FOREWORD 

This document provides the third volume of EPA's responses to public comments on EPA's Proposed 

National Emission Standards for Hazardous Air Pollutants for Area Source Industrial 

Commercial Institutional Boilers. EPA published a Notice of Proposed Rulemaking in the Federal 

Register on June 4, 2010 at 75 FR 31895. EPA received comments on this proposed rule via mail, 

e-mail, facsimile, and at three public hearings held in Washington, DC, Houston, Texas, and Los 

Angeles, California in June 2010. Copies of all comments submitted and transcripts for the public 

hearings are available at the EPA Docket Center Public Reading Room. Comments letters and 

transcripts of the public hearings are also available electronically through http://www.regulations.gov 

by searching Docket ID EPA-HQ-OAR-2006-0790. 

Due to the size and scope of this rulemaking, EPA paraphrased a limited amount of major comment 

themes in the preamble of the final rule. This document contains the verbatim comments 

provided by each commenter extracted from the original letter or public hearing transcript. The 

document has been broken up into three sections to meet the electronic document size constraints 

of the Docket.

For each comment, the name and affiliation of the commenter, the document control number 

(DCN) assigned to the comment letter, and the number of the comment excerpt is provided. 

Table 1 of this document provides a complete listing of the DCN and affiliations included in this 

document. In some cases the same comment excerpt was submitted by two or more commenters 

either by submittal of a form letter prepared by an organization or by the commenter 

incorporating by reference the comments in another comment letter. Rather than repeat these 

comment excerpts for each commenter, EPA has listed the comment excerpt only once and 

provided a list of all the commenters who submitted the same form letter or otherwise 

incorporated the comments by reference in Tables 2 and 3 at the end of this document. 

Several of EPA's responses to comments are provided immediately following each comment 

excerpt. However, in instances where several commenters raised similar or related issues, EPA 

has grouped these comments together and provided a single response after the first comment 

excerpt in the group and referenced this response in the other comment excerpts. In some cases, 

EPA provided responses to specific comments or groups of similar comments in the Preamble to 

the final rulemaking. Rather than repeating those responses in this document, EPA has 

referenced the Preamble or the appropriate technical support document for a description of the 

analysis included in the final rule. In other cases EPA has provided a general response at the 

beginning of a section of this document which responds to the comments within the section.

Parallel with this rulemaking effort are three separate, but related rulemakings that may be of 

interest to stakeholders. These three rules are: National Emission Standards for Hazardous Air 

Pollutants for Major Source Industrial/Commercial/Institutional Boilers and Process Heaters 

(Docket ID: EPA-HQ-OAR-2002-0058); Identification of Non-Hazardous Secondary Materials 

That Are Solid Waste (Docket ID: EPA-HQ-RCRA-2008-0329); and Standards of Performance 

for New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration Units (Docket ID: EPA–HQ–OAR–2003–0119). 
Given the identical proposal dates, and the related nature of these other rules, many commenters 

submitted comments to this rulemaking docket that were specific to one of these related 

rulemakings. Some commenters submitted a single DCN with comments on all four rules while 

others submitted a separate DCN specific to each rule. Many commenters submitted identical 

comments to all of these dockets. In order to reduce duplicative comments, this document flags 

comments associated with any of the above three related rulemakings as out-of-scope comments 

for this response to comment document. To the extent that the commenter submitted these 

comments to the appropriate rulemaking document, responses have been developed in the 

response to comment documents for each of these related rulemakings. For this reason, EPA 

encourages the public to read the other response to comment documents prepared for these three 

other rulemakings as they may contain topics relevant to these other rulemakings. 
Table of Contents

Rule Language Corrections............................................................................................................. 5

Rule Language: Definitions (existing)........................................................................................ 5

Rule Language: Definitions (new)............................................................................................ 29

Rule Language: Tables 1 through 6.......................................................................................... 30

Rule language Excluding Definitions and Tables 1-6 .............................................................. 35

Other - Rule Language Corrections.......................................................................................... 50

Testing and Monitoring................................................................................................................. 53

Stack Test Methods................................................................................................................... 53

CEMS: General......................................................................................................................... 64

CO CEMS................................................................................................................................. 72

PM CEMS................................................................................................................................. 94

COMS (opacity)........................................................................................................................ 98

Averaging Times for Monitored Pollutants............................................................................ 101

Fuel Analysis Methods ........................................................................................................... 114

Detection Levels ..................................................................................................................... 118

Measurement Methodology Impractical................................................................................. 123

Reduced Testing Allowance ................................................................................................... 132

Compliance Flexibility for Small Entities.............................................................................. 136

Operating Parameter Monitoring ............................................................................................ 148

Other - Testing and Monitoring .............................................................................................. 160

Startup, Shutdown, and Malfunction (SSM)............................................................................... 176

SSM - Regulatory Text Provisions......................................................................................... 176

Other - SSM............................................................................................................................ 234

Recordkeeping and Reporting Requirements ............................................................................. 247

Data Reporting Requirements................................................................................................. 247

Records That Must Be Retained ............................................................................................. 260

Electronic Reporting Mechanism ........................................................................................... 265

Recordkeeping and Reporting: Streamlining NSPS ............................................................... 282

Other - Recordkeeping and Reporting Requirments............................................................... 282

Health Based Compliance Alternatives...................................................................................... 284

Other - Health Based Compliance .......................................................................................... 284

Compliance ................................................................................................................................. 286

Fuel Switching Compliance.................................................................................................... 286

Switching Subcategories......................................................................................................... 289

Common Stack Provision ....................................................................................................... 291

Compliance Dates................................................................................................................... 291

Other - Compliance................................................................................................................. 303

Impacts Analysis......................................................................................................................... 306

Costs:Controls......................................................................................................................... 306

Costs: Testing and Monitoring................................................................................................ 331

Social Costs............................................................................................................................. 344

Economic Impacts................................................................................................................... 346

Emission Impacts.................................................................................................................... 421

Secondary Impacts.................................................................................................................. 428

Health Benefits........................................................................................................................ 510
Other - Impact Analysis.......................................................................................................... 525

Executive Orders......................................................................................................................... 526

Executive Order 12866, Regulatory Planning and Review .................................................... 526

Executive Order 13132, Federalism ....................................................................................... 527

Executive Order 13175, Consultation and Coordination with Indian Tribal Governments... 532

Executive Order 13045, Protection of Children from Environmental Health Risks and Safety 

Risks........................................................................................................................................ 532

Unfunded Mandates Reform Act of 1995............................................................................... 534

Regulatory Flexibility Act as Amended by the Small Business Regulatory Enforcement 

Fairness Act (RFA) of 1996 SBREFA), 5 U.S.C. 601 et Seq................................................. 535

Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy 

Supply, Distribution, or Use ................................................................................................... 538

Executive Order 12898: Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations............................................................................. 538
Rule Language Corrections

Rule Language: Definitions (existing)

Commenter Name: James McGrath

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-0395

Comment Excerpt Number: 1

Comment: I would like to comment on the proposed definition of "Gas-fired boiler" found in 40 

CFR 63.11237 of the proposed regulation. I believe that the proposed 48 hour/calendar year 

period for periodic testing of liquid fuel is not sufficient time and should be removed altogether 

from the definition or at least increased. I recommend that EPA revise the definition by either 

removing the proposed 48 hr/year limit for performing periodic testing or by increasing this 

allowance to at least 60 hours/calendar year to allow adequate time for periodic testing of liquid 

fuel. 

Rationale: Boiler tuning alone can take 40 hours/calendar year. If, in addition to the 40 

hours/year required for boiler tuning, a facility was required to perform operator training and 

also required to fire oil for a short time during an annual boiler inspection, these activities 

combined could easily exceed the proposed 48 hour/calendar year allowance. 

Response: The 48 hours per year allowance was adopted because of the need to test an 

emergency fuel in order to ensure that the unit could effectively operate using the emergency 

fuel during a period of gas curtailment. California regulations stipulate a 48-hour limit on this 

periodic testing on emergency fuels, and we adopted their precedent. 

Commenter Name: David Meierhenry

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-0414.1

Comment Excerpt Number: 2

Comment: I support the definition of gas-fired boiler found in 63.11231 although adding 

propane to the definition could be beneficial for further clarification. 

Response: EPA thanks the commenter for his support of the definition og gas-fired boilers. We 

also agree with the comment regarding propane and have added propane to the definition of 

natural gas.

Commenter Name: James McGrath

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-0395

Comment Excerpt Number: 2
Comment: Also, the definition for "Oil subcategory" does not indicate any numerical time 

limitation for periodic testing of liquid fuel so there seems to be an inconsistency between these 

two definitions. Based on the proposed definition of "Oil subcategory" a dual-fuel, natural 

gas/distillate oil fired boiler would not be included in the "Oil subcategory" definition as long as 

it met the listed criteria in the definition (only during gas supply emergencies, curtailment, etc...) 

and regardless of how many hours were required for periodic testing of liquid fuel. 

Response: We do not believe it is necessary to include periodic testing allowance in the 

definition of “oil subcategory” because the definition states that gas-fired boilers are excluded 

from that definition. The definition of “gas-fired boiler” does include the periodic testing limit. 

However, in order to avoid any confusion, the 48-hour periodic testing limit has been added to 

the definition of “oil subcategory.”

Commenter Name: Robert H. Colby and G. Vinson Hellwig

Commenter Affiliation: National Association of Clean Air Agencies (NACAA)

Document Control Number: EPA-HQ-OAR-2006-0790-2022.1

Comment Excerpt Number: 31

Comment: The definition of “coal” in the section 112 major source rule includes “coal refuse.” 

Coal refuse is defined as coal wastes that have ash content higher than 50 percent and heat value 

of less than 6000 BTU. The rule then sets out that it applies to units that combust “coal.” 

However, units that combust coal refuse with those properties may well be subject to section 129 

limits. EPA should correct the definition to avoid any confusion on this issue. 

Response: We agree that an area source boiler burning coal refuse that is defined as solid waste 

would be subject to section 129 limits. We have included coal refuse in the definition of “coal” 

in case any area source boiler is burning coal refuse that is not defined as solid waste. 

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 33

Comment: Federal, state, or local governments and gas suppliers have in the past required a 

facility to curtail its use of natural gas so that it can be used for home heating or another critical 

need. The length of the curtailment usually lasts a very short time period during which the 

facility may either restrict production or switch to a liquid fuel to maintain the same level of 

production. These occurrences will only be taken in the national interest or for regional or local 

emergency type situations and only for a short time period. Onsite gas supply emergencies could 

also occur whereby use of gas fuel is not possible and backup liquid fuel firing is required in 

order to maintain critical production or services. Periods of backup fuel use would be limited to 

the time to complete repairs and safely return the gaseous fuel system to service. 
CIBO requests that EPA expand the definition of gaseous fuel-fired boilers and process heaters 

to include gas curtailment required by a government agency (federal, state, local), natural gas 

supplier, or on-site gaseous fuel system emergencies. During the limited time of curtailment 

when the facility switches from gas to backup liquid fuel (recommended to be limited to 876 

hours per year (10%)), new or reconstructed boiler and process heater affected sources would be 

exempt from complying with the liquid fuel standards (if they are included in the final rule). The 

exemption should allow for periodic backup fuel operation and testing in order to prove that it is 

available and reliable should it be needed; that testing time should be included within the 

876hour limit. In addition, this 10% annual time allowance would also allow for periodic

operation on oil to allow turnover of oil in the storage tank to prevent oil degradation that might 

impact reliability when needed in an emergency. A facility should be able to apply to the 

permitting authority for an extension of the 876-hour exclusion if curtailments cause the unit to 

exceed that time limit. 

Documentation of time firing backup fuel should be provided to the permitting authority by the 

affected source as part of the semi-annual reporting requirement. A review of California rules 

(i.e., Ventura County Rule 74.15; Kern Rule 435.2; Bay Area Rule 9.7; Santa Barbara Count 

Rule 342; Yolo-Solana Rule 2.27; South Coast Rule 1146; and SCAWMD Rule 1109) shows 

substantial relaxation of requirements in recognition of natural gas curtailments. Each of the 

California rules provides for less stringent limits when a normally gas-fired unit burns liquids -

during a curtailment and while testing to assure operability on liquids in case a curtailment 

should occur. 

If there is a curtailment of natural gas because of national interest, it is important as part of our 

National Energy Policy that refineries and petrochemical plants be allowed to continue 

production at the pre- curtailment levels so that there is a sufficient supply of home heating oil, 

jet fuel, diesel, gasoline, feedstocks, etc. If facilities are forced to limit production, the reduction 

in supplies may further intensify the problem because of the reduction in supply of products such 

as home heating oil, diesel, jet fuel, and gasoline. Similar issues exist at other critical 

manufacturing facilities. 

The exemption would enable the facility to operate under the pre- curtailment gaseous fuel 

compliance requirements and thus be excluded from the liquid fuel requirements. Further, new or 

reconstructed units would not be required to install pollution control equipment required for 

liquid fuels which may never be used or only used for a very short time period over many years. 

Response: We disagree that the definition of “gas-fired boiler” needs to be revised to allow for 

an area source boiler to operate on oil beyond periods of gas curtailment or gas supply 

emergencies. The Boiler Area Source NESHAP does not apply to gas-fired boilers located at an 

area source. A dual fuel boiler that combusts oil outside of periods of gas curtailment, gas 

supply emergencies, and allowed periodic testing would be considered in the oil subcategory and 

subject to the Boiler Area Source NESHAP.

Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 44

Comment: EPA has included vague definitions in the Proposed Rule that create a gap in 

coverage for certain boilers. EPA should provide clarity so that sources can be confident they are 

in compliance with the final rule. EPA defines the "biomass subcategory" to include "any boiler 

that burns any amount of biomass, but no coal, either alone or in combination with liquid fuels or 

gaseous fuels." 75 FR 31930. The coal subcategory is defined to include "any boiler that burns 

any coal alone or at least 10% coal on an annual heat input basis in combination with biomass, 

liquid fuels, or gaseous fuels." 75 FR 31930-31. As drafted, these definitions appear to create a 

gap in coverage for boilers that may burn less than 10% coal and more than 90% biomass. EPA 

should revise the biomass subcategory to allow up to 10% coal firing. 

Response: We agree that the definition of the various categories created a potential gap in 

coverage of area source boilers. We have revised the definitions in the final rule to close these 

gaps.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 69

Comment: EPA Should Clarify That Boilers Using Liquid Fuel for Limited Times Are Not 

Subject to Emission Limits in Table 1. 

Small sites that are area sources of HAP should have the flexibility to use liquid fuel or fuel oils 

on a limited basis without these sources being classified as a unit that combusts oil. A boiler that 

uses less than 10% liquid fuel or fuel oil on an annual average heat input basis should not be 

classified as a New Oil or Existing Oil Boiler. We believe that making such an adjustment to this 

rule will better align the area source rule with the major source MACT rule in subpart DDDDD 

for boilers and heaters, which uses a 10% heat input criterion to classify a number of sources. In 

addition, allowing this additional flexibility in the final rule will result in a negligible emission 

increase of HAPs from these boilers at area sources. We suggest changes to the definitions later 

in this comment package that reflect this comment. 

Response: We disagree with the comment. The Boiler Area Source NESHAP differs from the 

Boiler MACT in that gas-fired boilers are not part of the area source boiler category. In the 

Boiler Area Source NESHAP, if a predominantly gas-fired area source boiler was allowed to 

combust oil for an extended period it would not be subject to standards. In the Boiler MACT, 

the dual-fuel boiler whether it is considered a gas or oil unit would still be subject to the 

regulation. 
Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 70

Comment: EPA Should Modify the Definition of "Gas-Fired Boilers" and the Oil Subcategory. 

EPA Should Modify the Definition of "Gas- Fired Boilers" to include boilers that burn less than 

10% liquid fuels on an average annual heat input basis. The definition of "gas-fired boiler" is too 

restrictive for small sources and does not represent GACT. Specifically, the proposed rule 

classifies any existing boiler that burns even a small amount of oil as an oil-fired unit subject to a 

stringent carbon monoxide limit of 2 ppmv. Area source sites need additional flexibility to 

combust fuel oils on a limited basis without boilers being classified under the Existing Oil 

subcategory. 

The proposed area source rule is more stringent than the proposed MACT standards for boilers at 

major sources. Specifically, §63.7575 defines gas fired units as "Unit designed to burn gas 1 

(NG/RG) subcategory includes any boiler or process heater that burns at least 90% natural gas 

and or/refinery gas on a heat input basis on an annual average." 

Therefore, EPA must provide at least the same exclusion for boilers at area sources that burn less 

than 10% oil or other fuels on a heat input basis. Based on the above reasoning, we recommend 

that the definition for Gas-Fired boiler in § 63.11237 be revised as follows: 

Gas-fired boiler includes any boiler that burns at least 90 percent gaseous fuels on a heat input 

basis on an annual average, and a boiler that burns liquid fuel only during periods of gas 

curtailment, gas supply emergencies, or periodic testing on liquid fuel. Periodic testing of liquid 

fuel shall not exceed a combined total of 48 hours during any calendar year. 

75 FR 31931 

Response: We disagree with the comment. See response to comment EPA-HQ-OAR-2006-

0790-1783.1, Excerpt 69.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 71

Comment: EPA should revise the definition for the "Oil" subcategory to remove the exclusion 

for units that burn solid fuel. EPA should also remove the limitation that boilers in the Oil 

subcategory must either burn liquid fuel alone or in combination with gaseous fuels. Instead, 

EPA should amend the definition so that the Oil subcategory includes "any boiler that burns at 
least 10 percent liquid fuels on a heat input basis on an annual average. Gas boilers that burn 

liquid fuel during periods of gas curtailment, gas supply emergencies, or for periodic testing of 

liquid fuel are not included in this definition." 

Response: The definition of “oil subcategory” has been revised to read “any boiler that burns 

any liquid fuel and is not in either the biomass or coal subcategories. Gas-fired boilers that burn 

liquid fuel during periods of gas curtailment, gas supply emergencies, or for periodic testing, not 

to exceed 48 hours during any calendar year, of liquid fuel are not included in this definition.”

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 72

Comment: EPA’s Definition of "Natural Gas" in the Proposed Rule is in Conflict With the 

Agency’s Own Views As To That Term. 

EPA failed to use the definition of "Natural Gas" that represents the most current thinking of the 

agency. The definition adopted in § 60.41 Subpart Da, published in the Federal Register on 28th 

January 2009 (Federal Register /Vol. 74, No. 17 /Wednesday, January 28, 2009 /Rules and 

Regulations, p. 5079) includes an third definition of Natural Gas to read, 

§ 60.41Da Definitions. 

Natural gas means: 

(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic 

formations beneath the earth’s surface, of which the principal constituent is methane; or 

(2) Liquid petroleum gas, as defined by the American Society of Testing and Materials in ASTM 

D1835 (incorporated by reference, see § 60.17); or 

(3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, 

natural gas must either be composed of at least 70 percent methane by volume or have a gross 

calorific value between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and 1,150 

Btu per dry standard cubic foot). 

This third definition enables affected sources to burn gaseous fuels that are substantially similar 

to naturally occurring natural gas without being subject to a variety of additional requirements 

that impose a regulatory and cost burden on the source. The net impact of this third definition is 

to promote the beneficial combustion of clean gaseous fuels, such as clean Landfill Gas, which 

might otherwise be released into the atmosphere or flared. As EPA has indicated in its Landfill 

Methane Outreach Program (LMOP), 
The U.S. Environmental Protection Agency’s Landfill Methane Outreach Program (LMOP) is a 

voluntary assistance program that helps to reduce methane emissions from landfills by 

encouraging the recovery and beneficial use of landfill gas (LFG) as an energy resource. LFG 

contains methane, a potent greenhouse gas that can be captured and used to fuel power plants, 

manufacturing facilities, vehicles, homes, and more. http://www.epa.gov/lmop/ 

By failing to adopt the most current definition of "Natural Gas", as incorporated into § 60.41 

Subpart Da, EPA is inhibiting sources from burning clean gaseous fuels like Landfill Gas that 

could be beneficially combusted. EPA should define "Natural Gas" to be identical to the 

definition in § 60.41Subpart Da. 

Response: We agree and have revised the definition of “natural gas” in the final rule.

Commenter Name: Rich Hardegger and Bill McMurtry

Commenter Affiliation: Barr Engineering Company and Darling International Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1911.1

Comment Excerpt Number: 1

Comment: The proposed rule defines biomass as follows: 

Biomass means but is not limited to, wood residue, and wood products (e.g., trees, tree stumps, 

tree limbs, bark, lumber, sawdust, sanderdust, chips, scraps, slabs, millings, and shavings); 

animal manure, including litter and other bedding materials; vegetative agricultural and 

silvicultural materials, such as logging residues (slash), nut and grain hulls and chaff (e.g., 

almond, walnut, peanut, rice, and wheat), bagasse, orchard prunings, corn stalks, coffee bean 

hulls and grounds. This definition of biomass fuel is not intended to suggest that these materials 

are or [are] not solid waste. 

We are requesting the EPA’s consideration of vegetable- and animal-derived fats to be included 

in the list of biomass materials. These materials are products of vegetable oil recycling and 

animal rendering that are typically used as feedstock for manufacturing other commodity or 

specialty products. When markets determine that these fats are available for use as fuel, boilers 

permitted to use liquid biofuels switch from fossil fuel to biofuel as their primary fuel. A notable 

reference regarding this energy source is the June 2002 University of Georgia study in 

cooperation with the Poultry Protein & Fat Council of the U.S. Poultry & Egg Association, and 

the Fats and Proteins Research Foundation, Inc. 

(http://www.biorefinery.uga.edu/docs/biofuel_oil_report.pdf ). 

Vegetable- and animal-derived fats, such as yellow grease, poultry grease and tallow, for 

example, are renewable energy materials derived from plant (crops) and animal (livestock) 

sources that have a short-term carbon cycle. Their periodic availability to displace a fraction of 

our fossil fuel demand makes them worthy of inclusion within the biomass fuel category and 

definition. 
Response: We agree with the comment and have added liquid biofuels to the definition of 

“Liquid fuel.”

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 7

Comment: This proposal applies to boilers at area sources. Boiler is defined in proposed 

§63.11237 as “an enclosed combustion device in which water is heated to recover thermal 

energy in the form of steam or hot water. A device combusting solid waste, as defined in 40 CFR 

241.3, is not a boiler. Waste heat boilers are excluded from this definition.” The first sentence of 

this definition is slightly different from the definition in the proposed major source rule, which 

reads “an enclosed device using controlled flame combustion and having the primary purpose of 

recovering thermal energy in the form of steam or hot water”. We recommend the two 

definitions be made identical and that the definition in §63.7575 be used for area sources as well 

as major sources. We believe the concept of “primary purpose” is an important one, since there 

are many cases where some hot water or steam production occurs from waste heat from process 

heaters, turbines or other combustion or process equipment and thus that equipment might be 

mistakenly deemed to be boilers under the proposed area source definition. Since the area source 

rulemaking record only deals with traditional boilers, it is critical that the rule be limited to those 

devices and the primary purpose test provides that assurance. 

Response: We agree and have revised the definition of “boiler” to be consistent with the Boiler 

MACT definition.

Commenter Name: Andrea Grant

Commenter Affiliation: Castle Oil Corporation

Document Control Number: EPA-HQ-OAR-2006-0790-1945.1

Comment Excerpt Number: 7

Comment: Proposed regulation 63.11194 addresses which sources are to become subject to the 

NESHAP rule. It states that the rule applies to each new or existing affected source as defined in 

paragraphs (1) and (2): 

(1) The affected source is the collection of all existing industrial, commercial, and institutional 

boilers within a subcategory located at an area source. 

(2) The affected source is each new or reconstructed industrial, commercial, or institutional 

boiler located at an area source. 
The text of the Preamble and the proposed regulation speak in terms of individual boilers, but 

proposed regulation 63.11194 is confusing and could be read to require the combination of 

existing boilers at a given area source. Such an interpretation would be inconsistent with the rest 

of the rule that establishes individual boiler standards. Moreover, as stated, there is no evidence 

that data from individual large boilers (e.g. 30MMBtus/hr) can appropriately be applied to 

several smaller, connected boilers. EPA should, therefore, clarify the language of the provision. 

The recommendations that follow assume that the requirements are applicable to distinct, 

individual boilers. 

Response: The proposed rule incorporated the broader definition of affected source from the 

revised General Provisions. The General Provisions define the affected source as “the collection 

of equipment, activities, or both within a single contiguous area and under common control that 

is included in a section 112(c) source category or subcategory . . . “ Therefore, the definition of 

existing affected source in the final rule will remain the collection of existing industrial, 

commercial, or institutional boilers within a subcategory located at a area source of HAP 

emissions. The emission limits, work practice standard, and management practice are applicable 

to individual units within the affected source.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 8

Comment: The commercial boiler, industrial boiler and institutional boiler definitions in the 

proposal include units that generate electricity, as well as those that generate steam or hot water. 

While there may not be any boilers that generate electricity without first generating steam or hot 

water, there may be such devices in the future or these definitions might be misinterpreted to 

include devices that generate electricity without combustion, e.g., nuclear reactors. Including 

electricity generation in these definitions serves no purpose and should be removed, so that these 

definitions mirror the general boiler definition. 

Response: The definition of “Boiler” has been revised to include “using controlled flame 

combustion.”

Commenter Name: Renee Lesjak Bashel

Commenter Affiliation: Small Business Environmental Assistance Programs, SBEAP

Document Control Number: EPA-HQ-OAR-2006-0790-2195.1

Comment Excerpt Number: 10
Comment: Recommendation: Modify or clarify the definition of biomass (should be biomass 

fuels) when including “animal manure, including litter and other bedding materials” so the rule 

does not include very small operations unintentionally. 

First, the definition should read “biomass fuels” not just “biomass”. This would match the 

proposed NESHAP for boilers and process heaters at major sources. Second, the way it is 

currently defined veterinary clinics and similar small operations could potentially be affected by 

this rule in the event they burn bedding and litter from their kennels. This could create confusion 

in two ways. First, where they may have an incinerator to burn the animal carcasses and also 

burn waste bedding in the unit, the two wastes would make the unit fall under two rules. Second, 

if they don’t incinerate carcasses but have a boiler that can burn the bedding/litter then they will 

now have many more restrictions on what was a better disposal option than sending that waste to 

a landfill. Operations like veterinary clinics appear to be a small business sector that was not 

addressed in the impact analysis for the rule. 

Response: To clarify, an incinerator would not be subject to two rules. As stated, in section 

63.11195 of the final rule, any boiler subject to standards under section 129 of the Clean Air Act 

is exempt from this final rule.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 11

Comment: Boiler system is defined in §63.11237 as “the boiler and associated components, 

such as, the feedwater system, the combustion air system, the fuel system (including burners), 

blowdown system, combustion control system, and the energy consuming systems.” The term 

“energy consuming systems” would seem to bring every steam and hot water consumer at a site 

into the definition. This makes no sense. Boiler systems are associated with the production of 

steam or hot water (per the boiler definition) and not with the steam or hot water consumers. 

Allowing the output from one area source category to be used as a rationale to regulate 

operations that are part of other source categories is a precedent-setting expansion of the area 

source program and violates the provisions of the Clean Air Act (CAA). If accepted, this 

approach could be used to establish numerous additional requirements on other source 

categories. For example, the oil and gas area source category rulemaking could inappropriately 

be used to regulate all refining and chemical operations in the country, because their processes 

are based on oil and gas production. 

Including that term “energy consuming systems” in the boiler system definition only adds 

confusion to the regulation, muddies the affected source, and serves no purpose, since consumers 

are not being regulated. Furthermore, there is no legal basis for regulating other source categories 

under this regulation. This term should be removed from the boiler system definition. 
Response: In the final rule, we have revised the definition of “boiler system” to remove the 

term “energy consuming systems.” We have added a definition of “Energy use system” to 

clarify what the required energy assessment should include. In the final rule, we have also 

revised the definition of ‘Energy assessment” to clarify that the energy use systems to be 

included are only those systems using energy from affected boilers. 

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 12

Comment: It is unclear whether the “fuel system” referred to in the boiler system definition is 

just the system associated with the boiler or the entire fuel system for the site. Including the 

entire site fuel system is unreasonable and would also make the affected facility definition and 

the rule requirements applicability unclear. We recommend this point be clarified by changing 

the term from “the fuel system” to “the boiler fuel system”. 

Response: We agree and have made the change in the final rule.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 13

Comment: Natural gas is defined in the proposal as follows. Natural gas means: 

(1) A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in geologic 

formations beneath the earth’s surface, of which the principal constituent is methane; or 

(2) Liquid petroleum gas, as defined by the American Society for Testing and Materials in 

ASTM D1835–03a, "Standard Specification for Liquid Petroleum Gases" (incorporated by 

reference, see § 63.14(b)). 

The latest definition of natural gas in the NSPS Subpart Db and Dc rules also include a 

paragraph 3 as follows in order to include synthetic natural gas generated from coal[footnote: 

Added to the NSPS subparts by amendment on January 28, 2009 (74 FR 5072).] 

a mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural 

gas must either be composed of at least 70 percent methane by volume or have a gross calorific 

value between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and 1,150 Btu per 

dry standard cubic foot) 
This paragraph should be added to the proposed definition, so this rule is consistent with the 

other combustion rules potentially applicable to these units. 

Natural gas, as described in paragraph 1 of the proposed definition, must be separated from oil, 

production water, and solids and adjusted to pipeline specifications in production batteries and in 

natural gas plants. Thus, “natural gas” is generally processed to some degree prior to using as a 

fuel and thus might be construed as not being “a naturally occurring mixture.” Additionally, 

intermediate gas streams (i.e., gas streams that are separated from the hydrocarbon/water mixture 

removed from the ground that do not yet meet the pipeline quality natural gas specifications) are 

combusted in boilers and process heaters at the production site or the gas plant. Thus, we believe 

some clarification is needed in the definition of natural gas to be clear that processed and 

intermediate streams are included. 

We recommend the definition be revised to make it clear that gases derived from the “naturally 

occurring mixture found in geological formations” meets the definition of natural gas, as long as 

the principal constituent is methane, by revising proposed paragraph 1 as follows. 

(1) A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in geologic 

formations beneath the earth’s surface, of which the principal constituent is methane, including 

intermediate gas streams generated during processing of natural gas at production sites or at gas 

processing plants. 

Response: The definition of “Natural gas” is revised in the final rule to address the comment.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 16

Comment: Gas-fired boiler is defined in proposed §63.11237 as “any boiler that burns gaseous 

fuels not combined with any solid fuels, burns liquid fuel only during periods of gas curtailment, 

gas supply emergencies, or periodic testing on liquid fuel. Periodic testing of liquid fuel shall not 

exceed a combined total of 48 hours during any calendar year.” Under the major source rule, gasfired sources may fire up to 10% liquid on an annual basis. The area source definition should be 

made consistent with the major source one. 

Consistency is needed to avoid confusion and foster compliance since many companies operate 

both area and major sources and because a certain amount of liquid firing is often necessary to 

optimize boiler operation and minimize fuel costs and to allow maintenance of the gas system. 

Response: We disagree with the comment. See response to comment EPA-HQ-OAR-2006-

0790-1783.1, Excerpt 69.
Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Goup

Document Control Number: EPA-HQ-OAR-2006-0790-1916.1

Comment Excerpt Number: 22

Comment: SEVERAL PROPOSED DEFINITIONS REQUIRE FURTHER REVISION AND 

CLARIFICATION. 

There are several definitions in EPA’s proposed Boiler MACT rule that require additional 

revision and clarification. Specifically, EPA defines “natural gas” in proposed § 63.7575, as: 

(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic 

formations beneath the earth’s surface, of which the principal constituent is methane; or 

(2) Liquid petroleum gas, as defined by the American Society for Testing and Materials in 

ASTM D1835-03a, “Standard Specification for Liquid Petroleum Gases” (incorporated by 

reference, see § 63.14(b). 

The first part of the definition seems to rely on EPA’s definition of “natural gas” in several 

previous MACT standards promulgated by EPA. Both of these rules address processors and 

providers of natural gas, not customers or end users of the gas. Given that end users do not know 

or have control of the source of materials introduced into the distribution system, EPA’s 

proposed definition of “natural gas” is problematic if any kind of biogas, landfill gas, or 

“synthetic gas converted from coal” is in the main pipe. EPA’s proposed definition needs to be 

expanded to cover other types of fuel gases that are carried through the main pipeline. 

To address this concern, the Auto Group recommends that EPA add a third component to the 

definition that would include “any gas that is transported through a commercial natural gas 

pipeline.” This addition would allow fuel gases that are carried through the commercial pipeline 

to be treated as natural gas and regulated as such. Furthermore, it would not require consumers to 

determine what type of fuel gas is in the natural gas pipeline and whether that fuel gas comes 

from a geologic formation or from some other source that results in commercial grade natural 

gas. 

Response: The revision suggested by the comment is unnecessary in the context of the Boiler 

Area Source NESHAP because the rule does not apply to gas-fired boilers. A gas-fired boiler is 

defined as a boiler burning gaseous fuel and gaseous fuel is defined as including, but not limited 

to, natural gas landfill gas, and biogas. 

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Goup

Document Control Number: EPA-HQ-OAR-2006-0790-1916.1

Comment Excerpt Number: 23
Comment: Given the importance of landfill gas and the fact that landfill gas can be processed to 

the extent that it is like natural gas (and even injected into natural gas pipelines), the Auto Group 

recommends that EPA add a component to the definition of “natural gas” that would include 

landfill gas, i.e., a fourth component to the definition that would say “any landfill gas that is 

processed and transported through a dedicated pipeline.” “Landfill gas” also could be defined as 

“gas derived from the decomposition of waste in a landfill.” This would ensure that landfill gas 

units are treated similarly to natural gas units given these fuels can be found in the same 

distribution system. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1916.1, Excerpt 22.

Commenter Name: Leon Lataille

Commenter Affiliation: Massachusetts Water Resources Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1896.1

Comment Excerpt Number: 1

Comment: Deer Island boilers typically operate on digester gas for approximately 98% of heat 

input, on an annual average basis, using ultra low sulfur no. 2 fuel oil for startups and for periods 

when digester gas is unavailable due to process issues, or when available digester gas is 

insufficient during winter months to provide sufficient thermal energy for plant needs. The 

amount of digester gas available is dependent on a number of factors including the influent 

wastewater characteristics and can vary significantly even within the course of a day. Every 

effort is made to maximize the beneficial use of digester gas, and to minimize the use of oil as a 

cost saving measure. Oil is, however, required during startup due to the design of the boiler. The 

proposed definition of gaseous fuel boilers makes reference to gas curtailment, which relates to 

suppliers of natural gas, but does not take into account users of on-site generated biogas, which 

are subject to limits on the availability of biogas not from suppliers but by the nature of the 

supply source. The definition of gaseous fuel boilers should be expanded to include "boilers 

using biogas which supply on an annual average basis at least 90% of heat input required by the 

operation". 

Response: We disagree with the comment. See response to comment EPA-HQ-OAR-2006-

0790-1783.1, Excerpt 33.

Commenter Name: Randy Thurman and Brent Stevenson

Commenter Affiliation: Arkansas Environmental Federation and Arkansas Forest & Paper 

Council

Document Control Number: EPA-HQ-OAR-2006-0790-1921.1

Comment Excerpt Number: 2
Comment: Boilers proposed to be regulated by this rule are also used widely by facilities to 

provide heat and steam critical for continuous safe operation of hospitals, institutions and small 

manufacturers. As these rules become effective many of the facilities will switch to natural gas 

as their principal fuel. As proposed, [by definition] these boilers are limited to use of liquid fuel 

for only 48 hours per year for testing and periods of gas curtailment or gas supply emergencies. 

Due to the critical function of many of these boilers, the rules should allow use of liquid fuel for 

up to 500 hours per year for gas-fired boilers. This small change would allow use of liquid fuels 

for a period of time limited to emissions usually considered insignificant under Arkansas and 

most other state air permitting programs and would serve as a easily measured limit to assure the 

boilers are operated as gas-fired boilers in the majority. The clarification would eliminate the 

confusion and differing opinions about what constitutes supply interruption. 

Response: We disagree with the comment. See response to comment EPA-HQ-OAR-2006-

0790-1783.1, Excerpt 33.

Commenter Name: Brad Cooley

Commenter Affiliation: GDF SUEZ Energy Generation North America, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2134.1

Comment Excerpt Number: 3

Comment: DEFINITION OF NATURAL GAS: The proposed rule does not reflect the most 

current definition of “natural gas” which was adopted in Section 60.41 of Subpart Da as 

published in the Federal Register on January 28, 2009 (74 FR 5079). This definition allows 

sources to burn gaseous fuels that are substantially similar to naturally occurring natural gas, 

including clean Landfill Gas, without being subject to additional regulatory requirements and 

costs. GSEGNA requests that the Agency adopt this definition of natural gas into the proposed 

rule. 

Response: We agree and have revised the definition of “Natural gas” in the final rule.

Commenter Name: Brad Cooley

Commenter Affiliation: GDF SUEZ Energy Generation North America, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2134.1

Comment Excerpt Number: 4

Comment: EXCLUSION FOR GAS-FIRED BOILERS DURING PERIODS OF 

CURTAILMENT: GSEGNA supports the Agency’s inclusion of gas-fired boilers that burn 

liquid fuel only during periods of natural gas curtailment in the definition of gas-fired boilers. 

Response: EPA thanks the commenter for their support on this issue.
Commenter Name: Kevin F. Biernacki

Commenter Affiliation: Veolia Energy North America

Document Control Number: EPA-HQ-OAR-2006-0790-2273

Comment Excerpt Number: 10

Comment: We suggest that the definition of gas-fired boiler in the area source rule match the 

definition of “Unit designed to burn gas 1 (NG/RG Subcategory)” in the proposed ICI Boiler 

regulation for major sources of HAPs. This definition would provide consistency between the 

programs and offer operational flexibility. For reference, the major source regulation definition 

is, “Gas-fire boiler includes any boiler that burns at least 90 percent natural gas on a heat input 

basis on an annual average.” 

Response: We disagree with the comment. See response to comment EPA-HQ-OAR-2006-

0790-1783.1, Excerpt 69.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 17

Comment: We suggest that the definition of gas-fired boiler in the area source rule match the 

definition of “Unit designed to burn gas 1 (NG/RG Subcategory)” in the proposed ICI Boiler 

regulation for major sources of HAPs. This definition would provide consistency between the 

programs and offer operational flexibility. For reference, the major source regulation definition 

is, “Gas-fire boiler includes any boiler that burns at least 90 percent natural gas on a heat input 

basis on an annual average.” 

Response: We disagree with the comment. See response to comment EPA-HQ-OAR-2006-

0790-1783.1, Excerpt 69.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 29

Comment: In 63.7575, the second sentence in the definition for “Coal” is incomplete. It states 

“Synthetic fuels derived from coal for the purposes of creating useful heat including, but not 

limited to, solvent-refined coal, coal-oil mixtures, and coal water mixtures, for the purposes of 

this subpart.” It is not clear whether this sentence intends to include or exclude these materials 

from the definition of coal. This definition should be clarified. 
Response: The commenter is referring to the definition in Boiler MACT. Provided the 

commenter has submitted this comment to the Boiler MACT rulemaking docket, the response to 

this comment will be provided there.

Commenter Name: Jim Simon

Commenter Affiliation: American Sugar Cane League

Document Control Number: EPA-HQ-OAR-2006-0790-2281.1

Comment Excerpt Number: 29

Comment: Bagasse is the primary fuel burned at Louisiana sugar mills although it is sometimes 

necessary for mills to supplement bagasse with natural gas. We therefore propose, in addition to 

the exemption, the following definitions to be added to 63.11236: 

Bagasse means the matted cellulose fiber residue from sugarcane that has been processed in a 

sugar mill. 

Bagasse-fired boiler includes any boiler that burns bagasse as its primary fuel source but may 

also burn natural gas and/or other clean cellulosic biomass materials, including but not limited to 

forest-derived biomass and other biomass crops, provided that the total sum of supplemental 

fuels not exceed 10% of the fuel combusted on an annual basis based on gross heat input. 

Response: The definition of “biomass” in the final rule (and as in the proposed rule) includes 

the term “bagasse.” We disagree with the need to add a definition of a “bagasse-fired boiler.” 

The definition of “Biomass subcategory” addresses bagasse-fired boilers.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 30

Comment: Duke Energy agrees with and supports the definition given in 63.7575 for “fuel 

type”. Specifically Duke Energy agrees that receiving fuel from different suppliers does not 

constitute and change in fuel type. 

Response: The commenter is referring to the definition in Boiler MACT. Provided the 

commenter has submitted this comment to the Boiler MACT rulemaking docket, the response to 

this comment will be provided there.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy
Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 31

Comment: Duke Energy believes that EPA’s definition of a hot water heater is overly 

restrictive, or at best confusing. In 63.7575, EPA defines a Hot water heater as “a closed vessel 

with a capacity of no more than 120 U.S. gallons in whish water is heated by combustion of 

gaseous or liquid fuel... at pressures not exceeding 160 psig...” By this definition, regulated 

sources could include a very large number of hot water heaters used by offices, hospitals, 

schools, commercial businesses, and other non-industrial sources. Water could be used for 

bathing, dish washing, space heating and other similar purposes not associated with industrial 

activities. While these types of hot water heaters are typically found at sources that are not 

considered major sources of HAPs, major source facilities sources can also have these types of 

hot water heaters. EPA should restrict the definition of a hot water heater for purposes of this 

rule to include only units that are specifically used as part of an industrial process. EPA should 

consider increasing the capacity of these units above 120 gallons. 

Response: The commenter is referring to the definition in Boiler MACT. Provided the 

commenter has submitted this comment to the Boiler MACT rulemaking docket, the response to 

this comment will be provided there.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 2

Comment: The definition of "deviation" in 40 CFR 63.11237 does not establish guidelines to 

determine continuous compliance with limits and work practice standards in the rule. The 

definition states a deviation is not always a violation. While we agree with this assertion, the 

EPA should clearly define when deviations become violations as the EPA has defined in 

previous rules such as 40 CFR 63 Subpart MM — National Emission Standards for Hazardous 

Air Pollutants For Chemical Recovery Combustion Sources At Kraft, Soda, Sulfite, And StandAlone Semichemical Pulp Mills, 40 CFR 63 Subpart LL — National Emission Standards for 

Hazardous Air Pollutants For Primary Aluminum Reduction Plants, and 40 CFR 63 Subpart DD 

— National Emission Standards for Hazardous Air Pollutants From Off-Site Waste And 

Recovery Operations. 

Response: We understand the concern of the commenter but we disagree with adding a 

definition on when a deviation becomes a violation. 

Commenter Name: Douglas I. Greenhaus

Commenter Affiliation: National Automobile Dealers Association

Document Control Number: EPA-HQ-OAR-2006-0790-2047.1
Comment Excerpt Number: 2

Comment: NADA is concerned that the area source NESHAP for Industrial, Commercial, and 

Institutional Boilers may impose additional regulatory burdens on space heaters/boilers. On the 

one hand, proposed 40 CFR §63.11237 defines a boiler as an enclosed combustion device in 

which water is heated to recover thermal energy in the form of steam or hot water. Thus, since 

most space heaters heat air, not water, they should fall outside the rule. 

Response: We agree that space heaters that heat only air are not covered by this rule. The area 

source boiler NESHAP only applies to boilers with a boiler defined as a combustion unit that 

recovers energy in the form of steam or hot water. A boiler, burning coal, biomass, or liquid 

fuel, used for space heating would be subject to this rule. A combustion unit that heats air for 

space heating would not be a boiler and, thus, not subject to this rule. 

Commenter Name: Debra J. Jezouit

Commenter Affiliation: The Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2006-0790-1986.1

Comment Excerpt Number: 2

Comment: The Class of ‘85 agrees with EPA’s determination that natural gas-fired area source 

Boilers should not be regulated under the Proposed Rule. However, the Group would like EPA to 

clarify that whether a source is a gas-fired Boiler is determined by the fuel it actually combusts, 

not on the fuels it has the potential to combust. Clarifying the definition of gas-fired Boiler will 

allow sources to more easily determine the applicability of the Proposed Rule and avoid 

unnecessary compliance issues. 

Response: The definition of “gas-fired boiler” in the final rule is based on what the boiler 

combusts and not on what it has the potential to combust.

Commenter Name: Tom Siegrist

Commenter Affiliation: Koch Nitrogen Company, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-2216

Comment Excerpt Number: 2

Comment: A “gas-fired boiler” is proposed to be defined as any boiler that burns gaseous fuels 

not combined with any solid fuels, burns liquid fuel only during periods of gas curtailment, gas 

supply emergencies, or periodic testing on liquid fuel. The proposed definition would limit the 

periodic testing of liquid fuel to a combined total of 48 hours during any calendar year. This 

definition would appear to significantly limit liquid firing for gas-fired boilers, especially for 

those boilers that only occasionally fire oil as a fuel and have the associated emissions already 

covered by an existing air permit. An alternative approach would be to define an allowable 

amount of liquid fired, including that fired during curtailments, emergencies, and testing, that 
would serve as a threshold to distinguish between gas-fired and an oil-fired boilers. Use of an 

annual capacity factor, similar to that used in NSPS Subpart Db, would facilitate the 

implementation of such an approach. KNC proposes that the following definition of “annual 

capacity factor” and modified definition of “gas-fired boiler” be added to 40CFR63.11237: 

Annual capacity factor means the ratio between the actual heat input to a unit subject to this 

subpart, as applicable, during a calendar year and the potential heat input to the unit had it been 

operated for 8,760 hours during a calendar year at the maximum steady state design heat input 

capacity. 

Gas-fired boiler means any boiler that burns gaseous fuels not combined with any solid fuels and 

that may burn liquid fuel during such times as periods of gas curtailment, gas supply 

emergencies, or periodic testing on liquid fuel. Non-gaseous fuels are limited to no more than 10 

percent of the unit’s annual capacity factor. 

Response: We disagree with the comment. See response to comment EPA-HQ-OAR-2006-

0790-1783.1, Excerpt 33.

Commenter Name: John Lyons

Commenter Affiliation: Kentucky Division for Air Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2218.1

Comment Excerpt Number: 3

Comment: The definitions for “boiler” in the proposed major source rule and area source rule 

are different. For consistency, EPA needs to clarify the two definitions. 

Response: We agree and have made the definition of boiler in the final rule more consistent 

with the definition in the Boiler MACT.

Commenter Name: Thompas P. Balf

Commenter Affiliation: Campus Cortium for Environmental Excellence

Document Control Number: EPA-HQ-OAR-2006-0790-1657.1

Comment Excerpt Number: 3

Comment: Currently, the definition of gas-fired boiler includes: “...any boiler that burns 

gaseous fuels not combined with any solid fuels, burns liquid fuel only during periods of gas 

curtailment, gas supply emergencies, or periodic testing on liquid fuel. Periodic testing of liquid 

fuel shall not exceed a combined total of 48 hours during any calendar year (Proposed definition 

at 40 CFR 63.11237). First, we do not believe that the applicability criteria for areas sources of 

HAPs should be more restrictive than the criteria for major sources. Second, this definition and 

the 48 hour limit may pose significant problems during routine and emergency maintenance and 

testing times. 
We suggest that the definition of gas-fired boiler in the area source rule match the definition of 

“Unit designed to burn gas 1 (NG/RG Subcategory) in the proposed ICI Boiler regulation for 

major sources of HAP. This definition would provide consistency between the programs and 

offer operational flexibility. 

We suggest changing the language in the rule to read: 

“Gas-fire boiler includes any boiler that burns at least 90 percent natural gas on a heat input basis 

on an annual average. 

Response: We disagree with the comment. See response to comment EPA-HQ-OAR-2006-

0790-1783.1, Excerpt 69.

Commenter Name: Barry Christensen

Commenter Affiliation: Occidental Chemical Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2227.1

Comment Excerpt Number: 4

Comment: OCC strongly supports the proposed definition of “boiler" which excludes waste heat 

boilers from this area source standard. Emissions from a combustion unit with a waste heat boiler 

are most appropriately regulated by the applicable standards for the particular type of 

combustion unit. This is appropriate because it is often not feasible to separate the combustion 

source emissions from the heat recovery steam generator emissions. 

Response: EPA thanks the commenter for their support on this issue.

Commenter Name: Bruce A. Steiner

Commenter Affiliation: American Coke and Coal Chemicals Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2007

Comment Excerpt Number: 5

Comment: ACCCI requests that EPA provide clarification that boilers firing liquefied petroleum 

gas (LPG) or propane-derived synthetic natural gas (SNG) as a backup fuel are considered a gasfired boilers. We note that EPA proposes to incorporate ASTM D183503a to define "natural gas" 

for purposes of this regulation. It is important that any standard incorporated by the regulation be 

broad enough to encompass the use of propane (a constituent of LPG) as natural gas and not just 

mixtures. Most LPG mixtures include butane, which reduces the effectiveness of LPG at low 

temperatures, causing many facilities to substitute propane. Propane (and/or LPG) is mixed with 

air to create SNG, which should be specifically allowed to be considered as natural gas for 

purposes of this rule. LPG-based SNG is often used for emergency backup and EPA should 

make this point explicit in the final rule. 
Response: We agree and have revised the definition of “Natural gas” in the final rule to include 

propane.

Commenter Name: Barry Christensen

Commenter Affiliation: Occidental Chemical Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2227.1

Comment Excerpt Number: 5

Comment: OCC respectfully requests clarification of the exemption (63.11195(a)), for boilers 

regulated by another area source standard. One of our locations burns process vent gases in an 

onsite boiler and consequently is preparing to comply with the Chemical Area Source rule. OCC 

respectfully requests clarification that this boiler is not subject to this Subpart JJJJJ standard, 

including during intermittent periods (e.g. maintenance outages) when vent gases are not 

introduced to the unit. 

Response: Applicability determinations are made by the EPA Regional Offices on a case-bycase basis. We have included a list of sources that are not subject to the final rule. The final 

rule clarifies that boilers that are specifically listed as, or included in the definition of, an affected 

source in any other NESHAP are not subject to the Boiler Area Source NESHAP. However, we 

do not exclude boilers that are used as control devices unless they are specifically considered 

part of any other NESHAP’s definition of affected source. 

Commenter Name: Bruce A. Steiner

Commenter Affiliation: American Coke and Coal Chemicals Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2007

Comment Excerpt Number: 6

Comment: We request clarification that a boiler combusting landfill gas (or similar gaseous 

fuels derived from landfills or monofills) be considered a gas-fired boiler and not in the biomass 

category. ACCCI considers these fuels to fall under the definition of biogases, which are 

included in the definition of gaseous fuels, but we are aware that EPA has taken the position that 

gas derived from landfills is "biomass" under other rules. We seek clarification that for purposes 

of this rule it is not the agency’s intent to regulate boiler use of landfill or monofill gas, even if 

derived in whole or part from materials that might be defined as biomass. 

Response: The definition of “gaseous fuel” in the final rule does include landfill gas and biogas.

Commenter Name: Kevin M. Dempsey

Commenter Affiliation: American Iron and Steel Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2061

Comment Excerpt Number: 14
Comment: The Definition of Gas-Fired Boilers Should be Amended 

The definition of gas-fired boilers includes those units burning gaseous fuels, which by further 

definition includes process gases (e.g., coke oven gas or blast furnace gas). However, the 

definition of gas-fired boiler is qualified by stating that gaseous fuels cannot be combined with 

any liquid fuel except during periods of gas curtailment, gas supply emergencies, or periodic 

testing on liquid fuels. Without clarification of that definition, the exemption for gas fired boilers 

is potentially negated. 

While process gas-fired boilers, such as coke oven gas-fired boilers, are primarily designed to 

burn process gas, usually with natural gas as a back-up fuel, they are sometimes supplemented 

with liquid fuels when the supply of process gas from the is interrupted due to operational 

difficulties or reduced operations necessitated by business conditions or when steam demands 

elsewhere in the plant cannot be met by the available process gas supply to the boilers. It is not 

clear from the definition of gas-fired boiler whether the terms gas curtailment and gas supply 

emergencies pertain to commercial natural gas supplies or can be interpreted to include 

occasions of curtailment and supply deficiencies from the process supplying the gas. In the 

absence of clarifying language in the definition, the occasional use of liquid fuel would place 

these boilers (as well as any units using any liquid fuel, except in the stated circumstances) into a 

category that requires stringent emission limits, the installation of costly emission control 

equipment, and testing, monitoring and recordkeeping obligations. 

Response: We disagree with the comment. See response to comment EPA-HQ-OAR-2006-

0790-1783.1. However, the standard for oil-fired area source boilers in the final rule is based on 

GACT which is a management practice of a tune-up, instead of the MACT-based emission limits 

presented in the proposed rule.

Commenter Name: Kevin M. Dempsey

Commenter Affiliation: American Iron and Steel Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2061

Comment Excerpt Number: 16

Comment: In addition, AISI requests that EPA provide clarification that boilers firing liquefied 

petroleum gas (LPG) or propane-derived synthetic natural gas (SNG) as a backup fuel are 

considered a gas-fired boilers. We note that EPA proposes to incorporate ASTM D183503a to 

define "natural gas" for purposes of this regulation. It is important that any standard incorporated 

by the regulation be broad enough to encompass the use of propane (a constituent of LPG) as 

natural gas and not just mixtures. Most LPG mixtures include butane, which reduces the 

effectiveness of LPG at low temperatures, causing many facilities to substitute propane. Propane 

(and/or LPG) is mixed with air to create SNG, which should be specifically allowed to be 

considered as natural gas for purposes of this rule. LPG-based SNG is often used for emergency 

backup and EPA should make this point explicit in the final rule. 
Response: The definition of “natural gas” in the final rule includes LPG and propane.

Commenter Name: Kevin M. Dempsey

Commenter Affiliation: American Iron and Steel Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2061

Comment Excerpt Number: 17

Comment: We request clarification that a boiler combusting landfill gas (or similar gaseous 

fuels derived from landfills or monofills) is considered a gas-fired boiler and not in the biomass 

category. AISI considers these fuels to fall under the definition of biogases, which are included 

in the definition of gaseous fuels, but we are aware that EPA has taken the position that gas 

derived from landfills is "biomass" under other rules. We seek clarification that for purposes of 

this rule it is not the agency’s intent to regulate boiler use of landfill or monofill gas, even if 

derived in whole or part from materials that might be defined as biomass. 

Response: The definition of “gaseous fuel” in the final rule does include landfill gas and biogas.

Commenter Name: Charles B. Jones, III

Commenter Affiliation: Georgia Traditional Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1923.1

Comment Excerpt Number: 19

Comment: There are varying definitions in the two sets of Boiler rules for the same terms 

("boiler" and "biomass" are examples) that need to be reconciled. 

Response: We agree and have made the definitions in the final rule more consistent with the 

definitions in the Boiler MACT.

Commenter Name: Kevin M. Dempsey

Commenter Affiliation: American Iron and Steel Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2061

Comment Excerpt Number: 31

Comment: The Definition of Hot Water Heater Needs to be Revised 

In section IV.A of the preamble to the Proposed Rule, EPA states that the proposal would not 

regulate hot water heaters as defined in 63.7575. EPA recognizes that all hot water heaters meet 

the proposed definition of a boiler because they are enclosed devices that combust fuel for the 
purpose of heating water, but it is further stated that the when the hot water output from a hot 

water heater is intended for personal use rather than for use in an industrial, commercial, or 

institutional process, the hot water heater is more appropriately identified as a residential-type 

boiler and not an industrial, commercial, or institutional boiler. 

EPA seeks to establish a definition for hot water heaters that would distinguish residential-type 

units or those used for non-process purposes from process-related units. However, the proposed 

definition bases the exemption solely on the size and output of the unit by limiting the capacity 

of an exempted hot water heater to 120 gallons, the pressure to 160 psig, and the temperature to 

120 °F. 

In order to maintain consistency with the rationale used to exempt hot water heaters, a hot water 

heater should be distinguished from a boiler by the intended use of its output, not its physical 

parameters. Accordingly, AISI recommends the following revision to the definition in §63.7575: 

Hot water heater means a device in which water is heated by combustion of gaseous or liquid 

fuel and is withdrawn for personal use and not for use in an industrial, commercial, or 

institutional process. 

Response: We disagree with revising the definition of hot water heater. The definition in the 

final rule is based on the definition of hot water heater contained in California’s air regulation. 

The concern with basing the definition on personal use is defining what is personal use as 

opposed to what is commercial or institutional use. For example, a boiler located in a dormitory 

or on campus providing hot water is considered an institutional boiler whether or not the hot 

water is use for personal use of the students living in the dormitory. 

Rule Language: Definitions (new)

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 10

Comment: Some devices use electricity to heat water or produce steam. These are not generally 

thought of as enclosed combustion devices, but “enclosed combustion” is not a defined term and 

could be reinterpreted in the future. We therefore ask the Agency make clear that these are not 

“boilers” under this proposal. 

Response: We agree and have revised the definition of a “boiler” to include “using controlled 

combustion.”
Commenter Name: David J. Prior

Commenter Affiliation: New York State Energy Research and Development Authority, 

NYSERDA

Document Control Number: EPA-HQ-OAR-2006-0790-1913.2

Comment Excerpt Number: 18

Comment: Since interruptible gas customers’ dual fuel boilers would be classified as a gas 

boiler if they only use liquid fuel during gas curtailment or gas supply emergencies, EPA should 

define a period of gas curtailment or supply emergency. Would it be defined by when the gas 

utility requires interruptible customers to curtail demand? There are economic conditions under 

which customers will switch, but would those qualify as well? 

The proposed rules define gas-fired boilers: Gas-fired boiler includes any boiler that burns 

gaseous fuels not combined with any solid fuels, burns liquid fuel only during periods of gas 

curtailment, gas supply emergencies, or periodic testing on liquid fuel. Periodic testing of liquid 

fuel shall not exceed a combined total of 48 hours during any calendar year. 

Response: The final rule does contain a definition for “Period of natural gas curtailment or 

supply interruption.”

Commenter Name: Barry Christensen

Commenter Affiliation: Occidental Chemical Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2227.1

Comment Excerpt Number: 3

Comment: OCC respectfully requests clarification of the definition of gaseous fuels. OCC 

requests specific language in the rule to clarify that hydrogen, which is generated as a byproduct 

in two of our area source Chlor-Alkali facilities, is considered to be a process gas in the 

definition of gaseous fuels. Our byproduct hydrogen is sold as a product to industrial and 

medical gas manufacturing facilities or is used onsite and burned as a fuel. One of our locations 

fires hydrogen in combination with natural gas in boilers. Another location burns hydrogen in its 

waste heat boilers. 

Response: The definition of “gaseous fuels” has been revised to include hydrogen.

Rule Language: Tables 1 through 6

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1
Comment Excerpt Number: 22

Comment: CIBO recommends that EPA clarify certain aspects of its proposed testing regime 

prior to finalizing the Proposed Rule. First, in Table 4 there is no need to require sources to 

convert CO emissions to lb/MMBtu. 75 FR 31915. While Table 4 states that stack testing applies 

to new units, existing coal units may have to undergo stack testing in order to show compliance 

with mercury limits. 

Response: We agree and Table 4 has been revised.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 26

Comment: With regard to Table 5, if CO limits as ppm with O2 correction, there is no need for 

flow traverse and conversion to lb/MMBtu in Table 5 unless it is allowed as an alternate limit. 

EPA should replicate its approach in the Proposed Boiler MACT Rule at Table 3. 75 FR 32023. 

Response: We agree and Table 4 has been revised to remove the flowrate requirement.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 50

Comment: Additionally, EPA has not included requirements for wet scrubbers in Table 3. 75 FR 

31914. Some boilers rely on wet scrubbers to comply with the mercury and PM emission limits. 

Monitoring of pressure drop and liquid flow rate for wet scrubbers should be included in this 

Table 3. Furthermore, EPA should incorporate the monitoring options for additional devices per 

Table 7 of the Proposed Boiler MACT Rule (75 FR 32071). 

Response: We agree and monitoring of pressure drop and liquid flow rate for wet scrubbers is 

included in Table 3 of the final rule. Table 3 has also been revised to incorporate the monitoring 

options for additional devices.

Commenter Name: James P. Brooks

Commenter Affiliation: Maine Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2006-0790-1915.1

Comment Excerpt Number: 16
Comment: Table 1 of the proposed Subpart JJJJJJ indicates CO compliance should be based on 

a daily block average even for units without a CEM. The Maine DEP believes this may be an 

error and recommends that EPA require three one-hour runs instead. 

The Title and headings for Table 3 indicate that the operating limits only apply to units subject to 

mercury emission standards. We have been told by EPA contacts, however, that the title and 

heading are incorrect. If the monitoring requirements in Table 3 apply to units subject to any of 

the emission standards, it would require COMS for very small boilers utilizing ESPs for PM 

control. We request that EPA review the content and applicability of this Table to ensure 

appropriate requirements would be applied. 

Response: We agree and both Tables 1 and 3 has been revised to reflect the final rule 

requirements.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 69

Comment: Table 3 includes operating limits for boilers with mercury emission limits. This table 

should be expanded to also include operating limits for boilers that have PM limits and use 

control devices to comply with those limits. In addition, some boilers may use wet scrubbers to 

comply with the mercury and PM emission limits. Therefore, monitoring for wet scrubbers 

should be included in this table (e.g., monitoring pressure drop and liquid flow rate). EPA should 

incorporate the monitoring options for additional devices per Table 7 of the proposed boiler 

MACT (75 FR 32071). 

Response: We agree and monitoring of pressure drop and liquid flow rate for wet scrubbers is 

included in Table 3 of the final rule. Table 3 has also been revised to incorporate the monitoring 

options for additional devices.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 74

Comment: In Table 4 to subpart JJJJJJ of Part 63, Item 3.f should be deleted. The CO emission 

limits are in ppm so facilities do not need to convert tested CO emissions to lb./MMBTU. 

Response: We agree and Table 4 has been revised.
Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 75

Comment: Existing coal units may have to do stack testing to show compliance with Hg limit; 

however, the text immediately preceding Table 4 says it applies to new units. The text should 

indicate that the testing procedures apply to new and existing units. 

Response: We agree and Table 4 has been revised.

Commenter Name: Robert R. Scott

Commenter Affiliation: New Hampshire Department of Environmental Services

Document Control Number: EPA-HQ-OAR-2006-0790-1952.1

Comment Excerpt Number: 19

Comment: 63.11201 does not reference the Table 3 mercury standards but Table 3 references 

63.11201. 

Response: Section 63.11201 has been revised to reference Table 3.

Commenter Name: Robert R. Scott

Commenter Affiliation: New Hampshire Department of Environmental Services

Document Control Number: EPA-HQ-OAR-2006-0790-1952.1

Comment Excerpt Number: 21

Comment: Table 3 refers to 63.11211(c) but should be 63.11211 (b). 

Response: Table 3 has been revised based on the comment.

Commenter Name: Gary Melow

Commenter Affiliation: Michigan Biomass

Document Control Number: EPA-HQ-OAR-2006-0790-1917.1

Comment Excerpt Number: 25

Comment: Table 4 of the proposed rule outlines stack testing requirements and requires that a 

lb/MMBtu value be calculated for CO. However, the proposed CO limitation is a corrected PPM 

value. 
Response: We agree and Table 4 has been revised.

Commenter Name: Daniel Moss

Commenter Affiliation: Society of Chemical Manufacturers and Affiliates

Document Control Number: EPA-HQ-OAR-2006-0790-2018.1

Comment Excerpt Number: 13

Comment: A technical correction: The sentence that introduces Table 2 says “As stated in §§ 

63.11202 and 63.11203.” [Footnote: 75 Fed. Reg. at 31932.] There are no such subsections; the 

correct reference would be to § 63.11201(b). 

Response: We agree and Table 2 has been revised.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 19

Comment: Item (1) in Table 2 of the rule has a single compliance option listed in the second 

column. This item is lettered. Item (2) in Table 2 of the rule has a single compliance option listed 

in the second column. This item is not lettered. The EPA should clarify the lettering in Table 2 of 

the rule. 

Response: Table 2 has been revised based on the comment.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 51

Comment: Table 3 Should Include Monitoring For Additional Control Devices. Table 3 

includes operating limits for boilers with mercury emission limits. This table should be expanded 

to also include operating limits for boilers that have PM limits and use control devices to comply 

with those limits. In addition, some boilers may use wet scrubbers to comply with the mercury 

and PM emission limits. Therefore, monitoring for wet scrubbers should be included in this table 

(e.g., monitoring pressure drop and liquid flow rate). EPA should incorporate the monitoring 

options for additional devices per Table 7 of the proposed Boiler MACT (75 Fed. Reg, 32071). 
Response: We agree and monitoring of pressure drop and liquid flow rate for wet scrubbers is 

included in Table 3 of the final rule. Table 3 has also been revised to incorporate the monitoring 

options for additional devices.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 53

Comment: Technical Edits Are Needed On Table 5. 

The text prior to Table 5 on fuel analysis states that the requirements in Table 5 apply to new 

units. These requirements also should apply to existing coal-fired units using fuel analysis to 

comply with the proposed mercury limit. 

Response: We agree and Table 5 has been revised.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 54

Comment: Technical Edits Are Needed On Table 4. 

There are a few technical edits necessary on Table 4. First, Item 3.f should be deleted. The CO 

emission limits are in ppm so facilities do not need to convert tested CO emissions to lb/MMBtu. 

Second, existing coal units may have to do stack testing to show compliance with the Hg limit; 

however, the text immediately preceding Table 4 says it applies to new units. The text should 

indicate that the testing procedures apply to new and existing units. 

Response: Table 4 has been revised to address the comment.

Rule language Excluding Definitions and Tables 1-6

Commenter Name: R.H. Pankratz

Commenter Affiliation: Babcock and Wilcox Pantex, DOE/NNSA

Document Control Number: EPA-HQ-OAR-2006-0790-0466

Comment Excerpt Number: 1

Comment: Proposed § 63.11222(b)(6)(iii). 63.11222(b) You must conduct a tune-up of the 

boiler biennially to demonstrate continuous compliance as specified in paragraphs (b)(1) through 

(6) of this section. 
(6) Maintain on-site and submit, if requested by the Administrator, an annual report containing 

the information in paragraphs (b)(6)(i) through (iii) of this section, 

(i) The concentrations of CO in the effluent stream in ppmvd, and oxygen in percent dry basis, 

measured before and after the adjustments of the boiler; 

(ii) A description of any corrective actions taken as a part of the combustion adjustment; and 

(iii) The type and amount of fuel used over the 12 months prior to the annual adjustment. 

Comment: §63.11222(b)(6)(iii) requires a regulated entity is to provide information related to an 

“annual adjustment”, which is not referenced anywhere else in this proposed regulation. For 

consistency, replace the terms “adjustments of the boiler”, “combustion adjustment”, and 

“annual adjustment” with “tune-up of the boiler as defined in §63.11222(b) of this section”. 

Comment: §63.11222(b) requires a biennial tune-up of the boilers affected by this Subpart. 

§63.1122(b)(6) and §63.11222(b)(6)(iii) requires an annual action based on the biennial action in 

§63.11222(b). For clarity the periodic requirements should be consistent. For consistency, 

replace annual with biennial in the periodic requirements in §63.11222(b)(6) and 

§63.11222(b)(6)(iii).

Response: Section 63.11222(b) has been revised in the final rule based on the comment.

Commenter Name: Dorris Bender

Commenter Affiliation: City of Independence Water Pollution Control Department

Document Control Number: EPA-HQ-OAR-2006-0790-0351

Comment Excerpt Number: 2

Comment: 63.11222 Paragraph (b)(6)(iii) requires an annual report of the type and amount of 

fuel used over the 12 months prior to the annual adjustment. “Annual adjustment” conflicts with 

the proposed rule requirement for a biennial (not annual) boiler tune-up. Clarification is needed. 

We do not object to the proposed recordkeeping and reporting requirements for boiler fuel usage.

Response: Section 63.11222(b) has been revised in the final rule based on the comment.

Commenter Name: Dorris Bender

Commenter Affiliation: City of Independence Water Pollution Control Department

Document Control Number: EPA-HQ-OAR-2006-0790-0351

Comment Excerpt Number: 3

Comment: 63.11224. Paragraph (c)(2) states, “You must keep records to document conformance 

with the work practices, emission reduction measures, and management practices required by 

§63.11215 as specified in paragraphs (c)(2)(i) through (iv) of this section.” However, neither 

§63.11215 nor §63.11224 has a paragraph (c)(2)(iii) or (iv). Clarification is needed.

Response: Section 63.11224 has been clarified based on the comment.

Commenter Name: David Meierhenry
Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-0414.1

Comment Excerpt Number: 9

Comment: 63.11205(a) states, “At all times you must operate and maintain any affected 

source...in a manner consistent with safety and good air pollution control practices...” The 

phrase “...safety and...” should be deleted. There is obviously no denying the importance of 

employee safety programs and I encourage the EPA to discuss their safety philosophy as well as 

their relationship with OSHA in the preamble. Putting a reference to safety in the rule, however, 

makes it an enforceable condition, similar to OSHA’s general duty clause, but it is too vague, illdefined, and inappropriate for an air pollution control rule. In a proposal covering 40 pages of 

Federal Register text with over 40,000 words there is no discussion of the agency’s safety 

expectations. 

The EPA’s incorporation of safety into the rule raises, at a minimum, the following questions. 

Which safety practices do the EPA find acceptable or unacceptable? Are OSHA standards the 

primary concern? What about the NFPA 101 Life Safety Code, industry standards, 

manufacturer’s guidelines, and company safety policies? If an employee is injured while 

performing boiler maintenance, or a contractor is injured conducting an energy assessment or 

stack test, will this be a violation of Subpart JJJJJJ? Does it have to be a recordable injury? Will 

a violation occur if an exit sign in the boiler room is missing but there is no injury? Will the EPA 

inspectors be looking at the safety training programs? Will they be examining the OSHA 300 

logs? Can citizen lawsuits be filed under the Clean Air Act for safety issues related to this rule? 

As stated previously, the phrase “safety and” should be deleted from 63.11205(a). 

Response: The phrase “safety and” included in 63.11205(a) is only restating the General 

Provision requirement contained in 40 CFR 63.6(e) Operation and maintenance requirements, 

which state “...in a manner consistent with safety and good air pollution control practices...”

Commenter Name: Bob Pankratz

Commenter Affiliation: Babcock and Wilcox Technical Services Pantex, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-0833

Comment Excerpt Number: 1

Comment: §63.11222(b)(6)(iii) requires a regulated entity is to provide information related to an 

“annual adjustment”, which is not referenced anywhere else in this proposed regulation. For 

consistency, replace the terms “adjustments of the boiler”, “combustion adjustment”, and 

“annual adjustment” with “tune-up of the boiler as defined in §63.11222(b) of this section”. 

Comment: 

§63.11222(b) requires a biennial tune-up of the boilers affected by this Subpart. §63.1122(b)(6) 

and §63.11222(b)(6)(iii) requires an annual action based on the biennial action in §63.11222(b). 

For clarity the periodic requirements should be consistent. For consistency, replace annual with 

biennial in the periodic requirements in §63.11222(b)(6) and §63.11222(b)(6)(iii). 
Response: Section 63.11222(b) has been revised in the final rule based on the comment.

Commenter Name: Cynthia Finley

Commenter Affiliation: National Association of Clean Water Agencies

Document Control Number: EPA-HQ-OAR-2006-0790-0838.1

Comment Excerpt Number: 5

Comment: In §63.1124, paragraph (c)(2) states, “You must keep records to document 

conformance with the work practices, emission reduction measures, and management practices 

required by §63.11215 as specified in paragraphs (c)(2)(i) through (iv) of this section.” Neither 

§63.11215 nor §63.1124 has paragraphs with these numbers, however. EPA should clarify or 

correct this statement. 

Response: Section 63.11224 has been clarified based on the comment.

Commenter Name: Catherine Fitzsimons

Commenter Affiliation: Iowa Department of Natural Resources

Document Control Number: EPA-HQ-OAR-2006-0790-1829.1

Comment Excerpt Number: 2

Comment: The proposed rule requires annual testing for PM and mercury; if three consecutive 

tests show emissions at or below 75% of limit, test frequency can drop to every three years. The 

proposal includes the following: 

63.11214(d) If a performance test shows emissions exceeded 75 percent of the emission limit, 

you must conduct annual performance tests for that pollutant until all performance tests over 

consecutive 3-year period show compliance. 

Shouldn’t this specify that annual testing is required until three consecutive tests again show that 

emissions are at or below 75% of limit? If they show compliance but are above 75% of limit, the 

testing frequency would remain annual. 

Response: We have clarified the provision by specifying that annual testing is required until 

three consecutive tests again show that emissions are at or below 75% of the limit.

Commenter Name: Renee Lesjak Bashel

Commenter Affiliation: Small Business Environmental Assistance Programs, SBEAP

Document Control Number: EPA-HQ-OAR-2006-0790-2195.1

Comment Excerpt Number: 15

Comment: Recommendation: Correct the following typos: 
• 63.11221(a)(3) – too many “you have” 

• 63.11211(a) – spell out CMS and all other acronyms the first time they are used in the rule 

Response: The edits have been made to the final rule.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 18

Comment: We do request that the language of the proposed exemptions in §63.11195(a) and (b) 

be clarified, however, to be clear that the exemption applies to not only a boiler that is an 

affected facility under CAA §112 or 129, but also to any boiler that is part of an affected facility 

under those CAA sections. For instance, under part 63 subpart UUU, a CO boiler is part of the 

Fluid Catalytic Cracking Unit affected facility and its emissions are regulated by that subpart, but 

CO boilers are not listed as an affected facility on their own under that rule. The word 

“specifically” should be deleted from §63.11195(a) and (b). 

Response: Section 63.11195(a) has been revised to include the phrase “, or included in the 

definition of,” which is intended to include any boiler that may not be specifically listed in 

another section 112 standard but is include as part of the affected source and, thus, it emissions 

are already regulated.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 20

Comment: Under proposed §63.11194(a)(1), an affected source is “the collection of all existing 

industrial, commercial, and institutional boilers within a subcategory located at an area source.” 

The subcategories of concern under this proposal are listed in §63.11200, but (a)(1) could be 

easily misinterpreted to include boilers in subcategories that are not listed in §63.11200. Thus, 

we recommend (a)(1) be revised to specifically reference §63.11200 or that the subcategories be 

listed in (a)(1) as well as in §63.11200. Furthermore, it is unclear if the boilers within all of the 

subcategories listed in §63.11200 comprise one affected source or whether there is a separate 

affected source for each subcategory. We ask the Agency to clarify that point. 

Under §63.11194(a)(2) another affected source is defined as “each new or reconstructed 

industrial, commercial, or institutional boiler located at an area source.” Since this paragraph 

does not limit these affected sources to only the subcategories listed in §63.11200, presumably 
every new or reconstructed boiler at an area source is an affected facility under this rule, 

regardless of the fuel it combusts. Such a designation would trigger burdensome reporting and 

recordkeeping requirements for boilers not subject to rule requirements or addressed in the 

record. Therefore, we believe that (a)(2) must be revised to limit the boilers covered to those in 

one of the subcategories listed in §63.11200. As for (a)(1), §63.11200 should be specifically 

referenced from (a)(2) or the subcategories should be specifically listed in (a)(2). 

Response: Section 63.11194 has been revised to clarify that new boilers only within the listed 

subcategory are affected sources.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 39

Comment: Proposed §63.11221(a)(1) states “you must not operate above any of the applicable 

maximum operating limits or below any of the applicable minimum operating limits listed in 

Table 3 to this subpart at all times.” However, the limits in Table 3 have averaging times and 

thus sources may operate above and below those limits as long as the averages meet the limit. 

Thus the phrase “at all times” is incorrect and should be deleted. The Table 3 limits should not 

be turned into instantaneous limits through §63.11221(a)(1). 

The same problem occurs in proposed §63.11221(a)(5) relative to the Table 1 CO limits. Those 

limits are daily average limits, so the requirement in (a)(5) to meet the CO limit “at all times” is 

incorrect and that phrase should be deleted. 

Response: We agree with the comment and the phrase has been removed from the final rule.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 64

Comment: Proposed §63.11224(a)(3)(i) requires an initial certification that ““This facility 

complies with the requirements in §63.11222(b) to conduct a biennial tune-up of the boiler”. 

Sources cannot make that certification, since they will only have done the initial tune-up. 

Therefore, they cannot certify that they have met the requirement for biennial tune-ups”. This 

statement should be changed to only require that sources certify that the initial tune-up has been 

completed. 
Response: We agree and the appropriate paragraph was revised in the final rule.

Commenter Name: Leon Lataille

Commenter Affiliation: Massachusetts Water Resources Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1896.1

Comment Excerpt Number: 4

Comment: 63.11214(a) requires annual testing, with extensions for PM and mercury testing 

under certain conditions listed in (b) through (d). 63.11214(e) indicates that boilers of 10 to 100 

MMBtu/hr size must conduct annual tests for CO. The status of annual testing for CO for boilers 

less than 10 MMBtu/hr is not mentioned. Add text to clarify the testing requirements for boilers 

less than 10 MMBtu/hr. 

Response: Boilers less than 10 MMBtu/h are subject to only a work practice standard or a 

management practice of conducting an initial and biennial tune-up. There are no emission 

testing requirements for boilers less than 10 MMBtu/h.

Commenter Name: Robert R. Scott

Commenter Affiliation: New Hampshire Department of Environmental Services

Document Control Number: EPA-HQ-OAR-2006-0790-1952.1

Comment Excerpt Number: 10

Comment: EPA proposes allowing a facility to use up to 10% of an alternative fuel that a boiler 

is "designed" to burn without having to comply with appropriate emission limits. NHDES 

suggests that EPA change the word "designed" to "permitted" to burn. While a unit may be 

designed to burn certain fuels, a state may have placed limitations on the type of fuel used within 

a permit. 

Response: In the final rule, the definitions of the various subcategories have been revised and 

are based on the percent of annual heat input to the boiler, not on design limits. 

Commenter Name: John C. deRuyter

Commenter Affiliation: DuPont

Document Control Number: EPA-HQ-OAR-2006-0790-1964.1

Comment Excerpt Number: 11

Comment: The wording in §63.11223(d) should be clarified relative to COMS installation to 

avoid confusion. It should be revised to read: “If you have an applicable opacity operating limit 

under this rule, you must install...” 
Response: The wording in §63.11223(d) (now §63.11224(d)) has been revised.

Commenter Name: Robert R. Scott

Commenter Affiliation: New Hampshire Department of Environmental Services

Document Control Number: EPA-HQ-OAR-2006-0790-1952.1

Comment Excerpt Number: 18

Comment: The regulations list emission limitations for CO corrected to two different percent 

oxygen (3% and 7%). NHDES requests that the regulations specify the emission limitations in 

lb/MMBtu heat input as well as ppm consistently in the final rules so that emission limitations 

can be compared for the various types of fuel combusted. 

Response: The CO emission limits in the final rule are corrected to 3 percent oxygen.

Commenter Name: Robert R. Scott

Commenter Affiliation: New Hampshire Department of Environmental Services

Document Control Number: EPA-HQ-OAR-2006-0790-1952.1

Comment Excerpt Number: 20

Comment: The language preceding Table 2 refers to §§63.11202 and 63.11203 but should 

reference 63.11201. 

Response: The language preceding Table 2 has been revised.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 25

Comment: We recommend that the monitoring plan section of the proposed rule be clarified to 

more clearly define the contents of sections 63.11223(b) – (e). 

We recommend the monitoring plan sections be reviewed/updated to more clearly describe the 

requirements. For example, paragraph (b) refers to boilers that show compliance with an 

emission limit through stack testing and states that these units must have a monitoring plan for 

each CMS including information regarding ongoing QA, maintenance and recordkeeping 

procedures. Considering facilities that perform stack testing will not have analyzers installed for 

continuous monitoring, does this section refer to the reference method monitoring equipment in a 

stack testing protocol? For example, more clearly stating reference method analyzers used during 

annual compliance testing or facility installed analyzers to show compliance with emission limits 

would be much clearer. 
In addition, paragraph (c) includes references of both CMS and CPMS in a confusing fashion. 

This paragraph applies to analyzers either installed by the facility or used during compliance 

testing with the reference method and more explicitly stating these ideas would help clarify this 

section. Also citing the specific section within the rule that requires the installation of the 

analyzers being discussed would also be helpful. 

Why does paragraph (c)(4) require three hour block averages when in the case of CO data the 

compliance period is a calendar day using hourly averages? Is this section referring to stack 

testing reference method data that uses 3-hr data for compliance purposes? Please review/update 

accordingly to more clearly state which monitoring plan paragraphs apply to compliance 

reference method stack testing data vs. facility installed COMS/CO CEMS data. 

Paragraph (d) for COMS and (e) for CO CEMS are much more straightforward, but how do they 

fit in with the prior sections (b) and (c)? Are the requirements in paragraphs (b) and (c) also 

required for COMS and CO CEMS as well? 

Response: Paragraphs (b), (c), and (d) are stand along paragraphs. Paragraph (b) presents the 

requirements for the site-specific monitoring plan, if applicable. Paragraph (c) presents the 

requirements for continuous monitoring of a control device’s parameter, if applicable. Paragraph 

(d) presents the requirements for continuous monitoring of opacity, if applicable. In the final 

rule, the requirement for continuous monitoring of CO has been deleted. 

Commenter Name: Thompas P. Balf

Commenter Affiliation: Campus Cortium for Environmental Excellence

Document Control Number: EPA-HQ-OAR-2006-0790-1657.1

Comment Excerpt Number: 4

Comment: For dual fuel fired units that are applicable to the proposed regulation and are 

primarily gas-fired, it is not clear that they are exempt from meeting the applicable emissions 

limits while burning natural gas (i.e., under conditions of gas curtailment or other gas firing-only 

operating times). 

In 40 CFR 63.11201(a), specify that “You must comply with each emission limit specified in 

Table 1 of this subpart that applies to your boiler while firing the fuel subject to the emission 

limit. 

Response: Section 63.11195 (Are any boilers not subject to this subpart?) specifically states 

that “a gas-fired boiler as defined by this subpart” is not subject to the final rule. Therefore, a 

gas-fired boiler, meeting the definition in the final rule, is not subject to the rule when burning 

oil if the combustion of oil is during periods of gas curtailment or gas supply emergencies.
Commenter Name: Thompas P. Balf

Commenter Affiliation: Campus Cortium for Environmental Excellence

Document Control Number: EPA-HQ-OAR-2006-0790-1657.1

Comment Excerpt Number: 5

Comment: Regarding the same section 63.11223(e)(6), as defined in the regulation the "oil 

subcategory includes any boiler that does not burn any solid fuel and burns any liquid fuel either 

alone or in combination with gaseous fuels." For this reason it appears that boilers that co-fire 

natural gas and fuel oil would use co-firing CEMS emissions data within the daily averages to 

show compliance with the fuel oil firing emission limits. 

Would gas firing only hours be included within the daily averages for dual fuel fired boilers? 

Instead of adding specifics to the regulation, is this an example of a question that would be 

answered by a facility and specified within the site specific monitoring plan? 

Response: In the final rule, the CO emission limits for oil-fired boilers have been replaced with 

a management practice of a biennial tune-up requirement.

Commenter Name: Thompas P. Balf

Commenter Affiliation: Campus Cortium for Environmental Excellence

Document Control Number: EPA-HQ-OAR-2006-0790-1657.1

Comment Excerpt Number: 7

Comment: Section 63.11223(e) does not reference an installation requirement for the Oxygen 

analyzer. 

It seems that either 40 CFR 60 PS-3 should be referenced here for the installation requirements 

for the O2 analyzer or PS-4B be referenced for both CO and O2. 

Response: The requirement for the installation and operation of a CO CEMS has been removed 

in the final rule.

Commenter Name: Debra J. Jezouit

Commenter Affiliation: The Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2006-0790-1986.1

Comment Excerpt Number: 9

Comment: Proposed section 63.11224(b) (75 Fed. Reg. 31929, column 3) states, "You must 

prepare, by March 1 of each year, an annual compliance certification report for the previous 

calendar year containing the information specified in paragraphs (b)(1) through (b)(3) of this 

section." Please clarify whether "(b)(3)" should be "(b)(4)." 
Response: In the final rule (b)(3) has been revised to read (b)(4).

Commenter Name: Debra J. Jezouit

Commenter Affiliation: The Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2006-0790-1986.1

Comment Excerpt Number: 10

Comment: Proposed section 63.11224(b)(3) (75 Fed. Reg. 31929, column 3) states, "If the 

source is not in compliance, include a description of deviations..." It is unclear whether the 

phrase "If the source is not in compliance" in this statement is in reference to the reporting period 

for which the annual compliance certification report is being prepared. 

Response: The introductory paragraph (b) states that the information in subparagraph (3) is for 

the previous calendar year.

Commenter Name: Arthur Blazer

Commenter Affiliation: Council of Western State Foresters

Document Control Number: EPA-HQ-OAR-2006-0790-1962.1

Comment Excerpt Number: 10

Comment: Preamble to the rule provides contradictory information about the treatment of 

mercury from biomass boilers. The discussion in the draft rule preamble related to mercury from 

biomass systems is confusing. The discussion from p. 56 seems to contradict previous statements 

regarding MACT-based controls for mercury only being imposed on coal boilers. The discussion 

on p. 75 is confusing with regard to mercury emissions from biomass boilers. Also, statements 

seem to indicate that EPA is willing to consider regulating biomass boilers for mercury 

emissions through MACT-based emission standards. It should be made clear in the rule that 

mercury emissions from biomass boilers using unadulterated wood fuel are not a concern. 

Response: The discussion in the proposal preamble was whether mercury emission from 

biomass-fired area source boiler should be established under a MACT approach (as was done for 

coal-fired boilers) or under GACT. Section 112 of the Clean Air Act requires EPA to develop 

standards for listed source categories. Biomass-fired boilers are included in the listed categories 

of area sources and mercury is one of the listed HAP and one of the listed urban HAP.

Commenter Name: Debra J. Jezouit

Commenter Affiliation: The Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2006-0790-1986.1

Comment Excerpt Number: 11
Comment: Proposed Table 6, for section 63.7(e)(1) in the column entitled "Applies to subpart 

JJJJJJ" states, "No. Subpart DDDDD specifies conditions for conducting performance test at 

section 63.11210." The Group believes that Subpart JJJJJJ should be referenced instead of 

subpart DDDDD and the citation for conditions for conducting performance tests should be 

section 63.11212. 

Response: We agree and Table 6 has been revised.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 11

Comment: In 63.11212(a), the EPA proposes that facilities must conduct all performance tests 

according to the requirements in 63.7 and no additional information is given. In 63.7520(a) of the 

Boiler MACT Rule, the EPA provides definitive sections in 63.7 with which facilities are 

required to comply. In addition, in the Boiler MACT Rule, the EPA clearly states that the sitespecific test plan must be developed according to 63.7(c). Since area source facilities must meet 

the same requirements, as listed in Table 6, the EPA should consider adding the same additional 

information in the Area Source Boiler Rule for clarity. 

Response: Section 63.11212 of the final rule has been revised to be consistent with section 

63.7520 of the Boiler MACT.

Commenter Name: Debra J. Jezouit

Commenter Affiliation: The Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2006-0790-1986.1

Comment Excerpt Number: 12

Comment: Proposed section 63.11213 and Table 5 do not appear to address fuel sample 

collection for liquid fuels. 

Response: We are not aware of a collection method for liquid samples.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 12
Comment: In 63.11214(f), the EPA proposes that "If you demonstrate compliance with the 

mercury based on fuel analysis..." [75 FR 31927]. It appears that the words "emission limit" were 

omitted and the sentence should read "If you demonstrate compliance with the mercury emission 

limit based on fuel analysis..." 

Response: The words “emission limit” have been added in the final rule.

Commenter Name: Debra J. Jezouit

Commenter Affiliation: The Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2006-0790-1986.1

Comment Excerpt Number: 13

Comment: Proposed section 63.11237 includes biodiesel in the definition of "Liquid fuel." 

Please clarify whether liquid biofuels such as crude palm oil and other crude biofuels and algal 

fuel are considered "Liquid fuel" as defined in the Proposed Rule. 

Response: The term “liquid biofuels” has been added to the definition of liquid fuels in the 

final rule.

Commenter Name: Debra J. Jezouit

Commenter Affiliation: The Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2006-0790-1986.1

Comment Excerpt Number: 14

Comment: Proposed section 63.1124(a)(3) requires the Notification of Compliance Status to be 

submitted "no later than 120 days after the compliance date specified in section 63.11196 unless 

you must conduct a performance test." Please clarify whether this exception also applies to 

owners and operators who are required to conduct a performance evaluation on the CEMS in lieu 

of a performance test. 

Response: The requirement of installing a CEMS was removed in the final rule.

Commenter Name: Daniel Moss

Commenter Affiliation: Society of Chemical Manufacturers and Affiliates

Document Control Number: EPA-HQ-OAR-2006-0790-2018.1

Comment Excerpt Number: 16

Comment: EPA should be clearer that sources only have to stack test for pollutants for which 

they have applicable, numerical emission limits. 
For existing units, the proposed rule sets numerical emission limits for emissions of (i) mercury 

from coal-fired units and (ii) CO from coal, oil and biomass-fired units. EPA should clarify that 

only these units need to conduct performance testing, and only for these pollutants. SOCMA 

believes that this EPA’s intent, based on the following provisions: 

Proposed Section 63.11210(a) (“You must demonstrate initial compliance with each emission 

limit that applies to you.”) 

Section 63.7(e) of the General Provisions, incorporated by reference in Table 6 (which refers to 

“determining compliance with the relevant standard.”) 

Nonetheless, SOCMA is concerned that there is some ambiguity about units that are subject to 

tune-up requirements for particular pollutants; i.e., emissions of PM from all categories of 

existing units and emissions of Hg from oil and biomass-fired existing units. SOCMA would 

appreciate clarification that these units do not have to test for emissions of these pollutants. 

Response: We disagree that further clarification is needed.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 18

Comment: In 63.11222(b), the EPA proposes the continuous compliance requirement of 

biennial tune-ups for boilers. Section IV.G of the preamble [75 FR 31902] describes the 

proposed continuous compliance requirements, including annual stack tests and monitoring 

requirements. The EPA did not identify any continuous compliance requirements for boiler tuneups. The EPA should identify continuous compliance requirements for tune-ups in the preamble. 

Response: Section 63.11223 of the final rule presents how continuous compliance with the 

work practice or management practice of a tune-up is demonstrated.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 20

Comment: In 63.11201(a), the rule states that facilities must demonstrate compliance with each 

emission limit specified in Table 1 of the Area Source Boiler Rule. Table 1 of the rule should 

state that the boiler must achieve "less than or equal to" the emission limit instead of "meet" for 

clarity. 
Response: Table 1 of the final rule has been revised to address the comment.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 22

Comment: In 63.11237, the format for the definition of deviation should match the Boiler 

MACT Rule definition. Item (3) in the Area Source Boiler Rule definition is a stand alone 

sentence and not an instance of a deviation. 

Response: The definition of “deviation” in the final rule has been revised to be consistent with 

the Boiler MACT.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 25

Comment: There appears to be a grammatical error: a new sentence should be started between 

"...data base" and "the owner or operator..." In addition, the EPA should make the electronic 

reporting language in the Area Source Boiler Rule consistent with the Boiler MACT Rule 

language in 63.7550(h) to further clarify when and how stack test data should be entered into the 

EPA’s data base. 

Response: The electronic reporting language in the Area Source Boiler Rule has been revised 

in the final rule to be consistent with the Boiler MACT Rule language in 63.7550(h).

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 27

Comment: In Table 6 of the Area Source Boiler Rule, the EPA proposes the applicability of the 

General Provisions to Subpart JJJJJJ. The citation for 63.7(e)(1) incorrectly refers to Subpart 

DDDDD in the application column. 

Response: Table 6 of the final rule has been revised to address the comment.
Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 60

Comment: The regulatory language should make clear that the CO is only to be minimized to 

the extent the adjustments do not increase NOx emissions, decrease unit combustion efficiency, 

cause flame impingement or flame instability, or cause other safety issues, and that portable CO 

and O2 analyzers are acceptable, and that these tests are not performance tests. 

Response: The rule language in section 63.11223(b)(4) states “Optmize total emissions of CO 

consistent with the manufacturer’s specifications.”

Other - Rule Language Corrections

Commenter Name: Sheldon Schultz

Commenter Affiliation: Yanke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-0837

Comment Excerpt Number: 12

Comment: The time base of the averaging period must be established in the rule, indicating 

daily or monthly is not a rule and leaving this to argument later is not acceptable rule making. In 

my opinion monthly makes the most sense and is a reasonable compromise between hourly and 

annual. 

Response: The averaging times are established in the final rule.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 38

Comment: Since proposed §63.11211(b) contains requirements for demonstrating compliance 

with mercury limits through fuel analysis, that paragraph should be moved to §63.11213, which 

contains the rest of the requirements for such analyses and is titled “What fuel analyses and 

procedures must I use for the performance tests?” Otherwise the requirements in §63.11211(b) 

are likely to be missed. 
Additionally, it should be clarified that fuel analyses are not performance test and that all of the 

notice, planning, reporting and other requirements associated with performance tests do not 

apply to these multi-sample fuel analyses. 

Response: We disagree, §63.11211(b) refers to §63.11213.

Commenter Name: John Huber

Commenter Affiliation: National Oilheat Research Alliance

Document Control Number: EPA-HQ-OAR-2006-0790-1831.1

Comment Excerpt Number: 6

Comment: Comments Seeking Clarification 

Size and Affected Facilities 

EPA’s definition uses the following language. 

§ 63.11194 What is the affected source of this subpart? (a) This subpart applies to each new or 

existing affected sources as defined in paragraphs (a)(1) and (2) of this section. (1) The affected 

source is the collection of all existing industrial, commercial, and institutional boilers within a 

subcategory located at an area source. (2) The affected source of this subpart is each new or 

reconstructed industrial, commercial, or institutional boiler located at an area source. 

In describing boiler and boiler configurations, NORA has described facilities that may have 

multiple boilers with a total BTU value in excess of 30 MMBTU but generally each boiler will 

be less than 10 MMBTU. Our reading of the regulations indicates that the partial exemption for 

boilers with less than 10 MMBTU capacity should apply to a single boiler and thus two boilers 

that are utilized in one heating systems each with a capacity of 9 MMBTU would be within the 

10 MMBTU treatment described in “§ 63.11215 How do I demonstrate initial compliance with 

the work practice standard, emission reduction measures, and management practice? (a) If you 

own or operate an existing boiler with a heat input capacity of less than 10 MMBTU, you must 

submit a signed statement in the Notification of Compliance Status report that indicates that you 

conducted a tune-up of the boiler.” Furthermore, the regulation defines a boiler in clear terms an 

enclosed combustion device, whereas multiple boilers would indeed be defined as multiple 

enclosed combustions devices in “§63.11237 What definitions apply to this subpart? Boiler 

means an enclosed combustion device in which water is heated to recover thermal energy in the 

form of steam or hot water.” 

NORA in its comments believes that this definition is appropriate and therefore the size limit 

should be based on individual boilers, and not on boiler systems composed of multiple boilers. 

NORA would like clarification on this issue, but all of our comments are based on individual 

boiler sizing. 

Response: We agree that the size limit is based on individual boilers.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control
Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 6

Comment: The EPA states in the preamble, section IV.E (75 FR 31902), that in the event a 

source fails to comply with a standard as a result of a malfunction event, the EPA will determine 

an appropriate response. However, the definition of deviation in 63.11237 gives the entity 

responsible for enforcement of these standards discretion to determine what constitutes a 

violation. It is unclear as to whether the EPA will retain enforcement authority of this portion of 

the rule. The preamble for the final rule should clearly state who will have authority to determine 

malfunctions, and the appropriate response required by the facility. 

Response: We have added provisions to this final rule to include an affirmative defense to civil 

penalties for exceedances of emission limits that are caused by malfunctions.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 13

Comment: Section 63.11224(a) requires the 60 day Notification of Intent to conduct a 

performance test as prescribed in 63.7(b) but it fails to specify to whom it needs to be submitted. 

Perhaps the text could be revised to indicate that the Notification of Intent be submitted to the 

"delegated authority." 

Response: The wording “delegated authority’ was added to the appropriate paragraph in the 

final rule.

Commenter Name: Tim W. Sonnichsen

Commenter Affiliation: Sonnichsen Engineering, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-2139.1

Comment Excerpt Number: 13

Comment: The MACT Rules are all but unreadable 

Owners, managers and operators of biomass-fired boilers are very busy people. The length, 

format and the rambling question-and-answer nature of the MACT “rule” are not acceptable. 

In preparing the final rule, kindly provide summary documents that are clear , concise, and to the 

point. If you must include an additional 200 to 300 pages for the lawyers to decipher, then so be 

it. 
Response: After the rule is promulgated, there will be outreach activity that will include 

development of a brochure that will provide information to help an owner or operator to 

determine how their boiler may be affected by the Area Source Boiler NESHAP.

Testing and Monitoring

Stack Test Methods

Commenter Name: Rob Barton and Ralph Roberson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2006-0790-1978.1

Comment Excerpt Number: 13

Comment: EPA should include the following reference methods for compliance demonstration: 

a. EPA Method 30A, 30B (mercury) 

b. EPA Method 5B (total, filterable PM) 

Response: The final rule includes Methods 30 A and 30B, but not Method 5B. A source 

wishing to use Method 5B will need to apply for an alternative testing procedure per Section 

63.7(f).

Commenter Name: James P. Brooks

Commenter Affiliation: Maine Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2006-0790-1915.1

Comment Excerpt Number: 8

Comment: Commonly applied monitoring methods for carbon monoxide have a standard 

deviation of 5 ppm, which exceeds the limits proposed for several boiler subcategories in both 

the Area Source and Major Source Boiler MACTs. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Goup

Document Control Number: EPA-HQ-OAR-2006-0790-1916.1
Comment Excerpt Number: 19

Comment: In addition, CEMs are not an appropriate way to measure emissions during SSM 

events. Specifically, CEMs are certified using reference test methods that require near steady 

state operation. RATA testing requires near steady state operation for 21 minute intervals and is 

performed only after a boiler has reached normal operating conditions. The conditions that occur 

during SSM events are anything but steady state and therefore there would be no way to verify 

with a RATA test that the CEMs is operating properly. 

Response: There are no CEMS requirements for this rule, except for the use of an O2 monitor 

to ensure good combustion practices for minimizing CO emissions. Also see the preamble for 

revised treatment of SSM. 

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 34

Comment: According to proposed §63.11212(c), stack tests must be performed at maximum 

normal operating load. This will require the boiler to be at that particular rate for a significant 

part of a day (e.g., 12+ hours). This has several potential consequences that do not appear to have 

been considered. If the boiler is not needed to run at these high rates, fuel will be wasted, excess 

steam or hot water will have to be vented to the atmosphere and extra CO2 and pollutants will be 

emitted. For standby and emergency boilers, essentially all the firing during the test period would 

be waste and all pollutants emitted would be excess. If the boiler is part of a process operation 

(as opposed to providing space heating or hot water), that operation may be affected, incurring 

excess operating costs and possibly wasting additional energy and increasing process emissions. 

Thus, if the annual performance test requirement is maintained, the annual test should be allowed 

to be deferred until the boiler is operating at least 80% of capacity for operational reasons. 

Proposed §63.11212(c) requires that stack tests be performed at maximum normal operating load 

while burning the type of fuel or mixture of fuels that have the highest content of mercury. This 

requirement makes no sense for liquid- or biomass fired boilers, since there is no emission 

limitation proposed for mercury for those boilers. 

Furthermore, it is impossible to operate a boiler at precisely the “maximum normal operating 

load” or the “highest content of mercury.” Both of these requirements should be reworded to 

require the test be performed “at or near” the maximum operating load and, only where there is a 

mercury emission limit, at or near the highest mercury content. This would make these 

requirements feasible and comport with normal stack testing practice, where operation of a 

combustion source at between 80 and 100% of design capacity is typically considered 

representative for performance test purposes. 
We also note that annual stack testing at maximum mercury levels will result in significant 

mercury emissions that would not normally occur, since most boilers never actually run 

maximum mercury fuels and because the boiler will have to run a significant quantity of high 

mercury feed because they are only capable of storing one feed. While the amount of 

unnecessary, excess mercury emissions may be relatively small for any one boiler, the national 

total will be significant because of the large number of boilers and the claimed mercury emission 

reductions for this rulemaking should be reduced accordingly. 

Response: The final rule requires that testing be performed at representative operating loads. 

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 78

Comment: The proposed area source rule requires a minimum 1-hour sampling time for PM and 

2-hour sampling time for mercury stack testing. The proposed Boiler MACT rule requires a 

minimum 4-hour sampling time for all compounds.60 We agree that the proposed sampling 

times in the area source rule are adequate and EPA should provide justification for requiring 

longer sampling times. 

Response: We agree with commenters that the rule must clarify minimum sample volumes and 

assure that the specifications are consistent between test methods and with the method 

capabilities. The correct approach to measuring low quantities of emissions is to specify 

collection of a minimum sample volume that assures accuracy sufficient to determine 

compliance at the level of the emissions standard 

In response, the final rule will specify that the test run durations will be consistent with the 

methods prescribed procedures. For PM Methods, Method 29, and for the ASTM D6784-02, 

applications will be 3 dscm, consistent with the methods prescribed procedures. One may collect 

4 dscm in 3 to 4 hours of testing with Method 29 or with Method 5.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 80

Comment: The proposal also asks, “As discussed previously, the standard reference methods for 

measuring emissions of mercury, CO (as a surrogate for POM), and PM (as a surrogate for urban 

non-mercury metals) are EPA Methods 29, 10, and 5 and are not applicable for sampling small 

diameter stacks. We [EPA] solicit comment on whether it would be technically infeasible to 

design sampling ports adequate for the test methods in boilers that are below a certain size.” We 
do not believe EPA should spend valuable time investigating whether or not EPA test methods 

should be modified for the purposes of gaining additional emission information for this rule from 

small sources unlikely to have an impact on the environment. Previous work preparing the 

standards in question went through extensive scientific validation for all aspects of the test 

standards. These standards are regularly reviewed. If the technology changes in a way to allow 

for the additional information EPA speculates about in this query, that technology will be 

integrated into the EPA test method at the appropriate time in the future. 

Response: EPA thanks the commenter for this comment. The soliciting of comment on this topic 

has enabled EPA to finalize an approach for certain small boilers. See response to other 

comments on this issue. 

Commenter Name: Gary Melow

Commenter Affiliation: Michigan Biomass

Document Control Number: EPA-HQ-OAR-2006-0790-1917.1

Comment Excerpt Number: 4

Comment: If sources considered utilities under other rules are regulated as industrial units under 

this rule, then any emission limitation established that is corrected to O2 should also have an 

option for a limit corrected to CO2. The CEMS for most utility units have been changed to use 

CO2 as the diluent gas instead of O2. 

Response: There are no CEMS requirements in the final rule that require use of a diluent 

monitor to correct to O2. There is an O2 requirement for certain boilers to ensure good 

combustion practices for minimizing CO emissions. 

Commenter Name: Bob Perry

Commenter Affiliation: FirstEnergy Corp

Document Control Number: EPA-HQ-OAR-2006-0790-1959.1

Comment Excerpt Number: 17

Comment: EPA should include the following reference methods for compliance demonstration: 

a. EPA Method 30A, 30B (mercury) 

b. EPA Method 5B (total, filterable PM) 

Response: The final rule includes Methods 30 A and 30B, but not Method 5B. A source 

wishing to use Method 5B will need to apply for an alternative testing procedure per Section 

63.7(f).

Commenter Name: Cynthia A. Finley
Commenter Affiliation: National Association of Clean Water Agencies

Document Control Number: EPA-HQ-OAR-2006-0790-2260.1

Comment Excerpt Number: 3

Comment: In section 63.11212(c), stack tests are required to be conducted at the "maximum 

normal operating load while burning the type of fuel or mixture of fuels that have the highest 

content of mercury." For existing boilers with a rating greater than 100 MMBtu/hr, the 

applicable emissions limit is for carbon monoxide, with no limit for mercury. Requiring a 

maximization of mercury containing fuel is not the relevant issue for initial testing for these 

boilers. The appropriate test condition should instead be the maximum normal operating load 

using the predominant fuel. 

Response: Please see preamble for discussion on changes made to the final rule which require 

testing at fewer facilities.

Commenter Name: John Lyons

Commenter Affiliation: Kentucky Division for Air Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2218.1

Comment Excerpt Number: 5

Comment: Method 30b is not listed as an option for mercury compliance testing in table 5 of 

subpart DDDDD of Part 63. Method 30b is currently in use for mercury compliance testing over 

Method 29. 

Response: The final rule includes Methods 30 A and 30B, but not Method 5B. A source 

wishing to use Method 5B will need to apply for an alternative testing procedure per Section 

63.7(f).

Commenter Name: Christopher S. Colman

Commenter Affiliation: Hess Corp.

Document Control Number: EPA-HQ-OAR-2006-0790-2168.1

Comment Excerpt Number: 10

Comment: Test methods specified may not work at smaller facilities. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr. Also, please see preamble for discussion on changes 

made to the final rule which require testing at fewer facilities.

Commenter Name: Rob Barton
Commenter Affiliation: RMB Consulting and Research

Document Control Number: EPA-HQ-OAR-2006-0790-2140.1

Comment Excerpt Number: 11

Comment: EPA should include the following reference methods for compliance demonstration: 

EPA Method 30A, 30B (mercury) and EPA Method 5B (total, filterable PM) 

Response: The final rule includes Methods 30 A and 30B, but not Method 5B. A source 

wishing to use Method 5B will need to apply for an alternative testing procedure per Section 

63.7(f).

Commenter Name: Rob Barton

Commenter Affiliation: RMB Consulting and Research, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2198.1

Comment Excerpt Number: 11

Comment: Compliance Procedures Should Include Alternative EPA Reference Methods 

EPA should include the following reference methods for compliance demonstration: 

a. EPA Method 30A, 30B (mercury) 

b. EPA Method 5B (total, filterable PM) 

Response: The final rule includes Methods 30 A and 30B, but not Method 5B. A source 

wishing to use Method 5B will need to apply for an alternative testing procedure per Section 

63.7(f).

Commenter Name: Christopher Recchia

Commenter Affiliation: Biomass Energy Resource Center

Document Control Number: EPA-HQ-OAR-2006-0790-2008.1

Comment Excerpt Number: 12

Comment: Method 10 testing is fine for stack tests, but those results cannot be used to support 

conclusion that boilers (MACT floor) can operate 24/7 in compliance with those standards at all 

loads and during operation in pilot or stand-by mode. 

Response: Please see preamble for adjusted emission limits.

Commenter Name: Martin Lunde

Commenter Affiliation: Citizen
Document Control Number: EPA-HQ-OAR-2006-0790-2065.1

Comment Excerpt Number: 15

Comment: Every biomass heating unit should be tested utilizing the fuel it is intended to burn, 

not "lab" fuel. For instance, do not use crib wood fuel (present EPA fuel spec) to test a cordwood 

burning hydronic units. As is being demonstrated in the field every day, the utilization of crib 

wood as a test fuel is not a good predictor of clean cordwood combustion. 

Response: The rule requires use of the fuel with the highest emitting potential that the source 

intends to combust. The Agency does not consider a “lab” fuel that is not representative of the 

fuel to be combusted as appropriate under this subpart.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 25

Comment: UARG generally supports EPA’s proposal to use periodic performance tests, rather 

than CEMS, as the primary method for determining compliance with emission limits when limits 

cannot be met based on fuel analysis. UARG believes that such periodic tests will ensure “on an 

ongoing basis, that the air pollution control device is operating properly and its performance has 

not deteriorated.” 75 Fed. Reg. at 32,033. UARG also supports EPA’s proposal for reduced 

periodic testing, but objects to the restrictions EPA proposes. In addition, UARG asks that EPA 

provide options for use of several additional well established test methods not included in the 

rules, and options that would allow for reduced run length when appropriate. 

Response: EPA acknowledges the commenter’s support. Also note that the final rule includes 

Methods 30 A and 30B, but not Method 5B . A source wishing to use Method 5B will need to 

apply for an alternative testing procedure per Section 63.7(f). With respect to reduced run length, 

see the response to DCN EPA-HQ-OAR-2006-0790-1957.1, Comment Excerpt Number 28.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 28

Comment: UARG agrees that because EPA’s proposed emission limits were based on test data 

collected using runs of at least four hours, EPA cannot require compliance with the emission 

limits based on runs of shorter length. Moreover, in some cases, four hours (or longer) may be 

needed to obtain an adequate sample volume. However, in those cases where a source is able to 

obtain an adequate sample and meet an emission limit with a shorter run time, that option should 

be provided. UARG requests that EPA provide for that possibility by allowing shorter sampling 
times when the owner/operator can meet the comparable data quality objectives of the longer 

sampling time. Allowing shorter run times could significantly reduce the cost of compliance for 

some sources. 

Response: We agree with commenters that the rule must clarify minimum sample volumes and 

assure that the specifications are consistent between test methods and with the method 

capabilities. The correct approach to measuring low quantities of emissions is to specify 

collection of a minimum sample volume that assures accuracy sufficient to determine 

compliance at the level of the emissions standard 

In response, the final rule will specify that the test run durations will be consistent with the 

methods prescribed procedures. For PM Methods, Method 29, and for the ASTM D6784-02, 

applications will be 3 dscm, consistent with the methods prescribed procedures. One may collect 

4 dscm in 3 to 4 hours of testing with Method 29 or with Method 5.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 30

Comment: To demonstrate compliance with the PM limits through stack tests, EPA proposes to 

allow use of Methods 5, 5D (required for positive pressure fabric filters), or 17. Proposed Table 

5. Sources performing calibrations of PM CEMS under PS 11, on the other hand, are also 

allowed the option of using Method 5B -- Determination of Nonsulfuric Acid Particulate Matter 

Emissions from Stationary Sources. Method 5B was specifically developed to determine primary 

filterable PM emissions from sources with wet scrubbers and is routinely allowed for stack 

testing under federal regulations. See, e.g., 40 C.F.R. Part 60, Subparts D (60.46(b)), Da 

(60.50Da(e)(1)), Db (60.46b(d)(2)), Dc (60.45c(a)(2)) and Part 63, Subparts QQQ (63.1450(b), 

UUU (63.1579 and Tables). EPA should allow use of Method 5B or explain why the method is 

not appropriate for demonstrating compliance with the proposed limits. 

Response: The final rule includes Methods 30 A and 30B, but not Method 5B. A source 

wishing to use Method 5B will need to apply for an alternative testing procedure per Section 

63.7(f).

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 30

Comment: EPA Method 10 was reviewed to assess the potential accuracy of the CO emissions 

data that were included in the floor calculation. If the primary purpose of the testing was to 
measure CO emissions for compliance purposes, one would expect that a diligent stack tester, 

seeing minimal CO emissions, might settle on a span of 50 ppm CO for the actual compliance 

test, the data from which would then have an absolute accuracy of +/- 1ppm (50ppm * 2%, 

ignoring the stated M10 accuracy of NDIR analyzers of +/-5% of calibrated span). If the span 

gas is higher than 50 ppm, the expected accuracy would be greater than +/- 1ppm. That level of 

accuracy is very different from the appearance of the data that is presented in the area source 

floor memo, where CO values are reported out to 3 significant figures at levels sometimes less 

than 1 ppm. This is a misrepresentation of the accuracy of the test method. 

Response: Test method measurement imprecision is a contributor to the variability of a set of 

emissions data. One element is associated with method detection capabilities and a second is a 

function of the measurement value. Measurement imprecision is proportionally highest for 

values measured below or near a method’s detection level and proportionally decreasing for 

values measured above the method detection level. 

Probability procedures applied in calculating the floor or an emissions limit inherently and 

reasonably account for emissions data variability including measurement imprecision when the 

database represents multiple tests from multiple emissions units for which all of the data are 

measured significantly above the method detection level. That is less true when the database 

includes emissions occurring below method detection capabilities and are reported as the method 

detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).

The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than 

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 
Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 31

Comment: Proposed Table 5 lists Methods 2, 2F or 2G as the methods to determine the velocity 

and volumetric flow rate of the stack gas when testing for PM, HCl, and Hg, and Method 4 to 

determine moisture content for all pollutants. 75 Fed. Reg. at 32,069. Use of these methods is not 

necessary, or reasonable, because all of the methods specified in Table 5 for concentrations of 

those emissions also provide measurements of velocity and flow. Likewise, the methods used to 

determine pollutant concentrations (e.g., Methods 5, 23, and 26A) also determine stack moisture. 

Therefore, EPA should either remove those references or make use of those methods optional. 

Response: EPA disagrees, and has retained Methods 2, 2F, and 2G.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 57

Comment: EPA Should Explain The Discrepancies Between The Sampling Time Requirements 

Of This Rule And The Proposed Boiler MACT Rule. The proposed area source rule requires a 

minimum 1-hour sampling time for PM and 2-hour sampling time for mercury stack testing. 

[Proposed 63.11212 at 75 Fed. Reg. 31926] The proposed Boiler MACT rule requires a 

minimum 4-hour sampling time for all compounds. [Proposed 63.7520 at 75 Fed. Reg. 32052] 

We agree that the proposed sampling times in the area source rule are adequate and EPA should 

provide justification for requiring longer sampling times. 

Response: We agree with commenters that the rule must clarify minimum sample volumes and 

assure that the specifications are consistent between test methods and with the method 

capabilities. The correct approach to measuring low quantities of emissions is to specify

collection of a minimum sample volume that assures accuracy sufficient to determine 

compliance at the level of the emissions standard 

In response, the final rule will specify that the test run durations will be consistent with the 

methods prescribed procedures. For PM Methods, Method 29, and for the ASTM D6784-02, 

applications will be 3 dscm, consistent with the methods prescribed procedures. One may collect 

4 dscm in 3 to 4 hours of testing with Method 29 or with Method 5.

Commenter Name: Jim Griffin
Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 62

Comment: EPA should specify that the oxygen measurement should be based on either an O2 

CEMS reading ( if the unit has one), or the use of a portable emissions monitor. It should be 

made clear that a Method 3 oxygen measurement is not required. 

Flexibility should be provided to apply specific steps as appropriate for the particular unit. 

Response: The test method provisions in the rule indicate the generally required measurements 

as part of all stack tests. If the source wishes to seek an alternate method, a source may request 

an alternate through the general provisions in section 63.7.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 75

Comment: In Table 5 to proposed Subpart DDDDD, we believe EPA should include Method 

30B as an acceptable mercury performance testing method. RMB’s experience with Method 30B 

indicates that the method can provide superior precision and accuracy at low mercury 

concentrations. Method 30B has been shown to produce comparable results to the methods that 

were specified to collect the Hg emission data upon which EPA has developed the proposed Hg 

emission limits For example, when EPA promulgated Method 30B as a direct final rule, the 

Agency provided the following rationale.I4 

In considering development of a sorbent trap-based reference method, EPA has reviewed 

historical emissions data where sorbent trap measurement systems 

were operated concurrently with either the Ontario Hydro Method or Method 29 (40 CFR part 

60, appendix A-8). EPA has also conducted several field test evaluations of sorbent trap systems 

versus the Ontario Hydro Method in collaboration with the Electric Power Research Institute 

(EPRI). Based on these efforts, we have concluded that a sorbent trap-based technique coupled 

with appropriate performance criteria and QA procedures can provide Hg emissions data of 

quality comparable to that produced by the Ontario Hydro Method. 

Response: The final rule includes Methods 30 A and 30B, but not Method 5B. A source 

wishing to use Method 5B will need to apply for an alternative testing procedure per Section 

63.7(f).

Commenter Name: Wayne York

Commenter Affiliation: Hancock Lumber Company, Inc
Document Control Number: EPA-HQ-OAR-2006-0790-2002

Comment Excerpt Number: 4

Comment: Requiring annual CO testing following the full “Reference Method” testing 

requirements as specified in 40 CFR 60 Appendix A is not environmentally beneficial. At any 

given facility, it is conceivable that there may be an environmental benefit from conducting an 

initial test, because they may need to tune their boilers or make adjustments to meet the 

emissions limit initially. However, annual testing will not continue to improve emissions, but 

will add ongoing costs with little or no additional environmental benefit. 

