdata.com ) A similar cost estimation from STAPPA - ALAPCO , 2006 provides information for boilers in the size range of >2,000 MMBTU/hr (~600 MW) and <2,000 MMBTU/hr achieving from 80 - 90% SO 2 removal efficiency . These cost estim ates provide the initial and ongoing costs of installing wet scrubbers. For units > 600 M W , the capital costs are between $ 1 4 0 - $ 51 0 /M W ; operation and maintenance costs range from $ 1 4 - $ 3 4 /M W ; and the ultimate cost effectiveness is shown to be from $ 1 7 0 - $3 4 0 /ton SO 2 removed. For boilers < 600 M W per hour, the capital costs are between $ 51 0 - $ 5,1 00 /M W ; operation and maintenance costs (O&M) range from $ 3 4 - $ 1,020 /M W ; and the ultimate cost effectiveness is shown to be from $ 5 7 0 - $4, 55 0 /ton removed. As was the case with wet scrubbers, this information demonstrates a strong cost effectiveness advantage realized by installing control devices on the larger emission units. (Converted from 2001 to 2006 dollars using a conversion factor of 1.1383 www.inflationdata.com) Integrated Planning Model (IPM ® ) background documentation defines a range of control efficiencies, costs, and applicability based on unit size and coal ty pe.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 12 (http://www.epa.gov/airmarkets/progsregs/epa - ipm/pas t - modeling.html ) Lime Spray Dry (LSD) technology

is one form of SO 2 control applied by Integrated Planning Model (IPM ® ) . LSD is assumed to achieve a SO 2 removal percentage of 90%. According to Integrated Planning Model (IPM ® ) documentation, the costs us ed b y 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 b y EPA’s Office of Research and Development. The cost and performance calculations were primarily a function of heat rate, capacity , and sulfur content. The range of various scrubber costs is included in Attachment 1. Depending on boiler size, boiler capacity factor, and coal sulfur content, the fixed capital costs range from $1 42 to $1 83 /kW, while fixed operation and maintenance costs (O&M) range from $ 5 to $ 7 /kW - yr and variable O&M costs range from 1. 9 to 2. 4 mills/kWh. Assuming the typical costs in Attachment 1, an EGU rated 800 MW, a capital cost i nvestment of $156/kW or $125 million would be expected. Fixed O&M and variable O&M costs would be approximately $6 /kW - yr and 2.2 mills/kWh respectivel y 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, and sulfur content. Using the data in Attachment 1 and appl yi ng a standard engineering economics anal ys is (Attachment 2), the costs of SO 2 removal using this control technology varies from approximately $4 80 - $6 00 per ton of SO 2 removal, ( Converted from 1999 to 2006 dollars using a conversion factor of 1.2101 www.inflationdata.com ). Cost of Flue Gas Desulfurization (FGD)

– Dry The cost of flue gas desulfurization varies depending on a number of factors including the size of the boiler, SO 2 reduction requirements, boiler capacity factor, and fuel sulfur content. Taking these factors into account, the ty pical cost effective ness of a 1,000 MMBTU/hr (~300MW) coal fired 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 b oiler and SO 2 control efficiency, but firing low - sulfur coal, the cost per ton is slightly higher at $ 764 per ton of SO 2 controlled. ( Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options , STAPPA - ALAPCO, March 2006) (Converted from 2003 to 2006 dollars using a conversion factor of 1.0959 www.inflationdata.com ) T he 2005 EPA document titled, Multipollutant Emission Control Technology Options for Coalfired Power Plants , shows that advan ced dry FGD sy stems can cost from $50 - $150 per kW, have fixed operation and maintenance costs ranging from <$1 - $3 per kW - yr, (based on 1 - 2% of capital), and variable operation and maintenance costs from 0.2 - 0.7 mills/kWh. Assuming an SO 2 reduction percentage of 4 0%, capacity factor of 85%, coal sulfur content of 1.5 %, and coal heat content of 12,000 BTU/lb and applying a standard engineering economics analy sis (Attachment 2 ), the costs of SO 2 removal using this control technology varies from approximately $250 - $850 per ton ( Converted from 2005 to 2006 dollars using a conversion factor of 1.0322 www.inflationdata.com) ) .Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 13 Summary of SO 2 Reduction Costs The cost of SO 2 reductions on a per ton basis for EGUs is dependent on the cost (and availability) of fuels, boiler size and ty pe, equipment retrofit costs, the desired emission reduction, and other site specific factors. Although these factors can cause the cost of the reductions to be well above or below the ind ustry 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 fuel switching or coal cleaning. Within the range of estimat ed costs for a given boiler size , the low e nd of the SO 2 reduction cost is generall y 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 (200**  **6 dollars/t**  **on of S O**  **2 Reduced)**  **Technology Description**  **Performance Cost Range**  **(200 6**  **d ollar**  **s/t on 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

swi tching 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 (virtuall y 0% sulfur) Replace coal combustion with natural gas Virtually eliminate SO 2 emissio ns 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 co sts 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 $ 5 7 0 - $ 5 , 7 00 for EGUs < 1,200 MW $ 33 0 - $ 5 7 0 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 $5 7 0 - $4, 55 0 for EGUs <600 MW $1 7 0 - $3 4 0 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 - $ 85 0 for EGUs ~300 MW Table references: 1. EIA website accessed on 2/20/07 : http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html 2. EIA website accessed on 2/20/07 : http://www.eia.doe.gov/cn eaf/coal/page/acr/table31.html 3. ST APPA - ALAPCO. Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options ; March 2006.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 14 4. U.S. EPA. EPA - 600/R - 05/034; Multipollutant Emission Control Technology Options for Coal- fired Power Plants ; March 2005. 5. U.S. EPA. Integrated Planning Model (IPM ® ) b ackground documentation located on website: http://www.epa.gov/airmarkets/progsregs/epa - ipm/pa st - mo deling.html 6. Final Draft Report - Comparison of CAIR and CAIR Plus Proposal Using the Integrated Pla nning Model (IPM ® ), ICF Resources ; May 30, 2007. 7. World Bank Organization. Information located on website: http://www. wo rldbank.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 previou s Phase I of the NO X SIP Call, EPA provided a compliance date of about 31⁄2 years from the SIP submittal date. Most MACT standards allow a 3 - year compliance period. Under Phase I of the NO X SIP Call, EPA provided a 2 - ye ar period after the SIP submittal dat e for compliance. States generall y provided a 2 - year period for compliance with RACT rules. For the purposes of this review, we have assumed that a maximum of 2 ye ar s after SIP submittal is adequate for pre combustion controls (fuel switching or cleaning ) and a maximum of 3 year s is adequate for the installati on of post combustion controls. For post - combustion controls, site - specific information must be supplied to vendors in order to determine the actual time needed for installation of a given control. Large scale implementation of control devices within the EGU sector, particularly in a short time period, may require consideration of impacts on regional electricity demands. Integrated Planning Model (IPM ® ) has allowed for these and other impacts in determining the least cost approach to emission reductions, however, there is a great deal of uncertainty associated with modeled results in comparison to real - world applications of control strategies. For BART control measures, the proposed BART guidelines require S tates to establish enforceable limits and require compliance with the BART emission limitations no later than 5 ye ars after EPA approves the regional haze SIP. **Energy and Non -** **Air Impacts** Fu el switching and cleaning may add to transportation iss ues and secondary environmental impacts from waste disposal and material handling operations (e.g. fugitive dust). Additionally , these SO 2 control methods can create fuel suppl y problems if several large customers of various ty pes of coal suddenl y m ake ch anges in purchasing patterns. The main impact would be on the stability of fuel prices. It is not likely that this would be a persistent problem. Another impact of fuel switching is that the modifications required for switching from one fuel to another may

require a unit to be examined for major NSR permitting requirements. This is true even for modifications required for addition of controls since the modifications could trigger the definition of a “significant modification” under NSR/PSD . Fuel switch ing between ty pes and geographic sources of coal and installation of control devices can significantl y effect mercury emissions. Data from EPA's Mercury Information Collection Request (ICR) revealed that many power plants have existing mercury capture as a co - benefit of air pollution control technologies for NO X , SO 2 and PM . This includes capture of particulate bound mercury

in PM control equipment and capture of soluble ionic mercury in wet FGDAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 15 sy stems. Additional data have also shown that the use of SCR for NO X control enhances oxidation of elemental mercury to the soluble ionic form, resulting in increased removal in the wet FGD s ys tem for units burning bituminous coal. Overall the ICR data revealed higher levels of Hg capture for bituminous coal - fired plants as compared to subbituminous coal - fired plants. Other factors that influence mercury emissions from coal combustion are chlorine content of the coal and fl y ash composition. FGD s ys tems typicall y operate with high pressure drops across the control equipment, resulting in a significant amount of electricity required to operate blowers and circulation pumps. In addition, some combinations of FGD technology and plant configuration may require flue gas reheating to prevent ph ys ical damage to equipment , resulting in higher fuel usage. According to Integrated Planning Model (IPM ® ) background documentation, wet FGD sy stems reduce the capacity of the EGU by

2.1%. This means that the scrubber reduces the amount of electricity for sale to the grid b y 2.1%. The main effect of this reduction is the increased cost of energy production. The primary

environmental impact of FGD s ys tems 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 bottom of the FGD in a reaction tank. The slurry is then dewatered and a portion of the contaminant - laden water is removed from the s ys tem as wastewater. Waste from the FGD s ys tems will increase sulfate , metals, and solids loading in a facility ’s wastewater, potentially

impacting community

wastewater treatment facilities for smaller units that do not have self contained water treatment s ys tems. In some cases FGD operation necessitates installation of a clarifier on site to remove excessive pollutants from waste water. This places additional burdens on a facility or community

wastewater treatment and solid waste management capab ilities. These impacts will need to be anal yz ed on a site - specific basis. If lime or limestone scrubbing is used to produce calcium sulfite sludge, the sludge must be stabilized prior to land filling. If a calcium sulfate sludge is produced, dewatering alone is necessary before land filling, however, SO 2 removal costs are higher due to increased equipment costs for this ty pe of control sy stem. In some cases calcium sulfate sludge can be sold for use in cement manufacturing. With wet FGD technologies a significant visible plume is present from the source due to condensation of water vapor as it exits the smoke stack. Although the water eventuall y evaporates and the plume disappears, community impact may

be significant. **Remaining Useful Life of the Sour ce**  Available information for remaining useful life estimates of EGU boilers indicates a wide range of operating life time s , depending on size of the unit, capacity factor, and level of maintenance performed. Ty

pical life expectancies range to 50 years or more. Additionally , implementation of regulations over the ye ars has resulted in retrofitting that has ultimately increased the expected life span of many EGUs. The lifetime of an EGU may be extended through repair, repowering , or other strategies if the unit is more economical to run than to replace with power from other sources. This may

be particularly

likel y if the unit serves an area which has limited transmission capacity available to bring in other power.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for So urce Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 2: Source Category Analysis: Electric Generating Units Page 2 - 16 **REFERENCES** 2002 MANE - VU Emissions Invent ory Version 3. EPA Clean Air Markets Division, (CAMD). Personal communication regarding control at coal fired EGUs in the United States from Mr. Peter Kokopeli (202 - 343 - 9085), (kokopeli.peter@epa.gov) via E - mail on April 3 and April 10, 2007. NESCAUM. Assessment of Control Technology Options for BART -Eligible Sources ; March, 2005. Midwest RPO. Candidate Control Measures

– Source Category: Electric Generating Units ; 12/09/2005. STAPPA - ALAPCO . Controlling Fine Particulate Matter Under the Clean Air Ac t: A Menu of Options ; March 2006. Evans, David A; Hobbs, B.F.; Oren, C.; Palmer, K.L . Modeling the Effects of Changes in New Source Review on National SO2 and NO X Emissions from Electricity- Generating Units . U.S. EPA. EPA - 600/R - 05/034; Multipollutant Emission Control Technology Options f or Coalfired Power Plants ; March 2005. U.S. EPA. Integrated Planning Model (IPM ® ) background documentation located on website: (http: //www.epa.gov/airmarkets/progsregs/epa - ipm/past - modeling.html ) IC F Resources. Final Draft Report - Comparison of CAIR and CAIR Plus Proposal Using the Integrated Planning Model (IPM ® ), May 30, 2007 . GE Water & Process Technologies. Information accesse d on web March 27, 2007: http://www.zenon.com/applications/FGD_wastewater_treatment.shtml Energy Information Administration (EIA) . Information located on website: http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html Energy Information Administration (EIA) . Information located on website: http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html Energy Information Administration (EIA) . Information located on website: http://www.eia.doe.gov/cn eaf/electricity/ 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 Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control O ptions, and Four Factor Analysis Chapter 3: An alysis of Selected Electric Generating Units (EGUs) Page 3 - 1 **CHAPTER 3 A** **NALYSIS OF SELECTED ELECTRIC GENERATING UNITS**  **(EGUs )**  **EGU FACILITY CONTROLS** The Vermont Department of Environmental Conservation (VTDEC) used the CALPUFF model to estimate sulfate ion impacts from large EGUs and determine the major EGUs and process units (boilers) at the EGUs that contribute to visibility impairment in Class IMANE - VU areas and Class Iareas 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 Iareas. Proximity of the individual sources to Class I areas and variations in meteorology on the 20% worst visibility day s resulted in varying impacts from individual sources on each Class Iarea. In subsequent discussions with MARAMA and the Reasonable Progress Workgroup, MACTEC was directed to focus on the emissions from the top 30 individual sourc es for this analy sis. The 30 individual sources are located at 23 distinct facilities. The location of the 23 EGU facilities of interest is included in Figure 3.1. Since EGUs are the largest emitters of SO 2 in the United States and have the greatest imp act on haze in the MANE - VU Class I areas, it is particularly useful to determine what controls have recentl y b een applied at these facilities (since the 2002 emission inventory). Also important is information about controls that are currentl y being applie d at facilities, or are planned for addition in the future. MACTEC gathered information from two primary sources of data for anal ysis 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. In formation 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 and an y available information on BART , consent decrees, or other regulations that will impact EGU control devices. The MANE - VU CAIR Plus model results represent an estimate of the additional controls that might be installed under a more stringent cap and trade program in the Eastern U.S. Th e comparison of this estimate to the known planned controls for these 30 key EGUs is intended to give an idea of whether a stricter cap would in fact result in great controls at these sources.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control O ptions, and Four Factor Analysis Chapter 3: An alysis 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**  **® )**  **A NALYSIS**  For EGUs, EPA used the Integrated Planning Model (IPM ® ) to estimate which units will install controls at what costs and which units will buy credits. The RPOs also made some Integrated Planning Model (IPM ® ) runs to determine which units will install controls to comply with the EPA CAIR rule. Additionally , an even more stringent “CAIR Plus” strategy was investigated using the Integrated Planning Model (IPM ® ) . The parsed results which include mod eled control scenarios for individual EGUs were used to help determine costs for EGUs, and ultimately estimate the marginal cost of SO 2 reductions for the model planning ye ars of 2009, 2012, and 2018. MACTEC obtained information from the CAIR Plus Policy Case, (MARAMA_4c) for the years 2009, 2012, and 2018 for the 30 EGUs. The information obtained included unit design capacity, SO 2 emissions, assumed existing controls, and controls to be applied as calculated b y the Integrated Planning Model (IPM ® ) . The information was available for each of the individual ye ars, (2009, 2012, and 2018). Also available were the resulting changes in design capacity due to controls, production output, or other factors from Integrated Planning Model (IPM ® ) . The parsed model data do not supply specific design information pertaining to the scrubber size,Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control O ptions, and Four Factor Analysis Chapter 3: An alysis of Selected Electric Generating Units (EGUs) Page 3 - 3 costs, or other related information for individual units. It is only possible to determine the year that the scrubber is due to be installed on individual process units. Info rmation from the CAIR Plus Integrated Planning Model (IPM ® ) run is included in Table 3. 1. Integrated Planning Model (IPM ® ) projection s in Table 3.1 are not intended to be interpreted literall y, but only as an example of the least - cost results from one set of inputs to the model. Also, the controls applied by Integrated Planning Model (IPM ® ) may differ from planned controls at the facility . For information on planned controls at these facilities , please see Table 3.2Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Meth odology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 4 **Table 3.**  **1 Integrated Planning Mod**  **el ( IPM**  **® version 2.1.9)**  **CAIR Plus Projection**  **s for the Top 30 EGUs Responsible for Visibility Impairment in MANE**  **- VU**  **Class I Areas State**  **Facility ID Facility**  **Prim ary Emissions**  **Point Descriptions Point #**  **2002 SO 2**  **Total (Tons)**  **1 2018 SO**  **2**

**Total (Tons)**  **2 SO**  **2 R** **eduction**

**(2002 -** **2018) (Tons/Year)**  **3 % SO**  **2**

**Reduction (2002**  **- 2018)**  **3 Design** 

**Capacity**4 **Existing Control 4**  **MANE_VU CAIR Plus**  **Projection 5**  TN D03406C10 Johnsonville Coal - wall fired; dry bottom boiler 10 108,789 46,000 63,000 58% 15,688 MMBTU Cold - side ESP; LNB SC R by 2012 OH D028404 Conesville Coal - tangential; dry bottom boiler 4 92,340 7,000 85,000 92% 764 MW Cold - side ESP; LNB + OFA + BOOS SCR and Scrubber by 2009 PA D031361 Keystone Coal - tangential; dry bottom boiler 1 87,709 5,000 83,000 94% 8,010 MMBTU Cold - side ESP + SCR; LNB;

OFA Scrubber by 2009 OH D02872C04 Muskingum River Coal - cyclone; wet

bottom boiler 4 24,484 1,000 23,000 96% 205 MW to 201 MW by 2012 Cold - side ESP; OFA SCR and Scrubber by 2012 PA D03179C01 Hatfield’s Ferry Coal - wall fired; dry bottom boiler 1 55,695 13,000 43,000 77% 5,766 MMBTU Cold - side ESP + SNCR; LNB None OH D02876C01 Kyger Creek Coal - wall fired; wet bottom boiler 1 13,789 1,000 13,000 93% 13,789 MMBTU Cold - side ESP + SCR; OFA Scrubber by 2012 WV D03935C02 John E. Am os Coal - wall fired; dry bottom boiler 2 31,465 6,000 25,000 81% 7,020 MMBTU Cold - side ESP + SCR; LNB Scrubber PA D031362 Keystone Coal - tangential; dry 2 62,890 4,000 59,000 94% 8,010 MMBTU Cold - side ESP + SCR; LNB;

OFA Scrubber by 2009 IN D01010C05 W abash River Coal - wall fired; dry bottom boiler 5 9,380 1,000 8,000 89% 95 MW Cold - side ESP + Cyclone; LNB + OFA SNCR by 2009 PA D031491 Montour Coal - tangential; dry bottom boiler 1 61,005 4,000 57,000 93% 744 MW Cold - side ESP + SCR; LNB + OFA Scrubber by 2009 NC D080421 Belews Creek Coal - wall fired; dry bottom boiler 1 57,848 3,000 55,000 95% 1,096 MW Cold - side ESP + SCR; LNB Mercury control WV D03948C02 Mitchell Coal - wall fired; dry bottom boiler 2 29,532 6,000 24,000 80% 7,020 MMBTU Cold - side E SP + SCR + Wet

Scrubber; LNB None PA D031222 Homer City Coal - wall fired; dry bottom boiler 2 55,346 3,000 52,000 95% 6,792 MMBTU Cold - side ESP + SCR; LNB +

OFA Scrubber by 2009 PA D031492 Montour Coal - tangential; dry bottom boiler 2 50,441 4,000 46,0 00 92% 729 MW Cold - side ESP + SCR; LNB + OFA Scrubber by 2009 MD D01571CE2 Chalk Point Coal - wall fired; dry bottom boiler 2 23,537 2,000 22,000 92% 335 MW Cold - side ESP; LNB SCR and Scrubber by 2009 MI D01733C12 Monroe Coal - cell fired; dry bottom boi lers 1 & 2 48,563 28,000 21,000 42% 770, 785 MW Cold - side ESP + SCR; LNB None PA D031221 Homer City Coal - wall fired; dry bottom boiler 1 45,745 3,000 43,000 93% 607 MW Cold - side ESP + SCR; LNB + OFA Scrubber by 2009 NC D080422 Belews Creek Coal - wall fired; dry bottom boiler 2 45,236 3,000 42,000 93% 1,096 MW Cold - side ESP + SCR; LNB Mercury control WV D039432 Fort Martin Coal - wall fired; dry bottom boiler 2 45,890 5,000 41,000 89% 4,634 MMBTU Cold - side ESP + SNCR; LNB

+ OFA Scrubber by 2012 WV D03 9431 Fort Martin Coal - tangential; dry bottom boiler 1 45,228 5,000 40,000 89% 4,460 MMBTU Cold - side ESP + SNCR; LNB

+ OFA Scrubber by 2012 WV D039353 John E. Amos Coal - wall fired; dry bottom boiler 3 44,030 9,000 35,000 80% 11,900 MMBTU Cold - side ESP + SCR; LNB ScrubberAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Meth odology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 5 **Table 3.**  **1 Integrated Planning Mod**  **el ( IPM**  **® version 2.1.9)**  **CAIR Plus Projection**  **s for the Top 30 EGUs Responsible for Visibility Impairment in MANE**  **- VU**  **Class I Areas State**  **Facility ID Facility**  **Prim ary Emissions**  **Point Descriptions Point #**  **2002 SO 2**  **Total (Tons)**  **1 2018 SO**  **2**

**Total (Tons)**  **2 SO**  **2 R** **eduction**

**(2002 -** **2018) (Tons/Year)**  **3 % SO**  **2**

**Reduction (2002**  **- 2018)**  **3 Design** 

**Capacity**4 **Existing Control 4**  **MANE_VU CAIR Plus**  **Projection 5**  OH D0283612 Avon Lake Coal - wall fired; dry bottom boiler 12 41,872 6,000 36,000 86% 6,040 MMBTU Cold - side ESP Scrubber by 2009; SCR by 2012 VA D037976 Chesterfield Coal - tangential; dry bottom boiler 6 40,923 4,000 37,000 90% 6,650 MMBTU Cold - side ESP; LNB + OFA SCR and Scrubber by 2012 PA D082261 Cheswick Coal - tangential; dry bottom boiler 1 42,018 5,000 37,000 88% 550 MW Cold - side ESP + SCR ; LNB + OFA Scrubber by 2009 OH D028281 Cardinal Coal - cell fired; dry bottom boilers 1 39,894 2,000 38,000 95% 600 MW to 587 MW in 2012 Cold - side ESP + SCR; LNB Scrubber by 2012 MD D015731 Morgantown Coal - tangential; dry bottom boiler 1 37,757 3,000 35,000 92% 570 MW Cold - side ESP; LNB +OFA SCR and Scrubber by 2009 OH D028667 W H Sammi s Coal - wall fired; dry bottom boiler 7 33,720 3,000 31,000 91% 593 MW to 818 MW in 2012 Cold - side ESP + SNCR; LNB Scrubber in 2009; Coal to IGCC in 2012 MD D015732 Morgantown Coal - tangential; dry bottom boiler 2 32,587 3,000 30,000 91% 570 MW Cold - sid e ESP; LNB +OFA SCR and Scrubber by 2009 MA D016193 Brayton Point Coal - wall fired; dry bottom boiler 3 19,451 3,000 16,000 85% 5,800 MMBTU Cold - side ESP; LNB + OFA SCR, Scrubber, Mercury Control by 2009 NJ D023781 B L England Coal - cyclone; wet bottom boiler 1 10,080 1,000 9,000 90% 129 MW Cold - side ESP; + SNCR; OFA None Note: CEMS hourly data was used in the modeling of the emission units, not annu al emissions . Also, a single emission unit at a generating plant may represent two or more emission units at that plant emitting from the same stack point . (Refer to the detailed explanation in the Introduction section of this report). Table references: 1 . 2002 SO 2 total for the emission point from RPO emission inventory 2 . Integrated Planning Model (I PM ® ) CAI R Plus projected 2018 SO 2 total for the emission point (rounded to nearest 1,000 tons) 3 . Approximate reduction in SO 2 emissions for 2018 Integrated Planning Model (IPM ® ) versus 2002 RPO emission inventory (rounded to nearest 1,000 tons) 4 . Information from Integrated Planning Model (IPM ® ) and RPO emission inventories 5 . Information from Integrated Planning Model (IPM ® ) CAIR Plus ScenarioAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 6 Integrated Planning Model (IPM ® ) background documentation defines a range of control efficiencies, costs, and applicability based on unit size and coal ty pe. (http://www.epa.gov/airmarkets/progsregs/epa - ipm/past - modeling.html ) Three scrubber control technologies are discussed briefl y in Integrated Planning Model (IPM ® ) background documentation; 1. L imestone Fo rced Oxidation (LSFO), 2. Magnesium Enhanced Lime (MEL) and 3. L ime Spray

