MEMORANDUM

SUBJECT: CISWI E.O. 12866 Meetings

FROM: Toni Jones, U.S. Environmental Protection Agency

TO: Commercial and Institutional Waste Incinerators (CISWI) Rule Docket

This memorandum lists various stakeholder meetings with the Office of Management and 

Budget in response to the mandate of Executive Order 12866. Meeting materials and handouts 

are attached.

• Jane Luxton, Pepper Hamilton LLP on behalf of Treated Wood Council – 11/8/11 at 2:30 pm

• Tim Hunt, AF&PA – 11/9/11 at 4:00 pm

• Bryan Brendle, Portland Cement Association– 11/10/11 at 1:00 pm

• Peter Pagano, American Iron and Steel Institute – 11/15/11 at 11:00 am

• Gregory M. Carnrick, Gephardt Government Affairs – 11/16/11 at 4:30 pm

• Hal Shapiro, Akin Gump – 11/18/11 at 3:00

• Douglas Green, Venable LLP on behalf of NORA – 11/22/11 at 2:00 pm

• Lisa Jaeger, Bracewell & Giuliani on behalf of CIBO – 11/22/11 at 5:00 pm

• Tracey Norberg, Rubber Manufacturers Association – 11/23/11 at 2:00 pm

• William Turley, Construction Materials Recycling Association – 11/29/11 at 5:00 pm
 

November 18, 2011

Via email: chiggins@omb.eop.gov  

Ms. Cortney Higgins

Office of Information and Regulatory Affairs

The Office of Management and Budget

725 17th Street, N.W.

Washington, DC 20503

Re: Non‐Hazardous Secondary Materials – Executive Order 12866 Review of Forthcoming

EPA Proposed Rule: Standards of Performance for New Stationary Source and Emission

Guidelines for Existing Sources:  Commercial and Industrial Solid Waste Incinerator

Units: Reconsideration and Proposed Amendments

Dear Ms. Higgins:

The Treated Wood Council (TWC) appreciated the opportunity to meet with you and other

representatives of the Office of Information and Regulatory Affairs (OIRA), Environmental Protection

Agency (EPA), and other interested federal government offices on November 8, 2011, during the

interagency review of EPA’s forthcoming proposed rule on Non‐Hazardous Secondary Materials (NHSM),

which we understand will now be part of a new proposed rule on Commercial and Industrial Solid Waste

Incinerator Units (CISWI).  We have not, of course, seen the proposed rule, and accordingly base our

comments on the description of EPA’s intended rule that is contained in EPA Administrator Jackson’s

October 20, 2011 letter to Senators Wyden and Snowe.   

TWC reiterates that EPA’s authority over nonhazardous secondary materials extends only to

those that are discarded, under a line of binding court decisions, e.g., American Mining Congress v. EPA,

824 F.2d 1177 (D.C. Cir. 1987).  As discussed at our meeting, used treated wood has a long history of

legitimate use as a valuable fuel in combustion units.  Examples include creosote railroad ties and utility

poles treated with pentachlorophenol, which are in demand as valuable fuels.

For many years, contracts and arrangements have been in place for “takeback” of railroad ties

treated with creosote, which are valuable as a fuel because of their lower moisture content – compared

to virgin wood – and higher BTU value, a result of the fact that creosote is made from coal tar oil, which

increases the burning temperature of wood products treated with it.  An electricity‐generating plant in

central Pennsylvania was constructed specifically to burn creosote‐treated wood products, because of

this richer burning capacity.  Cogen plants in the MidWest and other parts of the country preferentially

choose to burn railroad ties and penta treated utility poles because of these favorable properties, and

1111 19th Street, NW 

Suite 800 

Washington, DC 20036 

Phone: (202) 463-2045 

Fax: (202) 463-2059 
paper mills throughout the country similarly seek treated wood biomass.  These market realities have

existed for many years, and have been recognized in comments submitted in EPA’s prior NHSM

rulemaking by states that have noted the appropriateness of treated wood products for boiler

combustion.  Further, EPA’s materials characterization paper on construction and demolition materials

acknowledges that treated wood is “in demand” for use as a fuel.   

The Administrator’s letter references three categories of nonwaste secondary materials that

EPA is likely to set forth in the proposed rule:  (1) traditional fuels such as virgin wood, (2) nonwaste

materials that have a track record of use as fuel, and (3) materials that are established as fuel on a case

by case basis, using the “legitimacy criteria” identified in EPA’s March 2011 final rule or “other

circumstances” that demonstrate that the materials are combusted as fuel.  One example that the letter

cites of the second category as nonwaste materials, is resinated wood.  Resinated wood includes

products that contain formaldehyde and organic solvents that were deliberately added to provide

properties useful for the product.  Treated wood is analogous, in that it consists of wood with chemicals

added as preservatives to make a useful product.  Just as resinated wood is regarded as a valuable

secondary material for combustion, the same is true of treated wood products.  When nonhazardous

treated wood products are combusted as fuel, they too are not discarded.   

Strong policy reasons support the view that these materials should not be viewed as wastes.  

Biomass, including treated wood, that is burned for fuel results in lower greenhouse gas (GHG)

emissions than combustion of comparable quantities of fossil fuels.  Barring treated wood from this

legitimate use will lead to the substitution of fossil fuels such as coal, oil, or natural gas and greater GHG

emissions.  In addition, misclassification of these materials as wastes will result in their diversion to

landfills, a less desirable option in EPA’s established hierarchy than reuse as a combustion fuel.   

For all these reasons, EPA should recognize that nonhazardous treated wood products are not

discarded when combusted for fuel.  EPA should not pursue a rule that upsets the longstanding use of

treated wood as a valuable boiler fuel and produces undesirable environmental outcomes.

       Sincerely,

              

       Jeffrey T. Miller

       President & Executive Director

cc: George Faison, EPA/OSWER (faison.george@epa.gov)

Bob Wayland, EPA/OAR (wayland.robertj@epa.gov)

Tom Gillis, EPA/OP (gillis.thomas@epa.gov)

Toni Jones, EPA/OAR (jones.toni@epa.gov)

David Cozzie, EPA/OAR (cozzie.david@epa.gov)

Dom Mancini, OMB/OIRA (dmancini@omb.eop.gov)

Glen Sheriff, CEQ (glenn_d_sheriff@ceq.eop.gov)

Kevin Bromberg, SBA/Advocacy (kevin.bromberg@sba.gov)

Bruce Rodan, OSTP (brodan@ostp.eop.gov)

Kevin Neyland, OMB/OIRA (kneyland@omb.eop.gov)

Sandra Levy, CEA (slevy@cea.eop.gov)

David Rostker, SBA/Advocacy (david.rostker@sba.gov )
   

Executive Summary 

Economic Impact of Pending Air Regulations on the U.S. Pulp and Paper Industry 

September 2011 

Findings

The costs of implementing Boiler MACT regulations, when combined with the anticipated 

costs of implementing other pending air regulations, would place at risk 36 mills and 20,541 

pulp and paper mill jobs nationally – 18 percent of the primary pulp and paper industry 

workforce. Those jobs losses would rise to 87,299 if jobs in the supplier and downstream 

industries and jobs associated with the re-spending of wages are figured into the equation. 

These 87,299 job losses would result in about $4 billion in reduced wages and some $1.3 

billion in lost state, local and federal taxes (including FICA taxes). 

Background

In March 2011, the Environmental Protection Agency (EPA) issued final rules establishing 

Maximum Achievable Control Technology for industrial boilers, commonly referred to as the 

Boiler and Incinerator MACT rules. Several other unrelated air regulations are also pending. 

They include but are not limited to Cluster MACT reopening, Pulp and Paper Residual Risk, 

and several National Ambient Air Quality Standard (NAAQS) revisions that directly or 

indirectly drive more stringent rules. 

Fisher International, authors of this report, conducted the economic and job impact analysis of 

the cumulative impacts of the final Boiler MACT rules and other pending air regulations under 

consideration by the EPA. Fisher International, a market leader specializing in market and 

economic data on U.S. paper mills, utilized its proprietary database of mill assets and cost-ofproduction to make its evaluations of potential job loss and mill closures. 

The compliance cost data used in the Economic Impact analysis are attributed to URS, a 

leading provider of engineering, construction and technical services. While this report uses 

the same methodology as was used in the 2010 Fisher International report on the proposed 

rules, the capital and operating costs of compliance to regulations were updated by URS, 

based on the latest available information. 

The focus of the Fisher International study was to quantify the likely impact of potential new 

air regulations on employment in U.S. pulp and paper mills. 

Methodology

Fisher International determined that the typical U.S. paper mill could, at most, absorb an 

average 12.5% increase in its cost of production before its free cash flow would be 

exhausted. Using information provided by URS, Fisher then determined mills that reached or 

exceeded the 12.5% threshold to be in jeopardy of closing. Finally, Fisher isolated the impact 

of Boiler MACT by determining whether the mills most at risk would not close if Boiler MACT 

were removed from the suite of pending air regulations. 
September 7, 2011

As most regulations require both capital and operating costs, a formula was devised to 

translate capital costs into operating costs by using an interest rate of 11 percent and a term 

of five years. This weighted average cost of capital was based on a 2010 survey of 

investment bankers and industry analysts. Further details regarding the cost analysis can be 

found in the report. 

Job Losses and Mills At Risk Associated with Boiler MACT and Air Regulations1

Mills At Risk Pulp and Paper

Mill job losses

Including jobs in other 

industries sustained by 

the mills 

Boiler MACT 36 20,541 87,299 

All Air Regulations2 79 38,060 161,755 

In brief, the Fisher findings suggest that the Boiler MACT regulations, considered along with 

the costs of other pending air regulations, would place at risk 36 mills and 20,541 pulp and 

paper mill jobs nationally (18% of the primary pulp and paper industry workforce). If jobs in 

the supplier and downstream industries and jobs associated with the re-spending of wages 

are figured into the equation, the job losses rise to 87,299. A multiplier effect of 4.25 was 

chosen based on a study by the Economic Policy Institute. AF&PA estimates that these 

87,299 job losses would result in about $4 billion in reduced wages and some $1.3 billion in 

lost state, local and federal taxes (including FICA taxes). 

According to URS, the total capital costs for the forest products industry from upcoming EPA air 

regulations are about $17 billion. The Fisher findings indicate that the entire suite of air 

regulations could place 79 pulp and paper mills in jeopardy of closing, resulting in the loss of 

38,060 pulp and paper mill jobs, or 33% of the primary pulp and paper workforce. If jobs in 

supplier industries and jobs associated with the re-spending of wages are also included, the 

jobs loss figure rises to 161,755. AF&PA estimates that these 161,755 job losses would result 

in $7.4 billion in reduced wages and some $2.5 billion in lost state, local and federal taxes 

(including FICA taxes). 

This new study, when compared to the 2010 study, shows that the final Boiler MACT rules 

place about 3,500 more jobs at risk than the proposed rule. This is due partly to the fact that 

many more boilers using biomass as a fuel will be treated as incinerators rather than boilers 

and subject to much more costly control technology. Overall, slightly fewer jobs are placed at 

risk from the cumulative burden in the 2011 study. Several marginal mills have closed since 

the previous study was completed, taking them out of the calculation and the overall health of 

the industry improved as the overall economy improved between the two studies.

                                                           

1

 Note that these estimates do not include jobs losses in the wood products manufacturing sector of the forest 

products industry from an estimated $2 billion in new MACT costs. 

2

 Roughly $2 billion in new capital costs for pulp and paper mills meeting various National Ambient Air Quality 

Standards (NAAQS); changes to the New Source Review (NSR) requirements; New Source Performance 

Standards (NSPS) and the Clean Air Interstate Rule (CAIR) were not factored into the mill closure/job loss 

calculations because they could not be allocated to specific mills.
Boiler MACT-NHSM Issues

November 9, 2011
Overview

Major issue for forest product manufacturers

$7 Billion in capital to meet March rules 

87,000 jobs at risk due to potential paper mill closures

Severe impacts on wood product mills as well

Non-Hazardous Secondary Material (NHSM)

Roadblocks for biomass residuals and other common fuels

Boiler MACT – major issues

Achievable limits – CO, dioxin, and new sources

Boiler testing for CO, PM subcategories, and time to comply

2
NHSM: Perverse Outcomes

Preamble identifies many materials as likely to be fuels, HOWEVER

Rule language requires meeting “legitimacy criteria” 

contaminant level must be comparable to “traditional fuel” - coal, wood, etc.

Ignores historical use of these alternative fuels

Many biomass residuals will flunk test - turning boilers into “Incinerators” (3X cost)

Resinated wood, wastewater and paper process residuals become solid wastes

No health concerns – very small quantities and well controlled under MACT

Many/Most facilities will stop burning, landfill materials and buy fossil fuels

Millions of tons filling our landfills

$660 million/year just for forest products – some mills won’t survive

Failure to fix puts MACT floor analysis in jeopardy ... again.

3
NHSM Fixes

List residuals as non-waste fuels, including:

Biomass [such as, Resinated wood, Wastewater and 

Paper recycling residuals, used Railway Ties]

TDF and used oil

Urban wood (clean C&D) as traditional fuel/clean biomass

Ensure contaminant legitimacy criteria do not prevent 

materials becoming fuel – make discretionary factor

Create workable petition process for classifying other 

NHSM as non-waste fuels

Address contained gas to reflect comfort letter to AF&PA

4
Boiler MACT: Unachievable

Unachievable biomass limits for Carbon Monoxide

Problem: Many biomass boilers cannot consistently meet CO limit

Solution: set feasible short term limits and alternative longer-term (monthly) 

limits that reflect data variability; mine existing data as much as possible; use 

Upper Permissible Limit at 99.9%

Biomass Stokers: ~900 ppm (3-hr) and ~500 ppm (monthly)

Biomass Fluidized bed: ~700 ppm (3-hr) and ~350 ppm (monthly)

Unachievable limits for Dioxin

Problem: Data are below levels that can accurately be measured (see diagram); 

results are meaningless at extremely low levels ; limits more stringent than any 

MACT (see chart)

Solution: Adopt reasonable work practices for all subcategories to sustain 

efficient combustion, as law provides 

5
Concentration in Relative Units

6

Method Sensitivity Decision Points

LC LD LQ

Cannot differentiate

from background 

LC

LD

LQ

Critical Level

Limit of Detection

Limit of Quantitation

Can differentiate

from background. 

Low confidence in 

detection. 

Analyte is detectable.

Low confidence in 

quantity.

The analyte is 

quantifiable with a

known level of 

precision and bias

Analyte Concentration

Method Sensitivity Benchmarks

(All dioxin detections 

are here -- below the 

level of confidence 

that the number is 

accurate)
7
Boiler MACT: Unachievable

Unachievable New Source Limits

Problem: non-gas boilers can’t reliably meet; discourages replacement of older 

boilers/modernization including new biomass units

Solution: test methods can’t measure at these levels so adjust limits to reflect 

quantitation limits

8

HAP/Surrogate Biomass Stokers Biomass Fluidized

PM (lb/MM Btu) ~0.01 ~0.008

CO (3-hr in ppm) 550 300

CO (monthly in ppm) ~400 ~250

Mercury (lb/T Btu) ~3.5 ~3.5
Boiler Testing

Four CO CEMs tests getting underway on top 

performing stoker and fluidized bed biomass boilers 

Best to have year of data given operational and fuel 

changes – wettest biomass January to May

If EPA finalizes in April, only have Nov-Jan test data

will continue to test some units beyond January

every extra month important depending on “mining” of 

existing data

Notice of Data Availability – consider late data

9
Reasonable Particulate Limits

The depressed housing market has hit the wood 

product industry especially hard with 128,000 jobs 

lost since 2008 (28% of the work force)

Banks will not lend money or companies cannot 

commit capital for controls - mills will close

PM limits based on the unique fuels, products and 

boiler designs could make the limits affordable and 

protective

More compliance time, may see return to profitability

10
Adequate Time to Comply – Five Years

Three years insufficient given the investment of billions of 

dollars – need 5 yrs; Incinerators get up to 5 yrs.

Most complex set of requirements manufacturers have ever 

faced and in the worst economy since passage of the Act.

Evaluation of control strategies for five pollutants plus other 

obligations requires many engineering studies and planning.

Competition fierce for control vendors and qualified 

consultants given other rules (e.g., Utility MACT, CSAPR)

More time increases the odds that mills will return to 

profitability and be able to afford controls rather than close

Periodically report progress – did in Paper Cluster MACT

Ask for comment in the preamble on extra two years 11
Other Reconsideration Issues

Minimum of 90 day comment period to examine 

floor data and multiple rules together

PM CEMS not justified

Retain work practices for start-up and shutdown

Achievable liquid fuel limits (very low CO and PM 

limits) – distillate and residual subcategories

Defer energy audit for GACT sources by 2 years

New Source date should be reset with this proposal

12
CUMULATIVE COST BURDEN

ANALYSIS OF AIR REGULATIONS 

POTENTIALLY IMPACTING THE 

FOREST PRODUCTS INDUSTRY

Prepared for:

1111 19th St. NW, Suite 800

Washington, DC 20036

Prepared by:

URS Corporation 

1600 Perimeter Park Drive

Morrisville, North Carolina 27560

(919) 461-1100

URS Project No. 31826756

Updated August 2011
TABLE OF CONTENTS

i

1. Introduction/Summary ...................................................................................................1-1

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

1.2 Conclusions .............................................................................................. 1-1

1.3 Report Organization ................................................................................. 1-2

2. Air Regulations Evaluated .............................................................................................2-1

2.1 Regulations Evaluated ............................................................................. 2-1

2.2 Regulatory Timeline ................................................................................ 2-2

3. Cost Methodology ..........................................................................................................3-1

3.1 Cost Estimate Methodology ..................................................................... 3-1

3.1.1 Boiler Category ............................................................................ 3-2

3.1.2 Boiler Regulatory Cost Scenarios Evaluated for MACT and 

CISWI .......................................................................................... 3-4

3.1.3 Wood Products Category ............................................................. 3-6

3.1.4 Pulp and Paper Category .............................................................. 3-6

3.1.5 Collateral Emissions or Energy Increases for Controls ............... 3-6

3.2 Potential Regulatory Costs not Captured in this Analysis ....................... 3-7

TABLES 

Table 2-1 List of Air Regulations Evaluated and Compounds Regulated 

Table 2-2 Forest Products Industry Regulatory Cost Timeline 

APPENDICES 

Appendix A Cost Estimate Summaries 

Appendix B Cost Estimates by Category and Regulatory Action 

Appendix C Detailed Boiler MACT Cost Spreadsheets 
TABLE OF CONTENTS

ii

List of Acronyms and Abbreviations

AF&PA American Forest and Paper Association

BACT Best Available Control Technology

BART Best Available Retrofit Technology

CAIR Clean Air Interstate Rule

CISWI Commercial or Institutional Solid Waste Incinerator

CO2 Carbon Dioxide

CEMS Continuous Emissions Monitoring System

CPMS Continuous Parameter Monitoring System

EPA Environmental Protection Agency

GACT Generally Available Control Technology

GHG Greenhouse Gas

H2S Hydrogen Sulfide

HAP Hazardous Air Pollutant

HBCA Health Based Compliance Alternative

LAER Lowest Achievable Emission Rate

MACT Maximum Achievable Control Technology

NAAQS National Ambient Air Quality Standards

NCASI National Council for Air and Stream Improvement

NESHAP National Emission Standards for Hazardous Air Pollutants

NHSM Non-Hazardous Secondary Materials 

NOx Nitrogen Oxides

NSPS New Source Performance Standards 

NSR New Source Review

PCWP Plywood and Composite Wood Products

PM Particulate Matter

PM10 Particulate Matter with diameter less than 10 microns

PM2.5 Particulate Matter with diameter less than 2.5 microns

P&P Pulp and Paper

PSD Prevention of Significant Deterioration

RTR Risk and Technology Review
TABLE OF CONTENTS

iii

SO2 Sulfur Dioxide

SSM Startup, Shutdown, or Malfunction

VOC Volatile Organic Compound
SECTIONONE Introduction/Summary

1-1

1. Section 1 ONE Introduction/Summary

1.1 INTRODUCTION

URS Corporation (URS) performed a detailed analysis of the cumulative cost burden of air 

regulations that may potentially impact American Forest and Paper Association (AF&PA)

member companies (e.g., wood products manufacturing facilities and pulp and/or paper 

manufacturing facilities). The purpose of the analysis was to determine a rough order of

magnitude estimate of the cumulative cost burden that would be imposed on the Forest Products 

Industry if EPA implements various air regulatory changes that are currently under 

consideration. The air quality regulations evaluated would impact member company boilers and 

other process equipment. The cost estimates were compiled in a Microsoft Excel workbook;

were based on published information or similar project costs; have been reviewed by member 

company representatives; and have been made available to the US EPA and others for review. 

Note that the Boiler MACT and CISWI costs are based on the March 2011 rules and information 

in EPA’s March 2011 survey and emissions databases, but also take into account the

promulgated solid waste definition rule, that determines whether secondary materials being

burned in boilers are fuels or solid waste and whether boilers are regulated under Boiler 

MACT/GACT or CISWI. This document provides background information on the regulations

included in the analysis and the methodologies used in the analysis. 

1.2 CONCLUSIONS

The following presents a summary of the conclusions from the cost estimate analysis.

 Based on the analysis described in this report, air regulatory actions currently under 

consideration by EPA could result in a Forest Products Industry total estimated initial 

capital cost of $16.5 billion and an estimated annualized cost of $4.3 billion.

 The regulatory action with the most significant economic impact on facilities with 

industrial boilers will be the revised Industrial Boiler Maximum Achievable Control 

Technology (MACT) Standard, combined with the revised CISWI and solid waste 

definition rules. We have estimated costs using a primary scenario that assumes many

secondary materials burned by forest products facilities are determined to be solid waste, 

and also under a secondary scenario that assumes many of these materials are determined 

to be fuels.

 The regulatory action with the most significant economic impact on wood products 

facilities is expected to be the revisions to the wood products MACT standard.

 The regulatory actions with the most significant economic impact on pulp and paper mills 

are considered to be discretionary actions, and not mandated actions, and include

regulation of hydrogen sulfide (H2S) as a hazardous air pollutant (HAP), regulation of 

recovery furnaces under the Clean Air Interstate Rule (CAIR) that currently regulates 

fossil fuel-fired utility boilers, and adding regulated compounds to the pulp and paper 

MACT standards.
SECTIONONE Introduction/Summary

1-2

1.3 REPORT ORGANIZATION

The remainder of this report is divided into the following sections:

Section 2.0: Air Regulations Evaluated

Section 3.0: Cost Methodology and Results

The table of contents contains a detailed listing of tables and appendices. 
SECTIONTWO Air Regulations Evaluated

2-1

2. Section 2 TW O Air R egulations Ev aluated

2.1 REGULATIONS EVALUATED

AF&PA member companies identified several air quality regulations that have the potential to 

significantly impact them economically. Of the regulations identified, some are regulations that 

EPA is required to promulgate or revise and some are regulations that EPA may decide to 

review, revise, or implement. Note that because the regulatory scheme for greenhouse gases 

(GHG) is uncertain, this analysis did not focus on the cost of GHG regulations, which is also 

expected to be significant for the industry.

Table 2-1 presents the potential air regulatory actions considered and the main regulated 

compounds impacted. AF&PA considers the following regulatory actions discretionary on the 

part of EPA: 

 Revisiting the pulp and paper MACT standards outside of the required risk and 

technology review (RTR) requirements;

 Including industrial boilers and recovery furnaces in the Clean Air Interstate Rule (CAIR)

replacement, now termed the Cross State Air Pollution Rule (CSAPR);

 Regulating H2S as a HAP;

 Developing New Source Performance Standards (NSPS) for wood products 

manufacturing; and 

 Revisions to the current Kraft Pulp Mill NSPS under 40 CFR 60, Subpart BB. 

The other non-discretionary regulatory actions include:

 Boiler MACT re-promulgation (will result in significantly lower limits than the 2004

regulation that was vacated);

 Generally Achievable Control Technology (GACT) for boilers located at area sources of 

HAP;

 Regulation of boilers as commercial or industrial solid waste incinerators (CISWI) if

certain materials are deemed waste and not fuel;

 Risk and Technology Review for Pulp and Paper MACT rules (to determine if additional 

HAP emissions controls are needed);

 Reviewing/lowering the National Ambient Air Quality Standard (NAAQS) for Nitrogen 

Oxides, new 1-hour standard (NOx);

 Reviewing/lowering the NAAQS for Sulfur Dioxide, new 1-hour standard (SO2);

 The Continuous Parameter Monitoring System (CPMS) rule specifying quality assurance

procedures for CPMS required by NSPS and MACT standards;

 Full implementation of the NAAQS for particulate matter less than 2.5 microns in 

diameter (PM2.5);

 Revisions to the Plywood and Composite Wood Products (PCWP) MACT due to court 

decisions;
SECTIONTWO Air Regulations Evaluated

2-2

 Changes to the PCWP and Pulp and Paper MACT rules due to the SSM vacatur (sources 

are no longer exempt from compliance during periods of SSM);

 Reviewing/lowering the Ozone NAAQS and increased number of non-attainment areas; 

and

 Further regulation of sources under the Regional Haze rule to meet future progress 

targets.

Estimated regulatory costs are summarized in Appendix A and are presented by rule in 

Appendix B of this document.

2.2 REGULATORY TIMELINE

The air regulations were evaluated in order of expected effective date and efforts were made to 

avoid double counting regulatory impacts. For example, if a boiler installed acid gas controls 

under Boiler MACT for control of hydrogen chloride and other inorganic HAPs, the facility

would presumably not have to install additional controls on the boiler as a result of future

regulations impacting SO2 emissions. 

Table 2-2 presents the regulatory cost impact analysis by year, based on the expected timing. 

For rules where the majority of the sources are impacted upon the initial promulgation of the rule

(e.g., Boiler MACT), estimated capital costs are phased three years prior to the compliance date 

and annual costs remain constant each year following the compliance date (the number of 

affected sources is assumed to remain relatively constant). For rules where sources are impacted 

over time (e.g., NSPS), annual operating costs increase over time as the number of affected units

increases. Details on how the cost estimates were developed are presented in Section 3.
SECTIONTHREE Cost Methodology

3-1

3. Section 3 THR EE Cost Methodology

3.1 COST ESTIMATE METHODOLOGY

URS estimated air regulatory costs for three categories of forest products industry sources: 

industrial boilers, wood products industry sources (non-boilers), and pulp and paper industry

sources (non-power boilers). The regulations considered in this analysis were assigned to one or 

more of these categories, as shown in Table 2-1, and in general are ordered by expected effective

date.

The three key variables in the analysis were the cost of controls, the number of affected units, 

and the inter-relationship of the regulations. For each category and regulation, potential 

compliance or emissions control scenarios were determined based on the compounds expected to 

require control, and for each of these scenarios, compliance costs and numbers of units included

in the scenario were estimated. Both a capital cost and an annual operating cost were

determined, and the capital cost was annualized using a capital recovery factor to develop the

total estimated annual cost for each scenario. The regulatory costs are driven by selection of the 

compliance method or control technology to achieve significant emission reductions rather than 

to meet any specific limit under a particular regulation.

Capital and operating costs estimates are not intended to represent a worst case analysis. Rather, 

they represent median costs for the various scenarios based on published reports, industry

information on specific project costs, EPA reports or control device fact sheets, or actual BACT 

or BART analyses submitted to permitting agencies. A primary resource was the document 

“Evaluation of Air Pollution Control Costs for the Pulp and Paper Industry,” prepared by

National Economic Research Associates (NERA) in May 2003. Note that costs were not scaled 

from the date of the reference used to 2011 dollars as the intent was to develop an order of 

magnitude estimate for each control scenario. 

Air emissions controls were assigned to the rule with the earliest effective date. For example, if 

a later rule requires the same controls (e.g., industrial boilers are covered by CAIR at a date 

following the implementation Boiler MACT), the control cost is not double counted. However, 

if a cost from an earlier rule does not occur, or if a rulemaking is delayed, later rules could then 

become more expensive than currently estimated. Summaries of the estimated costs for each 

regulatory action and each category are presented in Appendix A.

URS received the following estimates from the National Council for Air and Stream 

Improvement (NCASI) regarding the numbers of each type of forest products industry facility:

700 sawmills (approximately 221 of which are major sources of HAP),

300 wood products mills (approximately 170 of which are major

sources), 

300 converting plants (mostly area sources), and

379 pulp and paper mills (mostly major sources),

including 100 Kraft, 8 semi chemical, 

18 mechanical pulp, 5 sulfite, and 1 soda.
SECTIONTHREE Cost Methodology

3-2

3.1.1 Boiler Category 

The detailed cost estimates for the boiler category are presented in Appendix B. URS received 

the following information from NCASI regarding the number and types of boilers in the forest 

products industry (note that 301 of the 918 pulp and paper mill boilers are at the 100 Kraft mills):

916 pulp and paper mill boilers

83 coal

67 coal/wood

108 wood

658 oil/gas (about half of these are major sources of HAP)

820 wood products mill boilers

600 wood (100 major sources, 500 area sources)

120 gas (most area sources of HAP)

100 oil (most area sources of HAP)

200 boilers at converting plants (probably all area sources)

The EPA collected information during Phase 1 of the Boiler MACT information collection 

request (ICR) on 455 boilers at facilities in NAICS 322xxx (pulp and paper and packaging) and 

369 boilers in NAICS code 321xxx (wood products). 

In the boiler category, all forest products industry boilers (not including pulp mill recovery

boilers) will fall under Boiler MACT, Boiler GACT, or CISWI. URS identified the regulated 

compounds likely to require control, likely control options (sometimes by boiler fuel type), 

typical control costs, and estimated number of units affected for each rule. For the regulatory

actions that may occur after these first three rules, we then estimated additional numbers of

boilers that will also be affected, in an attempt to avoid double counting control costs. However, 

note that an individual unit might be represented more than one time in the table if it has to 

install two different types of controls for different regulated compounds (e.g., fabric filter for PM 

and carbon injection for mercury). Costs of the boiler rules were allocated to the wood products 

and pulp and paper sectors based on information about the numbers, types, and sizes of boilers in 

each category.

A detailed spreadsheet was developed to estimate costs for Boiler MACT, based on EPA’s major 

source boiler inventory database table. Because the rule does not include emission limits for

natural gas boilers, boilers less than 10 MMBtu/hr heat input, or limited use units, these units are

not included in the cost analysis. Based on the information in the EPA emissions database on 

boiler size, fuel, existing controls, and emissions, we estimated costs of controls that would 

likely be necessary to comply with the Boiler MACT for coal, biomass, and liquid boilers. Note 

that EPA’s March 2011 rule assumed that landfill gas boilers (formerly in the Gas 2 category)

could comply with MACT using work practices. As some forest products boilers at major 

sources did not receive an ICR from EPA in 2008, we added information for those boilers to the 

detailed spreadsheet based on a database maintained by Fisher International and information

from NCASI. 

Information from various sources was used to determine a base capital cost for a 250 MMBtu/hr

boiler for each PM, CO, and HCl control technology option and then scaled using an 0.6 power 

function based on the size of each boiler in the inventory. For example, the capital cost of a wet 

scrubber on a 100 MMBtu/hr boiler is calculated as the base cost times (100/250)0.6. A fixed 
SECTIONTHREE Cost Methodology

3-3

cost of $1 million was assumed for installation of a carbon adsorption system for Hg and/or 

dioxin control, as these systems do not vary much in cost by boiler size. Base cost assumptions 

are presented below. Operating costs are based on EPA and vendor information.

Base Control Size, MMBtu 250

Fabric Filter Capital Cost $7,000,000

Wet Scrubber Capital Cost $8,000,000

WS/FF/ESP upgrade Capital Cost $4,000,000

Carbon Injection for Hg/dioxin

Capital Cost $1,000,000

Combustion Improvements or

Catalyst for CO Capital Cost $3,000,000

Interest Rate 7 percent

Equipment life, yrs 15

Capital recovery factor 0.110

Activated Carbon rate, lb/mmacf 4

Activated Carbon cost, $/lb $1.00

Wet scrubber annual operating

cost, $/acfm $10

FF annual operating cost $200,000

For the Boiler MACT control costs, we assumed that if emissions information (either sitespecific test data or EPA’s baseline emission factors by boiler type and existing control) 

indicated the boiler would not meet the March 2011 limits, the unit would need MACT, which 

EPA says is a fabric filter (FF) plus carbon injection plus wet scrubber plus combustion 

improvements (or CO catalyst). In their boiler inventory table, EPA put the boiler pollution 

controls into categories. The categories are explained in greater detail in EPA’s baseline

emission factor memo, but basically are as follows: for PM control code, 1=FF, 2=EFB/ESP, 

3=venturi scrubber, 4=wet scrubber, 5=multiclone, 6=none/mist eliminator/unknown. If a unit

did not already have a FF or ESP and there was information that indicated the unit cannot meet 

the limit, we assumed a new FF. If the unit already had a FF or ESP and there was information 

that indicated the unit cannot meet the limit we assumed an upgrade to the existing control 

equipment. For HCl control code, 1=wet scrubber or spray dryer, 2=dry scrubber, 3=sorbent 

injection, 4=venturi scrubber, 5=none/dry PM only. To estimate control costs for HCl, if there

was information that indicated the unit cannot meet the limit, we assumed either a scrubber 

upgrade or new scrubber depending on whether the unit currently had a scrubber. For Hg control 

code, 1=carbon injection, 2=FF plus sorbent injection or spray dryer, 3=FF only, 4=wet scrubber, 
SECTIONTHREE Cost Methodology

3-4

5=venturi scrubber, 6=none/multiclone/EFB/mist eliminator. For Hg and dioxin, if there was 

information that indicated the unit cannot meet the limit, we added carbon injection. For CO, if 

there was information that indicated the unit cannot meet the limit, then we assumed that capital 

would be necessary to either perform combustion/fuel feed improvements or other boiler 

improvement projects to reduce CO or install a CO catalyst.

CISWI rule costs were developed in much the same manner as the Boiler MACT costs, using

EPA’s CISWI database. Control costs for NOx were added if necessary, assuming a base cost 

for SNCR of $4 million.

We assumed that compliance with Boiler GACT will only require tune-ups. Note that many

facilities may choose fuel switching as a compliance option; however, as the cost of fuel 

switching is highly dependent on site specific factors (e.g., whether the boiler can burn the

alternate fuel, what upgrades must be made to the fuel supply system) and the price of fuel is 

likely to change over time due to factors like supply and demand, we did not attempt to quantify

costs for fuel switching. 

For each rule, a total annual cost is presented based on the sum of each line item under the rule 

and represents the first year of implementation of the rule (for some rules the annual operating

cost will increase over time as more sources become subject to the rule, such as NSPS). The

Boiler MACT and CISWI Rules account for the majority of the estimated cost in the boiler

category and are expected to require significant additional control cost for the forest products 

industry. The total estimated annual cost of the boiler regulations examined is $1.3 billion. The

majority of this cost impact will be on the pulp and paper category, primarily impacting Kraft 

mills (it is estimated that Kraft mills will bear around 70 percent of the pulp and paper category’s 

cost, based on the allocation of boilers at Kraft mills versus other mills). We anticipate that the 

Kraft pulp mills would bear the majority of the Boiler MACT cost assigned to the pulp and paper 

category and that non-Kraft mills would bear the majority of the Boiler GACT cost assigned to 

facilities in the pulp and paper category.

3.1.2 Boiler Regulatory Cost Scenarios Evaluated for MACT and CISWI

URS assumed that the health based compliance alternative (HBCA) is no longer an option for 

Boiler MACT. However, the following table shows potential savings that could be realized if 

the HBCA is an option under Boiler MACT. Note that the analysis did not differentiate by fuel, 

so if manganese is the only metal that can be excluded from a TSM limit using HBCA, then coal 

and oil-fired boilers would not benefit from HBCA as much as a wood-fired boiler would, and 

the savings would be less for the industry as a whole.

Potential Cost Savings with HBCA under Boiler MACT

Pulp and Paper Wood Products

Capital Cost Annual Cost Capital Cost Annual Cost

Assuming 50% of mills could comply with

PM/metals and HCl using HBCA instead of

add-on controls:

$830 million $156 million $226 million $30 million

Assuming 90% of mills could comply with

PM/metals and HCl using HBCA instead of

add-on controls:

$1.5 billion $282 million $407 million $54 million
SECTIONTHREE Cost Methodology

3-5

URS examined two regulatory scenarios for Boiler MACT and CISWI. The Non-Hazardous 

Secondary Materials (NHSM) definition rule determines whether boilers are regulated under 

Boiler MACT or CISWI. If a boiler or other combustion unit burns a secondary material that is 

solid waste, it will be regulated under the CISWI rule. The current Boiler MACT database

contains units that burn some types of secondary materials, and only a few forest products boilers 

are in the CISWI database. Even though EPA is contemplating guidance that indicates many

materials traditionally burned as fuels can still be classified as fuels, the current rule language

may result in many materials being classified as solid waste (e.g., wastewater treatment 

residuals, recycling process residuals, TDF, resinated wood, creosote treated wood/rail ties). 

URS evaluated the impacts of having these materials considered solid wastes and having 104 

boilers burning these materials install controls to comply with the CISWI rule instead of the

Boiler MACT. Under this scenario, we estimate that one third of the 500 forest products area

source boilers and 85 wood products facilities burning sanderdust in dryers would also have to 

install controls to comply with the CISWI rule (the average per boiler control cost of the

104 additional boilers of $7.8 million is used for these estimates).

Scenario Boiler MACT CISWI Rule Total Cost

Control Cost When Many

NHSM are Wastes not Fuels

$3.7 Billion $3.3 Billion $7 Billion

Control Cost When Most

NHSM are Fuels not Waste

$4.3 Billion $470 Million $4.8 Billion

If facilities were to stop burning NHSM and replace the fuels with natural gas, operating costs

would increase instead of capital costs. Based on the number of mills known to burn NHSM and 

estimated amounts burned (based on 2005 NCASI survey and supplier estimates), the annual cost 

for forest products industry boilers to stop burning wastewater treatment residuals, recycling

process residuals, TDF, resinated wood, and creosote treated wood/rail ties would be over 

$650 million.

Material # Mills # Boilers 2005 Amount

(Tons)

% of Total 

Boiler Fuel 

Used

Cost to landfill and

replace with natural gas

1

Wastewater Treatment 

Residuals 57 68 1,340,000 1.8 $159,000,000

TDF 21 29 401,500 1.2 $68,582,000

Recycling Process Residuals 211 14 172,200 0.3 $24,200,000

Rail ties 312 550,000 0.10 $57,600,000

Resinated Wood 100+ 2,500,000 73.5 $352,000,000

Total $661,382,000

1 = TDF and Railroad ties costs only include fuel replacement, not landfilling

2 = This is likely to be an underestimate. There are more than 100 mills that recycle, but not all have on-site boilers

3 = This represents an estimate by a major supplier of rail ties used by the FPI in 2011
SECTIONTHREE Cost Methodology

3-6

3.1.3 Wood Products Category 

The detailed cost estimates for the wood products category are presented in Appendix B. Note

that we have not included emissions controls for lumber kilns, although we have assumed that 

there will be some cost to implement the expected work practice requirements. We have

assumed that the level of control for currently controlled wood products MACT sources will not 

change (e.g., EPA will not increase the required control efficiency from 90 percent to 

95 percent). We have also assumed that backup controls will not be required as a result of the

SSM vacatur.

Of the regulatory actions evaluated, the revisions to the PCWP MACT will pose the most

significant cost burden on the wood products industry (non-boiler sources), as additional sources 

are expected to require control under the revised rule. The total estimated annual cost of the 

potential wood products air regulatory actions examined (excluding boiler regulations) is 

$230 million.

3.1.4 Pulp and Paper Category

The detailed cost estimates for the pulp and paper category are presented in Appendix B. Note

again that we have attempted to avoid double counting in the cost analysis, but one facility might 

have control costs under different regulations. URS received the following information from 

NCASI regarding the number of existing recovery furnaces and lime kilns at pulp and paper 

mills:

53 Direct contact evaporator (DCE) recovery furnaces

108 Non-direct contact evaporator (NDCE) recovery furnaces

140 Lime kilns

The highest potential cost impacts for the pulp and paper industry (non-power boiler sources) are

from regulatory actions that are not required to be implemented: regulating H2S as a HAP, 

including recovery furnaces in CAIR, and making significant revisions to the pulp and paper 

MACT rules (e.g., adding regulated compounds). 

The regulation of H2S as a HAP is expected to cause significant regulatory burden as it would 

likely require H2S emission reductions from wastewater treatment systems. This could require

conversion of systems with aerated stabilization basins to activated sludge systems at a capital 

cost of approximately $35 million for each of 67 mills. Based on the items in a Sierra Club 

petition to add regulated compounds to the pulp and paper MACT standards, we have estimated 

control scenarios and control costs that amount to over $1 billion per year for the pulp and paper 

industry. The total estimated annual cost of the potential pulp and paper air regulatory actions 

examined is $1.9 billion. 

3.1.5 Collateral Emissions or Energy Increases for Controls

The detailed cost estimates in Appendix B also present information on whether a collateral 

emissions or energy increase can be expected with implementation of a control technology. 
SECTIONTHREE Cost Methodology

3-7

Where a control is expected to significantly increase electricity or fuel consumption, or will

convert CO to CO2 (e.g., a catalyst installed on a boiler), we have estimated the CO2 emissions 

increase in metric tons per year. The notes column in the detailed cost estimates included in 

Appendix B provides the assumptions used to estimate CO2. CO2 emissions from combustion of 

additional biomass are not estimated, as these emissions are considered carbon neutral. 

Increased electricity and fuel consumption due to implementation of certain control strategies 

will also lead to higher NOx emissions, which would not be favorable in an ozone non-attainment 

area. An impact of reducing CO and THC emissions through combustion controls and fuel 

switching may be increases in NOx emissions, but the impact would be dependent on the

operating conditions at each boiler before and after the change.

3.2 POTENTIAL REGULATORY COSTS NOT CAPTURED IN THIS ANALYSIS

The forest products industry faces other non-Clean Air Act regulatory costs under the Clean 

Water Act and the Resource Conservation and Recovery Act. There are also significant costs 

expected to be incurred by any future GHG regulatory scheme. For example, electricity may

become very expensive for facilities that buy power from coal-fired power plants and facilities 

that operate coal-fired boilers may be financially impacted if a carbon tax or cap and trade

program is enacted. Renewable energy legislation is also expected to significantly increase the 

cost of biomass, the forest products industry’s raw material. This analysis only captured costs

that will potentially be incurred as a result of non-GHG air regulatory actions currently being

considered by EPA. We were also unable to predict the impact of the Electric Utility MACT on 

fuel and operating costs (e.g., increased electricity cost due to increased utility control costs or 

increased natural gas cost due to increase in Utility conversions of coal-fired units to natural gas 

and decrease in industrial availability).

Note that originally, we had developed cost estimates for the impact of EPA rolling back NSR

reform (e.g., reverting to the “actual to potential” PSD applicability test instead of the “baseline

actual to projected actual” applicability test). However, recent information indicates that EPA 

does not intend to go forward with this action. We originally estimated a capital cost for

industrial boilers of $308 million due to a large number of projects triggering PSD review that 

would not have under the NSR reform rule, with an estimated annual cost of $38.8 million. The

estimated costs for pulp and paper mills were approximately $115 million in capital and 

$28 million in annual costs, and for wood products facilities were $101 million in capital and 

$16 million in annual costs.
Tables
Table 2-1. List of Air Regulations Evaluated and Compounds Regulated

Wood Products - 

srcs already 

controlled

Wood Products - 

uncontrolled 

srcs

Pulp and Paper - pulp 

mill srcs already 

controlled

PM/metals Hg NOx SO2/acid gas VOHAP/CO Dioxin GHG VOC VOC VOC VOC TRS VOC TRS VOC TRS VOC TRS PM/metals NOx SO2/acid gas TRS Hg VOHAP/CO dioxin GHG PM/metals acid gas TRS Hg VOHAP/CO

Boiler MACT 1 x x x x x

Boiler GACT 2 x x x

CISWI 3 x x x x x x

CAIR for industrial 

boilers 4 x x x x x x

Regional Haze 5 x x x x x

CO2 regulated 6 x x

NOx NAAQS 

lowered 7 x x x

SO2 NAAQS 

lowered 8 x x

Ozone NAAQS 

lowered 9 x x x x x x x x x x x

PM2.5 NAAQS 

fully implemented 10 x x x x x x x x

SSM goes away 

under MACT 11 x x x x x x x x

NSR reform 12 x x x x x x x x x x x x x x x x x x x x x x x x x x

PCWP MACT 

revisions 13 x

PCWP MACT 

residual risk 14 x x

NSPS for wood 

products 20 PM/NOx? PM/NOx?

H2S listed as HAP 15 x x x x x x

P&P MACT I 

revisions 16 x x x

P&P MACT II 

revisions 17 x x x x x x x x x x

P&P MACT 

residual risk 18 x x x x x x x x x x x x x

NSPS BB 

revisions 19 ? x ? ? x ? x ?

Notes

1. Boilers covered by MACT would not be covered by GACT. Many boilers will need control upgrades under MACT.

2. Boilers covered by GACT will not be covered by MACT. Costs under GACT will likely be lower than costs to comply with MACT, since work practices are allowed for existing biomass and liquid (coal has Hg limit).

3. Boilers covered by CISWI will not be covered by MACT or GACT. This will affect boilers burning materials deemed to be waste.

4. CAIR rule may be revised to cover fossil fuel-fired industrial boilers >250 MMBtu, and this could possibly include recovery boilers.

5. Sources close to Class I areas may be required to control SO2/NOx/PM to improve Regional Haze. 

6. Regulation of CO2 would require emissions and control analyses for projects resulting in emissions increases, a cap and trade program may result in required reductions. BACT may be fuel switching.

7. Lowering of NOx ambient standard could result in NOx controls where a major project requires NAAQS modeling. New 1-hour standard difficult to comply with. States using modeling for attainment designations.

8. Lowering of SO2 ambient standard could result in SO2 controls where a major project requires NAAQS modeling. New 1-hr standard difficult to comply with. States using modeling for attainment designations.

9. Further lowering of ozone NAAQS puts more sources in non-attainment areas and may have to do RACT or install LAER for projects.

10. Full implementation of PM2.5 NAAQS may result in additional controls if a project cannot demonstrate compliance (not much room between background and standard).

11. Sources subject to MACT may not be allowed control device downtime or venting allowance. Will need backup controls, better controls, or more frequent process shutdowns.

12. Note that EPA has denied the petition for reconsideration of NSR reform at present, but if NSR reform were rolled back, more projects may trigger PSD review and BACT controls.

13. More sources may require control at PCWP plants (expand oxidizers or add additional oxidizers or biofilters)

14. Residual risk review may result in lower emission limits or additional regulated sources.

15. If H2S is listed as a HAP, EPA would have to revisit pulp and paper MACT and add H2S emission standards/possible additional controls (e.g., WWTP).

16. Sierra Club has sued because some pollutants not required to be controlled, some unregulated sources can be traded for regulated sources, some sources can be overcontrolled instead of controlling a regulated source further.

17. Sierra Club has sued because some pollutants not required to be controlled, some unregulated sources can be traded for regulated sources, some sources can be overcontrolled instead of controlling a regulated source further.