We recommend significantly reducing the testing frequency for CO emissions. Annual testing 

will result in diminishing returns. We would recommend the frequency be once per five year 

period. This could be augmented with boiler tune-ups during the interim between tests, if 

necessary. Alternatively, the CO testing should have a mechanism to reduce the required testing 

frequency, depending on the level of performance achieved during the previous test(s), as is 

included in the proposed rule for the particulate matter (PM) and mercury testing requirements 

under 40 CFR 63.11214(a)-(d). 

For units greater than 10 MMBtu/hr, the requirement to test is in effect the major component of 

the Maximum Achievable Control Technology (MACT) finding. 

Table 4 of the proposed rule, entitled “Performance (Stack) Testing Requirements ,” requires CO 

testing to include Reference Methods 1-4, including Determination of Stack Flow Rate,

Volumetric Flow Rate, and Stack Moisture Content. None of these parameters are actually 

critical to the determination of CO emissions in terms of pounds per MMBtu (lb/MMBtu). It is 

our understanding that the determination of CO in terms of lb/MMBtu can be conducted far more 

cost-effectively based on the instrumental measurement of CO, and determination of oxygen and 

carbon dioxide (either instrumentally or using a Fyrite or equivalent method), and abbreviated 

methods for moisture determination, such as the use of “midget impingers” or “wet-bulb/drybulb”, when using the fuel factor calculations as listed in 40 CFR 60 Appendix A Method 19. 

Response: See response to EPA-HQ-OAR-2006-0790-2192.1, Comment Excerpt Number 6.

CEMS: General

Commenter Name: Margaret E. Sheehan

Commenter Affiliation: Energy Justice Network

Document Control Number: EPA-HQ-OAR-2006-0790-1053.1

Comment Excerpt Number: 2

Comment: The EPA should require Continuous Emissions Monitoring for mercury, dioxin and 

other toxic and hazardous air pollutants. 

The EPA should require biomass plants to use Continuous Emissions Monitoring Systems 

(CEMS) for toxic air pollutants, and to have the data released real time on websites that can be 

accessed by the public. Yearly stack tests do not give an accurate estimate of emissions during 
start-up, shut-down or upset conditions – which, for some pollutants, most notably dioxins – can 

be hundreds of times higher than during steady-state operation (which is when stack testing is 

typically done). CEMS equipment for many of these pollutants has been tested and verified by 

EPA’s Environmental Technology Verification Program. [See Reference 8 in submittal.] 

In addition to mercury contamination, contamination from toxic and hazardous air pollutants 

such as copper, iron and zinc need to be addressed through increased monitoring.Wood waste 

from construction and development contain metals such as copper and zinc.13 These metals are 

strongly correlated with dioxin formation and can serve as catalysts for dioxin formation.14 15 

As demonstrated in the following section, dioxin is a highly toxic threat to public health. 

Response: For the operations and facilities subject to the rule, we believe that the combination of 

periodic compliance emissions testing and continuous monitoring of operational and parametric 

control measure conditions is appropriate for assuring ongoing compliance. 

Commenter Name: Rich Raiders

Commenter Affiliation: Arkema Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1958.1

Comment Excerpt Number: 6

Comment: EPA Should Provide Compliance Flexibility For Owners of Continuous Emissions 

Monitors. 

Arkema appreciates that EPA did not require continuous emissions monitors (“CEMS”) in the 

proposed Boiler MACT and generally achievable control technology (“GACT”) area source 

standards. EPA also did not require extensive CEMS use in the proposed CISWI standards. 

However, situations may exist where a facility may elect to install, or may have already installed, 

one or more CEMS units on units regulated in one of the proposed source categories. In these 

cases, EPA should allow facilities to demonstrate compliance using common CEMS protocols 

and relative accuracy test audit (“RATA”) protocols used for other Clean Air Act obligations. 

Facilities opting into using CEMS for compliance with one or more pollutants should be 

exempted from the proposed testing requirements so long as the facility follows appropriate 

CEMS performance demonstrations. 

Response: We agree that we should encourage use of CEMS including for conducting initial 

compliance tests and for demonstrating ongoing compliance. The final rule would allow for use 

of CEMS as an alternative monitoring method. Using the alternative monitoring procedures of 

the general provisions, the rule allows for the source owner or operator to install and operate 

continuous emissions monitoring systems in lieu of some testing and parametric monitoring. 

This process requires source owners to propose site-specific monitoring plans for approval. 

These plans would include CEMS performance specifications and periodic quality assurance and 

quality control steps to assure the quality of the alternative monitoring data.
Commenter Name: Cheryl Johncox

Commenter Affiliation: Minneapolis Neighbors for Clean Air

Document Control Number: EPA-HQ-OAR-2006-0790-1971

Comment Excerpt Number: 8

Comment: The EPA should require biomass plants to use Release CEMS data for toxic air 

pollutants. 

CEMS equipment for many of these pollutants has been tested and verified by EPA’s 

Environmental Technology Verification Program. [U.S. Environmental Protection Agency, 

Advanced Monitoring Systems Center - Verified Technologies. http://www.epa.gov/etv/vtams.html.] 

Response: For the operations and facilities subject to the rule, we believe that the combination 

of periodic compliance emissions testing and continuous monitoring of operational and 

parametric control measure conditions is appropriate for assuring ongoing compliance. 

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Goup

Document Control Number: EPA-HQ-OAR-2006-0790-1916.1

Comment Excerpt Number: 20

Comment: From an economic perspective, the use of CEMs to measure emissions during SSM 

events is not feasible. First, facilities do not have CEMs on every boiler or process heater at a 

facility and, therefore, the equipment would need to be installed on multiple units at the affected 

facilities. The cost of installing a CEMs is considerable. One vendor estimate indicates that the 

total installed cost can range from $35,000-45,000 per unit. This includes the cost for the sample 

line, sample probe, rack, analyzers, data collection and engineering. In addition to these costs, 

there also are operating expenses for the equipment that can run from $24,000-$34,000 annually 

per CEMs. This amounts to a significant cost for an affected source for equipment that is not 

even demonstrated as an accurate way to measure during SSM events. Furthermore, for those 

CEMs that already are installed, EPA’s proposed emission limits would necessitate an additional 

range to monitor compliance. This would mean additional equipment would be needed just for 

this rule, which would require additional installation and operational costs as well for existing 

CEMs. Considering that a vast majority of facilities have multiple affected units, the use of 

CEMs is not economically feasible. 

Response: Please see preamble for discussion on the removal of CO CEMS from the 

requirements.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA
Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 68

Comment: In order to reduce the burden of the rule on area sources, installation of CEMS and 

COMS should not be required for boilers that do not already operate CEMS or COMS. Area 

sources may not have the required knowledge or manpower to operate complex continuous 

monitoring systems on their boilers, so the monitoring should be as simple as possible. Parameter 

monitoring or visible emissions observations should be sufficient for these small sources to 

ensure continued proper operation of the boiler and any associated air pollution control 

equipment. 

Response: Please see preamble for discussion on the removal of CO CEMS from the 

requirements.

Commenter Name: Thompas P. Balf

Commenter Affiliation: Campus Cortium for Environmental Excellence

Document Control Number: EPA-HQ-OAR-2006-0790-1657.1

Comment Excerpt Number: 2

Comment: Section 63.11223(e)(6) describes the CEMS data needed to calculate a daily average 

and excludes data when the "boiler is operating at less than 50 percent of its rated capacity." This 

concept appears to exclude startup/shutdown data and for boilers that have a low capacity factor 

or can fire at any load or are permitted to fire at loads less than 50% of the unit’s rated capacity, 

CO CEMS daily data may never or very infrequently be valid. For this reason, it appears the 

CEMS installation requirement needs to include certain exemptions, in light of the fact that 

requiring units to install CEMS that will rarely report data does not seem to be cost effective. For 

example, the recently promulgated 40 CFR 98 Mandatory Greenhouse Gas Reporting Rule 

requires CEMS be installed on boilers that satisfy numerous criteria including "the unit has 

operated for more than 1,000 hours in any calendar year since 2005" as stated within 40 CFR 

98.33(b)(4). 

Exempt boilers from installing CEMS that do not operate more than 1,000 hours per year at a 

capacity greater than 50% of its rated capacity. Compliance with applicable limits could still be 

verified by stack testing. 

Response: Please see preamble for discussion on the removal of CO CEMS from the 

requirements.

Commenter Name: Debra J. Jezouit

Commenter Affiliation: The Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2006-0790-1986.1

Comment Excerpt Number: 5
Comment: EPA proposes to require the use of carbon monoxide ("CO") continuous emissions 

monitoring systems ("CEMS"). Proposed section 63.11223(e)(2) would require a performance 

evaluation of each CEMS to be conducted in accordance with section 63.8 and PS 4A of 40 

C.F.R. Part 60, Appendix 13. However, the Proposed Rule, 40 C.F.R section 63.8, and PS 4A of 

40 C.F.R Part 60, Appendix B, do not specify the frequency at which the performance evaluation 

of the CEMS must be conducted. The Group recommends following the frequency specified in 

Procedure 1 of 40 C.F.R. Part 60, Appendix F - Quality Assurance Procedures. 

Response: Please see preamble for discussion on the removal of CO CEMS from the 

requirements.

Commenter Name: Debra J. Jezouit

Commenter Affiliation: The Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2006-0790-1986.1

Comment Excerpt Number: 6

Comment: EPA proposes to require the use of carbon monoxide ("CO") continuous emissions 

monitoring systems ("CEMS"). Proposed section 63.11223(e)(4) would require CO CEMS data 

to be reduced as specified in section 63.8(g)(2). Following the June 1, 2006 revision of 40 C.F.R. 

section 60.13(h) (i.e., harmonization of Part 60 with Part 75), 40 C.F.R. section 63.8(g)(2) is no 

longer consistent with section 60.13(h). The Group recommends that EPA harmonize the data 

reduction requirements in 40 C.F.R. Part 63 with 40 C.F.R. Parts 60 and 75. 

Response: Please see preamble for discussion on the removal of CO CEMS from the 

requirements.

Commenter Name: Charles B. Jones, III

Commenter Affiliation: Georgia Traditional Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1923.1

Comment Excerpt Number: 8

Comment: GTMA opposes any continuous emission monitoring requirement for boilers located 

at an Area Source of HAP, such as the proposed requirement for boilers greater than 100 

MMBtu/hr to have CEMS for carbon monoxide (CO). EPA states that it has no emission data for 

POM on coal boilers, but chose CO as the surrogate, assuming that as an indicator of incomplete 

combustion, it would also potentially indicate elevated organic HAP emissions. EPA provides no 

evidence or data to support the assertion that minimizing CO emissions through more complete 

combustion will result in minimizing organic urban HAP emissions. EPA should study this 

further before arbitrarily imposing CEMS on minor area sources. 
Response: Please see preamble for discussion on the removal of CO CEMS from the 

requirements.

Commenter Name: Debra J. Jezouit

Commenter Affiliation: The Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2006-0790-1986.1

Comment Excerpt Number: 8

Comment: The Group requests that EPA extend the deadline for complying with the Proposed 

Rule to five years. The Proposed Rule will, in many cases, require facilities to install controls on 

a large number of Boilers located at multiple generating stations. Additionally, numerous 

facilities will be required to install CEMS on many of the Boilers requiring controls. The 

proposed three-year compliance deadline, in addition to the one-year compliance extension that 

may be granted on a case-by-case basis, would not provide enough time for many facilities to 

retrofit their affected boilers and meet the proposed standards. For example, one Group member 

estimates that it will take five years to design, permit, procure, install, and receive regulatory 

approval to comply with the Proposed Rule. Accordingly, EPA should extend the compliance 

deadline. 

Response: Please see preamble for discussion on the removal of CO CEMS from the 

requirements.

Commenter Name: Thompas P. Balf

Commenter Affiliation: Campus Cortium for Environmental Excellence

Document Control Number: EPA-HQ-OAR-2006-0790-1657.1

Comment Excerpt Number: 8

Comment: Absence of a discussion regarding the application of the “diluent cap” for boilers 

CEMS data. 

Apply the 40 CFR 75 diluent cap of 14% for boilers acceptable within hourly CO calculations 

using CEMS data when O2 values are greater than 14%. If so, we request that the application of 

the “diluent cap” to CEMS data be documented within the final regulation. 

Response: Please see preamble for discussion on the removal of CO CEMS from the 

requirements.

Commenter Name: Thompas P. Balf

Commenter Affiliation: Campus Cortium for Environmental Excellence

Document Control Number: EPA-HQ-OAR-2006-0790-1657.1

Comment Excerpt Number: 10
Comment: There is no discussion of time sharing CEMS in the proposed rule (i.e., use of a 

single CEMS over multiple units/stacks). For example, in 63.11223(c)(1), as long as the 

minimum data availability requirements are satisfied (i.e. one sample within each quadrant of the 

hour) time sharing of CEMS appears to be allowed for facility’s that are equipped with multiple 

units. We commend the Agency for this cost-effective and flexible approach and recommend a 

brief discussion of this monitoring option within the final rule. 

Discuss the option for facilities to utilize CEMS time sharing in the final rule to help industry 

mitigate CEMS installation costs required by this regulation. 

Response: Provided the minimum data availability requirements are met, time-sharing of CEMS 

is permissible. However, the only CEMS requirement in the rule is for documenting compliance 

with an O2 operating limit to demonstrate good combustion practices for minimizing CO 

emissions.

Commenter Name: Thompas P. Balf

Commenter Affiliation: Campus Cortium for Environmental Excellence

Document Control Number: EPA-HQ-OAR-2006-0790-1657.1

Comment Excerpt Number: 11

Comment: Size of unit dictates installation of CEMS rather than operational history. Under the 

agency’s new federal Greenhouse Gas rules, the Agency provided a thoughtful analysis, and 

operational parameters, to the requirement for installation of CEMS. 

We recommend the agency review the CEMS installation requirements in comparison to other 

regulations and develop further thoughtful language that would include at least 

acknowledgement of a unit’s historical operations or permitted operational scenarios prior to 

being required to install CEMS. 

Response: Please see preamble for discussion on the changes to monitoring requirements.

Commenter Name: W. Randall Rawson

Commenter Affiliation: American Boiler Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1897.1

Comment Excerpt Number: 16

Comment: Comments Relating to Monitoring and Continuous Emission Monitoring Systems 

Requirements 

ABMA believes that the monitoring and CEMS requirements of the Proposed Area Source Rule 

should be clarified. As an initial matter, ABMA recommends that EPA evaluate the technical 

feasibility of in-situ measurements at the very low emission levels identified in the proposed 
rule. To the extent that EPA has not done any such evaluation, ABMA recommends that EPA 

contact CEMS manufacturers to ensure that CEMS will provide an accurate and feasible tool for 

compliance. 

Response: Please see preamble for discussion on the changes to monitoring requirements.

Commenter Name: Daniel Moss

Commenter Affiliation: Society of Chemical Manufacturers and Affiliates

Document Control Number: EPA-HQ-OAR-2006-0790-2018.1

Comment Excerpt Number: 17

Comment: EPA should not mandate CEMS or COMS. 

SOCMA believes that requiring continuous monitoring, either of emissions or opacity, does not 

reflect “generally available control technology” at area source boilers. CEMS and COMS are 

very rarely found on area source boilers, and are seldom if ever required by permitting agencies. 

One of these units costs roughly $250,000. This quarter-million dollar expense is excessive and 

unnecessary when its cost is viewed in light of: 

the small size of such units; 

the small size of the average business operating them; 

the relatively low volume of emissions from them; and 

the lack of variability in such emissions if the units are periodically stack-tested and tuned up –

as the rule otherwise requires. 

The high cost of fuel will also continue to drive owners to operate their boilers efficiently, again 

minimizing emissions.

Response: Please see preamble for discussion on the removal of CO CEMS from the 

requirements.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 50

Comment: EPA Should Not Require CEMS Or COMS On Area Source Boilers. In order to 

reduce the burden of this rule on area sources, installation of CEMS and COMS should not be 

required for boilers that do not already operate CEMS or COMS. Area sources may not have the 

required knowledge or manpower to operate complex continuous monitoring systems on their 

boilers, so the monitoring requirements should be as simple as possible. Parameter monitoring or 
visible emissions observations should be sufficient for these small sources to ensure continued 

proper operation of the boiler and any associated air pollution control equipment. 

Response: Please see preamble for discussion on the removal of CO CEMS from the 

requirements. A COMS is one option for listed control devices, but sources can opt for control 

device parameter monitoring instead of an opacity operating limit. For other control devices not 

specifically listed, the source would have to use an opacity limit and demonstrate compliance 

with a COMS, although the source can request an alternative under the general provisions of Part 

63.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 49

Comment: EPA Should Not Require CEMS Or COMS On Area Source Boilers. In order to 

reduce the burden of this rule on area sources, installation of CEMS and COMS should not be 

required for boilers that do not already operate CEMS or COMS. Area sources may not have the 

required knowledge or manpower to operate complex continuous monitoring systems on their 

boilers, so the monitoring requirements should be as simple as possible. Parameter monitoring or 

visible emissions observations should be sufficient for these small sources to ensure continued 

proper operation of the boiler and any associated air pollution control equipment. 

However, if COMS are required in the final rule, EPA needs to clarify proposed 63.11223(d) to 

eliminate confusion as to when a COMS is required. We suggest the following revision: 

“(c) If you have an applicable opacity operating limit under this rule, you must install, operate, 

certify and maintain each...” 

This requirement should only be applicable relative to an opacity limit in this particular rule, not 

if there is some existing opacity requirement under some other program, such as state rules. 

Response: See the response to Comment Excerpt Number 50 for this commenter.

CO CEMS 

Commenter Name: William H. Carlson

Commenter Affiliation: Carlson Small Power Consultants

Document Control Number: EPA-HQ-OAR-2006-0790-1493.1

Comment Excerpt Number: 4
Comment: The solution to continuous compliance with CO emissions limits is a catalytic CO 

reduction unit, a basically unproven device in this application. It will require natural gas or 

propane for catalyst regeneration, a scandal in and of itself. The solution, for an existing unit, is 

basically to install an expensive retrofit, raise annual operating cost, and hope that it works. 

Response: Please see preamble for changes to emission limit requirements in final rule.

Commenter Name: Donald R. Schregardus

Commenter Affiliation: Department of the Navy, Department of Defense

Document Control Number: EPA-HQ-OAR-2006-0790-1947.1

Comment Excerpt Number: 5

Comment: EPA is also proposing that compliance be determined using EPA Method 10 or a CO 

continuous emission monitoring system (CEMS) which meets Performance Specification 4 (PS4). Method 10 was developed many years ago and was designed to conduct CO measurements

above 20 ppm. Likewise, PS-4 is intended for use on CO CEMS that have a monitor range of 0-

1000 ppm and PS-4A specifies a monitor range of 0-200 ppm. To measure concentrations near 

the proposed 1-2 ppmdv rc7( 3% 0, limit, instrumentation designed for ambient monitoring 

would need to be incorporated and the methods revised accordingly. Having not developed this 

instrumentation and methodology to use on individual emission sources, one does not know if 

these systems will provide reliable data for the purpose of demonstrating compliance. In 

addition, the proposed rule states that all CO measurements have to be converted to a constant 

3% 0, basis. EPA has not considered the potential error associated with the 02 measurements at 

such low concentrations. The potential errors associated with all of the analyzers in a field 

environment have to be considered in evaluating the potential problems with demonstrating 

compliance with the proposed CO limit. 

For comparison, the current 8-hour CO National Ambient Air Quality Standard (NAAQS) is 9 

ppm and the current 1-hour CO NAAQS is 35 ppm. It is unrealistic for a combustion source such 

as a boiler to draw in combustion air from the surrounding ambient air at these CO levels and be 

required to actually act as a pollution control device and reduce the CO concentration in the 

ambient air. 

Response: Please see preamble for discussion on the removal of CO CEMS from the 

requirements. Also please see preamble for changes to emission limit requirements in final rule.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 47

Comment: The Proposed Rule requires area sources to utilize CEMS and in some circumstances 

COMS. 75 FR 31903-29. These requirements are extremely burdensome on area sources 
considering the testing requirements and costs. The requirement for CO CEMS for units less than 

100 MMBtu per hour is too onerous. Many units at this size in the industrial and institutional 

sector do not operate that frequently, therefore the cost of installing CO CEMS is not justified for 

units with such limited operation. CIBO recommends that EPA remove this requirement and 

present alternatives to either install CEMS or use stack testing for any units with limits. EPA 

could also increase the threshold requirement for CO CEMS to 250 MMBtu per hour or provide 

a limited use exemption such as 10 percent use. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement. Also see the response to EPA-HQ-OAR-2006-0790-1925.1, Comment 

Excerpt Number 50.

Commenter Name: Stephen E. Woock

Commenter Affiliation: Weyerhaeuser Company

Document Control Number: EPA-HQ-OAR-2006-0790-1984.1

Comment Excerpt Number: 13

Comment: We are concerned about the proposed requirement to install and use CO CEMS. The 

proposed rule would require a CO CEMS for boilers with a heat input capacity of 100 mmBtu 

per hour or more. The quality assurance testing and maintenance of such a device, will strain 

resources at typical area source facilities. We urge EPA to drop this requirement in the area 

source rule. However, for units that have a CO emissions limit but must demonstrate compliance 

with a performance test, the proposed CO limit in the form a of "daily average" makes no sense 

given the performance test provisions. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Bill Perdue

Commenter Affiliation: American Home Furnishings Alliance, AHFA

Document Control Number: EPA-HQ-OAR-2006-0790-1970.1

Comment Excerpt Number: 15

Comment: The proposed rule is unclear in its requirement for CO testing for some boilers 

smaller than 10 MMBTU/hr. The heading to Table 4 specifies: “As stated in § 63.11212, you 

must comply with the following requirements for performance (stack) test for new affected 

sources:”, however 63.11213(e) seems to indicate that CO testing is required for all units with a 

CO limitation, including existing units. Requiring small boilers <10MMBTU to test for CO 

presents a significant regulatory burden, particularly considering the size and impact of the 

individual unit. 
Response: Please see preamble for changes to emission limits in final rule.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 32

Comment: EPA has collected 30-day CO CEMS data from major sources and may have 

coincidentally collected area source CEMS data. However, we believe EPA needs to collect 

much more and if it pursues setting a CO emission limit base the limit on long term data. We are 

providing 30 day CO CEMS data from area sources with this submission (see Appendix 3). 

However, we believe EPA should go one step further and evaluate the annual variability of CO 

data from sources with CEMS. We are also providing annual CEMS data with this submission 

(see Appendix 4). As noted elsewhere, CO emissions from boilers can be highly variable, 

especially when fuel mix and load change. But variability also comes from weather, which is 

seasonal and with biomass fuel moisture levels, which are also seasonal. Seasonality also affects 

startups (particularly) and a shutdown since it is the cold surfaces in boilers that lead to spikes in 

CO levels during startup. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 32

Comment: Where CO CEMS are not required (boilers between 10 and 100 MMBTU/hr design 

heat input), sources should be given the option of using CEMS because such analyzers may be 

required for permit or operating reasons, if a CO emission limit is finalized. 

Response: Though CO CEMS are not required by the final rule, facilities do have the option to 

install one for reasons not pertaining to the rule.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 33
Comment: Permit compliance stack tests represent an inherently flawed data set for establishing 

CO limits. Facilities are typically required to conduct stack tests while operating at 90 percent of 

full load or greater, and during normal operating conditions. These operating conditions are 

designed to challenge the boiler in at least two areas where state permit authorities have the 

greatest concern regarding boilers: particulate and NOx emissions (CO is not even mentioned in 

wood/oil fired boiler NSPS). These operating conditions virtually ensure peak combustion 

efficiency. Therefore, a CO stack test is going to represent the best CO performance, the lowest 

emission levels, in any boiler. This is widely recognized. EPA has primarily used 3-run stack test 

data from an extremely limited number of sources to develop the proposed area source limit. The 

data collected represent only a small snapshot in time captured during the best operating 

conditions, to set emission limits for a pollutant that is highly variable. Even EPA acknowledges 

this fact in the preamble of the Major Source rule, noting “We believe that single short term 

stack test data (typically a few hours) are probably not indicative of long term emissions 

performance, and so are not the best indicators of performance over time”[ 43 75 FR 32024]. 

In sum, using short-term test data to identify ‘best performers’ and then setting a 24 hour average 

emission limit based on the short-term data suffers from three significant shortcomings: 

1. The majority of the best performers have a single Method 10 test which provides almost no 

information on CO temporal variability. 

2. Short-term tests do not reflect startup, shutdown, or malfunction conditions, nor do they 

capture fluctuations in emissions due to load swings, fuel quality changes, or changes in fuel 

mix. 

3. Best performers should be those units having the lowest long-term average CO emission rates, 

not those with the lowest 3-hour test averages. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 33

Comment: Under the proposal, liquid-fired boilers over 100 MMBTU/hr appear to be required 

to perform initial and annual stack tests and to install and operate CO CEMS. Boilers between 10 

MMBTU/hr and 100 MMBTU/hr are required to perform annual stack tests. We have several 

concerns about these requirements. 

Requiring both stack tests for CO and continuous monitoring is a wasteful and unnecessary 

duplication. One or the other is all that is necessary. The requirement to perform annual CO stack 

tests for boilers where CEMS are required may, in fact, not be what the Agency intended and 

may be an oversight in the drafting of §63.11211(a). In either case, we recommend that 

§63.11211(a) be revised to exclude boilers with CO CEMS. 
Many small area sources have no CEMS expertise (and likely no engineering expertise) available 

onsite or even within the owner’s company. Requiring CEMS and all the associated claptrap or 

annual performance tests imposes an unreasonable burden on these facilities and provisions are 

needed to provide relief in these situations. We do not believe the Agency correctly estimated the 

high ongoing costs associated with the CO CEMS requirements for facilities where there are no 

onsite engineering resources. Meeting the requirements of Appendix B and F of Part 60 

(particularly the RATA requirements) for such units imposes tremendous unconsidered costs, 

when engineering resources must be hired on an hourly basis. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 55

Comment: We support EPA’s decision in §63.11223(e)(6) to exclude data collected from 

sources required to collect CO emission data with CEMS “when your boiler is operating at less 

than 50% of its rated capacity” for calculating data reporting averages. Currently, this 

requirement and therefore this aspect of the rule would only apply to CO emissions from units 

greater than 100 MMBTU/hr. capacities. Boilers with less capacity may have installed CEMS as 

a permit condition and others may do so in the future so this section should be written to clearly 

apply to all units with CO CEMS. Additionally, units with capacity greater than 250 

MMBTU/hr. must install Particulate CEMS devices. 

This exclusion should also apply to those units. We recommend that the language in 

§63.11223(e) be modified to account for smaller units that have installed CO CEMS and units 

required to install PM CEMS. In our separate comments for the Major Source rule, we discuss 

our recommendation against the use of PM CEMS that also applies here (See Section XXIV, 

EPA-HQ-OAR-2002-0058; we incorporate those comments by reference). 

Response: Please see preamble for changes to requirements in final rule, including elimination 

of the CO CEMS requirement.

Commenter Name: Cheryl Sonnier Nolan

Commenter Affiliation: Louisiana Department of Environmental Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2277

Comment Excerpt Number: 4

Comment: CO CEMS 
Existing boilers at Louisiana’s sugar mills would be subject to a CO emission standard. New 

boilers would be subject to a PM standard as well as a more stringent CO standard. Most of the 

boilers at sugar mills operate at greater than 100 MM Btu/hr and, under the proposed subpart, 

would be required to install a CO GEMS. Many mills would therefore be required to install a CO 

GEMS on multiple boilers, which would be extremely burdensome from an economic 

perspective given the seasonal nature of such sources. 

Should EPA improperly conclude that all biomass-fired sources are subject to 40 CFR 63 

Subpart JJJJJJ, EPA should reconsider the need for CO GEMS and provide an alternative means 

to demonstrate compliance with the CO standard short of annual Method 10 stack testing (e.g., 

allow the use of portable analyzers). 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 4

Comment: The proposed CO oil firing emission limits for new/existing sources are 1 ppmvdc 

and 2 ppmvdc, respectively and boilers greater than 100 mmbtu/hr would be required to install 

CO CEMS according to 40 CFR 60 PS-4A. The allowed error for CO according to the 40 CFR 

60 relative accuracy test is a 5 ppm difference between the reference method and facility CO 

CEMS. Considering the reference method can only quality assure data to within 5 ppm, the 

proposed CO limits are indistinguishable from zero. How can a permit limit, under this proposal, 

be set below the allowable deviation in the reference test method? How could this be 

enforceable? 

Considering the limitation with the current EPA reference method (i.e. 40 CFR 60 PS-4A) we 

request that the CO standard be set to nothing lower than 10 ppmvdc, which is twice the allowed 

error of the required relative accuracy test within 40 CFR 60 PS-4A. If EPA is intent on 

implementing a CO emissions limit less than 10 ppmvdc, we believe either 40 CFR 60 PS-4A 

needs to be revised or another monitoring regulation developed and referenced within this 

proposed NESHAP area source boiler regulation that would require the CO CEMS be quality 

assured at a level half the proposed limit. Is EPA currently working on an updated CO 

monitoring regulation for low emission limits in parallel with the development of this regulation? 

Response: Please see preamble for changes to requirements in final rule, including the 

elimination of the CO CEMS requirement.

Commenter Name: Bob Perry
Commenter Affiliation: FirstEnergy Corp

Document Control Number: EPA-HQ-OAR-2006-0790-1959.1

Comment Excerpt Number: 4

Comment: EPA should limit continuous monitoring requirement for CO to boilers greater than 

250 mmbtu/hr having capacity factors greater than 10%. As previously noted, FENOC Industrial 

Boilers operate on a very infrequent basis. In addition to the additional expense of continuous 

CO monitor not being warranted, the lack of run time could seriously hamper compliance with 

the extremely low CO limits. Longer averaging times would be of little value in achieving 

compliance due to low capacity factors. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 5

Comment: According to the Summary of This Proposed Rule Section E, the proposed limits 

have been developed in a method that is consistent with Sierra Club vs. EPA considering EPA 

has established standards in this rule that apply at all times. However, according to Section 

63.11223(e)(6) CO CEMS data is not to be included within the compliance average when a 

boiler is operated at less than 50% of its rated capacity. 

If the intention is to develop a regulation that applies during all operating times then all CO 

CEMS data should be used within the compliance average. Excluding CO CEMS data when a 

boiler is operating less than 50% of its rated capacity does not appear to be inline with the 

concept that the CO emission limits apply during all operating times. We recommend that this 

provision within Section 63.11223(e)(6) be removed and the CO emission limits be reevaluated 

as described within Concerns #1, #2, #6, #7 and #12 of this letter. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Gary Melow

Commenter Affiliation: Michigan Biomass

Document Control Number: EPA-HQ-OAR-2006-0790-1917.1

Comment Excerpt Number: 10
Comment: We have CO CEMs to monitor against emission limits (most being established as 

BACT under PSD). We do not believe that CEMs are reasonable for smaller area sources (<100 

MMBtu/hr) which represent the majority of the source category being regulated here. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Kevin F. Biernacki

Commenter Affiliation: Veolia Energy North America

Document Control Number: EPA-HQ-OAR-2006-0790-2273

Comment Excerpt Number: 12

Comment: A concern of ours is whether or not a unit that has not fired oil in years or does not 

operate regularly over the 50% load threshold would be subject to the rule or required to install 

CO CEMS with the possibility of never having to use the CO CEMS data. We recommend a 

CEMS installation applicability section similar to the recently promulgated 40 CFR 98 

Mandatory Greenhouse Gas Reporting Rule that would take into consideration operating history 

and fuel(s) combusted from a given boiler. For example, including a statement such as: 

“Boilers that are above the rated capacity threshold(s) to install a CO CEMS and have operated 

on a fuel regulated by this rule for more than 1,000 hours in a calendar year since 1/1/2010 are 

required to install a CO CEMS.” 

A statement such as this would help make sure CO CEMS would not be required on boilers that 

would not report data from the CO CEMS in a quantity great enough to justify the costs 

associated with installing and maintaining a CEMS. We also recommend a tiered CO CEMS 

installation requirement such that coal fired boilers >100 mmbtu/hr, biomass boilers >150 

mmbtu/hr and fuel oil firing boilers >200 mmbtu/hr would be required to install CO CEMS 

instead of all boilers >100 mmbtu/hr be required to install CEMS. We recommend the CEMS 

installation be tiered by fuel and size to reflect the higher level of HAPs emitted from coal 

boilers then biomass boilers then fuel oil boilers. Stack testing could be required as an alternative 

compliance method for boilers that do not satisfy additional CO CEMS installation requirements. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 18
Comment: We recommend a more thoughtful CEMS installation applicability section similar to 

the recently promulgated 40 CFR 98 Mandatory Greenhouse Gas Reporting Rule that would take 

into consideration operating history and fuel(s) combusted from a given boiler. For example, 

including a statement such as, 

“Boilers that are above the rated capacity threshold(s) to install a CO CEMS and have operated 

on a fuel regulated by this rule for more than 1,000 hours in a calendar year since 1/1/2010 are 

required to install a CO CEMS.” 

A statement such as this would help make sure CO CEMS would not be required on boilers that 

would not report data from the CO CEMS in a quantity great enough to justify the costs 

associated with installing and maintaining a CEMS. We also recommend a tiered CO CEMS 

installation requirement such that coal fired boilers >100 mmbtu/hr, biomass boilers >150 

mmbtu/hr and fuel oil firing boilers >200 mmbtu/hr would be required to install CO CEMS 

instead of all boilers >100 mmbtu/hr. We recommend the CEMS installation be tiered by fuel 

and size to reflect the higher level of HAPs emitted from coal boilers then biomass boilers then 

fuel oil boilers. Stack testing could be required as an alternative compliance method for boilers 

that do not satisfy additional CO CEMS installation requirements. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 21

Comment: Discuss within the regulation common stack applications and state that under certain 

common stack circumstances CO CEMS installations may not be feasible. Also discuss stack 

structural limitations regarding CEMS installations and whether capital improvements on older 

exhaust stacks would be required to install CEMS. Under these situations, an alternative 

compliance strategy would need to be developed by the site and approved by EPA. An 

alternative may be to allow stack testing of these units even if the boilers are above the size 

limits required to install CEMS considering a facility may be able to shutdown the other 

combustion units for a short compliance testing period or perform stack testing at an alternative 

location that would not be accessible to a CEMS installation. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC
Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 22

Comment: The CO CEMS calculation methodology is not discussed thoroughly enough within 

the proposed rule. 

Include a more detailed CO daily (or 30 operating day) average calculation discussion. For 

example, 

- How many hours are needed to calculate the daily average? We recommend 18 operating hours 

while firing a fuel regulated under this rule to mimic the Pennsylvania Continuous Source 

Monitoring Manual Revision Number 8 that has recently been released. 

- A discussion of what types of data are included in the analysis. For example, for a dual or cofiring unit we assume that natural gas only firing hours would be excluded within the daily 

average and co-firing hours that include a fuel regulated under this rule would be included. 

- We recommend that the diluent cap be allowed and included within the final rule. For example, 

when oxygen levels exceed 14% then 14% O2 would be used in the CO ppmvdc calculation to 

avoid excessive CO ppmvdc values due to startup/shutdown conditions. The diluent cap is 

allowed under 40 CFR 75 and other regulations. 

- If 30-day rolling averages are adopted as a compliance averaging time frame we recommend 

specifying the data include operating days (i.e. operated at least 18 hours) with a data lookback 

time period of three years (i.e. 1095 days). 

Response: Please see preamble for changes to monitoring requirements, and elimination of CO 

CEMS requirement.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 23

Comment: For facilities that operate numerous boilers, we assume time sharing CEMS would be 

allowed if the CEMS installations meet the rules minimum data availability requirements. 

Specifically include mention of time sharing CEMS as an alternative to help facilities minimize 

costs where a given facility operates multiple boilers. Since time-sharing CEMS are not overly 

common, mentioning them within the regulation may allow sources to minimize costs where 

they may not have been aware that time sharing CEMS would be an option. 

Response: Provided the minimum data availability requirements are met, time-sharing of CEMS 

is permissible.

Commenter Name: Jim Simon

Commenter Affiliation: American Sugar Cane League
Document Control Number: EPA-HQ-OAR-2006-0790-2281.1

Comment Excerpt Number: 26

Comment: The Requirement to Install CO CEMS Is Unjustified. 

EPA wisely determined that the cost per unit of a PM CEMS “...would make them an 

unreasonable monitoring option” for boilers at area sources. 75 Fed. Reg. 31910 (June 4, 2010). 

With regard to the requirement to install CO CEMS and conduct annual CO testing, EPA merely 

states that “cost information for CO CEMS provided by commenters on the NESHAP for major 

source boilers” was reviewed. Id. The EPA then concludes that requiring CO CEMS for boilers 

with a heat input capacity of at 100 MMBtu/hour is reasonable. 

The lack of any justification or cost analysis related to the requirement to install CO CEMS at 

area sources suggests that EPA arbitrarily applied conclusions arrived at from its review of data 

collected for major sources. This fact supports the ASCL’s position that the requirement for a 

CO CEMS for boilers located at area sources be removed. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Fred P. Osman

Commenter Affiliation: Osman Environmental Sollutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-2146.1

Comment Excerpt Number: 2

Comment: Secondly, meeting the CO standards on a daily average basis will be very difficult 

for units that have CEMS and have relatively long start-up times. Whatever CO limit EPA 

ultimately publishes will likely be difficult for a biomass boiler to consistently achieve on a daily 

basis, with any available control technology. Units that are equipped with CEMS should be 

allowed to prove compliance with the GACT limit on a 30-day rolling basis to address SSM 

issues. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Frank A. Stanonik

Commenter Affiliation: Air-Conditioning, Heating, and Refrigeration Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2156.1

Comment Excerpt Number: 2

Comment: Even if such designs were possible, to our knowledge the laboratory quality 

instruments used to measure CO are not sufficiently precise to accurately measure 1 ppm. 
Operators at area sources that are purchasing new oil boilers at these lower inputs will be asking 

the boiler manufacturer to provide units that meet these emission limits. But as we noted, those 

products do not exist. 

Response: Please see preamble for changes to the final rule which pertain to this topic.

Commenter Name: Gregory A. Wilkins

Commenter Affiliation: Marathon Petroleum Company, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-2165.1

Comment Excerpt Number: 2

Comment: It is recommended that EPA add clarifying language to the CO CEMS requirement 

to make clearer that CO CEMS are not required for equipment subject to work practice 

standards. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: G. Vinson Hellwig

Commenter Affiliation: Michigan Department of Natural Resources and Environment

Document Control Number: EPA-HQ-OAR-2006-0790-2016.1

Comment Excerpt Number: 2

Comment: In Part 63.11223(e)(6) for boilers with a heat input capacity of 100 MMBtu/hr or 

greater, 

monitoring of CO emissions is required as a surrogate for polycyclic organic matter (POM). The 

proposed rule states that the CO continuous emission monitoring system (CEMS) daily average 

data calculation shall not include "data recorded during periods when your boiler is operating at 

less than 50 percent of its rated capacity." In Michigan it is common for a boiler to be sized to 

provide both process steam and steam for heating the facility during winter. Many boilers are 

operated at less than 50 percent load during warm weather, so the installation and use of a CEMS 

as required in the proposed rule will demonstrate either compliance with the CO limit an 

indication of the POM emissions from these boilers during a large portion of the year. However, 

there will be extended periods where monitoring is not required. 

It is unclear what the reasoning is for dropping the data for a load less than 50 percent. The limits 

are in units of parts per million (ppm), rather than pound per hour (Ib/hr). Mass emissions would 

likely be less at lower loads since less fuel is burned. Concentration of CO is an indicator of 

efficiency (and efficient combustion would be expected to produce lower POM emissions), but 

boiler efficiency is not optimized at loads less than 50 percent. Less efficient combustion, by 

definition, produces higher CO emissions, which is the reason for monitoring the emissions of 

CO. 
When measuring the CO concentration in ppm with a CEMS, a false high indication for CO 

occurs when very low diluent gas concentrations are measured. If low concentration data are 

used to calculate CO in lb/MMBtu emission rates during low capacity operation, mathematically 

the last term in the equation causes the emission rate calculation to approach infinity as the 

measured diluent value approaches a value representative of zero heat input (i.e. 0.0% when 

carbon dioxide (CO2) is the monitored diluent). Thus, during periods of low capacity boiler 

operation, when the heat input and CO2 concentrations are low (or high as would be the case if 

oxygen were being measured), the CO lb/MMBtu emission rates become artificially inflated. 

One solution to this dilemma is to limit the emissions on a mass basis (lb/hr) for periods of low 

capacity boiler operation and to use the GEMS data during other times. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Thomas D. Emero

Commenter Affiliation: Beaver Wood Energy

Document Control Number: EPA-HQ-OAR-2006-0790-2166.1

Comment Excerpt Number: 5

Comment: BWE boilers will be equipped with a CO continuous emissions monitoring system 

(CEMS), which will be subject to federal relative accuracy test audits, thus additional annual 

stack testing is not only redundant but an operating cost that can be avoided while not presenting 

any harm or risk to the environment or human health. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Robert W. Glowinski

Commenter Affiliation: American Wood Council

Document Control Number: EPA-HQ-OAR-2006-0790-1930.1

Comment Excerpt Number: 6

Comment: NCASI analyzed long-term CO CEMS data for three boilers located at wood product 

plants. These three boilers burn similar wood fuels and operate in a similar manner to hundreds 

of other wood-fired boilers found at wood panel plants and sawmills that will become subject to 

the area source boiler rule. The 24-hr and 30-day average CO profiles for these units are 

presented in Appendix A. Daily average CO concentrations computed by the Maine DEP for 

seven wood-fired boilers potentially subject to GACT, all of which were electric generating units 

(EGUs), are also presented in Appendix A. Table 1 [See submittal] summarizes the type of 

boilers, boiler capacities, type of fuels fired, and percent of 24-hr averages that were less than the 

proposed GACT limit of 160 ppm @ 7%O2 for the biomass subcategory. The CO CEMS data 

for the boiler at Mill A were analyzed over two different time periods (A1 and A2). All ten 
boilers had numerous 24-hour averages above the proposed limit. Furthermore, many of the 30-

day rolling averages for each of the three boilers at wood panel plants exceeded 160 ppm. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Richard Rosvold

Commenter Affiliation: Xcel Energy Services, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2259.1

Comment Excerpt Number: 6

Comment: It is unclear why the EPA is requiring that CO measurements for many units be 

corrected to 3% oxygen (02) instead of a more typical 7% 02. Please explain the basisfor the 3% 

02 correction as opposed to 7% 02 as is used in other EPA regulations. Absent valid justification, 

we suggest that a 7% 02 basis be used throughout this rule. 

Response: See the preamble for revisions to the CO limitations and compliance demonstration 

methods.

Commenter Name: Lewis F. Gossett

Commenter Affiliation: South Carolina Manufacturers Alliance

Document Control Number: EPA-HQ-OAR-2006-0790-2196.1

Comment Excerpt Number: 7

Comment: SCMA does not believe that any continuous emission monitoring (such as CEMS) 

can be justified for a boiler that is not a major source of HAP, such as the proposed requirement 

for boilers greater than 100 MMBtu/hr to have CEMS for carbon monoxide (CO), especially 

when CO is just a surrogate for POM and other organic urban HAP. EPA states that they have no 

emission data for POM on coal boilers, but chose CO as the surrogate, assuming that as an 

indicator of incomplete combustion, it would also potentially indicate elevated organic HAP 

emissions. EPA provides no evidence or data to support their assertion that minimizing CO 

emissions through more complete combustion will result in minimizing organic urban HAP 

emissions. EPA should study this further before arbitrarily imposing CEMS on minor area 

sources. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Dan H. Williams

Commenter Affiliation: Sealed Air Corp
Document Control Number: EPA-HQ-OAR-2006-0790-2228.1

Comment Excerpt Number: 10

Comment: A 1 or 2 ppm limit is below the accuracy level of most if not all existing CO CEMS 

and stack test methods. Calibrations are done with an allowable drift for most standards that is 

greater than 2 ppm (5 ppm is allowed by Part 60 Performance Specification 4 for a CO CEM 

spanned at 100 ppm). [Footnote: 100 ppm is a typical CO CEMS span and allows the instrument 

to monitor the most common range of CO concentrations with reasonable accuracy.] For CO 

monitoring, there are no CEMS commercially available that can accurately and predictably 

measure sub-1 ppmv concentrations in the flue gas, thus it is impossible to accurate determine is 

a source is complying with a 1 or 2 ppm standard and there is no way sources can provide a 

compliance margin.. The accuracy of CO CEMS is limited by the equipments ability to precisely 

remove measurement bias and interference, which includes CO2 which is the major component 

of exhaust gas. EPA needs to consider true real world monitoring schemes and recognize 

measurement limitations. 

In addition to CO CEMS having an allowable drift of 5%, calibration gases typically have an 

accuracy of ±2% and there is an accuracy band for sampling and conditioning. Thus, 

measurement uncertainty for a CO CEMS adds up to several percent. Furthermore, the EPA 

Methods used for units without CEMS and for calibrating CO CEMS do not define their 

detection limits, but experience shows that they are not accurate in the low ppm range, adding 

more uncertainty. While people read and report CO results below 1 or 2 ppm, there is little 

certainty associated with the accuracy of those reports. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Robert W. Glowinski

Commenter Affiliation: American Wood Council

Document Control Number: EPA-HQ-OAR-2006-0790-1930.1

Comment Excerpt Number: 13

Comment: While the tendency is to think that further reductions in CO emissions will improve 

the quality of the combustion, and in turn minimize emissions of other organic compounds, this 

is not necessarily true. Instead, forcing CO emissions lower and lower ends up over-constraining 

the combustion process, producing negative impacts on other air quality concerns, without 

documented improvements in emissions of organics. Most boilers are designed to mix fuel and 

air at an appropriate ratio, and to provide sufficient residence time for the fuel to combust 

completely. Obviously, these factors are fuel-dependent, as a gaseous fuel will require less time 

for complete combustion than a liquid fuel, which in turn requires less time to burn than a solid 

fuel. The need for longer residence time is why the radiant sections in solid-fuel fired boilers are 

larger than for gas-fired units. The size of the boiler is typically optimized to allow for complete 

combustion, while minimizing the cost of construction materials. If the construction cost were 
not a concern, a new boiler could be designed with additional residence time to complete the 

combustion process and minimize CO emissions. 

Unfortunately, increasing the size of the furnace is not an option for existing units. For these 

units, the strategy for reducing CO emissions is typically to raise the level of excess oxygen. The 

increase in oxygen concentration has two positive effects. First, it acts to overcome poor 

distribution of the fuel. Second, it increases the flame temperature, which speeds up the 

combustion reactions, allowing more complete combustion to occur for the same residence time. 

However, there are a number of negative impacts associated with operating a boiler at higher 

levels of excess oxygen. Many boilers do not have sufficient fan capacity to run with elevated 

excess oxygen at the high end of the load range. Therefore, these units would effectively be 

derated by such strategy. A site might have to add another boiler to offset the reduction in steam 

generating capacity. 

The minimization of excess oxygen in boiler applications is a key feature for maximizing boiler 

efficiency. The boiler efficiency is defined by the amount of combustion air that is present, and 

the difference between the ambient temperature and the stack exhaust temperature. The more air 

that is heated up through the combustion process, the more heat is lost to the atmosphere, causing 

the boiler to be less efficient. A less efficient boiler will require more fuel to be fired to produce 

a given amount of steam. The additional fuel firing results in higher operating costs, and higher 

greenhouse gas emissions. 

Minimizing the level of excess oxygen is also a primary strategy for reducing NOx emissions 

from a boiler. The NOx formation mechanisms are dependent upon the temperatures in the flame 

zone, and the stoichiometry. Reducing the level of excess oxygen reduces the peak flame 

temperature, which reduces the rate at which the nitrogen in the air dissociates. As such, there is 

less monatomic nitrogen available to be oxidized to form ‘thermal NOx’. Similarly, if there is 

less oxygen present, the monatomic nitrogen is less likely to be oxidized (and more likely to 

react with a second monatomic nitrogen to form diatomic nitrogen). This reduces both the 

amount of thermal NOx, and the ‘fuel NOx’ (NOx that is formed by the release of fuel-bound 

nitrogen). Therefore, increasing the level of excess oxygen will result in higher NOx emissions. 

Low-NOx burner (LNB) designs manipulate the stoichiometry within the flame to minimize 

NOx formation. These designs establish a fuel-rich zone for the initial phase of combustion, and

then add air at a later stage in the outer regions of the flame. In the initial phase, there is not 

sufficient oxygen available to form significant amounts of NOx, and in the secondary phase, the 

flame is much cooler, which also inhibits NOx formation. However, these burners often operate 

with CO emission up to 100 ppmvd in the upper part of the load range. At mid loads, the CO 

begins to increase and at low loads, it may reach 400 ppmvd for a liquid-fired boiler. These lowNOx burners will not be able to achieve CO emissions as low as 2 ppmvd over all operating 

scenarios. 

The requirements of the National Fire Protection Act (NFPA) specify the minimum total air flow 

at which a boiler can operate, which is independent of the boiler load. This value is commonly 

25 or 30 percent of the total air flow. As a result, boilers that are operating at loads less than 25 
percent experience increasing levels of excess air because the fuel flow is decreasing with load, 

but the air flow remains fixed. The amount of excess air can become sufficiently high that it acts 

as a heat sink and reduces the flame temperature. The cooling of the flame slows the combustion 

kinetics, and often produces higher CO emissions. Therefore, low CO emission limits could 

restrict the minimum load capability of a boiler. Since boilers are often run at minimum load

(either in warm standby mode, or due to low steam demand), this results in the boiler ‘idling’ at a 

higher load than was previously necessary. An obvious outcome of operating at higher load is the 

increased fuel costs. Another is the relative increase in greenhouse gas emissions. 

Response: Please see the preamble for a discussion of the standard setting process for CO.

Commenter Name: Robert W. Glowinski

Commenter Affiliation: American Wood Council

Document Control Number: EPA-HQ-OAR-2006-0790-1930.1

Comment Excerpt Number: 15

Comment: The Grayling data is from a year where demand was reduced, mostly running at 

partial load. When running full load, Grayling mixes TDF with the wood, noted on the TDF 

meter reading. When not running TDF, CO will typically be higher. 

Cadillac does not fire TDF. It has a dispatch contract where the utility can run full load or part 

load (part load being a bit under 50% load). Some of the Cadillac data is from part load, although 

that is not indicated on the emission data provided, though it can be done. 

Hillman fires TDF typically but not continuously. 

Viking pulled 1 random day per month for a year since they have an older CEMs/DAS that does 

not import to a spreadsheet. They typically will always be co-firing with TDF and occasionally 

Rail Road Ties. Before TDF and Rail Road Ties were used, their CO ran consistently higher. 

Consequently they always co-fire a drier fuel. 

Response: See the preamble for a discussion of the revised CO emission limits and CO 

compliance mechanisms, which address the commenter’s concerns. We also finalized a solid 

fossil fuel definition that clarifies that TDF is part of the coal/solid fossil fuel subcategory.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 46

Comment: UARG has several concerns regarding EPA’s proposed use of CO CEMS. First, 

EPA’s proposed performance specifications for CO CEMS are not appropriate for use at the

level of some of the proposed CO limits or at certain units. Second, the proposed requirement to 
use oxygen (O2) CEMS to correct CO CEMS data to 3 percent O2 is unduly restrictive. Third, 

EPA’s proposal to treat all periods of CO CEMS downtime as a deviation is not reasonable. 

Finally, the proposed rules do not clearly exempt units with CO CEMS from initial and annual 

performance testing. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 47

Comment: PS 4A was developed primarily for CEMS that comply with emission standards “less 

than 200 ppmv.” 40 C.F.R. Part 60, Appendix B, PS 4A § 1.2.1. In contrast, EPA proposes 

standards ranging from a high of 1,010 ppmv to a low of 1 ppmv (both corrected to 3 percent 

O2). While one could certainly question the reasoning behind applying a specification written for 

low emission standards to some of the proposed standards, UARG’s primary concern is with the 

1 ppmv standard. Applying PS 4A (or any specification) to a limit that low presents many 

problems. The first issue is a simple matter of the technology. Experience with CO analyzers 

suggests that a typical 24-hour drift can be on the order of 1 ppmv. See Attachment B at 2. 

Depending upon the span of the instrument, the allowed drift could be much greater. PS 4A 

allows and anticipates drift of up to 5 percent of the established span value for 6 out of 7 days. 

PS 4A § 13.1. If a CEMS can be expected to drift on a daily basis an amount equal to the 

emission limit, compliance with that limit would certainly be impossible. 

Perhaps more significant, however, are EPA’s expectations for accuracy under the “relative 

accuracy specification.” When EPA developed PS 4A, the Agency recognized the potential 

difficulty in meeting the relative accuracy specification at low levels and included an alternative 

specification. At the time, EPA determined that the lowest achievable relative accuracy standard 

was 5 ppm. PS 4A, § 13.2. Again, expecting sources to determine compliance with a 1 ppm 

standard with a CO CEMS that has allowable error of 5 ppm is not reasonable. In short, while the 

PS 4A drift specification and relative accuracy standard may be achievable, they have little 

relevance in assuring the accuracy of the 1 ppmv measurement EPA’s proposed standard 

requires the CO CEMS to make. And EPA has presented no data to determine the achievability 

of any more stringent performance specifications. 

UARG also is concerned about several other requirements for CO CEMS that may not be 

achievable. PS 4A specifies a response time test protocol (to measure the time it takes to achieve 

95 percent of a stable value) and requires that the response time not exceed 1.5 minutes. When 

measuring low levels of any emission, a common strategy used is to use a longer averaging time 

in the analyzer itself to reduce signal noise. Making CO measurements at 5-10 ppm may require 

an analyzer averaging time in the 3-5 minute range. While the 1.5 minute response time may 

have been achievable for the source categories for which EPA wrote PS 4A, it may not be 
achievable for CO CEMS installed on the tall stacks typical of units owned and operated by 

UARG members due to long sample lines and long sample acquisition time (even with increased 

sample gas pressure and flow rate over those typically used). Nor does UARG understand the 

purpose of this requirement, given that the CEMS are provided a full 15-minutes to complete a 

measurement cycle. Proposed § 63.7525(a)(3). 

Moreover, although EPA does not propose any ongoing quality assurance requirements for CO 

CEMS, other than those established under § 63.8 and the unit’s site-specific monitoring plan at § 

63.7505(d), UARG expects EPA and states to require that those plans include the same types of 

tests found in 40 C.F.R. Part 60, Appendix F, Procedure 1. To ensure that a monitor is measuring 

accurately in the range that includes the emission limit, the CEMS span is usually set at 1.5 to 2 

times the emission limit. See, e.g., PS 4A, § 6.1.2 (addressing dual range analyzers); Attachment 

B at 2. Procedure 1 requires a quarterly cylinder gas audit (“CGA”) to be performed at two audit 

points based on a percent of span (20-30 and 50-60 percent). A CGA also must be performed 

using an audit gas that has been certified by comparison to the National Institute of Standards 

and Technology (“NIST”) or EPA Traceability Protocol 1. Procedure 1, § 5.1.2. The lowest 

NIST-traceable CO audit gas UARG has been able to locate is 5 ppmv. However, a unit that sets 

its CO span at 2 ppm as recommended in PS 4A would need NIST traceable gases of 

approximately 0.5 ppmv and 1 ppmv to meet the CGA requirement. Although EPA presumably 

could waive both the span recommendation and CGA requirement, UARG questions what 

confidence its members could have in the ability of a CO CEMS that does not satisfy those 

criteria to accurately monitor compliance with a 1 ppm standard. EPA must reconsider its 

proposed emission standards and performance evaluation requirements in light of these 

problems. It simply is not possible to comply with EPA’s proposed CO monitoring requirements. 

Attachment B at 2.

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 48

Comment: By choosing O2 as the basis for the correction (instead of CO2), EPA has precluded 

the use of dilution-based monitoring systems, which have become the systems of choice for 

UARG members under EPA’s Acid Rain Program because of their proven accuracy and 

reliability. [Footnote: Dilution systems are often the only reasonable choice for units with wet 

scrubbers because they eliminate plugging and other issues associated with corrosive flue gas 

conditions.] Dilution-based systems measure on a wet basis and can accurately measure CO2, but 

cannot be used to measure O2 because the dilution air contains O2. To allow source 

owners/operators to choose the most accurate and reliable system, and the system with which 

they have the most experience (and can use for compliance with other rules), EPA should 

promulgate alternative standards in lb/mmBtu. Attachment B at 5. In addition, any emission limit 
expressed at any O2 concentration can be directly converted to an equivalent lb/mmBtu limit. 

EPA should promulgate the standards in this fashion to allow sources to choose their preferred 

sampling system and diluent. UARG has previously discussed these conversions and the 

advantages of such standards for boilers in its Petition for Reconsideration of EPA’s 2006 

Standards of Performance for Stationary Combustion Turbines, EPA-HQ-OAR-2004-0490- 0325 

at 11-13 (Sept. 7, 2006) (incorporated by reference). [Footnote: EPA granted that petition on 

December 7, 2006.] 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 61

Comment: For a short term adjustment situation, unit firing and stack conditions will not change 

enough for the stack moisture to vary significantly. Comparing CO measurements on either a wet 

or dry basis, before and after adjustment, is more than adequate to reflect the impact of 

adjustments. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 71

Comment: The proposed IB rule requires units with a heat input capacity ?100 x 106 Btu/hr to 

install, operate, and maintain CO and O2 continuous emission monitoring systems (CEMS). (15 

FR 32055) The O2 analyzer must comply with Performance Specification 3 (PS-3), and the CO 

analyzer with Performance Specification 4A (PS-4A). Unfortunately, PS-4A does not appear 

adequate for many of the proposed CO emission limits. Quoting from PS-4A, [t]his performance 

specification was developed primarily for CEMS that comply with low emission standards (less 

than 200 ppmv). (40 C.F.R. Part 60, Appendix B, Performance Specification 4A, section 1.21.) 

For six of the nine subcategories for new units, EPA has proposed CO limits < 90 ppmv, and for 

five of the nine subcategories for existing units, EPA has proposed CO limits < 90 ppmv. Four 

subcategories (two for new units and two existing for existing units) have proposed CO limits 

equal to 1 ppmv. The proposed 1 ppmv limits present problems from multiple perspectives, not 

the least of which are measurement concerns. Anyone with much experience with a CO analyzer 
knows that the typical 24-hour drift of a CO analyzer is on the order of 1 ppmv. Thus, the 

expected daily drift of the analyzer is about equal to the proposed emission limit. When EPA 

developed PS-4A, the Agency recognized the potential difficulty in meeting the relative accuracy 

specification at low levels because the stack concentration, as measured by the appropriate 

reference method, is in the denominator of the relative accuracy equation. Thus, as the stack 

concentration approaches zero, the computed relative accuracy approaches infinity. EPA 

recognized this problem and included an alternate specification of 5 ppmv when relative 

accuracy is calculated as the absolute average difference between the reference method and 

GEMS plus the 2.5 percent confidence coefficient.5 The problem is that EPA’s current CO 

performance specification permits the analyzer error (relative accuracy) to be a factor equal to 5 

times four of the proposed CO emission limits. 

Although no specific quality assurance requirements are contained in the proposed rule, RMB is 

concerned that EPA might be tempted to simply insert some of the requirements contained in 40 

C.F.R. Part 60, Appendix F in the final lB MACT rule. A number of significant CO monitoring 

issues would occur if EPA were to include the quality assurance requirements in Procedure 1 of 

Appendix F in the final rule. The span of a compliance monitor is typically selected to be 1.5 to 2 

times the emission limit. Procedure 1 requires a quarterly cylinder gas audit (CGA) be 

performed at two audit points: (1) 20 to 30 percent of the span value and (2) 50 to 60 percent of 

the span values. A CGA must be conducted with audit gases that have been certified by 

comparison to National Institute of Standards and Technology (NIST) or EPA Traceability 

Protocol No. 1. Assume for an lB boiler with a 1 ppmv CO limit, we have selected a span equal 

to 2 ppmv. To conduct the quarterly CGA we need NIST-traceable audit gases equal to about (1) 

0.25 x 2 = 0.5 ppmv and (2) 0.5 x 2 = 1 ppmv. The lowest NIST-traceable CO calibration gas 

that RMB has been able to locate is 5 ppmv. Thus, it would not be possible to comply with the 

proposed CO monitoring requirements. 

Another non-trivial issue posed by Procedure 1 is the definition of an "out-of-control" period 

when a calibration drift (CD) is failed. Procedure 1 states the "out-of-control" period is the time 

corresponding to completion of the daily CD check preceding the daily CD check that results in a 

CD in excess of four times the allowable limit.6 In other words, this provision in Procedure 1 

results in data being invalidated retrospectively. The retrospective invalidation of CO data places 

the owner/operator in an untenable situation given the requirement to report any period for which 

the monitoring system is out-of-control as a deviation from the monitoring requirements.7 

Hopefully, EPA’s omission of Procedure 1 from the proposed lB MACT rule was not an 

oversight, but rather a recognition of many of the issues discussed above. RMB encourages EPA 

to continue to allow owner/operators the flexibility in developing site-specific monitoring plans 

that is currently provided for in the proposed rule.8 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.
PM CEMS

Commenter Name: John Huber

Commenter Affiliation: National Oilheat Research Alliance

Document Control Number: EPA-HQ-OAR-2006-0790-1831.1

Comment Excerpt Number: 21

Comment: In the case of heating oil, sulfur content of the fuel and carbon content (soot) from 

poor combustion would dominate particulate emissions and far outweigh metal content in 

emissions. The amount of fuel burned and the metal content of the fuel will determine the 

emissions. PM testing will have no impact on these values. 

Response: The EPA determined it is appropriate to use PM as the surrogate for non-Hg metal 

HAP; see the response to EPA-HQ-OAR-2002-0058-3187.1, excerpt 10. For existing oil boilers 

there is not a PM limit in the final rule, so this will not be an issue.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 50

Comment: EPA’s proposal to use PM CEMS is seriously flawed. First, EPA provides no PM 

CEMS data to support any of its proposed requirements or averaging times. In fact UARG 

doubts that there is any PM CEMS installed and operating on a single unit that is subject to this 

proposed rule. EPA also fails to provide any analysis to justify use of stack test data to set a 

proposed PM CEMS standard. While averaging time can be used to compensate for variability 

not seen in individual stack tests, that adjustment cannot be made by simply arbitrarily selecting 

a longer period (e.g., daily or monthly). Nor is that adjustment sufficient to compensate for the 

differences between the methods themselves (Method 5 and PM CEMS). Second, EPA has failed 

to consider the limitations of PM CEMS in measuring emissions during periods of startup, 

shutdown, and malfunction, which are not conditions under which the PM CEMS are correlated. 

Third, EPA has failed to consider whether PM CEMS can be correlated under PS 11 at the levels 

of EPA’s proposed standards (or whether PM CEMS can even measure such low levels). 

One of the primary challenges in developing PM CEMS standards is the nature of the technology 

itself, which differs significantly from the technology EPA used to establish the numerical 

portion of the PM emission limits. Unlike Method 5, PM CEMS do not provide a direct measure 

of mass PM. Instead, they provide an indirect measure by “correlating” the monitor’s response to 

short term stack tests (e.g., Method 5 tests) conducted over a range of concentrations that must 

be sufficient to include the level of the applicable emission standard. Even at the point of initial 

certification, however, a PM CEMS meeting the criteria in PS 11 can produce responses that 

differ significantly (on the order of 25 percent) from what would be obtained with Method 5. 

Attachment B at 3-4. [Footnote: See also UARG Comments, EPA-HQ-OAR-HQ-OAR-2005-

0031-0246, at 3-10.] An additional point of concern is the lack of information on the long term 
stability of the PS 11 correlations to Method 5 as conditions in the stack gas change over time. 

Unlike SO2 and NOx CEMS, which are challenged on a frequent basis with gases of a known 

concentration, there are no PM calibration gases. See, e.g., PS 11 2.2. As a result, PM CEMS 

responses are reevaluated at much less frequent intervals due to the burdens of Method 5 testing 

(e.g., annually). And, unlike Method 5, PM CEMS sample at a single point, which may not be 

representative of concentrations across the stack of a stratified gas stream. 

Some of the issues with PM CEMS technology might be addressed in the standard setting 

process by setting limits based on PM CEMS data collected at sources representative of the 

range of units subject to the standard, and over a sufficient period of time to ensure that any lack 

of stability in the calibration is taken into account. As EPA previously concluded 

When a PM CEMS is used for compliance monitoring, the PM emission limit that is used as a 

compliance set point should be based on PM CEMS data collected from many representative 

sources over an extended period (e.g., at least 6 months). The accuracy limitations of a PM 

CEMS must also be considered when setting an emission limit. 

UARG Comments on Proposed Standards of Performance for Electric Steam Generating Units 

(Apr. 29, 2005), EPA-HQ-OAR-2005-0031-0129, at 43 (quoting EPA “Current Knowledge of 

Particulate Matter (PM) Continuous Emission Monitoring” (September 2000), A-2001-10-II-A2, 

at 7-2 (emphasis added). UARG has found no evidence that EPA has considered how the 

permissible PM CEMS measurement error might impact compliance determinations under this 

proposed rule. Attachment B at 4. 

EPA’s proposed use of PM CEMS in this rule presents two additional challenges. Because 

EPA’s proposed standard provides no exception for periods of startup, shutdown, or malfunction, 

the standard must be achievable under those conditions as well as the normal operating 

conditions under which stack tests are conducted. According to EPA’s preamble discussion, EPA 

intends to address startup and shutdown by using daily or monthly averages and by establishing 

standards using CEMS data that include periods of startup and shutdown. 75 Fed. Reg. at 32,013. 

Again, since EPA has not identified any PM CEMS data used to establish the proposed 

standards, let alone PM CEMS data that include periods of startup and shutdown, UARG 

assumes that EPA intends to rely solely on averaging time to compensate for the higher emission 

rates expected during those periods. However, EPA has no basis to assume that PM CEMS data 

collected during periods of startup and shutdown will be accurate even within the permissible 

error bands described above, because PM CEMS are not correlated to Method 5 under those 

conditions (nor could they be given the difficulty of performing EPA test methods under such 

non-steady state conditions). 

EPA also has failed to consider the ability of PM CEMS to meet the PS 11 criteria at the levels 

of EPA’s proposed standards, or even the ability of PM CEMS to measure at that level at all. For 

example, although a number of PM CEMS have been installed and operated at coal-fired boilers 

in recent years, UARG is not aware of any instance in which a PM CEMS has been correlated at 

the level of EPA’s proposed standard for new coal-fired boilers (0.001 lb/mmBtu). A PM 

concentration equivalent to that standard -- 1 mg/m3 -- is indistinguishable from zero when 

measured by a PM CEMS. Attachment B at 4. This raises significant issues with respect to PS 11 
correlation. PS 11 requires the owner/operator to attempt to obtain three different PM 

concentrations during correlation testing, and allows use of a zero point in place of one 

concentration if three cannot be achieved. Although PS 11 expresses these concentrations as a 

percent of the “maximum PM concentration,” without an explicit waiver from all applicable 

emission standards no owner/operator can test at a level above the applicable PM emission limit 

(or any other limit that might be exceeded during such testing if related controls, e.g., a wet SO2 

scrubber, must be bypassed or turned off). UARG questions whether it is even conceivable to 

create, much less measure, two PM levels between zero and 1 mg/m3. And, EPA has provided 

no data or discussion to suggest that it is possible. Attachment B at 4. 

In short, EPA has not provided sufficient support for its proposal to use PM CEMS, let alone to 

require their use to make compliance determinations. Even if a source could meet EPA’s PS 11 

correlation criteria at all of the levels EPA has proposed, there is no evidence that EPA’s 

proposed standards sufficiently compensate for the permissible measurement error or for data 

collected during startup, shutdown, or malfunction at either of the averaging periods EPA 

mentions. 

Response: There are no PM CEMS requirements in the standards for area sources.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 72

Comment: EPA’s proposed IB MACT rule requires PM CEMS for compliance demonstration 

for units with heat input capacity greater than 250 x 106 Btu/hr that burn coal, biomass or 

residual oil.9 There are considerably more technical issues with using PM CEMS for compliance 

determinations than EPA apparently realizes. RMB reaches this conclusion based on its review 

of EPA’s response to comments in the recently released Portland Cement MACT rule. In that 

rulemaking, industry commenters raised a number of legitimate technical issues, which EPA 

summarily dismissed with a series of platitudes that were absent either technical support or test 

data. For example, in one response EPA states, in fact, PS-11 and Procedure 2 are working well. 

It would be helpful if EPA provided some "facts" to buttress this statement. 

Unlike conventional CEMS (SO2, NOx, CO2, etc.), PM CEMS do not measure mass directly. 

Rather, PM CEMS measure a parameter such as light scattering or beta attenuation which then 

must be correlated to PM concentration. Just by the very nature of the correlation process, there 

must be some allowable variation between the PM CEMS response and that which is accepted as 

the correct value (i.e., reference method measurement). In other words, the correlation line does 

not pass through all the data points meaning that there is deviation between the PM CEMS 

response and the corresponding reference method measurement. As explained below, the 

allowable deviation is controlled by the statistical criteria imbedded in the EPA performance 

specification. 
On January 12, 2004, EPA published in the Federal Register Performance Specification 11 (PS11), Specification and Test Procedures for Particulate Matter Continuous Emission Monitoring 

Systems at Stationary Sources.1° The principal component of PS-11 is the required correlation 

testing and subsequent correlation analysis. To comply with PS-11, the PM CEMS correlation 

must meet the following statistical criteria: 

The correlation coefficient shall be 0.85. 

The confidence interval (95%) half range at the median PM CEMS response value must be 

within 10% of the PM emission limit value. 

The tolerance interval half range at the median PM CEMS response value must have 95% 

confidence that 75% of all possible values are within 25% of the PM emission limit value. 

As the third bullet item (tolerance interval) indicates, PS-11 allows considerable variation 

between the PM CEMS responses and the individual reference method test values. RMB finds no 

evidence in the rulemaking docket that EPA has considered how permissible PM CEMS 

measurement errors would impact compliance determinations. 

Another important PM CEMS technical issue the Agency appears to have overlooked is an 

assessment of the lowest PM concentration that a PM CEMS can reasonably be expected to 

resolve. PS-11 directs the owner/operator to correlate the PM CEMS to conditions consistent 

with those at which the PM CEMS operates. For example, PS-11 states, if your PM CEMS 

extracts and heats the sample gas to eliminate water droplets, then measures and reports PM 

emissions under those actual conditions, you must convert your reference method results to those 

same conditions (e.g., mg/acm at 160°C)." EPA’s proposed PM emission limit for new coal-fired 

boilers is 0.001 lb/106 Btu. EPA’s proposed emission limit, in units of PM concentration, is on 

the order of 1 mg/m3. In RMB’s considerable experience with PM CEMS installations, we have 

never observed a PM CEMS that could measure a concentration this low. A PM concentration of 

1 mg/m3 is indistinguishable from zero, or for that matter, 2 mg/m3 with a PM CEMS. 

PS-11 requires the owner/operator to attempt to obtain three different PM concentrations at 

which to conduct the correlation testing.12 

Level 1: from zero to 50 percent of the maximum PM concentration. 

Level 2: 25 to 75 percent of the maximum PM concentration. 

Level 3: 50 to 100 percent of the maximum PM concentration. 

PS-11 is silent with respect to defining "maximum PM concentration," but it is safe to assume 

that no responsible owner/operator is going to deliberately exceed the allowable PM limit Thus, 

for discussing new coal-fired units, 1 mg/m3 would be the maximum PM concentration. There is 

absolutely no conceivable way to create, much less to measure, two PM levels between zero and 

1 mg/m3. There is a second option if you cannot obtain the three distinct PM concentration 

levels. PS-11 allows you to test over "the maximum range of PM concentrations that is practical" 

and to add zero point data through either of several optional approaches.13 As stated above, 
there simply is no range between zero and 1 mg/m3. It is virtually impossible for a PM CEMS to 

comply with PS-11 when the PM emission limit is 0.001 lb/106 Btu. 

Response: There are no PM CEMS requirements in the standards for area sources.

COMS (opacity)

Commenter Name: Rob Barton and Ralph Roberson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2006-0790-1978.1

Comment Excerpt Number: 14

Comment: EPA has specified the use of a continuous opacity monitoring system (COMS) with 

an opacity operating limit of 10% (based on a daily block average) for sources equipped with a 

baghouse or ESP. While the proposed 10% limit might be suitable as a default value, EPA 

should allow sources the option of establishing an alternative opacity operating limit for those 

sources than can not meet the proposed limit due to stack size or fuel-related issues. This would 

also allow some sources additional operating flexibility while still providing a reasonable 

assurance of compliance with the underlying emission limits. 

Response: Please see DCN EPA-HQ-OAR-2006-0790-1959.1, Comment Excerpt Number 18.

Commenter Name: Arthur N. Marin

Commenter Affiliation: Northeast States for Coordinated Air Use Management, NESCAUM

Document Control Number: EPA-HQ-OAR-2006-0790-2137.1

Comment Excerpt Number: 26

Comment: It is our understanding that the proposed rules require installing an opacity monitor, 

if any facility installs an ESP in order to meet a 10% opacity limit on a daily basis, with no de 

minimus threshold. Additionally, if a facility installs a fabric filter, it would be required to install 

an opacity monitor or a broken bag leak detector, with no de minimus threshold. We recommend 

that EPA require opacity monitors only on units larger than 30 mmBtu/hr. 

Response: In the final rule, opacity or parameter monitoring is required for certain boilers above 

10 mmBtu/hour capacity. 

Commenter Name: Gary Melow

Commenter Affiliation: Michigan Biomass

Document Control Number: EPA-HQ-OAR-2006-0790-1917.1
Comment Excerpt Number: 13

Comment: Additionally, EPA could consider that wood, coal, and oil boilers over 30 MMBtu/hr 

are required by NSPS Dc to install and operate continuous opacity monitors (exception, light 

distillate oil fired boilers). Poor combustion conditions in solid fuel boilers will result in excess 

opacity. Smaller boilers generally have simple particulate matter control systems that are easily 

overwhelmed when combustion conditions are poor. EPA could consider the use of continuous 

opacity monitors as a work practice for solid fuel boilers over 30 MMBtu/hr as a method to 

ensure good combustion in these boilers. 

Response: Please see preamble for changes to the requirements in the final rule.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 18

Comment: Under EPA’s proposal, units that do not use a wet scrubber (e.g., units with no 

controls or with a dry scrubber) must comply with an opacity limit of 10 percent based on a daily 

block average. Proposed 63.7500(a)(2) and Tables 4 and 8.[Footnote: Source owners/operators 

can apply to the Administrator for approval of an “alternative opacity emission limit” under 

63.6(h)(9). Proposed 63.7570(b)(2).] 

Although opacity can be used as an “indicator” of particulate emissions, or as a trigger to initiate 

corrective action on an ESP, there is not a sufficiently direct correlation between opacity and PM 

or Hg to justify imposition of an enforceable limit. 

For example, it is well known that the relationship between opacity and mass PM (i.e., mass 

concentration) is affected by the particulate size distribution, particle shape, and the color 

(reflectivity) of the flyash. Numerous tests have confirmed that western subbituminous coal ash 

creates considerable opacity at very low fuel gas particulate mass loading, while eastern 

bituminous coal has a higher opacity/mass relationship. Duke Energy’s experience is that opacity 

and particulate emission rates vary even when using bituminous coal from different vendors. 

Given these and other variables, the relationship simply is not sufficient to make assumptions 

based on the proposed opacity operating limit that the PM limit is not being met. The use of 

opacity as an operating limit for mercury (“Hg”) is even more problematic. Mercury is emitted 

from boilers in three forms - particle bound, oxidized, and elemental. Even if opacity were 

directly related to PM (which it is not), it would only be sensitive to particle bound Hg. Oxidized 

and elemental Hg cannot be detected at all by an opacity monitor. EPA has not adequately 

explained how this tenuous relationship can justify use of opacity as a limit that could create 

liability for violation of the Hg emission limit. 
In summary, while opacity is a useful indicator of ESP problems that should be investigated and 

corrected, ESP power is not, and the relationship between opacity to stack emissions of PM and 

Hg is not sufficient to conclude that the emission limit is being exceeded. 

Response: We believe that continuous monitoring is needed to ensure ongoing compliance with 

this rule. In order to minimize costs, we look for parameters that are already monitored to use for 

compliance demonstration. We require performance tests to demonstrate compliance with 

emission limits, then use operating limits to ensure the source is operating similarly to how it 

was operating when it completed a successful performance test. Under the final rule, we clarify 

that tests are to be performed under representative operating conditions. Also, operating limits 

are not direct measures of emissions, but provide measure of fuel characteristics and control 

device performance. We have also provided for scaling certain parameters such as sorbent 

injection rate based on the operating load, to address load conditions that are less than those that 

occur during testing. You are also able to petition the Administrator for approval of an 

alternative monitoring plan under section §63.8(f) of subpart A of part 63.

Commenter Name: Bob Perry

Commenter Affiliation: FirstEnergy Corp

Document Control Number: EPA-HQ-OAR-2006-0790-1959.1

Comment Excerpt Number: 18

Comment: EPA has specified the use of a continuous opacity monitoring system (COMS) with 

an opacity operating limit of 10% (based on a daily block average) for sources equipped with a 

baghouse or ESP. While the proposed 10% limit might be suitable as a default value, EPA 

should allow sources the option of establishing an alternative opacity operating limit for those 

sources than can not meet the proposed limit due to stack size or fuel-related issues. This would 

also allow some sources additional operating flexibility while still providing a reasonable 

assurance of compliance with the underlying emission limits. 

Response: The general provisions in Part 63 provide a mechanism for a source to seek an 

alternative opacity limit based on site-specific issues.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 27

Comment: In Cases Where EPA is Mandating the Use of PM monitors, it Should Give Sources 

the Ability to Delete Opacity Monitoring Requirements 

In cases where PM monitoring is required, Duke Energy strongly recommends that EPA allow 

sources with current opacity monitoring requirements to supersede those requirements where 
they are required to install PM monitors. The source need simply demonstrate that the new 

particulate limit is more stringent than the existing opacity limits. Duke Energy feels that this is 

an excellent example of regulatory flexibility. Moreover, sites should not be put in a position of 

“double jeopardy” by having to measure and report against both. 

Response: This issue is not relevant to area source standards, where PM CEMS is not required.

Commenter Name: Rob Barton

Commenter Affiliation: RMB Consulting and Research, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2198.1

Comment Excerpt Number: 12

Comment: Continuous Compliance Procedures Should Include Option for Alternative UnitSpecific Opacity Operating Limit 

EPA has specified the use of a continuous opacity monitoring system (COMS) with an opacity 

operating limit of 10% (based on a daily block average) for sources equipped with a baghouse or 

ESP. While the proposed 10% limit might be suitable as a default value, EPA should allow 

sources the option of establishing an alternative opacity operating limit for those sources than 

can not meet the proposed limit due to stack size or fuel-related issues. This would also allow 

some sources additional operating flexibility while still providing a reasonable assurance of 

compliance with the underlying emission limits. 

Response: Please see DCN EPA-HQ-OAR-2006-0790-1959.1, Comment Excerpt Number 18.

Averaging Times for Monitored Pollutants

Commenter Name: Harry Dresser, Jr.

Commenter Affiliation: Maine Energy Systems

Document Control Number: EPA-HQ-OAR-2006-0790-1060.1

Comment Excerpt Number: 5

Comment: It is recommended that both tests be conducted over a 24 hour test period during 

which full load operation is demanded at least 10% of the test period and turn down rates do not 

go below one-third of full load. 

Response: See the changes to the emission limit and monitoring requirements discussed in the 

preamble to the final rule.
Commenter Name: Michael J. Hagenbarth

Commenter Affiliation: RockTenn

Document Control Number: EPA-HQ-OAR-2006-0790-1473.1

Comment Excerpt Number: 10

Comment: EPA’s variability analysis also is magnified by the fact that 3-hour testing data are 

used to set standards with far longer averaging times. Thus, there is a fundamental disconnect 

between the form of the data used to determine the standard and the form of the standard itself. 

We support longer averaging times than proposed in the Area Source Rule, and these standards 

should be based on emissions data collected over comparable periods. Any emissions limits set 

for CO should be based on a 30-day averaging period to accommodate the significant variability 

in CO emissions reflected in long term CO monitoring data. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Russell A. Wozniak

Commenter Affiliation: The Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2006-0790-1766.1

Comment Excerpt Number: 3

Comment: EPA proposes to use a daily averaging time for the carbon monoxide emission limits 

for New Oil and Existing Oil fired boilers in Table 1 to Subpart JJJJJJ of the proposed rule. 

At a minimum, EPA should establish either a 30 day or an annual average period in cases where 

a CO CEMS is utilized to demonstrate compliance. Using a 30 day averaging period is consistent 

with EPA’s proposed MACT rule. This GACT rule should not be more stringent than the MACT 

requirements for the oil subcategory. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Kerry Flick

Commenter Affiliation: Metso Power

Document Control Number: EPA-HQ-OAR-2006-0790-1490.1

Comment Excerpt Number: 8

Comment: Over a sufficient period of time it is reasonable to expect the emissions average to be 

stable. Our experience would suggest that not less than 30 days should be considered a 

reasonable period for this purpose. 
Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 25

Comment: EPA should clarify why the Proposed Rule allows one hour sampling time for PM 

and two-hour sampling time for mercury while the Proposed Boiler MACT Rule requires four 

hour sampling time. 

Response: We agree with commenters that the rule must clarify minimum sample volumes and 

assure that the specifications are consistent between test methods and with the method 

capabilities. The correct approach to measuring low quantities of emissions is to specify 

collection of a minimum sample volume that assures accuracy sufficient to determine 

compliance at the level of the emissions standard 

In response, the final rule will specify that the test run durations will be consistent with the 

methods prescribed procedures. For PM Methods, Method 29, and for the ASTM D6784-02, 

applications will be 3 dscm, consistent with the methods prescribed procedures. One may collect 

4 dscm in 3 to 4 hours of testing with Method 29 or with Method 5.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 28

Comment: EPA has established averaging times requirements that cannot be met by a top

performing unit over a range of operating conditions. EPA should provide longer averaging 

times for certain parameters and emissions. Additionally, EPA should adopt a 30-day averaging 

period for CO as it has done in the Proposed Boiler MACT Rule. See generally 75 FR 32006. 

For a comprehensive discussion of averaging times, please refer to CIBO’s comments on the 

Proposed Boiler MACT Rule. [See DCN: 2006-0790-1783.2 for related comments.] 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO
Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 48

Comment: EPA has proposed monitoring of CO limits on a daily average in all cases. EPA 

should change this requirement so that compliance is done on a 30-day rolling average for CO 

CEMS. Costs are another issue when considering CEMS for area sources. EPA estimates capital 

costs of requiring PM CEMS to area source boilers to be $88,000 per unit and annualized costs 

of $33,000 per unit, with a total annual cost of $4.5 billion. 75 FR 31910. EPA has determined 

these costs were unreasonable. As stated in CIBO’s comments on the Proposed Boiler MACT 

Rule, EPA should amend the final rule to include parameter monitoring or visible emissions 

observations instead of CEMS and COMS. [See DCN: 2006-0790-1783.2 for related comments.] 

If CO CEMS or COMS requirements remain, final rule language should be made clear that use 

of those is only required "if you have an applicable opacity limit under this rule,..." or "if you 

have an applicable CO limit under this rule and your boiler..." so that the requirement is only 

related to limits imposed under this rule and not related to any other requirements the unit might 

be subject to. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Douglas J. Fulle

Commenter Affiliation: Oglethorpe Power Corporation

Document Control Number: EPA-HQ-OAR-2006-0790-1798.1

Comment Excerpt Number: 6

Comment: EPA should consider extending the averaging period for the CO standard to a 30-day 

rolling average, as proposed in the major source category. Under this approach, EPA could use 

the available CO CEMS data for an appropriate well-performing area source biomass unit to set 

the standard. This would assure that the form of the standard was entirely consistent with the 

underlying data used to set the standard. The proposed rule is flawed in this regard because it 

inappropriately sets a daily average emissions standard based on data derived from emissions 

test, which typically have duration of only a few hours. A 30-day rolling average would provide 

the same overall level of health and environmental protection as the proposed daily average, yet 

would accommodate normal emissions variability that might span a period of days rather than a 

period of hours. 

For example, it is reasonable to assume that certain affected units would run at reduced load for a 

period of days. Basic engineering principles suggest that, beyond a certain point, combustion 

conditions should be expected to deteriorate as load decreases, which would result in relatively 

higher CO emissions. The CO CEMS data included in EPA’s database, when correlated against 

firing rate, demonstrate this to be the case. Thus, a 30-day average would accommodate the 

higher CO emissions from a short period of low-load operations -assuming, of course, that there 

is a sufficient period of operations at higher loads to balance out the low-load operations. 
If the EPA can validate that the relevant CO CEMS data also include representative numbers and 

periods of startups and shutdowns, setting a 30-day average may preclude the need to set a 

separate standard for startup and shutdown. EPA must be careful if it takes this approach, 

however, to make absolutely sure that the emissions data reasonably reflect and reasonably 

anticipate startup and shutdown periods. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Renee Lesjak Bashel

Commenter Affiliation: Small Business Environmental Assistance Programs, SBEAP

Document Control Number: EPA-HQ-OAR-2006-0790-2195.1

Comment Excerpt Number: 5

Comment: This area source NESHAP sets a CO limit based on a “daily average” while the 

major source boiler 

NESHAP allows “30 day rolling average for units 100 MMBTU/hr or greater, 3-run average for 

units less 

than 100 MMBTU/hr”. The “daily average” calculation is very difficult to manage no matter 

what size 

operation, but most particularly at small operations. And it also is more difficult to maintain a 

daily 

average when taking into account fluctuations in boiler operations from one day to the next. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 28

Comment: Averaging times of longer than 24 hours are needed for CO emissions from 

industrial boilers, especially those in the forest products industry that burn multiple fuels which 

have varying emissions characteristics, in order to preserve operational flexibility and ensure 

cost-efficient operation of the boiler. The facility must be able to operate the boiler in a manner 

that is responsive to process needs. Unlike a utility boiler, which is typically operated at a full 

load or without short term cycling, industrial and commercial boilers are typically operated with 

swings in demand, based on production in manufacturing and building usage for commercial 

operations. Swings in load cause variability in CO emissions and longer averaging times are 

needed in order to average out unavoidable instantaneous CO emission shifts. Longer averaging 
periods are also desirable if the emission limits are going to apply at all times, including periods 

of startup, shutdown, and malfunction. 

There are factors beyond the boiler operator’s control that can cause emissions to vary over a 

period of days and not hours. For example, the weather will impact moisture content of solid 

fuels, which will affect how the fuels combust over a period of days, 

not hours. For a biomass boiler, the fuel supply and fuel characteristics could also vary over a 

period of days because mills have multiple biomass fuel suppliers providing both green and dry 

wood. This issue is discussed further below in Section VII A. For EPA to promulgate a 

numerical CO standard, particularly one where CEMS is a compliance requirement, a 30-day 

averaging period to account for operational and emissions variability in biomass units is 

imperative. Such an averaging period was not evaluated or considered in this proposal and EPA. 

Since EPA has not developed a dataset to allow it to repair this and other fundamental 

achievability flaws in the limited time period EPA has been given to promulgate this standard, it 

reinforces the recommendation we are making here to proceed in the direction of a GACT rule 

that 

refines and develops management or work practices in order to reduce HAP emissions from Area 

Source boilers. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Mary Graham

Commenter Affiliation: Charles Metro Chamber of Commerce

Document Control Number: EPA-HQ-OAR-2006-0790-1953.1

Comment Excerpt Number: 6

Comment: If EPA decides that a numeric standard is needed, the Agency should rely on the 

available long term data from the better performing area source boilers to establish a standard 

with a reasonably long averaging time (such as a 30-day rolling average), rather than the 

proposed 24-hour averaging time. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Kevin F. Biernacki

Commenter Affiliation: Veolia Energy North America

Document Control Number: EPA-HQ-OAR-2006-0790-2273

Comment Excerpt Number: 8

Comment: We believe the CO ppmvdc emissions limit magnitude needs to be reevaluated and 

increased. To help with the concept of applying a single limit to a facility that changes load 
regularly we recommend increasing the compliance averaging time frame for facilities required 

to show compliance with the emissions limit using CEMS to a 30 operating day rolling average. 

Importantly, the average would be over 30 operating days instead of calendar days. Using 

operating days would allow facilities the most operating flexibility to satisfy the emissions limit 

without being forced to operate units (therefore unnecessarily adding to air pollution concerns) 

unnecessarily to satisfy an emission limit that would be based on 30 calendar days. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 11

Comment: To help with the concept of applying a single limit to a facility that changes load 

regularly we recommend increasing the compliance averaging time frame for facilities required 

to show compliance with the emissions limit using CEMS to a 30 operating day rolling average. 

Importantly, the average would be over 30 operating days instead of calendar days. Using 

operating days would allow facilities the most operating flexibility to satisfy the emissions limit 

without being forced to operate units (therefore unnecessarily adding to air pollution concerns) 

unnecessarily to satisfy an emission limit that would be based on 30 calendar days. We are 

unclear of the documented health benefits that would justify a daily compliance time frame in 

lieu of a 30 operating day compliance time frame. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Robert R. Scott

Commenter Affiliation: New Hampshire Department of Environmental Services

Document Control Number: EPA-HQ-OAR-2006-0790-1952.1

Comment Excerpt Number: 12

Comment: There is significant variation in the amount and duration of startup, shutdown and 

malfunction (SSM) emissions for various fuels. NIIDES anticipates that variations in SSM 

emissions would be greater for boilers firing solid fuels such as biomass, than for boilers firing 

liquid fuels such as heating oil. NHDES recommends that EPA consider setting 30-day 

averaging times for solid fuel boilers. 

Response: Please see preamble for discussion on the SSM requirements.
Commenter Name: Sarah E. Amick

Commenter Affiliation: Rubber Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1918.1

Comment Excerpt Number: 16

Comment: EPA’s variability analysis also is magnified by the fact that 3-hour testing data are 

used to set standards with far longer averaging times. Thus, there is a fundamental disconnect 

between the form of the data used to determine the standard and the form of the standard itself. 

We support longer averaging times than proposed in the Area Source Rule, and these standards 

should be based on emissions data collected over comparable periods. Any emissions limits set 

for CO should be based on a 30-day averaging period to accommodate the significant variability 

in CO emissions reflected in long term CO monitoring data. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Jim Simon

Commenter Affiliation: American Sugar Cane League

Document Control Number: EPA-HQ-OAR-2006-0790-2281.1

Comment Excerpt Number: 27

Comment: The CO CEMS averaging time required for area source boilers is daily and the 

averaging time required for major source boilers is a rolling 30-day period. Because emission 

spikes can be statistically absorbed during a 30-day averaging period, the daily averaging time is 

considered more stringent. Creating more stringent averaging periods for boilers operating at an 

area source is not justified. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 5

Comment: The EPA has established violation thresholds for operating limits for section 112(d) 

source categories such as those found in 63.864(k)(2), 63.848(i), and 63.695(e)(5). This rule 

needs to clearly identify when boilers are in violation of the standards when operating parameters 

used to demonstrate continuous compliance are not met. Also, the EPA proposes the use of 

continuous opacity monitoring systems (COMS) and continuous parameter monitoring systems 

(CPMS) for certain affected boilers to demonstrate continuous compliance with the standards. 
The rule needs to include a percentage of time during a 6-month period that these continuous 

monitoring systems (CMS) are required to be operational and meet any operating limit in order 

to determine compliance. 

Response: The rule establishes that failure to meet a monitored emission limit, work practice 

requirement, or operating limit constitutes a deviation. As for continuous monitoring system data 

availability requirements, the final rule includes revisions to the general requirements for 

operating continuous monitoring systems that addresses this concern. We have not included any 

specific minimum data availability requirement. We believe that numerical missing data 

allowances quickly become targets or excuses, not incentives to conduct monitoring in a manner 

consistent with good air pollution control practices. For all monitoring required or applied as an 

option under this rule, we have included provisions that would require you to operate the 

monitoring system and collect data at all required intervals at all times the affected source is 

operating except for periods of monitoring system malfunctions, repairs associated with 

monitoring system malfunctions, and required monitoring system quality assurance or quality 

control activities (including, as applicable, calibration checks and required zero and span 

adjustments). Further, you may not use data recorded during monitoring system malfunctions, 

repairs associated with monitoring system malfunctions, or required monitoring system quality 

assurance or control activities in calculations used to report emissions or operating levels. A 

monitoring system malfunction is any sudden, infrequent, not reasonably preventable failure of 

the monitoring system to provide valid data. Monitoring system failures that are caused in part 

by poor maintenance or careless operation are not malfunctions. You must use all the data 

collected during all other periods in assessing the operation of the control device and associated 

control system. 

Commenter Name: George M. Israel

Commenter Affiliation: Georgia Chamber of Commerce

Document Control Number: EPA-HQ-OAR-2006-0790-1996.1

Comment Excerpt Number: 6

Comment: I strongly encourage you to correct this problem by carefully tailored standards that 

protect against the ill effects of air toxics, while not unnecessarily discouraging the construction 

of much needed renewable biomass boilers. This can be accomplished by using a 30-day 

averaging period instead of the proposed 24-hour or simply use the same “work practices” 

approach applied to gas-fired boilers already include in the proposed rule. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Duane Mummert

Commenter Affiliation: South Carolina Chamber of Commerce
Document Control Number: EPA-HQ-OAR-2006-0790-2247

Comment Excerpt Number: 6

Comment: The ETC suggests that a work practice standard is most appropriate due to the lack 

of relevant data and the fact that an emission testing during startup is not technically and 

economically practicable. If EPA decides that a numeric standard is needed, the Agency should 

rely on the available long term data from the better performing area source boilers to establish a 

standard with a reasonably long averaging time (such as a 30-day rolling average), rather than 

the proposed 24-hour averaging time. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Charles B. Jones, III

Commenter Affiliation: Georgia Traditional Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1923.1

Comment Excerpt Number: 7

Comment: The rules should include an emission averaging compliance option in order to 

enhance compliance flexibility and to improve consistency between the Area and Major Source 

Boiler rules (e.g., a 30-day averaging period for the carbon monoxide emission limit for solid 

fuel boilers). 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Thomas D. Emero

Commenter Affiliation: Beaver Wood Energy

Document Control Number: EPA-HQ-OAR-2006-0790-2166.1

Comment Excerpt Number: 7

Comment: BWE suggests EPA re-consider the requirement for compliance with the CO limit to 

be demonstrated on a daily average and would prefer the 30 day rolling average afforded boilers 

of the same size under the proposed Major Source rule. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: John Hopewell

Commenter Affiliation: American Coatings Association
Document Control Number: EPA-HQ-OAR-2006-0790-2062.1

Comment Excerpt Number: 8

Comment: Rolling Averages for CEMS Should be the Same for Both Boiler Rules. In the 

companion Major Source NESHAP proposal, 8 EPA specifies a 30-day rolling average for units 

that have a CEMS (i.e. units with 100 MMBTU/hour or greater capacity). However, in the Area 

Source NESHAP, EPA has proposed a daily rolling average. EPA should make the Area Source 

NESHAP consistent with the Major Source NESHA P and specify a 30-day rolling average for 

units with a CEMS. 

Response: The final rule uses a 30-day average for monitoring O2 as an operating limit for 

good combustion practices to minimize CO emissions, consistent with the major source 

NESHAP.

Commenter Name: Kevin M. Dempsey

Commenter Affiliation: American Iron and Steel Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2061

Comment Excerpt Number: 12

Comment: EPA’s variability analysis also is magnified by the fact that 3-hour testing data are 

used to set standards with far longer averaging times. Thus, there is a fundamental disconnect 

between the form of the data used to determine the standard and the form of the standard itself. 

We support longer averaging times than proposed in the Area Source Rule, and these standards 

should be based on emissions data collected over comparable periods. Any emissions limits set 

for CO should be based on a 30-day averaging period to accommodate the significant variability 

in CO emissions reflected in long term CO monitoring data. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Rob Barton

Commenter Affiliation: RMB Consulting and Research

Document Control Number: EPA-HQ-OAR-2006-0790-2140.1

Comment Excerpt Number: 12

Comment: EPA has specified the use of a continuous opacity monitoring system (COMS) with 

an opacity operating limit of 10% (based on a daily block average) for sources equipped with a 

baghouse or ESP. While the proposed 10% limit might be suitable as a default value, EPA 

should allow sources the option of establishing an alternative opacity operating limit for those 

sources than can not meet the proposed limit due to stack size or fuel-related issues. This would 

also allow some sources additional operating flexibility while still providing a reasonable 

assurance of compliance with the underlying emission limits. 
Response: Please see DCN EPA-HQ-OAR-2006-0790-1959.1, Comment Excerpt Number 18.

Commenter Name: Wayne J. Galler

Commenter Affiliation: Georgia Industry Environmental Coalition, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1997.1

Comment Excerpt Number: 17

Comment: EPA’s variability analysis also is magnified by the fact that 3-hour testing data are 

used to set standards with far longer averaging times. Thus, there is a fundamental disconnect 

between the form of the data used to determine the standard and the form of the standard itself. 

GIEC would support longer averaging times than proposed in the Area Source Rule, and these 

standards should be based on emissions data collected over comparable periods. Any emissions 

limits set for CO should be based on a 30-day averaging period to accommodate the significant 

variability in CO emissions reflected in long term CO monitoring data. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Bruce A. Steiner

Commenter Affiliation: American Coke and Coal Chemicals Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2007

Comment Excerpt Number: 20

Comment: EPA’s variability analysis also is magnified by the fact that 3-hour testing data are 

used to set standards with far longer averaging times. Thus, there is a fundamental disconnect 

between the form of the data used to determine the standard and the form of the standard itself. 

We support longer averaging times than proposed in the Area Source Rule, and these standards 

should be based on emissions data collected over comparable periods. Any emissions limits set 

for CO should be based on a 30-day averaging period to accommodate the significant variability 

in CO emissions reflected in long term CO monitoring data. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 48
Comment: Where a COMS or CO CEMS is used, a daily block average is specified, but EPA 

should incorporate a 30-day rolling averaging period under this rule, as it has done for CO 

CEMS in the proposed Boiler MACT rule. There are factors beyond the boiler operator’s control 

that can cause emissions to vary over a period of days and not hours. For example, the weather 

will impact moisture content of solid fuels, which will affect how the fuels combust over a 

period of days, not hours. For a biomass boiler, the fuel supply and fuel characteristics could also 

vary over a period of days because facilities have multiple biomass fuel suppliers providing both 

green and dry wood. For all types of boilers, the pollutant content of the fuel will vary over a 

period of days, as evidenced by the range of results obtained during the 30-day fuel sampling 

required by EPA for many Phase 2 ICR participants. Where CEMS are the compliance method 

(e.g., CO), we support a 30-day rolling average basis to account for operational and emissions 

variability. 

Response: Because CO CEMS are no longer required in the final rule, this concern is no longer 

applicable. For a COMS, both rules use a daily block average.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 63

Comment: Proposed section 63.7525(b)(3) states, compliance with the applicable emission limit 

shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average 

emission concentrations using the continuous monitoring system outlet data. This is totally 

unacceptable and certainly has not been demonstrated to be achievable on any one of several 

levels. It is also inconsistent with a statement in the preamble, which states . . . we are proposing 

that PM CEMS be installed and operated and that PM levels (monthly average) be maintained 

below the applicable PM limit." 

It is not at all certain that the proposed PM emission limits are continuously achievable. After all, 

the numerical limits are based on snapshot tests, and we question whether long-term variability is 

accurately reflected in EPA’s standard setting approach. Perhaps more importantly, the 

rulemaking record contains no analysis in which EPA purports to equate the snapshot PM stack 

testing data to continuous PM CEMS data. For example, EPA might be able to show that the 

numerical limit, which is enforced through periodic stack testing, would be of the same 

stringency as the limit enforced with continuous data on a 30-day rolling average basis. Second, 

Response: PM CEMS are not required under this rule.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1
Comment Excerpt Number: 73

Comment: Proposed section 63.7525(b)(6) states, when PM emissions data are not obtained 

because of CEMS breakdown, . . . emission data shall be obtained by using other monitoring 

methods as approved by the Administrator . . . to provide, as necessary, valid emission data for 

all operating hours per 30-day rolling average [emphasis added]. It is unprecedented to require 

emission data to be collected for all operating hours to demonstrate compliance with a numerical 

emission limit Granted, cap-and-trade programs, which are based on mass emissions, require 

accounting for each operating hours. However, programs such as EPA’s Acid Rain Program 

contain procedures for filling in missing CEMS data (i.e., missing data substitution algorithms) 

and do not mandate alternative or back-up data collection methods. Also note that a 30-day 

rolling average is references in this section, which is inconsistent with proposed §63.7525(b)(3), 

as discussed above. 

Response: PM CEMS are not required under this rule.

Fuel Analysis Methods

Commenter Name: William H. Carlson

Commenter Affiliation: Carlson Small Power Consultants

Document Control Number: EPA-HQ-OAR-2006-0790-1493.1

Comment Excerpt Number: 11

Comment: In reality, both emissions of metallic and non-metallic HAP’s from biomass 

combustion are a function of the fuel, not the combustion process or even the pollution control 

devices. EPA should focus on the fuel, both generically and specifically by facility. An 

individual facility should be able to provide extensive test data of its fuel to demonstrate that it is 

not a significant source of HAP’s, and thus is exempt from this entire regulation. It would not 

just be exempt from Hg or HCl testing as a result, but from the entire PM/CO proxy compliance 

program. Alternatively, a facility could accept restrictions in its air quality permits on taking 

certain types of fuels known to have HAP’s consequences (e.g. salt water soaked bark) and step 

up to CO/PM compliance if the economics dictate. 

Response: EPA thanks the commenter for their input. EPA is not providing the option of testing 

HAPs to become exempt, however, the only limit in the final Area Boiler rule for biomass units 

is a PM limit for new biomass boilers.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 39
Comment: EPA has provided in the Proposed Rule that certain new and existing area source 

boilers may choose to demonstrate compliance with emission standards on the basis of fuel 

analysis. 75 FR 31902. For a comprehensive discussion of our recommendations regarding fuel 

analysis, please refer to CIBO’s comments on the Proposed Boiler MACT Rule. [See DCN: 

2006-0790-1783.2 for related comments.] In addition to those comments, CIBO offers the 

following recommendations. 

For units complying with the proposed mercury standard, the Proposed Rule requires monthly 

fuel analysis and maintenance of the annual average at or below a specified limits. 75 FR 31902. 

The monthly requirement is too burdensome on sources. CIBO recommends EPA amend the 

Proposed Rule to include quarterly monitoring and no fuel sampling should be required in any 

period if the unit does not operate during the period. EPA should also not require fuel analysis 

for single fuel units complying via stack testing. Additionally, the text associated with Table 5 

indicates that table applies to new units. 75 FR 31934. CIBO recommends that EPA extend this 

applicability to existing coal-fired units that use fuel analysis to comply with the proposed 

mercury standard. 

Response: A monthly frequency provides assurance of continuous compliance with the emission 

limits and the final rule only has a mercury limit for new and existing coal units. These sources 

can conduct performance testing and could qualify for reduced performance testing if they opt to 

demonstrate compliance with stack testing. The fuel analysis compliance option is a compliance 

alternative and since coal can be a non-homogeneous fuel, and vary in mercury content, monthly 

analysis is appropriate in this case. Fuel analyses are not required for single fuel units; see the 

rule initial compliance requirements for revised language. 

Commenter Name: Sharene Shealey

Commenter Affiliation: RRI Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1839.1

Comment Excerpt Number: 4

Comment: EPA allows for demonstration of compliance with the mercury emission limits 

through fuel analysis in the proposed rule in section 63.11211(b). For liquid-fired units, 

specifically distillate-oil fired units, EPA should also allow for demonstration ofcompliance with 

particulate matter standards by fuel-based methods. PM emissions are directly correlated to fuel 

and combustion conditions and are expected to be relatively low for distillate-oil fired units. 

Response: EPA did not finalize a fuel analysis approach for PM in the final rule. Existing liquid 

units are not subject to PM limits in the final rule and new liquid units have testing requirements 

and an emission limit consistent with the New Source Performance Standards (40 CFR part 60 

subparts Db and Dc). 
Commenter Name: Cheryl Johncox

Commenter Affiliation: Minneapolis Neighbors for Clean Air

Document Control Number: EPA-HQ-OAR-2006-0790-1971

Comment Excerpt Number: 7

Comment: The Agency states, for units that choose to comply with either the mercury emission 

limit or the HCl emission limit based on fuel analysis rather than on performance stack testing, 

we are proposing that you maintain daily fuel records that demonstrate that you burned no new 

fuels or fuels from a new supplier such that the mercury content or the chlorine content of the 

inlet fuel was maintained at or below your maximum fuel mercury content operating limit or 

your chlorine content operating limit set during the performance stack tests. 

However, C&D materials and disaster debris by their definition are materials whose 

characteristics are determined by the demolition of structures with varying age and compositions 

and thus are constantly changing. How does the EPA propose to define whether the fuel type 

constitutes a change or mixture that would require recalculations and perhaps new performance 

tests? Monitoring emissions based on daily record as an alternative to stack emissions is 

unrealistic at best. 

Given the concentrations of metals such as arsenic, chromium, lead and mercury contamination 

levels that can exist in waste wood fuel streams, using PM as a surrogate for metal emissions in 

the boiler rules is inadequate. Biomass boilers burning contaminated wood will inevitably have 

greater metals emissions than those burning forest biomass, even if particulate levels are similar. 

A permissive set of rules that permits extensive use of secondary materials as fuel will virtually 

guarantee an increase in heavy metals emissions from biomass power, with emissions going 

undetected due to the reliance on particulate matter as a proxy for these toxins. 

Response: Biomass boilers do not have emission limits for Hg or HCl, see the preamble for 

discussion.

Commenter Name: Caroline Choi

Commenter Affiliation: Progress Energy

Document Control Number: EPA-HQ-OAR-2006-0790-2226.1

Comment Excerpt Number: 4

Comment: The Mercury Fuel Analysis Requirements Are Potentially Confusing 

In 63.11213(a), EPA proposes requiring that fuel analyses be performed according to 

63.11213(b) and (c) as well as Table 5 to Subpart JJJJJ. Table 1 of Subpart JJJJJ shows that 

mercury limitations would apply to new and existing coal units only. However, in the sentence 

just prior to Table 5 on page 31934 of the Federal Register EPA states that the fuel analysis 

testing is for new affected sources, while the specific analytical methods are referenced for coal, 

biomass, and liquid samples. These multiple references make EPA’s intent unclear. Progress 

Energy requests that EPA clarify these references so that the fuel analyses are for coal-fired units 

only. 
Response: Coal units are the only subcategory that is required to meet emission limits. However, 

it is possible in some circumstances that a unit meets the definition of the coal subcategory but 

fires multiple fuels such as blends of coal and biomass or fire oil during parts of the year. Units 

firing multiple fuels are subject to fuel analysis requirements in order to demonstrate initial 

compliance. Since the determination of a subcategory is on an annual heat input basis, these 

other test methods may be necessary and have been included in the final rule.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 32

Comment: UARG supports the option to use fuel analysis to demonstrate compliance where 

possible, and does not object to a requirement to perform a new fuel analysis for Hg and chlorine 

when a new fuel is combusted. [Footnote: Again, UARG seriously questions whether any source 

could take advantage of the fuel analysis option for demonstrating compliance at the level of 

EPA’s proposed emission limits.] However, UARG does not understand why EPA has proposed 

to require monthly fuel analysis for sources that have not changed fuel type, or how that analysis 

is used. UARG also requests minor changes in the fuel sampling and analysis procedures, which 

are overly prescriptive. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1783.1, Excerpt Number 39.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 33

Comment: Sources that demonstrate compliance with the Hg or HCl limit through fuel analysis 

must conduct fuel analysis for each type of fuel combusted according to 63.7521 and Table 6, 

and “establish operating limits according to 63.7530 and Table 8.” Proposed 63.7510(b). 

Proposed 63.7530(c) provides procedures for calculating Hg and HCl emission rates. To 

demonstrate compliance, the calculated rate cannot exceed the applicable emission limit using 

the fuel analysis and based on an upper 90th percentile confidence interval. In the 2004 rule, 

EPA required repeat fuel analysis when a new type of fuel is combusted, and not later than 5 

years after the lasts fuel analysis. 69 Fed. Reg. 55,218, 55,256 (Sept. 13, 2004). However, EPA 

now proposes to require new fuel analysis monthly, regardless of whether the type or mixture of 

fuel combusted has changed. 

UARG does not understand the purpose of monthly analysis if the fuel type or mixture of fuels 

has not changed. EPA provides no explanation in the rule or preamble. To the contrary, although 
EPA’s preamble does reference a requirement for monthly fuel analysis, EPA does not say why. 

Moreover, EPA’s preamble states that compliance is determined based on the “annual average” 

of those analyses. 75 Fed. Reg. at 32,033. That averaging period is not reflected in the rule. 

Other rule provisions shed no light on the requirement. The provisions that address continuous 

compliance for units that demonstrate compliance through fuel analysis only require new 

analysis when a new fuel is combusted. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1783.1, Excerpt Number 39.

Detection Levels

Commenter Name: Glenn C. England

Commenter Affiliation: Environ Corp.

Document Control Number: EPA-HQ-OAR-2006-0790-1967.1

Comment Excerpt Number: 2

Comment: The detection limits reported among different source testers and laboratories varies 

substantially. EPA should evaluate detection limits achieved in all tests to assure that emission 

limits are not established below the limit of quantitation that can be routinely achieved in 

practice. 

In the emission test data collected for HCl, mercury and dioxins/furans during the ICR, a very 

wide range of detection limits achieved by different stack testers and laboratories using the same 

EPA test methods is evident. (See submittal for Figures 1, 2, and 3 showing HCl, mercury, and 

dioxins/furans detection limits, respectively.) HCl and mercury detection limits span 

approximately three orders of magnitude, and dioxins/furans TEQ detection limits span four 

orders of magnitude. One might point to the specific type of source and potential matrix 

interferences as a source of the variability. Examining the data for HCl and mercury, this does 

not appear likely because the detection limits for clean, gas-fired sources span almost the same 

range as detection limits for all fuels including coal, biomass and liquids. This wide range of 

method performance is an indication of reproducibility among different testers, even though the 

same test methods were used in almost all cases. 

This provides an indication of the significance of factors beyond the analytical method detection 

limit. These test methods were originally developed for measuring emissions from waste 

incinerators at concentrations several orders of magnitude higher than gas-fired sources. While 

the methods may perform sufficiently well in those applications, these results indicate the 

processes in the test methods are not sufficiently well controlled for reliable measurements near 

the method detection limits. 

EPA should not set emission limits lower than the limit of quantitation that can be routinely 

achieved in practice by most source testers and laboratories. For example, a 99% upper 

prediction limit (UPL) could be calculated using all of the detection limits reported in EPA’s 

database, and this could be used to establish an alternative measurement performance based 
minimum limit that can be measured routinely in practice. The detection limit data used for 

establishing the alternative measurement performance based minimum limit need not be limited 

to data in the MACT floor because there is no requirement for EPA to establish limits that can 

only be measured by the top source testers and laboratories on an occasional good day. Instead, 

EPA must set limits for which measurements are technically feasible. 

An example calculation of an alternative minimum emission limit using the same methodology 

that EPA used for establishing proposed MACT emission limits for mercury is shown in Table 1 

of the submittal. Neglecting the outliers apparent in Figure 2 of the submittal, there are 304 

detection limits reported for undetected mercury results. The 99% UPL of these detection limits 

is 3.7E-06 lb/MMBtu. The corresponding limit of quantitation would be 10/3 times this (Keith et 

al., 1983), or 1.2 E-05 lb/MMBtu. This represents an alternative mercury emission limit that 

could be measured above the detection limits 99% of the time in a 3-run future test by any test 

team and laboratory. All of the proposed mercury emission limits are less than level. 

EPA’s proposed emission limit for Gas 2 equates to a concentration of few parts per billion. 

Using the same approach for HCl (See Table 2 of the submittal for estimation of HCl detection 

limits), an alternative method performance based minimum limit of 0.005 lb/MMBtu, or 

approximately 5 ppm of HCl. Based on this approach, the proposed Gas 2 emission limit appears 

to be technically infeasible from a measurement perspective. 

The 99% UPL of the reported detection limits is a very conservative indicator of method 

performance – perhaps overly conservative. Other metrics may be considered. However, in any 

event EPA fully consider and understand the disparity in measurement performance indicated in 

EPA’s database before establishing emission limits that are near or below detection limits. 

Response: Probability procedures applied in calculating the floor or an emissions limit 

inherently and reasonably account for emissions data variability including measurement 

imprecision when the database represents multiple tests from multiple emissions units for which 

all of the data are measured significantly above the method detection level. That is less true when 

the database includes emissions occurring below method detection capabilities and are reported 

as the method detection level values.

We applied the following procedures to account for the effect of measurement imprecision 

associated with a database that includes method detection level data. The first step was to define 

a method detection level that is representative of the data used in establishing the floor or 

emissions limit and that also minimizes the influence of an outlier test-specific method detection 

level value. We reviewed each pollutant-specific data set to identify the highest test-specific 

method detection level reported that was also equal to or less than the average emissions level 

(i.e., unadjusted for probability confidence level) calculated for the data set. We believe that this 

approach is representative of the data collected to develop the floor or emissions limit while to 

some degree minimizes the effect of a test(s) with an inordinately high method detection level 

(e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or 

the procedure for determining the detection level was other than that specified).
The second step in the process is to calculate three times the representative method detection 

level and compare that value to the calculated floor or emissions limit. If three times the 

representative method detection level were less than the calculated floor or emissions limit 

calculated from the UPL, we would conclude that measurement variability was adequately 

addressed. The calculated floor or emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the representative method detection level were greater than

the UPL, we would conclude that the calculated floor or emissions limit does not account 

entirely for measurement variability. If indicated, we substituted the value equal to three times 

the representative method detection level to apply as the adjusted floor or emissions limit. This 

adjusted value would ensure measurement variability is adequately addressed in the floor or the 

emissions limit. 

Commenter Name: Glenn C. England

Commenter Affiliation: Environ Corp.

Document Control Number: EPA-HQ-OAR-2006-0790-1967.1

Comment Excerpt Number: 3

Comment: EPA should re-assess test method performance capabilities at low concentrations and 

revise the proposed emission limits to assure that they are not less than the limit of quantitation 

for their respective measurement methods. 

Many of the proposed performance test methods for demonstrating compliance with the 

proposed emission limits were conceived, developed and evaluated in the 1980’s and 1990’s for 

application to waste incinerators, municipal waste combustors and coal-fired boilers. They have 

not been similarly evaluated for concentrations as low as many of the proposed emission limits. 

The fact that a method produces a number does not necessarily mean that number is a reliable 

indication of the true value. The range of detection limits reported in EPA’s database indicates 

the need for a full evaluation of method performance at low concentrations, including precision, 

accuracy and reproducibility. 

Response: See the response to EPA-HQ-OAR-2006-0790-1967.1, Comment Excerpt Number 2. 

Commenter Name: Russell A. Wozniak

Commenter Affiliation: The Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2006-0790-1766.1

Comment Excerpt Number: 11

Comment: EPA’s proposed rule references EPA Performance Specification 4A for a carbon 

monoxide (CO) CEMS. Section 1.2.1. of PS 4A states that this specification was developed 

primarily for CEMS that comply with low emission standards (less than 200 ppmv). Dow further 

comments that EPA may need to make additional adjustments if CO emission standards are 
indeed set at a level of less than 10 ppmv for oil fueled sources due to QA/QC issues as 

discussed below. 