Dryer (L SD). Each of the three scrubber control technologies are applicable for distinct unit sizes and coal ty pes, but there is no indication in the parsed Integrated Planning Mod el (IPM ® ) results as to which ty pe of scrubber has been applied b y 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. Depending o n boiler size, boiler capacity factor, and coal sulfur content, the fixed capital costs range from $1 40 to $ 580 /kW, while fixed operation and maintenance costs (O&M) range from $ 5 to $24 /kW - yr and variable O& M costs range from 1.0 to 2.4 mills/kWh. Assumi ng the typical costs in Attachment 1, an EGU rated 500 MW, (the approximate average of the 30 units included in this analy sis), a capital cost inves tment 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 ty

pical SO 2 reduction from a 500 MW unit (assuming a minimum of 90% reduction), based on the 30 units included in this analy sis would be from 4,000 to 4 0 ,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 anal yz ed here are already subject to a variety of existing emission control requirements, including CAIR, BART, mercury controls, the NO X SIP call, and EPA’s acid rain control program. Therefore, it is expected that at least some of the 30 EGUs will already be adding control by

2018. To investigate this possibility , MACTEC contacted S tate agencies with facilities in the list of the top 30 individual sources. We requested EGU permit information, information about SO 2 controls recentl y implemented or planned at the facility , and an y available information on BART, consent decrees, or other regulations that will impact EGU control devices. The information we have obtained is included in Table 3. 2 .Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 7 **Table 3.2 Point Source Information**  **fo r**  **the Top 30 EGUs Responsible for**

**Visibility Impairment in MANE -** **VU Class I Areas Facility Nam**  **e State**  **2002 SO**  **2 Total**  **(tons) a**  **Prim ary Emissions Point** 

**Description Point**  **ID (Perm** **it ID No.)**  **Design**

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Addi tional** 

**Inform ation**  Johnsonville 1, 2 , 3 TN 108,789 Coal - fired Boilers 01 - 10 for steam & electricity generation. The units are pulverized coal, dry-bottom boilers without fly ash reinjection. Units 1 - 6 are Com bustion Engineering tangentially- fired boilers . Units 7 - 10 are Foster Wheeler wall fired boilers. All boilers exhaust through a common stack. 43 - 0011 - 01 - 10 15,688 MMBTU/hr ESP Com bustion of low - sulfur fuel (since 2002) SCR by 2018 2018 SO 2 emissions

will be approximately 51,000 tpy

Conesville 4 OH 92 ,340 Unit 4 Main Boiler - Com bustion Engineering mo del 7868 pulverized coal - fired, dry - bottom boiler B004 7,960 MM BTU/hr ESP FGD and SCR by 8/18/09 N/A

Key stone (aka Reliant Energy Northeast Mgmt/Keystone Power Plant) 5 PA 87,709 Boiler 1 w /low NO X burner 1 (031) 8,717 MM BTU/hr Cold - side ESP SCR FGD Alternate operation: SCR System Boiler 1 Muskingum River 6 OH 24,484 Unit 3 Main Boiler - Babcock and Wilcox mo del RB - 248 (custom) coal - fired, cyclone boiler B004 2,150 MMBTU/hr ESP None planned N/AAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 8 **Table 3.2 Point Source Information**  **fo r**  **the Top 30 EGUs Responsible for**

**Visibility Impairment in MANE -** **VU Class I Areas Facility Nam**  **e State**  **2002 SO**  **2 Total**  **(tons) a**  **Prim ary Emissions Point** 

**Description Point**  **ID (Perm** **it ID No.)**  **Design**

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Addi tional** 

**Inform ation**  Hatfield’s Ferry 5 PA 55,695 Babcock & Wilcox Boiler #1 that burns bituminous coal (227 tons/hr) and No. 2 fuel oil (1,384 gal/hr) 1 (031) 5,766 MM BTU/hr Cold - side ESP FGD N/A Kyger Creek6 OH 13,789 Unit #1 Boiler - Babcock and Wilcox pulverized coal - fired, wet - botto m boiler B001 1,850 MMB TU/hr ESP SCR, FGD operational by 1/01/09 N/A

John E. Amos 7,8 WV 31, 465 Dry - bottom w all - fired coal boiler 2 800 MW, 7,020 MMB TU/hr ESP

Lo w NO X burners SCR FGD

(12/2008) Vents through CS012 Key stone (aka Reliant Energy Northeast Mgmt/Keystone Power Plant) 5 PA 62,890 Boiler 2 w /low NO X burner 2 (032) 8,717 MMB TU/hr Cold - side ESP SCR FGD Alternate operation: SCR System Boiler 2 Wabash (aka Duke Energy Indiana, Inc. - Wabash River Generating Station) 9, 10 IN 9,380 Wall fired coal elec tric utility boiler (pulverized

– dry bottom) constructed in 1956 using No. 2 fuel oil as ignition fuel 5 1,096.2 MMB TU/hr Lo w - NO X

burner (NO X ) ESP (PM) None Stack is equipped with CEM for SO 2Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 9 **Table 3.2 Point Source Information**  **fo r**  **the Top 30 EGUs Responsible for**

**Visibility Impairment in MANE -** **VU Class I Areas Facility Nam**  **e State**  **2002 SO**  **2 Total**  **(tons) a**  **Prim ary Emissions Point** 

**Description Point**  **ID (Perm** **it ID No.)**  **Design**

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Addi tional** 

**Inform ation**  Montour (aka PPL Montour, LLC

– Montour Steam Electric Statio n) 5 PA 61,005 CE Boiler

– Unit #1 that burns bituminous coal and No. 2 fuel oil 1 (031) 7,317 MMB TU/hr Cold - side ESP SCR FGD N/A

Belew s Creek (aka Duke Power’s Belews Creek Plant) 11 NC 57,848 Coal - fired electric utility boiler constructed in 1974 1 1,120 MW None Scrubbers (2008) Expected rate under

their compliance plan for the Clean Smokestacks Act is 0.150 lbs SO 2/MMBTU . Expected emissions SO 2 for 2013 and later is 5,512 tpy. Mitchell 7 , 1 2 WV 2 9,532 Dry - bottom w all - fired coal boiler 2 800 MW, 7,020 MMB TU/hr ESP

Lo w NO X burners FGD

(1/2007); SCR (4/2007) Vents through CS012 Homer City (aka Homer City OL/Homer City Generation Station 1 3 PA 55,346 Boiler No. 2 (Unit 2) 2 (032) 6,792 MMB TU/hr Cold - side ESP SCR FGD N/A

Montour (aka PPL Montour, LLC

– Montour Steam Electric Station) 5 PA 50,441 CE Boiler

– Unit #2 that burns bituminous coal and No. 2 fuel oil 2 (032) 1,239 MMB TU/hr Cold - side ESP SCR FGD N/AAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 10 **Table 3.2 Point Source Information**  **fo r**  **the Top 30 EGUs Responsible for**

**Visibility Impairment in MANE -** **VU Class I Areas Facility Nam**  **e State**  **2002 SO**  **2 Total**  **(tons) a**  **Prim ary Emissions Point** 

**Description Point**  **ID (Perm** **it ID No.)**  **Design**

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Addi tional** 

**Inform ation**  Chalk Point 15 , 1 6 MD 23,537 Steam Unit 2 is a wall fired, dry bottom, supercritical boiler base loaded unit. The primary fuel is coal with natural gas and No. 2 oil used for ignition. 2 342 MW Lo w NO X burners ESP SACR LNBs & SOFA (NO X ) SCR and FGD

(2009/2010 timeframe) Unit covered under the

MD Healthy Air Act

Monroe (aka Detroit Edison

– Monroe Power Plant) 1 6 MI 48,563 4 cell burner boilers (Boiler Unit Nos. 1, 2, 3, and 4) constructed in the late 1960s (1968 - 1969) and modified in 1994 EG01 EG02 EG03 EG04 3,000 MW (total) Dry wire ESP (SO 3 ) FGD (Units 3 & 4) @ 97% CE May

put scrubbers on Units 1 & 2 later If additional scrubbers

are added, a SO 2 reduction of 97% is anticipated Homer City (aka Homer City OL/Homer City Generation Station 1 3 PA 45,745 Boiler No. 1 (Unit 1) 1 (031) 6,792 MMB TU/hr Cold - side ESP SCR FGD N/A

Belew s Creek (aka Duke Power’s Belews Creek Plant) 1 1 NC 45,236 Coal - fired electric utility boiler constructed in 1975 2 1,120 MW None Scrubbers (2008) Expected rate under

their compliance plan for the Clean Smokestacks Act is 0.150 lbs SO 2/MMBTU . Expected emissions SO 2 for 2013 and later is 4,639 tpy.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 11 **Table 3.2 Point Source Information**  **fo r**  **the Top 30 EGUs Responsible for**

**Visibility Impairment in MANE -** **VU Class I Areas Facility Nam**  **e State**  **2002 SO**  **2 Total**  **(tons) a**  **Prim ary Emissions Point** 

**Description Point**  **ID (Perm** **it ID No.)**  **Design**

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Addi tional** 

**Inform ation**  Fort Martin 7, 8 WV 45,228 Tangentially - fired coal boiler 1 552 MW, 4,460 MMB TU/hr ESP

Lo w NO X burners SNCR Trim FGD (4Q

2009) N/A

Fort Martin 7, 8 WV 45,890 Wall - fired coal boiler 2 55 MW, 4,634 MMB TU/hr ESP

Lo w NO X burners SNCR Trim FGD (1Q

20 10) N/A

John E. Amos 7, 8 WV 4 4,030 Dry - bottom w all - fired coal boiler 3 1,300 MW, 11,900 MMB TU/hr ESP

Lo w NO X burners SCR FGD

(12/2007) N/A

Avon Lake 6 OH 41,872 Boiler #12 - Pulverized coal - fired, dry bottom, boiler B012 6,040 MMB TU/hr ESP SCR and FGD ope rational by 2010 N/A Chesterfield (aka Chesterfield Power Station) 1 7 VA 40,923 Com bustion Engineering tangentially - fired coal boiler equipped with startup burners 6 (ES 6A) 6,650 MMB TU/hr SCR ESP Stage combustion coal burners FGD (95%

CE under constructio n, operational 2008) The unit is restricted to

burn 2,330,160 tons/yr of coal at an annual average heating value of 12,500 B TU/lbs Cheswick (aka Cheswick Power Station) 1 8 PA 42,018 Tangentially - fired “main” boiler that burns bituminous coal (primary fuel) , natural gas, and synfuel 1 5,500 MMB TU/hr (coal & synfuel) 1,000 MMB TU/hr (NG) Lo w NO X

burners SCR ESP w / f lue gas conditioning (PM) FGD (98%

CE planned) N/AAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 12 **Table 3.2 Point Source Information**  **fo r**  **the Top 30 EGUs Responsible for**

**Visibility Impairment in MANE -** **VU Class I Areas Facility Nam**  **e State**  **2002 SO**  **2 Total**  **(tons) a**  **Prim ary Emissions Point** 

**Description Point**  **ID (Perm** **it ID No.)**  **Design**

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Addi tional** 

**Inform ation**  Cardinal 6, 12 OH 39,894 Unit 1 Main Boiler - Babcock and Wilcox, pulverized coal - fired, dry bottom, cell burner boiler B001 527 MMB TU/hr ESP FGD (2/2008) N/A Morgantown 1 4 , 1 5 MD 37,757 Com bustion Engineering, Inc., Unit Boiler No. 1 - steam generating coal fired utility boiler installed in 1967 which primarily combusts Eastern Bituminous coal conta ining no more than 2% sulfur by weight and secondary fuel is No. 6 oil containing no more than 2% sulfur by weight 1 (F - 1) 5,317 MMB TU/hr ESP SO 3 injection Lo w NO X burners SCR and FGD

(2009/2010 timeframe) Stacks equipped with

SO 2 , NO X , CO 2 , and ultrasonic flow mo nitors. Unit covered under the MD Healthy Air Act.

W H Sammis 6 OH 33,720 Coal Fired Boiler No.1 - Foster - Wheeler pulverized coal - fired, dry - bottom boiler B007 1,822 MMB TU/hr Fabric filter ESP FGD operational 12/31/09 SNCR Operational 06/06 N/AAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 13 **Table 3.2 Point Source Information**  **fo r**  **the Top 30 EGUs Responsible for**

**Visibility Impairment in MANE -** **VU Class I Areas Facility Nam**  **e State**  **2002 SO**  **2 Total**  **(tons) a**  **Prim ary Emissions Point** 

**Description Point**  **ID (Perm** **it ID No.)**  **Design**

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Addi tional** 

**Inform ation**  M organtown 1 4 , 1 5 MD 32,587 Com bustion Engineering, Inc., Unit Boiler No. 2 - steam generating coal fired utility boiler installed in 1967 primarily combusts Eastern Bituminous coal w/ no mo re than 2% sulfur by weight and secondary fuel is No. 6 oil w/ no mo re than 2% sulfur by weight 1 (F - 2) 5,317 MMB TU/hr ESP SO 3 injection Lo w NO X burners SCR and FGD

(2009/2010 timeframe) Stacks equipped with

SO 2 , NO X , CO 2 , and ultrasonic flow mo nitors. Unit covered under the MD Healthy Air Act.

Br ayton Point 1 9 MA 19,451 Water tube boiler 3 (EU3) 5,655 MMB TU/hr ESP w /flue gas conditioning (PCD - 3) Fuel sulfur

content (2011) FGD (2011) BART recommended

controls for SO 2 are 95% control or 0.15 lb/MMB TU (coal), 0.33 lb/MMB TU (0.3% fuel sulfur limit) (oil) B L England20 , 2 1 NJ 10,080 Wet - bottom , cyclone coal boiler 1 129 MW ESP SNCR None The facility will either close by 2012 or install scrubbers on all coal fired units. One scrubber is already installed and the other unit would get a 95% CE

–mi nimum, but unclear if this unit is already controlled.

a 2002 SO 2 total for the emission point from RPO emission inventory .Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 14 1 Tennessee Department of Environment and Conservation, Division of Air Pollution Control. Personal communication regarding Jo hnsonville facility from Ms. Julie A slinger (615 - 532 - 0587, Julie.Aslinger@state.tn.us ) via E - mail on March 1, 2007. 2 MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid - Atlantic No rth Eastern Class I Areas”, March 8, 2007. Comment regarding Johnsonville facility received from Ms. Julie Aslinger (615 - 532 - 0587, Julie.Aslinger@state.tn.us ) via E - mail on March 30, 2007. 3 MACTEC, Inc., “Documentation of the Base G 2002 Base Year, 2009 and 2018 Emission Inventories for VISTAS”, January, 2007. 4 Ohio Environmental Protection Agency, Division of Air Pollution Control. Personal communications regarding Conesville facili ty from Mr. William Spires (614 - 644 - 3618, bill.spires@epa.state.oh.us ) via E - mail on February 20 and 21, 2007. 5 Pennsylvania Department of Environmental Protection, Bureau of Air Quality. Personal communications regarding Keystone, Hatfield’s Ferry, and Montour facilities from Ms. Nancy Herb (717 - 783 - 9269, nherb@state.pa.us ) via E - mail on January 31 and February 7, 2007. 6 Ohio Environmental Protection Agency, Division of Air Pollution Control. Personal communication regarding Muskingum, Kyger Creek, Avon Lake, Cardinal, and WH Sammis facilities from Mr. William Spires (614 - 644 - 3618, bill.spires@epa.state.oh.us ) via E - mail on Febru ary 20, 2007. 7 West Virginia Division of Air Quality. Personal communication regarding John. E. Amos, Mitchell, and Fort Martin facilities from Ms. Laura Crowder (304 - 926 - 0499 Ext. 1247, LCROWDER@wvdep.org ) via E - mail on February 17, 2007. 8 MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid - Atlantic North Eastern Class I Areas”, March 8, 2007. Comments regarding John E. Amos, Mitchell, and Fort Martin and facilities received from Ms. Laura Crowder (304 - 926 - 0499 Ext. 1247, LCROWDER@wvdep.org ) via E - mail on March 30, 2007. 9 Indiana Department of Environmental Management, Office of Air Quality. Personal communi cation regarding Wabash facility between Mr. Jay Koch (317 - 233 - 0581, JKOCH@idem.IN.gov) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007. 10 Indiana Department of Environmental Management, Offi ce of Air Quality. Personal communications regarding Wabash facility from Mr. Jay Koch (317 - 233 - 0581, JKOCH@idem.IN.gov) via E - ma il on February 1 and 5, 2007. 11 North Carolina Department of Environment and Natura l 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. 1 2 MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid - Atlantic North Eastern Class I Areas”, March 8, 2007. Comments regarding Mitchell and Cardinal facilities received from Mr. David J. Long, P.E. of American Electric Power (614 - 716 - 1245, djlong@aep.com) via E - mail on March 29, 2007. 1 3 Pennsylvania Department of Environmental Protection, Bureau of Air Quality. Personal communications regarding Homer City fac ility f rom Ms. Nancy Herb (717 - 783 - 9269, nherb@state.pa.us ) via E - mail on January 31 and February 7 and 8, 2007. 1 4 Maryland Department of the Environment. Personal communication regarding Chalk Point and Morgantown faci lities from Mr. Andy Heltibridle (410 - 537 - 4218, aheltibridle@mde.state.md.us ) via U.S. mail on February 9, 2007. 1 5 MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid - Atlantic North Eastern Class I Areas”, March 8, 2007. Comments regarding Chalk Point and Morgantown facilities received from Mr. Brian Hug (410 - 537 - 4125, bhug@mde.state.md.us ) via E - mai l on March 14, 2007. 1 6 Michigan Department of Environmental Quality, Air Quality Division. Personal communication regarding Monroe facility from Ms . Teresa Walker (517 - 335 - 2247, walkertr@michigan.gov) via E - m ail on February 7, 2007. 1 7 Virginia Department of Environmental Quality, Division of Air Quality. Personal communication regarding Chesterfield facility fro m Ms. Doris McLeod (504 - 698 - 4197, damcleod@deq.vi rginia.gov) via E - mail on February 9, 2007. 1 8 Allegheny County Health Department . Personal communications regarding Cheswick facility from Ms. Jayme Graham (412 - 578 - 8129, JGraham@achd.net) via E - mail on February 2, 2007. 1 9 Massachusetts Department of Environmental Protection. Personal communications regarding Br ayt on Point facility from Mr. Donald Squires (617 - 292 - 5618, Donald.Squires@state.ma.us ) via E - mail on February 2 and 7, 2007. 20 New Jersey Department of Environmental Protection, Division of Air Quality. Personal communications regarding B.L. England f acility 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. 2 1 New Jersey Department of Environmental Protection, Division of Air Quality. Personal communications regarding B.L. England f acility from Mr. Ray Papalski (609 - 633 - 7225, Ray.Papalski@dep.state.nj.us ) via E - mail on February 1, 2007.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 15 Table 3.3 presents a side by side comparison of the predicted control information from T ables 3.1 and 3.2 . The existing control information available from Integrated Planning Model (IPM ® ) data was in disagreement with the information reported by the States for many

of the EGUs. Since controls at the EGUs may have changed recently

[ since Integrated Planning Model (IPM ® v.2.1.9) ] , Table 3.3 reports existing control information obtained from the States for this report. The information on proposed or planned controls obtained from the States reflects that 26 of the 30 EGUs included in this study plan to install SO 2 control (FGD/sc rubber), 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 contro l information from 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 information 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 website and in the I CF report titled: Final Draft Report

– Comparison of CAIR and CAIR Plus Proposal Using the Integrated Planning Model (IPM ® ) . **Table 3.3 Comparison of Controls**  **Predicted by Integrated Planning Model (IPM**  **® )**  **CAIR Plus**  **Results v**  **ersus Proposed/Planned Control Additions by the**  **State/ Facility**  **(by 2018) at the Top**  **30 EGUs Responsible for Visibility Impairment in MANE -** **VU Class I Areas Facility**  **Name State**  **Point**

**# 2002**  **SO 2**  **(tons) Existing** 

**Controls (based on**  **inform ation**  **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 operationa l 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 Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 16 **Table 3.3 Comparison of Controls**  **Predicted by Integrated Planning Model (IPM**  **® )**  **CAIR Plus**  **Results v**  **ersus Proposed/Planned Control Additions by the**  **State/ Facility**  **(by 2018) at the Top**  **30 EGUs Responsible for Visibility Impairment in MANE -** **VU Class I Areas Facility**  **Name State**  **Point**

**# 2002**  **SO 2**  **(tons) Existing** 

**Controls (based on**  **inform ation**  **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 unavailabl e} 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 % r eduction 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} S crubber 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} Scr ubber 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/flu e 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 Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 17 **Table 3.3 Comparison of Controls**  **Predicted by Integrated Planning Model (IPM**  **® )**  **CAIR Plus**  **Results v**  **ersus Proposed/Planned Control Additions by the**  **State/ Facility**  **(by 2018) at the Top**  **30 EGUs Responsible for Visibility Impairment in MANE -** **VU Class I Areas Facility**  **Name State**  **Point**

**# 2002**  **SO 2**  **(tons) Existing** 

**Controls (based on**  **inform ation**  **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 cond itioning (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 information for Integrated Planning Model (IPM ® ) and State agency contacts associated with Tables 3.1 and 3.2.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 18 **REFERENCES** 2002 MANE - VU Emissions Inventory Version 3. NESCAUM. Assessment of C ontrol Technology Options for BART -Eligible Sources ; March, 2005. Midwest RPO. Candidate Control Measures

– Source Category: Electric Generating Units ; 12/09/2005. STAPPA - ALAPCO . Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Op tions ; March 2006. Evans, David A; Hobbs, B.F.; Oren, C.; Palmer, K.L . Modeling the Effects of Changes in New Source Review on National SO2 and NO X Emissions from Electricity- Generating Units . IC F Resources. Final Draft Report - Comparison of CAIR and CAIR Plus Proposal Using the Integrated Planning Model (IPM ® ), May 30, 2007 . U.S. EPA. EPA - 600/R - 05/034; Multipollutant Emission Control Technology Options f or Coalfired Power Plants ; March 2005. U.S. EPA. Integrated Planning Model (IPM ® ) background documentation located on website: (http://www.epa.gov/airmarkets/progsregs/epa - ipm/past - modeling.html ) Energy Information Administration (EIA) . Information located on web site: http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html Energy Information Administration (EIA) . Information located on website: http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html World Bank Organization. Information located on website: http://www.worldbank .org/html/fpd/em/power/EA/mitigatn/aqsocc.stmAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 19 **Attachment 1. Illustrative Scrubber Costs (1999 $) for Representative**  **MW and Heat Rates** 