18. Residual risk review may result in lower emission limits or additional regulated sources.

19. EPA conducting a review/possible update of NSPS BB.

20. Not sure what this regulation would include - maybe standards for new dryers.

Pulp and Paper - CCA mills Pulp and Paper - Smelt Tanks

Pulp and Paper - 

Wastewater 

Treatment Systems Pulp and Paper - BLOX Pulp and Paper - Recovery Boilers/Lime Kilns

Rule Notes

Boilers/Process Heaters at Wood Products and Pulp and Paper

Pulp and Paper - Paper 

Machines
Table 2-2. Forest Products Industry Regulatory Cost Timeline

Year --> 2010 2011 2012 2013 2014 2015 2016 2017 

Rule

$370,000,000 $925,000,000 $2,405,000,000

$290,000,000 $290,000,000 $290,000,000 $

$700,000,000 $700,000,000 $700,000,000 $700,000,000 $700,000,000 $

$1,000,000 $2,500,000 $6,500,000

$9,000,000 $9,000,000 $9,000,000 $9,000,000 $9,000,000 

$109,795 $9,000,000 $9,000,000 $9,000,000 $9,000,000 $9,000,000 

$325,000,000 $812,500,000 $2,112,500,000

$805,000,000 $805,000,000 $805,000,000 $

$1,160,000,000 $1,160,000,000 $1,160,000,000 $1,160,000,000 $1,160,000,000 $1,

$62,000,000 $62,000,000

$7,000,000 $7,000,000 $7,000,000 $7,000,000 $7,000,000 

$21,000,000 $21,000,000 $21,000,000 $21,000,000 $21,000,000 

$620,500,000

$142,000,000 $142,000,000 $142,000,000 $142,000,000 $

$68,127,565 $211,000,000 $211,000,000 $211,000,000 $211,000,000 $

$140,000,000

$28,000,000 $28,000,000 $28,000,000 $28,000,000 

$15,371,247 $43,000,000 $43,000,000 $43,000,000 $43,000,000 

CPMS Rule

$60,000,000 $120,000,000 $120,000,000 $120,000,000 $120,000,000 $$60,000,000 $120,000,000 $120,000,000 $120,000,000 $120,000,000 $$47,000,000 $117,500,000 $305,500,000

$80,000,000 $80,000,000 $80,000,000 

$5,160,347 $18,061,216 $46,443,126 $130,000,000 $130,000,000 $

$318,000,000

$42,000,000 $42,000,000 $42,000,000 

$34,914,691 $77,000,000 $77,000,000 $77,000,000 

$100,000,000

$3,000,000 $3,000,000 $3,000,000 $3,000,000 $3,000,000 

$10,979,462 $14,000,000 $14,000,000 $14,000,000 $14,000,000 $14,000,000 

$780,000,000

$360,000,000 $360,000,000 $360,000,000 $360,000,000 $

$85,639,807 $450,000,000 $450,000,000 $450,000,000 $450,000,000 $

$330,000,000 $825,000,000 $2,145,000,000

$300,000,000 $300,000,000 $300,000,000 $300,000,000 $

$36,232,226 $710,000,000 $710,000,000 $710,000,000 $710,000,000 $$83,000,000 $83,000,000 $83,000,000 $83,000,000 $83,000,000 

$8,000,000 $16,000,000 $24,000,000 $32,000,000 

$9,112,954 $18,000,000 $36,000,000 $54,000,000 $72,000,000 

$270,000,000 $675,000,000 $1,

$180,000,000 $

$470,000,000 $470,000,000 $

$78,000,000 $195,000,000 $507,000,000

$100,000,000 $100,000,000 $

$8,563,981 $29,973,933 $180,000,000 $180,000,000 $

$28,000,000 $28,000,000 $28,000,000 

$4,000,000 $8,000,000 

$3,074,249 $7,000,000 $14,000,000 

Initial Capital Cost $0 $0 $160,000,000 $2,800,000,000 $3,200,000,000 $7,270,000,000 $950,000,000 $790,000,000 $1,Annual O&M Cost $0 $0 $0 $80,000,000 $1,000,000,000 $2,200,000,000 $2,300,000,000 $2,500,000,000 $2,Total Annual Cost $0 $0 $10,000,000 $2,200,000,000 $3,500,000,000 $3,600,000,000 $4,300,000,000 $4,400,000,000 $4,

= Expected Final Rule Timing

Capital costs for rules with 3-year compliance windows (e.g., MACT) spread out assuming 10% in Year 1, 25% in Year 2, 65% in Year 3.

Boiler GACTBoiler MACTP&P MACT II revisions/RTR

(assume variable applicability timing per proposed rule)

CISWICAIR for industrial boilers/ recovery boilersPM2.5 NAAQS fully implementedSSM goes away under MACTRegional HazeNSPS Subpart BB updateH2S listed as HAPOzone NAAQS loweredWood Products NSPSP&P MACT I revisions/RTRSO2 NAAQS loweredNOx NAAQS loweredPCWP MACT revisions/RTR
Appendix A

Cost Estimate Summaries
Combined Summary of Forest Products Industry Air Regulatory Cost Impacts

Updated 8/17/2011

Rule

Initial Capital 

Cost

Initial Annual 

Operating Cost

Total Annual 

Cost

Reopen Pulp and Paper MACTs $4,080,000,000 $660,000,000 $1,200,000,000

CAIR for Industrial Boilers/ Recovery 

Furnaces $470,000,000 $80,000,000 $130,000,000

Boiler MACT/CISWI/Boiler GACT $7,000,000,000 $1,100,000,000 $1,900,000,000

H2S HAP listing $2,700,000,000 $180,000,000 $470,000,000

Wood Products MACT revsions $780,000,000 $100,000,000 $180,000,000

SSM revisions $100,000,000 $3,000,000 $14,000,000

NAAQS revisions $1,200,000,000 $49,000,000 $100,000,000

Other Rules $180,000,000 $310,000,000 $410,000,000

Total $16,500,000,000 $2,500,000,000 $4,400,000,000

Capital Annual Capital Annual

Assuming 50% of mills could comply with 

PM and HCl using HBCA: $829,726,380 $156,451,238 $226,211,712 $29,727,589

Assuming 90% of mills could comply with 

PM and HCl using HBCA: $1,493,507,483 $281,612,228 $407,181,082 $53,509,660

Note - the HBCA savings analysis does not differentiate between fuel. If a metals HBCA is not feasible for

a coal or oil fired boiler because manganese is the only pollutant that can be evaluated and excluded from

TSM, then the pool of boilers that would benefit from PM/metals HBCA would be smaller.

Note that the initial capital cost and the initial annual operating cost represent the cost for the initial number of 

units/facilities subject to the rule. For some rules, the number of units subject will increase over time (e.g., NSPS).

Pulp and Paper Wood Products

Potential savings with HBCA under Boiler MACT
Costs of Clean Air Rules for the Forest Products Industry

Updated 8/17/2011Organized by Rule:

Rule

Industrial Boilers 

- Initial Cost

Industrial Boilers 

- Initial Annual 

Operating Cost

Industrial Boilers - 

Total Annual Cost

Wood Products 

Sources - Initial 

Cost

Wood Products 

Sources - Initial 

Annual 

Operating Cost

Wood 

Products 

Sources - Total 

Annual Cost

Pulp and Paper 

Mills - Initial Cost

Pulp and Paper 

Mills - Initial 

Annual Operating 

Cost

Pulp and Paper 

Mills - Total 

Annual Cost

Ind

In

Boiler MACT $3,700,000,000 $290,000,000 $700,000,000 $3,Boiler GACT $10,000,000 $9,000,000 $9,000,000 $

CISWI $3,250,000,000 $805,000,000 $1,160,000,000 $3,

CAIR for industrial boilers/ recovery boilers $0 $0 $0 $470,000,000 $77,000,000 $130,000,000 $4Ozone NAAQS lowered $0 $0 $0 $32,000,000 $5,000,000 $8,500,000 $92,000,000 $1,500,000 $12,000,000 $1NOx NAAQS lowered $607,000,000 $141,900,000 $209,000,000 $2,500,000 $0 $300,000 $11,000,000 $0 $1,500,000 $6SO2 NAAQS lowered $100,000,000 $20,000,000 $31,000,000 $40,000,000 $7,500,000 $12,000,000 $1CPMS Rule $0 $69,000,000 $69,000,000 $0 $35,000,000 $35,000,000 $0 $12,000,000 $12,000,000 PM2.5 NAAQS fully implemented $180,000,000 $26,000,000 $45,000,000 $18,000,000 $0 $2,200,000 $120,000,000 $16,000,000 $30,000,000 $3Regional Haze $60,000,000 $7,500,000 $14,000,000 $32,000,000 $3,600,000 $7,100,000 $PCWP MACT revisions/RTR $780,000,000 $95,000,000 $180,000,000 $7SSM goes away under MACT $0 $0 $0 $100,000,000 $3,000,000 $14,000,000 $1Wood Products NSPS $28,000,000 $4,000,000 $7,000,000 $P&P MACT I revisions/RTR $780,000,000 $360,000,000 $450,000,000 $7P&P MACT II revisions/RTR $3,300,000,000 $300,000,000 $710,000,000 $3,NSPS Subpart BB update $83,000,000 $8,000,000 $18,000,000 $H2S listed as HAP $2,700,000,000 $180,000,000 $470,000,000 $2,Total Regulatory Cost $7,900,000,000 $1,370,000,000 $2,200,000,000 $860,000,000 $140,000,000 $230,000,000 $7,700,000,000 $1,000,000,000 $1,900,000,000 $16Cost by Sector With Boiler Rule Costs Allocated to Wood Products and Pulp and Paper by Rule

Rule

Wood Products 

Initial Cost

Wood Products 

Initial Annual 

Operating Cost

Wood Products 

Total Annual Cost

Pulp and Paper 

Initial Cost

Pulp and Paper 

Initial Annual 

Operating Cost

Pulp and 

Paper Total 

Annual Cost

Boiler MACT $900,000,000 $50,000,000 $140,000,000 $2,800,000,000 $240,000,000 $550,000,000Boiler GACT $10,000,000 $7,000,000 $7,000,000 $1,000,000 $1,000,000 $1,000,000CISWI $2,049,000,000 $615,000,000 $840,000,000 $1,200,000,000 $190,000,000 $320,000,000CAIR for industrial boilers/ recovery boilers $0 $0 $0 $470,000,000 $80,000,000 $130,000,000

Ozone NAAQS lowered $32,200,000 $5,000,000 $9,000,000 $95,000,000 $2,000,000 $12,000,000NOx NAAQS lowered $32,800,000 $7,000,000 $10,000,000 $590,000,000 $140,000,000 $200,000,000SO2 NAAQS lowered $5,000,000 $1,000,000 $2,000,000 $139,000,000 $26,000,000 $41,000,000CPMS Rule $0 $69,000,000 $69,000,000 $0 $46,000,000 $46,000,000

PM2.5 NAAQS fully implemented $26,400,000 $2,000,000 $4,500,000 $284,000,000 $40,000,000 $71,000,000Regional Haze $3,000,000 $400,000 $700,000 $89,000,000 $11,000,000 $21,000,000PCWP MACT revisions/RTR $780,000,000 $90,000,000 $180,000,000 $0 $0 $0

SSM goes away under MACT $0 $0 $0 $100,000,000 $3,000,000 $14,000,000Wood Products NSPS $28,000,000 $4,000,000 $7,000,000 $0 $0 $0

P&P MACT I revisions/RTR $0 $0 $0 $780,000,000 $360,000,000 $450,000,000P&P MACT II revisions/RTR $0 $0 $0 $3,340,000,000 $300,000,000 $710,000,000NSPS Subpart BB update $0 $0 $0 $83,000,000 $8,000,000 $18,000,000

H2S listed as HAP $0 $0 $0 $2,650,000,000 $180,000,000 $470,000,000Total Regulatory Cost $3,800,000,000 $860,000,000 $1,270,000,000 $12,600,000,000 $1,600,000,000 $3,000,000,000

Note that the initial capital cost and the initial annual operating cost represent the cost for the initial number of units/facilities subject to the rule. For some rules, the number of units subject will increase over time (e.g., NSPS). For costs over time, see the timeline ta
List of Possible Controls for 

Control Technology Unit Costs (

1. Scrubber (acid gases, H2S and SO2) $4 

2. ESPs or ESP upgrade (metals and PM) $3 

3. Carbon injection (mercury) $1

4. Oxidation catalysts (CO) $1‐

5. SNCR or SCR (NOx) $4 

6. Low NOx burner or combustion controls $0

7. Steam stripper/incinerator (VOCs/organic HAPs) $2

8. Fabric Filter (mercury/metals/PM) $7

9. Fuel switching (numerous pollutants) $1‐

10. Ducting sources to existing controls (HAPs) $2

11. Redesigned wastewater treatment (H2S) $3

12. Redesign Recovery Furnaces (organic HAPs) $20

TOTAL COST PER MILL* $25 M to $1

*depends on existing controls, type of mill/equipment and number of units affected
Summary of Benefits and Disbenefits of Various Control Strategies

Control Strategy Pollutants Reduced Collateral Increases/Impacts/Disbenefits

Scrubber on 

combustion unit SO2, acid gases, Hg

Installation of a scrubber on a combustion unit would likely require a bigger fan to pull 

the gases through the scrubber (increased electricity) and would increase water usage 

at the facility. Increased water usage is counter to the sustainability goals of many 

facilities. Many river systems have recently experienced record low flow due to 

extended drought periods, along with increasing competition from various 

upstream/downstream uses (municipalities, recreation, power generation, aquatic 

habitat). Depending on the water source, additional fresh water usage may not be 

feasible. If caustic is required, this is a high operating cost for facilities where a source 

of caustic is not available onsite. Scrubbers also produce wastewater and sludge that 

must be disposed of.

Reduce biomass 

burning to reduce CO CO

The forest products industry often produces steam and energy using renewable 

energy sources, such as biomass. Many facilities generate their own fuel from onsite 

operations such as log debarking, sawing, and sanding. Replacing biomass fuel with 

fossil fuel in an effort to reduce CO emissions would be contrary to our national goal to 

reduce our dependence on fossil fuels and increase generation of power through 

combustion of renewable fuels. Biomass is considered a "carbon neutral" fuel under 

many greenhouse gas reporting protocols because it is formed by removing carbon 

from the atmosphere. Therefore, replacing biomass fuels with fossil fuels would 

increase the concentration of CO2 in the atmosphere. Disposal of biomass generated 

during the production process at forest products facilities becomes problematic, 

consuming enormous amounts of space and eventually releasing methane during the 

natural decay process, a greenhouse gas 21 times more potent than CO2 released 

during combustion.

Install catalyst to 

reduce CO emissions CO

Catalyst oxidizes CO to CO2, so it increases greenhouse gas emissions instead of 

reducing emissions per the national goal.

Oxidizer on wood 

products or pulp and 

paper unit VOC/organic HAP

Installing an oxidizer increases auxiliary fuel usage (e.g, natural gas) and creates 

emissions of NOx, CO, and CO2 when the fuel is burned and the VOC compounds are 

oxidized. In areas where ground level ozone formation is NOx limited (e.g., Southeast 

US), this is contrary to the goal of reducing ground level ozone formation. This 

approach also is contrary to the goal of reducing fossil fuel usage.

Steam stripper

VOC/organic HAP, 

TRS

Installing a steam stripper to remove VOC/HAP/TRS from condensates prior to 

sending them to WWTP results in collateral emissions increases from burning these 

gases (NOx if ammonia is present and SO2 from burning TRS). The steam stripper 

operation also increases energy usage. If a mill is steam limited, a package boiler 

may have to be purchased to provide the steam.

Eliminate use of 

condensates in pulp 

mill/causticizing and 

use fresh water

VOC/organic HAP, 

TRS

Eliminating recycle of condensates within the mill will increase a mill's usage of fresh 

water, which may or may not be feasible, depending on the water supply. Many river 

systems have recently experienced record low flow due to extended drought periods, 

along with increasing competition from various upstream/downstream uses 

(municipalities, recreation, power generation, aquatic habitat). Energy use will also 

increase if the fresh water must be heated.

Increase the percent 

reduction required 

under PCWP MACT 

from 90% to 95% VOC/organic HAP

Increasing the percent reduction required under PCWP MACT would have the effect of 

eliminating the use of biofilters and RCOs. Facilities would have to convert RCOs to 

RTOs or replace biofilters with RTOs in order to achieve a higher percent reduction on 

a consistent basis. Increase in use of RTOs would increase natural gas usage and 

emissions of NOx, CO, and CO2. In areas where ground level ozone formation is NOx 

limited (e.g., Southeast US), this is contrary to the goal of reducing ground level ozone 

formation. This approach also is contrary to the goal of reducing fossil fuel usage.

Install biofilters to 

achieve HAP 

reductions at currently 

uncontrolled PCWP 

sources. VOC/organic HAP

Biofilters typically require a large footprint, especially when dealing with large air flows. 

The incoming air may need to be treated to adjust for moisture, temperature, or 

entrained particulate. Biofilters may not be feasible in cold climates. If there is a 

problem with the biological media, it takes time to get back to well-controlled 

conditions. If a faciltiy is shutdown for an extended period due to market conditions or 

other reasons, biofilter microbes will require replacement. Biofilters do not control all 

VOC compounds. Biofilters convert VOC and organic HAP into CO2.

SCR on boiler NOx

Installation of SCR on industrial boilers is generally not cost effective. SCR has very 

high initial and operating costs. Reheating of the flue gas may be required for SCR to 

work properly, which increases energy usage. A large volume of both catalyst and 

reagent (ammonia) are required. There are safety issues associated with storage and 

handling of ammonia, and ammonia slip can occur, which can impact plume visibility. 

The spent catalyst must be disposed of following replacement, creating a solid waste. 

If adequate particulate controls are not in place prior to the SCR, catalyst poisoning 

can also occur, and catalyst poisoning/fouling exacerbates the ammonia slip issue. 

The catalyst also oxidizes SO2 to SO3 (leading to sulfate formation, potentially 

impacting visibility) and CO to CO2.
Appendix B

Cost Estimates by Category and Regulatory Action
Costs of Clean Air Rules for the Forest Products Industry

Rule/Timing Pollutant Control

 Initial Investment 

per Unit 

Number of Units 

Upgraded/ 

Additional Units 

Affected

% Probability Total Cost (initial investment) 

 Annualized 

Capital Cost per 

Unit 

 Total Annualized 

Capital Cost 

 Typical Annual 

Operating Cost 

per Unit 

 Total Annualized 

Operating Cost 

 Total Annualized 

Cost 

 Cost Per 

Facility 

 Collateral 

Emissions/ 

Energy 

Increases 

 Estimated 

CO2 

increases, 

metric tons 

Boiler MACT HCl Scrubber (coal) 8,479,228 $ 65 551,149,820 $ 930,974 $ 60,513,288 $ 1,500,000 $ 97,500,000 $ 158,013,288 $ 4,861,947 $ water

Based on Bburning "trad

HCl Scrubber (wood) - $ 0 - $ - $ - $ 1,000,000 $ - $ - $ #DIV/0! water

Based on Bburning "trad

HCl Scrubber (gas2) - $ 0 - $ - $ - $ - $ - $ - $ - $ water Based on B

HCl Scrubber (oil) 6,896,710 $ 54 $ 372,422,340 $ 757,222 $ 40,889,971 $ 1,000,000 $ 54,000,000 $ 94,889,971 $ 3,514,443 water

Based on Bburning "trad

PM/metals

Upgrade existing controls or add FF (wood) $ 4,441,848 215 $ 954,997,320 $ 487,691 $ 104,853,572 $ 77,000 $ 16,555,000 $ 121,408,572 $ 1,129,382

Based on Bburning "trad

PM/metals

Upgrade existing controls or add FF (coal) $ 5,601,456 45 $ 252,065,520 $ 615,010 $ 27,675,439 $ 194,000 $ 8,730,000 $ 36,405,439 $ 1,618,020

Based on Bburning "trad

PM/metals

Upgrade existing controls or add FF (oil) $ 5,994,297 59 $ 353,663,523 $ 658,142 $ 38,830,354 $ 300,000 $ 17,700,000 $ 56,530,354 $ 1,916,283

Based on Bburning "trad

PM/metals Add FF (gas2) $ - 0 $ - $ - $ - $ - $ - $ - $ - Based on B

Mercury/ dioxin

Carbon injection (coal) $ 1,000,000 98 $ 98,000,000 $ 109,795 $ 10,759,873 $ 420,000 $ 41,160,000 $ 51,919,873 $ 1,059,589

Based on Bburning "tradparticulate cfollowing ca

Mercury/ dioxin

Carbon injection (wood) $ 1,000,000 253 $ 253,000,000 $ 109,795 $ 27,778,040 $ 211,000 $ 53,383,000 $ 81,161,040 $ 641,589

Based on Bburning "tradparticulate cfollowing ca

Mercury/ dioxin

Carbon injection (gas2) $ - 0 $ - $ - $ - $ - $ - $ - $ - Based on B

Mercury/ dioxin

Carbon injection (oil) $ 1,000,000 55 $ 55,000,000 $ 109,795 $ 6,038,704 $ 28,000 $ 1,540,000 $ 7,578,704 $ 275,589

Based on Bburning "tradparticulate cfollowing ca

CO

CO catalyst or combustion improvements (coal) $ 3,008,120 45 $ 135,365,400 $ 330,275 $ 14,862,393 $ - $ 14,862,393 - $ $ 660,551 CO2

Based on Bburning "trad

CO

CO catalyst or combustion improvements (wood) $ 2,341,248 214 $ 501,026,978 $ 257,056 $ 55,010,069 $ - $ 55,010,069 - $ $ 514,113 CO2

Based on Bburning "trad

CO

CO Catalyst - Gas2 (landfill gas) $ - 0 $ - $ - $ - $ - $ - $ - -$ CO2

CO

CO catalyst or combustion improvements (oil) $ 2,616,873 57 $ 149,161,761 $ 287,319 $ 16,377,160 $ - $ 16,377,160 - $ $ 574,637 CO2 4,782

Based on Bburning "tradassume avg AP-42 CO opercent con

All Energy audit $ 75,000 442 $ 33,150,000 $ 75,000 $ 33,150,000

$ 3,709,002,662 $ 436,738,863 $ 290,568,000 $ 694,156,863 note - cost 

Industrial Boilers at Forest Products Facilities

Expected timing: reproposal Oct 2011, final Apr 2012 
Costs of Clean Air Rules for the Forest Products Industry

Rule/Timing Pollutant Control

 Initial Investment 

per Unit 

Number of Units 

Upgraded/ 

Additional Units 

Affected

% Probability Total Cost (initial investment) 

 Annualized 

Capital Cost per 

Unit 

 Total Annualized 

Capital Cost 

 Typical Annual 

Operating Cost 

per Unit 

 Total Annualized 

Operating Cost 

 Total Annualized 

Cost 

 Cost Per 

Facility 

 Collateral 

Emissions/ 

Energy 

Increases 

 Estimated 

CO2 

increases, 

metric tons 

Industrial Boilers at Forest Products Facilities

Boiler GACT PM/metals Fabric Filter 500,000 $ 0 - $ - $ - $ - $ - $ - $ -$ 

No PM limits rule. Only 2 known.

Mercury

Carbon injection following FF 1,000,000 $ 0 - $ - $ - $ - $ - $ - $ -$ 

No Hg limits rule. Only 2 known.

CO/POM Tune-up 2,219 $ 1200 2,662,800 $ - $ 2,219 $ 2,662,800 $ 2,662,800 $ 4,438 $ Assumes all CO/POM Energy audit $ 5,000 1200 $ 6,000,000 $ - $ 5,000 $ 6,000,000 $ 6,000,000 $ 10,000

Assumes newill no longe

assumes req

CO/POM

Combustion controls (wood) 500,000 $ 0 $ - $ - $ - $ - $ - $ - -$ 

may increase 

NOx

No controls limits for exis

CO/POM LBMS $ 20,000 0 $ - $ - $ - $ - $ - $ - -$ 

No controls limits for exis

$ -

$ 8,662,800 $ - $ 8,662,800 $ 8,662,800 note - cost 

CISWI SO2/acid gas Scrubber $ 12,414,444 39 $ 484,163,333 $ 1,363,039 $ 53,158,531 $ 1,500,000 $ 58,500,000 $ 111,658,531 $ 2,863,039 water

PM/metals/ dioxin Fabric Filter $ 6,701,895 74 $ 495,940,248 $ 735,832 $ 54,451,573 $ 194,000 $ 14,356,000 $ 68,807,573 $ 929,832

Mercury Carbon injection 1,000,000 $ 112 $ 112,000,000 $ 109,795 $ 12,296,998 $ 420,000 $ 47,040,000 $ 59,336,998 $ 529,795

NOx SNCR $ 2,610,540 50 $ 130,527,013 $ 286,623 $ 14,331,164 $ 1,200,000 $ 60,000,000 $ 74,331,164 -$ 

NOx SCR $ 8,000,000 0 $ - $ - $ - $ - $ - $ - -$ ammoniaCO CO catalyst $ 3,445,537 23 $ 79,247,343 $ 378,301 $ 8,700,932 $ - $ - $ 8,700,932 $ 378,301 CO2 19,295

Area source boiler controls $ 7,800,000 165 $ 1,287,000,000 $ 856,398 $ 141,305,682 $ 2,500,000 $ 412,500,000 $ 553,805,682 $ 3,356,398 CO2

assumes 1/3 secondary m

Sanderdust dryers controls $ 7,800,000 85 $ 663,000,000 $ 856,398 $ 72,793,836 $ 2,500,000 $ 212,500,000 $ 285,293,836 $ 3,356,398 CO2

assumes 85 resinated wo

$ - $ - $ - $ -

$ 3,251,877,937 $ 357,038,718 $ 804,896,000 $ 1,161,934,718 note - cost p

NOx NAAQS NOx

Combustion controls $ 500,000 85 $ 42,500,000 $ 54,897 $ 4,666,272 $ - $ - $ 4,666,272 $ 54,897

Assumes liqclose to NAA 

New 1-hour standard NOx SNCR $ 4,000,000 115 $ 460,000,000 $ 439,178 $ 50,505,527 $ 1,200,000 $ 138,000,000 $ 188,505,527 $ 1,639,178

Assumes fathat are projan SCR.

Final Jan 2010, designations 2012, implementation 2013 NOx SCR $ 8,000,000 13 $ 104,000,000 $ 878,357 $ 11,418,641 $ 301,000 $ 3,913,000 $ 15,331,641 $ 1,179,357 ammonia

Assumes fathat are closSNCR

$ 606,500,000 $ 66,590,440 $ 141,913,000 $ 208,503,440 note - cost p

Ozone NAAQS NOx

Combustion controls $ 500,000 $ - $ - $ - $ - $ - $ - -$ 

NOx SNCR $ 4,000,000 $ - $ - $ - $ - $ - $ - -$ 

NOx SCR $ 8,000,000 $ - $ - $ - $ - $ - $ - -$ ammonia

More NA Areas NOx/VOC

More complex permitting/ permitting for more sources $ 40,000 80 $ 3,200,000 $ 4,392 $ 351,343 $ - $ 351,343 $ 4,392

The permitticomplex for become SerTitle V (50 tp

$ 3,200,000 $ 351,343 $ - $ 351,343 note - cost p

Addresse

Assumes bomaterials suresiduals, TDunder CISW

Expected timing: reproposal Oct 2011, final Apr 2012 Timing: Final Rule 

March 2011August 2011 for 

possible new lower standard, designations 2012, implementation 2014
Costs of Clean Air Rules for the Forest Products Industry

Rule/Timing Pollutant Control

 Initial Investment 

per Unit 

Number of Units 

Upgraded/ 

Additional Units 

Affected

% Probability Total Cost (initial investment) 

 Annualized 

Capital Cost per 

Unit 

 Total Annualized 

Capital Cost 

 Typical Annual 

Operating Cost 

per Unit 

 Total Annualized 

Operating Cost 

 Total Annualized 

Cost 

 Cost Per 

Facility 

 Collateral 

Emissions/ 

Energy 

Increases 

 Estimated 

CO2 

increases, 

metric tons 

Industrial Boilers at Forest Products Facilities

SO2 NAAQS SO2 Scrubber 8,000,000 $ 13 104,000,000 $ 878,357 $ 11,418,641 $ 1,500,000 $ 19,500,000 $ 30,918,641 $ 4,756,714 $ water

Remaining cto need scru

New 1-hour standard final 2010, designations 2012, implementation 2013 SO2

Low sulfur fuel/ fuel switch 0 - $ - $ - $ - $ - $ -$ 

Any boiler blikely have bBMACT/CIS

$ 11,418,641 104,000,000 $ 19,500,000 $ 30,918,641 $ 

CAIR/CSAPR for industrial boilers SO2 Wet Scrubber 8,000,000 $ 0 - $ - $ - $ - $ - $ - $ -$ water Covered abo

PM ESP $ 5,000,000 0 $ - $ - $ - $ - $ - $ - $ electricity 0 Covered abo

-

NOx

combustion controls $ 500,000 0 $ - $ - $ - $ - $ - $ - $ - Covered abo

NOx SNCR $ 4,000,000 0 $ - $ - $ - $ - $ - $ - $ - Covered aboNOx SCR $ 8,000,000 0 $ - $ - $ - $ - $ - $ - -$ ammonia Covered abo

$ - $ - $ - $ - note - cost 

Continuous Parametric Monitoring System Rule Shutdown to QA 600 $ - $ - $ - $ 100,000 $ 60,000,000 $ 60,000,000 $ 100,000

Shutdown 4 put cost for 100 kraft miwould be 60

in new MACT rules

Effort required to comply 600 $ - $ - $ - $ 15,000 $ 9,000,000 $ 9,000,000 $ 15,000

One facility's manpower r

$ - $ - $ 69,000,000 $ 69,000,000

PM2.5 NAAQS fully implemented PM2.5 ESP/FF upgrade 3,000,000 $ 5 $ 15,000,000 $ 329,384 $ 1,646,919 $ 65,000 $ 325,000 $ 1,971,919 $ 394,384 1,690

Assumes onachieve low MACT or CIto meet PM2calculated uincrease/yr/uCO2/MWh. 

PM2.5 WESP $ 10,000,000 10 $ 100,000,000 $ 1,097,946 $ 10,979,462 $ 1,800,000 $ 18,000,000 $ 28,979,462 $ 2,897,946 water

A few boilers 

or other con

NOx SNCR 4,000,000 $ 5 20,000,000 $ 439,178 $ 2,195,892 $ 1,200,000 $ 6,000,000 $ 8,195,892 $ 1,639,178 $ 

Assumes uncan't model NAAQS and to reduce ni

2011 NOx SCR 8,000,000 $ 5 40,000,000 $ 878,357 $ 4,391,785 $ 301,000 $ 1,505,000 $ 5,896,785 $ 1,179,357 $ ammonia

Assumes uncan't model NAAQS and to reduce ni

NOx

Combustion controls $ 500,000 5 $ 2,500,000 $ 54,897 $ 274,487 $ - $ - $ 274,487 $ 54,897

Assumes uncan't model NAAQS and to reduce ni

SO2 Scrubber $ 8,000,000 0 $ - $ 878,357 $ 1,500,000 - $ $ - $ - water

Any boiler blikely have babove.

SO2 Low sulfur fuel 0 $ - $ - $ - $ - $ -

Any boiler blikely have babove.

$ 177,500,000 $ 19,488,546 $ 25,830,000 $ 45,318,546 note - cost p

EPA working on CAIR replacement 3 - proposal and final 2012, implement 2015
Costs of Clean Air Rules for the Forest Products Industry

Rule/Timing Pollutant Control

 Initial Investment 

per Unit 

Number of Units 

Upgraded/ 

Additional Units 

Affected

% Probability Total Cost (initial investment) 

 Annualized 

Capital Cost per 

Unit 

 Total Annualized 

Capital Cost 

 Typical Annual 

Operating Cost 

per Unit 

 Total Annualized 

Operating Cost 

 Total Annualized 

Cost 

 Cost Per 

Facility 

 Collateral 

Emissions/ 

Energy 

Increases 

 Estimated 

CO2 

increases, 

metric tons 

Industrial Boilers at Forest Products Facilities

Regional Haze SO2 Scrubber 8,000,000 $ 0 - $ 878,357 $ - $ 1,500,000 $ - $ - $ water

Any boiler blikely have babove.

SO2 Low sulfur fuel 0 - $ - $ - $ - $ - $ 

Any boiler blikely have babove.

PM ESP 5,000,000 $ 0 - $ 548,973 $ - $ 77,000 $ - $ - $ electricity 0

Probably adabove

NOx SNCR 4,000,000 $ 5 20,000,000 $ 439,178 $ 2,195,892 $ 1,200,000 $ 6,000,000 $ 8,195,892 $ 1,639,178 $ 

Assumes smdidn't get cahave to instareductions

NOx SCR $ 8,000,000 5 $ 40,000,000 $ 878,357 $ 4,391,785 $ 301,000 $ 1,505,000 $ 5,896,785 $ 1,179,357 ammonia

Assumes smdidn't get cahave to instareductions

$ 60,000,000 $ 6,587,677 $ 7,505,000 $ 14,092,677 note - cost p

Total Regulatory Cost $ 7,920,743,399 $ 898,214,228 $ 1,367,874,800 $ 2,232,939,028 25,767

700 sawmills Capital Recovery Factor Calcuation for Annualized Costs:

300 converting Interest Equipment

300 wood products Rate Life, yrs CRF

400 pulp and paper 12 semi chem, 20 newsprint100 of which are kraft 7.00% 15 0.110

Cost per facility for MACT, GACT, CAIR assumes 2 boilers per facilityBART -additional control to meet milestones following 2018
Costs of Clean Air Rules for the Forest Products Industry

Rule/Timing Pollutant Control

 Initial Investment

per Unit 

Number of Units 

Upgraded/ 

Additional Units 

Affected

% Probability Total Cost (initial investment) 

 Annualized 

Capital Cost per 

Unit 

 Total 

Annualized 

Capital Cost 

 Typical Annual 

Operating Cost 

per Unit 

 Total 

Annualized 

Operating Cost 

 Total 

Annualized 

Cost 

 Cost Per 

Facility 

 Collateral 

Emissions/ 

Energy 

Increases 

 Estimated 

CO2 

increases, 

metric tons 

Ozone NAAQS NOx

LNB - direct fired units 500,000 $ 10 5,000,000 $ 54,897 $ 548,973 $ - $ - $ 548,973 $ 54,897 $ 

Assumes unitneed NOx redhave to install 

$ - - $ - $ - $ - $ 

VOC Oxidizer 5,000,000 $ 5 25,000,000 $ 548,973 $ 2,744,866 $ 1,000,000 $ 5,000,000 $ 7,744,866 $ 1,548,973 $ energy, NOx 9,225

Assumes a neto be installed at 5 plants in increase calcunatural gas*87CO2/MMBtu (

More NA Areas NOx/VOC

More complex permitting/ permitting for more sources $ 40,000 50 $ 2,000,000 $ 4,392 $ 219,589 $ - $ 219,589 - $ $ 4,392

The permitting complex for fabecome SerioV (50 tpy).

$ 32,000,000 $ 3,513,428 $ 5,000,000 $ 8,513,428

NOx NAAQS NOx

LNB - direct fired units $ 500,000 5 $ 2,500,000 $ 54,897 $ 274,487 $ - $ 274,487 - $ $ 54,897

Assumes unitcan't model coNAAQS and hon a direct fire

New 1-hour standard Final Jan 2010, designations 2012, impl. 2013 $ - $ - $ -

$ 2,500,000 $ 274,487 $ 274,487 - $ 

Continuous Parametric Monitoring System Rule Shutdown to QA 300 $ - $ - $ - $ 100,000 $ 30,000,000 $ 30,000,000 $ 100,000 Shutdown 4 ti

As part of MACT/ NSPS revs

Effort required to comply 300 $ - $ - $ - $ 15,000 $ 4,500,000 $ 4,500,000 $ 15,000

One facility's emanpower req

$ - $ - $ 34,500,000 $ 34,500,000

PM2.5 NAAQS fully implemented PM2.5 ESP upgrade $ 3,000,000 5 $ 15,000,000 $ 329,384 $ 1,646,919 $ 65,000 $ 325,000 $ 1,971,919 $ 394,384 electricity 338

Assumes unitcan't model coand have to ucomply. CO2 MWh additionavg 0.676 MT 

October 2011 NOx

LNB - direct fired units $ 500,000 5 $ 2,500,000 $ 54,897 $ 274,487 $ - $ 274,487 - $ $ 54,897

Assumes unitcan't model coand have to infired unit to im

$ 17,500,000 $ 1,921,406 $ 325,000 $ 2,246,406

PCWP MACT redo and remand VOHAP Catalytic Oxidizer 5,000,000 $ 85 $ 425,000,000 $ 548,973 $ 46,662,715 $ 1,000,000 $ 85,000,000 $ 1,548,973 131,662,715 $ energy, NOx 156,833

Assumes a neto be installed 1 for half of exfacilities. CO2 MMBtu/hr natCO2/MMBtu (

minimal residual risk costs VOHAP Biofilter $ 3,000,000 85 $ 255,000,000 $ 329,384 $ 27,997,629 $ 100,000 $ 8,500,000 $ 36,497,629 $ 429,384

Assumes a neinstalled to cohalf of existing facilities

ICR 2011, rule late 2013 VOHAP Enclosure $ 500,000 170 $ 85,000,000 $ 54,897 $ 9,332,543 $ 5,000 $ 850,000 $ 10,182,543 $ 59,897

Assumes encsources not cavg of 1 new 170 major sou

Sierra Club petition to redo MACTs VOHAP

Work practices - lumber kilns $ 55,000 225 $ 12,375,000 $ 6,039 $ 1,358,708 $ 1,300 $ 292,500 $ 1,651,208 $ 7,339

Assumes 225 have to implepractices on lupractice imple

meters for lum

VOHAP

Work practices - wood products mills 10,000 $ 170 1,700,000 $ 1,098 $ 186,651 $ 1,300 $ 221,000 $ 407,651 $ 2,398 $ 

Assumes 170 plants will havon units withoInitial cost incimplementatiosetting up rec

$ - - $ 

$ 85,538,247 779,075,000 $ 94,863,500 $ 180,401,747 $ 

Wood Products Plant Sources (Other Than Boilers)

Note - assumes no lumber kiln control, existing control requirement remains 90% instead of increasing and forcing conversion of RCO to RTOAugust 2011 for possible new lower standard, designations 2012, implementation 2014
Costs of Clean Air Rules for the Forest Products Industry

Rule/Timing Pollutant Control

 Initial Investment

per Unit 

Number of Units 

Upgraded/ 

Additional Units 

Affected

% Probability Total Cost (initial investment) 

 Annualized 

Capital Cost per 

Unit 

 Total 

Annualized 

Capital Cost 

 Typical Annual 

Operating Cost 

per Unit 

 Total 

Annualized 

Operating Cost 

 Total 

Annualized 

Cost 

 Cost Per 

Facility 

 Collateral 

Emissions/ 

Energy 

Increases 

 Estimated 

CO2 

increases, 

metric tons 

Wood Products Plant Sources (Other Than Boilers)

SSM exemption changes HAP

Shutdown process instead of vent - $ 0 - $ - $ - $ - $ - $ - $ 

Plan maintenaequipment if mnot change cuduring SSM e

Assumes RDCME will remain and operation will not be significantly impacted HAP

Duct to backup control $ 2,000,000 0 $ - $ 219,589 $ - $ - $ - $ -

Assumes it is backup controductwork onlyoption.

HAP

Install backup control $ 5,000,000 0 $ - $ 548,973 $ - $ - $ - $ - energy, NOx 0

Cost of installprocess does primary contro

$ -

$ - $ - $ - $ -

Wood Products NSPS PM WESP $ 5,000,000 5 $ 25,000,000 $ 548,973 $ 2,744,866 $ 800,000 $ 4,000,000 $ 6,744,866 $ 1,348,973 water 1,690

Assumes mills capacity and wPM controls dWESP to contcaptured by ocalculated usielectricity/yr/uCO2/MWh.

Reviewing need for NSPS for plywood/wood products, scope uncertain NOx

LNB - direct fired units $ 500,000 5 $ 2,500,000 $ 54,897 $ 274,487 $ - $ 274,487 - $ $ 54,897

Assumes mills capacity and wNOx controls 

Possible rule 2013 $ - $ - $ - $ - $ -

$ 27,500,000 $ 3,019,352 $ 4,000,000 $ 7,019,352

Total Regulatory Cost $ 858,575,000 $ 94,266,920 $ 138,688,500 $ 158,861 232,955,420

700 sawmills, approx 221 are major Capital Recovery Factor Calcuation for Annualized Costs:300 wood products, approx 170 are major Interest Equipment

Rate Life, yrs CRF

72 softwood plywood plants

7.00% 15 0.110
Costs of Clean Air Rules for the Forest Products Industry

Rule/Timing Pollutant Control

 Initial Investment

per Unit 

Number of Units 

Upgraded/ 

Additional Units 

Affected

% Probability Total Cost (initial investment) 

 Annualized 

Capital Cost per 

Unit 

 Total 

Annualized 

Capital Cost 

 Typical Annual 

Operating Cost 

per Unit 

 Total 

Annualized 

Operating Cost 

 Total 

Annualized 

Cost 

 Cost Per 

Facility 

 Collateral 

Emissions/ 

Energy 

Increases 

 Estimated 

CO2 

increases, 

metric tons 

Wood Products Plant Sources (Other Than Boilers)

Example Cost Analysis just for control of dry dryers under PCWP MACT (estimated 40 dry dryers at 31 plants):

Catalytic Oxidizer 5,000,000 $ 16 80,000,000 $ 548,973 $ 8,783,570 $ 350,000 $ 5,600,000 $ 14,383,570 $ 898,973 $ energy, NOx 29,522

Assumes a neto be installed of 31 facilities CO2 increase natural gas*87CO2/MMBtu (

Biofilter 3,000,000 $ 15 45,000,000 $ 329,384 $ 4,940,758 $ 35,000 $ 525,000 $ 5,465,758 $ 364,384 $ 

Assumes a neinstalled to cofacilities will c

Enclosure 500,000 $ 31 15,500,000 $ 54,897 $ 1,701,817 $ 5,000 $ 155,000 $ 1,856,817 $ 59,897 $ 

New enclosurwith dry dryer

$ 15,426,145 140,500,000 $ 6,280,000 $ 21,706,145 $ 
Costs of Clean Air Rules for the Forest Products Industry

Rule/Timing Pollutant Control

 Initial 

Investment per 

Unit 

Number of Units 

Upgraded/ 

Additional Units 

Affected

% Probability Total Cost (initial investment) 

 Annualized 

Capital Cost 

per Unit 

 Total Annualized 

Capital Cost 

Typical Annual 

Operating Cost 

per Unit 

 Total Annualized 

Operating Cost 

 Total Annualized 

Cost 

 Cost Per 

Facility 

 Collateral 

Emissions/ 

Energy 

Increases 

 Estimated 

CO2 

increases, 

metric tons 

P&P Cluster MACT I / III redo VOHAP Steam strippers 2,000,000 $ 25 50,000,000 $ 219,589 $ 5,489,731 $ 2,400,000 $ 60,000,000 $ 65,489,731 $ 2,619,589 $ energy 1,872,023

Assinstreducoa86.0EF)

Minimal residual risk costs - 2011 VOHAP

Paper machine controls 3,400,000 $ 200 680,000,000 $ 373,302 $ 74,660,345 $ 1,500,000 $ 300,000,000 $ 374,660,345 $ 3,746,603 $ energy 369,019

Asssort macchamacmay faciincrnatuCO2

Sierra Club petition to redo MACTs VOHAP

Pipe additional sources to combustion 2,000,000 $ 25 50,000,000 $ 219,589 $ 5,489,731 $ - $ - $ 5,489,731 $ 219,589 $ 

If Crequwasinci

$ 85,639,807 780,000,000 $ 360,000,000 $ 445,639,807 $ 

P&P MACT II redo HCl Scrubber 8,000,000 $ 120 960,000,000 $ 878,357 $ 105,402,840 $ 1,500,000 $ 180,000,000 $ 285,402,840 $ 3,805,371 $ water

Asson 7

Minimal residual risk costs - 2011 Organic HAP

BLOX control -RTO/scrubber 8,000,000 $ 27 50% 108,000,000 $ 878,357 $ 23,715,639 $ 500,000 $ 13,500,000 $ 37,215,639 $ 2,756,714 $ 

energy/ 

water 49,818

AssconinstCO2 MMkg C

Organic HAP

Recovery BoilerDCE to NDCE conversion 20,000,000 $ 26 50% 260,000,000 $ 2,195,892 $ 57,093,205 $ - $ - $ 57,093,205 $ 4,391,785 $ 

Assreconew Alteless 

Organic HAP

Organic HAP limits for lime kilns $ 2,000,000 40 $ 80,000,000 $ 219,589 $ 8,783,570 $ 1,200,000 $ 48,000,000 $ 56,783,570 $ 1,419,589

fresh water, 

heat loss 1,497,618

AssconareastripCO2 to mCO2MM

Organic HAP

Organic HAP limits for lime kilns $ 75,000 40 $ 3,000,000 $ 8,235 $ 329,384 $ - $ - $ 329,384 $ 8,235

Assconareaano

Organic HAP

Organic HAP limits for semi-chem mills 8,000,000 $ 5 $ 40,000,000 $ 878,357 $ 4,391,785 $ - $ 4,391,785 $ 878,357 energy 9,225

AssrecosmaincrnatuCO2

RTR proposal 2011; final 2012 Hg/dioxin

Carbon Injection plus fabric filter - lime kilns $ 8,000,000 108 $ 864,000,000 $ 878,357 $ 94,862,556 $ 222,000 $ 23,976,000 $ 118,838,556 $ 1,584,514

Assneediox

Hg/dioxin

Carbon Injection plus fabric filter - recovery boilers $ 8,000,000 121 $ 968,000,000 $ 878,357 $ 106,281,197 $ 222,000 $ 26,862,000 $ 133,143,197 $ 1,775,243

Assneediox

Sierra Club petition to redo MACTs PM/HAP

Smelt Tank Scrubber $ 500,000 81 $ 40,500,000 $ 54,897 $ 4,446,682 $ 75,000 $ 6,075,000 $ 10,521,682 $ 210,434 water

Ass

be nlowno lrecoHAP 

PM/HAP

PM limits for sulfite and semi-chem mills 3,000,000 $ 7 21,000,000 $ 329,384 $ 2,305,687 $ 65,000 $ 455,000 $ 2,760,687 $ 394,384 $ 

Asswill 

PM/HAP RB ESP upgrades 3,000,000 $ - $ 329,384 $ - $ 65,000 $ - $ - $ -$ energy 0

ProexisHg/

PM/HAP LK ESP upgrades 3,000,000 $ - $ 329,384 $ - $ 65,000 $ - $ - $ -$ energy 0

ProexisHg/

$ 407,612,544 3,344,500,000 $ 298,868,000 $ 706,480,544 $ 

Pulp and Paper Sources (Other Than Power Boilers)

Note - assumes that 

installing RTO is not a 

control option to 

reduce lime kiln 

organic HAP 

emissions due to cost
Costs of Clean Air Rules for the Forest Products Industry

Rule/Timing Pollutant Control

 Initial 

Investment per 

Unit 

Number of Units 

Upgraded/ 

Additional Units 

Affected

% Probability Total Cost (initial investment) 

 Annualized 

Capital Cost 

per Unit 

 Total Annualized 

Capital Cost 

Typical Annual 

Operating Cost 

per Unit 

 Total Annualized 

Operating Cost 

 Total Annualized 

Cost 

 Cost Per 

Facility 

 Collateral 

Emissions/ 

Energy 

Increases 

 Estimated 

CO2 

increases, 

metric tons 

Pulp and Paper Sources (Other Than Power Boilers)

NSPS Subpart BB NOx

LNB/Combustion Controls 500,000 $ 10 5,000,000 $ 54,897 $ 548,973 $ - $ - $ 548,973 $ 54,897 $ 

AssNSP

NOx SCR 8,000,000 $ 1 8,000,000 $ 878,357 $ 878,357 $ 301,000 $ 301,000 $ 1,179,357 $ 1,179,357 $ ammonia

AssNSPthat 

Part of integrated P&P rulemaking (2011?) SO2 Scrubber 8,000,000 $ 5 40,000,000 $ 878,357 $ 4,391,785 $ 1,500,000 $ 7,500,000 $ 11,891,785 $ 2,378,357 $ water

AssNSP

SO2 Low sulfur fuel 5 - $ - $ - $ - $ - $ -$ 

AssNSP

PM ESP upgrade 3,000,000 $ 10 30,000,000 $ 329,384 $ 3,293,839 $ 65,000 $ 650,000 $ 3,943,839 $ 394,384 $ 3,380

AssNSPincrelec0.67

$ 9,112,954 83,000,000 $ 8,451,000 $ 17,563,954 $ 

SSM exemption changes HAP

Shutdown process instead of venting during APCD malfunction or maintenance 100 - $ - $ - $ - $ - $ -$ 

Facopeinstvento smal

Changes in mill operation to account for loss of compliance exemption during SSM HAP

Duct to backup control $ 2,000,000 10 $ 20,000,000 $ 219,589 $ 2,195,892 $ - $ - $ 2,195,892 $ 219,589

Assan ecos

Assumes venting and APCD excursion allowances do not go away in Subparts S and MM. HAP

Install backup control (e.g., RTO/ scrubber for HVLC) 8,000,000 $ 10 $ 80,000,000 $ 878,357 $ 8,783,570 $ 300,000 $ 3,000,000 $ 11,783,570 $ energy, 1,178,357 NOx 18,451

Cosso pwheincrnatuCO2

$ - $ - $ - $ - $ -

$ 100,000,000 $ 10,979,462 $ 3,000,000 $ 13,979,462

Continuous Parametric Monitoring System Rule Shutdown to QA 100 $ - $ - $ 100,000 $ 10,000,000 $ 10,000,000 $ 100,000 Shu

As part of MACT/ 

NSPS revs

Effort required to comply 100 - $ - $ 15,000 $ 1,500,000 $ 1,500,000 $ 15,000 $ 

One man

$ - - $ 11,500,000 $ 11,500,000 $ 

Ozone NAAQS NOx Combustion controls 500,000 $ 50 25,000,000 $ 54,897 $ 2,744,866 $ - $ - $ 2,744,866 $ 54,897 $ 