A CO CEMS will have to be ranged from 0 to 10 ppmv in order to adequately measure CO 

concentrations in the 0 to 1 or 2 ppmv range. The accuracy of a CO CEMS meeting the 

requirements of Performance Specification 4A is ~ 5% of the range or in this case + 0.5 ppmv 

(see Section 13.2 of PS4A). This level is troubling in that the uncertainty of the measurement is 

50% of the proposed emission standard in this case, thus further contributing to the challenges of 

meeting a 1 ppmv standard on a consistent basis for new sources. 

In addition, such a small allowable emission level will make conducting the Relative Accuracy 

Audits and Tests very difficult to complete. Section 13.2 of PS4A require that the RA of the 

CEMS must be no greater than 5 percent when the applicable emission standard is used to 

calculate RA. Thus, one would be comparing values that are less than 1 ppmv and looking for 

agreement between those values when the accuracy of EPA Method 10 is itself only about 0.2 

ppmv or in this case 20% of the allowable CO emission concentration. The final rule would need 

to allow for an absolute difference of less than 1 ppmv for example versus a fraction of the 

allowable ppmv value to be used for QA/QC purposes. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Russell A. Wozniak

Commenter Affiliation: The Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2006-0790-1766.1

Comment Excerpt Number: 12

Comment: Demonstrating compliance with a 1-2 ppmv CO limit by conducting testing via EPA 

Reference Method 10 will be very difficult, if not impossible, to demonstrate as noted below: 

Under Methods 10 and 7E, the span of the CO analyzer cannot be greater than 5 ppmv as Section 

3.4 of Method 10 notes that the measured emissions should be between 20-100 percent of the 

calibration span. So, even if measured emissions were 1 ppmv, the span could not exceed 5 

ppmv. Section 9.0 of EPA Method 7E has a QA/QC table that states that the analyzer and 

calibration gas performance must be within 2% of the calibration span of the analyzer (2% of 5 

ppmv = 0.1 ppmv) or alternatively 0.5 ppmv. Using the 2% criteria means that the acceptable 

result of the span calibration verification would have to be within 2% or within 0.1 ppmv of the 

calibration gas, which borders on the reasonable detection capabilities of a CO emission 

analyzer. 

Thus, one would be forced to use the alternative 0.5 ppmv for QA/QC purposes. This level is 

troubling in that the uncertainty of the measurement is 50% of the proposed emission standard 

(New Oil Fired Boilers) in this case, thus further contributing to the challenges of meeting a 1 

ppmv standard on a consistent basis. 
Furthermore, EPA Method 7E requires the use of three calibration gases between the 0 to 5 

ppmv level in order to meet the QA/QC requirements for the analysis. Obtaining and using three 

different calibration gas standards in this range is a requirement that is excessive in this case. 

Therefore, the QA/QC requirements should be modified to require only a single point calibration 

at these low concentrations. 

Similar to the calibration concerns, allowable drift would also have to meet the same alternative 

criteria of 0.5 ppmv, which again is 50% of the allowable CO concentration. 

Response: Please see preamble for changes to the final rule, including the elimination of the CO 

CEMS requirement.

Commenter Name: Robert G. Hedden

Commenter Affiliation: Oilheat Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-2249

Comment Excerpt Number: 5

Comment: The laboratory test instrument Beckett uses for these measurements is a nondispersive Infrared absorption spectrophotometer. The repeatability of this instrument is 2.5 ppm 

CO. At only 1% of the smallest measurement range for the instrument (0-250 ppm), this is twoand-one-half times the maximum limit proposed in the rule. Typical field test equipment is not as 

capable for measuring low CO levels at this precision, and typical repeatability is ±10 ppm. 

Based on the capability of the equipment used to set up and maintain residential and light 

commercial burners, the proposed maximum is not reliably measurable. 

Response: Please see preamble for changes to the final rule, including the CO emission limits.

Commenter Name: Rob Barton

Commenter Affiliation: RMB Consulting and Research, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2198.1

Comment Excerpt Number: 7

Comment: At least one of the reported CO test data sets using EPA Reference Method 10 (RM10) is within the range of uncertainty for the test method. The accuracy for most nondispersive 

infrared analyzers (NDIR) is approximately ±5 percent of span after calibration. [Footnote: 40 

CFR 60, Appendix A-4, Method 10] The average reported CO emissions for the Thompson Falls 

wood-fired boiler is 20.6 PPM using an analyzer span value of 600 PPM. The accuracy of RM10 in this case is ±30 PPM. These test runs should be treated as “non-detect” values. RMB 

recommends that EPA screen the remaining MACT floor data to determine whether similar 

problems exist for other test data. 
Response: Please see the preamble for revisions to the proposed CO limits. Also, see the 

response to EPA-HQ-OAR-2006-0790-1967.1, Comment Excerpt Number 2. 

Measurement Methodology Impractical

Commenter Name: George Whiting

Commenter Affiliation: EcoHeat Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-0832

Comment Excerpt Number: 2

Comment: Perhaps some simpler rules would accomplish your goals,at less administrative cost 

and less cost to the industry and customers. One simple test: if smoke is visible from the chimney 

for durations longer than 5 or 10 minutes at start-up and shut-down, then the boiler needs to go in 

for further testing. If not, then it falls below an acceptable threshold. That would address your

particulates goals, and ensure that the boiler is not going to bother neighbors. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-2192.1, excerpt number 6.

Commenter Name: Cynthia Finley

Commenter Affiliation: National Association of Clean Water Agencies

Document Control Number: EPA-HQ-OAR-2006-0790-0838.1

Comment Excerpt Number: 3

Comment: The proposed rule requires that the biennial tune-up “measure the concentrations in 

the effluent stream of CO in parts per million, by volume, dry basis (ppmvd), before and after the 

adjustments are made.” In addition, the facility must maintain and potentially submit an annual 

report that contains “the concentrations of CO in the effluent stream in ppmvd, and oxygen in 

percent dry basis, measured before and after the adjustments of the boiler” and “the type and 

amount of fuel used over the 12 months prior to the annual adjustment.” These requirements to 

measure effluent stream gases are inconsistent with EPA’s reasoning for establishing work 

practice standards rather than emissions limits for small boilers. EPA states in the proposed rule 

that the standard methods for measuring emissions of mercury, carbon monoxide (CO), and 

particulate matter (PM) are not applicable for sampling stacks with a diameter less than 12 

inches, which are generally found on boilers with a capacity less than 10 MMBtu/h. In addition, 

many of these small boilers would require expensive modification to install sampling ports and a 

platform to access the stack. Since it is not feasible to require emissions limits due to the 

technological limitations of monitoring and testing, as well as the costs of necessary 

modifications to perform the tests, it is also not feasible to require emissions testing as part of the 

biennial tune-up. 
Response: We have modified the language at 63.11223(b) in order remove the requirement to be 

measured on a dry basis. This change allows CO to be measured using portable monitors in the 

tune-up process. These portable monitors can be used in smaller stacks. See further responses to 

comments on the tune-up components in the preamble and tune-up section of this document.

Commenter Name: Sheldon Schultz

Commenter Affiliation: Yanke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-0837

Comment Excerpt Number: 7

Comment: It is incomprehensible that “the Administrator determines that...the application of 

measurement methodology to a particular class of sources is not practicable due to technological 

and economic limitations” (page 17 of 196) when the subject is MACT (maximum achievable 

control technology). Economics and technology are not mitigating factors in application of 

MACT. 

Response: For the operations and facilities subject to the rule, we believe that the combination of 

periodic compliance emissions testing and continuous monitoring of operational and parametric 

control measure conditions is appropriate for assuring ongoing compliance.

Commenter Name: Donald R. Schregardus

Commenter Affiliation: Department of the Navy, Department of Defense

Document Control Number: EPA-HQ-OAR-2006-0790-1947.1

Comment Excerpt Number: 6

Comment: New small boilers (less than 10 MMBtu/hour) are typically designed like comparable 

existing units with small diameter stacks. These small stacks do not allow for accurate 

application of standard EPA test methods required to demonstrate compliance with emission 

limits. 

EPA indicates on p. 31906 of the preamble that small boilers (less than IOMMBtu/hour) 

typically have small diameter stacks (less than 12 inches). EPA acknowledges that sampling 

emissions from these small stacks using the prescribed EPA test methods can result in inaccurate 

measurements. EPA conducted a cost analysis to evaluate the economic impact of the testing and 

monitoring costs that facilities with small units would incur and concluded that the annual costs 

would have significant adverse economic impact on these facilities. Therefore, EPA determined 

that it is not feasible to enforce emission standards for existing small boilers (heat input capacity 

of less than 10 MMBtu/hour). Based on this analysis, no emission limits should be promulgated 

for comparable small new or reconstructed boilers. While a new facility can ensure sampling 

ports are available, these boilers will still be constructed with the small diameter stacks which 

would lead to questionable emission test results. Stack size is based on factors other than 

sampling accommodation. As noted in an earlier comment some sources do not have a choice of 

fuel which is one of the reasons EPA cites for deciding to impose limits on small new boiler. 
Require work practices in lieu of establishing emission limits for new and reconstructed boilers 

with a rated heat input capacity of less than 10 MMBtu/hour. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: N/A

Commenter Affiliation: Sierra Club, Earth Justice, Clean Air Task Force, Natural Resources 

Defense Council

Document Control Number: EPA-HQ-OAR-2006-0790-1982.1

Comment Excerpt Number: 17

Comment: The limitations identified by EPA do not make measurement methodology 

impracticable. EPA does not claim that any measurement method other than method 5 raises any 

technical issues at all for stacks less than twelve inches in diameter. Method 5, as EPA points 

out, is a method for measuring emissions of PM. Thus, the alleged technical limitation on 

measuring emissions in stacks with diameters less than twelve inches are not even relevant to 

emissions of mercury and CO, the only two pollutants for which EPA is even proposing MACT 

standards. 

Response: See the preamble for discussion

Commenter Name: N/A

Commenter Affiliation: Sierra Club, Earth Justice, Clean Air Task Force, Natural Resources 

Defense Council

Document Control Number: EPA-HQ-OAR-2006-0790-1982.1

Comment Excerpt Number: 18

Comment: Further, EPA’s alleged concerns about the absence of sampling ports and platforms 

are unsupported by record evidence and unconnected to the statutory standard. EPA does not say 

how many area source boilers with heat input capacity do not have sampling ports or platforms, 

and thus gives no indication about whether the absence of such equipment is even an issue for a 

significant portion of the population. Moreover, EPA does not even claim that it would be 

impracticable to install sampling ports or platforms on boilers that currently lack them, far less 

provide record evidence to support such a claim. Absent showings that boilers do not have and 

cannot install sampling ports or platforms, EPA’s bare assertion that some boilers currently lack 

them is statutorily irrelevant. Notably, the record includes discussion of a study in which the 

majority of emissions data for the study was from boilers smaller than 10 MMBtu. EPAHQOAR-2006-0790-0048. Stack tests were taken for PM10, PM2.5, and condensable PM. The 

document containing that study notes that many state permitting authorities require “a number of 

technical analyses” which can include emissions tests, from these small boilers. Id. at 1. If small 
boilers must provide this information to state regulatory agencies, boiler operators must have 

developed ways to test emissions from small boilers. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Bill Perdue

Commenter Affiliation: American Home Furnishings Alliance, AHFA

Document Control Number: EPA-HQ-OAR-2006-0790-1970.1

Comment Excerpt Number: 16

Comment: Small vent diameters for liquid fired units would create technical difficulties in 

implementing EPA test methods. The AHFA opposes ANY source test requirement for any 

boilers <10MMBTU/hr. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-0838.1, excerpt number 3.

Commenter Name: John Huber

Commenter Affiliation: National Oilheat Research Alliance

Document Control Number: EPA-HQ-OAR-2006-0790-1831.1

Comment Excerpt Number: 10

Comment: Vent Constraints: The efficiency of boilers has been increasing under pressure from 

federal minimum efficiency standards, the Energy Star Program, building standards activities, 

and federal and state incentive programs. As efficiency increases, exhaust gas temperature 

decreases as does the buoyancy that has traditionally been used for venting the products of 

combustion safely to the outdoors through a chimney. 

Concerns about venting safety have been an important factor in setting the recent minimum 

efficiency standards for boilers and furnaces [ref]. Building codes [NFPA 31. Chapter 6 ] provide 

constraints on vent systems in the form of allowable vent diameters and construction materials to 

avoid flue gas spillage and the potential for unintended water vapor condensation with higher 

efficiency equipment. The use of a 12” stack for compatibility with the EPA-5 method for PM 

testing is not allowable with smaller systems. 

In response to the efficiency/venting issue sidewall venting is now being used in practice in some 

applications. As an example of this commercial practice, Field Controls offers a complete series 

of sidewall vent system products applicable for boilers as large as 3 MMBTU 

(www.fieldcontrols.com ). These systems include an induced draft fan which is mounted on an 

outside wall and a vent termination which is intended to impart momentum to the exhaust gas to 

avoid contact of the exhaust with building sidewall materials and to avoid the potential for reentrainment of the exhaust products into the building. Barometric dampers are used in 

combination with these products which are installed close to the boiler and serve to control the 

level of draft at the boiler exit by mixing room air with the exhaust gas at a variable rate. 
Typically the draft inducer is as close as possible to the boiler. Induced draft, sidewall venting 

systems of this type, where there is no “stack” are not compatible with EPA test methods for CO 

and PM. 

Other boiler products, including high efficiency condensing oil boilers, use “direct vent” 

systems. Here an induced draft fan is not used and the vent system is under a positive pressure 

from the burner combustion air fan. These are sidewall vented and combustion air is directed to 

the burner air inlet from the outside at about the same side wall location. The advantage of 

having this arrangement is that outside sidewall air pressure variations, wind driven, affect both 

the air inlet as well as the exhaust and reduce wind effects on operating air/fuel ratio. Typically, 

a two pipe concentric vent arrangement is used with the exhaust gas in the center pipe and 

combustion air flowing through the annular region between the outer and inner pipe. Outside 

combustion air is partially preheated in this arrangement, recovering additional energy from the 

exhaust gas and reducing the potential for burner and combustion problems with cold outside air. 

As in the case of inducer-product sidewall vent a high momentum vent termination is again used 

and there is no “stack”. Adding sampling ports which pass through the outer annulus could result 

in leaks and cross-contamination of combustion air with flue gases. This could have a negative 

impact on the measurements, create service issues, and increase the risk of safety hazards. These 

systems are again not compatible with EPA test methods for CO and PM. Examples of systems 

of this type include the Peerless Pinnacle oil-fired condensing boiler [www.peerlessboilers.com] 

and the Quietside QXM8 oil boiler. Manufacturer’s specifications for the QXM8 specify 3 inch 

diameter venting, with no deviations and prohibit vertical venting. 

(http://www.quietside.com/images/Quietside/Products/DPW/166-

168/QXM8%20IOM%20Supplement.pdf) 

Heat Dissipation during Test: Oil boilers installed as the sole heat source for smaller commercial 

and institutional buildings are often significantly oversized for the design day space heat load 

and also for the heat distribution capacity of the baseboard radiator or fan coil capacity. In some 

cases this 

situation results from the use of these boilers for domestic hot water in addition to just space 

heating. With domestic hot water loads, either involving an internal heat exchanger coil or an 

external indirect storage tank, short periods of higher firing rate are needed to rapidly respond to 

a domestic hot water draw. 

The standard for evaluation of the Annual Fuel Utilization Efficiency (AFUE) of small 

residential boilers for example [ASHRAE Standard 103-2007- ANSI/ASHRAE Standard 103-

2007 is entitled Method of Testing for Annual Fuel Utilization Efficiency of Residential Central 

Furnaces and Boilers. The scope of this standard includes residential boilers with inputs less than 

300,000 BTU/hr.], is based on a national average oversize factor of 1.7 (input capacity to design 

day heat load). Boiler installations for small commercial buildings are seen as very similar to 

residential buildings. 

Because these boilers are typically installed in this way, there is no possibility to run them in the 

field in steady state as the heat produced cannot be practically dissipated, even on the coldest 

(“design”) day. For this reason EPA Method 5 and 39 tests cannot be conducted. 

In the proposed rule, it is stated that commercial boilers affected typically start only once each 

day. This is clearly not consistent with smaller systems used for space heating where 20 – 50 

starts per day are quite common. In the AFUE test procedure, testing is done under what is seen 

as a national average burner cycling patterns – 9.68 minutes of firing followed by 33.26 minutes 
of idle. Again, boilers in small commercial buildings operate in a manner similar to those in 

residential buildings. 

Available Space Constraints: In many smaller commercial buildings boilers and other utilities are 

designed into small spaces. In the case of the replacement of an existing boiler with a new boiler, 

which may be subject to the testing requirements of the proposed regulations (see comments on 

new versus existing), it is likely that the boiler would have to be moved to provide the venting 

configuration required for the testing. This would require significant cost associated with 

rerouting of hydronic piping and add far more to the cost than simply a change in flue pipe size. 

In the case of a new building design, significant additional space would have to be provided to 

accommodate the proposed testing which would be cost prohibitive. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Marilyn Crockett

Commenter Affiliation: Alaska Oil and Gas Association

Document Control Number: EPA-HQ-OAR-2006-0790-2212.1

Comment Excerpt Number: 2

Comment: However, AOGA is very concerned about the lack of a similar de minimis cutoff for 

new boilers. As proposed, emission standards will apply to any new boiler regardless of size. 

New boilers less than 10 MMBtu/hr also have small diameter stacks. In Table 4 of the proposed 

rule, EPA identifies reference test methods for demonstrating compliance that apply to all boilers 

subject to numerical standards, but EPA has already concluded that these methods are not 

feasible for small boilers. 

On page 31909 of the preamble, EPA again notes the inapplicability of the reference test 

methods to small boilers, and also the excessive costs associated with annual testing and 

monitoring requirements for both new and existing units. However, EPA then goes on to indicate 

that they will not propose work practice standards for new boilers. EPA’s basis for this decision 

is very unsatisfactory. EPA states that new facilities have the “added flexibility of including 

compliance costs into their design and planning.” AOGA believes that the inconsistency with 

this line of reasoning is clear: the costs remain and are still excessive. EPA also states that “a 

new facility has the option of fuel selection in minimizing their compliance costs.” This 

statement is clearly not universally true. For example, natural gas is unavailable in rural Alaska 

and large parts of urban Alaska (e.g., the cities of Fairbanks, and Juneau, Alaska). Existing and 

new boilers in areas without access to natural gas supplies clearly have no way of “selecting” 

natural gas rather than distillate fuel to minimize compliance costs. 

In summary, AOGA believes that the underlying need for a work practice standard for small 

boilers clearly applies to both new and existing boilers, and we request that EPA revise the rule 

accordingly. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.
Commenter Name: Frank A. Stanonik

Commenter Affiliation: Air-Conditioning, Heating, and Refrigeration Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2156.1

Comment Excerpt Number: 3

Comment: It is not economically feasible to install separate pollution control devices on these 

small boilers. These units have stacks that are less that 12” in diameter and cannot accommodate 

the necessary testing apparatus and sampling methods. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Daniel Moss

Commenter Affiliation: Society of Chemical Manufacturers and Affiliates

Document Control Number: EPA-HQ-OAR-2006-0790-2018.1

Comment Excerpt Number: 4

Comment: Furthermore, EPA’s cost-to-sales analysis to evaluate the impact of testing and 

monitoring costs for these boilers is revealing. With the analysis indicating that total compliance 

costs range from 3-19% of the average firm revenues for nearly eighty percent of facilities, EPA 

concluded that “the annual costs for testing and monitoring alone would have a significant 

adverse economic impact on these facilities,” and that the costs for small institutional and 

commercial facilities “would be prohibitive.” [Footnote: 75 Fed. Reg. at 31906.] SOCMA 

members confirm that the boilers that fall into this size category (<10 MMbtu/hour) are typically 

very small – like those in small office buildings, for example. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Daniel Moss

Commenter Affiliation: Society of Chemical Manufacturers and Affiliates

Document Control Number: EPA-HQ-OAR-2006-0790-2018.1

Comment Excerpt Number: 5

Comment: The SBREFA Panel organized for this rule by the Small Business Administration 

echoed some of these concerns. In a 2009 letter to Administrator Jackson accompanying the 

Panel’s report, the Panel highlighted comments by small entity representatives that “a regulatory 

approach to improved combustion efficiency, such as work practice standards, would have 

positive impacts with respect to the environment and energy use and save on compliance costs. 

The [small entity representatives] strongly suggested that a work practice standard would be 
necessary for area sources to comply with the rule. . . . Because of the potential burdens and 

costs of meeting” the new rules, the Panel urged EPA to consider adopting different options to 

promote flexibility, including those of work practice standards. [Footnote: Executive Summary 

accompanying Report of the Small Business Advocacy Review Panel for EPA’s Proposed Boiler 

MACT and Area Sources Rules (sent to EPA Administrator Lisa Jackson)] 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Jim Pettiford

Commenter Affiliation: Fulton Thermal Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2192.1

Comment Excerpt Number: 6

Comment: The proposed rule would require annual PM and CO emissions testing for boilers 

over 10 MMBTU per hour in capacity and which have been installed after the June 4, 2010 date 

of publication of the new rule. Since PM emission testing is expensive, and since PM emissions 

are primarily a function of fuel sulfur content, we would suggest instead a provision that requires 

the use of lower sulfur 

fuel to ensure the low PM emissions that are desired. To ensure that CO emissions are 

maintained at a suitably low level, we would encourage USEPA to promulgate a modified rule 

that limits the annual test procedure to just CO emission and Bacharach smoke number 

measurements. 

Response: For the operations and facilities subject to the rule, we believe that the combination of 

periodic compliance emissions testing and continuous monitoring of operational and parametric 

control measure conditions is appropriate for assuring ongoing compliance. EPA has not 

considered a fuel sulfur limit as part of this rulemaking.

Commenter Name: Robert W. Glowinski

Commenter Affiliation: American Wood Council

Document Control Number: EPA-HQ-OAR-2006-0790-1930.1

Comment Excerpt Number: 9

Comment: Most boilers are designed to mix fuel and air at an appropriate ratio, and to provide 

sufficient residence time for the fuel to combust completely. Obviously, these factors are fueldependent, as a gaseous fuel will require less time for complete combustion than a liquid fuel, 

which in turn requires less time to burn than a solid fuel. The need for longer residence time is 

why the radiant sections in solid-fuel fired boilers are larger than for gas-fired units. The size of 

the boiler is typically optimized to allow for complete combustion, while minimizing the cost of 

construction materials. If the construction cost were not a concern, a new boiler could be 
designed with additional residence time to complete the combustion process and minimize CO 

emissions. 

Unfortunately, increasing the size of the furnace is not an option for existing biomass stoker 

units. For these units, the strategy for reducing CO emissions typically includes an optimization 

of the distribution of combustion air between the grate and primary/secondary air levels. 

However, this has the possibility of increasing boiler NOx levels since wood-fired boiler NOx 

emissions are very dependent on achieving optimal air staging which often comes at an expense 

of increased CO emissions. 

Response: Biomass boilers do not have CO limits in the final rule.

Commenter Name: Robert G. Hedden

Commenter Affiliation: Oilheat Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-2249

Comment Excerpt Number: 9

Comment: It is our understanding that the proposed test procedure requires at least a 12-inch 

diameter flue pipe. The flue pipes on less than 3 MMBtu/h boilers are 4 to 8 inches. Increasing 

the flue pipe size to perform the test will increase condensing of the flue gasses in the flue pipe 

and heat exchanger and result in decreased efficiency, and increased fuel consumption. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Wayne York

Commenter Affiliation: Hancock Lumber Company, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2002

Comment Excerpt Number: 5

Comment: It could be argued that the Reference Method testing itself provides no 

environmental benefit, but adds significant cost to the regulated facilities. The actual 

environmental benefit comes from the maintenance and tune up that would be conducted prior to 

testing. This work is typically conducted by boiler technicians using hand-held instruments, and 

results in a direct benefit in the form of reduced emissions and improved energy efficiency. 

Additional Reference Method testing, especially for small boilers less than 30 MMBtu/hr, 

provides no additional environmental benefit and adds significant cost. 

Allowing the use of portable hand-held analyzers in lieu of full reference method testing for 

small units from 10-30 MMBtu/hr could be a viable option to reduce the cost but still provide a 

similar level of benefit for this rule; 
Response: For the operations and facilities subject to the rule, we believe that the combination of 

periodic compliance emissions testing and continuous monitoring of operational and parametric 

control measure conditions is appropriate for assuring ongoing compliance. EPA disagrees hat 

compliance monitoring and oversight activities provides no environmental benefit, and considers 

these measures an important element of ensuring that the intended emission reductions are 

achieved. 

Reduced Testing Allowance

Commenter Name: Russell A. Wozniak

Commenter Affiliation: The Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2006-0790-1766.1

Comment Excerpt Number: 10

Comment: Typically, MACT regulations provide allowance for process changes at an affected 

source if it can be demonstrated that an existing performance test can be shown to be valid. 

Below is suggested regulatory text for addition to the final rule: 

A unit is not required to conduct a performance test for an emission point for which a 

performance test was conducted within the previous 5-year period, using the same test methods 

specified in this section and for which either no deliberate process changes have been made since 

the test, or the owner or operator can demonstrate that the results of the performance test, with or 

without adjustments, reliably demonstrate compliance despite process changes. The operating 

limits reported under the previous performance test shall be sufficient to meet the monitoring 

requirements in this subpart. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 23

Comment: EPA should amend the text associated with Table 4 to reflect that it applies to new 

and existing units. EPA should remove the requirement to be 75% of limit to be eligible for 

reduced stack testing frequency. This requirement is not justified and in order to minimize the 

burden on facilities, there needs to be less frequent stack testing. Overall, CIBO supports the 

reduction of stack testing frequency for CO to between 10 MMBtu/hr and 100 MMBtu/hr. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76.
Commenter Name: Jon Strimling

Commenter Affiliation: American Biomass Company

Document Control Number: EPA-HQ-OAR-2006-0790-1904.1

Comment Excerpt Number: 3

Comment: The rule should institute an initial third party certification test with required annual 

tune-ups without ongoing costly stack testing. Once a boiler (or range of boilers) is tested, that 

boiler would be approved for installation until a change was made in the boiler design. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76.

Commenter Name: Arthur N. Marin

Commenter Affiliation: Northeast States for Coordinated Air Use Management, NESCAUM

Document Control Number: EPA-HQ-OAR-2006-0790-2137.1

Comment Excerpt Number: 27

Comment: In the proposed rules, EPA indicates that once a facility has demonstrated 

compliance with the emission limit, it can reduce the frequency of stack testing. There is, 

however, a lack of clarity on the percentage a facility must fall below the emission limit to 

qualify for this reduction. In section 63.7515(b), EPA specifies that a facility must fall below 

75% of the emission standard, whereas sections 63.7555 (c) (5) and 63.7555 (d) (6) refer to a 

90% threshold. The NESCAUM states request EPA to clarify its intent. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 76

Comment: EPA should remove the requirement in 63.11214 that a unit must test below 75 

percent of the applicable limit to qualify for a reduced testing frequency. We do not believe this 

restriction is justified, as there are major source rules that only require initial performance testing 

or testing every 5 years. The Hazardous Waste Combustor MACT (Subpart EEE) requires a 

Comprehensive Performance Test only once every 5 years. Many MACT standards and NSPS 

only require one initial performance test unless there is a physical change to the control device 

that would increase emissions. The rule requires continuous monitoring of operating parameters 

and fuel input that are meant to provide an ongoing assurance of compliance with the emission 

limits. As long as the facility continues to operate in a similar mode following the initial 

performance test and maintains operating parameters and fuel inputs within the established 

operating ranges, annual stack testing for all pollutants is not necessary. We believe that it is 
appropriate for EPA to require stack testing once every 5 years for area source boilers, as 

emissions from these boilers are small, the monitoring required by the rule will provide a 

reasonable assurance of compliance with the emission limits, and allowing a reduced testing 

frequency will reduce the cost of the rule. The reduced frequency for testing should be allowed 

not only for PM and mercury, but also for CO. As stated previously, we believe a more 

appropriate regulatory approach for CO emissions from area sources is management or work 

practice standards, rather than ongoing testing and monitoring. 

Response: Please see the discussion of the reduced testing frequency requirements finalized in 

the rule. 

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 15

Comment: EPA has proposed the establishment of requirements for subsequent testing that 

allow a reduced testing frequency under certain conditions. While Duke Energy agrees that 

sources should be able to perform certain tests on a reduced frequency, it believes that EPA is 

overly restrictive in two areas and should make changes. First, EPA has not extended the option 

for reduced testing frequency to dioxin and furans. EPA has offered no justification for this 

discrepancy and Duke Energy believes that the dioxin/furan testing frequency should be allowed 

to be reduced along with the other pollutants. Duke Energy also believes that the requirements 

for extended testing frequency should not be that the unit demonstrating 75% of the standard. 

Rather it recommends that the unit pass either two test in a row, or one test by no more than 90% 

of the standard. EPA has also not addressed the issue of how a limit of detection is handled in the 

context of reduced testing frequency. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76.

Commenter Name: Barry Bernstein

Commenter Affiliation: Better World Energy, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-2275

Comment Excerpt Number: 3

Comment: We recommend an initial third party certification stack test, with required annual 

tune ups without on-going costly stack testing. A manufacturer should be granted an exemption 

from stack testing if the same design combustor/ boiler , air pollution controls and fuel type are 

used with a new customer. .Annual stack testing is a financial burden, especially on small 

systems that operate on a seasonal, 6 — 8 month, basis and recognition must be given to the 

unavailability of independent certified testing services. 
Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76.

Commenter Name: Thomas D. Emero

Commenter Affiliation: Beaver Wood Energy

Document Control Number: EPA-HQ-OAR-2006-0790-2166.1

Comment Excerpt Number: 6

Comment: The proposed schedule of PM testing every year, which can then be reduced to every 

third year if emissions are less than 75% of the standard can also be reduced without increasing 

risk to the environment or human health. BWE suggests requiring testing every third year if the 

initial testing indicates PM emissions are 75% of the standard and requiring annual testing until 

such time as the results are less than 75% of the standard. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76.

Commenter Name: Michael Wagner

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2271

Comment Excerpt Number: 8

Comment: Reduce the amount of performance testing required by the proposed rule. 

Response: Work practice standards are now in place for all units under 10 MMBtu/hr, no testing 

is required.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 55

Comment: EPA Should Remove The Requirement To Be 75% Of The Limit To Be Eligible For 

Reduced Stack Testing Frequency And Should Require Less Frequent Testing. EPA should 

remove the requirement in proposed 63.11214 that a unit must test below 75% of the applicable 

limit to qualify for a reduced testing frequency. EPA has not justified this restriction. The 

proposed rule requires continuous monitoring of operating parameters and fuel input that are 

meant to provide an ongoing assurance of compliance with the emission limits. As long as the 

facility continues to operate in a similar mode following the initial performance test and 

maintains operating parameters and fuel inputs within the established operating ranges, annual 

stack testing for all pollutants is not necessary. For area source boilers, we believe that it would 

be appropriate for EPA to require stack testing once every 5 years, as emissions from these 
boilers are small, the monitoring required by the rule will provide a reasonable assurance of 

compliance with the emission limits, and allowing a reduced testing frequency will reduce the 

cost of the rule. The reduced frequency for testing should be allowed for PM, mercury, and CO. 

As stated previously, we believe a more appropriate regulatory approach for CO emissions from 

area sources is work practice standards, rather than ongoing testing and monitoring. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 56

Comment: Facilities Should Be Able To Test One Unit If It Is Representative Of Multiple Units 

At A Facility. Another measure that would reduce the cost of complying with this rule would be 

to allow facilities to group like units and test one representative boiler instead of requiring them 

to test each and every boiler at the facility. For example, if a facility has multiple 25 MMBtu/hr 

boilers that are of the same design and fire the same fuel, they should be able to test one of these 

boilers to represent emissions of the rest of the group. The periodic testing could “rotate” among 

the boilers in the group. This option would reduce the cost associated with emissions testing for 

facilities with many similar boilers. 

Response: EPA disagrees with the commenter. Each and every unit that is part of the affected 

source is subject to an emission limit or work practice standard. From a compliance perspective 

it is too difficult to establish representative criteria given the multiple variables of fuel and 

operations cited by many other commenters.

Compliance Flexibility for Small Entities

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 29

Comment: Louisiana’s sugar cane grinding season is relatively short lasting approximately 115 

days a year. Such a short grinding season means that under the proposed regulations, our mills 

would be required to test each boiler three times more often than non-seasonal industries, based 

on total hours of operation. 
Response: The final rule does not include limits for existing biomass units and only a PM limit 

for new biomass units, thus reducing the burden. The EPA did not have sufficient data for area 

source boilers to create a limited use subcategory, but the operating schedule mentioned above 

exceeds the limited use threshold of 876 operating hours per year.

Commenter Name: G. Vinson Hellwig

Commenter Affiliation: Michigan Department of Natural Resources and Environment

Document Control Number: EPA-HQ-OAR-2006-0790-2016.1

Comment Excerpt Number: 1

Comment: With regard to the feasibility of designing sampling ports for boiler stacks with small 

diameters (less than 12 inches), we consider such testing to be unnecessary due to the minimal 

expected impact on air quality from boilers that operate with small diameter stacks. The 

proposed work practice standards will provide adequate emission control for small boilers 

without the addition of a testing requirement. 

A representative search of 30 permits for small boilers identified eight boilers, rated at 3.35 

million British thermal units per hour (MMBtu/hr) or less, with stack diameters less than 12 

inches. For comparison, some of the same facilities also operate emergency generators 

(reciprocating internal combustion engines) rated up to 1000 kilowatts (kW) with exhaust stacks 

less than 12 inches in diameter. A generator output of 1000 kW is equivalent to 3.4 MMBtu/hr or 

1341 horsepower. On March 3, 2010, the EPA published final revisions to the NESHAP for 

Reciprocating Internal Combustion Engines (RICE) (40 CFR Part 63 Subpart ZZZZ) which 

includes performance testing requirements for carbon monoxide (CO) and formaldehyde on a 

concentration basis, using established test methods applicable to small diameter stacks. If the 

EPA includes a performance test requirement for boilers with small diameter stacks, perhaps an 

approach similar to that taken for the RICE NESHAP would be more suitable for the small 

boilers. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Jonathan Wood

Commenter Affiliation: Vermont Agency of Natural Resources

Document Control Number: EPA-HQ-OAR-2006-0790-2248

Comment Excerpt Number: 3

Comment: The proposed requirement for annual compliance testing for all boilers that have 

emission limits is overly burdensome on both the smaller facilities and the regulatory agencies 

that must oversee this. Again, additional size thresholds with increasing testing and monitoring 

requirements on progressively larger boilers would seem appropriate. The major source boiler 

rule as proposed includes such progressively more stringent requirements. For the area source 

rule, an initial commissioning compliance test would seem appropriate for all boiler units. After 

the initial test, units in the range 1-10 MMBTU/hr should be required to conduct annual tune-
ups. For units in the range 10-30 MMBTU/hr, annual tune-ups should be supported with stack 

testing conducted every 5 years. For units in the range 30 — 100 MMBTU/hr in addition to the 

initial stack test, annual tune-ups, and a subsequent stack test every 5 years, they should use 

monitoring techniques similar to Compliance Assurance Monitoring (CAM). Boilers greater than 

100 million should be subject to the annual compliance test provisions as proposed as well as 

annual tune-ups and CAM. 

Response: For the operations and facilities subject to the rule, we believe that the combination of 

periodic compliance emissions testing and continuous monitoring of operational and parametric 

control measure conditions is appropriate for assuring ongoing compliance. Please see the 

preamble for information on current requirements, including work practice standards for all units 

under 10 MMBtu/hr. 

Commenter Name: John Lyons

Commenter Affiliation: Kentucky Division for Air Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2218.1

Comment Excerpt Number: 4

Comment: At a time when there is considerable encouragement to convert to renewable energy, 

it should be noted that the majority of biomass-only boilers are smaller than others. The most 

publicized uses of biomass may involve electricity generation, but more effective uses of 

biomass may prove to be in areas such as the U.S. Forest Service’s "Fuels for Schools" program, 

which will involve many boilers rated at 10 MMBtu/hr or smaller. The financial burden of 

annual or near-annual repeat testing could easily be enough to prevent transitions away from coal 

or oil to cleaner fuels. While it is good to require testing and tune-ups of units that have probably 

never been tested before, the long-term frequency of these measures required in the proposed 

JJJJJJ needs to be reduced in order to be practical. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Fred Gordon

Commenter Affiliation: Herman Miller, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2046.1

Comment Excerpt Number: 5

Comment: Other considerations for small sources, such as reducing the testing frequency from 

the annual requirement in the proposed rule similar to the size differentiation for continuous 

emission monitors, should be a part of this rule, in order to relieve small sources of some of the 

compliance costs that may make continued operation of these units impractical under the current 

proposal. 
Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Martin Lunde

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2065.1

Comment Excerpt Number: 11

Comment: Instead of yearly stack testing for small users, certify the equipment through 

independent lab certification tests (as is presently done with residential equipment) and enforce a 

yearly maintenance program. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Christopher Recchia

Commenter Affiliation: Biomass Energy Resource Center

Document Control Number: EPA-HQ-OAR-2006-0790-2008.1

Comment Excerpt Number: 11

Comment: Annual testing is technologically infeasible for units under 5 MMBtu and 

economically infeasible for units under 10 MMBtu. It is also unnecessary, as there are other 

measures typically performed during annual maintenance that could be reported to ensure proper 

tuning and operation, such as CE and pressure drop across fabric filter. 

Response: Please see preamble for information on current requirements, including work 

practice standards for all units under 10 MMBtu/hr.

Commenter Name: Thompas P. Balf

Commenter Affiliation: Campus Cortium for Environmental Excellence

Document Control Number: EPA-HQ-OAR-2006-0790-1657.1

Comment Excerpt Number: 13

Comment: Annual stack testing for units greater than 10MMBTU/hr is costly with limited 

added value. 

We suggest stack testing be required for applicable units every three (3) years. 
Response: We disagree with the commenters’ assertions that the performance testing 

requirements are excessive. As discussed earlier, the combination of periodic compliance 

emissions testing and continuous monitoring of operational and parametric control measure 

conditions is appropriate for assuring continuous compliance with the emissions limitations. 

Without recurring testing, we would have no way to know if parameter ranges established during 

initial performance testing remained viable in the future.

Commenter Name: Dan H. Williams

Commenter Affiliation: Sealed Air Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2228.1

Comment Excerpt Number: 14

Comment: As proposed, the area source MACT standard causes facilities to source test boilers 

greater than or equal to 10 MMBTU/hr on an annual basis. This results in excessive testing costs 

on a frequent basis. By virtue of being an area source, the emissions of hazardous air pollutants 

are small and in most cases not even significant. This costly testing unfairly penalizes 

responsible manufacturing or commercial operations that were not a substantial risk to human 

health or the environment in the first place. 

Response: See the response to EPA-HQ-OAR-2006-0790-1657.1, Comment Excerpt Number 

13.

Commenter Name: Daniel Moss

Commenter Affiliation: Society of Chemical Manufacturers and Affiliates

Document Control Number: EPA-HQ-OAR-2006-0790-2018.1

Comment Excerpt Number: 14

Comment: EPA should require a source to perform stack testing only every five years instead of 

annually (unless it has a change that could affect emissions). 

SOCMA appreciates the possibility under proposed Section 63.11214 that sources can reduce 

stack testing for PM and Hg to once every three years if certain conditions are met. However, we

believe the trigger threshold (75% of the emissions limit) should simply be the emissions limit –

so long as a unit demonstrates compliance for three years, it should be able to reduce stack 

testing frequency. 

Also, the proposed performance testing requirements are too stringent. A stack test for CO costs 

$10,000. Stack tests for PM or Hg are even more expensive, although there are some efficiencies 

in conducting multiple tests at the same time. These costs are significant burdens to small 

businesses, particularly when one considers that they are additive to the costs associated with the 

proposed energy assessment and other provisions in the proposal. We also note that most state 

permits only require one stack test during the permit term (often five years). Limiting stack tests 
to once every five years would enable small facilities to reduce test mobilization and 

demobilization costs, which make up 25 – 50% of the total stack testing cost. 

Response: See the response to EPA-HQ-OAR-2006-0790-1657.1, Comment Excerpt Number 

13.

Commenter Name: Daniel Moss

Commenter Affiliation: Society of Chemical Manufacturers and Affiliates

Document Control Number: EPA-HQ-OAR-2006-0790-2018.1

Comment Excerpt Number: 15

Comment: SOCMA proposes that EPA limit stack testing to units burning coal or #6 fuel oil. 

Lighter fuel oils generate such relatively smaller concentrations of emissions that the costs of 

stack testing are far less justifiable. 

Response: All units with applicable emission limits must perform stack testing. However, the 

final rule only includes a PM limit for new oil boilers thus reducing the burden.

Commenter Name: Barry Christensen

Commenter Affiliation: Occidental Chemical Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2227.1

Comment Excerpt Number: 16

Comment: The proposed annual carbon monoxide testing requirement for existing oil fired 

boilers is too frequent. These tests are complex and expensive for smaller facilities. It should be 

acceptable to use NOx and CO measurements made with handheld meters during the biennial 

tune-ups to qualify as a compliance check to ensure CO emissions are within limitations. If EPA 

retains the Method 10 compliance test requirement, it should be no more frequent than once 

every 5 years. 

Response: See the response to EPA-HQ-OAR-2006-0790-1657.1, Comment Excerpt Number 

13.

Commenter Name: Daniel Moss

Commenter Affiliation: Society of Chemical Manufacturers and Affiliates

Document Control Number: EPA-HQ-OAR-2006-0790-2018.1

Comment Excerpt Number: 18

Comment: SOCMA would support an opacity limit, enforceable through traditional means, in 

lieu of a numerical PM limit that would be enforced through COMS. 
Response: The final rule does not implement this approach. A COMS, if used under the rule, 

will be used to ensure continuous compliance with an opacity operating limit.

Commenter Name: Richard Bellefleur

Commenter Affiliation: Wellons FEI, Corp

Document Control Number: EPA-HQ-OAR-2006-0790-1300.1

Comment Excerpt Number: 3

Comment: Wellons does support testing wood fired units when they are first put into service. 

This helps ensure that the equipment was designed and built in order to meet regulations. Having 

to test the units once every year, will put significant financial burden on the system users, 

especially in the smaller end range. Good maintenance programs and yearly shut downs and 

inspections should be sufficient in order to maintain the equipment performing as it was when it 

was initially tested. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Rich Raiders

Commenter Affiliation: Arkema Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1958.1

Comment Excerpt Number: 8

Comment: In the proposed Boiler MACT, Boiler GACT, and CISWI proposals, EPA proposes 

initial and periodic compliance tests. EPA should refine the periodic testing proposal to reduce 

the undue burden on owners and operators, especially in the Boiler GACT source category. 

The annual Boiler GACT testing requirement is unprecedented for area sources complying with 

Part 63 standards applying exclusively to area sources. Nowhere in the language of § 112(k), the 

GACT statutory authorization, did Congress instruct EPA to regulate area sources with the same 

rigor as major sources. GACT standards, by their nature, should not be as stringent as MACT 

standards. GACT compliance demonstrations, by definition, should be less onerous than MACT 

compliance demonstrations. GACT sources should not be subject to any annual stack testing of 

any boiler. If EPA believes that periodic boiler testing is required, a frequency of every fiveto ten 

years is adequate, given the limited resources available to the typical GACT facility. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Andrea Grant
Commenter Affiliation: Castle Oil Corporation

Document Control Number: EPA-HQ-OAR-2006-0790-1945.1

Comment Excerpt Number: 2

Comment: If even assuming the EPA determines that it must regulate POM, it is not required to 

apply a MACT standard to control that pollutant. Section 112(d)(5) of the Clean Air Act 

provides an alternative approach for controlling pollutants from Area Sources listed pursuant to 

Section 112(c). EPA is authorized to impose GACT emission standards or management practices 

on such sources. Because the boilers that would be subject to the proposed rule are listed 

pursuant to both Sections 112(c)(3) and (c)(6), EPA is permitted to impose either a GACTdetermined numerical emission standard or a management practice on such sources. 

The Agency has already found that a management practice -- a mandatory biennial tune-up 

program -- will meet the required public health and environment objectives embodied in Section 

112 for very small boilers. EPA determined that compliance with numerical emission standards 

would be infeasible due to technical and economic limitations. However, Section 112(d)(5) 

provides for the adoption of the same management practice without any need to determine if 

compliance with numerical emission standards are not feasible. 

Response: See the preamble for discussion.

Commenter Name: Renee Lesjak Bashel

Commenter Affiliation: Small Business Environmental Assistance Programs, SBEAP

Document Control Number: EPA-HQ-OAR-2006-0790-2195.1

Comment Excerpt Number: 7

Comment: Or instead of eliminating the energy assessment, use it as an alternate to the stack 

testing requirement 

for units under 100 MMBTU/hr. It could include a requirement that some percentage of the 

recommendations for energy efficiencies be adopted in order to avoid stack testing. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Andrea Grant

Commenter Affiliation: Castle Oil Corporation

Document Control Number: EPA-HQ-OAR-2006-0790-1945.1

Comment Excerpt Number: 9

Comment: EPA should exempt the very smallest units (less than 3MMBtus/hr) from the 

NESHAP rule entirely and impose a management/work practice requirement of biennial boiler 

tune-ups on those boilers (new and existing) with a heat input capacity between 3 and 9.99 
MMBtus/hr. Moreover, because EPA has not assembled more than very limited data for boilers 

with a heat input capacity below 30 MMBtus/hr, the Agency should apply the management/work 

practice requirement to those boilers as well. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Renee Lesjak Bashel

Commenter Affiliation: Small Business Environmental Assistance Programs, SBEAP

Document Control Number: EPA-HQ-OAR-2006-0790-2195.1

Comment Excerpt Number: 11

Comment: Recommendation: Reduce the frequency or completely eliminate the periodic testing 

required for 

units below 100 MMBTU/hr. A new compliance test in the event a change is made to the unit 

that 

would impact the results of the initial compliance test, is reasonable. 

In most state air permits, the smallest sources are only required to conduct a one-time 

compliance 

demonstration test to establish parameters for periodic monitoring. The only time an additional 

compliance test is required is in the event something changes (e.g., primary fuel, reconstruction) 

that 

would impact the performance experienced during the initial test. A similar practice for 

compliance 

demonstration with this rule would make the most sense. 

Since 100 MMBTU/hr is already used in this rule as a threshold for applying more stringent 

requirements, 

this would make the most sense as a cut off for more frequent testing. Even then, something less 

frequent is more reasonable for area sources. If an area source is required to get a Title V permit, 

then 

testing for each permit renewal, once every five years, to re-establish the monitoring parameters 

would 

be a reasonable frequency. In some states, a single stack must have emissions at the major source 

level 

(100 TPY of criteria pollutants) before more frequent testing is required, such as a biennial basis 

– still 

not annual. 

Response: We disagree with the commenters’ assertions that the performance testing 

requirements are excessive. As discussed earlier, the combination of periodic compliance 

emissions testing and continuous monitoring of operational and parametric control measure 
conditions is appropriate for assuring continuous compliance with the emissions limitations. 

Without recurring testing, we would have no way to know if parameter ranges established during 

initial performance testing remained viable in the future.

Commenter Name: David J. Prior

Commenter Affiliation: New York State Energy Research and Development Authority, 

NYSERDA

Document Control Number: EPA-HQ-OAR-2006-0790-1913.2

Comment Excerpt Number: 11

Comment: For units equal to or smaller than 2 mmBtu/h, each model should be tested rather 

than require initial compliance or annual stack testing on each unit. 

Response: Please see preamble for information on current requirements, including work 

practice standards for all units under 10 MMBtu/hr.

Commenter Name: Andrea Grant

Commenter Affiliation: Castle Oil Corporation

Document Control Number: EPA-HQ-OAR-2006-0790-1945.1

Comment Excerpt Number: 14

Comment: EPA has proposed a complex and costly rule for Area Source boilers. The rule 

appears to be based largely on data from EPA’s investigation of larger boilers -individual boilers 

with a heat input capacity of 30 MMBtus/hr and greater. There is limited evidence that either 

new or existing smaller boilers could meet the proposed standards for PM and CO. Moreover, 

the fuel oil industry and certainly owners/operators of the boilers subject to the rule lack 

experience testing for these components and lack the necessary equipment to conduct such tests. 

Its purchase or the reliance on an outside, independent testing firm would be very costly and 

burdensome, imposing significant harm on an entire industry in which there are many small and 

medium-sized companies. 

Accordingly, EPA should: 

1. Withdraw the proposed rule as it applies to Area Source oil-fired boilers. There is insufficient 

evidence to show that regulation of such boilers is needed under the requirements of Section 112 

of the Clean Air Act; 

2. In the alternative, (1) exempt oil-fired boilers with a heat input capacity of less than 3 

MMBtus/hr from the rule; (2) permit all oil-fired boilers (new and existing) with a heat input 

capacity between 3 and 9.99 MMBtus/hr to meet the NESHAP obligations by establishing a 

management/work practice of a boiler tune-up program to be performed every two years on each 

regulated boiler; and (3) consider allowing oil-fired boilers (new and existing) with a heat input 

capacity between 10 and 30 MMBtus/hr also to comply with the management/work practice. 
3. If the Agency determines it must establish numerical emission standards to regulate Area 

Source boilers, then, at the very least, withdraw the current proposal; 

adopt a number of additional subcategories reflecting (a) the size of different oil-fired boilers as 

discussed above, and (b) the different operation of smaller connected boilers; and establish 

realistic and achievable standards that will not unduly burden the regulated community. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: David J. Prior

Commenter Affiliation: New York State Energy Research and Development Authority, 

NYSERDA

Document Control Number: EPA-HQ-OAR-2006-0790-1913.2

Comment Excerpt Number: 17

Comment: Small businesses and institutions should not have to undergo costly stack tests. The 

above recommendations will prevent undue expenses and retain the environmental benefits 

intended by the Area Source Boiler Rule. Fuel switching is not a viable option for many New 

York boiler operators. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Leon Lataille

Commenter Affiliation: Massachusetts Water Resources Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1896.1

Comment Excerpt Number: 6

Comment: As the owner of small boilers ranging in size (10 from 0.23 to 1.0 MMBtu/hr, 16 

from 1.0 to 5.0 MMBtu/hr, and 8 from 5.0 to 9.0 MMBtu/hr), the requirement for annual testing 

for new small boilers will become an issue as the replacement of these boilers occurs. The cost of 

stack testing for small boilers is out of proportion to the attendant benefit, particularly in the case

of boilers with low fuel consumption, on the order of 5,000 gallons per year of less. Testing in 

these cases becomes a significant percentage of the annual cost of operation. Biennial tune-ups 

of new boilers would seem to be a more appropriate approach to compliance. 

Response: Please see preamble for information on current requirements, including work 

practice standards for all units under 10 MMBtu/hr.
Commenter Name: Jon Bolling

Commenter Affiliation: Prince of Wales Community Advisor Council

Document Control Number: EPA-HQ-OAR-2006-0790-1935.1

Comment Excerpt Number: 7

Comment: Eliminate source testing requirements 

The proposed NESHAP rule for area sources requires management practices (a maintenance 

plan) for existing and new biomass boilers. Annual source testing is required for all boilers 

installed after June 4, 2010. Above, annual source testing could increase the O&M costs for an 

installation by 30 times. 

The costs to these small rural communities to source test these boilers will be immense. 

Installation of controls required to meet the emission standards will incur increased capital and 

operating costs. Costs will be further exacerbated by the high costs to transport and house 

technicians to perform required maintenance. EPA argues in the RICE NESHAP proposed rule 

that source testing is too expensive to be justified for smaller engines not subject to numerical 

emission standards. Since EPA acknowledges cost as a consideration, should EPA demonstrate 

by regulation that urban HAP standards do apply to rural areas, rural Alaska should be subject to 

GACT, not MACT, and EPA should limit the area source requirements to maintenance and 

management practices. 

Response: Please see preamble for information on current requirements, including work practice 

standards for all units under 10 MMBtu/hr.

Commenter Name: Jim Pettiford

Commenter Affiliation: Fulton Thermal Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2192.1

Comment Excerpt Number: 8

Comment: Fulton has recently taken initial steps to review the North American biomass?fired 

boiler sector with European’style, ultra?low emissions, combustion technology. Fulton believes 

that cleaner combustion performance by biomass?fired boilers will be necessary for the 

long?term market acceptance of solid biomass fuels as renewable energy resources. Fulton 

nevertheless wishes to express concern about the proposed Area Source Boiler Rule 

requirements as would apply to 

biomass?fired systems. 

We believe that the proposed PM emission limit of 0.03 lb/MMBTU can be generally achieved 

by advanced technology, biomass?fired boilers, either with well?engineered, staged combustion 

or through the retrofit installation of electrostatic precipitators or baghouse filters. The proposed 

rule would require, however, annual PM and CO emission testing for all biomass?fired boilers, 

regardless of size, installed after the June 4, 2010 publication date of the proposed Area Source 

Boiler Rule. 
It has been documented in European testing that the long?term, field performance of ultra?clean 

(under 0.05 lb/MMBTU), biomass?fired boilers will generally be within acceptable tolerances of 

laboratory certification testing results so long as clean, uncontaminated biomass fuel is used for 

boiler operation. 

Fulton therefore recommends that USEPA establish a regulatory process for biomass?fired 

boilers under 10 MMBTU per hour capacity which requires PM and CO emission testing by the 

manufacturer at the time of product certification under other (e.g., UL) standards, but which 

allows instead for an annual tune?up, including CO emission testing, to ensure clean, long?term 

boiler performance. 

Response: Please see preamble for information on current requirements, including work 

practice standards for all units under 10 MMBtu/hr.

Operating Parameter Monitoring

Commenter Name: Barry Christensen

Commenter Affiliation: Occidental Chemical Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2227.1

Comment Excerpt Number: 8

Comment: Averaging times for operating parameters require clarification. Since daily averages 

are specified for CO for oil fired units, it would greatly facilitate implementation of the rule if 

EPA amended the final rule to require that any operating parameter limits also be specified as 

daily averages. OCC respectfully requests that EPA revise the final rule to require that operating 

parameter limits be measured as daily averages. 

Response: The final rule clarifies the averaging periods that apply based on the monitoring and 

testing that applies. Generally, if a CEMS is used, a 30-day rolling average applies. Opacity 

uses a 24-hour block average, while other operating parameters generally use a 4-hour block 

average to be generally consistent with the anticipated length of conducting a performance test. 

For initial and annual performance tests, compliance is determined based on the actual test 

period for a specific test.

Commenter Name: Charles B. Jones, III

Commenter Affiliation: Georgia Traditional Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1923.1

Comment Excerpt Number: 9

Comment: The requirement for parametric monitoring of differential pressure (DP) and flow 

rate on scrubbers cannot be justified for true minor sources of HAP emissions that have 
voluntary controls that reduce other pollutant types. Further, sources that installed air pollution 

devices (APCDs) to become synthetic minor (SM) area for pollutants not directly addressed by 

this rulemaking — whether criteria pollutants or HAP, should likewise not be subject to 

parametric monitoring not already required by their current air operating permits. For example, 

facilities with mercury emissions well below the major source threshold and therefore not 

triggering MACT would not have added controls for that reason. The rules would place MACT 

on these sources for mercury emissions when they are not a major source of mercury under the 

Clean Air Act. 

Response: Table 6 of the final rule clarifies that the operating parameters such as pressure drop 

from wet scrubbers are only required if the unit is subject to an emission limit and the unit has a 

wet scrubber installed. If a unit not subject to an emission limit, such as an existing biomass unit, 

then there is no need to subject that unit to parametric monitoring.

Commenter Name: Chris V. Isaacson

Commenter Affiliation: Alabama Forestry Association

Document Control Number: EPA-HQ-OAR-2006-0790-2060

Comment Excerpt Number: 11

Comment: The proposed energy audit requirements are not needed or justified. 

The proposed rule would require all existing affected units to conduct a one-time "energy 

assessment" in order to "identify energy conservation measures (such as process changes or other 

modifications to the facility) that can be implemented to reduce the facility energy demand 

which would result in reduced fuel use." 75 Fed. Reg. at 31907. The Agency asserts that, 

"Reduced fuel use will result in a corresponding reduction in HAP, and non-HAP, emissions." 

Id. This work practice requirement is an "above the floor" measure that EPA argues is justified in 

light of the emissions reductions and cost savings that can be realized by identifying and 

implementing energy efficiency projects. 

This proposed requirement is beyond EPA’s authority and should not be included in the final 

rule. To begin, EPA is only authorized under 112 to regulate "sources" of HAPs. For example, 

112(d)(1) explains that EPA may distinguish among classes, types, and sizes of sources within a 

category or subcategory in establishing ... standards" (emphasis added). More particularly, 

112(d)(2)(A) authorizes EPA to establish standards that would "reduce the volume of, or 

eliminate emissions of, [HAPs] through process changes, substitution of materials or other 

modifications"; however, this authority is limited in 112(d)(2) standards regulating "sources in 

the category or subcategory to which such emission standard applies." The term "source" 

unambiguously means something that actually emits HAPs. Because the proposed energy 

assessment requirement would apply to processes that demand energy from affected boilers, but 

are not necessarily sources of HAPs themselves, EPA’s proposal exceeds the Agency’s limited 

authority to regulate only HAP "sources." 

In addition, EPA proposes in 63.11194 to define the affected source under this rule to include 

only "industrial, commercial, and institutional boilers." EPA further proposes to define the terms 
"industrial boiler," "commercial boiler," and "institutional boiler" to include only boilers and not 

other parts of the facilities to which the boilers belong. 75 Fed. Reg. at 31931 (proposed 

63.11237). By the very terms of the proposed rule, the affected source category only includes 

boilers. Thus, the proposed energy assessment requirement is not supportable because it would 

apply to equipment that is not part of the source category being regulated. 

Response: Please see preamble for discussion of energy audit requirements.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 38

Comment: UARG objects to EPA’s proposal to set enforceable operating limits based on 

control device parameters measured during performance testing. Establishment of such limits 

reduces operational flexibility, deprives sources of the use of any control device margin, and 

allows enforcement for events beyond the owner/operator’s control. 

EPA’s current proposal is based on the faulty assumptions that the values of the parameters 

identified by EPA have a direct relationship to the level of emissions, and that exceedances of 

those limits therefore indicate an exceedance of the emission limit as well. To the extent 

possible, source owners and operators will contract for control equipment that is designed to 

provide a “margin of compliance” with the applicable emission limitation. [Footnote: For 

example, it is relatively common for new ESPs to be purchased with extra fields and sections 

which will allow the source to continue to operate in compliance with applicable emission limits 

even when there are problems with other parts of the controls. Fabric filters and scrubbers can 

also be purchased with extra capacity (i.e., additional modules) for the same purpose.] In 

addition to reducing the possibility of an exceedance of the limit, this margin is intended to 

provide flexibility for the source to account for an inevitable control equipment or operational 

problem. Any source that is able to normally operate with a margin of compliance will loose part 

of that margin of compliance if they conduct performance testing under normal operations, 

because they will establish operating limits that would require them to continue to over-control 

forevermore. The only way such sources could avoid surrendering whatever margin of 

compliance they have would be to deliberately reduce performance of their controls to attempt to 

generate the least stringent operating limits consistent with achievement of the applicable 

emission standard. EPA’s proposal thus has the perverse result of encouraging sources to focus 

their attention on learning how to manipulate their operations to allow testing as close as possible 

to their emission limit by reducing performance of their controls. 

Unfortunately, even the “detuning” of a control device during performance testing will not 

ensure that the operating limits established during the test are reasonable, or necessary for 

achievement of the applicable emission limit. As EPA has previously recognized in the context 

of the NSPS and the CAM rule “many sources operate well within permitted limits over a range 

of process and pollution control device operating parameters,” and requiring sources to 
continuously maintain parameters that “happened to exist” during the most recent performance 

test may not be “possible or wise.” 62 Fed. Reg. 54,900, 54,907, 54,926-27 . 

That is because control device parameters, such as those identified by EPA for scrubbers and 

ESPs, do not necessarily have a direct relationship to emissions, but instead are interrelated with 

the design of the control device and the interaction of various parameters. As a result, a single 

parameter may vary widely with little effect on emissions. See UARG Comments on Proposed 

National Emission Standards (Mar. 14, 2003), EPA-HQ-OAR-2002-0058-0413, Attachment C 

(incorporated by reference). For example, total ESP power may be completely unrelated to ESP 

performance for a multi-sectional ESP. Id. at 2 and Appendix 1. This power approach for ESPs 

simply does not work and that fact is easily demonstrated in the cited material. Similarly, 

because scrubber pressure drop and liquid flow rate are usually a function of boiler load, 

recording levels of those parameters above or below those recorded during a performance test are 

not necessarily indicative of emissions levels at a different load. Id at 2. Many industrial boilers 

operated at variable load levels because they follow process demand. As the load drops, the 

scrubber pressure drop also moves down. This change does not necessarily indicate a drop in 

scrubber performance. In fact, the scrubber performance is likely to improve at reduced load. 

Although EPA’s provision of a 10 percent difference from the average tested value recognizes 

some of the normal operational variability of control devices, it may not be sufficient in some 

circumstances. Without a clear correlation between such operating parameters and the applicable 

emission limit, imposition of those values as enforceable limits would unreasonably restrict 

source and control device operation and subject sources to potential enforcement without any 

evidence that an emission limits has been violated. 

Response: We believe that continuous monitoring is needed to ensure ongoing compliance with 

this rule. In order to minimize costs, we look for parameters that are already monitored to use for 

compliance demonstration. Operating limits are not direct measures of emissions, but provide 

measure of fuel characteristics and control device performance. We require performance tests to 

demonstrate compliance with emission limits, and then use operating limits to ensure the source 

is operating similarly to how it was operating when it completed a successful performance test. 

Under the final rule, we clarify that tests are to be performed under representative operating 

conditions. Also in response to comments, EPA reviewed the proposed procedure for 

establishing the operating parameter limits (i.e., calculated as the average of three test runs and 

as 90 percent of the average value recorded during the applicable performance tests) and 

concluded that it may be too restrictive on control device operations in terms of energy or other 

operating needs. We determined that the operating limits should be more appropriately based on 

values recorded during the performance test runs. The final rule requires that operating limits be 

established on a site-specific basis as the minimum (or maximum, as appropriate) operating 

parameter value measured over a single test run during the performance test. This approach has 

been incorporated into the final rule for all applicable operating parameters and will result in 

achievable operating ranges that will ensure that the control devices used for compliance will be 

operated to achieve continuous compliance with the emissions limits.
We have also provided for scaling certain parameters such as sorbent injection rate based on the 

operating load, to address load conditions that are less than those that occur during testing. You 

are also able to petition the Administrator for approval of an alternative monitoring plan under 

section §63.8(f) of subpart A of part 63.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 40

Comment: EPA’s proposal to use these parameters is subject to the same flaws as EPA’s other 

proposed operating limits -- namely the lack of a sufficient relationship between the parameters 

measured during performance testing and actual emissions. For example, as described above, 

because scrubber pressure drop, liquid flow rate, and sorbent injection rate vary with boiler load, 

establishment of a limit based on conditions during performance testing may tell EPA little about 

actual emissions under other load conditions. Moreover, when EPA in 2008 considered the 

relationship between liquid flow rate and PM in the context of the NSPS for electric steam 

generating units at 40 C.F.R. Subpart Da, EPA concluded that, at the level of the NSPS (i.e., 

0.015 lb/mmBtu), PM emissions controlled by an ESP were not particularly sensitive to the 

actual liquid flow rate. EPA “Response to Public Comments on Rule Amendments Proposed 

June 12, 2008 (73 FR 33642)” (Nov. 2008), EPA-HQ-OAR-2005-0031-0284, at § 2.5.3. 

Response: See the response to EPA-HQ-OAR-2006-0790-1957.1, Comment Excerpt Number 

38.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 45

Comment: According to the preamble, EPA intends to propose (1) that units with wet scrubbers 

and an ESP and/or fabric filter establish and comply with ESP operating parameters and/or a 

BLDS, and (2) that units without a wet scrubber comply with an opacity standard, unless they 

have a fabric filter, in which case they must use a BLDS. 75 Fed. Reg. at 32,013-14. In other 

words, (1) a source with an ESP without a wet scrubber would not have the option of monitoring 

ESP parameters in lieu of opacity, (2) a unit with a fabric filter without a wet scrubber would not 

have the option of monitoring opacity in lieu of a BLDS, and (3) a unit without a wet scrubber 

that has an ESP and a fabric filter would only use a BLDS. However, that is not what the 

proposed rule language requires. 

First, the rule clearly provides that use of a BLDS if optional, at least for a unit with a dry control 

system. Second, the rule appears in one place to require all units with an ESP to establish 

minimum voltage and secondary current (or total power), but in other parts clearly limits use of 
ESP operating parameters to units with wet scrubbers. Third, the rule does not reflect any 

exemption from opacity monitoring for units with a fabric filter and a BLDS. In short, not only 

does the preamble conflict with the rule, the rule itself is internally inconsistent. 

UARG understands that units with wet control systems cannot monitor opacity and as a result 

must use some other technique. As a result, for units with wet scrubbers, UARG supports the use 

of ESP parameters as indicator monitoring as described in section D.2. However, if such 

parameters are sufficient for units with wet scrubbers, UARG does not understand why they also 

would not be sufficient for units with dry controls. As a result, EPA should remove the rule 

language restricting use of ESP parameters to units with wet controls and offer source 

owners/operators the choice. For units with fabric filters, EPA should revise its preamble to be 

consistent with the proposed rule, which clearly allows fabric filter equipped units with dry 

control systems the choice of using opacity instead of a BLDS. EPA also should revise to make 

clear that units complying with an opacity standard do not have to establish ESP operating 

parameters. 

Response: Under the area source standards, the options requested in these comments are 

allowed. Typically, for larger boilers EPA would not consider opacity as the most appropriate 

option for units with a fabric filter, but has provided additional flexibility for the smaller units 

subject to this subpart. 

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 47

Comment: EPA Should Include Longer Averaging Times For Operating Parameters And CO 

Emissions. The industrial boilers that will be subject to this rule may burn more than one type of 

fuel and may have frequent load swings. Therefore, the emissions from these boilers will vary 

over the course of a day, depending on the fuel burned and the required steam production. EPA 

acknowledged during the Phase 2 ICR stack test program that emissions from industrial boilers 

are variable by requesting multi-year historical stack test data and conducting 30-day fuel and 

emissions monitoring studies. We believe that additional variability data and CEMS data should 

be reviewed to support longer averaging times, especially since lengthening averaging times and 

incorporating variability seems to be EPA’s preferred approach for addressing emissions during 

startups, shutdowns, and malfunction periods. The court reviewing the Brick MACT authorized 

EPA to look at intra-unit variability and EPA’s work on the Hazardous Waste Combustion 

MACT confirmed the importance of considering variability. The EPA also acknowledged that 

averaging times longer than 3 hours can be appropriate for compliance with the condensate 

collection and treatment requirements in Pulp and Paper MACT, Subpart S. Therefore, it is 

inappropriate for EPA to set limits in this area source boiler rule that cannot be met consistently 

by a top performing unit under all operating conditions. One way to consider a unit’s variability 

in emissions is to set a longer averaging time for compliance with an emission limit. 
Averaging times of longer than 3 hours are needed for industrial boilers, especially those that 

burn multiple fuels and have varying emissions characteristics, in order to preserve operational 

flexibility and ensure cost-efficient operation of the boiler. The facility must be able to operate 

the boiler in a manner that is responsive to process needs, not at full load all the time. Longer 

averaging periods are also desirable if the emission limits are going to apply at all times, 

including periods of startup, shutdown, and malfunction. The proposed rule specifies 3-hour 

averages are to be calculated for operating parameters [75 Fed. Reg. 31928], although the 

preamble states that daily averages should be calculated [75 Fed. Reg. 31902]. We support daily 

block averages for CPMS. A 24-hour averaging period acknowledges process variability, lessens 

the effect of short process upsets on compliance, and captures the variable emissions and 

operating characteristics of a unit over an operating day. 

Response: The final rule uses 4-hour block averages for the control device operating limits in 

this rule. That period is established to be generally consistent with the anticipated period for 

performance tests under this subpart.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 51

Comment: On October 9, 2008, EPA proposed PS 17 and amendments to the Part 63 general 

provisions to address selection and installation of CPMS and ongoing quality assurance of data 

from CPMS (in Procedure 4). 73 Fed. Reg. 59,956 (Oct. 9, 2008). Proposed PS 17/Procedure 4 

covers CPMS used to measure and record temperature, pressure, liquid flow rate, gas flow rate, 

mass flow rate, pH, or conductivity on a continuous basis. UARG submitted detailed comments 

objecting to several aspects of EPA’s proposal, including EPA’s proposal to make the final 

specifications applicable in lieu of requirements in the individual Part 63 subparts, without any 

revision of those subparts to consider or reference applicability of the new requirements. UARG 

Comments, EPA-HQ-OAR-2006-0640-0064 (Feb. 5, 2009) (incorporated by reference). 

Although EPA has since indicated in its regulatory agenda its intention to issue a supplemental 

proposal to address comments received on that proposal, EPA has not withdrawn its prior 

proposal. As a result, UARG continues to object to EPA’s proposed approach and to any 

automatic applicability of additional requirements to this rule without subsequent proposal and 

revision of this rule. EPA has adequate opportunity to propose whatever performance 

specifications it deems appropriate in this rulemaking. 

Response: The Agency acknowledges the commenter's concerns on the continuous parameter 

monitoring system performance specifications and quality assurance procedures proposal, but 

notes that this action is for the Boiler MACT proposal. The Agency agrees with the commenter 

that the Agency is able to propose appropriate performance specifications in this and any other 

rulemaking. In keeping with this ability, the Agency has developed and finalized specific 

requirements for performance specifications for this rule, allowing source owners or operators to 
develop plans customized for their sites. Source owners or operators are encouraged to build on 

their existing practices, rather than start from scratch, to minimize the burden associated with 

providing a continuous assurance of compliance as required by the statute.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 49

Comment: There are discrepancies in the monitoring discussion in the preamble versus the rule 

tables. For example, the preamble calls for monitoring for pressure drop and liquid flow rate and 

"maintain the daily block averages at or above the minimum operating limits established during 

the performance test." 75 FR 31902. This requirement however is not included in Table 3. 75 FR 

31914. EPA should expand this table should to also include operating limits for boilers that have 

PM limits and use control devices to comply with those limits. For a comprehensive discussion 

of operating limits, please refer to CIBO’s comments on the Proposed Boiler MACT Rule. [See 

DCN: 2006-0790-1783.2 for related comments.] 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1957.1, Excerpt Number 45.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 51

Comment: EPA proposes that operating parameters measured during performance tests should 

constitute minimum site-specific operating requirements subsequent to the performance test. It is 

inappropriate and in many cases not technically feasible to use operating conditions during a 

performance test, which are typically conducted at or near the unit’s maximum firing rate, to 

establish a minimum requirement for all possible load ranges. EPA should amend the Proposed 

Rule to allow for optimum system operations and ratio-type parameters. The following 

comments detail why the current proposal is unacceptable. 

EPA sets minimum required operating parameters at high load conditions, which are applicable 

to all operating conditions going forward. This approach is unacceptable. EPA’s function is not 

to dictate how a source operates each and every unit, but instead to limit emissions impacts to the 

environment. It is unreasonable to place many of the hard limits derived from the operating 

limits approach on a facility long term. 

With many pollution control technologies, the proposed approach to establishing and 

maintaining minimum operating limits would result in needless over-consumption of sorbents at 

great cost to the facility with little or no commensurate benefit to human health. As an example, 
the sorbent injection rate of activated carbon for the control of mercury varies with the volume of 

flue gas generated during combustion. To establish a minimum sorbent injection rate at or near 

the unit’s maximum continuous rating (MCR) would result in nearly double the sorbent injection 

rate during turndown to 50% load. While such an approach may work for based loaded utility 

boilers, there are a great diversity of units and operating conditions affected under this rule as 

compared to utility-type units. Institutional, commercial and industrial boilers vary loads widely 

based on site conditions, business conditions, season and time of day, this would result in 

pointless expense to the facility with no benefit to the environment or to human health. Similar 

issues arise with use of scrubbers relative to load or throughput variations and their impact on 

operating parameters. 

Response: See the response to EPA-HQ-OAR-2006-0790-1957.1, Comment Excerpt Number 

38.

Commenter Name: Gary Melow

Commenter Affiliation: Michigan Biomass

Document Control Number: EPA-HQ-OAR-2006-0790-1917.1

Comment Excerpt Number: 11

Comment: Active combustion controls utilizing an O2 monitor with either an automatic or 

adjustable air distribution system managed full time by boiler operators would achieve the 

purpose of ensuring good combustion in large biomass or solid fuel-fired units. EPA should 

consider the use of an O2 monitor with alarm for mid-sized biomass or solid fuel boilers. This 

would provide a good indication of proper combustion. 

Response: Under the Part 63 general provisions, an owner /operator can always request an 

alternative monitoring method. EPA agrees with the commenter's general point that there will be 

situations in which alternatives to the methods specified in the rule can provide a reasonable 

assurance of compliance.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 17

Comment: Duke Energy strongly disagrees with EPA’s current proposal to set enforceable 

operating limits based on control device parameters measured during performance testing. 

Establishment of such limits reduces operational flexibility, deprives sources of the use of any 

control device margin, and allows enforcement for events beyond the control of the 

owner/operator. 
EPA’s proposal is based the faulty assumptions that the values of the parameters identified by 

EPA have a direct relationship to the level of emissions, and that exceedances of those limits 

therefore indicate an exceedance of the emission limit as well. To the extent possible, source 

owners and operators will contract for control equipment that is designed to provide a “margin of 

compliance” with the applicable emission limitation.[Footnote: For example, it is relatively 

common for new ESPs to be purchased with extra fields and sections which will allow the source 

to continue to operate in compliance with applicable emission limits even when there are 

problems with other parts of the controls. Fabric filters and scrubbers can also be purchased with 

extra capacity (i.e., additional modules) for the same purpose.] In addition to reducing the 

possibility of an exceedance of an emission limit, this margin is intended to provide flexibility 

for the source to account for the inevitable control equipment or operational problem. Any 

source that is able to normally operate with a margin of compliance will lose part of that margin 

of compliance if they conduct performance testing under normal operations, because they will 

establish operating limits that would require them to continue to over-control forevermore. The 

only way such sources could avoid surrendering whatever margin of compliance they have 

would be to deliberately reduce performance of their controls to attempt to generate the least 

stringent operating limits that are consistent with achievement of the applicable emission 

standard. EPA’s proposal thus could have the perverse outcome of encouraging sources to focus 

their attention on learning how to manipulate their operations to allow testing as close as possible 

to their emission limit by reducing performance of their controls. 

Unfortunately, even the “detuning” of a control device during performance testing will not 

ensure that the operating limits established during the test are reasonable, or necessary for 

achievement of the applicable emission limit. As EPA has previously recognized in the context 

of the NSPS and the CAM rule, “many sources operate well within permitted limits over a range 

of process and pollution control device operating parameters,” and requiring sources to 

continuously maintain parameters that “happened to exist” during the most recent performance 

test “may not be possible or wise.” 62 Fed. Reg. 54907, 54926-27. This is because control device 

parameters, such as those identified by EPA for scrubbers and ESPs, do not necessarily have a 

direct relationship to emissions, but instead are interrelated with the design of the control device 

and the interaction of various parameters. As a result, a single parameter may vary widely with 

little effect on emissions. For example, total ESP power may be completely unrelated to ESP 

performance for a multi-sectional ESP. This power approach for ESPs simply does not work and 

that fact is easily demonstrated by real world operating experience. Precipitator power will vary 

depending upon a number of factors including operating conditions, coal quality, etc, a fact that 

Duke Energy routinely sees in the operation of its own units. Similarly, scrubber pressure drop is 

a direct function of boiler load. A basic engineering principles is that pressure drop through a 

restriction such as a scrubber vessel is a directly related to velocity. As the velocity increases, the 

pressure drops. Recording pressure drop during a performance test will not be indicative of 

emissions levels at a different load. Industrial boilers operate at variable load levels because they 

follow process demand. As the load drops, the scrubber pressure drop decreases. This change 

does not necessarily indicate a drop in scrubber performance. In fact, the scrubber performance is 

likely to improve at reduced load. Unfortunately as EPA has proposed the standard, simply 

reducing load will put a source in a condition of non-compliance.” 
Similarly scrubber flow will also change depending upon operating conditions and system 

chemistry requirements such as the required slurry density. Many sources do not normally install 

flow meters in this situation and installing them in this application will be costly and fraught with 

monitoring difficulties and inaccuracies. If EPA feels that it needs a metric to ensure proper 

scrubber operation, it should limit its requirements to operating the same number of scrubber 

flow pumps that a source used during the performance test, and demonstrate that the flue gas is 

indeed going through the scrubber module and not being bypassed. 

Although EPA’s provision of a 10 percent difference from the average tested value recognizes 

some of the normal operational variability of control devices, it will not be sufficient in many 

circumstances. Without a clear correlation between such operating parameters and the applicable 

emission limit, imposition of those values as enforceable limits would unreasonably restrict 

source and control device operation and subject sources to potential enforcement without any 

evidence that an emission limits has been violated. This is particularly important where EPA’s 

proposal runs counter to basic engineering principals. 

Units that use an ESP in combination with a wet scrubber (and thus cannot monitor opacity) 

must comply with operating limits on the voltage and secondary current (or total power input) of 

the ESP collection plates. Proposed 63.7530(b)(3)(ii). EPA’s proposal to use opacity and ESP 

voltage and power measurements as enforceable operating limits is flawed. The use of total 

power is not at all reliable as an indicator of ESP performance or problems. 

Finally, EPA’s proposal to require the use of ESP parameters has similar flaws. Total ESP power 

input is not directly related to particulate removal performance, particularly for the modern 

multi-section ESPs that are likely to be installed to comply with a MACT. Moreover, none of the 

ESP parameters are likely to have any relationship to PM for units that also have a wet scrubber, 

because a wet scrubber is also highly effective in controlling high levels of particulate matter 

coming out of an ESP that is not performing at its intended control efficiency. 

Under EPA’s proposal, units that use a wet scrubber must also comply with operating limits for 

pH, and units that use a dry scrubber must comply with an operating limit on sorbent injection 

rate. Proposed 63.7530(b)(3)(i) and (iii). EPA’s proposal to use these parameters is subject to the 

same flaws as EPA’s other proposed operating limits -- namely the lack of a sufficient 

relationship between the parameters measured during performance testing and actual emissions. 

For example, as described above, because pH and sorbent injection rate vary with boiler load and 

coal chemistry, establishment of a limit based on conditions during performance testing may tell 

EPA little about actual emissions under other load conditions. Moreover, when EPA in 2008 

considered the relationship between liquid flow rate and PM in the context of the NSPS for 

electric steam generating units at 40 C.F.R. Subpart Da, EPA concluded that, at the level of the 

NSPS (i.e., 0.015 lb/mmBtu), PM emissions controlled by an ESP were not particularly sensitive 

to the actual liquid flow rate. EPA Response to Public Comments on Rule Amendments 

Proposed June 12, 2008 (73 FR 33642), EPA-HQ-OAR-2005-0031-0284, at 2.5.3. 

Response: See the response to EPA-HQ-OAR-2006-0790-1957.1, Comment Excerpt Number 

38.
Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 20

Comment: Rather than establish enforceable operating limits, EPA should use the approach 

taken in the CAM rule and require sources to establish site-specific operating parameter ranges 

to define conditions under which compliance with the applicable limit can be reasonably assured. 

This approach already has been upheld as sufficient to satisfy the CAA’s requirements for 

demonstrating continuous compliance. See Natural Resources Defense Council v. EPA, 194 F.3d 

130 (D.C. Cir. 1999) (rejecting NRDC’s argument that the CAM rule’s “reasonable assurance of 

compliance” is not sufficient to assure continuous compliance as required by the CAA). Source 

owners and operators would then be required to monitor those parameters and respond to 

changes that indicate problems with the controls that could jeopardize compliance. 

Whether using a single control device or combination of devices, sources are in the best position 

to determine what parameters and levels are consistent with compliance. In many cases, multiple 

parameter relationships or supplemental operational data will provide a higher level of 

compliance assurance than the level that happens to be measured during a discrete performance 

test. This is particularly true for sources with a significant margin of compliance. In addition, 

units with significant margins of compliance should be allowed to establish operating levels by 

extrapolating parameter data beyond that obtained during a performance test based on other 

information. Allowing such extrapolations is essential for some sources to provide needed 

operational flexibility. Attempting to establish “worst case” test conditions on a scrubber or 

multi-section ESP, where the possible combinations of parameters are numerous, would at the 

least be difficult and could be impossible without a major research effort. Allowing extrapolation 

of results avoids the necessity of repeated testing.[Footnote: A similar approach has been used in 

CAM protocols, including a protocol developed by the Electric Power Research Institute (EPRI) 

for ESPs (allowing extrapolation up to 1.25 times the recorded value for measurements taken at 

less than 80 percent of the applicable emission limit).] 

Once sources have established appropriate operating parameter ranges based on data collected 

during performance tests, as well as other operating data and engineering principles, those 

parameters would be monitored and any deviation from them would trigger a requirement for 

investigation and corrective action to return the parameter to the appropriate range. Although this 

range may in some cases be similar to the minimum values that would be established under 

EPA’s proposed rule, allowing sources to respond with corrective action (rather than simply 

record exceedances and report deviations) achieves EPA’s intended result without subjecting 

sources to potential unreasonable enforcement. 

Response: See the response to EPA-HQ-OAR-2006-0790-1957.1, Comment Excerpt Number 

38.
Other - Testing and Monitoring

Commenter Name: Charles Niebling

Commenter Affiliation: New England Wood Pellet

Document Control Number: EPA-HQ-OAR-2006-0790-0836

Comment Excerpt Number: 14

Comment: Based on this approach, the initial and interim recommended limits and practices 

include: 

Initial independent third party certification test for biomass boilers to prove compliance. Once a 

boiler (or range of boilers) is tested, that boiler would be approved for installation until a change 

was made in the boiler design; 

Work practice standard for biomass boilers, consisting of an annual boiler tune-up according to 

manufacturers’ specifications. 

Combined with the revised limits above, initial emissions testing and work practice standards for 

maintenance will ensure that clean-burning boilers are installed and that they consistently

achieve high emission standards. NEWP believes that superior emission performance can be best 

achieved and be cost effective over the long-term with on-site tune-ups rather than onerous 

annual emission testing requirements for boiler owners. The proposed annual tune-up of boilers 

to meet manufacturers’ specifications is consistent with typical manufacturers’ recommendations 

for regular maintenance and is consistent with what the EPA has proposed for existing Area 

Source Boilers. 

Response: Please see the rule for changes to emission limits and work practice requirement.

Commenter Name: Los Angeles Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0397

Comment Excerpt Number: 73

Comment: All burning facilities must be subject to these standards and controls for air quality 

monitoring and reporting requirements. 

Response: Please see the final preamble for EPA’s rationale for determining the appropriate 

standards, testing, monitoring, and reporting requirements for the different subcategories of 

boilers subject to this rule.

Commenter Name: Gailyn Messersmith

Commenter Affiliation: Messersmith Manufacturing, Inc
Document Control Number: EPA-HQ-OAR-2006-0790-1949.1

Comment Excerpt Number: 6

Comment: Require initial 3rd party emissions compliance testing with annual tune-ups to insure 

the original manufacturer’s specifications are maintained. 

Response: Please see preamble for discussion of compliance requirements in the final rule.

Commenter Name: Eric Trauner

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2286

Comment Excerpt Number: 8

Comment: Stack testing demands should be lowered to biennial at first, then trending toward 

once per five years after two successful tests. It must be underlined that there are relatively few 

stack testing firms that are qualified to conduct such testing, and excessive testing will result in a 

rush of unqualified, inexperienced stack testers hitting the market. In turn, there would be a rush 

of flawed emissions data hitting the very database that US-EPA is seeking to create. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76. 

Category 11J.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 10

Comment: The EPA proposes that facilities conduct yearly performance tests for the first three 

years for affected sources that elect to demonstrate compliance with any of the emission limits 

through performance testing. Facilities could establish an every three-year schedule if the 

performance tests for the pollutant show that emissions are at or below 75 percent of the 

emission limit for at least three consecutive years. 

The EPA proposes that affected sources conduct performance tests at the "maximum normal 

operating load." However, this maximum normal operating load is not defined in the proposed 

rule. Facilities use different fuels depending on many variables such as availability and cost. 

Fuels are also combusted in different proportions throughout the year. The EPA should provide a 

clear definition of maximum normal operating load proposed in 63.11237. The EPA should also 

clearly define how a source that utilizes more than one fuel should comply with this requirement. 

Having this clearly defined is necessary not for only determining compliance with the emission 

standards, but also for adequately approving site-specific test plans that would be required in 

63.11212. 
Response: The final rule specifies the use of representative operating conditions.

Commenter Name: Richard Rosvold

Commenter Affiliation: Xcel Energy Services, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2259.1

Comment Excerpt Number: 10

Comment: §63.11223(b) states if you demonstrate compliance using a stack test, you have to 

prepare a site specific monitoring plan. However, the language related to monitoring plans 

applies to continuous monitoring systems that are used with add-on control devices. For CO in 

all categories, and possibly for PM on liquid-fueled units, this would not apply. EPA needs to 

clarify this language. 

Response: The EPA has minimized the testing and monitoring in the final rule. Please see the 

preamble for discussion on this topic.

Commenter Name: Barry Christensen

Commenter Affiliation: Occidental Chemical Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2227.1

Comment Excerpt Number: 19

Comment: Clarification is needed as to how temporary tube blowing is factored into compliance 

tests for particulate matter for new oil fired units. It is unclear to what extent these periods have 

been factored into the data base for coal and oil fired units or are to be considered when 

conducting performance tests for particulate. 

Response: The PM limits for new oil units are based off NSPS standards and no data was used 

to calculate the GACT floor. When performing stack tests for compliance boilers shall run at 

representative operating load conditions; temporary tube blowing should not occur during this 

testing.

Commenter Name: Kyle Gibeault

Commenter Affiliation: Biomass Thermal Energy Council, BTEC

Document Control Number: EPA-HQ-OAR-2006-0790-1914.1

Comment Excerpt Number: 25

Comment: The Biomass Thermal Energy Council (BTEC) has developed a suggested approach 

to developing common-sense regulations, which we believe will achieve improvements in air 
quality while balancing the costs of implementation. Messersmith Manufacturing, Inc. agrees 

with the recommendations of BTEC to 

1) begin with an initial minimum performance standard for Carbon Monoxide and Particulate 

Matter with reductions thereafter based on data collected the first two years of the Rule’s 

implementation and 

2) an initial third party certification test with required annual tune-ups without on-going costly 

stack testing. Once a boiler or range of boilers is/are tested that boiler/range of boilers would be 

approved for installation until a change was made in the boiler design. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76. 

Category 11J.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 26

Comment: UARG agrees performance testing should not be required any more frequently than 

annually, and supports inclusion of a reduced testing provision. However, UARG does not 

believe that the 75 percent criterion (or a 90 percent criterion) is reasonable given the extremely 

low levels of EPA’s proposed limits. UARG requests that EPA remove this restriction, which 

EPA did not deem necessary in the 2004 rule. EPA has provided no reason for this restriction, or 

data suggesting that any source could achieve 75 percent (or even 90 percent) of the proposed 

emission limits, some of which are established at or near the detection limit. UARG does not 

understand how a source could test at a percent of the detection limit. The requirement that 

source and control device operation remain consistent with prior successful testing should be 

sufficient to ensure representativeness of the prior test(s). 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76. 

Category 11J.

Commenter Name: Kyle Gibeault

Commenter Affiliation: Biomass Thermal Energy Council, BTEC

Document Control Number: EPA-HQ-OAR-2006-0790-1914.1

Comment Excerpt Number: 28

Comment: Wellons does support testing wood fired units when they are first put into service. 

This helps ensure that the equipment was designed and built in order to meet regulations. Having 

to test the units once every year, will put significant financial burden on the system users, 

especially in the smaller end range. Good maintenance programs and yearly shut downs and 
inspections should be sufficient in order to maintain the equipment performing as it was when it 

was initially tested. 

Response: Work practice standards are now in place for all units under 10 MMBtu/hr, no testing 

is required.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 43

Comment: To ensure that the proposed 24-hour block opacity standard is achievable during 

periods that include startups and shutdowns, when PM controls may not be at full efficiency, 

EPA should include a minimum data requirement for calculation of compliance with the 

proposed opacity standard. If EPA has established the 10 percent standard based on data showing 

that compliance is achievable with 24 hours of data, including startup and shutdown data, EPA 

should either (1) limit the compliance calculation to any day upon which the unit operates for at 

least 24 hours, or (2) combine data from the partial operating day with data from the prior or next 

day full operating day. This approach would be similar to that taken in 40 C.F.R. Subpart Da, 

60.48Da(g)(3) (stating that averages for compliance with the daily PM standard are only 

calculated for “boiler operating days that have valid data for at least 18 hours of unit operation 

during which the standard applies”), except that standard would apply at all times. If EPA does 

not have data demonstrating that the standard is achievable on a 24-hour block basis including 

startup and shutdown, EPA must provide a higher limit or a longer averaging period consistent 

with the data it has. EPA also must provide that data in the docket. 

Response: See the preamble for how SSM periods are handled in the final rule. EPA believes 

that a 24-hour block period for opacity is an appropriate period to ensure continuous compliance 

with good operating practices to minimize emissions.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 44

Comment: Under EPA’s proposal, units that use a fabric filter (whether or not using a wet 

scrubber) that choose to demonstrate continuous compliance using a BLDS (instead of 

monitoring opacity) must install, operate, calibrate and maintain a BLDS “for each exhaust stack 

of the fabric filter” consistent with the “manufacturer’s written specifications and 

recommendations” and in accordance with EPA’s “Fabric Filter Bag Leak Detection Guidance,” 

EPA-454/R-98-015 (Sept. 1997). The BLDS must be certified by the manufacturer to be capable
of detecting PM at a concentration of 10 milligrams per actual cubic meter or less. Id. The BLDS 

must be operated such that the “system alarm does not sound more than 5 percent of the 

operating time during any 6-month period.” Proposed § 63.7530(b)(3)(iv). Records must be kept 

of each alarm period. If inspection of the bag demonstrates that no corrective action is required, 

no alarm time is counted. If corrective action is required, the alarm time is counted as the actual 

time taken to initiate corrective action with a minimum of 1 hour counted for each alarm. 

Proposed § 63.7540(a)(7). In short, EPA largely proposes to simply repromulgate the BLDS 

requirements from the 2004 final rule. When UARG questioned several aspects of that rule as 

proposed, see UARG Comments, EPA-HQ-OAR-2002-0058-0413 at 24, EPA simply referred 

back to its 1997 guidance. See EPA Response to Public Comments, EPA-HQ-OAR2002-0058-

0611 at 114. 

The proposed requirement to follow all manufacturer specifications and recommendations and 

EPA’s 1997 guidance is not reasonable. With respect to manufacturer requirements, EPA has not 

reviewed these procedures and cannot assure that a particular manufacturer’s installation, 

operation, and adjustment procedures will be compatible with the proposed or final regulatory 

requirements. Manufacturers may have written recommendations that are suitable for some 

applications and are not suitable for other applications. Many of the manufacturers also are 

foreign entities that rely on other companies to represent their products in different countries and 

develop written “recommendations.” The source owner or operator is responsible for the 

selection, installation, operation, and maintenance of the monitoring equipment. While 

manufacturer’s specifications and recommendations may be useful to a source owner/operator’s 

understanding of the equipment, they are not necessarily appropriate regulatory requirements. 

EPA has offered no data to demonstrate that any BLDS will work as the manufacturer claims. 

EPA’s guidance also has no place as a regulatory requirement. EPA’s guidance addresses only 

one type of BLDS (the “triboelectric”) and is based on information provided by a single 

manufacturer. The definition of BLDS clearly allows use of a variety of technologies, including 

electrodynamic, light scattering, and light transmittance. Proposed § 63.7575. The guidance 

explains that the alarm setting procedure is dependent on the type and configuration of the fabric 

filter and filter cleaning cycle. But it addresses only one baghouse configuration. The document 

excludes all other technologies (e.g., light scattering, light transmission, optical scintillation, and 

electro-dynamic devices). In short, the existing Guidance Document is out of date and is 

technically flawed. 

Response: The EPA has no reason to believe that the “Office of Air Quality Planning and 

Standards (OAQPS) Fabric Filter Bag Leak Detection Guidance" document needs updating or is 

inadequate. EPA has no knowledge that the QA procedures within the Bag Leak Detection 

Guidance is inadequate. Technical specifications, installation procedures, operation and 

maintenance procedures, quality assurance procedures, or alarm setting procedures are contained 

within the EPA guidance document for bag leak detectors and are supplemented in 

manufacturer’s specifications , installation procedures, and directions. Performance 

specifications and quality assurance procedures found in Appendix B and F, respectively, of Part 

60 are for the purpose of certifying a CEMS and for continual quality assurance for CEMS that 

are used for continual compliance with an emission limit and therefore are not applicable to 
BLDs. False alarms and instrument malfunctions or misapplication of BLDs is a site specific 

issue and can be averted by careful selection of an appropriate BLD and manufacturer with a 

vendor guarantee of acceptable performance. EPA’s guidance for BLDs is not a certification 

procedure like performance specifications in Appendix B of Part 60 and therefore will not 

contain tests for certification. The bag leak detection system must be certified by the 

manufacturer and not the owner/operator. The operator must consider any operational changes 

and stack gas changes when selecting an appropriate BLD. BLD setup procedures and BLD 

system adjustments found within EPA’s BLD guidance is sufficient for accounting for these 

changes. The EPA BLD guidance is applicable to charge transfer type devices but several 

different manufacturer’s instruments can be used that are applicable to this guidance. The EPA 

BLD guidance addresses only one suggested approach to the use of bag leak detectors. However, 

proper setup and operation of a bag leak detector can vary with site-specific conditions and those 

conditions may dictate variances from the approach suggested in this guidance. 

Commenter Name: Thomas A. Nyquist

Commenter Affiliation: Princeton University

Document Control Number: EPA-HQ-OAR-2006-0790-1764.1

Comment Excerpt Number: 2

Comment: With regard to the proposed testing timeframes, 48 hours during any calendar year 

may be insufficient for some operators. Princeton is required by its Title V permit to perform 

compliance testing of all Cogeneration plant sources while firing both primary and backup fuels, 

with the sources operating at maximum firing rates. It is not uncommon to encounter operational 

difficulties during testing, especially while trying to achieve maximum loads, which results in 

testing that takes weeks rather than days. One year, Princeton pilot tested the use of biodiesel in 

its plant as part of ongoing efforts to introduce renewable fuels to achieve sustainability goals. 

This testing exceeded 48 hours since it was the first time the fuel was burned in this type of 

turbine and various scenario’s of operation were conducted to obtain valuable emission data. 

Under the proposed rule, biodiesel is classified as oil, and rule language may discourage testing 

of certain alternative fuels based on this limitation. 

Response: Although the example provided by the commenter is for a turbine and outside the 

scope of this rulemaking, the Agency recognizes unique circumstances that some units may face 

with respect to introducing new fuels. However, since the 48 hours is applicable generally and is 

appropriate in the majority of cases, we have retained this language in the final rule. As part of 

the Title V permit compliance testing program, you may develop a site-specific test plan that can 

be approved by the relevant delegated authority.

Commenter Name: Ashley B. Peterson

Commenter Affiliation: American Meat Institute

Document Control Number: EPA-HQ-OAR-2006-0790-1486.1

Comment Excerpt Number: 6
Comment: Finally, we suggest that annual stack testing is not necessary in order to demonstrate 

compliance with emission limits. Performing a stack test on each boiler annually is burdensome 

and provides no additional valuable information or safeguard. One test is sufficient as is required 

for current new construction permits. If the stack test is passed at that time, emissions from the 

system will not appreciably change unless the system is modified. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76. 

Category 11J.

Commenter Name: Russell A. Wozniak

Commenter Affiliation: The Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2006-0790-1766.1

Comment Excerpt Number: 8

Comment: Section 63.11214(a) of EPA’s proposed rule requires annual retesting for carbon 

monoxide (CO). 

EPA provides no insight or justification in the preamble or otherwise for requiring annual 

retesting. Annual retesting is an unnecessary and burdensome requirement. A number of the 

MACT Standards for major stationary sources have no scheduled retesting requirements and 

only require event driven retesting such as a major modification. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76. 

Category 11J.

Commenter Name: Rich Raiders

Commenter Affiliation: Arkema Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1958.1

Comment Excerpt Number: 9

Comment: The Boiler and CISWI standards regulate a variety of pollutants, some of which may 

not be present in the combustion stream nor emitted from the products of combustion. For 

instance, many CISWI units combust organic streams or organic and aqueous mixtures that do 

not contain halogen concentrations beyond trace salt chlorides. The potential of such a unit to 

emit HCl, chlorine, or dioxins and furans (“D/F”) is insignificant. These same streams often do 

not contain detectible amounts of metal HAP or metallic CISWI constituents. The potential of 

such units to emit cadmium, lead, and mercury, among other metals, is minimal. In these 

situations, EPA should allow affected sources to combine a one-time compliance stack test with 

process knowledge of the material being combusted to streamline the compliance demonstration 

for certain parameters. We understand that EPA has far less flexibility in streamlining 

compliance demonstrations for common products of combustion, such as particulate matter, 
oxides of nitrogen (“NOx”), and sulfur dioxide (“SO2”). But when feasible, EPA should allow 

owners and operators to use process knowledge and chemistry to show that some regulated 

emissions are not of concern from certain regulated units. 

Response: We disagree that the performance testing requirements are excessive. The 

combination of periodic compliance emissions testing and continuous monitoring of operational 

and parametric control measure conditions is appropriate for assuring continuous compliance 

with the emissions limitations. Without recurring testing, we would have no way to know if 

parameter ranges established during initial performance testing remained viable in the future. 

See the preamble for discussion of testing requirements, and reduced testing frequency if certain 

conditions are met.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 24

Comment: EPA should also allow testing of representative units. If one unit is representative of 

multiple units (e.g., same size/type/fuel), that unit should be tested. 

Response: EPA disagrees with the commenter. Each and every unit that is part of the affected

source is subject to an emission limit or work practice standard. From a compliance perspective 

it is too difficult to establish representative criteria given the multiple variables of fuel and 

operations cited by many other commenters.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 27

Comment: The proposed frequency of testing is unreasonable and out of character with other

MACT and NSPS standards and other state performance testing requirements. EPA has proposed 

the most aggressive performance testing requirements we are aware. The Hazardous Waste 

Combustor MACT (Subpart EEE), for example requires a Comprehensive Performance Test 

only once every five years. Many MACT standards and NSPS standards only require one initial 

performance test unless there is a physical change to the control device. Given the very stringent 

limits EPA has proposed, very few, if any units are likely to qualify for this provision, so we are 

not sure of its value. CIBO proposes that EPA use a testing frequency that is the standard for 

other criteria pollutants of once per permit term (i.e., every five years), using the language from 

major source MACT document section XIX Emissions Testing. 
Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1958.1, Excerpt Number 9. 

Commenter Name: James P. Brooks

Commenter Affiliation: Maine Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2006-0790-1915.1

Comment Excerpt Number: 5

Comment: EPA should require periodic monitoring for units between 10 and 100MMBtu/hr. 

The Maine DEP recommends that EPA require initial and biennial CO compliance testing for 

units in this size category. We believe that installation of continuous monitoring systems for 

these units is impractical. Existing units should be required to perform an annual tune-up, which 

will ensure good combustion efficiencies. 

Response: CO CEMS are not a requirement of the final rule. Please see preamble for this and 

other changes.

Commenter Name: Stephen E. Woock

Commenter Affiliation: Weyerhaeuser Company

Document Control Number: EPA-HQ-OAR-2006-0790-1984.1

Comment Excerpt Number: 12

Comment: There are a multitude of requirements for performance testing, continuous emissions 

monitoring systems (CEMS), continuous parameters monitoring systems (CPMS), operating 

parameters, instrument calibration and other quality assurance requirements embedded in the 

rule. We urge EPA to carefully evaluate the many recommended improvements the AWC and 

CIBO comments deliver on these rule provisions. EPA should streamline the requirements where 

possible, correct discrepancies identified in comments submitted by the trade groups and respond 

to opportunities to minimize the monitoring burdens these extensive and complex provisions 

carry with them. 

Response: EPA has taken all comments into consideration and has modified a number of the 

monitoring provisions. Please see the final preamble, and responses throughout this document.

Commenter Name: Renee Lesjak Bashel

Commenter Affiliation: Small Business Environmental Assistance Programs, SBEAP

Document Control Number: EPA-HQ-OAR-2006-0790-2195.1

Comment Excerpt Number: 12

Comment: One consideration EPA does not appear to address is the capacity for stack testing 

firms to conduct such 
a high number of tests as would be required each year under this rule as proposed. Even if new 

firms 

take up the task, many will take time to gain the necessary experience to do it well and provide 

accurate results. 

Response: See the preamble for certain changes to the testing provisions that will reduce the 

overall number of tests, including changes for boilers under 10 mmBtu/hour capacity.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 66

Comment: Table 6 of the proposal identifies Part 63 General Provisions that will apply to this 

subpart. We believe the Agency should specify that §63.8(a)(d) does not apply. This is 

essentially a QA/QC planning requirement, but proposed §63.11223 already covers this and the 

two sets of requirements will conflict. 

Response: Section 63.8(a)(2) is intended to apply to this subpart and imposes general provisions 

that work together with the specific requirements in the rule.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 77

Comment: To reduce the cost of complying with this rule would be to allow facilities to group 

like units and test one representative boiler instead of requiring them to test each and every boiler 

at the facility. For example, if a facility has multiple 25 MMBtu/hr boilers that are of the same 

design and fire the same fuel, they should be able to test one of these boilers to represent 

emissions of the rest of the group. The periodic testing could “rotate” among the boilers in the 

group. This option would reduce the cost associated with emissions testing for facilities with 

many similar boilers. 

Response: EPA disagrees with the commenter. Each and every unit that is part of the affected 

source is subject to an emission limit or work practice standard. From a compliance perspective 

it is too difficult to establish representative criteria given the multiple variables of fuel and 

operations cited by many other commenters.
Commenter Name: Leon Lataille

Commenter Affiliation: Massachusetts Water Resources Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1896.1

Comment Excerpt Number: 3

Comment: 63.11212 (c) requires that stack tests be conducted at the "maximum normal 

operating load while burning the type of fuel or mixture of fuels that have the highest content of 

mercury..". In the case of the Deer Island boilers, which use digester gas as the preferential fuel 

and fuel oil only for startups and to augment heat input, digester gas would constitute the normal 

operating load condition, and as an existing boiler rated at greater than 100 MBtu/hr, the 

applicable emissions limit is for carbon monoxide with no limit for mercury. For existing boilers 

with a carbon monoxide limit, requiring a maximization of mercury containing fuel does not 

seem to be the relevant issue. In the case of carbon monoxide and the Deer Island dual fuel 

boiler, at maximum normal operating load the emissions are very low for either digester gas or 

fuel oil, or dual fuel. Accordingly, the appropriate test condition would be the maximum normal 

operating load using the predominant fuel. 

Response: The testing requires the fuel with the highest emissions potential for each regulated 

pollutant. So, if a boiler is subject only to a CO standard, then that would be the regulated 

pollutant under this section of the rule. 

Commenter Name: Brad Hunter

Commenter Affiliation: GreenWood Resources

Document Control Number: EPA-HQ-OAR-2006-0790-2099.1

Comment Excerpt Number: 5

Comment: The rule should institute an initial third party certification test with required annual 

tune-ups without ongoing costly stack testing. Once a boiler (or range of boilers) is tested, that 

boiler would be approved for installation until a change was made in the boiler design. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76.

Commenter Name: Michael T. Palko

Commenter Affiliation: Pennsylvania Department of Conservation and Natural Resources

Document Control Number: EPA-HQ-OAR-2006-0790-1895.1

Comment Excerpt Number: 11

Comment: The rule should institute an initial third party certification test with required annual 

tune-ups without ongoing costly stack testing. Once a boiler (or range of boilers) is tested, that 

boiler would be approved for installation until a change was made in the boiler design. 
Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76. 

Commenter Name: Sarah E. Amick

Commenter Affiliation: Rubber Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1918.1

Comment Excerpt Number: 21

Comment: If initial compliance with the mercury emission limit is demonstrated by a fuel 

analysis performance test, the proposed rule requires monthly fuel analyses for each type of fuel 

burned. Specifically, EPA indicates that “for new and existing area source boilers with 

applicable emission limits, we are proposing that you must conduct initial stack tests or fuel 

analysis (for mercury) to determine compliance with the PM, mercury, and CO emission limits.” 

The proposal also specifies that when burning a new type of fuel, a fuel analysis must be 

conducted prior to burning the new type of fuel. Fuel usage (type and amount) must be recorded 

on a monthly basis for each unit. 

We believe the monthly fuel analysis requirement is too frequent and burdensome for area source 

units complying with the mercury emission limit using fuel analysis. RMA recommends that 

EPA require fuel analysis on a quarterly basis for units complying with mercury using fuel 

analysis. Additionally, we recommend that EPA clarify that no fuel analysis is need for single 

fuel units complying with applicable mercury emissions using stack testing. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1783.1, Excerpt Number 39. 

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 24

Comment: Section 63.11223(e) does not reference an installation requirement for the oxygen 

analyzer. 

It seems that either 40 CFR 60 PS-3 should be referenced here for the installation requirements 

for the O2 analyzer or PS-4B be referenced for both CO and O2. 

Response: These requirements are addressed through incorporation of the applicable general 

provisions.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 52
Comment: The Frequency Of Fuel Analyses Should Be Reduced. For units complying with the 

proposed mercury emission limits using fuel analysis, EPA proposes to require monthly fuel 

analyses. In order to reduce the regulatory burden on area sources, we propose reducing the 

frequency to quarterly fuel analyses. In addition, no fuel sampling should be required in any 

period if the unit does not operate during the period.[ 63.11214(f) at 75 Fed. Reg. 31927] 

The proposed Boiler MACT rule includes an exemption for single fuel fired affected sources 

from the initial compliance requirements for conducting a fuel analysis for each type of fuel in 

63.7510(a). This exemption should also be included in this area source rule for coal fired units 

that have a mercury limit (if that limit remains in the final rule). We also urge EPA to 

specifically note that for single fuel fired units, the exemption from fuel analysis still applies for 

coal fired boilers that startup on natural gas or fuel oil, or that are burning process gases in a 

boiler for emissions control and not for heat value. Where EPA is requiring fuel analyses for 

multi-fuel boilers for determining fuel operating limits for mercury, EPA should not include 

gaseous fuels in the fuel testing requirements since collecting samples of these gases is 

dangerous; concentrations of chlorine and mercury in gaseous fuels will be very small; and these 

concentrations have virtually no effect on the total amount of mercury and chlorine being input 

to the boiler. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1783.1, Excerpt Number 39. 

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 52

Comment: EPA proposes to require monitoring at all times the source is operating except for 

“monitor malfunctions, associated repairs, and required quality assurance or control activities 

including, as applicable, calibration checks and required zero and span adjustments).” In addition 

for CO CEMS, and COMS, EPA proposes to define each period in which the monitoring system 

is “out of control,” and not providing data for calculations, as a “deviation” of monitoring 

requirements that could result in enforcement. Proposed §§ 63.7525(a)(6), 63.7525(c)(6), 

63.7575. Although EPA does not define “out of control,” EPA provides the following examples 

for COMS -- “including any periods that the COMS fails to pass a daily calibration drift 

assessment, a quarterly performance audit, or an annual zero alignment audit.” EPA generally 

defines “out-of-control” to include failure of a calibration or performance audit. 

EPA’s proposed definition of these periods as a deviation is unreasonable and inconsistent with 

the Part 63 general provisions. Section 63.8(c)(3) specifically includes “out-of-control” periods 

as one of the exceptions to continuous operation. All monitoring systems will have out-of-control 

periods and EPA has provided no data to suggest that it has proposed use of technology or 

applicable performance standards that would not result in some failures of applicable 

performance specifications. Rather than subject source owners/operators to potential 
enforcement (and citizen suits) for routine and unavoidable failures of performance 

specifications, EPA should (consistent with its general provisions) revise the list of occurrences 

to specifically exempt “out of control” periods from the requirement for monitoring operation. 

[Footnote: EPA’s proposed language also does not explicitly include “maintenance periods” 

even though such periods also are excluded under the monitoring provisions in § 63.8(c)(3). To 

avoid confusion, EPA should include maintenance in § 63.7525(b). Maintenance is a process that 

is 

(continued...)] An out-of-control monitor may need to be taken off-line for evaluation and 

corrective action, or be calibrated in order to bring it back into control. 

For PM CEMS, EPA does not define such periods as “deviations,” but instead proposes to 

require the source owner/operator to obtain data “by using other monitoring systems as approved 

by the Administrator or EPA Reference Method 19 of appendix A to 40 CFR part 60” to provide 

data for all operating hours during which data are not obtained from the PM CEMS because of 

“breakdowns, repairs, calibration checks, and zero and span adjustments.” This proposal is even 

more unreasonable in that EPA has neither established that PM CEMS are capable of operating 

without missing any data -- they cannot -- nor provided any other method capable of providing 

continuous PM data during such periods. PM CEMS downtime will occur both frequently (in the 

case of calibration checks, and zero and span adjustments) and unexpectedly (in the case of 

breakdowns and repairs). EPA has identified no EPA-approved “system” that could provide data 

during such periods (and UARG is aware of none) and the cited reference method -- Method 19 -

- “does not include any sample collection or analysis procedures” (it only provides data reduction 

procedures). Method 19, § 1.1. 

Although EPA has previously adopted a provision with some similar language, that provision 

was in the context of an “option” for PM CEMS (not a requirement) and it limited the need for 

data collection to those instances when data were not collected for a minimum of “90 percent 

(only 75 percent is required prior to January 1, 2010) of all operating hours” in the 30- day 

rolling average period. 40 C.F.R. § 60.48Da(p)(8). When UARG objected to the proposed 

requirement in Subpart Da, EPA provided the following response: 

EPA concluded that the data availability requirements are appropriate. While EPA encourages 

the optional use of PM CEMS, we are aware that no PM CEMS is presently being used for 

compliance purposes in the United States. EPA, therefore, encourages steam generating unit 

owners or operators who elect to apply PM CEMS to notify EPA as soon as data are collected so 

that EPA can evaluate the data and, if the data supports doing so, propose revisions to the data 

availability requirements. 

essential to avoiding breakdowns or malfunctions, and generally requires the monitoring systems 

to be taken off-line. 

EPA “Summary of Public Comments on Reconsideration and Amendments Proposed February 

9, 2007 (72 FR 6320)” (Apr. 13, 2007), EPA-HQ-OAR-2005-0031-0260 at 13. In short, EPA 

acknowledged it lacked data to support even a 75 percent availability requirement, but asserted it 

did not need to because use of CEMS was optional. EPA also agreed to examine data when they 
became available. EPA has provided no data in this rulemaking to support the proposed 

requirement. If EPA wants to impose a minimum data availability requirement for PM CEMS 

that are required under this rule, EPA must examine available PM CEMS data and propose a data 

availability requirement that is achievable. EPA has never considered one hundred percent data 

availability to be reasonable or necessary under command and control programs like the NSPS 

and NESHAPS, and it should not do so here. Attachment B at 4-5. 

Response: We have not included any specific minimum data availability requirement, and are 

not defining deviations in the manner described in this comment. We believe that numerical 

missing data allowances quickly become targets or excuses, not incentives to conduct monitoring 

in a manner consistent with good air pollution control practices. For all monitoring required or 

applied as an option under this rule, we have included provisions that would require you to 

operate the monitoring system and collect data at all required intervals at all times the affected 

source is operating except for periods of monitoring system malfunctions, repairs associated with 

monitoring system malfunctions, and required monitoring system quality assurance or quality 

control activities (including, as applicable, calibration checks and required zero and span 

adjustments). Further, you may not use data recorded during monitoring system malfunctions, 

repairs associated with monitoring system malfunctions, or required monitoring system quality 

assurance or control activities in calculations used to report emissions or operating levels. A 

monitoring system malfunction is any sudden, infrequent, not reasonably preventable failure of 

the monitoring system to provide valid data. Monitoring system failures that are caused in part 

by poor maintenance or careless operation are not malfunctions. You must use all the data 

collected during all other periods in assessing the operation of the control device and associated 

control system.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 74

Comment: For units with heat input greater than 100 lb/106 Btu/hr, EPA’s proposed section 

63.7525(a) requires the continuous measurement of CO and 02. This requirement is the direct 

and unfortunate result of EPA’s choice of units for the CO emission limit (i.e., x ppm by volume, 

dry basis corrected to 3% 02). By choosing 02 as the basis for correction (instead of CO2), EPA 

has precluded the use of dilution-based monitoring systems, which have proved to be so reliable 

and accurate in other regulatory programs such as EPA’s Acid Rain Program. Dilution-based 

systems measure on a wet basis and can accurately measure CO2. Dilution-based systems cannot 

be used to measure 02 and generally do not measure on a dry basis. The monitoring and 

compliance determination procedures for CO would be much more straightforward, if the units 

of the emission limit were lb/106 Btu instead of ppm by volume, dry basis corrected to 3% 02. 

Response: Please see preamble for discussion on the removal of CO CEMS from the 

requirements.
Startup, Shutdown, and Malfunction (SSM)

SSM - Regulatory Text Provisions

Commenter Name: Cynthia Finley

Commenter Affiliation: National Association of Clean Water Agencies

Document Control Number: EPA-HQ-OAR-2006-0790-0838.1

Comment Excerpt Number: 4

Comment: The proposed requirement for an annual report with effluent stream measurements 

and fuel use before the “annual adjustment” also conflict with the requirement for a tune-up once 

every two years. With the biennial tune-up requirement, adjustments would be made once every 

two years, and any measurements or records related to the boiler and its tune-up should be 

completed on a biennial basis rather than on an annual basis. 

Response: Section 63.11222(b) has been revised in the final rule based on the comment.

Commenter Name: Sheldon Schultz

Commenter Affiliation: Yanke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-0837

Comment Excerpt Number: 11

Comment: There is one set of laws that come from a court room and another that we deal with 

from chemistry and physics. A boiler start up begins with temperatures near ambient but CO and 

VOC’s don’t ignite until the temperature reaches 1100 degrees F so start up and shut downs are 

special events and require separate rules dictated by the laws of science. The rule appears to 

consider only base load boiler operation and many boilers operate differently. 

Response: Commenter is correct that EPA lacks data for startup and shutdown. However, in the 

final rule, the actual emission measurements are required to be performed at maximum load and 

continuous compliance for all pollutants is demonstrated through the various parameter 

monitoring that is required by the rules.

Commenter Name: Donald R. Schregardus

Commenter Affiliation: Department of the Navy, Department of Defense

Document Control Number: EPA-HQ-OAR-2006-0790-1947.1

Comment Excerpt Number: 1
Comment: With due consideration to safety and operational requirements, some of the pollution 

control equipment (such as baghouses) of already permitted sources are designed to have 

different procedures of operation during SSM events. As a consequence, these sources will not 

be able to comply with the proposed standards during SSM events. 

Per Section 63.11201(c), the standards set forth in the rule apply at all times. There is no specific 

allowance for SSM periods relative to the emission limits in the rule. EPA discusses in section 

1V.E. on page 31901, that startup and shutdown periods were taken into account when setting 

the standards which are daily or monthly averages and thus achievable even when a startup or 

shutdown occurs. However, in Table 1 of the proposed rule, the emission limit for particulate 

matter from new units operating on any of the listed fuels is not based on an average 

over a time period. This is an unachievable standard since some pollution control devices cannot 

be in service until temperatures rise and conditions stabilize, during which emissions are known 

to exceed such low emission limits. 