**under the Assumptions in EPA Base Case 2004 Scrubber Type**  **Capacity**

**(M W)**  **Heat Rate (BTU/kWh) Cost** 

**9,000 10,000**  **11,000** LSFO Min. Cutoff: >= 100 MW Max. Cutoff: None Assuming 3.0% Sulfur Content Coal (by weight) with Heating Value of 11,900 BTU/lb 100 456 19 1.6 469 19 1.7 481

20 1.9 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh 300 225 11 1.6 234 11 1.7 243

20 1.9 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh 500 173 9 1.6 180 9 1.7 187 9 1.9 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh 700 142 8 1.6 149 8 1.7 155 8 1.9 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh 1,000 157 7 1.6 166 8 1.7 174 8 1.9 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh MEL Min. Cutoff: >= 100 MW Max. Cutoff: <500 MW Assuming 1.5% Sulfur Content Coal (by weight) with Heating Value of 11,900 BTU/lb 100 340 17 0.8 351 17 0.9 362 17 1 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh 200 224 12 0.8 233 12 0.9 241 12 1 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh 300 224 11 0.8 235 11 0.9 245 12 1 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh 400 200 10 0.8 210 10 0.9 220 10 1 Cap.Cost ( $/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh 500 178 9 0.8 187 9 0.9 196 9 1 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh LSD Min. Cutoff: >= 550 MW Max. Cutoff: None Assuming 1.5% Sulfur Content Coal (by weight) with Heating Value of 11,900 BTU/lb 600 137 5 1.6 144 5 1.8 151 6 2 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh 700 127 5 1.6 134 5 1.8 140 5 2 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh 800 124 5 1.6 130 5 1.8 135 5 2 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kW

h 900 125 4 1.6 131 4 1.8 137 4 2 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh 1,000 118 4 1.6 124 4 1.8 130 4 2 Cap.Cost ($/kW)

Fix. O&M $/kW - yr Var. O&M mills/kWh Table reference: Copy of Table 5.3 from EPA Integrated Planning Model (IPM ® ) documentation (http://www.epa.gov/airmarkets/progsregs/epa ipm/docs/bc5emission.pdf ) . (Note: To adjust cost data from 1999 to 2006, multiply by 1.2101 www.inflationdata.comAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 3: Analysis of Selected Electric Generating Units (EGUs) Page 3 - 20 **Attachment 2. Engineering Methodology Used to Calculate $/ton Pollutant Reduction**  Calculation of Cost per ton of SO2 of scrubbing **First, calculate annual cost of a scrubber ($/kW/yr) Cost data**  Cap Fix O&M Var O&M

469 19 1.7 $/Kw $/KW -yr $/kW h **As sume**  Cap Rec Factor CapacFact

0.15 0.85 1/y r 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 -y r $/KW -y r **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 Em issions rate 3% 2 divided by 0.012 = 5 dim ensls dim esnlss MBT U/lb lb/MBT U **Use emissions rate and assumed plant efficiency/operating hours to get emissions/kw /yr**  UnconSO2 Reduction Heat Rate Cap Factor Hr/y r tons/lb

5 0.9 0.01 0.85 8760 0.0005 = **0.167535** lb/MBT U dim ensionless MBT U/kW h dim ensls hr/y r 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/y r by

ton/k w/yr

= **608.877** = 102.01 divided by 0.167535 $/KW -yr tons/kw-yrAssessment of Reasonable Progress for Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 1 **CHAPTER 4 SOURCE CATEGORY ANALYSIS: INDUSTRIAL, COMMERCIAL, AND**  **INSTITUTIONAL BOILERS SOURCE CATEGORY DESCRIPTION**  The MANE - VU contribution assessment has demonstrated that SO 2 emissions are the principal contributor to visibility

impairment in Class Iareas in the northeast. After electric generation units, Industrial, Commercial, and Institutional (ICI) boilers and heaters are the next largest class of pollution sources that contribute to SO 2 emissions. Ty pical industrial applications include chemical, refining, manufacturing, metals, paper, petroleum, food production and a wide variety of other small industries an d commercial heating applications. Commercial and institutional boilers are normally

used to produce steam and h ot water for space heating in office buildings, hotels, apartment buildings, hospitals, universities, and similar facilities. Most commercial and institutional boilers are small, with 80% of the population smaller than 15 million British Thermal Units per hour (MMB TU/hr) . A fairl y wide range of fuels are used by ICI boilers, ranging from coal, petroleum coke, distillate and residual fuel oils, natural gas, wood waste or other class of waste products. Boilers aggregated under the ICI classification are generally smaller than boilers in the electric power industry , and ty pically have a heat input in the 10 to 250 MMB TU/hr range; however, industri al boilers can be as large as 1,000 MMB TU/hr or as small as 0.5 MMB TU/hour. The process that a particular unit serves strongl y i nfluences the boiler fuel choice. For example, the iron and steel industry uses coal to generate blast furnace gas or coke ove n gas that is used in boilers, resulting in sulfur emissions. Pulp and paper processing may use biomass as a fuel, resulting in high PM emissions. Units with short duty cycles may

utilize oil or natural gas as a fuel. The use of a wide variety of fuels is an important characteristic of the ICI boiler category . While many

boilers are capable of co - firing liquid or gaseous fuels in conjunction with solid fuels, boilers are usuall y designed for optimum combustion of a single specific, fuel. Changes to the fuel ty

pe may , therefore, reduce the capacity , duty cycle, or efficiency

of the boiler. Boiler design also play s a role in the uncontrolled emission rate. Most I CIboilers are of three basic designs: water tube, fire tube, or cast iron. The fuel - firin g configuration is a second major identifier of boiler design for solid fuels. Stoker boilers are the oldest technology and are still widely used for solid - fueled boilers. Pulverized coal boilers succeeded stokers as a more efficient method of burning co al and are used in larger boiler designs. Circulating fluidized bed (CFB) boilers are the most recent type of boiler for solid fuel combustion and are becoming more commonplace. CFB boilers are capable of burning a variety of fuels, and are more efficient and less polluting than stoker or pulverized coal boilers. Combined heat and power (CHP) or cogeneration technologies are also used to produce electricity and steam or hot water from a single unit. Some I CIboilers are used only in the colder months for space heating, while others have high ca

pacity utilization year round.Assessment of Reasonable Progress for Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 2 **Clean Air Act Regulations Controlling ICI Boilers** Emissions from IC I boilers are currently governed by

multiple S tate and f

ederal regulations under the Titles I, III, and IV of the C lean Air Act. Each of these regulatory programs is discussed in the following paragraphs. Title I regulates criteria pollutants by requiring local governments to adopt State Implementation Plans (SIPs) that set forth their strategy for achieving reduction s in the particular criteria pollutant(s) for which they are out of attainment. The SIP requirements includes Reasonabl y Available Control Technology (RACT) requirements, but more stringent requirements may be imposed depending on the locale's degree of no n attainment with ambient air standards. Title Ialso imposes New Source Performance Standards (NSPS) on certain specified categories of new and modified large stationary sources. In 1986, EPA codified the NSPS for industrial boilers (40 CFR part 60, sub parts Db and Dc) and revised portions of them in 1998 to reflect improvements in control methods for the reduction of NO X emissions. Subpart Db applies to fossil fuel - fired IC I units greater than 100 MMB TU per hour that were constructed or modified after June 19, 1984. Subpart Dc applies to fossil fuel - fired IC I units from 10 to 100 MMB TU 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 p ermitting requirements that impose control technologies of varying levels of stringency

(known as New Source Review, or NSR). NSR prescribes control technologies for new plants and for plant modifications that result in a significant increase in emissions, subjecting them to Best Available Control Technology (BACT) in attainment areas and to the Lowest Achi evable Emission Rate (LAER) in non attainment areas. C ontrol strategies that constitute BACT and LAER evolve over time and are reviewed on a case by cas e basis in St ate permitting proceedings. On September 13, 2004, EPA published a final rule under Title III of the CAA to substantially reduce emissions of toxic air pollutants from I CIboilers. These Maximum Achievable Control Technology

(MACT) standards appl y 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 sy stems to fuel switching to the install ation of a fabric filte r 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 f ocusing primarily

on p ower 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 program on a voluntary basis and receive their own acid rain allowances. The Opt - in Program offers sources such as ICI boilers a financial incentive to voluntarily

reduce its 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 allowanc e market. The regulation of IC I boilers by various CAA programs has resulted in a variety of unit level emission limits resulting from SIP, NSPS, NSR, or MACT requirements. Overlaid on these unit level requirements are s ystem - wide allowances of the NO X S IP call and the Acid Rain SO 2 opt - inAssessment of Reasonable Progress for Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 3 program. Thus, the specific emission limits and control requirements for a given ICI boiler vary and depend on boiler age, size, and geographic location. **EVALUATION OF CONTROL OPTIONS** An undesirable b y- 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 ty pically have sulfur contents less than 0.5 % while residual oil can have 1 - 2 % sulfur b y weight. Petroleum coke, a by product 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. Ai r pollution reduction and control technologies for I CIboilers have advanced substantially over the past 25 years. In addition, advances in power generation technologies, renewable energy , and energy

efficiency

have the potential to further reduce emissio ns from these facilities. The focus of this evaluation is on the first category mentioned above - emission control technologies. The timing and magnitude of reductions from the other strategies

– improved technologies, demand reduction/energy efficiency , and clean power should be considered as part of a longer term solution. Control techniques may

be classified into three broad categories: fuel treatment/substitution, combustion modification, and post - combustion control. Fuel treatment primarily reduces SO 2 and includes coal cleaning using ph ys ical, chemical, or biological processes. Fuel substitution involves burning a cleaner fuel or renewable fuel. Combustion modification includes any phy sical or operational change in the furnace or boiler and is so metimes discussed in conjunction with post - combustion control technologies. Post - combustion control employ s a device after the combustion of the fuel and is applied to control emissions of SO 2 . Itshould be noted that phy sical or operational changes to a furnace or boiler may require that the unit be examined for applicability

under the Prevention of Significant Deterioration (PSD) program. There are a wide variety of proven control technologies for reducing SO 2 emissions from I CI boilers. The method of SO 2 control appropriate for any individual I CIboiler is dependent upon the ty pe of boiler, type of fuel, capacity utilization, and the types and staging of other air pollution control devices. However, cost effective emissions reduction technologies for SO 2 are available and are effective in reducing emissions from the exhaust gas stream of I CIboilers. Effective post - combustion SO 2 controls for boilers, and particularly coal - fired boilers, are well understood and have been applied to a number of sourc es over the ye ars in response to regulations in the form of NSPS, PSD/NSR, 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 Rule (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 Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 4 Examples of such strategies include switching to a fuel with a lower sulfur content, or coal cleaning prior to combustion. M ethods of SO 2 control applicable to ICI boilers are listed in Table 4. 1 with a brief description of the control option, applicability , and range of performance. After the table, a more detailed description of the control option and an analysis of the four factor assessment for reasonable progress is presented. **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 formation during combustion. The exception to the nearl y universal use of post - combustion controls is found in fuel switching and, more significantl y, in fluidized bed boilers, in which limestone is added to the fuel in the combustion chamber. Post - combustion SO 2 control is accomplished by reacting the SO 2 in the gas with a reagent (usually calcium - or sodium - based) and removing the resulting product (a sulfate/sulfite) for dispos al or commercial use depending on the technology used. SO 2 reduction technologies are commonly

referred to as Flue Gas Desulfurization (FGD) and are usuall y described in terms of the process conditions (wet versus dry), b yp roduct utilization (throwaway ver sus saleable) and reagent utilization (once - through versus regenerable). Within each technology

category , multiple variations are possible and typi cally involve the ty

pe and preparation of the reagent, the temperature of the reaction (for dry processes), the use of enhancing additives, etc. Because these variations mostly involve complex process chemistry , but are fundamentall y similar, this summary focuses on the major categories of SO 2 control technologies, their applicability , performance and cost. Des criptions of available SO 2 control technology

options are in Table 4. 1. A brief discussion of these techniques follows.Assessment of Reasonable Progress for Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 5

**Ta ble**  **4. 1**  **Available SO 2**  **Control Options For ICI Boilers Technology**  **Description Applicability**  **Performance** Switch to a Low Sulfur Co al (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 (virtuall y 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 lower sulfur distillate oil. Alternatively, replace medium sulfur distillate oil with ultra - low

sulfur distillat e 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 Com bustio n Control A reactive material, such as limestone or bi carbonate, is introduced into the combustion chamber along with the fuel Applicable to pulverized coal - fired boilers and circulating fluidized bed boilers 40% - 85% reductions in 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 P owdered 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 BAR T -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 Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 6 Switch to Coal with Lo wer Sulfur Content Switching from a high sulfur fuel to one with sufficiently lo w sulfur content is the first option available for SO 2 reduction in this category for pre - combustion control of SO 2 . Fuels naturally low in sulfur content are readil y available for solid (coal) and liquid (oil) fired boilers. For coal fired boilers, low - sulfur fuels may be obtained directly

or, alternatively , the sulfur content of coal fired in the boiler may

be lowered first by

cleaning the coal or blending coals obtained from several sources. However, burning low - sulfur fuel may not be a technicall y feasible or economically practical SO 2 control alternative for all boilers. In some cases, a fuel with the required sulfur content to meet the applicable emission reduction may not be available or cannot be fired satisfactoril y in a given boiler unit desi gn. Even if such a fuel is available, use of the lower - sulfur fuel that must be transported long distances from the supplier may not be cost competitive with burning higher sulfur fuel supplied b y near - by suppliers and using a post - combustion control devi ce. The feasibility of fuel switching depends partl y on the characteristics of the plant and the particular ty pe of fuel change being considered. Many plants will be able to switch from high - sulfur to low - sulfur bituminous coal without serious difficulty , but switching from bituminous to sub bituminous coal may

present greater challenges and costs. In some instances, fuel switching will require significant investment and modifications to an existing plant. Switching to a lower sulfur fuel, either coal o r oil, can affect fuel handling s ys tems, boiler performance, PM control effectiveness and ash handling s ys tems. Overall SO 2 reductions estimated from switching to low - sulfur fuels range from 50 - 80%. Switch to Natural Gas Switching from coal combustion t o natural gas combustion virtually eliminates SO 2 emissions. It is technicall y feasible to switch from coal to natural gas, but it is currently un economical to consider this option for large ICI s due to the fuel quantity necessary

and the price of natural gas. The price of natural gas is roughl y seven times the price of coal in terms of heating value. Reduced Sulfur Oil Oil - fired boilers may

opt for lower sulfur distillate fuels or, if available, ultra - low sulfur distillate fuel. Number 2 distillate fu el 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 u se. Currentl y, the sulfur content in Number 2 oil varies between 15 and 20,000 ppm. Beginning in 2006, the permissible level of sulfur in highway diesel fuel (ultra low sulfur diesel, or UL SD) was reduced to15 ppm. Prior to that, highway low sulfur dies el fuel was refined to contain 500 ppm sulfur (Low Sulfur Diesel, or LSD). Consequentl y, refineries have already performed the capital investments required for the production of L SD and ULSD fuel oil. Based on EIA data for the week of Feb 23, 2007 domestic production of ULSD fuel oil accounted for about 45% of all distillate oil in the United States and L SD fuel oil accounted for slightly ov er 17% of domestic production (See Chapter 8).Assessment of Reasonable Progress for Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 7 Coal Cleaning According to the 2006 STAPPA - ALAPCO document on control technologies titled Controlling Particulate Matter Under the Clean Air Act: A Menu of Options , coal cleaning or washing is a widely practiced method of reducing impurities in coal, particularly sulfur. Reducing the sulfur content of the fuel used in th e boiler reduces the SO 2 emissions proportionally . Coal cleaning has been shown to reduce SO 2 emissions by 20 - 25%, while increasing the heating value of the fuel. Additional removal can be achieved through advanced chemical washing techniques, but no det ailed information on these techniques was available. Conventional (phy sical) coal washing techniques remove ash and sulfur from coal by crushing the fuel and separating the components in a liquid bath, such as water. The lighter coal particles float to the top of the bath for recovery , while the heavier impurities sink to the bottom for removal. Although there are benefits associated with coal washing, there are limitations associated with this technology . The 20 - 25% SO 2 reduction is beneficial, but pos t - combustion controls have been shown to reduce SO 2 emissions by greater percentages. Also, solid and liquid wastes are generated using the washing process and must be addressed. Combustion Control SO 2 reduction is also possible through combustion relat ed control technologies. One such technolog y that has been demonstrated and is currently available is the use of fluidized bed boilers . Fluidized bed boilers generall y operate at lower temperatures than other combustion systems, 800° to 870 ° C (1500° F t o 1600° F). The lower temperatures 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 thermody

namically stable at bed temperatures. 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 bubbling beds. In ei ther case, the sorbent is removed with the ash from the bed and sent to disposal. Flue Gas Desulfurization (FGD) There are three types of FGD scrubbers: wet, spray dry, and dry . According to the 2006 STAPPA - ALAPCO document on control technologies titled Controlling Particulate Matter Under the Clean Air Act: A Menu of Options , EPA reports that 85% of the FGD sy stems in use in the United States are wet sy stems. Twelve percent of the FGD s ys tems are spray dry s ys tems, and 3% are dry

s ys tems. The operatin g parameters, efficiency , and costs of each SO 2 removal method are different. SO 2 in the flue gas can be removed b y reacting the sulfur compounds with a solution of water and an alkaline chemical to form insoluble salts that are removed in the scrubber ef fluent. These processes are called “wet FGD s ys tems”. Most wet FGD s ys tems for control of SO 2 emissionsAssessment of Reasonable Progress for Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 8 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 s ys tem designs (e.g., sodium carbonate, magnesium oxide, dual alkali) are used by a small number of boilers. The basic wet limestone scrubbing process is simple and is the ty pe most widely

used for control of SO 2 emissions from coal - fired electric utility boilers. L imestone sorbent is inexpensive and generall y available throughout 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 s lurry and reacts with limestone to form an insoluble sludge. The sludge, mostly calcium sulfite hemi - hydrate and gy

psum, is disposed of in a pond specificall y constructed for the purpose or is recovered as a salable b yproduct. The wet lime scrubber operat es 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 reacts with h ydrated lime to form an insoluble sludge. The hydrated lime provides greater alkalinity (higher pH) and reactivity than limestone. However, lime scrubbing processes require disposal of large quantities of waste sludge. The SO 2 removal efficiencies of existing wet limestone 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 scrubbers, 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 b y the same principle as wet lime scrubbing, except that the flue gas is contacted with a fine mist of lime slurry

instead of a bulk liquid (as in wet scrubbing). F or the spray dryer absorber process, the combustion gas containing SO 2 is contacted with fine spray droplets of hydrated lime slurry in a spray dryer vessel. This vessel is located downstream of the air heater outlet where the gas temperatures are in the range of 120 to 180 °C (250 to 350 °F). The SO 2 is absorbed in the slurry and reacts with the h ydrated lime reagent to form solid calcium sulfite and calcium sulfate as in a wet lime scrubber. The water is evaporated b y the hot flue gas and forms dry , so lid particles containing the reacted sulfur. These particles are entrained in the flue gas, along with fl y 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 cap ture has also been observed in downstream particulate collection devices, especially fabric filters. This process produces dry reaction waste products for eas y disposal. The primary

operating parameters affecting SO 2 removal are the calcium - reagent - to - su lfur stoichiometric ratio and the approach to saturation in the spray dryer. To increase overall sorbent use, the solids collected in the spray dryer and the PM collection device may be recycled. The SO 2 removal efficiencies of existing lime spray dryer sy stems range from 60 - 95 % . For the dry

injection process, dry

powdered lime (or another suitable sorbent such as trona) is directly injected into the ductwork upstream of a PM control device. Some sy stems use sprayAssessment of Reasonable Progress for Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 9 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 solid s are entrained in the combustion gas stream, along with fl y ash, and collected b y the PM control device. The SO 2 removal efficiencies of existing dry injection sy s tems range from 40 to 60% . **FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR ICI BOI**  **LERS** Each of the control options presented in Table 4. 1 is reviewed in this section utilizing a four factor anal ys is approach for determining reasonable progress as required by Section 169A(g)(1) of the Clean Air Act and Section 51.308(d)(1)(i)(A). The i nformation provided in this section is intended to be used b y the S tates in setting Reasonable Progress Goals (RPGs) for reducing region al haze in Class I areas in MANE - VU Class Iareas. **Cost of Compliance** To compare the various control options, information has been compiled on the cost - effectiveness of retrofitting controls. In general, cost - effectiveness increases as boiler size and capacity factor (a measure of boiler utilization) increases. Cost of Switching to L ow Sulfur Coal , Distillate Oil, or Nat ural Gas Switching to a low - sulfur coal or blending a lower sulfur coal can impact cost due to the following two main reasons: 1. The cost of low - sulfur coal compared to higher sulfur coal. 2. The cost of boiler or coal handling equipment modifications necessary The cost of low - sulfur coal compared to higher sulfur coal is not only related to the “dollar per ton” cost of the coal, but the heating value of the coal also impacts the cost anal ys is. Table 4. 2 reflects the potential sulfur reduction possible by sw itching fuels: Table 4. 3 shows the average 2004 and 2005 cost data from the Energy Information Administration for various fuels. Refineries were required to make significant capital investments to meet the L SD and ULSD highway fuel sulfur requirement. T o achieve the LSD and UL SD sulfur goals, refineries were required to implement diesel desulfurization technologies. Estimates for the capital costs were developed in 2001 b y the Energy Information Administration (EIA) and are based on calendar ye ar 1999. Table 4. 4 presents the capital costs for desulfurization technologies presented b y the EIA. The EIA developed estimates for new and revamped desulfurization technologies at existing refineries.Assessment of Reasonable Progress for Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 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 deploy ment and impleme ntation of desulfurization technologies at refineries. EPA estimated that it would cost existing refineries an estimated $50 million per refinery to install desulfurization technologies. No estimates were made for the costs associated with new refineries as none are currently being constructed in the United States. The EPA anal ys is spread the investment cost over a 2 - ye ar period. Consequently , it was estimated that the US refinery- wide investment for calendar ye ar 2004 was $2.4 5 billion and $2. 83 billio n for calendar year 2005 (EIA 2001) (Converted from 2001 to 2006 dollars using a conversion factor of 1.1383 www.inflationdata.com) . Using the most recentl y available EIA price information for 2006 No. 2 Distillate oil for industrial, commercial, and institutional facilities in the northeast (excluding taxes), a cost per ton of SO 2 removed was calculated to be $734/ton SO 2 by switching to 500 ppm L SD and $554/t o n SO 2 by

switching to ULSD fuel oils. (See the discu ssion of fuel oil prices in Chapter 7

– Heating Oil.) Cost of Coal Cleaning The World Bank, an organization which assists with economic and technological needs in developing countries reports that the cost of physically cleaning coal varies from $1 t o $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 Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 11 Cost of Combustion Control Dry sorbent inje ction , (DSI), sy stems have lower capital and operation costs than post combustion FGD s ys tems due to: simplicity of design, lower water use requirements, and smaller land use requirements. Table 4. 3 presents the estimated costs of adding DSIbased SO 2 controls to I CIboilers based on boiler size, fuel ty pe, 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 I njection (** **DSI )**  **Costs For ICI Boilers (2006 dollars)** 