Assconredu

NOx SCR 8,000,000 $ 5 40,000,000 $ 878,357 $ 4,391,785 $ 301,000 $ 1,505,000 $ 5,896,785 $ 1,179,357 $ ammonia

Assas a redufeas

VOC Oxidizer 5,000,000 $ 5 25,000,000 $ 548,973 $ 2,744,866 $ - $ 2,744,866 $ 548,973 $ energy, NOx 9,225

May areaNOxMMkg C

More NA areas NOx/VOC

More complex permitting/ permitting for more sources 40,000 $ 50 2,000,000 $ 4,392 $ 219,589 $ - $ - $ 219,589 $ 4,392 $ 

The combecTitle 

$ 10,101,105 92,000,000 $ 1,505,000 $ 11,606,105 $ 

CAIR Replacement SO2 Wet Scrubber 8,000,000 $ 50 400,000,000 $ 878,357 $ 43,917,850 $ 1,500,000 $ 75,000,000 $ 118,917,850 $ 2,378,357 $ water

AssCAI

PM ESP upgrade 3,000,000 $ 5 15,000,000 $ 329,384 $ 1,646,919 $ 65,000 $ 325,000 $ 1,971,919 $ 394,384 $ energy 1,690

AssCAICOelec0.67

NOx Combustion controls 500,000 $ 25 $ 12,500,000 $ 54,897 $ 1,372,433 $ - $ - $ 1,372,433 $ 54,897

AssCAI(uni

NOx SCR $ 8,000,000 5 $ 40,000,000 $ 878,357 $ 4,391,785 $ 301,000 $ 1,505,000 $ 5,896,785 $ ammonia 1,179,357

AssCAI(and 

$ 467,500,000 $ 51,328,987 $ 76,830,000 $ 128,158,987

EPA working on CAIR replacement 3 - proposal and final 2012, implement 2015August 2011 for possible new lower standard, designations 2012, implementation 2014
Costs of Clean Air Rules for the Forest Products Industry

Rule/Timing Pollutant Control

 Initial 

Investment per 

Unit 

Number of Units 

Upgraded/ 

Additional Units 

Affected

% Probability Total Cost (initial investment) 

 Annualized 

Capital Cost 

per Unit 

 Total Annualized 

Capital Cost 

Typical Annual 

Operating Cost 

per Unit 

 Total Annualized 

Operating Cost 

 Total Annualized 

Cost 

 Cost Per 

Facility 

 Collateral 

Emissions/ 

Energy 

Increases 

 Estimated 

CO2 

increases, 

metric tons 

Pulp and Paper Sources (Other Than Power Boilers)

NOx NAAQS NOx

LNB/Combustion Controls 500,000 $ 5 2,500,000 $ 54,897 $ 274,487 $ - $ - $ 274,487 $ 54,897 $ 

AsscanNAAcon

New 1-hour standard proposed June 2009; Final Jan 2010, designations 2012 NOx SCR 8,000,000 $ 1 8,000,000 $ 878,357 $ 878,357 $ 301,000 $ 301,000 $ 1,179,357 $ 1,179,357 $ ammonia

AsscanNAANOx 

$ 1,152,844 10,500,000 $ 301,000 $ 1,453,844 $ 

SO2 NAAQS SO2 Scrubber 8,000,000 $ 5 40,000,000 $ 878,357 $ 4,391,785 $ 1,500,000 $ 7,500,000 $ 11,891,785 $ 2,378,357 $ water

AsscanNAA

New 1-hour standard final 2010, designations 2012, implementation 2013 SO2 Low sulfur fuel 10 - $ - $ - $ - $ - $ -$ 

AsscanNAAfuel

$ 4,391,785 40,000,000 $ 7,500,000 $ 11,891,785 $ 

PM2.5 NAAQS fully implemented PM2.5 ESP upgrade 3,000,000 $ 5 15,000,000 $ 329,384 $ 1,646,919 $ 65,000 $ 325,000 $ 1,971,919 $ 394,384 $ energy 1,690

AsscanNAARB calcincrCO2

October 2011 NOx SCR 8,000,000 $ 1 8,000,000 $ 878,357 $ 878,357 $ 301,000 $ 301,000 $ 1,179,357 $ 1,179,357 $ ammonia

AsscanNAAto reis fe

NOx

LNB/Combustion Controls 500,000 $ 5 2,500,000 $ 54,897 $ 274,487 $ - $ - $ $ 274,487 $ 54,897

AsscanNAAto re

SO2 Scrubber $ 8,000,000 10 $ 80,000,000 $ 878,357 $ 8,783,570 $ 1,500,000 $ 15,000,000 $ 23,783,570 $ water 2,378,357

AsscanNAAto reredu

SO2 Low sulfur fuel $ 2,000,000 5 $ 10,000,000 $ 219,589 $ 1,097,946 $ - $ 1,097,946 $ 219,589

AsscanNAAfuel

$ 115,500,000 $ 12,681,279 $ 15,626,000 $ 28,307,279
Costs of Clean Air Rules for the Forest Products Industry

Rule/Timing Pollutant Control

 Initial 

Investment per 

Unit 

Number of Units 

Upgraded/ 

Additional Units 

Affected

% Probability Total Cost (initial investment) 

 Annualized 

Capital Cost 

per Unit 

 Total Annualized 

Capital Cost 

Typical Annual 

Operating Cost 

per Unit 

 Total Annualized 

Operating Cost 

 Total Annualized 

Cost 

 Cost Per 

Facility 

 Collateral 

Emissions/ 

Energy 

Increases 

 Estimated 

CO2 

increases, 

metric tons 

Pulp and Paper Sources (Other Than Power Boilers)

H2S listed as HAP H2S Scrubber 4,000,000 $ 50 200,000,000 $ 439,178 $ 21,958,925 $ 750,000 $ 37,500,000 $ 59,458,925 $ 1,189,178 $ water

Instemi

Sierra Club letter sent 3/09 H2S

Duct additional sources to control 2,000,000 $ 50 100,000,000 $ 219,589 $ 10,979,462 $ - $ - $ 10,979,462 $ 219,589 $ 

SO2 from 

combustion

Asssouconexis

H2S

Tall Oil System H2S limits - scrubber upgrade 200,000 $ 30 6,000,000 $ 21,959 $ 658,768 $ - $ - $ 658,768 $ 21,959 $ 

Asswill accWowou

H2S

Discontinue use of condensates as water at uncontrolled sources - $ 10 - $ - $ - $ - $ - $ - $ -$ 

incr fresh 

water use, 

heat loss

H2S elimreplthat Conor s

H2S WWTP upgrades 35,000,000 $ 67 2,345,000,000 $ 3,842,812 $ 257,468,395 $ 2,170,000 $ 145,390,000 $ 402,858,395 $ 6,012,812 $ 

trucking 

sludge to 

landfill

AssconMills and not 

H2S Steam stripper 2,000,000 $ 0 - $ 219,589 $ - $ 1,200,000 $ - $ - $ energy 0

InstprefconmakMA

$ 291,065,550 2,651,000,000 $ 182,890,000 $ 473,955,550 $ 

Regional Haze SO2 Scrubber 8,000,000 $ 2 16,000,000 $ 878,357 $ 1,756,714 $ 1,500,000 $ 3,000,000 $ 4,756,714 $ 2,378,357 $ water

Assscruscru

SO2 Low sulfur fuel 2 - $ - $ - $ - $ - $ -$ 

Assabo

PM ESP 5,000,000 $ - $ 548,973 $ - $ 77,000 $ - $ $ - electricity 0

adeach

NOx SCR $ 8,000,000 2 $ 16,000,000 $ 878,357 $ 1,756,714 $ 301,000 $ 602,000 $ 2,358,714 $ ammonia 1,179,357

AssneeSCR 

$ 32,000,000 $ 3,513,428 $ 3,602,000 $ 7,115,428

Total Regulatory Cost $ 7,716,000,000 $ 887,579,746 $ 970,073,000 $ 1,857,652,746 3,832,139

300 converting plants Capital Recovery Factor Calcuation for Annualized Costs:

400 pulp and paper facilities Interest Equipment

100 of which are kraft Rate Life, yrs CRF

56 DCE recovery boilers 7.00% 15 0.110

112 NDCE recovery boilers144 lime kilns

BART -additional control to meet milestones following 2018
Appendix C

Detailed Boiler MACT Cost Spreadsheets
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

ALAbitibiBowaterCP Power Boiler #1 1

MajorSource AL Boiler 300 300 8760 0 PC False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALAbitibiBowaterCP Power Boiler #2 1

MajorSource AL Boiler 300 300 8760 0 PC False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALAbitibiBowaterCP Power Boiler #3 1

MajorSource AL Boiler 300 300 8760 0 PC False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALAbitibiBowaterCP Power Boiler #4 1

MajorSource AL Boiler 300 300 8760 0 PC False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALBoiseWhitePaperJackson 102‐0001‐Z013 1

MajorSource AL Boiler 435 435 8400 1964 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Venturi Scrubber 0 96.23577545 3.764224548 0 96

ALBrewton SB‐1 1

MajorSource AL Boiler 68 68 8700 1974 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

ALChapmanForestProducts

EU 001 Wood FiredBoiler 1

MajorSource AL Boiler 86.25 86.25 8760 1974 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 0 100 0 0 

ALChapmanForestProducts

EU 002 Wood FiredBoiler 1

MajorSource AL Boiler 47.38 47.38 8760 1993 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 0 100 0 0 

ALChapmanForestProducts

EU 003 Wood FiredBoiler 1

MajorSource AL Boiler 47.38 47.38 8760 1967 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 0 100 0 0 

ALGeorgiaPacificNaheola Z015 ‐ CB1 1

MajorSource AL Boiler 425 425 8760 1958 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 38.6035845 61.3964155 0 0 61

ALGeorgiaPacificNaheola Z016 ‐ CB2 1

MajorSource AL Boiler 318 318 8760 1962 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 56.1006735 43.89932654 0 0 56

ALGeorgiaPacificNaheola Z017 ‐ PB3 1

MajorSource AL Boiler 379 379 5000 1970 N/A load following False Liquid Heavy Liquid No HAP APCD Control 0 0 100 0 

ALGPBelkLumber

EU 001 Wood FiredBoiler 1

MajorSource AL Boiler 69 69 8760 1974 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 100 0 0 

ALGPBrewtonMill

BR‐PSG0‐S021 No.

2 Power Boiler 1

MajorSource AL Boiler 390 390 8640 1963 Stoker/SlopedGrate/Other Base‐loaded True Biomass Wet Biomass

ElectrostaticPrecipitator 0 79.53986768 0 0 79

ALGPBrewtonMill

BR‐PSG0‐S026 No.

3 Power Boiler 1

MajorSource AL Boiler 608 608 8640 1981 Stoker/SlopedGrate/Other Base‐loaded True Biomass Wet Biomass

ElectrostaticPrecipitator 0 100 0 0 

ALGPBrewtonMill

BR‐PSG0‐S018 No.

1 Power Boiler 1

MajorSource AL Boiler 289 289 2880 1956 N/A load following False Liquid Light Liquid No HAP APCD Control 0 0 34.32321744 0 

ALGPEngineeredWoodProductsThornsby

EU 001 Wood FiredBoiler 1

MajorSource AL Boiler 61.77 61.77 8760 1979 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Wet Scrubber 0 100 0 0 

ALGPPetermanPly

EU001 Woodwaste

Boilerw/Multiclone and 1

MajorSource AL Boiler 224 224 8305 1977 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

Electrostatic

Precipitator 0 0 00 

ALGPTalladegaPly

EU001 Wood

Waste Boiler w

Multiclone and ESP 1

MajorSource AL Boiler 185 185 8520 1975 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

Electrostatic

Precipitator 0 0 00 

ALGulfLumber Boiler #1 1

MajorSource AL Boiler 68 68 7500 1983 Stoker/SlopedGrate/Other False Biomass Wet Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALIPCourtland

No.2 Combination

Boiler / 11CU201 1

MajorSource AL Boiler 735 735 8511 1979 PC load following False Coal Coal

Dry

ScrubberElectrostaticPrecipitator 0 0 00 

ALIPCourtland

No. 1 Combination

Boiler / 11CU101 1

MajorSource AL Boiler 398 398 1437 1970 Stoker/SlopedGrate/Other Standby False Biomass Wet Biomass Venturi Scrubber 0 0 00 

ALIPCourtland

No. 3 Combination

Boier / 11CU301 1

MajorSource AL Boiler 710 710 8291 1993 FB Base‐loaded True Biomass Wet Biomass

Electrostatic

Precipitator 0 87.74449361 3.710686781 0 87

ALIPPineHill 109‐0001‐Z010 1

MajorSource AL Boiler 770 770 8400 1968 PC Base‐loaded False Coal Coal

ElectrostaticPrecipitator 0 0 00 

ALIPPineHill 109‐0001‐Z007 1

MajorSource AL Boiler 705 705 8400 1968 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 0 00 

ALIPPrattville Z008 1

MajorSource AL Boiler 630 630 8471 1980 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 33.2403294 66.75967059 0 0 66

ALIPPrattville Z006 1

MajorSource AL Boiler 707 707 8553 1967 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 80.61485909 0 0 80

ALIPRiverdale

No. 1 Bark Boiler /

BK01 1

MajorSource AL Boiler 245 245 8400 1979 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass Venturi Scrubber 0 0 00 

ALK‐CMobile Bark Boiler #7 1

MajorSource AL Boiler 750 750 8760 0 Stoker/SlopedGrate/Other False Coal Coal Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALK‐CMobile Power Boiler #6 1

MajorSource AL Boiler 500 500 8760 0 PC False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALManningtonWoodFloors BB01 1

MajorSource AL Boiler 28.2 28.2 8760 1991 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

Electrostatic

Precipitator 0 100 0 0 

ALManningtonWoodFloors BB02 1

MajorSource AL Boiler 28.2 28.2 8760 2005 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

Electrostatic

Precipitator 0 100 0 0 

ALMeadwestvacoCottonton46

No.1 WoodResidue Boiler 1

MajorSource AL Boiler 337 337 8520 1966 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 0 0 00 

ALMeadwestvacoCottonton46

No.2 WoodResidue Boiler 1

MajorSource AL Boiler 550 550 8520 1981 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 0 00 

ALMeadwestvacoCottonton46

No.3 WoodResidue Boiler 1

MajorSource AL Boiler 915 915 8520 1990 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 0 0 00 

ALP&WAlabamaRiver Power Boiler #1 1

MajorSource AL Boiler 440 440 8760 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALP&WAlabamaRiver Power Boiler #2 1

MajorSource AL Boiler 190 190 8760 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALP&WAlabamaRiver Power Boiler #3 1

MajorSource AL Boiler 440 440 8760 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALRock‐TennDemopolis Power Boiler #3 1

MajorSource AL Boiler 250 250 8760 0 Stoker/SlopedGrate/Other False Coal Coal Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALRock‐TennDemopolis Power Boiler #1 1

MajorSource AL Boiler 225 225 8760 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALScotchLumber

EU 001 (Wood‐Fired Boiler) 1

MajorSource AL Boiler 98.5 98.5 8400 1988 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

ALSeamanTimber 1 1

MajorSource AL Boiler 28.7 28.7 7500 1996 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

ALSmurfit‐Stone Waste Boiler #1 1

MajorSource AL Boiler 225 225 8760 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass

Wet Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALSmurfit‐Stone Waste Boiler #2 1

MajorSource AL Boiler 375 375 8760 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALSmurfit‐Stone Power Boiler #1 1

MajorSource AL Boiler 170 170 8760 0 N/A False Liquid Heavy Liquid

Wet

ScrubberWetElectrostatic Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALSmurfit‐Stone Power Boiler #2 1

MajorSource AL Boiler 170 170 8760 0 N/A False Liquid Heavy Liquid

Wet

ScrubberWetElectrostatic Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ALWestervelt Wellons ‐ Unit 001 1

MajorSource AL Boiler 98 98 8200 1997 Stoker/SlopedGrate/Other Base‐loaded True Biomass Wet Biomass

Electrostatic

Precipitator 0 100 0 0 

ALWestervelt Teaford ‐ Unit 003 1

MajorSource AL Boiler 99 99 8400 2006 Stoker/SlopedGrate/Other load following True Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

ALWestFraserCitronelle Boiler‐1 1

MajorSource AL Boiler 90 90 7800 1973 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Wet Scrubber 0 100 0 0 

ALWestFraserMaplesville Boiler‐1 1

MajorSource AL Boiler 119 119 8708 1974 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 0 100 0 0 

ALWeyerhaeuserMillport Boiler No. 1 1

MajorSource AL Boiler 115 115 8100 1973 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass No HAP APCD Control 0 100 0 0 

ARAnthonyForestProducts SN‐12 1

MajorSource AR Boiler 29.56 29.56 8592 1997 Fuel Cell load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

ARAnthonyForestProducts SN‐13 1

MajorSource AR Boiler 29.56 29.56 8592 1997 Fuel Cell load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

ARAnthonyForestProducts SN‐16 1

MajorSource AR Boiler 29.75 29.75 8592 2002 Fuel Cell load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

ARDeltaNaturalKraft

Hog Fuel Boiler (SN‐

05) 1

MajorSource AR Boiler 160 160 8600 1976 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

ARDelticTimberWaldo

Wood Fired Boiler

No. 1 (SN‐13) 1

MajorSource AR Boiler 60 60 8760 1995 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

ElectrostaticPrecipitator 0 100 0 0 

ARDelticTimberWaldo

Wood Fired Boiler

No. 2 (SN‐14) 1

MajorSource AR Boiler 60 60 8760 1995 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

ElectrostaticPrecipitator 0 100 0 0 

ARDelticTimberWaldo

Wood Fired Boiler

No. 3 (SN‐20) 1

MajorSource AR Boiler 60 60 8760 2005 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

ElectrostaticPrecipitator 0 100 0 0 

ARDel‐Tin SN‐05 1

MajorSource AR Boiler 291 291 8760 1997 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ARDomtarIndustries PB2 1

Major Source AR Boiler 820 820 8520 1975 Stoker/SlopedGrate/Other load following Coal Coal Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ARDomtarIndustries PB1 1

Major Source AR Boiler 580 580 8049 1967 Stoker/SlopedGrate/Other load following Biomass Wet Biomass

Electrostatic Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ARDomtarIndustries PB3 1

Major Source AR Boiler 790 790 8160 1990 Stoker/SlopedGrate/Other load following Biomass Wet Biomass

Electrostatic Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

AREvergreenPackaging BB 1

MajorSource AR Boiler 500 500 8570 1958 Stoker/SlopedGrate/Other Base‐loaded True Biomass Dry Biomass Venturi Scrubber 0 100 0 0 

AREvergreenPackaging PB1 1

MajorSource AR Boiler 600 600 6000 1958 N/A Base‐loaded True Liquid Heavy Liquid No HAP APCD Control 0 0 40.5398746 0 

ARGBPMorrilton SN‐02 1

MajorSource AR Boiler 162 162 2880 1968 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

ARGBPMorrilton SN‐04 1

MajorSource AR Boiler 452 452 8400 1965 Stoker/SlopedGrate/Other Base‐loaded True Biomass Wet Biomass Venturi Scrubber 0 100 0 0 

ARGeorgiaPacificCrossett93

SN‐WB1 WoodBoiler 1

MajorSource AR Boiler 245 245 8400 1981 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Wet Scrubber 0 100 0 0 

ARGeorgiaPacificCrossett93

SN‐WB2 WoodBoiler 1

MajorSource AR Boiler 245 245 8400 1981 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

ARGeorgiaPacificFordyce

SN ‐ 01 Wood Fuel

Boiler 1

MajorSource AR Boiler 185 185 8147 1974 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Wet Scrubber 0 100 0 0 

ARGPCrossett92 SN‐03 1

MajorSource AR Boiler 1001 1001 8400 1984 Stoker/SlopedGrate/Other Base‐loaded True Biomass Wet Biomass Wet Scrubber 0 100 0 0 

ARGPCrossett92 SN‐22 1

MajorSource AR Boiler 720 720 8500 1973 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass Wet Scrubber 0 0 00 

ARGPFordyceOSB

SN ‐ 01A ThermalOil Heaters (#1) 1

MajorSource AR

ProcessHeater 40 40 8000 1999 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ARGPFordyceOSB

SN ‐ 01A ThermalOil Heaters (#2) 1

MajorSource AR

ProcessHeater 40 40 8000 1999 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ARGPGurdonPlyLumber

SN 02 No. 2 Wood

Residue FiredBoiler 1

MajorSource AR Boiler 135 135 8400 1979 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Venturi Scrubber 0 100 0 0 

ARGPGurdonPlyLumber

SN 01 No. 1 Wood

Residue FiredBoiler 1

MajorSource AR Boiler 135 135 8640 1979 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Venturi Scrubber 0 100 0 0 

ARLeolaLumberMill SN‐01A 1

MajorSource AR Boiler 94.15 94.15 8400 1994 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

ARLeolaLumberMill SN‐01B 1

MajorSource AR Boiler 94.15 94.15 8400 1994 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

ARLeolaLumberMill SN‐19 1

MajorSource AR Boiler 28.8 28.8 8400 1999 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ARPotlatchForestCypressBend Power Boiler #1 1

MajorSource AR Boiler 479 479 8700 1976 N/A load following True Liquid Heavy Liquid No HAP APCD Control 0 0 00 

ARPotlatchForestPrescott McBurney Boiler 1

MajorSource AR Boiler 175 175 8400 1996 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

ARPotlatchForestWarren Wellons Boiler 1

MajorSource AR Boiler 280 280 8400 1990 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass

ElectrostaticPrecipitator 0 100 0 0 

ARRiversideFurniturePlant5

SN‐01 Wood‐fired

Boiler 1

MajorSource AR Boiler 19.5 19.5 8760 1987 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

ARTemple‐Inland PWBTHERM48 1

MajorSource AR

ProcessHeater 40 40 5600 1994 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ARTemple‐Inland PDTHERM48 1

MajorSource AR

ProcessHeater 40 40 6150 1994 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

ARTemple‐Inland HTFTHERM48 1

MajorSource AR

ProcessHeater 40 40 7100 1994 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ARWestFraserHuttig SN‐24 1

MajorSource AR Boiler 29.63 29.63 8290 2004 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

ARWestFraserHuttig SN‐01 1

MajorSource AR Boiler 118 118 8650 1972 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

ARWeyerhaeuser SN‐06 1

MajorSource AR Boiler 78.5 78.5 8520 1972 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass No HAP APCD Control 0 100 0 0 

ARWeyerhaeuserDierksMill SN‐45 1

MajorSource AR Boiler 249 249 8400 1997 Fuel Cell load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

AZCatalystPaperSnowflake

Power Boiler #2

Coal 1

MajorSource AZ Boiler 1132 1132 8640 1975 PC load following False Coal Coal

Wet

ScrubberElectrostaticPrecipitator 100 0 0 0 

AZCatalystPaperSnowflake

Power Boiler #3

Natural Gas 1

MajorSource AZ Boiler 337 337 8400 2002 N/A Standby True Liquid Light Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

CAHumboldtFlakeboard143 NS‐028 1

MajorSource CA Boiler 40 40 6000 1971 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass No HAP APCD Control 0 0 00 

CARoseburgWeed Boiler 1

MajorSource CA Boiler 169.74 169.74 8400 1996 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 100 0 0 

CASierraPine‐Rocklin SPRKBL01 1

MajorSource CA Boiler 71.7 71.7 8424 1976 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass

Venturi

ScrubberElectrostaticPrecipitator 0 0 00 

FLCFRC252

Boiler #3

(McBurney) 1

MajorSource FL Boiler 85 85 8592 1980 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Wet Scrubber 0 100 0 0 

FLCFRC252

Boilers #4 & #5

(Hurst) 1

MajorSource FL Boiler 29.9 29.9 8592 1994 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

FLGPHawthorne

EU 001 Wood FiredBoiler 1

MajorSource FL Boiler 224 224 8556 1980 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 99.99980871 0 0 99

FLGPHosfordOSB

011‐THERMAL OIL

HEATER #1 1

MajorSource FL

ProcessHeater 40 40 8000 2003 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

FLGPHosfordOSB

011‐THERMAL OIL

HEATER #2 1

MajorSource FL

ProcessHeater 40 40 8000 2003 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

FLGPPalatka EU16 1

MajorSource FL Boiler 512.7 512.7 8400 1965 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 75.88820041 24.11179959 0 7

FLIPPensacola

Power Boiler 3 / EU

ID 33 1

MajorSource FL Boiler 347 347 8577 1961 PC load following True Coal Coal Venturi Scrubber 99.9692341 0 0 0 99

FLIPPensacola

Power Boiler 4 / EU

ID 37 1

MajorSource FL Boiler 666 666 8360 1981 Stoker/SlopedGrate/Other Base‐loaded True Biomass Wet Biomass Venturi Scrubber 11.4089608 80.97907581 0 0 80

FLNorthFloridaLumber 3‐3900‐150 1

MajorSource FL Boiler 23 23 8064 1981 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

FLNorthFloridaLumber 4‐5700‐01 1

MajorSource FL Boiler 42.9 42.9 8400 1979 Stoker/SlopedGrate/Other False Biomass Wet Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

FLRayonierPerformance PB06 1

MajorSource FL Boiler 525 525 8592 1983 FB load following False Biomass Wet Biomass

Wet

ScrubberElectrostaticPrecipitator 0 86.97087675 0 0 86

FLSmurfit‐Stone 7PB 1

MajorSource FL Boiler 1021 1021 8421 1981 PC Base‐loaded False Coal Coal

ElectrostaticPrecipitator 100 0 0 0 

FLSmurfit‐Stone Power Boiler #4 1

MajorSource FL Boiler 375 375 8760 0 PC False Coal Coal Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

FLSmurfit‐Stone 5PB 1

MajorSource FL Boiler 805 805 8530 1968 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass

Electrostatic

Precipitator 0 55.86707367 44.13292633 0 55

FLSmurfit‐Stone Power Boiler #3 1

MajorSource FL Boiler 375 375 8760 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

FLSmurfitStonePanamaCity

No. 4 Combination

Boiler 1

MajorSource FL Boiler 545 545 8760 0 Stoker/SlopedGrate/Other False Coal Coal Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

FLSmurfitStonePanamaCity

No. 3 Combination

Boiler 1

MajorSource FL Boiler 505 505 8760 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

GAAbitibiBowater Power Boiler #1 1

MajorSource GA Boiler 275 275 8760 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

GACaraustar CB01 1

MajorSource GA Boiler 313 313 8592 1982 PC load following True Coal Coal Fabric Filter 100 0 0 0 

GAGPCedarSprings

U501 ‐ Power

Boiler No 2 1

MajorSource GA Boiler 784 784 8200 1967 PC load following True Coal Coal Venturi Scrubber 88.3636364 0 0 0 88

GAGPCedarSprings

U500 ‐ Power

Boiler No 1 1

MajorSource GA Boiler 784 784 8200 1963 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass Venturi Scrubber 58.6560364 34.20652999 0 0 58

GAGPCelluloseBrunswick

U700 ‐‐ No. 4Power Boiler 1

MajorSource GA Boiler 800 800 8568 1961 Stoker/SlopedGrate/Other Standby False Biomass Wet Biomass

ElectrostaticPrecipitator 0 78.62667093 5.046531014 0 78

GAGPCelluloseBrunswick

U707 ‐‐ No. 7Power Boiler 1

MajorSource GA Boiler 208 208 2100 2003 N/A Base‐loaded True Liquid Light Liquid

Electrostatic

Precipitator 0 0 100 0 

GAGPCelluloseBrunswick

U706 ‐‐ No. 6Power Boiler 1

MajorSource GA Boiler 370 370 8568 1999 N/A Base‐loaded True Liquid Light Liquid

Electrostatic

Precipitator 0 0 100 0 

GAGPMadisonPly

800 Wood WasteBoiler 1

MajorSource GA Boiler 355 355 8500 1979 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 100 0 0 

GAGPMonticelloPlywood

EU700 ‐ Wood

Waste Boiler 1

MajorSource GA Boiler 235.3 235.3 8520 1985 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 100 0 0 

GAGPSRMRiincon EU BO01 1

MajorSource GA Boiler 422 422 8400 1986 FB load following False Coal Coal

Fabric FilterDry

Sorbent Injection 0 0 00 

GAGPSRMRiincon EU BO02 1

MajorSource GA Boiler 422 422 8400 1990 FB Base‐loaded False Coal Coal

Fabric FilterDry

Sorbent Injection 100 0 0 0 

GAGPSRMRiincon EU BO03 1

MajorSource GA Boiler 422 422 8400 1995 FB load following False Coal Coal

Fabric FilterDry

Sorbent Injection

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

GAGPWarmSprings

EU600 Wood FuelBoiler 1

MajorSource GA Boiler 180 180 8520 1974 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

GAGPWarrenton

400B Wood Waste

Boiler 1

MajorSource GA Boiler 85.7 85.7 7565 1973 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

ElectrostaticPrecipitator 0 100 0 0 

GAGPWoodClaxton 400 1

MajorSource GA Boiler 86 86 7000 1973 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

GAGraphicPackaging Bark Boiler #2 1

MajorSource GA Boiler 375 375 8760 0 PC False Coal Coal Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

GAGraphicPackaging Power Boiler #1 1

MajorSource GA Boiler 188 188 8760 0 PC False Coal Coal Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

GAGraphicPackaging Power Boiler #2 1

MajorSource GA Boiler 188 188 8760 0 PC False Coal Coal Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

GAInternationalPaperAugustaMills PB2A 1

MajorSource GA Boiler 686 686 8600 1965 PC load following False Coal Coal

ElectrostaticPrecipitator 95.0161347 0 0 0 95

GAInternationalPaperAugustaMills PB1A 1

MajorSource GA Boiler 680 680 8600 1959 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Venturi Scrubber 66.5223908 29.73588096 0 0 66

GAInternationalPaperAugustaMills PB3A 1

MajorSource GA Boiler 560 560 8600 1989 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

Electrostatic

Precipitator 0 93.75578168 0 0 93

GAInterstateResources Power Boiler #2 1

MajorSource GA Boiler 250 250 8760 0 FB False Biomass Wet Biomass

Wet

ScrubberElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

GAInterstateResources Power Boiler #3 1

MajorSource GA Boiler 188 188 8760 0 N/A False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

GAIPSavannah

No. 13 Power

Boiler ‐ PB13 1

MajorSource GA Boiler 1280 1280 8506 1982 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator 84.5172681 15.48273189 0 0 84

GALangboardWillacoochee EU24 1

MajorSource GA Boiler 185 185 8760 1998 FB Base‐loaded False Biomass Wet Biomass

Electrostatic

Precipitator 0 100 0 0 

GALouisianaPacificAthens TOH Wood Burner 1

MajorSource GA

ProcessHeater 40 40 8200 2004 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

GAP&GAlbany B002 1

MajorSource GA Boiler 216 216 8277 1981 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 0 00 

GAP&GAlbany B001 1

MajorSource GA Boiler 187 187 7597 1972 N/A Standby False Liquid Light Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

GAPCAValdosta 1006 1

MajorSource GA Boiler 243 243 8400 1953 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 0 100 0 0 

GAPCAValdosta 1005 1

MajorSource GA Boiler 360 360 8448 1964 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 0 100 0 0 

GARayonierBaxley PB01 1

MajorSource GA Boiler 58.74 58.74 8300 1974 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Venturi Scrubber 0 100 0 0 

GARayonierBaxley PB02 1

MajorSource GA Boiler 61.54 61.54 8400 1987 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

GARayonierJesupMill PB01 1

MajorSource GA Boiler 176 176 8352 1954 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Wet Scrubber 0 97.2825637 2.717436299 0 97

GARayonierJesupMill PB02 1

MajorSource GA Boiler 313 313 8352 1955 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Dry ScrubberCyclone

or Multiclone 0 65.59155381 34.40844619 0 65

GARayonierJesupMill PB03 1

MajorSource GA Boiler 612 612 8352 1973 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Venturi Scrubber 0 79.88612095 19.05169589 0 79

GARoseburgForestVienna

600‐wood fired

boiler 1

MajorSource GA Boiler 53.3 53.3 8194 1969 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

GASPNewsprint PB1 1

MajorSource GA Boiler 249 249 7752 1979 PC load following False Coal Coal

ElectrostaticPrecipitator 100 0 0 0 

GASPNewsprint PB2 1

MajorSource GA Boiler 550 550 8496 1989 FB load following False Coal Coal

ElectrostaticPrecipitator 30.0045638 0 50.03171372 0 30

GATempleInlandRome PB4 1

MajorSource GA Boiler 565 565 8757 1962 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass

ElectrostaticPrecipitator 0 100 0 0 

GATempleInlandRome WF 1

MajorSource GA Boiler 856 856 8757 2004 FB Base‐loaded False Biomass Wet Biomass

Electrostatic

Precipitator 0 100 0 0 

GATempleInlandThomson BW‐B001 1

MajorSource GA Boiler 40 40 6165 1974 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass

ElectrostaticPrecipitator 0 100 0 0 

GATempleInlandThomson Coen 1

MajorSource GA

ProcessHeater 30 30 6165 1997 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

GAWestFraserFolkston FOB2 1

MajorSource GA Boiler 29.26 29.26 6680 1996 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

GAWestFraserFolkston FOB1 1

MajorSource GA Boiler 28.5 28.5 6767 1969 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

GAWeyerhaeuserCoOglethorpe

Power Boiler

(U400) 1

MajorSource GA Boiler 660 660 8400 1980 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Venturi Scrubber 0 100 0 0 

GAWYPortWentworth Power Boiler #4 1 Major SourGA Boiler 375 375 Stoker/SlopedGrate/Other #N/A Biomass Wet Biomass Electrostatic Precipitato

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

IA3MKnoxville

EPN 007‐031 Boiler

2 1

MajorSource IA Boiler 72 72 4340 1974 N/A Base‐loaded False Liquid Light Liquid No HAP APCD Control 0 0 100 0 

IA3MKnoxville

EPN 007‐030 Boiler

1 1

MajorSource IA Boiler 72 72 5524 1974 N/A Base‐loaded False Liquid Light Liquid No HAP APCD Control 0 0 100 0 

IAJELD‐WENDubuque Wood Fired Boiler 1

MajorSource IA Boiler 86 86 8760 1947 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

IDChilcoLakeSawmill HFB1 1

MajorSource ID Boiler 125 125 8500 1977 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass

Electrified Filter Bed

(EFB) 0 100 0 0 

IDMoyieSprings Lumber420 HFB1 1

MajorSource ID Boiler 125 125 8500 1972 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass

Electrified Filter Bed

(EFB) 0 100 0 0 

IDPotlatch PB‐1 CE 1

MajorSource ID Boiler 27.6 27.6 8544 1964 Fuel Cell load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

IDPotlatch PB‐2 Riley 1

MajorSource ID Boiler 92 92 8544 1966 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

IDPotlatch PB‐3 Hurst 1

MajorSource ID Boiler 39.675 39.675 8640 1987 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

IDRileyCreekLumber HFB1 1

MajorSource ID Boiler 70.23 70.23 8500 1976 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

IDRileyCreekLumber HFB2 1

MajorSource ID Boiler 67.69 67.69 8500 1975 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

INJasperSeating9

Wood‐Fired Boiler

B1 1

MajorSource IN Boiler 10.5 10.5 8760 1968 Stoker/SlopedGrate/Other False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

INKimballOfficeJasper B‐1A 1

MajorSource IN Boiler 20.5 20.5 3500 1995 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

INKimballOfficeSalem Boiler 1 1

MajorSource IN Boiler 39.5 39.5 4000 1986 Stoker/SlopedGrate/Other load following False Coal Coal Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

INKimballOfficeSalem Boiler 2 1

MajorSource IN Boiler 39.5 39.5 4000 1986 Stoker/SlopedGrate/Other load following False Coal Coal Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

INNOFJasper Boiler 3 1

MajorSource IN Boiler 20.978 20.978 3500 1981 Stoker/SlopedGrate/Other load following False Coal Coal Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

INNOFJasper Boiler 1 1

MajorSource IN Boiler 10.487 10.487 3500 1977 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

INNOFJasper Boiler 2 1

MajorSource IN Boiler 10.487 10.487 3500 1978 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

KYDomtarHawesville

Biofuel Boiler B‐900 1

MajorSource KY Boiler 1050 1050 8400 1997 FB load following True Biomass Dry Biomass

Electrostatic

Precipitator 0 84.7460045 0 0 

KYHONCoOwensboro EP01 1

MajorSource KY Boiler

108.045884716157 108.0458847 5760 1980 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

KYNewPage‐Wickliffe B09 1

MajorSource KY Boiler 631 631 8433 1979 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 87.17182666 0 0 87

KYWeyerhaeuserEKY MP 01‐01 1

MajorSource KY

ProcessHeater 75 75 5458 1994 Fuel Cell load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 80.6352618 0 0 80

KYWeyerhaeuserEKY MP 01‐02 1

MajorSource KY

ProcessHeater 75 75 5458 1994 Fuel Cell load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 74.18034906 0 0 74

KYWeyerhaeuserEKY MP 01‐03 1

MajorSource KY

ProcessHeater 75 75 5458 1994 Fuel Cell load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 84.56775423 0 0 84

LABoiseCascadeFlorien B‐1 1

MajorSource LA Boiler 138 138 8592 1981 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Wet Scrubber 0 100 0 0 

LABoiseCascadeOakdale B‐1 1

MajorSource LA Boiler 138 138 8592 1977 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

LABoiseNewsprintDeRidder 69‐03 1

MajorSource LA Boiler 1591.3 1591.3 8400 1969 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Venturi Scrubber 0 70.52097331 5.357175702 0 70

LABoiseNewsprintDeRidder 79‐01 1

MajorSource LA Boiler 454.29 454.29 8400 1979 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Venturi Scrubber 0 78.79034704 0 0 78

LAGPLogansportPly EQT‐0009 1

MajorSource LA Boiler 222 222 8760 1977 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Wet Scrubber 0 100 0 0 

LAGPPortHudson

EQT0099

Combination BoilerNo. 1 1

MajorSource LA Boiler 459.2 459.2 5728 1969 Stoker/SlopedGrate/Other Base‐loaded True Biomass Wet Biomass Venturi Scrubber 0 94.26277582 0 0 94

LAGPPortHudson

EQT0109 ‐ No. 6CFB Boiler 1

MajorSource LA Boiler 1205 1205 8400 2006 FB load following True Biomass Wet Biomass

Dry Scrubber

LimestoneInjectionElectrostatic 83.0112489 13.93135275 3.057398327 0 83

LAGPSpringhillWood

01‐79 Woodwaste

Fired Boiler 1

MajorSource LA Boiler 208.8 208.8 8400 1979 Stoker/SlopedGrate/Other load following True Biomass Dry Biomass Wet Scrubber 0 100 0 0 

LAGraphic Packaging Bark Boiler 1

MajorSource LA Boiler 750 750 8760 Stoker/SlopedGrate/Other #N/A False Biomass Wet Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

LAHoodIndustries

EQT001 (wood‐

fired boiler No. 1) 1

MajorSource LA Boiler 62.4 62.4 8400 1976 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

LAHoodIndustries

EQT002 (wood‐

fired boiler No. 2) 1

MajorSource LA Boiler 62.4 62.4 8400 1981 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

LAHuntNatalbany EQT0001 1

MajorSource LA Boiler 92.3 92.3 8592 1980 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

LAHuntPollock EQT0005 1

MajorSource LA Boiler 61.5 61.5 8592 1989 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

LAHuntPollock EQT0017 1

MajorSource LA Boiler 80 80 8592 1979 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 0 00 

LAInternationalPaperRedRiverMill

EQT011 Hogged Fuel Boiler No. 2 1

Major Source LA Boiler 940 940 Stoker/SlopedGrate/Other #N/A Biomass Wet Biomass

Electrostatic Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

LAIPMansfield

1-78 - No. 1 Power Boiler / EQT005 1

Major Source LA Boiler 760 760 Stoker/SlopedGrate/Other #N/A Coal Coal

Electrostatic Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

LAIPMansfield

2-78 - No. 2 Power Boiler 1

Major Source LA Boiler 760 760 Stoker/SlopedGrate/Other #N/A Coal Coal

Electrostatic Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

LASmurfit‐Stone Power Boiler #2 1

MajorSource LA Boiler 750 750 8760 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

LATempleInlandBogalusa No. 10C Boiler 1

MajorSource LA Boiler 494.4 494.4 8600 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

LATempleInlandBogalusa No. 12 Boiler 1

MajorSource LA Boiler 787.5 787.5 8600 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

LAWestFraserJoyce 74B 1

MajorSource LA Boiler 58.3 58.3 6800 1973 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

LAWestFraserJoyce 74A 1

MajorSource LA Boiler 58.3 58.3 7550 1973 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

LAWestFraserJoyce 75A 1

MajorSource LA Boiler 154.2 154.2 8000 1973 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

LAWeyerhaeuser1043 EQT ‐ 0010 1

MajorSource LA Boiler 100 100 8400 1974 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

LAWeyerhaeuserDodson ES‐017 WFB 1

MajorSource LA Boiler 233 233 8200 1996 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

MAHollingsworth&vose Boiler #1 1

MajorSource MA Boiler 49.5 49.5 8400 1988 N/A Base‐loaded False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MAMWCustomPapers #1 Boiler 1

MajorSource MA Boiler 37.5 37.5 8760 0 N/A False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MAMWCustomPapers #2 Boiler 1

MajorSource MA Boiler 48 48 8760 0 N/A False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MANewarkAmerica Boiler #2 1

MajorSource MA Boiler 230 230 7500 2000 N/A load following True Liquid Light Liquid No HAP APCD Control 0 0 00 

MDNewPage‐Luke No. 24 1

MajorSource MD Boiler 590 590 8616 1959 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal Fabric Filter 99.0811881 0 0.91881192 0 99
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

MDNewPage‐Luke No. 25 1

MajorSource MD Boiler 785 785 8640 1965 PC load following True Coal Coal Fabric Filter 100 0 0 0 

MEDomtarBaileyville #9 Power Boiler 1

MajorSource ME Boiler 625 625 8644 1971 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Venturi Scrubber 0 0 00 

MEHuberEngineeredWoodLLC Boiler No.1 1

Major Source ME Boiler 84 84 Stoker/SlopedGrate/Other #N/A Biomass Dry Biomass

Electrostatic Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MEKatahdinPaperCo EB1 1

MajorSource ME Boiler 370 370 4500 1953 N/A load following True Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MEKatahdinPaperCo EB2 1

MajorSource ME Boiler 370 370 4500 1953 N/A load following True Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MEKatahdinPaperCo EB3 1

MajorSource ME Boiler 498 498 8300 1980 Stoker/SlopedGrate/Other Base‐loaded True Biomass Wet Biomass

Electrostatic

Precipitator 0 0 00 

MELincolnPaper&Tissue #8 Power Boiler 1

MajorSource ME Boiler 433 433 8600 1991 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

Electrostatic

Precipitator 0 89.56851608 10.36406801 0 89

MELincolnPaper&Tissue

#7 Tissue Machine

Dryer 1

MajorSource ME

ProcessHeater 14.976 14.976 8400 1978 N/A False Liquid Light Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MEMadisonPaper #7 Boiler ME6737 1

MajorSource ME Boiler 117 117 5150 1991 N/A Base‐loaded True Liquid Heavy Liquid No HAP APCD Control 0 0 100 0 

MEMadisonPaper #6 Boiler ME6454 1

MajorSource ME Boiler 99 99 8250 1980 N/A load following True Liquid Heavy Liquid Spray Dryer 0 0 100 0 

MEMadisonPaper #4 Boiler ME5949 1

MajorSource ME Boiler 119 119 8450 1968 N/A load following True Liquid Heavy Liquid Spray Dryer 0 0 100 0 

MENewPage‐Rumford Cogen#6 1

MajorSource ME Boiler 630 630 8000 1990 FB Base‐loaded False Biomass Dry Biomass

Dry Sorbent

InjectionElectrostaticPrecipitator 12.2049719 57.43989926 3.195629338 0 5

MENewPage‐Rumford PB#3 1

MajorSource ME Boiler 300 300 1900 1948 N/A Standby True Liquid Heavy Liquid Venturi Scrubber 0 0 73.19148936 0 

MENewPage‐Rumford Cogen#7 1

MajorSource ME Boiler 630 630 8000 1990 FB Base‐loaded False Biomass Dry Biomass

Dry Sorbent

InjectionElectrostaticPrecipitator 12.1239147 57.49813574 3.199404525 0 57

MERedShield Riley Boiler 1 Major SourME Boiler 188 188 Stoker/SlopedGrate/Other #N/A Biomass Wet Biomass Electrostatic Precipitato

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MERedShield Power Boiler #5 1

MajorSource ME Boiler 250 250 8760 0 N/A False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MESappiWestbrook Power Boiler #20 1 Major SourME Boiler 188 188 N/A #N/A Liquid Heavy Liquid

No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MESappiWestbrook Power Boiler #17 1 Major SourME Boiler 213 213 N/A #N/A Liquid Heavy Liquid

No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MESappiWestbrook Power Boiler #18 1 Major SourME Boiler 213 213 N/A #N/A Liquid Heavy Liquid

No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MESappiWestbrook Power Boiler #21 1 Major SourME Boiler 844 844 PC #N/A Coal Coal Electrostatic Precipitato

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MESDWarren #21 Boiler 1

MajorSource ME Boiler 1074 1074 8440 1981 Stoker/SlopedGrate/Other load following True Biomass Dry Biomass

Electrostatic

Precipitator 28.6138666 67.60790872 1.081996092 0 67

MESDWarren Power Boiler #20 1

MajorSource ME Boiler 188 188 8760 0 N/A False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MESDWarrenSomerset No1 Power Boiler 1

MajorSource ME Boiler 848 848 8375 1975 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

ElectrostaticPrecipitator 0 92.01078652 7.989213478 0 92

MESDWarrenSomerset No2 Power Boiler 1

MajorSource ME Boiler 1300 1300 8533 1989 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

DryScrubberElectrostatic Precipitator 0 62.4595014 29.93520612 0 6

MEVersoPaper Boiler #8 1

MajorSource ME Boiler 814 814 8400 1984 Stoker/SlopedGrate/Other Base‐loaded True Biomass Dry Biomass

Electrostatic

Precipitator 14.5458823 46.62256337 29.33682042 0 46

MEVersoPaper Boiler #5 1

MajorSource ME Boiler 371 371 1300 1966 N/A Standby True Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MEVersoPaperAndroscoggin WFI 1

MajorSource ME Boiler 480 480 8400 1976 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Venturi Scrubber 0 87.19900338 12.80099662 0 

MIDecorativePanels Boiler #1 1

MajorSource MI Boiler 96 96 8000 1957 Stoker/SlopedGrate/Other load following True Coal Coal

ElectrostaticPrecipitator 0 0 00 

MIDecorativePanels Boiler #2 1

MajorSource MI Boiler 96 96 8000 1957 Stoker/SlopedGrate/Other True Coal Coal

ElectrostaticPrecipitator 0 0 00 

MIDecorativePanels Boiler #3 1

MajorSource MI Boiler 79 79 8000 1962 Stoker/SlopedGrate/Other load following True Biomass Dry Biomass Cyclone or Multiclone 0 0 00 

MIEBEddyPaper EUBOILER5 1

MajorSource MI Boiler 196 196 8500 1969 PC load following False Coal Coal

ElectrostaticPrecipitator 0 0 00 

MILPCSagola TOH‐Wood 1

MajorSource MI

ProcessHeater 60 60 8400 1987 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

Dry ElectrostaticGranular Filter 0 100 0 0 

MIManistiquePaper EUBLR001 1

MajorSource MI Boiler 1047.795 1047.795 8616 1964 Stoker/SlopedGrate/Other load following False Coal Coal

ElectrostaticPrecipitator 100 0 0 0 

MIManistiquePaper EUBLR002 1

MajorSource MI Boiler 739.62 739.62 8616 1977 Stoker/SlopedGrate/Other load following False Coal Coal

ElectrostaticPrecipitator 100 0 0 0 

MIMenominee #5 Boiler 1

MajorSource MI Boiler 81.8 81.8 8400 1950 Stoker/SlopedGrate/Other Standby False Coal Coal Fabric Filter 100 0 0 0 

MIMenominee #3 Boiler 1

MajorSource MI Boiler 101 101 8544 1962 Stoker/SlopedGrate/Other load following False Coal Coal Fabric Filter 100 0 0 0 

MINeenahPaperMI Boiler 1 1

MajorSource MI Boiler 202 202 8520 1958 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal Fabric Filter 100 0 0 0 

MINewPageEscanaba Power Boiler #11 1

MajorSource MI Boiler 938 938 8760 1981 PC False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MINewPageEscanaba Power Boiler #7 1

MajorSource MI Boiler 154 154 8760 1947 N/A False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MINewPageEscanaba Power Boiler #8 1

MajorSource MI Boiler 563 563 8760 1968 N/A False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MINewPageEscanaba Power Boiler #9 1

MajorSource MI Boiler 563 563 8760 1972 Stoker/SlopedGrate/Other False Biomass Wet Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MIPackagingCorpofAmerica EUBOILER1 1

MajorSource MI Boiler 240 240 8712 1950 PC load following False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

MISmurfitStoneOntonagon No. 1 Riley Boiler 1

MajorSource MI Boiler 375 375 8200 PC #N/A True Coal Coal

Furnace Sorbent

InjectionElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MIVersoPaperQuinnesec Waste Fuel Boiler 1

MajorSource MI Boiler 624 624 8589 1981 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass

ElectrostaticPrecipitator 0 0 00 

MN3MHutchinson EU002 ‐ Boiler 4 1

MajorSource MN Boiler 110 110 3500 1967 N/A Base‐loaded False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MN3MHutchinson EU001 ‐ Boiler 3 1

MajorSource MN Boiler 110 110 5000 1967 N/A Base‐loaded False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MNAndersonCorpBayport Boiler 11 EU620 1

MajorSource MN Boiler 52 52 7008 2006 Stoker/SlopedGrate/Other Base‐loaded True Biomass Dry Biomass

ElectrostaticPrecipitator 0 80.63403738 0 0 80

MNAndersonCorpBayport Boiler 12 EU621 1

MajorSource MN Boiler 52 52 7008 2006 Stoker/SlopedGrate/Other Base‐loaded True Biomass Dry Biomass

ElectrostaticPrecipitator 0 80.63403738 0 0 80

MNBoisePaper1212 EU 430 Boiler #2 1

MajorSource MN Boiler 395 395 8350 1956 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass

Electrostatic

Precipitator 0 92.33629867 7.663701327 0 9

MNGPDuluth EU31 Boiler #1 1

MajorSource MN Boiler 43 43 8400 1971 N/A load following False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MNGPDuluth EU32 Boiler #2 1

MajorSource MN Boiler 43 43 8400 1971 N/A load following False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MNGPDuluth EU34 Boiler #4 1

MajorSource MN Boiler 60 60 8400 1974 Dutch Oven/Susp. Burner Base‐loaded False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MNGPDuluth EU35 Boiler#5 1

MajorSource MN Boiler 17 17 8400 1975 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MNGPDuluth EU33 Boiler #3 1

MajorSource MN Boiler 43 43 8400 1971 N/A load following False Liquid Heavy Liquid

ElectrostaticPrecipitator 0 0 100 0 

MNNorbordMinnesota Konus No. 1 1

MajorSource MN

ProcessHeater 20 20 8200 1980 Dutch Oven/Susp. Burner Base‐loaded False Biomass Wet Biomass

Cyclone or

Multiclone/ElectrifiedFilter Bed (EFB) 0 100 0 0 

MNNorbordMinnesota Konus No. 2 1

MajorSource MN

ProcessHeater 20 20 8200 1980 Dutch Oven/Susp. Burner Base‐loaded False Biomass Wet Biomass

Cyclone or

Multiclone/ElectrifiedFilter Bed (EFB) 0 100 0 0 

MNSappiCloquet EU002 1

MajorSource MN Boiler 300 300 8363 1965 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

Electrostatic

Precipitator 0 0 00 

MNSappiCloquet EU004 1

MajorSource MN Boiler 430 430 8532 1980 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

Electrostatic

Precipitator 0 0 00 

MNVersoPaper EU018 Bros 1

MajorSource MN Boiler 119 119 3700 1934 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal Venturi Scrubber 100 0 0 0 

MNVersoPaper EU006 B&W 1

MajorSource MN Boiler 368 368 8520 1981 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 70.5864405 20.18134521 2.334740365 0 70

MNWausauPaper‐Brainerd EU 002 1

MajorSource MN Boiler 54 54 2100 1945 Stoker/SlopedGrate/Other load following False Coal Coal

ElectrostaticPrecipitator 100 0 0 0 

MNWausauPaper‐Brainerd EU 003 1

MajorSource MN Boiler 107 107 8400 1958 Stoker/SlopedGrate/Other load following False Coal Coal

ElectrostaticPrecipitator 0 0 00 

MNWausauPaper‐Brainerd EU 004 1

MajorSource MN Boiler 107 107 8400 1958 Stoker/SlopedGrate/Other load following False Coal Coal

ElectrostaticPrecipitator 0 0 00 

MNWeyerhaeuserIronton

EU 001 ‐ 4 CellFurnace 1

MajorSource MN

ProcessHeater 225 225 8114 1990 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

ElectrostaticPrecipitator 0 100 0 0 

MSBowaterSouth Bark Boiler 1

MajorSource MS Boiler 234 234 8600 1989 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 0 92.99788788 3.76048334 0 92

MSGeorgiaPacificMonticello

AA‐403 (UT‐3)

Combination Boiler 1

MajorSource MS Boiler 917 917 8400 1967 Stoker/SlopedGrate/Other Base‐loaded True Biomass Wet Biomass

ElectrostaticPrecipitator 0 94.19760252 0.046687697 0 9

MSGPBaySprings

AA‐001 (Boiler No.