For example. a DoD facility operates baghouse control devices that must be bypassed during 

startup and shutdown due to explosion risk. This requirement is a documented standard operating 

procedure implemented at the facility and is based on recommendations of the equipment 

manufacturer. Because of these requirements for safety considerations, the Agency should adopt 

procedures similar to what was done in the Miscellaneous Organic Chemical Manufacturing 

NESHAP (40 CFR Part 63, Subpart FFFF [40 C.F.R. § 63.2450(q)]. This provision allows 

facilities that cannot meet an emission limit for safety reasons, to submit documentation in their 

precompliance report explaining why an undue safety hazard would be created if the air emission 

controls were installed, and to describe the procedures that you will implement to minimize HAP 

emissions from these vent streams. This provision is provided where it is unsafe to control the 

source at any time but it could be used as a model in the boiler rule to allow sources to avoid 

control during startup and shutdown when safety issues prevent use of controls. 

The final rule should contain a provision similar to 40 CFR Part 63, Subpart FE IF, 63.2450(q) to 

exclude SSM events from the emission limits when it can be demonstrated that it is necessary to 

bypass emission controls for safety reasons. 

Response: In the final rule, EPA has taken into account startup and shutdown periods and has 

not established different standards for those periods. The standards that we are promulgating are 

based on short term stack tests for pollutants that generally are not expected to vary significantly 

at startup and shutdown. For CO, which in some cases varies at startup and shutdown, the 

operating limits will ensure that combustion conditions are optimized and CO emissions are 

minimized. Boilers, especially coal-fired boilers, do not normally startup and shutdown more the 

once per day. Thus, we are not establishing a separate emission standard for these periods 

because startup and shutdown are part of their routine operations and, therefore, are already 

addressed by the standards. Periods of startup, normal operations, and shutdown are all 

predictable and routine aspects of a source’s operation. We have evaluated whether it is 

appropriate to have the same standards apply during startup and shutdown as applied to normal 

operations, and as the rule is structured, well operated and controlled units should be able to meet 

the standards at all times.
In the final rule, the actual emission measurements for compliance are required to be 

performed at maximum load and continuous compliance for all pollutants is demonstrated 

through the various parameter monitoring that is required by the rules.

Commenter Name: Rob Barton and Ralph Roberson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2006-0790-1978.1

Comment Excerpt Number: 1

Comment: Specifically, EPA should reconsider setting standards that apply during startup, 

shutdown, and malfunction (SSM), since as explained in our major source comments EPA did 

not collect data during these events. Southern Company’s experience with our coal-fired power 

plants has shown that SSM events have an effect on emissions. Certainly, work practice 

standards would be more appropriate during SSM events. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Douglas J. Fulle

Commenter Affiliation: Oglethorpe Power Corporation

Document Control Number: EPA-HQ-OAR-2006-0790-1798.1

Comment Excerpt Number: 3

Comment: The proposed Area Source Rule does not include a separate standard for startup and 

shutdown. This is a fundamental problem that, if not corrected, will cause the final CO standard 

for new biomass fired boilers to be not achievable by even well designed new affected boilers, 

such as OPC’s Warren County project. As a result, EPA must include a separate standard for 

startup and shutdown in the final rule. 

EPA explains in the preamble that, "Based upon continuous emission monitoring data, obtained 

as part of the information collection effort for the major source boiler and process heater 

rulemaking, which included periods of startup and shutdown, over long averaging periods, 

startups and shutdowns will not affect the achievability of the standards." 75 Fed. Reg. at 31901. 

There are three fundamental problems with this justification for not including startup and 

shutdown standards in the rule. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Douglas J. Fulle

Commenter Affiliation: Oglethorpe Power Corporation

Document Control Number: EPA-HQ-OAR-2006-0790-1798.1

Comment Excerpt Number: 5
Comment: Second, EPA’s emissions database provides CO continuous emissions monitoring 

system ("CEMS") data from several of the better performing sources in the biomass subcategory. 

(see submittal for graphical depiction of the data for these seven units). Contrary to EPA’s 

assertion in the preamble, these data show that daily average CO emissions should be expected to 

vary considerably on a day-to-day basis and that the variability spans the proposed level of the 

standard. While it is difficult to discern the reasons for this variability based on the information 

provided in the database, there is little doubt that startups and shutdowns significantly contribute 

to the variable emissions performance of these units. Thus, the data for relevant boilers in the 

area source biomass subcategory indicate that EPA needs to include express accommodation for 

startups and shutdowns. 

Basic scientific and engineering principles support the need for a separate standard for startup 

and shutdown. In our case, the boiler vendors for our Warren County project indicate that startup 

of the unit will last up to 18 hours. During that period of time, combustion conditions will not be 

optimum due to the generally low tiring rate, the fact that the firing rate will be ramped up over 

the startup period, and the need to shift from biodiesel as a startup fuel to biomass for normal 

operations. Thus, 18 hours of non-optimum firing conditions will result in CO emissions 

performance -even on a daily average basis -that will be markedly different than performance 

during normal operations. EPA’s failure to acknowledge these basic technical and engineering 

principles renders the proposed CO standard arbitrary. 

Furthermore there are no proven or reliable technologies available to control CO during startups 

and shutdowns. Oxidation catalysts have been used to control CO with very unfavorable results. 

According to the Electric Power Research Institute (EPRJ), only one facility is operating a 

biomass boiler with an oxidation catalyst at about 80% CO oxidation efficiency (April 2008). 

The oxidation catalyst works efficiently only at an optimal temperature window; however, under 

startup conditions the lower temperatures encountered make the catalyst ineffective. Second, for 

catalysts built on a ceramic base, the temperature rise inherent in startup must be carefully 

controlled to prevent thermal cracking and subsequent catalyst failure. See submittal Attachment 

2 for EPRI White Paper "Implications of EPA ‘s Proposed Industrial Boiler Maximum 

Achievable Control Technology (MACT) Rule/or Biomass Power Plants", page 7, Area Sources 

Boiler Rule, dated July 2010. 

For these reasons, we believe that a separate standard for startup and shutdown is needed and is 

amply justified. We suggest that a work practice standard is most appropriate due to the lack of 

relevant CO startup data and the fact that CO emissions monitoring during startup is not 

technically and economically practicable. If EPA decides that a numeric standard is needed, the 

Agency should rely on the available CEMS data from the better performing biomass fired boilers 

in the Area Source database. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Lisa Beal
Commenter Affiliation: Interstate Natural Gas Association of America

Document Control Number: EPA-HQ-OAR-2006-0790-1919.1

Comment Excerpt Number: 11

Comment: EPA should clarify that startup, shutdown and malfunction plans and associated 

reporting are not required. 

In Table 9 of the proposed rule, items 1(d) and 2 delineate requirements regarding startup, 

shutdown, and malfunction (SSM) plans and reporting. However, EPA indicates it is changing 

SSM requirements in response to recent Court decisions, and multiple citations in Table 10 of the 

proposed rule indicate that SSM plans and associated reporting are not required. These two 

tables are contradictory. Items 1(d) and 2 from Table 9 should be deleted. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Russell A. Wozniak

Commenter Affiliation: The Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2006-0790-1766.1

Comment Excerpt Number: 13

Comment: EPA’s proposed rule requires that emission limits apply at all times, including times 

of Start-up, Shutdown, and Malfunction (SSM). EPA needs to further develop the requirements 

for boilers during times of SSM. At major source and area source sites, it is well known that both 

CO and oxygen levels will be significantly higher during an initial period of start-up. This is due 

to the boiler operating during this transition time between zero load and the desired operating 

load. Also, oxygen concentrations will vary during times of start-up, making the correction to 

3% oxygen a very significant one if a CEMS is used to demonstrate compliance. For example, 

during times of start-up, the oxygen concentration may be ~ 15%, so the correction to 3% 

oxygen would be 17.9/5.9 or approximately a factor of 3. Note that oxygen concentrations closer 

to 20.9% can result in very high correction factors. Even a small number of hours with high CO 

concentrations (corrected to 3% oxygen) would likely create a situation where the source would 

not meet a low CO concentration level over a daily average as required for existing oil units. 

Dow believes that all sources in the existing oil source category will experience these difficulties 

during times of start-up. Furthermore, EPA’s General Provisions require that performance testing 

be conducted during conditions other than a start-up, shutdown, or malfunction (see Section 

63.7(e)). 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.
Commenter Name: Russell A. Wozniak

Commenter Affiliation: The Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2006-0790-1766.1

Comment Excerpt Number: 14

Comment: Boilers that combust liquid fuels - These sources should be subject to management 

practices, as allowed under Section 112(d)(5) of the Clean Air Act, during SSM periods that 

require the boiler and any air pollution equipment to achieve steady state operating conditions 

within 24 hours from the commencement of start-up. In addition, since most boilers do not startup more than 1 time per quarter, EPA could limit the use of management practices to 96 hours 

per year. Thus, similar to the recently promulgated Engine RICE MACT rule amendments, the 

boiler would not be subject to a numerical concentration-based standard for the hours that it 

takes to ramp up steam production and pressures. Dow believes that this approach would 

continue to minimize any HAP emissions from these sources without jeopardizing the ability of 

the source to meet a CO emission level over a daily average period. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: N/A

Commenter Affiliation: Sierra Club, Earth Justice, Clean Air Task Force, Natural Resources 

Defense Council

Document Control Number: EPA-HQ-OAR-2006-0790-1982.1

Comment Excerpt Number: 36

Comment: [See Exhibit B of submittal for manuscript discussing why SSM events should not be 

exempt; “Gaming the System: How OFF-the-Books Industrial Upset Emissions Cheat the Public 

Out of Clean Air.” 

Response: SSM events are not exempt from the rule. Please see response to DCN EPA-HQOAR-2006-0790-1747.1, Excerpt Number 1. Also, section 63.11226 has been added to the final 

on how a source may assert an affirmative defense if an emission limit is exceeded during a 

malfunction.

Commenter Name: Stephen E. Woock

Commenter Affiliation: Weyerhaeuser Company

Document Control Number: EPA-HQ-OAR-2006-0790-1984.1

Comment Excerpt Number: 4
Comment: Boiler startup, shutdown and malfunction (SSM) events also contribute to higher CO 

emissions. EPA did not adequately take these conditions into account when setting the limits. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Jeffery S. Hannapel

Commenter Affiliation: National Association for Surface Finishing

Document Control Number: EPA-HQ-OAR-2006-0790-1840.1

Comment Excerpt Number: 5

Comment: The proposed Boiler GACT does not include a separate standard for startup and 

shutdown for area source boilers. Without this provision, the final emissions limitations may not 

be achievable, even by well designed and operated boilers. EPA should, therefore, include a 

separate standard for startup and shutdown for area source boilers in the final rule. 

EPA explains in the preamble that, “Based upon continuous emission monitoring data, obtained 

as part of the information collection effort for the major source boiler and process heater 

rulemaking, which included periods of startup and shutdown, over long averaging periods, 

startups and shutdowns will not affect the achievability of the standards.” 75 Fed. Reg. at 31901. 

This justification for not including startup and shutdown standards in the proposed Boiler GACT 

rule is flawed for the following reasons. 

First, the continuous monitoring data that EPA presents in the major source Boiler MACT 

proposal is for units that will not be subject to the Boiler GACT and that are not the unit(s) from 

which EPA obtained the data used in setting the proposed area source standards. Thus, these 

emissions data cannot lawfully be used in determining the area source standards because these 

data are derived from sources that do not belong to the area source category. The conclusion that 

a separate standard for startup and shutdown is not needed can only be based on data from the 

source(s) that are actually used by EPA to set the area source standards or on a showing that the 

data from some other boilers are representative of the performance of the area source boilers 

used as the basis for the proposed area source standards. 

Second, EPA’s emissions database provides continuous emissions monitoring system (CEMS) 

data from several of the better performing sources. These data show that daily average emissions 

should be expected to vary. Undoubtedly, startups and shutdowns significantly contribute to the 

variable emissions performance of these units. Thus, EPA’s own data indicate that the Boiler 

GACT needs to include a specific accommodation for startups and shutdowns. 

Third, basic scientific and engineering principles support the need for a separate standard for 

startup and shutdown. Particularly for CO emissions, combustion conditions will not be optimum 

during startup periods due to the generally low firing rate and the fact that the firing rate will be 

ramped up over the startup period. Thus, a significant period of non-optimum firing conditions 
will result in CO emissions performance – even on a daily average basis – that will be markedly 

different than performance during normal operations. EPA’s failure to acknowledge these basic 

technical and engineering principles is an arbitrary and capricious process for establishing 

applicable standards for area source boilers. 

A separate standard for startup and shutdown is, therefore, needed and is sufficiently justified. A 

work practice standard would be more appropriate due to the lack of relevant data and the fact 

that emission testing during startup is not technically and economically practicable. If EPA 

decides that a numeric standard is needed, the Agency should then rely on the available longterm data from the better performing area source boilers to establish a standard with a reasonably 

long averaging time (such as a 30-day rolling average), rather than the proposed 24-hour 

averaging time. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Joe Muehlbach

Commenter Affiliation: Quad/Graphics

Document Control Number: EPA-HQ-OAR-2006-0790-1961.1

Comment Excerpt Number: 5

Comment: In previous MACT standards EPA provided companies with the flexibility to employ 

alternative compliance approaches that were shown to be protective of public health and 

approved by the U.S. EPA as well as flexibility during start-up and shut down of the boilers 

when there can be compliance issues that are due simply to the action of turning on or shutting 

off the boiler. Removing this flexibility will only serve to catch an otherwise compliant boiler 

with relatively small exceedences that are only present due to the nature of the start-up or shutdown and not indicative 

of how that boiler performs during hours of normal operation. The proposed rules do not provide 

this compliance flexibility which may needlessly increase the costs of compliance without 

achieving any measurable environmental protections. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Christian Richter and Jeff Hannapel

Commenter Affiliation: American Foundry Society

Document Control Number: EPA-HQ-OAR-2006-0790-1857.2

Comment Excerpt Number: 6
Comment: EPA should also provide a more thorough variability analysis and set a separate 

standard for periods of startup and shutdown. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Stephen E. Woock

Commenter Affiliation: Weyerhaeuser Company

Document Control Number: EPA-HQ-OAR-2006-0790-1984.1

Comment Excerpt Number: 10

Comment: EPA has chosen to assume for the proposed rule that emissions during SSM events 

are either (a) already incorporated into the emission limits they proposed based on a view that at 

least some of the stack test data in the database adequately represent such periods, or (b) the 

averaging periods EPA proposes provide sufficient room to smooth out emission spikes during 

those events so that compliance can be planned and engineered. 

Based on our experience with boiler emissions during SSM events, we believe EPA’s 

assumptions will prove inadequate in many cases, putting our sources at compliance risk for 

events that EPA failed to adequately consider in the MACT floors. We refer EPA to the very 

extensive technical discussions contained in the AWC and CIBO comments reaching the same 

conclusion. Those comments demonstrate how such events are not adequately included in the 

database nor are existing combustion units capable of meeting the emission limits. At some of 

our wood products mills their biomass boilers are operated on a four or five day schedule, so 

start-ups and shutdowns occur twice a week, making this a routine concern. 

As a remedy, we encourage EPA to consider establishing work practices to address emissions 

during these SSM periods, but urge EPA while doing so to take care not to create redundant new 

regulatory burdens (i.e., either work in concert with or exempt from, the current Part 63 General 

Provisions that address the minimization of emissions consistent with safety and good 

combustion practices). We refer EPA to the NEDA and AWC comments for detailed discussion 

of the legal requirement for addressing SSM periods so that the standards established under CAA 

§ 112(d) are "achievable." In the longer term EPA could collect the data to ensure that such 

events are truly represented in the database before establishing emission limits including SSM 

periods. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Robert L. Garfield

Commenter Affiliation: Food Industry Environmental Council

Document Control Number: EPA-HQ-OAR-2006-0790-1835.1
Comment Excerpt Number: 13

Comment: Finally, EPA’s analysis failed to properly address the variability of the data, as well 

as emissions associated with startup, shutdown and malfunction. Thus, EPA’s proposed limits do 

not appropriately address the variability in emissions of various HAPs. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: James P. Brooks

Commenter Affiliation: Maine Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2006-0790-1915.1

Comment Excerpt Number: 15

Comment: While the Maine DEP recognizes that the courts decreed that emission standards 

established under the Clean Air Act must apply at all times, EPA must still consider the practical 

limitations of implementing this directive. Reality shows that during periods of startup and 

shutdown, all types of boilers emit more pollutants than during steady state operations. This is 

particularly true for biomass boilers, where the fuel is introduced onto the combustion chamber 

more gradually during start up and ceases combustion more gradually than liquid or gaseous 

fuels. Maine’s experience is that the amount of time to reach the desired steady state for 

minimizing emissions depends on a number of factors such as the design of the system, its size, 

and the type of fuel that is combusted. The Maine DEP also recognizes that insufficient data is 

currently available to establish alternative emission standards for start-up and shutdown period. 

Therefore, we recommend that EPA require facilities to develop and implement plans to 

minimize the amount of time for startup and shut-downs and to minimize the amount of 

pollutants emitted during these periods. Accompanying emission standards with long averaging 

periods will ensure that overall emissions from affected units are minimized. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 17

Comment: Provisions for start-ups and shutdowns will need to be incorporated into the rule. 

Wood and multi-fueled fired boilers produce large CO variations during startups as the boiler 

heats up. Start-up can take up to 14 hours for some units. Shutdowns can also result in significant 

CO variability. 
Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Goup

Document Control Number: EPA-HQ-OAR-2006-0790-1916.1

Comment Excerpt Number: 18

Comment: The Proposed Approach for Emissions from Landfill Gas Units During Startup, 

Shutdown, and Malfunction Periods Is Arbitrary, Capricious, Not Supported by the Record, and 

Not in Accordance with the Statute. 

In § 63.7505(a) of the proposed Boiler MACT rule, sources would be subject to emission limits 

and operating limits at all times.[ See id. at 32,050.] This would mean that units using landfill 

gas would have to comply with the emission limits under any and all conditions. EPA’s proposed 

approach to addressing startup, shutdown, and malfunction (SSM) periods for other gas units in 

the Boiler MACT is contrary to the statute’s requirement that the standards established under 

section 112(d) be “achievable.”[ See CAA 112(d)(2); 42 U.S.C. § 7412(d)(2).] Furthermore, 

EPA’s claims that the MACT standards reflect startup and shutdown periods are not supported 

by the record. 

To address the decision in Sierra Club v. EPA,[ 551 F.3d 1019 (D.C. Cir. 2008), cert. denied, 

2010 U.S. LEXIS 2265(2010).] which vacated the exemption in 40 C.F.R. § 63.6(f)(1) and (h)(1) 

for SSM periods, EPA proposes emissions standards in the MACT for boilers and process 

heaters that apply at all times, including periods of SSM. EPA claims in the preamble that startup 

and shutdown periods were taken into consideration when setting the MACT standards.[ See 75 

Fed. Reg. at 32,012-13.] According to the preamble, CEM data from the best performing units, 

which include startup and shutdown periods, are used to set the floor levels in the proposed rule.[ 

See id. at 32,013] EPA further notes that startup and shutdown are part of “routine operations” 

and are therefore “already addressed” in the MACT standards.[ See id.] While the Auto Group 

agrees with EPA that startup and shutdown are part of routine operations, these periods have not 

been adequately addressed by EPA’s proposed emission limits or analyzed properly when setting 

the floors. As discussed below, work practices should be established to accommodate startup and 

shutdown periods. 

With regard to malfunctions, however, EPA states that these periods should not be viewed as a 

“distinct operating mode,” and thus, emissions from these periods do not need to be factored into 

developing the MACT floor levels.[ See id.] Moreover, EPA states that even if malfunctions 

were to be considered a distinct operating mode, it would be “impracticable to take malfunctions 

into account in setting CAA section 112(d) standards for major source boilers and process 

heaters” given that these episodes are by definition sudden and unexpected events which vary in 

degree, frequency, and duration.[ See id.] The Auto Group agrees that it would be impracticable 

to establish emission limits for malfunctions as they vary in degree, frequency and duration. As 

discussed in detail below, work practices also should be established to accommodate malfunction 

periods. 
When setting standards in the early 1990’s under CAA section 112(d), EPA used its New Source 

Performance Standards (NSPS) program as a model. The section 112 standards were 

acknowledged by EPA to be “essentially equivalent to [section 111] performance standards” and 

that “unpredicted and reasonably unavoidable failures of air pollution control systems” would 

occur.[ See 58 Fed. Reg. 42,760, 42,777 (Aug. 11, 1993).] To address this situation, EPA 

adopted a similar exemption to the one in the NSPS Program for SSM events and imposed a 

“general duty” to minimize emissions. Thus, EPA acknowledged, as early as 1993, that SSM 

events are not appropriate for inclusion in a MACT standard and that an alternative approach 

should be used to address these situations. While the D.C. Circuit has ruled that sources cannot 

be exempt from complying with MACT standards, the court noted that Congress recognized in 

some instances that it may not be feasible to prescribe or enforce an emission standard under 

section 112, and so section 112(h) “work practices” or “operational” standards are available in 

certain limited situations.[ See Sierra Club v. EPA, 551 F.3d at 1028.] 

The D.C. Circuit also has recognized that standards based on what sources achieve must account 

for the limitations inherent in the technology used to reduce emissions. For example, in a case 

reviewing NSPS under section 111 of the CAA, Portland Cement Ass’n v. Ruckelshaus,[ 486 

F.2d 375, 398 (D.C. Cir. 1973).] the court acknowledged that “’startup’ and ‘upset’ conditions 

due to plant or emission device malfunction, is an inescapable aspect of industrial life and that 

allowance must be made for such factors in the standards that are promulgated.”[ Portland 

Cement Ass’n v. Ruckelshaus, 486 F.2d at 399] Furthermore, in National Lime Ass’n v. EPA,[ 

627 F.2d 416 (D.C. Cir. 1980).] the court noted that. “a uniform standard must be capable of 

being met under most adverse conditions which can reasonably be expected to recur.”[ National 

Lime Ass’n v. EPA, 627 F.2d at 431 n.46.] The D.C. Circuit acknowledged this same principle 

almost 20 years later when reviewing emission standards for new sources in the medical waste 

incinerator rule under section 129 in Sierra Club v. EPA.[ 167 F.3d 658 (D.C. Cir. 1999).] 

In that case, while the court did not find the record sufficient to support EPA’s approach for new 

sources, the D.C. Circuit did not object to a standard-setting approach which would account for 

the performance of technology under the “worst reasonably foreseeable circumstances.” [Sierra 

Club v. EPA, 167 F.3d at 665.] Furthermore, the D.C. Circuit reiterated the principle in National 

Lime that “where a statute requires that a standard be ‘achievable,’ it must be achievable ‘under 

the most adverse circumstances which can reasonably be expected to recur.’[Id. at 665 (citing 

National Lime Ass’n v. EPA, 627 F.2d 416, 431 n.46 (D.C. Cir. 1980)).] 

EPA’s MACT floor-setting approach in the proposed Boiler MACT ignores these longstanding 

principles and mischaracterizes the role startup and shutdown data play (or rather, does not play, 

as the case is here) in EPA’s floor-setting process. As noted above, EPA claims that the agency 

considered startup and shutdown periods when setting the floors because CEMs data, relied on 

by EPA in “establishing the standards,” included data from those periods.[ See 75 Fed. Reg. at 

32,012.] Despite this claim, however, EPA does not rely on the CEMs data when setting the 

floors for boilers and process heaters. To the contrary, as indicated by the ERG memorandum in 

the docket, EPA uses test run data collected through the ICR phase II testing process, which 

reflect normal (often steady state) operating conditions, to set the proposed floors.[ See 

Memorandum from A. Singelton, ERG, to J. Eddinger, U.S. EPA, MACT Floor Analysis (2010) 

for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission 

Standards for Hazardous Air Pollutants – Major Source at 3 (April 2010).] Thus, according to 
EPA’s own docket materials, the data used to set the proposed floors fail to account for the 

dynamic conditions and variable emissions occurring during startup and shutdown episodes. 

Furthermore, as the ERG memorandum makes abundantly clear, EPA’s approach does not make 

use of the CEMs data (with the startup and shutdown information) in its variability analysis.[ Id.] 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Britt S. Fleming

Commenter Affiliation: Auto Goup

Document Control Number: EPA-HQ-OAR-2006-0790-1916.1

Comment Excerpt Number: 21

Comment: In light of the absence of startup and shutdown emissions information from the test 

run data relied on by EPA to set the proposed standards and the difficulty of collecting data from 

such brief operation periods, including data from CEMs, it is appropriate for EPA to set work 

practices for these events for boilers and process heaters. As discussed earlier, section 112(h) 

allows EPA to set work practice standards for situations where “it is not feasible in the judgment 

of the Administrator to prescribe or enforce an emission standard . . . .”[ CAA § 112(h)(1); 42 

U.S.C. § 7412(h)(1).] Gathering data from startup and shutdown periods would be challenging 

given the brief nature of these periods as well as the need to define the exact time period for what 

is considered “startup” and/or “shutdown.” Moreover, the definition of “not feasible to prescribe 

or enforce an emission standard” is defined in the CAA as any situation where “the application 

of measurement methodology to a particular class of sources is not practicable due to 

technological and economic limitations.”[ CAA § 112(h)(2); 42 U.S.C. § 7412(h)(2).] 

Attempting to measure combustion emissions while the boiler (or process heater) is in a state of 

flux does not lead to reproducible or reliable data and is not economically feasible. Startup and 

shutdown episodes, therefore, fit with this definition and would justify the agency setting work 

practices to address emissions during these periods. Furthermore, a work practices approach for 

these periods would be in keeping with the statute’s requirement that MACT standards be 

“achievable” as well as with the requirement that a MACT standard apply at all times. 

A work practices approach for these periods also would be consistent with EPA’s recently 

promulgated MACT standards for compression ignition reciprocating internal combustion 

engines (CI-RICE).[ See National Emission Standards for Hazardous Air Pollutants for 

Reciprocating Internal Combustion Engines, 75 Fed. Reg. 9648 (Mar. 3, 2010).] Based on 

comments received from stakeholders, EPA finalized work practice standards for startup because 

the agency determined that it was “not feasible to finalize numerical emission standards that 

would apply during startup because the application of measurement methodology to this 

operation is not practicable due to technological and economic limitations.”[ Id. at 9656] 

According to EPA, applicable test methods that would be needed to measure during these events 
“do not respond adequately to the relatively short term and highly variable exhaust gas 

characteristics occurring during these periods.”[ Id. at 9665.] Furthermore, EPA determined that 

the cost for testing all the engines affected by the rule to get the necessary data could be more 

than $1 billion.[ See id.] Startup and shutdown periods for boilers encounter similar testing 

challenges and costs. 

With respect to malfunctions, as noted earlier, EPA argues in the preamble to the proposed 

Boiler MACT that these periods should not be considered a “distinct operating mode” and uses 

this to justify not factoring these emissions into the proposed MACT standards. Considering that 

EPA’s proposed MACT standards are supposed to apply at all times, the implication is that 

periods of malfunction also are covered by the MACT standards that apply during normal 

operations. This directly conflicts with the statutory requirement that the MACT standard be 

“achievable.” 

Given that the floor data does not consider malfunctions and that the statute requires that the 

MACT standard be “achievable,” EPA should set work practice requirements to address periods 

of malfunctions as well. As noted above, section 112(h) allows EPA to set work practice 

standards for situations where “it is not feasible in the judgment of the Administrator to prescribe 

or enforce an emission standard . . . .” Similar to startup and shutdown, malfunctions fit with the 

situations described in the definition of “not feasible to prescribe or enforce an emission 

standard” as any situation where “the application of measurement methodology to a particular 

class of sources is not practicable due to technological and economic limitations.” Emission 

testing for malfunctions would be near impossible to conduct given the sporadic, short term, and 

unpredictable nature of the events. As noted earlier, EPA acknowledges in the preamble to the 

proposed Boiler MACT that it is “impracticable” to take periods of malfunctions into account 

when setting emissions standards given the “myriad different types of malfunctions that can 

occur across all sources in the category” and that “malfunctions can vary in frequency, degree, 

and duration, further complicating” the standard setting process.[ 75 Fed. Reg. at 32,013.] 

Section 112(h) work practice standards, therefore, are well-suited to address malfunction periods 

and the complexities and challenges surrounding collecting data and establishing numerical 

standards for those events. 

For these reasons, the Auto Group recommends that for startup and shutdown periods, EPA 

consider a work practices requirement similar to the approach used in the CI-RICE MACT noted 

above, that would limit these periods to three hours or require sources to comply with 

manufacturer specifications, if available. For startups, boilers and process heaters need to be 

brought up to normal firing rates slowly, and three hours, as a default, is a sufficient period of 

time to ensure that the unit reaches the optimal firing rate without damaging the unit. With 

regard to malfunction periods, the Auto Group suggests that EPA require owners and operators 

to minimize emissions during malfunctions to the greatest extent practicable and follow safe 

operation practices. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.
Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 73

Comment: With regard to malfunctions, EPA argues in the preamble to the Proposed Boiler 

MACT that these periods should not be viewed as a “distinct operating mode,” and thus, 

emissions from these periods do not need to be factored into developing the MACT floor levels. 

See id. Moreover, EPA states that even if malfunctions were to be considered a distinct operating 

mode, it would be “impracticable to take malfunctions into account in setting CAA section 

112(d) standards for major source boilers” given that these episodes are by definition sudden and 

unexpected events which vary in degree, frequency, and duration. Id. These circumstances apply 

to area sources as well. 

Considering that EPA’s proposed standards are supposed to apply at all times, the implication is 

that periods of malfunction also are covered by the standards that apply during normal 

operations. This directly conflicts with the statutory requirement that the standard be 

“achievable.” EPA has failed to recognize that it is likely that even best performers will 

experience malfunctions. It is possible for pollution control equipment to fail in various ways. 

Electrostatic fields trip, power failures do occur, fabric filters fail, scrubber pumps fail even at 

best performers and despite the best efforts of companies to prevent and minimize such events. 

Industry can and does work to minimize such periods, but they do occur. Further, manufacturers 

of such equipment routinely make emission guarantees for normal operations and although they 

sometimes oversize equipment to account for some of the variability described above, it is very 

doubtful that vendors would provide sufficient numerical guarantees for equipment under such 

situations. 

Given that the floor data does not consider malfunctions and that the statute requires that the 

standard be “achievable,” EPA should set management or work practice requirements to address 

periods of malfunctions as well. As noted above, section 112(h) allows EPA to set management 

or work practice standards for situations where “it is not feasible in the judgment of the 

Administrator to prescribe or enforce an emission standard . . . .” Similar to startup and 

shutdown, malfunctions fit with the situations described in the definition of “not feasible to 

prescribe or enforce an emission standard” as any situation where “the application of 

measurement methodology to a particular class of sources is not practicable due to technological 

and economic limitations.” Emission testing for malfunctions would be near impossible to 

conduct given the sporadic and unpredictable nature of the events. As noted earlier, EPA 

acknowledges in the preamble that it is “impracticable” to take periods of malfunctions into 

account when setting emissions standards given the “myriad different types of malfunctions that 

can occur across all sources in the category” and that “malfunctions can vary in frequency, 

degree, and duration, further complicating” the standard setting process.57 Section 112(h) 

management or work practice standards, therefore, are well-suited to address malfunction 

periods and the complexities and challenges surrounding collecting data and establishing 

numerical standards for those events. 
For these reasons, AF&PA believes that it is appropriate for EPA to revisit this issue. We suggest 

that EPA propose management or work practice standards that would allow sources a certain

time period for start-up, shutdown and malfunction events and as long as certain procedures are 

followed, then compliance would be met. Those management or work practice standards should 

require the development and implementation of an emissions minimization plan that will result 

in (a) minimizing emissions during such events that would exceed otherwise applicable emission 

limitations, and (b) for malfunctions that will cause the unit to exceed otherwise applicable 

emission limitations, promptly identifying and implementing measures to remedy the 

malfunction. While there may be some instances where standard management or work practices 

can be identified for a type of source, we caution that overly prescriptive and non-facilityspecific requirements can actually be counterproductive, restricting the operators’ flexibility in a 

way that hampers their ability to troubleshoot or respond to an event, or that compromises safety. 

The plan itself should not be incorporated into the Title V permit. The plan should be an 

evolving document, and it would be very cumbersome to have to seek a modification of the Title 

V permit every time the plan changed. If the details of the emissions minimization plan had to be 

made part of the permit, facilities would tend to make the plans less specific and therefore 

probably less useful. For the same reason, these plans should be maintained at the facility rather 

than being required to be submitted to the permitting authority with the Title V application or 

otherwise. 

Alternatively, EPA could establish a threshold of exceedances either a number or percentage of 

operating times that could occur during a quarterly or six month period before a violation occurs. 

This methodology is consistent with other standards such as 40 CFR 63 Subpart S and MM. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: James P. Brooks

Commenter Affiliation: State of Maine Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2006-0790-1941.1

Comment Excerpt Number: 4

Comment: Provisions for start-ups and shutdowns will need to be incorporated into the rule. 

Wood and multi-fueled fired boilers produce large CO variations during startups as the boiler 

heats up. Start-up can take up to 14 hours for some units. Shutdowns can also result in significant 

CO variability. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Mary Graham
Commenter Affiliation: Charles Metro Chamber of Commerce

Document Control Number: EPA-HQ-OAR-2006-0790-1953.1

Comment Excerpt Number: 5

Comment: The proposed Area Source Rule does not include a separate standard for startup and 

shutdown. This is a fundamental problem that, if not corrected, will cause the final standards to 

be unachievable even by well designed and operated boilers. As a result, EPA must include a 

separate standard for startup and shutdown in the final rule. 

Basic scientific and engineering principles support the need for a separate standard for startup 

and shutdown. Particularly for CO emissions, combustion conditions will not be optimum during 

startup periods due to the generally low firing rate and the fact that the firing rate will be ramped 

up over the startup period. Thus, a significant period of non-optimum firing conditions will result 

in CO emissions performance — even on a daily average basis — that will be markedly different 

than performance during normal operations. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Robert Klemans

Commenter Affiliation: Florida Electric Power Coordinating Group

Document Control Number: EPA-HQ-OAR-2006-0790-1955.1

Comment Excerpt Number: 5

Comment: EPA Should Not Treat HAP Emissions During Startup and Shutdown the Same as 

HAP Emissions During Normal Operation. The IB ICR did not require any testing during startup, shutdown and malfunction events. Without emissions data during these periods, EPA has no 

factual basis for concluding that the best performing units can achieve the proposed MACT 

limits during start-up, shutdown and malfunction events. Operations during boiler start-ups are 

different than normal plant operations. Certain plant components must be started in a specific 

sequence in order to ensure that steady state operations can be achieved. During start-up, not all 

pieces of control equipment will be operating at peak efficiency. The FCG urges EPA to exempt 

these events based on the lack of data availability and its unrestricted operational control. In 

addition, FCG believes that startup, shutdown and malfunction events should be excluded from 

all emission averaging requirements in the IB MACT proposal. These events were not included 

in the ICR data gathering used to develop the emission standards, thus many of the proposed 

standards will be impossible to meet if these periods are included in the averaging periods. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Mark Denzler
Commenter Affiliation: Illinois Manufacturers' Association

Document Control Number: EPA-HQ-OAR-2006-0790-2004

Comment Excerpt Number: 6

Comment: Startup, Shutdown, and Malfunction Requirements Are Unrealistic. The EPA 

proposal specifies that its emission limits apply during periods of startup, shutdown, and 

malfunction. In support of this proposal, EPA states that startup and shutdown emissions are 

equivalent to normal operation emissions based on continuous emission monitoring data 

obtained from best performing units that included periods of startup and shutdown. However, the 

test data does not show a sufficiently representative sampling of startup, shutdown, and 

malfunction conditions that represent their duration and variety of characteristics. By considering 

these periods to be part of “routine operations” EPA ignored the circumstances that justify the 

establishment of work practices or alternative emission limits that would apply in such situations. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Edward J. Wilusz

Commenter Affiliation: Wisconsin Paper Council

Document Control Number: EPA-HQ-OAR-2006-0790-2133

Comment Excerpt Number: 8

Comment: EPA makes a similar mistake with regard to its proposal not to set a separate 

standard for periods of startup, shutdown, and malfunction. On the one hand, EPA asserts that 

“[t]he standards we are proposing are daily or monthly averages ... [t]hus, we are not 

establishing separate emission standards for these periods because startup and shutdown are part 

of their routine operations and, therefore, are already addressed by the standards.” On the other 

hand, EPA uses short term performance test results to set the standards rather than the results of 

long-term CEMS monitoring. As a result, the emissions data on which the standards are based do 

not, in fact, reflect or adequately accommodate emissions from periods of startup, shutdown, or 

malfunction. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: John C. deRuyter

Commenter Affiliation: DuPont

Document Control Number: EPA-HQ-OAR-2006-0790-1964.1

Comment Excerpt Number: 9
Comment: EPA has proposed that their averaging time basis for compliance with the emissions 

limits would be adequate to cover startup and shutdown periods, and malfunctions are simply not 

addressed in that they should not occur. DuPont believes this approach is unworkable and fails to 

recognize the realities of operating the many types of boilers currently in operation. As a base 

issue, EPA has not utilized long term emissions data such as CO CEMS data to adjust emissions 

test data to be representative of actual operating data over time. Additionally, while a couple of 

the 30 day CEMS test units included startups and shutdowns within the period, that was not done 

for all units, and there was no long term CEMS data for oil fired boilers. 

It is not feasible to conduct emissions testing during SSM periods due to the variable nature of 

those conditions. It is not feasible to conduct emissions testing during malfunctions since by 

definition there are operational problems that could indeed be safety issues during those periods. 

Therefore, trying to incorporate SSM periods into an emission limit that must be met at all time 

is fraught with problems. We are concerned that if such limits were set, operators could be 

placed in an untenable position of trying to operate equipment and not exceed emissions limits, 

and be tempted to take shortcuts that could place equipment and personnel at risk relative to 

equipment integrity and safety. However, the approach in this rule of limiting CO limit 

applicability to 50% operating rate or greater avoids much of the SS issues for CO, but those 

issues still exist for the other MACT limits. 

Therefore, we urge EPA to utilize its discretion to allow facilities to establish site and unitspecific startup and shutdown plans as a work practice approach during SS periods so that 

appropriate practices are followed with minimization of emissions during those periods to the 

extent practical. Malfunctions should also be managed similarly with a malfunction plan, so that 

operators are knowledgeable and trained to recognize potential malfunctions and to take 

appropriate actions which allow for safety as of utmost importance with protection of equipment 

integrity. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Bob Perry

Commenter Affiliation: FirstEnergy Corp

Document Control Number: EPA-HQ-OAR-2006-0790-1959.1

Comment Excerpt Number: 10

Comment: The MACT floor analysis does not account for effects of startup, shutdown, or 

malfunction (SSM) on CO emissions for new or existing units. This is critical for units that are 

required to demonstrate continuous compliance with the CO limit using a CO CEMS since Part 

63 no longer includes exemptions for SSM periods. 

Unfortunately, EPA has not presented sufficient data for those units in the MACT floor pool to 

address load-related variability. EPA will need to obtain additional data (e.g. CO CEMS data) in 
order to conduct this analysis. In obtaining this data, RMB recommends that EPA include 

periods of startup/shutdown (particularly cold-start) that are representative of each boiler class. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Michael A. Livermore

Commenter Affiliation: Institute for Policy Integrity New York University School of Law

Document Control Number: EPA-HQ-OAR-2006-0790-1899.1

Comment Excerpt Number: 11

Comment: Start up, shut down, and malfunction rules: The previous boiler MACT proposal and 

the prior solid waste incinerator rules contained exceptions for otherwise applicable emissions 

limits during “periods of startup, shutdown, and malfunction. [Footnote: 75 Fed. Reg. at 32,035.] 

In accordance with the D.C. Circuit’s opinion in Sierra Club v. EPA (2008), [Footnote: 551 F.3d 

1019 (DC Cir. 2008), cert. denied, 2010 U.S. LEXIS 2265 (2010).] the current proposed rules do 

not contain any such exemptions, and the proposed standards would apply to regulated sources at 

all times. [Footnote: 75 Fed. Reg. at 32,012.] 

In addition to the legal reasons contained in the D.C. Circuit’s opinion, this change is also 

justified on policy grounds. As the proposed rule notes, startup and shutdown are entirely 

predictable events and can be included in the general emissions standard by EPA. [Footnote: 75 

Fed. Reg. at 32,013.] By contrast, malfunction events should be entirely unpredictable and, as the 

preamble for the Major Source Proposal notes, the best performing sources should not be 

malfunctioning at all. [Footnote: 75 Fed. Reg. at 32,013.] 

Response: We agree that standard should apply at all times. Please see response to DCN EPAHQ-OAR-2006-0790-1747.1, Excerpt Number 1. Also, section 63.11226 has been added to the 

final on how a source may assert an affirmative defense if an emission limit is exceeded during a 

malfunction.

Commenter Name: Robert E. McKenna

Commenter Affiliation: Motor and Equipment Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1920.1

Comment Excerpt Number: 11

Comment: Finally, EPA’s analysis failed to properly address the variability of the data, as well 

as emissions associated with startup, shutdown and malfunction. Thus, EPA’s proposed limits do 

not appropriately address the variability in emissions of various HAPs. 
Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 12

Comment: If an unrepresentative steady state emission limit and/or compliance averaging time 

is implemented (e.g.. 1 or 2 ppmvdc CO using a daily average of CEMS data) with this 

regulation both of which obviously were not developed to take into consideration 

startup/shutdown/load changing/non-routine operations, we request an alternative compliance 

method during startup/shutdown/load changing/non-routine operating times for units that are 

required to install CEMS. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 13

Comment: For units that will be required to install CO CEMS we request the option to use the 

facility CO CEMS data to develop site specific startup/shutdown/load changing/non-routine 

operating times emission limits based upon historical CEMS data. This way required CEMS data 

could be put to good use to develop limits that would apply to a given facility. Data during 

startup/shutdown/load changing/non-routine operating times would be evaluated separately from 

steady state operations. The limits developed by a facility would be maintained in the facility’s 

monitoring plan and would be available to EPA upon request. Although this recommendation 

would require additional work from facilities it would allow facilities that could not satisfy the 

steady state emissions limit during startup/shutdown/load changing/non-routine operating times 

to evaluate these transient operating conditions separately. This data analysis process would also 

better serve the concept of emission limits applying during all operating time frames. If this 

alternative method would be adopted by a facility the data analysis option of including only data 

greater than 50% of its rated load would not be necessary considering startup/shutdown/load 

changing/non-routine operating times would be evaluated separately. We recommend EPA 

review the following reference regarding the application of the upper prediction bound when 

developing emission limits during startup and shutdown operating times. We are available to 

discuss this reference further, if requested. 
Suess, D.T., Suess, E.A., Gregory, S.R. Development of startup and shutdown permit limits 

based upon historical data from combustion sources monitored by continuous emission 

monitoring systems, Extended Abstract AWMA, 2009-A597-AWMA 

Response: First, please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt 

Number 1. Second, the requirement for certain area source boilers to install and operate CO 

CEMS has been removed from the final rule. Also, section 63.11226 has been added to the final 

on how a source may assert an affirmative defense if an emission limit is exceeded during a 

malfunction.

Commenter Name: Robert R. Scott

Commenter Affiliation: New Hampshire Department of Environmental Services

Document Control Number: EPA-HQ-OAR-2006-0790-1952.1

Comment Excerpt Number: 14

Comment: EPA should use portable analyzers to evaluate SSM emissions at smaller boilers in 

the ICR that do not have CEMs concurrently during future compliance testing. This should give 

EPA sufficient information within five years from promulgation of the regulation to develop 

appropriate limits and averaging times for SSM emissions. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Sarah E. Amick

Commenter Affiliation: Rubber Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1918.1

Comment Excerpt Number: 18

Comment: The proposed Area Source Rule does not include a separate standard for startup and 

shutdown. This is a fundamental problem that, if not corrected, will cause the final standards to 

be not achievable by even well designed and operated boilers. As a result, EPA must include a 

separate standard for startup and shutdown in the final rule. 

EPA explains in the preamble that, “Based upon continuous emission monitoring data, obtained 

as part of the information collection effort for the major source boiler and process heater 

rulemaking, which included periods of startup and shutdown, over long averaging periods, 

startups and shutdowns will not affect the achievability of the standards.” 75 Fed. Reg. at 31901. 

There are three fundamental problems with this justification for not including startup and 

shutdown standards in the rule. 

The continuous monitoring data that EPA presents in the major source industrial boiler MACT 

proposal is for units that will not be subject to the Area Source Rule and that are not the unit(s) 

from which EPA obtained the data used in setting the proposed area source standards. Thus, 

these emissions data cannot lawfully be used in determining the area source standards because 
these data are derived from sources that do not belong to the area source category. The 

conclusion that a separate standard for startup and shutdown is not needed can only be based on 

data from the source(s) that are actually used by EPA to set the area source standards or on a 

showing that the data from some other boilers are representative of the performance of the area 

source boilers used as the basis for the proposed area source standards. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1.

Commenter Name: Sarah E. Amick

Commenter Affiliation: Rubber Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1918.1

Comment Excerpt Number: 19

Comment: EPA’s emissions database provides continuous emissions monitoring system 

(“CEMS”) data from several of the better performing sources. Contrary to EPA’s assertion in the 

preamble, these data show that daily average emissions should be expected to vary considerably 

on a day-to-day basis and that the variability spans the proposed levels of the standards. While it 

is difficult to discern the reasons for this variability based on the information provided in the 

database, there is little doubt that startups and shutdowns significantly contribute to the variable 

emissions performance of these units. Thus, the data indicate that EPA needs to include express 

accommodation for startups and shutdowns. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Sarah E. Amick

Commenter Affiliation: Rubber Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1918.1

Comment Excerpt Number: 20

Comment: Basic scientific and engineering principles support the need for a separate standard 

for startup and shutdown. Particularly for CO emissions, combustion conditions will not be 

optimum during startup periods due to the generally low firing rate and the fact that the firing 

rate will be ramped up over the startup period. Thus, a significant period of non-optimum firing 

conditions will result in CO emissions performance – even on a daily average basis – that will be 

markedly different than performance during normal operations. EPA’s failure to acknowledge 

these basic technical and engineering principles renders the proposed standards arbitrary. 

We believe that a separate standard for startup and shutdown is needed and is amply justified. 

RMA suggest that a work practice standard is most appropriate due to the lack of relevant data 

and the fact that an emission testing during startup is not technically and economically 

practicable. If EPA decides that a numeric standard is needed, the Agency should rely on the 

available long term data from the better performing area source boilers to establish a standard 
with a reasonably long averaging time (such as a 30-day rolling average), rather than the 

proposed 24-hour averaging time. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Gary Melow

Commenter Affiliation: Michigan Biomass

Document Control Number: EPA-HQ-OAR-2006-0790-1917.1

Comment Excerpt Number: 24

Comment: Another complication of establishing a CO emission limitation in PPM, corrected to 

O2, is that it is not practical to use this type of emission limit during startup and shutdown 

events. This problem would not be detectable for a source that does periodic stack testing at 

normal load. However, for sources such as ours that are required by permit to operate continuous 

emission monitors at all times that we are combusting any fuel, this problem is very obvious. All 

of our air permits were long ago revised to remove corrected PPM limits for all pollutants with 

CEMs during startup and shutdown. (Limits in the form of lb/MMBtu share the same problem.) 

There are mathematical problems in using concentration levels corrected to an O2 level under 

startup conditions. Elevated O2 levels seen during startup result in highly inflated PPM values 

(we refer to this as “data blowup”) that cannot be compensated for in a longer averaging time. 

For example, in the first hour of startup when the O2 levels are very close to ambient levels, the 

O2 correction calculations provided for in Method 19 of 40 CFR 60 Appendix B yield invalid 

number. If the O2 monitor reads 20.9% (common for the first hour in startup), the emissions in 

corrected PPM is equal to infinity. If the O2 monitor reads 21% at the beginning of a startup 

(possible, given the accuracy of the instrument), the corrected PPM value will be a very large 

negative number. It is not uncommon to see corrected PPM in the tens of thousands in the first 

couple hours of startup. This happens despite the fact that actual emissions (raw PPM) values are 

quite low. 

Excessively high PPM corrected values will continue for several hours in a cold startup, and it 

can take up to 12 hours for our sources to approach an O2 level of 7%. The same mathematical 

problem occurs in a shutdown, although for a shorter amount of time. No averaging time will 

compensate for the invalid values seen when using a concentration corrected to a given % O2 

during startup. We have corrected our operating permits in all cases to eliminate the use of a 

PPM corrected value (or a lb/MMBtu value, which in Method 19 carries the same mathematical 

problem see equations 19-1 to 19-3) during startup or shutdown conditions. We instead rely on 

mass emission rate values, which is practical on a unit-by-unit basis considering actual size. See 

data in Attachment D which uses an arbitrary raw CO concentration value of 20 PPM and 

calculates the corrected PPM value at various O2 levels. The same problem occurs during 

shutdown, only the timeframe is shorter. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 
Commenter Name: Michael Hutcheson

Commenter Affiliation: Ameren Corp.

Document Control Number: EPA-HQ-OAR-2006-0790-2012.1

Comment Excerpt Number: 1

Comment: US EPA requests comment on whether additional provisions should be added to 

regulatory text in light of the absence of an SSM exemption. Ameren believes that US EPA errs 

by not including an exemption for Startups, Shutdowns and other transient events such as 

malfunctions which are inherently uncontrolled or difficult to control. US EPA has not even 

attempted to show that given the add-on controls and fuel mixes required for compliance with 

this standard sources will be able to achieve the vary stringent limitations. US EPA merely states 

that boilers do not normally startup and shutdown more than once per day and therefore are part 

of their routine operations and are already addressed by the standards. 

This premise is flawed. The standards proposed are not based on any startup or shutdown 

operations. None of the stack test data collected during the ICR includes any startup or shutdown 

periods and therefore the MACT standards do not reflect the emission limitation achievable by 

the best performing 12 % of sources during these periods. 

US EPA can not definitively state that based on the record, the standards reflect emission rates 

that are achievable during startups, shutdowns, malfunctions or other transient events by the best 

performing 12 % of sources. Because US EPA cannot definitively state that, US EPA needs to 

revise the standards to reflect levels achievable during these periods by either collecting 

additional data or by exemption. 

US EPA also apparently maintains that because boilers “normally” do not startup and shutdown 

daily so it isn’t important for the standards to reflect SSM periods. Whether or not boilers startup 

and shutdown daily, however, is irrelevant to the standards setting process. US EPA professes 

that these periods are “routine operations” and if this is the case, the standards should reflect 

emission rates that the best performing boilers are able to achieve during these “routine 

operations”. US EPA states it believes boilers can meet these standards during startup and 

shutdown periods, but provides no data which supports that argument. US EPA needs to provide 

actual data to support its claims that the best performing sources have achieved these standards 

in practice during startups, shutdown and/or malfunction periods. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Thompas P. Balf

Commenter Affiliation: Campus Cortium for Environmental Excellence

Document Control Number: EPA-HQ-OAR-2006-0790-1657.1

Comment Excerpt Number: 1
Comment: The proposed rule does not provide exemptions from emissions limits during periods 

of startup, shutdown, malfunction, and other non-routine operational scenarios. The intentions of 

the limits represent mainly steady state operations for boilers since an oil-fired boiler frequently 

operating in a non-steady state manner (i.e. startup/shutdown/load change...) could not satisfy a 

daily average emissions limit at the proposed levels (i.e. 1 ppmvdc for new boilers and 2ppmvdc 

for existing boilers). This approach raises questions/challenges for our members with respect to 

“averaging” emissions and requirements for installation of Continuous Emissions Monitoring 

System (CEMS) equipment. 

While the proposed rule requirements for CEMS compliance data does not take into 

consideration emissions data taken at less than 50 percent of a boilers rated capacity (i.e. 

startup/shutdown data), some startup, shutdown, malfunction and other non-routine operational 

data would still be included. For boilers that regularly startup or shutdown or operate in a manner 

that requires regular load changes, the proposed limits may be unattainable on a daily average. 

Considering 40 CFR 60 Subpart Db, which also applies to boilers >100mmbtu/hr, utilizes 30-day 

CEMS averages for NOx compliance for residual oil firing boilers and that the CO proposed 

limits in this proposed rule are extremely low, it seems as if a 30-day averaging time frame 

would be more appropriate than daily averaging time frames to allow for units to better average 

transient operating events over a longer portion of time. 

Recommendation: We suggest a 30-day average time frame excluding startup, shutdown, 

malfunction, and other non-routine operational scenarios. If 30-day averages are adopted by 

EPA, we would suggest adopting the data reduction requirements found in 40 CFR 60 Subpart 

Db. 

If daily averages are deemed necessary by EPA, we request a discussion regarding the health 

benefits to justify daily averages in lieu of 30-day average compliance time frames. After 

revisiting the limit magnitudes and CEMS installation requirements as described in greater detail 

below, we suggest that the daily average calculation require at least 18 operating hours (i.e. 75% 

of hours per day) to calculate a daily average to avoid calculating averages that may consist of 

mainly startup, shutdown, malfunction or other non-routine operational scenario data. For 

reference, the most recent version of the Pennsylvania Department of Environmental Protection’s 

Continuous Source Monitoring Manual Revision Number 8 requires 18 valid hours to calculate a 

daily average. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Caroline Choi

Commenter Affiliation: Progress Energy

Document Control Number: EPA-HQ-OAR-2006-0790-2226.1

Comment Excerpt Number: 2
Comment: EPA Should Not Treat HAP Emissions During Startup and Shutdown the Same as 

HAP Emissions During Normal Operation 

The IB information collection request (ICR) did not require any testing during start-up, shutdown 

and malfunction events. Without emissions data during these periods, EPA has no factual basis 

for concluding that the best performing units can achieve the proposed MACT limits during 

start-up, shutdown and malfunction events. Operations during boiler start-ups are different than 

normal plant operations. Certain plant components must be started in a specific sequence in order 

to ensure that steady state operations can be achieved. During start-up, not all pieces of control 

equipment will be operating at peak efficiency. Progress Energy believes that work practice 

standards are far more appropriate during periods of start-up, shutdown and malfunction. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Cynthia A. Finley

Commenter Affiliation: National Association of Clean Water Agencies

Document Control Number: EPA-HQ-OAR-2006-0790-2260.1

Comment Excerpt Number: 2

Comment: The proposed NESHAP does not have an exemption for startups, shutdowns, and 

malfunctions (SSM), and Table 6 removes the requirements for an SSM plan and the 

requirements to maintain and operate the facility according to that plan. Compliance with the 2 

ppm carbon monoxide emissions limit for existing liquid fueled boilers will be difficult for some 

boilers if the startup emissions must be included in the daily average emissions value. For 

example, one NACWA member has boilers with a design that requires the use of diesel fuel 

during startup. The startup sequence typically takes about six hours for a cold start, to control 

thermal expansion of the boiler. While carbon monoxide emissions are well below the 2 ppm 

limit during normal operation on digester gas, oil, or mixed fuel, inclusion of boiler startups will 

cause the carbon monoxide emissions to exceed the 2 ppm limit. The boilers employ low NO), 

burners and flue gas recirculation, and the operation has been evaluated and optimized by 

combustion experts to ensure efficient combustion. The rule should address a source specific 

exemption for situations in which emissions have been minimized to the extent possible to avoid 

noncompliance due to startups. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: William Rogers

Commenter Affiliation: DTE Energy

Document Control Number: EPA-HQ-OAR-2006-0790-2159.1

Comment Excerpt Number: 2
Comment: Operations during periods of startup, shutdown and malfunction are different those 

of steady state operation. Yet, EPA did not require any testing during these periods of upset 

conditions. EPA suggests that startup and shutdown periods have been taken into account "in 

establishing the standards in this rule", but there is no demonstration that the best performing 

units can achieve the proposed MACT limits during periods of startup, shutdown or malfunction. 

EPA must obtain emission data during these periods and utilize this data while setting MACT 

emission limits. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 3

Comment: An affected source required to use a continuous emission monitor (CEM) that fails to 

comply with an emission limit should be considered a violation even during startup and 

shutdown events. Continuous emission monitoring data obtained from best performing units, and 

used in establishing the standards, include periods of startup and shutdown. The EPA did not 

establish separate emission standards for these periods because startup and shutdown are part of 

routine operations and are being addressed by the proposed standards. There should not be 

discretion for what constitutes a violation when an affected source required to have a CEM fails 

to meet the specified emission limit. 

Response: First, please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt 

Number 1. Second, the provision requiring CO CEMS has been removed from the final rule. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Terry Walmsley

Commenter Affiliation: Fibrowatt LLC

Document Control Number: EPA-HQ-OAR-2006-0790-2201.1

Comment Excerpt Number: 3

Comment: While Fibrowatt has concerns about uniform treatment of biomass fuels, the 

categorization of boiler types under the Major Source Boiler Rule, the methodology utilized to 

arrive at emission limits under the Major Source Boiler Rule and the Area Source Boiler Rule, 

and the means prescribed for demonstrating compliance with said emissions limits, the primary 

concern of Fibrowatt relates to the Major Source Boiler Rule and the Area Source Boiler Rule’s 

intention to apply the proposed emission limits during "startup, shutdown, and malfunction." 
As stated in the Major Source Boiler Rule at 32050 and the Area Source Boiler Rule at 31926, a 

source must meet emission standards at all times during the operation of the plant, therefore this 

presumably would uniformly include during periods of Startup, Shutdown, and Malfunction 

("SSM") . While EPA suggests that a uniform emission limit can encompass normal SSM, 

Fibrowatt believes that continuous compliance can be adversely impacted by a truncated daily 

averaging period. Fibrowatt further believes that this requirement can have practical problems 

associated with normal transitions through periods of SSM and supports an approach that would 

stipulate an alternative but enforceable limit during periods of startup and shutdown as opposed 

to a single uniform limit. Fibrowatt further requests that EPA provides more definitive guidelines 

on how periods of malfunction will be appropriately addressed in the rules and address emission 

limit applicability during such unpredictable occurrences. 

As an example, under normal and predictable startup operations, a requirement to continuously 

meet uniform emission limits may be difficult for certain types of biomass fuels as the unit 

progresses through the normal transition from startup fuel to biomass fuel. Although Fibrowatt 

utilizes a low emission startup fuel (expected to be propane) and it is reasonable to maintain 

emission standards while on startup fuel, the switch from propane to certain biomass fuels in a 

spreader=stoke boiler can typically result in a significant variation in carbon monoxide (CO) 

emissions that can adversely effect the CO average (especially during truncated daily operations) 

and therefore compliance demonstration. Including such startup period in the normal compliance 

determination for CO may not be achievable under all conditions and all biomass fuels where the 

normally startup period can run for a long period of time, for example during a "cold=start ." 

Furthermore, the Major Source Boiler Rule at 32013 and the Area Source Boiler Rule at 31901 

suggest that emissions during malfunction events would represent an alternative operating mode 

but does not resolve how this alternative operating mode would be adequately dealt with in the 

proposed rule. While the supporting language in the Major Source Boiler Rule at 32013 and the 

Area Source Boiler Rule at 31902 suggest that EPA will determine an appropriate response to 

the malfunction event, this is not adequately addressed in the proposed Major Source Boiler Rule 

and the Area Source Boiler Rule as it relates to limit applicability "at all times." 

Fibrowatt requests that EPA better=defines its "appropriate response" to malfunction events so 

regulated parties under the Major Source Boiler Rule and the Area Source Boiler Rule can 

properly evaluate measures required during such malfunction events. Fibrowatt further requests 

an additional comment period be given for regulated parties to assess what EPA establishes as 

good operating practices during malfunction events and associated consequences to EPA’s 

"appropriate response" to such events. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Thomas D. Emero

Commenter Affiliation: Beaver Wood Energy

Document Control Number: EPA-HQ-OAR-2006-0790-2166.1

Comment Excerpt Number: 3
Comment: BWE also takes exception with the proposed rule allowing no exemptions of the 

emission limits during start up, shutdown, or malfunctions. BWE will strive to operate in full 

compliance with all emission limits at all times, but as stated earlier the use of biomass fuel in 

northern climates presents operating challenges that may result in occasional CO spikes due to 

frozen or wet fuel being introduced to the boiler, BWE believes allowances for unavoidable 

malfunctions and during startup/shutdown periods must be included in the proposed regulation. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Paul Lyskava

Commenter Affiliation: Pennsylvania Forest Products Association

Document Control Number: EPA-HQ-OAR-2006-0790-2223.1

Comment Excerpt Number: 4

Comment: Furthermore, If EPA adopts numeric emissions limitations, the final rule must 

include a separate standard for periods of startup and shutdown. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. .

Commenter Name: Rob Barton

Commenter Affiliation: RMB Consulting and Research

Document Control Number: EPA-HQ-OAR-2006-0790-2140.1

Comment Excerpt Number: 4

Comment: The MACT floor analysis does not account for effects of startup, shutdown, or 

malfunction (SSM) on CO emissions for new or existing units. This is critical for units that are 

required to demonstrate continuous compliance with the CO limit using a CO CEMS since Part 

63 no longer includes exemptions for SSM periods. 

Unfortunately, EPA has not presented sufficient data for those units in the MACT floor pool to 

address load-related variability. EPA will need to obtain additional data (e.g. CO CEMS data) in 

order to conduct this analysis. In obtaining this data, RMB recommends that EPA include 

periods of startup/shutdown (particularly cold-start) that are representative of each boiler class. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Keith M. Krom
Commenter Affiliation: AT&T, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2243

Comment Excerpt Number: 4

Comment: EPA should define standards for start-up, shutdown, and malfunction 

Citing a decision of the U.S. Court of Appeals for the District of Columbia Circuit [Footnote: 

Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008)], EPA has determined that affected sources 

will not be exempted from the standards proposed during periods of time involving start-ups, 

shutdowns, and malfunctions ("SSM"). Instead, EPA indicates that its proposed standards would 

apply at all times. EPA’s stated rationale is that because the standards apply on a daily or 

monthly basis, this amount of averaging time means that the “achievability of the 

standard[s]”with regard to startups and shutdowns is not affected. With respect to malfunctions, 

EPA simply indicates that such should not be viewed as a distinct operating period and that "[i]n 

the event that a source fails to comply with the applicable section 112(d) standards as a result of 

a malfunction event, EPA would determine an appropriate response based on, among other 

things, the good faith efforts of the source to minimize emissions during malfunction periods, 

including preventative and corrective actions, as well as root cause analyses to ascertain and 

rectify excess emissions." 

If EPA believes that judicial decisions constrain its ability to exempt sources from SSM periods, 

it should otherwise establish relevant requirements for such periods. Where the Agency is setting 

an achievable standard with reference to the "best performing 12 percent of the existing sources," 

the Agency should develop the technical basis for any decisions it makes that are applicable to 

SSM periods. The Agency should not rely on a standard that is derived from normal operations 

of a source to define the performance required during inevitable SSM periods. In the context of 

this proposed rule, AT&T is not aware of any specific analysis within the record of this 

rulemaking that separately established the technical basis for the standards EPA seeks to apply 

during SSM periods. Instead, it appears that the Agency assumed that start-up and shutdown 

periods were achievable based simply on the averaging period of the proposed standard. 

With regard to malfunctions, EPA clearly made no effort to assess achievability of the standards 

it is proposing during such periods. Instead, EPA proposes that AT&T and other entities subject 

to this rulemaking should be placed a position where the Agency will decide on a future, 

undefined "appropriate" response. In effect, the Agency is indicating that it will decide the 

appropriate standard to apply for malfunctions outside the context of this rulemaking. This is 

clearly unacceptable to sources seeking to ensure their compliance with promulgated regulations. 

In effect, EPA is making it impossible to comply during a malfunction period where, by 

definition, a source is addressing "sudden and unexpected events."

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Abbie Krebsbach

Commenter Affiliation: Montana Dakota Utilities Co

Document Control Number: EPA-HQ-OAR-2006-0790-1975.1
Comment Excerpt Number: 4

Comment: Another concern of Montana-Dakota’s is that the rule does not provide a startup, 

shutdown, malfunction (SSM) exemption, and based on review of data from its applicable unit(s) 

that the numeric emissions limitations on particulate matter (PM), opacity, mercury and carbon 

monoxide (CO) will be unachievable, even with the proposed pollution controls required. The 

EPA must carefully reconsider how periods of SSM should be addressed, especially when 

requiring very stringent emission limits as proposed in the rule. Particularly for CO emissions, 

combustion conditions will not be optimum during startup periods when boiler operations are not 

as efficient as during full load operations. If SSM periods are not addressed appropriately, 

unachievable standards will result for not only older boilers, but for newer boilers as well. As a 

result, EPA must either include a separate standard for SSM conditions, or provide a longer 

averaging period, such as a semiannual or annual rolling average for all proposed MACT 

standards. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Rob Barton

Commenter Affiliation: RMB Consulting and Research, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2198.1

Comment Excerpt Number: 4

Comment: The MACT floor analysis does not account for effects of startup, shutdown, or 

malfunction (SSM) on CO emissions for new or existing units. This is critical for units that are 

required to demonstrate continuous compliance with the CO limit using a CO CEMS since Part 

63 no longer includes exemptions for SSM periods. 

Unfortunately, EPA has not presented sufficient data for those units in the MACT floor pool to 

address load-related variability. EPA will need to obtain additional data (e.g. CO CEMS data) in 

order to conduct this analysis. In obtaining this data, RMB recommends that EPA include 

periods of startup/shutdown (particularly cold-start) that are representative of each boiler class. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Robert W. Glowinski

Commenter Affiliation: American Wood Council

Document Control Number: EPA-HQ-OAR-2006-0790-1930.1
Comment Excerpt Number: 4

Comment: In addition, provisions for start-ups and shutdowns will need to be incorporated into 

the rule. Wood and multi-fueled fired boilers produce large CO variations during startups as the 

boiler heats up. Start-up can take up to 14 hours for some units. Shutdowns can also result in 

significant CO variability. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. .

Commenter Name: Duane Mummert

Commenter Affiliation: South Carolina Chamber of Commerce

Document Control Number: EPA-HQ-OAR-2006-0790-2247

Comment Excerpt Number: 5

Comment: The proposed Area Source Rule does not include a separate standard for startup and 

shutdown. This is a fundamental problem that, if not corrected, will cause the final standards to 

be not achievable by even well designed and operated boilers. As a result, EPA must include a 

separate standard for startup and shutdown in the final rule. Basic scientific and engineering 

principles support the need for a separate standard for startup and shutdown. Particularly for CO 

emissions, combustion conditions will not be optimum during startup periods due to the 

generally low firing rate and the fact that the firing rate will be ramped up over the startup 

period. Thus, a significant period of non-optimum firing conditions will result in CO emissions 

performance — even on a daily average basis — that will be markedly different than 

performance during normal operations. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Chris V. Isaacson

Commenter Affiliation: Alabama Forestry Association

Document Control Number: EPA-HQ-OAR-2006-0790-2060

Comment Excerpt Number: 5

Comment: If EPA adopts numeric emissions limitations, the final rule must include a separate 

standard for periods of startup and shutdown. 

The proposed Area Source Rule does not include a separate standard for startup and shutdown. 

This is a fundamental problem that, if not corrected, will cause the final standards to be not 

achievable by even well designed and operated boilers. As a result, EPA must include a separate 

standard for startup and shutdown in the final rule. 

EPA explains in the preamble that, "Based upon continuous emission monitoring data, obtained 

as part of the information collection effort for the major source boiler and process heater 
rulemaking, which included periods of startup and shutdown, over long averaging periods, 

startups and shutdowns will not affect the achievability of the standards." 75 Fed. Reg. at 31901. 

There are three fundamental problems with this justification for not including startup and 

shutdown standards in the rule. 

First, the continuous monitoring data that EPA presents in the major source industrial boiler 

MACT proposal is for units that will not be subject to the Area Source Rule and that are not the 

unit(s) from which EPA obtained the data used in setting the proposed area source standards. 

Thus, these emissions data cannot lawfully be used in determining the area source standards 

because these data are derived from sources that do not belong to the area source category. The 

conclusion that a separate standard for startup and shutdown is not needed can only be based on 

data from the source(s) that are actually used by EPA to set the area source standards or on a 

showing that the data from some other boilers are representative of the performance of the area 

source boilers used as the basis for the proposed area source standards. 

Second, EPA’s emissions database provides continuous emissions monitoring system ("CEMS") 

data from several of the better performing sources. Contrary to EPA’s assertion in the preamble, 

these data show that daily average emissions should be expected to vary considerably on a dayto-day basis and that the variability spans the proposed levels of the standards. While it is 

difficult to discern the reasons for this variability based on the information provided in the 

database, there is little doubt that startups and shutdowns significantly contribute to the variable 

emissions performance of these units. Thus, the data indicate that EPA needs to include express 

accommodation for startups and shutdowns. 

Third, basic scientific and engineering principles support the need for a separate standard for 

startup and shutdown. Particularly for CO emissions, combustion conditions will not be optimum 

during startup periods due to the generally low firing rate and the fact that the firing rate will be 

ramped up over the startup period. Thus, a significant period of non-optimum firing conditions 

will result in CO emissions performance — even on a daily average basis — that will be 

markedly different than performance during normal operations. EPA’s failure to acknowledge 

these basic technical and engineering principles renders the proposed standards arbitrary. 

For these reasons, we believe that a separate standard for startup and shutdown is needed and is 

amply justified. We suggest that a work practice standard is most appropriate due to the lack of 

relevant data and the fact that an emission testing during startup is not technically and 

economically practicable. If EPA decides that a numeric standard is needed, the Agency should 

rely on the available long term data from the better performing area source boilers to establish a 

standard with a reasonably long averaging time (such as a 30-day rolling average), rather than 

the proposed 24-hour averaging time. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Richard Rosvold

Commenter Affiliation: Xcel Energy Services, Inc
Document Control Number: EPA-HQ-OAR-2006-0790-2259.1

Comment Excerpt Number: 5

Comment: The EPA intends the listed limits to apply at all time periods, including during 

startup and shutdown. Their justification for this is that the limits are considered daily or monthly 

averages, and thus any spikes experienced during startup and shutdown would be smoothed out 

in the averaging. This is explained on page 31901 in the preamble to the rule, but not in the 

regulation itself. At a minimum, Table 1 of the regulation should be edited to indicate the 

appropriate averaging time for each pollutant. However, we question the validity of establishing 

limits during startup and shutdown in this manner. Carbon monoxide (CO) emissions spike 

during periods of startup and shutdown, often to levels that are orders of magnitude greater than 

the average values achieved during normal operations. The magnitude of these spikes is so 

severe in comparison with the limit, that we doubt any existing units would be able to meet a 

limit of 2 ppm. And while it is true, as EPA states on page 31901 of the preamble, that solid fuel 

boilers do not normally start up and shut down more than once per day, liquid fuels boilers have 

that capability. Imposition of such severe limits would eliminate that operating scenario. Also, 

there are many units that are primarily run to test the unit’s operating capabilities. These units are 

run for only a short time at high loads in a given operating run. The high concentrations during 

startup and shutdown severely skew the average concentrations. This also creates issues with 

compliance demonstration, as for many units, compliance is demonstrated with the average of 

three 1-hour long stack tests using EPA Method 10 conducted at maximum operating load. This 

testing method was not developed with startup and shutdown operations in mind. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Lewis F. Gossett

Commenter Affiliation: South Carolina Manufacturers Alliance

Document Control Number: EPA-HQ-OAR-2006-0790-2196.1

Comment Excerpt Number: 6

Comment: The proposed Area Source Rule does not include a separate standard for startup and 

shutdown. This is a fundamental problem that, if not corrected, will cause the final standards to 

be not achievable by even well designed and operated boilers. As a result, EPA must include a 

separate standard for startup and shutdown in the final rule. 

Basic scientific and engineering principles support the need for a separate standard for startup 

and shutdown. Particularly for CO emissions, combustion conditions will not be optimum during 

startup periods due to the generally low firing rate and the fact that the firing rate will be ramped 

up over the startup period. Thus, a significant period of non-optimum firing conditions will result 

in CO emissions performance – even on a daily average basis – that will be markedly different 

than performance during normal operations. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 
Commenter Name: John Donahue

Commenter Affiliation: Sappi Fine Paper North America

Document Control Number: EPA-HQ-OAR-2006-0790-2210.1

Comment Excerpt Number: 7

Comment: The proposed Area Source Rule does not include a separate standard for startup and 

shutdown. This is a fundamental problem that, if not corrected, will cause the final standards to 

be not achievable by even well designed and operated boilers. As a result, EPA must include a 

separate standard for startup and shutdown in the final rule. 

EPA explains in the preamble that, “Based upon continuous emission monitoring data, obtained 

as part of the information collection effort for the major source boiler and process heater 

rulemaking, which included periods of startup and shutdown, over long averaging periods, 

startups and shutdowns will not affect the achievability of the standards.” 75 Fed. Reg. at 31901. 

There are three fundamental problems with this justification for not including startup and 

shutdown standards in the rule. 

The continuous monitoring data that EPA presents in the major source industrial boiler MACT 

proposal is for units that will not be subject to the Area Source Rule and that are not the unit(s) 

from which EPA obtained the data used in setting the proposed area source standards. Thus, 

these emissions data cannot lawfully be used in determining the area source standards because 

these data are derived from sources that do not belong to the area source category. The 

conclusion that a separate standard for startup and shutdown is not needed can only be based on 

data from the source(s) that are actually used by EPA to set the area source standards or on a 

showing that the data from some other boilers are representative of the performance of the area 

source boilers used as the basis for the proposed area source standards. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Robert E. Cleaves

Commenter Affiliation: Biomass Power Association

Document Control Number: EPA-HQ-OAR-2006-0790-1992.1

Comment Excerpt Number: 7

Comment: A significant problem, as will be noted by others, is that the emission standards make 

no accommodation for startup and/or shutdown. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: John T. Heard

Commenter Affiliation: Virginia Coal Association, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2155.1
Comment Excerpt Number: 7

Comment: EPA makes a similar mistake with regard to its proposal not to set a separate 

standard for periods of startup, shutdown, and malfunction. On the one hand, EPA asserts that 

"[t]he standards we are proposing are daily or monthly averages „. [t]hus, we are not establishing 

separate emission standards for these periods because startup and shutdown are part of their 

routine operations and, therefore, are already addressed by the standards." (see submittal for 

footnote 6) On the other hand, EPA uses short term performance test results to set the standards 

rather than the results of longterm CEMS monitoring. As a result, the emissions data on which 

the standards are based do not, in fact, reflect or adequately accommodate emissions from 

periods of startup, shutdown, or malfunction. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: John Donahue

Commenter Affiliation: Sappi Fine Paper North America

Document Control Number: EPA-HQ-OAR-2006-0790-2210.1

Comment Excerpt Number: 8

Comment: EPA’s emissions database provides continuous emissions monitoring system 

(“CEMS”) data from several of the better performing sources. Contrary to EPA’s assertion in the 

preamble, these data show that daily average emissions should be expected to vary considerably 

on a day-to-day basis and that the variability spans the proposed levels of the standards. While it 

is difficult to discern the reasons for this variability based on the information provided in the 

database, there is little doubt that startups and shutdowns significantly contribute to the variable 

emissions performance of these units. Thus, the data indicate that EPA needs to include express 

accommodation for startups and shutdowns. 

Also, basic scientific and engineering principles support the need for a separate standard for 

startup and shutdown. Particularly for CO emissions, combustion conditions will not be optimum 

during startup periods due to the generally low firing rate and the fact that the firing rate will be 

ramped up over the startup period. Thus, a significant period of non-optimum firing conditions 

will result in CO emissions performance – even on a daily average basis – that will be markedly 

different than performance during normal operations. EPA’s failure to acknowledge these basic 

technical and engineering principles renders the proposed standards arbitrary. 

For these reasons, we believe that a separate standard for startup and shutdown is needed and is 

amply justified. We suggest that a work practice standard is most appropriate due to the lack of 

relevant data and the fact that an emission testing during startup is not technically and 

economically practicable. If EPA decides that a numeric standard is needed, the Agency should 

rely on the available long term data from the better performing area source boilers to establish a 

standard with a reasonably long averaging time (such as a 30-day rolling average), rather than 

the proposed 24-hour averaging time. 
Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: John Hopewell

Commenter Affiliation: American Coatings Association

Document Control Number: EPA-HQ-OAR-2006-0790-2062.1

Comment Excerpt Number: 9

Comment: EPA requests comment on whether there are any provisions that were inadvertently 

incorporated or overlooked in the proposal in light of the absence of an SSM exemption. EPA 

addressed the Startup and Shutdown periods by establishing daily or monthly average limits. -

However, there is no provision to address Malfunctions. EPA’s proposed standards will apply at 

all times, including during Malfunctions. 

EPA acknowledges the occurrence of legitimate malfunctions and the varied nature of 

malfunctions that can occur. However, the agency proposes to address Malfunctions by 

conducting case-by-case evaluations to determine if “among other thi ngs, the good faith efforts 

of the source to minimize emissions during malfunction periods, including preventative and 

corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. EPA 

would also consider whether the source’ s failure to comply with the CAA section 112(d) 

standard was, in fact, ‘sudden, infrequent, not reasonably preventable’ and was not instead 

‘caused in part by poor maintenance or careless peration.’” This approach is unacceptable to the 

regulated community. 

EPA has identified a legitimate problem with its rulemaking but has abdicated its responsibility 

to address that problem by passing it to the Office of Enforcement, state and local enforcement 

agencies, and non-government organizations. Each of these entities will have different 

interpretations of “malfunction” and when they are acceptable and unacceptable. This means that 

the standard to which industry must comply is ambiguous. EPA should correct this problem in 

the rule. 

For these reasons, the ACA believes that it is appropriate for EPA to revisit this issue. ACA 

suggests that EPA propose work practice standards that would allow sources a certain time 

period for start-up, shutdown and malfunction events and as long as certain procedures are 

followed, then compliance would be met. EPA could establish a threshold of exceedances that 

could occur during a quarterly or six month period before a violation occurs. This methodology 

is consistent with the MACT standard such as 40 CFR 63 Subpart MM which are well-suited to 

address malfunction periods and the complexities and challenges surrounding collecting data and 

establishing numerical standards for those events. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.
Commenter Name: Wayne J. Galler

Commenter Affiliation: Georgia Industry Environmental Coalition, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1997.1

Comment Excerpt Number: 9

Comment: The proposed Area Source Rule does not include a separate standard for startup and 

shutdown. GIEC believes that this approach will cause the final standards to be unachievable by 

even well designed and operated boilers. Therefore, GIEC recommends a separate standard for 

startup, shutdown, and malfunction in the final rule. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Sheila C. Holman

Commenter Affiliation: North Carolina Department of Environment and Natural Resources

Document Control Number: EPA-HQ-OAR-2006-0790-2222.1

Comment Excerpt Number: 9

Comment: [See submittal for Attachment A, Topic 2, which discusses SSM provisions.] 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Jay C. Moon

Commenter Affiliation: Mississippi Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-2000

Comment Excerpt Number: 10

Comment: EPA’s analysis failed to properly address the variability of the data, as well as 

emissions associated with startup, shutdown and malfunction. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Wayne J. Galler
Commenter Affiliation: Georgia Industry Environmental Coalition, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1997.1

Comment Excerpt Number: 11

Comment: EPA’s emissions database provides continuous emissions monitoring system 

("CEMS") data from several of the better performing sources. Contrary to EPA’s assertion in the 

preamble, these data show that daily average emissions should be expected to vary considerably 

on a day-to-day basis and that the variability spans the proposed levels of the standards. While it 

is difficult to discern the reasons for this variability based on the information provided in the 

database, startups and shutdowns can contribute to the variable emissions performance of these 

units. Thus, the data suggest that EPA should accommodate startups and shutdowns. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Ted Michaels

Commenter Affiliation: Energy Recovery Council

Document Control Number: EPA-HQ-OAR-2006-0790-1951.1

Comment Excerpt Number: 11

Comment: Citing a 2008 court decision (Sierra Club v. EPA) related to General Provisions 

under 40 CFR Part 63, EPA has proposed that Boiler MACT emission standards apply at all 

times, including during periods of startup, shutdown and malfunction (SSM). EPA acknowledges 

that the Court’s decision did not specifically address category-specific SSM provisions. We 

believe that EPA is over-stepping its authority to void longstanding category-specific SSM 

provisions. 

Aside from this legal deficiency, EPA’s proposed floor setting methodology fails to adequately 

consider biomass unit emissions that occur during SSM periods. In its proposal EPA uses short 

term performance test results to set the floors for CO. EPA inappropriately concludes that the CO 

standard reflects startup and shutdown periods citing CO CEM data from two major source 

biomass boilers which are not area source boilers, claiming “over long averaging periods, 

startups and shutdowns will not affect the achievability of the standards.” (75 FR 31901). The 

inapplicability of the major source CO data invalidates EPA’s conclusion for CO. In addition, 

EPA offers no SSM data for PM or opacity, two other pollutants with proposed standards under 

the Area Source Boiler Rule. As a result, EPA’s standards do not, in fact, reflect or adequately 

accommodate SSM emissions at area source boilers. 

Emissions can be significantly higher during SSM due to the unavoidable less-thanoptimal 

emissions control performance during transitional (non-steady state) conditions. For example, at 

biomass-to-energy facilities combustion-related emissions such as CO, particulate (smoke) and 

opacity increase during the startup period when load and temperature are coming up to full load 

steady-state conditions. The Maine Department of Environmental Protection has stated “Wood 

and multi-fueled boilers produce large CO variations during startups as the boiler heats up. Startups can take up to 14 hours for some units. Shutdowns can also result in significant CO 
variability.” [Letter James P. Brooks, Bureau Director, State of Maine Bureau of Air Quality to 

James Eddinger, USEPA, February 4, 2010. ] [See submittal for letter.] Startup burners reduce 

emissions by preheating the combustion chamber and downstream equipment but are not sized to 

achieve full load temperatures and even if they were could not completely avoid temporary suboptimal combustion conditions as heat load shifts from auxiliary fuel to waste during startup and 

from waste to auxiliary fuel during shutdown. Air pollution control equipment goes through 

similar transient temperature and flow conditions. These conditions are distinct from the variable 

conditions that occur during normal operation. EPA’s emission database excludes SSM periods 

and therefore does not capture this component of variability, leading to MACT floors that have 

not been achieved in practice. 

Consider for example Covanta Energy Corporation’s biomass-to-energy facility in Delano, 

California. The Delano plant combusts biomass in two bubbling fluidized bed combustors each 

equipped with natural gas fired auxiliary burners for startup and shutdown. The following table 

compares CO emissions observed during startup and shutdown periods with those during normal 

operations for the most recent four calendar quarters. Hourly averages from each unit were 

collected from the certified CEM system. Startup consisted of 2 hours worth of data before 

boilers were online and shutdown consisted of 2 hours of data after the boilers were offline. 

Normal emissions constitute the remaining hours. As can be seen both the average CO emissions 

and the standard deviation are far greater during startup and shutdown indicating a variability 

that EPA’s floor methodology does not consider. [See submittal for table.] 

EPA should set standards which consider SSM emissions. ERC suggests that work practice 

standards are most appropriate due to the lack of relevant data and the fact that emission testing 

during startup is not technically and economically practicable. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Martin T. Booher

Commenter Affiliation: Ethan Allen Interiors, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1974.1

Comment Excerpt Number: 12

Comment: EPA stated that its use of emissions averages should address any need for start-up 

and shut-down emissions. 75 Fed.Reg. 31.901. EPA’s averages were based on emissions from 

major source boilers. Given the wide variance in emissions between biomass-fired boilers, 

especially with respect to area source boilers, which tend to have different operating parameters 

than major source boilers, EPA’s use of averages may not adequately address this issue. Given 

this variability in facility use among industries, and the widely ranging emissions that can result, 

EPA also should consider setting specific start-up and shutdown limits that would give biomassfired area source boilers additional flexibility to meet regulatory requirements. 
Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Wayne J. Galler

Commenter Affiliation: Georgia Industry Environmental Coalition, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1997.1

Comment Excerpt Number: 12

Comment: Basic scientific and engineering principles support the need for a separate standard 

for startup and shutdown. Combustion conditions will not be optimum during startup periods due 

to the generally low firing rate and the fact that the firing rate will be ramped up over the startup 

period. Thus, a significant period of non-optimum firing conditions can result in emissions 

performance - even on a daily average basis - that will be markedly different than performance 

during normal operations. 

For these reasons, GIEC believes that a separate standard for startup and shutdown is needed. 

GIEC suggests that a work practice standard is most appropriate due to the lack of relevant data 

and the fact that an emission testing during startup is not technically and economically 

practicable. If EPA decides that a numeric standard is needed, GIEC urges the Agency to rely on 

the available long term data from the better performing area source boilers to establish a standard 

with a reasonably long averaging time (such as a 30-day rolling average), rather than the 

proposed 24-hour averaging time. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Ted Michaels

Commenter Affiliation: Energy Recovery Council

Document Control Number: EPA-HQ-OAR-2006-0790-1951.1

Comment Excerpt Number: 12

Comment: If EPA decides that a numeric standard is needed there are a few options. First, EPA 

could set standards applicable at all times which reflect the emissions variability inclusive of 

SSM. Second, EPA could set distinct standards which would apply only during SSM periods. 

Both these options are problematic - since its area source boiler emission database does not 

contain SSM data EPA would need to gather additional test data for the various categories and 

units. There are also difficulties trying to set concentration-based standards corrected to a 

standard diluent concentration (e.g., ppmdv @ 3% O2) for startup and shutdown periods. 

Emission concentrations soar artificially due to the exponentially increasing correction factor as 

the stack oxygen concentration approaches ambient levels and CO2 concentrations approach 

zero. At low unit loads at the beginning of startup or at the end of shutdown corrected emission 

concentrations could be very high giving the appearance of significant emissions when the actual 

mass emissions (pounds per hour) are small due to the low stack volumetric flow rates. If EPA 
decides to set concentration standards for SSM periods it should recognize the diluents caps of 

14 percent for oxygen or 5 percent for carbon dioxide in emission calculations as is currently 

done in the Large MWC MACT rule (40 CFR 60.58b (b)(8)). 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Ted Michaels

Commenter Affiliation: Energy Recovery Council

Document Control Number: EPA-HQ-OAR-2006-0790-1951.1

Comment Excerpt Number: 13

Comment: ERC supports a third option for numeric Area Source Boiler SSM standards which 

solves both the data availability and concentration-based standards problems. This approach 

would require that each State address SSM emission standards in its State Implementation Plans 

(SIP). The SIP would specify a procedure which would be used to set mass emission standards 

for CO and PM (e.g., pounds per startup period) and % for opacity for each subcategory and unit 

case-by-case based on emissions reductions achieved using accepted startup, shutdown and 

malfunction related procedures. For example, for a unit using auxiliary burners for startup, the 

startup CO limit would be set considering the limitations of a properly operated burner and boiler 

design during the defined startup period. SSM emissions would be minimized by the same 

emission reduction technologies that would enable units to comply with Area Source boiler 

standards and would thus represent a small component of a unit’s annual emissions. The case-bycase SSM emission limits would be written into facility permits and become federally 

enforceable mass emission standards. The unit’s continuous emission rate monitoring system 

(CERMS) would measure and report mass emissions during SSM periods. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Michael A. Livermore

Commenter Affiliation: Institute for Policy Integrity New York University School of Law

Document Control Number: EPA-HQ-OAR-2006-0790-1899.1

Comment Excerpt Number: 15

Comment: Start up, shut down, and malfunction rules: The previous boiler MACT proposal and 

the prior solid waste incinerator rules contained exceptions for otherwise applicable emissions 

limits during “periods of startup, shutdown, and malfunction. [Footnote: 75 Fed. Reg. at 32,035.] 

In accordance with the D.C. Circuit’s opinion in Sierra Club v. EPA (2008), [Footnote: 551 F.3d 

1019 (DC Cir. 2008), cert. denied, 2010 U.S. LEXIS 2265 (2010).] the current proposed rules do 
not contain any such exemptions, and the proposed standards would apply to regulated sources at 

all times. [Footnote: 75 Fed. Reg. at 32,012.] 

In addition to the legal reasons contained in the D.C. Circuit’s opinion, this change is also 

justified on policy grounds. As the proposed rule notes, startup and shutdown are entirely 

predictable events and can be included in the general emissions standard by EPA. [Footnote: 75 

Fed. Reg. at 32,013.] By contrast, malfunction events should be entirely unpredictable and, as the 

preamble for the Major Source Proposal notes, the best performing sources should not be 

malfunctioning at all. [Footnote: 75 Fed. Reg. at 32,013.] 

Response: First, the standards in the final rule do apply at all times. Second, please see 

response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. Also, section 63.11226 

has been added to the final on how a source may assert an affirmative defense if an emission 

limit is exceeded during a malfunction.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 16

Comment: The IB ICR did not require any testing during start-up, shutdown and malfunction 

events. Without emissions data during these periods, EPA has absolutely no factual basis for 

concluding that the best performing units can achieve the proposed MACT limits during start-up, 

shutdown and malfunction events. See 75 Fed. Reg. at 32,012-13. Operations during boiler startups are different than normal plant operations. Certain plant components must be started in a 

specific sequence in order to ensure that steady state operations can be achieved. During start-up 

not all pieces of control equipment will be operating at peak efficiency. Furthermore, manual 

compliance monitoring methods may not provide accurate measurements during start-up 

conditions. Work practices standards are far more appropriate during periods of start-up, 

shutdown and malfunction. 

If EPA insists on setting emission limits for these periods of operation then the Agency must 

obtain emission data during these periods of operation and properly analyze those data in order 

to set MACT emission limits. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1
Comment Excerpt Number: 20

Comment: Compliance with the proposed CO limits is problematic particularly during unit 

startups. As discussed in section I.H. above, there is no factual support for EPA’s conclusion that 

the CO standard is “achievable” during plant startup. No CO emissions testing was conducted 

during plant startup of biomass units. Startup of a biomass can take up to a day. During startup, 

work practice standards are more appropriate than CO emission limits. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Kevin M. Dempsey

Commenter Affiliation: American Iron and Steel Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2061

Comment Excerpt Number: 20

Comment: If EPA Adopts Numeric Emissions Limitations, the Final Rule Must Include a 

Separate Standard for Periods of Startup and Shutdown 

The Proposed Rule does not include a separate standard for startup and shutdown. This is a 

fundamental problem that, if not corrected, will cause the final standards to be unachievable by 

even well designed and operated boilers. As a result, EPA must include a separate standard for 

startup and shutdown in the final rule. 

EPA explains in the preamble that, “Based upon continuous emission monitoring data, obtained 

as part of the information collection effort for the major source boiler and process heater 

rulemaking, which included periods of startup and shutdown, over long averaging periods, 

startups and shutdowns will not affect the achievability of the standards.” 75 Fed. Reg. at 31901. 

There are three fundamental problems with this justification for not including startup and 

shutdown standards in the rule. 

EPA’s emissions database provides continuous emissions monitoring system (CEMS) data from 

several of the better performing sources. Contrary to EPA’s assertion in the preamble, these data 

show that daily average emissions should be expected to vary considerably on a day-to-day basis 

and that the variability spans the proposed levels of the standards. While it is difficult to discern 

the reasons for this variability based on the information provided in the database, there is little 

doubt that startups and shutdowns significantly contribute to the variable emissions performance 

of these units. Thus, the data indicate that EPA needs to include express accommodation for 

startups and shutdowns. 

Basic scientific and engineering principles support the need for a separate standard for startup 

and shutdown. Particularly for CO emissions, combustion conditions will not be optimum during 

startup periods due to the generally low firing rate and the fact that the firing rate will be ramped 

up over the startup period. Thus, a significant period of non-optimum firing conditions will result

in CO emissions performance – even on a daily average basis – that will be markedly different 
than performance during normal operations. EPA’s failure to acknowledge these basic technical 

and engineering principles renders the proposed standards arbitrary. 

For these reasons, we believe that a separate standard for startup and shutdown is needed and is 

amply justified. We suggest that a work practice standard is most appropriate due to the lack of 

relevant data and the fact that an emission testing during startup is not technically and 

economically practicable. If EPA decides that a numeric standard is needed, the agency should 

rely on the available long term data from the better performing area source boilers to establish a 

standard with a reasonably long averaging time (such as a 30-day rolling average), rather than 

the proposed 24-hour averaging time. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Bruce A. Steiner

Commenter Affiliation: American Coke and Coal Chemicals Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2007

Comment Excerpt Number: 21

Comment: The Proposed Rule does not include a separate standard for start-up and shutdown. 

This is a fundamental problem that, if not corrected, will cause the final standards to be 

unachievable by even well designed and operated boilers. As a result, EPA must include a 

separate standard for startup and shutdown in the final rule. 

EPA explains in the preamble that, “Based upon continuous emission monitoring data, obtained 

as part of the information collection effort for the major source boiler and process heater 

rulemaking, which included periods of startup and shutdown, over long averaging periods, 

startups and shutdowns will not affect the achievability of the standards.” 75 Fed. Reg. at 31901. 

There are three fundamental problems with this justification for not including start-up and 

shutdown standards in the rule. 

The continuous monitoring data that EPA presents in the major source industrial boiler MACT 

proposal is for units that will not be subject to the Proposed Rule and that are not the unit(s) from 

which EPA obtained the data used in setting the proposed area source standards. Thus, these 

emissions data cannot lawfully be used in determining the area source standards because these 

data are derived from sources that do not belong to the area source category. The conclusion that 

a separate standard for start-up and shutdown is not needed can only be based on data from the 

source(s) that are actually used by EPA to set the area source standards or on a showing that the 

data from some other boilers are representative of the performance of the area source boilers 

used as the basis for the proposed area source standards. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Bruce A. Steiner

Commenter Affiliation: American Coke and Coal Chemicals Institute
Document Control Number: EPA-HQ-OAR-2006-0790-2007

Comment Excerpt Number: 22

Comment: EPA’s emissions database provides continuous emissions monitoring system 

(CEMS) data from several of the better performing sources. Contrary to EPA’s assertion in the 

preamble, these data show that daily average emissions should be expected to vary considerably 

on a day-to-day basis and that the variability spans the proposed levels of the standards. While it 

is difficult to discern the reasons for this variability based on the information provided in the 

database, there is little doubt that startups and shutdowns significantly contribute to the variable 

emissions performance of these units. Thus, the data indicate that EPA needs to include express 

accommodation for start-ups and shutdowns. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Bruce A. Steiner

Commenter Affiliation: American Coke and Coal Chemicals Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2007

Comment Excerpt Number: 23

Comment: Basic scientific and engineering principles support the need for a separate standard 

for start-up and shutdown. Particularly for CO emissions, combustion conditions will not be 

optimum during start-up periods due to the generally low firing rate and the fact that the firing 

rate will be ramped up over the startup period. Thus, a significant period of non-optimum firing 

conditions will result in CO emissions performance – even on a daily average basis – that will be 

markedly different than performance during normal operations. EPA’s failure to acknowledge 

these basic technical and engineering principles renders the proposed standards arbitrary. 

For these reasons, we believe that a separate standard for start-up and shutdown is needed and is 

amply justified. We suggest that a work practice standard is most appropriate due to the lack of 

relevant data and the fact that an emission testing during startup is not technically and 

economically practicable. If EPA decides that a numeric standard is needed, the agency should 

rely on the available long term data from the better performing area source boilers to establish a 

standard with a reasonably long averaging time (such as a 30-day rolling average), rather than 

the proposed 24-hour averaging time. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 40
Comment: EPA’s Approach To Addressing SSM Violates The Clean Air Act. EPA’s approach 

to addressing startup, shutdown, and malfunction (SSM) periods in the proposed rule is contrary 

to the statute’s requirement that the standards established under 112(d)(2) be “achievable.” 

Furthermore, EPA’s claims that the standards reflect startup and shutdown periods are not 

supported by the record. 

To address the decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), cert. denied, 

2010 U.S. LEXIS 2265 (2010), which vacated the exemption in 40 C.F.R. 63.6(f)(1) and (h)(1) 

for SSM periods, EPA proposes “daily or monthly averages” standards in this area source rule 

that apply at all times, including periods of SSM. EPA claims in the preamble that startup and 

shutdown periods were taken into consideration when setting these standards based on CEMS 

data obtained from major sources pursuant to the proposed MACT standards. 75 Fed. Reg. 

31901-02. According to the preamble, continuous emissions monitoring data from the best 

performing units, which include startup and shutdown periods, are used to set the floor levels in 

the proposed rule. See id. EPA further notes that startup and shutdown are part of “routine 

operations” and are therefore “already addressed” in the MACT standards. See id. 

With regard to malfunctions, however, EPA states that these periods should not be viewed as a 

“distinct operating mode,” and thus, emissions from these periods do not need to be factored into 

developing the MACT floor levels. See id. Moreover, EPA states that even if malfunctions were 

to be considered a distinct operating mode, it would be “impracticable to take malfunctions into 

account in setting CAA section 112(d) standards for area source boilers” given that these 

episodes are by definition sudden and unexpected events which vary in degree, frequency, and 

duration. Id. 

When setting 112(d) standards in the early 1990s, EPA used its New Source Performance 

Standards (NSPS) program as a model. The 112 standards were acknowledged by EPA to be 

“essentially equivalent to [section 111] performance standards” and that “unpredicted and 

reasonably unavoidable failures of air pollution control systems” would occur. 58 Fed. Reg. 

42760, 42777 (Aug. 11, 1993). To address this situation, EPA adopted a similar exemption to the 

one in the NSPS Program for SSM events and imposed a “general duty” to minimize emissions. 

Thus, EPA acknowledged, as early as 1993, that SSM events are not appropriate for inclusion in 

a 112 standard and that an alternative approach should be used to address these situations. While 

the D.C. Circuit has ruled that sources cannot be exempt from complying with MACT standards, 

the court noted that Congress recognized in some instances that it may not be feasible to 

prescribe or enforce an emission standard under 112, and so 112(h) “work 

practices” or “operational” standards are available in certain limited situations. See Sierra Club 

v. EPA, 551 F.3d at 1028. 

The D.C. Circuit also has recognized that standards based on what sources achieve must account 

for the limitations inherent in the technology used to reduce emissions. For example, in a case 

reviewing 111 NSPS, Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 398 (D.C. Cir. 

1973), the court acknowledged that “ ‘startup’ and ‘upset’ conditions due to plant or emission 

device malfunction, is an inescapable aspect of industrial life and that allowance must be made 

for such factors in the standards that are promulgated.” Id. at 399. Furthermore, in National Lime 

Ass’n v EPA, 627 F.2d 416 (D.C. Cir. 1980), the court noted that “a uniform standard must be 

capable of being met under most adverse conditions which can reasonably be expected to recur.” 
Id. at 431 n.46. The D.C. Circuit acknowledged this same principle almost 20 years later when 

reviewing emission standards for new sources in the medical waste incinerator rule under 129 in 

Sierra Club v. EPA, 167 F.3d 658 (D.C. Cir. 1999). In that case, while the court did not find the 

record sufficient to support EPA’s approach for new sources, the D.C. Circuit did not object to a 

standard-setting approach which would account for the performance of technology under the 

“worst reasonably foreseeable circumstances.” See id. at 665. Furthermore, the D.C. Circuit 

reiterated the principle in National Lime that “where a statute requires that a standard be 

‘achievable,’ it must be achievable ‘under the most adverse circumstances which can reasonably 

be expected to recur.’” Id. at 665 (citing National Lime Ass’n v EPA, 627 F.2d 416, 431 n.46 

(D.C. Cir. 1980)). 

EPA’s MACT floor-setting approach ignores these longstanding principles and mischaracterizes 

the role startup and shutdown data plays (or rather, does not play, as the case is here) in EPA’s 

floor-setting process. As noted above, EPA claims that the agency considered startup and 

shutdown periods when setting the floors because CEMS data, relied on by EPA in “establishing 

the standards,” included data from those periods. This representation is a serious misstatement of 

the Agency’s record. As discussed in the following subsection, EPA does not rely on the CEMS 

data when setting the floors for boilers. Thus, according to EPA’s own docket materials,[See 

e.g., Memorandum from A. Singelton, ERG, to J. Eddinger, U.S. EPA, MACT Floor Analysis 

(2010) for the Industrial, Commercial, and Institutional Boilers and Process Heaters National 

Emission Standards for Hazardous Air Pollutants – Major Source at 3 (April 2010).] the data 

used to set the proposed floors fail to account for the dynamic conditions and variable emissions 

occurring during startup and shutdown episodes. Furthermore, as the ERG memorandum makes 

abundantly clear, EPA’s approach does not make use of the CEMS data (with the startup and 

shutdown information) in its variability analysis where it would be the most helpful in reflecting 

real world fluctuations in emissions. Id. 

Given the absence of startup and shutdown emissions information from the test run data relied on 

by EPA to set the proposed standards and the difficulty of collecting data from such brief 

operation periods, it is appropriate for EPA to set work practices or management practices for 

these events for area source boilers. 

Section 112(h)(1) of the CAA allows EPA to set work practice standards for situations where “it 

is not feasible in the judgment of the Administrator to prescribe or enforce an emission standard . 

. . .” Gathering data from startup and shutdown periods would be challenging given the brief 

nature of these periods as well as the need to define the exact time period for what is considered 

“startup” and/or “shutdown.” Gathering data during a malfunction event would be even more 

challenging. Moreover, the definition of “not feasible to prescribe or enforce an emission 

standard” is defined in 112(h)(2) as any situation where “the application of measurement 

methodology to a particular class of sources is not practicable due to technological and economic 

limitations.” Startup, shutdown and malfunction episodes fit with this definition and would 

justify the agency setting work practices to address emissions during these periods. 

Alternatively, when establishing emission standards for area sources EPA has the authority to 

establish “management practices” in lieu of MACT or GACT. Section 112(d)(5) states in 

pertinent part: 

“With respect only to ... area sources ... the Administrator may, in lieu of the authorities provided 

in paragraph (2) and subsection (f) of this section, elect to promulgate standards or requirements 
... which provide for the use of [GACT] or management practices to reduce emissions of 

[HAP.]” 

EPA should use this statutory authority to require management practices to reduce HAP 

emissions during periods of SSM at area sources. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 41

Comment: UARG also is very concerned about the potential for enforcement of operating 

parameter and opacity limits during periods of startup, shutdown, and in the event of equipment 

malfunction. When EPA finalized its rule in 2004 with enforceable operating parameters, it did 

so with a rule that also made clear that those limits did not apply during periods of “startup, 

shutdown, and malfunction.” 40 C.F.R. 63.7505(a), 69 Fed. Reg. at 55,254. EPA’s current 

proposal contains no such exception, but instead would allow enforcement of deviations from 

operating parameters during periods of startup and shutdown, when controls would not be 

expected to be operating at the same levels as during performance tests, and due solely to 

equipment malfunctions. In the preamble, EPA discusses its approach to these events. 75 Fed. 

Reg. at 32,013. Regarding startup and shutdown, EPA asserts that it has taken these periods into 

account by using CEMS data from best performing units that include periods of startup and 

shutdown, and by proposing use of “daily or monthly averages.” Regarding malfunctions, EPA 

asserts that it would use a variety of information to determine an appropriate response to 

exceedances caused by equipment malfunction. Id. 

EPA’s preamble assertions regarding startup and shutdown are inapplicable to control device 

operating parameter limits, which are based on 12-hour averages (not daily or monthly averages) 

established during performance test (not based on CEMS data that include startup and 

shutdown). Even a daily block average, as proposed for opacity, does not provide sufficient 

protection if the unit does not startup or shutdown at exactly midnight, since there might not be 

sufficient data under normal operating conditions to compensate for the startup or shutdown 

period. In short, EPA has made absolutely no allowance in its rules for periods of startup and 

shutdown. To the contrary, EPA has proposed to require sources to establish control device 

operating parameter levels that are dependent upon load during periods of “maximum normal 

operating load,” and then maintain those levels during periods other than maximum normal 

operating load, including startup and shutdown. EPA’s proposal is patently unreasonable. EPA 

must address these periods in some other manner, for example by establishing simple work 

practice standards in lieu of operating parameters. 
EPA’s promise to address periods of equipment malfunction by considering other information 

before enforcing exceedances of operating limits also provide little comfort, especially given the 

risk of citizen suits. Although UARG appreciates EPA’s proposal to make clear that “deviations” 

of operating limits are not necessarily violations, nothing in EPA’s proposal would prevent EPA, 

a state, or a plaintiff in a citizen suit from simply determining in their “discretion” that any 

particular exceedance constitutes a violation. Proposed 63.7575. MACT standards are 

technology-based standards and must recognize that even the best performing technology 

occasionally fails. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 42

Comment: It is very common in industry for certain control devices to be out of operation 

during periods of start-up due to the nature of the equipment. Electrostatic precipitators (ESPs) 

must typically warm-up to be effective. It is also necessary to establish proper O2 levels in the 

flue gas prior to ESP energization to prevent ignition of flammable mixtures in the ESP due to 

sparking. This practice is necessary to ensure that boilers are started up in a safe manner. 

Premature starting of this equipment will lead to short term stability problems that could result in 

unsafe actions and longer term degradation of ESP performance due to fouling, increased 

chances of wire damage or increased corrosion within the chambers. Vendors providing this 

equipment make it part of the standard operating procedures. 

During periods of startup, combustion starts and as fuel is introduced the boiler and ESP warm 

up on a designated curve that could last for between 5 and 8 hours. As the boiler and control 

device heats up, additional fuel is added until the ESP meets its design temperature, the O2 level 

is correct, and normal fuel firing then is resumed. During such periods it is likely that emissions 

will exceed the standards proposed and would never be able to recover to meet the average 

opacity limitations. 

Given the limited carbon monoxide data and total absence of startup and shutdown emissions 

information for other pollutants from the test run data relied on by EPA to set the proposed 

standards and the infeasibility, if not impossibility, of collecting data from such brief operation 

periods for other pollutants, it is appropriate for EPA to set work or management practices for 

these events for boilers. 

Furthermore, a work or management practices approach for these periods would be in keeping 

with the statute’s requirement that standards be “achievable” as well as with the court’s 

requirement that a standard apply at all times. 
A work or management practices approach for these periods also would be consistent with 

EPA’s recently promulgated standards for compression ignition reciprocating internal 

combustion engines (CI-RICE). See National Emission Standards for Hazardous Air Pollutants 

for Reciprocating Internal Combustion Engines, Final Rule, 75 Fed. Reg. 9648 (Mar. 3, 2010). 

Based on comments received from stakeholders, EPA finalized work practice standards for 

startup because the agency determined that it was “not feasible to finalize numerical emission 

standards that would apply during startup because the application of measurement methodology 

to this operation is not practicable due to technological and economic limitations.” Id. at 9656. 

According to EPA, applicable test methods that would be needed to measure during these events 

“do not respond adequately to the relatively short term and highly variable exhaust gas 

characteristics occurring during these periods.” Id. at 9665. Furthermore, EPA determined that 

the cost for testing all the engines affected by the rule to get the necessary data could be more 

than $1 billion. See id. SSM periods for area source boilers encounter similar testing challenges 

and costs. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Alicia Oman

Commenter Affiliation: National Association of Manufacturers

Document Control Number: EPA-HQ-OAR-2006-0790-2234.1

Comment Excerpt Number: 54

Comment: In addition, during Start-up, Shutdown, Malfunction (SSM) periods, boilers and 

process heaters operate under conditions that are likely to generate unavoidable increases in CO 

emissions. These conditions are driven by safety considerations (e.g., ensuring sufficient air flow 

to avoid explosive fuel-rich scenarios), operational concerns (e.g., gradually warming up the 

equipment in order to prevent thermal damage), and warranty requirements (e.g., equipment 

vendors require gradual warm-up as a warranty condition). Thus, setting the proposed 

inappropriately low CO emissions limit will encourage quick start-up and shutdown of 

equipment in order avoid exceedances of limit. EPA should not promulgate a rule that promotes 

such unsafe and improper operation of boilers and process heaters. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Alicia Oman

Commenter Affiliation: National Association of Manufacturers

Document Control Number: EPA-HQ-OAR-2006-0790-2234.1
Comment Excerpt Number: 55

Comment: EPA’s approach to addressing startup, shutdown, and malfunction (SSM) periods in 

the Proposed Boiler MACT is contrary to the statute’s requirement that the standards established 

under section 112(d) be “achievable.” See 42 U.S.C. § 7412(d)(2). Furthermore, EPA’s claims 

that the MACT standards reflect startup and shutdown periods are not supported by the record. 

To address the decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), cert. denied, 

2010 U.S. LEXIS 2265(2010), which vacated the exemption in 40 C.F.R. § 63.6(f)(1) and (h)(1) 

for SSM periods, EPA proposes emissions standards in the MACT for industrial boilers and 

process heaters that apply at all times, including periods of SSM. EPA claims in the preamble 

that startup and shutdown periods were taken into consideration when setting the MACT 

standards. See Proposed Boiler MACT Rule at 32,012-13. According to the preamble, 

continuous emissions monitoring data from the best performing units, which include startup and 

shutdown periods, are used to set the floor levels in the proposed rule. See id. at 32,013. EPA 

further notes that startup and shutdown are part of “routine operations” and are therefore 

“already addressed” in the MACT standards. See id. 

With regard to malfunctions, however, EPA states that these periods should not be viewed as a 

“distinct operating mode,” and thus, emissions from these periods do not need to be factored into 

developing the MACT floor levels. See id. Moreover, EPA states that even if malfunctions were 

to be considered a distinct operating mode, it would be “impracticable to take malfunctions into 

account in setting CAA section 112(d) standards for major source boilers and process heaters” 

given that these episodes are by definition sudden and unexpected events which vary in degree, 

frequency, and duration. Id. 

When setting standards in the early 1990’s under CAA 112(d), EPA used its New Source 

Performance Standards (NSPS) program as a model. The section 112 standards were 

acknowledged by EPA to be “essentially equivalent to [section 111] performance standards” and 

that “unpredicted and reasonably unavoidable failures of air pollution control systems” would 

occur. 58 Fed. Reg. 42,760, 42,777 (Aug. 11, 1993). To address this situation, EPA adopted a 

similar exemption to the one in the NSPS Program for SSM events and imposed a “general duty” 

to minimize emissions. Thus, EPA acknowledged, as early as 1993, that SSM events are not 

appropriate for inclusion in a MACT standard and that an alternative approach should be used to 

address these situations. While the D.C. Circuit has ruled that sources cannot be exempt from 

complying with MACT standards, the court noted that Congress recognized in some instances 

that it may not be feasible to prescribe or enforce an emission standard under section 112, and so 

section 112(h) “work practices” or “operational” standards are available in certain limited 

situations. See Sierra Club v. EPA, 551 F.3d at 1028. 

The D.C. Circuit also has recognized that standards based on what sources achieve must account 

for the limitations inherent in the technology used to reduce emissions. For example, in a case 

reviewing NSPS under section 111 of the CAA, Portland Cement Ass’n v. Ruckelshaus, 486 

F.2d 375, 398 (D.C. Cir. 1973), the court acknowledged that “‘startup’ and ‘upset’ conditions 

due to plant or emission device malfunction, is an inescapable aspect of industrial life and that 

allowance must be made for such factors in the standards that are promulgated.” Id. at 399. 
Furthermore, in National Lime Ass’n v. EPA, 627 F.2d 416 (D.C. Cir. 1980), the court noted that 

“a uniform standard must be capable of being met under most adverse conditions which can 

reasonably be expected to recur.” Id. at 431 n.46. The D.C. Circuit acknowledged this same 

principle almost 20 years later when reviewing emission standards for new sources in the 

medical waste incinerator rule under section 129 in Sierra Club v. EPA, 167 F.3d 658 (D.C. Cir. 

1999). In that case, while the court did not find the record sufficient to support EPA’s approach 

for new sources, the D.C. Circuit did not object to a standard-setting approach which would 

account for the performance of technology under the “worst reasonably foreseeable 

circumstances.” See id. at 665. Furthermore, the D.C. Circuit reiterated the principle in National 

Lime that “where a statute requires that a standard be ‘achievable,’ it must be achievable ‘under 

the most adverse circumstances which can reasonably be expected to recur.’” Id. at 665 (citing 

National Lime Ass’n v. EPA, 627 F.2d 416, 431 n.46 (D.C. Cir. 1980)). 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Alicia Oman

Commenter Affiliation: National Association of Manufacturers

Document Control Number: EPA-HQ-OAR-2006-0790-2234.1

Comment Excerpt Number: 56

Comment: EPA’s MACT floor-setting approach in the Proposed Boiler MACT ignores these 

longstanding principles and mischaracterizes the role startup and shutdown data plays (or rather, 

does not play, as the case is here) in EPA’s floor-setting process. As noted above, EPA claims 

that the agency considered startup and shutdown periods when setting the floors because CEMS 

data, relied on by EPA in “establishing the standards,” included data from those periods. See 

Proposed Boiler MACT Rule at 32,012. This representation is a serious misstatement of the 

Agency’s record. EPA does not rely on the CEMs data when setting the floors for boilers and 

process heaters. To the contrary, as indicated by the ERG memorandum in the docket, EPA uses 

test run data collected through the ICR phase II testing process, which reflect normal (often 

steady state) operating conditions, to set the proposed floors. See Memorandum from A. 

Singelton, ERG, to J. Eddinger, U.S. EPA, MACT Floor Analysis (2010) for the Industrial, 

Commercial, and Institutional Boilers and Process Heaters National Emission Standards for 

Hazardous Air Pollutants – Major Source at 3 (April 2010). Thus, according to EPA’s own 

docket materials, the data used to set the proposed floors fail to account for the dynamic 

conditions and variable emissions occurring during startup and shutdown episodes. Furthermore, 

as the ERG memorandum makes abundantly clear, EPA’s approach does not make use of the 

CEMs data (with the startup and shutdown information) in its variability analysis where it would 

be the most helpful in reflecting real world fluctuations in emissions. Id. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 
Commenter Name: Alicia Oman

Commenter Affiliation: National Association of Manufacturers

Document Control Number: EPA-HQ-OAR-2006-0790-2234.1

Comment Excerpt Number: 57

Comment: Given the absence of startup and shutdown emissions information from the test run 

data relied on by EPA to set the proposed standards and the difficulty of collecting data from 

such brief operation periods, it is appropriate for EPA to set work practices for these events for 

boilers and process heaters. As noted earlier, section 112(h) allows EPA to set work practice 

standards for situations where “it is not feasible in the judgment of the Administrator to prescribe 

or enforce an emission standard . . . .” CAA 112(h)(1); 42 U.S.C. 7412(h)(1). Gathering data 

from startup and shutdown periods would be challenging given the brief nature of these periods 

as well as the need to define the exact time period for what is considered “startup” and/or 

“shutdown.” Moreover, the definition of “not feasible to prescribe or enforce an emission 

standard” is defined in the CAA as any situation where “the application of measurement 

methodology to a particular class of sources is not practicable due to technological and economic 

limitations.” CAA 112(h)(2); 42 U.S.C. 7412(h)(2). Startup and shutdown episodes fit with this 

definition and would justify the agency setting work practices to address emissions during these 

periods. Furthermore, a work practices approach for these periods would be in keeping with the 

statute’s requirement that MACT standards be “achievable” as well as with the requirement that 

a MACT standard apply at all times. 

A work practices approach for these periods also would be consistent with EPA’s recently 

promulgated MACT standards for compression ignition reciprocating internal combustion 

engines (CI-RICE). See National Emission Standards for Hazardous Air Pollutants for 

Reciprocating Internal Combustion Engines, Final Rule, 75 Fed. Reg. 9648 (Mar. 3, 2010). 

Based on comments received from stakeholders, EPA finalized work practice standards for 

startup because the agency determined that it was “not feasible to finalize numerical emission 

standards that would apply during startup because the application of measurement methodology 

to this operation is not practicable due to technological and economic limitations.” Id. at 9656. 