**Fuel SO**  **2**

**Reduction (%**  **) Capacity** 

**Factor (%) Cost Effectiveness ($/Ton of SO**  **2 )** 

**100 MMB**  **TU /hr**  **250**

**MMBTU/hr 1,000** 

**MMBTU/hr** 2% - sulfur coal 40 14 4 , 686 3793 2 , 979 50 1 , 312 1062 834 83 772 624 490 3 .43% - sulfur coal 40 14 2 , 732 2 , 212 1 , 737 50 765 619 486 83 450 364 286 2% - sulfur coal 85 14 2 , 205 1 , 786 1 , 402 50 617 500 392 83 363 294 231 3.43% - sulfur coal 85 14 1 , 286 1 , 040 818 50 360 291 229 83 212 171 134 Calculations based on information available from EPA P ublications, 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 co nversion 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 sy s tems typicall y require significant area for construction of the absorber towers, sorbent tanks, and waste handling. The facility costs are, therefore, variable and dependent on the availability of space for construction of the FGD sy stem. Solid waste han dling is another factor that influences the cost of FGD control sy stems. Significant waste material may be generated that requires disposal. This cost may be mitigated, however, b y utilization of a forced oxidation FGD process that produces commercial quality gy psum, which may

be sold as a raw material f or other commercial processes.Assessment of Reasonable Progress for Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 12 Table 4. 4 presents the total estimated cost effectiveness of adding FGD based SO 2 controls to I CI boilers based on boiler size, fuel ty pe, and capacity

factor. There is no indication that these cost data include revenue from gy psum sales. Revenue from gy psum sales would reduce the cost of these controls . **Table 4.4 Estimated**  **Fl ue Gas Desulfurization**  **( FGD**  **) Costs For ICI Boilers**  **(2006 dollars)**

**Fuel Technology**  **SO 2**  **Reduction (%**  **) Capacity** 

**Factor (%) Cost Effectiveness ($/Ton of SO**  **2 )** 

**100 MMB**  **TU /hr**  **250**

**MMBTU/hr 1,000** 

**MMBTU/hr** High - sulfur coal a FGD (Dry) 40 14 3,781 2,637 1,817 50 1,379 1,059 828 83 1,006 814 676 Lower - sulfur coal b FGD (Dry) 40 14 4,571 3,150 2,119 50 1,605 1,207 928 83 1,147 906 744 Coal FGD (Spray

dry) 90 14 4,183 2,786 1,601 50 1,290 899 567 83 843 607 407 High - sulfur coal a FGD (Wet) 90 14 3,642 2,890 1,909 50 1,116 875 601 83 709 563 398 Lower - sulfur coal b FGD (Wet) 90 14 4,797 3,693 2,426 50 1,415 1,106 751 83 892 705 492 Oil c FGD (Wet) 90 14 10,843 8,325 5,424 50 2,269 1,765 1,184 83 1,371 1,079 740 a. Assumes sulfur content = 3.43% and ash content = 12.71%. b. Assumes sulfur content = 2.0% and as h content = 13.2%. c. Sulfur content of oil is not specified. Table reference s : Source: Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options , STAPPA - ALAPCO, 2006 . Primary Reference: Khan, S. Methodology, Assumptions, and Refere nces— Preliminary SO2 Controls Cost Estimates for Industrial Boilers (EPA - HQ - OAR - 2003 - 0053 - 166), October -November 2003. (Converted from 200 4 to 2006 dollars using a conversion factor of 1.0 672 www.inflationdata.c om) **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 compliance date of about 31⁄2 years from the SIP submittal date. Most MACT standards allow a 3 - year compliance period. Under Phase IIAssessment of Reasonable Progress for Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 13 of the NO X SIP Call, EPA provided a 2 - ye ar period after the SIP submittal date for compliance. States generall y provided a 2 - year period for compliance with RACT rules. For the purposes of this rev iew, we have assumed that a 2 - ye ar period after SIP submittal is adequate for pre combustion controls (fuel switching or cleaning) and a three ye ar period for the installation of post combustion controls. For BART control measures, the proposed BART guid elines require S tates to establish enforceable limits and require compliance with the BART emission limitations no later than 5 ye ars after EPA approves the regional haze SIP. Refiners in the United States are already producing low sulfur diesel fuel whic h may be marketed as distillate oil. There is a potential that offshore refiners may not be able to produce enough 15 ppm sulfur for export to the Northeast United States to meet peak demand, but so far this has not occurred. IC I boilers would not have t o retrofit or install expensive control technology to burn ULSD distillate fuel oil, therefore, compliance with the standard is driven b y 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 ye ars depending on the size of the facility and specific control technology selected. **Energy and Non -** **Air Impacts** Fu el switching and cleaning do not significantl y affect the efficiency of the boiler but may

add to transportation issues and secondary environmental impacts from waste disposal and material handling operations (e.g. fugitive dust). FGD s ys tems ty picall y operate with high pressure drops across the control equipment, resulting in a significant amount of electricity required to operate blowers and circulation pumps. In addition, some combinations of FGD technology and plant configuration may

require flue gas reheating to prevent phy sical damage to equipment, resulting in higher fuel usage. The primary

environmental impact of FGD s ys tems 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 F GD liquid. The liquid slurry

collects in the bottom of the FGD in a reaction tank. The slurry is then dewatered and a portion of the contaminant - laden water is removed from the s ys tem as wastewater. Waste from the FGD s ys tems will increase sulfate, metals, and solids loading in a facility ’s wastewater, potentially

impacting community

wastewater treatment facilities for smaller units that do not have self contained water treatment s ys tems. In some cases FGD operation necessitates installation of a clarif

ier on site to remove excessive pollutants from wastewater. This places additional burdens on a facility or community

wastewater treatment and solid waste management capabilities. These impacts will need to be anal yz ed on a site - specific basis. If lime or limestone scrubbing is used to produce calcium sulfite sludge, the sludge must be stabilized prior to land filling. If a calcium sulfate sludge is produced, dewatering alone is necessary before land filling,Assessment of Reasonable Progress for Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 14 however, SO 2 removal costs are higher due to increased equipment costs for this ty pe of control sy stem. In some cases calcium sulfate sludge can be sold fo r use in cement manufacturing. With wet FGD technologies a significant visible plume is present from the source due to condensation of water vapor as it exits the smoke stack. Although the water eventuall y evaporates and the plume disappears, community impact may

be significant. Reducing the sulfur contents of distillate fuel oil has a variety of beneficial consequences for I CI boilers. L ow su lfur distillate fuel is cleaner burning and emits less particulate matter which reduces the rate of fouling of heating units substantially and permits longer time intervals between cleanings. According to a study conducted by

the New York State Energy Res earch and Development Authority, (NYSERDA), boiler deposits are reduced b y a factor of two by lowering the fuel sulfur content from 1,400 ppm to 500 ppm. These reductions in buildup of deposits result in longer service intervals between cleanings. (Batey and McDonald 2005) **Remaining Useful Life of the Source** Available information for remaining useful life estimates of I CIboilers indicates a wide range of operating time, depending on size of the unit, capacity factor, and level of maintenance performed. Ty

pical life expectancies range from about 10 years up to over 30 years.Assessment of Reasonable Progress for Regional Haze In MANE - VU Clas s I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 4: Source Category Analysis: Industrial, Commercial, and Institutional Boilers Page 4 - 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 . Contract No. 6204 - IA BR - BR - 00. U.S. EPA , 2005, Multipoint Emission Control Technology Options for Coal- fired Power Plants , Washington, DC, EPA - 600/R - 05/034. U.S. EPA, 2003, Air Pollution Control Technology Fact Sheet , Washington, DC, EPA - 425 /F - 03 - 034. STAPPA ALAPCO, 2006, Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options . The Lake Mich igan Air Directors Consortium, Midwest Regional Planning Organization Boiler Best Available Retrofit Technology Engineering Ana lysis , March 30, 2005 U.S. EPA, 1993, PM

- 10 Innovative Strategies: A Sourcebook for PM - 10 Control Programs , Research Triangle Park, NC, EPA - 452/R - 93 - 016. U.S. Energy

Information Administration, October 2000, Energy Policy Act Transportation Rate Study: Final Report on Coal Transportation , Publication downloaded from World Wide Web in February , 2007 at http://www.eia.doe.gov/cneaf/coal/coal_trans/epact2000.html GE Water & Proces s Technologies. Information accessed on web March 27, 2007: http://www.zenon.com/applications/FGD_wastewater_treatment.shtml U.S. Energy

Information Administration, 2007. : ”No. 2 Distillate Prices By Sales Ty pe”, In formation downloaded from the World Wide Web on March 7, 2007, at http://tonto.eia.doe.gov/dnav/pet/pet_pri_dist_dcu_R1X_m.htm U.S. En ergy

Information Administration, 2007. :”weekl y Inputs, Utilization and Production”, In formation downloaded from the World Wide Web on March 7, 2007, at http://tonto.eia.doe.gov/dnav/pet/pet_pnp_wiup_dcu_r10_w.htmThis page left blank intentionally.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selec ted Industrial, Commercial, and Institutional Boilers Page 5 - 1 **CHAPTER 5 ANALYSIS OF SELECTED**  **INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL BOILERS**  **SOURCE CATEGORY DESCRIPTION** Modeling of visibility

impacts on Class I regions was c onducted by the Vermont Department of Environmental Conservation (VTDEC) and MANE - VU to identify the major I CIsources contributing to visibility

impairment in the northeast. Table 5. 1 lists the I CIsources identified to contribute significant levels of S O 2 to the MANE - VU region. MACTEC was directed b y MARAMA and the Reasonable Progress Workgroup to focus on the 1 7 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 I CIboilers and specific ally the control method for SO 2 applied to any individual ICI boiler is dependent upon the type of boiler, type of fuel, capacity utilization, and the ty pes and staging of other air pollution control devices. Ho wever, cost effective emissions reduction technologies for SO 2 are available and are effective in reducing emissions from the exhaust gas stream of I CIboilers. **INFORMATION OBTAINED FROM STATE AGENCIES** For the selected ICI boilers, MACTEC contacted S tate and or regional regulatory agencies to evaluate the status of each unit and determine if additional pollution controls had been mandated as a part of regulatory

actions taken since the data used for the visibility impairment modeling w ere collected. Tabl e 5. 1 presents the information obtained from the States .Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Me thodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5 - 2

**Table 5.1 Point Source Information Collected from the Top 1**  **7 Industrial Facilities**  **Responsible for Visibility Impairment in**  **MANE -** **VU Class I Areas** 

**Facility Nam e**  **State 2002**  **SO 2**  **Total (tons)**  **Prim ary**  **Em issions Point** 

**Description Point ID**  **(Perm it**  **ID No.) Design** 

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Additional**

**Inform ation**  Motiva Enterprises LLC

– Delaware City 1 DE 29,747 Fluid Coking Unit (FCU) and FCU Carbon Monoxide Boiler 002 57,19 9 barrels per day of total feed None Cansolv Regenerative Wet Gas Scrubber and SNCR Data from Permit

APC - 82/0829 Amendment 5 SO 2 permit limit is 174 tpy Fluid Catalytic Cracking Unit (FCCU) and FCCU Carbon Monoxide Boiler 012 FCCU coke burn rate limit is 56,000 lbs/hr None Cansolv Regenerative Wet Gas Scrubber Data from Permit

APC - 82/0981 Amendment 6 SO 2 permit limit is 361 tpyAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Me thodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5 - 3

**Table 5.1 Point Source Information Collected from the Top 1**  **7 Industrial Facilities**  **Responsible for Visibility Impairment in**  **MANE -** **VU Class I Areas** 

**Facility Nam e**  **State 2002**  **SO 2**  **Total (tons)**  **Prim ary**  **Em issions Point** 

**Description Point ID**  **(Perm it**  **ID No.) Design** 

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Additional**

**Inform ation**  Kodak Park Division2, 3 NY 23,508 Building 31 and 321 stationary combustion installations, including package ABD built up boil ers used for the generation of process steam and electricity Boilers: 1

– Package boiler, No. 6 2

– Package boiler, No. 6 3

– Package boiler, No. 6 4

– Package boiler, No. 6 13

– Underfed stoker, coal 14

– Underfed stoker, coal 11

– Underfed stoker, coal 1 2

– Underfed stoker, coal 15

– Wet bottom cyclone, coal/No. 6 16

– Wall - fired, coal/No. 6 41

– Wet bottom cyclone, coal/No. 6 42

– Wet bottom cyclone, coal/No. 6 43

– Wet bottom cyclone, coal/No. 6 44

– Tangential - fired pulverized coal, coal/No. 2 U0015 Bo ilers (EP 031B - 1): 1 2 3 4 13 14 Boilers (EP 031B - 2): 11 12 15 16 Boilers (EP 321B - 3): 41 42 Boilers (EP 321B - 4): 43 44 98 MMB TU/hr

98 MMBTU/hr 98 MMBTU/hr 98 MMBTU/hr 265 MMBTU/hr 265 MMBTU/hr 197 MMBTU/hr 222 MMBTU/hr 478 MMBTU/hr 544 MMBTU/hr 500 MMBTU/hr 500 MMBTU/hr 640 MMBTU/hr 670 MMBTU/hr None BART analysis - NO X & SO 2 controls affordable on Boilers 41, 42, & 43 Wet scrubber (90% reduction) wo uld be ~$2,150/ton Dry scrubber (40% reduction) wo uld be ~$1,850/ton Process K07 (Bldg 31) is

No. 6 fuel oil combustion in package boilers Process K09 (Bldg 31) is bituminous coal combustion in built up Boilers 13 and 14 Process K10 (Bldg 31) is No. 6 fuel oil combustion in built up Boilers 15 and 16 Process K11 (Bldg 31) is bituminous coal combustion f

or built up Boiler 15 Process K12 (Bldg 321) is No. 6 fuel oil combustion for built up Boilers 41, 42 and 43 Process K13 (Bldg 321) is bituminous coal combustion for built up Boilers 41, 42 and 43 Process K14 (Bldg 321) is No. 2 fuel oil combustion with NS PS applicability in Boiler 44 Process K15 (Bldg 321) is bituminous low sulfur coal combustionAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Me thodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5 - 4

**Table 5.1 Point Source Information Collected from the Top 1**  **7 Industrial Facilities**  **Responsible for Visibility Impairment in**  **MANE -** **VU Class I Areas** 

**Facility Nam e**  **State 2002**  **SO 2**  **Total (tons)**  **Prim ary**  **Em issions Point** 

**Description Point ID**  **(Perm it**  **ID No.) Design** 

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Additional**

**Inform ation**  MW Custom Papers LLC

– Chillicothe Mill 4 OH 23,216 No.5 Coal Boiler - we t bottom, pulverized coal fired boiler (C. E. model VU - 40), capable of running on #2 fuel oil as backup fuel B001 380 MMBTU/hr maximum heat input Cyclone/

multi - clone ESP None 9.9 lbs of sulfur dioxide per MMBTU actual heat input No.7 Coal Boiler - we t bottom, pulverized coal fired boiler (C. E. model VU - 405), capable of running on #2 fuel oil as backup fuel B002 422 MMBTU/hr maximum heat input Cyclone/

multi - clone ESP None 9.9 lbs of sulfur dioxide per MMBTU actual heat input

No.8 Coal Boiler - we t bottom, pulverized coal fired boiler (C. E. model VU - 40), capable of running on #2 fuel oil as backup fuel. B003 505 MMBTU/hr maximum heat input Cyclone/

multi - clone ESP None 9.9 lbs of sulfur dioxide per MMBTU actual heat inputAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Me thodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5 - 5

**Table 5.1 Point Source Information Collected from the Top 1**  **7 Industrial Facilities**  **Responsible for Visibility Impairment in**  **MANE -** **VU Class I Areas** 

**Facility Nam e**  **State 2002**  **SO 2**  **Total (tons)**  **Prim ary**  **Em issions Point** 

**Description Point ID**  **(Perm it**  **ID No.) Design** 

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Additional**

**Inform ation**  Eastman Chemical Com pany 5, 6 TN 22,882 Two fuel burning installations (B - 83 - 1 & B 253 - 1) w/a total of 19 coal fired boilers of which 14 units (#18 - #24) are located at Powerhouse B - 83 - 1 & 5 units (#25 - #29) are located at Powerhouse B - 253 - 1. The primary fuel is coal. In addition, wood, waste solids, wa ste liquids, & biosludge may be burned in these Powerhouses, whil e NG & process gas may also be burned in the Powerhouse B 253 - 1 boilers. 82 - 0003 - 01 - 19 (020101, 021520) 6,625 Million

BTU/hr nominal heat input ESP Scubbers potentially The five boilers in

Powerhouse B - 253 - 1 are subject to BART. The State does not have c onfirmation yet, but they believe that the boilers will be controlled by scrubbers of some sort. Units #11 - #17, that were located at Powerhouse B - 83 - 1, have been removed

Coal - Fired Boilers 30 and 31 PES B - 325 - 1or 82 - 1010 - 15 (261501) Heat input is

limi ted to 780 and 880 MMBTU/hr, respectively, on a 30 calendar day rolling average basis None None

Westvaco Fine Papers 7, 8 MD 19,083 Boiler 24 is a coal fired cyclone boiler 1 590 MMBTU/hr maximum heat input SNCR

(NO X ) ESP (PM) Baghouse

(PM) Not BART eligible

due to ageAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Me thodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5 - 6

**Table 5.1 Point Source Information Collected from the Top 1**  **7 Industrial Facilities**  **Responsible for Visibility Impairment in**  **MANE -** **VU Class I Areas** 

**Facility Nam e**  **State 2002**  **SO 2**  **Total (tons)**  **Prim ary**  **Em issions Point** 

**Description Point ID**  **(Perm it**  **ID No.) Design** 

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Additional**

**Inform ation**  Boiler 25 is a coal fired tangential boiler 2 785 MMBTU/hr maximum heat input Lo w NO X

burners/ overfired air (NO X ) ESP (PM) Scrubber

(FGD in design) SNCR (NO X ) Baghouse to replace ESP (PM) BART eligible

PPG Industries Inc. 9 WV 12,678 Bo iler 3 is a coal - fired boiler installed in 1942 and mo dified in 1981 R011 (002) or S076 243 MMBTU/hr Fabric filter Lo w NO X burners None Not BART eligible Boiler 4 is a coal - fired and natural gas - fired boiler installed in 1952 R015 (001) or S076 496 MMB TU/hr ESP Lo w NO X burners None Not BART eligible Boiler 5 is a coal - fired boiler installed in 1966 R072 (003) or S482 878 MMBTU/hr ESP Lo w NO X burners None BART eligible, facility to decrease emissions by using low - sulfur coal and taking an emission li mit of 1,478.8 lb SO 2/hrAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Me thodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5 - 7

**Table 5.1 Point Source Information Collected from the Top 1**  **7 Industrial Facilities**  **Responsible for Visibility Impairment in**  **MANE -** **VU Class I Areas** 

**Facility Nam e**  **State 2002**  **SO 2**  **Total (tons)**  **Prim ary**  **Em issions Point** 

**Description Point ID**  **(Perm it**  **ID No.) Design** 

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Additional**

**Inform ation**  Williams Ethanol Services Inc. 10, 11 IL 12,244 4 boilers Boiler A & B are coal - fired boilers constructed in 1944 Boiler C is a coal/oil supplemental - fired boiler constructed in 1958 Boiler D is a NG/No. 2 oil fired boiler construc ted in 1976 10 Boilers A & B: 242 MMBTU/hr Boiler C: 330 MMBTU/hr Boiler D: 195 MMBTU/hr Boilers A &

B: Multi cyclone Boiler C: ESP Boiler D: None None Not BART eligible. There is also a steep acid preparation system (Unit 2) that converts sulfur into sulfurous acid that will be used for the steeping process. Total sulfur usage for this unit is limited to 961,750 lbs/yr (at least 48% of the sulfur added to steepwater shall be retained in the products shipped from the plant).Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Me thodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5 - 8

**Table 5.1 Point Source Information Collected from the Top 1**  **7 Industrial Facilities**  **Responsible for Visibility Impairment in**  **MANE -** **VU Class I Areas** 

**Facility Nam e**  **State 2002**  **SO 2**  **Total (tons)**  **Prim ary**  **Em issions Point** 

**Description Point ID**  **(Perm it**  **ID No.) Design** 

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Additional**

**Inform ation**  Corn Products International Inc. 10, 11 IL 9,281 Utilities: Coal fired Boilers #1, #2, & #3 (pre 1972) Natural gas - fired Boilers #4 & #5 (pre 1972) Natural gas - fired Boiler #6 constructed in 1992 2 natural gas - fired turbines constructed in 1995 Group 9 Boilers #1, #2, & #3: 250 MMBTU/hr Boilers #4 & #5: 312.5 MMBTU/hr Boiler #6: 600 MMBTU/hr Turbines: 65 MMBTU/hr Boilers #1,

#2, & #3: ESP Boilers #4 & #5: None Boiler #6: low -NO X burner & flue gas recirculation Turbines: None None Not BART eligible

Mead Westvaco Packaging Resource Gro up 12 VA 8,552 Four (4) boilers #6

– primarily coal - fired #7

– coal/bark/wood - fired #8 - coal/bark/wood - fired #9

– primarily coal - fired 25 550 MMBTU/hr 440 MMBTU/hr 580 MMBTU/hr 807 MMBTU/hr ESP

Scrubbers FGR LNB None

PH Glatfelter Co./Spring Grove 13, 14 PA 7,855 #4 Power Boiler that burns bituminous coal (13 tons/hr), #6 oil (751 gal/hr), & #2 oil (108 gal/hr) 034 363.7 MMBTU/hr Cyclone

dust collector ESP None Not BART eligibleAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Me thodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5 - 9

**Table 5.1 Point Source Information Collected from the Top 1**  **7 Industrial Facilities**  **Responsible for Visibility Impairment in**  **MANE -** **VU Class I Areas** 

**Facility Nam e**  **State 2002**  **SO 2**  **Total (tons)**  **Prim ary**  **Em issions Point** 

**Description Point ID**  **(Perm it**  **ID No.) Design** 

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Additional**

**Inform ation**  #5 Power Boiler that burns bituminous coal (10.3 tons/hr), #6 oil (300 gal/hr), “as fired” wood (12.2 tons/hr), & #2 oil (451.2 gal/hr) 035 262.3 MMBTU/hr Cyclone

dust collector ESP None BART eligible

Goodyear Tire & Rubber Co. 4 OH 5,903 "A " Boiler, which is a coal fired boiler B101 301 MMBTU/hr ESP None 4.64 lbs of sulfur diox ide per MMBTU actual heat input for B101, B102, and B103 exiting through Stack 4 "B" Boiler, w

hich is a coal fired boiler B102 301 MMBTU/hr ESP None 4.64 lbs of sulfur dioxide per MMBTU actual heat input for B101, B102, and B103 exiting through Stack 4 "C" Boiler, w

hich is a coal fired boiler B103 174 MMBTU/hr ESP None 4.64 lbs of sulfur dioxide per MMBTU actual heat input for B101, B102, and B103 exiting through Stack 4Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Me thodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5 - 10

**Table 5.1 Point Source Information Collected from the Top 1**  **7 Industrial Facilities**  **Responsible for Visibility Impairment in**  **MANE -** **VU Class I Areas** 

**Facility Nam e**  **State 2002**  **SO 2**  **Total (tons)**  **Prim ary**  **Em issions Point** 

**Description Point ID**  **(Perm it**  **ID No.) Design** 

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Additional**

**Inform ation**  Sunoco Inc. (R&M) 15, 16 PA 3,645 Plt. 10 - 4 FCC Unit 101 4,792.000 bbl/hr fres h feed None SCR and a wet gas scrubber installed in 2010. At the latest, compliance is required by 2013. SO 2 limit of 9.8

lbs/1000 lbs of coke burn - off in the catalyst regenerator determined daily on a 7 - day rolling average basis Valero Refining Co.