1) 1

MajorSource MS Boiler 73 73 7811 1972 Stoker/SlopedGrate/Other False Biomass Dry Biomass

ElectrostaticPrecipitator 0 100 0 0 

MSGPBaySprings

AA‐003 (Boiler No.

2) 1

MajorSource MS Boiler 59.42 59.42 7811 1990 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

MSGPGlosterPly AA‐002 1

MajorSource MS Boiler 48 48 7875 1966 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

MSGPGlosterPly AA‐001 1

MajorSource MS Boiler 48 48 7881 1966 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

MSGPGlosterPly AA‐003 1

MajorSource MS Boiler 98 98 7883 1967 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

MSGPLouisvillePly AD‐003 (Boiler #3) 1

MajorSource MS Boiler 124 124 8343 1978 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

ElectrostaticPrecipitator 0 100 0 0 

MSGPNewAugusta

AA‐015 Power

Boiler 1

MajorSource MS Boiler 642 642 8520 1983 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 100 0 0 

MSGPTaylorsvillePly AA‐700 1

MajorSource MS Boiler 155 155 8652 1979 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass

ElectrostaticPrecipitator 0 100 0 0 

MSGPTaylorsvillePly AA‐500 1

MajorSource MS Boiler 169 169 8724 1969 Stoker/SlopedGrate/Other False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

MSGPTylertownMill

AA‐001,

Woodwaste Boiler 1

MajorSource MS Boiler 30 30 8688 1978 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

MSHankinsLumber Boiler #1 (AA‐001) 1

MajorSource MS Boiler 65 65 8000 1981 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

MSHankinsLumber Boiler #2 (AA‐002) 1

MajorSource MS Boiler 23 23 8000 1973 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

MSHoodBeaumont

AA‐030 (Wood‐

Fired Boiler) 1

MajorSource MS Boiler 140 140 8400 1994 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 0 100 0 0 

MSHoodWaynesboro

AA‐001 (Wood‐

Fired Boiler) 1

MajorSource MS Boiler 100 100 8400 1971 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

MSHoodWiggins

AA‐001 (Wood‐

Fired Boiler No. 1) 1

MajorSource MS Boiler 65 65 8400 1971 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

MSHoodWiggins

AA‐002 (Wood‐

Fired Boiler No. 2) 1

MajorSource MS Boiler 65 65 8400 1971 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

MSHoodWiggins

AA‐003 (Wood‐

Fired Boiler No. 3) 1

MajorSource MS Boiler 90 90 8400 1975 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone 0 100 0 0 

MSIPVicksburg

Power Boiler‐AA‐

006 1

MajorSource MS Boiler 870 870 8400 1967 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass Wet Scrubber 0 88.24659211 0 0 88
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

MSNorbordMS Wellons No. 1 1

MajorSource MS

ProcessHeater 100 100 8400 1995 Fuel Cell load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 100 0 0 

MSNorbordMS Wellons No. 2 1

MajorSource MS

ProcessHeater 100 100 8400 1995 Fuel Cell load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 100 0 0 

MSNorbordMS Wellons No. 3 1

MajorSource MS

ProcessHeater 100 100 8400 1995 Fuel Cell load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 100 0 0 

MSSandersonPlumbing AD‐001 1

MajorSource MS Boiler 11.29 11.29 5808 1994 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone 0 0 00 

MSShuqualakLumber Boiler 1 (AA‐101) 1

MajorSource MS Boiler 42 42 8000 1988 Dutch Oven/Susp. Burner Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

MSShuqualakLumber Boiler 2 (AA‐102) 1

MajorSource MS Boiler 15 15 8000 1979 Dutch Oven/Susp. Burner Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

MSShuqualakLumber Boiler 3 (AA‐107) 1

MajorSource MS Boiler 29 29 8000 1998 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

MSShuqualakLumber Boiler 4 (AA‐108) 1

MajorSource MS Boiler 29 29 8000 2004 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

MSWeyerhaeuser1398 Boiler No. 1 1

MajorSource MS Boiler 140 140 8200 1976 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

MSWeyerhaeuser1398 Boiler No. 2 1

MajorSource MS Boiler 28.9 28.9 8200 2002 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

MSWeyerhaeuserBruce

AA‐001 No. 1Boiler 1

MajorSource MS Boiler 70 70 8496 1973 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass No HAP APCD Control 0 100 0 0 

MSWeyerhaeuserBruce

AA‐002 No. 2Boiler 1

MajorSource MS Boiler 115 115 8496 1992 Fuel Cell load following False Biomass Dry Biomass

ElectrostaticPrecipitator 0 100 0 0 

MSWeyerhaeuserColumbus AA‐012 1

MajorSource MS Boiler 1400 1400 8570 1979 Stoker/SlopedGrate/Other load following True Biomass Dry Biomass

Electrostatic

Precipitator 14.8262321 76.92055489 2.313984958 0.128555 76

MTPlumCreek Core Coen 1

MajorSource MT

ProcessHeater 50 50 8400 1985 Dutch Oven/Susp. Burner Base‐loaded False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MTPlumCreek Face Coen 1

MajorSource MT

ProcessHeater 50 50 8500 0 Dutch Oven/Susp. Burner Base‐loaded False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MTPlumCreek Line 2 Coen 1

MajorSource MT

ProcessHeater 85 85 8500 2000 Dutch Oven/Susp. Burner Base‐loaded True Biomass Dry Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MTPlumCreek Wellons Plywood 1

MajorSource MT

ProcessHeater 30 30 8500 1965 Fuel Cell Base‐loaded False Biomass Wet Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

MTPlumCreek Hog Fuel Boiler 1

MajorSource MT Boiler 292 292 8700 1973 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator 0 0 00 

MTRoseburgMissoula Boiler 1

MajorSource MT Boiler 55 55 8400 1969 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone 0 1.217587622 0 0 1.

MTSmurfitStone Multi‐Fuel Boiler 1

MajorSource MT Boiler 402.5 402.5 8520 Stoker/SlopedGrate/Other #N/A False Biomass Dry Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

NCBlueRidgePaper G11037 1

MajorSource NC Boiler 364 364 7800 1930 PC load following True Coal Coal

ElectrostaticPrecipitator 100 0 0 0 

NCBlueRidgePaper G11038 1

MajorSource NC Boiler 364 364 7890 1930 PC load following True Coal Coal

ElectrostaticPrecipitator 100 0 0 0 

NCBlueRidgePaper G11039 1

MajorSource NC Boiler 399 399 8150 1946 PC load following True Coal Coal

ElectrostaticPrecipitator 100 0 0 0 

NCBlueRidgePaper G11040 1

MajorSource NC Boiler 535 535 8350 1986 PC load following True Coal Coal

ElectrostaticPrecipitator 100 0 0 0 

NCBlueRidgePaper G11042 1

MajorSource NC Boiler 380 380 7700 1952 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 67.8933946 32.10660538 0 0 67

NCDomtar

65‐25‐0310 (No. 2

Hog Fuel Boiler) 1

MajorSource NC Boiler 889 889 8279 1982 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Cyclone or

Multiclone/ElectrifiedFilter Bed (EFB) 29.1516149 70.6691113 0.179273819 0 70

NCDomtar

66‐25‐2050 (No. 1

Package Boiler) 1

MajorSource NC Boiler 360 360 1342 1996 N/A Standby True Liquid Light Liquid Scrubber (unknown) 0 0 100 0 

NCDomtar

64‐25‐0290 (No. 1

Hog Fuel Boiler) 1

MajorSource NC Boiler 747.5 747.5 8337 1977 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Cyclone or

Multiclone/ElectrifiedFilter Bed (EFB) 17.6021553 82.12547152 0.272373193 0 82

NCGPAhoskieCNS

ES‐B1 ‐ Wood Fired

Boiler 1

MajorSource NC Boiler 91.8 91.8 7000 1973 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

NCGPDudley ES‐B1 1

MajorSource NC Boiler 254 254 8500 1979 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Wet Scrubber 0 100 0 0 

NCGPRoxboro

ES‐1 Wood fired

Boiler 1

MajorSource NC Boiler 70 70 8400 1985 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

NCGPWhiteville ES‐B2 1

MajorSource NC Boiler 241.5 241.5 8664 1984 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Wet Scrubber 0 100 0 0 

NCInternationalPaperRiegelwood PB2 1

MajorSource NC Boiler 425 425 8400 1957 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 12.7551416 60.6741094 26.57074895 0 60

NCInternationalPaperRiegelwood PB1 1

MajorSource NC Boiler 250 250 5000 1951 N/A Standby False Liquid Heavy Liquid Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

NCInternationalPaperRiegelwood PB5 1

MajorSource NC Boiler 600 600 8400 1978 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass Venturi Scrubber 11.5526316 74.77354722 13.67382119 0 74

NCJacksonPaperSylva JP‐021 1

MajorSource NC Boiler 145.1 145.1 8592 1982 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Venturi Scrubber 0 92.35407109 0 0 92

NCJeld‐Wen Boiler 1 1

MajorSource NC Boiler 43.6 43.6 8400 1988 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone 0 100 0 0 

NCKapStone PB1 1

MajorSource NC Boiler 550 550 8600 1966 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 42.5487419 57.45125807 0 0 57

NCKapStone PKG2 1

MajorSource NC Boiler 185 185 2000 1974 N/A Standby False Liquid Heavy Liquid No HAP APCD Control 0 0 100 0 

NCLAPacificRoxboro TOH#1w 1

MajorSource NC

ProcessHeater 40 40 3700 1995 Dutch Oven/Susp. Burner load following False Biomass Wet Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

NCLAPacificRoxboro TOH#2w 1

MajorSource NC

ProcessHeater 40 40 3700 1995 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

NCLPRoaringRiver Boiler #2 1

MajorSource NC Boiler 79 79 8400 1969 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Venturi Scrubber 0 100 0 0 
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

NCLPRoaringRiver Boiler #1 1

MajorSource NC Boiler 44 44 1000 1969 N/A Base‐loaded False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

NCLPRoaringRiver Boiler #3 1

MajorSource NC Boiler 183 183 8400 1979 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber 0 0 00 

NCSeaboardLumber ES‐3 1

MajorSource NC Boiler 55.82 55.82 8400 2005 FB load following False Biomass Wet Biomass

Electrostatic

Precipitator 0 100 0 0 

NCSeaboardLumber ES‐NB 1

MajorSource NC Boiler 33 33 8400 1979 FB load following False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

NCSeaboardLumber ES‐SB 1

MajorSource NC Boiler 33 33 8400 1979 FB load following False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

NCUniboardUSA

Suspension Burner

ID 1430 1

MajorSource NC

ProcessHeater 60 60 8200 1996 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

NCWestFraser ES‐BW‐1 1

MajorSource NC Boiler 104.336 104.336 8675 1974 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

NCWeyerhaeuserGrifton ES‐SEH‐2901 1

MajorSource NC

ProcessHeater 57.16 57.16 8400 1989 Fuel Cell load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 0 00 

NCWeyerhaeuserGrifton ES‐SEH‐3901 1

MajorSource NC

ProcessHeater 98 98 8400 1998 Fuel Cell load following False Biomass Dry Biomass

Electrostatic

Precipitator 0 0 00 

NCWeyerhaeuserGrifton ES‐SHE‐1901 1

MajorSource NC

ProcessHeater 57.16 57.16 8400 Fuel Cell #N/A False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

NCWeyerhaeuser‐Vanceboro ES 150‐001 1

MajorSource NC Boiler 579 579 6000 1969 N/A Base‐loaded False Liquid Heavy Liquid No HAP APCD Control 0 0 100 0 

NCWeyerhaeuser‐Vanceboro ES 161‐001 1

MajorSource NC Boiler 287 287 8760 1996 N/A load following True Liquid Heavy Liquid Dry Scrubber 0 0 100 0 

NYFinchPaper

#9 Woodwaste

Boiler (BLR‐1749) 1

MajorSource NY Boiler 172.5 172.5 8520 1977 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

NYIntlPaperTiconderoga PB1 1

MajorSource NY Boiler 855 855 8520 1970 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass

Dry ScrubberCycloneor Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OHAppletonIdeas Boiler 2 (B002) 1

MajorSource OH Boiler 156 156 8400 1960 Stoker/SlopedGrate/Other load following False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OHAppletonIdeas Boiler 4 (B003) 1

MajorSource OH Boiler 245 245 8539 1968 Stoker/SlopedGrate/Other load following False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OHGlatfelterChillicothe Power Boiler #7 1

MajorSource OH Boiler 375 375 8760 0 PC False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OHGlatfelterChillicothe Power Boiler #8 1

MajorSource OH Boiler 500 500 8760 0 PC False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OHGlatfelterChillicothe Power Boiler #6 1

MajorSource OH Boiler 288 288 8760 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass

Wet Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OHRockTennCincinnati B001 1

MajorSource OH Boiler 81 81 8136 1960 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OHSmartPapersHoldingsLLC B010 1

MajorSource OH Boiler 420 420 8540 1928 PC load following True Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OHSmurfitCoshocton B006 1

MajorSource OH Boiler 644 644 8625 1982 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OKGPMuskogeeMill B‐2 1

MajorSource OK Boiler 345 345 7320 1975 PC Base‐loaded False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OKGPMuskogeeMill B‐4 1

MajorSource OK Boiler 460 460 8496 1982 PC load following True Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OKGPMuskogeeMill B‐3 1

MajorSource OK Boiler 460 460 8640 1979 PC load following False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OKIPValliant

Bark Boiler EUGD1 1 Major Source OK Boiler 900 900 Stoker/SlopedGrate/Other #N/A Biomass Wet Biomass Venturi Scrubber Data Not Provided Data Not Provided Data Not Provided Data Not Provided 

OKIPValliant

Power Boiler EUG‐

D2 1

MajorSource OK Boiler 945 945 8642 1972 N/A load following False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OKPanPacificProducts EU 100 1

MajorSource OK Boiler 45 45 6500 1995 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

OKWeyerhaeuserWrightCity EUG 19 1

MajorSource OK Boiler 240 240 8400 1978 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORBBSMMedford B1 1

MajorSource OR Boiler 57.5 57.5 8760 1955 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORBBSMMedford B2 1

MajorSource OR Boiler 80.5 80.5 8760 1964 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORBBSMMedford B3 1

MajorSource OR Boiler 115 115 8760 1991 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORBlueHeronPaper G Boiler 1

MajorSource OR Boiler 112 112 8712 1949 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORBoiseBuilding B2 1

MajorSource OR Boiler 80 80 8600 1970 Dutch Oven/Susp. Burner Base‐loaded False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORCascadePacificPulp PB1EU 1

MajorSource OR Boiler 230 230 8603 1968 N/A Base‐loaded False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORFlakeboardEugene Boiler‐2 1

MajorSource OR Boiler 51 51 7700 1987 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORGeorgiaPacificWaunaMill

EU33 ‐ Power

Boiler 1

MajorSource OR Boiler

191.894613356164 191.8946134 8400 1965 N/A load following False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORGeorgiaPacificWaunaMill

EU35 ‐ Fluidized

Bed Boiler 1

MajorSource OR Boiler 179 179 8400 1996 FB Base‐loaded False Biomass Dry Biomass

Fabric FilterDry

Sorbent Injection

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORGPToledo

EU13 ‐ Power

Boiler #1 1

MajorSource OR Boiler 187.5 187.5 8600 1957 N/A load following False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORJeldWenKlamanthFalls BLRG 1

MajorSource OR Boiler 74 74 8760 1988 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORRosboroSpringfield DV 01.1 1

MajorSource OR Boiler 50 50 8700 1946 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORRosboroSpringfield DV 01.2 1

MajorSource OR Boiler 50 50 8700 1946 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

ORRosboroSpringfield DV 01.3 1

MajorSource OR Boiler 50 50 8700 1946 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORRoseburgCoquille Boiler 1 1

MajorSource OR Boiler 127.65 127.65 8400 1959 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORRoseburgForestDillard Boiler #1 1

MajorSource OR Boiler 309 309 8500 1966 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORRoseburgForestDillard Boiler #2 1

MajorSource OR Boiler 309 309 8500 1974 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORRoseburgForestDillard Boiler #6 1

MajorSource OR Boiler 520 520 8500 1976 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORRoseburgRiddle2 Boiler #1 1

MajorSource OR Boiler 126.5 126.5 8500 1967 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORRoseburgRiddle2 Boiler #2 1

MajorSource OR Boiler 80.5 80.5 8500 1974 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORSierraPine SPMDBL01 1

MajorSource OR Boiler 103.5 103.5 7077 1992 Dutch Oven/Susp. Burner load following True Biomass Dry Biomass

Wet

ScrubberElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORSierraPineSpringfield SPSPCU01 1

MajorSource OR

ProcessHeater 20 20 8760 1970 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORSierraPineSpringfield SPSPCU03 1

MajorSource OR

ProcessHeater 30 30 8760 1975 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORSierraPineSpringfield SPSPCU04 1

MajorSource OR

ProcessHeater 30 30 8760 1975 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORSPNewsprint B10‐EU 1

MajorSource OR Boiler 567 567 7880 1980 Stoker/SlopedGrate/Other Base‐loaded True Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORSPNewsprint B9‐EU 1

MajorSource OR Boiler 274 274 8400 1975 Stoker/SlopedGrate/Other Standby False Biomass Dry Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORStimsonLumberForestGrove Boiler 1 1

MajorSource OR Boiler 76 76 8400 1973 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORStimsonLumberForestGrove Boiler 2 1

MajorSource OR Boiler 76 76 8400 1978 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

ORStimsonLumberForestGrove Boiler 3 1

MajorSource OR Boiler 76 76 8400 1978 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

PAAppletonPapers #033 1

MajorSource PA Boiler 205.03 205.03 8400 1995 N/A Standby True Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

PAAppletonPapers #036 1

MajorSource PA Boiler 180 180 8400 1977 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

PACraftMaster

No3 Boiler Source

ID 033 1

MajorSource PA Boiler 273.2 273.2 8600 1996 Stoker/SlopedGrate/Other load following True Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

PADomtarJohnsonburg #81 Coal Boiler 1

MajorSource PA Boiler 246 246 8640 1984 PC load following True Coal Coal

Wet

ScrubberElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

PADomtarJohnsonburg #82 Coal Boiler 1

MajorSource PA Boiler

246.6666667 246.6666667 8640 1984 PC load following True Coal Coal

Wet

ScrubberElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

PAPHGlatfelter PB3 1

MajorSource PA Boiler 140.1 140.1 1374 1948 PC Standby False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

PAPHGlatfelter PB4 1

MajorSource PA Boiler 363.7 363.7 8550 1956 PC load following True Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

PAPHGlatfelter PB1 1

MajorSource PA Boiler 262.3 262.3 8574 1965 PC Base‐loaded True Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

PAPHGlatfelter PB5 1

MajorSource PA Boiler 545 545 8412 1989 FB Base‐loaded False Biomass Wet Biomass

Dry Sorbent

InjectionElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

PAProctorGambleMehoopanyPA Boiler #1 (031) 1

MajorSource PA Boiler 242 242 8400 1966 N/A load following True Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

PATeamTen

033A Babcock and

Wilcox No. 7 Boiler 1

MajorSource PA Boiler 236 236 8400 1957 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

PATemple‐Inland Westec 1

MajorSource PA

ProcessHeater 50 50 7100 1994 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

PATemple‐Inland GEKA 1

MajorSource PA

ProcessHeater 66 66 7250 1994 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCBowaterCoatedPaper

Combination BoilerNo. 1 1

MajorSource SC Boiler 405 405 8600 1959 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCBowaterCoatedPaper Power Boiler 1

MajorSource SC Boiler 375 375 1000 1959 N/A Standby False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCBowaterCoatedPaper

Combination BoilerNo. 2 1

MajorSource SC Boiler 720 720 8600 1968 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCChesterWoodProducts Boiler 1

MajorSource SC Boiler 142 142 8640 1981 Stoker/SlopedGrate/Other False Biomass Wet Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCCogenSouth B001 ‐ Main Boiler 1

MajorSource SC Boiler 1337 1337 8592 1999 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass

Spray Dryer/Fabric

Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCCollumsLumber 01 1

MajorSource SC Boiler 33.5 33.5 8200 1988 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCGPProsperityPly

B, Wood FiredBoiler 1

MajorSource SC Boiler 200 200 8520 1989 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCGPRussellville Wood‐fired boiler 1

MajorSource SC Boiler 248.67 248.67 8400 1986 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCInternationalPaperEastover No. 2 Power Boiler 1

MajorSource SC Boiler 500 500 8500 1989 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCInternationalPaperEastover No. 1 Power Boiler 1

MajorSource SC Boiler 545 545 8600 1982 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCIPGeorgetown PB01 1

MajorSource SC Boiler 592 592 8616 1982 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCIPGeorgetown PB02 1

MajorSource SC Boiler 592 592 8616 1982 Stoker/SlopedGrate/Other load following True Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCMarlboroPaper Hogged Fuel Boiler 1

MajorSource SC Boiler 470 470 8400 1989 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

SCNewSouthCamden WWB1 1

MajorSource SC Boiler 92 92 8400 1982 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCNewSouthCoConway WWB1 1

MajorSource SC Boiler 92 92 8400 1983 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCNewSouthLumberCoDarlington BLR1 1

MajorSource SC Boiler 28.93 28.93 8400 1994 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCNewSouthLumberCoDarlington BLR3 1

MajorSource SC Boiler 28.7 28.7 8400 1997 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCRoseburgForestRussellville Boiler 1

MajorSource SC Boiler 30.8 30.8 8480 1971 Dutch Oven/Susp. Burner Base‐loaded False Biomass Dry Biomass Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCSimpsonLumberGeorgetown 02 1

MajorSource SC Boiler 63.7 63.7 8592 1975 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCSimpsonLumberGeorgetown B03 1

MajorSource SC Boiler 28.7 28.7 8592 1998 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCSmurfitStone Unit 15: Boiler #3 1

MajorSource SC Boiler 343 343 8380 1963 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCSmurfitStone Unit 16: Boiler #4 1

MajorSource SC Boiler 955 955 8380 1987 Stoker/SlopedGrate/Other Base‐loaded True Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCSonocoHartsville Boiler Number 9 1

MajorSource SC Boiler 180 180 8111 1997 FB Base‐loaded False Coal Coal

Fabric FilterDry

Sorbent Injection

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCSonocoHartsville Boiler Number 3 1

MajorSource SC Boiler 178 178 8345 1950 PC Base‐loaded False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCSonocoHartsville Boiler Number 4 1

MajorSource SC Boiler 380 380 8400 1957 Stoker/SlopedGrate/Other load following False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCWestFraserNewberry B2 1

MajorSource SC Boiler 28.7 28.7 8169 1996 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCWestFraserNewberry B3 1

MajorSource SC Boiler 28.7 28.7 8196 1996 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

SCWestFraserNewberry B1 1

MajorSource SC Boiler 28.7 28.7 8386 1996 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TNArborCraft B‐1 1

MajorSource TN Boiler 17.14 17.14 8000 1990 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TNArborCraft B‐2 1

MajorSource TN Boiler 17.14 17.14 8000 1990 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TNBowaterNewsprint Power Boiler No. 1 1

MajorSource TN Boiler 214 214 8600 1956 PC load following False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TNBowaterNewsprint Power Boiler No. 2 1

MajorSource TN Boiler 460 460 8600 1957 PC load following True Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TNBowaterNewsprint Power Boiler No. 3 1

MajorSource TN Boiler 460 460 8600 1957 PC load following True Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TNBowaterNewsprint

Bubbling FluidizedBed Boiler 1

MajorSource TN Boiler 877 877 8600 1997 FB Base‐loaded False Biomass Wet Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TNDomtar2384 HFB1‐1 1

MajorSource TN Boiler 544 544 8760 1998 FB Base‐loaded True Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TNPackagingCorpCounce

Combination Boiler #2 1 TN Boiler 860 860 Stoker/SlopedGrate/Other #N/A Biomass Wet Biomass

Electrostatic Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TNPackagingCorpCounce

Combination Boiler#1 1

MajorSource TN Boiler 400 400 5689 1961 N/A Standby False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXAnthonyForestProd‐ATL EP 10.1 Superior 1

MajorSource TX Boiler 24 24 8592 1996 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXAnthonyForestProd‐ATL EP 11.1 Hurst 1

MajorSource TX Boiler 28.7 28.7 8592 1997 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXDibollTemple‐Inland COEN 1

MajorSource TX

ProcessHeater 28 28 7500 1989 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXDibollTemple‐Inland PB‐44 1

MajorSource TX Boiler 40 40 7500 1970 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXGPClevelandPlyLumber GRP‐SBOIL 1

MajorSource TX Boiler 289.8 289.8 8568 1979 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXInternationalPaperQueenCity PB02 1

Major Source TX Boiler 1084 1084 8400 Stoker/SlopedGrate/Other #N/A Biomass Wet Biomass venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXLPCarthage

TOH Primary WoodBurner 1

MajorSource TX

ProcessHeater 32 32 8600 1996 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXLPJasperOSB

Suspension Burner

#3 1

MajorSource TX

ProcessHeater 125.9642 125.9642 5613 1993 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXLPJasperOSB

Thermal Oil Heater

‐ Wood 1

MajorSource TX

ProcessHeater 34 34 7200 1993 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXMeadWestvacoEvadale 21‐2081 1

MajorSource TX Boiler 318 318 8400 1994 Stoker/SlopedGrate/Other Standby True Biomass Wet Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXNorbordTexasJefferson North Teaford 1

MajorSource TX

ProcessHeater 175 175 7000 2005 Stoker/SlopedGrate/Other Base‐loaded True Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXNorbordTexasJefferson South Teaford 1

MajorSource TX

ProcessHeater 175 175 7000 2005 Stoker/SlopedGrate/Other Base‐loaded True Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXNorbordTexasNacogdoches Core McConnell 1

MajorSource TX

ProcessHeater 40 40 8000 1986 Dutch Oven/Susp. Burner Base‐loaded False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXNorbordTexasNacogdoches Konus No. 1 1

MajorSource TX

ProcessHeater 16 16 8000 1986 Fuel Cell Base‐loaded False Biomass Wet Biomass

Electrified Filter Bed

(EFB)

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXNorbordTexasNacogdoches Konus No. 2 1

MajorSource TX

ProcessHeater 16 16 8000 1986 Fuel Cell Base‐loaded False Biomass Wet Biomass

Electrified Filter Bed

(EFB)

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXNorbordTexasNacogdoches Surface McConnell 1

MajorSource TX

ProcessHeater 40 40 8000 1986 Dutch Oven/Susp. Burner Base‐loaded False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXNorbordTexasNacogdoches Teaford 1

MajorSource TX

ProcessHeater 60 60 8000 2006 Stoker/SlopedGrate/Other Base‐loaded True Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXPinelandTemple‐Inland EPN22 1

MajorSource TX Boiler 175 175 8000 1973 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

TXPinelandTemple‐Inland EPN91 1

MajorSource TX

ProcessHeater 22 22 8000 1985 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXPinelandTemple‐Inland EPN92 1

MajorSource TX

ProcessHeater 22 22 8000 2005 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXTempleInlandFiberboard FB‐25 1

MajorSource TX Boiler 230 230 8640 1979 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXTemple‐InlandOrange Bark Boiler 1

MajorSource TX Boiler 394 394 8760 0 Stoker/SlopedGrate/Other False Biomass Wet Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

TXwestfraser Boiler‐1 1

MajorSource TX Boiler 90.7 90.7 8472 1980 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAATCPanels

Babcock & Wilcox

Boiler 1

MajorSource VA Boiler 46 46 8280 1971 Dutch Oven/Susp. Burner load following False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAATCPanels Coen Burner 1

MajorSource VA

ProcessHeater 40 40 8280 1989 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VABassettFiberboard BL2 1

MajorSource VA Boiler 35 35 6000 1977 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VABassettFiberboard BL1 1

MajorSource VA Boiler 25.1 25.1 8400 1969 N/A load following False Liquid Light Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VABearIslandPaperCoAshland

Unit Ref #2

(Combo Boiler) 1

MajorSource VA Boiler 243 243 8760 1979 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAGeorgiaPacificBrooknealGladys 5600 1

MajorSource VA

ProcessHeater 240 240 8000 1995 Fuel Cell load following False Biomass Wet Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAGeorgiaPacificEmporia WWB 1

MajorSource VA Boiler 179.4 179.4 8500 1977 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAGPBigIsland2703

PWR04 ‐ No. 4Power Boiler 1

MajorSource VA Boiler 284 284 8529 1943 PC Base‐loaded True Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAGPBigIsland2703

PWR05 ‐ No. 5Power Boiler 1

MajorSource VA Boiler 334 334 8567 1947 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAGPJarrattFiberboard

EP‐15 No. 3 Keeler

Boiler 1

MajorSource VA Boiler 86.6 86.6 8400 1978 Stoker/SlopedGrate/Other load following False Coal Coal Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAGreif BLR01 1

MajorSource VA Boiler 225 225 5141 1975 N/A load following True Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAGreif BLR05 1

MajorSource VA Boiler 244 244 8640 2000 Stoker/SlopedGrate/Other Base‐loaded True Biomass Wet Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAGreif BLR02 1

MajorSource VA Boiler 225 225 8640 1975 N/A load following False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAMeadWestVaco‐CovingtonVA PWR007 1

MajorSource VA Boiler 440 440 8200 1950 Stoker/SlopedGrate/Other load following False Coal Coal

Dry

ScrubberElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAMeadWestVaco‐CovingtonVA PWR008 1

MajorSource VA Boiler 580 580 8300 1955 Stoker/SlopedGrate/Other load following False Coal Coal

Dry

ScrubberElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAMeadWestVaco‐CovingtonVA PWR009 1

MajorSource VA Boiler 807 807 8500 1964 Stoker/SlopedGrate/Other Base‐loaded True Coal Coal

Dry

ScrubberElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VAMeadWestVaco‐CovingtonVA PWR006 1

MajorSource VA Boiler 550 550 8600 1940 PC Base‐loaded True Coal Coal

Dry

ScrubberElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VASmurfitStoneHopewell Combination Boiler 1

MajorSource VA Boiler 846 846 8575 1979 PC load following False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VASmurfitStoneWestpt PB08 1

MajorSource VA Boiler 553 553 8047 1964 PC load following True Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

VASmurfitStoneWestpt PB10 1

MajorSource VA Boiler 659 659 8285 1981 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WABoiseKettleFallsPlywood B1 1

MajorSource WA Boiler 45 45 8400 1975 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass

Cyclone or

Multiclone/ElectrifiedFilter Bed (EFB)

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WABoisePaperWallula Hog Fuel Boiler 1

MajorSource WA Boiler 270.25 270.25 8500 1978 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Venturi

ScrubberElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WAGPCamas No. 3 Power Boiler 1

MajorSource WA Boiler 276 276 8000 1948 Stoker/SlopedGrate/Other load following True Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WAGPCamas No. 5 Power Boiler 1

MajorSource WA Boiler 318 318 8340 1970 N/A load following True Liquid Heavy Liquid Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WAGraysHarborPaper No. 6 Boiler (EU2) 1

MajorSource WA Boiler 210 210 4750 1952 Dutch Oven/Susp. Burner False Biomass Wet Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WAGraysHarborPaper No. 8 Boiler (EU1) 1

MajorSource WA Boiler 400 400 7646 1976 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WAJeldWenWhiteSwan Boiler 1 1

MajorSource WA Boiler 47.3 47.3 8400 1984 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WAJeldWenWhiteSwan Boiler 2 1

MajorSource WA Boiler 37.8 37.8 3000 1997 N/A load following False Liquid Light Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WAKimberlyClarkEverett

No. 14

CogenerationBoiler 1

MajorSource WA Boiler 435 435 8180 1995 Stoker/SlopedGrate/Other Base‐loaded True Biomass Dry Biomass Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WANipponPaper #9 Package Boiler 1

MajorSource WA Boiler 115 115 1600 1964 N/A Standby False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WANipponPaper #8 Hog Fuel Boiler 1

MajorSource WA Boiler 161 161 8550 1953 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WANipponPaper #10 Package Boiler 1

MajorSource WA Boiler 115 115 3000 1982 N/A Standby False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WAPonderayAbibo FBB boiler 1

MajorSource WA Boiler 64 64 8600 0 FB False Biomass Dry Biomass

Fabric FilterDry

Sorbent Injection

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WAPort Townsend Power Boiler 1 Major SourWA Boiler 188 188 N/A #N/A Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WASierraPacific Co‐Gen 1

MajorSource WA Boiler 287.5 287.5 8400 2006 Stoker/SlopedGrate/Other Base‐loaded True Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WASimpsonLumberCompany EU1 1

MajorSource WA Boiler 185 185 8500 1986 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WASimpsonTacoma2784 #7 PB 1

MajorSource WA Boiler 345 345 8700 1991 Stoker/SlopedGrate/Other load following True Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

WAWeyerhaeuser_Raymond

Hog Fuel Boiler

EU1 1

MajorSource WA Boiler 115 115 8550 1996 Fuel Cell load following False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WAWeyerhaeuserLongview

No. 11 Hog Fuel

Boiler 1

MajorSource WA Boiler 632.5 632.5 8400 1975 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Duct Sorbent

InjectionElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIAlgoma B02 1

MajorSource WI Boiler 21 21 3949 1986 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIAlgoma B03 1

MajorSource WI Boiler 34 34 4751 1987 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIAppleton

B22 Coal Fired

Boiler 1

MajorSource WI Boiler 44 44 8232 1947 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal Cyclone or Multiclone

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIAppletonCoated B23 1

MajorSource WI Boiler 341 341 8520 1985 Stoker/SlopedGrate/Other Base‐loaded True Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIDomtar2814 B11, S11 1

MajorSource WI Boiler 120 120 7728 1972 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIDomtar2814 B10, S10 1

MajorSource WI Boiler 200 200 8400 1976 N/A Base‐loaded False Liquid Light Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIDomtarNekoosa B22 ‐ Boiler No. 7 1

MajorSource WI Boiler 148.4 148.4 1468 1942 Stoker/SlopedGrate/Other Standby False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIDomtarNekoosa B20 ‐ Boiler No. 1 1

MajorSource WI Boiler 153.4 153.4 8640 1947 PC load following False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIDomtarNekoosa B21 ‐ Boiler No. 2 1

MajorSource WI Boiler 153.4 153.4 8640 1952 PC load following False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIDomtarNekoosa B24 ‐ Boiler No. 10 1

MajorSource WI Boiler 303.2 303.2 8640 1966 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIFlambeauRiverPaper B24 1

MajorSource WI Boiler 249 249 8400 1982 Stoker/SlopedGrate/Other Base‐loaded False Biomass Wet Biomass Venturi Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIGPGreenBay2818

B25 ‐ Stoker Boiler

#5 1

MajorSource WI Boiler 200 200 4080 1950 Stoker/SlopedGrate/Other Standby False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIGPGreenBay2818

B29 ‐ Fluidized BedBoiler #9 1

MajorSource WI Boiler 486 486 7896 1992 FB Base‐loaded False Coal Coal

Fabric FilterDry

Sorbent Injection

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIGPGreenBay2818

B26 ‐ Stoker Boiler

#6 1

MajorSource WI Boiler 350 350 8304 1962 Stoker/SlopedGrate/Other load following False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIGPGreenBay2818

B28 ‐ Stoker Boiler

#8 1

MajorSource WI Boiler 235 235 8304 1975 Stoker/SlopedGrate/Other load following False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIGPGreenBay2818

B27 ‐ Cyclone

Boiler #7 1

MajorSource WI Boiler 615 615 8328 1969 Stoker/SlopedGrate/Other load following False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIGPGreenBay2818

B10 Wastepaper

Sludge‐Fired Boiler

10 1

MajorSource WI Boiler 95 95 8376 1998 FB Base‐loaded True Biomass Wet Biomass Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIGreenBayPackagingMillDivision

Boiler B26‐ Coal

Fired Boiler 1

MajorSource WI Boiler 229 229 8760 1977 Stoker/SlopedGrate/Other load following False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WILPHayward K1 Line 1 Konus 1

MajorSource WI

ProcessHeater 19.4 19.4 6575 1979 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

Electrified Filter Bed

(EFB)

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WILPHayward K2 Line 1 Konus 1

MajorSource WI

ProcessHeater 19.4 19.4 6575 1979 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

Electrified Filter Bed

(EFB)

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WILPHayward K3 Line 2 Konus 1

MajorSource WI

ProcessHeater 23.8 23.8 6575 1981 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

Electrified Filter Bed

(EFB)

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WILPHayward K4 Line 2 Konus 1

MajorSource WI

ProcessHeater 23.8 23.8 6575 1981 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

Electrified Filter Bed

(EFB)

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WINeenahPaperAppleton Union Boiler (B22) 1

MajorSource WI Boiler 60 60 5900 1957 N/A load following False Liquid Heavy Liquid No HAP APCD Control

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WINewPageBiron B24 1

MajorSource WI Boiler 445.16 445.16 8324 1986 Stoker/SlopedGrate/Other load following False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WINewPageBiron B23 1

MajorSource WI Boiler 340 340 8349 1958 PC Base‐loaded False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WINewPageKimberly B21 1

MajorSource WI Boiler 137.5 137.5 8760 1951 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WINewPageKimberly B22 1

MajorSource WI Boiler 165 165 8760 1957 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WINewPage‐Whiting B24 1

MajorSource WI Boiler 211.4 211.4 8626 1976 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WINewPage‐WisconsinRapids

Power Boiler 1 ‐ 

B21 1

MajorSource WI Boiler 412.3 412.3 8623 1966 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WINewPage‐WisconsinRapids

Power Boiler 2 ‐ 

B20 1

MajorSource WI Boiler 412.3 412.3 8623 1966 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIPCATomahawk B24 1

MajorSource WI Boiler 250.6 250.6 8312 1977 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIPCATomahawk B27 1

MajorSource WI Boiler 122 122 8381 1955 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIPCATomahawk B28 1

MajorSource WI Boiler 190.9 190.9 8397 1956 Stoker/SlopedGrate/Other Base‐loaded False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIThilmanyLLC B07 1

MajorSource WI Boiler 204 204 7989 1948 Stoker/SlopedGrate/Other load following False Biomass Wet Biomass Wet Scrubber

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIThilmanyLLC B11 1

MajorSource WI Boiler 379 379 8400 1967 Stoker/SlopedGrate/Other load following False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIThilmanyLLC B09 1

MajorSource WI Boiler 192.4 192.4 8657 1957 Stoker/SlopedGrate/Other False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIThilmanyPapersNicoletMill B23 1

MajorSource WI Boiler 105 105 8616 1960 Stoker/SlopedGrate/Other load following False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIThilmanyPapersNicoletMill B24 1

MajorSource WI Boiler 105 105 8616 1963 Stoker/SlopedGrate/Other load following False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIWausau

# 5 Power Boiler

(B24) 1

MajorSource WI Boiler 143 143 8520 1966 Stoker/SlopedGrate/Other load following False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIWausau

# 6 Power Boiler

(B20) 1

MajorSource WI Boiler 211.7 211.7 8600 1975 Stoker/SlopedGrate/Other load following False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 
FacilityID UnitID Unit CountMajor Source State ClassificatioCapacity (mCmapacity_Numeri Hours Per Year Installe Combustor Design Duty Cycle w NOx BurnAeCT Fuel Catego Baseline Fuel Cat Total Control Coal % Biomass % Liquid % Gas 2 %

F

WIWausauRhine B20 1

MajorSource WI Boiler 91 91 3000 1934 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIWausauRhine B21 1

MajorSource WI Boiler 91 91 3000 1929 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIWausauRhine B22 1

MajorSource WI Boiler 91 91 3000 1929 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIWausauRhine B23 1

MajorSource WI Boiler 91 91 3000 1941 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal Fabric Filter

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WIWausauRhine B26 1

MajorSource WI Boiler 300 300 8600 1958 Stoker/SlopedGrate/Other Base‐loaded False Coal Coal

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WVGPMtHopeOSB

5600 ‐ Wellons

Energy System 1

MajorSource WV

ProcessHeater 240 240 8000 1995 Fuel Cell load following False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WVJELD‐WENCraigsville Wood Fired Boiler 1

MajorSource WV Boiler 62.5 62.5 8760 1998 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

Electrostatic

Precipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

WVWeyerhaeuserBuckhannon 001‐01 1

MajorSource WV

ProcessHeater 116 116 8376 1995 Stoker/SlopedGrate/Other load following False Biomass Dry Biomass

ElectrostaticPrecipitator

Data Not Provided

Data Not Provided

Data Not Provided

Data Not Provided 

Represents Biomass, Coal, Liquid, Gas2 New In Inventory Added to Old, not in New (probably didn't get ICR) CISWI units kept in CISWI, not here

Shaded units indicate changes to EPA inventoryDeleted limited use units 554 Subtotal for filtered units (F9 to update)

1593 Total Unit Count 
FacilityID

ALAbitibiBowaterCPALAbitibiBowaterCPALAbitibiBowaterCPALAbitibiBowaterCPALBoiseWhitePaperJacksonALBrewtonALChapmanForestProductsALChapmanForestProductsALChapmanForestProductsALGeorgiaPacificNaheolaALGeorgiaPacificNaheolaALGeorgiaPacificNaheolaALGPBelkLumberALGPBrewtonMillALGPBrewtonMillALGPBrewtonMillALGPEngineeredWoodProductsThornsbyALGPPetermanPlyALGPTalladegaPlyALGulfLumberALIPCourtlandALIPCourtlandALIPCourtlandALIPPineHillALIPPineHillALIPPrattvilleALIPPrattvilleALIPRiverdaleALK‐CMobileALK‐CMobileALManningtonWoodFloorsALManningtonWoodFloorsALMeadwestvacoCottonton46ALMeadwestvacoCottonton46ALMeadwestvacoCottonton46ALP&WAlabamaRiverALP&WAlabamaRiverALP&WAlabamaRiverALRock‐TennDemopolisALRock‐TennDemopolisALScotchLumberALSeamanTimber

Hg %red

Dioxin 

Limit

Dioxin 

Emissions

Dioxin 

Difference

Dioxin 

%red CO Limit

CO 

Emissions

CO 

Difference CO %red

HCl 

Control 

Group

Hg 

Control 

Group

PM 

Control 

Group

Metals 

Control 

Group NAICS

PM Need 

Upgrade?

HCl Need 

Upgrade?

Hg Need 

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Dioxin 

Need 

Upgrade?