According to EPA, applicable test methods that would be needed to measure during these events 

“do not respond adequately to the relatively short term and highly variable exhaust gas 

characteristics occurring during these periods.” Id. at 9665. Furthermore, EPA determined that 

the cost for testing all the engines affected by the rule to get the necessary data could be more 

than $1 billion. See id. Startup and shutdown periods for boilers present similar levels of testing 

challenges and costs. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Alicia Oman

Commenter Affiliation: National Association of Manufacturers

Document Control Number: EPA-HQ-OAR-2006-0790-2234.1

Comment Excerpt Number: 58
Comment: With respect to malfunctions, EPA argues in the preamble to the Proposed Boiler 

MACT that these periods should not be considered a “distinct operating mode” and uses this to 

justify not factoring these emissions into the proposed MACT standards. Considering that EPA’s 

proposed MACT standards are supposed to apply at all times, the implication is that periods of 

malfunction also are covered by the MACT standards that apply during normal operations. This 

directly conflicts with the statutory requirement that the MACT standard be “achievable.” 

Given that the floor data does not consider malfunctions and that the statute requires that the 

MACT standard be “achievable,” EPA should set work practice requirements to address periods 

of malfunctions as well. As noted above, section 112(h) allows EPA to set work practice 

standards for situations where “it is not feasible in the judgment of the Administrator to prescribe 

or enforce an emission standard . . . .” Similar to startup and shutdown, malfunctions fit with the 

situations described in the definition of “not feasible to prescribe or enforce an emission 

standard” as any situation where “the application of measurement methodology to a particular 

class of sources is not practicable due to technological and economic limitations.” Emission 

testing for malfunctions would be near impossible to conduct given the sporadic and 

unpredictable nature of the events. As noted earlier, EPA acknowledges in the preamble to the 

Proposed Boiler Rule that it is “impracticable” to take periods of malfunctions into account when 

setting emissions standards given the “myriad different types of malfunctions that can occur 

across all sources in the category” and that “malfunctions can vary in frequency, degree, and 

duration, further complicating” the standard setting process. Proposed Boiler MACT Rule at 

32,013. Section 112(h) work practice standards, therefore, are well-suited to address malfunction 

periods and the complexities and challenges surrounding collecting data and establishing 

numerical standards for those events. 

Response: Section 63.11226 has been added to the final on how a source may assert an 

affirmative defense if an emission limit is exceeded during a malfunction.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 64

Comment: EPA’s underlying database contains no data for start-up, shutdown or malfunction 

events — yet these periods of operation are not excluded from compliance obligations. This is 

yet another example of how the Agency has failed to show that the proposed emission limits are 

achievable. Another critical issue with respect to the achievability of the proposed emission 

limits is the absence of an exemption for start-up, shutdown and malfunction events. Clearly, the 

data upon which EPA characterized the best performing similar source and the best performing 

12 percent of existing sources contain no start-up, shutdown or malfunction events. EPA has 

absolutely no technical basis to claim the proposed emission limits are achievable -- as is 

required by law.12 If EPA insists on not exempting start-up, shutdown and malfunction events, 

the Agency must deal with emissions that occur during such events. 
The simplest approach is to suggest that EPA obtain data representative of start-up, shutdown 

and malfunction events, include such data in a proper analysis and choose a numerical emission 

limits that can be achieved in practice. However, the data collection approach may not be 

realistic in every case. For example, manual test methods, such as EPA Method 5 for PM, are 

designed to be used under steady state conditions. Trying to conduct a Method 5 test during a 

boiler start-up may neither be practical nor accurate. Likewise, PM CEMS may not be the 

answer because a PM CEMS must be correlated with manual test data to be accurate. Thus, in 

cases where data collection during start-up, shutdown and malfunction events is not feasible, 

EPA should set work practice standards. However, EPA cannot simply ignore emission 

variability during start-up, shutdown and malfunction events and pretend that the emission limits 

are achievable without addressing this fundamental issue. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Also, section 63.11226 has been added to the final on how a source may assert an affirmative 

defense if an emission limit is exceeded during a malfunction.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 33

Comment: If CO CEMS are required in the final rule, ACC supports the proposed CO CEMS 

data averaging approach in 40 CFR 63.11223(e)(6) wherein data must not be used during periods 

of monitoring malfunction, associated repairs, out-of-control periods, required QA or control 

activities, or when the boiler is operating at less than 50% of rated capacity. As indicated above, 

operation at less than 50% load results in inherently increased CO emissions. When fuel input is 

low, as during periods of startup and shutdown, oxygen levels are higher, making the corrected 

pollutant concentrations much higher. EPA has recognized boiler, or burner, turndown ratio as a 

factor affecting performance in several contexts. See, EPA, Final Technical Support Document 

for HWC MACT Standards, Vol. IV, p. 3.6 (July 1999); EPA Region 6 Center for Combustion 

Science and Engineering, Hazardous Waste Combustion Unit Permitting Manual, Component 1 

How to Review a Test Burn Plan, p. D-5.5 (Tetra Tech Jan. 1998). This approach of excluding 

CO CEMS data below 50% of rated capacity should also be included in the major source 

Boiler/Process Heater MACT rule, Subpart DDDDD, and it is curious why this is not the case. In 

fact, the 2004 Boiler rule recognized that CO emissions could be higher at low loads by not 

requiring CO CEMS data obtained at less than 50 percent of maximum load be included in the 

30-day CO average. 

Response: The requirement for CO CEMS has been removed from the final rule.

Commenter Name: Jim Griffin
Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 43

Comment: Even Top Performers Malfunction. With regard to malfunctions, EPA states in the 

preamble to this proposed rule that these periods should not be viewed as a “distinct operating 

mode,” and thus, emissions from these periods do not need to be factored into developing the 

MACT floor levels. See id. Moreover, EPA states that even if malfunctions were to be 

considered a distinct operating mode, it would be 

“impracticable to take malfunctions into account in setting CAA section 112(d) standards for 

major source boilers and process heaters” given that these episodes are by definition sudden and 

unexpected events which vary in degree, frequency, and duration. Id. 

Considering that EPA’s proposed MACT standards are supposed to apply at all times, the 

implication is that periods of malfunction also are covered by the standards that apply during 

normal operations. This directly conflicts with the statutory requirement that the standard be 

“achievable.” EPA has failed to recognize that even best performers will experience 

malfunctions. It is possible for pollution control equipment to fail in various ways. Electrostatic 

fields trip, power failures do occur, fabric filters fail, scrubber pumps fail even at best performers 

and despite the best efforts of companies to prevent and minimize such events. Industry can and 

does work to minimize such periods, but they do occur. Further, manufacturers of such 

equipment routinely make emission guarantees for normal operations and although they 

sometimes oversize equipment to account for some of the variability described above, it is very 

doubtful that vendors would provide sufficient numerical guarantees for equipment under such 

situations. 

Given that the floor data does not consider malfunctions and that the statute requires that the 

standards be “achievable,” EPA should establish separate work or management practice 

requirements using its authority under either 112(h) or 112(d)(5) to address periods of 

malfunctions. 

Emission testing for malfunctions would be near impossible to conduct given the sporadic and 

unpredictable nature of the events, in addition to the fact that many combustion related 

malfunctions impose safety risks to onsite personnel and equipment, and potentially off-site. As 

noted earlier, EPA acknowledges in the preamble that it is “impracticable” to take periods of 

malfunctions into account when setting emissions standards given the “myriad different types of 

malfunctions that can occur across all sources in the category” and that “malfunctions can vary 

in frequency, degree, and duration, further complicating” the standard setting process.[ 75 Fed. 

Reg. 31902] Section 112(h) work practices or 112(d)(5) management practices are well-suited to 

address malfunction periods given the complexities and challenges surrounding collecting data 

during these potentially dangerous episodes and establishing numerical standards for those 

events. 

For all of the above reasons, ACC believes that EPA must revisit the SSM issue. ACC suggests 

that EPA propose work/management practice standards that would allow sources a certain time 
period for start-up, shutdown and malfunction events and as long as certain procedures are 

followed, then compliance would be met. Those work/management practice standards should 

require the development and implementation of an emissions minimization plan that will result 

in (a) minimizing emissions during such events that would exceed otherwise applicable emission 

limitations, and (b) for malfunctions that will cause the unit to exceed otherwise applicable 

emission limitations, promptly identifying and implementing measures to remedy the 

malfunction. While there may be some instances where standard work practices can be identified 

for a type of source, ACC cautions that overly prescriptive and non-facility-specific requirements 

can actually be counterproductive, restricting the operators’ flexibility in a way that hampers 

their ability to troubleshoot or respond appropriately to an event, or that compromises safety. The 

plan should be an evolving document, and should be maintained at the facility and, upon request, 

be available for review by EPA or the State regulatory authority. 

Alternatively, EPA could establish a threshold of exceedances, either a number or percentage of 

operating times that could occur during a quarterly or six month period before a violation occurs. 

This methodology is consistent with other MACT standards such as 40 CFR 63 Subpart S and 

MM. 

Response: Section 63.11226 has been added to the final on how a source may assert an 

affirmative defense if an emission limit is exceeded during a malfunction.

Other - SSM

Commenter Name: Norman Bujold

Commenter Affiliation: Cleaver Brooks

Document Control Number: EPA-HQ-OAR-2006-0790-0392.1

Comment Excerpt Number: 2

Comment: START UP, SHUT DOWN AND MALFUNCTION (SSM) ALL AREA 

CLASSIFICATIONS 

Depending on the boiler size, FGR usage, steam pressure and temperature, the start up conditions 

will change. The following is a non exhaustive list of parameters that will affect the start up 

period: 

During cold start, the furnace temperature is low which will result in higher CO emission. 

High pressure boilers take longer to come up to temperature. 

Super heated steam applications take longer to reach their normal operating conditions. 

Low NOx high FGR applications have very low air velocities at the burner during cold start. 

This is because the FGR cannot be introduced to the burner before it reaches a certain 

temperature therefore reducing the volumetric flow of the air at the burner by a significant 

amount, again resulting in higher CO emissions. 

Combustion air temperature in temperate climate and for applications using steam air heaters. 
Including startup periods in the average emission calculations could lead to out of compliance 

results. 

For example, if we look at a typical IWT low NOx gas burner application with a 24 hour 

average. The guaranteed emissions are <30ppmv NOx and < 25ppv CO. With the burner 

mounted on a super heated steam IWT boiler that take five hours to get on line and 4 hours to 

reach its minimum burner operating conditions. The calculated average CO emissions on a 24 hr 

period including the cold start would be: 

200ppm x 2hr/24hr + 100ppm x 2hr/24hr + 15 ppm X 18hr/24hr = 36.25 ppm 

We can see that the 24 hours average does not meet the 25ppm limit even if its normal operating 

CO emission is 15ppm. 

The same reasoning will apply to PM emission. 

We think that the SSM must be considered in the emission calculations. Their impact will be 

different depending on the application thus a general rule would be hard to come up with. We 

have included below some typical boiler and burner warm up numbers (actual numbers depend 

on application): 

Typical boiler warmup time 

1-2 hours for FT boilers. 

3-4 hours IWT 150psig 

4-5 hours super heated IWT packaged boiler 

5 hours and more, super heated field erected boilers 

Burner typical cold start CO emissions 

Gas: 100 ppmv to 300 ppmv 

Oil: 50 ppmv to 250 ppmv . 

Response: In the final rule, EPA has taken into account startup and shutdown periods and has 

not established different standards for those periods. The standards that we are promulgating are 

based on short term stack tests for pollutants that generally are not expected to vary significantly 

at startup and shutdown. For CO, which in some cases varies at startup and shutdown, the 

operating limits will ensure that combustion conditions are optimized and CO emissions are 

minimized. Boilers, especially coal-fired boilers, do not normally startup and shutdown more the 

once per day. Thus, we are not establishing a separate emission standard for these periods 

because startup and shutdown are part of their routine operations and, therefore, are already 

addressed by the standards. Periods of startup, normal operations, and shutdown are all 

predictable and routine aspects of a source’s operation. We have evaluated whether it is 

appropriate to have the same standards apply during startup and shutdown as applied to normal 

operations, and as the rule is structured, well operated and controlled units should be able to meet 

the standards at all times.

In the final rule, the requirement for CO CEMS has been removed, the actual emission 

measurements for compliance are required to be performed at maximum load, and continuous 
compliance for all pollutants is demonstrated through the various parameter monitoring that is 

required by the rules. Also, section 63.11226 has been added to the final on how a source may 

assert an affirmative defense if an emission limit is exceeded during a malfunction.

Commenter Name: Los Angeles Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0397

Comment Excerpt Number: 27

Comment: I also want to underscore the importance of eliminating the malfunction exemptions. 

On the other rules, the exemption allows chemical plants, refineries and other major facilities to 

violate their emissions standards over and over and over again without any accountability. 

And as you know, I have personally fought a very long battle with the Agency on the 

startup/shutdown of malfunction provisions. These provisions at large sources of combustion like 

refineries, chemical manufacturing facilities, power plants, cement kilns can double or triple 

emissions. 

And it’s very difficult with these startup/shutdown and malfunction get out of jail free cards for 

local citizen groups to have any kind of enforcement hook to reduce those emissions. It makes a 

mockery of the toxic release inventory. It makes a mockery of the permits to allow these start-up 

and shutdown malfunction exemptions. 

And so I actually copied pretty good case law from the D.C. Circuit on this and we want to make 

sure that these startup/shutdown malfunction provisions are closed. 

Response: The standards contained in the final rule apply at all times. Please see response to 

DCN EPA-HQ-OAR-2006-0790-0392.1, Excerpt Number 2. 

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 94

Comment: Especially important to us is EPA’s decision to eliminate the outrageous malfunction 

exemption. In other words, the exemptions of our chemical plants, refineries, and other major 

polluters to violate the emission standards and blanket our communities in toxic pollution over 

and over again without any accountability. Closing that loophole means that these facilities will 

have to run their boilers and process heaters responsibly. We know that powerful industry 

lobbyists are lining up to oppose this rule. They want loopholes and exemptions. They want the 

rules weakened and delayed, but these rules will prevent 4,800 unnecessary deaths every year 

and will save billions of dollars in costs. Lisa Jackson, do not cave in to industrial pressure. 
Make these rules stronger, not weaker, and we issue them without delay -- please issue them 

without delay. 

Response: The standards contained in the final rule apply at all times. Please see response to 

DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 102

Comment: Especially important to us is EPA’s decision to eliminate the malfunction exemption. 

We believe that closing the loophole means that facilities will have to run their boilers and 

process heaters responsibly. 

Response: The standards contained in the final rule apply at all times. Please see response to 

DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Michael J. Hagenbarth

Commenter Affiliation: RockTenn

Document Control Number: EPA-HQ-OAR-2006-0790-1473.1

Comment Excerpt Number: 4

Comment: The proposed Area Source Rule does not include a separate standard for startup and 

shutdown. This is a fundamental problem that, if not corrected, will cause the final standards to 

be not achievable by even well designed and operated boilers. As a result, EPA must include a 

separate standard for startup and shutdown in the final rule. 

EPA explains in the preamble that, "Based upon continuous emission monitoring data, obtained 

as part of the information collection effort for the major source boiler and process heater 

rulemaking, which included periods of startup and shutdown, over long averaging periods, 

startups and shutdowns will not affect the achievability of the standards." 75 Fed. Reg. at 31901. 

There are three fundamental problems with this justification for not including startup and 

shutdown standards in the rule. 

First, the continuous monitoring data that EPA presents in the major source industrial boiler 

MACT proposal is for units that will not be subject to the Area Source Rule and that are not the 

unit(s) from which EPA obtained the data used in setting the proposed area source standards. 

Thus, these emissions data cannot lawfully be used in determining the area source standards 

because these data are derived from sources that do not belong to the area source category. The 

conclusion that a separate standard for startup and shutdown is not needed can only be based on 

data from the source(s) that are actually used by EPA to set the area source standards or on a 
showing that the data from some other boilers are representative of the performance of the area 

source boilers used as the basis for the proposed area source standards. 

Second, EPA’s emissions database provides continuous emissions monitoring system ("CEMS") 

data from several of the better performing sources. Contrary to EPA’s assertion in the preamble, 

these data show that daily average emissions should be expected to vary considerably on a dayto-day basis and that the variability spans the proposed levels of the standards. While it is 

difficult to discern the reasons for this variability based on the information provided in the 

database, there is little doubt that startups and shutdowns significantly contribute to the variable 

emissions performance of these units. Thus, the data indicate that EPA needs to include express 

accommodation for startups and shutdowns. 

Third, basic scientific and engineering principles support the need for a separate standard for 

startup and shutdown. Particularly for CO emissions, combustion conditions will not be optimum 

during startup periods due to the generally low firing rate and the fact that the firing rate will be 

ramped up over the startup period. Thus, a significant period of non-optimum firing conditions 

will result in CO emissions performance — even on a daily average basis — that will be 

markedly different than performance during normal operations. EPA’s failure to acknowledge 

these basic technical and engineering principles renders the proposed standards arbitrary. 

For these reasons, we believe that a separate standard for startup and shutdown is needed and is 

amply justified. We suggest that a work practice standard is most appropriate due to the lack of 

relevant data and the fact that an emission testing during startup is not technically and 

economically practicable. If EPA decides that a numeric standard is needed, the Agency should 

rely on the available long term data from the better performing area source boilers to establish a 

standard with a reasonably long averaging time (such as a 30-day rolling average), rather than 

the proposed 24-hour averaging time. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Kerry Flick

Commenter Affiliation: Metso Power

Document Control Number: EPA-HQ-OAR-2006-0790-1490.1

Comment Excerpt Number: 7

Comment: Startup periods are not predictable and should not be included in the emissions 

averaging period. We recommend that startup periods be treated outside the averaging period 

similar to "periods of malfunction" (CAA section 112(d)). 

The 24-hour averaging period, proposed in the new ruling, does not provide owners/operators an 

adequate period of time to deal with transient operating conditions. We recommend that the 

averaging period for measuring emissions be based on a 30-day rolling average. The definition 

of the averaging period at Area Source facilities needs to be revised, which will also be 

consistent with that proposed for Major Sources. 
The combustion of biomass has its challenges. Biomass has a low calorific value and high 

moisture content when compared to fossil fuels. Biomass characteristics can vary significantly 

based on a number of factors, including species, geographic origin, and time of year. Thus, there 

is variability in biomass that is not inherent to the combustion of fossil fuels. This variability 

along with the extreme dynamics associated with startups of a biomass fired boiler make it 

unreasonable to include them in the emissions compliance averaging period. The proposed ruling 

states that "Periods of startup, normal operations, and shutdown are all predictable and routine 

aspects of a source’s operation." We have not found this to be the case in practice when it comes 

to biomass combustion. The variability in biomass makes it difficult to standardize an optimized 

mode of operation on a consistent basis, particularly during startup conditions. Thus, emission 

control during startup is anything but predictable and consistent. The source data supports this. 

The data presented for CO emissions fluctuates significantly during the performance testing 

period. Metso believes that no technology is commercially available, including oxidation 

catalysts, to control emissions of CO during startup or shutdown to the degree that would be 

required to satisfy the proposed rulings. These variations are further complicated by the fact that 

many units are not based-loaded and must deal with fluctuations in toad that will create transient 

conditions, even during normal operation. This can result in frequent operating instabilities 

lasting several hours, compounding the unpredictable nature of biomass combustion and the 

resulting emissions. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 41

Comment: There are two primary issues with regard to SSM events and the Proposed Rule. 

First, EPA is proposing that the emissions standards it has established in this rule apply during 

both normal operations and periods of SSM. Second, EPA has not taken periods of SSM into 

account when setting the proposed standards. As stated in CIBO’s comments on the Proposed 

Boiler MACT Rule, requiring emission controls during SSM is technically unfeasible and EPA’s 

failure to include periods of SSM when establishing the emission standards is unreasonable. For 

a comprehensive discussion of these issues, please refer to CIBO’s comments on the Proposed 

Boiler MACT Rule. [See DCN: 2006-0790-1783.2 for related comments.] 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1.

Commenter Name: Arthur N. Marin

Commenter Affiliation: Northeast States for Coordinated Air Use Management, NESCAUM

Document Control Number: EPA-HQ-OAR-2006-0790-2137.1

Comment Excerpt Number: 23
Comment: EPA proposes to regulate emissions of HAPs from boilers during all phases of 

operations, including startup, shutdown, and malfunction (SSM) periods. We are unsure how 

EPA has accounted for these emissions within the proposed emission limits, as the current data 

do not include such emission measurements. Furthermore, there is significant variation in the 

amount and duration of SSM emissions for various fuels and sizes of boilers. For example, we 

anticipate that variation in SSM emissions would be greater when using boilers firing solid fuels, 

such as biomass, than with boilers firing liquid fuels such as heating oil. NESCAUM 

recommends that EPA use facilities regulated under this effort to collect SSM emissions data and 

then revisit this issue no later than five years from promulgation to develop appropriate limits for 

SSM emissions. Facilities that measure emissions with CEMS could provide the basis for 

developing emission limits for SSM periods. In addition, EPA should examine how to evaluate 

SSM emissions at smaller boilers that do not have CEMS, and how those facilities could evaluate 

those emissions during compliance testing. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 31

Comment: Start-up and shutdown are considered part of normal operations under this proposal. 

The preamble claims that the CO CEM data gathered to support this and the major source 

rulemaking indicate that startups and shutdowns do not require separate treatment because the 

emission limits are daily. We believe this claim is valid for most shutdowns but is not true for 

most startups and particularly not for initial startups and startups after any refractory work. The 

EPA data cited as indicating startups are not a problem is unrealistically limited, does not include 

startup periods, and was selectively collected (see the discussion of this issue in Section VI.A of 

our comments on the proposed major source Boiler and Process Heater MACT rule). [See DCN: 

EPA-HQ-OAR-2002-0058-2960.1 for comments] 

Liquid-fired boilers will not be able to meet the proposed limits during most startups. In order to 

provide for dry-out of refractory, to avoid thermal expansion failures, and to avoid other damage, 

boiler startups must be done slowly as specified by the manufacturer. These startups often take 

most of a day, as the boiler temperature must be raised at a slow and controlled rate. Even where 

startups take less than a day, even an hour of high CO could cause a violation of the daily 

average limit. Since it would be almost impossible not to have high CO for at least a few hours 

during any startup, imposing the proposed daily average CO emission limit of 1 or 2 ppm on 

startup would seem to require most liquid-fired boilers to shutdown to avoid knowing violations 

of the standard. The Agency’s failure to adjust the proposed standard for the variability 

associated with startup or to establish a separate subcategory for startups is arbitrary and 
capricious, violates the requirements of §112(d)(2), that any MACT standard be achievable and 

violates the basic legal principal of rationality. 

Since it is not feasible for liquid-fired boilers to meet the proposed CO limits during startups and 

no add-on controls are economically or technically feasible for CO[footnote: The only available 

add-on control for CO is oxidation catalyst. This catalyst is ineffective at low temperature and 

thus is technically infeasible for use during startups, as well as being economically infeasible for 

use on oil fired boilers.], work practice requirements should be specified for these startups as 

provided for in §112(h). 

As discussed in the proposal preamble, CAA section 112(h) allows the Administrator to 

promulgate a design, equipment, work practice, or operational standard, or combination thereof, 

in certain cases where, in the judgment of the Administrator, it is not feasible to prescribe or 

enforce an emission standard under CAA section 112(d). These cases include the situation in 

which the application of measurement methodology to a particular class of sources is not 

practicable due to technical and economic limitations. We believe startups meet these 

requirements and thus a work practice requirement may be specified. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Leon Lataille

Commenter Affiliation: Massachusetts Water Resources Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1896.1

Comment Excerpt Number: 2

Comment: Startup of the boilers requires use of oil due to the design of the boilers. The startup 

sequence typically requires approximately 6 hours for a cold start, to control thermal expansion 

of the boiler. During this startup sequence, the carbon monoxide emissions are in excess of the 

proposed standard of 2 ppm to a degree that would result in the daily average value exceeding 

the standard. The carbon monoxide emissions are monitored by CEMS and concentrations 

during normal operation are well below the proposed standard of 2 ppm for operation on digester 

gas or oil, or mixed fuel. In the event that boiler startups include operation at greater than 50% 

load, the daily average with startups included would not meet the standard. The regulation does 

not provide for this situation, since there is no exemption for Startup, Shutdown and 

Malfunctions (SSM), and Table 6 removes the requirement for an SSM plan and the requirement 

to maintain and operate the facility in accordance with that plan. The boilers employ low NOx

burners, flue gas recirculation and the operation has been evaluated and optimized by 

combustion experts to ensure efficient combustion. Without the SSM exemption and SSM plan 

approach, compliance with the rule is problematic. The rule should address a source specific 

exemption for situations in which emissions have been minimized to the extent possible. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 
Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 3

Comment: Duke Energy urges EPA to use its authority under the CAA Sections 112 (d) (h) and 

111 to provide a work practice operational standard to address HAP emissions during startup and 

shutdown in lieu of a numerical limit. 

HAP emissions during startup and shutdown (“SU/SD”) should not be treated the same as HAP 

emissions during normal operations. EPA has not established a basis to conclude that SU/SD 

emissions of HAP are the same as during normal operations. Setting the same standard for 

SU/SD and normal operations will result in an unattainable standard for the owner/operator 

despite the application of MACT controls. In setting MACT standards, EPA must properly 

characterize the entire range of operation of the units used to determine the MACT Floor. EPA 

has to do this so that the units that set the MACT floor limits can actually comply with those 

limits. In its industrial boiler information collection request (“ICR”), EPA did not require any 

testing during start-up and shutdown events. However it is well documented that emissions 

profiles during these periods are significantly different from those during normal operation. 

SU/SD periods have highly variable operating conditions and consequently, reference test 

methods cannot be utilized because the sources do not operate in a steady state as required by the 

methods. As such, EPA biased the ICR testing by only specifying that tests be conducted at full 

load operation, and missed the extended start-up periods that electrostatic precipitators (“ESP”), 

selective catalytic reduction (“SCR”), and some flue gas desulfurization (“FGD”) control 

systems require to achieve optimal performance. Without emissions data during these periods, 

EPA has no data and no factual basis for concluding that the best performing units can achieve 

the proposed MACT limits during start-up and shutdown events. 

There are inherent problems in setting SU/SDS standards the same as the standards for normal 

operation, particularly for any standard that is based on an averaging time that is shorter than 30 

days or based on a few isolated short-term performance tests. Control devices and mechanisms 

do not perform at the same level of efficiency during these transitional periods when suitable and 

stable temperatures or chemical conditions have not been achieved. Certain plant components 

must be started in a specific sequence in order to ensure that steady state operations can be 

achieved, and not all pieces of control equipment will be operating at peak efficiency during 

start-up and shutdown. For example, industrial boilers equipped with SCR, must achieve a 

minimum flue gas temperature of 535-600 F (depends upon SO3 concentration) before reagent 

can be injected and react with the SCR catalyst. Flue gas temperatures must reach 270 F for coldside ESPs and 600F for hot-side ESPs to effectively control particulate matter (“PM”) and HAP 

associated with PM. A typical hot start-up takes 6-8 hours and a cold start-up may take 8- 24 

hours. Industrial boilers equipped with FGDs that use "mag-enhanced lime" can require 24- 36 

hours to build proper chemistry conditions for effective control as designed. 

Setting standards for SU/SD the same as for normal operation for wood-fired biomass boilers is 

also problematic. At a recent pollution control user’s group conference held in Charlotte NC, 
Duke Energy and others learned that boiler and pollution control vendors are also concerned with 

the SU/SD features of the proposed industrial boiler MACT standards. Vendors are unwilling to 

guarantee emission rates for PM and carbon monoxide (“CO”) based on the proposed ICI boiler 

MACT standards, and are particularly concerned with the numerical limits for SU/SD. As a 

consequence, several, untreated wood biomass projects have been postponed or cancelled due to 

the regulatory and compliance uncertainties of the proposed MACT standards, including the 

SU/SD provisions. There is no justification or technical basis for setting a numerical SU/SD limit 

with no data to support the limit. Setting numerical SU/SD limits without data based on an 

averaging period less than 30 days or based on a single or few isolated performance tests will 

result in an unattainable standard. 

EPA should replace the numerical SU/SD limits with a work practice/operational standard that 

require owners/operators to maintain and operate the industrial boiler in a manner consistent with 

good engineering and air pollution control practices as EPA did for the stationary RICE engine 

MACT rule. Owners/operators could be required to maintain a SU/SD Plan on site that identifies 

good engineering and pollution control SU/SD practices and procedures that recognize specific 

boiler and pollution control equipment designs. This approach is justified under the CAA Section 

112 (d) and (h), and is the only practical way to address HAP emissions during SU/SD given 

EPA’s lack of any emissions data during these periods. EPA has not established a technical basis 

to conclude that SU/SD emissions of HAP are the same as during normal operations. The 

assignment of any SU/SD numerical limit, even based on a 30 day average, is arbitrary and 

capricious, and infeasible given the lack of test data. The extensive testing that would be required 

to establish SU/SD numerical limits is not feasible and impractical from a technical or economic 

perspective. Setting any numerical SU/SD limit would need to be delayed until the necessary 

testing is completed. Testing would have to be source-specific and based on several tests over an 

extended period of time to come close to being representative of variations in boiler SU/SD 

conditions, and specific boiler and pollution control equipment designs. One would expect 

results of CO, PM, and HAP test results to vary greatly from one test to the next during transition 

SU/SD periods. FGDs, ESPs, and SCRs do not function or function poorly during SU/SD 

transitions. Since pollution control equipment is not designed to control during this transition, 

SU/SD testing would need to be done on essentially an uncontrolled boiler. Mandatory use of 

control equipment prematurely for the tests could damage or shorten the life of the pollution 

control equipment (or catalyst) and create unintended operational issues. 

Emissions from industrial boilers are different during normal operation and transition periods of 

SU/SD and it is not feasible to establish numerical emission standards. This situation is the 

circumstance in which Congress envisioned a work practice standard for periods of startup, 

shutdown and malfunction in 112 (h) of the CAA, and they reserved the application of numerical 

limits for normal operations. Setting MACT standards for normal operation based on suitable 

data and establishing a work practice/operation standard(s) for SU/SD that recognizes specific 

boiler and pollution control system designs will result in a MACT standard that applies at all 

time and is consistent with the recent Court Decision (Sierra Club v. EPA, 551 F. 3d 1019. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 
Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 7

Comment: Vendors question whether the CO standards are achievable during SU/SD after CO 

and PM MACT controls are installed. Boiler vendors are unwilling to guarantee emission rates 

based on the proposed ICI boiler MACT standards for PM and CO for new, reconstructed, and 

modified industrial boilers designed for wood biomass, particularly where the SU/SD standard is 

based on a daily averaging time or where performance testing includes SU/SD. 

Owners/operators of ICI boiler sources must have alternatives that provide a suitable chance for 

compliance during transitional SU/SD periods when their units are equipped with MACT 

controls. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 19

Comment: Duke Energy is very concerned about the potential for enforcement of operating 

parameter and opacity limits during periods of startup, shutdown, and in the event of equipment 

malfunction. When EPA finalized its rule in 2004 with enforceable operating parameters, it did 

so with a rule that also made clear that those limits did not apply during periods of “startup, 

shutdown, and malfunction.” 40 C.F.R. 3.7505(a), 69 Fed. Reg. at 55,254. EPA’s current 

proposal contains no such exception, but instead would allow enforcement of deviations from 

operating parameters during periods of startup and shutdown, when controls would not be 

expected to be operating at the same levels as during performance tests, and due solely to 

equipment malfunctions. In the preamble, EPA discusses its approach to these events. 75 Fed. 

Reg. 32013. Regarding startup and shutdown, EPA asserts that it has taken these periods into 

account by using CEMS data from best performing units that include periods of startup and 

shutdown, and by proposing use of “daily or monthly averages.” Regarding malfunctions, EPA 

asserts that it would use a variety of information to determine an appropriate response to 

exceedances caused by equipment malfunction. 

EPA’s preamble assertions regarding startup and shutdown are inapplicable to control device 

operating parameter limits, which are based on 12-hour averages (not daily or monthly averages) 

established during performance test (not based on CEMS data that include startup and 

shutdown). Even a daily block average, as proposed for opacity, does not provide sufficient 

protection if the unit does not startup or shutdown at exactly midnight, since there might not be 

sufficient data under normal operating conditions to compensate for the startup or shutdown 
period. In short, EPA has made absolutely no allowance in its rules for periods of startup and 

shutdown yet it has specific evidence that these periods are distinctively different. To the 

contrary, EPA has proposed to require sources to establish control device operating parameters 

levels that are dependent upon load during periods of “maximum normal operating load,” and 

then maintain those levels during periods other than maximum normal operating load, including 

startup and shutdown. EPA’s proposal is patently unreasonable. EPA must address these periods 

in some other manner, for example by establishing simple work practice standards in lieu of 

operating parameters. 

EPA’s promise to address periods of equipment malfunction by considering other information 

before enforcing exceedances of operating limits provide little comfort, especially given the risk 

of citizen suits. Although Duke Energy appreciates EPA’s proposal to make clear that 

“deviations” of operating limits are not necessarily violations, nothing in EPA’s proposal would 

prevent EPA, a state, or a plaintiff in a citizen suit from simply determining in their “discretion” 

that any particular exceedance constitutes a violation. Proposed 63.7575. MACT standards are 

technology-based standards and must recognize that even the best performing technology 

occasionally fails. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: W. Randall Rawson

Commenter Affiliation: American Boiler Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1897.1

Comment Excerpt Number: 3

Comment: In establishing achievable MACT emission standards for area sources, EPA should 

address the anticipated startup, shutdown and malfunction conditions that may be experienced 

across the wide range of boiler designs and applications. To the extent that emission standards 

must apply during periods of startup, shutdown and malfunction, they must be set in a manner 

which adequately accounts for anticipated emissions during those conditions. ABMA is 

concerned that the data on which EPA has relied does not adequately represent considerations 

that may affect such emissions, such as boiler size, usage of flue gas recirculation (“FGR”), 

steam pressure and temperature. These issues are particularly relevant to startup conditions, 

which are reasonably anticipated and can be evaluated in the standard-setting process. For 

example, the following factors should be considered in relation to CO emissions during startup: 

During cold start, furnace temperature is low and higher CO emissions will result; 

High pressure boilers take longer to come up to temperature; 

Super heated steam applications take longer to reach their normal operating conditions; 
Low NOx, high FGR applications have very low air velocities at the burner during cold start, 

because FGR cannot be introduced to the burner before it reaches a certain temperature, thereby 

reducing volumetric flow and resulting in higher CO emissions; 

A typical cold start CO emission level that may range up to 400 ppmvd or higher on oil, and the 

following wide range of boiler warm-up periods based on boiler type may result in significantly 

higher average CO emissions than experienced at steady-state operation: 

Firetube boilers: 1-4 hours 

Industrial watertube boilers (150 psig): 3-6 hours 

Super heated industrial watertube package boiler: 4-8 hours 

Super heated field erected boilers – 8 hours or more 

EPA’s preamble to the Proposed Area Source Rule does acknowledge an attempt to incorporate 

startup and shutdown emissions through its consideration of daily or monthly average CEMS 

data from the best performing units. However, EPA has not demonstrated that its data set 

adequately addresses the variability in startup length and associated emissions experienced in 

boilers of various design and load requirements. Therefore, ABMA believes that EPA should: (1) 

allow a period of time for startup, based on boiler type, during which emissions limits would not 

apply; (2) establish an alternative emission limit for startup periods based on boiler types within 

a subcategory and their load; or (3) review the data set and the anticipated startup conditions of 

various boiler types to ensure that the emission limits set for each subcategory are representative 

of multiple boiler designs and emission variability within the subcategory. The alternatives for 

defining reasonable emission standards for startup conditions should extend to startups 

occasioned by the range of circumstances, such as cold start after a period of scheduled nonoperation, as well as startup occurring after a malfunction during which cold-start parameters 

often apply. Additionally, EPA should extend similar consideration to emissions variability 

during shutdown periods. During these periods, considerable volumetric post- and pre-purge air 

change requirements serve to cool boilers down in an attempt to relieve the combustion chamber 

of unburned fuel and of flue gases prior to re-ignition sequence. 

ABMA also supports a limited allowance for malfunction periods. The term “malfunction” 

should be more precisely defined to include the variabilities of malfunction. Malfunction can 

range from the need for immediate and complete shutdown to malfunctions like an interruption 

in fuel supply or an inoperative CEMs that will require only a short downtime. A plant should 

not be required to completely shutdown due to a malfunction of the boiler, burner or boilerrelated equipment. Once defined, a malfunction should be regulated by alternative limits applied 

during the time it takes to complete corrective action and get the boiler back to normal 

operational mode. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Commenter Name: Daniel Moss

Commenter Affiliation: Society of Chemical Manufacturers and Affiliates
Document Control Number: EPA-HQ-OAR-2006-0790-2018.1

Comment Excerpt Number: 23

Comment: EPA has not appropriately addressed startup, shutdown and malfunction scenarios. 

In the preamble, EPA states: 

In establishing the standards in this rule, EPA has taken into account startup and shutdown 

periods and, for the reasons explained below, has not established different standards for those 

periods. The standards that we are proposing are daily or monthly averages. Based upon 

continuous emission monitoring data, obtained as part of the information collection effort for the 

major source boiler and process heater rulemaking, which included periods of startup and 

shutdown, over long averaging periods, startups and shutdowns will not affect the achievability 

of the standard. [Footnote: 75 Fed. Reg at 31901.] 

To be blunt, SOCMA believes this statement is inaccurate. We understand that all or virtually all 

of the emissions data on which EPA is relying is 1-hour stack test data, gathered when the boilers 

being tested were operating in steady-state mode at peak efficiency. Very few boilers, 

particularly oil-fired boilers, currently operate with continuous emissions monitors, and so 

whatever handful for which EPA has such data are almost certainly not representative of the 

larger universe of such boilers. Startup in particular can take several hours, particularly when the 

unit is cold, and even a 24-hour averaging time will not be sufficient to demonstrate compliance 

in such cases. SOCMA therefore believes that EPA should gather additional emissions data that 

includes representative emissions from startup and shutdown circumstances. 

As for malfunctions, SOCMA endorses the suggestions of the American Chemistry Council 

(ACC) and others that EPA establish work practice requirements for such conditions. These 

could include requiring (i) a root cause investigation regarding the cause of the malfunction or 

(ii) malfunction plans. Either could be covered by the recordkeeping requirements of the rule and 

thus be available to EPA (and indirectly to the public). 

Response:. Please see response to DCN EPA-HQ-OAR-2006-0790-1747.1, Excerpt Number 1. 

Recordkeeping and Reporting Requirements

Data Reporting Requirements

Commenter Name: R.H. Pankratz

Commenter Affiliation: Babcock and Wilcox Pantex, DOE/NNSA

Document Control Number: EPA-HQ-OAR-2006-0790-0466

Comment Excerpt Number: 2
Comment: Proposed §63.11237 Gas-fired boiler. 63.11237 Gas-fired boiler Gas-fired boiler 

includes any boiler that burns gaseous fuels not combined with any solid fuels, burns liquid fuel 

only during periods of gas curtailment, gas supply emergencies, or periodic testing on liquid fuel. 

Periodic testing of liquid fuel shall not exceed a combined total of 48 hours during any calendar 

year. 

Comment: §63.11195(e) states that gas-fired boilers, as defined in §63.11237, are not subject to 

this subpart. §63.11195 does not make clear what recordkeeping, if any, a gas-fired boiler, which 

does burn liquid fuels but meets the definition of a “gas-fired boiler,” has. If a gas-fired boiler 

meeting the definition in §63.11237 does have any recordkeeping requirements, they should be 

stated either in §63.11195 or §63.11237.

Response: We agree that gas-fired boilers located at an area source are not subject to subpart 

JJJJJJ or any requirements in the subpart. Section 63.11195 has been revised to clarify that the 

listed boilers are not subject to any requirements (e.g., notification, recordkeeping, reporting).

Commenter Name: Los Angeles Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0397

Comment Excerpt Number: 54

Comment: Although the rule that you have created will require reductions with major sources of 

air toxics and will require minimal reductions from sources that are not major, I think it’s 

important to note that of the 180,000 boilers and process heaters operating in America, that only 

14,000 are major sources. 

So EPA has proposed essentially do nothing regulatory with minimum control requirements, and 

no monitoring or reporting requirements for the remaining 166,000 boilers and process heaters. 

Schools and communities living or working near these plants that are not major will receive 

little, if any, relief from EPA. 

And let me give you an example, if I may. Across the United States large schools all have boilers 

and there would be no notification. This is our most vulnerable population and no knowledge of 

what was actually being burned in those boilers and they would be exposed. You know, we’re 

living in a time today of natural and manmade disasters that are horrific. 

Please, let’s try and work together to create a rule that is more protective and a rule that ensures 

protection of human health and our environment. 

Response: We disagree with the comment that schools and communities living or working near 

these plants that are not major will receive little, if any, relief from EPA. Industrial facilities 

having large boilers and process heaters are generally major sources and their boilers will be 

subject to the restrictive MACT-based emission limits in subpart DDDDD. The area source 

facilities covered by subpart JJJJJJ are predominantly commercial (e.g., hotels, apartment 

buildings) and institutional (e.g., hospitals, schools) facilities. The boilers located at area source 
facilities that are of most concern (i.e., coal-fired boilers) are subject to MACT-based emission 

limits in the final rule.

Commenter Name: Susan Eckerly

Commenter Affiliation: National Federation of Independent Business, NFIB

Document Control Number: EPA-HQ-OAR-2006-0790-1631.1

Comment Excerpt Number: 5

Comment: The continuous testing and monitoring requirements create considerable new 

paperwork and recordkeeping burdens : These requirements will require small business owners 

to spend more money on outside testing. The monitoring requirement will mean less time the 

business owner has to spend running the business and could become a paperwork nightmare. 

Response: The final rule has been revised to remove the requirement for large area source 

boilers to install and operate a CO CEMS. Also, the final rule has been revised to subject only 

existing coal-fired area source boilers to emission limits. Thus, the continuous testing and 

monitoring requirements is not applicable to most area source boilers (biomass-fired and oil-fired 

boilers).

Commenter Name: Russell A. Wozniak

Commenter Affiliation: The Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2006-0790-1766.1

Comment Excerpt Number: 15

Comment: EPA’s proposed section 63.11224(b) reporting requirement should be converted to a 

recordkeeping requirement. There is no environmental benefit in submitting of these reports on 

an annual basis. In addition, small sites are already subject to a number of other reporting 

obligations in the first quarter of each year, such as State Emission Inventory Reports, and 

Preparation of SARA Section 312 and 313 reports. The details contained in Section 63.11224(b) 

could also be made available upon request of the Administrator. 

Response: Section 63.11224(b) (now section 63.11225(b)) already states that the compliance 

report must be prepared but only submitted if any deviations occurred during the reporting 

period. Section 63.11225(b) has also been revised to require boilers that are only subject to the 

biennial tune-up requirement to only prepare a biennial compliance report.

Commenter Name: Russell A. Wozniak

Commenter Affiliation: The Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2006-0790-1766.1

Comment Excerpt Number: 16
Comment: The requirement to provide a report within 15 calendar days of any change in 

information that has already been provided is a signification burden for small sites that may have 

only one person covering all safety, health, and environmental requirements. As commented 

above, the facility should be required to keep the data on-site for any agency inspection or 

request for data. 

Dow recommends that Table 6 of this proposed regulation on page 58385 be changed to include 

that General Provision in Subpart A, §63.9(j) does not apply. Thus, the column titled “Applies to 

Subpart JJJJJJ? Should have the entry “No” for §63.9(j). The suggested rule text in Table 6 of 

subpart JJJJJJ revision: [SEE PDF FOR SUGGESTED TABLE 6] 

Response: WE disagree with the comment. Subpart JJJJJJ already reduces the burden of 

submitting reports. Only if there is a deviation from the applicable requirement does an area 

source facilities need to submit a report.

Commenter Name: Russell A. Wozniak

Commenter Affiliation: The Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2006-0790-1766.1

Comment Excerpt Number: 18

Comment: Table 6 of subpart JJJJJJ notes that section 63.5 of the General Provisions is not 

applicable. However, Section 63.11224(a)(1) requires that the owner/operator submit all of the 

notifications in various sections of the General Provisions including Section 63.5(b). Thus, 

EPA’s final rule should clarify whether or not the notification requirements of Section 63.5(b) 

apply. 

Response: Section 63.11224(a)(1) [now section 63.11225(a)(1)] has been revised to remove the 

reference to 63.5(b).

Commenter Name: Catherine Fitzsimons

Commenter Affiliation: Iowa Department of Natural Resources

Document Control Number: EPA-HQ-OAR-2006-0790-1829.1

Comment Excerpt Number: 1

Comment: Is it an annual or biennial tune-up report? The proposed rule requires a boiler tune-up 

every two years for small boilers at area sources. The proposal includes the following: 

63.11222(b)(6) Maintain on-site and submit, if requested by the Administrator, an annual report 

containing the information in paragraphs (b)(6)(i) through (iii) of this section, 

(i) The concentrations of CO in the effluent stream in ppmvd, and oxygen in percent dry basis, 

measured before and after the adjustments of the boiler; 

(ii) A description of any corrective actions taken as a part of the combustion adjustment; and 

(iii) The type and amount of fuel used over the 12 months prior to the annual adjustment. 
Based on the proposed rule, shouldn’t this specify a biennial report and biennial adjustment, 

rather than annual? 

Response: The commenter is correct and the final rule has been revised to specify a biennial 

report and biennial adjustment.

Commenter Name: Catherine Fitzsimons

Commenter Affiliation: Iowa Department of Natural Resources

Document Control Number: EPA-HQ-OAR-2006-0790-1829.1

Comment Excerpt Number: 3

Comment: Facilities are required to prepare an annual report, but do not need to submit unless 

there were deviations. The proposal includes the following: 

63.11224(b) You must prepare, by March 1 of each year, an annual compliance certification 

report for the previous calendar year containing the information specified in paragraphs (b)(1) 

through (b)(3) of this section. You must submit the report by March 15 if you had any instance 

described by paragraph (b)(3) of this section. 

(3) If the source is not in compliance, include a description of deviations from the 

applicable requirements, the time periods during which the deviations occurred, and the 

corrective actions taken. 

The report should be required to be submitted if the source experienced any deviations during the 

reporting year, not just if the source is out of compliance at the time when the report is being 

prepared. 

Response: We agree with the comment and section 63.11224(b)(3) [now section 

63.11225(b)(3)] has been revised to include any deviations.

Commenter Name: Marie Robinson

Commenter Affiliation: National Telecommunications Safety Panel

Document Control Number: EPA-HQ-OAR-2006-0790-1960.1

Comment Excerpt Number: 6

Comment: The EPA should adjust recordkeeping and the associated reporting requirements. The 

EPA is proposing to require “Records documenting monthly fuel use by each boiler, including 

the type(s) of fuel, including, but not limited to, a description of the fuel, including whether the 

fuel has received a non-waste determination by you or the EPA, and the total fuel usage amount 

with units of measure.” Small oil fired boilers at area sources are typically not equipped with 

individual fuel meters and may share a common fuel source with a variety of equipment –

engines and boilers. For oil-fired boilers that are not configured to combust biomass or coal, 

compliance with requirements to maintain records associated with individual unit monthly fuel 

consumption would be unnecessarily burdensome and provide no additional assurances of 

compliance or reduction of HAPs. We recommend that the EPA recognize this and modify the 
proposal to eliminate the fuel consumption information and retain the requirement to document 

fuel type and description. Documentation of fuel type could be supported by purchase receipts. 

Response: The recordkeeping requirement (63.11225(b)(4) of the total fuel use for each calendar 

month is only applicable to affected boilers subject to an emission limit. In the final rule, only 

coal-fired area source boilers are subject to an emission limit. The recordkeeping requirement 

(63.11225(c)(2)(ii)) to document monthly fuel use for each boiler has been revised to clarify that 

this provision is requesting information on the type(s) of fuels burned and not the amount of fuel 

burned.

Commenter Name: Marie Robinson

Commenter Affiliation: National Telecommunications Safety Panel

Document Control Number: EPA-HQ-OAR-2006-0790-1960.1

Comment Excerpt Number: 7

Comment: The EPA should correct the timeframe inconsistencies within § 63.11222. Per 

§63.11222(b)(6), if requested by the Administrator, an annual report is required detailing 

measurements associated with boiler adjustment, however the boiler tune-up requirement in 

§63.11222(b) is a biennial requirement. The EPA should adjust the report frequency to match the 

frequency of the biennial tune-up requirement. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1829.1, Excerpt Number 1.

Commenter Name: Cheryl Johncox

Commenter Affiliation: Minneapolis Neighbors for Clean Air

Document Control Number: EPA-HQ-OAR-2006-0790-1971

Comment Excerpt Number: 9

Comment: Continuous Emissions Monitoring Systems (CEMS) for toxic air pollutants, and to 

have the data released real time on websites that can be accessed by the public. Yearly stack tests 

do not give an accurate estimate of emissions during start-up, shut-down or upset conditions –

which, for some pollutants, most notably dioxins – can be hundreds of times higher than during 

steady-state operation (which is when stack testing is typically done). [DeVries, C. 

RauchgasemissionenundVerfahrensoptimierungen wa ̈hrend der ausserordentlichen 

Betriebssituation An- und Abfahren der Mu ̈llverbrennungsanlage in Amsterdam. In VDI 

Handbuch BAT- und preisorientierte Dioxin-/Gesamtemissionsminimierungstechniken; VDI 

Verlag: Du ̈sseldorf, 1999.], [Neuer-Etscheidt, K., H. O. Nordsieck, et al. (2006). "PCDD/F and 

other micropollutants in MSWI crude gas and ashes during plant start-up and shut-down 

processes." Environ Sci Technol 40(1): 342-9 http://www.ejnet.org/toxics/cems/2006_NeuerEtscheidt_dioxins_MSWI_gas_ashes_startup_shutdown.pdf.] 
Response: We agree that annual stack tests do not give an accurate estimate of emissions during 

all operating conditions. In the rule, we have requirements for continuous monitoring of the 

appropriate operating limits for the control technology used to achieve the applicable emission 

limits.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 35

Comment: Proposed §63.11214 requires, in several paragraphs, that annual performance tests be 

performed between 10 and 12 months after the previous performance test. We support the 

concept of providing a window for such testing, rather than requiring the test be performed on 

the same day every year, but this window, forces more frequent testing than annual and forces 

sources to change the month of testing every year, making compliance more difficult. For 

instance if a test is done in May one year, it must be done in April or May of the following year. 

Since good practice requires some allowance for problems and possible delay or retesting, 

prudent sources will test in April. Then the next year’s test would be in March, etc. Under the 

proposed system, testing is actually required on an approximately 11 month basis rather than an 

annual basis. We suggest §63.11214 be revised to specify annual tests may be done at any time 

in the same calendar quarter as the initial testing was done, regardless of the particular month in 

which the testing occurred. If a boiler does not operate during the quarter, testing should be 

required within 30 days after restart. 

Furthermore, because there will be thousands and thousands of such tests between this rule and 

the major source rule, provision is needed to allow sources to move the testing to other quarters, 

with agreement of the permitting authority. Stack testing, area source and local Agency resources 

are limited and workload needs to be spread throughout the year to allow these resources to be 

efficiently utilized. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1977.1, Excerpt Number 19.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 65

Comment: Proposed §63.11224(b)(4) requires annual reporting of monthly fuel usage for each 

affected source. We see no purpose for collecting such data. It does nothing to enhance 

compliance or reduce emissions and, in certain cases, would involve confidential data. If this is 

included to allow the Agency to do emission estimating, that is not an authorized activity under 
§112 of the CAA and should be done through the appropriate rulemaking. If it is included to 

allow estimating of CO2 emissions, that need has already been addressed through the GHG 

reporting rule and does not need to be duplicated here. This requirement should be deleted or 

justified under §112. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1960.1, Excerpt Number 6.

Commenter Name: Cheryl Sonnier Nolan

Commenter Affiliation: Louisiana Department of Environmental Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2277

Comment Excerpt Number: 3

Comment: Stack Testing 

The proposed subpart requires that sources conduct annual performance tests between ten 

months and twelve months of the previous year’s performance test. As noted above, sugar mills 

typically operate 100 days or less per year. Start and end dates for these seasonally-operated 

sources are highly dependent on the volume and condition of the year’s sugar cane crop. 

Given that Louisiana’s sugar mills operate less than a third of the year, this industry would be 

required to test each boiler three to four times more often than others operating boilers at sources 

that typically operate year round (based on boiler operating hours). As such, should EPA 

improperly conclude that all biomass-fired sources are subject to 40 CFR 63 Subpart JJJJJJ, the 

required stack testing frequency for bagasse-fired boilers located at sugar mills should be 

reduced to once every five years, and stack testing should be allowed to be conducted any time 

during the operating season. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1977.1, Excerpt Number 19.

Commenter Name: Kevin F. Biernacki

Commenter Affiliation: Veolia Energy North America

Document Control Number: EPA-HQ-OAR-2006-0790-2273

Comment Excerpt Number: 13

Comment: Stack testing frequency requirements currently state that “Each annual performance 

test must be conducted between 10 and 12 months after the previous performance test.” This 

current requirement would force units to operate to perform a compliance stack test in certain 

cases when a combustion unit was not planning to fire the necessary fuel, thus adversely 

contributing to higher levels of air pollution. 

Require compliance stack testing based on fuel operating months. For example, a stack test to 

illustrate compliance with a fuel oil emissions limit would be required between 10 and 12 fuel oil 
operating months after the previous performance test. A fuel oil operating month could be 

defined as a month in which a boiler operated on fuel oil for at least 168 hours. Another 

suggestion would be to adopt the 40 CFR 75 operating quarter language. For example, require a 

follow up stack test every four fuel (i.e. oil/biomass/coal) operating quarters and define an 

operating quarter in which a boiler operated on the fuel of interest (i.e. oil/biomass/coal) for at 

least 168 operating hours within the calendar quarter. 

We also recommend allowing for a “grace period” of 720 operating hours following the required 

time frame to perform the test to allow facilities adequate flexibility to perform these stack tests. 

We assume EPA’s intentions were not to force a facility to operate only for compliance testing 

purposes. These recommendations would clarify the stack testing frequency requirements. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1977.1, Excerpt Number 19.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 19

Comment: Stack testing frequency requirements currently state that “Each annual performance 

test must be conducted between 10 and 12 months after the previous performance test.” This 

current requirement would force units to operate to perform a compliance stack test in certain 

cases when a combustion unit was not planning to fire the necessary fuel, thus adversely 

contributing to higher levels of air pollution. 

Require compliance stack testing based on fuel operating months. For example, a stack test to 

illustrate compliance with a fuel oil emissions limit would be required between 10 and 12 fuel oil 

operating months after the previous performance test. A fuel oil operating month could be 

defined as a month in which a boiler operated on fuel oil for at least 168 hours. 

In lieu of operating months, we suggest to adopt the 40 CFR 75 operating quarter language. For 

example, require a follow up stack test every four fuel (i.e. oil/biomass/coal) operating quarters 

and define an operating quarter in which a boiler operated on the fuel of interest (i.e. 

oil/biomass/coal) for at least 168 operating hours within the calendar quarter. 

We also recommend allowing for a “grace period” of 720 operating hours following the required 

time frame to perform the test to allow facilities adequate flexibility to perform these stack tests. 

This “grace period” time frame is allowed within 40 CFR 75 for annual relative accuracy stack 

testing requirements. 

We assume EPA’s intentions were not to force a facility to operate only for compliance testing 

purposes. These recommendations would clarify the stack testing frequency requirements. 
Response: Rather than requiring stack tests to be conducted between 10 and 12 months, the 

final requirement is that each annual stack test must be no more than 13 months after the 

previous performance test.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 28

Comment: In 63.7550, EPA requires that sources file their semiannual reports by January 31st 

and July 31st of each year. The regulated community is inundated with numerous other reporting 

requirements during this same period. Duke Energy notes that in 63.7515 (g), EPA proposes to 

give sources 60 days to submit emission test reports. As a result, EPA should either directly 

allow, or allow local permitting agencies the flexibility to grant sources a minimum of 45 days, 

and preferably 60days to file their semi-annual reports. 

Response: The comment refers to a reporting requirement in subpart DDDDD that is not in 

subpart JJJJJJ. If the comment was submitted to the docket for subpart DDDDD, it will be 

address under that rulemaking.

Commenter Name: Winslow Sargeant

Commenter Affiliation: U.S. Small Business Administration

Document Control Number: EPA-HQ-OAR-2006-0790-2020

Comment Excerpt Number: 3

Comment: EPA Should Have Minimized Facility Monitoring and Reporting Requirements. 

Several SERs noted that recordkeeping activities, as written in the vacated boiler MACT, would 

be especially challenging for small entities that do not have a dedicated environmental affairs 

department. The SERs advocated for the most efficient way to get reductions in HAP and 

requested that the Panel consider all available alternatives to reduce to a bare minimum any 

extraneous requirements that require a lot of paperwork that in the opinion of the SERs do not 

contribute to emission reductions. 

Response: EPA must balance monitoring and reporting requirements with compliance 

assurance. EPA has determined that these requirements have been adequately minimized and are 

consistent with the General Provisions in 40 CFR 63 Subpart A.

Commenter Name: Alice Edwards

Commenter Affiliation: Alaska Department of Environmental Conservation

Document Control Number: EPA-HQ-OAR-2006-0790-1926.1
Comment Excerpt Number: 4

Comment: In addition to the monitoring, the proposed record keeping requirements are 

unrealistic for many small boiler owners/operators in Alaska. The record keeping and reporting 

requirements of the proposed rule are also likely to be overly burdensome and prohibitively 

expensive to small, remote communities and may strain their limited technical and human 

resources. There is a high turnover rate among operators, and limited training is available for 

both the operators of the boilers and the administrators of the records. Proper record knowledge 

transfer is often lost due to the turnover of staff. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-2020, Excerpt Number 3.

Commenter Name: Shelley Schneider

Commenter Affiliation: Nebraska Department of Environmental Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2021.1

Comment Excerpt Number: 4

Comment: EPA requires sources to prepare annual compliance reports and submit them only if 

they have experienced deviations from the applicable requirements. NDEQ requests that EPA 

require the reports be submitted annually, regardless if deviations have occurred. This will 

provide state/local permitting authorities, such as Nebraska, information to verify compliance 

and is consistent with minor source reporting requirements established within state operating 

permits for similar types of sources. 

Response: In the final rule, the requirement regarding annual compliance reports (63. 11225(b) 

has been revised for submittal to the permitting agency upon request.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion

Document Control Number: EPA-HQ-OAR-2006-0790-2257.1

Comment Excerpt Number: 4

Comment: EPA should reduce or even eliminate reporting requirements for boilers only subject 

to work practice standards. Since these units are not required to install control devices, perform 

testing or are not subject to monitoring requirements, reporting would only consist of general 

facility information, fuel usage and a statement that tune-ups and energy assessment 

requirements were met. It is overly burdensome to require semi-annual reports for this limited 

information. 
Response: We agree with the comment and the reporting and recordkeeping requirement for 

boilers subject only to the work practice r management practice of a tune-up has bben revised to 

biennial reporting.

Commenter Name: Winslow Sargeant

Commenter Affiliation: U.S. Small Business Administration

Document Control Number: EPA-HQ-OAR-2006-0790-1950.1

Comment Excerpt Number: 5

Comment: Several SERs noted that recordkeeping activities, as written in the vacated boiler 

MACT, would be especially challenging for small entities that do not have a dedicated 

environmental affairs department. The SERs advocated for the most efficient way to get

reductions in HAP and requested that the Panel consider all available alternatives to reduce to a 

bare minimum any extraneous requirements that require a lot of paperwork that in the opinion of 

the SERs do not contribute to emission reductions. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1631.1, Excerpt Number 5.

Commenter Name: Pamela F. Faggert

Commenter Affiliation: Dominion

Document Control Number: EPA-HQ-OAR-2006-0790-2257.1

Comment Excerpt Number: 5

Comment: We request that EPA provide clarification that fuel sampling and an associated fuel 

sampling plan is not required for boilers subject to work practice requirements. 

Response: Fuel sampling and an associated fuel sampling plan is only required for boilers 

subject to emission limits.

Commenter Name: Gregory A. Wilkins

Commenter Affiliation: Marathon Petroleum Company, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-2165.1

Comment Excerpt Number: 5

Comment: It is recommended that deviations resulting from EPA’s proposed 30-day rolling 

averages be determined from the daily number of events causing a deviation instead of each 

value above a standard on the 30-day rolling average. While these rolling averages make it more 

likely that a given standard be feasible, just one event (with a large peak concentration) can 

cause a series of rolling daily deviations. This is a misleading metric. It is more appropriate to 

report one deviation for the event that resulted in possibly several days of rolling average 

emissions to be over the standard. 
Response: The proposed subpart JJJJJ did not contain a 30-day rolling average requirement.

Commenter Name: John Lyons

Commenter Affiliation: Kentucky Division for Air Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2218.1

Comment Excerpt Number: 6

Comment: 40 CFR 63.11214(e), requires annual stack testing for CO, for boilers between 10 

MMBtu/hr and 100 MMBtu/hr. 40 CFR 63.11222 (b), requires a tune-up to be performed 

biennially, meaning once every 2 years. Part of the tune-up includes measuring the concentration 

in the effluent stream of CO in parts per million, by volume, dry basis (ppmvd), before and after 

adjustments to the boiler are made [40 CFR 63.11222(b)(5)]. It appears that the CO testing done 

before and after the tune-up is the same testing performed during the annual stack test. The 

processing and verification of these submittals will represent a significant increase in the 

workload of state’s environmental agencies. In order to eliminate this redundancy we suggest 

that either the annual stack testing not be required for the year of the tune-up, or that testing not 

be required before and after the tune-up. 

Response: To clarify, the tune-up requirement is applicable to boilers less than 10 million Btu 

per hour. For boiler between 10 and 100 million Btu per hour, annual CO testing was required 

and they were not subject to the tune-up requirement. Therefore, there is no redundancy for 

boilers between 10 and 100 million Btu per hour.

Commenter Name: Cynthia A. Finley

Commenter Affiliation: National Association of Clean Water Agencies

Document Control Number: EPA-HQ-OAR-2006-0790-2260.1

Comment Excerpt Number: 6

Comment: The proposed requirement for an annual report with effluent stream measurements 

and fuel use before the "annual adjustment" also conflicts with the requirement for a tune-up 

once every two years. With the biennial tune-up requirement, adjustments would be made once 

every two years, and any measurements or records related to the boiler and its tune-up should be 

completed on a biennial basis rather than on an annual basis. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-1939.1, Excerpt Number 76. 

Category 11J.

Commenter Name: Cynthia A. Finley

Commenter Affiliation: National Association of Clean Water Agencies
Document Control Number: EPA-HQ-OAR-2006-0790-2260.1

Comment Excerpt Number: 10

Comment: In section 63.1124, paragraph (c)(2) states, "You must keep records to document 

conformance with the work practices, emission reduction measures, and management practices 

required by section 63.11215 as specified in paragraphs (c)(2)(i) through (iv) of this section." 

Neither section 63.11215 nor section 63.1124 has paragraphs with these numbers, however. EPA 

should clarify or correct this statement. 

Response: Section 63.11224(c) has been corrected to read “as specified in paragraphs (c)(2)(i) 

and (ii) of this section.”

Records That Must Be Retained

Commenter Name: Bob Pankratz

Commenter Affiliation: Babcock and Wilcox Technical Services Pantex, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-0833

Comment Excerpt Number: 2

Comment: §63.11195(e) states that gas-fired boilers, as defined in §63.11237, are not subject to 

this subpart. §63.11195 does not make clear what recordkeeping, if any, a gas-fired boiler, which 

does burn liquid fuels but meets the definition of a “gas-fired boiler,” has. If a gas-fired boiler 

meeting the definition in §63.11237 does have any recordkeeping requirements, they should be 

stated either in §63.11195 or §63.11237. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-2243, Excerpt Number 7.

Commenter Name: Marie Robinson

Commenter Affiliation: National Telecommunications Safety Panel

Document Control Number: EPA-HQ-OAR-2006-0790-1960.1

Comment Excerpt Number: 5

Comment: The EPA should adjust requirements for on-site retention of records. In Subpart 

JJJJJJ, 63.11224(d), the EPA is proposing to require that each record be kept “onsite for at least 2 

years after the date of each recorded action . . .” Given the scope of requirements for this 

rulemaking, and especially the additional requirements that apply to new versus existing units, 

the NTSP believes that this requirement is problematic at best. Many facilities that contain area 

source boilers subject to this proposed rule are unmanned or located in remote areas. If 

supporting a telecommunications infrastructure, such facilities may also be widely spaced. It is 

therefore unlikely, from an enforcement perspective that the EPA or state authorities would seek 

to visit such facilities simply for the purpose of obtaining required records when a more efficient 
alternative could exist to obtain such records from a centralized office or business address. We 

recommend that the EPA recognize this fact and modify the proposal to allow records to 

maintained on- or off-site provided they can be made readily available to the EPA. 

In fact, the EPA does not require on-site recordkeeping in other, similar contexts. For example, 

final regulations for National Emission Standards for Hazardous Air Pollutants for Reciprocating 

Internal Combustion Engines require that records be “readily accessible” without reference to 

specific location. [Section 63.6660 provides that, “(c) You must keep each record readily 

accessible in hard copy or electronic form for at least 5 years after the date of each occurrence, 

measurement, maintenance, corrective action, report, or record, according to § 63.10(b)(1).”] The 

EPA could adopt similar regulatory language with regard to the recordkeeping requirements for 

area source boilers. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-2243, Excerpt Number 5.

Commenter Name: Kathleen Tobin

Commenter Affiliation: Verizon

Document Control Number: EPA-HQ-OAR-2006-0790-2014.1

Comment Excerpt Number: 1

Comment: Verizon believes that the provisions requiring that all recordkeeping be kept on-site 

are unnecessarily restrictive and costly. While this requirement will not place undue burdens 

upon parties with relatively few locations, the costs and burdens will be significant for 

companies, like Verizon, who have many thousands of locations. Moreover, the burdens and 

costs will be even greater to parties, like Verizon, who operate facilities that are normally 

unoccupied. 

Companies with many small locations should be allowed the opportunity to keep files in a 

central location, provided that copies can be quickly produced electronically or by facsimile at 

the local facility upon request. In addition, it should be clarified that records may be kept in hard 

copy or electronic form. This allowance would not weaken any of the benefits of the proposed 

rule and would be consistent with the final NESHAP for Reciprocating Internal Combustion 

Engines Rule [75 FR 9648 — 9690 (March 3, 2010)]. 

It should be noted that allowing the records to be centralized also provides security benefits. It is 

much more difficult to assure that employees or visitors to a facility do not accidently disturb 

documents if they are kept in a local office. Even more importantly, by centralizing the records it 

becomes far easier for a party to perform audits to assure that the records are, in fact, being 

properly maintained. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-2243, Excerpt Number 5.

Commenter Name: Kathleen Tobin

Commenter Affiliation: Verizon

Document Control Number: EPA-HQ-OAR-2006-0790-2014.1
Comment Excerpt Number: 4

Comment: The proposed rule requires reporting the total fuel used by each affected source. For

sources subject to work practices, record keeping is required for the type and amount of fuel used 

over the 12-month period. It should be noted that commercial boilers do not have totalizing fuel 

or hour meters on each unit. The addition of fuel or hour meters does not appear to be included in 

the cost analysis; therefore, this would be an additional cost burden to facilities. Hour meters are 

ineffective at projecting boiler fuel consumption, due to variable operating conditions and cycles. 

Fuel usage is usually best recorded during fuel oil deliveries. Verizon recommends the removal 

of the requirement to measure fuel usage for each boiler and replace it with maintaining fuel 

delivery receipts in order to demonstrate the type of fuel used and the total quantity of fuel 

purchased for a site. 

Response: Please see response to DCN EPA-HQ-OAR-2006-0790-2243, Excerpt Number 7.

Commenter Name: Keith M. Krom

Commenter Affiliation: AT&T, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2243

Comment Excerpt Number: 5

Comment: EPA should adjust requirements for on-site retention of records 

EPA is proposing to require that each record be kept "onsite for at least 2 years after the date of 

each recorded action . . . “ Given the scope of requirements for this rulemaking, and especially 

the additional requirements that apply to new versus existing units, AT&T believes that this 

requirement is problematic at best. Many facilities that contain area source boilers subject to this 

proposed rule are unmanned or located in remote areas. If supporting a telecommunications 

infrastructure, such facilities may also be widely spaced. It is therefore unlikely, from an 

enforcement perspective that, EPA or state authorities would seek to visit such facilities simply 

for the purpose of obtaining required records when a more efficient alternative could exist to 

obtain such records from a centralized office or business address. We recommend that EPA 

modify the proposal to allow records to be maintained on- or off-site provided they can be made 

readily available to EPA. 

In fact, EPA does not require on-site recordkeeping in other, similar contexts. For example, final 

regulations for National Emission Standards for Hazardous Air Pollutants for Reciprocating 

Internal Combustion Engines require that records be "readily accessible" without reference to 

specific location. [Footnote: Section 63.6660 provides that, "(c) You must keep each record 

readily accessible in hard copy or electronic form for at least 5 years after the date of each 

occurrence, measurement, maintenance, corrective action, report, or record, according to § 

63.10(b)(1)."] EPA could adopt similar regulatory language with regard to the recordkeeping 

requirements for area source boilers. 

Response: We disagree with the comment that many facilities that contain area source boilers 

subject to the proposed rule are unmanned or located in remote areas. Unlike internal 
combustion engines, which burn natural gas, affected area source boilers combust coal. biomass, 

or oil requiring onsite operators.

Commenter Name: Keith M. Krom

Commenter Affiliation: AT&T, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2243

Comment Excerpt Number: 7

Comment: EPA should adjust and clarify recordkeeping and associated reporting requirements 

and that individual boilers need not be fitted with a fuel meter 

EPA is proposing to require "Records documenting monthly fuel use by each boiler, including 

the type(s) of fuel, including, but not limited to, a description of the fuel, including whether the 

fuel has received a non-waste determination by you or EPA, and the total fuel usage amount with 

units of measure." For oil-fired boilers that are not configured to combust biomass or coal, 

compliance with requirements to maintain records associated with individual unit monthly fuel 

consumption would be unnecessarily burdensome and provide no additional assurances of 

compliance or reduction of HAPs. Small oil fired boilers at area sources are typically not 

equipped with individual fuel meters and may share a common fuel source with a variety of 

equipment - engines and boilers. EPA should recognize this and modify the proposal to eliminate 

the fuel consumption information for boilers that cannot fire biomass and coal and retain the 

requirement to document fuel type and description. Documentation of fuel type could be 

supported by purchase receipts. 

EPA has also proposed that annual compliance certification reports contain "the total fuel use by 

each affected source subject to an emission limit, for each calendar month within the reporting 

period . . .” Similar to our comments above, AT&T would suggest that such reporting 

requirements are unnecessarily burdensome and not needed for compliance. Therefore, EPA 

should instead allow for the use of data from fuel purchase records and other reliable information 

assembled in the normal course of business. EPA should clarify that certification reports can 

utilize reasonable methods to determine the fuel used by individual sources. 

In addition, should EPA decide to impose requirements to separately determine fuel use by each 

boiler, EPA should not impose requirements to specifically meter fuel use by each boiler. Many 

individual boilers may draw from a common fuel source at irregular intervals. This fuel source 

may be shared with a variety of equipment — engines and boilers. Small oil fired boilers at area 

sources are typically not equipped with individual fuel meters. Therefore records assembled in 

the normal course of business (e.g., for a common fuel source) should be considered sufficient to 

meet requirements for individual boilers, again relying on reasonable methods to allocate fuel 

use. 

Response: In the final rule, we have minimized the recordkeeping and reporting requirements 

for affected boilers that are not subject to emission limits. In the final rule, only existing coalfired boilers with heat input capacity of 10 million Btu per hour or greater are subject to emission 

limits. Since gas-fired area source boilers are not part of the source categories covered by 

subpart JJJJJJ, there are no reporting or recordkeeping requirements for gas-fired area source 

boilers.
Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 57

Comment: EPA’s proposal includes requirements for tracking of numerous data points, 

including fuel consumption; operating hours, startups, shutdowns including dates and times; 

equipment malfunctions including dates and times; numerous operating parameters including 

dates and times of deviations; CEMS, COMS, and CPMS calibration and quality 

assurance/quality control data; CEMS, COMS and CPMS maintenance information; CEMS, 

COMS, and CPMS out of control periods including reasons, dates and times; performance test 

reports; fuel sampling reports; vendor reports; and a number of other pieces of information. 

Records must be kept of virtually all information referenced in the proposal, including all CPMS 

data required to be collected, for 5 years. Proposed §§ 63.7555, 63.7560. Unfortunately, much of 

these data gathering requirements cannot be automated, but instead will have to be collected 

manually. Once the data are gathered, decisions will have to be made regarding what has to be 

reported and a report will have to be generated and certified. This will be a massive undertaking 

and the possibility of making an error during the process will be a virtual certainty. 

To reduce manpower requirements most sources will likely attempt to automate as much of the 

reporting and record keeping as possible. The equipment costs alone for implementing an 

automated (to the extent possible) data collection and report generation system for a unit with 

multiple controls is likely to be very high and there may be little opportunity for standardization 

of the software. In short, UARG does not believe that EPA, in proposing its enforceable 

operating limit approach, has adequately estimated or considered the data management costs of 

its proposal and requests that the Agency do so. 

Response: This comment pertains to requirement in the proposed subpart DDDDD and is 

addressed in that rulemaking.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 63

Comment: In addition, proposed 63.11222(b)(6)(iii) requires maintaining an annual report to 

include the type and amount of fuel used over the 12 months prior to the annual adjustment. 

There are two issues with this requirement: 

First, this rule stipulates biennial tune-ups for specific affected sources, not annual. 
Second, this implies that fuel metering is required for every boiler subject to tune-up 

requirements. There is no justification for a requirement to have individual boiler fuel use meters 

or other data since actual fuel use for a boiler is immaterial for documentation of a tune-up. The 

only requirement should be for identification of the fuel type used in the boiler over the prior 

operating period and the fuel type used during the tune-up. If EPA can justify a requirement for 

the source to determine the quantity of fuel combusted, it should be sufficient for the source to 

use available data such as from billing records, delivery receipts, tank level drop, common fuel 

meter, or other data to determine that quantity. 

Response: The final rule has been revised to require biennial reporting for boilers subject to the 

biennial tune-up requirement. In addition, the final rule have been revised to clarify that the fuel 

use reporting requirement is for information on the fuel type combusted and not the amount.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 64

Comment: The definition of “tune-up” is provided in 63.11237. It correctly focuses on the need 

to “optimize the combustion efficiency,” whereas proposed 63.11222(b)(4) requires the source to 

“minimize total emissions of CO,” which as noted above is an incorrect approach to a tune-up 

and will lead to lower efficiency and higher net total emissions. As stated above, EPA needs to 

correct the language in 63.11222. 

The “tune-up” definition also implies that use of an approved specialist could be required. EPA 

needs to recognize that many companies have in-house experts who are trained and well 

qualified to perform adjustments to burner systems and already do so. Continued use of in-house 

resources should be supported. 

Response: Section 63.11222(b)(4) [now section 63.11223(b)(4)] has been revised to read 

“Optimise total emissions of carbon monoxide ... consistent with the manufacturer’s 

specifications,,,”

Electronic Reporting Mechanism

Commenter Name: Rob Barton and Ralph Roberson

Commenter Affiliation: Southern Company

Document Control Number: EPA-HQ-OAR-2006-0790-1978.1

Comment Excerpt Number: 15

Comment: EPA proposes that, after December 31, 2011, sources must submit all compliance 

test results to EPA using the Electronic Reporting Tool (ERT) software or “other compatible 
electronic spreadsheet”. The ERT was used extensively in the Boiler MACT and EGU MACT 

ICRs. Our experience with this software suggests that reporting emissions data using the ERT is 

time consuming and represents an unnecessary burden to the regulated community. We 

recommend that EPA eliminate this requirement from the proposed rule unless or until EPA can 

establish the necessary statutory authority to develop such software. 

Assuming EPA can establish such authority, compliance data reporting software should 

minimize the burden on the regulated community by requiring only those data required to 

demonstrate compliance. This would include the raw emissions data and a limited amount of 

boiler and control device operating information from the emissions test period. It should also 

follow a transparent development process that includes feedback from the regulated 

community.5 The proposed use of the ERT does not meet either of these requirements. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Russell A. Wozniak

Commenter Affiliation: The Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2006-0790-1766.1

Comment Excerpt Number: 17

Comment: Section 63.11224(e) of EPA’s proposed rule requires that air emission test data from 

stack test reports be entered electronically into EPA’s WebFire database after completing a 

performance demonstration. 

EPA provides no insight or justification in the preamble or otherwise for requiring this form of 

data submittal. The cost of this requirement, as compared to conventional reporting, is not 

evaluated or disclosed in discussion of the cost and impact of the proposed rule. Although a 

number of affected facilities may be already trained and equipped to accomplish such electronic 

reporting, many smaller affected facilities have not had to participate in such reporting 

procedures in the past. These facilities will require additional staff time, equipment, and training 

to accomplish this requirement. The proposed requirement means that even the initial reporting 

must be conducted electronically. This further burdens affected facilities in unnecessarily having 

to develop new reporting techniques and procedures concurrent with the other tasks required to 

implement a new rule. EPA has failed to describe any benefit of this requirement as compared to 

these additional burdens. 

It is also likely that implementation of the initial testing, much less any later testing, will be 

accomplished under state authority. Unless state agencies are willing to use this same electronic 

reporting tool, facilities will have a dual requirement to report in one manner to satisfy State and 

Local requirements and in another manner to satisfy’s EPA’s Area Source regulation. EPA has 

also failed to describe any effort to convince state agencies to use this tool as their preferred 

reporting mechanism. 
Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 67

Comment: EPA is requiring submission of data via the Electronic Reporting Tool (ERT). 75 FR 

31903. Notwithstanding EPA’s assertions to the contrary, data submitted through the ERT is 

error-prone and imposes additional burdens on reporting sources because the ERT bypasses all 

data quality control. For the information collection process for the Boiler MACT suite of rules, 

EPA required sources to use the ERT. Sources had requested in the ICR proposal stage that EPA 

not utilize the ERT, which was going through Beta testing, and informed EPA that the ERT had 

serious flaws including difficulty of use, content problems and inaccessibility. EPA decided to 

use it for data collection for these rules. The concerns proved correct, however, as sources were 

compelled to use the ERT, which is a difficult and time-consuming tool for submission of test 

data. The ERT data compiled was riddled with mistaken entries, incorrect and missing data, and 

the ERT had generally faulty output. Then the problem was compounded when EPA relied on 

the inaccurate data, leading to multiple calculation and other inaccuracies. 

Using the ERT doubles the burden on sources that take the time to enter accurate source data, 

only to see it distorted. They then must spend hours finding the data error and conferring with 

EPA personnel to fix the problem. Only then are they able to consider EPA’s rule proposal and 

its impact on their sources. In part due to the ERT and resulting data problems, regulated sources 

sought an extension of the comment period. [See DCN: 2006-0790-1783.3 for Comment 

Extension Request and Description of the Development of the Boiler MACT Database 

(Attachment 2). 

In the past, sources did compliance tests for the state, and the state approved the data. The state 

effectively conducted quality control on the data. The ERT bypasses the state, creating data 

quality issues. Using the ERT means that data is transmitted without any quality control, and that 

results in multiple data errors. The ERT does not permit the easy identification or correction of 

errors. Reporting needs to be accomplished by whatever format permits the source to trace the 

same data throughout the process to ensure its integrity. This had been accomplished in the past 

by using the hard copy submitted to the State and a human being looking at data to quality 

control it. If there was a problem, this could be identified and resolved in the early stage, before 

the faulty data was applied to formulas. 

CIBO urges EPA to adopt a reporting methodology that ensures the data is quality controlled, 

and errors can be traced easily to their origins. The ERT needs to be improved before it is 

required for data submission for compliance demonstration. Inaccuracies may be more tolerable 

during the rule-writing process, but once the rules are in place, the stakes are much higher, as 

faulty ERT output can create compliance issues for sources. EPA may prefer the administrative 
ease of the ERT, but that should not outweigh the need for regulated sources to have assurances 

of accurate data and compliance status. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Sharene Shealey

Commenter Affiliation: RRI Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1839.1

Comment Excerpt Number: 3

Comment: In cases where an ICI Boiler is part of a Title V or state only operating permit, the 

local permitting agency has its own unique emission and compliance test reporting format. State 

and local agencies also enforce the specific conditions within these operating permits. In all 

locations where RRI Energy operates an industrial boiler, we are required to submit a hard copy 

of all compliance test results to the local permitting authority. To comply with the proposed rule, 

RRI Energy would be required to prepare a hard copy report for the state or local agency that 

issued the permit in addition to inputting the data into the Electronic Reporting Tool (ERT) or 

WebFIRE database when it becomes available. This is a duplication of effort, increasing the cost 

of reporting test information. 

RRI Energy would like EPA to provide a listing of those states who will utilize the ERT or 

WebFIRE as its means of collecting emission test data to determine compliance. Where a state or 

local agency does not adopt the ERT or WebFIRE reporting mechanism, or until such time local 

agencies do adopt the ERT or WebFIRE reporting, the regulated entity should not be required to 

duplicate reporting efforts. In these cases, compliance would be demonstrated by reporting in 

accordance with the permitting authority’s requirements. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Renee Lesjak Bashel

Commenter Affiliation: Small Business Environmental Assistance Programs, SBEAP

Document Control Number: EPA-HQ-OAR-2006-0790-2195.1

Comment Excerpt Number: 13

Comment: Recommendation: Take the burden off small sources for providing data 

electronically. Consultant 

costs will be prohibitive, alongside the already high cost of testing. 

At a recent training program, one of the SBEAPs reportedly learned that it can take a person—

with experience using computers—a couple days to enter all the data into EPA’s online system 
as required in 63.11224(e). The consultant fee was reportedly thousands of dollars, just for the 

data entry. If they cannot afford to have someone else enter the data, small business owners and 

their staff often lack basic computer use experience sufficient to maintain the most basic records 

and spreadsheets much less use a complex application on their own. In addition, many small 

businesses may not have the computing power to deal with a program in Microsoft Access and 

transfer files that it generates. 

Until EPA can streamline this system and make it something anyone can easily use, the burden 

of online data entry should be left to the major sources that are better able to afford the cost. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 62

Comment: EPA requests comment on the utility of the proposed requirement for electronic 

reporting of performance test results and associated operating data and the burden that owners 

and operators of boiler area source facilities estimate would be associated with this requirement. 

We see no value in this requirement for liquid-fired boilers and recommend its deletion. There is 

no justification for imposing this requirement. 

The preamble attempts to justify the extra cost and burden of this requirement (which is 

significant for the estimated 168,000 boilers subject to this proposal) on the basis that it will help 

improve emission factors and reduce the burdens associated with collecting data on emissions 

through §114 request. For liquid-fired boilers the only emission limitation where performance 

tests are required is for CO. The proposed limits are 1 and 2 ppm for new and existing boilers, 

respectively. We see no way collecting any amount of additional data would significantly 

improve the emission factor for liquid-fired boilers versus simply calculating the CO emissions 

using these extremely low concentrations. Furthermore, collecting data from hundreds of 

thousands of CO performance tests doesn’t help develop emission factors, because performance 

tests are all run at >80% of design firing and thus do not represent normal operation or normal 

operating variability for the vast majority of boilers. Since the 1 and 2 ppm limits apply at all 

times, they are a much better approximation basis for emission estimating than any liquid-firing 

emission factor developed from performance test data on sources subject to such low emission 

limits. 

The §114 argument is equally fallacious. §114 requests are actually very rare. The vast major of 

area sources never receive such a request. If the Agency does send out such requests to area 

sources in the future, it is highly unlikely historical CO performance tests will be requested, 

since CO will have already been addressed by this rulemaking. Similarly, enforcement based 

§114 requests are always limited to a few facilities and request vast quantities of data, with 
performance test information being a minor portion if requested at all. It makes no sense to 

require 168,000 boilers to provide data every year or two in order to save a few sources a few 

incremental hours of effort if they ever were to get a §114 request. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 86

Comment: The Requirement For ERT Reporting Should Be Removed. Industry had many 

problems submitting Industrial Boiler MACT and CISWI ICR data using the ERT, and there are 

still many problems with the tool based on experience that utilities and testing firms are having 

while entering Utility Boiler MACT ICR data into the tool. Use of this tool will add cost and 

burden to the emissions testing requirements in this rule. The tool is not a replacement for a stack 

test report, but rather an additional reporting burden, as permitting agencies will still require a 

hard copy stack test report with all supporting documentation. 

The following are examples of issues encountered with the ERT: 

*It is not intuitive and it is difficult to use. 

*It is not set up to handle data from multiple stacks from the same source being tested at the 

same time. 

*It only allows for one intermittent leak check during a test run. Many stacks have more than two 

ports so the ERT should be set up to handle those scenarios rather than having to add leak check 

volumes together to come up with a total. 

*It is not set up to handle mixed blend calibration gases, which are extremely common. 

*The import tool is inadequate, as it does not have enough rows for long runs and often imports 

data in the wrong order. 

*The tool is not set up to handle blank corrections. 

*The tool is “buggy” and slow to respond. 

*The tool seems to only be designed to work under the most ideal of test scenarios, which is not 

always realistic. The EPA should ask for comments on the format and uploading tool from 

individuals that encounter actual real world scenarios for testing to incorporate into future 

editions. 
*Revisions to the ERT should have a revision number such that the users can 

make sure the version they are using is the most recent version available. 

Requiring the ERT will add time and cost to stack testing projects, as time will have to be spent 

entering the test data into the tool and then quality assuring the ERT output. We do not believe 

that EPA has included this extra cost in their analysis. 

In addition, compliance tests are submitted to the state or local permitting agency for review and 

approval. At times, the agency provides comments to the regulated facilities that adjust the test 

results. In these cases, the information entered into the ERT at the time of the stack test would 

not match the final, state-approved emission test results. At a minimum, there needs to be a 

mechanism for the ERT data to be updated in these situations or a flag to indicate whether the 

report has been reviewed and approved by the permitting agency. Alternatively, EPA could 

require the permitting agency to enter the stack test results into the ERT once approved, rather 

than requiring facilities to enter the data. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 87

Comment: If use of the ERT is required, EPA needs to develop a comprehensive ERT Guidance 

Manual that provides complete instructions with examples for: 

*all entries including: 

*the various facility identification codes, and where to find them 

*BDL instructions 

*calibration instructions 

*required attachments 

*the “external” spreadsheets” that are used to import certain data into the ERT 

*the “external spreadsheets” that are used for reporting test methods not currently supported by 

the ERT 
*EPA should also develop an “outreach” or “training” program that provides instructions for 

specific source categories and related parameters. Such efforts need to be readily-available – via 

presentations at relevant conferences/seminars, as well as web-based sessions (”webinars”). 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Bob Perry

Commenter Affiliation: FirstEnergy Corp

Document Control Number: EPA-HQ-OAR-2006-0790-1959.1

Comment Excerpt Number: 19

Comment: EP A proposes that, after December 31, 2011, sources must submit all compliance 

test results to EPA using the Electronic Reporting Tool (ERT) software or “other compatible 

electronic spreadsheet”. The ERT was used extensively in the Boiler MACT and EGU MACT 

ICRs. Our experience with this software suggests that reporting emissions data using the ERT is 

time consuming and represents an unnecessary burden to the regulated community. We 

recommend that EPA eliminate this requirement from the proposed rule unless or until EPA can 

establish the necessary statutory authority to develop such software. 

Assuming EPA can establish such authority, compliance data reporting software should 

minimize the burden on the regulated community by requiring only those data required to 

demonstrate compliance. This would include the raw emissions data and a limited amount of 

boiler and control device operating information from the emissions test period. It should also 

follow a transparent development process that includes feedback from the regulated community. 

The proposed use of the ERT does not meet either of these requirements. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Shelley Schneider

Commenter Affiliation: Nebraska Department of Environmental Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2021.1

Comment Excerpt Number: 1

Comment: The proposed standards require sources to submit their performance test data 

electronically to EPA through the WebFIRE software. NDEQ appreciates that having the data 

submitted electronically will produce a larger data set EPA can utilize to develop more accurate 

emission factors. Conversely, if sources are not required to submit a paper copy of the test results 

to the state/local permitting authority, the data can not be reviewed and quality assured. The 

WebFIRE software does not have quality assurance flags to alert EPA that a test was conducted 

improperly or whether the data is accurate. Utilizing inaccurate or false data could lead to 

nonrepresentative emission factors and potential noncompliance with the emission limits. 
NDEQ requests EPA include a provision to require facilities to submit their testing results to 

their state/local permitting authority in addition to submitting the data electronically. The 

Nebraska Air Quality Regulations require facilities to provide emissions test results to NDEQ 

within 45 days of completion of the test. Not including this provision in the standard may 

unnecessarily result in noncompliance with the state regulations and may result in inaccurate test 

data. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Michael Hutcheson

Commenter Affiliation: Ameren Corp.

Document Control Number: EPA-HQ-OAR-2006-0790-2012.1

Comment Excerpt Number: 2

Comment: US EPA requests comment on the utility of the electronic stack test reporting 

requirement and the burden that owners and operators of boiler area sources would face. Ameren 

believes the electronic stack test reporting requirement is fraught with risk to sources. Placing 

stack test companies in control of boiler owner stack test data leaves boiler owners with all the 

risks associated with reporting errors but no control over the process. Boiler owners would be 

responsible for the conduct of the stack tester during the test and then after the test during the 

electronic reporting period. Even a responsible boiler owner who monitored the testing, corrected 

stack test errors during the report review process (and there are always errors), could not be 

assured that the stack tester properly reported the data to US EPA in the electronic reporting tool. 

This electronic reporting tool reporting requirement is a step beyond self-deviation reporting and 

goes to actual reporting of process and emissions data. This should not be a requirement, it is not 

required to comply with standards and is not required to meet the stack test reporting 

requirements of Subpart A. US EPA should not require electronic reporting of stack test data. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Alice Edwards

Commenter Affiliation: Alaska Department of Environmental Conservation

Document Control Number: EPA-HQ-OAR-2006-0790-1926.1

Comment Excerpt Number: 5

Comment: Administrators in these remote communities have a large array of duties with 

limited, systemized, electronic records management. The record systems are not part of a 

centralized system, and data collection is still primary a paper submittal system. In addition, the 

proposed rule assumes the Electronic Reporting Tool (ERT) will be readily understood and 
available. Alaska’s remote communities have limited internet access; and in communities with 

internet, connections are often slow and experience frequent and numerous disconnects. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Sheila C. Holman

Commenter Affiliation: North Carolina Department of Environment and Natural Resources

Document Control Number: EPA-HQ-OAR-2006-0790-2222.1

Comment Excerpt Number: 10

Comment: [See submittal for Attachment A, Topic 3, which discusses electronic reporting.] 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Rob Barton

Commenter Affiliation: RMB Consulting and Research

Document Control Number: EPA-HQ-OAR-2006-0790-2140.1

Comment Excerpt Number: 13

Comment: EPA proposes that, after December 31, 2011, sources must submit all compliance 

test results to EPA using the Electronic Reporting Tool (ERT) software or “other compatible 

electronic spreadsheet”. The ERT was used extensively in the Boiler MACT and EGU MACT 

ICRs. Our experience with this software suggests that reporting emissions data using the ERT is 

time consuming and represents an unnecessary burden to the regulated community. We 

recommend that EPA eliminate this requirement from the proposed rule unless or until EPA can 

establish the necessary statutory authority to develop such software. 

Assuming EPA can establish such authority, compliance data reporting software should 

minimize the burden on the regulated community by requiring only those data required to 

demonstrate compliance. This would include the raw emissions data and a limited amount of 

boiler and control device operating information from the emissions test period. It should also 

follow a transparent development process that includes feedback from the regulated community 

(see submittal for footnote 5). The proposed use of the ERT does not meet either of these 

requirements. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Rob Barton
Commenter Affiliation: RMB Consulting and Research, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2198.1

Comment Excerpt Number: 13

Comment: Inappropriate Use of ERT Software for Data Reporting 

EPA proposes that, after December 31, 2011, sources must submit all compliance test results to 

EPA using the Electronic Reporting Tool (ERT) software or “other compatible electronic 

spreadsheet”. The ERT was used extensively in the Boiler MACT and EGU MACT ICRs. Our 

experience with this software suggests that reporting emissions data using the ERT is time 

consuming and represents an unnecessary burden to the regulated community. We recommend 

that EPA eliminate this requirement from the proposed rule unless or until EPA can establish the 

necessary statutory authority to develop such software. 

Assuming EPA can establish such authority, compliance data reporting software should 

minimize the burden on the regulated community by requiring only those data required to 

demonstrate compliance. This would include the raw emissions data and a limited amount of 

boiler and control device operating information from the emissions test period. It should also 

follow a transparent development process that includes feedback from the regulated community. 

[Footnote: EPA followed this process in their development of the Clean Air Markets Division 

(CAMD) Emission Collection and Monitoring Plan System (ECMPS) software.] The proposed 

use of the ERT does not meet either of these requirements. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Martha E. Rudolph

Commenter Affiliation: Colorado Department of Public Health and Environment

Document Control Number: EPA-HQ-OAR-2006-0790-1979.1

Comment Excerpt Number: 14

Comment: The State intends to continue to request sources to submit stack test reports to the 

State, in addition to EPA’s collecting stack testing data via the Electronic Reporting Tool (ERT). 

The State appreciates EPA’s need to readily access stack test data and applauds efforts to 

improve emission factors. However, the State believes that the stack test data reported must be 

considered along with additional, specific information for each source’s operations. This 

evaluation cannot be easily conducted with the limited data reported in the ERT. The State 

believes that the stack test data submitted in the ERT, taken at face value, may be misleading 

unless the context in which the testing was completed is understood. Until the number and 

degree of source configuration and operation variables can be adequately accounted for and 

reported in one reporting tool, allowing the associated test data to be wholly considered, the State 

will continue to request stack test reports be submitted to the State. 
Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: John Hopewell

Commenter Affiliation: American Coatings Association

Document Control Number: EPA-HQ-OAR-2006-0790-2062.1

Comment Excerpt Number: 15

Comment: EPA discusses the requirement to submit data via its Internet -based portal. While we 

agree that electronic submittal and recordkeeping is an improvement, we also feel that EPA 

should account for the associated compliance costs. 

EPA concluded that the regulated sources will not need to input the data; the data input will be 

done by the independent contractor. EPA says that this will save industry both time and money. 

However, EPA ignores the fact that contractors cha rge the customer for each hour that they are 

working on our projects. Based on EPA’s description, we estimate that it would require one 

additional hour to input the test results into the ERT. Based on a typical professional services 

rate of $100/hour, this will add $100 to the cost of each stack test for each large boiler (heat input 

capacity > 10 MMBtu/hour). Based on EPA’s estimate of the number of affected units (174,427 

[Sum of Existing Units and New Units from Table 3. 75 FR 31914]) and the proportion of 

affected units that are large boilers (6% [Ratio of Large Boilers to Total Boilers for Government 

units. Table 7. 75FR 31922]), the ERT data entry would cost sources a collective $1 million per 

year. These costs are not identified in the proposal. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: John Hopewell

Commenter Affiliation: American Coatings Association

Document Control Number: EPA-HQ-OAR-2006-0790-2062.1

Comment Excerpt Number: 16

Comment: EPA says that there will be access to direct data submittal for WebFIRE by 

December 31, 2011 and requires industry to begin using it (§63.11224(e). Based on historical 

experience, there is a significant chance that EPA will not meet this deadline or, if the deadline is 

met, there will be multiple and potentially unworkable problems with the system. In these cases, 

it wil l be unreasonable to hold industry accountable for the deadline. In the past, environmental 

agencies have said that they will use “enforcement discretion” to not penalize industry for not 

entering data into an unworkable system. This is not acceptable. Following the experience with 

TRI-ME, TRI-MEweb, and other electronic systems, EPA should first make the system available 

for voluntary use. If and when WebFIRE is debugged, EPA can require that industry begin using 

the system within 6 months of a Federal Register notice. Please consider the following language: 

§63.11224(e) For affected facilities having applicable emission limits, you must submit an 
electronic copy of stack test reports to EPA’s WebFIRE data base after EPA’s WebFIRE 

database is operational and debugged. When the database is operational and debugged, EPA will 

provide notice in the Federal Register. Six months after this notice, within 60 days after the date 

of completing each performance evaluation conducted to demonstrate compliance with this 

subpart, the owner or operator of the affected facility must submit the test data to EPA by 

successfully entering the data electronically into EPA’s WebFIRE database through EPA’s 

Central Data Exchange. The owner or operator of an affected facility shall enter the test data into 

EPA’s data base using the Electronic Reporting Tool (ERT) or other compatible electronic 

spreadsheet. , the owner or operator of an affected facility shall enter the test data into EPA’s 

data base using the Electronic Reporting Tool located at 

http://www.epa.gov/ttn/chief/ert/ert_tool.html. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Barry Christensen

Commenter Affiliation: Occidental Chemical Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2227.1

Comment Excerpt Number: 17

Comment: Webfire needs a mechanism to capture and protect Confidential Business 

Information. OCC respectfully requests that since EPA is requiring the use of Webfire to submit 

stack test information, EPA establish a mechanism to submit information as "confidential 

business information" entitled to the usual protections against disclosure to the public by EPA. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 23

Comment: In 63.11224(e), the EPA proposes that sources that perform stack tests must submit 

an electronic copy of the stack test reports to EPA’s WebFIRE data base using the Electronic 

Reporting Tool. 

The EPA should allow for other electronic reporting options to provide flexibility for future 

changes in electronic reporting. In addition, the EPA should make the electronic reporting 

language in the Area Source Boiler Rule consistent with the Boiler MACT Rule language in 

63.7550(h) to further clarify when and how stack test data should be entered into the EPA’s data 

base. 
Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 53

Comment: The proposed rule states, “[a]fter December 31, 2011, within 60 days after the date 

of completing each performance evaluation conducted to demonstrate compliance” the 

owner/operator must “submit the test data to EPA by successfully entering the data electronically 

into EPA’s WebFIRE database through EPA’s Central Data Exchange . . . using the Electronic 

Reporting Tool (“ERT”) or other compatible electronic spreadsheet.” In the preamble, EPA 

states that WebFIRE will be available by that date. 75 Fed. Reg. at 32,015. EPA also asserts that 

the information required to be reported with ERT is “already required for the existing test 

methods and is necessary to evaluate the conformance to the test method.” 75 Fed. Reg. at 

32,016. As justification, EPA cites the benefits that will be derived from development of better 

emission factors. 

UARG objects to EPA’s proposed requirement to report using ERT and disagrees with EPA’s 

assertions regarding the impact of that requirement on reporting and on emission factor 

development. On December 14, 2009, UARG provided comments in response to the Agency’s 

Advance Notice of Proposed Rulemaking (“ANPR”) at 74 Fed. Reg. 52,723 (Oct. 14, 2009) 

soliciting comment on a number of aspects of emission factor development, including the 

possibility of requiring submission of all compatible Part 60 and Part 63 to WebFIRE using ERT. 

EPA-HQ-OAR-2009-0174-0040 (incorporated by reference). In those comments, UARG noted 

that its members’ experience with ERT was limited, but nonetheless noted a number of 

shortcomings in the program that were sufficient by themselves to cause UARG to object to any 

requirement to use ERT. UARG members have gained more experience with ERT in recent 

months that has simply confirmed and elevated those objections. Use of ERT is burdensome 

(easily adding 10-20 percent to the cost of compliance testing), requiring manual inputting of 

significant amounts of information much of which is not relevant to performance test results. It 

also is subject to significant performance issues, including software crashes and shutdowns, 

inoperable features (like report generation), and inadequate identification of errors preventing 

data analysis. In short, even if EPA can justify a requirement to report performance test data 

electronically, EPA cannot justify requiring sources to use this program. 

UARG also has a number of legal concerns with EPA’s proposal. First, EPA has made no effort 

in its proposal to identify the software it proposes to require, other than by name. If EPA 

finalized this rule, EPA could substitute virtually any version of this program, or even another 

program by the same name and attempt to mandate its use. For EPA to promulgate an 

enforceable software requirement, EPA must identify the software with sufficient specificity that 

it can be incorporated by reference into the rule. If EPA simply wants to require electronic 
reporting, EPA should limit its requirement to a specific format (e.g., xml) and allow sources to 

procure or develop their own software to comply with that format and the associated reporting 

elements. 

Contrary to EPA’s assertion, ERT as currently designed requires the reporting of vast amounts of 

information that are not otherwise required to be reported under the applicable EPA test 

methods, or EPA’s proposed rule. A brief comparison of the reporting requirements in Method 5 

(40 C.F.R. Part 60, Appendix A, Method 5, 11.2.2 and 11.2.4 -- “[r]eport the results to the 

nearest 0.1 mg”) with EPA’s description of ERT in its Electronic Reporting Users Guide Version 

3.1, June 2009 (creating test plan, run data, test data, process data, etc.) illustrates this point. 

Similarly, EPA’s proposed requirement to report “test data” is not sufficiently detailed to support 

reporting of all of the information that must be entered into ERT in order to submit data. To 

comply with the Paperwork Reduction Act and its implementing regulations, EPA must 

specifically identify each piece of information it seeks to have reported, explain how those data 

have practical utility, and estimate the costs of collection and EPA review of those data. EPA has 

done none of that. If EPA intends to require reporting of more than the test results already 

required to be reported under the applicable EPA test methods, EPA must issue a supplemental 

proposal identifying and soliciting comment on the information it seeks to collect. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 54

Comment: Any electronic report used to satisfy federal reporting requirements also must meet 

the requirements of the Cross-Media Electronic Reporting Rule, codified at 40 C.F.R. Part 3, 

including the requirement that the document include a valid electronic signature, as defined in 

the rule. EPA has made no attempt to explain how ERT or WebFIRE meet this requirement. 

UARG also is concerned regarding the ability of ERT to satisfy other criteria EPA deems 

necessary for valid electronic reporting, including whether (i) each electronic signature was a 

valid electronic signature at the time of signing; (ii) the electronic document cannot be altered 

without detection at any time after being signed; and (iii) each signatory had the opportunity to 

review in a human readable format the content of the electronic document that he or she was 

certifying to, attesting to or agreeing to by signing. See., e.g., 40 C.F.R. 3.2000(b)(5). In 

UARG’s experience, ERT satisfies none of these criteria. Especially troublesome is the inability 

of the responsible official to prevent revision of the information in ERT at or after the point of 

submittal. EPA cannot require sources to submit data using a mechanism that does not satisfy its 

own requirements for such submissions. Promises by EPA that these issues will be addressed by 

the time reports must be submitted are not sufficient to satisfy EPA’s obligations under the CAA 

to provide notice and opportunity for comment at the time of proposal. 
Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 55

Comment: UARG does not agree with EPA’s unsupported assertion that the information 

required to be submitted under ERT to WebFIRE will benefit EPA and sources by improving 

emission factors. EPA has yet to explain in any detail how the process of emission factor 

development from performance test data submitted to WebFIRE will work. In its comments on 

the ANPR, UARG expressed concerns about the process EPA described and objected to any 

attempts to mandate submission of reports before EPA had more completely explained its plans, 

completed any necessary rulemakings, and made operational its website. UARG reiterates those 

points here. EPA should not be promulgating requirements intended to support a larger program 

piecemeal before that program has been fully developed. See, e.g., UARG Petition for 

Reconsideration of Portions of Final Standards for Coal Preparation and Processing Plants, EPAHQ-OAR-2008-0260 (Dec. 7, 2009) at 8-9 (incorporated by reference). [Footnote: EPA granted 

UARG’s request for reconsideration of the ERT/WebFIRE reporting requirement in Part 60, 

Subpart Y on March 3, 2010.] EPA should reserve the question of mandatory reporting to 

WebFIRE until it has resolved the questions raised in the ANPR. 

Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 80

Comment: The Requirement For ERT Reporting Should Be Removed. We believe that the 

requirement for ERT reporting should be removed. In the recent past, industry had many 

problems submitting Industrial Boiler MACT and CISWI ICR data using the ERT, and many 

problems with the tool continue to exist based on experience that utilities and testing firms are 

having trying to enter Utility Boiler MACT ICR data into the tool. Use of this tool will add cost 

and burden to the emissions testing requirements in this rule. Moreover, the tool does not replace 

a stack test report, but rather is an additional reporting burden, as permitting agencies will still 

require a hard copy stack test report with all supporting documentation. 

The ERT Is Not Workable. Below are a number of issues we and others have encountered with 

the ERT: 
- It is not intuitive and is difficult to use. 

- It is not set up to handle data from multiple stacks from the same source being tested at the 

same time. 

- It only allows for one intermittent leak check during a test run. Many stacks have more than 

two ports so the ERT should be set up to handle those scenarios rather than having to add leak 

check volumes together to come up with a total. 

- It is not set up to handle mixed blend calibration gases, which are extremely common. 

- The import tool is inadequate, as it does not have enough rows for long runs and often imports 

data in the wrong order. 

- The tool is not set up to handle blank corrections. 

- The tool is idiosyncratic slow to respond. 

- The tool seems to be designed only to work under the most ideal of test scenarios. The Agency 

should ask for comments on the format and uploading tool from individuals that encounter real 

world scenarios for testing to incorporate into future editions. 

- Revisions and updates to the ERT should be apparent so that users can make sure the version 

they are using is the most recent version available. 

Requiring use of the ERT will add time and cost to stack testing projects, as time will have to be 

spent entering the test data into the tool and then quality assuring the ERT output. We do not 

believe that this extra cost is included in EPA’s analysis. 

In addition, compliance tests are submitted to the state or local permitting agency for review and 

approval. At times, the agency provides comments to the regulated facility that adjusts the test 

results. In these cases, the information entered into the ERT at the time of the stack test would 

not match the final, state-approved emission test results. At a minimum, there needs to be a 

mechanism for the ERT data to be updated in these situations or a flag to indicate whether the 

report has been reviewed and approved by the permitting agency. Alternatively, EPA could 

require the permitting agency to enter the stack test results into the ERT once approved, rather 

than requiring facilities to enter the data. 

If use of the ERT is required in the final rule, EPA needs to develop a comprehensive ERT 

Guidance Manual that provides complete instructions with examples for: 

- All entries, including: 

- the various facility identification codes, and where to find them, 

- BDL instructions, 

- calibration instructions, 

- required attachments; 

- the “external” spreadsheets” that are used to import certain data into the ERT; and, 

- the “external spreadsheets” that are used for reporting test methods not currently supported by 

the ERT. 

Lastly, EPA should develop an “outreach” or “training” program that provides instructions for 

specific source categories and related parameters. Such efforts need to be readily-available, i.e., 

through presentations at relevant conferences/seminars, as well as web-based sessions 

(“webinars”). 
Response: Please see the Preamble for a discussion of the use and benefits of using an Electronic 

Reporting Mechanism.

Recordkeeping and Reporting: Streamlining NSPS

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 88

Comment: Proposed 63.11224(b) requires submission of an annual compliance report by March 

1 of each calendar year, including a description of any deviations and corrective action 

and records of the amounts and types of fuel use. Sources are already required to submit other 

reports to permitting agencies at other times of the year, so EPA should allow permitting 

authorities the option of streamlining compliance reporting so the facility can prepare one annual 

report that covers all air regulatory requirements. Alternatively, EPA could require area sources 

to maintain compliance records and only submit reports upon request. 

Response: See response to DCN EPA-HQ-OAR-2006-0790-1923.1, excerpt number 6.

Commenter Name: Charles B. Jones, III

Commenter Affiliation: Georgia Traditional Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1923.1

Comment Excerpt Number: 6

Comment: EPA should eliminate the duplicative and unnecessary annual March 1 compliance 

report requirement for facilities that are already required to submit periodic compliance reports 

under an existing air permit (e.g., pursuant to Title V). 

Response: The requirement in section 63.11224(b) regarding annual compliance reports only 

required the preparation of the report by March 1 for the previous calendar year. The report was 

only required to be submitted if any deviation was experienced during the reporting period. 

Section 63.11224(b) [now 63.11225(b)] has been revised to clarify that the annual report, if no 

deviations occurred, only needs to be submitted upon request.

Other - Recordkeeping and Reporting Requirments

Commenter Name: Matthew Todd and David Friedman
Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 36

Comment: EPA should clearly demonstrate that resources exist for managing and evaluating an 

additional 100,000 plus stack tests per year. 

Response: In the final rule, the only existing area source boilers subject to emission limits are 

coal-fired. We estimate that there are about 3,700 existing area source coal-fired boilers.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 24

Comment: The EPA should clarify that reporting electronically to the EPA’s data base may not 

meet some state’s or other delegated authority’s reporting requirements and does not alleviate a 

source’s responsibilities from meeting those requirements. Delegated authorities may require 

different and/or additional information than what is required to be submitted to the EPA’s data 

base. 

Response: We agree that reporting electronically to the EPA’s data base may not meet some 

state’s or other delegated authority’s reporting requirements and that the requirement does not 

alleviate a source’s responsibilities from meeting those requirements. 

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 36

Comment: Some provisions also require approval in order to move forward. [Footnote: In 

several places, EPA uses the phrase submit for “approval upon request.” See proposed 

63.7505(d)(1) and 63.7522(g). It is not clear if EPA is referring to a source owner/operator’s 

request for approval, or a regulatory authority’s request for submission. EPA should revise these 

provisions to remove this ambiguous phrase.] Although the provisions generally establish a 

required time-frame for submittal, e.g., 60 days before the initial performance evaluation or 

compliance demonstration, the rules do not impose any deadline for a response by the 

Administrator, permitting authority, or regulatory authority. EPA should provide that timely 

submitted requests for approval are automatically approved after 30 days if no response is 

received. 
Response: This comment pertains to the major source boiler rulemaking. Provided the 

commenter has submitted this comment to the major source boiler rulemaking docket, the 

response to this comment will be provided there.

Health Based Compliance Alternatives

Other - Health Based Compliance

Commenter Name: Carl Johnson

Commenter Affiliation: Southern Pressure Treaters' Association

Document Control Number: EPA-HQ-OAR-2006-0790-0870.1

Comment Excerpt Number: 7

Comment: The health-based compliance option should be retained to prevent facilities from 

having to install unnecessary controls. 

Response: This comment pertains to the major source boiler rulemaking. Provided the 

commenter has submitted this comment to the major source boiler rulemaking docket, the 

response to this comment will be provided there.

Commenter Name: Los Angeles Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0397

Comment Excerpt Number: 36

Comment: Now, it’s probably never a good idea to complain about something without offering 

a solution. We suggest the use of a health risk analysis in lieu of the one-size-fits-all regulations 

that are proposed. 

Some years ago California enacted what is called the Air Toxics Hot Spots Program, the AB2588 

program, which requires a health risk analysis based on power plant emissions and toxics. This 

was done in California and a number of years ago. All biomass plants were suggested to the 

health risk analysis and all passed. We burn clean wood chips. Unfortunately, the category of 

fuel known as Construction and Demolition Wastes referred to as C and D, they’re looped 

together. 
Our plants take construction waste with clean cutoffs. Our permits prohibit painted or otherwise 

treated wood in our fuel plant. So demolition waste is generally completely ruled out. We would 

suggest that in lieu of either the Boiler MACT or the Area Source Rule for biomass power plants 

not burning waste but burning clean wood chip fuel, be subjected to a health risk analysis based 

on measured stack emission and accepted health risk methodologies. 

Response: In the final rule, standards for biomass-fired area source boilers are based on GACT, 

instead of the proposed MACT-based standards, and are subject to a management practice of a 

tune-up requirement.

Commenter Name: Arlington Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0396

Comment Excerpt Number: 54

Comment: EPA has the Clean Air Act authority through the 112(d)(4) to formulate MACT rules 

using a health threshold approach that would provide flexibility for sources while also ensuring 

the protection of public health. There is precedent for using that approach, and CIBO urges EPA 

to include that approach as a means to provide acid gas control in a cost-effective manner. 

Response: This comment pertains to the major source boiler rulemaking. Provided the 

commenter has submitted this comment to the major source boiler rulemaking docket, the 

response to this comment will be provided there.

Commenter Name: Duane C. Feagley

Commenter Affiliation: Pennsylvania Anthracite Council

Document Control Number: EPA-HQ-OAR-2006-0790-1052.1

Comment Excerpt Number: 2

Comment: EPA should allow facilities to demonstrate that emissions of certain pollutants do not 

pose a public health concern. A practical health oriented standard for threshold pollutants like 

hydrogen chloride and manganese would allow sources to demonstrate their emissions of these 

compounds pose no adverse risk. The Clean Air Act in §112(d)(4), expressly contemplates the 

use of such an approach which can be implemented without sacrificing risk reduction benefits. A 

health threshold standard is critical to the future viability of biomass and other boilers. EPA 

should make the health threshold standard an integral part of its final rule. 

Response: Under section 112(d)(4) of the Clean Air Act, the Administrator has discretionary 

authority to consider health oriented standard for threshold pollutants like hydrogen chloride and 

manganese. In the Boiler Area Source NESHAP, hydrogen chloride and manganese are not 

regulated under a MACT-based approach but under GACT-based approach.
Commenter Name: Allan Muller

Commenter Affiliation: Green Delaware

Document Control Number: EPA-HQ-OAR-2006-0790-1104

Comment Excerpt Number: 3

Comment: Stringent health-based and technology-based (MACT) requirements are urgently 

needed. 

Response: EPA thanks the commenter for their support.

Compliance

Fuel Switching Compliance

Commenter Name: Alicia Oman

Commenter Affiliation: National Association of Manufacturers

Document Control Number: EPA-HQ-OAR-2006-0790-2234.1

Comment Excerpt Number: 26

Comment: While owners and operators may seek to conduct testing at reasonable worst case 

conditions to assure compliance during less rigorous conditions, it is entirely possible that 

operations during less rigorous conditions could nevertheless accommodate variation that would 

not threaten compliance with the standard, but nevertheless could be relevant when the data are 

used to set standards on a pollutant-specific basis rather than a unit-specific basis. As a 

hypothetical example, the most rigorous testing condition for HCl emissions from a given boiler 

might be a feed with high halide content. Thus, it would be logical for testing to be performed 

under these conditions. However, other HAP constituents in the feed – such as metals – would 

not necessarily be at “worst case” levels during testing focused on halides. In this scenario, the 

testing might show extremely low levels of metals emissions, which would not necessarily 

reflect the higher levels of such emissions that might occur during normal operations. 

Response: As discussed in the comment above, HCl is not relevant to the area source standard. 

Provided the commenter has submitted this comment to the major source boiler rulemaking 

docket, the response to this comment will be provided there. Worst-case mercury conditions only 

apply for mercury at units that are subject to a numeric emission limit.

Sources must test under conditions that are representative of the source’s ability to comply 

continuously with the emission standards. If the source believes that conditions at maximum 

normal operating load are not reflective of conditions that most challenge the source's ability to 
comply, they may specify what other conditions are more reflective of continuous compliance in 

their test plan, as required under the General Provisions at 63.7(c). Further. the regulations have 

been amended to clarify that you must conduct performance stack tests at the maximum normal 

operating load while burning the type of fuel or mixture of fuels that has the highest content of 

particulate matter, as well as mercury. We have also added the clarifying language to the area 

source rule that is proposed in the analgous section of the Boiler MACT rule, What Stack Tests 

and Procedures must I use for the Performance Tests, which indicates that these requirements 

could result in the need to conduct more than one performance test.

Commenter Name: Arthur N. Marin

Commenter Affiliation: Northeast States for Coordinated Air Use Management, NESCAUM

Document Control Number: EPA-HQ-OAR-2006-0790-2137.1

Comment Excerpt Number: 25

Comment: EPA has not provided a clear definition as to what constitutes new fuel. Unlike liquid 

fuels and coal, most biomass fuels are inherently inhomogeneous. For example, does a wood 

chip facility need to test for Hg and HCl for every new load or new supplier of fuel? As 

proposed, the language is unclear as to when a facility must conduct a test to show compliance 

with emission limits when fuel switching occurs, or the frequency of this testing. NESCAUM 

recommends that EPA clarify this rule to require testing upon use of a new fuel. Additionally, 

NESCAUM recommends that EPA not require facilities burning biomass to conduct fuel testing 

on each new load of biomass nor when a facility switches biomass fuel suppliers. 