– NJ 17, 18 NJ 3,597 FCCU Regenerator with In Line Heater E21 or U1 102 MMBTU/hr WGS None Per Consent Decree, SO 2 concentration emission limits at the point of emission to the atmosphere of no greater than 25 ppmvd, measured as a 365 - day rolling average, and 50 ppmvd, measured as a 7 - day rolling average, both at 0% O 2 . Stone Container Corp. (dba Smurfit - Stone Contain) 19 VA 3,379 #8 Power Boiler that burns bituminous coal 2 1,056 MMBTU/hr None Wet gas scrubber (2007) Consent Decree dated

11/2004 which states that SO 2 emission rate will not exceed 0.26 lb/MMBTU on a 30 - day rolling average basis.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Me thodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5 - 11

**Table 5.1 Point Source Information Collected from the Top 1**  **7 Industrial Facilities**  **Responsible for Visibility Impairment in**  **MANE -** **VU Class I Areas** 

**Facility Nam e**  **State 2002**  **SO 2**  **Total (tons)**  **Prim ary**  **Em issions Point** 

**Description Point ID**  **(Perm it**  **ID No.) Design** 

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Additional**

**Inform ation**  Great Northern Paper Inc. Mill West20, 21 ME 1,842 Power Boilers #4 (Riley Stoker)) 004 (WB4) 740 MMBTU/hr None None Unit to be shut down so BART not an issue (only BART eligible source at this facility) NRG Energy Center Dover LLC 1, 22, 23 DE 1,836 Riley Stoker Boiler fired on pulverized bituminous coal (primary fuel) and natural gas (for startup/ignition). C - 1 (001) 243 MMBTU/hr Four (4) DB Riley Low NO X burners Cycloni c Com bustion Venturi burner assemblies Lo w excess air ESP w/23,000 ft2 collecting electrode area None Not BART eligible

Sappi Somerset20, 21 ME 1,734 Power Boiler #1 (Babcock & Wilcox) 001 (PB#1) 848 MMBTU/hr (all fuels) & 250 MMBTU/hr (fossil fuels) Non e None CEMS for SO 2 Facility to reduce SO 2 emissions by 50% by 2013 (BART deadline) 1 MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid - Atlantic North Eastern Class I Areas”, March 8, 2007. Co mments regarding Motiva Enterprises LLC

– Delaware City and NRG Energy Center Dover LLC facilities received from Mr. John Sipple ( 302 - 739 - 9435, John.Sipple@state.de.us ) via E - mail on March 13, 2007.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Me thodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5 - 12

2 New York State Department of Environmental Conservation, Division of Air Resources. Personal communications regarding Kodak Park Di vision facility between Mr. Mike Cronin, P.E. (518 - 402 - 8403, mpcronin@gw.dec.state.ny.us ) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on February 1 and 9, 2007. 3 New York State Department of Environmental Conservation, Division of Air Resources. Personal communications regarding Kodak Park Division facility from Mr. Mike Cro nin, P.E. (518 - 402 - 8403, mpcronin@gw.dec.state.ny.us ) via E - mail on February 12, 2007. 4 Ohio Environmental Protection Agency, Division of Air Pollution Control. Personal communication regarding MW Custo m Papers LLC

– Chillicothe Mill and Goodyear Tire and Rubber Company facilities from Mr. William Spires (614 - 644 - 3618, bill.spires@epa.state.oh.us ) via E - mails on February 20, 2007. 5 Tennessee Department of Environment and Conservation, Division of Air Pollution Control. Personal communication regarding Eastman Chemical Company facility from Ms. Julie Aslinger (615 - 532 - 0587, Julie.Aslinger@state.tn.us ) v ia E - ma il on March 1, 2007. 6 MACTEC Federal Programs, Inc., “Revised Draft Final, Assessing Reasonable Progress for Regional Haze in the Mid - Atlantic North Eastern Class I Areas”, March 8, 2007. Comments regarding Eastman Chemical Company facility receiv ed from Ms. Julie Aslinger (615 - 532 - 0587, Julie.Aslinger@state.tn.us ) via E - mail on March 30, 2007. 7 Maryland Department of the Environment. Personal communication regarding Westvaco Fine Papers facility between Mr. Andy Heltibridle (410 - 537 - 4218, aheltibridle@mde.state.md.us ) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007. 8 Maryland Department of the Environment. Personal communication regarding Westvaco Fine Papers facility from Mr. Andy Heltibridle (410 - 537 - 4218, aheltibridle@mde.state.md.us ) via E - mail on January 31, 2007. 9 West Virginia Division of Air Quality. Personal communications regarding PPG, Industries, Inc. facility between Ms. Laura Crowder (304 - 926 - 0499 Ext. 1247, LCROWDER@wvdep.org ) and Mr. Steve Pursley (304 - 926 - 0499 Ext. 1218) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on March 14, 2007. 10 Virginia Department of Environmental Quality, Division of Air Quality. Personal communication regarding Mead Westvaco Packag ing Resource Group facility between Ms. Doris McLeod (504 - 698 - 4197, damcleod@deq.virginia.gov) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on February 20, 2007. 11 Pennsylvania Department of Environmental Protection, Bureau of Air Quality. Personal communication regarding PH Glatfelter C ompany/ Spring Grove facility between Ms. Nancy Herb (717 - 783 - 9269, nherb@state.pa.us ) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007. 12 Pennsylvania Department of Environmental Protection, Bureau o f Air Quality. Personal communications regarding PH Glatfelter Company/Spring Grove facility from Ms. Nancy Herb (717 - 783 - 9269, nherb@state.pa.us ) via E - mail on January 31 and February 7, 2007. 13 Illinois Environmental Protection Agency, Bureau of Air. Personal communication regarding Williams Ethanol Services Incorporated and Corn Products International Incorporated facilities between Mr. Rob Kaleel (217 - 524 - 4387, Rob.Kaleel@illinois.gov) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on February 2, 2007. 14 Illinois Environmental Protection Agency, Bureau of Air. Personal communication regarding Williams Ethanol Services Incorpor ated and Corn Products Internati onal Incorporated facilities from Mr. Rob Kaleel (217 - 524 - 4387, Rob.Kaleel@illinois.gov) via E - mail on February 2, 2007. 15 Pennsylvania Department of Environmental Protection, Bureau of Air Quality. Persona l communications regarding Sunoco Inc. (R&M) facility between Ms. Nancy Herb (717 - 783 - 9269, nherb@state.pa.us ) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31, 2007. 16 Pennsylvania Department of Environmental Protection, Bureau of Air Quality. Personal communications regarding Sunoco Inc. (R&M) facility from Ms. Nancy H erb (717 - 783 - 9269, nherb@state.pa.us ) via E - mail on February 22, 2007. 17 New Jersey Department of Environmental Protection, Division of Air Quality. Personal communications regarding Valero Refining Company facil ity between Mr. Ray Papalski (609 - 633 - 7225, Ray.Papalski@dep.state.nj.us ) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on January 31 and February 2, 2007. 18 New Jersey Department of Environmental Protection, Division of Air Quality. Personal communication regarding Valero Refining Company facility from Mr. Ray Papalski (609 - 6 33 - 7225, Ray.Papalski@dep.state.nj.us ) via E - mail on February 21, 2007. 19 Virginia Department of Environmental Quality, Division of Air Quality. Personal communication regarding Stone Container Corp oration facility from Ms. Doris McLeod (504 - 698 - 4197, damcleod@deq.virginia.gov) via E - mail on February 9, 2007. 20 Maine Department of Environmental Protection Agency, Bureau of Air Quality. Personal communi cations regarding Great Northern Paper Incorporated Mill West and Sappi - Somerset facilities between Ms. Lynn Ross (207 - 287 - 8106, Lynn.Ross@maine.gov) and Mr. Marc Cone (207 - 287 - 2437) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on February 2, 2007. 21 Maine Department of Environmental Protection Agency, Bureau of Air Quality. Personal communication regarding Great Northern Paper Incorporated Mill West and Sappi - Somerset facilities between Ms. Lynn Ross ( 207 - 287 - 8106, Lynn.Ross@maine.gov) via E - mail on February 2, 2007.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Me thodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 5: Analysis of Selected Industrial, Commercial, and Institutional Boilers Page 5 - 13

22 Delaware Department of Natural Resources and Environmental Control, Division of Air and Waste Management. Personal communica tions regarding N RG Energy Center Dover LLC facility between Ms. Tammy Henry (302 - 323 - 4542, Tammy.Henry@state.de.us ) and Ms. Lori Cress, MACTEC Federal Programs, Inc. on March 5, 2007. 23 Delaware Department of Natural Resour ces and Environmental Control, Division of Air and Waste Management. Personal communications regarding NRG Energy Center Dover LLC facility from Ms. Tammy Henry (302 - 323 - 4542, Tammy.Henry@state.de.us ) via E - mail on March 5, 2007.This page left blank intentionally.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6 - 1 **CHAPTER 6 SOURCE CATEGORY ANALYSIS: KILNS**  **SOURCE CATEGORY DESCRIPTION** Portland cement is a main ingredient for concrete and other common building materials. Portland cement i s mainly composed of clinker, a material formed by heating limestone and other ingredients to temperatures over 1,4 00 o C ( 2,650 o F ) . High combustion temperatures require large amounts of fuel and can result 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 facility . The process flow diagram (taken from AP - 42) shows both wet and dry Portland cement processes. **Figure 6 .1**  **Po rtl**  **and Cement Process Flow Diagram**

EPA. January, 1995. AP42 Section 11.6

– “Portland Cement Manufacturing”. Figure 6 .1 shows that the Portland cement process can generall y be broken down int o the following steps: raw materials handling, raw material preparation, dry mixing, optionalAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6 - 2 preheating and/or precalcining, kiln treatment (p yr oprocessing step), clinker handling and storage, and finishing operations (finishing, storage and shipment). The py roprocessing step transforms the raw mix into clinkers, which are gray , glass - hard, spherically shaped nodules that range from 0.125 to 2.0 inches in diameter. The py roprocessing step is the predominant source of gaseous pollutant emissions. Ingen eral, there are five different processes used in the Portland cement industry to accomplish the py roprocessing step: the wet process, the dry process (long dry

process), the semidry

process, the dry process with a preheater, and the dry process with a preh eater/precalciner. Each of the p yr oprocessing types vary with respect to equipment design, method of operation, and fuel consumption. Generall y, fuel consumption decreases in the order of the processes listed due to the heat required to evaporate water p resent in the raw material slurry (e.g., wet processes use the most fuel). In the long dry

process, all of the py

roprocessing activity

occurs in the rotary

kiln. Dry

process py roprocessing s ys tems have been improved in thermal efficiency and productive c apacity through the addition of one or more cyclone - ty pe preheater vessels in the gas stream exiting the rotary kiln. This sy stem is called the preheater process. The vessels are arranged verticall y, in series, and are supported by a structure known as the preheater tower. Hot exhaust gases from the rotary kiln pass countercurrentl y through the downward - moving raw materials in the preheater vessels. Compared to the simple rotary kiln (long dry

process), the heat transfer rate is significantl y increased, the degree of heat utilization is greater, and the process time is markedl y reduced b y the intimate contact of the solid particles with the hot gases. The improved heat transfer allows the length of the rotary kiln to be reduced. An added benefit of the preheater operation is that hot gases from the preheater tower are used to help dry raw materials in the raw mill. Because the catch from the mechanical collectors, fabric filters, and/or electrostatic precipitators (ESP) that follow the raw mill is returned to the process, these devices can also be considered to be production machines as well as pollution control devices. Additional thermal efficiencies and productivity gains have been achieved by diverting some of the fuel to a calciner vessel at the base of the preheater tower. This sy stem is called the preheater/precalciner process. Regardless of the type of py roprocess used, the last component of the py roprocessing s ys tem is the clinker cooler. The clinker cooler serves two main purposes. First , this portion of the process:  recoups up to 30% of the heat input to the kiln sy stem;  locks in desirable product qualities by freezing mineralogy ; and  makes it possible to handle the cooled clinker with conventional conveying equipment. The more comm on ty

pes of clinker coolers are reciprocating grate, planetary , and rotary . In these coolers, the clinker is cooled from about 1,100°C to 90°C ( 2000°F to 200 °F ) by ambient air that passes through the clinker and into the rotary kiln for use as combustion ai r. However, in the reciprocating grate cooler, lower clinker discharge temperatures are achieved b y passing anAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6 - 3 additional quantity

of air through the clinker. Because this additional air cannot be used in the kiln for efficient combustion, it is vented to the atmosphere, used for drying coal or raw materials, or used as a combustion air source for the precalciner. The second portion of the clinker process, a series of blending and grinding operations, completes the transformation of clinker into finished cement. Up to 5% gypsum or natural anhydrite is added to the clinker during grinding to control the cement setting time, and other specialty chemicals are added as needed to impart specific product properties. This finish milling is accomplished almost exclusively in ball or tube mills. Ty

picall y, finishing is conducted in a closed - circuit sy stem, with product sizing by air separation. Coal is the fuel of choice in cement kilns, primarily because of its low cost, but also because the coal ash contribut es to the product. The current fuel usage in cement kilns is about 82% coal; 4% natural gas; and 14% other fuels, mainl y combustible waste (industrial waste, tires, sewage sludge, etc.). In addition to conventional fuels, many Portland cement facilities are emplo yi ng the use of petroleum derived coke (petcoke) blended with coal to fire kilns. Lime kilns are similar to cement kilns. The kiln is the heart of the lime manufacturing plant, where various fossil fuels (such as coal, petroleum coke, natural ga s, and fuel oil) are combusted to produce the heat needed for calcination. There are five different types of kilns used in lime manufacturing: rotary , vertical, double - shaft vertical, rotary hearth, and fluidized bed. The most popular is the rotary

kiln, however the double - shaft vertical kiln is an emerging new kiln technology

gaining in acceptance primaril y due to i ts energy efficiency . Similar to cement plants, rotary

kilns at lime manufacturing plants may also have preheaters to improve energy efficiency . Additional ly , energy efficiency is imp ro ved by routing exhaust from the lime coole r to the kiln . SO 2 emissions from lime predominately originate from compounds in the limestone feed material and fuels and are formed from the combustion of fuels and the heating of feed material in the kiln. All ty pes of kilns at lime manufacturing plants use external equipment to cool the lime product, except vertical (including double - shaft) kilns, where the cooling zone is part of the kiln. Ambient air is most oft en used to cool the lime (although a few use water as the heat transfer medium), and ty

pically all of the heated air stream exiting the cooler goes to the kiln to be used as combustion air for the kiln. The exception to this is the grate cooler, where more airflow is generated than is needed for kiln combustion, and consequentl y a portion (about 40 % ) of the grate cooler exhaust is vented to the atmosphere. EPA has estimated that there are ab out five to ten kilns in the United States that use grate coolers . The emissions from grate coolers include lime d ust (PM) and trace metallic HAP s found in the lime dust, but not ty pically SO 2 . For cement and lime kilns, add - on control technology options identified for SO 2 include advanced flue gas desulfurizatio n (AF GD), dry FGD, and wet FGD. **EVALUATION OF SO**  **2 EMISSION CONTROL OPTIONS**  Sulfur dioxide may

be generated both from the sulfur compounds in the raw materials and from sulfur in the fuel. The sulfur content of b oth raw materials and fuels varies from plant t o plant and with geographic location. However, the alkaline nature of the cement provides for directAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6 - 4 absorption of SO 2 into the product, thereb y reducing the quantity of SO 2 emissions in the exhaust stream. Depending on the process and 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 n ot strongl y dependent o n fuel sulfur content. Instead, SO 2 emissions are more closel y relat ed to the amount of sulfide (e.g. p yrite) in kiln feedstocks and to the molar ratio of total sulfur to total alkali input to the sy stem. Incement kilns SO 2 emissions generally depend on:

 Inherent SO 2 removal efficiency of kiln s ys tem during processing,  Form of sulfur (e.g. p yritic) and sulfur concentrations in raw material,  Molecular ratio between sulfur and alkalis,  Prevailing conditions (oxidizing or reducing) and their location within the kiln, and  Temperature profile in the kiln sy stem. SO 2 emission reductions may also result from attempts to reduce other pollutants (primarily NO X), typicall y due to changes in the flame characteristics of combustion. For example, staged combustion with mid - kiln injection of a low - sulfur fuel may be considered for re ducing 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 primaril y used to reduce NO X and because their efficiencies are typi cally more limited than other techniques they are not considered in additional det ail here. Other more specific SO 2 control technologies applicable to cement kilns are listed below. A summary of controls evaluated for this work is provided in Table 6.1 . Details of each of the control technologies follow Table 6.1. Additional information on this source category and associated controls can be found in the 2005 NESCAUM document titled: Assessment of Control Technology Options for BART -Eligible Sources .Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6 - 5

**Ta ble 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 of these materials is highly site spec ific. All Kilns Depends on availability of low sulfur raw materials Dry Flue Gas Desulfurization - Spray Dryer Absorption (FGD) Addition of absorbents such as

slaked lime (Ca(OH)2), quicklime (CaO) or activated fly ash with high CaO content to the exhaust gas of the kiln can absorb some of the 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 HC l, residual 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 r eact 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 O ther 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 typicall y results in lowered emissions. However, this technique is less effective in cement - making sy stems, 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 py rite content, compared to the sulfur content of its heating fuel, fuel switching may not be sufficient to reduce SO 2 emissions (Tanna and Schipholt, 2004). However, when fuel sulfur levels are high, fuel switching may

have a significant benefit in SO 2 levels. **Flue Gas Desulfurizat ion (FGD)**  Both wet and dry

flue gas desulfurization (FGD) systems have been used effectivel y to control SO 2 emissions from cement kilns. FGD s ys tems at cement facilities ty pically are , 1 ) dry

flue gas desulfurization (spray

dryer absorption) 2 ) wet flue gas desulfurization, and 3 ) advanced flue gas desulfurization (AFGD) . A brief description of each of these technologies is provided below.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6 - 6 Dry Flue Gas Desulfurization (Spray Dryer Absorption) Spray dryer absorption (SDA) sy stems spray lime slurry

int o an absorption tower where SO 2 is absorbed b y the slurry , forming a mixture of calcium sulfite and calcium sulfate . The liquid - to gas ratio is such that the water evaporates before the droplets reach the bottom of the tower. The dry solids are carried o ut with the gas and collected with a fabric filter or ESP. When used to specificall y control SO 2 , the term dry flue - gas desulfurization (dry FGD) may

also be used. As with other ty

pes of dry

scrubbing s ys tems (such as lime/limestone injection) exhaust gas es that exit at or near the adiabatic saturation temperatures can create problems with this control technology

by causing the baghouse filter cake to become saturated with moisture and plug both the filters and the dust removal sy stem. In addition, the li me slurry would not dry

properl y and would plug up the dust collection sy stem. However there is some argument in the control community

that indicates that some of the SO 2 removal actuall y occurs on the filter cake. Therefore, dry

FGD (spray

dryer absorpt ion) may not be technicall y feasible if exit gas temperatures are not substantially above the adiabatic saturation temperatures. For Portland cement facilities, these temperatures are likel y to be above the adiabatic saturation temperatures. Most of the spray

dryer ty pe SO 2 control technologies in the cement industry are applied to preheater or preheater/precalciner kilns. Exhaust gases from long dry kilns are cooled by

either spray water introduced into the feed end of the kiln or by dilution air - coolin g after the gases leave the kiln. Adding a conditioning tower to replace wet suppression or dilution air enables the alkaline slurry

s ys tem to be used to reduce SO 2 emissions (the equivalent of a spray dryer). The use of an alkaline slurry

spray dryer ty pe scrubber should be applied to long wet kilns with care because the addition of the lime slurry may drop the exhaust gases temperature below the acid adiabatic saturation temperatures, creating significant plugging and corrosion problems in the downstream particulate control device, du ct work, and induced draft fan. Wet Flue Gas Desulfurization (FGD) Wet scrubbing processes used to control SO 2 and particulate emissions are generall y termed flue gas desulfurization (FGD). FGD utilizes gas absorption tec hnology , the selective transfer of materials from a gas to a contacting 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 liquid 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 concentrating the resultant sludge . Calcium sulfite sludge is watery

and is typically stabilized with fly ash for land filling. C alcium sulfate sludge is stable and eas y to dewater. To produce calcium sulfate, an air injection blower is needed to supply the ox ygen for the second reactio n 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 Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6 - 7 can be avoided if these systems are installed downstream of a high effic iency particulate control device (e.g., fabric filter). Failure of the particulate control device can pose difficult problems for a downstream wet scrubber. Advanced Flue Gas Desulfurization (FGD) The AFGD process accomplishes SO 2 removal in a single ab sorber which performs three functions: prequenching the flue gas, absor bing SO 2 , and oxidizing the resulting calcium sulfite to wallboard - grade gy

psum. Figure 6.2 shows the process flow for an AFGD sy stem. In coming flue gas is cooled and humidified with process wet suppression before passing to the absorber. In the absorber, two tiers of fountain - like spray s distribute reagent slurry over pol ym er grid packing that provides a large surface area for gas/liquid contact. The gas then enters a large gas/liqu id disengagement zone above the slurry reservoir in the bottom of the absorber and exits through a horizontal mist eliminator.