CO Need 

Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $4,462,402 $8,924,805 $1,000,000 

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $4,462,402 $8,924,805 $1,000,000 #VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $4,462,402 $8,924,805 $1,000,000 #VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $4,462,402 $8,924,805 $1,000,000 

0.005 0.009345 -0.00434 46.50% 490 400.4394 89.56063 4 5 3 3 322 1 1 $9,759,500 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $3,205,084 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 321 1 2 2 $3,696,490 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 321 1 2 2 $2,580,424 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 321 1 2 2 $2,580,424 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $5,499,578 $0 $1,000,000 $0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $4,621,173 $0 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $8,984,989 $10,268,559 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 $0 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 1 2 2 2 $7,636,120 $8,726,994 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 996.9221 -506.922 50.85% 1 4 4 4 321 1 2 1 $3,025,524 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $3,744,939 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $3,338,866 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 2 2 2 $3,205,084 $0 $1,000,000 $

0.004 N/A N/A #VALUE! 160 170.3968 -10.3968 6.10% 2 6 2 2 322 2 2 1 $7,639,561 $0 $1,000,000 $0.005 N/A N/A #VALUE! 490 160.3697 329.6303 4 5 3 3 322 2 2 $9,252,602 $0 $1,000,000 

0.02 0.003299 0.016701 430 39.81268 390.1873 5 6 2 2 322 $0 $0 $0 

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $15,711,600 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $7,450,912 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $6,964,666 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $6,915,661 $0 $1,000,000 $

#VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 2 $13,532,274 $0 $1,000,000 $#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $6,062,866 $12,125,733 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 1309.168 -819.168 62.57% 5 6 2 2 321 2 1 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 1309.168 -819.168 62.57% 5 6 2 2 321 2 1 $0 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 2734.408 -2244.41 82.08% 4 5 3 3 322 1 2 1 $8,373,595 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 259.641 230.359 5 6 2 2 322 2 2 $6,419,683 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 121.8274 368.1726 4 5 3 3 322 2 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $9,826,653 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $3,392,721 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $9,826,653 $0 $1,000,000 $#VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 2 $7,000,000 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $6,571,183 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $4,003,094 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,910,131 $0 $1,000,000 
FacilityID

ALSmurfit‐Stone

ALSmurfit‐StoneALSmurfit‐Stone

ALSmurfit‐Stone

ALWesterveltALWesterveltALWestFraserCitronelleALWestFraserMaplesvilleALWeyerhaeuserMillportARAnthonyForestProductsARAnthonyForestProductsARAnthonyForestProductsARDeltaNaturalKraftARDelticTimberWaldoARDelticTimberWaldoARDelticTimberWaldoARDel‐Tin

ARDomtarIndustriesARDomtarIndustriesARDomtarIndustriesAREvergreenPackagingAREvergreenPackagingARGBPMorriltonARGBPMorriltonARGeorgiaPacificCrossett93ARGeorgiaPacificCrossett93ARGeorgiaPacificFordyceARGPCrossett92ARGPCrossett92ARGPFordyceOSBARGPFordyceOSBARGPGurdonPlyLumberARGPGurdonPlyLumberARLeolaLumberMillARLeolaLumberMillARLeolaLumberMillARPotlatchForestCypressBendARPotlatchForestPrescottARPotlatchForestWarrenARRiversideFurniturePlant5ARTemple‐Inland

ARTemple‐Inland

Hg %red

Dioxin 

Limit

Dioxin 

Emissions

Dioxin 

Difference

Dioxin 

%red CO Limit

CO 

Emissions

CO 

Difference CO %red

HCl 

Control 

Group

Hg 

Control 

Group

PM 

Control 

Group

Metals 

Control 

Group NAICS

PM Need 

Upgrade?

HCl Need 

Upgrade?

Hg Need 

Upgrade?

Dioxin 

Need 

Upgrade?

CO Need 

Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $3,754,962 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $5,101,698 $0 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 1 4 2 2 322 2 2 $3,173,696 $0 $0 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 1 4 2 2 322 2 2 $3,173,696 $0 $0 $#VALUE! 0.005 N/A N/A #VALUE! 490 432.518 57.48204 5 6 2 2 321 2 2 $2,280,508 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 159.4541 330.5459 5 6 2 2 321 2 2 $2,294,442 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 2 2 2 $3,792,098 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 321 1 2 2 $4,483,965 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $4,392,914 $0 $1,000,000 $

4 0.007409 3.992591 690 654.2629 35.73714 5 6 5 5 321 1 $1,944,271 $0 $0 

#VALUE! 4 N/A N/A #VALUE! 690 N/A N/A #VALUE! 5 6 5 5 321 2 $1,944,271 $0 $0 #VALUE! 4 N/A N/A #VALUE! 690 541.3322 148.6678 5 6 5 5 321 2 $1,951,759 $0 $0 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 322 1 2 2 $5,355,574 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 199.1758 290.8242 5 6 2 2 321 2 2 $1,698,974 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 266.9093 223.0907 5 6 2 2 321 2 2 $1,698,974 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,698,974 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $4,381,590 $0 $1,000,000 $#VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 1 4 4 322 322 2 22 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 322 2 22 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 322 2 22 

#VALUE! 0.005 N/A N/A #VALUE! 490 502.7179 -12.7179 2.53% 4 5 3 3 322 2 2 1 $10,610,016 $0 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 20.95782 -10.9578 52.29% 5 6 6 6 322 2 2 2 1 $11,836,540 $13,527,475 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 1068.183 -578.183 54.13% 5 6 5 5 322 1 2 1 $5,395,641 $0 $1,000,000 $

0.005 0.011704 -0.0067 57.28% 490 459.7391 30.26088 4 5 3 3 322 1 1 $9,986,587 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 2 2 2 $6,915,661 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $3,951,806 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 1 2 2 $5,843,016 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 322 2 2 $0 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 322 2 2 2 $13,204,852 $0 $1,000,000 $

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,331,149 $0 $1,000,000 #VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,331,149 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 339.1004 150.8996 4 5 3 3 321 2 2 $4,836,535 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 321.0572 168.9428 4 5 3 3 321 2 2 $4,836,535 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 237.9658 252.0342 5 6 2 2 321 2 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 391.8251 98.17495 5 6 2 2 321 2 $0 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,914,122 $0 $1,000,000 

#VALUE! 4 N/A N/A #VALUE! 10 57.5983 -47.5983 82.64% 5 6 6 6 322 1 2 2 1 $10,340,352 $11,817,546 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 $0 $0 $1,000,000 $

0.005 0.010353 -0.00535 51.70% 490 285.9735 204.0265 5 6 2 2 321 1 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,514,798 $0 $1,000,000 

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,331,149 $0 $1,000,000 #VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,331,149 $0 $1,000,000 
FacilityID

ARTemple‐Inland

ARWestFraserHuttigARWestFraserHuttigARWeyerhaeuserARWeyerhaeuserDierksMillAZCatalystPaperSnowflakeAZCatalystPaperSnowflakeCAHumboldtFlakeboard143CARoseburgWeedCASierraPine‐Rocklin

FLCFRC252FLCFRC252FLGPHawthorneFLGPHosfordOSBFLGPHosfordOSBFLGPPalatkaFLIPPensacolaFLIPPensacolaFLNorthFloridaLumberFLNorthFloridaLumberFLRayonierPerformanceFLSmurfit‐StoneFLSmurfit‐StoneFLSmurfit‐StoneFLSmurfit‐StoneFLSmurfitStonePanamaCityFLSmurfitStonePanamaCityGAAbitibiBowaterGACaraustarGAGPCedarSpringsGAGPCedarSpringsGAGPCelluloseBrunswickGAGPCelluloseBrunswickGAGPCelluloseBrunswickGAGPMadisonPlyGAGPMonticelloPlywoodGAGPSRMRiinconGAGPSRMRiinconGAGPSRMRiinconGAGPWarmSpringsGAGPWarrentonGAGPWoodClaxton

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Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,331,149 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 64.80667 425.1933 5 6 5 5 321 1 2 $1,947,032 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 475.1572 14.84284 5 6 5 5 321 1 2 $4,461,319 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $3,493,460 $0 $1,000,000 $

4 0.021378 3.978622 690 152.1682 537.8318 5 6 2 2 321 $0 $0 $0 

#VALUE! 0.004 N/A N/A #VALUE! 160 2.226869 157.7731 1 4 2 2 322 2 $0 $0 $1,000,000 

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $8,373,595 $9,569,823 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,331,149 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 $0 $0 $1,000,000 $

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 4 5 2 2 321 2 2 $0 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 363.9491 126.0509 1 4 4 4 321 2 2 $3,664,252 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,957,658 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 $0 $0 $1,000,000 $

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,332,085 $0 $1,000,000 

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,332,085 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 301.1009 188.8991 5 6 2 2 322 1 2 $6,154,800 $0 $1,000,000 

44.71% 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 4 5 3 3 322 2 1 2 $8,521,808 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $12,601,393 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,672,518 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,431,131 $0 $1,000,000 $

0.02 N/A N/A #VALUE! 430 72.01906 357.9809 1 4 2 2 322 1 $6,242,975 $0 $0 

0.004 N/A N/A #VALUE! 160 15.2574 144.7426 5 6 2 2 322 1 2 $0 $18,609,788 $1,000,000 

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $8,927,972 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 387.5904 102.4096 5 6 2 2 322 2 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $8,927,972 $0 $1,000,000 $

#VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 1 4 4 4 322 2 2 2 $11,173,055 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 322 2 2 2 $10,673,549 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $7,411,970 $0 $1,000,000 $

0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 3 1 1 322 1 1 2 $4,577,439 $9,154,878 $1,000,000 

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 4 5 3 3 322 1 2 2 $13,897,084 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 1 2 2 $13,897,084 $0 $1,000,000 $0.005 N/A N/A #VALUE! 490 217.2575 272.7425 5 6 2 2 322 2 $0 $0 $1,000,000 

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $0 $7,164,139 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 1.453583 8.546417 5 6 2 2 322 1 2 2 $5,060,775 $10,121,550 $1,000,000 

0.005 0.002012 0.002988 490 2475.007 -1985.01 80.20% 5 6 2 2 321 1 $0 $0 $0 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 $0 $0 $1,000,000 $

0.002 N/A N/A #VALUE! 82 N/A N/A #VALUE! 3 2 1 1 322 1 2 $5,476,252 $0 $1,000,000 

0.002 N/A N/A #VALUE! 82 N/A N/A #VALUE! 3 2 1 1 322 2 $0 $0 $1,000,000 

#VALUE! 0.002 N/A N/A #VALUE! 82 N/A N/A #VALUE! 3 2 1 1 322 2 $0 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $5,747,746 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 $0 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 $0 $0 $1,000,000 $
FacilityID

GAGraphicPackagingGAGraphicPackagingGAGraphicPackagingGAInternationalPaperAugustaMillsGAInternationalPaperAugustaMillsGAInternationalPaperAugustaMillsGAInterstateResourcesGAInterstateResourcesGAIPSavannahGALangboardWillacoocheeGALouisianaPacificAthensGAP&GAlbanyGAP&GAlbanyGAPCAValdostaGAPCAValdostaGARayonierBaxleyGARayonierBaxleyGARayonierJesupMillGARayonierJesupMillGARayonierJesupMillGARoseburgForestViennaGASPNewsprintGASPNewsprintGATempleInlandRomeGATempleInlandRomeGATempleInlandThomsonGATempleInlandThomsonGAWestFraserFolkstonGAWestFraserFolkstonGAWeyerhaeuserCoOglethorpeGAWYPortWentworthIA3MKnoxvilleIA3MKnoxvilleIAJELD‐WENDubuqueIDChilcoLakeSawmillIDMoyieSprings Lumber420IDPotlatchIDPotlatchIDPotlatchIDRileyCreekLumberIDRileyCreekLumberINJasperSeating9

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CO Need 

Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $8,927,972 $0 $1,000,000 

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $5,899,684 $0 $1,000,000 #VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $5,899,684 $0 $1,000,000 

0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 1 2 $0 $14,659,544 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 1 2 2 $12,759,668 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $

#VALUE! 0.02 N/A N/A #VALUE! 430 N/A N/A #VALUE! 1 4 2 2 322 2 $4,000,000 $0 $0 

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $5,899,684 $6,742,496 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $

#VALUE! 0.02 N/A N/A #VALUE! 430 N/A N/A #VALUE! 5 6 2 2 321 2 $3,338,866 $0 $0 

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,332,085 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 384.4832 105.5168 5 6 2 2 322 2 $0 $0 $1,000,000 

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $5,880,835 $6,720,954 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 3420.103 -2930.1 85.67% 4 5 3 3 322 1 2 1 $6,881,733 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 3420.103 -2930.1 85.67% 4 5 3 3 322 1 2 1 $8,711,953 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 321 1 2 2 $2,935,583 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 350.2887 139.7113 5 6 2 2 321 2 $0 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 322 1 2 2 $5,670,765 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 2 6 5 5 322 1 2 2 $8,010,519 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 347.8726 142.1274 4 5 3 3 322 1 2 $11,978,016 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,769,302 $0 $1,000,000 $

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $3,990,392 $7,980,785 $1,000,000 

0.002 N/A N/A #VALUE! 82 117.6226 -35.6226 30.29% 5 6 2 2 322 2 1 $0 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 130.3333 359.6667 5 6 2 2 322 2 $0 $0 $1,000,000 

0.02 0.009674 0.010326 430 129.2 300.8 5 6 2 2 322 $0 $0 $0 

#VALUE! 0.2 N/A N/A #VALUE! 470 563.5428 -93.5428 16.60% 5 6 2 2 321 2 2 1 $1,332,085 $0 $1,000,000 

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,961,583 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 13303.34 -12813.3 96.32% 5 6 5 5 321 2 2 1 $1,932,407 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 9463.896 -8973.9 94.82% 5 6 5 5 321 2 2 1 $1,902,133 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 1 2 2 $12,533,155 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 562 322 2 2 2 $5,101,698 $0 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $3,316,909 $3,790,753 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $3,316,909 $3,790,753 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $3,690,057 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 51.0253 438.9747 5 6 2 2 321 2 $0 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 1883.684 -1393.68 73.99% 5 6 2 2 321 2 1 $0 $0 $1,000,000 $

4 0.5656 3.4344 690 272.1349 417.8651 5 6 2 2 321 $0 $0 $0 

0.005 N/A N/A #VALUE! 490 454.9756 35.02441 5 6 2 2 321 2 $0 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,325,581 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 161.3135 328.6865 5 6 2 2 321 2 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 1308.888 -818.888 62.56% 5 6 2 2 321 1 2 1 $1,826,462 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 6 5 321 2 2 2 $1,044,835 $0 $1,000,000 
FacilityID

INKimballOfficeJasperINKimballOfficeSalemINKimballOfficeSalemINNOFJasperINNOFJasperINNOFJasperKYDomtarHawesvilleKYHONCoOwensboroKYNewPage‐Wickliffe

KYWeyerhaeuserEKYKYWeyerhaeuserEKYKYWeyerhaeuserEKYLABoiseCascadeFlorienLABoiseCascadeOakdaleLABoiseNewsprintDeRidderLABoiseNewsprintDeRidderLAGPLogansportPlyLAGPPortHudsonLAGPPortHudsonLAGPSpringhillWoodLAGraphic Packaging

LAHoodIndustriesLAHoodIndustriesLAHuntNatalbanyLAHuntPollockLAHuntPollock

LAInternationalPaperRedRiverMillLAIPMansfieldLAIPMansfieldLASmurfit‐Stone

LATempleInlandBogalusaLATempleInlandBogalusaLAWestFraserJoyceLAWestFraserJoyceLAWestFraserJoyceLAWeyerhaeuser1043LAWeyerhaeuserDodsonMAHollingsworth&voseMAMWCustomPapersMAMWCustomPapersMANewarkAmericaMDNewPage‐Luke

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PM Need 

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Need 

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CO Need 

Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,560,941 $0 $1,000,000 

#VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 2 $2,313,621 $2,644,139 $1,000,000 #VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 2 $2,313,621 $2,644,139 $1,000,000 #VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 2 $1,582,678 $1,808,775 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 6 5 321 2 2 2 $1,044,058 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 6 5 321 2 2 2 $1,044,058 $0 $1,000,000 #VALUE! 0.02 N/A N/A #VALUE! 430 111.6637 318.3363 5 6 2 2 322 $0 $0 $0 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 6 5 321 2 2 2 $4,231,545 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 265.0952 224.9048 5 6 2 2 322 2 $0 $0 $1,000,000 

#VALUE! 4 N/A N/A #VALUE! 690 109.5222 580.4778 5 6 2 2 321 1 $1,942,373 $0 $0 

#VALUE! 4 N/A N/A #VALUE! 690 N/A N/A #VALUE! 5 6 2 2 321 1 $1,942,373 $0 $0 #VALUE! 4 N/A N/A #VALUE! 690 109.5222 580.4778 5 6 2 2 321 1 $1,942,373 $0 $0 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 1 2 2 $4,900,738 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 1448.817 -958.817 66.18% 5 6 5 5 321 2 1 $0 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 602.5834 -112.583 18.68% 4 5 3 3 322 1 2 1 $21,251,289 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $10,016,914 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 342.8737 147.1263 1 4 4 4 321 1 2 $6,518,472 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 1260.465 -770.465 61.13% 4 5 3 3 322 2 2 1 $10,081,732 $0 $1,000,000 $#VALUE! 0.02 N/A N/A #VALUE! 430 N/A N/A #VALUE! 2 6 2 2 322 $0 $0 $0 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 2 2 2 $6,283,076 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $13,532,274 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 1768.444 -1278.44 72.29% 5 6 5 5 321 2 2 1 $3,044,001 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 2329.841 -1839.84 78.97% 5 6 5 5 321 2 2 1 $3,044,001 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 1569.911 -1079.91 68.79% 5 6 5 5 321 2 2 1 $3,849,950 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 584.8403 -94.8403 16.22% 5 6 5 5 321 2 2 1 $3,017,582 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 3566.918 -3076.92 86.26% 5 6 5 5 321 2 2 1 $3,533,361 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 322 2 22 

#VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 322 22 22 

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 322 2 22 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 322 2 2 2 $13,532,274 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 322 2 2 2 $10,538,556 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 322 2 2 2 $13,934,275 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 2331.176 -1841.18 78.98% 5 6 5 5 321 1 2 1 $2,922,370 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 1606.367 -1116.37 69.50% 5 6 5 5 321 1 2 1 $2,922,370 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 1741.834 -1251.83 71.87% 5 6 5 5 321 1 2 1 $5,238,231 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 375.5549 114.4451 5 6 2 2 321 2 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 433.2898 56.71016 5 6 2 2 321 2 $0 $0 $1,000,000 #VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $2,649,093 $3,027,535 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $2,242,605 $2,562,977 $1,000,000 #VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $2,600,631 $2,972,150 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 1.316966 8.683034 5 6 6 6 322 2 2 $0 $7,609,615 $1,000,000 

76.69% 0.003 N/A N/A #VALUE! 270 290.9382 -20.9382 7.20% 5 3 1 1 322 2 1 2 1 $0 $13,391,746 $1,000,000 $
FacilityID

MDNewPage‐Luke

MEDomtarBaileyville

MEHuberEngineeredWoodLLCMEKatahdinPaperCoMEKatahdinPaperCoMEKatahdinPaperCoMELincolnPaper&TissueMELincolnPaper&TissueMEMadisonPaperMEMadisonPaperMEMadisonPaperMENewPage‐RumfordMENewPage‐RumfordMENewPage‐RumfordMERedShieldMERedShieldMESappiWestbrookMESappiWestbrookMESappiWestbrookMESappiWestbrookMESDWarrenMESDWarrenMESDWarrenSomersetMESDWarrenSomersetMEVersoPaperMEVersoPaperMEVersoPaperAndroscogginMIDecorativePanelsMIDecorativePanelsMIDecorativePanelsMIEBEddyPaperMILPCSagolaMIManistiquePaperMIManistiquePaperMIMenomineeMIMenomineeMINeenahPaperMIMINewPageEscanabaMINewPageEscanabaMINewPageEscanabaMINewPageEscanabaMIPackagingCorpofAmerica

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Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

11.71% 0.004 N/A N/A #VALUE! 160 131.0361 28.96385 5 3 1 1 322 1 2 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 1 2 2 $12,130,035 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 321 2 2 2 $2,079,043 $0 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $8,856,356 $10,121,550 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $8,856,356 $10,121,550 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $6,048,304 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $5,561,459 $0 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $1,292,920 $1,477,622 $1,000,000 #VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $4,438,595 $5,072,680 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $4,015,274 $4,588,884 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $4,483,965 $5,124,531 $1,000,000 $

0.02 N/A N/A #VALUE! 430 14.60129 415.3987 3 6 2 2 322 $0 $0 $0 

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 4 5 3 3 322 1 2 $7,809,204 $0 $0 $

0.02 N/A N/A #VALUE! 430 14.60129 415.3987 3 6 2 2 322 $0 $0 $0 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 562 322 2 2 2 $3,371,248 $0 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $7,000,000 $8,000,000 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 566 322 2 2 2 2 $5,899,684 $6,742,496 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 566 322 2 2 2 2 $6,358,604 $7,266,976 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 566 322 2 2 2 2 $6,358,604 $7,266,976 $1,000,000 $#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 562 322 2 2 2 $8,300,446 $16,600,893 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $5,899,684 $6,742,496 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 275.416 214.584 5 6 2 2 322 2 $0 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 204.7091 285.2909 2 6 2 2 322 2 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $8,870,710 $10,137,954 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 1396.063 -906.063 64.90% 4 5 3 3 322 1 2 1 $10,353,299 $0 $1,000,000 $#VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 2 $2,252,468 $4,504,937 $1,000,000 $#VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 2 $2,252,468 $4,504,937 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $3,506,794 $0 $1,000,000 $

38.09% 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2112 $3,456,604 $6,913,208 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 67.95856 422.0414 5 6 5 5 321 1 2 $2,973,205 $0 $1,000,000 

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $0 $18,901,304 $1,000,000 $

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $0 $15,336,673 $1,000,000 $

#VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 2 2 2 2 $0 $4,092,399 $1,000,000 $

30.34% 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 1 1 2 2 $0 $4,644,284 $1,000,000 $

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 1 2 2 $0 $7,039,419 $1,000,000 $

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $8,843,368 $17,686,736 $1,000,000 

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $5,234,154 $5,981,890 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $11,393,026 $13,020,601 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 322 2 2 2 $11,393,026 $0 $1,000,000 $#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 3 1 1 322 2 2 2 $0 $7,806,435 $1,000,000 
FacilityID

MISmurfitStoneOntonagonMIVersoPaperQuinnesecMN3MHutchinsonMN3MHutchinsonMNAndersonCorpBayportMNAndersonCorpBayportMNBoisePaper1212MNGPDuluthMNGPDuluthMNGPDuluthMNGPDuluthMNGPDuluthMNNorbordMinnesotaMNNorbordMinnesotaMNSappiCloquetMNSappiCloquetMNVersoPaperMNVersoPaperMNWausauPaper‐BrainerdMNWausauPaper‐BrainerdMNWausauPaper‐BrainerdMNWeyerhaeuserIrontonMSBowaterSouthMSGeorgiaPacificMonticelloMSGPBaySpringsMSGPBaySpringsMSGPGlosterPlyMSGPGlosterPlyMSGPGlosterPlyMSGPLouisvillePlyMSGPNewAugustaMSGPTaylorsvillePlyMSGPTaylorsvillePlyMSGPTylertownMillMSHankinsLumberMSHankinsLumberMSHoodBeaumontMSHoodWaynesboroMSHoodWigginsMSHoodWigginsMSHoodWigginsMSIPVicksburg

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HCl Need 

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Hg Need 

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Dioxin 

Need 

Upgrade?

CO Need 

Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 3 6 2 2 322 2 2 $5,101,698 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 109.1374 380.8626 5 6 2 2 322 2 $0 $0 $1,000,000 

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $4,277,299 $4,888,342 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $4,277,299 $4,888,342 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 31.40845 458.5915 5 6 2 2 321 2 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 31.40845 458.5915 5 6 2 2 321 2 $0 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 321 2 2 2 2 $2,434,530 $2,782,320 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 321 2 2 2 2 $2,434,530 $2,782,320 $1,000,000 $#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,698,974 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $797,196 $0 $1,000,000 

4 0.010391 3.989609 10 77.82179 -67.8218 87.15% 5 6 2 2 321 1 1 1 $1,391,160 $2,782,320 $0 $

#VALUE! 0.2 N/A N/A #VALUE! 470 959.7274 -489.727 51.03% 5 6 2 2 321 1 2 1 $878,848 $0 $1,000,000 #VALUE! 0.2 N/A N/A #VALUE! 470 959.7274 -489.727 51.03% 5 6 2 2 321 1 2 1 $878,848 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $4,462,402 $0 $1,000,000 $0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $5,538,307 $0 $1,000,000 $

83.61% 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 4 5 3 3 322 1 1 2 2 $4,483,965 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 59.71165 430.2883 4 5 3 3 322 1 2 $8,827,602 $0 $1,000,000 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $0 $3,189,791 $1,000,000 $

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $0 $4,807,909 $1,000,000 $0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $0 $4,807,909 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 132.3223 357.6777 5 6 2 2 321 2 $0 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 412.9498 77.05025 4 5 3 3 322 2 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 326.7245 163.2755 5 6 2 2 322 2 2 $8,724,039 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 546.3959 -56.3959 10.32% 5 6 2 2 321 2 2 1 $1,911,128 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 585.9405 -95.9405 16.37% 5 6 2 2 321 2 2 1 $1,689,101 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $2,600,631 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $2,600,631 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $3,990,889 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 1 2 2 $2,626,328 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 101.9839 388.0161 5 6 2 2 322 2 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $3,002,583 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $5,534,343 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,961,583 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $3,119,479 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,672,518 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 383.3162 106.6838 4 5 3 3 321 2 2 $4,943,230 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $4,039,560 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $3,119,479 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $3,119,479 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $3,792,098 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 259.2119 230.7881 1 4 4 4 322 2 2 $14,792,637 $0 $1,000,000 
FacilityID

MSNorbordMSMSNorbordMSMSNorbordMSMSSandersonPlumbingMSShuqualakLumberMSShuqualakLumberMSShuqualakLumberMSShuqualakLumberMSWeyerhaeuser1398MSWeyerhaeuser1398MSWeyerhaeuserBruceMSWeyerhaeuserBruceMSWeyerhaeuserColumbusMTPlumCreekMTPlumCreekMTPlumCreekMTPlumCreekMTPlumCreekMTRoseburgMissoulaMTSmurfitStoneNCBlueRidgePaperNCBlueRidgePaperNCBlueRidgePaperNCBlueRidgePaperNCBlueRidgePaperNCDomtarNCDomtarNCDomtarNCGPAhoskieCNSNCGPDudleyNCGPRoxboroNCGPWhitevilleNCInternationalPaperRiegelwoodNCInternationalPaperRiegelwoodNCInternationalPaperRiegelwoodNCJacksonPaperSylvaNCJeld‐WenNCKapStoneNCKapStoneNCLAPacificRoxboroNCLAPacificRoxboroNCLPRoaringRiver

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Emissions

Dioxin 

Difference

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CO 

Emissions

CO 

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HCl 

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Hg 

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PM 

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Metals 

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Group NAICS

PM Need 

Upgrade?

HCl Need 

Upgrade?

Hg Need 

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Dioxin 

Need 

Upgrade?

CO Need 

Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

#VALUE! 4 N/A N/A #VALUE! 690 N/A N/A #VALUE! 5 6 2 2 321 $0 $0 $0 

#VALUE! 4 N/A N/A #VALUE! 690 N/A N/A #VALUE! 5 6 2 2 321 $0 $0 $0 #VALUE! 4 N/A N/A #VALUE! 690 N/A N/A #VALUE! 5 6 2 2 321 $0 $0 $0 

0.005 N/A N/A #VALUE! 490 476.2361 13.76386 5 6 5 5 321 2 2 $1,091,316 $0 $1,000,000 

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,400,400 $0 $1,000,000 $#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,294,162 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,922,086 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 122.248 367.752 5 6 5 5 321 2 2 $1,922,086 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 2891.434 -2401.43 83.05% 5 6 5 5 321 1 2 1 $4,943,230 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $1,918,107 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 2124.637 -1634.64 76.94% 5 6 6 5 321 1 2 1 $3,261,316 $0 $1,000,000 $

4 0.003171 3.996829 690 354.881 335.119 5 6 2 2 321 $0 $0 $0 

0.005 N/A N/A #VALUE! 490 96.24913 393.7509 5 6 2 2 322 2 $0 $0 $1,000,000 

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,522,923 $0 $1,000,000 $

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,522,923 $0 $1,000,000 $#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 4 5 3 3 321 2 2 2 $3,664,252 $0 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 690 N/A N/A #VALUE! 5 6 2 2 321 2 $1,120,905 $0 $0 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $4,390,618 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 53.53662 436.4634 5 6 5 5 321 2 2 $2,821,965 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $9,315,230 $0 $1,000,000 $

0.004 N/A N/A #VALUE! 160 75.24458 84.75542 5 6 2 2 322 1 1 2 $5,011,374 $10,022,748 $1,000,000 0.004 N/A N/A #VALUE! 160 15.82828 144.1717 5 6 2 2 322 1 1 2 $5,011,374 $10,022,748 $1,000,000 0.004 N/A N/A #VALUE! 160 15.3462 144.6538 5 6 2 2 322 1 1 2 $5,295,168 $10,590,336 $1,000,000 0.004 N/A N/A #VALUE! 160 13.49823 146.5018 5 6 2 2 322 2 $0 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 666.8057 -176.806 26.52% 4 5 3 3 322 1 2 1 $8,999,206 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 55.91815 434.0818 5 6 2 2 322 1 2 $0 $17,126,438 $1,000,000 

30.35% 4 N/A N/A #VALUE! 10 49.05812 -39.0581 79.62% 2 6 6 6 322 1 1 1 1 $8,711,953 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 1634.34 -1144.34 70.02% 5 6 2 2 322 2 1 $0 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $3,837,423 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 1 2 2 $7,066,987 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $3,261,316 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 1 2 2 $6,856,213 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $9,624,261 $0 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 1 4 4 4 322 2 2 $7,000,000 $0 $0 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $11,836,540 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 879.8478 -389.848 44.31% 4 5 3 3 322 1 2 1 $5,050,501 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $2,454,855 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 1 2 2 $11,234,446 $0 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 1 2 2 2 $5,843,016 $6,677,733 $1,000,000 $#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,332,085 $0 $1,000,000 #VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,332,085 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 321 2 2 2 $3,506,794 $0 $1,000,000 $
FacilityID

NCLPRoaringRiverNCLPRoaringRiverNCSeaboardLumberNCSeaboardLumberNCSeaboardLumberNCUniboardUSANCWestFraserNCWeyerhaeuserGriftonNCWeyerhaeuserGriftonNCWeyerhaeuserGriftonNCWeyerhaeuser‐Vanceboro

NCWeyerhaeuser‐Vanceboro

NYFinchPaperNYIntlPaperTiconderogaOHAppletonIdeasOHAppletonIdeasOHGlatfelterChillicotheOHGlatfelterChillicotheOHGlatfelterChillicotheOHRockTennCincinnatiOHSmartPapersHoldingsLLCOHSmurfitCoshoctonOKGPMuskogeeMillOKGPMuskogeeMillOKGPMuskogeeMill

OKIPValliantOKIPValliantOKPanPacificProductsOKWeyerhaeuserWrightCityORBBSMMedfordORBBSMMedfordORBBSMMedfordORBlueHeronPaperORBoiseBuildingORCascadePacificPulpORFlakeboardEugeneORGeorgiaPacificWaunaMillORGeorgiaPacificWaunaMillORGPToledoORJeldWenKlamanthFallsORRosboroSpringfieldORRosboroSpringfield

Hg %red

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CO 

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HCl 

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Hg 

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PM 

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Metals 

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Group NAICS

PM Need 

Upgrade?

HCl Need 

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Hg Need 

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Dioxin 

Need 

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CO Need 

Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 321 2 2 2 2 $2,468,344 $2,820,964 $1,000,000 $

42.50% 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 321 2 1 2 2 $5,805,033 $0 $1,000,000 $

#VALUE! 0.02 N/A N/A #VALUE! 430 N/A N/A #VALUE! 5 6 2 2 321 1 $1,626,934 $0 $0 #VALUE! 0.02 N/A N/A #VALUE! 430 N/A N/A #VALUE! 5 6 5 5 321 2 $2,077,028 $0 $0 #VALUE! 0.02 N/A N/A #VALUE! 430 N/A N/A #VALUE! 5 6 5 5 321 2 $2,077,028 $0 $0 #VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,698,974 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 321 2 2 2 $4,143,760 $0 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 690 460.0472 229.9528 5 6 2 2 321 $0 $0 $0 

#VALUE! 4 N/A N/A #VALUE! 690 460.0472 229.9528 5 6 2 2 321 $0 $0 $0 #VALUE! 4 N/A N/A #VALUE! 690 N/A N/A #VALUE! 5 6 2 2 321 2 $1,650,256 $0 $0 

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 1 2 2 2 $11,586,204 $13,241,376 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 2 6 6 6 322 1 2 2 $7,604,369 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $5,602,831 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 2 6 5 5 322 1 2 2 $14,639,077 $0 $1,000,000 $0.003 N/A N/A #VALUE! 270 45.63686 224.3631 5 6 2 2 322 1 2 $0 $6,028,382 $1,000,000 

0.003 N/A N/A #VALUE! 270 19.7315 250.2685 5 6 2 2 322 1 1 2 $3,951,806 $7,903,612 $1,000,000 

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $5,101,698 $10,203,396 $1,000,000 #VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $6,062,866 $12,125,733 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $4,354,432 $0 $1,000,000 $#VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 1 2 2 2 $0 $4,068,338 $1,000,000 $

25.28% 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2 1 2 $0 $10,921,331 $1,000,000 

0.005 N/A N/A #VALUE! 490 272.6726 217.3274 4 5 3 3 322 1 2 $12,349,960 $0 $1,000,000 

0.004 N/A N/A #VALUE! 160 26.51437 133.4856 5 6 2 2 322 2 2 $4,852,745 $0 $1,000,000 0.004 N/A N/A #VALUE! 160 13.96812 146.0319 5 3 1 1 322 2 $0 $0 $1,000,000 

0.004 N/A N/A #VALUE! 160 3.200772 156.7992 5 3 1 1 322 2 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 322 2 22 

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $15,545,086 $17,765,812 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 557.0262 -67.0262 12.03% 1 4 4 4 321 1 2 1 $2,501,852 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 $0 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 3852.927 -3362.93 87.28% 5 6 2 2 321 2 1 $0 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 3852.927 -3362.93 87.28% 5 6 2 2 321 2 1 $0 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 3852.927 -3362.93 87.28% 5 6 2 2 321 2 1 $0 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 147.0563 342.9437 5 6 5 5 322 2 $0 $0 $1,000,000 #VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $2,019,064 $0 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 4.871715 5.128285 5 6 6 6 321 1 2 2 $6,658,413 $7,609,615 $1,000,000 

0.2 N/A N/A #VALUE! 470 448.4687 21.53134 5 3 1 1 321 2 $0 $0 $1,000,000 

#VALUE! 4 N/A N/A #VALUE! 10 0.209332 9.790668 5 6 6 6 322 1 2 2 $5,972,714 $6,825,959 $1,000,000 

0.02 0.00228 0.01772 430 23.89197 406.108 3 2 1 1 322 $0 $0 $0 

#VALUE! 4 N/A N/A #VALUE! 10 27.20041 -17.2004 63.24% 5 6 6 6 322 1 2 2 1 $5,890,265 $6,731,731 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 297.4003 192.5997 5 6 2 2 321 2 2 $1,926,793 $0 $1,000,000 

0.2 0.032539 0.167461 470 409.9549 60.04505 5 6 5 5 321 1 $2,665,116 $0 $0 

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,665,116 $0 $1,000,000 $
FacilityID

ORRosboroSpringfieldORRoseburgCoquilleORRoseburgForestDillardORRoseburgForestDillardORRoseburgForestDillardORRoseburgRiddle2ORRoseburgRiddle2ORSierraPineORSierraPineSpringfieldORSierraPineSpringfieldORSierraPineSpringfieldORSPNewsprintORSPNewsprintORStimsonLumberForestGroveORStimsonLumberForestGroveORStimsonLumberForestGrovePAAppletonPapersPAAppletonPapersPACraftMasterPADomtarJohnsonburgPADomtarJohnsonburgPAPHGlatfelterPAPHGlatfelterPAPHGlatfelterPAPHGlatfelterPAProctorGambleMehoopanyPAPATeamTenPATemple‐Inland

PATemple‐Inland

SCBowaterCoatedPaperSCBowaterCoatedPaperSCBowaterCoatedPaperSCChesterWoodProductsSCCogenSouthSCCollumsLumberSCGPProsperityPlySCGPRussellvilleSCInternationalPaperEastoverSCInternationalPaperEastoverSCIPGeorgetownSCIPGeorgetownSCMarlboroPaper

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Difference CO %red

HCl 

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Group

Hg 

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Group

PM 

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Group

Metals 

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Group NAICS

PM Need 

Upgrade?

HCl Need 

Upgrade?

Hg Need 

Upgrade?

Dioxin 

Need 

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CO Need 

Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,665,116 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $4,676,776 $0 $1,000,000 $0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 2 2 2 $7,948,938 $0 $1,000,000 $0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 2 2 2 $7,948,938 $0 $1,000,000 $0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 2 2 2 $10,862,656 $0 $1,000,000 $0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $2,657,971 $0 $1,000,000 $0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 2 2 2 $3,546,595 $0 $1,000,000 $

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 1 4 2 2 321 2 2 2 $2,356,461 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $878,848 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,120,905 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,120,905 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $0 $13,076,027 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 322 2 2 2 $7,395,787 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 378.7998 111.2002 5 6 2 2 321 2 2 $1,957,871 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 378.7998 111.2002 5 6 2 2 321 2 2 $1,957,871 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 378.7998 111.2002 5 6 2 2 321 2 2 $1,957,871 $0 $1,000,000 #VALUE! 4 N/A N/A #VALUE! 10 33.09038 -23.0904 69.78% 5 6 6 6 322 2 2 2 1 $6,214,762 $7,102,585 $1,000,000 $

55.41% 0.005 N/A N/A #VALUE! 490 1070.274 -580.274 54.22% 4 5 3 3 322 1 1 2 1 $5,747,746 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 $0 $0 $1,000,000 $

0.004 N/A N/A #VALUE! 160 68.2946 91.7054 1 4 2 2 322 2 $0 $0 $1,000,000 0.004 N/A N/A #VALUE! 160 68.2946 91.7054 1 4 2 2 322 2 $0 $0 $1,000,000 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 1 2 $0 $5,651,827 $1,000,000 

0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 1 2 $0 $10,017,791 $1,000,000 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 1 2 $0 $8,233,888 $1,000,000 

0.02 N/A N/A #VALUE! 430 23.18695 406.813 3 6 2 2 322 $0 $0 $0 

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $6,864,727 $7,845,402 $1,000,000 $

#VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 2 2 2 2 $0 $7,728,108 $1,000,000 $

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 6 5 321 2 2 2 $2,665,116 $0 $1,000,000 $

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 6 5 321 2 2 2 $3,148,186 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $5,342,801 $0 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 1 2 2 2 $8,927,972 $10,203,396 $1,000,000 $

0.005 0.004861 0.000139 490 2818.176 -2328.18 82.61% 5 6 2 2 322 1 1 $7,545,630 $0 $0 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 2 2 2 $4,985,481 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 16.09804 473.902 1 2 1 1 322 2 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $2,095,853 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 1 2 2 $6,122,828 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $6,977,632 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 520.3779 -30.3779 5.84% 5 6 2 2 322 2 1 $0 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 25.71091 464.2891 5 6 2 2 322 1 2 $0 $12,769,206 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $6,709,482 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $6,709,482 $0 $1,000,000 $

0.005 0.002758 0.002242 490 313.5231 176.4769 5 6 2 2 322 $0 $0 $0 
FacilityID

SCNewSouthCamdenSCNewSouthCoConwaySCNewSouthLumberCoDarlingtonSCNewSouthLumberCoDarlingtonSCRoseburgForestRussellvilleSCSimpsonLumberGeorgetownSCSimpsonLumberGeorgetownSCSmurfitStoneSCSmurfitStoneSCSonocoHartsvilleSCSonocoHartsvilleSCSonocoHartsvilleSCWestFraserNewberrySCWestFraserNewberrySCWestFraserNewberryTNArborCraftTNArborCraftTNBowaterNewsprintTNBowaterNewsprintTNBowaterNewsprintTNBowaterNewsprintTNDomtar2384TNPackagingCorpCounceTNPackagingCorpCounceTXAnthonyForestProd‐ATLTXAnthonyForestProd‐ATLTXDibollTemple‐Inland

TXDibollTemple‐Inland

TXGPClevelandPlyLumber

TXInternationalPaperQueenCityTXLPCarthageTXLPJasperOSBTXLPJasperOSBTXMeadWestvacoEvadaleTXNorbordTexasJeffersonTXNorbordTexasJeffersonTXNorbordTexasNacogdochesTXNorbordTexasNacogdochesTXNorbordTexasNacogdochesTXNorbordTexasNacogdochesTXNorbordTexasNacogdochesTXPinelandTemple‐Inland

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CO 

Difference CO %red

HCl 

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Group

Hg 

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Group

PM 

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Group

Metals 

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Group NAICS

PM Need 

Upgrade?

HCl Need 

Upgrade?

Hg Need 

Upgrade?

Dioxin 

Need 

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CO Need 

Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 1 2 2 $2,195,678 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 1 2 2 $2,195,678 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $1,919,301 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 1 2 2 $1,910,131 $0 $1,000,000 

0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 3 1 1 321 2 2 $0 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,761,082 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,910,131 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $

0.002 0.001388 0.000612 82 168.4007 -86.4007 51.31% 3 2 1 1 322 1 1 $0 $0 $0 $

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $3,262,481 $6,524,962 $1,000,000 

#VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 2 2 2 2 $0 $10,284,807 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,910,131 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,910,131 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,910,131 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,401,976 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,401,976 $0 $1,000,000 

33.65% 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 1 2 $0 $0 $1,000,000 

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 $5,767,010 $11,534,019 $1,000,000 

0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2 $0 $0 $1,000,000 

0.02 0.005345 0.014656 430 115.3842 314.6158 5 6 2 2 322 $0 $0 $0 

0.02 0.01886 0.00114 430 81.74706 348.2529 5 6 2 2 322 1 $6,377,571 $0 $0 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 322 2 22 

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 1 2 2 $9,280,471 $10,606,253 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 300.3018 189.6982 5 6 5 5 321 1 2 $1,715,777 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 233.151 256.849 5 6 5 5 321 1 2 $1,910,131 $0 $1,000,000 #VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $1,882,040 $0 $1,000,000 

0.2 N/A N/A #VALUE! 470 69.30937 400.6906 5 6 2 2 321 2 2 $1,332,085 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 386.6385 103.3615 4 5 3 3 321 2 2 $7,648,796 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 322 2 22 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,165,161 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $2,651,211 $0 $1,000,000 $#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,208,324 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 6 5 322 2 2 2 $8,087,053 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $3,229,378 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $3,229,378 $0 $1,000,000 $#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,332,085 $0 $1,000,000 #VALUE! 4 N/A N/A #VALUE! 690 1222.067 -532.067 43.54% 5 6 2 2 321 1 $0 $0 $0 

#VALUE! 4 N/A N/A #VALUE! 690 1222.067 -532.067 43.54% 5 6 2 2 321 1 $0 $0 $0 #VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,332,085 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,698,974 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $3,229,378 $0 $1,000,000 $
FacilityID

TXPinelandTemple‐Inland

TXPinelandTemple‐Inland

TXTempleInlandFiberboardTXTemple‐InlandOrange

TXwestfraserVAATCPanelsVAATCPanelsVABassettFiberboardVABassettFiberboardVABearIslandPaperCoAshlandVAGeorgiaPacificBrooknealGladysVAGeorgiaPacificEmporiaVAGPBigIsland2703VAGPBigIsland2703VAGPJarrattFiberboardVAGreifVAGreifVAGreifVAMeadWestVaco‐CovingtonVAVAMeadWestVaco‐CovingtonVAVAMeadWestVaco‐CovingtonVAVAMeadWestVaco‐CovingtonVAVASmurfitStoneHopewellVASmurfitStoneWestptVASmurfitStoneWestptWABoiseKettleFallsPlywoodWABoisePaperWallulaWAGPCamasWAGPCamasWAGraysHarborPaperWAGraysHarborPaperWAJeldWenWhiteSwanWAJeldWenWhiteSwanWAKimberlyClarkEverettWANipponPaperWANipponPaperWANipponPaperWAPonderayAbibo

WAPort TownsendWASierraPacificWASimpsonLumberCompanyWASimpsonTacoma2784

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HCl 

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Hg 

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PM 

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Group

Metals 

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Group NAICS

PM Need 

Upgrade?

HCl Need 

Upgrade?

Hg Need 

Upgrade?

Dioxin 

Need 

Upgrade?

CO Need 

Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 6 5 321 2 2 2 $1,628,500 $0 $1,000,000 

#VALUE! 0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 6 5 321 2 2 2 $1,628,500 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 1089.894 -599.894 55.04% 1 4 4 4 321 2 2 1 $6,658,413 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 3 3 322 2 2 2 $9,196,695 $0 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 569.9905 -79.9905 14.03% 1 4 4 4 321 1 2 1 $3,809,767 $0 $1,000,000 $

0.2 N/A N/A #VALUE! 470 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,535,063 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,331,149 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 5 5 321 2 2 2 $2,151,666 $0 $1,000,000 #VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 321 2 2 2 2 $1,762,537 $2,014,328 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 1 2 2 $3,932,419 $7,864,837 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 690 172.6735 517.3265 5 6 2 2 321 1 $3,903,217 $0 $0 #VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 321 1 2 2 $5,736,242 $0 $1,000,000 $

0.004 N/A N/A #VALUE! 160 33.58487 126.4151 5 6 2 2 322 2 $0 $0 $1,000,000 

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $

37.87% 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 5 5 321 2 1 2 2 $3,705,483 $0 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $6,571,183 $7,509,923 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $6,571,183 $7,509,923 $1,000,000 $

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 2 6 2 2 322 2 2 $0 $0 $1,000,000 $

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 2 6 2 2 322 2 2 $0 $0 $1,000,000 $0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 2 6 2 2 322 2 2 $0 $0 $1,000,000 $0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 2 6 2 2 322 2 $0 $0 $1,000,000 

#VALUE! 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $16,624,485 $1,000,000 

0.004 0.003281 0.000719 160 16.49103 143.509 5 6 2 2 322 $0 $0 $0 

16.33% 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $0 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 5482.714 -4992.71 91.06% 5 6 2 2 321 2 1 $0 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 4 5 2 2 322 2 2 2 $4,191,364 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 295.5398 194.4602 5 6 2 2 322 2 2 $4,244,646 $0 $1,000,000 

#VALUE! 4 N/A N/A #VALUE! 10 36.53786 -26.5379 72.63% 4 5 3 3 322 2 1 $8,087,053 $0 $0 $

0.2 0.371994 -0.17199 46.24% 470 993.0823 -523.082 52.67% 4 5 3 3 322 1 1 1 1 $6,304,717 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 322 1 2 2 $9,280,471 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $1,473,034 $0 $1,000,000 $#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 321 2 2 2 2 $2,253,352 $2,575,260 $1,000,000 

0.005 N/A N/A #VALUE! 490 33.92247 456.0775 5 3 1 1 322 1 2 $0 $11,153,715 $1,000,000 

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 1 2 2 2 $4,392,914 $5,020,474 $1,000,000 $

0.005 0.00614 -0.00114 18.57% 490 498.4054 -8.40543 1.69% 4 5 3 3 322 1 1 1 $5,375,632 $0 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 1 2 2 2 $4,392,914 $5,020,474 $1,000,000 $#VALUE! 0.02 N/A N/A #VALUE! 430 N/A N/A #VALUE! 3 2 1 1 322 $0 $0 $0 

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 566 322 2 2 2 2 $5,899,684 $6,742,496 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 6 5 321 2 2 2 $7,612,315 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 321 2 2 2 $3,338,866 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 131.8708 358.1292 5 6 2 2 322 2 $0 $0 $1,000,000 
FacilityID

WAWeyerhaeuser_RaymondWAWeyerhaeuserLongviewWIAlgomaWIAlgomaWIAppletonWIAppletonCoatedWIDomtar2814WIDomtar2814WIDomtarNekoosaWIDomtarNekoosaWIDomtarNekoosaWIDomtarNekoosaWIFlambeauRiverPaperWIGPGreenBay2818WIGPGreenBay2818WIGPGreenBay2818WIGPGreenBay2818WIGPGreenBay2818WIGPGreenBay2818WIGreenBayPackagingMillDivisionWILPHaywardWILPHaywardWILPHaywardWILPHaywardWINeenahPaperAppletonWINewPageBironWINewPageBironWINewPageKimberlyWINewPageKimberlyWINewPage‐WhitingWINewPage‐WisconsinRapidsWINewPage‐WisconsinRapidsWIPCATomahawkWIPCATomahawkWIPCATomahawkWIThilmanyLLCWIThilmanyLLCWIThilmanyLLCWIThilmanyPapersNicoletMillWIThilmanyPapersNicoletMillWIWausauWIWausau

Hg %red

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%red CO Limit

CO 

Emissions

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Upgrade?