Response:

Biomass fuels encompass a broad range of materials which as the commenter points out are not 

all homogeneous. Biomass encompass a broad range of materials which as the commenter points 

out are not all homogeneous. The term biomass encompasses cellulosic biomass such as forestderived biomass, sawdust, wood chips, bark, bagasse, biomass crops used specifically for energy 

production, clean wood found in disaster debris, and resinated wood products. Whereas a switch 

in the source of wood chips would not constitute a new fuel, a switch from wood chips to a 

nonwood biomass, such as bagasse should be considered a switch in fuel given the differing 

physical and chemical characteristics of wood as compared to the nonwood biomasses. Note that 

the definition of fuel type does not classify individual fuel types received from different suppliers 

as new fuels.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 40

Comment: Proposed §63.11221(a)(3)(ii) requires a new performance test within 60 days of 

burning a new fuel if the fuel mercury level is higher than previous fuel’s mercury levels. 
However, 60 days is too short a period to do a performance test. Typically, 120 to 180 days is 

needed to plan and schedule a performance test and to meet the legal requirements in §63.7 

associated with performance tests. In particular, significant time is needed to comply with §63.7 

requirements, such as the requirement in §63.7(b) for a notice 60 days before the test and the 

§63.7(c) test plan and QA/QC requirements. 

Additionally, §63.11221(a)(3) should be limited to only coal-fired boilers, since they are the only 

boilers with mercury limits. It makes no sense to require mercury performance tests for biomassor liquid-fired boilers, where mercury emissions are not regulated. 

Response: Section 63.11221(a)(3) requires a fuel analysis of mercury concentrations only if 

there is an applicable mercury emission limit. Therefore, no fuel analysis for mercury is required 

if there is no applicable limit. Testing of a fuel under §63.11221(a)(3)(ii) is not required for 60 

days after you start burning the new fuel, whereas the fuel analysis that may trigger the 

requirement to test, is required during the planning stages, see §63.11221(a)(3): if you have you 

have an applicable mercury emission limit and you plan to burn a new type of fuel, then you 

must determine the mercury concentration. The results of this fuel analysis conducted during the 

planning stage, prior to the date you start to fire the fuel, will determine whether a performance 

test is necessary. The availablility of this time period before the source starts to fire the fuel is 

when the source needs to make plans for scheduling a test and may start on providing the 

notifications and test plan procedures in §63.7.

Commenter Name: Kevin F. Biernacki

Commenter Affiliation: Veolia Energy North America

Document Control Number: EPA-HQ-OAR-2006-0790-2273

Comment Excerpt Number: 11

Comment: We recommend including language to the applicability section for units that are 

permitted to fire fuel oil, but have not fired that fuel recently. Requiring boilers that are permitted 

to fire a fuel that is regulated under this proposed rule, but historically only fires natural gas 

should not be required to show compliance with this rule. Instead, an ongoing analysis should be 

performed to determine whether the gas fired boiler definition is no longer satisfied (e.g. the 

boiler would satisfy the oil subcategory and would be subject to the role at a later date). Under 

this situation additional timelines for existing boilers would need to be included within the 

regulation. 

Response: Please see preamble for how comment is addressed.

Commenter Name: Barry Christensen

Commenter Affiliation: Occidental Chemical Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2227.1

Comment Excerpt Number: 20
Comment: EPA should allow postponement of stack testing if it is not possible to burn 

alternative fuels. Three of our sites are permitted to burn fuel oil, but they do not necessarily 

have it onsite. A mechanism to request an extension for conducting the performance test should 

be available in the final rule. If the price of natural gas rises dramatically, to the point that it 

becomes a business decision to burn fuel oil, we would then be in a position to conduct the 

compliance test with fuel oil. 

Response: The facility is responsible for demonstrating that they are able to continuously 

comply with the emissions limits when operating under expected operating conditions. Existing 

sources are given 3 years to come into compliance and another 180 days to stack test. This 

should be sufficient time to acquire a sample of the fuels to be burned for a stack test. If a stack 

test does not represent the range of combined process and control measure conditions under 

which the facility expects to operate, the delegated agency may determine that retesting is 

warranted.

Switching Subcategories

Commenter Name: Renee Lesjak Bashel

Commenter Affiliation: Small Business Environmental Assistance Programs, SBEAP

Document Control Number: EPA-HQ-OAR-2006-0790-2195.1

Comment Excerpt Number: 14

Comment: Recommendation: Clarify the requirements or consequences in the event a company 

switches fuel to natural gas at any point, including after the compliance deadline for the final 

rule. 

There should be a clear statement about whether sources can be allowed completely out of the 

rule requirements should they completely change to natural gas at any point. 

Response: Consistent with the fuel switching procedures added to the regulations at 63.11225, a 

source may switch fuels, and this fuel switch may result in the applicability of a different 

subcategory, a different regulatory program (a switch to Section 129 if solid waste is 

combusted), or, in the example the commenter provides, a switch out of the Area Source MACT 

due to a switch to 100% natural gas. A source subject to the Area Source MACT that intends to 

make a switch to 100% natural gas is required to submit a 30 day advance notification of fuel 

switch, which will identify the effective date of the fuel switch, meaning in this case, the date on 

which the Area Source MACT is no longer applicable.

Commenter Name: Robert R. Scott

Commenter Affiliation: New Hampshire Department of Environmental Services

Document Control Number: EPA-HQ-OAR-2006-0790-1952.1
Comment Excerpt Number: 11

Comment: NHDES also considers the approach of categorizing boilers based on one primary 

fuel type to be problematic for enforceability. Boilers today are often configured to run on 

multiple fuels and the percentage of any one particular fuel over another can be based in part on 

the cost of each fuel. Therefore, a boiler that would be considered part of one sub-category based 

on the previous year’s annual heat input could be operating under an entirely different fuel 

loading scenario the following year. Also, without detailed requirements for tracking, 

recordkeeping and reporting, the 10% annualized usage number would be difficult for 

enforcement staff to verify. For example, if a biomass boiler co-fired with oil were to perform a 

stack test for CO, it would be required to meet the 100 ppm (@7% 0?) standard even if during 

the stack test it burned 99% oil, simply because it burned any amount of biomass. Since a 

precedent has been set in 40 CFR 60 with establishing emission limitations based on a weighted 

average between different fuel types, NHDES recommends that EPA provide this same 

mechanism in order to determine the applicable emission limitations for multi-fuel fired boilers. 

As an alternative, EPA could clarify in the regulation that if a device is operating under a dual 

fuel scenario, the device must comply with the lowest emission limit for each fuel burned. 

However, NHDES is concerned that by requiring multi-fuel fired units to comply with the lowest 

emission limit for each fuel type burned, this proposal would inadvertently push units into fuel 

switching situations that may result in boilers being required to meet more lenient standards. 

Therefore, NHDES also recommends that EPA encourage fuel switching not between solid and 

gaseous fuels but between "dirtier" and "cleaner" burning forms of the same fuel. 

Response: Consistent with the fuel switching procedures added to the regulations at 63.11225, a 

source may switch fuels, and this fuel switch may result in the applicability of a different 

subcategory, a different regulatory program (a switch to Section 129 if solid waste is 

combusted), or, in the example the commenter provides, a switch out of the Area Source MACT 

due to a switch to 100% natural gas. A source subject to the Area Source MACT that intends to 

make a switch to 100% natural gas is required to submit a 30 day advance notification of fuel 

switch, which will identify the effective date of the fuel switch, meaning in this case, the date on 

which the Area Source MACT is no longer applicable. 

Commenter Name: Debra J. Jezouit

Commenter Affiliation: The Class of '85 Regulatory Response Group

Document Control Number: EPA-HQ-OAR-2006-0790-1986.1

Comment Excerpt Number: 3

Comment: Additionally, the Group supports EPA’s decision to allow natural gas-fired Boilers to 

combust liquid fuel during periods of natural gas curtailment without triggering requirements 

under section 112. Periods of curtailment are unpredictable, infrequent, and completely beyond 

the control of a facility. These periods are akin to an emergency situation. Using liquid fuel 

during periods of curtailment in no way signals that a facility intends to "switch" fuels such that 

the Boiler would warrant regulation under section 112. 
Response: EPA thanks the commenters for their support on how gas-fired boilers are defined in 

the final rule.

Common Stack Provision

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 20

Comment: For facilities with a common stack and multiple emission units and/or types of 

emission units exhausting through a common stack there may be certain technical circumstances 

that would not allow for a CEMS installation considering the available location(s) would not 

satisfy the 40 CFR 60 installation recommendations and may not yield representative emissions 

data due to stratification problems. In addition, if stack structural improvements are required to 

install CEMS whether the stack is dedicated to a single combustion unit or is a common stack, 

would those improvements be required or would an alternative compliance method be allowed? 

Response: Oxygen monitors must be installed, operated, and maintained according to the 

applicable procedures under Performance Specification (PS) 3 of 40 CFR part 60, appendix B, 

and according to the site-specific monitoring plan developed for the rule. EPA understands that 

CEMS installation may require some engineering planning and perhaps modifications (e.g., 

multiple sampling probes and sample mixing) to assure a representative sample collection. We 

believe that the procedures provide sufficient flexibility to satisfy most, if not all, applications.

Compliance Dates

Commenter Name: David Meierhenry

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-0414.1

Comment Excerpt Number: 3

Comment: A biennial tune-up is required for boilers <10MMBtu/hr, as described in section 

IV.C of the preamble and specified in 63.11210(d) and Table 2. A tune-up every two years is not 

unreasonable but 63.11196(a) allows a three year compliance schedule. There is no 

environmental benefit and little benefit to the boiler owner/operator in delaying the initial tuneup for three years. The compliance schedule for the initial tune-up should be changed to two 

years after publication of the rule. 
Response: We agree and have revised 63.11196(a) to add the requirement that boilers subject 

to the tune-up requirement must achieve initial compliance within one year after publication.

Commenter Name: N/A

Commenter Affiliation: Mercatus Center, George Mason University

Document Control Number: EPA-HQ-OAR-2006-0790-1837.1

Comment Excerpt Number: 9

Comment: EPA might approach the uncertainty surrounding benefits by phasing in standards 

slowly. The portions of the rule expected to generate the greatest or most certain benefits should 

be phased in first, allowing the EPA to collect data on the performance of the rule and structure 

future rulemakings accordingly. 

Response: We agree and have revised 63.11196(a) to add the requirement that boilers subject 

to the tune-up requirement must achieve initial compliance within one year after publication.

Commenter Name: Stephen E. Woock

Commenter Affiliation: Weyerhaeuser Company

Document Control Number: EPA-HQ-OAR-2006-0790-1984.1

Comment Excerpt Number: 16

Comment: EPA does not address in this proposed rule, nor in any of the three related 

concurrently-propose CAA and RCRA rules, the timing of when a facility must stop burning a 

fuel that under the final non-hazardous secondary materials solid waste definition rule would be 

determined to be a solid waste, to avoid subjecting the air emissions source to the incinerator 

rule. We request EPA address this question in the rulemaking or guidance, and suggest the first 

significant compliance date of the area source rule or Boiler MACT to be the proper timing. For 

sources subject to an existing MACT rule (e.g. PCWP MACT) that combust a fuel that becomes 

a solid waste by regulatory definition, we recommend the date to be when the source renews its 

Title V air permit after the incinerator rule guidelines become effective in the State where the 

source is located. 

Response: Under the General Provisions [63.9(B0(2)] owners and operators of affected sources 

must submit the Initial Notification within 120 days after publication of the rule. We have added 

63.11196(d) to the final rule that addresses this comment. 

Commenter Name: James P. Brooks

Commenter Affiliation: Maine Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2006-0790-1915.1

Comment Excerpt Number: 18
Comment: Due to the broad scope of both the Area and Major Source Boiler MACTs, there will 

be significant demand for stack testing and installation of monitoring and control equipment. The 

Maine DEP is concerned that there will an insufficient supply of qualified testing companies to 

meet this demand within the proposed timeframes. We recommend that EPA allow one year for 

facilities to conduct initial compliance testing instead of the proposed 180 day period. We are 

also concerned that existing sources will be unable to install the necessary control and 

monitoring equipment within three years. There will be high demand and limited supply for the 

required equipment, and many facilities will need to undertake significant designing, planning 

and construction to locate the equipment within the existing facility. We recommend that EPA 

establish a compliance date five years from the date the final rule is published. 

Response: The EPA disagrees with the commenters that the 3-year compliance deadline is too 

short considering the number of sources that will be competing for the resources and materials 

from engineering consultants, equipment vendors, construction contractors, financial institutions, 

and other critical suppliers. However, we know that many sources will not need to install 

controls. As a result, since not everyone will need more than 3 years to actually install controls, 

the final rule does not allow an extra year for existing sources to comply with the final rule. 

Section 112(i)(3)(B) allows EPA, on a case-by-case basis to grant an extension permitting an 

existing source up to one additional year to comply with standards if such additional period is 

necessary for the installation of controls. The EPA feels that this provision is sufficient for those 

sources where the 3-year deadline would not provide adequate time to retrofit as necessary to 

comply with the requirements of the standard.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 22

Comment: Because of the short time between proposal (June 4, 2010) and the Court Ordered 

finalization of this rule (December 16, 2010) and the long delivery and construction times for 

CEMS and controls it is impossible for boilers that begin construction within a year or two after 

proposal to install controls or CEMS by the date this proposal is finalized or startup. The 

delivery times for equipment required by this regulation are likely to be greatly extended beyond 

normal deliveries, because of the massive number of units being impacted by these three 

rulemakings, all requiring equipment within the first three years after promulgation. EPA should 

provide up to three years (or 5 years if 5 years is provided for existing sources, as requested in 

our next comment) from the final rule publication for any boiler to come into compliance with 

any requirement involving facilities installation. 

It is apparent that, even with the changes suggested in these comments, owners and operators 

will be required to retrofit countless industrial boilers and process heaters in order to meet the 

final rule. The proposal would set a three-year compliance deadline for existing affected sources. 
However, this is an exceedingly short time given the extensive nature of the needed retrofits and 

the limited technical resources available to accomplish the retrofits (especially in light of the fact 

that area source boiler owners will be competing for equipment and technical resources with 

major sources and other key industry sectors such as the utility sector, which will have a similar 

compliance deadline for the utility MACT and also will be required to install substantial air 

pollution controls to meet the proposed Clean Air Transport Rule). 

To solve this problem, EPA must adopt a significantly longer compliance deadline. Nominally, 

EPA should adopt by rule an across-the-board one-year extension pursuant to §112(i)(3)(B) for 

any unit subject to an emission limit. However, even a four-year compliance period will be 

inadequate for many affected sources. Therefore, EPA should provide additional time by: (1) 

granting in the final rule a Presidential extension under §112(i)(4), given that it is in the “national 

security interests of the United States” to prevent widespread noncompliance in the industrial 

base; (2) declaring that the statutory three-year compliance period is impossible to meet or 

otherwise produces “absurd results,” which as demonstrated in EPA’s recent PSD Tailoring Rule 

are doctrines that allow EPA to depart from clear statutory directives in appropriate 

circumstances; and/or (3) establishing phased or sequenced requirements such that certain 

element of the rule become effective no later than three years after promulgation (thus satisfying 

§112(i)(3)(A)), while others are phased in at later times. EPA should provide up to five years for 

any unit subject to emission limits to comply with this rule. 

Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18.

Commenter Name: Ronald W. Gore

Commenter Affiliation: Alabama Department of Environmental Management

Document Control Number: EPA-HQ-OAR-2006-0790-1494.1

Comment Excerpt Number: 4

Comment: Given the stringency of many of the emission limitations listed in the proposed rule, 

the Department is concerned that many facilities may not have sufficient time to engineer and 

design the emissions control systems, raise the amount of capital to purchase the equipment, and 

install the required equipment. In addition, there could be hardware backlogs and/or insufficient 

skilled labor, which could delay compliance. The Department asks that the Agency consider a 

lengthy compliance timeline which would allow facilities to achieve compliance within practical 

timelines. 

Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18. In 

addition, the final rule has been revised such that only existing coal-fired area source boilers are 

subject to emission limits which may require the installation of control devices.

Commenter Name: Kevin F. Biernacki
Commenter Affiliation: Veolia Energy North America

Document Control Number: EPA-HQ-OAR-2006-0790-2273

Comment Excerpt Number: 6

Comment: If capital improvements are necessary to show compliance with this regulation, we 

are concerned that the 3 year time frame to illustrate compliance is not adequate. Importantly, 

capital improvements may include upgrades to burners and/or add-on controls to show 

compliance with emission limits to stack structural improvements for CEMS installation on older 

boilers. 

If capital improvements are required (e.g. burner upgrades, add-on controls, stack structural 

improvements for CEMS installations...) and cannot be implemented within the 3 years currently 

required within the proposed regulation, an implementation plan would be required to be 

submitted within the initial 3 year time frame outlining a compliance timeline that must be 

completed within an additional 3 year time frame. This request is being made because under 

certain circumstances difficult and timely burner studies may be required to optimize 

NOx/CO/opacity emissions concurrently; add-on controls installation and/or stack structural 

improvements in older facilities will not be trivial. 

Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 8

Comment: If capital improvements are necessary to show compliance with this regulation we 

are concerned that the 3 year time frame to illustrate compliance is not adequate. Importantly, 

capital improvements may include upgrades to burners and/or add-on controls to show 

compliance with emission limits to stack structural improvements for CEMS installation on older 

boilers. 

Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 9

Comment: Include a discussion within the regulation that acknowledges the fact that capital 

improvements may be necessary under certain circumstances to satisfy certain requirements 

within this regulation (e.g. emission limits, CEMS installations...). If capital improvements are 
required (e.g. burner upgrades, add-on controls...) and can not be implemented within the 3 years 

currently required within the proposed regulation, an implementation plan would be required to 

be submitted within the initial 3 year time frame outlining a compliance timeline that must be 

completed within an additional 3 year time frame. This request is being made because under 

certain circumstances difficult and timely burner studies may be required to optimize 

NOx/CO/opacity emissions concurrently; add-on controls installation and/or stack structural 

improvements in older facilities will not be trivial. 

Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18.

Commenter Name: Edward J. Wilusz

Commenter Affiliation: Wisconsin Paper Council

Document Control Number: EPA-HQ-OAR-2006-0790-2133

Comment Excerpt Number: 17

Comment: It is apparent that owners and operators will be required to retrofit countless 

industrial boilers and process heaters in order to meet the final rule. The proposal would set a 

three-year compliance deadline for existing affected sources. However, this is an exceedingly 

short time given the extensive nature of the needed retrofits and the limited technical resources 

available to accomplish the retrofits (especially in light of the fact that industrial boiler owners 

will be competing for equipment and technical resources with other key industry sectors such as 

the utility sector, which will have a similar compliance deadline for the utility MACT and also 

will be required to install substantial air pollution controls to meet the proposed Clean Air 

Transport Rule). 

To solve this problem, EPA must adopt a significantly longer compliance deadline. Nominally, 

EPA should adopt by rule an across-the-board one-year extension pursuant to § 112(i)(3)(B). 

However, even a four-year compliance period will be inadequate for many affected sources. 

Therefore, EPA should provide additional time by: (1) granting in the final rule a Presidential 

extension under § 112(i)(4), given that it is in the “national security interests of the United 

States” to prevent widespread noncompliance in the industrial base; (2) declaring that the 

statutory three-year compliance period is impossible to meet or otherwise produces “absurd 

results,” which as demonstrated in EPA’s recent PSD Tailoring Rule are doctrines that allow 

EPA to depart from clear statutory directives in appropriate circumstances; and/or (3) 

establishing phased or sequenced requirements such that certain element of the rule become 

effective no later than three years after promulgation (thus satisfying § 112(i)(3)(A)), while 

others are phased in at later times. 

Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy
Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 23

Comment: EPA proposes to set the compliance deadline for existing affected sources at three 

years after the date of publication of the final rule in the Federal Register. Duke Energy believes 

this provides an inadequate amount of time for the thousands of affected sources to be retrofit as 

necessary to meet the new MACT standards. When finalized, EPA estimates that under the 

alternative solid waste definition, the MACT standards will apply to the existing fleet of 525 coal 

units, 239 biomass units, 791 liquid fired units and 11,524 gas fired units. The capital costs will 

fall predominately to those industries which have solid fuel-fired, i.e., predominantly coal-fired, 

and bio-mass units. In order to meet the MACT standards, these owners will, by and large, have 

to install add-on controls. According to Table 9, out of a total of 13,079 existing units that will 

require controls, 764 are solid fuel fired, or about 6% of the total. 

Duke Energy anticipates that industry will face severe time and material constraints that will 

make it extremely difficult, if not impossible, for many facilities to meet the retrofit deadline of 

three years. Most of the targeted solid fuel-fired units are located at facilities that will have to 

undergo substantial re-engineering, e.g., due to space constraints, to accommodate new controls. 

Design, procurement, installation, and shakedown of these projects will easily consume three 

years. In short, more time is needed. Moreover it is inevitable that many existing boilers will be 

forced to convert to an alternative fuel such as natural gas, or even construct entirely new boilers. 

According to its rulemaking to date, EPA has not adequately considered these factors. 

External factors will also jeopardize compliance within three years. A large number of 

companies will be competing nationwide for limited resources and materials from engineering 

consultants, equipment vendors, construction contractors, financial institutions, and other critical 

suppliers. It is likely many companies will find themselves unable to procure the necessary 

goods and services to complete the retrofitting of their affected units within three years. In 

particular, Duke Energy is concerned about sources being able to procure bag houses and 

scrubbers because immediate industry demand will outstrip immediately available supplies. 

EPA must also realize that these retrofits will not occur in a vacuum. Because of EPA’s recently 

proposed Transport Rule and the forthcoming Utility MACT Rule, a large amount of retrofits 

will occur at the same time sources are attempting to meet the requirements of the Industrial 

Boiler MACT. Since many industrial boilers and process heaters can be relatively small sources, 

it is plausible that they will suffer from lower priorities compared to larger utility boilers. 

Industry must continue to operate as best as possible while retrofitting to meet the new MACT 

standards. In general, the existing solid fuel-fired boilers that will be subject to this new rule 

comprise the most critical part of the base load energy supply for their facilities. These units 

typically have high capacity utilization rates. Extensive outages for retrofitting must be carefully 

planned. Only when all of the critical prerequisites for the retrofit have been lined up, e.g., the 

engineering is complete and the control equipment is staged for immediate installation, can an 

owner afford to shut down a facility’s base load boiler to install the new controls. This will take 

careful planning and coordination both within the company and outside the company that will 

involve with engineering consultants, equipment vendors, and construction contractors. Duke 

Energy does not believe three years is sufficient to allow owners of many of the affected sources 

the time necessary to make the retrofits without substantial disruption to the operation of their 

facilities. 
Duke Energy recommends EPA address the foregoing problems by extending the compliance 

deadline to four years after the publication of the final regulations in the Federal Register. Duke 

Energy believes that the Agency would be fully justified in invoking 112(i)(3)(B) of the Clean 

Air Act to grant owners of all affected sources a one year extension of the compliance deadline. 

Four years would provide critically needed time for industry to conduct the necessary retrofitting 

with controls and absorb the great cost of these retrofits. Given the magnitude of the retrofit 

requirements and the likelihood of substantial difficulties fulfilling these requirements, it is 

essential that EPA provide all the flexibility within their authority. The one year compliance 

extension authorized by the Act is a legitimate and necessary solution to this problem, and Duke 

Energy urges EPA to incorporate a general one year compliance extension for existing affected 

sources in the final BPH MACT rule. In addition EPA must clearly articulate the conditions 

under which a source is eligible for this extension at the time that the rule is finalized. If it is 

uncertain that a source can qualify for an extension or it must go through an uncertain regulatory 

approval process, there is no way a source can effectively factor that extension into its planning 

process and risk possible noncompliance. Duke Energy supports giving this extension to all 

sources that actually install controls to attain compliance. 

Response: This comment pertains to the major source boiler rulemaking. Provided the 

commenter has submitted this comment to the major source boiler rulemaking docket, the 

response to this comment will be provided there.

Commenter Name: Chelly Reesman

Commenter Affiliation: JR Simplot Company

Document Control Number: EPA-HQ-OAR-2006-0790-2244

Comment Excerpt Number: 3

Comment: Within 3 years after the implementation of the proposed regulation, an affected 

source must achieve compliance with the applicable provisions in the rule. 

It is anticipated that compliance will require installation of additional control equipment which in 

turn requires, capital equipment budgeting, design, selection, manufacturing time for the control 

equipment, and possibly air permitting. It is unclear that it is possible to achieve compliance 

within 3 years. In particular, obtaining any necessary air permits in a timely matter has been an 

ongoing issue in a number of areas where Simplot does business in the United States. 

Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18.

Commenter Name: Robert Thornton

Commenter Affiliation: International District Energy Association

Document Control Number: EPA-HQ-OAR-2006-0790-2169.1

Comment Excerpt Number: 5
Comment: Given both the significant cost for design and construction of facilities to meet the 

standards and the current constraints on access to capital (particularly for colleges, universities 

and other institutions), the three year deadline for compliance will be onerous. 

Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18.

Commenter Name: Eric Trauner

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2286

Comment Excerpt Number: 7

Comment: The date for compliance should be set at five years, not three. By definition, there 

will be facilities that will not be able to comply with this MACT. Intelligent consideration of 

compliance options in such cases has many steps, each taking several months. For instance, it 

will take several weeks for a facility to review the final MACT and develop a compliance plan. 

A likely first step in such a compliance plan would be evaluation of current status, likely by stack 

testing. Because there are in fact a limited number of stack testers genuinely qualified to execute 

such work, even this seemingly simple step of compliance determination will take several 

months (as US-EPA has recently learned). Then, a review of compliance options in terms of 

engineering and economics will also take several months to a year. Hard engineering design can 

take an additional year or longer, followed by what could well be two years for acquisition of 

equipment, installation, and start-up/ shakedown, with a final official stack test. A sound 

compliance effort cannot be completed in three years. 

Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18.

Commenter Name: Christy Sammon

Commenter Affiliation: Southeastern Lumber Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1954.1

Comment Excerpt Number: 18

Comment: The Agency should provide for an extended compliance period. 

Given the tens of thousands of boilers that will have to be controlled as a result of these rules, it 

is unlikely that the capacity of existing vendors, contractors, engineers, and state regulatory 

personnel is sufficient to allow completion of all of the required modifications in a 3-year time 

period, or even a 4-year time period if facilities were granted a 1-year extension. EPA should 

evaluate all of the necessary capabilities and establish a compliance period based upon that 

evaluation. 

Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18.
Commenter Name: Alicia Oman

Commenter Affiliation: National Association of Manufacturers

Document Control Number: EPA-HQ-OAR-2006-0790-2234.1

Comment Excerpt Number: 37

Comment: EPA proposes to set the compliance deadline for existing affected sources at three 

years after the date of publication of the Final Rule in the Federal Register. It will be 

extraordinarily difficult – if not impossible – for all of the entities with existing boilers to make 

the changes necessary to comply with this rule in the three year timeframe that EPA proposes. 

Put simply, the normally herculean task of performing a boiler retrofit in three years will be 

made impossible by the enormous competition for critical resources and the likely gridlock in 

many state permitting processes that the broad application of this rule will create. Many boiler 

owners will be simply unable to secure equipment and assistance and/or to obtain the state/local 

permits needed to retrofit their units within three years. 

Even under the best of circumstances, a major retrofit of a boiler takes years from project start to 

finish. EPA has estimated that the installation of an activated carbon injection control system on 

one combustion unit – a comparatively simple installation – takes about 15 months. [Footnote: 

EPA, Engineering and Economic Factors Affecting the Installation of Control Technologies for 

Multipollutant Strategies (2002).] However, EPA expects a range of control devices will be used 

to meet the standards, including fabric filters, carbon bed adsorbers, activated carbon injection, 

electrostatic precipitators, wet scrubbers, replacement burners, and combustion controls. 

[Footnote: EPA, Regulatory Impact Analysis: National Emission Standards for Hazardous Air 

Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters, 3-1 (April 

2010) (“The control analysis considered fabric filters, carbon bed adsorbers, and activated carbon 

injection to be the primary control devices for mercury control, electrostatic precipitators for 

units meeting mercury limits but requiring additional control to meet the PM limits, wet 

scrubbers to meet the HCl limits, tune-ups, replacement burners, and combustion controls for CO 

and organic HAP control, and carbon injection for dioxin/furan control.”)] Further, the sheer 

number of boilers impacted by the rule will make finding – and then scheduling – the design and 

construction resources almost impossible. EPA estimates that there are approximately 13,555 

units located at 1,608 facilities covered by this rule. 75 Fed. Reg. 32048. Given that EPA has set 

emissions standards that no existing unit can meet, every single existing unit subject to an 

emission standard may need to be retrofitted. Boiler owners will need to hire consultants to assist 

them in designing and performing the retrofit. Thus, across the multitude of industries impacted 

by this rule, boiler owners will be competing for qualified consultants to design, permit and 

perform the retrofits necessary to make boilers compliant with this stringent rule. There are only 

a limited handful of consulting companies with the expertise to assist in such retrofits, and they 

will likely be unable to assist all of the boiler owners in less than three years. There will be a 

similar scarcity in equipment vendors, construction contractors, construction equipment (e.g, 

heavy lifting cranes), skilled labor (e.g., boilermakers), and other critical suppliers. Companies 

may even be unable to secure the basic building materials and control equipment (e.g., 

baghouses and scrubbers). 
Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18.

Commenter Name: Alicia Oman

Commenter Affiliation: National Association of Manufacturers

Document Control Number: EPA-HQ-OAR-2006-0790-2234.1

Comment Excerpt Number: 38

Comment: EPA should extend the compliance deadline given the breadth of sources and 

competition for resources. 

In order to retrofit a boiler, the owner will need to line up the capital necessary to pay for the 

retrofit. In these difficult economic times, just securing the necessary capital may take months, if 

not years. In addition, the owner will need to go though the relevant permitting process(es), 

which will similarly take months, if not years. Finally, once the finances are secure and the 

permitting is complete, the owner will actually need to perform the retrofit. The design, 

procurement, installation, and shakedown of a retrofit project (e.g., installing a scrubber on a 

large boiler) can easily take more than three years. 

In addition, the timing of the retrofit work needs to be carefully planned, particularly for boilers 

that provide the primary and/or base load energy supply for their facilities. A facility owner will 

only shut down a boiler when everything is properly staged to ensure minimal disruption of the 

facility’s operation. In addition to ensuring that the design work is completed and the control 

equipment and other supplies are on-site and ready for installation, the facility owner needs to 

make sure that the full suite of consultants and laborers are available for the installation. Based 

on a discussions with a number of potentially affected companies, the turnaround or shutdown 

cycles for boilers at many of the facilities is so long as to make this type of precise staging 

exceedingly difficult to do in a three year period without substantial business interruption. 

Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18.

Commenter Name: Alicia Oman

Commenter Affiliation: National Association of Manufacturers

Document Control Number: EPA-HQ-OAR-2006-0790-2234.1

Comment Excerpt Number: 39

Comment: In many instances, the installation of pollution control equipment and associated 

charges to boiler must be permitted under state air pollution statutes and/or construction codes 

(building permits, etc.). The proposed rule will result in an increase in the number of permit 

applications, potentially swamping the state and local agencies. Even in those areas where the 

rule may not result in significant increases in permitting work, the normal delays associated with 

permitting may make meeting the three year compliance deadline impossible. 
In light of the difficulty in meeting a three year compliance deadline, EPA and authorized states 

should be prepared to readily grant one-year extensions under CAA § 112(i)(3)(B) to those units 

that have problems installing the necessary control equipment to comply with the industrial 

Boiler MACT rule. 

Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18.

Commenter Name: Alicia Oman

Commenter Affiliation: National Association of Manufacturers

Document Control Number: EPA-HQ-OAR-2006-0790-2234.1

Comment Excerpt Number: 40

Comment: EPA should establish an extended two-step compliance period for situations where a 

boiler owner voluntarily elects to replace or retrofit a boiler to burn a cleaner fuel source. 

[Footnote: EPA recognizes the MACT rule should be crafted to encourage the use of cleaner 

fuels, such as natural gas. 75 Fed. Reg. 32025.] If a facility decides to switch to a cleaner fuel, 

the replacement or retrofit work required to make that switch will potentially take years, for all 

of the reasons discussed above. Rather than require the facility to add emissions controls to its 

existing boiler in time for the proposed three year compliance deadline – likely eliminating the 

possibility that the facility would switch to a cleaner fuel source – EPA should allow six years 

total for facilities to change their boilers and meet the MACT requirements for the cleaner fuel 

source. This six year period would occur in two steps; a no-backsliding provision would apply 

for three years from publication of the rule in the Federal Register, and then the facility would 

have three years to comply with MACT standard for the subcategory for the cleaner fuel 

subcatetory. EPA promulgated exactly this type of extended MACT compliance deadline for 

certain facilities that voluntarily elected to install new technology as part of the Pulp and Paper 

Cluster Rule. See Pulp and Paper Cluster Rule, 60 Fed. Reg. 18503, 18,508 (Apr. 15, 1998). 

[Footnote: This two-step approach for the MACT standard is consistent with the D.C. Circuit’s 

decision in NRDC v. EPA, 89 F.3d 1364 (D.C. Cir. 2007) (finding invalid EPA’s decision to 

extend the compliance deadline for a promulgated MACT rule by a year because of the 

substantial changes that the agency made to the rule). Rather than functioning as an extension of 

the compliance deadline, this MACT standard for certain facilities would become applicable in 

two steps. For the first three years, a no-backsliding MACT standard would be applicable, then 

the three year deadline to implement the MACT standard for the applicable “cleaner” source 

would begin to run.] In addition to providing an incentive for facilities to switch to cleaner fuel 

sources, this approach would reduce some of the competition for resources discussed above by 

extending the deadline to complete the work to replace or retrofit certain boilers. 

Response: See response for DCN EPA-HQ-OAR-2006-0790-1915.1, Excerpt Number 18.
Other - Compliance

Commenter Name: Sharene Shealey

Commenter Affiliation: RRI Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1839.1

Comment Excerpt Number: 5

Comment: EPA should allow an option for compliance with the emission standards of the 

proposed rule via certified use of ultra-low sulfur diesel fuel. In the preamble to the proposed 

major source rule, EPA states that fuel switching can lead to the reduction of some HAP 

emissions and increases in other HAP emissions. Switching from traditional No. 2 fuel oil to 

ultra-low sulfur diesel does not result in new or additional HAP emissions. Due to the reduced 

emissions, continuous compliance with the PM and mercury limits is obtained by the use of 

ultra-low sulfur diesel in distillate-fired sources. The annual compliance certification (supported 

by monthly record keeping as required in the proposed rule) would suffice to demonstrate initial 

and continuous compliance with the PM and mercury limits of the proposed rule. 

Response: In the final rule, the proposed MACT-based emission limits for existing oil-fired 

area source boilers was replaced with a GACT-based management practice. 

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 37

Comment: Proposed §63.11210(a) and (b) and §63.11211(a) and (b) all deal with initial 

compliance requirements, in some cases overlapping and in others, possibly conflicting. In any 

case, it is confusing to have these in separate sections and we recommend they be combined into 

one set of requirements in §63.11210 and that §63.11211 only deal with ongoing compliance. 

Response: EPA has reviewed the sections which address initial compliance requirements. 

While we agree that some of the requirements could be merged, the current structure makes a 

distinction between initial compliance obligations in §63.11210 and the means to demonstrate 

initial compliance in 63.11211, and follows a similar outline as Subpart DDDDD, the major 

source rule for boilers and process heaters. EPA and has not identified any conflicting 

requirements in these sections, and since the commenter did not identify a specific provision that 

conflicts, EPA is unable to respond to this portion of the comment. In reviewing the sections, 

however, we note that the Initial Compliance Requirements heading is misplaced, and should 

precede §63.11210. The heading for §63.11205 should read, General Compliance Requirements. 

EPA has made this correction. 
Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 4

Comment: The EPA proposes an operating limit for units controlled by a fabric filter in 

63.11221(a)(4). This limit applies to units which choose to demonstrate continuous compliance 

by using a bag leak detection system to be operated such that the bag leak detection system alarm 

does not sound more than 5 percent of the operating time during a 6-month period. In 

63.11221(b), the EPA proposes that facilities report each instance as a deviation from the 

emission limit for each instance the facility did not meet an emission limit and operating limit. 

Because the EPA has stated that the use of the above-mentioned alarm system demonstrates 

continuous compliance, then any additional deviations above the allowed 5 percent of the 

operating time during a 6-month period should be considered violations. 

Response: Consistent with the definition of deviation in § 63.11237, the determination of 

whether a deviation constitutes a violation of the standard is up to the discretion of the entity 

responsible for enforcement of the standards.

Commenter Name: John Hopewell

Commenter Affiliation: American Coatings Association

Document Control Number: EPA-HQ-OAR-2006-0790-2062.1

Comment Excerpt Number: 18

Comment: In the companion Major Source proposal, EPA allows emissions averaging for 

existing sources. EPA states that the emissions averaging “would not lessen the stringency of the 

MACT floor limits and would provide flexibility in compliance, cost, and energy savings to 

owners and operators.”29 The same is true for Area Sources. EPA should adopt analogous 

provisions in the Area Source NESHAP 

Response: In the final rule, the only existing area source boilers subject to emission limits are 

coal-fired boilers. We are not aware of an area source facility having multiple coal-fired boilers. 

However, in the event an area source facility has multiple coal-fired boilers, section 63.6(g) 

allows the source to petition EPA for an alternative means of emission limitation. 

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 42
Comment: Rather than establish enforceable operating limits, EPA should use the approach 

taken in the CAM rule and require sources to establish site-specific operating parameter ranges 

to define conditions under which compliance with the applicable limit can be reasonably assured. 

This approach already has been upheld as sufficient to satisfy the CAA’s requirements for 

demonstrating continuous compliance. See NRDC v. EPA, 194 F.3d 130, 135-37 (D.C. Cir. 

1999) (rejecting NRDC’s argument that the CAM rule’s “reasonable assurance of compliance” is 

not sufficient to assure continuous compliance as required by the CAA). Source owners and 

operators would then be required to monitor those parameters and respond to changes that 

indicate problems with the controls that could jeopardize compliance. 

Whether using a single control device or combination of devices, sources are in the best position 

to determine what parameters and levels are consistent with compliance. In many cases, multiple 

parameter relationships or supplemental operational data will provide a higher level of 

compliance assurance than the level that happens to be measured during a discrete performance 

test. This is particularly true for sources with a significant margin of compliance. EPA-HQOAR2002-0058-0413, Attachment C at 4. In addition, units with significant margins of compliance 

should be allowed to establish operating levels by extrapolating parameter data beyond that 

obtained during a performance test based on other information. Allowing such extrapolations is 

essential for some sources to provide needed operational flexibility. Attempting to establish 

“worst case” test conditions on a scrubber or multi-section ESP, where the possible combinations 

of parameters are numerous, would at the least be difficult and could be impossible without a 

major research effort. Id. Allowing extrapolation of results avoids the necessity of repeated 

testing. [Footnote: A similar approach has been used in CAM protocols, including a protocol 

developed by the Electric Power Research Institute for ESPs (allowing extrapolation up to 1.25 

times the recorded value for measurements taken at less than 80 percent of the applicable 

emission limit).] 

Once sources have established appropriate operating parameter ranges based on data collected 

during performance tests, as well as other operating data and engineering principles, those 

parameters would be monitored and any deviation from them would trigger a requirement for 

investigation and corrective action to return the parameter to the appropriate range. Although this 

range may in some cases be similar to the minimum values that would be established under 

EPA’s proposed rule, allowing sources to respond with corrective action (rather than simply 

record exceedances and report deviations) achieves EPA’s intended result without subjecting 

sources to potential unreasonable enforcement. 

Response: EPA does not agree that corrective action programs provide the same incentive to 

operate the facility in the same manner as it was operated during the performance test. 

Enforceable operating limits provide a greater assurance of continuous compliance, which is 

particularly appropriate when dealing with toxic air pollutants. EPA believes it is appropriate to 

identify specific operating parameters which sources may use to demonstrate continuing 

compliance. However, if a source believes that different operating parameters are more reflective 

of the source's emission levels, we encourage the source to submit a to establish and monitor 

alternative operating parameters, consistent with the procedures in § 63.7500(a)(2) and § 63.8(f).
Extrapolating parameter data beyond that documented during a performance test is not 

acceptable. However sources may reestablish their operating limits during subsequent 

performance tests.

Impacts Analysis

Costs:Controls

Commenter Name: N/A

Commenter Affiliation: N/A

Document Control Number: EPA-HQ-OAR-2006-0790-0067.1

Comment Excerpt Number: 4

Comment: The NESHAP does not mention what emission control equipment were used by 

these 2 sources. It is well documented that wet scrubbers are capable of removing approximately 

40 to 50% of mercury emissions. However, even this removal would not be sufficient for most 

coal fired boilers to comply with the proposed limit. Additional emission control equipment such 

as activated carbon injection and/or bag filters will be required to comply. Installing these types 

of facilities would be a significant financial burden to most small area sources. The proposed 

NESHAP states that the estimated annualized cost for installing emission controls and 

maintaining compliance is $160 Million per year for all 3,710 existing sources (Federal Register, 

June 4, 2010). This equates to an average compliance cost of $43,127.00 per source. It is 

unlikely that a source could install an activated carbon injection system and/or bag filters for this 

amount. Given this data on the high variability of mercury in coal, the cost estimate is most 

likely too low. USEPA needs to re-evaluate this cost estimate and consider the high variability of 

mercury in coal and the impact this will have on the cost of compliance. 

Response: See the preamble for discussion on the cost impacts and revised limits.

Commenter Name: Carl Johnson

Commenter Affiliation: Southern Pressure Treaters' Association

Document Control Number: EPA-HQ-OAR-2006-0790-0870.1

Comment Excerpt Number: 5

Comment: The cost of controls at a typical wood preserving facility would be in the millions of 

dollars per boiler and still may not meet the proposed limits. 
Response: See response to comment EPA-HQ-OAR-2006-0790-1914.1, excerpt 12 for control 

technology costs within the biomass industry.

Commenter Name: Charles Niebling

Commenter Affiliation: New England Wood Pellet

Document Control Number: EPA-HQ-OAR-2006-0790-0836

Comment Excerpt Number: 8

Comment: The economic and cost modeling for EPA’s boiler regulation are narrowly defined 

and do not reflect the reality and diversity in the biomass boiler marketplace. Proposed 

compliance measures entail installing an Electrostatic Precipitator (ESP) or a baghouse for 

boilers <5 MMBtu, which could equal or exceed the cost of the boiler itself, while for larger 

systems (<30 MMBtu), these control technologies could cost 

$150,000-$250,000. These proposed add-ons will make most biomass boiler projects 

uneconomical and discourage investment. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1914.1, excerpt 12 for control 

technology costs within the biomass industry.

Commenter Name: Los Angeles Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0397

Comment Excerpt Number: 21

Comment: Unfortunately, the cost of adding controls for many biomass boilers covered by the 

MACT rule, and especially the GACT rule, will exceed the original capital costs of the boiler, or 

even the cost of a new one. If a biomass GACT source is unable to achieve the carbon monoxide 

limits by simple means such as combustion controls, more exotic technologies will be needed. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1914.1, excerpt 12 for control 

technology costs within the biomass industry.

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 88

Comment: We are very concerned that these proposed 

rules are far more restrictive than needed to protect 

the environment. Industry cost estimates for compliance 

with these rules is in the range of $20 to $50 billion 
and significantly higher than EPA’s cost estimates. 

These high costs, at a time when the 

nation is recovering from the recession, are not 

sustainable and will result in further loss of 

high-quality manufacturing jobs in the United States as 

companies close or relocate offshore. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1783.1, excerpt 2 for control 

technology costs.

Commenter Name: Jim Hickman

Commenter Affiliation: Langdale Forest Product Company

Document Control Number: EPA-HQ-OAR-2006-0790-1379.1

Comment Excerpt Number: 3

Comment: The cost of controls is millions of dollars per boiler at a typical wood products 

facility, and a facility making such an investment may still not be able to achieve the required 

results. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1914.1, excerpt 12 for control 

technology costs within the biomass industry.

Commenter Name: Steven D. Swanson

Commenter Affiliation: Swanson Group, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1241

Comment Excerpt Number: 2

Comment: Specific to our operations, this rule will have a significant economic impact. While 

each boiler is different, new equipment (i.e. not including ongoing increased operating costs) will 

cost at least $3,500,000 at the low-end to upwards of $6,000,000 at the high end. (And this 

assumes these new controls can even achieve the CO limit). 

Response: See response to comment EPA-HQ-OAR-2006-0790-1796.1, excerpt 5 for 

suggestions to reduce control technology costs.

Commenter Name: Richard Bellefleur

Commenter Affiliation: Wellons FEI, Corp

Document Control Number: EPA-HQ-OAR-2006-0790-1300.1

Comment Excerpt Number: 2
Comment: There are different means of controlling particulate matter in the gas stream of a 

wood fired boiler. The most simple and basic of these is to use a Multiple cyclone in order to 

take the particulate out of the gas stream trough the use of centrifugal force. This method is very 

cost effective and eliminates approximately 75% of the particulate in the gas stream. This piece 

of equipment alone will not be sufficient to reach the new proposed limits. An Electrostatic 

Precipitator or a bag house has to be added to the energy system in order to bring the particulate 

even further down. Adding these types of filtering equipment will add significant cost to the

projects. In most cases, especially in smaller applications, it can greatly compromise project 

economics thus hindering North American efforts to transition from fossil fuels to greener 

heating alternatives. A limit of 0.25 lbs/MMBTU would be more reasonable and achievable with 

the multiple cyclone units alone, especially when dealing with area source sized projects with 

limited funding. 

Response: The PM limits for new biomass boilers are revised for the final rule. A new 

subcategory was created for biomass boilers between 10 and 30 mmBtu/hr which has an 

applicable limit of .07 lb/mmBtu. For biomass boilers greater than 30 mmBtu/hr the limit is the

same, .03 lb/mmBtu. See the preamble for further discussion on the cost impacts..

Commenter Name: Tyler McShan

Commenter Affiliation: McShan Lumber Company

Document Control Number: EPA-HQ-OAR-2006-0790-1380

Comment Excerpt Number: 2

Comment: We have been told that it would cost us hundreds of thousands of dollars to attempt 

to bring our boiler in compliance with the new regs and there would be no guaranteed result. 

Again, not a wise investment in what is already a marginal industry. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1796.1, excerpt 5 for 

suggestions to reduce control technology costs.

Commenter Name: Jack H. Britt

Commenter Affiliation: Jack H. Britt Consulting

Document Control Number: EPA-HQ-OAR-2006-0790-1832

Comment Excerpt Number: 2

Comment: Large facilities can pro-rate equipment costs over several years and depreciate 

annual costs in accounting; however, public facilities such as rural schools and hospitals cannot 

do this to any extent. 

Response: See the preamble for discussion on the cost impacts and revised limits.
Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 2

Comment: EPA estimates the GACT rule will have a "total national cost impact...for existing 

units [of] $696 million dollars in total annualized costs" and "total annualized costs (new and 

existing) for installing controls, conducting biennial tune-ups and an energy assessment, and 

implementing testing and monitoring requirements, is $1.0 billion." 75 FR 31914-15. 

EPA’s estimated costs of the rule are significantly lower that the real cost impact on sources. 

CIBO commissioned URS Corporation to work with its members to estimate the capital costs for 

installation of additional control technologies on existing boilers. The approach used by CIBO 

and URS (CIBO/URS) to estimate capital costs differed from EPA’s in several respects, as 

described in CIBO’s comments on the Proposed Boiler MACT Rule. [See DCN: 2006-0790-

1783.2, Section II for related comments.] 

Although EPA’s estimates indicate that the total annualized costs of the proposed Area Source 

Rule will be $1 billion, the total capital cost of the rule will be far in excess of that amount for all 

affected sources for installation of emissions controls required to meet the proposed standards. 

Major capital investments in add-on control technology will be required for continued operation 

of the ICI power house and energy base of the country. 

CIBO members have sources that will be subject to either MACT or GACT proposed standards 

or both. The reasoning and estimated costs for controls to meet proposed MACT standards 

provide information from which GACT-level controls and cost estimates can be extrapolated. 

CIBO conservatively estimates that the cost to sources to implement GACT will be significantly 

higher than EPA estimates. 

Response: See the preamble for discussion on the cost impacts.

Commenter Name: Donald R. Schregardus

Commenter Affiliation: Department of the Navy, Department of Defense

Document Control Number: EPA-HQ-OAR-2006-0790-1947.1

Comment Excerpt Number: 9

Comment: EPA estimates that the total national cost impact of this proposed rule for new and 

existing units is $1.0 billion in total annualized cost (Section VI.B. What are the cost impacts?). 

DoD believes that EPA has significantly underestimated the compliance cost impacts of this rule 

by not including operational and maintenance costs in the economic analysis. 

The U.S. Air Force (USAF) conducted a compliance cost estimate for area source facilities based 

on the requirements in the draft NESHAP. The USAF has approximately 460 affected boiler 
units at area sources that use coal and liquid fuels, and has estimated that the initial compliance 

cost is $74.2 million with an annual compliance cost of $28.6 million. The total annualized cost 

for USAF area sources would be $36.7 million using 7% interest and a 15 year life for capital 

equipment. Based on the USAF’s compliance cost estimate and the relatively small number of 

affected units compared to EPA’s cost impact and number of affected units, it appears that cost 

impact of the area source NESHAP is significantly underestimated. 

From the information in Table 3 of the preamble EPA’s annualized cost for a coal-fired boiler is 

$43.000 per boiler. In contrast the USAF cost estimate for capital cost is $2.41 million per boiler 

and an annual operational cost of $1.41 million per boiler for a total annualized cost of $1.7 

million per boiler. For oil-fired boilers at area sources, EPA annualized cost is $2,600 per boiler. 

The USAF estimates are capital costs of $704,216 per boiler and an annual cost of $213,246 for 

a total annualized cost of $290,785 per boiler. The USAF annual unit cost includes testing and 

monitoring along with required -maintenance and operations" costs. In contrast it appears that 

the annual costs in Table 3 did not include operations and maintenance costs for emission 

controls, which are significant and are driven by emission limits. As indicated in the preamble 

discussion of Table 3, the annual cost appears to be limited to only -installing controls, 

conducting biennial tune-ups and an energy assessment, and implementing testing and 

monitoring requirements." Operations and maintenance costs will be incurred for sustaining the 

required emissions control devices linked to this regulation. These costs should be reflected in 

Table 3. 

Reevaluate the economic impact of this NESHAP in Table 3 to account for the capital and 

annual recurring operations and maintenance costs for air pollution control equipment that will 

be required to meet the proposed emission limits. 

Response: Operation and maintenance costs are accounted for in a separate economic analysis; 

see the supporting statement and burden tables for the final rule for details on the analysis and 

the Paperwork Reduction Act section of the preamble for a brief summary.

Commenter Name: Russell A. Wozniak

Commenter Affiliation: The Dow Chemical Company

Document Control Number: EPA-HQ-OAR-2006-0790-1766.1

Comment Excerpt Number: 9

Comment: Dow estimates that the cost to have an emission testing contractor conduct an annual 

emission test for CO is approximately $10,000 for each emission source. This cost over a period 

of time is excessive when compared to the amount of air quality improvement that will be 

achieved. Thus, EPA should finalize a rule that requires testing after a five year period or upon a 

significant physical or operational change to a boiler. 

Response: The requirement for annual testing has not changed, however, CO limits for biomass 

and liquid boilers are not included in the final rule. See the preamble for discussion on the cost 

impacts and revised limits.
Commenter Name: Ardis Almond

Commenter Affiliation: Almond Brothers Lumber Company

Document Control Number: EPA-HQ-OAR-2006-0790-1449.1

Comment Excerpt Number: 1

Comment: What you are proposing is impossible - certainly from the financial standpoint, and 

probably from the technical side. The additions of millions of dollars worth of pollution 

equipment to every boiler would be the final blow to an already battered industry. Many, many, 

sawmills have been shut down for sometime, due to the awful housing market. I can give you a 

perfect example of one. There is another mill in our small rural town. It has been shut down for 

almost 3 years, now, and its 100 employees laid off. That company has diligently kept two 

employees working keeping their equipment greased, tested, and maintained for an expected start 

up at the first opportunity. That company had hopes of starting back up near the end of the year. I 

know they, now, can’t even consider it with the Boiler MACT proposal facing them. How can 

they start up a mill when they can barely afford to do so under the best of circumstances, much 

less, when they will have to put out millions before they put the first employee back to work? 

Response: See response to comment EPA-HQ-OAR-2006-0790-1783.1, excerpt 2 for control 

technology costs.

Commenter Name: Chris Mello

Commenter Affiliation: Alaska Energy Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1653.1

Comment Excerpt Number: 2

Comment: When most people think of rural America, they envision farmland and small 

communities 

with unpaved roads. In Alaska, rural encompasses a completely different meaning. Bush 

Alaska is probably a more descriptive term when describing the villages of Alaska. Rural or bush 

Alaskan villages are not connected to roads and are not serviced by the Alaska Marine Highway 

with year round, drive on/drive off ferry service. The only way to access these communities is by 

boat or plane. All supplies- food, clothing, construction materials, fuel, etc. — are barged into 

the village on boats during the summer months or delivered by planes. Most landing strips are 

gravel and only support small aircraft. 

The logistics to supply rural Alaskan villages results in some of the highest costs of living in the 

United States. Most rural villages rely on subsistence for some of their food. Unemployment 

often exceeds 50%. The high cost of living and high unemployment means the sustainability of 

this subsistence lifestyle is in peril. 

The map below illustrates the remoteness and lack of roads in rural Alaska. Source: Alaska 

Department of Environmental Conservation (2007); Northern Economics Inc., Alaska Map 

Company 
Rural Alaska Power Generation 

Over 180 communities in rural Alaska depend on diesel fuel for electricity. They are scattered 

over an area twice the size of Texas, and are located in remote areas of the state without road 

access. Access is limited to boat or air. More than 93% of these communities have a population 

less than 1000. The average population is only 310 residents. Each community has a school, post 

office, health clinic, airport, and community building, and a few have public water and sewer. 

These communities are located in the most severe arctic environments in the United States and 

rely entirely on locally diesel-generated electricity to maintain critical public infrastructure. 

Unlike the Continental U.S., they are not linked by electrical interties, but rely on a local, self 

sufficient, diesel power plant. 

This system of power generation is unique in the United States. 93% of rural Alaska power 

generation is fueled by diesel. While costs vary by region across the state, rural Alaska 

communities typically pay some of the highest fuel costs in the United States. This translates into 

high power costs. A gallon of diesel costs over five dollars in some areas. In many communities, 

the cost of power ranges from over fifty cents to nearly $1 per kilowatt-hour before a Power Cost 

Equalization (PCE) subsidy is provided.

Heating Systems in Rural Alaska 

Heating needs in rural Alaska are typically met through burning diesel, usually Jet A fuel, barged 

into the communities by boat. As with the electrical generation system, the logistics of barging 

heating fuels to the rural villages results in the some of the highest heating fuels costs in the 

United States. Barge deliveries can only be made during the summer months, so communities 

must estimate their annual usage and budget for the following year’s fuel inventory. Due to

fluctuations in fuel costs, accurate budgeting is extremely difficult and results in financial 

hardships for the communities. After freeze-up, any shortfalls of fuel must be flown in by air 

tanker at even higher costs. Because these communities are located in the most severe arctic 

environments in the United States, heating needs are a matter of life or death. 

Wood is growing as an important renewable energy source for Alaskans, with over 100,000 

cords per year used for residential space heating statewide. Closure of the major pulp mills in 

Sitka and Ketchikan in the 1990s brought an end to large-scale wood-fired power generation in 

Alaska; however, in the last few years, rural Alaska has seen an explosion in interest in using 

wood resources for space heating. Biomass district heating systems are a reliable method to 

provide heating to schools and other community buildings. To date, at least 30 communities are 

investigating the feasibility of biomass heating and at least 15communities are in construction or 

have operational systems. These are almost exclusively small stick-wood or chip heating systems 

that supply hot water to district heating systems. 

Utilizing biomass for heating needs in rural Alaska provides far more than just heat to a 

community. With fuel oil heating, funds leave the community to purchase the fuel and pay for 

the transportation and storage. With biomass, dollars stay within community since fuel is 

purchased locally. In addition, jobs are created through the harvest and processing of the wood, 
which is important in villages where unemployment is often over 50%. Many of the rural 

Alaskan villages have a history of a subsistence culture. 

The power and heating systems in rural Alaska are often operated as non-profits by city 

governments or regional cooperatives. Operations are tightly controlled for costs. There is little 

revenue margin to shield customers from increased operating costs, including rising wholesale 

fuel prices and regulatory compliance. 

Compliance with the proposed boiler NESHAP emissions rule presents a financial and logistical 

challenge to rural Alaska that will gravely increase annual operating costs, and seriously hamper 

future development of biomass heating systems. Cost increases will occur through increased 

capital costs for installation of emission control devices and increased operational and 

maintenance costs. 

The daily wellbeing of rural Alaska residents and communities depends on the ability to 

eLououtiLally heat their facilities. The uncertainty in fuels costs and ever increasing regulatory 

compliance costs makes it difficult for individuals, local and regional organizations to plan 

budgets for fuel, heat, and power costs. 

Response: See the preamble for discussion on the cost impacts and revised limits.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 4

Comment: AF&PA is very concerned that the proposed requirements are overly burdensome 

and will require substantial financial expenditures at levels higher than those estimated by EPA 

for oil fired boilers as well as biomass boilers. In the memorandum “Methodology for Estimating 

Control Costs for Industrial, Commercial, Institutional Boilers for the National Emission 

Standards for Hazardous Air Pollutants – Area Source,” EPA has followed the costing 

assumptions and techniques in the OAQPS Control Cost Manual (EPA 452/B-02-001). The 

memo states that the only control technologies evaluated were “fabric filter, low NOx burner, 

linkage-less boiler management system, and multiclone.” The memorandum does not specifically 

discuss how costs were estimated for these technologies, but instead refers to the discussion in 

the memorandum prepared for the Boiler MACT, “Methodology for Estimating Control Costs 

for the Major Source Industrial, Commercial and Institutional Boilers and Process Heaters 

National Emission Standards for Hazardous Air Pollutants.” 

We do not agree with the methodology used to determine the cost of CO emissions reductions 

for liquid fired boilers. The ERG MACT cost memorandum referenced by the GACT cost 

memorandum states that if baseline CO emissions were between 400 and 1000 ppm for boilers 

designed to burn liquid fuels, the cost of a low-NOx burner was estimated to achieve the MACT 

floor emission limits. The CO limits for these boilers in the proposed rule are 1-2 ppm. Based on 
conversations with burner vendors, a low-NOx burner is typically guaranteed to produce CO 

emissions of 50 to 100 ppm for liquid boilers. EPA’s assumption that burner retrofit can result in 

achieving the proposed 2 ppm CO limit for liquid boilers is simply unfounded, and they should 

provide justification for why they believe this is an appropriate approach or reevaluate their 

assumption. If the CO limits are finalized at 2 ppm for liquid fuel boilers, we believe that a new 

burner will not be sufficient for all area source boilers to reach that limit. EPA should revise the 

CO limit for liquid boilers to more accurately reflect what boiler and burner manufacturers 

currently guarantee, as this would be a more appropriate approach for setting a GACT limit and 

would not require unproven and costly controls such as a CO catalyst. 

Response: See the preamble for discussion on the cost impacts and revised limits.

Commenter Name: Robert L. Garfield

Commenter Affiliation: Food Industry Environmental Council

Document Control Number: EPA-HQ-OAR-2006-0790-1835.1

Comment Excerpt Number: 4

Comment: As EPA recognizes, the capital cost of emissions controls for the numerous existing 

gas-fired boilers would be extraordinarily high. Further, EPA correctly concluded that imposing 

emission limitations on gas-fired boilers would create a disincentive for switching to gas from 

oil, coal or biomass as a control technique. 

Response: EPA thanks the commenter for their input; in the final rule gas-fired boilers are not an 

applicable subcategory.

Commenter Name: Chris Mello

Commenter Affiliation: Alaska Energy Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1653.1

Comment Excerpt Number: 4

Comment: The typical cordwood boiler installed for district heating in a rual village has a 

capital cost of approximately $25,000 including shipping to the community. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1914.1, excerpt 12 for control 

technology costs within the biomass industry.

Commenter Name: William C. Scott

Commenter Affiliation: Collum's Lumber Products, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1796.1

Comment Excerpt Number: 5
Comment: The cost of controls is millions of dollars per boiler at a typical wood products 

facility, and a facility making such an investment may still not be able to achieve the required 

results. 

Response: See the preamble for discussion on the cost impacts and revised limits.

Commenter Name: Gary Rubenstein

Commenter Affiliation: Kauai Island Utility Cooperative, KIUC

Document Control Number: EPA-HQ-OAR-2006-0790-2028.1

Comment Excerpt Number: 9

Comment: For older boilers, which are nearing but not at the end of their useful life, it may not 

be cost effective to install a new burner or oxidation catalyst. If the boiler is retired only a few 

years after the control device is installed, then the upgrades will not have been utilized for their 

entire useful lives. Since control devices such as burners and oxidation catalysts must be 

designed and sized to match the boilers on which they are installed, one cannot automatically 

assume that a burner or catalyst system designed for one boiler can be used on another. 

Alternatively, a need to retain a burner or catalyst system for use on a replacement boiler may 

limit the source’s option for replacement boilers (i.e., the source would need to purchase a boiler 

compatible with the existing control devices). Consequently, although the useful life of the 

control device is considered in cost effectiveness calculations, if the control device will not be 

used for its predicted useful life, then the calculations will underestimate the cost effectiveness of 

the device. 

Response: The EPA does not predict the age of boilers to determine their useful life left nor how 

a boiler operator will implement their control devices. The costs are estimates and do not capture 

every scenario available but are based on reasonable assumptions for the whole market. Please 

note that CO limits for biomass and liquid boilers are not included in the final rule and thus the 

burden for their associated control devices is not applicable. See the preamble for discussion on 

the cost impacts and revised limits.

Commenter Name: Gary Rubenstein

Commenter Affiliation: Kauai Island Utility Cooperative, KIUC

Document Control Number: EPA-HQ-OAR-2006-0790-2028.1

Comment Excerpt Number: 13

Comment: Our preliminary analysis indicates that an oxidization catalyst would be required to 

meet the 2 ppmvd CO MACT limit for the KIUC Port Allen boiler. The cost of an oxidation 

catalyst for this boiler is many times higher than the oxidation catalyst costs deemed “not 

prohibitive” for the RICE NESHAP, for both installation and operation. Based on capital and 
operating costs received from Sud-Chemie and KIUC’s CEMS contractor, the costs to KIUC of 

complying with the NESHAP as proposed would be as shown below: 

* Capital cost for oxidation catalyst: $90,00019 plus tax and installation; 

* 

* Capital cost for CO/O2 CEMS: $188,000 20 ; 

* 

* Total capital investment: approximately $485,000; and 

* 

* Annual operating cost: approximately $95,000/year21. 

Details of these calculations are attached. (See submittal for data table.) Contributing to the 

installation costs are the physical configuration and operational characteristics of the KIUC Port 

Allen boiler. The temperature downstream of the air preheater, which is most accessible location 

for installation of an oxidation catalyst, ranges from 443 to 479?F. However, according to 

information from the catalyst manufacturer BASF, oxidation catalyst temperatures of 500o F are 

needed to oxidize CO and 700o F or more is needed to oxidize VOCs (see submittal for figure). 

The boiler outlet temperature at KIUC Port Allen is well below these levels; as a result, an 

oxidizing catalyst is not a feasible control technology unless the catalyst is installed at a location 

inside the boiler where the exhaust temperature is higher, or unless the flue gas is reheated prior 

to entering the oxidation catalyst. The need to install the oxidation catalyst upstream of the air 

preheater significantly increases the retrofit cost. In addition, KIUC burns small amounts of 

specification used oil in the boiler as a way of eliminating waste oil that would otherwise have to 

be disposed of in landfills. Although this used oil is burned only in small quantities, it contains 

impurities that will accelerate plugging of the catalyst surface, requiring more frequent catalyst 

washing than would otherwise be required for a catalyst used with virgin fuel oil only. More 

frequent catalyst washing translates into more frequent boiler outages. 

Response: See response to comment EPA-HQ-OAR-2006-0790-2025.1, excerpt 61 for cost of 

oxidation catalyst as a CO control technology.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 56

Comment: We note that we believe the proposed standards are not achievable. Therefore they 

are not achievable at any cost for the reasons noted. Nonetheless, we feel compelled to comment 

on EPA’s cost assessment performed for this rule. We do also make the point that EPA should be 

using all the available regulatory considerations that are afforded to GACT rules in §112(c) (5) 

and one of those considerations, unlike MACT, can be cost. It is therefore important for costs to 

be properly evaluated. We believe EPA’s cost analysis suffers from several methodology errors. 
First, we note the errors noted for biomass boilers. The methodology for estimating the area 

source control cost document states in section 3.0: "The controls analyzed for the impacts 

analysis include the fabric filter, low NOx burner, linkage-less boiler management system, and 

multi-clone." Further, in a second document concerning cost methodology for both rules, states 

on page 4 of the CO section "The baseline emissions for area source boilers in all fuel categories 

are less than 400 ppm, and so it is assumed that combustion controls, either a basic tune-up or a 

more advanced burner replacement or installation of a linkage-less boiler management system, 

can achieve the proposed MACT floor emission limits. No oxidation catalysts are estimated to be 

required to meet the MACT floor emission limits.”[See submittal for references]. 

Even with the limited area source dataset used to prepare this proposal, there are units outside the 

400 PPM range and we have identified others elsewhere in these comments. It is clear from the 

quotes above that no regenerative catalytic oxidizers (RCO) were considered in the cost 

methodology for area source biomass boilers even though they would clearly be needed to if 

limits were raised to a level achievable through employing that technology. There is further no 

consideration for the use a particulate control device on area source biomass boilers because 

there is no PM limit. 

Consequently, for biomass boilers the control costs are dramatically underestimated by not 

including cost estimates the either the particulate control necessary to protect the RCO or the 

RCO itself. These control technologies could easily cost one million dollars or more per boiler. It 

is impossible to estimate how many of the noted 10,958 biomass boilers would need this 

equipment since EPA provides almost no information about the vast majority of units in this 

source category. However, it is certain that very few, if any have RCO. Clearly this is a huge 

methodology error that could lead to billions of dollars of control equipment costs if such costs 

were to be correctly calculated. These costs, however uncertain, can be avoided altogether since 

EPA clearly has the authority to proceed with a work practice standard as we state elsewhere. 

Response: For biomass and oil-fired boilers, CO limits are not included in the final rule easing 

the burden. See the preamble for discussion on the cost impacts and revised limits.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 57

Comment: Regarding oil fired boilers, we are very concerned that the proposed requirements are 

overly burdensome and will require substantial financial expenditures at levels higher than those 

estimated by EPA. Per the memorandum noted above, 

EPA has followed the costing assumptions and techniques in the OAQPS Control Cost Manual 

(EPA 452/B-02-001). Again, the memo states that the only control technologies evaluated were 

“fabric filter, low NOx burner, linkage-less boiler management system, and multiclone.” The 

memorandum does not specifically discuss how costs were estimated for these technologies, but 

instead refers to the discussion in the memorandum prepared for the Boiler MACT, 
“Methodology for Estimating Control Costs for the Major Source Industrial, Commercial and 

Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air 

Pollutants.” EPA-HQOAR-2002-0058-0803. 

We also do not agree with the methodology used to determine the cost of CO emissions 

reductions for liquid fired boilers. The ERG MACT cost memorandum Id referenced by the 

GACT cost memorandum states that if baseline CO emissions were between 400 and 1000 ppm 

for boilers designed to burn liquid fuels, the cost of a lowNOx burner was estimated to achieve 

the MACT floor emission limits. The CO limits for these boilers in the proposed rule are 1-2 

ppm. Based on conversations with burner vendors, a low-NOx burner is typically guaranteed to 

produce CO emissions of 50 to 100 ppm for liquid boilers. EPA’s assumption that burner retrofit 

can result in achieving the proposed 2 ppm CO limit for liquid boilers is simply unfounded, and 

it is recommended the Agency provide justification for its approach or re-evaluate their 

assumptions. 

If the CO limits are finalized at 2 ppm for liquid fuel boilers, we believe unreasonable cost 

burdens will result since boiler and burner manufacturers cannot guarantee emission level 

compliance. In this case, EPA should reevaluate all data available for area sources area and 

reconsider area source CO standards that would not require unproven and costly controls. 

In our comments on the major source rules, we prepared an extensive cost analysis for the cost of 

the major and area source rules that is also relevant here (See Section II and Appendix C, EPAHQ-OAR-2002-0058; we incorporate those comments by reference) 

Response: See response to comment EPA-HQ-OAR-2006-0790-1939.1, excerpt 4 for 

methodology used to determine the cost of CO emissions reductions for liquid fired boilers.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 61

Comment: EPA significantly understates the cost of this proposal for many reasons. A 

fundamental problem is the false assumption that most existing liquid-fired boilers can meet the 

proposed CO limits at all times without add-on controls. This is incorrect. To meet the proposed 

CO emission limit at all times and also meet the applicable NOx limit, without sacrificing 

combustion efficiency, most liquid-fired boilers will require the installation of oxidation catalyst 

systems. Rather than just a small percentage of boilers requiring this control, essentially all will 

have to install this system in order to meet the proposed CO limits during startups, turndown and 

operations other than at performance test conditions. Additionally, the proposed CO limits are 

not achievable for many existing boilers, because the oxidation catalyst may be ineffective or 

may not fit in available space or because it is cheaper to replace the boiler. Thus, the cost basis 

for this proposal should assume a significant percentage of existing boilers will have to be 
replaced with gas fired boilers. As mentioned previously, there is also an energy penalty for 

adding oxidation catalyst to a boiler that needs to be reflected in the EPA analysis. In order for 

the catalyst to operate properly, stack temperatures will have to be raised several hundred 

degrees. This lost heat integration will have to be replaced with additional firing. 

The economic analysis should also reflect the fact, that a portion of the sources facing the need to 

replace their boilers will shutdown instead, resulting in economic loss for the economy and loss 

of jobs. The impacts of liquid-fired boilers being unable to meet the CO limits was not 

considered in the preamble discussions or in the background documents in the docket, thereby 

negating those analyses. 

Response: See the preamble for discussion on the cost impacts and revised limits.

Commenter Name: Gary Rubenstein

Commenter Affiliation: Kauai Island Utility Cooperative, KIUC

Document Control Number: EPA-HQ-OAR-2006-0790-2028.1

Comment Excerpt Number: 7

Comment: The RIA makes erroneous assumptions about the control strategy for area source 

boilers that are subject to MACT for POM. Specifically, the RIA assumes that liquid-fueled 

boilers with baseline CO emissions of up to 400 ppmvd @ 3% O2 will be able to achieve the 

MACT standard of 2.0 ppmvd @ 3% O2, solely through boiler tuning. This would represent an 

unrealistic 99.5% reduction. This assumption is stated below. 

Organic HAP and carbon monoxide can be controlled by either improving the combustion 

efficiency of the unit, or installing an oxidation catalyst on the exhaust of a combustion unit. The 

control strategy necessary to meet the MACT floor emission 

limit will vary depending on the magnitude between the baseline emissions and the CO MACT 

floor. A step function was used to delineate what type of control strategy should be analyzed in 

the cost impacts analysis: 

o Most boilers (other than Dutch ovens and PC-coal boilers discussed below) are designed to 

operate with CO emissions at or near 400 parts per million (ppm). A boiler tune-up, was 

estimated in the cost impacts analysis if the unit’s baseline emissions exceeded the floor for 

carbon monoxide (CO), but were less than or equal to 400 ppm @ 3% O2. 

o If the baseline CO emissions were between 400 and 1000 ppm @ 3% O2 for boilers and 

process heaters designed to burn liquid and gaseous fuels, the cost of a replacement low-NOx 

burner was estimated to achieve the MACT floor emission limits.15 

The two bullet points represent the first two “steps” in the control technology step-function. Only 

at the second step, where baseline CO emissions are between 400 and 1,000 ppm, does the 

analysis assume that a new burner would be required. With this assumption, only 3 of the 125 
existing oil-fired area source boilers evaluated in the MACT Floor Analysis would require either 

a burner retrofit and/or an oxidation catalyst.16 Such an assumption is not supported by realworld data and is very likely incorrect for older, oil-fired burners. Additionally, an inverse 

relationship between NOx and CO emissions is frequently encountered with extreme boiler 

tunings. That is, in tuning a boiler to achieve the lowest possible CO emissions, NOx emissions 

may increase substantially due to higher flame temperatures. Many boilers are already subject to 

NOx concentration or mass emission limits that would prevent extreme tuning for CO. These 

boilers must be tuned to balance CO and NOx emissions to meet emission limits for both 

pollutants. Due to the potential for boiler tuning to affect NOx emissions, the RIA must account 

for the impact of existing NOx rules, regulations, and permit limits in determining the feasibility 

of meeting MACT solely through tuning. The omission of these considerations greatly 

underestimates the number of boilers that will require burner replacements, oxidization catalysts, 

or both. 

Response: See the preamble for discussion on the cost impacts and revised limits.

Commenter Name: Gary Rubenstein

Commenter Affiliation: Kauai Island Utility Cooperative, KIUC

Document Control Number: EPA-HQ-OAR-2006-0790-2028.1

Comment Excerpt Number: 8

Comment: Likewise, the rule’s costs are greatly underestimated for the liquid fuel subcategory. 

We strongly believe that the RIA’s assumption that up to 99.5% CO control is possible via boiler 

tuning, with no other NOx or adverse operational effects, is incorrect. This assumption should be 

further investigated, revised, and substantiated, and the RIA costs should be adjusted 

accordingly. 

Response: See response to comment EPA-HQ-OAR-2006-0790-2028.1, excerpt 7 for CO 

control technology costs.

Commenter Name: Sarah E. Amick

Commenter Affiliation: Rubber Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1918.1

Comment Excerpt Number: 2

Comment: Gas fired boilers that burn oil during periods of curtailment, gas supply emergencies, 

or for periodic testing are not considered oil fueled boilers under the proposal.5 EPA defines 

curtailment as “a period of time during which the supply of natural gas to an affected facility is 

halted for reasons beyond the control of the facility. An increase in the cost or unit price of 

natural gas does not constitute a period of natural gas curtailment or supply interruption.”6 This 

proposal fails to take into account the current demand on natural gas. 
EPA’s recently promulgated rules to regulate Greenhouse Gases will likely increase the demand 

on natural gas supply. Should the price of natural gas increase, due to a decrease in available 

supply, RMA members would like to preserve the option to burn oil fuel during short-term 

spikes in the price of natural gas due to availability. In order to preserve the need to burn oil 

fuels, RMA members will need to install costly add-on controls to preserve the option to burn oil 

fuels. For example, oil fuel boilers greater than 10 MMBtu/hr will be required to install CO 

controls (either projects to improve combustion or fuel feed or installation of a CO catalyst). We 

estimate that the installation of CO controls on area source boilers classified as oil fueled boilers 

will cost RMA members a total of approximately $62 million dollars (assuming a fixed capital 

cost of $2.0 million dollars per boiler to install CO controls). 

Response: See response to comment EPA-HQ-OAR-2006-0790-2028.1, excerpt 7 for CO 

control technology costs. See response to comment EPA-HQ-OAR-2006-0790-1939.1, excerpt 4 

for methodology used to determine the cost of CO emissions reductions for liquid fired boilers.

Commenter Name: Heather M. Bartlett

Commenter Affiliation: SLR International Corp, Columbia Forest Products

Document Control Number: EPA-HQ-OAR-2006-0790-1963.1

Comment Excerpt Number: 3

Comment: Essentially, all existing wood-fired boilers in Area Sources will be required to install 

an oxidation catalyst in order to meet the proposed limit. So few wood-fired boilers have 

oxidation catalysts that this technology can be considered as not “commercially” viable or 

demonstrated. In many instances, flue gas temperature conditions will not be optimal to achieve 

significant CO destruction performance. Also, the particulate grain loadings in these boilers in 

the temperature ranges required by these catalysts will rapidly deteriorate the catalytic surfaces. 

Analyses indicate that the costs to install and maintain oxidation catalyst equipment in all 

instances will be prohibitively high and greatly exceed the cost-effectiveness criteria established 

by EPA. 

Response: See response to comment EPA-HQ-OAR-2006-0790-2025.1, excerpt 61 for cost of 

oxidation catalyst as a CO control technology.

Commenter Name: Matthew Markee

Commenter Affiliation: IN Group Companies

Document Control Number: EPA-HQ-OAR-2006-0790-1965.1

Comment Excerpt Number: 8

Comment: In addition to this lack of data resulting in a CO limit 2.5 to 4 times lower than the 

limit for Major Sources, attempting to comply with the limit will force small units to add very 

expensive CO controls, operate the units in such a manner that NOx emissions will be 

substantially increased, energy efficiencies will decrease and thus fuel consumption will increase 
significantly without incremental productivity gains, or discontinue operations altogether. 

Considering that many of these units are associated with small businesses, this is an altogether 

unfair and unreasonable burden. 

Response: See response to comment EPA-HQ-OAR-2006-0790-2028.1, excerpt 7 for CO 

control technology costs.

Commenter Name: Gary Melow

Commenter Affiliation: Michigan Biomass

Document Control Number: EPA-HQ-OAR-2006-0790-1917.1

Comment Excerpt Number: 15

Comment: The proposed limits of 160 PPM CO for existing biomass sources and 100 PPM CO 

for new biomass sources are not achievable for most forest-based wood biomass power plants 

unless a catalytic oxidizer is added. Even with a catalyst, some biomass facilities will not be able 

to meet the proposed CO standards. 

For new sources, EPA should consult with boiler manufacturers to assess what levels of 

emissions are being guaranteed as a general criterion for proposed MACT standards. Likewise, 

air pollution control vendors should be used as a resource for existing sources. A new project or 

air pollution control upgrades to a facility cannot be financed if there is no guarantee that the 

technology will permit the facility to meet applicable environmental standards. 

Table 3 of the preamble (75 FR at 31914) estimates the cost of the proposed standard at less than 

$4400 per existing biomass unit and $65,000 per new biomass unit. These costs are significantly 

understated and indicate EPA expects that the proposed limits for biomass boilers are achievable 

through good combustion practices, which is not true. 

Response: See response to comment EPA-HQ-OAR-2006-0790-2025.1, excerpt 61 for cost of 

oxidation catalyst as a CO control technology.

Commenter Name: Jim Simon

Commenter Affiliation: American Sugar Cane League

Document Control Number: EPA-HQ-OAR-2006-0790-2281.1

Comment Excerpt Number: 17

Comment: The cost of compliance for each bagasse-fired boiler operating at a Louisiana sugar 

mill is expected be considerably higher than the per source average estimated by EPA. A 

reasonable estimate of the cost to Louisiana mills is between $192 - $282.5 million, as explained 

below. The mills do not operate with a profit margin capable of supporting such an enormous 

capital investment. Ultimately, Louisiana and the nation will pay a hefty price for the Proposed 

Rule. 
As explained above, Louisiana’s biomass-fired boilers will be expected to meet considerably 

more stringent CO emission limits than boilers located at major sources. Existing sources will 

have to undergo extensive modifications in an attempt to meet the unjustifiable low emission 

limit of 160 ppm CO limit at 7% oxygen. 

Achieving compliance with such low emission rates for CO will require the installation of 

refractory walls and additional boiler controls at a cost of about $1,000,000 for each of the 71 

operating boilers. Because these modifications will result in decreased steam production, each of 

the eleven mills will need to install an additional 200,000 - 300,000 pound-per-hour boiler, 

ranging between $10,000,000 and $13,000,000 per unit. These estimates do not include the cost 

of installing a CO CEM unit on each boiler stack as required by the Proposed Rule. Further, it 

may be necessary to install additional NOx controls to offset the expected increase in NOx 

emissions as a result of operating boilers to meet the CO standards ($750,000 per boiler) and/or 

install and operate electrostatic precipitators for additional PM control ($1,200,000 per boiler). 

Using the most conservative estimates and assuming the elimination of all POM (as 7- HAP) 

emissions, the $192 million price tag would result in the reduction of only 42 pounds per year of 

POM (as 7-PAH), or $4.6 million per pound. At $282.5 million, the cost of removing 42 pounds 

per year of POM (as 7-PAH) would amount to $6.7 million per pound. 

Response: See response to comment EPA-HQ-OAR-2006-0790-2028.1, excerpt 7 for CO 

control technology costs. See response to comment EPA-HQ-OAR-2006-0790-1914.1, excerpt 

12 for control technology costs within the biomass industry.

Commenter Name: Gary Melow

Commenter Affiliation: Michigan Biomass

Document Control Number: EPA-HQ-OAR-2006-0790-1917.1

Comment Excerpt Number: 17

Comment: Retrofitting a CO catalyst on our existing sources would be extremely expensive. In 

addition to the high cost of the catalyst itself, the equipment must be placed downstream of the 

particulate control system. We have sources where the stack is attached to our particulate control 

device, so a new free standing stack would be required. Optimal CO catalyst reaction occurs at 

temperatures well above the exhaust stack gas temperatures at our facilities which run about 350 

degrees Fahrenheit. The reheating of exhaust gas is very expensive and very energy inefficient. 

Most likely natural gas would be used to reheat the boiler exhaust. Retrofit costs would also 

include a larger induced draft fan system to overcome additional pressure drop (further reducing 

energy efficiency). Based on experience estimating other types of add-on equipment to our 

existing facilities, we estimate that the cost of adding a CO catalyst to our facilities would easily 

run over $1 million and add significant operating costs. 

Response: See response to comment EPA-HQ-OAR-2006-0790-2025.1, excerpt 61 for cost of 

oxidation catalyst as a CO control technology.
Commenter Name: Jim Simon

Commenter Affiliation: American Sugar Cane League

Document Control Number: EPA-HQ-OAR-2006-0790-2281.1

Comment Excerpt Number: 21

Comment: The Cost of Compliance With GACT is Prohibitively High. 

The proposed GACT emission limit cannot be achieved from baggase-fired boilers using the best 

technology (cyclonic ash arrestors followed by venturi-type hydroscrubbers) now in use at 

Louisiana sugar mills. Much more expensive PM control systems would be required to meet the 

proposed emissions limit in order to control minimal urban HAP emissions. 

The only way that the proposed GACT PM limit can be achieved would be via dry scrubbing 

using a bag filtration system or an electrostatic precipitator (ESP) unit. The higher flue gas 

temperatures encountered with dry scrubbing would cause an increase in high boiling point POM 

emissions since POM would not tend to deposit on the hot ash particles removed, and the 

gaseous POM would be emitted from the stack; whereas POM, especially 7-PAH, is greatly 

reduced or eliminated in flue gas scrubbed of PM at temperatures below the boiling point of 

water, as is done at existing Louisiana sugar mills. 

To comply, a dual system would have to be used. The cost of installing both an adequate dry 

scrubber and wet scrubber would be prohibitive. If the proposed MACT rule stands, and the 

price of domestic raw sugar does not increase and remain very high, it is unlikely that any new 

bagasse boilers could be built, and unlikely that any old bagasse boilers could be upgraded to 

“new source” standards after the effective date of any such rule – all at no measurable benefit but 

very high costs and likely increase in 7-PAH and other POM emissions. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1300.1 for PM control 

technology costs. See response to comment EPA-HQ-OAR-2006-0790-1914.1, excerpt 12 for 

control technology costs within the biomass industry.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 1

Comment: ACC members use many boilers of various types, sizes, and fuel configurations to 

meet the heat and steam demands needed to energize the business of chemistry. ACC member 

companies are very concerned that the proposed requirements are overly burdensome and will 

require substantial financial expenditures at levels higher than those estimated by EPA. Per the 

memorandum “Methodology for Estimating Control Costs for Industrial, Commercial, 

Institutional Boilers for the National Emission Standards for Hazardous Air Pollutants – Area 
Source, EPA has followed the costing assumptions and techniques in the OAQPS Control Cost 

Manual (EPA 452/B-02-001). The memo states that the only control technologies evaluated were 

“fabric filter, low NOx burner, linkageless boiler management system, and multiclone.” The 

memorandum does not specifically discuss how costs were estimated for these technologies, but 

instead refers to the discussion in the memorandum prepared for the Boiler major source rule, 

“Methodology for Estimating Control Costs for the Major Source Industrial, Commercial and 

Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air 

Pollutants. 

As stated in our comments on the proposed Boiler major source rule (also referred to as the 

“Boiler MACT”) cost analysis, we do not agree with the methodology used to determine the cost 

of CO emissions reductions for liquid fired boilers. The ERG MACT cost memorandum 

referenced by the GACT cost memorandum states that if baseline CO emissions were between 

400 and 1000 ppm for boilers designed to burn liquid fuels, the cost of a low-NOx burner was 

estimated to achieve the MACT floor emission limits. Based on conversations with burner 

vendors, a low-NOx burner is typically guaranteed to produce CO emissions of 50 to 100 ppm 

for liquid boilers. However, the CO limits for these boilers in the proposed rule are 1-2 ppm. 

ACC member experience with Low NOx Burners firing fuel oil is that members will be unable to 

routinely meet the proposed CO limit. EPA’s assumption that burner retrofit can result in 

achieving the proposed 2 ppm CO limit for liquid boilers is simply unfounded, and it should 

provide justification for why it believes this is an appropriate approach or re-evaluate its 

assumption and revise the MACT floor accordingly. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1939.1, excerpt 4 for 

methodology used to determine the cost of CO emissions reductions for liquid fired boilers.

Commenter Name: W. Randall Rawson

Commenter Affiliation: American Boiler Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1897.1

Comment Excerpt Number: 2

Comment: In establishing achievable MACT emission standards for area sources, EPA should 

consider the multiple rules and emission standards that affect the full range of boilers and 

combustion equipment. As EPA is aware, many existing and new boilers are subject to multiple 

federal and state rules and emissions standards which may be inconsistent and/or conflicting. The 

technical implications to piece-meal rulemaking, such as a failure to consider the operational 

impacts of multiple emission standards, may adversely affect overall boiler performance as well 

as the goals of the Clean Air Act, and may needlessly drive up the cost of compliance. As an 

example, the stringent emission limits for carbon monoxide (“CO”) set forth in the Proposed 

Area Source Rule will affect sources’ ability to meet low nitrogen oxides (“NOx”) emissions 

because minimizing CO in the combustion system is a goal that is opposed to minimizing NOx 

in most boiler burners. Because boiler NOx emissions are generally regulated pursuant to control 

or emission standards implemented by state agencies, EPA may not have fully considered the 

impacts of such varying NOx control requirements on CO performance. Conversely, in some 

applications, such as in combustion turbine / heat recovery steam generation systems, CO control 
may adversely affect selective catalytic reduction for NOx control and particulate emissions due

to the oxidation of NO to NO2 and SO2 to SO3 and/or SO4. Inconsistencies in requirements for 

NOx and CO may needlessly cause boiler owners and operators to incur control costs that 

outweigh the relative environmental benefits, and may affect boiler performance. 

Response: See response to comment EPA-HQ-OAR-2006-0790-2028.1, excerpt 7 for CO 

control technology costs.

Commenter Name: Elizabeth E. Bass

Commenter Affiliation: Tuolumne County

Document Control Number: EPA-HQ-OAR-2006-0790-2250

Comment Excerpt Number: 2

Comment: Requiring PM controls for new boilers with a heat input rating greater than 10 

MMBtu/hr (defined as "large boilers") and using PM as a surrogate for non-mercury metallic 

HAPs is supported. However, there are concerns about the costs associated with requiring post 

combustion controls for new biomass boilers with a heat input rating of less than 10 MMBtu/hr 

(defined as "small boilers"). The proposed rule states that it is cost effective to apply control 

equipment such as fabric filters and ESPs to large boilers. We question whether fabric filters and 

ESPs are cost effective for large boilers rated just above the large boiler threshold (10 - 20 

MMBtu/hr). We also question whether applying these same types of control equipment to small 

boilers is cost effective. It does not appear that the proposed rule specifically addresses whether 

applying the above mentioned controls to small boilers is cost effective. This is a critical point 

since the costs for sophisticated controls can effectively preclude the use of small biomass 

boilers being used. 

Response: See repsonse to comment EPA-HQ-OAR-2006-0790-1300.1, excerpt 2 for PM 

control technology costs. See repsonse to comment EPA-HQ-OAR-2006-0790-1962.1, excerpt 5 

for small boiler control technology costs.

Commenter Name: Arthur Blazer

Commenter Affiliation: Council of Western State Foresters

Document Control Number: EPA-HQ-OAR-2006-0790-1962.1

Comment Excerpt Number: 5

Comment: Implementation of the Area Source Rule will have substantial negative economic 

impacts on small boilers. EPA specifically states that “we propose to regulate biomass-fired... 

boilers under GACT” due to concerns surrounding the costs of control technologies to small 

entities. However, in order to meet the proposed PM emissions limits, new biomass boilers are 

required to install either electrostatic precipitators or fabric filters. The cost of these technologies 

per unit of boiler output is greater for smaller boilers. Therefore, there are basic economic 
reasons why smaller biomass boilers cannot employ the same control technologies as larger 

boilers. 

Response: See the preamble for discussion on the cost impacts and revised limits.

Commenter Name: Tim W. Sonnichsen

Commenter Affiliation: Sonnichsen Engineering, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-2139.1

Comment Excerpt Number: 10

Comment: The economic burden on industrial plants will be staggering 

The rules attempt to quantify the economic impacts of imposing MACT on Area and Major HAP 

Sources. Cost estimates are presented on an annualized basis that, in effect, includes a factor of 

approximately 10% of the initial total capital costs. For example, installing a piece of equipment 

with the associated engineering and administrative services valued at $500,000 would generate 

an annualized cost of approximately $50,000. 

In my opinion, these estimates for existing Area Source boilers are misleading and grossly 

understated. Table 3 of the Area Source Rule indicates that the 11,000 affected existing biomass 

units will have a total annualized cost of $48 million annually, or approximately $5000 per unit. 

Based on the above, each unit would have a budget for all equipment and services of 

approximately $50,000 to comply with the CO emission standard. In my opinion, this will be 

wholly inadequate based on the likely need to install advanced overfire air systems and/or 

oxidation catalysts to meet the 160 ppm standard . The total capital costs for these installations 

will range from several thousand dollars to up to a million dollars per unit. In effect, the MACT 

cost values underestimate the costs of CO control by a factor of at least 10 and perhaps over 20. 

The total annualized costs for existing units would be 5 to 10 billion dollars annually rather than 

the $436 million giv en in the rule. The annualized cost to each unit to control CO (with little or 

no effect on organic HAP’s) would be $50,00 0 to $100,000 assuming that suitable CO control 

technology can be applied at all. 

The economic impact on new biomass units would be greater due to the need to install oxidation 

catalysts to meet the 100 ppm CO limit. The rule estimates that the annualized cost will be 

$65,000 per unit. Installing a $1 million dollar catalyst will result in an annualized cost twice that 

figure due to the need to periodically clean or replace the catalyst materials. 

I understand that several representatives of the wood-products industry, other owners and 

operators of biomass boilers, and several other industrial trade groups will provide comments on 

the MACT rules. Some will include the cost impacts to their facilities. Kindly consider their 

projections of the costs for achieving these MACT standards as real. (I helped prepare some of 

these estimates and can assure the EPA that they are, if anything, conservatively low for the 

retrofit of control technologies.) 
Response: See response to comment EPA-HQ-OAR-2006-0790-2025.1, excerpt 61 for cost of 

oxidation catalyst as a CO control technology.

Commenter Name: Michael Hutcheson

Commenter Affiliation: Ameren Corp.

Document Control Number: EPA-HQ-OAR-2006-0790-2012.1

Comment Excerpt Number: 10

Comment: US EPA’s estimate of costs underestimates the costs of controls by underestimating 

the cost of electricity to run those controls. Electricity costs are an annual cost of control and are 

a major component of the annualized cost of controls estimated. US EPA uses data from the US 

DOE Energy Information Agency to assess the annual cost of electricity associated with the cost 

of control. However, the US EPA erred by using data on national average reported revenue from 

industrial customers per net megawatt generated. The US EPA mistakenly associates utility 

revenue with industrial cost data which is inappropriate. The utility revenue data utilized does 

not include other costs borne by customers including taxes, distribution charges and 

environmental or other surcharges. In addition, similar higher revenue data per megawatt 

generated was also available for commercial accounts, however, this data was ignored despite 

the fact that the Boiler MACT affects commercial and institutional boilers. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1783.1, excerpt 2 for control 

technology costs. 

See preamble for response to unique comment: underestimate cost of controls due to cost of 

electricity

Commenter Name: Kyle Gibeault

Commenter Affiliation: Biomass Thermal Energy Council, BTEC

Document Control Number: EPA-HQ-OAR-2006-0790-1914.1

Comment Excerpt Number: 12

Comment: The economic and cost modeling for EPA’s boiler regulation are narrowly defined 

and do not reflect the reality and diversity in the biomass boiler marketplace. Proposed 

compliance measures entail installing an Electrostatic Precipitator (ESP) or a baghouse for 

boilers <5 MMBtu, which could equal or exceed the cost of the boiler itself, while for larger 

systems (<30 MMBtu), these control technologies could cost $150,000-$250,000. These 

proposed add-ons will make most biomass boiler projects uneconomical and discourage 

investment. 

Response: See the preamble for discussion on the cost impacts.
Commenter Name: Christy Sammon

Commenter Affiliation: Southeastern Lumber Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1954.1

Comment Excerpt Number: 15

Comment: The financial impact analysis for the area source rule fails to consider all of the costs. 

The financial analysis apparently does not include costs for the catalytic oxidizers that would be 

required to meet the proposed CO limits for area source biomass boilers. The high moisture 

content of the biomass fuels requires special firebox designs and combustion air systems, and 

these systems inherently result in higher levels of CO in the combustion process. Boiler tuning 

will not meet the proposed CO limits. A catalytic oxidizer would be required, and since 

particulate matter would damage the catalytic media, a particulate control device such as an ESP 

would be required ahead of the oxidizer. 

The cost to install a particulate control device and a catalytic oxidizer on a boiler could easily be 

one million dollars and could be significantly more for larger boilers. It is uncertain how many of 

the 10,958 biomass boilers that EPA believes are located at area sources are larger than the 10 

MMBtu/hr exemption level, and will, therefore, require these controls, but if only 25% require 

these controls the total cost would be 2.7 billion dollars or more. EPA has failed to consider 

these costs in the economic impact analysis for biomass boilers in the area source rule. In 

developing GACT standards, EPA is allowed to consider costs and this is clearly a case where

that consideration should lead to the selection of work practices rather than numerical limits 

requiring the installation of controls. 

Response: See response to comment EPA-HQ-OAR-2006-0790-2025.1, excerpt 61 for cost of 

oxidation catalyst as a CO control technology.

Commenter Name: Arthur Blazer

Commenter Affiliation: Council of Western State Foresters

Document Control Number: EPA-HQ-OAR-2006-0790-1962.1

Comment Excerpt Number: 18

Comment: Financial Impacts on New Projects 

To demonstrate the impact of the proposed regulations to project viability, fuel cost savings and 

project value are presented for a current USFS technical assistance project at a rural high school. 

Table 3 [SEE PDF FOR TABLE] presents the financial analysis for the installation of a 3.5 

mmBtu/hr central biomass boiler at the school. Project financial analyses are run with and 

without impacts from the proposed rule. 

The addition of an electrostatic precipitator and implementation of the required testing regime 

reduces the lifetime project value of the investment by more than 40%. While this is an example 

of the impact to a system less than 10 mmBtu/hr, larger systems will face similar, although less 

drastic financial impacts. 
Response: See response to comment EPA-HQ-OAR-2006-0790-1962.1, excerpt 5 for small 

boiler control technology costs.

Commenter Name: Jim Griffin

Commenter Affiliation: American Chemistry Council

Document Control Number: EPA-HQ-OAR-2006-0790-1925.1

Comment Excerpt Number: 3

Comment: In addition, EPA does not have enough data to support its assumption that fabric 

filters alone will be sufficient for area source coal-fired boilers to meet the proposed mercury 

limit. Sources likely will be burning coal with sufficiently variable mercury content to make 

carbon injection necessary as a control measure. EPA only gathered mercury emissions data 

from 9 coal boilers out of the estimated 3,710 that will be regulated by this rule and the Agency 

has gathered no fuel variability data for these boilers. Not accounting for actual or potential fuel 

mercury variability among the best performers is a gross omission that results in a standard that 

is not reflective of emission rates achieved in practice by best performers under worst case 

conditions that can be expected to occur, and this creates a standard that severely limits the 

achievability by other affected sources. This is contrary to CAA requirements. An analysis of 

EPA’s database for boilers at major sources shows that there are over 100 boilers in the coal 

subcategory with mercury emissions greater than the proposed area source limit of 3E-06 lb 

Hg/MMBtu, and over 40 of these units are equipped with fabric filters. As EPA has 

acknowledged that mercury is a fuel-based HAP, it is reasonable to assume that there are also 

coal-fired boilers at area sources that will not meet the proposed mercury limits with a fabric 

filter alone. Therefore, if EPA intends to retain a numerical emission limit for mercury in this 

rule, the cost analysis for mercury controls must be re-evaluated. 

Response: See the preamble for discussion on the cost impacts and revised limits. Please note 

that a fuel variability factor is now included in the MACT floor calculations.

Costs: Testing and Monitoring

Commenter Name: George Whiting

Commenter Affiliation: EcoHeat Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-0832

Comment Excerpt Number: 1

Comment: My company has recently introduced a wood pellet fueled central heating boiler, the 

EcoBoiler. Getting to this point has been a very expensive endeavor. The boiler has been safety 

tested and it burns much more cleanly than any wood boiler. We cannot afford to have testing 
regimens imposed on us, particularly ones such as proposed which does not conform to realworld experience. 

Response: See response to comments EPA-HQ-OAR-2006-1287, excerpt 3 and EPA-HQ-OAR2006-0790-1990.1, excerpt 12 for affect of monitoring requirements and costs on biomass 

systems.

Commenter Name: Charles Niebling

Commenter Affiliation: New England Wood Pellet

Document Control Number: EPA-HQ-OAR-2006-0790-0836

Comment Excerpt Number: 9

Comment: In addition to system improvements, annual emissions testing is conservatively 

estimated at $8,000- $15,000 per boiler system. That added cost likely surpasses the biomass fuel 

bill for smaller systems and is a major budget consideration for larger systems. Annual testing is 

also infeasible given geographical considerations, particularly in rural areas. Currently, there are 

simply not enough companies capable of conducting the annual testing. In Maine, there is not a 

single such company. Requiring annual testing will put a significant economic burden on 

schools, local governments, and small businesses. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1926.1, excerpt 3 for annual 

emissions testing costs for rural areas.

Commenter Name: Nathan McClure

Commenter Affiliation: Georgia Forestry Commission

Document Control Number: EPA-HQ-OAR-2006-0790-1287

Comment Excerpt Number: 3

Comment: The NREL studies also show that greenhouse gas warming potential is reduced by 

94% over direct fired coal power plants when using dedicated biomass feedstock in an integrated 

gasification combined cycle system. Small diameter trees removed during thinnings and other 

operations on managed forests in the South are also “dedicated” to harvest for market products, 

including biomass. 

• Therefore, new rules that increase air emission monitoring requirements and costs to meet these 

requirements on biomass-fired systems will discourage retention of renewable energy systems 

and be a roadblock for new investments in these type systems. This will likely further result in 

reversion to fossil fuel systems that could increase greenhouse gas, NOX, and SOx. 

• In addition, new rules that increase air emission monitoring requirements on biomass-fired 

systems could also affect a transfer of wood product manufacturing to other countries. This 

would result in the loss of jobs and other negative impacts on the economies of rural 

communities in the US, as well as a net increase in all pollutants from the manufacturing 
operation, because of less regulation on air emissions in Asia and South America where the 

manufacturing will likely occur. 

Response: See preamble for response.

Commenter Name: Steven D. Swanson

Commenter Affiliation: Swanson Group, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1241

Comment Excerpt Number: 4

Comment: The ongoing monitoring costs at each of our facilities and reduced production levels 

at one or more of our facilities (i.e. to meet the limits we will have to operate our boilers at less 

than full load) will make us less competitive. These problems are exacerbated by the fact that our 

products, while being consumed in the US, compete with foreign imports. Our competitors in 

foreign countries will most certainly not be burdened by these extra costs which will put 

additional strain on our ability to compete. 

Response: Please see preamble for changes to emission limits, as well as testing and monitoring 

costs.

Commenter Name: David Schutz and John Ussery

Commenter Affiliation: Northern New Mexico College

Document Control Number: EPA-HQ-OAR-2006-0790-1834.1

Comment Excerpt Number: 6

Comment: The costs of monitoring alone could have severe negative effects on the economics 

of using sustainable green fuels grown in local forests. 

Response: See response to comments EPA-HQ-OAR-2006-1287, excerpt 3 and EPA-HQ-OAR2006-0790-1990.1, excerpt 12 for affect of monitoring requirements and costs on biomass 

systems.

Commenter Name: N/A

Commenter Affiliation: Sierra Club, Earth Justice, Clean Air Task Force, Natural Resources 

Defense Council

Document Control Number: EPA-HQ-OAR-2006-0790-1982.1

Comment Excerpt Number: 19

Comment: EPA’s claims regarding economic limitations are similarly without merit. Although 

EPA is proposing MACT standards only for mercury and CO, EPA assumes – without any 
explanation – that sources would have to conduct annual stack tests for PM. 75 Fed. Reg. at 

31906. Thus, EPA arbitrarily and irrationally inflates the cost of compliance with mercury and 

CO emission standards by adding to them the alleged costs of compliance with a PM standard 

that it does not even propose to promulgate. Without the cost of a PM stack test, the total cost to 

sales ratio would be lower than the three percent that EPA views as excessive. 

Response: See response to comment EPA-HQ-OAR-2006-0790-2002, excerpt 2 for monitoring 

costs estimates of PM and CO.

The stack test costs have been updated to include relevant testing costs.

Commenter Name: N/A

Commenter Affiliation: Sierra Club, Earth Justice, Clean Air Task Force, Natural Resources 

Defense Council

Document Control Number: EPA-HQ-OAR-2006-0790-1982.1

Comment Excerpt Number: 20

Comment: Even if EPA’s discussion of cost concerns were not based on artificially inflated cost 

estimates, they would not be relevant to the statutory standard, that measurement methodology is 

not “practicable” due to economic limitations. EPA does not claim that compliance would be 

economically impracticable for boilers with heat input capacity less than 10MMBtu, only that 

compliance cost would exceed three percent of firm revenues for many boilers. That costs might 

exceed three percent of firm revenues does not make them impracticable, and EPA does not 

provide any reason to so believe. EPA does claim that compliance costs for schools and farms 

would be “prohibitive.” Even if that were true, it would not support the agency’s conclusion that 

enforcement of emission standards is impracticable for other boilers with a heat input capacity 

less than 10MMBtu. Moreover, EPA does not show that compliance costs would be 

impracticable for any units. 

Response: Please see Preamble for discussion of the costs associated with the rule.

Commenter Name: N/A

Commenter Affiliation: Sierra Club, Earth Justice, Clean Air Task Force, Natural Resources 

Defense Council

Document Control Number: EPA-HQ-OAR-2006-0790-1982.1

Comment Excerpt Number: 21

Comment: EPA’s analysis of costs also assumes that the only way to measure emissions so that 

emissions standards could be enforced would be an annual stack test for mercury and PM and a 

CEM for CO. Leaving aside that EPA is not even proposing a MACT standard for PM, and 

assuming arguendo that the combined cost of an annual stack test of mercury and a CO CEM is 
impracticable for some units, the agency provides no support for its claim that enforcement of 

mercury and CO standards could not be done through cheaper methods or could not be done for 

some subset of the boiler population. As noted above, the record plainly shows that the operators 

of smaller boilers can and do test their emissions and it is presumably done in a manner that is 

not impracticable. Yet the agency does not even attempt to evaluate cheaper compliance 

measures or identify any particular units or groups of units for which enforcement would truly be 

impracticable – creating the strong impression that the is simply choosing methods that it regards 

as expensive so that it can then reject those methods as too expensive. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1923.1, excerpt 10 for reducing 

impacts of monitoring. 

See preamble for response.to unique comment: didn't evaluate cheaper compliance measures .

Commenter Name: Chris Mello

Commenter Affiliation: Alaska Energy Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1653.1

Comment Excerpt Number: 3

Comment: The Alaska Wood Energy Development Group developed an estimate of the cost of 

annual stack testing for a rural Alaskan village. [See submittal for data table.] The following 

chart summarizes the quote received from Alaska Source Testing for the village of Stebbins, 

currently installing a biomass district heating system. Alaska Source Testing is one of Alaska’s 

two emissions testing companies. The estimated cost of annual stack testing in a rural Alaskan 

village is approximately $15,785. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1926.1, excerpt 3 for annual 

emissions testing costs for rural areas.

Commenter Name: Stephen E. Woock

Commenter Affiliation: Weyerhaeuser Company

Document Control Number: EPA-HQ-OAR-2006-0790-1984.1

Comment Excerpt Number: 5

Comment: The significant monitoring and reporting burdens and investment costs that will 

accompany the proposed PM limits proposed for new biomass boilers will dissuade such an 

investment. 

Response: See respsonse to comment EPA-HQ-OAR-2006-0790-2002, excerpt 2 for monitoring 

costs estimates of PM and CO. 
See response to comments EPA-HQ-OAR-2006-1287, excerpt 3 and EPA-HQ-OAR-2006-0790-

1990.1, excerpt 12 for affect of monitoring requirements and costs on biomass systems.

Commenter Name: Andrea Grant

Commenter Affiliation: Castle Oil Corporation

Document Control Number: EPA-HQ-OAR-2006-0790-1945.1

Comment Excerpt Number: 11

Comment: The Preamble states that monitoring equipment for CO is readily available. While it 

may be possible to obtain such equipment, it is not currently used by the fuel oil industry. Thus, 

it would represent a substantial capital expense for either the owner/operator of the boiler or the 

fuel oil provider if that company were to conduct the required tests. Indeed, because of these 

high costs, most fuel providers engaged to ensure that the boiler is compliant with EPA 

standards, would likely retain the services of an outside testing service. It is estimated that the 

cost of such services are prohibitive — each test for PM and CO would cost approximately 

$10,000 per boiler. 

Response: See response to comment EPA-HQ-OAR-2006-0790-2002, excerpt 2 for monitoring 

costs estimates of PM and CO.

Commenter Name: Chris Mello

Commenter Affiliation: Alaska Energy Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1653.1

Comment Excerpt Number: 11

Comment: The proposed NESHAP rule for area sources requires management practices (a 

maintenance plan) for existing and new biomass boilers. Annual source testing is required for all 

boilers installed after June 4, 2010. As discussed above, annual source testing could increase the 

O&M costs for an installation by 15-30 times. 

The costs to these small rural communities to source test these boilers will be immense. 

Installation of controls required to meet the emission standards will incur increased capital and 

operating costs. Costs will be further exacerbated by the high costs to transport and house 

technicians to perform required maintenance. EPA argues 11! the RICE NESHAP proposed rule 

that source testing is too expensive to be justified for smaller engines not subject to numerical 

emission standards. Since EPA acknowledges cost as a consideration, should EPA demonstrate 

by regulation that urban HAP standards do apply to rural areas, rural Alaska should be subject to 

GACT, not MACT, and EPA should limit the area source requirements to maintenance and 

management practices for commercial, industrial, and institutional. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1926.1, excerpt 3 for annual 

emissions testing costs for rural areas.
Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 58

Comment: On page 31910 of the proposal preamble, it is stated that “The proposed 

requirements [for demonstrating compliance] ensure compliance with this proposed rule without 

proposing a significant additional burden for facilities that must implement them.” This is 

patently false. The compliance requirements for CO monitoring and stack testing for liquid-fired 

boilers and the work practice, recordkeeping and reporting requirements for all sources are 

clearly huge new burdens. 

All affected sources must file initial notices and keep records. All sources with an affected boiler 

with a design heat input capacity ?10 MMBTU/hr must undergo an energy assessment. Boilers 

of <10 MMBTU/hr must do biennial tune-ups. These are extensive requirements, whose costs 

and burdens are significantly underestimated in the rule analysis, as we have discussed in our 

comments on each of these areas. 

Response: See repsonse to comment EPA-HQ-OAR-2006-0790-2002, excerpt 2 for monitoring 

costs estimates of PM and CO.

Commenter Name: Sarah E. Amick

Commenter Affiliation: Rubber Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1918.1

Comment Excerpt Number: 3

Comment: Existing area source boilers greater than 100 MMBtu/hr are required to install 

continuous emissions monitoring systems (CEMS). CEMS installation on RMA member boilers 

over 100 MMBtu/hr will cost the industry an additional $700,000 dollars. Requiring natural gas 

fired boilers that are designed to burn oil fuels as a back-up during periods of curtailment, gas 

supply emergencies, or during short-term spikes in natural gas prices due to limited availability, 

to install costly add-on controls that may infrequently be used seems counter productive. 

Because this cost estimate does not include costs of work practice, notification, recordkeeping 

and reporting requirements, the total cost for add on controls plus monitoring and maintenance 

costs will be significantly greater. 

Response: See response to comment EPA-HQ-OAR-2006-0790-2002, excerpt 2 for monitoring 

costs estimates of PM and CO.
See preamble for response to unique comment: cost of CEMS, cost estimate does not include 

work practice, recordkeeping/reporting, the total cost for controls plus monitoring will be 

greater.

Commenter Name: Alice Edwards

Commenter Affiliation: Alaska Department of Environmental Conservation

Document Control Number: EPA-HQ-OAR-2006-0790-1926.1

Comment Excerpt Number: 3

Comment: The required annual performance tests for new boiler will be particularly onerous for 

Alaskan sources. ADEC believes that the proposed rule will place an extraordinary burden on 

rural communities and others with small boilers who would need to perform annual performance 

tests under the proposal. The majority of Alaskan communities have fewer than 500 residents 

and are located in remote areas of the state without road access. These communities have limited 

economic and technical resources. Each community typically has a school, post office, health 

clinic, small airport, and one or two other community buildings. Most communities have no 

hotel, rental housing units, or restaurants. 

The main source of travel from Anchorage to rural communities is by commercial airline to a 

main hub. From the hub, travel to smaller communities is by small seven to twelve passenger 

planes. The logistics of transporting performance test equipment with an estimated weight of 

1,800 pounds to rural communities is riddled with difficulties. From Anchorage to one of the 

hubs, equipment has to be shipped on pallets. Upon reaching the destination hub the equipment 

is taken off the pallets and then transported by small plane. Depending on the weight limit of the 

small plane, this can take more than one and possibly up to three trips. The approximate cost for 

shipping the performance test equipment to a central hub such as Bethel is $1,500. The 

transportation from the hub to the rural community may be two and half times this cost. These 

costs do not include the return transportation costs for shipping the performance test equipment 

back to Anchorage. Additionally, extreme arctic summer and winter conditions frequently 

prevent or delay travel. Delays in travel would result in communities having to pay additional 

standby fees above the performance test cost. Estimated performance test costs can rapidly 

exceed $13,000 annually. Such costs would be prohibitive for rural communities and would 

strain their already tight budgets. 

Response: See preamble for response.

Commenter Name: Elizabeth E. Bass

Commenter Affiliation: Tuolumne County

Document Control Number: EPA-HQ-OAR-2006-0790-2250

Comment Excerpt Number: 5

Comment: Initial source testing to determine compliance with applicable emissions limits is 

supported. However, due to the costs associated with performing these tests, subsequent annual 
source testing is not warranted, particularly if the initial source test indicates emissions well 

below threshold levels. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1923.1, excerpt 10 for reducing 

impacts of monitoring. 

Please see the preamble for current testing requirements.

Commenter Name: Jim Pettiford

Commenter Affiliation: Fulton Thermal Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2192.1

Comment Excerpt Number: 5

Comment: Uncertainty over the accuracy of reasonably priced flue gas emission analyzers is a 

concern. Where 3ppm represents a ‘fail’ and 2ppm a ‘pass’ a high degree of accuracy and 

certainty is required. Typical, currently available, flue gas analyzers in the price range of a few 

thousand dollars do not have this kind of reliable resolution. The cost burden of purchasing such 

analyzers and arranging for their safe transportation to site to ensure proper operation is in our 

opinion overly burdensome. 

Response: Please see the preamble for current emission limits and testing requirements.

Commenter Name: Robert G. Hedden

Commenter Affiliation: Oilheat Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-2249

Comment Excerpt Number: 6

Comment: According to NYSERDA’s experience performing similar tests to the ones proposed 

by this rulemaking, the cost is approximately $10,000 per boiler. The retail cost for a less than 3 

MMBtu/h boiler is less than $3,000. The required test is over three times the cost of the boiler. 

Our new boilers are dramatically more efficient than many of the boilers operating in the field, 

but the unintended consequence of this rulemaking will be a very powerful disincentive for an oil 

heat user to replace their old inefficient boiler. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1241, excerpt 4 for secondary 

impacts of testing and monitoring costs.

See preamble for response to unique comment: Cost of testing disincentive for an oil heat user to 

replace their old inefficient boiler.
Commenter Name: Martin Lunde

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2065.1

Comment Excerpt Number: 8

Comment: High costs of testing and compliance measures for biomass boiler 

Response: See response to comments EPA-HQ-OAR-2006-1287, excerpt 3 and EPA-HQ-OAR2006-0790-1990.1, excerpt 12 for affect of monitoring requirements and costs on biomass 

systems.

Commenter Name: Cynthia A. Finley

Commenter Affiliation: National Association of Clean Water Agencies

Document Control Number: EPA-HQ-OAR-2006-0790-2260.1

Comment Excerpt Number: 9

Comment: To reduce compliance costs, EPA should adopt more economical test methods, such 

as the use of handheld meters. EPA should also reduce the bookkeeping requirements, such as 

eliminating the requirement for daily fuel records to prove that solid fuels are not used. Facilities 

such as wastewater utilities often contract for fuel on a long-term basis, making a daily fuel 

records unnecessary. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1923.1, excerpt 10 for reducing 

impacts of monitoring.

Commenter Name: Charles B. Jones, III

Commenter Affiliation: Georgia Traditional Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1923.1

Comment Excerpt Number: 10

Comment: GTMA believes that EPA greatly underestimates the cost of annual stack testing. 

While several pollutants may be monitored for not much more than the cost of a single pollutant 

once set up, the majority of the cost of stack testing is mobilization and demobilization of the 

testing contractor. There are also the expenses of providing stack access and installing testing 

ports in stacks if not already present. It is unreasonable to require a source as small as 10 

MMBtu/hr to test annually, if at all. EPA proposes annual performance (stack) tests to ensure, on 

an ongoing basis, that the APCDs are operating properly_ At the same time, EPA is requiring 

parametric monitoring of certain scrubber parameters on an on-going basis to also demonstrate 

proper functionality of the control device. 

For example, one of GTMA’s members has a TV permit with SM limits for HAP to avoid 

MACT, which requires the facility to conduct a stack test initially to determine the proper 
operating levels for the parameters to be monitored in order to achieve adequate control of HAP 

to stay below 10/25 tpy. In that case, ongoing parametric monitoring and subsequent reporting of 

excursions from established proper operating ranges in TV semi-annual and annual compliance 

certification reports is sufficient to demonstrate compliance with SM HAP limits. 

Requiring stack testing be repeated annually in addition to ongoing parametric monitoring is 

unreasonable and unnecessary. 