**Figure 6.2**  **Advanced Flue Gas Desulfurization Process Flow**

As the flue gas contacts the slurry , the sulfur dioxide is absorb ed, neutralized, and partiall y 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 Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6 - 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, s lurry falls into the slurry

reservoir where any unreacted acids are neutralized by

limestone injected in dry powder form into the reservoir. The primary reaction product, calcium sulfite, is oxidized to gy psum by the air rotary

spargers, which both mix th e slurry in the reservoir and inject air into it. Fixed air spargers assist in completing the oxidation. Slurry from the reservoir is c irculated to the absorber grid. A slurry stream is drawn from the tank, dewatered, and washed to remove chlorides and produce wallboard quality gy

psum. The resultant gy

psum cake contains less than 10 % water and 20 ppm chlorides. The clarified liquid is returned to the reservoir, with a slipstream being withdrawn and sent to the wastewater evaporation s ys tem for injectio n into the hot flue gas ahead of the electrostatic precipitator. Water evaporates and dissolved solids are collected along with the flyash for disposal or sale. The production of gy

psum may

actuall y be beneficial for Portland cement as gypsum is added to Portland cement in the final grinding process to regulate the setting time of the concrete. However, to date there are no known installations of AFGD at Portland cement facilities. **Inherent Removal** Removal of SO 2 in the cement manufacturing process is inherent to that process. The raw materials used in the process, primaril y limestone, are preheated in the cement - making process either in the preheater tower or in the rotary kiln. In either case, the limestone comes in contact with hot combustion exhaus t gases generating a free lime , which then reacts with SO 2 in the gas stream, providing in - process removal of sulfur in the kiln sy stem. Removal efficiencies in rotary kiln systems range between 38% and 99% of sulfur input, and 50% to 70% of the remaining SO 2 is removed from exhaust gases when passing through an in - line raw mill sy stem (Miller et al., 2001). The overall effectiveness and costs associated with this method are highl y variable and are related primarily

to the ty pe of kiln operation and the a bility 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 the nature of the Portland cement manufacturing process:  Change in the ox ygen concentration in the flame/exhaust gas area. The concentrations of oxygen and (more importantly) carbon monoxide strongl y 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 widel y used industrial practice, and a control technique applicable to all rotary

cement kilns. The downside of this technique is the more favorable conditions created for generation of NO X in the rotary kiln.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6 - 9  Burning - zone flame shape can be modified to ensure that reducing conditions in the flame are minimized. Flame imping ement in the hot zone has a major effect on SO 2 emissions from the kiln, even if total ox ygen 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 te chnique applicable to all rotary kilns producing cement clinker, requires proper solid fuel preparation and proper flame shaping and control.  Changes in raw materials to alter the alkali/sulfur molar ratio can also be used to control SO 2 emissions. SO 2 con centrations 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 typicall y low, due to more sulfur being retained as alkali sulfates in the clinker. Cement plants may also change their raw materials to reduce SO 2 emissions. Ty picall y this is accomplished b y substituting a raw material containing p yritic sulfur or organic sulfur with one containing lesser amounts of these compounds, leading to reduced SO 2 emissions. Rep lacement of raw materials, however, is often constrained b y economic considerations, while alkali input increase may also be limited by

cement product quality specifications on total alkali in cement.  Alterations to sy stem can influence SO 2 emissions. It has been found that an improved distribution of kiln feed may equalize temperatures in bottom stage cyclones and reduce SO 2 emission by

as much as 20% (Miller, 2001). As with inherent removal, the overall effectiveness and costs associated with this metho d are highl y variable and are related primaril y 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 C**  **ompliance** To compare the various control options, information has been compiled on the cost - effectiveness of retrofitting controls. In general, cost - effectiveness increases with the amount of cement produced b y the facility . In a study performed for LAD CO for a BART analy sis, MACTEC developed control c osts 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 scrubbing liquor. Caustic (NaOH) and limestone are potential al ternatives for a scrubber and could change the costs slightl y . While lime and limestone require additional equipment for slurry preparation and for solids separation from the sludge generated in the scrubber, lime scrubbers are the most commonly used sinc e lime is plentiful and relativel y cheap. Materials of construction must also be made suitable for caustic, lime, or limestone if existing equipment is modified for wet scrubbing of SO 2 . AFGD s ys tems require additional capital costs for the spargers and blowers necessary to oxidize the waste product to gy

psum and for equipment to dewater the product (e.g., centrifuge). However if the commercial grade gy psum can be sold or used by the cement facility , some of these costs can be offset.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6 - 10 Dry FGD costs were calculated based on the low and high control efficiencies ty pical for these sy stems . For dry

scrubbers, the flue gas must be cooled to a temperature 10 to 20 degrees above adiabatic saturation. This is ty picall y accomplished using a heat recovery boiler, an evaporative cooler or a heat exchanger. In addition, if the facility does not have one, a particulate removal device is required for removal of the dry materials used to absorb SO 2 . For all scrubbers, costs for an additional or upgraded induced air draft fan to make up for pressure drops within the sy stem may be required. Inaddition, for wet s ys tems, 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 s ys tems vary depending on the size of the kiln and control efficiency , so costs are presented for three size ranges of kilns. Although the capital and annual operating costs of these three ty pes of control 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 C**  **ontrol 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 $2,000 - $4,000 $4.5 - $14.5 $1.2

– $11.8 $13,600 - $38,000 Medium $14.1 - $45.9 $6.1 - $11.9 $8.9 - $29.0 Large $28.1 - $91.6 $12.1

– $23.7 $17.8 - $58.0 **Table 6. 3**  **SO 2**  **Control Costs for Wet FGD 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 $2.43

– $36.5 $3 - $9 $2,000 - $6,200 $ 1 .5 - $ 23.1 $ 0.9

– $ 18.9 $ 9,700 - $ 64 , 6 00 Medium $4.9 - $73.0 $6.0 - $18.4 $3.1 - $ 46.3 Large $9.5 - $142.5 $11.9

– $36.8 $ 6.2 - $ 92.5Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6 - 11 **Table 6. 4**  **SO 2**  **Control Costs for Dry FGD 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 $1.45

– $37.0 $3 - $9 $1,900 - $7,000 $0.9 - $26.3 $0.9

– $ 21.0 $ 10,000 - $ 72,800 Medium $2.9 - $84.9 $5.5 - $20.0 $1.8 - $52.6 Large $5.6 - $165. 5 $10.7

– $38.9 $3.6 - $105.2 The LADCO region had no wet kilns so cost estimates were not available for those type kilns. For the purposes of this study , wet kiln cost effectiveness is assumed to be similar to that for long dry kilns. Additional de tails concerning the calculation of cost effectiveness of controls for kilns is located in a document developed by MACTEC for LADCO titled: Cement Best Available Retrofit Technology (BART) Engineering Analysis . This document can be downloaded from the web at the following location: http://www.ladco.org/reports/rpo/Regional%20Air%20Quality /BART/Cement_BART_Engineeri ng% 20Anal ys is%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 - ye ar period after the SIP submittal date for compliance. States generall y provided a 2 - year period for compliance with RACT rul es. For BART control measures, the proposed BART guidelines require S tates to establish enforceable limits and require compliance with the BART emission limitations 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 switching or cleaning) and a three year period for the installati on of post combustion controls. **Energy and Non -** **Air Impacts** Fuel switching and cleaning and process changes do not significantl y impact efficiency of the cement operation, but may add to transportation issues and secondary environmental impacts from waste disposal and material handling operations (e.g. fugitive dust). FGD s ys tems ty picall y operate with high pressure drops across the control equipment, resulting in a significant amount of electricity

required to operate blowers and circulation pumps. In addition, some combinationsAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6 - 12 of FGD technology

and plant configuration may require flue gas reheating to prevent phys ical damage to equipment, resulting in higher fuel usage. Environmental Impacts The primary

environmental impact of AFGD is the generation of by product gy

psum. While gy psum is generated as a by product, the intent of th e AFGD s ys tem is to produce gy psum that is commercial grade that can be sold. Inthe case of cement kilns, production of gy psum would result in some cost offsets since gy psum is a component of Portland cement. Thus the gy psum produced could be used to of fset gy psum purchases. The primary

environmental impact of wet scrubbers is the generation of wastewater and sludge. Waste from wet scrubbers will increase the sulfate and solids loading in the facility ’s wastewater. This places additional burdens on a facility ’s wastewater treatment and solid waste management capabilities. These impacts will need to be anal yz ed on a site - specific basis. If lime or limestone scrubbing is used to produce calcium sulfite sludge, the sludge is water- laden, and it must be stabilized for land filling . If lime or limestone scrubbing is used to produce calcium sulfate sludge, it is stable and eas y to dewater. However, control costs will be higher because additional equipment is required. Scrubber exhaust gases are saturated with water, thus creating a visible plume. Plume visibility may be a local/community

concern. Once the exhaust mixes with sufficient air, the moisture droplets evaporate, and the plume is no longer visible. Disposal of removed material from dry FGD s ys t ems is also required and will result in landfill impacts. Energy Impacts A scrubber operates with a high pressure drop, resulting in a significant amount of electricity required to operate the blower and pump. In addition for some technologies, a flue g as reheater may be required resulting in slightl y increased fuel usage. **Remaining Useful Life of the Source** MACTEC could find little information on the typical lifetime of a cement plant . Ina Security and Exchange filing (http://www.secbd.org/prosmcldopr.html ) for a facility in India, typical lifetimes of various components of the plant range between 20 - 50 years. In an evaluation of waste management of cement kiln dust (CKD), remaining useful lifetimes of waste management units were around 20 years (http://www.epa.gov/epaoswer/other/ckd/rtc/chap - 4.pdf ). Thus we found nothing to suggest that the amortization of capital costs or calculation of annual operating costs would be affected by the remaining useful life. For the purposes of this analy sis, we assumed that the remaining us eful life of each emission unit was a minimum of at least 10 years and that it was likely that some unit s would continue to operate for at least 20 - 30 more years with p roper maintenance and upkeep.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 6: Source Category Analysis: Kilns Page 6 - 13 **REFE R** **E NCES**  Assessment of Control Technology Options for BART -Eligible Sources , NESCAUM, March 2005. EPA. January , 1995. AP42 Section 11.6

– “ Portland Cement M anufacturing”. Hansen, Eric R. Staged Combustion for NO X Reduction Using High Pressure Air Injection , IEEE - IAS/PCA 43rd Cement Industry Technical Conference; Jacksonville, FL : May 2002. Miller, F.M. et. al. Formation and Techniques of Control of Sulfur D ioxide and Other Sulfur Compounds in Portland Cement Kiln Systems . Portland Cement Association R&D Serial No. 2460, 2001. Tanna, B. and B. Schipholt. Waste -Derived Fuel Use in Cement Kilns ERAtech Group, LLC http://www.eratech.com/papers/wdf.htm , accessed September, 2004.This page left blank intentionally.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 7: Analysis of Selected Kilns Page 7 - 1 **CHAPTER 7 ANALYSIS OF SELECTED**  **KILNS SOURCE CATEGORY DESCRIPTION**  Emission control regulations for cement kilns have historically focused on particulate emissions. Over the past several years, regulations for the control of 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 the Clean Air Act and for sources subject to the Best Available Retrofit Technology (BART) requirements o f the regional haze regulations. Title I subject s new and modified large stationary sources that increase their emissions to permitting requirements that impose control technologies of varying levels of stringency (known as New Source Review, or NSR). NS R prescribes control technologies for new plants and for plant modifications that result in a significant increase in emissions, subjecting them to Best Available Control Technology (BACT) in attainment areas and to the Lowest Achievable Emission Rate (LAE R) in nonattainment areas. The control strategies that constitute BACT and LAER evolve over time and are reviewed on a case - by- case basis in S tate permitting proceedings. **INFORMATION OBTAINED FROM STATE AGENCIES** MACTEC contacted S tate agencies to obtai n 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 an y available information on BART, conse nt decrees, or other regulations that will impact control devices at the facilities. The information we obtained is included in Table 7. 1.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control O ptions, and Four Factor Analysis Chapter 7: Analysis of Selected Kilns Page 7 - 2

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

**Visibility Impairment in MANE -** **V U Class I Areas** 

**Facility Nam e**  **State 2002**  **SO 2**  **Total (tons)**  **Prim ary Emissions Point** 

**Description Point ID**  **(Perm it**  **ID No.) Design** 

**Capacity Existing** 

**Control(s) Proposed/** 

**Planned Control(s)**  **Additional**

**Inform ation**  LaFarge Building Materials Inc. 1 NY 14,800 Two rotary, wet process kilns (Kiln 1 & 2) and two clinker coolers (Clinker Cooler 1 & 2). There are buildings at either end of the kilns; the discharge end building where the clinker coolers are located, and the feed end building. 041000 Unknown Fabric filt er dust collector on clinker coolers (PM) ESP (PM) None

St. Lawrence Cement Corp.

– Catskill Quarry2, 3 NY 3,562 Cement kiln permitted to burn coal, oil, tires, waste oil, natural gas, non hazardous fuels, and coke . This is a wet kiln built in 1964. U00 K18 Unknown ESP Lo w - sulfur fuel Consent Decree dated

1/9/91 limits burning solid fuel with a max sulfur content of 3.8 lbs/MMBTU/hr. BART analysis has not been completed. Lafarge Midwest, Inc., Alpena Plant4 MI 16,576 Five rotary dry kilns, clinker coole rs and associated materials handling operations. Kilns fire with coal, coke or waste derived fuel EU - Kiln19 EU - Kiln20 EU - Kiln21 EU - Kiln22 EU - Kiln23 Unknown Baghouses on kiln dust return systems Unknown as of

date of report - these units are subject to BART SO 2 Emission limits

on all five kilns: EUKiln19 = 2,088 tons EUKiln20 = 2,065 tons EUKiln21 = 2,056 tons EUKiln22 = 9,685 tons EUKiln23 = 9,728 tons 1 New York State Department of Environmental Conservation, Division of Air Resources. Personal communic ation regarding LaFarge Building Materials Incorporated facility between Mr. Rick Leone (518 - 402 - 8403) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on February 2, 2007. 2 New York State Department of Environmental Conservation, Division of Air Resour ces. Personal communication regarding St. Lawrence Cement Corporation

– Catskill Quarry facility between Mr. Rick Leone (518 - 402 - 8403) and Ms. Lori Cress, MACTEC Federal Programs, Inc., on February 9, 2007.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control O ptions, and Four Factor Analysis Chapter 7: Analysis of Selected Kilns Page 7 - 3 3 New York State Department of Environmental Con servation, Division of Air Resources. Personal communication regarding St. Lawrence Cement Corporation

– Catskill Quarry facility from Mr. Rick Leone (518 - 402 - 8403) via E - mail on February 9, 2007. 4 Michigan Department of Environmental Quality, Air Quality Division. Personal communication regarding LaFarge Midwest, Incorporated Alp ena Plant from Ms. Teresa Walker (517 - 335 - 2247, walkertr@michigan.gov) via E - mail on February 7, 2007.This page lef t blank intentionally.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for S

ource Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8 - 1 **CHAPTER 8 HEATING OIL**  **BACKGROUND** Number 2 distillate fuel oil, heating oil, and diesel fuel oil are essentially the same refineryproduced liquid. In the Northeast United States, home heating accounts for 54 % of distillate fuel o il demand. In comparison, highway diesel accounts for 38 % (NESCAUM, 2005). Annual ly , home heating oil use generates an estimated 100,000 tons of sulfur dioxide (SO 2 ) emissions in the Northeast (NESCAUM, 2005). Climate and seasonality play important role s in the use of heating oil, and therefore the emissions from combustion of heating oil. While i t 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 St ates 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; therefore, the most effic ient 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 heating oi ls throughout the Northeast.

**Table 8.**  **1 State Sulfur Limits**  **f or Heating Oil**  **State Sulfur Limit in Percent**  **Sulfur Limit in parts per mi**  **llion (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 N ew 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 UL SD) was 15 ppm. Prior to that, highway low sulfur diesel fuel was refined to contain 500 ppm sulfur (Low Sulfur Diesel, or LSD). Consequently , refineries have already performed the capital investments required for the production of LSD and UL SD fuel oil. The Northeast S tates are considering adopting consistent low sulfur heating oil require ments, and a memorandum titled DRAFT Memorandum of Understanding for Regional Fuel Sulfur Content Standards forAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

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ource Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8 - 2 Distilla te Number 2 Heating Oil , the Northeast S tates 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 regarding the reduction of heating oil sulfur content to 15 ppm. This memorandum presents the four factor anal ys is that was applied to the heating oil sulfur reduction proposal. The four factors are: cost of compliance, time necessary for compliance, energy and non - air impacts, and remaining useful life of the sources. This document primaril y focuses on reducing the sulfur content of heating oil to 500 ppm. Information on reducing the sulfur content of heating oil to 15 ppm is presented wherever data were available. **FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR**  **EMISSIONS FROM HEATING OIL COMBUSTION Cost of Compliance**  Refinery Retrofit Costs Refineries were required to make significant capital investments to meet the L SD and ULSD highway fuel sulfur requirement. To achieve the LSD and UL SD sulfur goals, refineries were required to implement diesel desulfurization technologies. Estimates for the capital costs were developed in 2001 b y the Energy Information Administration (EIA) and are based on calendar ye ar 1999. Table 8. 2 presents the capital costs for desulfurization technologies develop ed b y the EIA , which were converted from a calendar year 1999 dollar basis to 2006 dollars . Th e EIA developed estimates for new and revamped desulfurization technologies at existing refineries. **Table 8.2**  **Ultra Low Sulfur Diesel (ULSD) Desulfurization Technology Costs**  **f or**  **Individual Refineries a**  **,b Desulfurization**  **Unit Type Throughput** 

**(Barrels per Day)**  **Capital Costs**

**( 2006**  **Dollars per Daily Barrel**  **Produced) Total Capital** 

**Cost per Unit (M**  **illion 2006**  **Dollars)** New 50,000 1,204 60.3 New 10,000 2,187 21.9 Revamp 50,000 716 35.8 Revamp 10,000 1, 464 14.6 aBased on c ost estimates for hydrotreaters to pr oduce ULSD. b Source for this information is the Energy Information Administration Note

– A conversion factor of 1.2101 wa s used to convert the dollar values from 1999 to 2006 www.inflationdata.com In its highw ay

diesel fuel rulemaking, EPA also developed cost estimates for the deploy ment and implementation of desulfurization technologies at refineries. EPA estimated that it would cost existing refineries an estimated $5 6 million (2006 dollars) per refinery to install desulfurizationAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

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ource Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8 - 3 technologies, and that this effort would be spread out over a 2 - ye ar time period. EPA based its conclusions on the assumption that refineries would revamp their hydrotreating technologies. It further estimated that 80 % of the h ydrotreaters at the refineries would be revamped. The EPA also estimated that the cost of a new hydrotreater would be $ 91 million (2006 dollars) , and that roughl y 25 refineries nationwide would have to make this investment. No estimates were made for the co sts associated with new refineries as none are currently being constructed in the United States. The EPA anal ys is spread the investment cost over a 2 - ye ar period. Consequently , it was estimated that the US refinery- wide investment for calendar year 2004 was $2.45 billion and $2.83 billion for calendar year 2005 (EIA 2001) (Converted from 2001 to 2006 dollars using a conversion factor of 1.1383 . www.inflationdata.com). In the August 9 , 2006 edition of This W e ek in Petroleum , EIA reported that total UL SD production progress has been good and that ULSD is currentl y being produced in all Petroleum Administration for Defense Districts (PADDs). Stocks of ULSD in the United States in January 2007 were approximately equal to distillate oil containing greater than 500 ppm sulfur. However on the East Coast, stocks of UL SD were approximately one - third the size of distillate oil stoc k s cont aining more than 500 ppm sulfur (EIA) . Another independent source , The Marathon Petroleum Company , LLC, found that 90 % of refineries in the continental United States that were included in a survey had designed units capable of producing UL SD. Also , Marathon determined that the planned US capacity for ULSD would be in excess of 2.5 mi llion barrels per day in 2006 (Marathon Petroleum Corporation 2007). Heating Oil Cost Increases It is assumed that the costs for retrofitting refineries will be passed on to consumers. In its December 2005 study, NESCAUM estimated that the average price increment for the lower sulfur product (500 ppm) would be $0.16 per gallon. In December 2005, this represented a 1 % increase of the average oil price. To update these costs we compared the costs of low - sulfur diesel fuel (15

– 500 ppm) with regular dies el 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 currentl y not reported and because diesel fuel and number 2 distill ate are essentially

the same product. It is therefore reasonable to assume that the cost differential between low sulfur and regular diesel fuel should reflect the potential cost differential between low sulfur and regular heating oil. All cost compariso ns are before taxes. EIA only reports a low - sulfur diesel fuel category which includes both low sulfur (500 ppm) and ultra low sulfur diesel (15 ppm). For the first two months on 2007, EIA reports that stocks of 15 ppm sulfur oil were roughly

twice that of 500 ppm sulfur oil. We averaged monthly costs to compute annual average costs for PADD 1A ( CT, ME, MA, NH, RI , VT ) and PADD 1B ( DE, DC, MD, NJ, NY, PA ) for low sulfur and regular diesel fuel from January to December 2006. For PADD 1A, the cost of low sulfur diesel fuel ranged from $1.954 to $2.433 per gallon and the cost of regular diesel fuel ranged from $1.963 to $2.429 per gallon. The monthly difference between low sulfur and regular diesel fuel ranged from - 1.1 cents per gallon to 0.5 cents per ga llon with an annual average of - 0.8 cents per gallon. That is, low - sulfur diesel fuel was on average less expensive that regular diesel fuel in PADD 1A in 2006. Similarly in PADD 1B, the cost of low sulfur diesel fuel ranged from $1.894 to $2.358 per gal lon and the cost of regular diesel fuel rangedAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

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ource Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8 - 4 from $1.894 to $2.321 per gallon. The monthly difference between low sulfur and regular diesel fuel ranged from - 1.3 cents per gallon to 4.7 cents per gallon with an annual average of 1.6 cents per gallon. In both regions fuel costs were highest in the summer and the difference in cost between low sulfur and regular diesel fuel was also highest in summer. To calculate an average cost differential, we weighed the PADD 1A and PADD 1B cost differentials by resi dential fuel use in each PADD for 2005 (the latest date data are available from EIA). In 2005, PADD 1A S tates used 1.9 million gallons and PADD 1B S tates used 2.5 million gallons. Therefore, on average low sulfur distillate oil would be expected cost 0.8 cents per gallon more than regular heating oil in MANE - VU S tates. This average price differential translates in to $734/ton of sulfur removed if it assumed that the low sulfur di esel has a concentration of 500 ppm sulfur or $554 /ton of sulfur removed for ultra low 15 ppm sulfur diesel . STAPPA - ALAPCO (2006) estimates that the annual fuel oil consumption per household is 865 gallons per year. Using the price differential data presented above, the average household would spend about $ 7 per ye ar additional on home heating costs by usin g low or ultra low sulfur fuel. The use of LSD/ULSD will also result in cost savings to owners/operators of residential furnaces and boilers due to reduced maintenance costs. When the existing heating oil sulfur content is 2, 000 ppm and 500 ppm sulfur is substituted, the service interval can be extended by a factor of three or more (e.g., cleaning at three ye ar intervals rather than annuall y). 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 ho mes switched to 500 ppm sulfur heating oil, more than $200 million a year could be saved, which would significantl y lower the overall operating costs of fuel oil marketers. Given the dominant share of the U.S. heating oil market represented b y the Northea st S tates, a large percentage of the projected national benefits would accrue in the region (NESCAUM 2005). In a brochure distributed by EIA titled Residential Heating Oil Prices: W hat 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 i mpact anal ys is for Heav y- Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements (2000). EPA found that refiners in the Mid - Atlantic and No rtheast (PADD 1) could produce more of this fuel and reduce the need for imports. EIA reports that in 2004, 5,975,966,000 gallons of heating oil were sold in the United States. This decreased to 5,548,827,000 gallons in 2005. The EIA publishes weekly updates on the availability

of heating oil. Information was retrieved for January 2007 and is summarized in Table 8. 3 below.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

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ource 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 Oilb 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 regarding the production and imports of heating oil. This information is summarized in Table 8.4, and includes specific data for the East Coast. The information presented in Table 8. 4 indicates that on a nationwide ba sis, more UL SD is produced than both LSD and high sulfur fuel. This is due to the predominant use of UL SD in highway diesel vehicles. This information also supports the conclusion that the United States has the infrastructure to produce adequate stocks o f L SD and ULSD. **Table 8.4**  **Distillate Production a**  **nd Imports (Million Barrels**  **p er 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 0.02 4 0.277 0.549 Im ports 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 use diesel, whereas the >500 ppm stocks are sold for heating oil. The 15 - 500 ppm fuel can still be used until 2010 under the hardship provisions of the heav y duty highway diesel program (EPA 2004). Under these provisions of the heavy duty highway diesel program, if there is a shortage of 15 ppm fuel, the 15 - 500 ppm fuel could be used to relieve the shortage. With this flexibility , the likelihood of a fuel shortage in the short term, due to usage of ULSD for heating oil is reduced. **Time Necessary f**

**or Compliance** Refiners in the United States are already producing low sulfur highway diesel fuel. This same fuel can be marketed as heating oil since it is the same refinery product as highway

diesel except with dye added to the fuel to differentiate it for tax purposes. Some time may be required toAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

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ource Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8 - 6 allow petroleum marketers to adjust to distributing ULSD to heating oil customers, however, the distribution network for motor fuels and heating oil are already in place . NESCAUM (2005) estimated that during peak periods of demand, up to 20 % of the required heating oil is imported. This analy sis does not address whether offshore refineries should be able to produce 15 ppm sulfur for export to the Northeast United States . Incase of a shortage of 15 ppm fuel during the transition period from L S D to UL SD, the heavy duty highway diesel program allows the use of 15 - 500 ppm sulfur fuel. Existing residential furnaces and boilers do not need to be retrofitted or modified to combust 15 ppm sulfur. The capacity for producing LSD and UL SD already exist s among US refiners. Consequently , the time necessary for compliance does not hinge on the heating oil furnace/boiler. **Energy and Non -** **Air Impacts** Reducing the sulfur contents of heating oil has a variety of beneficial consequences for residential furnac es and boilers. Lo w sulfur distillate fuel is cleaner burning and emits less particulate matter which reduces the rate of fouling of heating units substantially and permits longer time intervals between cleanings. According to a study conducted by

the Ne w York State Energy Research and Development Authority , (NYSERDA), boiler deposits are reduced by a factor of two b y lowering the fuel sulfur content from 1,400 ppm to 500 ppm. These reductions in buildup of deposits result in longer service intervals between cleanings. (Batey and McDonald 2005) . Batey

and McDonald (200 5) estimated that the potential cost savings from decreased vacuum cleanings ranges from $200 million per year to $390 million per year. The decreased deposits would also enable a more eff icient transfer of heat, thereb y reducing the fuel usage. Further reducing the heating oil sulfur from 500 to 15 ppm would increase the cost savings from decreased maintenance needs due to heat exchanger fouling. The decreased sulfur levels would enable manufacturers to develop more efficient furnaces and boilers by using more advanced condensing furnaces and boilers. These boilers recoup energy that is normally

lost to the heating of water vapor in the exhaust gases. Historically , the use of high sulfur fuels prevented this due to the corrosion of the furnace/boiler due to the creation of sulfuric acid in the exhaust gases. The increased efficiency results in a decrease in the amount of heating oil a heating unit uses, therefore, this would make a swit ch to lower sulfur heating oils more attractive and cost effective. **Remaining Useful Life o f**  **t he Source**  Residential furnaces and boilers have finite life times, but they do not need to be replaced to burn low or ultra low sulfur fuel. The Energy Researc h Center estimates that the average life expectancy

of a residential heating oil furnace is approximately 18 years, and that the average life expectancy

of a residential heating oil boiler is 20 - 25 years (Personal communication with Mr. John Batey , Energy Research Center on February 6, 2007). Finally , the number of homes that are being heated with heating oil is declining by approximately