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CO Need 

Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

4 0.001873 3.998127 690 121.2614 568.7386 5 6 2 2 321 $0 $0 $0 

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 3 6 2 2 322 2 2 $0 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 6 5 321 2 2 2 $1,583,673 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 206.6548 283.3452 5 6 6 5 321 2 2 $2,114,567 $0 $1,000,000 

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 5 5 322 2 2 2 2 $2,468,344 $2,820,964 $1,000,000 $

#VALUE! 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 322 2 2 2 2 $4,818,908 $9,637,816 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $6,122,828 $6,997,517 $1,000,000 $

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $0 $5,850,410 $1,000,000 $

0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 1 2 $0 $5,967,895 $1,000,000 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 1 2 $0 $5,967,895 $1,000,000 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $0 $8,981,802 $1,000,000 $0.005 N/A N/A #VALUE! 490 104.1038 385.8962 4 5 3 3 322 1 2 $6,983,187 $0 $1,000,000 

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 1 2 2 2 $3,498,759 $6,997,517 $1,000,000 $0.002 N/A N/A #VALUE! 82 98.36852 -16.3685 16.64% 3 2 1 1 322 1 2 1 $5,960,432 $0 $1,000,000 $0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 1 1 2 2 $4,894,821 $9,789,642 $1,000,000 $0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 1 1 2 2 $3,854,222 $7,708,444 $1,000,000 $0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 1 1 2 2 $6,864,692 $13,729,384 $1,000,000 $

57.03% 0.02 0.033158 -0.01316 39.68% 430 1.501291 428.4987 5 3 1 1 322 1 1 1 $0 $4,476,722 $1,000,000 

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 1 2 2 $0 $7,589,747 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 1204.099 -714.099 59.31% 5 6 2 2 321 2 2 1 $862,933 $0 $1,000,000 

#VALUE! 0.005 N/A N/A #VALUE! 490 743.4 -253.4 34.09% 5 6 2 2 321 2 2 1 $862,933 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 2350.471 -1860.47 79.15% 5 6 2 2 321 2 2 1 $975,533 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 1645.33 -1155.33 70.22% 5 6 2 2 321 2 2 1 $975,533 $0 $1,000,000 #VALUE! 4 N/A N/A #VALUE! 10 N/A N/A #VALUE! 5 6 6 6 322 2 2 2 2 $2,973,205 $3,397,948 $1,000,000 $

0.003 0.001521 0.001479 270 N/A N/A #VALUE! 5 6 2 2 322 2 $0 $0 $0 $

40.18% 0.004 N/A N/A #VALUE! 160 N/A N/A #VALUE! 5 6 2 2 322 1 1 2 $0 $9,620,848 $1,000,000 

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 322 1 1 2 2 $2,794,329 $5,588,659 $1,000,000 $

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 322 1 1 2 2 $3,117,356 $6,234,711 $1,000,000 $

47.05% 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 1 1 2 2 $3,617,087 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $

0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 1 1 2 2 $4,005,757 $8,011,514 $1,000,000 $

#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 1 1 2 2 $2,600,830 $5,201,659 $1,000,000 $#VALUE! 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 5 6 2 2 322 1 1 2 2 $3,402,354 $6,804,709 $1,000,000 $

10.88% 0.005 N/A N/A #VALUE! 490 N/A N/A #VALUE! 1 4 4 4 322 1 1 2 2 $6,196,010 $0 $1,000,000 $

0.003 0.008731 -0.00573 65.64% 270 64.45627 205.5437 5 6 2 2 322 1 1 1 $5,134,280 $10,268,559 $1,000,000 0.003 0.008731 -0.00573 65.64% 270 64.45627 205.5437 5 6 2 2 322 1 1 1 $3,418,370 $6,836,739 $1,000,000 0.003 N/A N/A #VALUE! 270 212.115 57.88501 5 6 2 2 322 1 2 $0 $4,753,785 $1,000,000 

0.003 N/A N/A #VALUE! 270 212.115 57.88501 5 6 2 2 322 1 2 $0 $4,753,785 $1,000,000 0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $0 $5,721,733 $1,000,000 $0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 322 1 2 2 $0 $7,240,332 $1,000,000 $
FacilityID

WIWausauRhineWIWausauRhineWIWausauRhineWIWausauRhineWIWausauRhineWVGPMtHopeOSBWVJELD‐WENCraigsvilleWVWeyerhaeuserBuckhannonRepresents Biomass, Coal, LiquShaded units indicate changes tDeleted limited use units

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Need 

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CO Need 

Upgrade? PM Upgrade Cost HCl Upgrade Cost Hg/Dioxin Upgrade Cost CO Upgra

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 2 2 2 $0 $4,362,654 $1,000,000 $

0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 2 2 2 $0 $4,362,654 $1,000,000 $0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 2 2 2 $0 $4,362,654 $1,000,000 $0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 3 1 1 322 2 2 2 $0 $4,362,654 $1,000,000 $0.003 N/A N/A #VALUE! 270 N/A N/A #VALUE! 5 6 2 2 322 2 2 $0 $0 $1,000,000 $

#VALUE! 4 N/A N/A #VALUE! 690 126.9091 563.0909 5 6 2 2 321 1 $3,903,217 $0 $0 

#VALUE! 0.005 N/A N/A #VALUE! 490 181.5465 308.4535 5 6 2 2 321 2 2 $1,741,101 $0 $1,000,000 #VALUE! 0.005 N/A N/A #VALUE! 490 22.81118 467.1888 5 6 2 2 321 2 $0 $0 $1,000,000 

Filtered Boilers: TOTAL $1,873,342,142 $1,036,172,140 $494,000,000 $94COUNT 545 545 545 AVERAGE $3,437,325 $1,901,233 $906,422 $

*Press F9 to recalculate 

All Boilers:TOTAL $5,119,891,642 $5,149,190,442 $1,424,000,000 $2,49

40 255 COUNT 1584 1584 1584 

23 115 AVERAGE $3,232,255 $3,250,752 $898,990 $










November 10, 2011 

peA Preferred Definition of ((Processing" 

IIProcessing means any operation that transforms discarded nonhazardous 

secondary material into a non-waste fuel or non-waste ingredient product. 

Processing includes, but is not limited to, removal of extraneous debris, sizing for 

safe and efficient handling, shredding, sorting, segregating, cleaning, culling, 

racking, or other systematic procedures for making a material ready for use as a 

fuel. For example, for tires being used as fuel in a portland cement kiln, neither 

shredding nor metal removal shall be necessary.1I 
SUGGESTED REGULATORY LANGUAGE 

TO CODIFY ADMINISTRATOR JACKSON'S 

MAY 17, 2011 RULING REGARDING 

PORTLAND CEMENT KILN INGREDIENTS 

(76 FR 28318, 28322) 

Both § 60.2265 (for subpart CCCC) and § 60.2875 (for subpart DDDD) 

contain the following definition for "waste-burning kiln" -

Waste-burning kiln means a kiln that is heated, in whole 

or in part, by combusting solid waste (as that term is 

defined by the Administrator pursuant to Subtitle D of 

RCRA). 

Only portland cement kilns that are "waste-burning kilns" as defined in these 

sections are subject to CISWI. We accordingly urge EPA to amend both 

§§ 60.2265 and 60.2875 by adding the following (new language in bold italics): 

Waste-burning kiln means a kiln that is heated, in whole 

or in part, by combusting solid waste (as that term is 

defined by the Administrator pursuant to Subtitle D of 

RCRA). Materials used as ingredients in portland 

cement kilns shall not be deemed combusted. 

There is currently no definition of "ingredient" in the CISWI 

regulations. We urge EPA to amend both §§ 60.2265 and 60.2875 by 

adding the following new definition (please note this definition is 

taken verbatim from the NHSM definitions - see § 241.2 at 76 FR 

15550): 

"Ingredient" means a non-hazardous secondary 

material that is a component in a compound, process, or 

product. 
PortlClnd Cemem flS50ciation 

August 18,2011 

Honorable Mathy Stanislaus 

Assistant Administrator Solid Waste and Emergency Response 

Environmental Protection Agency 

Ariel Rios Building 

1200 Pennsylvania Avenue, N.W. 

Washington, DC 20460 

Re: Portland Cement Association ("PCA") Petition to Amend NonHazardous Secondary Materials ("NHSM") Rule, Filed June 16, 2011 

Dear Mr. Stanislaus: 

Thank you for taking the time to meet with me and others from PCA regarding our abovereferenced NHSM rulemaking petition on August 4. Based on questions and points you and other 

EP A personnel raised during the meeting, we would like to follow up with further elaboration, as set 

forth below. 

Need for Coordination on Commercial and Industrial Solid Waste Incinerator (CISwn 

Rulemaking and Response to PCA's NHSM Administrative Petition 

In our NHSM rule administrative petition, we stated (on page 2): 

Since the CISWI and NHSM rules are so closely linked - in fact, the entire 

foundation for CISWI applicability over a facility rests entirely on the NHSM 

rule - we believe EPA should consider amendments to key provisions of the 

NHSM rule as EPA reconsiders the CISWI rule. 

We appreciated having representatives of EPA's Office of Air and Radiation (OAR) and an 

Office of General Counsel (OGC) CAA attorney participate with you and your Resource 

Conservation and Recovery Act (RCRA) staff in our August 4 meeting. We suggested at that 

meeting that since EPA has announced plans to issue a new proposed CISWI rule by the end of 

October, 2011, EPA's response to our NHSM petition could be folded into that CISWI rulemaking. 

To follow up on that suggestion, we are sending a letter today (copy attached) to Ms. Gina 

McCarthy, OAR's Assistant Administrator. We are also sending Ms. McCarthy a copy of this letter 

to you. 

As you will see in our letter to Ms. McCarthy, PCA filed a petition for reconsideration of the 

CISWI rule on May 20,2011. The first issue we raised in our CISWI petition is identical to the first 

issue raised in our NHSM petition: ingredients utilized by portland cement kilns are not 

"combusted," and therefore such ingredients cannot be deemed a "solid waste" under the NHSM rule 

and cannot be subject to the CISWI rule under CAA § 129. 

500 New Jersey Avenue, NW 

yth Floor 

Washington, D.C. 20001 

(202) 408-9494 
As we discussed in our August 4 meeting (and explained in both our NHSM and CISWI 

petitions), Administrator Jackson has already resolved that issue in a recent final Federal Register 

ruling. 76 FR 28322, May 17, 2011. We also pointed out that even though Administrator Jackson's 

ruling definitively resolves this issue, it is important that EPA now clarify the CISWI and NHSM 

rules on this point. 

Ms. Jackson's Federal Register ruling will not be codified in the c.P.R., but the CISWI and 

NHSM rules will. While nothing in the NHSM or CISWI rules contradicts these points, the rules do 

not expressly state them. For the benefit of the regulated community, state and regional personnel, 

and all interested parties, we believe it is incumbent upon EPA to clarify both rules on these points. 

To this end, we provided suggested regulatory language in an Addendum to our NHSM 

administrative petition. In today's letter to Ms. McCarthy, we suggest that similar or alternative 

language should be added to the CISWI rule. 

In today's letter to Ms. McCarthy, we also elaborate upon the suggestion we raised in our 

August 4 meeting with you that the upcoming CISWI preamble could reference and notice PCA's 

NHSM petition. PCA's NHSM administrative petition was filed pursuant to RCRA 

§ 7004(a). This subsection ofRCRA requires that EPA take action in the Federal Register with 

respect to any such petition within a reasonable time. 

In light of the extremely close relationship between the CISWI and NHSM rules, we believe 

it would be most appropriate for EPA to comply with its RCRA § 7004(a) obligations in this manner. 

EPA would then be procedurally postured to take final action on the NHSM petition at the same time 

it finalizes its CISWI rules. This coordination would be consistent with EPA's earlier approach of 

issuing the NHSM and CISWI rules in tandem. 

Follow Up on Points Raised in August 4 Meeting 

- Processing 

We repeated points made in our NHSM petition showing how EPA's approach to 

"processing" was, in our view, unnecessarily stringent and would discourage beneficial recyclelreuse 

of non-hazardous materials with no benefit to human health and the environment. We also pointed 

out that even if one were to concede (which we do not) that some D.C. Circuit case law under RCRA 

Subtitle C required the Subtitle D NHSM lUle's approach to "discard," there is no case law (or 

statutory language) requiring the NHSM lUle's approach to "processing." 

U sing tires as an example, EPA personnel asked what level of processing for whole tires 

from landfills and piles would we consider sufficient? EPA personnel wondered whether anything 

would be necessary in our view. 

The justification for the requirement for processing as expressed in EPA's preambles is to 

assure that a discarded material can be processed to a sufficient degree so that it can serve as a bona 

fide fuel material. We believe that if only a minimal amount of processing is necessary to make a 

certain type of "discarded" material a bona fide fuel (such as a whole tire), then as a matter oflogic, 

only a minimal amount of processing should be necessary. 

2 
In the draft regulatory language accompanying our NHSM petition, we made clear that 

(contraIY to EPA's current approach) shredding and metal removal would not be necessaIY for whole 

tires. We included several other types of actions, however, such as: removal of extraneous debris, 

sizing for safe and efficient handling, sorting, segregating, cleaning, culling, racking, and "other 

systematic procedures for making a material ready for use as a fuel." Thus something would be 

required under our approach. 

If some might consider this minimal, that is because only minimal processing is necessary to 

render a whole tire usable as a bona fide fuel in a cement kiln. And there clearly can be no health 

and environmental justification for EPA's current approach, since the NHSM rule excludes whole 

tires that have been subject to neither shredding nor metal removal if the tires come to a kiln through 

an "established program." 

As noted above, the tire derived fuel example was used for illustrative purposes. The cement 

sector utilizes a long list of alternatives to conventional fuels, most of which are acquired from off 

site and much of which generally require little processing to be effectively utilized (sizing for 

insertion into the kiln being the most common). Unnecessarily stringent processing requirements 

should not impede the use of alternative fuels. 

- "Traditional" Fuels 

We pointed out during the meeting (and explained further in our NHSM petition) that 

portland cement kilns have been utilizing tires on a routine basis since the 1980s, and that EPA 

should classify tires as "traditional" fuels. EPA personnel asked for our views on how lines could be 

drawn in determining how long a fuel must have been used to be considered "traditional." 

As in the case of "processing," there is no relevant statutory language or D.C. Circuit case 

law that restrains EPA's discretion on this issue. We note further that the first part of EPA's two-part 

regulatory definition of "traditional" uses the word "historical" but does not define that term. 40 

C.F.R. § 241.2, 76 FR at 15550. The second part of the definition discusses alternative fuels from 

virgin materials that can "now" be used as fuels, and does not require any "historical" use. We 

believe in this statutory/regulatOlY setting, EPA has ample leeway to classify tires as 'traditional" 

fuels where such classification with promote recyclelreuse of secondary materials and have no 

impact on human health and the environment. 

- The 2007 D.C. Circuit NRDC Opinion 

Some EPA personnel noted that if EP A amended the NHSM rule as we are requesting, most 

if not all material combusted as fuel by portland cement kilns would be excluded from the definition 

of solid waste (and therefore CISWI coverage), and this could appear contrary to the result in NRDC 

v. EPA, 489 F.3d 1250 (D.C. Cir. 2007). They expressed concern that the D.C. Circuit would view 

this as somehow inconsistent with their 2007 opinion. 

We explained in our NHSM petition (as well as our rulemaking comments) that EPA's 

discretion to exclude materials from the definition of solid waste through the RCRA NHSM 

rulemaking was in no way constrained by NRDC v. EPA, 489 F.3d 1250 (D.C. Cir. 2007). Section 

129(g)(1) of the CAA provides (with specified exceptions) that any facility that combusts any "solid 

waste" will be subject to CAA § 129. Section 129(g)(6) then provides that "solid waste" shall have 

the meaning established by the Administrator pursuant to RCRA. 

3 
In the 2000 CISWI rulemaking (65 Fed. Reg. 75338) leading up to the NRDC case, EPA had 

not attempted to exclude any non-hazardous material combusted for energy recovery from the 

definition of "solid waste" pursuant to RCRA. EPA had engaged in no RCRA rulemaking related to 

CISWI at all. 

Rather, EPA's CISWI rule simply provided that facilities combusting solid waste for energy 

recovery would not be subject to CISWI. Id. at 1256. It is easy to see how the D.C. Circuit could 

come to the conclusion that the rule "conflicts with the plain language of section 129." Id. at 1257. 

The rule said that material which could arguably be considered a "solid waste" would nevertheless be 

exempt from CAA § 129. 

EP A has now - quite properly - engaged in rulemaking under RCRA. There is absolutely 

nothing in the NRDC opinion that constrains EPA's discretion in defining solid waste under RCRA. 

In the RCRA rulemaking EPA can - as it has done - provide that certain materials managed in 

certain ways will not be deemed solid wastes for purposes of triggering CAA § 129. In fact, a vast 

amount of material that EPA attempted to exclude through its prior CISWI rulemaking is now 

excluded through the current NHSM rule. And that material is most clearly combusted for energy 

recovery. 

Certainly, the fact that a court has rejected a result an agency has reached through improper 

legal avenues does not mean the agency is precluded from later reaching the same result through 

proper legal avenues. We find that proposition rather unremarkable, and cannot imagine why the 

D.C. Circuit would have any problem with such a proposition. We note that just two months ago, the 

Supreme Court found it entirely appropriate to give effect to an FCC order that had previously been 

rej ected on judicial review when the FCC "found another way to support that same conclusion." 

Talk America, Inc. v. Michigan Bell Telephone, 131 S.Ct. 2254, 2264 (June 9,2011). EPA's RCRA 

rulemaking will stand or fall in the D.C. Circuit based on the rulemaking record and EPA's 

articulation of its rationale, and we are confident that EPA can articulate solid rationale for excluding 

bona fide fuels in a manner that serves the purposes ofRCRA Subtitle D. 

- "Concept Paper" for Legitimacy Criteria Comparable Contaminants 

PCA appreciates the opportunity provided by EPA to review the concept paper you 

distributed at the meeting, which is posted on EPA's Web site and dated July 11, 20 II. 

http://www.epa.gov/epawaste/nonhaz/define/pdfs/nhsm-concept.pdf. While we do believe that the 

grouping of contaminants by type is a step in the right direction, we struggle with the application of 

the guidance in practice at cement plants. As we have indicated on numerous occasions, cement 

plants are capable of using a long list of alternatives to conventional fuels. These fuels, like 

conventional fuels, are combusted to provide the necessary process heat to produce clinker, the 

intermediate cement product. The process temperatures are such that organic compounds present in 

fuels are fully combusted (greater than 99.99% destruction), whether they are contained in 

conventional or traditional fuels. Accordingly, PCA struggles with the approach outlined in the 

concept paper which would require a contaminant comparison between alternative and "traditional" 

fuels prior to combustion. For example, some alternative fuels may have a higher concentration of 

one or two organic compounds when compared to a traditional fuel, though this difference becomes 

irrelevant once the fuel is combusted in the kiln. 

4 
PCA believes that the focus should be on whether the utilization of an alternative fuel 

impacts a facility's ability to comply with the underlying air emission standards. This very burden of 

proof is already a part of the portland cement national emission standard for hazardous air pollutants 

(NESHAP), where the operator must determine whether (or not) to re-test a kiln to confirm 

compliance with an air emission standard when switching fuels. 

This makes sense, as the issue in question is whether the use of a non-hazardous alternative 

fuel will impact air quality. PCA believes that the approach currently employed under the NESHAP 

could also be employed here, especially in light of the fact that the focus in on non-hazardous 

materials in the first instance. In implementing such an approach, PCA believes it would be highly 

appropriate for cement plants to consider groups of pollutants, rather than individual pollutants, as 

has been suggested in the concept paper for contaminants in fuels pre-combustion. 

Moreover, EPA has already come to this very conclusion regarding scrap tires managed 

through an established program. EPA has determined that these tires can be deemed to pass the 

legitimacy criteria. PCA suspects that the Agency may have come to this conclusion having had the 

opportunity to review the comparative air emission analysis prepared by PCA addressing tire 

combustion in kilns which demonstrated that the emissions when burning tires versus when burning 

only conventional fuels are virtually indistinguishable. 

Lastly, we note that if EPA does plan to issue some type of comparable contaminant 

guidance, this should be offered up as an official change to the NHSM rule and be accomplished 

through normal notice and comment rulemaking. PCA continues to believe, however, that the 

legitimacy criteria in the NHSM rule for non-hazardous fuels are unnecessary and regulatory overkill 

for the materials in question. 

Please do not hesitate to contact me with any questions regarding PCA perspectives on this 

matter. I may be reached at (202) 408-9494 or aohare@cement.org. 

Cc: Gina McCarthy, OAR 

Barry Breen, OSWER 

Suzanne Rudzinski, ORCR 

Jim Berlow, ORCR 

John Michaud, OGC 

Steve Silverman, OGC 

5 

Sincerely, 

Andrew T. O'Hare 

Vice President, Regulatory Affairs 


















TUESDAY, NOVEMBER 08, 2011 1

TECHNICAL MEMORANDUM

Boiler MACT Economic Impact Evaluation

PREPARED FOR: Amy Banister, Waste Management, Inc.

PREPARED BY: Evan Griffiths, Dan Pitzler and Tom Kraemer, CH2M HILL

DATE: November 9, 2011

Introduction

This Technical Memorandum summarizes the economic evaluation of the cumulative, nationwide financial impacts of 

switching from landfill gas (LFG) to natural gas at facilities currently using LFG as boiler fuel, if this were to occur in 

response to the requirements of the currently promulgated Boiler Maximum Achievable Control Technology (MACT) 

rule. The facilities used for this evaluation were those included in a database spreadsheet provided by USEPA’s 

Landfill Methane Outreach Program (LMOP) by email to Waste Management on September 26 of this year.

This analysis is limited to the projected financial costs for existing projects utilizing landfill gas in boilers that would be 

affected by the Boiler MACT rule if it became effective. Additional economic impacts including projected loss of jobs 

have been projected by LMOP. Still more economic impacts would result from the inability to develop new projects 

that would use landfill gas in boilers. LMOP estimates there are over 500 landfills capable of development into 

landfill gas-to-energy projects. However, the number that would use LFG in boilers and the investments and returns 

for these prospective projects are too uncertain to estimate the financial impacts. 

Results

Table 1 lists the estimated financial impacts of switching from LFG to natural gas for all LFG-fired boilers in the United 

States listed in USEPA’s LMOP database. Costs in Table 1 are rounded to the nearest million dollars

TABLE 1. 

Summary Costs for Converting LFG Boiler and Boiler Steam Turbine Projects to natural gas

 

Type of Project NPV of Natural Gas 

Supply 

Minus LFG 

O&M Costs

NPV of Lost Royalty 

Payments

Capital Cost (2011 dollars) Abandoned Value 

(Depreciated Value of 

Capital Cost)

Boilers $797,000,000 $62,000,000 $156,000,000 $78,000,000

Boiler Steam Turbines $190,000,000 $15,000,000 $94,000,000 $9,000,000

Combined TOTAL (Boiler 

and Steam Turbine)

$987,000,000 $77,000,000 $250,000,000 $87,000,000

The order-of-magnitude estimate of the total direct financial impact of fuel-switching from LFG to natural gas for the 

list of sites provided by LMOP is thus estimated to be $1.064 billion, the sum of the NPV of natural gas costs in excess 

of LFG O&M costs, and the NPV of lost royalty payments to landfill owners. 

The costs for utilizing natural gas to replace the LFG were calculated for each project. These costs were computed as 

the net present value of the cost differences between natural gas supply and estimated LFG operations and 

maintenance (O&M) costs over the remaining life of the project. Lost royalty payments to landfill owner and/or 

developer were estimated based on the amount of BTUs for which royalty payments would no longer be paid over 

the remaining life of the system.

In addition to direct revenue impacts, project owners will lose the value of LFG processing and transport equipment 

that must be abandoned when switching from LFG to natural gas. To estimate this impact, the capital costs 

associated with constructing compressor systems and pipelines for utilizing LFG in the boiler projects were estimated 
BOILER MACT ECONOMIC IMPACT EVALUATION

TUESDAY, NOVEMBER 08, 2011 2

for each project in the LMOP database, as described below under Methodology. The costs were depreciated based 

on the age of the project to estimate the depreciated value of the installed system that would be abandoned. These 

sunk costs must be written off as stranded assets before they are fully depreciated. The total estimated capital 

assets lost for all existing project is $87 million. 

In addition, Waste Management has estimated they could lose $4 to 5 million annually in revenue from third party 

developers and directly from large industries. This loss of revenue is likely only a portion of the total revenue that 

could be lost when all other factors such as end user costs are also factored.

Methodology

A list of projects that use LFG as boiler fuel was generated by LMOP. LMOP is a voluntary program of the U.S. 

Environmental Protection Agency that is intended to help reduce methane emissions from landfills by encouraging 

the recovery and beneficial use of LFG as an energy resource. LMOP maintains a database of projects that use LFG as 

boiler fuel. This database was downloaded to an Excel file and used as the basis for this financial evaluation. The 

database contains, among other data, the landfill name, location, start-up date, quantity of LFG used, and the length 

of pipeline used to pipe the LFG from the landfill to the boiler location (i.e. project site). This data was sufficient to 

form the basis for an order-of-magnitude estimate of the total capital costs, depreciated capital costs (that would be 

abandoned upon switching to natural gas), annual O&M costs for the LFG-to-boiler fuel projects and lost royalty 

payments. Additional tabs were added to the LMOP database Excel file to aid in conducting the evaluation. 

A “Base Project” capital cost estimate was prepared and used as the basis to extrapolate the capital costs for 

compressing, chilling, and transporting LFG to the receiving boiler for each of the projects in the LMOP database. The 

Base Project construction cost is based on previous CH2M HILL projects for LFG compressor systems at landfills and 

the pipelines between the landfills and the gas use site. O&M costs for the base project were similarly estimated 

based on previous projects. The O&M costs for the LMOP sites were calculated based on the LFG flow which was 

used to compute compressor power requirements. Labor and materials O&M costs were assumed based on previous 

project experience. 

Once the costs for each system were extrapolated from the base project, additional project costs (engineering, 

administrative, etc) were added based on a percentage (Table 2) of the subtotal capital costs to estimate the grand 

total based on 2011 dollars. 

The grand total cost calculated for 2011 was then used to estimate the current year cost for construction of the 

compressor, chiller, and pipeline reflective of the startup date presented for each project in the database. This was 

done by multiplying the grand total base project cost by the ratio between the historic (i.e. date of startup) and 

current ENR (Engineering New Record) City CCI values. This value was then depreciated to 2011 using the straightline 

method and an assumed project life of 20 years to estimate the abandoned value of the LFG system and pipeline that 

would occur upon switching to natural gas.

The loss in royalty payments was calculated based on the amount of BTUs that would no longer be utilized by the end 

user over the remaining life of the LFG system and pipeline, multiplied by a factor that approximates typical royalty 

payments to landfill owners for landfill gas-to-energy projects. The total cost reported in Table 1 is the net present 

value of payments projected over the remaining life of the project if fuel-switching had not occurred. 

The cost for utilizing natural gas instead of landfill gas was calculated by subtracting the displaced cost of operating 

and maintaining the landfill gas processing and transport system from the cost for purchasing natural gas. The total 

natural gas cost that would be paid in lieu of the landfill gas was then calculated based on Net Present Value (NPV) 

using the remaining life of the system assuming a 20 year project life and a real interest rate of 7%, which is assumed 

to approximate the private sector cost of capital. Although many of the landfills are publicly owned, almost all of the 

boiler operations using the gas are privately owned and would bear the cost of switching to natural gas.

Assumptions

The following assumptions were made in conducting this economic evaluation. 
BOILER MACT ECONOMIC IMPACT EVALUATION

3

TUESDAY, NOVEMBER 08, 2011

1) The capital cost for the base project compressor and chiller system was estimated at $675,000 for a 750 cfm 

compressor system. The costs for systems that had flows less than or greater than this range were 

extrapolated from the base project using an extrapolation exponent of 0.75. The ratio of a given project 

capacity to the base project capacity is raised to the exponent and the result multiplied by the base project 

cost to estimate the given project cost.1

2) The capital costs for the base project pipeline were estimated at $2/in diameter-ft of pipeline for flows less 

than 2000 cfm and $6/in diameter-ft of pipeline for flows greater than 2000 cfm. Therefore, the installation,

including labor and materials, of a 4 inch pipeline at 1000 cfm would be $8/ pipeline ft or approximately 

$42,000 per mile plus other additional costs as described below.

3) If pipeline information was not listed for a project on the LMOP database, the median pipeline length (3.30 

miles) obtained from the boiler project tab was used. Just over half of the boiler site projects did not include 

pipeline length information. It is noted no pipeline information was provided on the Boiler-Steam Turbine 

Tab.

4) Project capital costs in addition to construction were added to the capital costs based on a percentage of the 

subtotal (compressor and pipeline) costs (Table 2).

TABLE 2. 

Additional Costs added to Capital Cost for Compressor System and Pipeline (Subtotal)

 

Item Percent Addition to Cost

Road Crossing (s) 10%

Engineering 10%

Permitting 3%

Administration and Legal 5%

Construction Management 8%

Mobilization/Demobilization 12%

5) The cost of natural gas was assumed to be the latest available average U.S. retail natural gas price for 

industrial users of $5.40 per MMBTU, as published by the U.S. Energy Information Agency. 

(http://38.96.246.204/totalenergy/data/annual/showtext.cfm?t=ptb0608) 

6) The price per kilowatt-hour for Operation and Maintenance (O&M) of the LFG system was assumed to be the 

latest available average U.S. retail electricity price for industrial users of $0.0679/kw-hr, as published by the 

U.S. Energy Information Agency. (http://38.96.246.204/totalenergy/data/annual/showtext.cfm?t=ptb0810)

7) The pipeline costs for transporting natural gas from a high pressure supply pipe line to the project site were 

considered minor (i.e. a trivial distance between the project site and supply pipeline); therefore, they were 

not estimated or considered in this evaluation.

8) Regional costs for capital investments including labor were not considered as part of the evaluation. It was 

assumed that the costs for varied capital and labor costs across the United States, which is covered by the 

LMOP program, would average out. Royalty payments were estimated at $0.75/MM BTU.

9) The life cycle of the LFG project was assumed to be 20 years.

 1 Whitesides, Process Equipment Cost Estimating by Ratio and Proportion

(http://www.pdhonline.org/courses/g127/g127content.pdf)
BOILER MACT ECONOMIC IMPACT EVALUATION

TUESDAY, NOVEMBER 08, 2011 4

10) The 20 City Construction Cost Index (CCI), which is calculated annually by The Engineering News Record 

(ENR), was used to calculate the capital costs of the landfill gas compressor and chiller based on the startup 

date from the estimated 2011 dollars (Grand Total) derived from the base project. The CCI values used in this 

estimation were an average of the 20 cities listed in the CCI.

11) The energy content of natural gas was assumed to be approximately 1000 BTU/ft3

.

12) The methane content of LFG was assumed to be 50%; therefore, the energy content was assumed to be 500 

BTU/ft3

.

13) The Net Present Value (NPV) was estimated based on an inflation rate of 3% and a nominal discount rate of 

10%. Therefore, the ‘real discount rate’ is 7%.

14) For projects older than twenty years, it is assumed there is no economic impact to fuel-switching. Projects at 

the end of their useful project lives are assumed to be replaced or abandoned in the near future. 
Copyrighted page(s) removed. Copyrighted 

material is not available in Regulations.gov since 

it may not be reproduced without consent of the 

copyright holder. 

Removed pages can be viewed at the USEPA 

Docket Center, Public Reading Room. 

Address: 1301 Constitution Ave, NW 

Room 3334 

Washington, DC 20004 

Telephone: 202-566-1744 

Email: docket-customerservice@epa.gov
Definition of resinated wood and resinated trim:

Resinated wood means wood products (containing resin binders and adhesives) 

derived fromproduced by primary and secondary wood products manufacturing. 

Resinated wood includes residues from the manufacture and use of resinated wood, 

including materials and comprised of such items as board trim, sander dust, and panel 

trim, and off-specification resinated wood products.

Suggested changes to March 2011 NHSM definitions.

 Clarifies the spectrum of resinated materials currently used as fuels throughout 

the wood product manufacturing process

 Includes definition of resinated wood trim to include broad class of materials 

produced at wood product mills.
Economic Impact of Pending Air Regulations on 

the U.S. Pulp and Paper Industry - Updated

Prepared by Fisher International, Inc. 

September 2011
2

Introduction

This report is an updated version of a report of similar name released in August 2010. It 

describes the potential impact of a series of rules issued by the Environmental Protection 

Agency (EPA) in March 2011 establishing Maximum Achievable Control Technology for 

industrial boilers, commonly referred to as the Boiler and Incinerator MACT rules

1

. 

Several other unrelated air regulations also are pending. They include but are not limited 

to the Cluster MACT reopening, Pulp and Paper Residual Risk, and several National 

Ambient Air Quality Standard (NAAQS) revisions that directly or indirectly drive more 

stringent standards. 

This update uses the same assumptions as the original report with the following 

exceptions:

 Pulp and paper mill assets and costs-of-production were taken from

FisherSolve

TM’s Q1_2011 release;

 Capital and operating costs of compliance to regulations were updated by the 

consulting firm URS based on the latest available information. 

The American Forest & Paper Association (AF&PA) engaged URS to update estimates of

the likely costs of complying with these pending regulation changes and Fisher 

International Inc. to assess the impact of these compliance costs on the economic viability

of U.S. pulp and paper mills.

The URS findings are presented in detail in a report entitled, “Cumulative Cost Burden

Analysis of Air Regulations Potentially Impacting the Forest Products Industry,” dated

August 2011. A regulation-specific summary of the URS cost estimates appears in

Appendix A of this report and indicates which rules were included in this assessment and 

which were not.

In summary, this update shows potentially severe impacts on the pulp and paper industry

from EPA regulations affecting industry boilers (e.g. Boiler MACT and CISWI) and other 

upcoming Clean Air rules for which the costs could be estimated, as follows:

 The Boiler MACT rules, after accounting for the impact on jobs of proposed 

general pulp and paper manufacturing Clean Air regulations, put at serious risk an 

incremental :

o 20,541 jobs in pulp and paper mills alone

o 87,299 jobs considering both job losses in pulp and paper mills and jobs 

lost along their supply chain and in the surrounding community.

2

 

1 On March 21, EPA published the Boiler MACT rule and three related rules -- the Commercial and Industrial 

Solid Waste Incinerator (CISWI) rule (setting emissions limits for non-hazardous solid waste incinerators); 

the definition of Non-Hazardous Secondary Materials (a Resource Conservation Recovery Act rule 

determining which materials are wastes and thus covered under the CISWI rule when burned); and Boiler 

GACT (Generally Achievable Control Technology for boilers at smaller sites). These four rules often are 

collectively referred to as the “Boiler MACT rules.”

2 Note that these estimates do not include job losses in the wood products manufacturing sector of the 

forest products industry from an estimated $2 billion in new MACT costs.
3

 The Boiler MACT rules and other upcoming Clean Air regulations put at serious 

risk a total of:

o 38,060 jobs in pulp and paper manufacturing alone

o 161,755 jobs considering both the losses in pulp and paper mills and the

jobs lost along the supply chain and in the surrounding community.

3

Methodology

Fisher International was asked to quantify the likely impact of new air pollution control 

regulations on employment in U.S. pulp and paper mills by estimating how many mills 

would be in jeopardy of closing if they had to comply with the relevant new air regulations.

To make the estimate, we used two major resources: FisherSolveTM, a proprietary

industry database describing the assets and costs-of-production of each mill, and

descriptions provided by URS of how different types of mills would need to respond to

each potential new regulation and the costs of that compliance.

We projected the costs of compliance for each mill and calculated them as a percentage 

of costs of production. When compliance would increase a mill’s cost-of-production by 

more than a sustainable amount, we listed that mill and its associated employment as 

being “at-risk.” Note that the costs projected in this report for each mill’s compliance do

not include the costs associated with a number of regulations for which URS was unable

to quantify a mill-specific compliance impact.

4

 Moreover, there is another set of

regulations that trigger a cost to a mill only when the mill makes a physical change in the

future, such as rebuilding a boiler. As we do not know which mills may make changes in

the future, these impacts also are not included in this analysis. For this reason, the 

analysis may understate the impact of regulations on mill costs and jobs.

We assumed that the “sustainable amount” of incremental cost a given mill can absorb is

equal to the amount of cash that the average mill produces for its owner after variable

costs and capital expenditures. In other words, when a mill gets to a cash break-even

level, it becomes a serious risk for closure. It would be fair to argue that this is a 

conservative assumption because many owners would prefer to shutter a mill well before it

reached a cash cost breakeven level to redeploy management time and maintenance

capital to other, more profitable facilities. The average sustainable amount of cost

increase for the industry based on this analysis is 12.5% of cost of production. (See below

for a more detailed explanation of how this figure was derived.)

 

3 Note these estimates do not include job losses in the wood products manufacturing sector of the forest 

products industry.

4 Roughly $2 billion in new capital costs for pulp and paper mills meeting various National Ambient Air Quality 

Standards (NAAQS), changes to the New Source Review (NSR) requirements, New Source Performance 

Standards (NSPS), and the Clean Air Interstate Rule (CAIR) were not factored into the mill closure/job loss 

calculations because they could not be allocated to specific mills.
4

For most regulations, compliance requires both capital and operating costs. We translated

capital costs into operating costs by using an interest rate of 11%, representing the

industry’s weighted average cost of capital (WACC), and a term of five years. We based

the WACC on a survey of investment bankers and industry analysts. The five-year term

was arrived at by noting that:

 the industry’s capital structure is approximately 50% debt and 50% equity,

 the average industry term of debt is about ten years, and

 funding with equity is equivalent to a term of “zero” years (because shares are

diluted immediately when a company raises cash by selling equity).

Therefore, the average payback term we used to calculate the cost of funding compliance

is five years ((10 years + 0 years) divided by 2 = 5 years).

The table below summarizes how we arrived at the financial “at-risk” rate of spending on 

compliance that would put a mill in jeopardy of closing. Ideally, we would have compared

the cost impact of compliance to mill margins. However, since we did not have data on

each mill’s profit margin, we assumed an industry average margin, added an industry

average factor for cash spent on capital and applied them to cost-of- production data that

we do have. This allowed us to create an industry average “at-risk” rate that we could

compare to the costs of compliance.

5

We estimated the industry average “at-risk” rate using data drawn from the financial 

statements of a group of public U.S. pulp and paper companies. We found the industry’s 

average gross margin over a 10-year period, which is revenue less the cost of goods sold

(mainly materials and labor) as a percentage of revenue. We then deducted average

capital expenditures per dollar of sales and an average cost-of-sales (such as broker 

commissions and early payment discounts).

Item Percent

10-year average industry gross margin 19.7%

Less 10-year average capital expenditures per $ of sales 7.6%

Less factor for cost of sales 2.0%

Equals at-risk rate as percent of sales 10.1%

At-risk rate as percent of cost-of-production 12.5%

 

5 While the methodology is the same, this description is different from the one supplied in the original report

in an attempt to clarify the methodology used.
5

These calculations resulted in an average “at-risk” rate (the maximum amount of cash 

cost increase the typical mill could absorb) of 10.1% of sales. Given the industry’s 

average margins, this is equivalent to 12.5% of cash cost-of-production. Hence, if air 

regulation-related incremental operating costs and annualized costs associated with 

capital expenditures to comply with the regulations amount to more than 12.5% of a mill’s 

cash costs, the mill is classified as at risk of closing.

The increase in costs of compliance with new air regulations will affect mills in different 

ways. In some cases, mills will suffer increases in costs greater than their domestic

competitors, thus losing competitiveness in their home markets and becoming risks for

closure. In other cases, even if all mills in a product category experience similar cost 

increases, many U.S. mills become “at-risk” for closure because international competitors 

gain a cost advantage and prevent prices from rising.

As of this date, there still is some uncertainty around how certain rules will be written. 

Therefore, this report contains the results of two scenarios, each representing one 

possible outcome. The results for Scenario 1 are presented in this report. The results for 

Scenario 2 are summarized at the end. The two scenarios are:

 Scenario 1 – many types of biomass that is burned are treated as solid waste, and 

therefore, are subject to the Solid Waste Incinerator rules instead of the Industrial 

Boiler MACT rule.

 Scenario 2 - many types of biomass that is burned are treated as fuel, and 

therefore, are subject to the Industrial Boiler MACT rule and not the Solid Waste 

Incinerator rule.

Scenario 1 Results

Analysis of mill-specific increases in annualized air regulation compliance costs suggest 

that the Boiler MACT regulations, if they are incremental to the pending manufacturingrelated air regulations, could result in the closure of 36 mills employing 20,541 people or

18% of the primary pulp and paper sector’s workforce. (The primary pulp and paper sector 

encompasses only pulp and paper mill jobs; the risk to logging jobs and converting 

operations are not included in these figures.)

The calculations suggest that 79 pulp and paper mills would be at significant risk of 

closing if the larger suite of new air regulations for which we have data were

implemented. These mills employ 38,060 people, or 33% of the primary pulp and paper 

sector’s workforce. The following table shows potential mill shutdowns and job losses:
6

 Mills at Significant Risk of Closure

Incremental from Adding

Boiler MACT P&P Mfg Regs Only

Total of Boiler MACT

and P&P Mfg Regulations

Jobs At Risk # of Mills Jobs At

Risk

# of Mills Jobs At

Risk

# of Mills

20,541 36 17,519 43 38,060 79

Base 113,858 349

Percent change 33% 23%

Ripple Effect

Pulp and paper mill jobs support jobs in other industries that supply the pulp and paper 

industry in local communities and throughout the United States. A scholarly paper 

prepared by the Economic Policy Institute -- “Updated Employment Multipliers for the US

Economy, 2003” -- was provided to Fisher by AF&PA. Table 9 of the paper indicates that

for every 100 jobs in the paper industry, there are an additional 325 jobs sustained in

other industries due to the purchase of supplies and the re-spending of worker incomes. 

Hence, the pulp and paper industry’s multiplier is 4.25.

Applying the 4.25 multiplier in the previous table suggests that 87,299 jobs can be lost by

imposing Boiler MACT regulations on top of the proposed new pulp and paper 

manufacturing-related air regulations (20,541 X 4.25 = 87,299). Atotal of 161,755 jobs –

inside and outside the pulp and paper industry -- could be lost as a result of the entire

suite of proposed air regulations (38,060 X 4.25 = 161,755).

Mill & Community Jobs at Risk at 4.25 Multiplier

Incremental from Adding

Boiler

P&P Mfg Only

Total of Boiler MACT and P&P 

Mfg Regulations

Scenario 87,299 74,456 161,755

Fisher International also calculated pulp and paper jobs losses associated with the 

proposed regulations by region. Regional figures do not include the multiplier effects.
7

Job losses for Regions (No Multiplier)

Incremental At Risk 

Jobs from Adding 

Boiler Regulations

At Risk Jobs for P&P 

Mfg. Regulations 

Only

At Risk Jobs for Boiler

and P&P Mfg 

Regulations

US -

Northeast 2,177 2,877 5,054

US -

Midwest

5,505 3,878 9,383

US -

Southeast

11,924 7,529 19,453

US - West 935 3,235 4,170

Total US 20,541 17,519 38,060

Scenario 2 Results

Under Scenario 2, many types of biomass that are burned are treated as fuel, and 

therefore, most plants are subject to the Industrial Boiler MACT rule and not the Solid 

Waste Incinerator rule.

The calculations for this scenario suggest that the Boiler MACT regulations, if they are

incremental to the pending manufacturing- related air regulations, could result in the

closure of 35 mills employing 19,921 people, or 17.5% of the primary pulp and paper 

sector’s workforce. If jobs in supplier industries and local communities are factored in, the 

number of jobs in jeopardy rises to 84,664. The impact of the pending manufacturingrelated air regulations on employment and mill closings is the same as under Scenario 1.

Comparison of Findings: This Report vs. August 2010 Report

In August 2010, Fisher prepared a study on EPA’s proposed Boiler MACT regulations and 

other pending air regulations. The August 2010 study found that 43,666 pulp and paper 

mill jobs would be placed at risk due to a broad suite of pending air regulations. 

Of the 43,666 at-risk paper industry jobs identified in the 2010 study, 26,778 were 

associated with the “other” pending air regulations and 16,888 with Boiler MACT-related 

compliance spending that is incremental to spending on the other air rules.

This new study examining the final Boiler MACT rules found that 38,060 paper industry 

jobs would be placed at risk due to the entire suite of air regulations. Among those 
8

38,060 jobs, 20,541 job losses could result from the final Boiler MACT/CISWI-related 

costs that are incremental to spending needed to comply with the other air regulations, 

and 17,519 jobs are placed at risk by the costs of non-Boiler MACT air regulations. 

The decline in the number of jobs placed in jeopardy by non-Boiler MACT air regulations 

between the original and updated study reflects several factors:

 Between the first and second studies, the number of mills operating in the U.S. 

declined by 7, and the employee base declined by 5,302 jobs. Of the 5,302 fewer 

jobs, 2,600 were lost due to mill closures after the completion of the first report, and 

the remainder reflected headcount reductions at mills that remained operational. 

 Average cost-of-production increased between the two study periods. Because we 

measured compliance costs as a percentage of cash costs, higher cash costs 

appeared to raise the threshold for compliance costs that would put mills at risk. In 

actuality, higher costs might put more U.S. mills at risk rather than fewer because 

foreign mills gain a cost advantage vis-a-vis U.S.mills. 

The increase in the number of jobs put at risk by Boiler MACT rules reflects the underlying 

fact that the regulations as a whole still threaten a significant number of mills and jobs:

 While fewer mills were placed in jeopardy of closing by the “other” air rules, the total

number of jobs at risk declined by a smaller number. The Boiler MACT/Incinerator 

MACT rules, therefore, account for a larger incremental impact.

 In the 2010 study, capital spending was estimated by URS at $5 billion for the 

proposed Boiler MACT/CISWI rules and $13.7 billion for the larger suite of pending 

air rules, including the Boiler MACT/CISWI rules. However, not all of the costs 

could be allocated to specific mills, so capital spending-related compliance costs 

used by Fisher came to $4.6 billion for Boiler MACT and $10.3 billion for the entire 

suite of air regulations.

 Capital spending for the 2011 study was estimated by URS at $4 billion for the final 

Boiler MACT/CISWI and $12.6 billion for all of the pending air rules, including Boiler 

MACT/CISWI. However, not all of the costs could be allocated to specific mills, so 

capital spending-related compliance costs used by Fisher came to about $3.8 billion

for Boiler MACT/CISWI and $10.1 billion for the entire suite of air regulations.

 The Boiler Rules changed between proposal and promulgation. In particular, more 

fuels were classified as solid wastes and therefore, many plants are subject to the 

CISWI rule instead of the Boiler MACT rule. In addition, costs were added for NOx 

emissions reduction requirements to mills in close proximity to projected nonattainment areas.
9

In sum, this study, like the preceding study, shows that the EPA’s Boiler MACT rules would 

have a major impact on the economic viability of many pulp and paper mills and place at risk 

tens of thousands of pulp and paper mill jobs as well as jobs in surrounding communities and 

supplier industries. 
10

Appendix A

URS Estimates of Pulp and Paper Mills Costs of Complying With

Proposed Air Regulations:

How Costs Were Determined:

URS Corporation (URS) worked with the American Forest and Paper Association 

(AF&PA) and its members to develop a rough order of magnitude estimate of the costs 

of complying with various air regulations that could impact the forest products industry. 

The cost estimates were compiled in a Microsoft Excel workbook; were based on 

published information or similar project costs; have been reviewed by member company 

representatives; and have been made available to the US EPA and others for review. 

The Boiler MACT and CISWI estimated costs are in large part based on information in 

EPA’s March 2011 survey and emissions databases.

Capital and operating costs estimates are not intended to represent a worst case 

analysis. Rather, they represent median costs for the various scenarios based on 

published reports, industry information on specific project costs, EPA reports or control 

device fact sheets, or actual Best Achievable Control Technology (BACT) or Best 

Achievable Retrofit Technology (BART) analyses submitted to permitting agencies. A

primary resource was the document entitled, “Evaluation of Air Pollution Control Costs

for the Pulp and Paper Industry,” prepared by National Economic Research Associates 

(NERA) in May 2003. All costs were discussed with a core team of AF&PA members 

and reviewed by URS engineers familiar with boiler and other pulp and paper mill 

operations and controls prior to finalizing the study.

Boiler MACT Costs:

The Boiler MACT will require emissions controls for particulate matter, hydrogen 

chloride, mercury, carbon monoxide, and dioxin/furan. The control technologies that 

EPA has identified as necessary to comply with the Boiler MACT are a fabric filter for 

control of particulate matter, carbon injection for control of mercury and dioxin/furan, a 

scrubber for control of hydrogen chloride, and combustion improvements or an oxidation 

catalyst for control of carbon monoxide. In some cases, the emission limits will be very

difficult to achieve over all operating conditions, but the cost analysis assumes that for 

each boiler, facilities can apply emissions controls to achieve the Boiler MACT limits with

a comfortable margin of compliance. In some cases, existing equipment configurations

may prove impossible to upgrade, and boilers and process heaters may need to be

replaced, which is a cost that is not reflected in the analysis. Note also that many

facilities may choose fuel switching as a compliance option; however, as the cost of fuel 

switching is highly dependent on site specific factors (e.g., whether the boiler can burn

the alternate fuel, what upgrades must be made to the fuel supply system) and the price

of fuel will change over time due to factors like supply and demand, URS did not attempt

to quantify costs for fuel switching.
11

The EPA collected information during Phase 1 of the Boiler MACT information collection 

request (ICR) on thousands of boilers and process heaters at hundreds of facilities. A 

detailed spreadsheet was developed to estimate costs for Boiler MACT for individual 

boilers and process heaters, based on EPA’s major source boiler inventory database 

table and the emissions data included in EPA’s boiler MACT database. URS extracted 

information from EPA’s major source boiler inventory database including boiler ID, size, 

fuel category, emissions, and current air pollution control equipment. Based on the 

information in EPA’s database and the baseline emission factors developed by EPA by 

boiler type and control device, URS determined whether each unit would require 

additional air pollution controls to meet the Boiler MACT limits. Note that we did not 

perform any quality assurance on the information in EPA’s database, but where we had 

knowledge that a boiler had been mis-categorized (e.g., a biomass boiler was listed as a

liquid boiler) we did make those changes in our spreadsheet.