Response: Please see the preamble for changes to testing and monitoring requirements.

Commenter Name: Martin Lunde

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2065.1

Comment Excerpt Number: 10

Comment: There has to be some recognition that small rural commercial, industrial and farm 

users do not have the resources to fund stack testing on a yearly basis, let alone buy ever more 

expensive equipment. The largest GARN system consumes a total of about $39,000 of locally 

harvested cordwood per year in their 4 GARN units. Stack testing might cost $5,000 per unit for 

a total of $20,000 per year...significantly increasing their cash flow requirements. Simply 

unrealistic; thus would probably force the school to use imported oil as their heat source. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1926.1, excerpt 3 for annual 

emissions testing costs for rural areas.

Commenter Name: Charlie Cary

Commenter Affiliation: Biomass Combustion Systems, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1990.1

Comment Excerpt Number: 11

Comment: The cost of regular stack testing as required by the proposed regulations has little off 

setting benefit and will reduce the economic viability of this renewable, low carbon fuel. On 

smaller systems, these annual tests can cost as much as the equipment saves over fossil fuel 

making a payback from the investment in wood energy impossible. On larger systems the cost 

will raise the bar for payback when a lower cost annual tune up will ensure that the boiler is 

operating at peak efficiency. Tune ups will insure the best performance out of an existing 

American investment while annual testing and punishing those who can not meet new, tougher 

standards, will simply drag down the already down forest products industry. 

Response: See preamble for response.
Commenter Name: Steven A. Brink

Commenter Affiliation: California Forestry Association

Document Control Number: EPA-HQ-OAR-2006-0790-2026.1

Comment Excerpt Number: 12

Comment: Under EPA’s new annual emissions testing requirement, testing expenses would add 

an estimated $8,000- $15,000 per boiler system. That added cost likely surpasses the biomass 

fuel bill for smaller systems and is a major budget consideration for larger biomass boiler 

systems. Also, proposed compliance technology requirements could cost more than the biomass 

systems themselves. 

Response: See response to comments EPA-HQ-OAR-2006-1287, excerpt 3 and EPA-HQ-OAR2006-0790-1990.1, excerpt 12 for affect of monitoring requirements and costs on biomass 

systems.

Commenter Name: Kyle Gibeault

Commenter Affiliation: Biomass Thermal Energy Council, BTEC

Document Control Number: EPA-HQ-OAR-2006-0790-1914.1

Comment Excerpt Number: 13

Comment: In addition to system improvements, annual emissions testing is conservatively 

estimated at $8,000- $15,000 per boiler system. That added cost likely surpasses the biomass fuel 

bill for smaller systems and is a major budget consideration for larger systems. Annual testing is 

also infeasible given geographical considerations, particularly in rural areas. Currently, there are 

simply not enough companies capable of conducting the annual testing. In Maine, there is not a 

single such company. Requiring annual testing will put a significant economic burden on 

schools, local governments, and small businesses. 

Response: See response to comment EPA-HQ-OAR-2006-0790-1926.1, excerpt 3 for annual 

emissions testing costs for rural areas.

Commenter Name: Martin Lunde

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2065.1

Comment Excerpt Number: 14

Comment: NIST certified C0 test equipment basic cost ranges from $16,000 to $25,000 plus 

ancillary equipment and ongoing supplies; not an insignificant investment for a small 

manufacturer. 
Response: See response to comment EPA-HQ-OAR-2006-0790-2002, excerpt 2 for monitoring 

costs estimates of PM and CO.

Commenter Name: Wayne York

Commenter Affiliation: Hancock Lumber Company, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2002

Comment Excerpt Number: 2

Comment: EPA seems to have significantly under-estimated the compliance costs for regulated 

facilities. 

We have obtained preliminary estimates of the cost of testing from local testing companies, and 

have found that Method 10 CO testing, with only abbreviated alternatives to Methods 1-4, could 

range from $3,500 to about $7,000 per facility, not including any required work to prepare the 

facility to test, such as installing stack sampling ports and platforms. In addition, these costs do 

not yet include estimates for administration and record-keeping, or conducting tune-ups or other 

facility upgrades which could be needed in order to meet the rule. Therefore, it is clear that the 

complete costs of meeting the proposed rule will be significantly higher than the estimates for 

“total compliance costs” included in EPA’s proposed rule (which we calculate to range from 

$2,595.19 to $4,380.36 per facility per year, based on Table 3 of the Preamble). 

Based on EPA’s figures, there will be nearly 223,000 facilities that will be regulated. The 

wording in the Preamble is unclear what portion of these are greater or less than 10 MMBtu/hr. 

However, it would seem that a significant portion of these will be greater than 10 MMBtu/hr, and 

therefore will need to be tested within six months of the compliance deadline. With so many 

newly-regulated sources needing to be tested, this will have a major impact of the capacity of the 

stack testing companies. It seems inconceivable that the stack-testing industry could 

accommodate this much additional testing in time to meet the deadlines. It is possible that the 

availability of testing firms will be a limiting factor regarding a facility’s ability to comply with 

this proposal. Also, if testing becomes “supply-limited,” testing costs could increase significantly 

above today’s prices. 

EPA conducted a "cost to sales" evaluation to compare the cost of compliance with the rule 

against the revenues of subject facilities. However, in their assumptions, EPA assumed that each 

facility would only have one boiler subject to the rule. In our estimation, most facilities in this 

area have multiple boilers and/or back-up boilers. The reasons for this include matching boiler 

size to heating loads to maximize energy efficiency, and the need for back up if the primary 

boiler goes off-line. Such facilities would have to bear additional testing costs and other 

compliance costs which EPA apparently did not take into account. 

Another reason that EPA’s cost estimates may be too low could be due to regional variations in 

cost. For example, in a rural area with a low population density such as in the State of Maine, 

travel costs can add significantly to the overall testing costs, especially since Department of 

Transportation rules limit the length of the work day for stack testing companies travelling with a 

full reference-method mobile laboratory. With any travel time greater than about 2 hours each 

way, the three one-hour CO runs will not be able to be completed in a one-day test effort, 

considering travel, set-up, testing, take-down, and return travel. This will add significantly to the 

costs of full Reference Method testing. 
Response: See preamble for response.

Social Costs

Commenter Name: Los Angeles Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0397

Comment Excerpt Number: 43

Comment: Those who benefit either economically or through the use of a product should be the 

ones that pay for that product. I should not be asked to subsidize the production of products for 

energy with my life or my health. When hazardous air pollutants are created that combine 

disposal or elimination, costs should be borne by those that benefit from the products. 

Response: EPA acknowledges this comment, but a general discussion of who pays for the 

environmental externalities that occur from the creation of products is outside the scope of this 

specific rulemaking.

Commenter Name: Arlington Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0396

Comment Excerpt Number: 65

Comment: The technology is available off the shelf for all of those size boilers; and yes, it will 

cost a little bit of money to do it, but it essentially is going to -– hopefully, even in doing a costbenefit analysis you look at our toxic rules and the CBAs actually show that there are 

tremendous values to having protective rules. 

And so I think it’s really about creating a rule that’s genuinely protective and at the very least 

having an inventory of all the facilities across this country of what they’re burning, in what 

quantities they’re burning. 

Response: EPA agrees that exposure to fine particulate matter and toxic air pollutants is 

associated with severe health effects. Reducing exposure to these pollutants is associated with 

substantial public health benefits.

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985
Comment Excerpt Number: 99

Comment: It has always been my experience that the EPA doesn’t take into account -- when the 

developing standards, they don’t take into account costs, that -- the costs that have to be made. 

However, since it has been brought up consistently throughout the day, I would like to add to 

that discussion; birth defects, asthma, bronchitis, heart attacks, cancer, premature death. 

These are some of the outcomes of being exposed to the air toxins that have been previously 

discussed, and I would like to see how much that costs. There is a cost associated with that. 

Last week, I was asked to go visit a young mother on the east end who lives next to a source that 

has already been cited for releasing some of the toxins previously mentioned. Because I spoke 

Spanish, they asked me to go talk to her and try to explain to her why her child was born with 

half a brain and suffered for six months and died. I really didn’t have an answer for that. 

All I could do was share her -- her concern. She was also -- she was extremely upset, and 

I’d like to know how much that’s worth. It was very difficult speaking with her, her trying to 

take care of her family, and still having two other children figuring out how -- what she was 

going to do living next to -- to the source, and if anybody was gonna do anything about 

it. I didn’t know what to tell her, but it did prompt me to come and give a few comments today. 

Response: EPA agrees that exposure to fine particulates and toxic air pollutants is associated 

with severe health effects and reducing exposure to these pollutants is associated with substantial 

public health benefits.

Commenter Name: Gary Rubenstein

Commenter Affiliation: Kauai Island Utility Cooperative, KIUC

Document Control Number: EPA-HQ-OAR-2006-0790-2028.1

Comment Excerpt Number: 2

Comment: The Regulatory Impact Analysis (RIA)8 for the Proposed Rule does not include an 

emissions inventory of POM for the sources covered under the regulation. Such an inventory is 

essential in establishing the need for the Proposed Rule and justification that the proposed level 

of control achieves human health benefits. 

Response: A technical memo has been placed in the docket that describes all of the categories 

and pollutants, including POM, used to fulfill EPA obligation under section 112(c)(6).

Commenter Name: Michael A. Livermore

Commenter Affiliation: Institute for Policy Integrity New York University School of Law

Document Control Number: EPA-HQ-OAR-2006-0790-1899.1

Comment Excerpt Number: 8

Comment: EPA’s regulatory impact analysis presents monetized benefits and annualized social 

costs for the year 2013 alone. Annualized social costs are based on estimates of annualized 
engineering-based compliance costs. Benefit estimates are based on emissions reductions in 2013 

alone. Capital costs appear to be annualized over the life of the relevant investment at a 7% 

interest rate (20 years for major equipment, 2 or 4 years for items like fabric filters). The energy 

assessment is annualized over 5 years (although no justification is given for this). While this is 

an appropriate method for determining costs and benefits for 2013, it ignores several important 

longer-term issues. 

For example, shutdown of existing units and increased numbers of new units are not accounted 

for. Shutdown of existing units due to the program would count as additional decreases in 

emissions and increased costs. Shutdown of units due to independent factors would not directly 

count as incremental decreases in emissions; however, this would result in spreading the 

compliance costs of these units over fewer years and fewer reduced emissions, and thus decrease 

the cost-effectiveness of the program. By contrast, the number of new units over time would 

probably add net benefits to the rule. 

In addition to these sorts of effects, the short time horizon for the regulatory impact analysis 

ignores future cost decreases due to both innovation and learning, effectively freezing the cost 

estimates at current technology costs. With technological innovation, economies of scale, and 

learning, compliance costs may decrease with time. [Footnote: For example, fabric filters may 

cost $X right now, last two years, and generate $Y/year benefits. But as the regulation increases 

market share for the filters and incentivizes innovation, as the manufacturers learn more costeffective filter production techniques, and as the polluters learn more cost-effective filter 

application techniques, in future years, maybe filters will only cost $1/2X and last for three 

years, but still generate $Y/year in benefits (or, possibly, $2Y, if the technology improves or if 

new applications have unexpected co-benefits).] Both the White House’s Office of Management 

and Budget and the EPA’s own Economic Analysis Guidelines stress the need to account for 

technological innovation and learning effects. [Footnote: WHITE HOUSE OFFICE OF MGMT. 

& BUDGET, CIRCULAR A-4 at 34 (2003); EPA, 240-R-00-003, GUIDELINES FOR 

PREPARING ECONOMIC ANALYSIS at 5-7(2008 external review draft).] In particular, the 

OMB’s Circular A-4 advises agencies: “The time frame for your analysis should cover a period 

long enough to encompass all the important benefits and costs likely to result from the rule.” 

[Footnote: CIRCULAR A-4, supra note 50, at 15. 

] Due to the short time horizon of its regulatory impact analysis, EPA may have underestimated 

the net benefits of various alternative policies. 

Response: The timeframe for this analysis is consistent with other recent EPA analyses. For 

this rule, the net benefits outweigh the costs even with several unquantified benefit categories.

Economic Impacts

Commenter Name: Gregg Tomberlin

Commenter Affiliation: Novo Energy, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-0834.1

Comment Excerpt Number: 2
Comment: The cost of compliance for existing biomass facilities will be in the billions causing 

many plants to close resulting in significant job losses in the midst of an historic recession. 

Response: Based on the changes made to the proposal regarding biomass-fired boilers, the 

estimated cost of compliance for existing biomass facilities has been reduced. 

Commenter Name: Charles Niebling

Commenter Affiliation: New England Wood Pellet

Document Control Number: EPA-HQ-OAR-2006-0790-0836

Comment Excerpt Number: 10

Comment: Many communities in rural regions rely upon or significantly benefit from the use of 

biomass boilers for consumption of biomass energy crops. By limiting the opportunity for 

biomass boilers, economic losses will be considerable, especially so in the wood products 

manufacturing, forestry, and agriculture sectors. 

Rural economies, which have suffered tremendously during the recession, benefit from the 

production and use of sustainable biomass. It is predicted that 342 private sector jobs are created 

during the production of 200,000 tons of biomass for heat [See submittal for Reference 4]. 

However, the proposed rule will certainly cause the opposite result and invalidate EPA’s original 

estimate of only 2,000 job losses. Biomass demand will drop in response to onerous, expensive, 

and unrealistic regulations; some boiler operators will have to reduce emissions by a factor of 

five over their current State air quality permits or go out of business entirely. The proposed rule 

states that new boiler purchasers have the option of selecting gaseous fuel types that are cleaner 

and avoid emissions testing. In many rural areas, natural gas pipelines do not exist and propane 

(the most expensive fuel type) is typically five to six times more expensive per Btu than wood 

chip fuel. 

Response: In the final rule, existing biomass-fired area source boilers are subject to a 

management requirement of a tune-up instead of the proposed emission limits which reduces the 

estimated cost of compliance for biomass facilities.

Commenter Name: Sheldon Schultz

Commenter Affiliation: Yanke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-0837

Comment Excerpt Number: 16

Comment: The cost impact information in is way off the mark in my opinion. A job loss 

estimate of 1,000 jobs does not match my view at all. In the forest products industry there are 

many existing boilers that are area sources. Most of these boilers are in the steaming capacity of 

40,000 to 100,000 pounds per hour. None of the existing boilers I’m aware of now achieve the 

CO standard and most process steam boilers do not now have CEM’s for CO. None of the 

existing boilers I’m aware of can be altered to achieve the CO standard. Economic times have 
not been favorable to the wood products industry so going into the new requirements the industry 

is not sitting on cash waiting to be spent. In the West there is a great deal of competition from 

Canada where in Alberta Province the CO standard for wood fired boilers is about 800 ppm. 

When the Boise Cascade sawmill shut down in Council, Idaho there was a loss of ninety mill 

jobs, about one hundred woods jobs, a few restaurants, a few gas stations, the hospital closed, 

student population dropped in the public school and hence teachers have suffered two pay cuts 

and the schools have dropped a number of extra-curricular programs. The value of property in 

Council fell according to the number of homes on the market due to lost jobs. In today’s lumber 

market there is no place to pass on the cost. In rural areas the 1,000’s of jobs that will be lost 

cannot be replaced by the creation of new energy auditor jobs. When the jobs go away the boiler 

becomes surplus equipment so it is not clear that the jobs created by the rule will have enough 

work to do 

Response: In the final rule, the proposed CO emission limitation for biomass boilers has been 

replaced with a management practice requirement of a biennial tune-up. There are no continuous 

monitoring requirements for existing biomass boilers in the final rule. Thus, the economic 

impact on these biomass facilities has been significantly reduced. 

Commenter Name: Los Angeles Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0397

Comment Excerpt Number: 24

Comment: EPA needs to look realistically at the economic impacts of these proposals. And I 

just add that many of our facilities in the forest products industry are in rural areas where 

manufacturing family-wage jobs are hard to find. And so we’re a major part of a vital and green 

economy in rural areas. We’ve been challenged by the recession, which has impacted our 

industry dramatically. We’ve lost 350,000 jobs in the industry in total. Some will say we’re 

crying wolf on jobs. I think I can confidently say that these rules, as they’re proposed, you’re 

going to find more plant closures. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0837

Comment Excerpt Number: 16

Commenter Name: Los Angeles Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0397

Comment Excerpt Number: 42

Comment: Overall, we believe Boiler MACT and the other boiler rules are too restrictive. It will 

place an enormous burden on manufacturers. It will impose unjustified limits that will impose a 
large unnecessary economic burden on the country. And the EPA has an opportunity to modify 

these requirements while being faithful to the legal obligation. 

Response: The EPA used a standard market analysis to analyze the proposed standards. The 

approach uses a single period multimarket partial equilibrium model to compare pre-policy 

market baselines with expected post-policy market outcomes. The analysis’ time horizon is the 

intermediate run; some production factors are fixed and some are variable and is distinguished 

from the very short run where all factors are fixed and producers cannot adjust inputs or outputs. 

The intermediate time horizon allows us to capture important transitory stakeholder outcomes. 

Key measures in this analysis include industry-level changes in price levels, production and 

consumption, jobs, international trade, and social costs (changes in producer and consumer 

surplus). The analysis did not show large changes in production, prices, or imports.

Commenter Name: Arlington Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0396

Comment Excerpt Number: 50

Comment: As proposed, the rules impose emission limits with no known means or assurance of 

achieving them. This will result in incredible uncertainty in the regulated community and a 

reluctance to invest in the United States. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0837

Comment Excerpt Number: 16

Commenter Name: Thomas McMillan

Commenter Affiliation: Baldwin Pole and Piling Co., Inc

Document Control Number: EPA-HQ-OAR-2006-0790-0608.1

Comment Excerpt Number: 1

Comment: We are joining with our wood preserving competitors and many other wood products 

facilities to comment on the proposed Boiler MACT Rules. Clearly, we are dismayed and 

discouraged over what the consequences would be to our small company business should these 

new regulations become law. 

If the projections are correct for what it will cost for us to comply (1-2 million dollars), with no 

guarantee that compliance is achievable, we are certain what our future business plan would be. 

We would simply convert our dry kilns from steam indirect fired back to a natural gas direct 

fired burner. The total cost to convert both kilns is estimated at approximately $400,000.00. The 

four employees currently working at the bark boiler would no longer be needed which would 

reduce our overall workforce by 10 percent and we would go to automatic controls requiring no 
manpower to operate. Furthermore, the automatic controls would allow us to operate the kilns 

over the weekend when electricity rates are lower. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836

Comment Excerpt Number: 10.

Commenter Name: Charles Thomas III

Commenter Affiliation: Shuqualak Lumber Co., Inc.

Document Control Number: EPA-HQ-OAR-2006-0790-0609

Comment Excerpt Number: 1

Comment: It has come to my attention that our company, Shuqualak Lumber Co., located in 

Shuqualak, MS is going to be required to install millions of dollars of equipment on our wood 

fired boilers due to proposed rules in the Boiler MACT. We have four wood fired boilers at our 

facility and if these rules are enforced, it will shut us down! We are located in one of the poorest 

counties in the United States. In fact, we are one of the few remaining industries in our county. 

These proposed rules will eliminate 105 direct jobs and approximately 800 indirect jobs. 

Response: The EPA used a standard market analysis to analyze the proposed MACT standards. 

The approach uses a single period multimarket partial equilibrium model to compare pre-policy 

market baselines with expected post-policy market outcomes. The analysis’ time horizon is the 

intermediate run; some production factors are fixed and some are variable and is distinguished 

from the very short run where all factors are fixed and producers cannot adjust inputs or outputs. 

The intermediate time horizon allows us to capture important transitory stakeholder outcomes. 

Key measures in this analysis include industry-level changes in price levels, production and 

consumption, jobs, international trade, and social costs (changes in producer and consumer 

surplus). This analysis was done on the national level for many reasons. Impacts on price level, 

international trade, national production, and jobs could not have been estimated if the analysis 

focused on regional or state levels. EPA also does not have the necessary data to estimate 

impacts on individual states. Even if EPA had the data a detailed estimate of individual state and 

industry responses would be beyond the scope of what could be accomplished for this analysis.

Commenter Name: Carolina Dauzat

Commenter Affiliation: Rex Lumber

Document Control Number: EPA-HQ-OAR-2006-0790-0610

Comment Excerpt Number: 1

Comment: I am writing this in response to the proposed rules for area source Boiler MACT. The 

rules the EPA is proposing are not achievable. These rules in enacted will cause great hardship to 

our industry and most likely cause the closure of many sawmills. In Florida alone, the estimate 

for capital expenditures in the forest products industry is over $170,000,000. We are located in 

rural small towns in the panhandle of Florida and soon rural Mississippi. The closure of our 
plants will be devastating on each of these local economies, losing over 125 jobs per location, 

that is a total loss of 375 jobs. Small towns need these jobs. We are one of the few manufacturing 

industries that still successfully operate in the United States, is the point to get rid of us too? 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0609 

Comment Excerpt Number: 1 

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 10

Comment: At the end of the day, we’ve heard a lot about jobs or costs to industry. Here in 

Houston, we understand that very well. We hear it every time a regulation is proposed, every 

time a standard is strengthened, we hear about jobs, but I think there’s also a very clear 

understanding amongst those that actually bear the burden of pollution in this region, that 

eventually those costs will get passed on to regular citizens. 

And the choice is not between having those costs or not having those costs; it’s how those costs 

will be borne, and I don’t think the EPA needs to have another hearing to ask citizens whether 

they would prefer to bear those costs in increased health expenditures or increase to consumer 

goods. I think the choice is clear, and I think the EPA is of finally starting to get that, that we 

need to protect public held to the maximum, that we need to lead industry to innovate, to figure 

out ways to add control measures that reduce energy use, but also reduce air emissions. 

And at the end of the day, folks will pay those higher costs for their consumer goods, but they’ll 

be able to do so from a point of view where their -- where their health has been protected, and I 

think everybody in this region would much prefer to spend a little more on their consumer goods 

and spend a lot less on their -- on their health expenditures. 

Response: Thank you for your comments.

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 22

Comment: Small facilities such as sawmills, which are a big supplier of raw materials to paper 

mills, will also be severely and economically harmed by EPA’s boiler rules for so-called area 

sources even though their emissions are tiny and not harmful. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836

Comment Excerpt Number: 10.
Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 24

Comment: Given the jobless nature of the economy recovery, the rulemaking will add excessive 

burdens to the expense of the manufacturing workers. The total capital costs just for the forest 

products industry alone are estimated at about $7 billion, and the costs for all manufacturing 

could be between $20 to $50 billion. A wide range of sectors and the jobs they sustain would be 

severely harmed. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0397 

Comment Excerpt Number: 42 

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 31

Comment: The cost of compliance with the proposed rule not only threatens the survival of 

Louisiana’s sugar industry, but does so with minimal to no measurable air quality improvements. 

Given the nominal total HAP emissions from Louisiana’s sugar mills, EPA can meet its mandate 

under the Clean Air Act to protect public health and the environment without throwing such 

a devastating, perhaps fatal, blow to this industry. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836

Comment Excerpt Number: 10.

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 58

Comment: Since the ‘70s, the government has taken a big step to increase air quality, in general, 

right? In every step that they’ve taken, the business community has come out and said that we’re 

gonna lose thousands of jobs, it’s going to ruin our business, in all of its stuff like that, and 

really, it hasn’t -- like there hasn’t been an economic downturn that you can really blame on 

environmental regulations. The economy is, though, a lot more flexible and able to accept 

environmental regulations in general, and in businesses are a lot more flexible than they realize. 

I mean, I -- it’s just tougher for them to make changes so when -- when looking to make -- to 
change these rules, just keep that in mind when they come out here and tell you it’s gonna ruin 

our business, we’re going to -- thousands of people are going to be unemployed. If you look at 

the past, that really hasn’t happened on a consistent basis. 

Response: The EPA analysis for this regulation indicates that production and employment 

changes are likely to be small. Many of the predictions of large employment changes and 

closures are based on a lack of market flexibility.

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 59

Comment: EPA’s proposed rules will create serious disincentives for the use of biomass and

alternative fuels and thereby increased use of fossil fuels, which we believe is counterproductive 

and contrary to the country’s energy interests. The rule will have undeniable economic 

consequences. The forest products industry has projected new equipment required under the 

proposed rules will cost more than $6 billion over a three-year compliance window plus billions 

more in subsequent years for operating maintenance expense. Those capital costs alone exceeds 

industry profit of recent years. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0609 

Comment Excerpt Number: 1 

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 67

Comment: The forest and paper products industry were green even before there was a label for 

being green. We have had green jobs for over a century, but only until recent years has there 

been a "buzzword" for being environmentally responsible. The forest products industry will 

always be the best environmental stewards of our forest and land. We are sustainable, renewable, 

and the greenest. We do not want our jobs, livelihood, and communities destroyed by your 

legislated rules that bring about unintended consequences of jobs lost. Your unintended 

consequences of stringent rules will put more mills on our map out of business. There are 

American workers’ names that go with the numbers on our map [see Map provided as

supplemental information to transcript]. The hourly workers are almost always the first to go. 

The PPRC urges you to "Seek a Balance" between the environment and industry. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0609 
Comment Excerpt Number: 1 

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 100

Comment: I’m a huge believer in -- everyone needs a job. I do realize the economy, that 

everyone needs to make a living. I’m a big believer in the ingenuity of the American 

businessman. Usually, what made this country great, and I truly believe that if you set that bar 

however you set it, they’re going to meet it, and they’re going to make a profit. That is what 

makes America great. And -- and I’m sure they’ll be able to do it, and -- and do it well. And 

everywhere it’s been my experience, and research has shown, where there is a good 

environment, there’s always a good economy. Bad environment, always -- is -- is bad -- bad 

economics at the end of the day. 

Response: Thank you for your comments.

Commenter Name: Charlie Cary

Commenter Affiliation: Biomass Combustion Systems, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1990.1

Comment Excerpt Number: 13

Comment: Rural economies, which have suffered tremendously during the recession, benefit 

from the production and use of sustainable biomass. The proposed rule states that new boiler 

purchasers have the option of selecting gaseous fuel types that are cleaner and avoid emissions 

testing. In many rural areas, natural gas pipelines do not exist and propane (the most expensive 

fuel type) is typically five to six times more expensive per BTU than wood chip fuel. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836

Comment Excerpt Number: 10.

Commenter Name: Steven A. Brink

Commenter Affiliation: California Forestry Association

Document Control Number: EPA-HQ-OAR-2006-0790-2026.1

Comment Excerpt Number: 13

Comment: In California’s biomass power generation industry, the powerplants all have existing 

power purchase agreements and would not be able to pass the cost of any retrofits or testing 

requirements on to utility rate payers. The California Energy Commission’s analysis indicates 
existing biomass powerplants would not be able to absorb the additional costs called for by the 

proposed MACT Rule and would go out of business. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836,

Comment Excerpt Number: 10.

Commenter Name: Steven W. Koehn

Commenter Affiliation: National Association of State Foresters

Document Control Number: EPA-HQ-OAR-2006-0790-2220.1

Comment Excerpt Number: 14

Comment: Economic Impacts on Rural Communities 

Many rural communities rely upon or significantly benefit from the use of biomass boilers for 

energy at manufacturing facilities, schools and hospitals. The rule, as proposed, will directly 

impact both boiler owners and fuel suppliers in these communities. By limiting the opportunity 

for biomass boilers, economic losses will be considerable, especially so in the wood products 

manufacturing, forestry, and agriculture sectors. 

Rural economies, which have suffered tremendously during the recession, benefit from the 

production and use of sustainable biomass. It is predicted that 342 private sector jobs are created 

during the production of 200,000 tons of biomass for heat (Biomass Thermal Energy Council, et 

al, “Heating the Northeast with Renewable Biomass: A Vision for 2025,” April 2010, pg. 37). 

However, the proposed rule will certainly cause the opposite result and invalidate EPA’s original 

estimate of only 2,000 job losses. Biomass demand will drop in response to onerous, expensive, 

and unrealistic regulations; some boiler operators will have to reduce emissions by a factor of 

five over their current State air quality permits or go out of business entirely. The proposed rule 

states that new boiler purchasers have the option of selecting gaseous fuel types that are cleaner 

and avoid emissions testing. In many rural areas, natural gas pipelines do not exist and propane 

(the most expensive fuel type) is typically five to six times more expensive per Btu than wood 

chip fuel. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42.

Commenter Name: Kyle Gibeault

Commenter Affiliation: Biomass Thermal Energy Council, BTEC

Document Control Number: EPA-HQ-OAR-2006-0790-1914.1

Comment Excerpt Number: 14

Comment: Many communities in rural regions rely upon or significantly benefit from the use of 

biomass boilers for consumption of biomass energy crops. By limiting the opportunity for 
biomass boilers, economic losses will be considerable, especially so in the wood products 

manufacturing, forestry, and agriculture sectors. 

Rural economies, which have suffered tremendously during the recession, benefit from the 

production and use of sustainable biomass. It is predicted that 342 private sector jobs are created 

during the production of 200,000 tons of biomass for heat. [Footnote: Biomass Thermal Energy 

Council, et al, “Heating the Northeast with Renewable Biomass: A Vision for 2025,” April 2010, 

pg. 37.] However, the proposed rule will certainly cause the opposite result and invalidate EPA’s 

original estimate of only 2,000 job losses. Biomass demand will drop in response to onerous, 

expensive, and unrealistic regulations; some boiler operators will have to reduce emissions by a 

factor of five over their current State air quality permits or go out of business entirely. The 

proposed rule states that new boiler purchasers have the option of selecting gaseous fuel types 

that are cleaner and avoid emissions testing. In many rural areas, natural gas pipelines do not 

exist and propane (the most expensive fuel type) is typically five to six times more expensive per 

Btu than wood chip fuel. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42 and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Michael A. Livermore

Commenter Affiliation: Institute for Policy Integrity New York University School of Law

Document Control Number: EPA-HQ-OAR-2006-0790-1899.1

Comment Excerpt Number: 16

Comment: Estimates of employment impact derived from Morgenstern et al.: The Regulatory 

Impact Analysis uses two techniques to estimate the changes in employment due to the proposed 

rules. The first is a longstanding method used by EPA in many previous analyses. This technique 

looks at the output decrease in the relevant sectors and uses an estimate for jobs per unit of 

output to calculate a projected decrease in employment. This “demand effect” technique for 

projecting changes in employment is described in the Economic Analysis Resource Document 

issued by the Office of Air Quality Planning and Standards in April 1999. [Footnote: OFFICE 

OF AIR QUALITY PLANNING AND STANDARDS, EPA, OAQPS ECONOMIC ANALYSIS 

RESOURCE DOCUMENT at 5-42 to 5-43 (1999).] It contains an implicit assumption that the 

result of environmental regulations will be price increases and that these price increases will 

result in lower sales for regulated entities. 

However, this type of employment projection is incomplete. The agency correctly identifies that 

there are at least two types of employment effects from environmental regulations which are not 

included in the “demand effect” calculation: the “cost effect” and the “factor shift effect.” 

[Footnote: RIA at 4-6 to 4-7.] The “cost effect” recognizes that, for a given level of output, 

expenditures on reducing pollution often require additional employees. The “factor shift effect” 

recognizes that production can be more or less labor intensive after compliance with an 

environmental regulation. 
The size of each of these effects and the direction of the “factor shift effect” are all empirical 

matters and will likely vary from industry to industry and from regulation to regulation. In order 

to estimate these effects, EPA uses econometric estimates from a 2002 paper by Morgenstern et 

al. [Footnote: RIA at 4-7.] This paper estimated the employment effects of spending on 

environmental policies across a number of industries. [Footnote: Richard D. Morgenstern, 

William A. Pizer & Jhih-Shyang Shih, Jobs Versus the Environment: An Industry Level 

Perspective, 43 JOURNAL OF ENVIRONMENTAL ECONOMICS AND MANAGEMENT 

412, 412 (2002).] As the RIA recognizes, the point estimates do not perfectly correspond to the 

analysis that EPA is doing. The range of industries analyzed is not the same and the paper uses 

older data. 

Nevertheless, this technique at least recognizes and has the possibility of capturing effects that 

the traditional techniques of estimating employment effects cannot. This makes the estimates 

derived from the Morgenstern paper at least as valuable as the traditional techniques of 

estimating employment effects. The adoption of this technique by EPA could attract additional 

interest in this area and encourage economists to publish new studies on the topic with newer 

data. 

Response: EPA acknowledges the comments. The costs of the rule have been decreased 

through changes made to requirements for biomass-fired and oil-fired boilers.

Commenter Name: Arthur Blazer

Commenter Affiliation: Council of Western State Foresters

Document Control Number: EPA-HQ-OAR-2006-0790-1962.1

Comment Excerpt Number: 17

Comment: EPA recognized this economic impact in the preamble to the proposed rule. On 

pages 55-56 of the preamble EPA states that “...Based on this analysis, pursuant to CAA section 

112(h), EPA is proposing that it is not feasible to enforce emission standards for area source 

boilers having a heat input capacity of less than 10 mmBtu/hr because of the technological and 

economic limitations described above. Thus, a work practice, as discussed below, is being 

proposed to limit the emissions of mercury and CO (as a surrogate for POM) for existing area 

source boilers having a heat input capacity of less than 10 MMBTU/h. We are specifically 

requesting comment on whether a threshold higher than 10 mmBtu/hr meets the technical and 

economic limitations as specified in section 112(h). 

The limits imposed for PM do not reflect GACT for units under10 mmBtu/hr and potentially for 

units up to 30 mmBtu/hr. By EPA’s own admission on Pages 55-56, the testing and monitoring 

costs alone are not implementable for existing boilers under 10 mmBtu/hr. The costs for new 

boilers would be little different than those for existing boilers, and thus the same conclusion 

should be drawn. 

EPA does not cite significant test data that are applicable to area source units and specifically 

states that no data from units under 10 mmBtu/hr were available with regard to PM emissions. 

On page 72, EPA refers to the NSPS CFR 60 subparts Db and Dc. They state it covers to all units 
over 10mmbtu/hr input. However, the only discussion in this reference refers to units over 8.7 

megawatts or 30mmBTU/hr. Also, the reference it indicates that the 0.03 lb/mmBtu of PM is for 

coal and oil, or a combination of these fuels and wood. A wood fired unit burning over 30% 

wood has a limit described is 0.1 lb/mmbtu for PMmmBtu. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1.

Commenter Name: Kyle Gibeault

Commenter Affiliation: Biomass Thermal Energy Council, BTEC

Document Control Number: EPA-HQ-OAR-2006-0790-1914.1

Comment Excerpt Number: 19

Comment: The particulate emission standard suggested in the MACT standard is equally as 

destructive to the wood energy market. In my home State of Massachusetts the market has 

clearly spoken on the cost effectiveness of ESPs and baghouses. There has not been a wood fired 

boiler put into the State of Massachusetts in the last 15 years without considerable public support 

because a baghouse or ESP is required to meet the State’s particulate emission standard of .1 

pounds per million BTU. The particulate emission standard in current MACT standard will 

unquestionably put wood fired boilers in this Country on permanent public sector life support. I 

know the public sector currently subsidies every other form of energy but wood energy up to 

now has found opportunities to pay for itself. This rule will kill that economic viability. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836, 

Comment Excerpt Number: 10.

Commenter Name: Arthur Blazer

Commenter Affiliation: Council of Western State Foresters

Document Control Number: EPA-HQ-OAR-2006-0790-1962.1

Comment Excerpt Number: 22

Comment: Rural economies, which have suffered tremendously during the recession, benefit 

from the production and use of sustainable biomass. It is predicted that 342 private sector jobs 

are created during the production of 200,000 tons of biomass for heat (Biomass Thermal Energy 

Council, et al, “Heating the Northeast with Renewable Biomass: A Vision for 2025,” April 2010, 

pg. 37). However, the proposed rule will certainly cause the opposite result and invalidate EPA’s 

original estimate of only 2,000 job losses. Biomass demand will drop in response to onerous, 

expensive, and unrealistic regulations; some boiler operators will have to reduce emissions by a 

factor of five over their current State air quality permits or go out of business entirely. The 

proposed rule states that new boiler purchasers have the option of selecting gaseous fuel types 

that are cleaner and avoid emissions testing. In many rural areas, natural gas pipelines do not 
exist and propane (the most expensive fuel type) is typically five to six times more expensive per 

Btu than wood chip fuel. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42 and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Kyle Gibeault

Commenter Affiliation: Biomass Thermal Energy Council, BTEC

Document Control Number: EPA-HQ-OAR-2006-0790-1914.1

Comment Excerpt Number: 22

Comment: Meeting the particulate emission standard would require the addition of an ESP or 

baghouse to every biomass boiler system. This will cause the price of each system to increase 

significantly, starting at upwards of $60,000 equipment cost for a smaller boiler and increasing to 

hundreds of thousands of dollars as the boiler size approaches 10 MMBtu/h. The annual testing 

requirement would require strict operating conditions and technical oversight that will be cost 

prohibitive in addition to the cost of the testing. While we realize that EPA is not concerned with 

the cost, it would mean that fewer public schools and industries would install wood burning 

systems. Our public schools are in financial trouble. Our Biomass Boiler Systems have been 

saving schools many dollars every year, frequently a teacher’s entire salary and more. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836, 

Comment Excerpt Number: 10.

Commenter Name: Kyle Gibeault

Commenter Affiliation: Biomass Thermal Energy Council, BTEC

Document Control Number: EPA-HQ-OAR-2006-0790-1914.1

Comment Excerpt Number: 29

Comment: A large portion of the end users that will be affected by these proposed rules will be 

hospitals, schools and small industries looking for a way out of high priced fossil fuels. Most of 

these potential projects would be in economically challenged rural areas were there is a 

significant downturn in the forest industry. With these new proposed rules most of these 

potential projects would no longer be feasible and the ones that are currently in operation would 

have to be shut down or retrofitted at significant cost to the end user. We think that the EPA 

should moderate their position on this issue to take into account the social-economic factors at 

hand, especially with the smaller scaled and sometimes financially burdened projects that are 

affected by the area source rules and regulations. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836, 
Comment Excerpt Number: 10.

Commenter Name: Steven D. Swanson

Commenter Affiliation: Swanson Group, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1241

Comment Excerpt Number: 1

Comment: The costs of the new equipment, controls and lost production required by this rule 

will be incurred during a shaky recovery and could realistically retard or kill that recovery. If the 

recovery is slower than we expect the additional costs could cause the complete closure of 

several of our facilities. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1 and Document Control Number: EPA-HQ-OAR-2006-0790-0836, 

Comment Excerpt Number: 10.

Commenter Name: R. Wade Mosby

Commenter Affiliation: The Collins Companies

Document Control Number: EPA-HQ-OAR-2006-0790-1461.1

Comment Excerpt Number: 1

Comment: The effect of these four proposed rules is that they threaten the viability of these 

three facilities that include 3 sawmills, a biomass power plant and a hardwood dimension plant. 

Currently no boiler manufacturer is willing to certify that their wood fired boilers will meet the 

proposed standard. Our facilities burn forest derived biomass, which is classified a "traditional 

fuel" instead of solid waste. 

The Chester, CA plant consists of a sawmill and biomass co-generation power plant that 

produces 12 MW of electricity. The steam also fires the lumber dry kilns and provides plant 

heating. This plant provides 108 union (Carpenters & Jointers) family wage jobs and is the 

largest employer in this small rural Sierra Nevada community. Replacement cost of a boiler with 

no guarantee of meeting the proposed standards would be approximately $20 million. This 

facility in 2009 had a payroll of $5.9 million, with $1.8 million in employee related taxes and 

$606 thousand in local property taxes. 

In Lakeview, OR we operate a sawmill with a wood fired boiler that produces steam for the dry 

kilns and plant heating. This facility employs 76 people with family wage jobs and is the largest 

private employer in this small rural Eastern Oregon town located 95 miles from the nearest 

regional shopping and medical facilities. A replacement boiler with no guarantee of meeting the 

proposed standards would be approximately $10 million. The Lakeview facility in 2009 had a 

payroll of $3 million, with $900 thousand in employee related taxes and paid $110 thousand in 

local property taxes. 
Our Kane, PA facility is a hardwood sawmill and dimension plant that utilizes a wood fired 

boiler for dry kilns and plant heating. We employ 99 people with family wage jobs and this is the 

largest private employer in this small rural Northern Appalachian town. A replacement boiler 

with no guarantee of meeting the proposed standards would run approximately $10 million. The 

Kane facility had a 2009 payroll of $3.7 million, with $1.1 million of employee related taxes and 

paid $593 thousand in local property taxes. 

Keep in mind that due to the current recession and housing crisis, these plants ran at a one shift 

reduced basis. In normal times we’d operate at a higher production level with the attendant 

increase in employment and payroll. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836, 

Comment Excerpt Number: 10.

Commenter Name: Joe O'Rourke

Commenter Affiliation: F.H. Stoltze Land and Lumber Company

Document Control Number: EPA-HQ-OAR-2006-0790-1467.1

Comment Excerpt Number: 2

Comment: The proposed MACT standards for Major Source boilers as well as Area Source 

boilers would be highly detrimental to our business too. The cost to comply with these new, 

stringent standards would jeopardize our ability to continue in business. That in turn would 

negatively affect our employees, our contractors, our suppliers, and the local and regional 

community. AF&PA has estimated that these new rules would cost the wood products industry 

$6 to $7 billion dollars over the next four years. In our own State of Montana, they estimate that 

there are seven Forest Products in operation, and that it would cost $60,000,000 in capital costs 

to bring those boilers into compliance with the new MACT standards. That works out to an 

incredible $8,500,000 per boiler. Don Wolf, of Burns & McDonnell Engineering Co. of St. Louis 

confirms this when he says “...the average capital cost of retrofitting biomass-fired boilers will 

be nearly $5 million”. Furthermore, he estimates that “...air-pollution-control retrofit 

projects/fuel-switching projects can take 18 months to three years from the start of compliance 

planning through engineering and construction to startup.” Our company has struggled mightily 

over the last several years to survive the severe economic downturn. Our business simply could 

not bear an added expense of that magnitude. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836, 

Comment Excerpt Number: 10.

Commenter Name: Steven D. Swanson

Commenter Affiliation: Swanson Group, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1241

Comment Excerpt Number: 3
Comment: At least one of our boilers will very likely, even with all of the latest control 

technologies, be unable to meet the CO limit, resulting in its cessation of operation. If we are 

unable to operate that boiler, the capital costs of a replacement boiler will very likely be cost 

prohibitive meaning the entire facility could be in jeopardy. The resultant loss in jobs (i.e. 75-150 

positions) would be a heavy hit to already battered rural Oregon, where unemployment levels are 

near or: exceed 20%. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0837, 

Comment Excerpt Number: 16.

Commenter Name: David Dungate and Scott Nichols

Commenter Affiliation: ACT Bioenergy and Tarm USA

Document Control Number: EPA-HQ-OAR-2006-0790-1472.1

Comment Excerpt Number: 3

Comment: Without changes to the Draft Area Source Boiler Rule so that the emission limits and 

compliance testing costs are reasonable, the commercial biomass boiler industry will be rendered 

uneconomical and the jobs in this industry sector and the environmental benefit of replacing 

fossil fuel with renewable biomass fuel will be lost. We urge you to revise the Rule so that the 

limits are comparable with European standards. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836, 

Comment Excerpt Number: 10.

Commenter Name: Steven Jarvis

Commenter Affiliation: Missouri Forest Products Association

Document Control Number: EPA-HQ-OAR-2006-0790-1477.1

Comment Excerpt Number: 1

Comment: The EPA cites estimated compliance costs at more than $10 billion initially and $4 

billion annually for both rules. However, the American Forest & Paper Association (AF&PA) 

estimates that the initial capital costs for the forest products industry alone may reach $7 billion. 

The proposed control technology standards are far more stringent than those in the vacated rule, 

and will present many new challenges for affected facilities. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836, 

Comment Excerpt Number: 10.

Commenter Name: Joe Fierst
Commenter Affiliation: Wausau Paper

Document Control Number: EPA-HQ-OAR-2006-0790-1488.1

Comment Excerpt Number: 1

Comment: As the Mill Manager for the Wausau Paper Mill in Rhinelander, Wisconsin I am very 

concerned that the proposed EPA Boiler MACT rule, if enacted, will substantially increase 

operating costs for our mill and could put mill jobs, and the communities that rely on these jobs, 

at risk. The proposed rule goes far beyond any previous regulation and any statute needed to 

protect the health of our communities. It seems highly likely that it may not be possible for many 

boiler operators to achieve the impractical standards necessary to comply with the rule’s 

requirements; no matter what kind of pollution controls are installed. 

I have seen many paper mills close in the last few years because of rising operating costs and the 

tragic U.S. economy, including several Wausau Paper facilities. Over the last few years Wausau 

Paper has had no choice but to close six facilities located in Appleton and Columbus, Wisconsin, 

Jay, Maine, Jackson, Mississippi, Groveton, New Hampshire, and Middletown, Ohio. Wausau 

Paper now employs roughly 1300 fewer employees than they did 10 years ago. 

The paper industry has experienced some very tough years. The impact of this overcompensating regulation, if unmodified, will drive further decline, and perhaps the demise of 

significant employers. Other good paying jobs are hard to find in these rural areas, so the harmful 

impact would last a long time, if not forever. Our town specifically, will suffer if support from 

the mill ends, not just from lost tax revenue, but also from the significant involvement the mill 

and its employees have in all aspects of the community. In the last ten years, paper industry 

employment in Wisconsin has dropped from 52,000 to 32,000. That’s over $1 billion in annual 

wages lost. The communities associated with these mills have suffered greatly, as a consequence. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836, 

Comment Excerpt Number: 10.

Commenter Name: Ashley B. Peterson

Commenter Affiliation: American Meat Institute

Document Control Number: EPA-HQ-OAR-2006-0790-1486.1

Comment Excerpt Number: 1

Comment: In terms of the economic burden, the capital cost expenditures that would be 

necessary to comply with the Rules are estimated to be in the tens of billions of dollars at 

thousands of facilities across the country. A wide range of sectors and the jobs they sustain 

would be severely affected – universities, small municipalities, food product processors, 

furniture makers, federal facilities, and a wide range of manufacturers and other businesses that 

operate gas, liquid, or solid-fueled fired boilers. Imposing such an economic burden on industry 

is substantial and would threaten the viability of some companies, particularly in these 

economically challenging times. . 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 
Comment Excerpt Number: 42.

Commenter Name: William H. Verner

Commenter Affiliation: Georgia Electric Membership Corporation

Document Control Number: EPA-HQ-OAR-2006-0790-1797.1

Comment Excerpt Number: 1

Comment: We are specifically concerned about the proposed boiler Maximum Achievable 

Control Technology (MACT) rule and its potential negative impact on jobs, our ability to 

recover from the current recession, and our ability to move to the use of renewable fuels. 

As the unemployment rate in Georgia hovers around 10 percent, and state and municipal 

finances are in dire straits, manufacturing jobs are being lost every day. While we support efforts 

to address serious health threats from air emissions, we also believe that regulations can be 

crafted in a balanced way that sustains both the environment and jobs. 

The proposed boiler MACT rule could impose millions of dollars in capital costs at 

approximately 5,000 existing facilities across the state of Georgia. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42.

Commenter Name: George N. Clark

Commenter Affiliation: Manufacture Alabama

Document Control Number: EPA-HQ-OAR-2006-0790-1634.1

Comment Excerpt Number: 1

Comment: If implemented, the proposed Boiler MACT rules will directly impact the operation 

of manufacturers, municipalities, universities, utilities and other commercial entities across 

Alabama and would strike a severe blow to Alabama’s economy. According to Alabama’s 

Governor, the impact of the proposed Boiler MACT rule on Alabama entities is estimated at 

$710 million. As Alabama strives to recover from the current recession, such costs could make 

or break the viability of continued operations. 

For example, the Alabama wood products industry alone generates $12.4 billion in revenue and 

employs over 43,000 individuals. As proposed, the Boiler MACT rules are estimated to cost the 

Alabama wood products industry over $620 million. As our state’s unemployment rate hovers 

around 11 percent, enacting stringent Boiler MACT rules would jeopardize the good paying jobs 

across the wood products industry and the entire manufacturing sector. Although Alabama 

manufacturers are fighting hard to thrive in this global economy, the flow of capital for new 

investment and hiring is still seriously restricted. 
Manufacture Alabama believes that the proposed Boiler MACT rules will hurt both large and 

small manufacturers and prevent expansion and growth in many urban, suburban, and rural 

counties, hindering their ability to create jobs. The cost to individual mills to comply with the 

proposed rules could be tens of millions of dollars at a time of fierce international competition 

and a weak economy. The combined estimated costs to the chemical, pulp and paper and utility 

industries is $11.5 billion dollars. Our nation is suffering through the most severe recession since 

the 1930s. Manufacturers have lost more than 2.1 million high-wage jobs across the nation. 

Economic recovery has not been swift and individual States are not recovering from the 

economic downturn at the same pace. 

We understand that the Boiler MACT rule alone could impose tens of billions of dollars in 

capital costs at thousands of facilities across the country. Manufacture Alabama fears that 

manufacturers may be forced to relocate overseas to countries with less strict environmental 

regulations simply because they cannot afford to operate under extreme financial conditions in 

the United States. Widespread leakage would competitively disadvantage Alabama and our 

nation and significantly impede economic recovery. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, and Document Control Number: EPA-HQ-OAR-2006-0790-

0985, Comment Excerpt Number: 58.

Commenter Name: James Happli, Jr

Commenter Affiliation: United Steel, Paper, Forestry, Rubber, Manufacturing, Energy, Allied 

Industrial and Service Workers International Union (Wausau Paper)

Document Control Number: EPA-HQ-OAR-2006-0790-1489.1

Comment Excerpt Number: 3

Comment: Many mills rely on coal-fired boilers for low-cost energy. Being a low-cost producer 

is how many paper mills continue to survive against foreign competition. Yet the proposed rule 

could result in the shut-down of many coal-fired boilers, which would lower the competitiveness 

of these mills, and cause more job losses. 

I have seen many paper mills close in the last few years because of rising operating costs and the 

tragic U.S. economy, including several Wausau Paper facilities. Over the last few years, Wausau 

Paper has had no choice but to close six facilities located in Appleton and Columbus, Wisconsin, 

Jay, Maine, Jacksonville, Mississippi, Groveton, New Hampshire and Middletown, Ohio. 

Wausau Paper now employs roughly 1300 fewer employees than they did 10 years ago. 

The paper industry has experienced some very tough years and the last thing it needs is some 

over zealous regulation to instigate further decline. I do not want my mill to be one of the next 

mills to close. Other good paying jobs are hard to find in our rural area so the harmful impact 

would last a long time, if not forever. Our town will suffer as well if the support from the mill 

ends, not just the taxes, but all of the involvement in the community. In the last ten years, paper 
industry employment in Wisconsin has dropped from 52,000 to 32,000. That’s over $1 billion in 

annual wages lost. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0836, 

Comment Excerpt Number: 10 and Document Control Number: EPA-HQ-OAR-2006-0790-

0985, Comment Excerpt Number: 58..

Commenter Name: Susan Parker Bodine

Commenter Affiliation: Used Oil Management Association, UOMA

Document Control Number: EPA-HQ-OAR-2006-0790-1972.1

Comment Excerpt Number: 3

Comment: It is clear from the docket that EPA has not considered the impacts of this proposed 

rule on manufacturers and users of these very small units. The docket does not include any 

emissions or economic data relating to small used-oil fired boilers. For example, EPA has not 

considered the effect of a tune-up requirement on owners of existing used oil-fired boilers. In the 

docket for the CISWI rule, EPA provided information that the initial cost of a boiler tune-up is 

$3,000 to $7,000 per boiler, and subsequent annual tuning costs are approximately $1,000 per 

boiler. (EPA-HQ-OAR-2003-0119-0041). In the Supporting Statement for the information 

collection provisions of the proposed Area Source Boiler rule, EPA asserts that boiler tune-ups 

cost $2,228. (EPA-HQ-OAR-2006-0790-0031). Similarly, EPA has not considered the effect of 

the cost of emissions controls on owners of new used oil-fired boilers. In the docket for the 

CISWI rule, EPA provides information that the cost of installing a fabric filter ranges from 

approximately $722,000 to $31.3 million, and annual costs range from approximately 

$139,000/yr to $9.6 million/yr. (EPA-HQ-OAR-2003-0119-0054). In the same document, EPA 

assumed that the capital cost of adding a fabric filter to a used oil heater would be $715,188 and 

the annual costs would be $150,051. Id. Given these costs, EPA’s statement in the preamble to 

the Area Source Boiler rule that fabric filters and electrostatic precipitators "are generally 

available and cost effective for new area source boilers" clearly does not apply to the small 

boilers that UOMA members manufacture. 75 Fed. Reg. at 31909. In fact, in the context of the 

CISWI rule, EPA assumes that these costs impose such a significant burden that units would shut 

down. (EPAHQ-OAR-2003-0119-0054). 

Before finalizing this regulation, EPA should conduct a cost-to-sales analysis of the economic 

impact of its proposed regulations on the small boilers that meet the limitations set forth in 40 

C.F.R. 279.23. Just as EPA determined that testing and monitoring costs would be unaffordable 

for area source boilers (75 Fed. Reg. at 31906), UOMA believes that compliance costs would 

form a large percentage of the revenues of many UOMA customers, and in some cases may even 

exceed those revenues, demonstrating that EPA’s proposal would impose a significant adverse 

economic impact on these small businesses. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 
Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

.

Commenter Name: Susan Eckerly

Commenter Affiliation: National Federation of Independent Business, NFIB

Document Control Number: EPA-HQ-OAR-2006-0790-1631.1

Comment Excerpt Number: 3

Comment: The controls, if available, will pose a great financial challenge for small businesses 

— most of which do not generate a profit. Requiring financially challenged firms to spend scarce 

resources on these controls in this economy will force small businesses to cut back hours, 

eliminate jobs, or worse, close their doors for good. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Steven Jarvis

Commenter Affiliation: Missouri Forest Products Association

Document Control Number: EPA-HQ-OAR-2006-0790-1477.1

Comment Excerpt Number: 3

Comment: If these rules are finalized as proposed, forest products companies will see reduced 

markets for wood residues, higher costs for marketing wood residues, higher costs for disposing 

of wood residues, and higher costs for using wood residues for on-site energy production. Forest 

products companies rely on their ability to sell or utilize wood residues to maintain the 

profitability of their operations. Reducing or eliminating this value stream, which may provide 

up to 15% of a sawmill’s income, will have serious consequences for an industry hard hit by the 

recession, resulting in another wave of mill closures. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.
Commenter Name: William H. Carlson

Commenter Affiliation: Carlson Small Power Consultants

Document Control Number: EPA-HQ-OAR-2006-0790-1493.1

Comment Excerpt Number: 6

Comment: Converse to the selected CO units, the units used to establish the PM standard are all 

large units, all above 10mmBtuJhr, and half above the 250 mmBtu/hr level. There is NO overlap 

with the CO unit list, not a coincidence. All are equipped with ESP’s. 

The data assembled by EPA, indicates that none of the existing small boilers and only 29% of the 

larger boilers are equipped with an ESP or equivalent device (baghouse). Thus, the vast majority 

of existing units will be forced to install an ESP or baghouse to continue in operation under the 

rule. 

Response: See response to Document Control Number: EPA-HQ-OAR-2006-0790-0836, 

Comment Excerpt Number: 10.

Commenter Name: David Schutz and John Ussery

Commenter Affiliation: Northern New Mexico College

Document Control Number: EPA-HQ-OAR-2006-0790-1834.1

Comment Excerpt Number: 7

Comment: By eliminating the option for the use of locally generated biomass as the primary 

fuel for the NNMC El Rito campus, several jobs that would otherwise be created will be lost. 

These go beyond the jobs of the boiler stokers, to include those local workers who would gather, 

prepare and transport the wood from the forest to the campus. 

Using local wood as the primary fuel for the campus would have cut the cost of heating the 

campus in half given the present cost of propane. These savings would increase as the cost of 

propane rises in the future. Last year the College spent over $160,000 on propane to heat the El 

Rito campus that serves less than 200 students. Reducing energy costs is a critical factor for the 

economic viability of the campus. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Joe Fierst

Commenter Affiliation: Wausau Paper
Document Control Number: EPA-HQ-OAR-2006-0790-1488.1

Comment Excerpt Number: 8

Comment: Not only is the approach that EPA used to develop emission limits badly flawed, the 

proposed Boiler MACT rule will impose a huge cost burden on our Wausau Paper -Rhinelander 

Mill facility that is Simply untenable, Based on best available estimates, we expect that Boiler 

MACT compliance will cost tens-of-millions and annual expenditure in operation and 

maintenance costs will rise several million, 

It is critical that EPA revise this rule in a common sense way, Addressing the risk to our jobs and 

our way of life must be part of any change, We need clean air, but we also need good paying 

jobs, Bring some balance to this rule, I respectively request that EPA review and implement the 

recommendations proposed by the American Forest & Paper Association (AF&PA) and the 

National Council of Air & Stream Improvement (NCASI) in their comments regarding this rule, 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Steven Jarvis

Commenter Affiliation: Missouri Forest Products Association

Document Control Number: EPA-HQ-OAR-2006-0790-1477.1

Comment Excerpt Number: 12

Comment: Rural economies, which have suffered tremendously during the recession, benefit 

from the production and use of sustainable biomass. It is estimated that 342 private sector jobs 

are created during the production of 200,000 tons of woody biomass for heat. [Footnote 5: 

Heating the Northeast with Renewable Biomass: A Vision for 2025, Biomass Thermal Energy 

Council, April 2010.] However, the proposed rule will certainly cause the opposite result and 

invalidate EPA’s original estimate of only 2,000 job losses. Biomass demand will drop in 

response to these proposed regulations; so strict that some biomass boiler operators will have to 

reduce emissions by a factor of five over their current state air quality permits employing 

expensive control technologies, or go out of business. 

MFPA asserts that the economic data used by the EPA is seriously flawed when it comes to job 

loss estimates. Most woody biomass boilers are located in economically depressed rural areas 

that depend on the forest products industry for employment. If these mills close due to the high 

costs of compliance, many more than 2,000 jobs will be lost in Missouri’s forest products 

industry alone. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 
Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Robert H. Colby and G. Vinson Hellwig

Commenter Affiliation: National Association of Clean Air Agencies (NACAA)

Document Control Number: EPA-HQ-OAR-2006-0790-2022.1

Comment Excerpt Number: 28

Comment: The proposed rules will create additional resource burdens on state and local 

permitting agencies that will have to issue several thousand Title V permit revisions, draft 

emission control regulations and submit them to EPA for review and approval under section 111 

of the CAA specifically set out its expectations of state and local permitting authorities and 

incorporate reasonable timelines in its implementation schedule. 

Response: In the final rule, and as was in the proposed rule, most area source boilers are 

exempted from title V permitting.

Commenter Name: Joe Muehlbach

Commenter Affiliation: Quad/Graphics

Document Control Number: EPA-HQ-OAR-2006-0790-1961.1

Comment Excerpt Number: 1

Comment: The proposed Boiler MACT rule will pose economic hardships to Wisconsin’s core 

manufacturing industries, especially forest products. The Wisconsin Paper Council has estimated 

that the total costs for Wisconsin manufacturing could top $680 million with the forest products 

industry bearing $470 million of that total. That hits a company such as Quad/Graphics twice as 

we will bear the costs of compliance at our facilities as well as those of one of our major 

suppliers — the paper mills. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Daniels W. Duplantis

Commenter Affiliation: Raceland Raw Sugar, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1858.1

Comment Excerpt Number: 1
Comment: As at all Louisiana sugar mills, RACELAND RAW SUGAR, L.L.C. operates 

multiple bagasse-fired boilers which fall under the scope of the Proposed Rule as currently 

written. 

The Proposed Rule would have a devastating, perhaps fatal, impact on the Louisiana sugar 

industry in general, and specifically on the RACELAND FACTORY. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Hank Russell

Commenter Affiliation: Cuolumne County Economic Development Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1658.1

Comment Excerpt Number: 1

Comment: The Tuolumne County Economic Development Authority (TCEDA) in Tuolumne

County is greatly concerned over EPA’s proposed Boiler MACT rule and the implications 

therein that would significantly burden, and have the potential to limit or shut down forest 

products industry boiler and cogeneration facilities. The continued effect to provide steam or 

electricity to the industry via biomass only adds a cost burden and a dependence on fossil and 

foreign fuels — both of which further limit the viability of the wood products industry. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Cindy Domenico

Commenter Affiliation: Boulder County Commissioners

Document Control Number: EPA-HQ-OAR-2006-0790-1652.1

Comment Excerpt Number: 1

Comment: Boulder County directly owns and manages the health of 30,000 acres of forested 

open space land. These forested lands require tree thinning to mitigate forest fires, respond to 

pine beetle infestation and improve forest health. The tree thinning process produces a large 

amount of biomass which historically has been burned in open fires during the winter as 

permitted by the air quality regulators for the area. To reduce the air quality impact of forest 

management, Boulder County has funded various projects that better utilize the wood and reduce 

air pollution. In 2005 Boulder County installed a 3MMBtu biomass boiler at our 90,547square 
foot Open Space and Transportation Complex in Longmont. In 2010 Boulder County received 

grant funding from the US Forest Service, The Department of Energy and the Colorado 

Department of Local Affairs as well as Qualified Energy Conservation Bonds to install another 

3.3MMBtu biomass boiler at the 150,296 square foot Boulder County Jail. The cost to add the 

equipment to meet the PM Standards on the boiler at the Boulder County Jail will be $110,000, 

which is more than a third of the cost for the biomass boiler by itself. This is a significant impact 

to the project cost and makes the small biomass boiler option financially challenging. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Ray Penick

Commenter Affiliation: Barge Forest Products Company

Document Control Number: EPA-HQ-OAR-2006-0790-1778.1

Comment Excerpt Number: 1

Comment: In this treacherous business climate, with the unlikely prospect for much 

improvement in our industry until 2013, another huge cost burden such as the investment to 

comply with the proposed boiler emission requirements would cause irreparable harm to our 

company. If these proposals become law, we believe they will be directly responsible for the loss 

of many good jobs, not only in this area of Mississippi, but across the country. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Roger Roth, Al Ott, Dean Kaufert, Karl Van Roy

Commenter Affiliation: Wisconsin Legislature

Document Control Number: EPA-HQ-OAR-2006-0790-1938.1

Comment Excerpt Number: 1

Comment: The draft rule before the EPA would significantly impact Wisconsin manufacturers, 

particularly in the forest products industry, by requiring costly improvements to reduce the 

amount of pollutants released by boilers. 

An earlier version of this rule allowed for Health-Based Compliance Alternatives, which were 

vital to allow many manufactures to comply with the rule. The latest version of the Industrial 
Boiler MACT lacks a similar provision. The revised rule also requires even more stringent 

emissions standards on coal- and biomass-fired boilers than were previously allowed. 

This rule will be detrimental to maintaining jobs in Wisconsin’s paper industry. In the past 

decade, there has already been a 40% reduction in the size of the workforce in this industry. 

Enacting this rule without changes will only further hurt our state’s manufacturing base. 

We ask that the Industrial Boiler MACT be revised to work with manufacturers in lowering 

emissions at a more affordable cost. 

Response: This comment pertains to the major source boiler rulemaking. Provided the 

commenter has submitted this comment to the major source boiler rulemaking docket, the 

response to this comment will be provided there.

Commenter Name: Bruce Coffee

Commenter Affiliation: Hurst Boiler and Welding Co

Document Control Number: EPA-HQ-OAR-2006-0790-1873.1

Comment Excerpt Number: 1

Comment: Hurst Boiler and Welding Co., Inc. Is a Georgia Company engaged in the design and 

construction of Industrial, Commercial, and Institutional Boilers, Area Sources, Process Heaters 

and Industrial Solid Waste Incinerators. We have approximately 300 employees. Our business 

will be directly and deleteriously affected by the proposed action. This is certain. 

Hurst Boiler and Welding Co builds all types of boilers but the bulk of our work is targeted 

toward the solid fuel market. This includes coal and biomass units. We believe this will be the 

end for coal fired equipment altogether. Already difficult, companies will soon find it impossible 

to decide to improve their competitiveness by investing in a fuel-saving biomass boiler, as the 

increased capital expenditure will essentially kill many of the projects we have proposed. We are 

not sure but we could certainly predict that our workforce would be “down-sized”. 

Without the ability to incorporate this cost-saving fuel alternative, many of these companies will 

be hastened toward their demise in the hostile business environment we see today. It will be 

difficult to assess the number of businesses that will not be started, the number that will cease to 

exist and the number that will move off-shore as a result of this stifling action. At the very time 

when our country needs all of the breaks it can get to increase employment this action will cause 

many jobs to just never materialize, others to be lost and speed the day when China’s economy 

overtakes our own. This is certain. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.
Commenter Name: Clark Diehl

Commenter Affiliation: Chips, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1635

Comment Excerpt Number: 1

Comment: I am a co-owner of two lumber mills in Virginia. Chips, Inc. employs 70 people and 

ArborTech Forest Products employs 80. Chips is a synthethic minor source and ArborTech is 

Title 5. Both mills are located in rural settings. Compliance for the new proposed Boiler MACT 

rules (if that is even possible) would require capital outlays of over $600,000 at Chips and over 

$1,500,000 at ArborTech. The lumber industry is in the third year of a severe downturn that has 

wiped out approximately 50% of 2006 production along with the related jobs. Both our 

companies have operated in the red for three years and it is unlikely we could raise the capital to 

comply with these proposed rules. This puts 150 direct jobs and over 400 indirect jobs (loggers, 

truckers, etc.) at risk. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Bill Perdue

Commenter Affiliation: American Home Furnishings Alliance, AHFA

Document Control Number: EPA-HQ-OAR-2006-0790-1970.1

Comment Excerpt Number: 2

Comment: The wood furniture manufacturing industry is especially vulnerable to the shift of 

domestic production to overseas sources. Wood furniture manufacturing has experienced a 

sustained downturn described by the U.S. Department of Commerce as a “perfect storm” of 

negative factors related to the housing market, foreign dumping, and a host of new standards 

(flammability, formaldehyde, finishing material composition, and now the proposed new Boiler 

MACT rule). Domestic employment in our industry has contracted from 620,000 jobs in 1990 to 

an estimated 360,000 jobs today, while there has been a 519% increase in wood casegoods 

furniture imports between 1998 and 2007. Between 2000 and 2008, 270 domestic furniture 

manufacturing operations have closed, including 112 plants in North Carolina, 31 plants in 

Virginia, and 30 plants in Mississippi. Although U.S. manufacturers in the past maintained near 

100% production in the United States, most major manufacturers have now relocated major 

portions of their manufacturing operations to overseas locations such as China and Viet Nam. 

The overseas infrastructure is in place to easily incorporate additional wood furniture 

manufacturing, and economic pressures continue to favor a shift from domestic to overseas 

employment. 

Fortunately there is light at the end of the tunnel for those manufacturers who have maintained 

domestic production, or who have at the very least mothballed rather than disassembled their 
domestic facilities. The Center for Industrial Studies projects moderate growth of the U.S. 

furniture industry in 2010, and Industry analyst Jerry Epperson of Mann, Armistead & Epperson 

has forecasted that U.S. consumer spending on furniture and bedding will rise 3.7% in 2010 and 

another 7.1% in 2011. Some domestic manufacturers have reported plans to expand domestic 

production for the first time in several years, however they are waiting to see the outcome of 

influencing activities such as the proposed boiler rule before committing to the investment in 

domestic production. The AHFA has significant concerns with this proposal because it would 

impose stringent numeric emissions limitations that would be impossible for our membership to 

meet without imposing new costs that would halt future domestics expansion plans and force 

additional facilities to close. In today’s economic climate, NO furniture manufacturer will elect

to invest significant capital and commit to increased operating expenses to install a control 

device of the type that would be required under the rule as written. We encourage the EPA to use 

the complete set of tools available under §112 to provide flexibility to vulnerable domestic 

manufacturers. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 2

Comment: It was not Congress’s intent for EPA to set emission limits under Section 112 of the 

Clean Air Act (CAA) without regard to feasibility or the impact on the sources being regulated 

or the economy in general. This is particularly true for area sources as demonstrated by Congress 

specifically providing for the use of Generally Available Control Technology (GACT) rather

than Maximum Available Control Technology (MACT) for such sources. The proposed emission 

limits for liquid-fired boilers in this proposal do not reflect GACT and will be unachievable in 

many cases. Where they are achievable, the cost to meet them will overwhelm the economics for 

many operations and cause them to shutdown, or in the case of offices, hospitals, universities, 

etc. cause large price increases that will further stifle the already weak US economy. For our area 

source operations with liquid-fired boilers, the increased costs will lead to shutdown of marginal 

facilities and consolidation, with a loss of jobs. At the area sources with liquid-fired boilers that 

remain in operation, the increased cost will ultimately be passed on to the public. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 
Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: W. James Wagoner

Commenter Affiliation: Butte County Air Quality Management District

Document Control Number: EPA-HQ-OAR-2006-0790-1993.1

Comment Excerpt Number: 3

Comment: The biomass boilers at POPI are older and retrofits to comply the regulation are not 

proven nor practical. If the proposed standard is implemented, the plant will likely be shuttered. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 5

Comment: Regarding cost impacts for biomass fired Boilers, AF&PA prepared an extensive 

analysis that is filed with our comments on the major source rule (See Section II comments on 

cost and in the Appendix C attachments to those comments in EPAHQ-OAR-2002-0058; we 

incorporate those comments by reference). But to provide only one example, the costs facing a 

composite panel member company operating a wood residue boiler of a modest size, less than 

100 MMBtu/hr, would be very high if the rules would not allow the use of current wood-fired 

boilers (EPA’s database has identified several composite panel plants as impacted by the rule). 

For these facilities, startling cost increases can be shown, should plants be forced to switch from 

wood residuals to natural gas because they cannot meet the proposed CO limit. Estimates for the 

cost of a plant to switch boiler fuel from a trim/sander dust mix to natural gas ranged from $1 

million to $3.5 million per year depending on boiler size and the price of gas (high 2002, low 

2006). 

However, there are facilities in our industry where natural gas is not available. Such facilities 

would either be forced to depend on propane or electric heat if they could not meet the proposed 

biomass CO limit. Not only would industrial competitiveness be impacted, but also other 

commercial businesses and institutional organizations using wood fuels would suffer. Prices to 

consumers and tuitions for academic institutions would rise. 
These consequences are completely unnecessary and EPA has the tools, within the legal 

framework of the Clean Air Act to fix them. Within these comments, AF&PA make several 

concrete suggestions to changes in EPA’s approach to Area Source CO limitations that would 

reduce HAP from wood fired area sources boilers and dramatically reduce the rule’s impact on 

businesses and institutions that depend on wood and other biomass fuels. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: David J. Prior

Commenter Affiliation: New York State Energy Research and Development Authority, 

NYSERDA

Document Control Number: EPA-HQ-OAR-2006-0790-1913.2

Comment Excerpt Number: 6

Comment: Other fuel options, such as propane, are available in parts of New York State outside 

of New York City. The ability to serve new propane demand will depend in large part on level of 

increased demand, location of new demand, and local supply conditions. 

Under the American Recovery and Reinvestment Act, 27 projects in New York State were 

awarded approximately $6 million to carry out energy efficiency improvements which included 

replacement of boiler systems. The proposed ASBR will detrimentally affect these projects as the 

associated costs and difficulties associated with the stack testing requirements were not 

accounted for. 

Response: Thank you for your comments.

Commenter Name: James P. Brooks

Commenter Affiliation: Maine Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2006-0790-1915.1

Comment Excerpt Number: 19

Comment: The Maine DEP also respectfully requests that EPA provide additional Section 105 

funding to states for implementation of the Area and Major Source Boiler MACTs. These rules 

will affect an enormous population of boilers nationwide, will result in the need for thousands of 

permit amendments, and will put a tremendous strain on already stretched state resources. 

Response: This comment is outside the scope of this rule.
Commenter Name: Randy Thurman and Brent Stevenson

Commenter Affiliation: Arkansas Environmental Federation and Arkansas Forest & Paper 

Council

Document Control Number: EPA-HQ-OAR-2006-0790-1921.1

Comment Excerpt Number: 1

Comment: We are writing to express the concerns of the members of the AEF and the AFPC 

about the proposed Boiler Area MACT rule -the Maximum Achievable Control Technology rule 

for industrial, commercial and institutional boilers -that was published June 4, 2010. As 

Arkansas strives to recover from the current recession, we are deeply concerned that the potential 

impact of pending Clean Air Act regulations could be unsustainable for Arkansas 

manufacturing).Both small and large businesses are vulnerable to the extremely costly regulatory 

burdens under the Boiler Area MACT, as are municipalities, universities, government facilities, 

and commercial entities. The combined cost to these entities in Arkansas is $490 million. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Jon Bolling

Commenter Affiliation: Prince of Wales Community Advisor Council

Document Control Number: EPA-HQ-OAR-2006-0790-1935.1

Comment Excerpt Number: 1

Comment: Many communities in rural Alaska depend on diesel fuel for electricity. 

Communities on Prince of Wales Island are no exception. The island has three communities that 

rely on community diesel fired electrical generation. Six other POW Island communities are tied 

together on an electrical grid that provides hydroelectric power as the primary electric source; 

however these communities are also seasonally dependent upon diesel-generated production of 

electricity to supplement the primary hydroelectric generation. All but one of these nine 

communities have populations of less than 1,000 residents. Similarly, heat for community 

buildings is commonly provided by diesel-fired boilers. However, over the past five years the 

number of buildings heated with woody biomass has significantly increased. The City of Craig 

here on POW Island, for example, just completed its second year of heating three municipal 

buildings using chips from a local sawmill to fire a wood boiler. The wood boiler displaced the 

use of thousands of gallons of diesel and propane. Other POW communities may choose to 

install similar systems to better control heating costs. 

Utilizing biomass for heating needs in rural Alaska provides far more than just heat to a 

community. With fuel oil heating, funds leave the community to purchase the fuel and pay for 
the transportation and storage. With biomass, dollars stay within community because fuel is 

purchased locally. In addition, jobs are created through the harvest and processing of the wood. 

Many rural Alaskan villages have a history of a subsistence culture. Biomass is a major step for 

communities to regain some of their independence and subsistence lifestyle. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Bill Thomas

Commenter Affiliation: Shuqualak Lumber Company

Document Control Number: EPA-HQ-OAR-2006-0790-1948.1

Comment Excerpt Number: 1

Comment: As an industry, forest products manufacturers are experiencing a severe economic 

downturn and fierce competition from overseas producers, an environment that we do not think 

will change anytime soon. We at Shuqualak Lumber have studied the proposed Boiler MACT 

and listened to our industry leaders, and we are quite concerned about the impact of this rule on 

our already-diminished operations. 

If this rule is finalized in its current form, we believe operations like ours may simply disappear. 

None of us can afford to invest millions of dollars in 3 or 4 new types of control equipment, nor 

do we have the confidence that existing control technologies are capable of achieving the 

applicable MACT limits even if we did make the prescribed investments. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Randy Thurman and Brent Stevenson

Commenter Affiliation: Arkansas Environmental Federation and Arkansas Forest & Paper 

Council

Document Control Number: EPA-HQ-OAR-2006-0790-1830.1

Comment Excerpt Number: 1

Comment: We are deeply concerned that the potential impact of pending Clean Air Act 

regulations could be unsustainable for Arkansas manufacturing:Both small and large businesses 
are vulnerable to the extremely costly regulatory burdens under the Boilei- Area MACT, as are 

municipalities, universities, government facilities, and commercial entities. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Michael T. Palko

Commenter Affiliation: Pennsylvania Department of Conservation and Natural Resources

Document Control Number: EPA-HQ-OAR-2006-0790-1895.1

Comment Excerpt Number: 1

Comment: Compliance costs are estimated at more than $10 billion initially and $4 billion 

annually for both rules. The proposed control technology standards are more stringent than those 

in the vacated rule, and will present many new challenges for affected facilities. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Malcolm Milne

Commenter Affiliation: Durgin and Crowell Lumber Co. Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1987.1

Comment Excerpt Number: 1

Comment: Durgin & Crowell has manufactured Eastern White Pine lumber at its sawmill since 

1976, and being able to produce affordable and efficient heat for its dry kilns is critical to the 

company’s viability. Durgin & Crowell would be subject to the proposed rule due to the 

operation of its existing biomass boiler. Any replacement or upgrade of the existing unit would 

be subject to the proposed limits, as well. 

This letter is meant to voice my concerns about the potential costs as a result of the new 

proposed standards, as well as the fear that the proposed emissions limits may be unrealistic. I 

hope that the EPA will give sufficient attention to the potential harm that the proposed rule could 

do to rural small businesses like ours, and the detrimental effects that could be felt in the local 

community, as seemingly constantly rising costs make it more difficult to remain a viable 

business. Whatever new standards are enacted, they should be based on available technology, 

and should take into account an accurate cost of compliance and the potential effects on subject 

entities and their employees. 
As proposed, the new area source boiler rules will likely force Durgin & Crowell to make 

significant expenditures toward upgrades to its existing wood boiler (>10mmBtu/hr), in order to 

come into compliance with the proposed limits for CO: 160 ppm @ 7% 02. Also, the new 

proposed rule will require our company to purchase expensive continuous emissions monitoring 

equipment, as well as increase the annual amount the company spends on monitoring. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Jim Simon

Commenter Affiliation: American Sugar Cane League

Document Control Number: EPA-HQ-OAR-2006-0790-2281

Comment Excerpt Number: 1

Comment: As an employee whose job depends up the economically viable Louisiana sugar cane 

industry, I am concerned that the Proposed Rule will have an unreasonably negative impact on 

the Louisiana sugar industry without resulting in any appreciable reduction in hazardous air 

emissions. The economic burdens inherent in the Proposed Rule threaten to devastate 

Louisiana’s sugar industry and, therefore, also threaten the economic livelihood of industry 

workers, suppliers, and service providers. The negligible benefit to be gained from the Proposed 

Rule, as applied to the Louisiana sugar industry, does not justify the economic costs and resultant 

threat to the industry. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Robert E. McKenna

Commenter Affiliation: Motor and Equipment Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1920.1

Comment Excerpt Number: 1

Comment: As context for these comments, it is important to consider that manufacturers are 

attempting to fully recover from the steepest economic downturn since the 1930s and bring back 

the 2.2 million high-wage jobs lost during recent years. MEMA strongly urges federal policy 

makers to create conditions that will lead to economic expansion and not stifle the industrial and 

manufacturing vitality necessary to create 
jobs and technologies that will continue to improve the nation’s air quality. Imposing unduly 

strict mandates on the manufacturing sector will not accomplish any of these objectives. 

New and overly stringent standards for industrial boilers will have an immediate impact on our 

members’ bottom line without demonstrated environmental benefits. Compliance costs 

associated with these harsh and inflexible proposed rules will cost U.S. manufacturing jobs and 

hurt global competitiveness, just as the economic recovery attempts to gain more traction. 

Further, as described below, the severity of the proposed standards may lead to the perverse 

effect of deterring projects that otherwise would realize environmental improvements. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Brian Breaux

Commenter Affiliation: Louisiana Farm Bureau Federation, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1966.1

Comment Excerpt Number: 2

Comment: The agricultural processors impacted by the proposed EPA emission rule provide the 

only market for farmers to sell their commodities. Therefore, if additions and renovations 

necessary for an agricultural processing facility to comply with this EPA proposed rule prove too 

costly and force its closure, it in turn eliminates the only market for our farmer’s crops. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Jon Bolling

Commenter Affiliation: Prince of Wales Community Advisor Council

Document Control Number: EPA-HQ-OAR-2006-0790-1935.1

Comment Excerpt Number: 2

Comment: Power and heating systems in rural Alaska are often operated as non-profits by city 

governments or regional cooperatives. Operations are tightly controlled for costs. There is little 

revenue margin to shield customers from increased operating costs, including rising wholesale 

fuel prices and regulatory compliance. 
Compliance with the boiler emissions rule presents a financial and logistical challenge to rural 

suppliers and has the potential to seriously increase the cost of heat and power or stop the 

development of biomass systems completely. Cost increases will occur through potential 

increases in the capital cost of the boiler systems for the installation of emission control devices 

and increases operational and maintenance costs. 

The Alaska Wood Energy Development Group recently developed an estimate of the cost of 

annual stack testing for a rural Alaskan village. The following chart summarizes the quote 

received from Alaska Source Testing for the village of Stebbins, currently installing a biomass 

district heating system. Alaska Source Testing is one of Alaska’s two emissions testing 

companies. [See submittal for chart with costs.] 

Please note that the estimate includes a condition that states that onsite delays caused by the 

client will be billed at the rates listed above. Extended on-site delays caused by facility 

operations, weather or other circumstances outside the bidder’s control will be billed at 

$1000/day for Project Manager and $600/day for Technician, plus expenses. 

The daily wellbeing of rural Alaska residents and communities depends on the ability to 

economically generate heat. The uncertainty in fuels costs and ever increasing regulatory 

compliance costs makes it difficult for individuals, local and regional organizations to plan 

budgets for fuel, heat, and power costs. 

Keeping cost impacts of federal regulations for boiler emissions to a minimum is important for 

air quality. An increase in cost of the installation and operation of heating systems means people 

will continue to rely on the import of Jet A for heating fuel and the export of local dollars. 

Unemployment will continue to be significant as biomass harvest jobs fail to materialize. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Bill Thomas

Commenter Affiliation: Shuqualak Lumber Company

Document Control Number: EPA-HQ-OAR-2006-0790-1948.1

Comment Excerpt Number: 2

Comment: One alternative to huge investments in control equipment is to deliberately reduce 

our allowable production capacity to a level that would make our mill a non-major HAP source, 

however, this option of reducing production makes our mill non-competitive. We would then be 

subject only to the area source rules which may also prove to be very expensive for our 

company. Other alternatives are not any more palatable, but would include major changes in the 
processes for the sake of eliminating boilers at our site altogether. Again, we are talking about 

extremely expensive propositions in a down economy. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Mike Comb

Commenter Affiliation: Louisiana Sugarcane Cooperative Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2135

Comment Excerpt Number: 2

Comment: The arbitrary and unreasonable grouping of bagasse with other combustion sources 

that contribute significantly higher emissions of hazardous air pollutants would place an 

enormous economic burden on Louisiana sugar mills, while achieving negligible reductions in 

the emission of such pollutants. The Proposed Rule would have a devastating, perhaps fatal, 

impact on the Louisiana sugar industry in general, and specifically on Louisiana Sugarcane 

Cooperative Inc. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Michael T. Palko

Commenter Affiliation: Pennsylvania Department of Conservation and Natural Resources

Document Control Number: EPA-HQ-OAR-2006-0790-1895.1

Comment Excerpt Number: 3

Comment: Forest products industries will see reduced markets for wood residues, higher costs 

for marketing wood residues, higher costs for disposing of wood residues, and higher costs for 

using production residues for on-site energy production. Forest industries rely on their ability to 

sell or fully utilize wood residues to maintain the profitability of their operations. Reducing or 

eliminating this value stream, which may provide up to 15% of a sawmill’s income, will have 

serious business consequences. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 
Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Jon Bolling

Commenter Affiliation: Prince of Wales Community Advisor Council

Document Control Number: EPA-HQ-OAR-2006-0790-1935.1

Comment Excerpt Number: 3

Comment: The majority of boilers purchased for use in rural Alaska are Garn cordwood boilers 

and Messersmith and Chipteck chip boilers. The typical Garn boilers cost approximately $25,000 

and the typical chip boilers are estimated at $250,000. Conversations with these manufacturers 

have apparently raised concerns about the ability to meet the .03 LB/MMBTU particulate limit 

and the 100 ppmv/daily average CO limit. If the current boilers are unable to meet the new 

standards, costly emissions control equipment will significantly increase the initial costs of the 

coilers and further increase the operational/maintenance costs. In all likelihood, these significant 

costs will halt the development of biomass projects in rural Alaska. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Malcolm Milne

Commenter Affiliation: Durgin and Crowell Lumber Co. Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1987.1

Comment Excerpt Number: 3

Comment: While we understand that the overall goal of the EPA’s proposed limit is to improve 

air quality, it is unclear to us what the exact financial impact would be to our company, or 

whether we would be able to meet the new standards, even with upgrades to our existing boiler 

system. The concern is, particularly amidst a historically depressed lumber market, that the 

proposed standards will adversely affect our cost of doing business, which will in turn harm the 

marketability of our products. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.
Commenter Name: David P. Tenny

Commenter Affiliation: National Alliance of Forest Owners

Document Control Number: EPA-HQ-OAR-2006-0790-1884.1

Comment Excerpt Number: 3

Comment: The proposed rule is arbitrary and capricious because its sets emissions limitations 

for biomass boilers that are so low they would require adoption of expensive, novel control 

technology at very little benefit to human health or the environment. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Brian Breaux

Commenter Affiliation: Louisiana Farm Bureau Federation, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1966.1

Comment Excerpt Number: 3

Comment: Just as important, the impact of this proposed rule stretches far beyond agriculture 

and has a direct affect on the economy of our entire State. For example, forestry is the largest 

agricultural commodity in Louisiana and one of our largest industries in our State with an 

estimated total value of over $4.2 billion. Sugarcane is the Louisiana’s largest agronomic 

commodity with an estimated value of $670 million to our State. Processing facilities in sugar 

and timber support an entire production infrastructure that provides jobs for thousands and 

thousands of Louisiana residents and in many cases in the primary source for employment in a 

region. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: John Huber

Commenter Affiliation: National Oilheat Research Alliance

Document Control Number: EPA-HQ-OAR-2006-0790-1831.1

Comment Excerpt Number: 5
Comment: Facilities affected could include very small apartment houses, small retail buildings, 

churches, nursing homes, hospitals, large multistory apartment buildings and universities with 

central steam plants. EPA acknowledged this in the rulemaking, but failed to fully assess the 

economic impact or feasibility of applying the standards of this rule to these sources. 

Small Apartment Houses – In many cities in the northeast, there are houses that have been 

converted into apartments. In some cases these may have been three story homes that have been 

cut into flats, or small houses that have been cut into different and much smaller apartments. 

Often they were not designed to have separate heating and domestic water for each apartment, 

but rather the residents control their heating by adjusting the radiators. Typically, the boilers 

operating these facilities will be on the large side of the residential market, and may approach 

200,000 -300,000 BTUH. 

Churches – Many churches in the region use heating oil for heating and hot water production. As 

with apartment buildings, these churches will be varied in size ranging from small congregations 

of 50-100 people, to much larger churches of several hundred congregants. Typically, churches 

do not maintain temperature during the week, but instead try to raise the temperature on the day 

of worship. Again, the boilers operating in these facilities will 

typically be on the large side of the residential. 

Small Retail Buildings – Throughout the colder climes, many retail buildings will be heated and 

supplied domestic water with boilers. These building may include small convenience stores, 

Laundromats, bookstores, or small strip malls. These facilities will generally have a small heat 

load and limited water load, and thus will often be using residential boilers of 100,000-200,000 

BTUH. 

Nursing Homes – Nursing homes need both consistent heat and significant domestic water. As a 

result, many of these facilities may be using commercial burners. A typical commercial burner 

may be able to generate 5 million BTUH, and be able to heat a fairly large building. As the 

facility grows, the industry will generally tie multiple boilers together to provide the appropriate 

heating. It should be noted, that these facilities are considered critical care, and may have 18-20 

MMBTU of total capacity, however it is often the result of two boilers of equal capacity, with 

the second boiler designed to be backup. 

Hospitals – Hospitals may also vary substantially from small rural hospitals with a minimal 

heating load to very large hospital centers in urban centers. The smaller hospitals may be using 

commercial burners, while the larger hospital centers may be using a central steam plant. Similar 

to nursing homes, they will have a second boiler for emergency backup. 

Apartment Buildings/Multi-Family Housing – Many multi-story apartment buildings use oil for 

their generation of heating and hot water. These facilities may use multiple boilers of <10 million 

BTU each. 

Universities, Campus Type Facilities – These large facilities often have a central boiler system, 

and often use a central steam distribution system. It is conceivable that these are major sources. 

Some of these facilities may burn coal or have emissions associated with agriculture or other 

industrial activities. However, it is also conceivable that these facilities will have a small 

outbuilding which may have a residential boiler installed. NORA believes that it is appropriate to 

exempt these facilities as area sources rather than major sources. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 
Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: David P. Tenny

Commenter Affiliation: National Alliance of Forest Owners

Document Control Number: EPA-HQ-OAR-2006-0790-1884.1

Comment Excerpt Number: 7

Comment: As reported by an AF&PA analysis, the forest products industry estimates the cost of 

compliance with the emissions limitations for biomass boilers would be $3.3 billion in that sector 

alone. In the preamble to the proposed rule, EPA recognizes that economic burden may justify an 

alternative compliance method. Because the costs to industry to achieve the proposed rule’s very 

low emissions limitations would be incredibly high and could not be consistently achieved in 

practice, EPA should revise its approach for biomass boilers to ensure that these boilers are not 

penalized because they start with a cleaner fuel. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Michael T. Palko

Commenter Affiliation: Pennsylvania Department of Conservation and Natural Resources

Document Control Number: EPA-HQ-OAR-2006-0790-1895.1

Comment Excerpt Number: 9

Comment: The rule’s high compliance costs will discourage renewable biomass use and 

disproportionately damage rural economies. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Michael A. Livermore

Commenter Affiliation: Institute for Policy Integrity New York University School of Law

Document Control Number: EPA-HQ-OAR-2006-0790-1899.1

Comment Excerpt Number: 12
Comment: Estimates of employment impact derived from Morgenstern et al.: The Regulatory 

Impact Analysis uses two techniques to estimate the changes in employment due to the proposed 

rules. The first is a longstanding method used by EPA in many previous analyses. This technique 

looks at the output decrease in the relevant sectors and uses an estimate for jobs per unit of 

output to calculate a projected decrease in employment. This “demand effect” technique for 

projecting changes in employment is described in the Economic Analysis Resource Document 

issued by the Office of Air Quality Planning and Standards in April 1999. [Footnote: OFFICE 

OF AIR QUALITY PLANNING AND STANDARDS, EPA, OAQPS ECONOMIC ANALYSIS 

RESOURCE DOCUMENT at 5-42 to 5-43 (1999).] It contains an implicit assumption that the 

result of environmental regulations will be price increases and that these price increases will 

result in lower sales for regulated entities. 

However, this type of employment projection is incomplete. The agency correctly identifies that 

there are at least two types of employment effects from environmental regulations which are not 

included in the “demand effect” calculation: the “cost effect” and the “factor shift effect.” 

[Footnote: RIA at 4-6 to 4-7.] The “cost effect” recognizes that, for a given level of output, 

expenditures on reducing pollution often require additional employees. The “factor shift effect” 

recognizes that production can be more or less labor intensive after compliance with an 

environmental regulation. 

The size of each of these effects and the direction of the “factor shift effect” are all empirical 

matters and will likely vary from industry to industry and from regulation to regulation. In order 

to estimate these effects, EPA uses econometric estimates from a 2002 paper by Morgenstern et 

al. [Footnote: RIA at 4-7.] This paper estimated the employment effects of spending on 

environmental policies across a number of industries. [Footnote: Richard D. Morgenstern, 

William A. Pizer & Jhih-Shyang Shih, Jobs Versus the Environment: An Industry Level 

Perspective, 43 JOURNAL OF ENVIRONMENTAL ECONOMICS AND MANAGEMENT 

412, 412 (2002).] As the RIA recognizes, the point estimates do not perfectly correspond to the 

analysis that EPA is doing. The range of industries analyzed is not the same and the paper uses 

older data. 

Nevertheless, this technique at least recognizes and has the possibility of capturing effects that 

the traditional techniques of estimating employment effects cannot. This makes the estimates 

derived from the Morgenstern paper at least as valuable as the traditional techniques of 

estimating employment effects. The adoption of this technique by EPA could attract additional 

interest in this area and encourage economists to publish new studies on the topic with newer 

data. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.
Commenter Name: Edward J. Wilusz

Commenter Affiliation: Wisconsin Paper Council

Document Control Number: EPA-HQ-OAR-2006-0790-2133

Comment Excerpt Number: 13

Comment: The rationale that supports the proposed approach for the Gas 1 subcategory applies 

equally well to biomass boilers and, therefore, provides ample support for adopting work 

practices instead of numeric emissions limitation for biomass boilers. For example, in the forest 

products industry alone, the estimated cost of complying with the proposed HAP emissions 

limitations for biomass boilers is $3.3 billion. This is an extraordinary cost that, in the context of 

the forest products industry, equals or exceeds the magnitude of the economic burden that EPA 

predicts for the Gas 1 subcategory. Similarly severe economic impacts are expected in other 

industry sectors where biomass boilers are widely use, such as the furniture, sugar, and 

agricultural products industries. Thus, there is strong economic justification for prescribing work 

practice standards for biomass boilers in lieu of numeric emissions limitations. 

Response: This comment pertains to the major source boiler rulemaking. Provided the 

commenter has submitted this comment to the major source boiler rulemaking docket, the 

response to this comment will be provided there.

Commenter Name: Edward J. Wilusz

Commenter Affiliation: Wisconsin Paper Council

Document Control Number: EPA-HQ-OAR-2006-0790-2133

Comment Excerpt Number: 18

Comment: the proposed standards are far more stringent than needed to assure protection of 

health and the environment from industrial boiler HAP emissions. Wisconsin’s pulp and paper 

industry faces a challenging global economic slump and fierce competition from overseas 

manufacturers. This situation has existed for the past ten years. Mills in Port Edwards, Niagara, 

Neenah, Menasha, and Kimberly have closed during that time. In the last ten years paper 

industry employment in Wisconsin has dropped from 52,000 to 32,000. That’s over $1 billion in 

annual wages lost. 

We are concerned that compliance with EPA’s proposed boiler MACT standards will be 

extremely expensive, if compliance can be achieved at all. EPA’s estimated capital costs of $9.5 

billion, a staggering estimate in its own right, appears to be low. Industry capital cost estimates 

for the forest products sector alone are estimated to be $6.8 billion. The estimated costs for 

Wisconsin are $680 million, with $470 million born by the forest products industry. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 
Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 24

Comment: The solid fuel fired units will require a capital investment of $5.1 billion out of the 

total $8.0 projected capital cost. While not discussed in detail in these comments, Duke Energy 

believes that EPA has significantly underestimated the capital cost of compliance with these 

rules. What is equally puzzling is that EPA projects in Table 11 that the rules will apply to only 

46 new units. Duke Energy believes that this number is grossly understated since many solid fuel 

fired units may be forced by economics to shutdown and repower with new boilers fired by 

natural gas or other fuels. More egregiously, many of these sources will alternatively decide to 

shut down permanently. 

Response: This comment pertains to the major source boiler rulemaking. Provided the 

commenter has submitted this comment to the major source boiler rulemaking docket, the 

response to this comment will be provided there.

Commenter Name: Brian Breaux

Commenter Affiliation: Louisiana Farm Bureau Federation, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1966.1

Comment Excerpt Number: 1

Comment: Our comments are submitted because we are very concerned that the proposed EPA 

rule on the emission standards for industrial, commercial and institutional boilers will negatively 

impact processors of agricultural commodities in our State such as sugar mills and timber 

processing facilities. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Wayne J. Galler

Commenter Affiliation: Georgia Industry Environmental Coalition, Inc
Document Control Number: EPA-HQ-OAR-2006-0790-1997.1

Comment Excerpt Number: 1

Comment: GIEC believes the proposed Area Source Boiler Standard is far more stringent than 

needed to assure protection of health and the environment due to HAP emissions from the 

affected boilers. GIEC members face a global economic depression and strong competition from 

overseas manufacturers. Therefore, it is imperative for environmental requirements such as these 

standards to be crafted such that public health and the environment are protected without 

requiring unnecessary expenditures of time and resources. 

EPA has the legal discretion and technical justification to create standards that minimize the 

burden to industry while still providing ample protection to human health and the environment. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Jay C. Moon

Commenter Affiliation: Mississippi Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-2000

Comment Excerpt Number: 1

Comment: New and overly stringent standards for industrial boilers will have an immediate 

impact on our members’ bottom line without demonstrated environmental benefits. Compliance 

costs associated with these harsh and inflexible proposed rules will cost U.S. manufacturing jobs 

and hurt global competitiveness, just as the economic recovery attempts to gain more traction. 

Further, as described below, the severity of the proposed standards may lead to the perverse 

effect of disincentivizing projects that otherwise would realize environmental improvements. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: John Ledger

Commenter Affiliation: Associated Oregon Industries

Document Control Number: EPA-HQ-OAR-2006-0790-2024.1

Comment Excerpt Number: 1
Comment: New and overly stringent standards for industrial boilers will have an immediate 

impact on Oregon’s economy without demonstrated environmental benefits. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Paul Lyskava

Commenter Affiliation: Pennsylvania Forest Products Association

Document Control Number: EPA-HQ-OAR-2006-0790-2223.1

Comment Excerpt Number: 1

Comment: We believe the proposed Area Source Boiler Standard is far more stringent than 

needed to assure protection of public health and the environment due to affected boilers. The 

result of the current proposal will be to impose significant and often unnecessary costs on our 

industry at a time when forest product companies are struggling to survive the domestic and 

global economic recession, tight credit markets and increased competition from overseas 

manufacturers. Therefore, it is imperative for mandatory environmental controls such as these 

standards to be tailored as closely as possible to ensure that health and the environment are 

protected without requiring unnecessary expenditures of time and resources. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: David M. Kiser

Commenter Affiliation: International Paper Company

Document Control Number: EPA-HQ-OAR-2006-0790-1924.1

Comment Excerpt Number: 1

Comment: The Boiler GACT rule as currently proposed will potentially impact 57 boilers at 45 

International Paper facilities. When considered with the 3 other boiler-related rules proposed at 

the same time [Footnote: The Non-Hazardous Secondary Materials or NHSM rule, the 

Commercial and Industrial Incinerator or CISWI rule and the Boiler Maximum Achievable 

Control Technology or MACT rule] (which IP has made separate comment), the exceedingly 

high potential cost of these rules necessitates that EPA use their full range of discretionary 

authority to make pragmatic decisions that minimize cost while meeting statutory requirements 

and ensuring with an appropriate margin of safety for the protection of the public and the 
environment. The comments of the American Forest and Paper Association (AF&PA), which IP 

participated in developing and incorporates herein by reference, demonstrates clearly and 

specifically that EPA has this discretion and indeed may be legally compelled to change their 

approach to ensure more pragmatic and legally defensible decisions. 

International Paper requests EPA consider these comments and alter the proposed rule in order to 

minimize its burden while being appropriately protective of the environment. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: A. Steven Young

Commenter Affiliation: Association of Independent Corrugated Converters

Document Control Number: EPA-HQ-OAR-2006-0790-1994.1

Comment Excerpt Number: 1

Comment: It is important to consider that manufacturers are attempting to fully recover from the 

steepest economic downturn since the 1930s and bring back the 2.2 million high-wage jobs lost 

during recent years. AICC strongly urges federal policy makers to create conditions that will lead 

to economic expansion and not stifle the industrial and manufacturing vitality necessary to create 

jobs and technologies that will continue to improve the nation’s air quality. Imposing unduly 

strict mandates on the manufacturing sector will not accomplish any of these objectives. 

New and overly stringent standards for industrial boilers will have an immediate impact on the 

independent corrugated converter’s bottom line without demonstrated environmental benefits. 

Compliance costs associated with these harsh and inflexible proposed rules will cost U.S. 

manufacturing jobs and hurt global competitiveness, just as the economic recovery attempts to 

gain more traction. Further, as described below, the severity of the proposed standards are 

disincentives to projects that otherwise would realize environmental improvements. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Dan H. Williams

Commenter Affiliation: Sealed Air Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2228.1
Comment Excerpt Number: 1

Comment: As an advocate of environmental stewardship, Sealed Air Corporation has made 

exhaustive efforts to minimize our impact to the environment through raw material 

replacement/reformulation efforts; a chemical approval or oversight program; conversion to 

electric boilers in some locations; use of only electrically heated extrusion systems; and 

primarily operating any boilers using clean burning fuels. In doing so, Sealed Air Corporation 

has been able to manage all our production operations as minor sources of hazardous air 

pollutants. Rather than waiting for applicable MACT standards to become applicable or be 

developed, Sealed Air voluntarily opted to eliminate the use of these materials. With the 

development of this area source MACT, Sealed Air is unduly pulled into federal permitting and 

standards that will in no way achieve a substantial reduction in hazardous air pollutants. 

Despite all these management efforts, Sealed Air believes that the standards as proposed will 

have a detrimental and likely significant effect on its operations in the U.S. without providing 

any substantive environmental benefits. At this point we see no option for compliance with the 

regulations at some of our facilities other than to cease operations. 

We ask that EPA consider the comments provided below and make the requested modifications 

to the proposed regulations. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Keith A. Craig

Commenter Affiliation: Pennsylvania Hardwoods Development Council

Document Control Number: EPA-HQ-OAR-2006-0790-2017.1

Comment Excerpt Number: 1

Comment: We write to express our grave concerns about the proposed Boiler MaximumAchievable Control Technology (Boiler MACT) rule published by the EPA on June 4, 2010. We 

believe the proposed rule could severely hurt the wood products manufacturing industry in 

Pennsylvania, already staggered by the on-going national recession. The wood products industry 

in this Commonwealth has lost over 20,000 jobs in the past two years, nearly a quarter of a 

robust employment level. Production has been cut in half. The proposed rule would potentially 

add tens of millions of dollars in capital and compliance costs to our companies, clearly 

unsustainable and at the worst possible time. 
Response: This comment pertains to the major source boiler rulemaking. Provided the 

commenter has submitted this comment to the major source boiler rulemaking docket, the 

response to this comment will be provided there.

Commenter Name: Mike Beebe

Commenter Affiliation: Governor, State of Arkansas

Document Control Number: EPA-HQ-OAR-2006-0790-2001

Comment Excerpt Number: 1

Comment: As our state’s unemployment rate has risen, I fear that enacting stringent federal 

Boiler MACT rules could jeopardize more good-paying jobs across the manufacturing sector. 

The Arkansas forest products industry alone generates $7.7 billion in revenue and employs more 

than 29,000 individuals, but the industry works continually to thrive in this economy. The flow 

of capital for new investment and hiring is still seriously restricted, and the estimated costs of the 

proposed rule to the Arkansas forest products industry (which they feel is significantly 

underestimated and could be over $390 million) could make or break the viability of continued 

operations. 

Response: This comment pertains to the major source boiler rulemaking. Provided the 

commenter has submitted this comment to the major source boiler rulemaking docket, the 

response to this comment will be provided there.

Commenter Name: Scott Manley

Commenter Affiliation: Wisconsin Manufacturers and Commerce

Document Control Number: EPA-HQ-OAR-2006-0790-2258.1

Comment Excerpt Number: 1

Comment: As context for these comments, it is important to consider that manufacturers are 

attempting to fully recover from the steepest economic downturn since the 1930s, and bring back 

the 2.2 million high-wage jobs lost during recent years. WMC strongly urges federal policy 

makers to create conditions that will lead to economic expansion and not stifle the industrial and 

manufacturing vitality necessary to create jobs and technologies that will continue to improve the 

nation’s air quality. Imposing unduly strict mandates on the manufacturing sector will not 

accomplish any of these objectives. 

New and overly stringent standards for industrial boilers will have an immediate and adverse 

impact on the ability of Wisconsin manufacturers to compete in an international marketplace, 

and will do so without demonstrated environmental 

benefits. Compliance costs associated with these harsh and inflexible proposed rules will be 

considerable. For example, the compliance cost in Wisconsin is expected to be $680 million, 

including a $470 million direct hit to Wisconsin’s pulp and paper industry alone. We are very 

concerned that these costs will result in manufacturing job loss at a time when Wisconsin is 

struggling to regain its economic footing. 
Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Patrick J. Medvecz

Commenter Affiliation: Wausau Paper Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2283

Comment Excerpt Number: 1

Comment: As the Corporate Vice President of Manufacturing & Technology for Wausau Paper 

Corp., headquartered in Mosinee, WI, I am very concerned that the proposed EPA Boiler MACT 

rule, if enacted, will substantially increase operating costs for our mills and could put mill jobs, 

and the communities that rely on these jobs, at risk. The proposed rule goes far beyond any 

previous regulation and any statute needed to protect the health of our communities. It seems 

highly likely that it may not be possible for many boiler operators to achieve the impractical 

standards necessary to comply with the rule’s requirements; no matter what kind of pollution 

controls are installed. 

I have seen many paper mills close in the last few years because of rising operating costs and the 

tragic U.S. economy, including several Wausau Paper facilities. Over the last few years Wausau 

Paper has had no choice but to close six facilities located in Appleton and Columbus, Wisconsin, 

Jay, Maine, Jackson, Mississippi, Groveton, New Hampshire, and Middletown, Ohio. Wausau 

Paper now employs roughly 1300 fewer employees than they did 10 years ago. 

The paper industry has experienced some very tough years. The impact of this overcompensating regulation, if unmodified, will drive further decline, and perhaps the demise of 

significant employers. Other good paying jobs are hard to find in these rural areas, so the harmful 

impact would last a long time, if not forever. The communities surrounding our mills will suffer 

if support from our mills end; 

not just from lost tax revenue, but also from the significant involvement the mill and its 

employees have in all aspects of the community. In the last ten years, paper industry employment 

in Wisconsin has dropped from 52,000 to 32,000. That’s over $1 billion in annual wages lost. 

The communities associated with these mills have suffered greatly, as a consequence. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Al Hankins, Jr.
Commenter Affiliation: Hankins Lumber Company, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1841.1

Comment Excerpt Number: 1

Comment: We are a lumber manufacturing company that supplies quality dimensional lumber to 

customers throughout the world. We began operations in the 1950s, and currently employ about 

100 people. Our company is the lifeblood of our rural town of Elliot Mississippi. 

As an industry, forest products manufacturers are experiencing a severe economic downturn and 

fierce competition from overseas that we do not think will end anytime soon. We at Hankins 

Lumber have studied the proposed Boiler MACT and listened to our industry leaders and we are 

quite concerned about the impact of this rule on our already-diminished operations. 

If this rule is finalized in its current form, we believe operations like ours may simply disappear. 

None of us can afford to invest millions of dollars in 3 or 4 new types of control equipment. That 

is not to mention that we are not confident that we would be capable of meeting all the applicable 

MACT limits even if we did make the prescribed investments. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Raymond J. Nutting

Commenter Affiliation: County of El Dorado Air Quality Management District

Document Control Number: EPA-HQ-OAR-2006-0790-2225.1

Comment Excerpt Number: 1

Comment: The AQMD Board is very concerned with the potential consequences of the 

proposed regulations and does not support the new Maximum Achievable Control Technology 

(MACT) standards for industrial boilers for major sources and area sources. The proposed boiler

MACT standards have not been properly determined and if implemented will result in multiple 

adverse outcomes. Compliance with this regulation will require existing facilities to install 

expensive and mostly untested "end of pipe" control technologies, which are not proven 

necessary to protect human health or environment. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.
Commenter Name: Dennis Vroman

Commenter Affiliation: United Steel Workers

Document Control Number: EPA-HQ-OAR-2006-0790-2209

Comment Excerpt Number: 1

Comment: As a representative of the United Steel Workers Local 11-0022 at the Wausau Paper 

Mill in Brainerd, Minnesota. I am very concerned that the proposed EPA Boiler MACT rule, if 

enacted, will substantially increase operating costs for our mill and could put our jobs, and the 

communities that rely on these jobs, at risk. My understanding of the proposed rule is that it goes 

far beyond any previous regulation and any statute needed to protect the health of our 

communities. It seems highly likely that it may not be possible for many boiler operators to 

achieve the impractical standards necessary to comply with the rule’s requirements; no matter 

what kind of pollution controls are installed. That makes no sense. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Keith M. Krom

Commenter Affiliation: AT&T, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2243

Comment Excerpt Number: 1

Comment: AT&T is concerned that EPA has insufficient data to support its proposal. Indeed, 

EPA indicates that it has no emission data for polycyclic organic matter ("POM" and limited 

emission data for mercury and carbon monoxide (CO) from area source boilers. In addition, there 

is limited information available to EPA through state permitting actions regarding such boilers. 

From AT&T’s review of the MACT floor analysis contained in the proposed rule, it appears that 

in formulating its regulatory standards, EPA has relied on mercury emission data for only 2 coalfired boilers and CO emission data for only 5 such boilers; for biomass-fired boilers, EPA 

indicated no state data was available and that the only emission data available to EPA was from a 

program to promote the burning of woody biomass in schools; and for oil-fired area source 

boilers, EPA indicated that CO emission data was available for 68 boilers as part of the Boiler 

MACT Information Collection Request. [Footnote: It also appears that EPA may have primarily 

or solely relied on data from boilers in excess of 10 MMBtu/hr heat input in establishing 

standards for boilers of all sizes EPA’s MACT floor analysis for this proposed rule notes that, 

"The emissions database contains PM test data for 75 area source boilers obtained from the ICR 

survey conducted for major sources. All of the boilers were greater than 10 million Btu per hour 

in size." Memorandum on MACT Floor Analysis for the Industrial, Commercial, Institutional 

Boilers National Emission Standards for Hazardous Air Pollutants — Area Source, U.S. 

Environmental Protection Agency, OAQPS/SPPD, April 2010 at 13.] 
Based on such a limited data set, EPA is nonetheless proceeding to propose regulatory standards 

affecting an estimated 183,000 existing units [Footnote: EPA’s MACT floor analysis indicates 

that, "Using the average nation-wide projections from the 13-state boiler inspector inventory, 

there are 182,671 boilers at area sources of HAP. Of these, 10,958 boilers are designed to fire 

biomass, 3,710 boilers are designed to fire coal, 168,003 boilers are designed to fire liquids. Id. 

at 3.] at 91,300 area source facilities. In addition to proposing daily and monthly emission limits 

applicable to larger area sources, EPA is also making several determinations with regard to what 

controls are appropriate and available for all new coal, biomass and oil-fired units (regardless of 

size), what limits should apply to sources during periods of start-up, shutdown and malfunction, 

what monitoring requirements are applicable and how compliance must be demonstrated. Given 

the full range of regulatory determinations that EPA is making within the Area Source Boiler 

Rule, we believe that a more prudent course would be for the Agency to take sufficient time to

gather relevant data. EPA must have sufficient data to underpin its final rulemaking; without 

such, Agency decisions on final requirements may be arbitrary and capricious. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Christopher S. Bond

Commenter Affiliation: Missouri, United States Senate

Document Control Number: EPA-HQ-OAR-2006-0790-2200.1

Comment Excerpt Number: 1

Comment: Families and communities across Missouri depend upon the forest products industry 

for their livelihood. These are good people who work hard for modest wages across the 14 

million 

forested acres in Missouri. Seventy-four percent of the energy needs of their employing sawmills 

come from their wood by-products. Woody biomass is not only an affordable fuel, it is also a 

renewable fuel that is lower in greenhouse gas emissions than alternative energy sources like 

coal-fired electricity or propane fired boilers. Those operations that do not use their own woody 

byproducts sell them to others, providing up to 15% of a sawmill’s income. This value as 

a fuel or income source is often the difference between profitability and layoffs or closure. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.
Commenter Name: Charlie Cary

Commenter Affiliation: Biomass Combustion Systems, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1990.1

Comment Excerpt Number: 2

Comment: The Federal Government has put together a case for recommending a five to one 

reduction in CO emissions and an eight to one reduction in particulate emissions over what most 

States previously required based on extrapolated, limited, data. 

Unquestionably, such a dramatic regulatory change would have a devastating impact on this 

moderate scale wood energy market. What I find particularly disturbing about these proposed 

regulations is methodology used to develop the emission standards and resulting economic

impact analysis are so incredibly limited in scope and flawed. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Ben Brandes

Commenter Affiliation: National Mining Association

Document Control Number: EPA-HQ-OAR-2006-0790-1980.1

Comment Excerpt Number: 2

Comment: EPA’s regulatory agenda for the power sector will almost certainly significantly 

reduce the use of coal for electric generation. While EPA so far has not done any study of the 

cumulative impact of these regulations on coal use (or otherwise), the contractor EPA uses to 

model impacts of individual regulations recently produced its own analysis showing that just the 

EGU MACT standards alone will force major retirements of coal-fueled power plants. Forced 

retirements will have substantial negative economic impacts nationally, but will also have severe 

impacts locally, as exemplified by the Arizona Hopi and the Navajo Generation Station: 

‘scott Canty, the Hopi Nation’s general counsel, explained to a panel of lawmakers on Nov. 2 

that closure of the Navajo Generating Station would cripple the tribal government. The Hopi 

Nation relies heavily on coal revenues to fund its government, Canty said. About 88 percent of 

the tribal government‘s budget comes from revenue generated by coal-fired energy production at 

the Navajo Generating Station, Canty said. . . . The EPA has proposed rules that would require 

the power plant to install expensive emissions equipment to address visibility impairment issues 

at the Grand Canyon. But the plant‘s owners and the tribes argue that the retrofit is too costly.7 

Moreover, news accounts recently reported that EPA is well aware that its regulatory efforts in 

the power sector will increase the costs to coal-fueled EGUs and make them less competitive 

with renewable resources. In an article entitled ?Administration Eyes EPA Rules To Spur Shift 

From Coal To Renewables, it was reported that: 
Rob Brenner of EPA’s Office of Air & Radiation told a July 28 meeting of the agency’s 

environmental justice advisers that pending rules to control emissions, waste and water 

discharges from utilities will not only protect public health but add costs to the industry that 

might make renewable energy a more viable alternative. 

?We need to set health-based standards for power plants, and once we do that then they can 

compete with some of these renewable sources, Brenner said at the National Environmental 

Justice Advisory Committee (NEJAC) meeting in Washington, DC. He added later, ?It’s not 

really a fair competition because [coal-fueled power plants] are cheaper than they should be 

because they’re not controlling their pollutants to their full extent because EPA is yet to issue 

key rules for the sector, including a mercury air rule and a plan to regulate coal combustion 

residue. 

The same article reported that the White House also understands that transforming the power 

sector will inevitably result in reduced use of coal and increased use of renewables. Referring to 

remarks of Nancy Sutley, Chair of the White House Council on Environmental Quality, the 

article reported that: 

Sutley responded that she doubts the existence of so-called clean coal. ?Other people have 

labeled it ?clean coal,‘ she said. ?I don’t know if I would necessarily concede that that is real. . . . 

I think in the long run, not just for the [United States] but for the world, that developing and 

making sure that there is access to these inherently cleaner sources of energy is important. . . . . 

We need to use energy more efficiently and more cleanly. 

[Footnotes 6: Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate 

Matter and Ozone, 75 Fed. Reg. 45,210, 45,227/3 (August 2, 2010), quoting the EPA 

Administrator‘s January 12, 2010 outline of the Agency‘s seven priorities.] 

[Footnote 7:Luige del Puerto, Hopi Nation in Arizona appeals for help as coal plant face 

disclosure, ARIZ. CAP. 

TIMES, Nov. 3, 2009, available at http://www.allbusiness.com/government/government-bodiesofficesregional/13389633-1.html.] 

[Footnote 8: Administration Eyes EPA Rules to Spur Shift from Coal to Renewables, 

InsideEPA.com (July 29, 2010), at http://insideepa.com/201007291915893/EPA-DailyNews/Daily-News/administration-eyesepa-rules-to-spur-shift-from-coal-to-renewables/menu-id95.html.] 