100,000/year (RedOrbit 2007). No geographical distribution was available forAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

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ource Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8 - 7 this estimate, but since heating oil is p redominantly 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 Regional Haze In MANE - VU Class I Areas

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ource Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 8: Heating Oil Page 8 - 8 **REFERENCES** Batey , J.E. and R. McDonald, 2005. Low Sulfur Home Heating Oil Demonstration Project Summary Report . Project funded by The New York Sate Energy Research and Development Authority . Contract No. 6204 - IA BR - BR - 00. Energy Research Center. Personal communication on February 6, 2007 with Mr. J ohn Batey and Mr. Bernd Haneke of MACTEC Federal Programs, Inc. EPA, 2004. Overview of EPA’s Low Sulfur Diesel Fuel Programs . Presented at the Ultra - Lo w Sulfur Diesel Fuel Implementation Workshop by the EPA’s Office of Transportation and Air Quality , Ne w Orleans, Louisiana, November 15, 2004. Marathon Petroleum Company , LLC. Ultra Low Sulfur Diesel. PowerPoint Presentation downloaded from the World Wide Web on January 31, 2007 from: http://www.maratho npetroleum.com/ NESCAUM, 2005. Low Sulfur Heating Oil in the Northeast States: An Overview of Benefits, Cos ts and Implementation Issues . RedOrbit, 2007. Refiners Have Many Options to Convert High - Aromatic Streams into ULSD . Article downloaded from the World Wide Web on January 31, 2007 at: http://www.redorbit.com STAPPA ALAPCO, 2006. Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options . US Energy

Information Administration, Augus t 9, 2006. This W eek in Petroleum . US Energy

Information Administration, 2001. Brochure titled Residential Heating Oil Prices: What Consumers Should Know . US Energy

Information Administration, 200 1. The Transition to Ultra - Lo w – Sulfur Diesel Fuel: Ef fects on Prices and Supply . Publication downloaded from the World Wide Web on January 31, 2007 at: www.eia.doe.gov/oiaf/servicerpt/ulsd US Energy

Information Administration, 2007. Information downloaded from the World Wide Web on March 8, 2007.at: http://tonto.eia.doe.gov/dnav/pet/pet_pri_dist_dcu_R1X_m.htm US EPA, 2000. Regulatory Impact Analy sis: Heavy Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements . EPA Publication Number EPA420 - R - 00 - 026.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9 - 1 **CHAPTER 9 RESIDENTIAL WOOD COMBUSTION**  **BACKGROUND** The MANE - VU Contribution Assessment and other MANE - VU reports have documented that v isibility impairment in this region is primaril y due to regional secondary sulfate. However, in the M ANE - VU Class I areas, biomass combustion also has been identified as a contributor to visibility impairment. Biomass combustion emissions due to human ac tivity primarily derive from residential wood combustion . While some biomass burning occurs throughout the ye ar, residential wood combustion occurs predominantly in the winter months, potentially contributing to wintertime peaks in PM concentrations. In the document, Control Analysis and Documentation for Residential W ood Combustion in the MANE- VU Region , OMNI Environmental Services, Inc. (OMNI) conducted a control anal ys is and documentation of residential wood combustion (RWC) in the 11 S tates and the Di strict of Columbia that make up the MANE - VU region. Information for the OMNI anal ys is was obtained from: (1) The MANE - VU Residential Wood Combustion Emission Inventory published by MARAMA (July

2004 report), (2) Residential Energy Consumption Surveys pub lished by the E IA, (3) the National Emission Inventory published by

the EPA , (4) Simmons Marketing Research reports, and (5) American Housing Survey s for the United States published by the U.S. Department of Commerce and the U.S. Department of Housing and Urban Development. In addition, the results of three RWC surveys at the S tate - 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 sur vey s to the S tate level for three S tates. These were the: (1) 1995 Delaware Fuelwood Survey , (2) Residential Fuelwood Use in Maine, Results of 1998/1999 Fuelwood Survey , and (3) Vermont Residential Fuel Wood Assessment for 1997 - 1998. To facilitate unders tanding of the cost effectiveness analy ses 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 catal yt ic, and certified non - catal yt ic 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 primaril y rel y on radiant and convection heat transfer, in contrast to centralized heating s ys tems such as warm - air furnaces or boilers which utilize heat distribution sy stems to heat multiple rooms. Fireplace inserts are essentially wood stoves that are designed to be inserted into an existing fireplace cavity . Be cause of the heat transfer shielding effect of the fireplace cavity

and the fact the majority of existing fireplace chimneys are against an outside wall, their heating efficiency is less than a similar freestanding woodstove. Many fireplace inserts have f

ans to facilitate transfer of heat from the portion that is inside the fireplace cavity . Both freestanding cordwood stoves and fireplace inserts rel y on a natural draf t using room air for combustion and the venting of exhaust through the chimney to the atmosphere. Though theAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9 - 2 majority of cordwood heaters use room air for combustion, some insert installations, such as in mobile homes, require the use of outside air for combustion. **Uncertified Conventional Cordwood -**  **Fired Stoves and Fireplace Inserts** Uncerti fied cordwood fired stoves and fireplace inserts include units manufactured before the 40 CFR Part 60, Subpart AAA New Source Performance Standard (NSPS) July 1, 1990 certification requirement, and currently or recentl y manufactured exempt units which operate similarly to some old pre - EPA certification units. **NSPS Certified Catalytic Cordwood -**  **Fired Stoves and Fireplace Inserts** Certified catal yt ic units pass the exhaust through a catal ys t to achieve emission reductions. Generally , a coated ceramic honeycomb cataly st is located inside the stove where the incompletely

combusted gases and particles ignite and are combusted further, thus reducing air emissions and increasing combustion overall efficiency . **NSPS Certified Non -**  **Catalytic Cordwood -**  **Fired Stoves and Fireplace Inserts**  Certified non - catal yt ic stoves and fireplace inserts rely on design features to reduce air emission and increase efficiency . They generally rely on the introduction of heated secondary air to improve combustion, as well as firebox insulation, and baffles to produce a longer, hotter gas flow path, as well as other design features to achieve low emissions and higher efficiency . **Pellet Stoves and Fireplace Inserts** Analogous to cordwood stoves and fireplace inserts, pellet stoves and firepl ace inserts are considered room heaters. They burn pellets generally

made from sawdust, although there has been, and continues to be, research into utilizing other biomass fuels to make pellets. Combustion air is drawn from the room for most models, and exhaust is vented outdoors. Some pellet appliances use outside air for combustion. Pellet stoves and inserts require the use of electric motors to power the combustion air and heat transfer fans and the pellet - feeding auger. Modern pellet units use electronic sensors and controls. Pellets are introduced into the hopper, and the auger continuously feeds a consistent amount of pellets into the firebox. The feed rate is controlled electronicall y by a feed rate setting selected by the user. There are two b asic designs: bottom - feed and top - feed models. Pellet units have a high efficiency and low emissions due to the use of the electric auger and fan that produce uniform and controlled combustion conditions. Some units are certified by the NSPS process and some are not. The performance of the certified and uncertified models are similar. What is considered b y most as a “loop - hole” in the NSPS regulations essentiall y allows certification to be bypassed. **Wood -**  **burning Fireplaces without Inserts** Fireplaces w ithout inserts include manufactured units (often referred to as “zero - clearance” fireplaces) and site - built masonry units operated both with and without glass doors. Combustion air is drawn from the natural draft created b y fire, and that same draft vents the exhaust gases through the chimney . Fireplaces without inserts have low efficiencies due to the large amount of heated room air that is exhausted out of the chimney from the draft. Many

fireplaces without inserts are not used in a given year, some are used for aesthetic purposes and some are used forAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9 - 3 heating. Those that are used for heating are almost always used for secondary heating purposes and not primary

heating due to their low efficiency and lack of heat transfer capabilities. Manufactured wax/fiber firelogs are often used as a fuel in them with about 30% of fireplace users nationwide claiming that they use wax/fiber firelogs some of the time. Most fireplaces are wall - mounted, however, this category also includes some free - standing models. **D irect Vent Gas Stoves and Fireplace Inserts (LPG and Natural Gas)**  Direct vent gas stoves and inserts are sealed units that draw their combustion air from, and vent their exhaust to, the outside air. Venting can be extended vertically or horizontally

out of the home. A common ty

pe of venting is coaxial, which has the exhaust pipe contained within the air inlet pipe, so the temperature of the combustion air is raised, and the temperature of the exhaust is lowered, creating more efficient combustion. Itsh ould be noted that natural gas is not readil y available in all locations, however LPG may be available for use . **Vent -**  **Free Gas Stoves and Fireplace Inserts (LPG and Natural Gas)** Vent - free gas stoves and inserts receive their combustion air from the room i n which the unit is placed, and all of the products of combustion are exhausted into the room as well. The high efficiency of vent free units is due to the fact that the heat produced is kept in the room. Vent free gas stoves and inserts have a maximum h eat 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. Itis important to note that vent - free natural gas and LPG sto ves, 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 b y moisture created from their use, as combustion gases are no t vented to the atmosphere. If the devices are used prudentl y, these problems are reduc ed. Their appropriate role is for aesthetics and minor secondary heating. Just as with direct vent gas stoves and fireplace inserts, LPG can be used as an alternative where natural gas is not readil y available. **B -** **Vent Gas Stoves and Fireplace Inserts (LPG and Natural Gas)** B - vent gas stoves and inserts draw their combustion air from the room, and exhaust is vented outdoors. These units use a draft hood for the proper venting of exhaust. B - vent gas stoves and inserts have lower efficiency than direct vent due to the fact that already heated room air is used as combustion air, which is then exhausted to the outdoors, taking heat away from the room. **OMNI Study Summary** In the OMNI study, the amount of fuel consumed by RWC devices was considered the measure of activity . Activity

data w ere provided by

individual appliance typ e b y S tate and for the total MANE - VU region. The activity study conducted by

OMNI showed that the re we re approximately

6.4 million tons of fuel burned in 2002 by RWC devices in the MANE - VU region. The majority of RWC combustion was located in New York (1.9 million tons of fuel burned) and Penns yl vania (1.4 million tons of fuel burned).Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9 - 4 OMNI then compiled an emissions inventory by county , by S tate, and for the entire MANE - VU region for the 2002 base year. The dry mass of fuel (activity) for cordwood, pellets, and manufactured wax/fiber firelogs compiled in the activity task was multiplied by

the appl icable emission factor in the units of mass air pollutant per mass of dry fuel. The emission factors were obtained by

reviewing and averaging (if multiple sources were available) data obtained from available reports and publications. PM and VOC (an ozone precursor) are the main criteria pollut ants of concern for RWC and non attainment areas. The OMNI emissions inventory reported that there were 92,470 tons of total PM emissions and 87,741 tons of VOC generated from RWC devices in the MANE - VU region durin g the base ye ar (2002) . It should be noted that this analy sis assumed that PM 10 was equivalent to PM. The only emissions control efficiency , and control device information available is for PM 10 . We have therefore assumed that data for PM 10 are applicabl e to PM 2.5 . Table 9. 1 from the OMNI report summarizes measures for RWC RACM developed by EPA in EPA - 450/2 - 89 - 015. OMNI reported the RACM fall in three primary categories: (1) improvement of performance, (2) reducing the use of RWC devices, and (3) episo dic curtailment. The effectiveness in reducing RWC emissions and a related discussion of each of the various activities are also provided in Table 9. 1. In addition to the three primary categories for RWC RACM, the RACM document emphasizes the importance of public awareness in many RWC emission control program s and provides considerable information on the subject .Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9 - 5

**Table 9.**  **1 Summary o**  **f Measures Available f**  **or RWC RACM –**  **PM 10**  **Program Elements**  **Estimated Effectiveness**  **(%) Discussion**  **IMPROVEMENT OF PERFORMANC E**  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 unenforceab le: 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 i nstallation is inspected. Pellet stoves 90 Reduction in emissions from each new or existing conventional, uncertified RWC device replaced with a pellet stove. 75 Reduction in emissions from each new or

existing Phase II EPA certified RWC device replaced with a pellet stove. EPA Phase II certified RWC devices ~50 Reduction in emissions from each new or existing conventional, uncertified RWC device replaced with an EPA Phase II certified RWC device. Retrofit requirement <5 Reduction in emissions from eac h existing conventional, uncertified RWC device equipped with a retrofit catalyst or pellet hopper (to maximum when all existing uncertified RWC devices have retrofit devices installed). Accelerated changeover requirement ~50 Reduction in emissions from e ach existing conventional, uncertified RWC device replaced with Phase II certified device. 100 Reduction in emissions from each existing

conventional, uncertified RWC device removed and not replaced: requires existing device to be disabled and not resold . Accelerated changeover inducement ~50 Reduction in emissions from each existing conventional, uncertified RWC device replaced with Phase II certified device. 100 Reduction in emissions from each existing

conventional, uncertified RWC device removed an d not replaced: requires existing device to be disabled and not resold.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, 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 credit recognized for fireplace inserts, since inserts change use of fireplace from aesthetic to primary heat source, resulting in an increase in amount of wood combusted and higher overall emissions. Wood moisture <5 Reduction in total emissions from all RWC devices in the community/a irshed. 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 emis sions from all RWC devices in the community/airshed. **REDUCING USE OF RWC DEVICES** Availability of alternative fuels 100 Reduction in emissions from each RWC device removed from service and replaced with device using natural gas: recognize no mo re than 10% of RWC devices replaced under program with no additional incentives. Emission trading Com putation 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 ne w 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 ne w dw ellings 100 Reduction in emissions from new RWC devices purchased for installation in new dwellings. Regulat ory

ban on existing RWC devices 100 Reduction in emissions from each RWC device removed.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, 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 measures for RWC BACM developed by EPA in EPA - 450/2 - 92 - 002. As shown in Table 9. 2, the BACM fall into two primary categories: (1) integral measure s which are necessary for the success of a long - term RWC pollutant reduction programs but, b y themselves, are not adequate to provide long - term reductions and (2) flexible (long - term) measures to reduce, eliminate, or prevent increases in pollutant emissio ns for existing and/or new installations. With the exceptions of the device and upgrade offsets, the specific elements of the BACM are essentiall y those described in the RACM document with the various efficiencies listed in Table 9. 1 being applicable.

**Ta ble 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 F**  **lexible 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. De vice 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 ne w stove installations EPA certified, Phase II st oves or equivalent. 3. Changeover to low emitting device. 3 3. Restriction on number and density of new wood - burning stove and/or fireplace installations.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9 - 8

**Ta ble 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 F**  **lexible Measures that Reduce**  **Emissions from New and Existing**  **Installations 2**  4. Measures to improve wood burning performance:

- control of wood mo isture content

- weatherization o f homes with wood stoves

- educational opacity program 4. Requirement that new stove installations be low emitting.

1 Integral measures are regarded as critical for the success of a RWC control program, but by themselves are not intended to result in long - term attainment of the 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 model units that perform better in the field than the class collectively (an example might include masonry heaters, uncertified pellet - fueled devices, and wood f ired gasification centralized heating systems). 4 Offsets are intended to achieve emission reductions, when retiring (device offset) or changing - out (upgrade offset) conventional stoves, greater than the emissions increase resulting from new stove installations. Table Reference: U.S. EPA, 1992, Technical Information Document for Residential Wood Combustion Best Available Control Measures , Research Triangle Park, NC, EPA - 450/2 - 92 - 002. OMNI reported that the RWC RACM and BACM have been the basis for PM 10 inn ovative strategies implemented in various western States and in local jurisdictions and have also been, in large part, the basis for a number of western State and their local RWC regulations. As part of these strategies, strict particulate emission standards have been developed which will take effect in 2008. The OMNI report states that the Washington State standard is notable among State and local regulations for residential wood burning devices . Washington State has implemented more stringent standards for residential wood burning devices, so devices installed in Washington State must be certified to the more stringent standard. This has affected the stove market because many U.S. certified stove manufacturers choose to have their appliances certified to the more stringent Washington State standard, unless the manufacturer can not or does not choose to test to the tighter standard. Discussions with EPA indicate that most manufacturers are choosing to design and sell units that meet the Washington State standards of 4.5 g/hr for non catal yt ic wood stoves and 2.5 g/hr for cataly tic wood stoves (personal communication with Mr. John Dupree of the U.S. EPA).Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, 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 Complia nce**  OMNI anal yz ed the cost effectiveness of five categories of widel y existing, older technology wood - burning devices. These are: (1) freestanding cordwood stoves, (2) cordwood - fueled fireplace inserts, (3) cordwood fireplaces (without inserts) used for heating purposes, (4) centralized cordwood heating s ys tems and (5) cordwood fireplaces used for aesthetic purposes. Table 9. 3 lists these five categories with the available, improved technology replacement, installation scenarios, and fuel switching alter natives that would reduce particulate and VOC emissions. OMNI noted that w ood resources are abundant and widely utilized as fuel, and heating is essential due to the climate of the region. The cost to households of any regulatory

program mandating accept able heating practices is an important consideration. Likewise, the cost to households of an y voluntary program is paramount for its success. The cost effectiveness of all reasonable scenarios for the replacement, modification or alternative fuel use for older existing, high em ission wood - burning appliances wa s provided in the OMNI report for regulators and policy makers charged with the task of specifically lowering particulate and VOC emissions fro m residential wood combustion. The tables provided in this chapter based on the OMNIreport 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 t echnology

centralized cordwood heating s ys tem, the best current option in terms of cost among the pellet, natural gas, and LPG options, is natural gas (assuming natural gas is available). Similarly , for wood - burning fireplaces used for aesthetics, manufac tured wax/fiber firelogs offer the lowest cost per unit mass of air pollutant reduction. The cost effectiveness of each option is dependent on the costs of the new equipment and the cost of required fuels. The costs presented in the tables in this chapte r we re the most current information available as of the date of th e OMNI report. Estimates of costs per ton of reductions in the tables in this chapter are specific to the MANE - VU region because they reflect the estimated usage of various devices in this region.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9 - 10

**Table 9.**  **3 Improved Technologies a**  **nd Fuel Alternatives Existing Cordwood Device**  **High Technology Replacement, Installation or Alternative Fuel**  Uncertified Freestanding Cordwood Stove Replacement with Certified NSPS Non - Catalytic Cordwood Stove Replacement with Certified NSPS Catalytic Cordwood Stove Replacement with Pellet Stove Replacement with Gas Stove

– natural gas (B vent, direct vent) Replacement with Gas Stove

– LPG (B vent, direct vent) Uncertified Cordwood Fireplace Insert Replace me nt with Certified NSPS Non - Catalytic Cordwood Insert Replacement with Certified NSPS Catalytic Cordwood Replacement with Pellet Insert Replacement with Gas Insert

– natural gas (B vent, direct vent) Replacement with Gas Insert

– LPG (B vent, dir ect vent) Cordwood Fireplace without Insert Used for Heating Installation of Certified NSPS Non - Catalytic Cordwood Insert Installation of Certified NSPS Catalytic Cordwood Insert Installation of Pellet Insert Installation of Gas Insert

– natural gas (B - vent, direct vent) Installation of Gas Insert

– LP G (B - vent, direct vent) Cordwood Fireplace Used for Ae sthetic Purposes Installation of Gas Log Set

– natural gas (vented and vent free) Installation of Gas Lo g Set

– LPG (vented and vent free) W ax/Fiber Firelog Fuel Centralized Cordwood Heating Sy stem Pellet Furnace or Boiler Gas Furnace or Boiler

– natural gas Gas Furnace or Boiler

– LPG OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and Documentation for Residential Wood Combustion in the MANE- VU Region . Project funded by Mid - Atlantic Regional Air Management Association, Inc., December 19, 2006.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9 - 11 Table 9.4 from the OMNI report demonstrates the cost effectiveness of replacing three typ es of cordwood stoves and fireplaces with devices that emit less PM. Table 9.5 from the OMNI report demonstrates the impact on cost effectiveness of the same replacements on VOC reductions. The cost effectiveness tables are in reference to the replacement of an existing RWC device, and do not include new construction. In Tables 9.4 and 9.5, if the total annual cost of the improved technology and alternative fuel replacement or installation is less than the total annual cost of the existing device, and there is corresponding pollutant reduction after installation or replacement, then there is no cost for the pollution reduction, and the cell is marked as “**”. The replacement options for which there is no cost may

actuall y represent cost savings, and thus are the most cost effective options for replacement. **Table 9.**  **4 PM**  **Redu ction Cost Effectiveness f**  **or Replacement o**  **f Existing Uncertified**  **Freestanding Cordwood Stove/Insert and Cordwood Fireplace w/o Insert for Heating Existing**  **Cordwood Device**  **Certified**

**NSPS Non**  **** **Catalytic Cordwood**  **Stove Certified** 

**NSPS Catalytic**  **Cordwood Stove**  **Pellet**

**Stove Gas** 

**Stove**   ** NG,** **B Vent Gas** 

**Stove**   ** NG,** **Direct Vent**  **Gas**

**Stove**   ** LPG,** **B Vent Gas** 

**Stove**   ** LPG,** **Direct Vent**  **PM Reduction Cost Effectiveness ($/ton)** Uncertified Freestanding Cordwood Stove 1,170 3,300 8,960 5,350 3,530 12,600 9,760 Uncertified Cordwood Fireplace Insert   5,180 1,910 **  8,980 6,040 Cordwood Fireplace w/o Insert for Heating 3,880 5,670 8,330 ** ** 1,880 695 OMNI Environmental Services, Inc. Task 6, Technical Mem orandum 4 (Final Report), Control Analysis and Documentation for Residential Wood Combustion in the MANE- VU Region . Project funded by Mid - Atlantic Regional Air Management Association, Inc., December 19, 2006. ** N o cost for the pollution reduction. Tables 9.4 and 9.5 indicate that OMNI estimated that in the MANE - VU region there are several options for reducing emissions from two of the above ty pes of fireplaces that would reduce emissions at essentially

no cost, due to fuel cost savings.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9 - 12 **Table 9.**  **5 VOC**  **Re duction Cost Effectiveness**  **for Replacement o f Existing**  **Uncertified Freestanding Cordwood Stove/Insert and Cordwood Fireplace w/o Insert for Heating**  **Existing Cordwood**  **Device Certified** 