A spreadsheet was developed that represents only the units to be regulated by the rule

(excludes natural gas boilers, process heaters, boilers and process heaters less than 10

MMBtu/hr heat input, and limited use units). Based on the information in the EPA 

emissions database, we estimated costs of controls that would likely be necessary to 

comply with the Boiler MACT for coal, biomass, liquid, and Gas 2 boilers 10 MMBtu/hr 

and greater (note that for the final rule, EPA moved all gas-fired boilers to the Gas 1 

subcategory unless they were burning any amount of coke oven gas or blast furnace 

gas). As some forest products boilers at major sources did not receive an ICR from EPA

in 2008, we added information for those boilers to the detailed spreadsheet based on

information from AF&PA/National Council for Air and Steam Improvement (NCASI).

There are likely other units that are not included in the study, as other trade groups have

submitted comments indicating that EPA has likely underestimated the universe of

affected units (e.g., American Chemistry Council (ACC) and American Petroleum 

Institute (API)/ National Petrochemical and Refiners Association (NPRA).

Information from various sources was used to determine a base capital cost for a 250

MMBtu/hr boiler for each PM, CO, and HCl control technology option and then scaled

using an 0.6 power function based on the size of each boiler in the inventory. For 

example, the capital cost of a wet scrubber on a 100 MMBtu/hr boiler is calculated as the

base cost times (100/250)

0.6

. A fixed cost of $1 million was assumed for installation of a

carbon adsorption system for Hg and/or dioxin control, as these systems do not vary

much in cost by boiler size. Base cost assumptions are presented below.

Base Control Size, MMBtu 250

Fabric Filter $7,000,000

Scrubber $8,000,000

Scrubber/FF/ESP upgrade $4,000,000

Carbon Injection for Hg/dioxin $1,000,000

Combustion Improvements or Catalyst for CO $3,000,000
12

Controls were evaluated separately, first for particulate matter, then for hydrogen 

chloride, then for mercury and dioxin/furan, and last for carbon monoxide. To estimate 

Boiler MACT controls and costs for each unit, if there was no emissions information 

available for a particular boiler, we use the baseline emission factors developed by EPA 

for their analysis. In their boiler inventory table, EPA put the boiler pollution controls into 

categories. The categories are explained in greater detail in EPA’s baseline emission 

factor memo, but basically are as follows: for PM control code, 1=FF, 2=EFB/ESP, 

3=venturi scrubber, 4=wet scrubber, 5=multiclone, 6=none/mist eliminator/unknown. If a

unit did not already have a FF or ESP and there was information that indicated the unit

cannot meet the limit, we assumed a new FF. If the unit already had a FF or ESP and

there was information that indicated the unit cannot meet the limit we assumed an 

upgrade to the existing control equipment. For HCl control code, 1=wet scrubber or 

spray dryer, 2=dry scrubber, 3=sorbent injection, 4=venturi scrubber, 5=none/dry PM 

only. To estimate control costs for HCl, if there was information that indicated the unit 

cannot meet the limit, we assumed either a scrubber upgrade or new scrubber 

depending on whether the unit currently had a scrubber. For Hg control code, 1=carbon 

injection, 2=FF plus sorbent injection or spray dryer, 3=FF only, 4=wet scrubber, 

5=venturi scrubber, 6=none/multiclone/EFB/mist eliminator. For Hg and dioxin, if there 

was information that indicated the unit cannot meet the limit, we added carbon injection. 

For CO, if there was information that indicated the unit cannot meet the limit, then we 

assumed that capital would be necessary to either perform combustion/fuel feed 

improvements or other boiler improvement projects to reduce CO or install a CO 

catalyst.

Although EPA’s estimates indicate that the total capital cost of the final rule will be $5

billion, URS has estimated that the total capital cost of the rule will be over $14 billion for 

all industry ($2.85 to 3.2 billion for pulp and paper mills, depending on whether more 

materials are waste or fuel). It is evident major capital investments in add-on control 

technology will be required for continued operation of solid and liquid fueled boilers and

process heaters.

URS capital cost estimates differ from EPA’s cost estimates as follows:

 EPA has used the outdated Control Cost Manual and URS based cost estimates 

on more recent information, including actual vendor cost estimates, actual project 

costs, BACT and BART analyses, industry control cost studies, etc.

 URS used a CO catalyst cost 4 times higher than EPA’s. The URS cost is based 

on a recent quote from BASF and EPA’s is based on the 1998 Control Cost 

Manual section on catalytic oxidizers for VOC control.

 EPA has estimated that a tune-up or burner replacement will be adequate for 

many units to achieve the CO limits. URS does not agree with this assumption 

because some of the CO limits are fairly low and must be met over all operating 

conditions except startup and shutdown, so we have estimated higher costs to 

implement combustion controls, burner replacements, fuel feed system 

improvements, or CO catalyst.
13

 URS CO control capital costs are higher than EPA’s, mostly because EPA 

assumed that tune-ups and replacement burners will be adequate for the vast 

majority of boilers to comply, and URS does not agree with that assumption.

 EPA has estimated that activated carbon injection will be required on only 120 

existing units because installation of a fabric filter is expected to achieve the 

mercury emission limits, except in cases where a unit already has a fabric

filter and does not meet the limits. URS does not agree that fabric filters will 

be sufficient to reduce mercury emissions to the ultra-low levels in this rule.

There is a flaw in the logic that fabric filters are expected to achieve mercury

emission limits when there are many boilers in the database that are equipped

with fabric filters and have measured mercury emissions higher than the

applicable limit. EPA’s estimated industry-wide capital cost for activated 

carbon injection presented in the ERG cost and emissions impacts memo is 

extremely low, at only $6.2 million (only $52,000 per unit average). This cost 

better represents 12 units than 120 affected units.

 EPA has estimated costs to install packed bed scrubbers for HCl control. 

Industrial boilers do not use packed bed scrubbers for acid gas control, as the 

limitations of these devices make them impractical for use on applications with 

high flow rates, high PM loading, and high inlet pollutant concentration. EPA’s 

own fact sheet on these devices, located at

http://www.epa.gov/ttn/catc/dir1/fpack.pdf, lists these limitations of these

devices and indicates that they are only used in applications up to 75,000

scfm, which limits their use to small units only (EPA responded to this 

comment by applying multiple packed bed scrubbers to units with higher flow

rates). Facilities will instead install wet scrubbers, dry scrubbers, or semi-dry

scrubbers to control acid gas emissions from industrial boilers. EPA has 

estimated HCl control costs for equipment that industry is not likely to install.

 EPA has assumed that facilities will not incur costs to comply with the 

dioxin/furan standards because they will test for dioxin/furan and be below 

detection levels. This logic does not make sense, especially when there are 

boilers in the EPA emissions database with dioxin/furan emissions that are

non- detect but actually measured emissions higher than the applicable limit

and there are boilers where EPA’s baseline emission factor for dioxin/furan is

above the applicable limit. We have estimated carbon injection as the control

measure for dioxin/furan emissions, assuming that it will be effective at these

low levels.
14

The following capital costs for control additions/upgrades were estimated by URS for 

pulp and paper coal, biomass, and liquid units having numerical emission limits 

under Boiler MACT (assuming many materials burned are solid waste and not fuel). 

This is Scenario I:

The following capital costs for control additions/upgrades were estimated by URS for 

pulp and paper coal, biomass, and liquid units having numerical emission limits 

under Boiler MACT (assuming many materials burned are fuels and not solid waste). 

This is Scenario II:

These estimated costs differ from the costs of the proposed rule as follows:

 The final emission limits and the combination of biomass and coal boilers into

a solid fuel subcategory for the fuel-based HAP (PM, HCl, and Hg) resulted in

a reduction in control cost for many units.

 For the proposed rule, since many of the limits were so low as to be 

unachievable, we estimated that controls would be required on boilers where

no emissions information was available. For the final rule costs, if no boilerspecific emissions information was available we used EPA’s baseline

emission factors by boiler type and control type to determine if controls would

be required.

 Costs for compliance with the CO limits were adjusted based on information 

received from companies that had done preliminary engineering and cost 

estimates. We used a base cost of $3 million and scaled using the 0.6 factor 

by boiler size for the final rule, versus a fixed cost of $2 million for the

proposed rule.

PM 

Upgrade Cost

HCI 

Upgrade Cost

Hg/Dioxin 

Upgrade Cost

CO 

Upgrade Cost

Total 

Capital Cost

$1.1 Billion $918 Million $232 Million $578 Million $2.85 Billion

PM 

Upgrade Cost

HCI 

Upgrade Cost

Hg/Dioxin 

Upgrade Cost

CO 

Upgrade Cost

Total 

Capital Cost

$1.3 Billion $1 Billion $270 Million $660 Million $3.2 Billion
15

 Costs for mercury and dioxin are captured in the same column because it is 

assumed that carbon injection will be needed to meet both, based on the use 

of carbon injection to meet dioxin standards for higher emitting source 

categories such as municipal waste incinerators. However, the costs to 

achieve the dioxin limits for industrial boilers are uncertain and are likely 

underestimated because most of the dioxin limits are 100-1000 times lower 

than any previous MACT and it is unclear what emission reduction strategies 

could be implemented to meet the standards. The dioxin limits are essentially 

unachievable for most boilers.

CISWI Rule:

Costs for the CISWI Rule were developed in a similar manner as costs for the Boiler 

MACT rule. EPA’s CISWI ICR database was used to determine which units would

be subject to the CISWI rule and what controls would be needed. Units were also 

identified that were in EPA’s Boiler MACT database, but burn NHSM such as 

wastewater treatment residuals, recycling process residuals, TDF, resinated wood, 

creosote treated wood/rail ties. Costs were assigned for PM/metals, NOx, acid gas,

and mercury/dioxin controls. The estimated capital cost of controls for boilers at 

large pulp and paper mills, assuming the current NHSM rule, which classifies many 

existing biomass fuels as solid wastes, is approximately $950 million. Smaller mills 

that would otherwise be regulated under the Boiler GACT rule but are burning 

secondary materials could also face costs under CISWI, but those costs were not 

modeled in this study. If changes are affected to the NHSM rule that allow more 

materials to be classified as fuels, the cost for CISWI controls for large pulp and 

paper mill boilers could be reduced to $470 million.

Scenario Solid Waste 

Determination

Capital Cost for Boilers at 

Large Pulp and Paper 

Mills

One Many materials wastes $950 M

Two Few materials wastes $470 M

Other Pending Air Regulations Where Costs Could Be Assigned to Mills

6

 Cluster MACT I/III Re-do and Residual Risk

o $780 million – >95% of costs due to MACT organic HAP (Methanol) 

controls on paper machines; $360 million in O&M is especially high due

to energy intensive nature of controls which also produce over 2 million 

metric tons of CO2

 

6

Fisher was unable to allocate about $2 billion of these costs to specific mills, so the total capital cost 

used was $6.3 billion.
16

o New Cluster MACT could set limits on additional pieces of equipment

(like paper machines) for organic HAPs; EPA has discretion not to

undertake de novo review of MACTs

o Residual risk review likely to show few risks remain

o EPA scheduled to complete in June 2012 with controls by mid-2015

 Cluster MACT II Re-do and Residual Risk

o $3.3 billion: >95% of cost due to MACT; $300 million in O&M plus 1.5 

million metric tons of new CO2 emissions

o New MACT II could lead to addition of mercury, and HCl controls and 

more stringent PM controls on recovery furnaces, lime kilns, and smelt 

tanks. Again, EPA has discretion whether to revisit MACTs;

o Residual risks from these sources also small

o EPA is likely to complete in 2013 with controls by 2016

 Hydrogen Sulfide HAP Listing

o $2.7 billion in capital, plus $180 million in operating costs

o Assumes H2S listed as HAP and MACT establishes limits for pulping

 operations and wastewater treatment ponds

o EPA has discretion to deny petition or conclude not an issue for pulp 

mills based on careful risk assessment

o Possible final rule in 2015 (maybe sooner), with 2018 implementation

 NOx Controls due to Tighter NAAQS

o Assumed NOx controls (either low-NOx burners, SNCR, or SCR) 

needed on boilers at facilities in or near projected non-attainment 

areas.

o $600 million in capital, plus $140 million in operating costs.

o Final 1-hour NOx standard was published in 2010, ozone standard

expected to be lowered in 2011 (reductions will be driven by NOx in 

many areas), implementation in 2013.

o Facilities have had problems meeting new 1-hour NOx standard when 

modeling for projects

Other Pending Air Regulations Where Costs Could NOT Be Assigned to Mills

 Boiler Area Source/GACT

o Rule sets HAP emission requirements for smaller biomass and liquid 

boilers at so called “area sources” such as box plants; rule does not 

apply to gas-fired boilers.

o Impact of rule is minimal since EPA adopted work practices (tune-ups) 

rather than numeric limits for CO for existing biomass and liquid 

boilers.

o Final rule March 2011, compliance within 3 years
17

 CAIR 3/Cross-State Rule for Industrial Boilers and Recovery Furnaces

o $870 million in capital; total O&M would be $220 million

o Assumes next phase of rule requires medium and large boilers burning

majority coal or oil to significantly reduce SO2 and NOx

o Possible promulgation in 2012 with compliance over the next five

years

 Start-up, Shutdown & Malfunctions (SSM) Provisions Removed from MACT

o $100 million, plus $3 million in O&M

o If EPA compelled to eliminate SSM exemptions and venting 

allowances then installation of redundant controls or suffer periods of 

shutdown with no production would drive costs even higher. EPA has 

discretion to develop reasonable work practices to replace current 

SSM exemptions

o EPA linking schedule with pulp and paper MACT rules, so complete by

2012

 Ozone NAAQS revisit

o $400 million in capital and $30 million in O&M

o Tighter standard will drive more VOC and NOx controls than other 

rules require for smaller contributors in or near more numerous nonattainment areas

o EPA plans to reset NAAQS in 2011; impacts would occur 4 to 5 years 

after finalization

 PM fine NAAQS Implementation

o $284 million in capital and $40 million in O&M

o Assume tighter annual standard will drive further SO2 and NOx 

controls. As in all the above NAAQS, EPA has the discretion to 

determine “ample margin of safety” necessary to protect public health.

o Final in 2012 with controls needed for attainment 5 or so years out

 Revised NAAQS for SO2

o $40 million in capital and $7.5 million in operating costs

o Final in June 2010 with controls on select sources in five years (2015)

o Significant uncertainty in ability to meet increments modeling for 

projects

 Kraft Pulp NSPS Revisions

o $83 million in capital through 2020 and $56 million six years after 

effective date given more mills trigger retrofit requirements

o EPA can defer action on NSPS or set equivalent to MACT to avoid 

new costs

o EPA linking schedule with pulp and paper MACT rules so complete by

April 2012
1

EPA’s Prior Determinations That Landfill Gas is Not a Solid Waste

• Since 1986, EPA has determined under RCRA that landfill gas would be regulated as an 

“air pollutant”, rather than as “solid waste” In that regard, the regulation of MSW 

landfill emissions was considered during deliberations under a RCRA subtitle D 

rulemaking. In 1986 and 1987 the Administrator decided to regulate these emissions 

under the authority of the Clean Air Act. See, e.g. March 6, 1986 Memorandum from 

Marcia Williams to H. Lanier Hickman, Jr. (attached), cited in Definition of Solid Waste 

Compendium, Volume U, (Un)-Contained Gases (December 2010)(attached) (see 

particularly page 9, which refers to the Hickman memorandum and which characterizes

landfill gas as “uncontained” and therefore not “solid waste”). After further 

consideration, the EPA announced in the Federal Register on August 30, 1988 (53 Fed. 

Reg. 33,314) (attached) their decision to regulate MSW landfill emissions under section 

111 of the CAA. This ultimately occurred through the promulgation of the landfill 

NSPS, 40 CFR Part 60, Subparts WWW and Cc in 1996. 

• In the proposed Landfill NSPS standards published on May 30, 1991 (56 Fed. Reg.

24,468) (attached), EPA again reiterated its decision to treat landfill gas as a Clean Air 

Act pollutant (rather than as solid waste).

• The issue was re-raised during public comment for the proposed NSPS. In response, 

EPA specifically stated in response: “the RCRA subtitle D establishes a framework for 

controlling the management of nonhazardous solid waste. Because the intent of this rule 

is to regulate emissions of landfill gas, and not solid waste, this regulation has been 

developed under the CAA instead of under RCRA. Some requirements in the RCRA 

subtitle D regulation are referenced within the NSPS and EG and are necessary to achieve 

compliance with these regulations.” See Air Emissions From Municipal Solid Waste 

Landfills – Background Information for Final Standards and Guidelines, EPA-453/R-94-

021 (December 1995), at pages 1-4, 2-31 to 2-34 (attached). Thus, the concept of 

utilizing RCRA authority and regulating landfill gas as solid waste was specifically 

rejected by EPA at that time. “Although one commenter suggested that LFG emissions 

should be regulated under RCRA authority, the EPA continues to consider Section 111 

NSPS and EG to be the appropriate statutory approach for regulating these emissions 

because the adverse health and welfare effects of concern result from air emissions. 

Therefore, the final notice added MSW landfills as a source category for regulation under 

Section111(b)(1)(A) of the CAA to the priority list in 40 CFR 60.16.” See id.

• On January 16, 2003, EPA issued National Emission Standards for Hazardous Air 

Pollutants: Municipal Solid Waste Landfills (68 Fed. Reg. 2,227), which ensured that 

landfill gas collection and treatment and/or control systems (including combustion units 

and landfill gas used on or offsite in beneficial use projects) achieved MACT level 

controls.

• EPA again noted on March 22, 2004, in revisions to its Criteria for Municipal Solid 

Waste Landfills, Final Rule for Research, Development and Demonstration Permits for 

Municipal Solid Waste Landfills: 
2

“With the exception of explosive gas control requirements, landfill gas controls are not 

regulated pursuant to Subtitle D of RCRA: rather landfill gas emissions are regulated 

under the Clean Air Act (CAA). The air criteria in 40 CFR 258.24 refer to CAA 

requirements by requiring compliance with the applicable State Implementation Plan 

provisions under section 110 of the CAA. Specific requirements pertaining to landfill gas 

emissions from MSWLF units are addressed in 40 CFR Part 60,Subparts Cc and WWW. 

Recently, EPA promulgated National Emission Standards for Hazardous Air Pollutants: 

Municipal Solid Waste Landfills (68 FR 2227, Jan. 16, 2003). This rule includes 

requirements for initiating landfill gas collection and control in bioreactor landfills. See 

40 CFR Part 63, Subpart AAAA.... [C]onsistent with section 1006(b) of RCRA, EPA 

sees no need for additional requirements under RCRA to address air emissions in today’s

rule.” 

See Final Rule, Research, Development and Demonstration Permits for Municipal Solid 

Waste Landfills, 69 Fed. Reg. 13,242 (2004) (attached).

• Thus, by 2004, all landfills regulated under WWW were regulated under the Section 112 

Landfill MACT standards promulgated at 40 CFR Part 63, Subpart AAAA. In all 

instances, the notion was that landfill gas would be combusted either in open flares, 

enclosed combustors (enclosed flares, turbines, engines or boilers), or the gas would be 

treated (compressed, filtered to 10 microns or less, and cooled or chilled) and routed for 

use as fuel as either onsite or offsite. When combusted in turbines, engines or boilers, the 

landfill gas is either controlled to NSPS-specified treatment limits, or it is ”treated” as per 

the NSPS for end use. 

• Having exercised its asserted authority under RCRA Section 4004 to regulate air 

emissions from landfills as a “designated air pollutant” under the Clean Air Act rather 

than as solid waste under RCRA, the combustion of this designated air pollutant in a 

flare, turbine, boiler or engine should not be deemed to be the combustion of a solid 

waste. Stated differently, something cannot be a designated air pollutant and a solid 

waste at the same time. 

• For purposes of Section 129, the term “solid waste’ has the meaning established by the 

Administrator pursuant to the Solid Waste Disposal Act. The meaning established for 

many years by the Administrator pursuant to the Solid Waste Disposal Act (RCRA) was 

that landfill gas would not be treated as solid waste, and its combustion would not be 

treated as solid waste combustion, but rather, as an uncontained gaseous emission 

regulated as a designated air pollutant by the Clean Air Act. There is nothing in the NonHazardous Secondary Materials Rule (NHSM) that establishes that landfill gas is a solid 

waste, and the regulatory impact analysis for the CISWI rule gave no consideration of 

landfill gas as a source type for establishment of MACT. Indeed, the NHSM establishes 

that solid waste follows the meaning of solid waste for purposes of Subtitle D, 40 CFR 

258.2. That definition excludes uncontained gas from the definition of solid waste, and 

has via rulemaking always excluded landfill gas.
3

Longstanding EPA Precedent that Uncontained Gas is not a Solid Waste

• The statutory definition of “solid waste” includes “contained gaseous material.” 42 USC 

§ 6903(27). 

 

• EPA interpretation of the term “contained gaseous material” demonstrates that RCRA 

only applies to “contained” gases, to the exclusion of “uncontained” gases. 

• EPA’s interpretation of “contained” has been limited to gas present inside “containers.”

o In a 1989 preamble to a final rule dealing with the listing of certain hazardous 

substances under RCRA, EPA stated that EPA “believes our authority to identify 

or list a waste as hazardous under RCRA is limited to containerized or condensed 

gases (i.e., section 1004(27) of RCRA excludes all other gases from the definition 

of solid wastes and thus cannot be considered hazardous wastes). See Hazardous 

Waste Management System: Identification and Listing of Hazardous Waste, 54 

Fed. Reg. 50968, 50973 (Dec. 11, 1989).

o The CISWI Rule promulgated in 2000 defined contained gaseous material as 

limited to “gases that are in a container when that container is combusted.” (EPA 

provided no explanation for deletion of this definition, which was not mandated 

or even discussed in the D.C. Circuit’s NRDC decision.)

o Similarly, 40 CFR Part 60, Subpart EEEE, governing Other Solid Waste 

Incineration Units, includes the same definition of “contained gaseous material.”

• EPA has a longstanding policy providing that fume incinerators are subject to regulation 

only under the CAA, and not also RCRA.

o For example, in the preamble to a 1982 dealing with regulation of incinerators 

that burn hazardous waste, EPA stated that “fume incinerators are subject only to 

regulation under the Clean Air Act . . . . Fume incinerators which are used to 

destroy gaseous emissions from various industrial processes, for example, are not 

subject to regulation under RCRA. In general, the RCRA standards do not apply 

to fume incinerators since the input is not identifiable as a solid waste.” See The 

Hazardous Waste Management System, Interim Final Amendments to Interim 

Final and Final Rules, 47 Fed. Reg. 27,520, 27,530 (June 24, 1982). See also, 

RCRA Superfund Hotline Monthly Summary, 9488.1986(03) available at RCRA 

Online. 

o EPA has reaffirmed this position on subsequent occasions. For example, in the 

1989 preamble discussed above, EPA stated that “fume incinerators are installed 

as air pollution control devices pursuant to regulations under the Clean Air Act; 

they are used to destroy gaseous emissions from various industrial processes. 

EPA concluded that, in general, RCRA standards do not apply to fume 

incinerators because the input (an uncontainerized gas) is not a solid waste.” 54 
4

Fed. Reg. 50,973 n.5. See also, Memorandum from Matthew Straus, Chief, 

Waste Characterization Branch, to Clifford Ng, Engineer, EPA Region II, dated 

June 17, 1987, available at RCRA Online (“Methanol-laden air from the drying 

and granulation step of the process does not meet the definition of solid waste 

under RCRA because it is in vapor form and not confined in a container.”)

• On a few occasions, some in EPA attempted to take a broader view of contained gas (e.g. 

piping was enough) but that view was rejected by the courts or the administrative 

tribunal. See, e.g. In re BP Chemicals America, Inc., RCRA Appeal No. 89-4, 1991 EPA 

App. LEXIS 27; 3 E.A.D. 667 (EPA Admin., Aug. 20, 1991) (The Administrator 

specifically rejected Region V's argument that gaseous emissions were "contained" by the 

process units they passed through, associated piping or the facility itself, holding that the 

Agency's definition of the term "contained" has consistently been confined "in the 

narrower sense of being in an individual container such that the gas is amenable to 

shipment”). See also In re: Chemical Waste Management of Indiana, Inc., RCRA Appeal 

No. 95-4, 1995 EPA App. LEXIS 31(EPA Environmental Appeals Board, Aug. 23, 1995)

(emissions from microencapsulation of hazardous debris) (The EAB concludes the air 

emissions are excludable from Subtitle C regulation "because the air emissions that the 

Region seeks to regulate are not containerized.”)

• In the landfill gas context, that view was similarly rejected by stakeholder groups 

assigned to review combustion issues. See, e.g., Recommendation from the Incinerator 

Workgroup on Section 112 Subcategories April 28, 1998 (“Section 129 Requirements. 

Section 129 applies to "solid waste combustion.” Because solid waste is defined to 

exclude gases (except gases which are in containers), Section 129 does not apply to 

landfill gas flares.”) (available at http://www.epa.gov/ttn/atw/iccr/incin/rec-112.pdf).

 The final Boiler MACT rule expressly recognizes that landfill gas constitutes a “gaseous 

fuel.” (76 Fed. Reg. 15,684)

 See also: 

o Burning of Hazardous Waste in Boilers and Industrial Furnaces, Final Rule, 56 

Fed. Reg. 7134, 7200 (Feb. 21, 1991) (activated carbon units used as air emission 

control devises are not subject to RCRA because “the gas originally treated is not 

a solid waste (it is an uncontained gas).” See also RCRA Online Determinations 

12783 (November 20, 1986) (Volatile organics released to the air are not 

hazardous waste because they are not solid wastes. (They do not fit the definition 

established in §1004(27) of RCRA as "contained gaseous materials.")”

o Hazardous Waste TSDF - Technical Guidance RCRA Air Emission Standards for 

Process Vents and Equipment Leaks, EPA-450/3-89-021 (July 1990) at pages 2-3: 

"Air standards have been promulgated for the control of air emissions from 

permitted hazardous waste incinerators. 40 CFR Part 264, Subpart O. These 

standards require that incinerators burning hazardous waste be operated to achieve 

a destruction and removal efficiency (DRE) of at least 99.99 percent for those 
5

primary organic hazardous constituents listed in the facility permit However, the 

process vent stream (i.e. gases and vapors) from a hazardous waste management 

unit would not be classified as a hazardous wastes. Noncontainerized gases 

emitted from hazardous wastes are not themselves hazardous wastes because the 

RCRA statute implicitly excludes them. Therefore combustion of process vent 

streams in an incinerator is not subject to the 99.99 DRE requirement." 

o Hazardous Waste Treatment, Storage, and Disposal Facilities (TSDF): 

Background Information for Promulgated Organic Air Organic Air Emission 

Standards for Tanks, Surface Impoundments, and Containers, EPA/453/R94/076b (November 1994) (since organic vapors emitted from hazardous waste 

are not solid or hazardous waste, control devices installed to comply with Subpart 

CC organic vapor control requirements are not hazardous waste management 

units and do not require RCRA permits).
Defining Landfill Gas as Solid Waste

Implications for Renewable Energy & Innovative Materials Management

The Agency’s statements in the NHSM rulemaking record (the Response to Comments document), and the 

deletion from the CISWI rule of the definition of “contained gaseous material” clarified as “gases that are in 

a container when the container is combusted” have created significant uncertainty about the regulatory 

status of landfill gas combusted in pollution control devices and as a fuel.

Regulating LFG as a solid waste will have a dramatic and detrimental impact on the use of 

LFG as a renewable fuel, disrupting a significant portion of the US renewable energy portfolio. 

According to DOE’s Energy Information Administration, the entire domestic solar industry produced a little 

over 800-thousand megawatt hours of power in 2009. That same year WM produced over five times that 

amount of electricity from landfill gas. 

WM has 131 landfill gas-to energy (LFGTE) projects and has been producing LFGTE since the mid-1980’s.

Municipalities, state and federal agencies, and private entities have invested in LFG to energy projects with 

strong encouragement from:

• Congress (Renewable Energy Production Tax Credit) available since the early 1990’s;

• EPA’s Landfill Methane outreach Program (LMOP);

• 29 state Renewable Portfolio Standards that recognize LFG as a renewable energy source; and

• EPA’s Renewable Fuel Standard (RFS2) regulation (for transportation & heating fuel) that specifies 

LFG as an advanced biofuel and biogenic MSW remaining after reasonably practicable separation of 

recyclables as renewable biomass;

• OSWER cites LFG to energy as part of its “Green Remediation” goals.

Private companies and local governments have made significant capital investments to make these 

renewable energy projects possible. About a half a billion dollars have been invested in projects across the 

country to deliver landfill gas to third parties for use as fuel.

Failure to recognize LFG as a legitimate fuel will undermine significant sustainability 

investments by cities and small communities, private companies large and small, and 

members of the federal family.

Examples of how LFG fuels many companies’ and Federal Agencies’ sustainability goals:

• LFG provides 95% of NASA Goddard Spaceflight Center’s heating energy;

• DoD is turning to LFG to electricity to power its bases (e.g., Ft Benning);

• DARPA awarded WM’s partner, Terrebon, a $20M contract to make jet fuel from LFG and organic 

waste;

• LFG powers Dell’s Corporate HQ campus, BMW’s Greenville Mfg facility, DuPont, Dow, GM, Ford 

plants to name a few;

• LFG powers U. of New Hampshire’s facility heating;

• LFG powers small businesses in rural communities: paint shops, greenhouses, glassblowing, schools

• LFG converted to LNG powers over 300 WM garbage trucks in CA
Regulation of landfill gas under Section 129 would be detrimental to the economy and the 

environment.

Regulation of the combustion of landfill gas for energy recovery under section 129 would likely end these 

beneficial projects. We would simply return to flaring the landfill gas. Customers purchasing landfill gas as 

a fuel would stop doing so. The benefits of criteria pollutant reductions and greenhouse gas emission 

reductions associated with using landfill gas as a fuel would be lost.

Regulation of landfill gas under Section 129 of the CAA would also dramatically affect the cost of capture 

and control of landfill gas. Landfill gas flares, engines and turbines (all of which are approved pollution 

control devices under the MSW Landfill NSPS and NESHAP) would need to be replaced with thermal 

oxidizers to meet the section 129 standards. EPA estimated the annual costs of compliance per site to be 

about $186,000, or for WM more than $50 million per year. Our rough estimates of the capital costs for 

WM to install thermal oxidizers to replace flares would exceed the total estimated costs of the CISWI rule 

for its intended sources (about $412 million). The costs would be ruinous to the local governments that 

own and operate many landfills. 

EPA is already successfully regulating Landfill gas emissions.

EPA has established extensive regulatory programs based on the determination that landfill gas is not a 

solid waste. 

WM has already invested about $330 million in over 200 active LFG collection systems and spends about 

$30 million each year on O&M. 

Federal regulation of MSW landfills under sections 111 and 112 of the CAA, and promotion of LFG capture 

and beneficial use has been highly successful as demonstrated in EPA’s U.S. GHG Inventory, which shows 

LFG emissions have declined by over 20% from 1990 through 2009.

The Derived-From Rule has never been pertinent to the status of Non-Hazardous Solid 

Waste.

The Derived-From rule states that all wastes that are produced as the result of treatment, storage, or 

disposal of a listed hazardous waste are regulated as that listed hazardous waste §261.3(c)(2)(i). The same 

is true of characteristic wastes, unless the resulting waste does not exhibit a hazardous characteristic 

§261.3(d)(1). There is no such derived-from concept in Subtitle D of RCRA. (see §257.2 Solid Waste 

Facility Definitions and 258.2 Definitions under MSW Landfill Criteria) In fact, the Derived-From Rule only 

applies to wastes derived from hazardous wastes. (See 

http://homer.ornl.gov/sesa/environment/guidance/rcra/derived.pdf)

Extension of this Derived-From concept to Non Hazardous Solid Waste will render 

renewable energy and materials recovery from MSW inoperable in the U.S. 


1

Recommendations for OMB

Landfill Gas (LFG) Issues in Non-Hazardous Secondary Materials (“NHSM”) 

Commercial and Institutional Solid Waste Incineration (“CISWI”) and Boiler 

MACT Rules

1) EPA should clarify in regulation that landfill gas (LFG) is not a solid waste subject 

to the NHSM Rule. Agency statements in the Responses to Comments Document for the 

NHSM Rule (February 2011) at (3b-13-1; 3b-13-2; and 3b-13-4) indicated that EPA had changed 

long-standing interpretation of what constitutes “contained gaseous material” a component of

the definition of “solid waste,” as well as the regulatory status of LFG.

EPA has since provided helpful “comfort letters” to WM and the AF&PA clarifying that EPA has 

not changed its prior interpretations and affirmed generally that gaseous material is not solid 

waste unless held in a container when combusted, consistent with the regulatory definition and 

interpretations of “contained gaseous material” EPA has used over many years and in various 

contexts. Instead, LFG has long been subject to overlapping federal, state and local regulatory 

programs that have required the control of LFG as an air pollutant, not a solid waste, and have 

encouraged the use of LFG as fuel where economically and practically feasible to do so. EPA’s 

letter to WM clarified that it did not intend to change prior interpretations of the regulatory 

status of LFG. (Attachment A – August 5, 2011 Letter from EPA to Waste Management)

The EPA comfort letters were offered as a band aid fix at a point when the Agency did not want 

to reopen the NHSM Rule. Now that it has reopened the rule, EPA needs to provide regulatory 

certainty and eliminate confusion resulting from the Response to Comments document for the 

NHSM Rule. Specifically, consistent with the statutory definition of “solid waste,” EPA should

clarify in the NHSM Rule that the rule may apply only to contained gaseous material, and not to 

uncontained gaseous streams such as LFG.

2) EPA also should restore the deleted regulatory definition of “contained gaseous 

material” in the CISWI Rule. Consistent with the existing CISWI Rule and the discussion 

above, maintaining the definition within CISWI for “contained gaseous material” will clarify that 

LFG is not solid waste under typical LFG control and combustion scenarios, including when

conveyed to a pollution control device for air emission control; when conveyed to a combustion 

device for electricity generation; or when conveyed to third parties for use as a fuel. Failure to 

clarify that CISWI does not apply to LFG combustion will adversely affect beneficial use and 

control of LFG. (Attachment B –Defining LFG as Solid Waste-Implications for Renewable Energy 

& Innovative Materials Management)
2

• Regulating LFG as solid waste would have a dramatic and detrimental impact on use of 

LFG as a renewable fuel.

• Regulation of LFG under CISWI would, for WM alone, exceed the total estimated costs 

of the CISWI Rule for its intended sources – about $412 million in capital, $50 

million/year in O&M.

• Failure to recognize LFG as a legitimate fuel will undermine private, local government 

and federal sustainability initiatives.

3) EPA should insert regulatory language in the NHSM Rule that lists LFG as a 

“traditional fuel.” The Agency needs to correct the rulemaking record at the NHSM Rule 

Response to Comments 3b-13-2 where the Agency suggests that LFG must meet the legitimacy 

criteria of the NHSM rule to be deemed a legitimate fuel, even though the Agency later clarified 

that LFG is not a solid waste in its comfort letter to WM. Like natural gas, refinery gas, blast 

furnace gas, recovered gaseous butane and coke oven gas, all of which are listed within the 

NHSM Rule definition of “traditional fuels,” LFG should be acknowledged as a traditional fuel. 

Failure to clarify in the NHSM Rule that LFG is a traditional fuel is contrary to statutory and 

regulatory definitions and program policies that recognize LFG as a renewable fuel. For 

example:

• EPA’s Landfill Methane Outreach Program (LMOP) promotes use of LFG as a renewable 

fuel for boilers, turbines and engines;

• The Federal Renewable Energy Production Tax Credit rewards electricity production 

from LFG;

• EISA 2007 and EPA’s Renewable Fuel Standard (RFS2) which specify that LFG is an 

advanced biofuel;

• The Boiler MACT Rule defines LFG as a gaseous fuel; and

• All 29 state Renewable Portfolio Standards define LFG as a renewable fuel for green 

electricity production.

EPA has now through its comfort letters clarified that it maintains its long-standing definition of 

“contained gaseous material” and maintains prior Agency determinations that LFG is not a solid 

waste. The Agency should amend its rulemaking record and clarify in rule language that LFG is 

a traditional fuel, not a solid waste, and therefore NOT subject to the NHSM Rule. (Attachment 

C – EPA’s Prior Determinations That LFG is Not a Solid Waste)

4) EPA should amend the Boiler MACT Rule to categorize LFG as a “Gas 1” fuel. 

Alternatively, EPA should correct the fuel specification used to qualify gaseous fuels 

as “other Gas 1 fuels.” The combustion of LFG in boilers is a positive alternative to control 

of LFG in flares. Failure to categorize LFG as a “Gas 1” fuel will subject LFG boilers to stringent 

emission limits, thereby creating strong disincentives to the use of LFG in boilers and hampering

many private, local government and federal government facilities’ sustainability efforts and 

significantly disrupting domestic renewable energy production. The U.S LFG to energy sector is 

a significant portion of the domestic renewable energy sector, producing more than 7 times the 

energy output of the entire domestic solar energy sector.
3

Under the Boiler MACT, units designed to burn Gas 1 fuel (including natural gas and refinery 

gas) are not subject to emission limits, while units designed to burn “Gas 2” fuels are subject to 

strict emission limits for PM, HCL, Mercury, CO and dioxins/furans. By EPA’s own analysis the 

control costs for Gas 2 boilers are estimated to be higher than the combined compliance capital 

costs for boilers and process heaters in all other categories. All of WM’s LFG customers have 

indicated that they would switch to natural gas or other fossil fuels if LFG-fired boilers are 

subject to “Gas 2” emission limits. 

The environmental consequences of fuel switching from landfill to natural gas are very 

detrimental:

As of September 20, 2011, EPA’s LMOP has data on 60 US boiler projects and 17 projects that 

utilize LFG in a boiler-steam turbine. EPA estimates that the 60 boiler projects utilize 

approximately 1900 Million British Thermal Units (MMBtu) per hour of LFG, and that the 17 

boiler-steam turbine projects utilize approximately 2400 MMBtu per hour of LFG. If the project 

owners switch from LFG to natural gas, LFG will still be generated by the landfills and therefore 

must be combusted in flares, increasing emissions of greenhouse gases and criteria pollutants.

EPA calculated the net increase in overall fossil fuel based CO2 emissions from boiler and boiler 

–turbine projects would be 2,025,698 tons. The nation would also realize an additional 12,841

tons of CO, 291 tons of PM and 684 tons of NOx. SO2 and Hg emissions would also increase 

slightly by 10.2 and 0.0052 tons, respectively. (Attachment D –EPA LMOP Environmental 

Analysis provided to WM)

The financial costs associated with switching from LFG to natural gas to comply with the 

Boiler MACT as promulgated, are also quite significant. For boiler and boiler-turbine projects 

now using LFG, the order-of-magnitude estimate of the total direct costs of fuel switching to 

natural gas is estimated to be $ 1.064 billion. 

In addition, project owners will lose the value of the LFG processing and transport equipment 

that must be abandoned when fuel switching from LFG. The total estimated capital assets lost 

for existing projects is $87 million. (Attachment E – CH2M Hill Boiler MACT Economic Impact 

Evaluation)

If EPA does not categorize LFG as a “Gas 1” fuel, it should revise and correct the fuel 

specification used to allow other gases to qualify as “Gas 1.” The fuel specification relies on 

two constituents as parameters; mercury and hydrogen sulfide (H2S). H2S is an inappropriate 

parameter for this MACT standard, and is set at a technically infeasible level. Therefore, in 

revising the specification, EPA should rely solely on the mercury parameter and remove the 

H2S parameter. Based upon a review of the EPA docket for the Boiler MACT, CH2M HILL 

concluded the following with respect to the fuel speceification:
4

EPA has not established a valid rationale for using H2S, as a relevant parameter. MACT 

regulates hazardous air pollutant (HAP) emissions. H2S is not a HAP, nor has EPA established 

(or even suggested in its rationale of the fuel specification) any correlation of H2S in fuel with 

any HAP or HAP surrogate emissions. 

EPA has not established a valid rationale for the specific H2S concentration of 4 parts per 

million by volume (ppmv) in the fuel specification. The specified concentration is based on 

natural gas sweetening for corrosion protection. However, boiler units generally do not 

require this level of protection. Fuel gases, including refinery gases, that have much higher 

H2S levels, commonly are used in boilers without treatment to the fuel specification 

standard. (Attachment F – CH2M Hill Review of Technical Basis for H2S in Boiler MACT Fuel 

Specification)

5) EPA should clarify the Non-Waste Determination Process. The NHSM Rule framework for 

distinguishing alternative fuels from solid waste is to require that the secondary material be 

sufficiently processed in producing the fuel, and that the fuel meets enumerated “legitimacy 

criteria.” In this evaluation, EPA requires a comparison of contaminants in the fuel product to 

traditional and alternative fuel materials. There is a great deal of uncertainty surrounding how 

these non-waste determinations will be conducted, and the type of analysis and information 

required to satisfy the Agency.

1. Fuel combustors and/or fuel producers should receive one-time, national non-waste 

determinations;

2. EPA’s headquarters Office of Resource Conservation and Recovery should make 

coherent, consistent determinations to ensure national consistency;

3. The legitimacy criteria should be discretionary rather than mandatory. The criteria were 

developed originally to provide indicia of legitimate recycling of hazardous waste. The 

criteria are not appropriate mandatory requirements in this context;

4. EPA’s legitimacy analysis should focus on the heating value of the fuel, whether material 

management and processing is conducted in a safe and protective manner, and whether 

the material’s use as a fuel will extract value from the material and reduce landfill 

disposal.

Failure to adequately clarify the process and criteria by which legitimacy determinations may 

be made will create enormous disincentives to recovering energy value from materials which 

otherwise would be landfilled.
Boiler Emissions EnvAnalysis-092611-LMOP forWM.XLSX 9/26/11

Baseline Emissions = LFG fired in boilers

New Emissions Scenario = Natural gas fired in boilers, LFG flared

LFG Energy Boiler Projects LFG Energy Boiler-Steam Turbine Projects

Total Estimated MMBtu/hr of LFG Utilized = 1,896 Total Estimated MMBtu/hr of LFG Utilized = 2,499

Project Count = 60 Project Count = 17

Emissions 

Source Pollutant Baseline New Scenario Increase

Emissions 

Source Pollutant Baseline New Scenario Increase

Fossil CO2 0 873,972 873,972 Fossil CO2 0 1,151,726 1,151,726

CO 0 CO 0

PM 0 PM 0

NOx 0 NOx 0

SO2 115 4.4 -111 SO2 152 5.8 -146

Hg 0 Hg 0

Fossil CO2 - 0 0 Fossil CO2 - 0 0

CO - 5,540 5,540 CO - 7,301 7,301

PM - 126 126 PM - 165 165

NOx - 295 295 NOx - 389 389

SO2 - 115 115 SO2 - 152 152

Hg - 0.0022 0.0022 Hg - 0.0030 0.0030

Fossil CO2 873,972 Fossil CO2 1,151,726

CO 5,540 CO 7,301

PM 126 PM 165

NOx 295 NOx 389

SO2 4.4 SO2 5.8

Hg 0.0022 Hg 0.0030

Assumptions and Rationale:

References:

same

same

same

Boiler 

Emissions (tpy)

same

same

same

same

Boiler Emissions Analysis

Greenhouse Gas Reporting Program (GHGRP) - 40 CFR 98, Subpart C, Table C-1 (Default CO2 Emission Factors and High Heat Values for Various Types of Fuel), 

Default natural gas (weighted U.S. average) CO2 emission factor.

http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&sid=4069608504fe50a3a5715cd4da0bae39&rgn=div6&view=text&node=40:21.0.1.1.3.3&idno=40

AP-42 (LFG) - Chapter 2 (Solid Waste Disposal), Section 2.4 (MSW Landfills), November 1998.

http://www.epa.gov/ttn/chief/ap42/ch02/final/c02s04.pdf

AP-42 (Natural gas) - Chapter 1 (External Combustion Sources), Section 1.4 (Natural Gas Combustion), July 1998.

http://www.epa.gov/ttn/chief/ap42/ch01/final/c01s04.pdf

6. A gross capacity factor of 90% was applied to all of the emission calculations to account for loss of energy production due to problems in the gas collection 

system, problems with project equipment, weather related interruptions of the local utilities, and shutdowns at the energy consumer end of the system.

Flare Emissions 

(tpy)

Overall 

Emissions 

Increase (tpy)

Flare Emissions 

(tpy)

Overall 

Emissions 

Increase (tpy)

1. To estimate boiler and flare emissions, emission factors were applied to the total estimated amount of LFG utilized (MMBtu/hr) for boiler projects and boilersteam turbine projects from the LMOP database (as of Sept 20, 2011). Emissions for individual boilers and boiler projects were not analyzed.

2. CO2 - All CO2 generated from LFG (combustion of CH4 and generation of CO2 from decomposition of MSW) was considered biogenic and not included in the 

calculations. CO2 generated from combustion of natural gas as a fossil fuel (non-biogenic) was included in the calculations using an emission factor of 53.02 kg 

CO2/MMBtu (116.9 lb CO2/MMBtu) from Subpart C of the Greenhouse Gas Reporting Program (GHGRP).

3. CO, PM & NOx - For combustion by-products CO, PM & NOx, emission factors for LFG-fired boilers and natural gas-fired boilers were not found to be statistically 

unique and, in addition, they vary by individual boiler instead of fuel type. Therefore, for this analysis, it was assumed that CO, PM & NOx emissions from boilers 

would not change when the fuel is switched from LFG to natural gas. Emissions of CO, PM & NOx were estimated for LFG being flared using emission factors from 

AP-42 (Table 2.4-5) of 750 lb CO/million dscf methane, 17 lb PM/million dscf methane, and 40 lb NOx/million dscf methane.

4. SO2 emissions were estimated for the baseline and new emissions scenario because the amount of SO2 emitted from combustion in a boiler or flare varies by 

the fuel type. The decrease in SO2 boiler emissions is a result of LFG typically containing higher levels of sulfur than natural gas. SO2 emissions for LFG-fired boilers 

and flares were estimated using a default sulfur content of 46.9 ppmv for raw LFG from AP-42 (pg 2.4-8) and assumes all sulfur compounds in LFG are converted to 

SO2 during combustion. SO2 emissions from natural gas-fired boilers were estimated using an emission factor of 0.6 lb SO2/million scf from AP-42 (Table 1.4-2).

5. Mercury (Hg) - Emission factors for Hg for LFG-fired boilers and natural gas-fired boilers were not found to be statistically unique. The amount of Hg in LFG and 

natural gas was found to be very similar since Hg passes through combustion devices and the amount emitted varies by the amount of Hg in the fuel itself. 

Therefore, for this analysis, it was assumed that Hg emissions from boilers would not change when the fuel is switched from LFG to natural gas. Emissions of Hg 

were estimated for LFG being flared using a default Hg concentraion of 2.92E-04 ppmv from AP-42 (Table 2.4-1).

Boiler 

Emissions (tpy)

same
Operational LFG Energy Boiler Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 1

Landfill ID #

Landfill Name

Landfill State

Landfill Owner Organization

Project ID #Expansion ID #

Current 

Project 

Status Project Name

Project Start 

Date

Project 

Shutdown 

Date

LFGE Project 

Type

36 Acme LF CA Acme Fill Corporation 91 0 Operational Project #1 1/1/1982 Boiler

122

Cold Canyon LF Solid Waste Disposal 

Site CA Waste Connections, Inc. 178 0 Operational Project #1 1/1/1999 Boiler

264 Sacramento City LF CA City of Sacramento, CA 323 0 Operational Project #1 1/1/1990 Boiler

428 Saint Lucie County SLF Phase I FL St. Lucie County 493 0 Operational Project #1 8/22/2005 Boiler

0 Shutdown Project #1 6/15/2008 12/31/2008 Boiler

1 Operational

Project #1, DeExpansion #1 1/1/2009 Boiler

0 Operational Project #1 2/23/2005 Boiler

1 Operational

Project #1, 

Expansion #1 1/1/2007 Boiler

542 Elkhart County - CR 7 LF IN Elkhart County, IN 609 0 Operational Project #1 6/1/2007 Boiler

1939 South Side Landfill IN Balkema 167015 0 Operational Project #2 11/1/1999 Boiler

1943 Laubscher Meadows LF IN Republic Services, Inc. 180863 0 Operational Project #2

5/29/2009

Boiler

1939 South Side Landfill IN Balkema 180981 0 Operational Project #6 6/30/2009 Boiler

636 Brooks LF KS City of Wichita, KS 706 0 Operational Project #1

9/1/1998

Boiler

660 Seward County Landfill KS Seward County, KS 730 0 Operational Project #1

6/1/2007

Boiler

681 Outer Loop RDF KY Waste Management, Inc. 751 0 Operational Project #1 5/1/1999 Boiler

715 East Baton Rouge Parish LF LA

City of Baton Rouge/East Baton Rouge 

Parish 785 0 Operational Project #1 12/28/2004 Boiler

462 Old Dixie Highway MSW Landfill GA

Dalton-Whitfield Regional Solid Waste 

Management Authority (DWRSWMA), 

GA

527

2303 Pine Bluff Landfill GA Waste Management, Inc. 180396
Operational LFG Energy Boiler Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 2

Landfill ID #

Landfill Name

36 Acme LF

122

Cold Canyon LF Solid Waste Disposal 

Site

264 Sacramento City LF

428 Saint Lucie County SLF Phase I

542 Elkhart County - CR 7 LF

1939 South Side Landfill

1943 Laubscher Meadows LF

1939 South Side Landfill

636 Brooks LF

660 Seward County Landfill

681 Outer Loop RDF

715 East Baton Rouge Parish LF

462 Old Dixie Highway MSW Landfill

2303 Pine Bluff Landfill

LFG Use Details

LFG Flow to Project (mmscfd) - IndividualLFG Flow to Project (mmscfd) - Total

End User Organization

No. of BoilersHeat Input (MMBtu/hr)Heat Input per Boiler (MMBtu/hr)

1.5 1.5

Central Contra Costa Sanitary 

District 31.6

LFG piped 2 miles to oilfield to fuel steam generators, the steam is used to increase the productivity of the oil wells, LFG 

providing 20% of fuel needs 1.008 1.008

Plains Exploration and 

Production Company 21.3

fuel for almond grower's boilers 1.6 1.6

California Almond Growers 

Exchange (CAGE) 33.7

retrofitted boiler for steam production in juice manufacturing plant 1.008 1.008 Tropicana 1 21.3 21.3

2-mile pipeline to one boiler, end user to consume 240 billion Btu/yr, facility manufactures latex for carpet backing 

applications 1.296

2-mile pipeline to (1) boiler, average LFG use = 9,100 MMBtu/month, use fluctuates as fuel needs vary due to batch 

processing at plant, facility manufactures latex for carpet backing applications 0.864

2.304

1.296

compressed LFG co-fired with NG in 2 boilers at county jail 1 mile away for heating and production of hot water for the 

kitchen and laundry facilities 0.346 0.346

Elkhart County Correctional 

Complex 2 7.3 3.6

three modified boilers (1 coal, 2 NG), each rated at 60,000 lb/hr (plant 8) 2.4 2.4 Rolls Royce 3 50.6 16.9

5-mile pipeline to 3 boilers at industrial facility for production of nutritional infant products, LFG will almost completely 

replace facility's use of NG 2.16 2.16

Mead Johnson 

Nutritionals/Bristol-Myers 

Squibb 3 45.5 15.2

0.72 0.72 Vertellus 15.2

LFG transported via 11-mile pipeline to water tube CB DL-94 boiler with dual-gas burner requiring 100 MMBtu/hr heat 

input to produce ~80K lb/hr in the production of 25 mil gal of ethanol per year, co-fire NG in winter only, LFG usage is 

2:1 over NG 3.7 3.7 Abengoa Bioenergy Corporation 1 78.0 78.0

Two 25 hp blowers pull LFG from gas vents & leachate cleanouts, uncleaned LFG is piped 1,800 ft to nearest wastewater 

treatment anaerobic lagoon and injected under floating cover to join lagoon's gas, used as boiler fuel 0.1 0.1 National Beef 2.1

LFG transported via ~5 mile pipeline 0.72 0.72 General Electric 15.2

steam boiler(s) 1.09 1.09 Deltech Corporation 23.0

Styron LLC 18.2

25.3

18.2

3.6 Pilgrim's Pride 75.9 3.5-mi pipeline to chicken processing cooperative for use in (3) 125 psig steam boilers, 90 MMBtu/hr capacity, LFG used 

to heat equipment for processing chickens for pet food

0.864 1

3
Operational LFG Energy Boiler Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 3

Landfill ID #

Landfill Name

Landfill State

Landfill Owner Organization

Project ID #Expansion ID #

Current 

Project 

Status Project Name

Project Start 

Date

Project 

Shutdown 

Date

LFGE Project 

Type

0 Operational

Project #1 - End 

User 1

1 Operational

Project #1 - End 

User 2

0 Operational Project #2 10/1/2003

1 Operational

Project #2, 

Expansion #1 1/1/2009

741 Brown Station Road Sanitary LF MD Prince George's County, MD 811 0 Operational Project #1 4/20/1987 Boiler

0 Shutdown Project #1 1/15/2003 12/31/2010

1 Operational

Project #1, DeExpansion #1 1/1/2011

1897

Vienna Junction Industrial Park 

Landfill MI Republic Services, Inc. 166947 0 Operational Project #1 1/1/1995 Boiler

1936 Eagle Valley Landfill MI Waste Management, Inc. 0 Operational

Combination 

Project 1/1/1998

1894 Oakland Heights Development MI Republic Services, Inc. 1 Operational

Combination 

Project 1/1/1998

2068

Autumn Hills Recycling & Disposal 

Facility MI Waste Management, Inc. 180117 0 Operational Project #1 1/1/2005 Boiler

1990 Muskegon DPW Type II Landfill MI Muskegon County, MI 181030 0 Operational Project #2 12/31/2006 Boiler

814 Crow Wing County SLF (new) MN Crow Wing County, MN 884 0 Operational Project #1 10/1/2009 Boiler

832 IESI Landfill MO Progressive Waste Solutions Ltd. 902 0 Operational Project #3 1/1/1997 Boiler

1963 Pecan Grove Sanitary Landfill MS Waste Management, Inc. 167045 0 Operational Project #1 7/12/2005 Boiler

0 Shutdown Project #1 1/1/1997 12/31/2003

1 Operational

Project #1, DeExpansion #1 1/1/2004

0 Operational Project #1 12/1/1989

1 Operational

Project #1, 

Expansion #1 10/1/1997

1075 Cumberland County LF NC Cumberland County, NC 1148 0 Operational Project #1

12/1/1997

Boiler

1093 Henderson County LF NC Henderson County, NC 1166 0 Operational Project #1 1/1/1997 Boiler

Boiler

Boiler

Boiler

Boiler

Boiler

7/10/2010 Boiler

768 Sandy Hill SLF MD Prince George's County, MD 838

180199

1064 City of Greensboro LF NC City of Greensboro, NC 1137

1066 Wilder's Grove Landfill NC City of Raleigh Solid Waste Services 

Dept.

1139

167010

730 North Baton Rouge Landfill LA City of Baton Rouge/East Baton Rouge 

Parish 800

700 Woolworth Road Landfill LA City of Shreveport, LA
Operational LFG Energy Boiler Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 4

Landfill ID #

Landfill Name

741 Brown Station Road Sanitary LF

1897

Vienna Junction Industrial Park 

Landfill

1936 Eagle Valley Landfill

1894 Oakland Heights Development

2068

Autumn Hills Recycling & Disposal 

Facility

1990 Muskegon DPW Type II Landfill

814 Crow Wing County SLF (new)

832 IESI Landfill

1963 Pecan Grove Sanitary Landfill

1075 Cumberland County LF

1093 Henderson County LF

768 Sandy Hill SLF

1064 City of Greensboro LF

1066 Wilder's Grove Landfill

730 North Baton Rouge Landfill

700 Woolworth Road Landfill

LFG Use Details

LFG Flow to Project (mmscfd) - IndividualLFG Flow to Project (mmscfd) - Total

End User Organization

No. of BoilersHeat Input (MMBtu/hr)Heat Input per Boiler (MMBtu/hr)

ExxonMobil Baton Rouge 

Polyolefins

Novolyte Technologies, Inc.

2.592

1.008

2.5 mile pipeline from landfill to 2 boilers at correctional facility 1.332 1.332

Prince George's Co. Correctional 

Facility 2 28.1 14.0

2.13

1.55

2 million sq. ft. manufacturing plant produces 130,000-150,000 MMBtu/yr from 2 boilers using LFG 0.864 0.864 General Motors Company 2 18.2 9.1

1.08

1.08

6.5-mile pipeline to soybean plant, boilers will produce heat and steam used to process beans 1.65 1.65 Zeeland Farm Soya 34.8

local chemical pigment company uses LFG in its boiler 0.432 0.432 Sun Chemical Company 9.1

Raypak Raytherm H1125 boiler supplies heat to in-floor heating system in 11,000 sq ft maintenance building, replaced 

heater orifices in boiler for lower Btu 0.043 0.043 Crow Wing County SLF (new) 1 0.9 0.9

0.7 mile pipeline 0.3 0.3 Pattonville High School 6.3

LFG is used in retrofitted boiler(s) 24/7, piped over 5 miles, system designed for 3,200 cfm 3.3 3.3

EI DuPont de Nemours & 

Company 69.6

2.2

0.97

0.8

0.8

LFG is refrigerated, filtered through a 10 micron screen, and compressed before being piped 2 miles under a river to a 

steam boiler and oil heater at soybean processing facility; 2nd boiler (53 MMBtu/hr on LFG) added in 2006 1 1 Cargill 2 21.1 10.5

LFG and NG co-fired in Cleaver-Brooks boiler, steam sold to juice plant 0.82 0.82 Clement-Pappas 1 17.3 17.3

20.5

16.9

38.0

10.9

75.9

45.5

3

1

2

75.9

32.7

20.5

33.7

3.6

3.6 LFG is processed (free liquid & solids removal via a suction scrubber), compressed, and dehydrated (via a refrigeration 

system), then piped 7 miles to 2 steam boilers at GM for both heating & cooling purposes, offsetting NG use General Motors Company

3.75-mi pipeline to the south and 1.5-mi to the north supply 80-85 MMBtu/hr total to boilers

1927 Hiene field-erected brick set 70,000 lb/hr boiler retrofitted with 2 Coen burners to generate 30,000 lb/hr of 350 

psig saturated steam (co-fired with NG or #6 fuel oil), LFG is monitored at each well for % CH4, CO2, & O, and vacuum Cone Mills

LFG transported via 1-mile pipeline to be co-fired with NG in two 800-hp Cleaver Brooks firetube boilers (eliminated use 

of fuel oil); produces steam to heat facility and warm pharmaceutical cultures Ajinomoto USA, Inc.

NASA Goddard Space Flight 

Center

plant is located between the 2 LFs, LFG is used in boilers converted from coal-firing to generate steam and provide utility 

service to the main assembly plant, some coal is still used in winter but boilers run only on LFG the rest of the year General Motors Company

1.55

2.16

0.97

1.6

LFG is piped 5.5 mi. to (3) 1995 40,000 lb/hr package boilers modified to burn LFG and use NG and fuel oil as backup; 

steam from boilers is circulated to heat the Center's buildings

2
Operational LFG Energy Boiler Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 5

Landfill ID #

Landfill Name

Landfill State

Landfill Owner Organization

Project ID #Expansion ID #

Current 

Project 

Status Project Name

Project Start 

Date

Project 

Shutdown 

Date

LFGE Project 

Type

1122 Pitt County LF NC Pitt County, NC 1196 0 Operational Project #1 1/1/1998 Boiler

0 Shutdown Project #1 11/1/1997 12/31/2005 Boiler

1 Operational

Project #1, 

Expansion #1

5/15/2006

Boiler

2 Operational

Project #1, 

Expansion #2 11/1/2009 Boiler

2153 City of Fargo Landfill ND City of Fargo, ND 180222 0 Operational Project #1 5/15/2002 Boiler

1839

Turnkey Recycling & Environmental 

Enterprises NH Waste Management, Inc. 181082 0 Operational Project #1 1/1/1991 Boiler

940 Burlington County SLF NJ

Burlington County Board of Chosen 

Freeholders 180439 0 Operational Project #1 1/1/1996 Greenhouse

1006 Ontario County SLF NY Ontario County, NY 180964 0 Operational Project #2 3/1/2008 Boiler

1164 Tremont LF OH Danis 1238 0 Operational Project #1

9/4/2002

Boiler

1174 Bedford #1 and #2 LFs OH Bedford-Ecol, Inc. 1248 0 Operational Project #1 1/1/1986 Boiler

1202 Evergreen Recycling & Disposal LF OH Waste Management, Inc. 1276 0 Operational Project #1 1/1/1999 Boiler

0 Shutdown Project #1 10/1/1999 12/31/2007 Boiler

1 Operational

Project #1, DeExpansion #1 1/1/2008 Boiler

1167 Cuyahoga Regional Sanitary LF OH Waste Management, Inc. 180129 0 Operational Project #2 1/1/2001 Boiler

1908 Lake County LF OH Lake County, OH 180968 0 Operational Project #2 1/1/2009 Boiler

1294

Commonwealth Environmental 

Systems (CES) LF PA DeNaples Brothers 1369 0 Operational Project #1

6/20/2005

Boiler

1275 Lycoming County LF PA Lycoming County, PA 180916 0 Operational Project #2 1/1/2003 Boiler

1918 Wellford LF SC

Spartanburg County Public Works 

Department, SC 166973 0 Operational Project #2 6/22/2011 Boiler

1908 Lake County LF OH Lake County, OH 166959

1837 North Wake Solid Waste Landfill NC Wake County, NC 166410
Operational LFG Energy Boiler Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 6

Landfill ID #

Landfill Name

1122 Pitt County LF

2153 City of Fargo Landfill

1839

Turnkey Recycling & Environmental 

Enterprises

940 Burlington County SLF

1006 Ontario County SLF

1164 Tremont LF

1174 Bedford #1 and #2 LFs

1202 Evergreen Recycling & Disposal LF

1167 Cuyahoga Regional Sanitary LF

1908 Lake County LF

1294

Commonwealth Environmental 

Systems (CES) LF

1275 Lycoming County LF

1918 Wellford LF

1908 Lake County LF

1837 North Wake Solid Waste Landfill

LFG Use Details

LFG Flow to Project (mmscfd) - IndividualLFG Flow to Project (mmscfd) - Total

End User Organization

No. of BoilersHeat Input (MMBtu/hr)Heat Input per Boiler (MMBtu/hr)

1 boiler of 2 produces steam for hospital use 1 1 Pitt County Memorial Hospital 1 21.1 21.1

2-mile pipeline to Cleaver Brooks fire-tube steam boiler designed to burn LFG with NG as back-up, generating 23-25,000 

lb steam/hr, 1/2 of plant's demand 1.296

Existing boiler with a maximum heat input of 96.2 mmBtu/hr was modified to add LFG as another fuel, running a 

combination of LFG and NG to meet site's steam demands, No. 2 Fuel Oil is used as a back-up for NG during times of 

curtailments, 2-mile pipeline 1.8

2-mile pipeline 1.224

1.5-mile pipeline to oilseed processing/crushing plant, LFG provides 1/3 of plant's thermal energy needs (1/3 from 

sunflower hulls, 1/3 from NG) 1.152 1.152 Cargill 24.3

2.03 MMBtu/hr Envirex boiler (model 1506 RM) at leachate plant 0.09 0.09

Turnkey Recycling & 

Environmental Enterprises 1 1.9 1.9

LFG (instead of propane) fuels boiler to heat 46,000 sq. ft. greenhouse, LFG heats greenhouse, office, and lab space as 

well as aquaculture and agriculture systems 0.216 0.216 Rutgers EcoComplex 1 4.6 4.6

pipeline carries LFG to small package boiler that runs on NG or LFG, in 4000 ft2 administrative office adjacent to the 

landfill 0.009 0.009 Ontario County, NY 1 0.2 0.2

LFG used directly for combustion units including: human comfort boiler, process ovens, process heaters, and air 

pollution abatement unit 0.5082 0.5082

International Truck and Engine 

Corporation - Springfield 

Operations 1 10.7 10.7

LFG is piped ~3 mi. to fuel boilers that generate steam for space heating and hot water, backup system allows boilers to 

supplement LFG w/ NG if necessary 2 2 Lucent Technologies 42.2

1.1 1.1 Walbridge Coatings 23.2

retrofitted boiler ~3 miles from landfill at fatty acid/glycerin plant 2.016 Twin Rivers Technologies

1.72

Hardy Industrial Technologies, 

LLC

LFG fires boilers that generate steam for process use (to cook food) and comfort heat, provides 90 percent of the 

processing and building heating needs; 2.5 mile pipeline 1.728 1.728 Stouffer's Foods 36.4

2 boilers 2.016 2.016 Nova Chemicals, Inc. 2 42.5 21.3

1/2-mi pipeline, 800 hp boiler (24,000 lb/hr) burns LFG for steam to convert raw potatoes into dehydrated flakes, 

30,000 gal propane tank for back-up fuel or to co-fire if LFG heating value drops below a critical point, boiler load 

managed by steam demand 0.24 0.24 Keystone Potato 1 5.1 5.1

heating 65,000 ft2 on-site Materials Recovery Facility with two 2.4 MMBtu/hr boilers (~150 cfm peak) 0.019 0.019 Lycoming County LF 2 0.4 0.2

6.1-mi pipeline to (1) Cleaver-Brooks 600 HP fire-tube boiler, (1) Cleaver-Brooks 250 HP fire-tube boiler, (1) Carotek 400 

HP hot oil heater; offsetting NG use; provides 100% of facility's energy needs 0.72 0.72 Milliken & Company 2 15.2 7.6

36.3

63.8 Mallinckrodt Inc., a Covidien 

company

1 63.8

1.72 1 36.3

3.024
Operational LFG Energy Boiler Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 7

Landfill ID #

Landfill Name

Landfill State

Landfill Owner Organization

Project ID #Expansion ID #

Current 

Project 

Status Project Name

Project Start 

Date

Project 

Shutdown 

Date

LFGE Project 

Type

2105

Three Rivers Regional Subtitle D 

MSWLF SC Three Rivers Solid Waste Authority, SC 180166 0 Operational Project #1 5/15/2008 Boiler

1913 Greenwood Landfill SC Greenwood County Public Works, SC 0 Operational

Combination 

Project 6/25/2009

2115 Greenwood County Subtitle D LF SC Greenwood County Public Works, SC 1 Operational

Combination 

Project 6/25/2009

2294 Sioux Falls Regional Sanitary Landfill SD City of Sioux Falls, SD 180387 0 Operational Project #1 2/28/2009 Boiler

0 Operational Project #1 8/1/2004

1 Operational

Project #1, 

Expansion #1 11/1/2005

1388 Iris Glen Landfill TN City of Johnson City, TN 1464 0 Operational Project #1

2/1/2007

Boiler

1812 Blue Ridge LF TX Republic Services, Inc. 101871 0 Operational Project #1 12/1/2009 Boiler

1948 Rosenberg Landfill TX Fort Bend County, TX 167030 0 Operational Project #1 1/1/2000 Boiler

1473 City of Waco LF TX City of Waco, TX 180913 0 Operational Project #2 4/24/2008 Boiler

1465 McCarty Road LF TX Republic Services, Inc. 180917 0 Operational Project #2 3/1/2009 Boiler

Boiler

180176 Boiler

1330 South Shelby Landfill TN Republic Services, Inc. 1406
Operational LFG Energy Boiler Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 8

Landfill ID #

Landfill Name

2105

Three Rivers Regional Subtitle D 

MSWLF

1913 Greenwood Landfill

2115 Greenwood County Subtitle D LF

2294 Sioux Falls Regional Sanitary Landfill

1388 Iris Glen Landfill

1812 Blue Ridge LF

1948 Rosenberg Landfill

1473 City of Waco LF

1465 McCarty Road LF

1330 South Shelby Landfill

LFG Use Details

LFG Flow to Project (mmscfd) - IndividualLFG Flow to Project (mmscfd) - Total

End User Organization

No. of BoilersHeat Input (MMBtu/hr)Heat Input per Boiler (MMBtu/hr)

15.8-mile pipeline to retrofitted steam boiler at industrial site 1.656 1.656

Kimberly Clark Beech Island 

Facility 1 34.9 34.9

0.46

0.116

11-mile pipeline to plant for use in boiler for producing portion of 105 million gallons of ethanol per year, offsets 10% of 

NG needs 1.8 1.8 POET 1 38.0 38.0

6.048

1.152

PSA, carbon filter, & membrane filtration system, ~90% pipeline quality gas (~875 Btu/scf), ~4 mi pipeline, capacity of 

100,000 lb/hr steam, 7.5 MW, & chilled water (offsets NG use in 4 industrial boilers or 3.5 MW engine/genset) 2.16 2.16

Veterans Affairs Medical Center, 

Mountain Home 4 45.5 11.4

34-mile pipeline to (1) boiler 4.32 4.32 Ineos Olefins Corporation 1 91.1 91.1

5-mile pipeline supplies LFG to a boiler to generate steam for process use and comfort heat, LFG & NG mix 1 1 Frito-Lay Inc. 1 21.1 21.1

Filtered and dehydrated LFG is piped ~5 miles to replace 60% of plant's NG usage, co-fired (NG) boilers generate steam 

for cooking, hot water, and humidity control 1.19 1.19 Mars North America 25.1

6-mile pipeline, LFG for primary fuel for 4 boilers, for heat and steam in the brewing process, will replace 55% of NG use 6.48 6.48 Anheuser-Busch Companies 4 136.6 34.2

50.6

12.1 6.1

151.8

2

3

0.576

LFG is piped 5 miles to 3 boilers for steam generation at the Solae facility, a soy based food ingredients plant 7.2 The Solae Company

5.2 mi pipeline to 2 (full-time) converted NG boilers - 197,000 decatherms to start, to provide up to 60% of end user's 

energy needs FujiFilm
Operational LFG Energy Boiler Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 9

Landfill ID #

Landfill Name

Landfill State

Landfill Owner Organization

Project ID #Expansion ID #

Current 

Project 

Status Project Name

Project Start 

Date

Project 

Shutdown 

Date

LFGE Project 

Type

1586 Lynchburg City LF VA City of Lynchburg 0 Operational

Combination 

Project 1/1/2002

1587 Lynchburg City SLF VA City of Lynchburg 1 Operational

Combination 

Project 1/1/2002

1597 SPSA Regional LF VA

Southeastern Public Service Authority, 

VA 167139 0 Operational Project #3 8/1/2001 Boiler

2131 Rockingham County Landfill VA

Rockingham County Department of 

Public Works, VA 180195 0 Operational Project #1

6/1/2010

Boiler

1702

Veolia ES Cranberry Creek Landfill, 

LLC WI Veolia ES Solid Waste, Inc. 1782 0 Operational Project #1 10/15/2005 Boiler

1705

Valley Trail Recycling & Disposal 

Facility WI Waste Management, Inc. 1785 0 Operational Project #1 12/1/1998 Boiler

1707 Winnebago County LF-Sunnyview WI Winnebago County, WI 180929 0 Operational Project #3 1/1/2006 Boiler

2225 Wetzel County Landfill WV J.P. Mascaro & Sons 180309 0 Operational Project #1 1/1/2003 Boiler

Project Count 60

1665 Boiler
Operational LFG Energy Boiler Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 10

Landfill ID #

Landfill Name

1586 Lynchburg City LF

1587 Lynchburg City SLF

1597 SPSA Regional LF

2131 Rockingham County Landfill

1702

Veolia ES Cranberry Creek Landfill, 

LLC

1705

Valley Trail Recycling & Disposal 

Facility

1707 Winnebago County LF-Sunnyview

2225 Wetzel County Landfill

LFG Use Details

LFG Flow to Project (mmscfd) - IndividualLFG Flow to Project (mmscfd) - Total

End User Organization

No. of BoilersHeat Input (MMBtu/hr)Heat Input per Boiler (MMBtu/hr)

0.11

0.44

Transmission by 2.4-mile pipeline (14 in. HDPE pipe) to 2 retrofitted boilers producing 25,000 lbs steam 1 1 Ciba Specialty Chemicals 2 21.1 10.5

(1) 500-HP boiler initially at half-load, 15,000 lbs/hr low pressure steam to sterilize surgical equipment, cook food & heat 

water, 2 boilers will operate at full-load during winter - LFG can meet 100% of peak heat demand, 3rd boiler will be backup unit 0.7488 0.7488 Rockingham Memorial Hospital 1 15.8 15.8

1.5-mile pipeline to steam boilers to energize a cranberry concentrator, dual-fuel boilers can burn LFG, NG, or 

combination 0.84 0.84 Ocean Spray Cranberries, Inc. 17.7

boiler uses 400 cfm when operational 0.576 0.576 National By-Products, Inc. 1 12.1 12.1

0.1224 0.1224

Winnebago County Highway 

Building 2.6

LFG fed to boiler to heat leachate for pre-treatment, heating allows less chemicals to be used to treat the leachate 0.15 0.15 1 3.2 3.2

Sum 67 1,896

Missing 20

Assume 1 Boiler for Missing 87

boiler is 64 feet from landfill 0.55 Rock Tenn Paper 1 11.6 11.6
Operational LFG Energy Boiler Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 11

Landfill ID #

Landfill Name

Landfill State

Landfill Owner Organization

Project ID #Expansion ID #

Current 

Project 

Status Project Name

Project Start 

Date

Project 

Shutdown 

Date

LFGE Project 

Type

Projects Utilizing LFG in Boiler(s) but also in other Equipment So Amount of LFG Utilized Just by Boiler(s) is Unknown

2288 City of LaGrange Landfill GA City of LaGrange, GA 180378 0 Operational

Project #1 - End 

User 1 10/3/2005 Direct Thermal

832 IESI Landfill MO Progressive Waste Solutions Ltd. 166964 0 Operational Project #1 1/1/1983 Direct Thermal

1154 Yancey/Mitchell County LF NC Yancey County 1228 0 Operational EnergyXchange 4/22/1999 Direct Thermal

1748 L.P. Gill LF NE L.P. Gill 6427 0 Operational Project #1 4/1/2008 Direct Thermal

0 Operational Project #1

12/15/2004

Direct Thermal

1 Operational

Project #1, 

Expansion #1 10/18/2005 Direct Thermal

2 Operational

Project #1, 

Expansion #2 2/1/2006 Direct Thermal

3 Operational

Project #1 - End 

User 4 12/10/2008 Boiler

4 Operational

Project #1 - End 

User 5 12/15/2008 Boiler

5 Operational

Project #1 - End 

User 6 12/17/2008 Direct Thermal

6 Operational

Project #1 - End 

User 7 12/20/2008 Direct Thermal

1257 Pine Grove LF PA Waste Management, Inc. 180903 0 Operational Project #2 3/1/2008 Direct Thermal

1928 Palmetto Landfill SC Waste Management, Inc. 180843 0 Operational Project #2

9/1/2006

Direct Thermal

Project Count 8

Total Project Count 68

1266 Lanchester LF PA Chester County Solid Waste Authority, 

PA

1341

1269 Conestoga LF PA Republic Services, Inc. 180899
Operational LFG Energy Boiler Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 12

Landfill ID #

Landfill Name

Projects Utilizing LFG in Boiler(s) but also in 

2288 City of LaGrange Landfill

832 IESI Landfill

1154 Yancey/Mitchell County LF

1748 L.P. Gill LF

1257 Pine Grove LF

1928 Palmetto Landfill

 

1266 Lanchester LF

1269 Conestoga LF

LFG Use Details

LFG Flow to Project (mmscfd) - IndividualLFG Flow to Project (mmscfd) - Total

End User Organization

No. of BoilersHeat Input (MMBtu/hr)Heat Input per Boiler (MMBtu/hr)

LFG burned directly in 3 Interface hot oil burners and a steam boiler (instead of NG) for process heat conditioning 

equipment for 600 cfm and 8 miles of pipeline 0.0415 0.28 InterfaceFLOR 1

oil burner and rotary dryers at North Asphalt plant, boiler at concrete facility Breckenridge Ready-Mix 1

LFG fuels furnaces for glass blowers and metal workers and potters' kilns (Craft Studio) and boilers to heat greenhouses 

via radiant floor heating (Project Branch Out) 0.054 0.054

EnergyXchange Renewable 

Energy Center

LFG is compressed at the LF and piped 1.25 miles to the refinery to replace 1/3 of NG needs in thermal oxidizer/boiler, 

refinery has 50 mil gal ethanol/yr production capacity 0.864 0.864 Siouxland Ethanol LLC 1

13-mile pipeline, Dart is furthest customer, LFG provides 100% of Dart's fuel needs - combusted in nine boilers, two 

thermal oxidizers, two building heaters, and two ovens, LFG generates electricity to treat & transport LFG (self-reliant 

project) 3.456 Dart Corporation 9

13-mile pipeline, combusted in three boilers at Advanced Food Products, usage is seasonal, LFG generates electricity to 

treat & transport LFG (self-reliant project) 1.584 Advanced Food Products 3

13-mile pipeline, combusted in one boiler at L&S Sweeteners, LFG generates electricity to treat & transport LFG (selfreliant project) 0.432 L&S Sweeteners 1

LFG is dewatered, filtrated, and compressed, then piped 9 miles to connect to Lanchester LF project pipeline; 2 boilers H.R. Ewell 2

LFG is dewatered, filtrated, and compressed, then piped 9 miles to connect to Lanchester LF project pipeline; 1 boiler New Holland Concrete 1

LFG is dewatered, filtrated, and compressed, then piped 9 miles to connect to Lanchester LF project pipeline; 4 oil 

heaters and 6 boilers Tyson Foods Incorporated 6

LFG is dewatered, filtrated, and compressed, then piped 9 miles to connect to Lanchester LF project pipeline; 1 boiler, 2 

ovens, 2 rooftop building heaters Case New Holland 1

2-mile pipeline, burned in industrial heater and used to power steam boiler; displacing 300,000 gallons of fuel oil use per 

year 0.44 0.44 Guilford Technical Textiles 1

LFG fuels 19 of 23 paint shop oven burners and indirect heating of area (displaces NG), processes using LFG are 

regenerative thermal oxidizer & hot air supply units (heater boxes), also fueling burner for 1 of 3 boiler systems, total 

use is 27 MMBtu/hr 1.152 1.152 BMW Manufacturing Co., LLC 1

Sum 28

Missing 1

Assume 1 Boiler for Missing 29

Total Known 95

Total with Assumption 116

3.6

5.472
Operational LFG Energy Boiler/Steam Turbine Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 1 Landfill ID #

Landfill Name

Landfill State

Landfill Owner 

Organization

Project ID #Expansion ID #

Current 

Project 

Status Project Name

Project Start 

Date

Project 

Shutdown 

Date

LFGE Project 

Type LFG Use Details

0 Shutdown Project #1 12/15/1999 12/31/2008

1 Operational

Project #1, DeExpansion #1 1/1/2009

72 BKK Landfill-Phases I & II CA BKK Corporation 128 0 Operational Project #2 1/1/1992 Steam Turbine

128 Coyote Canyon SLF CA Irvine Company 184 0 Operational Project #1 1/1/1989 Steam Turbine Zurn boiler supplying a steam turbine driving a 27.5 MW generator

274 Scholl Canyon SLF CA

Sanitation Districts of Los 

Angeles County, CA, City of 

Glendale, CA 333 0 Operational Project #1 7/1/1994 Steam Turbine

5-mile pipeline delivers LFG to be used in unit 3, 4, or 5 at Grayson Power 

Plant, remaining capacity of units is fueled by NG

352 Puente Hills LF CA

Sanitation Districts of Los 

Angeles County, CA 414 0 Operational

Project #3, Steam 

Cycle Plant 8/8/1986 Steam Turbine 2 boilers to steam turbine

354 Spadra LF CA

Sanitation Districts of Los 

Angeles County, CA 418 0 Operational Project #1 2/21/1990 Steam Turbine steam boiler power plant

1780 Palos Verdes Landfill CA

Sanitation Districts of Los 

Angeles County, CA 101831 0 Operational Project #1 5/20/1988 Steam Turbine 1988 steam plant rated at 12 MWe

0 Operational Project #1 1/1/1995

1 Operational

Project #1, 

Expansion #1 1/1/2004

2 Operational

Project #1, 

Expansion #2 1/1/2010

420 Orange County SLF FL Orange County, FL 485 0 Operational Project #1 4/1/1998 Steam Turbine

1.6 mile pipeline to Stanton Energy Center, LFG co-fired with coal in 1 of 2 

boilers retrofitted with an LFG port to produce steam and electricity

424 North Central Landfill FL

Polk County Board of 

County Commissioners, FL 489 0 Operational Project #1 1/1/1997 Steam Turbine

supplements wood waste and waste tires fuel for steam driven electric 

generators

Steam Turbine 1-mile pipeline to co-fired boilers

coal, oil, natural gas co-fired utility boiler

1829 Cherry Island Landfill DE

Delaware Solid Waste 

Authority 166401

1770 Los Reales Landfill AZ City of Tucson, AZ 101803 Steam Turbine
Operational LFG Energy Boiler/Steam Turbine Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 2 Landfill ID #

Landfill Name

72 BKK Landfill-Phases I & II

128 Coyote Canyon SLF

274 Scholl Canyon SLF

352 Puente Hills LF

354 Spadra LF

1780 Palos Verdes Landfill

420 Orange County SLF

424 North Central Landfill

1829 Cherry Island Landfill

1770 Los Reales Landfill

MW Capacity - Individual

MW 

Capacity 

Type

Other MW Capacity 

Type Description

MW Capacity - TotalLFG Flow to Project (mmscfd) - IndividualLFG Flow to Project (mmscfd) - Total

End User Organization

No. of BoilersHeat Input (MMBtu/hr)Heat Input per Boiler (MMBtu/hr)

6 Unknown

2.4 Unknown 1.5

6 Estimated rated capacity: 6.8 MW 6 Anaheim Public Utilities 70.2

21 Unknown 21 7 7 San Diego Gas & Electric Company 1 147.6 147.6

8 Unknown 8 9.29 9.29 City of Glendale, CA 1 195.9 195.9

50 Other contract capacity 50 33.1 33.1 Southern California Edison (SCE) Company 2 697.9 348.9

8.5 Other contract capacity 8.5 6 6 Southern California Edison (SCE) Company 126.5

6 Other operating capacity 6 8.52 8.52 Southern California Edison (SCE) Company 179.6

Unknown 2

Unknown 4.4

Unknown 0.8

12.4 Unknown 12.4 5.76 5.76 Orlando Utilities Commission (OUC) 1 121.4 121.4

5 Other 10% of 50 MW 5 2.83 2.83 Wheelabrator Ridge Energy (WRE) 59.7

31.6

7.2 Connectiv Power 151.8

2.4 1.5 Tucson Electric Power Company 1 31.6
Operational LFG Energy Boiler/Steam Turbine Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 3 Landfill ID #

Landfill Name

Landfill State

Landfill Owner 

Organization

Project ID #Expansion ID #

Current 

Project 

Status Project Name

Project Start 

Date

Project 

Shutdown 

Date

LFGE Project 

Type LFG Use Details

0 Shutdown Project #1 5/1/1999 12/31/1999

1 Shutdown

Project #1, DeExpansion #1 1/1/2000 12/31/2000

2 Shutdown

Project #1, DeExpansion #2 1/1/2001 12/31/2002

3 Shutdown

Project #1, DeExpansion #3 1/1/2003 12/31/2003

4 Operational

Project #1, DeExpansion #4 1/1/2004

554 MacBeth Road Landfill IN Republic Services, Inc. 180202 0 Operational Project #3 5/1/2002 Boiler

LFG is piped 8 or 9 mi. for use in 1 of 3 powerhouse boilers that was 

converted from using NG or fuel oil; boiler produces steam to heat 

assembly plant and process equipment, and to drive turbines to produce 

chilled water and to pump water

787 Fitchburg-Westminster LF MA Waste Management, Inc. 857 0 Operational Project #1 1/1/1997 Steam Turbine LFG is supplemental fuel to wood waste plant

945 Middlesex County LF NJ

Middlesex County Utilities 

Authority 180848 0 Operational Project #1 1/1/2000 Steam Turbine

1252 Tullytown LF PA Waste Management, Inc. 0 Operational

Combination 

Project 1/1/1997 boiler/steam turbine

1249 GROWS LF PA Waste Management, Inc. 1 Operational

Combination 

Project - 

Expansion #1 1/1/1999

boiler to steam turbine; each of the 2 steam turbine-generator units at the 

Fairless Hills power generation facility is 30 MW but only one is operating

1252 Tullytown LF PA Waste Management, Inc. 2 Operational

Combination 

Project - 

Expansion #2 1/1/2007

1249 GROWS LF PA Waste Management, Inc. 3 Operational

Combination 

Project - 

Expansion #3 1/1/2007

boiler to steam turbine; each of the 2 steam turbine-generator units at the 

Fairless Hills power generation facility is 30 MW

1327 Steam Turbine

436 North LF FL City of Jacksonville, FL 501 Steam Turbine LFG injected into natural gas line feeding a utility steam boiler
Operational LFG Energy Boiler/Steam Turbine Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 4 Landfill ID #

Landfill Name

554 MacBeth Road Landfill

787 Fitchburg-Westminster LF

945 Middlesex County LF

1252 Tullytown LF

1249 GROWS LF

1252 Tullytown LF

1249 GROWS LF

436 North LF

MW Capacity - Individual

MW 

Capacity 

Type

Other MW Capacity 

Type Description

MW Capacity - TotalLFG Flow to Project (mmscfd) - IndividualLFG Flow to Project (mmscfd) - Total

End User Organization

No. of BoilersHeat Input (MMBtu/hr)Heat Input per Boiler (MMBtu/hr)

2.55 Unknown 1.26

2.07 Unknown 1.03

0.96 Unknown 0.48

0.78 Unknown 0.42

0.54 Unknown 0.29

2.52 2.52 General Motors Company 1 53.1 53.1

2.09 Unknown 2.09 1.56 1.56 Pine Tree Biogas 32.9

9.9 Unknown 9.9

Public Service Electric & Gas Company 

(PSE&G) 115.8

11 Unknown

14.3 Unknown

2.2 Unknown

2.5 Unknown

6.1

1 394.3

1

30 18.7 Exelon Power

0.54 0.29 JEA 6.1

394.3
Operational LFG Energy Boiler/Steam Turbine Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 5 Landfill ID #

Landfill Name

Landfill State

Landfill Owner 

Organization

Project ID #Expansion ID #

Current 

Project 

Status Project Name

Project Start 

Date

Project 

Shutdown 

Date

LFGE Project 

Type LFG Use Details

0 Operational

Project #2 - End 

User 1 7/28/1998

1 Operational

Project #2 - End 

User 2 7/28/1998

1473 City of Waco LF TX City of Waco, TX 1550 0 Operational Project #1 3/1/2004 Steam Turbine

steam boiler from an old naval destroyer ship powers two 750 kW steam 

turbine generators from an old missile carrier, enclosed loop system cools 

& condenses steam

Project Count 17

Projects Utilizing LFG in Boiler(s) but also in other Equipment So Amount of LFG Utilized Just by Boiler(s) is Unknown

1903

Woodland Meadows LandfillNorth MI Waste Management, Inc. 0 Operational

Combination 

Project 1/1/1991

1911

Woodland Meadows LandfillSouth MI Waste Management, Inc. 1 Operational

Combination 

Project, Expansion 

#1

1912

Woodland Meadows LandfillVan Buren MI Waste Management, Inc. 2 Operational

Combination 

Project, Expansion 

#1

Project Count 1

Total Project Count 18

1256 Keystone Sanitary Landfill, 

Inc.

PA Keystone Sanitary Landfill, 

Inc.

167018 Cogeneration

12-mile pipeline transports LFG to converted coal-fired boiler to generate 

steam to supply steam turbine. Power is sold to the wholesale market. 

Steam is also sold to a plastics manufacturer. Plant's full capacity is 21 MW 

and burns NG as well as LFG.

166953 Reciprocating 

Engine

1.3-mile pipeline to steam boilers and 2.4 MW cogeneration plant (3 

engines) - equivalent MW total is 3.5 MW
Operational LFG Energy Boiler/Steam Turbine Projects in LMOP Database 9/20/11

This information is from the LMOP Landfill/Project database. 

Information in the database is compiled from a variety of sources 

by voluntary submittal, is updated periodically, and can change. 

LMOP cannot guarantee the validity of the data. 6 Landfill ID #

Landfill Name

1473 City of Waco LF

Projects Utilizing LFG in Boiler(s) bu 

1903

Woodland Meadows LandfillNorth

1911

Woodland Meadows LandfillSouth

1912

Woodland Meadows LandfillVan Buren

1256 Keystone Sanitary Landfill, 

Inc.

MW Capacity - Individual

MW 

Capacity 

Type

Other MW Capacity 

Type Description

MW Capacity - TotalLFG Flow to Project (mmscfd) - IndividualLFG Flow to Project (mmscfd) - Total

End User Organization

No. of BoilersHeat Input (MMBtu/hr)Heat Input per Boiler (MMBtu/hr)

Unknown PPL Corporation

Unknown PEI Power

1.5 Other rated capacity 1.5 1 1 Tenaska 1 21.1 21.1

Sum 11 2,499

Missing 7

Assume 1 Boiler for Missing 18

0 Unknown 0

0 Unknown 0

3.5 Unknown 2.016

Sum 0

Missing 1

Assume 1 Boiler for Missing 1

Total Known 11

Total with Assumption 19

1 93.6

Ford Motor Company

8

3.5 2.016

93.6
Wastewater Treatment Residuals (WWTR) at Forest Product Mills as Non-Waste Fuels

1. Generation and Management 

In 2008, 23 percent of WWTR were used in boilers as a critical source of energy for 

mills. Use depends on fuel availability, cost of alternative fuels and the capacity of the 

boiler to use alternative fuels. For example, if a mill has a surplus of hog fuel/bark, it will 

not need the makeup energy from other onsite residuals such as WWTR. 

Over 90 percent of WWTR are processed in some manner to ensure fuel product 

specification needs are met. The primary preparation is dewatering with belt filter or 

screw presses. This results in the delivery of a material to the boiler that is ready to burn 

according to the specifications of the mill’s biomass boilers which are uniquely designed 

to handle a wide range of fuel qualities and moisture contents. 

Two types of residuals are generated by mills. Primary residuals are generated on a 

continuous basis. They are typically conveyed directly from the clarifiers to dewatering 

equipment, dewatered, mixed with hog fuel (with bins and metered conveyors or in piles 

with a front end loader) and conveyed to boiler in a continuous or semi-continuous 

process. 

Secondary WWTR are generated depending upon the type of secondary treatment in 

use. In some instances, the residuals are generated continuously (such as for activated 

sludge); in others (such as aerated stabilization) residuals are generated far less 

frequently. For activated sludge systems, like with primary residuals, wastewater is 

decanted from the secondary clarifiers, and residuals are removed from the bottom of 

the clarifiers and sent directly to be dewatered. 

When aerated stabilization residuals are burned, they are normally staged for a time to 

allow free water to drain. This would occur on a concrete pad on another surface, in a 

fabric tube or any other manner that allows free water to drain back to WWT system. 

Additional dewatering is accomplished with screw presses, belt presses or other similar 

devices. 

When WWTR are not immediately used as fuels, they are stored in piles like other 

biomass materials such as bark and hog fuel because they have similar Btu and content 

properties. Because of their similar properties, WWTR are blended with other fuels to 

obtain the optimum overall fuel properties and consistency prior to introduction into the 

boiler to produce stable combustion conditions. WWTR, with the other fuels, are 

delivered to the boiler in the same manner as other biomass fuels primarily via conveyor 

belt, but often using a front end loader. As mentioned, in most instances storage is 

minimized and the fuel is prepared, conveyed, blended with other fuels and burned in a 

continuous or semi-continuous process. 
A typical configuration for management of primary and secondary residuals is shown on 

the following diagram. 

These facts demonstrate that WWTR destined for energy recovery in a mill boiler is not 

a solid waste because it is not discarded and is managed to enhance its fuel qualities 

and stored and burned like other biomass residuals. 

2. Reliability in meeting steam demands of the manufacturing process 

Multi-fuel boilers at pulp and paper mills are designed to burn a wide variety of biomassbased materials with different fuel characteristics and moistures. For example, typically, 

hog fuel ranges from 35 – 60 percent moisture content. However, during certain times 

of the year, very wet bark (which can be as high as 70 percent moisture content) is used 

Mill 

Process 

Equalization 

Basin 

Primary 

Clarifiers 

Process Wastewater

Secondary 

Clarifiers 

Contact / Aeration 

Basins 

WWTR 

Dewatering 

Thickener 

Waste Treatment 

Residuals

Primary Residuals 

Secondary Residuals 
as a fuel. The moisture content of WWTR when burned is in the same range as 

biomass hog fuel and similar in terms of biomass content and thus fuel value. 

A typical mill with an activated sludge system may have combined primary and 

secondary WWTR content as follows: Water - ~60%; Wood fiber - 8-20%; other 

Biomass - 12-16%; Paper fillers - 14-20%; 

WWTR are produced at a steady and regular rate at pulp and paper mills as clarifier 

solids streams and thus are a steady, reliable, and necessary part of the fuel stream. 

Clarifiers exist for the purpose of removing the largely paper fiber solids from the 

wastewater as the first step in WWT. As noted earlier, depending on the type of 

wastewater treatment process in place, some mills have both primary and secondary 

clarifiers. Fiber also carries over to secondary treatment systems where it builds up 

with time and is then removed and handled in a similar manner to clarifier solids. 

Removal of WWTR from secondary treatment systems, polishing ponds and other areas 

downstream of clarifiers is necessary to maintain treatment system performance and it 

is scheduled appropriately to achieve this objective. Timing is unique to the system 

configuration, pulp mill performance and other site specific factors. 

Thus boiler operators at mills can plan for that portion of the Btu needs that comes from 

WWTR when determining the mix of fuels to use at any given time (hog fuel, other 

biomass residuals, or fossil fuels). Relative amounts of WWTR, hog fuel and other fuels 

feeding a given boiler depend on the particular site equipment scenario of the mill: 

dewatering equipment, WWTR properties, and boiler design. 

For all the above reasons, WWTR is a reliable source of fuel. In fact, WWTR is used as 

the primary fuel (and in some cases as the only fuel) in fluidized Bed Combustors (FBC) 

in the US. In fact, one of the best performing boilers used to set the MACT floor for 

carbon monoxide from FBC burns only WWTRs. 

3. Material Specifications 

WWTR Btu/lb values range from 3,300 to 9,500 (on a dry basis) depending on whether 

it is derived from primary or secondary wastewater treatment, type of pulp and paper 

mill and the quantity of clay or other inert materials present. As noted, dewatering of 

WWTR is a regular practice to ready the material for combustion. In the rare cases 

when dewatering does not occur, the WWTR meets the combustion specifications to 

efficiently burn in the biomass boiler when mixed with other fuels. Using additional 

energy to dewater WWTR becomes counterproductive to the energy balance of the mill. 
4. Off-site WWTR Management 

According to AF&PA’s 2008 member survey, WWTR were managed in a number of 

different ways: 23 percent were burned for energy, 16 percent for land application, and 

13 percent for other beneficial uses (such as raw materials for other processes – roofing 

felt, flower pots, potting soil, etc.).1

 Thus, more than half of WWTR are managed for 

beneficial use. When burned for energy, WWTR are almost entirely managed on site. 

However, when used for other purposes, WWTR are shipped off site usually in trucks. 

As shown in the diagram above, WWTR are generally dewatered prior to management 

– including when shipped off site to reduce transportation costs and ease the handling 

of the material. 

                                                      

1 Of course, the NHSM Rule only addresses whether materials are wastes when combusted. 

Management of WWTR for other purposes is not relevant to a determination whether they are solid 

wastes when they are managed as fuel to be burned for energy recovery
5. Contaminant Levels in WWTR 

As presented to OSW in June, the chart below shows that there is a range of values for select contamthe variability ranges from 2 to 5 times between the mean and the 90th percentile confidence interval a(see mercury as example shaded in orange). This is no different than many other materials used as fuare derived from natural materials which have inherent variability. The level of contaminants in no way performance characteristics of WWTR as a fuel. 

Wastewater Treatment Residuals Select Constituent Variability for Available Test Da

BTU 

(BTU/lb) 

Hg 

(mg/Kg)

Cl- 

(mg/Kg)

As 

(mg/Kg) Be (mg/Kg) Cd (mg/Kg) Cr (mg/Kg) Pb (mg/Kg) 

Number of Samples 94 82 93 77 53 82 84 77 

Mean 5800 0.040 361 1.15 0.206 0.376 11.35 4.94 

Std. Dev. 1548 0.063 661 1.18 0.106 0.366 6.96 2.55 

T-distribution factor 1.296 1.296 1.296 1.296 1.299 1.296 1.296 1.296 

90% Confidence 

Interval 7,807 0.123 1217 2.68 0.345 0.850 20.37 8.24