**NSPS Non**   ** Catalytic** **Cordwood Stove**  **Certified**

**NSPS Catalytic**  **Cordwood Stov**  **e Pellet** 

**Stove Gas** 

**Stove**   ** NG,** **B Vent Gas** 

**Stove**   ** NG,** **Direct Vent**  **Gas**

**Stove**   ** LPG,** **B Vent Gas** 

**Stove**   ** LPG,** **Direct Vent**  **VOC Reduction Cost Effectiveness ($/ton)** Uncertified Freestanding Cordwood Stove 1,260 2,960 7,740 4,940 3,260 11,800 9,130 Uncertified Cordwood Fireplace Insert   4,480 1,760 **  8,410 5,640 Cordwood Fireplace w/o Insert for Heating 7,900 10,400 13,200 ** ** 3,090 1,140 OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and Documentation for Residential Wood Combustion in the MANE- VU Region . Project funded by Mid - Atlantic Regional Air Management Association, Inc., December 19, 2006. ** N o cost for the pollution reduction. Table 9.6 presents the cost effectiveness in terms of dollars per ton of PM reduction and VOC reduction for replacement of an existing centralized cordwood heating s ys tem with three available technologies. The cost effectiveness tables are in reference to the replacement of an existing RWC device, and do not include new con struction. The most cost effective option is replacing the existing sy stem with a natural gas furnace or boiler. This option is not feasible in areas that do not have access to natural gas, and the increase in costs associated with using LPG is significant. **Table 9.**  **6 Reduction Cost Effectiveness f**  **or t**  **he Replacement of a**  **n Existing Centralized Cordwood Heating System**  **High Technology Replacement, Installation or**  **Alternative Fuel PM Reduction**  **Cost Effectiveness ($/ton)**  **VOC Reduction Cost Effectiveness**  **($/to n)**  Pellet Furnaces and Boilers 7,810 17,200 Gas Furnaces and Boilers

– Natural Gas 3,030 7,150 Gas Furnaces and Boilers - LPG 9,370 23,100 OMNI Environmental Services , Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and Documentation for Residential Wood Combustion in the MANE- VU Region . Project funded by Mid - Atlantic Regional Air Management Association, Inc., December 19, 2006. Table 9.7 presents the cost effectiveness in terms of dollars per ton of PM reduction and VOC reduction fo r the addition of a gas log set or use of wax/fiber firelogs in an existing fireplace withAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, and Four Factor Analysis Chapter 9: Residential Wood Combustion Page 9 - 13 no insert. Burning wax/fiber firelogs in the existing fireplace is, by far, the most cost effective option for reducing emissions of PM and VOC. **Table 9.**  **7 Polluta**  **n t Reduction Cost Effectiveness for the Addition o**  **f a Gas Log Set or Use**  **o f Wax/Fiber Firelogs**  **in a n Existing Fireplace**  **w/o Insert Used f or Aesthetics** 

**Pollutant Pollutant Reduction Cost Effectiveness ($/ton)** 

**Vent -**  **Free Gas Log Set**  **- NG**  **Vented Gas**

**Log Set -**  **NG Vent**  **- Free Gas** 

**Log Set -**  **LPG Vented** 

**Gas Log**   ** LPG** **Wax/Fiber**

**Firelog Fuel** PM 27,100 29,900 29,400 34,100 2,530 VOC 43,900 48,500 48,300 56,600 5,110 OMNI Environmental Services, Inc. Task 6, Technical Memorandum 4 (Final Report), Control Analysis and Docume ntation for Residential Wood Combustion in the MANE- VU Region . Project funded by Mid - Atlantic Regional Air Management Association, Inc., December 19, 2006. OMNI presented no cost - effectiveness summary for other RWC control measures such as described in E PA’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 RWC are existing technology , the time necessary

for compliance would depend on the amount of time it would take to regulate the sources and establ ish compliance deadlines. The Feasibility Assessment of a Change out/Education Progra m for Residential W ood Combustion from the Canadian Council of Ministers of the Environment suggests a phased approach for national implementation. A phased approach will enable the program to evolve over time and benefit from lessons learned in the earl y stages of the program. Phasing also reflects the reality that building awareness and changing behavior is a long - term investment. The approach that this report proposed had two phases. The first phase (2005 - 2006) focused on building a base for support and understanding around RWC in a single province. The second phase (2007 and beyond) and full roll - out involved the realization of independent, arms length management of public education and outreach b y all stakeholders throughout Canada. The main steps for this phase included:

 Implementation of national regulation as soon as possible (i.e. 2008 - 2009);  Full operational capacity across Canada;  Funding to come from multiple sources (i.e. nationwide partnerships with the insurance, financial, and utilities industries);  Movement of various groups from being target audiences to becoming key players in designing and delivering woodstove change - out/public education campaigns; and  Multi - stakeholder involvement and shared leadership (governments together with bus iness and industry , communities, and non - governmental organizations).Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, 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 benefits of biom ass combustion and the minimal acid gas emissions (acid precipitation impacts) from wood combustion are strong environmental advantages. Further, the fact that wood is a domestic renewable energy source and the fact that the cost of natural gas, propane, and fuel oil have a history of rising together have been responsible for the increase in the use of RWC. For example, several S tates are encouraging the use of renewable energy

sources such as wood for heating purposes . The Canadian Council of Ministers of the Environment study estimated that the increase in combustion efficiency

associated with a switch out to a more efficient stove would save on average more than one cord of wood per stove per heating season. Any mandatory change out program should be mindful that even with assistance, woodstove change out programs will impact families that are least able to bear the burden of additional costs. Voluntary

programs do not impose this economic burden on families less able to bear associated costs. **Remain ing Useful Life Of The Source**  From information obtained from a scoping study that was prepared for Environment Canada in 1997, ( Gulland Associates Inc., 1997) the durability of low emission stoves has improved considerabl y . P remature stove degradation is not viewed as a problem. In most new stoves today , vulnerable parts can be replaced , and manufacturers now use more heat - resistant materials such as ceramics and stainless steel. The performance and durability of cataly tic stoves has also improved throu gh better design and use of materials. The useful life of a wood stove catal yt ic element is estimated to be 9,000 to 12,000 hours, or three to five ye ars of use, depending on heating demand, user skill , and degree of maintenance provided. The best mechani sm 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 ye ars (per industry references) , over which time the incremental cost of advanced technologie s 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 est ablished as manufacturers seek to fill the low cost market niche formerl y filled by conventional stoves; that is, plain, unadorned styling and lacking additional features such as ash pan and large glass door panel. ( Gulland Associates Inc., 1997) Many wo odstove manufacturers have chosen to manufacture products at a reasonable cost that meet more stringent emissions standards such as those in Washington State (personal communication with Mr. John Dupree of EPA) . Implementation of stricter emissions standards in additional states or regions will likely increase the competition to produce these woodstoves at even more reasonable prices.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Op tions, 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 Documen tation for Residential W ood Combustion in the MAN E- VU Region . Project funded b y Mid - Atlantic Regional Air Management Association, Inc., December 19, 2006. Headquarters, U.S. EPA. Personal communication regarding the number of new residential wood burnin g 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 W ood Combustion Emission Control Measures , Re search Triangle Park, NC, EPA - 450/2 - 89 - 015. U.S. EPA, 1992, Technical Information Document for Residential W ood Combustion Best Available Control Measures , Research Triangle Park, NC, EPA - 450/2 - 92 - 002. U.S. EPA, 1993, PM

- 10 Innovative Strategies: A Sourcebook for PM - 10 Control Programs , Research Triangle Park, NC, EPA - 452/R - 93 - 016. The Canadian Centre for Pollution Prevention, CULLBRIDG Marketing and Communic ations and Action - Environment, Feasibility Assessment of a Change - out/Education Program for Residential W

ood Combustion, A Step - by- Step Approach to a National Program Aimed at Reducing Emissions from Residential W ood Combustion . September 20, 2004. Gulland Associates Inc., Scoping Study: Reducing Smoke Emissions From Home Heating With Wood . Prepared for Environment Canada, March 31, 1997. Environment Australia (2002). Technical Report No. 4: Review of Literature on Residential Firewood Use, Wood

- Smoke and Air Toxics . 49p. Report available on the Environment Australia website http://ea.gov.au/atmosphere/airtoxics/report 4/exec - summary .html.This page left blank intentionallyAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion

– Outdoor Wood - Fired Boilers Page 10 - 1 **CHAPTER 10**  **RESIDENTIAL WOOD COMBUSTION -**  **OUTDOOR WOOD**  **- FIRED**  **BOILERS BACKGROUND**  Outdoor wood - fired boilers are used in the Northeast United States, and their use is increasing as more traditional heating fuels (heating oil, natural gas) are becoming more expensive. NESCAUM (2007) estimates that the sale of outdoor wood - fired boilers is increasing b y 25 - 50% annually . N ationwide there are between 155,000 and 2 00,000 boilers in service (Personal communication with Lisa Rector, NESCAUM) . If the sales trends continue, NESCAUM estimates that there may

be up to 500,000 boilers nationally by 2010. Outdoor wood - fired boilers are used for heating and providing hot water for both individual homes and for “mini - district heating” (Woodheat.org 2007). Additional uses of outdoor wood fired boilers include heating swimming pools and greenhouses. Outdoor wood - fired boilers are ty picall y located in sheds that are located ne ar buildings. Heated water is conveyed through underground or insulated pipes. Even though outdoor wood - fired boilers may be economical solutions to home heating and hot water production, they

contribute significantl y to air pollution. Outdoor boilers e mit so much smoke they

have been banned by some local jurisdictions (Woodheat.org 2007). NESCAUM (2007) estimates that the average fine particulate emissions from one outdoor wood - fired boiler are equivalent to the emissions from 22 US Environmental Prote ction 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 infor mation was calculated by NESCAUM using data from tests conducted on outdoor wood - fired boilers for EPA (EPA 1998 a). (Guldberg 2007) used data from 56 outdoor wood - fired boilers tests conducted by EPA in 1995 and 1999 , and estimated that outdoor wood - fired boilers emit 1.44 pounds of PM per MMBTU heat input. In comparison, the EPA estimate (EPA 1998b ) for PM from residential fuel oil combustion is 0.4 pounds of PM per thousand gallons of fuel combusted . Assuming a heating value of 140 MMBTU per thousand g allons of fuel oil, the PM emission factor is 0.003 pounds of PM per MMBTU heat input for residential fuel oil combustion. Similarly , for residential natural gas combustion, (EPA 1998c ) assuming a natural gas heating value of 1,020 BTU per standard cubic foot, the PM emission factor is 0.002 pounds per MMBTU heat input. Based on these emission factor estimates, and strictly on the basis of heat input, outdoor wood fired boilers emit rough ly 500 times as much PM as oil - fired residential furnaces and 750 ti mes as much PM as natural gas - fired residential furnaces based on the low - range estimate of PM emissions from outdoor wood - fired boilers . Based on the upper range of the PM emissions estimate from outdoor wood - fired boilers , the y emit roughly 1,000 times as much P M as oil - fired residential furnaces and 1,500 times as much PM as natural gas - fired furnaces. Heav y 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 nearl y impossible due to the coolingAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion

– Outdoor Wood - Fired Boilers Page 10 - 2 effect that the jacket has on the firebox. The flaming combustion of wood cannot occur below about 540 C ( 1,000 F) , so the steel s urfaces of the water jacket backed up by water at approximately 65 C (150 F) chill and quench the flames well before complete combustion can occur. In addition outdoor wood - fired boilers smoke heavily due to their cyclical operating pattern. When the temperature of the water within the boiler falls below a set point, its combustion air damper opens and/or a small fan forces combustion air into the firebox. Once the water is heated back to the upper set point, the fan is turned off and/or the combustion air damper closes. During the off cycles the fire smolders and much of the smoke condenses as creosote on the cold steel internal surfaces. When the thermostat again calls for heat and incoming combustion air rekindles the fire, the heat ignites the creos ote clinging to the boiler walls. This leads to an increase in emissions that accompanies the poor combustion in the firebox. Outdoor wood - fired boilers are also sometimes not sized appropriately for the house that they

are intended to heat. For example , an oversized boiler will tend to run in the smoldering phase longer than in the full out burn phase, thereby producing more smoke. It has been suggested that excessive production of emissions by outdoor wood - fired boilers is associated improper installation of the boiler or the use of fuels not designed to be combusted in the boiler (personal communication with Peter Guldberg, Tech Environmental). Additionally , Guldberg, 2007 suggests that emissions from outdoor wood - fired boilers are comparable to othe r wood - fired combustion devices in terms of lbs/MMBTU heat generated. In any case, Guldberg, 2007 indicates that outdoor wood - fired boiler manufacturers have worked with EPA to develop a voluntary Outdoor Wood - fired Heater Program with a Phase I emission target of 0.6 lb/MMBTU . According to Guldberg, 2007 manufacturers will offer the outdoor wood - fired heaters qualified to achieve the Phase I standard later in 2007. **NESCAUM’s Model Rule** On January

29, 2007, NESCAUM made available its “Outdoor Hydronic H eater Model Regulation.” The model rule is designed to serve as a template to assist S tate and local agencies in adopting requirements that will reduce air pollution from outdoor wood - fired boilers. The model rule was developed in cooperation with a numb er of S tates and EPA. The model rule has provisions for:

 Critical definitions,  Emission standards,  Test method procedures,  Certification process, and  Labeling requirements. The model rule contains a single method for regulating new units with respect to the critical elements and contemplates that S tates may propose alternative approaches for other provisions. It also provides alternatives for states to consider for regulating previousl y i nstalled units (NESCAUM 2007).Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion

– Outdoor Wood - Fired Boilers Page 10 - 3 NESCAUM’s model rule sets standard s for particulate matter (PM) emissions by phases for residential and commercial boilers. The PM standards for both boiler types are identical. Phase I call s for a PM emission limit or 0.44 pounds per million BTU heat input. This standard would have to be met b y 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 fi led a regulation on outdoor wood - fired boilers with the S ecretary of State and the Legislative Committee on Administrative Rules . The rule legally went into effect on April 27, 2007, and adopt s NESCAUM’s model rule Phase 1 PM emi ssion 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.or g . (Etter, personal communication) This section of this document addresses the four factor analysis which includes the following elements: cost of compliance, time necessary for compliance, energy

and non - air impacts, and remaining useful life of the s ource. **FOUR FACTOR ANALYSIS OF POTENTIAL CONTROL SCENARIOS FOR OUTDOOR**  **WOOD -**  **FI RED**  **BOILERS Cost of Compliance**  Outdoor wood - fired boilers are priced according to their size (heat output). For example, Northwest Manufacturing sells a line of outdoor wood - fired boilers that ranges in price from $4,295 for a boiler that will heat a 2,000 square foot house to $12,995 for a boiler that can heat up to 20,000 square feet. Similarly , Hud - Son Forest Equipment has a line of outdoor wood - fired boilers that range in price from $6,095 for boiler that can heat a 2,000 square foot house to $7,795 for a boiler that can heat up to 10,000 square feet. There are currently

onl y a few outdoor wood - fired boiler manufacturers whose products would meet the 2008 NESCAUM phase I standard of 0.44 lb/MMBTU . NESCAUM estimates that there are “several units currentl y on the market that can meet this standard.” In addition, NESCAUM estimates that more stringent air standards that it proposed should come into compliance in 2010 would c urrentl y onl y be met by one unit. Consequently, manufacturers of outdoor wood - fired boilers would have to invest money into research and development in order to manufacture boilers that would meet NESCAUM’s model standards. MACTEC contacted an outdoor wo od - fired boiler manufacturer to determine cost increases due to the NESCAUM rule. The boiler manufacturer was not able to provide estimated cost increases necessary to manufacture boilers meeting the NESCAUM model rule standards (personal communication wi th Central Boiler, Inc.). MACTEC also investigated the costs of replacing the outdoor wood - fired boilers with heating oil - fired furnaces and boilers. We determined that the capital cos t 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 Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion

– Outdoor Wood - Fired Boilers Page 10 - 4 $1,800 (Alpine Home Air 2007). Therefore, oil - fired boilers and furnaces can be substantiall y 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 b y households in the Northeast. It was estimated that households use approximately

865 gal/yrof fuel oil (STAPPA - ALAPCO 2006). Therefore, the annual average heating cost using fuel would c urrentl y be approximately $2,100 (assuming a fuel oil price of $2.4 0 /gal). The University of Wisconsin Solid and Hazardous Waste Education Center (2007) estimates that it would take only 4 full cords of oak firewood to heat a house per year. At approximately

$200/cord (Boston.com 2004), this equates to an annual fuel cost of $800/year. Consequently , the annual cost for firewood is $1,300 less than the cost of distillate fuel oil. Additionally , man y operators of outdoor wood boilers have access to a free supply of firewood for the boiler, thus the only fuel cost to these operators is the time, effort, and expense associated with gathering the wood and cutting it for use in the outdoor wood - fired boiler . Assuming the average household use of 865 gal/yrof fuel oil, and a fuel oil heating value of 140 MMBTU per thousand gallons, the annual heat input required is 121.1 MMBTU. The emission factors for residential fuel oil combustion, natural gas combustion, and wood combustion in outdoor wood - fired boilers are 0.003, 0.002, and 1.5 to 3.1 pounds of PM per MMBTU heat input respectivel y . 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 woul d be 0.2 pounds, and the emissions from the outdoor wood - fired boiler would be from 180 to 380 pounds. The cost of replacing an outdoor wood - fired boiler with an oil - fired furnace or boiler is estimated to be from $1,560 to $3,825 (Alpine Home Air 2007). I f the capital cost of the oil - fired furnace or boiler is spread over ten years, the annual ized 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 suppl y, or must purchase the wood by the cord. Based on these estimates, the PM cost effectiveness of replacing an outdoor wood - fired boiler with an oil - fired furnace or boiler would be from $1,700 to $13,000 per ton of PM reduced. The costs for replacement of outdoor wood - fired boilers with natural gas - fired furnaces or boilers have not been quantified. **Time Necessary for Compliance** Outdoor wood - fired boilers have been in operation for app roximately the last 15 years (p ersonal communication with P. Etter from Vermont Air Pollution Control). Consequently , the average age of outdoor wood - fired boilers is not known. On at least one occasion, a boiler vendor opted to go out of business rather than honor 5 - year warranties (personal communication with J. Gulland from OutdoorHeat.org). If States pass a rule similar to NESCAUM’s and existing boilers are grandfathered, only new boilers would be required to meet the more stringent standards. In th e section on residential heating, it was estimated that the average useful life of a residential boiler is between 18 - 25 years. Well manufactured outdoor wood - fired boilers may have similar useful lives. Therefore, new boilers meeting more stringent PM e missions standards would be phased in slowly as older boilers are replaced. Replacement of wood - fired boilers with oi l - fired furnaces or boilers could occur on a very quick schedule. The number of residential boiler/furnace manufacturers in the United S t ates isAssessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion

– Outdoor Wood - Fired Boilers Page 10 - 5 indicative of the fact that there is an ample suppl y of manufacturers. Although it is possible for outdoor wood - fired boilers to be replaced quickl y, realistically , most of these units have been installed within the past 15 years. Since they are designed to last for approxi mately 20 years, operators of the outdoor wood - fired boilers would likely be reluctant to replace them immediately . **Energy and Non -** **Air Impacts** Wood is a renewable resource that is plentiful in the United States Northeast. The increased use of outdoor wood - fired boilers would lead to an increase in the amount of firewood that is combusted in the US Northeast on an annual basis. Alternativel y, tighter rules regarding the PM emissions from outdoor wood - fired boilers may lead to a decrease in their use, which would make more firewood available for use in wood stoves and fire places. A move away from wood fired boilers would increase the demand on heating fuels such as heating oil, propane, and potentially

coal or natural gas. The increased use of outdoor wood - fired boilers may have a variety of non - air impacts on the environment, especially

on forest and water resources. The potential impacts are outlined below. Nuisance Smoke : Outdoor wood - fired boilers typ ically have very short stacks, and are prone to smoke. The short stacks oftentimes prevent proper mixing of the smoke and soot with the surrounding air, thereb y creating nuisance smoke problems for surrounding houses or co mmunities (Michigan DEQ 2007). Water : In creased 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 ecosy stems that are integral to rivers and streams. Soils : In creased logging may impact soils in many

way s. For example, heavy machinery

used to fell and process trees may lead to rutting and compaction of the soil, which in turn leads to higher erosion and/or altered vegetative regrowth. Wildlife : Increased logging may put pres sure on existing wildlife populations in the US Northeast b y al tering their critical habitat. Threatened and Endangered Species : Increased logging in Northeast may impact threatened and endangered species through habitat destruction or alteration. **Remai ning Useful Life of the Source**  The useful life of outdoor wood - fired boilers is approximately 20 years, which is also very close to the useful life of other residential boilers (Etter, personal communication). In addition, Mr. Etter indicated that outdoo r wood - fired boilers have only been around for approximately 15 ye ars, therefore, most of the boilers that have been put into service are likely to remain there for at least the next five years.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion

– Outdoor Wood - Fired Boilers Page 10 - 6 **REFERENCES** EPA, 1998 a . Emissions from Outdoor W ood -Burning Residential Hot W ater Furnaces . EPA Publication Number EPA - 600/R - 98 - 017. EPA, 1998b. AP - 42 section 1.3. Fuel Oil Combustion . EPA, 1998c. AP - 42 section 1.4. Natural Gas Combustion . Etter, P., Vermont Department of Environmental Conservation, Air Po llution Control Division. Personal communication with Mr. Bernd Haneke, MACTEC Federal Programs, Inc., on March 9, 2007. Etter, P., Vermont Department of Environmental Conservation, Air Pollution Control Division. Personal communication with Mr. William Hodan, MACTEC Federal Programs, Inc., on July 3, 2007. Gulland, J., OutdoorHeat.org. Personal communication with Mr. Bernd Haneke, MACTEC Federal Programs, Inc., via E - mail on March 9, 2007 . Guldberg, P., Tech Environmental, Inc. Personal communicatio n with Mr. William Hodan, MACTEC Federal Programs, Inc. via E - mail on May 17, 2007. Guldberg, P. 2007. Outdoor W ood Boilers

– New Emissions Test Data and Future Trends . Presented at the 16th Annual International Emission Inventory Conference - Emission Inventories: “Integration, Analy sis, and Communications” Killeen, W. 2004. Firewood Shortage Reflected in Prices . Document obtained from the World Wide Web at: www.boston.com Michigan Department of Environmental Quality 2007. Outdoor W

ood Boiler and Air Quality Factsheet . Document obtained from the World Wide Web at: www.michigan.gov/deqair NESCAUM, 2006. Assessment of Outdoor W ood - fired Boilers . Document obt ained from the World Wide Web at: http://burningissues.org/outdoor - wood - boilers.htm NESCAUM, 2007. Outdoor Hydronic Heater Model Regulation . Document obtained from the World Wide Web at : http://burningissues.org/outdoor - wood - boilers.htm NESCAUM. Personal communication between Ms. L isa Rector and Dr . Art Werner, MACTEC Federal Programs, Inc., on June 6, 2007. STAPPA ALAPCO, 2006. Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options . Central Boiler, Inc. Personal communication between Mr. Rodney Tollefson and Mr. Bernd Haneke, MACTEC Federal Programs, Inc., on March 8, 2007.Assessment of Reasonable Progress for Regional Haze In MANE - VU Class I Areas

Methodology for Source Selection, Evaluation of Control Options, and Four Factor Analysis Chapter 10: Residential Wood Combustion

– Outdoor Wood - Fired Boilers Page 10 - 7 University

of W isconsin 2005. Using W ood as a Residential Heating Fuel: Issues and Options . Published by

the University

of Wisconsin Solid and Hazardous Waste Education Center, and downloaded from the World Wide Web at: uwm.edu/Dept/shwec/publications/cabinet/p2/outd oor wood firedboilers.pdf In formation on prices of furnaces and boilers were obtained from the World Wide Web using the following URLs: www.alpinehomeair.com ; www.hud - son.com/woodfurnaces.htm ; www.woodmaster.com/web.htm