[Footnote 9: Administration Eyes EPA Rules to Spur Shift from Coal to Renewables, 

InsideEPA.com (July 29, 2010), at http://insideepa.com/201007291915893/EPA-DailyNews/Daily-News/administration-eyesepa-rules-to-spur-shift-from-coal-to-renewables/menu-id95.html.] 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Alice Edwards

Commenter Affiliation: Alaska Department of Environmental Conservation
Document Control Number: EPA-HQ-OAR-2006-0790-1926.1

Comment Excerpt Number: 2

Comment: The economic impact of the rule will be significant to Alaskan sources. ADEC 

believes that the economic impact analysis (EIA) conducted by EPA which underlies the rule 

does not adequately take into consideration the costs and conditions found in Alaska and faced 

by Alaskan sources—particularly small and rural sources. The EIA is based on generalized 

national costs to commercial enterprises (Morgenstern et al) and do not reflect the significantly 

higher true costs found in Alaska, particularly in rural and native communities. Alaskan 

communities face much higher costs for fuel, transportation, and labor than the rest of the United 

States; are located at great distance from trained testing professionals; and have limited local 

economic resources. It appears unlikely that the EIA conducted by EPA took the myriad Alaska 

specific factors into account in determining that all new and existing boiler sources should be 

subject to the requirements under the proposed rule. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Robert E. Cleaves

Commenter Affiliation: Biomass Powe Association

Document Control Number: EPA-HQ-OAR-2006-0790-1992.1

Comment Excerpt Number: 2

Comment: As proposed, these rules are unachievable and could cause the closure of existing 

biomass energy plants and certainly frustrate the growth of this industry. If that were to happen, 

virtually every major renewable energy policy at the federal and state level would come to an 

abrupt halt. 

The Administration’s support of biomass has been unwavering and involves almost every 

member of the Cabinet -

The White House. In a series of seven Executive Orders, involving Presidents Clinton, Bush, and 

Obama, the federal government is mandated to “lead by example” and purchase 50% renewable 

power, including biomass. (13101 of September 14, 1998; 13123 of June 3, 1999, 13134 of 

August 12, 1999, 13148 of April 21, 2000, 13149 of April 21, 2000, 13514 of October 5, 2009). 

A Presidential Directive, signed by the President on May 5, 2010, directed the acceleration of 

investment in, and production of, various biofuels including biomass. 

USDA. The Agency launched an unprecedented effort through the Biomass Crop Assistance 

Program, to accelerate the industry and, according to Secretary Vilsack, “stimulate biomass 

production...that will benefit producers and provide materials necessary to generate clean energy 

and reduce carbon pollution.” To date, BCAP is responsible for over $200 million in support for 
bioenergy. Other USDA programs include the Biorefinery Assistance Program (Section 9003 of 

the Farm Bill), the Rural Energy for America Program, and grants under the American Recovery 

and Reinvestment Act to enhance woody biomass utilization, totaling nearly $55 million in 14 

states. 

DOE. Secretary Chu has supported grants for wood-to-energy and forest utilization projects 

designed to “create jobs, promote our energy independence, and cut our carbon emissions by 

unlocking the enormous potential for renewable energy in the Western United States.” 

Interior. Secretary Salazar has created a federal task force to boost investment in biomass. 

Council on Environmental Quality. The Chair of the White House Council on Environmental 

Quality, Nancy Sutley has declared that biomass is among “the issues we are also focused on at 

the White House under the leadership of President Obama.” Indeed, CEQ recently proposed to 

exclude biofuel and biomass combustion from the federal government’s greenhouse gas 

accounting and reporting guidance because they are biogenic emissions in contrast to carbon 

from fossil fuels that “represents a net increase in atmospheric carbon...”)See 75 Fed Reg.49913 

(August 16, 2010) 

EPA. EPA has encouraged the use of biomass at coal plants fined for violating federal emission 

standards. A recently announced settlement with Ohio Edison involved the requirement that the 

utility increase biomass combustion to decrease its carbon emissions. EPA declared that 

“Today’s settlement improves air quality for the local community and reduces greenhouse 

emissions by requiring the use of a renewable, carbon-neutral fuel to generate electricity.” Joint 

EPA/DOJ Press Release dated August 12, 2009. 

DOJ. The Department of Justice has extolled the use of biomass to improve air quality at coal 

plants, commenting on the same settlement that “We are pleased that Ohio Edison has chosen to 

significantly reduce greenhouse gases and other pollutants ...and hope that [it] will become the 

standard-bearer for other companies considering conversion to renewable biomass fuels ...” 

Treasury. The Department of Treasury has awarded millions in so-called 1603 Grants to support 

new biomass to electricity facilities. 

Commerce. Finally, the Department of Commerce, through its International Trade 

Administration, has encouraged and supported US companies in the export of technology 

relating to biomass. 

In Congress, biomass has been included in every single piece of renewable energy legislation 

beginning with the Public Utility Policy Act of 1978. Support for biomass is universal, bipartisan, and spans the scope of virtually every major energy policy enacted by the Congress. 

Support for biomass receiving tax incentives like other renewables began in 1992 with passage 

of the National Energy Policy Act and has been continuous and unwavering. 
Biomass utilization has been supported through Congressional farm policy, most recently in Title 

IX of the Food, Conservation and Energy Act of 2008. 

Most importantly, biomass is a cornerstone of Waxman Markey (HR 2454) and Bingaman 

(S.1462), and is included in every major proposed effort by Congress to adopt a federal 

renewable energy standard a goal that President Obama has voiced long-standing support for. 

Finally, biomass plays a critically important role in the efforts by states to achieve renewable 

goals. Forty six states and US territories have some form of a renewable portfolio standard; 

virtually all of these states include biomass, which is considered critical in meeting state goals. 

For example, in Massachusetts, it is estimated that in 2008, biomass provided nearly 40% of the 

Commonwealth’s supply. See MA RPS Compliance Report for 2008 at page 10. In the 

Southeast, the potential for biomass is enormous. The Southern Alliance for Clean Energy to 

recently estimated that the resource in that region could provide up to 25% of its power needs by 

2025. 

Internationally, the support for biomass is widespread. The United Kingdom recently announced 

that it would remove an obstacle to financing biomass power plants by supporting the industry 

through obligations on utilities to use biomass power for the next 20 years. Bloomberg, July 27, 

2010. And recently, the European Commission declared that biomass has a “large potential as a 

source of renewable energy and greenhouse gas reductions. In fact, the EU predicts that biomass 

could reduce carbon dioxide 55 to 98 percent but only with a “concerted effort by companies and 

public institutions to remove a number of significant growth barriers.” “Biomass for Heat and 

Power,” European Climate Foundation. 

The proposed rules are uneconomic, unachievable and will frustrate the nation’s renewable 

energy goals at a time of grave economic conditions. 

In light of the overwhelming support for biomass from every corner of government, it is 

imperative that EPA adopt a rule that is protective of the public health and the environment while 

also allowing this critically important energy source to be fully utilized. We are concerned that 

the proposed rules will impose tens of billions of dollars in capital costs at thousands of facilities 

across the country. Thus, we ask EPA to consider flexible approaches that appropriately address 

the diversity of boilers, operations, sectors, and fuels that could prevent severe job losses and 

billions of dollars in unnecessary regulatory costs. In this regard, we ask you to consider three 

particular issues. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Paolo Maffei
Commenter Affiliation: Tuolumne County

Document Control Number: EPA-HQ-OAR-2006-0790-2276

Comment Excerpt Number: 2

Comment: Now the proposal is to apply equal emission standards to small and large 

furnaces. If this forces many to shut down, it puts additional strain on the grid, creates 

power loss as local generation is replaced by more distant power sources and raises 

the question of what happens to the feedstock no longer used. Why impose additional and 

unreasonable requirements, especially in today’s economy? 

Response: This comment pertains to the major source boiler rulemaking. Provided the 

commenter has submitted this comment to the major source boiler rulemaking docket, the 

response to this comment will be provided there.

Commenter Name: Martin Lunde

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2065.1

Comment Excerpt Number: 2

Comment: The proposed rule will shut those businesses whose employees manufacture, 

distribute, sale and service the small commercial wood units. In my particular case it would 

directly affect approximately 46 people, indirectly many more. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Michael A. Zapkin

Commenter Affiliation: Eastman Kodak Company

Document Control Number: EPA-HQ-OAR-2006-0790-2170.1

Comment Excerpt Number: 2

Comment: Cost and job implications of the Boiler MACT are not justified by the HAP emission 

reductions realized. 

Kodak’s Eastman Gelatine facility operates three boilers with dual fuel capability that are 

covered by the Area Source Boiler MACT. These boilers can be fired exclusively with either #6 

oil or natural gas. The boilers currently operate under a Title V permit with a CO limit of 200 

ppmv. The excessively stringent proposed limit of 2 ppmv will force the facility to undertake 
significant boiler modifications or to operate the boilers with natural gas as the only fuel. The 

dual fuel capability gives the facility a strong negotiating position when dealing with natural gas 

providers and transporters. Taking that away could seriously inhibit our ability to get the best 

prices possible, with potentially catastrophic consequences impacting the long term viability of 

Eastman Gelatine. 

Specifically, the cost of natural gas will most likely increase. At Eastman Gelatine, the loss of 

our dual fuel negotiating position would jeopardize the current, favorable transport fee for 

natural gas ($450K per year versus an increase of up to $1.65 million dollars per year). 

Finally, increased costs due to modifications for reduced CO emissions ($100K or more), stack 

tests ($35K -$40K per year), fuel tests ($1500 per year), and other activities $5K - $8K for 

mandated energy audit) would increase the financial burden to EG. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Joseph M. Cloutier

Commenter Affiliation: RE-Gen, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-2284.1

Comment Excerpt Number: 2

Comment: RE-Gen is concerned that the EPA’s proposed rules will result in the closure of 

existing plants and possibly stop the growth of the biomass industry. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Bruce Lisle

Commenter Affiliation: Biofuel Boiler Technologies

Document Control Number: EPA-HQ-OAR-2006-0790-1981.1

Comment Excerpt Number: 3

Comment: As a start up entity, we have created “green jobs”, without government support, and 

we expect to create more, except this proposed rule, if implemented in its current form, will 

probably dictate that we significantly scale down or close down. Demand for biomass boilers, 
especially in the sizes below 10MBTU/hr, will evaporate. Because of the retroactive potential of 

this proposed rule, customers are waiting to see the outcome of this proposed rule before making 

a biomass boiler buying decision. The President has stated he would like to create 2,000,000 

“green jobs”, this proposed rule is contrary to that initiative. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Kevin Van De Wege

Commenter Affiliation: Washington House of Representatives

Document Control Number: EPA-HQ-OAR-2006-0790-2164.1

Comment Excerpt Number: 3

Comment: In addition to financial investments, the state has pursued policy opportunities to 

promote long term stability and investment in the biomass industry. The state passed a law in 

2010 allowing for long term contracts for biomass purchase from state timber lands. In addition 

to providing stability to the industry, our state DNR anticipates additional revenues from forest 

residuals to be a benefit to the common school trust fund. In recent years the state has provided 

tax incentives for hog fuel and biomass energy, authorized county governments to acquire 

biomass generation facilities, and ensured that our greenhouse gas policies reflect our priorities 

in this area. 

We have heard credible concerns from the affected industries in our state that the current rules 

promote unattainable standards that will seriously endanger the viability of these businesses and 

all the progress we have made to date. We respectfully request that you revisit the MACT 

standards as they relate to biomass boilers and incinerators, in particular by ensuring that any 

performance standards are achievable by real-world boilers, taking into account variability in 

boiler design and fuel supply, and ensuring that these new regulations do not cause inadvertent 

environmental and economic harm by closing down opportunities for generation of renewable 

power through biomass. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Arthur Blazer

Commenter Affiliation: Council of Western State Foresters
Document Control Number: EPA-HQ-OAR-2006-0790-1962.1

Comment Excerpt Number: 3

Comment: EPA should avoid promulgating rules that result in negative economic impacts to 

rural communities, rural manufacturers, landowners and the entire biomass chain. Many rural 

communities rely upon or significantly benefit from the use of biomass boilers for energy at 

manufacturing facilities, schools and hospitals. The rule, as proposed, will directly impact both 

boiler owners and fuel suppliers in these communities. By limiting the opportunity for biomass 

boilers, economic losses will be considerable, especially so in the wood products manufacturing, 

forestry, and agriculture sectors. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Arthur Blazer

Commenter Affiliation: Council of Western State Foresters

Document Control Number: EPA-HQ-OAR-2006-0790-1962.1

Comment Excerpt Number: 4

Comment: Fuel switching is not possible in many areas due to the lack of low-cost alternative 

fuels. The emission limits and testing procedures proposed for new biomass boilers under 10 

mmBtu/hr impose onerous capital and annual costs on potential project owners. These owners 

are typically schools, small businesses, hospitals, and other institutions in rural areas without 

access to natural gas as a fuel. Thus, this proposed rule will disproportionately impact the ability 

of entities in rural and potentially economically depressed areas to move from fuel oil or propane 

to a renewable and lower cost fuel. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Arie Verloop

Commenter Affiliation: Jansen Combustion and Boiler Technologies, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1856.1

Comment Excerpt Number: 4
Comment: The rules as they stand could cost the pulp and paper industry an estimated $4-5 

billion and could cost the entire U.S. manufacturing industry an estimated $21 billion, and will 

likely result in the loss of hundreds of thousands of jobs due to the very high cost to the industry. 

It does not make good sense to burden an already fragile economy with regulatory rulings that do 

not commensurately protect the environment and the health of the populace. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Christopher S. Bond

Commenter Affiliation: Missouri, United States Senate

Document Control Number: EPA-HQ-OAR-2006-0790-2200.1

Comment Excerpt Number: 4

Comment: EPA’s proposed rules also threaten the ability of struggling families and 

communities to protect and create jobs. Many parts of rural Missouri, ideal places for the growth 

and use of biomass, are struggling mightily in the current hard economic times. Rural workers 

just cannot handle more bureaucratic and expensive regulations from Washington that kill jobs 

instead of create them. Experts estimate EPA’s proposed regulations will cost the forest products 

industry $7 billion. Killing just one job unnecessarily is not only unfair to struggling workers, it 

is unconscionable. The administration can hardly claim it cares about job creation if it finalizes 

regulations as proposed by EPA in this case. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Dennis Vroman

Commenter Affiliation: United Steel Workers

Document Control Number: EPA-HQ-OAR-2006-0790-2209

Comment Excerpt Number: 4

Comment: Many mills rely on coal-fired boilers for low-cost energy. Being a low-cost producer 

is how many paper mills continue to survive against foreign competition. Yet the proposed rule 

could result in the shut-down of many coal-fired boilers, which would lower the competitiveness 

of these mills, and cause more job losses. 
I have seen many paper mills close in the last few years because of rising operating costs and the 

tragic U.S. economy, including several Wausau Paper facilities. Over the last few years, Wausau 

Paper has had no choice but to close six facilities located in Appleton and Columbus, Wisconsin, 

Jay, Maine, Jacksonville, Mississippi, Groveton, New Hampshire and Middletown, Ohio. 

Wausau Paper now employs roughly 1300 fewer employees than they did 10 years ago. 

The paper industry has experienced some very tough years and the last thing it needs is some 

over zealous regulation to instigate further decline. I do not want my mill to be one of the next 

mills to close. Other good paying jobs are hard to find in our rural area so the harmful impact 

would last a long time, if not forever. Our town will suffer as well if the 

support from the mill ends, not just the taxes, but all of the involvement in the community. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Dennis Vroman

Commenter Affiliation: United Steel Workers

Document Control Number: EPA-HQ-OAR-2006-0790-2209

Comment Excerpt Number: 5

Comment: I do support clean air and water but the proposed Boiler MACT rule is not 

reasonable. My family lives near the mill and I want them safe. Over the years, I have seen the 

mill get better environmentally. The equipment and practices we have are helping make us a 

greener facility in our community. Also, I am proud to work at a mill that produces a green 

product that is made from renewable local forests. You go into stores these days and it is hard to 

find things made in America anymore. We need more American products supporting good 

manufacturing jobs!! 

It is critical that EPA revise this rule in a common sense way. Addressing the risk to our jobs and 

our way of life must be part of any change. We need clean air, but we also need good paying 

manufacturing jobs. Bring some balance to this rule. I respectively request that EPA review and 

implement the recommendations proposed by American Forest & Paper Association (AF&PA) 

and National Council of Air & Stream Improvement (NCASI) in their comments regarding this 

rule. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.
Commenter Name: Craig S. Smith

Commenter Affiliation: Biewer Wisconsin Sawmill

Document Control Number: EPA-HQ-OAR-2006-0790-2232

Comment Excerpt Number: 6

Comment: In consideration of the financial burden placed on small to medium sized companies 

and municipalities to achieve unrealistic and unachievable results, coupled with discouraging the 

use of locally available biomass as a fuel resource, I ask that the U.S. EPA consider making 

changes to the proposed area source boiler rule. Modifications should reflect the limitations and 

requirements that are indicative of the burdens placed on the appropriate parties involved. Failure 

to do so will force many small to medium size companies to go out of business and force 

municipalities and institutions to switch from economically available biomass to propane or 

natural gas boilers for financial reasons. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Troy Runge

Commenter Affiliation: Wisconsin Bioenergy Initiative

Document Control Number: EPA-HQ-OAR-2006-0790-2245

Comment Excerpt Number: 6

Comment: One of the goals of the state of Wisconsin and the U.S. is to help build a local energy 

economy by using both woody and agricultural fuels (e.g. densified prairie grasses, corn stover, 

etc.). In order to jump-start these businesses, the state of Wisconsin is sponsoring a new biomass 

boiler planned for the Charter Street Heating Plant. This boiler is just one of several projects 

planned for the state to generate heat and power from biomass. These projects are critical to the 

goal of achieving 25% of Wisconsin’s energy from renewable resources by the year 2025. 

However, the proposed MACT standards for new biomass boilers are extremely stringent and 

will severely limit — if not eliminate — the ability to burn many of the biomass fuels envisioned 

to be developed with these projects. To understand why the Boiler MACT could create this 

unintended consequence a few examples of issues created are described. 

Example 1) Hydrochloric acid (HCI) emissions under the Boiler MACT would require emissions 

to be below 0.004 lbs/MMBtu. Whereas this is achievable for wood chips or wood pellets, 

agricultural fuels are expected to have issues as these materials have naturally higher chlorine 

levels with levels that can be as high as 0.50 lbs/MMBtu for incoming material. To insure 

emissions are low enough for compliance the boiler will be required to remove 98.4% of the HCI 

produced which will be challenging without capital intensive scrubbing equipment. This will 

undoubtedly lead to the use of more woody fuels which have lower HCI or the replacement of 

biomass for fossil fuels. Woody resources are currently available in Wisconsin but purposely 
grown bioenergy crops and agricultural residues will be required to meet long term energy 

independence goals. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Don Kaiser

Commenter Affiliation: Pellet Fuels Institute

Document Control Number: EPA-HQ-OAR-2006-0790-2231

Comment Excerpt Number: 8

Comment: In Establishing the GACT Standard for PM from New Area Source Boilers with 

Design Capacity Less Than 10 mmBtu/hr, EPA May and Should Take into Account the 

Importance of Maintaining a Viable Market for New Pellet-Fired Boilers Below That Level in 

Order to Promote the Continuing Expansion of the Pellet Fuel Market as a Valuable Source of 

Renewable Energy. 

Pellet fuel is a renewable, clean-burning and cost-stable heating alternative currently used 

throughout North America. Pellet fuel is refined and densified biomass, enabling remarkable 

consistency and burn efficiency at a fraction of the particulate emissions of raw biomass. Pellet 

manufacturers take woody biomass by-products and refine them into pencil-sized pellets that are 

uniform in size, shape, moisture, density and energy content. 

Pellet fuel is an important source of energy from the standpoint of the Nation’s economy and its 

policies on energy, forest management and the environment. First, the moisture content of pellets 

is substantially lower (4% to 8% compared to 20% to 60% for raw biomass). Less moisture 

means higher BTU value and easier handling, especially in freezing situations, than with green 

raw biomass materials. Second, the density of pellet fuel is substantially higher than raw biomass 

(40 lbs. per cubic foot verses 10-25 lbs. per cubic foot in raw material form). More fuel can be 

transported in a given truck space, and more energy can be stored at the respective site. Finally, 

pellets are more easily and predictably handled. Their uniform shape and size allows for a 

smaller and simpler feed system that reduces costs as well. 

In setting a GACT standard, EPA may take costs and other factors into account. Here, a GACT 

standard of 0.03 lb/mmBtu for new area source biomass boilers below 10 mmBtu/hr would 

destroy much, if not all of the market for new pellet-fired boilers, because of the high and 

generally prohibitive cost of ESP or FF control, especially for units below 3 mmBtu/hr. That 

impact would severely compromise the current market for pellet fuel and the potential for 

expanding the usage of pellet fuel. EPA should work to avoid that consequence. Pellet fuel is 

valuable from an economic standpoint, but it also furthers the policies of governments in the 

areas of energy, forest management and the environment. 
Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Patrick J. Medvecz

Commenter Affiliation: Wausau Paper Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2283

Comment Excerpt Number: 8

Comment: Not only is the approach that EPA used to develop emission limits badly flawed, the 

proposed Boiler MACT rule will impose a huge cost burden on our Rhinelander and Mosinee, 

WI; Brainerd, MN and Middletown, OH facilities that is simply untenable. Based on best 

available estimates, we expect that Boiler MACT compliance will cost tens-of-millions and 

annual expenditure in operation and maintenance costs will rise several million for each Wausau 

Paper facility. 

Response: This comment pertains to the major source boiler rulemaking. Provided the 

commenter has submitted this comment to the major source boiler rulemaking docket, the 

response to this comment will be provided there.

Commenter Name: Winslow Sargeant

Commenter Affiliation: U.S. Small Business Administration

Document Control Number: EPA-HQ-OAR-2006-0790-1950.1

Comment Excerpt Number: 8

Comment: As discussed above, the Agency has failed to utilize the discretion under the Clean 

Air Act to minimize small business burdens while maintaining environmental protection. The 

current proposal, if implemented without change, is likely to have significant adverse impacts on 

American jobs and the US economy. Given the importance of this rule to small businesses, we 

hope to collaborate closely with EPA in formulating the final regulation. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.
Commenter Name: Charlie Cary

Commenter Affiliation: Biomass Combustion Systems, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1990.1

Comment Excerpt Number: 9

Comment: The economic impact analyses are seriously flawed. The proposed requirement of 

160 PPM of CO for existing wood boilers over 10,000,000 BTU/hr will significantly reduce the 

number of wood fired boilers in this Country and put thousands of people out of work. These 

existing boilers were permitted under significantly less stringent standards and simply will not be 

able to meet the new, lower standard. Based on my 25 years of experience, I believe that at least 

half of the existing boiler between10 and 30,000,000 BTU/hr. will not be able to meet this 

standard, and will need to be shut down or significantly rebuilt. The forest products industry, 

where many of these boilers are located, has been hit hard by the recent economic turndown and 

many, many mills will simply not be able to afford to make the shift. In addition, these 

regulations will drive some plants to burn fossil fuel and others to lay off workers. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Thompas P. Balf

Commenter Affiliation: Campus Cortium for Environmental Excellence

Document Control Number: EPA-HQ-OAR-2006-0790-1657.1

Comment Excerpt Number: 9

Comment: It is the belief of many of our members that older boilers greater than 10MMBtu/Hr 

will require additional pollution controls -- at great expense -- to meet the CO emissions limit in 

this proposed rule. Similarly, the installation and long-term maintenance of CEMS will be very 

costly, with questionable benefit under certain circumstances. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Charlie Cary

Commenter Affiliation: Biomass Combustion Systems, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1990.1

Comment Excerpt Number: 10
Comment: In my sector of the wood energy market, the private sector has spoken on the cost 

effectiveness of baghouses and ESPs required to meet the proposed particulate standard in my 

home state of Massachusetts. There has not been a wood fired boiler sited in the State without 

significant public sector subsidies since the State implemented particulate regulations requiring 

this expensive fuel gas filtration equipment. Until the cost of fossil fuel increases, the free market 

can not cost justify this equipment. So the result of these proposed MACT standards would be to 

take an industry which has developed independently of public sector support and put it on public 

sector life support for the foreseeable future. Is it good public policy to push an industry onto the 

public dole based on conclusion drawn from a limited and potentially flawed data set? 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Steven W. Koehn

Commenter Affiliation: National Association of State Foresters

Document Control Number: EPA-HQ-OAR-2006-0790-2220.1

Comment Excerpt Number: 10

Comment: Financial Impacts on New Projects 

To demonstrate the impact of the proposed regulations to project viability, fuel cost savings and 

project value are presented for a current USFS technical assistance project at a rural high school. 

Table 3 presents the financial analysis for the installation of a 3.5 mmBtu/hr central biomass 

boiler at the school. [See submittal for Table 3.] Project financial analyses are run with and 

without impacts from the proposed rule. 

The addition of an electrostatic precipitator and implementation of the required testing regime 

reduces the lifetime project value of the investment by more than 40%. While this is an example 

of the impact to a system less than 10 mmBtu/hr, larger systems will face similar, although less 

drastic financial impacts. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Gailyn Messersmith
Commenter Affiliation: Messersmith Manufacturing, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1949.1

Comment Excerpt Number: 11

Comment: Conduct much more rigorous studies to establish or verify the following: 

* A true and accurate cost to utilize said technology including the impact on local economies. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Michael Hutcheson

Commenter Affiliation: Ameren Corp.

Document Control Number: EPA-HQ-OAR-2006-0790-2012.1

Comment Excerpt Number: 12

Comment: The use of the Morgenstern et al. (2002) methodology and assumptions to estimate 

the effect of the proposed rule on employment is improper. The Morgenstern methodology is 

based on general data in four large industrial sectors during a 12 year period (1979 to 1991) 

which includes 1990 the date of the Clean Air Act Amendments. Morgenstern’s methodology 

does not identify the direct effects of environmental regulation on employment, it measures the 

effect of reported environmental expenditures on employment at a time when environmental 

regulation was in it’s infancy. The period studied cannot be considered analogous to this 

proposed regulation for the following reasons: 

1. During the early years of environmental regulation and the associated environmental 

expenditures studied, control costs were on the order of $500 per ton of pollutant abated. Today 

proposed rule has costs of $27,000 per ton of PM abated for existing biomass fuel fired sources, 

$40,000 per ton of PM for liquid fuel fired sources and $95,000 per ton of pm for coal units. 

2. Environmental regulations in the early days and those costs were directly related to production 

processes and increases in costs affected all producers in an industry similarly. These proposed 

regulations affect utility (steam) costs and are not directly attributable to any production process. 

Costs for compliance will vary greatly across individual industries with little chance for pollution 

abatement activities or byproduct developments to lessen the costs. 

3. The proposed regulations will eliminate several currently utilized byproduct reutilization 

programs such as coal fly ash reutilization in concrete because the activated carbon required to 

control Hg and/or dioxin/furans renders fly ash unsuitable for use in concrete mixes. 

4. The costs for compliance will require much larger capital investments than the process 

specific regulations which were studied by Morgenstern et al. (2002). The capital investments 

required under this proposed rule will require financing which may not have been required for 

the much smaller capital investment required during the period studied by Morgenstern. 
5. Morgenstern studied general cost and employment data in four specific large industries 

affected by environmental regulation. This regulation affects both large and small industries as 

well as commercial and institutional entities. These later two affected entities are not subject to 

the “demand effect” described by Morgenstern because they are not involved in production. 

Similarly, their operations cannot be subject to a “factor-shift effect” because there are not 

involved in production and therefore, post regulation production technologies will not have the 

same impact on employment as in industry. Unlike a production facility complying with 

environmental regulation of production processes, commercial and institutional entities with 

boilers affected by the Boiler MACT will not be able to substitute labor for other production 

inputs as production choices become more flexible over time as US EPA (and Morgenstern) 

indicates results in positive job gains. These entities cannot substitute labor for other production 

inputs because the Boiler MACT affects utility costs and steam production not production costs. 

6. In the years studied by Morgenstern, the United States was a leading industrial nation and 

under little economic pressure to compete internationally for industrial jobs. However, the 

advances in the international shipping industry which occurred beginning in the late 1980s and 

continuing through the present have resulted in 

international competition for industrial jobs. The US must compete with lower labor costs, lower 

tax rates and lower environmental costs in other countries competing for industrial jobs. The 

proposed regulation on industrial, commercial and institutional boilers, puts additional cost 

pressures on US industries not incurred in other industrializing nations who are competing for 

the industrial jobs which are jeopardized by the proposed rule. 

7. Morgenstern’s methodology assumed large plants bear most of the regulatory costs and this 

assumption may have been proper for large industries like the pulp and paper, plastics, petroleum 

and iron and steel industries studied by Morgenstern. This assumption is not transferrable to the 

Boiler MACT which requires compliance for all affected units and therefore affects large and 

small industries as well as large and small commercial and institutional entities. 

For the above reasons, the Morgenstern et al. analysis is not analogous to the Boiler MACT. All 

of the above indicates that the economic impact analysis and the regulatory impact analysis 

conducted for this proposed rule underestimates costs, overestimates benefits and underestimates 

job losses and as result should be revised with a more reasoned analysis. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Charlie Cary

Commenter Affiliation: Biomass Combustion Systems, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1990.1

Comment Excerpt Number: 12

Comment: The cost of these regulations will have a disastrous effect on rural economies. Many 

communities in rural regions rely on, or significantly benefit from, the use of biomass boilers for 
consumption of biomass energy crops. By limiting the opportunity for biomass boilers, economic 

losses will be considerable, especially so in the wood products manufacturing, forestry, and 

agriculture sectors. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Steven W. Koehn

Commenter Affiliation: National Association of State Foresters

Document Control Number: EPA-HQ-OAR-2006-0790-2220.1

Comment Excerpt Number: 13

Comment: The proposed rule will mean that many existing biomass boilers will have to be 

taken out of service in three years. Impacts on existing businesses, particularly in the wood 

products sector may be substantial given the current economic downturn impacts on this industry 

sector. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Dan H. Williams

Commenter Affiliation: Sealed Air Corp

Document Control Number: EPA-HQ-OAR-2006-0790-2228.1

Comment Excerpt Number: 13

Comment: Source testing efforts for establishment of the MACT floor were performed on 

sources operating at or near maximum firing rates. As boilers and combustion sources are 

operated closer to the design capacity, the efficiency of combustion is expected to be as high as 

possible. This causes the establishment of a MACT floor to represent the best pollutant 

concentrations from the most efficiently operating units. Boiler operations and efficiency are 

greatly impacted by steam or energy demands at the plant. If a facility has any hopes of operating 

in compliance with the emission limitations, the facility would be required to either burn 

excessive fuel or waste heat when demands on the system are not maximized. Aside from the 

excess fuel usage, it directly causes an increase in greenhouse gas emissions, equipment wear, 

maintenance costs, and the untimely replacement or repair of equipment. 
Response: Thank you for your comment. See the final rule for how this comment was 

addressed.

Commenter Name: Wayne York

Commenter Affiliation: Hancock Lumber Company, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2002

Comment Excerpt Number: 1

Comment: Hancock is deeply concerned about the potential financial impacts of this rule for our 

company, as well as the overall impacts to other companies and institutions, many of which have 

limited financial resources. According to EPA’s own estimates, this rule will apply to nearly a 

quarter of a million facilities Based on the Preamble to the Proposed NESHAP for Industrial, 

Commercial, and Institutional Boilers Located at Area Sources, Federal Register Notice Dated 

6/4/2010, Table 3 “Summary of Annual Costs for New and Existing Sources .”. The total costs to 

these facilities will be staggering. In addition, in these times of limited government budgets, this 

large number of subject facilities will likely overwhelm EPA and the States’ ability to effectively 

implement this proposed rule. 

In addition, we are also concerned about the effect of this rule on other entities. For example, 

school districts throughout our state have been facing tremendous budget deficits, and have been 

laying-off teachers and other staff. The costs of these rules will not be able to be absorbed and 

will result in additional cuts in education. 

Therefore, it is imperative that EPA develop a more cost-effective approach for this source 

category. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Wayne York

Commenter Affiliation: Hancock Lumber Company, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2002

Comment Excerpt Number: 3

Comment: We question EPA’s assertion that the proposal would not have disproportionate 

budgetary impacts on any particular region, as listed in the Preamble Section VIII(D)(3). For 

example, in Maine we have far colder weather than in many regions, we are a rural state, we 

have limited availability of natural gas, we already have competitive disadvantages compared to 

nearby states, and in addition, due to our proximity to the Canadian border, manufacturing jobs 

are often outsourced to Canada, especially in the forest products industry. For these reasons, we 

feel that the Northeast, and Maine in particular, will face disproportionate costs due to this rule. 
Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Emission Impacts

Commenter Name: George Whiting

Commenter Affiliation: EcoHeat Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-0832

Comment Excerpt Number: 4

Comment: Compare the positive impact of wood pellet central heating to the negative impact of 

any solid waste incinerator. Your looking at burdening the good, whereas there’s much more that 

can be done with making the bad less bad. Think of what can be done to make incinerators less 

bad. Perhaps consumer education would be a better use of your resources. 

The main point I’d like to make is that wood pellet boilers such as the EcoBoiler are already 

much better for the environment than oil and propane boilers, and that if you create a 

disincentive for these boilers by increasing the costs for the companies that make them, you are 

ironically making a negative impact on the environment rather than a positive one as one would 

expect the EPA to do. 

Response: See the response to comment EPA-HQ-OAR-2006-0790-1493.1, excerpt 10.

Commenter Name: Raymond J. Nutting

Commenter Affiliation: County of El Dorado Air Quality Management District

Document Control Number: EPA-HQ-OAR-2006-0790-2225.1

Comment Excerpt Number: 2

Comment: The implementation of the proposed MACT will result in a shutdown of many 

existing biomass plants throughout California and prevent construction of new facilities. Such 

scenario will almost certainly cause significant increases in local and regional levels of 

particulate matter, toxic pollutants and greenhouse gases since unmanaged biomass wastes will 

be consumed by wildfires, through prescribed burning or be land filled. In addition, it will be 

necessary to burn more fossil fuel to accommodate for lost biomass energy. 

Response: See the response to comment EPA-HQ-OAR-2006-0790-1493.1, excerpt 10.
Commenter Name: Winslow Sargeant

Commenter Affiliation: U.S. Small Business Administration

Document Control Number: EPA-HQ-OAR-2006-0790-1950.1

Comment Excerpt Number: 4

Comment: The very stringent new source boiler standards, in our view, are more likely to 

contribute to worse air pollution by deterring companies from purchasing and installing new 

energy efficient and less polluting boilers in the future. 

EPA based emissions limits on a relatively small number of boilers in some subcategories, which 

in combination with significant non-detect data drove the MACT floor to unreasonably low 

levels in some cases. EPA needs to refine the statistical approach that it takes to setting 

emissions limits by taking emissions variability into account for sources, such as boilers. 

Because of this approach, Advocacy has heard repeatedly that the carbon monoxide (CO) limit 

will be exceedingly costly for many units to meet under any circumstances. 

The stringent new source provision of the proposal likewise will , deter many sources from 

upgrading to new boilers because the new source performance standards are also based on the 

emissions of the synthetic source which would be so impractical as to inhibit any potential gains 

from installing newer, more fuel-efficient, lower emitting technology. 

Response: See the response to comment EPA-HQ-OAR-2006-0790-1653.1, excerpt 12.

Commenter Name: Alicia Oman

Commenter Affiliation: National Association of Manufacturers

Document Control Number: EPA-HQ-OAR-2006-0790-2234.1

Comment Excerpt Number: 53

Comment: The controls necessary to meet EPA’s stringent proposed emissions limitations for 

CO will result in increased energy usage along with increased emissions of other pollutants. 

EPA’s proposed CO emissions limit arbitrarily and capriciously fails to recognize the 

dependency between CO and other emissions, which makes this rule impossible to implement in 

either process heaters or boilers. Requiring such extraordinarily low CO levels will have an 

adverse impact on other emissions such as NOx, PM, greenhouse gases (GHG) and even HAPs. 

Reducing CO to extremely low levels will require increased excess air levels which reduce 

efficiency, increasing the amount of fuel that must be fired and therefore increasing the total 

mass of other pollutants (i.e. HAPs, GHGs, NOx, SOx, PM, etc.). For example, CO and NOx 

emissions are both dependent on the residence times and temperatures of the flue gas in the 

firebox, but in different ways. For most boilers and process heaters achieving low NOx 

emissions, there is insufficient time at temperature to oxidize CO to 1 ppm. As CO decreases, 
NOx increases and vice versa, so emissions control in any fired equipment is a trade-off between 

the two. 

Response: See the response to EPA-HQ-OAR-2006-0790-2025.1, excerpt 60.

Commenter Name: William H. Carlson

Commenter Affiliation: Carlson Small Power Consultants

Document Control Number: EPA-HQ-OAR-2006-0790-1493.1

Comment Excerpt Number: 1

Comment: My contention in these remarks is that this action by EPA, with respect to biomass 

alone, will actually worsen air quality in America, the exact opposite of its intent. I do not 

contend that this was EPA’s intention in drafting these biomass rules, but that will be the 

practical result due to poor understanding of the units chosen to represent the industry, poor 

understanding of the dynamics of biomass combustion, and a complete lack of understanding of 

the makeup and economics of biomass combustion. This deterioration of air quality will come 

about as a result of a dismantling of existing biomass combustion in both the forest products and 

biomass power industries and the elimination of future biomass combustion units, all as a result 

of this rule and, to a lesser degree, to the inclusion of biomass in EPA’s Tailoring Rule. 

Response: See the response to comment EPA-HQ-OAR-2006-0790-1493.1, excerpt 10.

Commenter Name: Russ Mull

Commenter Affiliation: Shasta County Air Quality Management Distric

Document Control Number: EPA-HQ-OAR-2006-0790-1167

Comment Excerpt Number: 4

Comment: While the NESHAP supporting documents calculate the benefits of reduced PM2.5 

emissions from the controlled facilities, the analysis should include the increase in PM2.5 

resulting from the complete shutdown of the biomass facilities in California, minus increase in 

PM2.5 from currently managed State and private lands that will be consumed in wildfires. 

Approximately 1,000,000 acres of unmanaged Federal land is consumed by wildfires in 

California each year. It can be assumed, that this acreage will increase by the proportion of 

Federal land to State and private land, as these wildfires will not be contained at the Federal land 

boundaries. Since State and private lands will lose the management option of utilizing biomass 

for energy and building material purposes, fuel buildup and wildfires will be inevitable. Most 

sawmills currently operating in California’s forests are co-located with a biomass cogeneration 

facility. The requirements of this Rule will result not only in the shutdown of the area source 

industrial boilers used for cogeneration, but these power producing facilities are a major source 

of revenue for the adjoining lumber mill and most wood products industry within the State will 

be eliminated. While this economic disaster is of no concern to Federal regulatory officials, since 

45 percent of the land in California is owned by the Federal government, an approximate 100 
percent increase in PM2.5 emission from wildfires will be the ultimate result of this Rule. 

According to AP-42 factors, an additional 1,000,000 acres of wildfire will produce an additional 

650,000 tons of PM2.5 annually in California. This additional emission of PM2.5 should be 

added to the benefit calculation. 

Response: See the response to comment EPA-HQ-OAR-2006-0790-1493.1, excerpt 10.

Commenter Name: William H. Carlson

Commenter Affiliation: Carlson Small Power Consultants

Document Control Number: EPA-HQ-OAR-2006-0790-1493.1

Comment Excerpt Number: 10

Comment: So, what will be the environmental outcome of this scenario; precipitated solely by 

the EPA biomass boiler MACT regulations (with an assist from the Tailoring Rule). The net 

effect will be a worsening of air quality across the U.S., both for criteria pollutants, and for 

carbon, and yes, for HAP’s. In the interest of capturing a few pounds of mercury or dioxin, we 

will have increased emissions from open burning some 30 fold versus current combustion. Much 

more wood waste will go to landfills where methane and CO will seep out despite efforts to 

extract it Forest managers will lose options for disposal of noncommercial materials leading to 

less forest management activity, more and larger fires and decreased forest health, all having dire 

air quality and carbon consequences. A program designed to improve air quality results in poorer 

air quality all due to a lack of understanding of the situation of the industry you were seeking to 

regulate. 

Response: All existing biomass boilers and new biomass boilers with heat input capacity less 

than 10 mmBtu/hr no longer have applicable emission limits, and for new biomass boilers only 

units greater than 10 mmBtu/hr have PM limits and these are based on GACT and not MACT. 

With these changes to the final rule commenter concerns about biomass boilers shutting down 

and leading to increased emissions from wildfires, landfilling, or open burning should be 

alleviated.

Commenter Name: Chris Mello

Commenter Affiliation: Alaska Energy Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1653.1

Comment Excerpt Number: 8

Comment: There are no known units, large or small, that can meet both limits (CO and 

particulates) at the same time.Much of the wood used in biomass boilers is harvested for wildfire 

prevention, right-of-way clearing, and forest health. In communities without a biomass system, 

wood harvested in preventative measures is typically burned in open slash piles. The EPA 

Report: Development of Emissions Inventory Methods for Wildland Fire illustrates that the 

particulate emissions related to slash pile burning approximates 19 pounds per ton of wood, 
where an average biomass boiler (2002) produces approximatly 1.9 pounds per ton of wood. Fire 

mitigation reduces the severity of wildfires that result in emissions of 30 pound per ton of wood 

burned. With Alaska averaging up to a million acres of wildfire annually, fire mitigation wood 

harvest is a large source of particulate emission, and it would be advantageous to dispose of this 

wood in a clean burning boiler that also displaces diesel heating fuel. 

Response: See the response to comment EPA-HQ-OAR-2006-0790-1493.1, excerpt 10.

Commenter Name: Arthur N. Marin

Commenter Affiliation: Northeast States for Coordinated Air Use Management, NESCAUM

Document Control Number: EPA-HQ-OAR-2006-0790-2137.1

Comment Excerpt Number: 12

Comment: Many NESCAUM states have adopted, or are in the process of adopting, standards 

for ultra-low sulfur heating oil; it is imperative that EPA’s proposed regulations do not impair 

state efforts to reduce sulfur emissions from these sources. NESCAUM recommends that EPA 

analyze the multi-pollutant benefits gained by encouraging the use of 15 ppm ultra-low sulfur 

heating oil and incorporate these requirements, when appropriate, in the final rule. 

Response: The EPA has determined it is not necessary to create a separate subcategory for ultralow sulfur diesel. However, with the revised standards for existing and new boilers there should 

not be a disincentive to use ultra-low sulfur diesel and the rule should not impact state efforts to 

reduce sulfur emissions.

Commenter Name: Chris Mello

Commenter Affiliation: Alaska Energy Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1653.1

Comment Excerpt Number: 12

Comment: Due to the high cost of heating fuel in rural Alaska, there is an economic incentive to 

replace older oil fired boilers with new, high efficiency units. The new boilers not only provide 

improved fuel economy, they also produce far less exhaust emissions compared to existing 

antiquated boilers. However, as written, all new boilers (oil fired, biomass, etc.) installed after 

June 4, 2010 in a commercial, industrial or institutional facility will be subject to annual source 

testing requirements. An unintended consequence of this proposed rule will be that old, 

antiquated heating equipment will remain in service —resulting in poorer air quality and 

financial hardship to operators of regulated boilers in rural Alaska. 

Response: New boilers must still meet emission limits but they have changed from proposal. 

New large (>10 mmBtu/hr) coal boilers must meet MACT limits for CO and Hg while new large 

(>10 mmBtu/hr) coal, biomass, and liquid boilers must meet GACT limits for PM. All new small 
boilers (<10 mmBtu/hr) do not have emission limits. With the revised limits the associated 

burden will be reduced making it more manageable for facilities to install new area source 

boilers.

Commenter Name: Gary Rubenstein

Commenter Affiliation: Kauai Island Utility Cooperative, KIUC

Document Control Number: EPA-HQ-OAR-2006-0790-2028.1

Comment Excerpt Number: 15

Comment: Finally, the assessment of the impacts of the proposed rule should also take into 

account the possibility that the boiler would be replaced rather than retrofitted, and the potential 

increases in PM10/PM2.5 emissions that would result. The KIUC boiler emits about 1.74 lb/hr of 

PM2.5, based on AP-42 emission factors.23 A small oil-fired gas turbine in the same size range 

(~10 MW) will have a manufacturer’s guaranteed PM2.5 emission rate of about 4 lb/hr24 , while 

a reciprocating compression-ignition engine will have a PM2.5 emission rate of about 8.8 

lb/hr.25 Therefore, replacing the existing boiler with either a gas turbine or a CI engine would 

increase fine particulate emissions by between 10 and 26 tons per year. 

Response: Except for coal, existing boilers do not have applicable emission limits. Those 

commenters who were concerned about the cost of complying with the rule and were considering 

installing a new boiler do not need to worry about this.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 60

Comment: The preamble presents an extensive discussion of the assumed benefits of this 

proposal. However, it fails to consider the dis-benefits. A significant item is the increase in NOx 

emissions that will result from this proposal. Reducing CO to the levels proposed for liquid-fired 

boilers will significantly increase NOx emissions nationally. To avoid these increases, boilers 

which are subject to NOx limits will have to install low-NOx burners, just to maintain the NOx 

levels they were meeting before this CO limit is imposed. Many boilers will likely not be able to 

maintain their NOx levels even with burner changes and will have to be replaced or fitted with 

Selective Catalytic Reduction NOx controls. It is even unclear that any new liquid-fired boiler 

can simultaneously meet both the CO limits proposed here and applicable NOx limits without 

add-on NOx controls. Add-on NOx controls for replacement and existing boilers will add 

massive costs and create NH3 and PM emissions. 

In order to minimize CO, liquid-fired boilers will have to operate with significantly more excess 

air than is typical today. This causes the boiler to have to fire more fuel and increases CO2

emissions, HAP emissions, VOC emissions, NOx emissions and, in some cases emissions of 
sulfur species. Alternately, add-on oxidation catalyst systems will be needed to control the CO, 

but these systems lead to increased PM2.5 emissions and have the potential to generate 

additional dioxin/furans. These impacts were not addressed in the EPA analysis, but are very 

significant. 

Finally, EPA estimates 228 million kilowatt hours of additional energy use due to this proposal. 

This estimate is likely grossly understated since EPA assumed add-on controls for only a small 

percentage of liquid-fired boilers, rather than for essentially all such boilers and because they did 

not account for the need to convert the boilers to balanced draft or to account for the 

inefficiencies of raising stack gas temperatures to reach oxidation catalyst operating 

temperatures. The additional emissions from electric generators resulting from this increase in 

demand and the additional energy use needed to offset raising stack temperatures do not appear 

to have been taken into account in EPA’s analysis. 

Response: The CO limits for liquid boilers have been removed, so commenter concerns about 

potential emissions increases or impacts on meeting other pollutant limits (e.g. NOx limits) due 

to the proposed CO limits should be alleviated.

Commenter Name: Arnold Schwarzenegger

Commenter Affiliation: Governor of the State of California

Document Control Number: EPA-HQ-OAR-2006-0790-1777.1

Comment Excerpt Number: 8

Comment: The power plants also have existing power purchase agreements and would not be 

able to pass the cost of the retrofit on to utility ratepayers. The Energy Commission’s analysis 

indicates that the existing biomass power plants would not be able to fund the retrofit needed to 

meet the MACT Rule and would discontinue operation. 

The California Air Resources Board indicates that the proposed rule will not necessarily improve 

the air quality, and we agree that it will have unintended consequences. Specifically, the 

Bioenergy Interagency Working Group believes the proposed rule will have negative 

environmental impacts by increasing the amount of opening burning of agricultural and forest 

waste, there will be higher risks of wildfires, and more greenhouse gas from landfills. 

Response: See the response to comment EPA-HQ-OAR-2006-0790-1493.1, excerpt 10.

Commenter Name: Thompas P. Balf

Commenter Affiliation: Campus Cortium for Environmental Excellence

Document Control Number: EPA-HQ-OAR-2006-0790-1657.1

Comment Excerpt Number: 6
Comment: As you reduce your emissions of CO, under certain circumstances NOx emissions 

will increase. 

We suggest that the Agency further explore and discuss the relationships between CO and NOX 

and align its priorities so that the regulated community does not find itself in an untenable 

compliance challenge involving “technical dissonance.” This issue is more pressing given the 

fact that many states have non-attainment zones for ozone NAAQS, and NOx is an ozone 

precursor. 

Response: See the response to EPA-HQ-OAR-2006-0790-2025.1, excerpt 60.

Secondary Impacts

Commenter Name: Andrew Plant

Commenter Affiliation: University of Maine

Document Control Number: EPA-HQ-OAR-2006-0790-0869

Comment Excerpt Number: 1

Comment: The rule changes put forth by the EPA are unfair in relative terms to biomass 

generated heat and electricity production. As is, the rules would make it near impossible for the 

combustion of biomass resources for utilization as heat, power, or a combination of the two 

(CHP) in commercial, industrial, or institutional settings using currently available technology. 

The financial burdens associated with the rule changes could possibly have the effect of biomass 

energy dependent industries shutting down altogether, and loss of an inexpensive fuel. In 

simplest remediation of the new rules, independent MACT and GACT standards for boilers 

based upon fuel-type are recommended. 

The rule changes based upon emissions and air quality signal a tremendous short-coming or even 

failure in US Energy Policy. A policy incorporating all aspects of energy usage needs to be set 

forth. It is the responsibility of EPA to assess Greenhouse Gas and Climate Change impacts in 

addition to Air Quality. Fuel use policy needs to incorporate the entire picture, and not a 

piecemeal picture in which individual policies regarding issues of air quality, greenhouse gases, 

or other regulatory parameters are promulgated separately. By then, as a result of the first issued 

policy change (Air Quality), the research and development of some renewable energy 

alternatives such as biomass may cease. 

This single ruling could decide the fate of several renewable fuels without the consideration of 

many other variables that need to be weighed. Life cycle analyses of fossil fuels and their 

renewable fuel replacements needs to done. Air quality is only one component of a fuel 

assessment matrix that should be used. Weighted rankings could be developed in which to assess 

different fuels in regards to air emissions, greenhouse gas potential, land-use change impact, and 

economic impact; all of which should be done on a life cycle basis, and all of which need factor 

in the variability of end-use systems (Electric standalone versus combined heat and power; 

Gasification vs Direct Combustion). Fuel policy should not be entirely determined by EPA, but 
in combination and interdepartmental cooperation between the EPA, Dept of Energy, and the 

USDA. 

Attached are academic manuscripts providing a resource for examples of Life Cycle Analyses 

and Policy tools. 

[See: DCN:EPA-HQ-OAR-2002-0790-0869.1, DCN:EPA-HQ-OAR-2002-0790-

0869.2,DCN:EPA-HQ-OAR-2002-0790-0869.3, and DCN:EPA-HQ-OAR-2002-0790-0869.4 

for manuscripts.] 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Thomas Deerfield

Commenter Affiliation: Dalson Energy

Document Control Number: EPA-HQ-OAR-2006-0790-0831

Comment Excerpt Number: 1

Comment: As the Biomass Thermal Energy Council (BETC) has so thoroughly and lucidly 

explained, the proposed rule for boilers would effectively shut down the existing biomass 

thermal industry. In addition, the proposed rule would force America into continued reliance on 

non-renewable fossil fuels. 

I work on renewable energy projects in rural communities in Alaska, mostly Native villages. 

Most are remote, requiring enormous transportation costs for conventional fuels. Many are 

surrounded by overgrown, wildfire-prone forests. The proposed rules will make it more difficult 

to deploy small wood boilers for schools and clinics. 

Small wood boilers in rural communities create local jobs to harvest and process the wood fuel. 

They provide an alternative to money going out of the community to buy imported fossil fuel. 

They greatly reduce the danger of oil spills in area rivers (the oil is shipped in on river barges), 

potentially devastating fish runs. They reduce wildfire risk to community structures. They help 

make the communities more self-reliant, and build a stronger local economy. 

One-size-fits-all rules in this case means that rules that may be appropriate in New York or 

Denver are applied to rural Alaska, which is an entirely different world. We propose a more 

balanced approach. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Gregg Tomberlin

Commenter Affiliation: Novo Energy, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-0834.1
Comment Excerpt Number: 3

Comment: There would be a reduction in the generation of renewable energy which would most 

likely be replaced with energy generated from the combustion of fossil fuels resulting in more 

pollutants and greenhouse gases discharged into the environment. The timing for this type of 

program could not be any worse give the historic economic downturn in this country, the impetus 

for renewable energy development and the mandate for green house gas reduction. 

The Clean Air Act rightly directs that emissions requirements shall be less than “the average 

emission limitation achieved by the best performing 12 percent of the existing sources”. While 

there is latitude to impose more stringent requirements than this norm, why would that latitude 

be exercised to limit or stop the development of a renewable fuel that could be an important 

player in the reduction of the use of fossil fuels and greenhouse gas emissions? The use of clean 

fuels like biomass should be encouraged and assisted instead of penalized. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Carl Johnson

Commenter Affiliation: Southern Pressure Treaters' Association

Document Control Number: EPA-HQ-OAR-2006-0790-0870.1

Comment Excerpt Number: 6

Comment: If a plant converted to natural gas boilers, the capital investment may not be carried 

by the market rendering the company non-competitive against imports and alternative products. 

If the rules are finalized as written, some utility pole treating plants and supporting operations 

could be forced into closure resulting in hundreds of unemployed workers and a shortage of 

utility poles for grid maintenance and new line construction. Restoration of electrical, 

telecommunication, internet and cable service after natural disasters (i.e. hurricanes, ice storms, 

etc.) would take longer due to fewer plants operating. 

Response: With the revised MACT and GACT standards for the final rule, EPA does not 

anticipate boiler operators will use fuel switching to natural gas as a compliance option.

Commenter Name: Charles Niebling

Commenter Affiliation: New England Wood Pellet

Document Control Number: EPA-HQ-OAR-2006-0790-0836

Comment Excerpt Number: 11
Comment: Encouraging increased dependence on fossil fuels for thermal needs impedes federal, 

state and local renewable energy and greenhouse gas reduction goals. Forest products industries 

and other businesses alike rely on renewable, low cost wood residue for heating. Restricting 

biomass thermal applications through unreasonably expensive and compliance measures of 

questionable value will serve the counterproductive purpose of encouraging nonrenewable fossil 

fuels use and reduce local self-reliance. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Charles Niebling

Commenter Affiliation: New England Wood Pellet

Document Control Number: EPA-HQ-OAR-2006-0790-0836

Comment Excerpt Number: 15

Comment: Biomass thermal energy today is a growing industry. Roughly one million American 

businesses, citizens, and institutions use biomass to meet their space heating, cooling, or process 

heat needs. NEWP supports the EPA in setting emission standards for biomass boilers that push 

the industry to produce clean?burning, high?efficiency appliances. 

The biomass thermal industry has great potential to grow, innovate, and support local community 

energy independence and greenhouse gas reduction through the replacement of fossil fuel 

heating with high efficiency biomass boilers. As proposed, the only certainty is that the Area 

Source rule will devastate the biomass thermal industry and small businesses, and local 

government and schools will be forced to look for non-renewable fossil fuels for their heating 

needs. By revising the rule to reflect a common-sense approach, EPA can still achieve major 

improvements to air quality and support the ancillary environmental, economic, and social 

benefits that biomass thermal supports. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Los Angeles Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0397

Comment Excerpt Number: 22

Comment: While EPA states that fuel switching is not part of their control strategy, the reality is 

that operators may find it cheaper to purchase a new gas-fired boiler than to put controls on 

existing biomass units. So much for transitioning to a sustainable energy economy. 
Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Los Angeles Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0397

Comment Excerpt Number: 33

Comment: All of our plants employ the best available technology as defined here in California. 

And our engineers to date have found no retrofits or mods that would meet the entire suite of 

regulations. I would point out that efforts to reduce carbon monoxide will, in our plants, 

invariably reduce -- increase emissions of NOx, which is an undesirable reaction. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: Arlington Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0396

Comment Excerpt Number: 52

Comment: Imposing severe and unattainable emission limitations on sources that use or may 

use locally available alternative fuels such as bio-based fuels, landfill gas, and process off-gases, 

will decrease the use of alternative fuels and put greater demand on conventional fossil fuel use 

to the extent that continued operations are justified. These impacts are counter to the stated 

administration goals of improving national energy efficiency, reducing greenhouse gases, 

increasing national security, and increasing employment. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion.

Commenter Name: Harry Dresser, Jr.

Commenter Affiliation: Maine Energy Systems

Document Control Number: EPA-HQ-OAR-2006-0790-1060.1

Comment Excerpt Number: 1
Comment: If one reviews the successes that have been achieved in reduction of megatons of oil 

equivalents in Western Europe, it becomes immediately clear that the biomass energy source is 

the shortest route to reduction in fossil fuel consumption and dependency. Of all oil energy 

replacement, nearly 60% of the offset enjoyed in Western Europe over the last decade is 

attributable to fossil fuel replacement with biomass energy. Each of the other renewable energy 

sources individually represents less than 10% of the oil energy offsets. 

Eighty percent of the heating oil burned in the U.S. is burned in the largely rural northeastern

U.S. Awareness of this substantial dependency and the associated environmental and Þnancial 

impacts has led private entities to spend several years preparing biomass heating opportunities 

for homes, businesses, and institutions. Some of the cleanest burning small scale cordwood and 

pellet burning appliances available in the world are being made available in the Northeast to help 

allay some of this fossil fuel dependency. 

Like all U.S. markets, this small boiler market has struggled to sustain itself in the face of 

widespread recession. Despite the generally gloomy economic picture, late spring of 2010 

showed promise of growing boiler replacement activity, mostly in the small commercial and 

institutional segments. 

The release in June of proposed EPA regulations that would, if enacted, affect even very small 

boilers, deadened the market enthusiasm for boiler replacement. Potential end-users worried 

about equipment being made obsolete by retro-active rule changes and about costly add-ons and 

annual tests or mandated, on-going work practice standards. 

As European boiler manufacturers, distributors, and installing technicians consider the need to 

replace an enormous inventory of fossil fuel boilers of all sizes that will be made useless by 

depleted supply in a matter of several short decades, they worry about the reality of successful 

manufacture and replacement on such a short timeline. The 

U.S. unwittingly faces the same challenge. To compound that problem with the introduction of 

these proposed standards—standards that are not achieved frequently even among countries that 

have been more attentive to emissions than ours has—and to mandate annual testing or work 

practice standards as further burden to the technical community would seem burdensome enough 

to make a large looming problem insurmountable. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. In addition, tune-ups 

are required biennially instead of annually. See the preamble for further discussion on the 

economic impacts of the rule. Please note that greenhouse gas emissions from biomass boilers 

are not within the scope of this rulemaking.

Commenter Name: Duane C. Feagley

Commenter Affiliation: Pennsylvania Anthracite Council

Document Control Number: EPA-HQ-OAR-2006-0790-1052.1

Comment Excerpt Number: 1

Comment: The proposed Boiler MACT standards threaten to tighten current operating specs 

even further. The net effect will cause facilities using anthracite coal to convert to other sources 

of energy. 
Response: The final rule includes revised MACT and GACT standards. With the changes it will 

reduce the burden for facilities to comply but will still provide a valuable environmental benefit.

Commenter Name: Carolina Dauzat

Commenter Affiliation: Rex Lumber

Document Control Number: EPA-HQ-OAR-2006-0790-0610

Comment Excerpt Number: 2

Comment: Biomass has always been effectively used as an alternative energy source in our 

industry, these rules are not in sync with the President’s own push for greater use of alternative 

energy sources. 

Response: EPA is charged with regulating industrial, commercial, and institutional boilers and 

process heaters and many industrial boilers use biomass as a fuel. Consequently, we must 

regulate these units under this rule. We believe that the final rule should not discourage the 

beneficial use of renewable energy sources such as biomass. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Thomas McMillan

Commenter Affiliation: Baldwin Pole and Piling Co., Inc

Document Control Number: EPA-HQ-OAR-2006-0790-0608.1

Comment Excerpt Number: 2

Comment: At the current MMBTU price of natural gas we are certain our drying cost would be 

less with gas compared to the bark boiler drying cost after factoring in depreciation associated 

with the new regulations. This may not be the case if gas prices go back to high market levels of 

several years ago. This uncertainty coupled with the fact that we believe we are contributing in 

our own small way to alleviating our nations dependence on fossil fuels by burning wood waste 

has kept us from considering a switch back to gas. Now, if these proposed Boiler MACT 

regulations become law, we will have no choice but to switch. 

Thank you for allowing our company to comment. We believe we have a common goal with our 

government to achieve what is best for the country and that this issue should be able to be 

resolved without forcing us back to dependence on oil or gas. We are asking you to provide us 

with regulations that will continue to allow us to bum our own waste residues for boiler fuel. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion.
Commenter Name: Mike Hubbard

Commenter Affiliation: National Council of Textile Organizations

Document Control Number: EPA-HQ-OAR-2006-0790-1062

Comment Excerpt Number: 3

Comment: Loss of more US jobs to foreign competitors with no effective emissions controls: 

We note that the US textile segment is a clean industry. US mills use about one?fourth of the 

coal used by a Chinese mill for a single pound of production. Further, the US mills already 

produce far less emissions per pound of coal than our Chinese counterparts. We also note that the 

companies using boilers typically do so in support of other operations like dyeing and finishing, 

which require significant expense and effort to maintain air and water quality. US companies 

manage these operations, but many of our foreign competitors do not. If the goal of the US 

Government is to improve the environment, moving production from clean US companies to 

companies in China will have the opposite effect. The result will be greater mercury emissions in 

addition to other forms of air and water pollution due to poor controls in some of the largest 

textile and apparel producing countries. 

Response: EPA is charged with regulating industrial, commercial, and institutional boilers and 

process heaters and many industrial boilers use coal as a fuel. Consequently, we must regulate 

these units under this rule. Considering the impact on emissions from other countries is outside 

the scope of this rulemaking.

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 28

Comment: The League also notes that the proposed boiler rules for major and area sources are 

contrary to the efforts of the current administration with regards to "green" energy initiatives. 

The proposed rules provide for a distinctive -- provides for dis- -- provides for a disincentive for 

the use of renewable resources and the reduction of our dependence on fossil fuels. 

All Louisiana sugar mills utilize bagasse-fired boilers as the primary source of power for mill 

operations, with nearly 100 percent of the bagasse burned at any given mill being generated onsite. Although a couple of mills supplement the bagasse with clean wood products during initial 

start-up, none supplements with fuel oil or coal. 

Response: The final rule includes revised MACT and GACT standards. With the changes it will 

reduce the burden for facilities to comply but will still provide a valuable environmental benefit.

Commenter Name: Martin Lunde

Commenter Affiliation: Citizen
Document Control Number: EPA-HQ-OAR-2006-0790-2065.1

Comment Excerpt Number: 1

Comment: The proposed requirements for tighter emission standards and annual testing are very 

expensive; and will essentially eliminate wood as a viable, cost effective fuel for the small rural 

commercial/industrial and farm user. 

Response: All new and existing boilers with heat input capacity less than 10 mmBtu/hr do not 

have limits but must conduct tune-ups, the revisions will reduce the burden for facilities to 

comply with the final rule.

Commenter Name: George M. Israel

Commenter Affiliation: Georgia Chamber of Commerce

Document Control Number: EPA-HQ-OAR-2006-0790-1996.1

Comment Excerpt Number: 1

Comment: If enacted in its current form, this standard would have a detrimental impact on the 

development of electric energy from Georgia biomass. 

The proposed standard contradicts the administration’s desire for increased use of renewable 

energy sources for power generation. The proposed emissions limitations for new boilers fueled 

by biomass would impose a suite of standards that, under the best circumstances, would 

substantially increase the cost of any new biomass-fueled boiler. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Elizabeth Keokosky

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2230

Comment Excerpt Number: 1

Comment: I also believe that biomass has the possibility of being 

a very important contributer to the decrease in global warming, renewable energy, energy 

independence and the rural economy. In your proposal describing the pollutants you state "We 

do not know the extent to which the adverse health effects described above occur in 

the populations surrounding these facilities."But we do know the 

effects of carbon dioxide, nitrogen oxide, and methane emissions on the world. And we do know 

the effects of resouce wars for oil in 

the mid-east and oil pollution in the Gulf. 
Considering that there is no energy source at this time that does not have some down side, 

perhaps it is better to use a life cycle analysis rather than piecemeal demolition making it 

impossible for an infant industry to gain a foothold. 

Biomass has great potential for partial fossil fuel replacement. CO 

and PM pollution is not trivial but let us support research that allows us to find the time and 

technology to alleviate adverse effects rather than set unrealistic standards before we are capable 

of meeting them. Let us do everything we can to increase stove and boiler efficiency and 

make the rules which guide responsible use of biomass in a sustainable fashion. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Robert E. Cleaves

Commenter Affiliation: Biomass Powe Association

Document Control Number: EPA-HQ-OAR-2006-0790-1992.1

Comment Excerpt Number: 1

Comment: EPA Needs to Appreciate Renewable Energy Policy Implications of these Rules 

We have a number of specific recommendations regarding these three inter-related rulemakings, 

which appear below. Before addressing the rule, however, it is critically important for EPA to 

understand both the gravity of the problem created by what has been proposed and the impact 

these rules will cause to a larger effort underway in this country to fight climate change, 

strengthen the health of our forests and agricultural lands, and grow the green jobs economy -

each a critically important policy initiative in the Congress, at the White House, and for the 46 

states and territories who have adopted renewable portfolio standards that include support for 

biomass. 

To place biomass energy in the context of the larger push for renewable energy, consider the 

current and potential significance of biomass power. DOE estimates that biomass generates 45 

billion kilowatt-hours of electricity from biomass, or 1.2 percent of total electric energy sales. If 

on-site power is considered along with thermal, the actual contribution from biomass is four 

times that estimate. In any event, biomass provides over 50% of the Nation’s renewable energy 

supply, and DOE believes that potential biomass could supply as much as 14 percent of the 

Nation’s power needs by 2030. Without biomass, it is uniformly believed—from members of 

Congress to members of the Cabinet—that the Nation will be unable to meet increased 

renewable energy goals. 

Unlike wind or solar, biomass energy is baseload generation, available 24/7, and does not require 

expensive new transmission infrastructure. And unlike many other renewable sources, biomass is 

a “jobs creating machine” for rural America. A recent study authored by Navigant Consulting 

estimated that the build out of biomass in just five southeastern states could double the Nation’s 

biomass capacity and create 60,000 new jobs. 

Biomass is not just an untapped source of renewable energy; it’s also an enormous 

environmental challenge that poses significant ecological risks. Consider the recent call for help 
by the Western Governors Association for the federal government to adopt a “cohesive federal 

policy on the use of biomass for energy production” to combat pine bark beetle infestations that 

have decimated 21 million acres, creating ecological and safety risks to rural communities. As 

expressed by the WGA, “biomass utilization represents one of the most viable new means 

available to address this ecological crisis, while decreasing fossil fuel usage and stabilizing a 

depressed lumber and forest-product market.” See August 10, Press Release, “Increased Use of 

Biomass Energy, Improved Forest Health Requires Cohesive Federal Policy” (at www.wga.org) 

Response: EPA is charged with regulating industrial, commercial, and institutional boilers and 

process heaters and many industrial boilers use biomass as a fuel. Consequently, we must 

regulate these units under this rule. We believe that the final rule should not discourage the 

beneficial use of renewable energy sources such as biomass. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Fred Gordon

Commenter Affiliation: Herman Miller, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2046.1

Comment Excerpt Number: 1

Comment: The manufacture of office furniture requires the use of wood and wood composite 

materials. The Company is a progressive steward in the use of renewable and sustainable natural 

resources. The use of engineered wood products have enhanced the performance and extended 

the effective service life of our products using various wood manufacturing techniques while at 

the same time reducing the environmental impact on wood resources and the environment. 

Wood residuals and other cellulosic secondary materials that might otherwise be discarded and 

transported to a landfill for disposal are being manufactured into a stable board using resins and 

glues. The Company purchases such materials for beneficial reuse which become the backbone 

of any number of innovative and functional furniture products. In so doing, what otherwise 

would be a "waste" is converted into usable and often superior performing raw material products. 

As part of its facility operations, the Company utilizes wood—fired combustion unit for energy 

recovery to generate steam for heating and cooling of the facility, as well as humidification of 

the buildings. The steam boiler is equipped with pollution control equipment to minimize 

emissions from the boiler. Routine operation of the boiler includes combustion of particleboard 

cut-offs and trimmings from the facility’s manufacturing operations, along with scrap wood and 

pallets and paper and cardboard from facility operations. Recent consumption of particle board, 

wood and paper/cardboard has provided greater than 90% of the heat input to this boiler, 

providing, on average, over 7,000 MMBTUs per month from these cellulosic biomass fuels. If 

not for the ability to beneficially use these renewable biomass fuel sources, the Company would 

need to consume substantial equivalent amounts of fossil fuels. 
Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. 

Commenter Name: Douglas I. Greenhaus

Commenter Affiliation: National Automobile Dealers Association

Document Control Number: EPA-HQ-OAR-2006-0790-2047.1

Comment Excerpt Number: 1

Comment: The compliant on-site burning of used motor oils, in space heaters or otherwise, 

promotes an array of benefits including environmental (no off-site mismanagement, no off-site 

transport, etc), energy security, fuel cost reduction, and the elimination of potential of off-site 

liability risks. 

The space heater regulation keys on three criteria: 

1. Burning only the dealership’s used oil and that of DIYs. 

2. Burning only in units of .5 million Btu’s/hour or less. 

3. Venting of combustion gases to the atmosphere.

Response: Classification of used oil pertains to the Identification of Non-Hazardous Materials 

That Are Solid Waste and it is out of scope for this boiler rulemaking.

Commenter Name: Arthur Blazer

Commenter Affiliation: Council of Western State Foresters

Document Control Number: EPA-HQ-OAR-2006-0790-1962.1

Comment Excerpt Number: 1

Comment: Vast areas of federal, state and private forests in the Western U.S. are identified for 

fuels reduction that reduces wildfire risk to communities and protects critical forest resources. 

Large landscapes are being impacted by bark beetle; removing the hazard trees generates large 

volumes of wood materials that currently have few local options for value?added products. 

Options for local, small’scale energy uses such as heating school campuses, prisons, and 

greenhouse complexes are a cost effective way of utilizing the forest and manufacturing residues, 

while contributing to community and state renewable energy goals. Larger bioenergy facilities 

also have a role in the western landscape in the form of combined heat and power, industrial 

boilers, and community energy systems, and are currently one of the major producers of 

renewable energy for the United States. 

The draft Area Source and Major Source Rules will directly impact the cost and viability of 

existing and new systems. Unfortunately, these rules potentially have the unintended 

consequence of providing no options for using forest residues other than slash pile burning in the 

forest. This option alone cannot provide our nation with the resources needed to maintain healthy 

forests and help meet renewable energy standards. Although the rulemaking process such as the 
MACT standards are not required to look at these trade?offs and the alternative fates, the reality 

is that clean burning of forest biomass in modern high efficiency biomass boilers creates many 

benefits for society beyond renewable energy because it reduces this alternative source of 

emissions while producing renewable energy. 

Response: EPA is charged with regulating industrial, commercial, and institutional boilers and 

process heaters and many industrial boilers use biomass as a fuel. Consequently, we must 

regulate these units under this rule. We believe that the final rule should not discourage the 

beneficial use of renewable energy sources such as biomass.

Commenter Name: Joseph M. Cloutier

Commenter Affiliation: RE-Gen, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-2284.1

Comment Excerpt Number: 1

Comment: RE-Gen is concerned that the EPA’s proposed rules will: Diminish our country’s 

energy security; Affect our efforts to meet our nation’s state Renewable Standard Portfolios; 

Reduce our ability to grow energy jobs through new companies like RE-Gen, LLC and 

Renewable Energy Fuels, LLC; Stall or diminish the ability for RE-Gen and/or its clients to 

develop biomass projects; Derail the effort to strengthen the health of our forests and agricultural 

lands; and Distract our fight to better climate change 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Steven W. Koehn

Commenter Affiliation: National Association of State Foresters

Document Control Number: EPA-HQ-OAR-2006-0790-2220.1

Comment Excerpt Number: 1

Comment: NASF has an interest in promoting markets for forest products including forest 

derived biomass. New markets for biomass have significant potential to improve the 

management of both private and public forest lands. We have concerns that the proposed Area 

Source rule will prevent new markets for forest biomass from developing. Unnecessarily 

stringent regulations in the proposed rule can be cost prohibitive and have the potential to 

prevent new investment in wood-based bioenergy facilities. This will cause boilers to increase 

their use of fossil fuels which runs counter to the nation’s renewable energy goals. Further, lack 

of markets for biomass will increase onsite open burning which can have negative public health 

impacts due to the release of methane and black carbon. We strongly encourage EPA to avoid 
finalizing regulations that have unintended consequences that limits forest role in delaying the 

nation’s shift to clean, renewable energy. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Michael A. Zapkin

Commenter Affiliation: Eastman Kodak Company

Document Control Number: EPA-HQ-OAR-2006-0790-2170.1

Comment Excerpt Number: 1

Comment: The proposed boiler MACT creates emissions standards for oil-fired boilers that are 

unnecessarily stringent that will significantly increase the cost of power for Kodak. This increase 

in costs will make Kodak’s US manufacturing less competitive and potentially jeopardizing these 

US manufacturing operations. Kodak proposes that EPA develop more reasonable standards that 

are achievable in practice, consistent with Clean Air Act requirements. Detailed comments 

follow below. 

Response: The final rule includes revised MACT and GACT standards. With the changes it will 

reduce the burden for facilities to comply but will still provide a valuable environmental benefit.

Commenter Name: John Karakash

Commenter Affiliation: Resource Professionals Group, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-2194

Comment Excerpt Number: 1

Comment: RPG is a consulting firm serving governmental agencies, utility companies and 

businesses working to lower demand on foreign oil, mitigate climate change and increase local 

employment in green collar jobs. A 14 person tour of renewable energy and forest management 

work in Austria initiated by RPG’s managing consultant led to publication by Science of the 

Policy Forum article “Wood Energy in America” in March, 2009 (Richter, et al.) Today, RPG is 

completing the final report of a USDA sponsored national survey of architects and design 

engineers on their interest and needs in specifying modern equipment that can heat and cool 

commercial class buildings using wood fuels. 

We believe clean air obligations can be achieved more quickly, to a larger degree and at lower 

cost if EPA would take a more broad approach in limiting particulate and carbon emissions and 

increase the collaborative base in ways that have not been addressed by the rules as proposed. 
As drafted, adoption of the proposed rules will limit, without scientific basis, nascent growth of 

the only industry that can significantly and simultaneously solve multiple problems, each 

recognized and being inadequately addressed in other ways. EPA has the potential with a 

comprehensive approach to: 

enable commercial class building designers to meet mandates to cut fossil energy use and carbon 

emissions; 

lower the expense associated with wildfire prevention, suppression, and loss of life and property 

and release of uncontrolled emissions; 

stimulate a fungible shift of natural gas from thermal use into clean transportation fuels. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion.

Commenter Name: Mat Ehrhardt

Commenter Affiliation: California Air Pollution Control Officers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1995.1

Comment Excerpt Number: 1

Comment: CAPCOA strongly supports efforts to reduce risks associated with emissions of air 

toxics and CAPCOA’s member agencies have long been EPA’s partner in such efforts. However, 

we are concerned that the proposed Area Source MACT standards will not achieve the desired 

goal of reducing toxic emissions risk to the nation’s residents, but will create difficulties in 

meeting a great number of environmental goals of the state of California. We believe that the 

effect of the standards will be to cause increases in NOx and PM2.5, or shutdowns of existing 

facilities, causing significant environmental impacts that have not been adequately addressed by 

EPA. We are also concerned that EPA’s statements regarding applicability of the MACT 

standards may have limit the potential for affected parties for participating in the public process. 

Response: The final rule includes revised MACT and GACT standards. With the changes it will 

reduce the burden for facilities to comply but will still provide a valuable environmental benefit.

Commenter Name: John Ledger

Commenter Affiliation: Associated Oregon Industries

Document Control Number: EPA-HQ-OAR-2006-0790-2024.1

Comment Excerpt Number: 2

Comment: The severity of the proposed standards may lead to the perverse effect of 

disincentivizing projects that otherwise would realize environmental improvements. 
Response: The final rule includes revised MACT and GACT standards. With the changes it will 

reduce the burden for facilities to comply but will still provide a valuable environmental benefit.

Commenter Name: Bruce Lisle

Commenter Affiliation: Biofuel Boiler Technologies

Document Control Number: EPA-HQ-OAR-2006-0790-1981.1

Comment Excerpt Number: 2

Comment: Because of the “one size fits all” proposed rule, an installation of small biomass 

boilers in churches, schools, commercial establishments, will not take place because the 

proposed control equipment will be more expensive than the boiler equipment and the skill set 

necessary to operate such control equipment will not be available. This will have the effect of 

shutting down this marketplace. 

Response: Small boilers less than 10 mmBtu/hr do not have applicable limits in the final rule but 

must perform tune-ups, minimizing the burden to boiler operators.

Commenter Name: Mary L. Frontczak

Commenter Affiliation: Peabody Energy

Document Control Number: EPA-HQ-OAR-2006-0790-2163.1

Comment Excerpt Number: 2

Comment: This discrimination against coal extends to EPA’s proposed area source boiler rule. 

Area source natural gas-fueled boilers are not even regulated under that rule, while coal-fueled 

boilers are. This will require owners and operators of area source coal-fueled boilers to spend an 

additional $160 million in annualized capital costs to comply with the rule. 

EPA’s discrimination against coal will evidently have its desired effect. EPA projects that "... the 

majority of new boilers and process heaters will be built to fire natural gas as opposed to solid 

and liquid fuels.” According to the Agency, no new coal-fueled units will be built in the next 

three years, while 33 new natural gas/refinery gas units will be built. Moreover, according to 

comments filed in this docket today by the Industrial Energy Consumers of America ("IECA") 

(at page 4), fuel switching caused by the Boiler MACT rule will increase natural gas demand by 

.65 TCF to .85 TCF in a relatively short time period. As set forth in the IECA comments, this is 

equal to a 3% increase in national demand (natural gas demand increased by only 2.81 % from 

1996 to 2008) and will bring the country to a level of natural gas demand that EIA has not 

forecast until 2025. 

Response: It is necessary to note that the limits of this rule were not a factor in projecting the 

number of new units. Rather, projections were based on the economic outlook of the energy 

sector. With the revised emission limits switching to natural gas as a compliance option should 

be minimized.
Commenter Name: Charles B. Jones, III

Commenter Affiliation: Georgia Traditional Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1923.1

Comment Excerpt Number: 2

Comment: EPA’s approach focus on individual HAPs has resulted in a failure to recognize the 

interplay between emissions controls and emissions of other pollutants. For example, GTMA is 

concerned that the controls necessary to meet the stringent emissions limitations for CO will 

result in increased energy usage, with the concomitant increase in emissions of NOx and other 

pollutants. It appears that EPA failed to account for this interrelationship in its economic 

analysis. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: Steven A. Brink

Commenter Affiliation: California Forestry Association

Document Control Number: EPA-HQ-OAR-2006-0790-2026.1

Comment Excerpt Number: 2

Comment: The standards in the proposed rule could cause existing biomass boilers to add Hg 

and HCL control technologies, such as activated carbon injection, carbon beds, or wet scrubbers 

and CO control technology (afterburners or catalytic oxidizers). The likely outcome would be 

very small emission reductions and likely be prohibitively expensive for anyone to make the 

investments. The result would be millions of tons of biomass open burned or land-filled and 

additional fossil fuels to replace the renewable energy that is currently produced by biomass 

boilers. 

Response: Biomass boilers do not have Hg or HCl limits in the final rule.

Commenter Name: Fred Gordon

Commenter Affiliation: Herman Miller, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-2046.1

Comment Excerpt Number: 2

Comment: Production operations and techniques at our manufacturing plants are optimized to 

increase yield while minimizing waste and scrap. Yield improvement further reduces waste at the 

same time minimizing raw material demands and consumption. Resin and glue containing 

engineering wood products are being used in many applications including the building trades and 

other commercial applications. Cut-offs and trimmings are inevitable "byproducts" of the use of 
these engineered wood products. These byproducts provide a viable biomass fuel for small 

energy recovery boilers such as ours. 

Applying emissions standards which are practicably unachievable to small energy recovery 

boilers such as ours will circumvent the opportunities to reuse, recycle and/or reclaim the fuel 

value of the types of residual wood materials we have described above. This would be an 

environmental step backwards. It would prevent the best use and reuse of these biomass 

materials. Strictly regulating energy recovery units such as ours will effectively force 

manufacturers to landfill viable raw materials and stifle additional innovation and environmental 

progress. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. 

Commenter Name: Tyler McShan

Commenter Affiliation: McShan Lumber Company

Document Control Number: EPA-HQ-OAR-2006-0790-1380

Comment Excerpt Number: 1

Comment: People still burn their yards to kill insect pests and just last year the Federal 

government PAID us to burn thousands of acres of timberland to cut down on the fuel supply 

and decrease the risk of wild fire. We do some of this every year anyway, last year we just got 

paid for it. 

Our boiler is used to burn sawdust that is generated by sawing lumber. The steam is then used to 

dry our lumber. The fuel is the same material (pine trees) that we were paid to burn last year. If 

this fuel was not burned we would have to pay someone to dispose of it and we would have to 

burn natural gas or fuel oil to dry our lumber. In today’s completive market, this would not be 

feasible. We could not compete and would have to shut down. 

The only jobs in Pickens County in the private sector are in forest products or raising and 

processing chickens. After 4 generations for raising trees, a renewable source of building 

products and fuel for renewable energy, I would hate to have to try raising chickens. Not only 

would our 58 employees be out of work, but the people who cut and haul logs to our mill and our 

lumber from it would have to find something else to do as well. 

There has been a lot of hope placed in the future of biofuel and the utilization of our forest 

products as a source of truly green renewable energy. In fact Alabama Power has struck a deal 

with one of our much larger neighbor sawmills for them to generate renewable power to replace 

some of that that is currently produced by burning coal. I hope they have already started 

construction of the boiler to be used for that project because as I understand your proposed regs 

it is not likely a new boiler could comply. 
Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion.

Commenter Name: Richard Bellefleur

Commenter Affiliation: Wellons FEI, Corp

Document Control Number: EPA-HQ-OAR-2006-0790-1300.1

Comment Excerpt Number: 4

Comment: A large portion of the end users that will be affected by these proposed rules will be 

hospitals, schools and small industries looking for a way out of high priced fossil fuels. Most of 

these potential projects would be in economically challenged rural areas were there is a 

significant downturn in the forest industry. With these new proposed rules most of these 

potential projects would no longer be feasible and the ones that are currently in operation would 

have to be shut down or retrofitted at significant cost to the end user. We think that the EPA 

should moderate their position on this issue to take into account the social-economic factors at 

hand, especially with the smaller scaled and sometimes financially burdened projects that are 

affected by the area source rules and regulations. 

Response: The final rule includes revised MACT and GACT standards which will reduce the 

compliance burden.

Commenter Name: Steven D. Swanson

Commenter Affiliation: Swanson Group, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1241

Comment Excerpt Number: 8

Comment: Our company has, in the past, seriously considered installing new biomass boilers 

fitted with turbines that can generate clean, "green" power to meet our Nation’s growing demand 

for renewable energy. Unfortunately, the stringent limits proposed in the Area Source and 

MACT rule will make projects that are already marginally economical to be that much less so, 

meaning that in our case, these projects will not occur. This rule will serve to significantly disincentivize new biomass power projects, which until now, had been promoted by both State and 

Federal programs. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Steven Jarvis

Commenter Affiliation: Missouri Forest Products Association
Document Control Number: EPA-HQ-OAR-2006-0790-1477.1

Comment Excerpt Number: 2

Comment: While only 22 (19 Area Source and 3 Major Source) of these wood-fired boilers are 

currently permitted in Missouri, hundreds of smaller boilers are either operating in or planned to 

be built in the near future. Included are the “Fuels for Schools” project to replace old fuel oil 

boilers with modern wood-fired boilers at seven schools in southern Missouri that is on hold, 

pending EPA’s final Solid Waste and Boiler rules. 

Unintended Consequences of this Proposal 

In a recent article, the U.S. Secretary of Agriculture Tom Vilsack was quoted as saying, “Energy 

derived from woody biomass has enormous potential benefits for reducing greenhouse gas 

(GHG) emissions, developing clean, home-grown energy, and providing economic opportunities 

for rural America. Markets for woody biomass can also bolster forest restoration efforts on both 

public and private lands, improving the ecological health of our forests and reducing the impacts 

of global climate change.” So true! [Footnote 1: Woody Biomass Utilization, Promoting Healthy 

Forests and Rural Economies, Newsline, Vol. 9 No. 3, 2010.] 

Woody biomass provides a cost effective and renewable alternative to fossil fuels. At the same 

time woody biomass is nearly greenhouse gas (GHG) neutral when it comes from sustainably 

managed forest lands. Biomass energy currently accounts for about 53% of the nation’s 

renewable energy use or about 4% of our nation’s total energy use (EIA Energy Review, 2008). 

The preponderance of this woody biomass energy production is by forest related industries, 

where sawmills supply 74% of their own energy needs from wood by-products of the 

manufacturing process. [Footnote 2: Greenhouse Gas and Carbon Profile of the U.S. Forest

Products Industry Value Chain, Environmental Science & Technology, Vol. 44, No. 10, 2010.] 

The new rules proposed by the EPA will directly impact both forest landowners and forest 

products companies. Forest management efforts across the nation will be impeded by reductions 

in markets for low quality wood thus further reducing a landowner’s ability to influence forest 

composition and forest health. Wood utilized in the U.S. to manufacture forest products is 

primarily produced on privately-owned forest land that allows forest landowners to profitably 

continue sustainable forest management. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: David Schutz and John Ussery

Commenter Affiliation: Northern New Mexico College

Document Control Number: EPA-HQ-OAR-2006-0790-1834.1

Comment Excerpt Number: 2

Comment: The monitoring requirements of proposed regulations would create an excessive 

economic cost that would destroy the cost advantage of using this renewable resource and 

hamper the government’s efforts to reduce the risk of catastrophic wildfires. 
Response: Emission limits and the associated monitoring requirements are revised for the final 

rule, reducing the burden for compliance.

Commenter Name: Kerry Flick

Commenter Affiliation: Metso Power

Document Control Number: EPA-HQ-OAR-2006-0790-1490.1

Comment Excerpt Number: 2

Comment: If the ruling is written into law as proposed, the future of the U.S. biomass renewable 

energy market willbe significantly impacted. Most new plants will not be feasible from a 

financial perspective given the high costs associated with the integration of needed technologies 

and equipment. There will be a significant increase in the cost to make power and Utilities will 

be forced to pass this onto the consumer. resulting in a much higher price for electricity. Thus, it 

is believed that the proposed ruling will discourage, if not eliminate, new development of 

renewable biomass power. We believe that this is not the intent of the current Administration 

from an energy or economic policy perspective. As a form of renewable energy, biomass energy 

is CO2 neutral hence does not contribute to the global green house gas emissions. Furthermore, 

producing energy form biomass clearly helps our rural economy and energy security. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: William H. Verner

Commenter Affiliation: Georgia Electric Membership Corporation

Document Control Number: EPA-HQ-OAR-2006-0790-1797.1

Comment Excerpt Number: 3

Comment: Also this proposed rule is in direct conflict with the administration’s push for 

renewables, in that renewable biomass facilities would be subject to this rule. This could 

jeopardize 

Response: Please note that greenhouse gas emissions from biomass boilers are not within the 

scope of this rulemaking, however we believe that the final rule should not discourage the 

beneficial use of renewable energy sources such as biomass.

Commenter Name: David Schutz and John Ussery

Commenter Affiliation: Northern New Mexico College

Document Control Number: EPA-HQ-OAR-2006-0790-1834.1
Comment Excerpt Number: 3

Comment: Northern Mew Mexico College has been planning to install biomass boilers to as part 

of an ARRA funded upgrade of the heating systems for its El Rito campus. These plans are 

threatened by the proposed rule. 

The fuel for these boilers was to have been cordwood and wood scrap obtained from the 

otherwise unmerchantable wood created by the thinning of the adjacent Carson National Forest. 

Decades of fire suppression have led to dangerous and unhealthy forests that are at risk of 

catastrophic wildfire. Extinguishing the natural occurrence of periodic fire has allowed the 

growth of a significant amount of excess small trees in the forest. These serve as ladder fuels that 

are leading to an increase in the number of fires and the intensity of these fires. This increased 

severity not only threatens communities in these forested landscapes, but releases a tremendous 

amount of pollution that contains many more harmful emissions than wood fired boilers. 

Current US Forest Service procedures for forest restoration and hazardous fuel reduction call for 

the cutting and in most cases burning the excess trees to reduce stand density and to remove 

unhealthy trees. Nationwide there are hundreds of millions of acres of national forest that need 

this treatment. 

The thinning of these dense forests usually requires the cutting of 200 to 2000 trees per acre. The 

amount of fuel brought to the forest floor through thinning can range between 10 and 40 dry tons 

per acre. The material that is not removed for firewood or other purposes is left to dry so it can 

be later burned through controlled burns. Over a thousand acres of forest are being thinned this 

year in just the El Rito ranger district of the Carson National Forest near the campus. 

Just this week (August 20, 2010) the USDA announced funding for a restoration plan for more 

than 200,000 acres in the southwestern Jemez Mountains that will receive up to $40 million in 

federal funds over the next 10 years. This will include the thinning of 90,000 acres, with a target 

of reducing the number of trees to 40 or 50 per acre from the current 1200 to 2000 per acre. This 

will create a huge volume of forest fuels that if they are not removed and used as residential or 

industrial fuels, will either be left to rot, thereby producing large amounts of methane, or more 

likely, will be disposed of through controlled burns. There are no pulpwood plants or other 

industries in New Mexico that are able to put these materials to other use. 

The open fires of controlled burns usually last for several days and create huge columns of 

particulate laden smoke that can usually be seen fifty miles away. This smoke creates a health 

hazard for those living downwind. 

Response: The EPA thanks the commenter for their input, but the EPA did not have ample time 

or data to analyze the potential impacts the rule may have on open burning. However, limits for 

existing biomass boilers are not included in the final rule, and new boilers must only meet a 

GACT PM limit thus minimizing the burden to facilities.

Commenter Name: David Schutz and John Ussery
Commenter Affiliation: Northern New Mexico College

Document Control Number: EPA-HQ-OAR-2006-0790-1834.1

Comment Excerpt Number: 4

Comment: The emissions of biomass boilers should not be compared to those using nonrenewable fossil fuels. The combustion of fossil fuels represents a net addition of carbon to our 

atmosphere that already bears an excessive load of carbon. The burning of coal, petroleum and 

natural gas adds hundreds of millions of tons of carbon which the planet has stored for millions 

of years. The burning of wood is carbon neutral because it is part of the natural cycle of fixing 

and releasing carbon on an ongoing basis. 

Properly designed biomass boilers minimize the emission of particulates and combustion 

byproducts compared to what would be generated by the open burning of forest residues. This 

reduction would be greater than ninety percent. 

Response: The EPA thanks the commenter for their input, but the EPA did not have ample time 

or data to analyze the potential impacts the rule may have on open burning. However, limits for 

existing biomass boilers are not included in the final rule, and new boilers must only meet a 

GACT PM limit thus minimizing the burden to facilities.

Commenter Name: Steven Jarvis

Commenter Affiliation: Missouri Forest Products Association

Document Control Number: EPA-HQ-OAR-2006-0790-1477.1

Comment Excerpt Number: 4

Comment: The secondary use of wood residues, by-products of the manufacturing process, for 

energy production offers societal, economic, and other benefits including greater overall energy 

efficiency, less reliance on fossil fuels for energy, lower GHG emissions, less use of landfill 

capacity, more U.S. manufacturing jobs, and enhanced use of sustainable American forest 

products. In fact, the U.S. forest products industry produces more renewable energy than the total 

produced by wind, solar and geothermal sources combined! Without wood as a source of fuel for 

renewable energy production, it is highly unlikely that the state of Missouri will be able to meet 

its 15% renewable energy mandate by 2021. This is an outcome that the EPA should fully 

support, however, the proposed rule will likely have the opposite effect. 

MFPA asserts that the EPA is not justified in regulating Major or Area Source Biomass Boilers 

due to the net positive contribution of growing trees and storing carbon in forest products on the 

carbon cycle. The net annual addition of carbon in forest and paper products is sufficient to 

offset all direct GHG emissions as well as all indirect emissions associated with purchased 

electricity by the forest products industry. 

Response: EPA is charged with regulating industrial, commercial, and institutional boilers and 

process heaters and many industrial boilers use biomass as a fuel. Consequently, we must 

regulate these units under this rule. We believe that the final rule should not discourage the 
beneficial use of renewable energy sources such as biomass. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Susan Eckerly

Commenter Affiliation: National Federation of Independent Business, NFIB

Document Control Number: EPA-HQ-OAR-2006-0790-1631.1

Comment Excerpt Number: 4

Comment: Excessive requirements on new boilers: The excessive requirements on new boilers 

are a disincentive for small businesses to purchase one. Boilers are already expensive; the 

requirements will make new ones even more so. This runs counter to limiting air emissions. New 

boilers already run cleaner than older ones. EPA could achieve its goal of reducing air emissions 

by incentivizing the purchase of newer, more efficient boilers. For example, EPA could exempt 

new boilers entirely, or allow the purchase of a new boiler to waive the annual testing 

requirements for at least five years. 

EPA could have reduced the burden on small entities by providing an exemption on boilers that 

are only used once or twice per week or for a total of a few hours. Instead, the rule now broadly 

affects the smallest of small businesses — and is likely to impact small institutions like schools 

and churches. 

Response: All new and existing boilers with heat input capacity less than 10 mmBtu/hr do not 

have limits but must conduct tune-ups, the revisions will reduce the burden for facilities to 

comply with the final rule.

Commenter Name: David Schutz and John Ussery

Commenter Affiliation: Northern New Mexico College

Document Control Number: EPA-HQ-OAR-2006-0790-1834.1

Comment Excerpt Number: 8

Comment: Nationwide there is enormous benefit for increased use of biomass as fuel. These 

benefits, as well as the negative impact of restricting the use of biomass fuels are laid out in great 

detail in the attached National Renewable Energy Laboratory report “The Value of the Benefits 

of U.S. Biomass Power” 

Since the Forest Service has only limited funds to pay for forest thinning, the creation of a 

biomass fuel market for thinning products would increase the number of acres that could be done 

with the dollars available. There are hundreds of millions of acres of national forest that require 

treatment for hazardous fuel reduction, but most of this will remain untreated if there are no 

commercial uses for the material generated in the process. 
Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. 

Commenter Name: William H. Carlson

Commenter Affiliation: Carlson Small Power Consultants

Document Control Number: EPA-HQ-OAR-2006-0790-1493.1

Comment Excerpt Number: 9

Comment: For discussion in this section, it will be assumed the existing fleet of >1OmmBtuJhr 

biomass boiler will require a catalytic CO unit for CO compliance and an ESP unit for PM 

compliance, a combined investment of several million dollars, even on a modest sized unit. 

There are basically two categories that make up the greater than 10 million Btu/hr family of 

biomass boilers in the U.S. : 

1 Process steam boilers in the forest products industry, with and without power generation 

2 Independent power biomass boilers supporting renewable power generation 

In neither case does the boiler owner have any shred of cost pass through ability. The forest 

products owner is hemmed in by Canadian and international competition and unable to raise 

product prices. His alternative to a need for a large capital investment is to revert to burning 

natural gas, oil or propane in his boiler. This outcome is no win for air quality and national 

energy security. 

The independent power industry is a more complex issue and there have been small pockets in 

the U.S. (CA, New England) that, at times in the past could have supported the types of capital 

investments required by your proposed regulations, and in fact some in these pockets are 

included in our top 12%. More generally, new biomass power is a marginal investment, needing 

substantial incentives, a state RPS and cheap fuel to go forward. Virtually everywhere in the 

U.S., the availability of cheap wind power limits the upside for biomass investments. 

The situation for existing biomass power is even worse. Most projects either have ended their 

original PURPA power contracts or are close to the end. These plants,in most states having RPS 

legislation, will not qualify for that states’ RPS because only projects "new" since a certain date 

qualify. I have several clients in this circumstance and they will not be adding additional 

pollution control equipment; believe me. 

You will notice in the above descriptions I have not mentioned electric utility ownership of 

biomass power facilities. That is because you can basically count the biomass power facilities 

owned by traditional electric utilities in their own service territories on one hand. If you were 

thinking that the plants would have a mechanism to pass through increased costs to ratepayers, 

you were mistaken. 

A quick history lesson is in order here. Biomass boilers were installed initially in the forest 

products industry, though more expensive than fossil fuel boilers, as air quality restrictions on 
"tepee" burners eliminated that option for mill residual disposal. So, initially, they themselves 

were a form of pollution control. 

The second wave of additions in the 1980’s, was a product of PURPA as utilities were required 

to purchase the power output from biomass power facilities and fossil based "avoided cost" 

prices were high at the time. That wave closed the last of the tepee burners, brought an option for 

diverting wood from urban waste streams ahead of landfills, diverted various ag wastes away 

from open burning and created a home for the noncommercial fraction of fuel from forest 

management activities designed to lower fire potential, increase forest vim and vigor and 

eliminate open burning. All of these diversions had positive national air quality outcomes. 

The latest round of industry growth, beginning about 2004-2005 was fueled by the availability of 

tax credits and the new state adoptions of RPS standards. This expansion is taking place in areas 

of the country with historic low power prices (Pacific Northwest, upper Midwest, South) and will 

feature the same forest management residuals and urban wood diversion as other geographic 

areas. An added benefit to this round of expansions is that forest slash piles will be utilized as 

fuel versus their traditional method of disposal by open burning. Again, this round of expansion 

will be a win for national air quality. 

With that background and explanation, what do I believe will be the practical impact of EPA’s 

adoption of the boiler MACT rules for biomass as proposed? For existing forest products 

industry boilers there will be a mass exodus to natural gas, propane or oil. Those currently 

considering biomass CHP facilities to eliminate fossil fuel boilers or to replace older boilers will 

kill those plans overnight. 

For the existing fleet of biomass power facilities, the decision will simply be to close on the day 

prior to the effective date of the new regulations. This will clearly be the last straw for these 

facilities, as they have no mechanism to pay for these costs and are currently running only to 

meet long term contract obligations. 

The impact on the new expanding biomass power industry will be even more immediate. The 

proposed rules, coupled with EPA’s proposed Tailoring Rule for biomass, will shut down the 

new industry immediately, and even the threat of this action is beginning that shutdown. Banks 

will no longer be interested in lending to an industry with this capital cost structure, or this level 

of compliance uncertainty. Manufacturer guarantees will be worthless because of the caveats 

associated with including startup and shutdown emissions. That shutdown will be widespread 

and final, except for perhaps a few utility sponsored projects that know that they can pass 

through whatever the costs turn out to be. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Steven Jarvis
Commenter Affiliation: Missouri Forest Products Association

Document Control Number: EPA-HQ-OAR-2006-0790-1477.1

Comment Excerpt Number: 13

Comment: The EPA proposed rule states that new boiler purchasers have the option of selecting 

gaseous fuel types that are cleaner to avoid emissions testing. The estimated cost of biomass 

boiler emission controls at a typical forest products facility will be more expensive than the 

purchase of a brand new natural gas boiler. However, in many rural areas, natural gas pipelines 

do not exist and propane is a much more expensive alternative gaseous fuel type. EPA’s proposal 

rules will force a switch from a renewable and less costly fuel (wood) to natural gas, fuel oil or 

propane (that is five to six times more expensive per Btu than wood fuel) which are also fossil 

fuels! 

MFPA claims that it is economically essential for the forest products industry to produce heat 

and power from existing biomass boilers rather than switching to natural gas or other gaseous 

fuels. Besides the boiler replacement cost, using natural gas or other gaseous fuels will greatly 

increase heat and power operating costs and create a disposal problem for the wood by-products 

that used to be burned as a wood fuel and cannot be sold for non-fuel purposes. 

Response: The final rule has revised limits and new biomass boilers must only meet a GACT 

PM limit thus minimizing the burden to facilities. See the preamble for further discussion on the 

economic impacts of the rule.

Commenter Name: Steven Jarvis

Commenter Affiliation: Missouri Forest Products Association

Document Control Number: EPA-HQ-OAR-2006-0790-1477.1

Comment Excerpt Number: 17

Comment: It is confusing to MFPA members that every other agency, except the EPA, seems to 

recognize the importance of wood as a renewable fuel source. It is equally confusing that all 

agencies don’t seem to recognize the dependence of the forest products industry has on wood for 

energy production. Simply put, the industry could not operate without using wood for energy. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion.

Commenter Name: Robert D. Bessette

Commenter Affiliation: Council of Industrial Boiler Owners, CIBO

Document Control Number: EPA-HQ-OAR-2006-0790-1783.1

Comment Excerpt Number: 40
Comment: EPA states in the Proposed Rule that "new facilities [have] the option of fuel 

selection in minimizing their compliance costs." 75 FR 31909. This is statement is not accurate. 

First, specific fuel types are not available at different locations, and new units may need to burn a 

specific fuel to be viable. Second, EPA cannot arbitrarily set a standard that eliminates a source’s 

ability to burn specific fuels. This may be the exact case when considering biomass units. EPA 

has established emission standards as stringent as coal for renewable fuels such as biomass. This 

could discourage the use of renewable fuels. For a comprehensive discussion of these issues, 

please refer to CIBO’s comments on the Proposed Boiler MACT Rule. [See DCN: 2006-0790-

1783.2 for related comments.] 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Bill Perdue

Commenter Affiliation: American Home Furnishings Alliance, AHFA

Document Control Number: EPA-HQ-OAR-2006-0790-1970.1

Comment Excerpt Number: 1

Comment: The wood furniture manufacturing industry burns kiln dried wood containing less 

than 20% moisture to generate the heat and steam necessary to manufacture our finished product. 

This fuel is produced directly from the furniture manufacturing process. Our industry is one of 

the original recycling sectors in industrial manufacturing. Modern manufacturers achieve 

approximately 50% yield from sawmill wood stock. Rather than dispose of the remaining 50% 

dry wood biomass in a landfill, the biomass “off-fall” is beneficially used to produce energy. By 

combusting kiln dried wood in steam generating boilers, the wood furniture industry avoids 

reliance on fossil fuels for process and domestic heating purposes. Combustion of our wood fuel 

also precludes landfilling the wood off-fall, which would add environmental insult to the injury 

of being prevented from using a valuable fuel commodity. The proposed rule, in concert with the 

parallel rulemaking Emissions Standards for Major Industrial/Commercial and Institutional 

Boilers and Process Heaters, threaten to put an end to the widespread use of this domestic, 

renewable, carbon-neutral fuel. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: James P. Brooks

Commenter Affiliation: Maine Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2006-0790-1915.1

Comment Excerpt Number: 2
Comment: There are numerous publicly funded institutional facilities in Maine that may be 

unable to cover the necessary capital costs for achieving compliance with the proposed 

standards. The vast majority of those affected units are less than 10 MMBtu/hr. Discontinuation 

of those affected units or switching to natural gas are not options (natural gas availability is 

extremely limited in Maine). EPA’s broad inclusion of all units, regardless of design capacity, is 

a flawed approach that will have a substantial negative economic impact on Maine’s 

municipalities and public health facilities while the decrease in HAP emissions will be minimal. 

Response: All boilers with heat input capacity less than 10 mmBtu/hr are not subject to emission 

limits.

Commenter Name: Jon Strimling

Commenter Affiliation: American Biomass Company

Document Control Number: EPA-HQ-OAR-2006-0790-1904.1

Comment Excerpt Number: 2

Comment: High compliance costs will discourage adoption of low cost, low carbon heating 

fuels in the low-to-middle income families who are most in need of clean, affordable heating 

technologies 

Response: The final rule includes revised MACT and GACT standards. With the changes it will 

reduce the burden for facilities to comply but will still provide a valuable environmental benefit.

Commenter Name: Ardis Almond

Commenter Affiliation: Almond Brothers Lumber Company

Document Control Number: EPA-HQ-OAR-2006-0790-1449.1

Comment Excerpt Number: 2

Comment: Here is another personal example from our operation: We have barely survived 

through the recession and for most of last year ran only 30 hours per week. We were able to 

survive primarily because we are an export mill cutting lumber for world markets and were not 

as damaged by the housing bust. (We are one of the good guys, helping the trade deficit.) We do 

not have a boiler, but instead we dry our lumber with a direct fired natural gas kiln. As an 

engineer, I have had a long range plan of converting our drying system from natural gas (a fossil 

fuel) to a steam kiln with a biomass burning boiler (our own sawdust – a carbon neutral 

renewable resource). The plan included a co-generation system to produce electricity for our 

plant and possibly some of the community. We have cancelled all work on that project because 

of Boiler MACT. This was one of the plans for the future to make us more efficient and help our 

company survive in a competitive world. Now this won’t happen, at least until these restrictive 

proposals are defeated. Even then, I don’t know if I would ever recommend this, when some 

group at the EPA could shut down a system with few regulations that do not even have to be 

approved by Congress. 
On the one hand, government wants us to use more biomass and at the same time creates 

regulations that make that impossible. I don’t understand it. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Stephen E. Woock

Commenter Affiliation: Weyerhaeuser Company

Document Control Number: EPA-HQ-OAR-2006-0790-1984.1

Comment Excerpt Number: 2

Comment: Weyerhaeuser is concerned with how biomass is treated as a fuel category in this 

rule and in the major source Boiler MACT rule. Because Weyerhaeuser is a major grower and 

provider of timber and manufacturer of wood and pulp/paper products, we have a significant 

interest both in the markets for the primary timber resources and secondary materials that end up 

as biofuels or biomass fuels. As on-site energy producers and consumers, most of our mills use 

significant quantities of biomass for fuel in its various forms and from a variety of sources. 

While some amount of fossil fuels are used at most mills and some smaller mills use only fossil 

fuels, most of our mills primarily use biomass to fuel their boilers and process heaters. In fact, 

using 2009 data as a snapshot, among our five U.S. pulp mills the median biomass-sourced fuel 

energy consumed for on-site energy production was 91% of the total on-site fuel energy 

consumed. For our major and area source wood products mills in the U.S. that utilize biomass 

fuels, the median biomass fuel energy was 85% of the total on-site fuel energy consumed. 

[Footnote: Btu basis, estimated from all biomass fuels used to fire on-site boilers and process 

heaters during 2009. For pulp mills this includes recovery furnaces combusting the biomass 

contained in the recycled pulping liquors.] Our mills also marketed some 4800 billion BTUs in 

biomass residuals fuels energy to third parties in 2009. And although we 

do not have a specific estimate, we expect an even larger additional amount of biomass fuel is 

derived from our timber and forest residuals sales to third parties. Use of these renewable

biomass fuels supports the Nation’s goals to reduce dependence on foreign energy sources and 

reduce the greenhouse gas footprint of energy production. Their use also helps incent the 

longterm keeping of working forest lands as forest. The AWC comments go into more detail on 

the Forest Products Industry significant use of biomass to self-satisfy energy needs and the 

NAFO comments address the growing use and importance of this renewable resource 

nationwide. For example, the AWC comments identify that there are over 800 boilers and 

process heaters at wood products facilities in the U.S. and the majority of these boilers burn 

biomass. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.
Commenter Name: Bruce Coffee

Commenter Affiliation: Hurst Boiler and Welding Co

Document Control Number: EPA-HQ-OAR-2006-0790-1873.1

Comment Excerpt Number: 2

Comment: These actions will greatly increase the growth in demand for Natural Gas, a fossil 

fuel. In spite of the fuel crisis of a couple of year ago, and the Enron Crisis of a decade ago, this 

action will have the unintended consequence of driving more energy control into the hands of a 

few. From recent experience, we know that the price of Natural Gas can “sky-rocket” and catch 

companies mid-stream and drive many to bankruptcy. This is certain. 

Response: With the revised MACT and GACT standards for the final rule, EPA does not 

anticipate boiler operators will use fuel switching to natural gas as a compliance option.

Commenter Name: Joe Muehlbach

Commenter Affiliation: Quad/Graphics

Document Control Number: EPA-HQ-OAR-2006-0790-1961.1

Comment Excerpt Number: 3

Comment: This broad, "hypothetical boiler" approach that EPA is proposing will also have 

another unintended consequence: it will provide a significant disincentive for conversion of 

existing coal-fired boilers to renewable energy fuels such as biomass. The anticipated cost for 

compliance for biomass boilers under the proposed approach to a MACT standard will likely be 

prohibitive for anyone considering such a renewable energy conversion project. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 3

Comment: AF&PA is concerned about the impact of the area source rule on our leadership in 

the national effort to increase the use of renewable energy. Of late, many forest products 

facilities are reducing their consumption of fossil fuels and increasing their use of biomass. In 

2008, 65 percent of the total energy used by AF&PA member pulp and paper mills was 

generated from renewable sources. At wood products facilities, 74 percent of energy used was 

produced from biomass sources. The Forest Products Industry leads all other industries in the use 
of renewable energy and utilization of industry-generated by-product materials. In other words, 

our industry combines a tradition of recycling with a strong degree of energy independence. 

For the forest products industry, “sustainability” is not a buzzword or a marketing slogan -- it is 

our foundation. We are, and must be, committed to ensuring that our resources will be as 

plentiful and available to future generations as they are today; to preserving and growing our 

contributions to the economy; and to fostering the wellbeing of the communities where we live 

and work. We responsibly produce essential products to meet basic human needs from renewable 

and recyclable resources. The economic, societal and environmental aspects of our industry’s 

sustainability include the following: 

* Employing over 900 thousand workers – more than the automotive industry – often in small 

rural communities where good paying jobs are critical 

* Being among the top ten manufacturing employers in 48 states generating many more jobs in 

industries throughout the supply chain and in local businesses, which sustain communities and 

families 

* Continuously evolving and innovating our paper, packaging and wood products to meet 

society’s needs 

* Bringing home ownership within reach for millions of Americans – which enhances economic 

vitality and social stability -- by providing affordable, energy-efficient building materials. 

We sustainably use renewable resources since trees provide our raw materials and energy. The 

industry grows more trees (4 million daily) than are harvested. We practice sustainable forest 

management, and today America has more forestland than 50 years ago. Demand for forest 

products keeps millions of acres of land sustainably forested for future use while providing 

habitat for wildlife and recreational opportunities for the community, enhancing our air and 

water resources and sustaining the economy of the region. Finally, our industry has combated 

illegal logging around the world and supports only responsible/sustainable use of forest 

resources. 

We produce and use more renewable energy than any other industrial sector – and more than all 

the solar, wind and geothermal power combined. Paper, pulp and wood products mills generate 

65% of their energy needs from carbon-neutral, renewable biomass – equivalent to 200 million 

barrels of oil annually. The forest products industry is the nation’s leader in the use of cogeneration technology (also called “combined heat and power”). 

A more thorough discussion of these sustainability and renewable fuel issues is contained in our 

comments on the major source boiler rule (See Section II submitted to Docket EPA-HQ-OAR2002-0058; we incorporate those comments by reference). That discussion also includes a 

thorough enumeration of all the other regulatory challenges and impacts affecting the paper and 

wood products industries, discussions that are also relevant here. 
One of our major concerns is the impact of the Carbon Monoxide (CO) emission limits proposed 

for area source boilers. We are concerned that, if implemented as proposed, they could deter 

building new and eliminate many existing area source boilers. If such a result would occur, many 

of the achievements listed above might be reversed. Additionally, many of the renewable fuels 

programs in the 30+ states that have implemented them would be challenged to meet their goals. 

However, we feel that no such dire consequence is necessary. We discuss later in these 

comments the options available to the agency within the confines of the Clean Air Act that 

would both enable it to reduce HAP and meet statutory requirements. Implementation of these 

recommendations may enable most of the areas source boiler operations of the forest products 

industry to continue to operate and sustainably contribute to the communities in which they 

operate. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: W. James Wagoner

Commenter Affiliation: Butte County Air Quality Management District

Document Control Number: EPA-HQ-OAR-2006-0790-1993.1

Comment Excerpt Number: 4

Comment: The facility is required to utilize agricultural biomass, such as orchard prunings, as 

fuel. If the plant closes, this material will likely, once again, be disposed of by open, 

uncontrolled burning that results in significantly higher criteria pollutant emissions and may also 

release higher levels of toxic air contaminants into our air basin. 

Response: The EPA thanks the commenter for their input, but the EPA did not have ample time 

or data to analyze the potential impacts the rule may have on open burning. However, limits for 

existing biomass boilers are not included in the final rule, and new boilers must only meet a 

GACT PM limit thus minimizing the burden to facilities.

Commenter Name: Bruce Coffee

Commenter Affiliation: Hurst Boiler and Welding Co

Document Control Number: EPA-HQ-OAR-2006-0790-1873.1

Comment Excerpt Number: 4

Comment: At a time when we should be increasing our sustainability by decreasing our 

dependence on fossil fuels, this is a major step backwards for the country. This will have a 

detrimental effect on development of the very fuels we need to use most to slow the flow of 

wastes into our landfills. 
Response: The final rule includes revised MACT and GACT standards. With the changes it will 

reduce the burden for facilities to comply but will still provide a valuable environmental benefit.

Commenter Name: Joe Muehlbach

Commenter Affiliation: Quad/Graphics

Document Control Number: EPA-HQ-OAR-2006-0790-1961.1

Comment Excerpt Number: 4

Comment: As a company running several manufacturing plants in an ozone non-attainment zone 

as well as impacted by PM2.5 non-attainment we are particularly interested in any action that has 

the potential to increase NOx emissions. Concerns have been raised by the Wisconsin 

Department of Natural Resources that the pollution control approaches required for other 

pollutants in the rule may have the unintended consequence of increasing NOx emissions. 

Tremendous efforts have been made in Southeastern Wisconsin resulting in measurable 

improvements to the air quality and the state is now on track to comply with both the federal 

ozone and PM2.5 standards and anything that may set back those efforts are cause for concern. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: David J. Prior

Commenter Affiliation: New York State Energy Research and Development Authority, 

NYSERDA

Document Control Number: EPA-HQ-OAR-2006-0790-1913.2

Comment Excerpt Number: 4

Comment: Oil and Wood Use and Prices for the Commercial and Industrial Sectors - In 2008, 

New York State used 1.9 billion gallons of distillate fuels (includes #2 home heating oil, 

kerosene, and diesel fuel) and 557.2 million gallons of residual fuel oil. The commercial sector 

consumed 76.1, 41.9, and 8.2 trillion British thermal units (Btu) of distillate, residual fuel oil, 

and wood fuel respectively. Likewise, the industrial sector consumed 19.7, 6.9, and 14.2 trillion 

Btu of distillate, residual fuel oil, and wood fuel (NYSERDA, 2010)[footnote: NYSERDA. 

2010. Patterns and Trends New York State Energy Profiles: 1994-2008. NYSERDA, Albany, 

NY.] Between the year 2007 and 2008, distillate fuel and residual fuel prices increased by 33% 

and 43% respectively while natural gas prices increased by a lesser amount, 10 – 14%. This price 

variation created an economic incentive for facilities to switch fuels. The price of wood for the 

commercial and industrial sectors is not reported by NYSERDA, however, it has been reported 

that residential wood prices increased only 3% during this period (NYSERDA, 2010)[ Personal 

communications with wood fuel industry personnel]. 

Attempting to replace any significant portion of heating fuels, particularly wood and distillate 

fuels, with natural gas, propane, or electricity would require extensive infrastructure expansion, 

excessive lead times, and considerable expense. 
Response: With the revised MACT and GACT standards for the final rule, EPA does not 

anticipate boiler operators will use fuel switching to natural gas as a compliance option.

Commenter Name: Jon Strimling

Commenter Affiliation: American Biomass Company

Document Control Number: EPA-HQ-OAR-2006-0790-1904.1

Comment Excerpt Number: 5

Comment: If left unchanged, this rule has the potential to inflict catastrophic damage on the 

wood pellet industry at a tremendous cost to society. The adoption of wood pellet stoves has 

been driven by the low cost and environmental benefits of wood pellet fuels. Pellet stoves have 

in many cases displaced traditional wood stoves, resulting in net benefits to air quality. Wood 

stove change out programs across the country have spurred pellet stove adoption and resulted in 

lower emissions and cleaner air. It is critical for the EPA to understand how wood pellets act as a 

substitute for other higher emissions biomass fuels like cord wood. If this rule goes into effect, 

the long term impact on the biomass thermal industry could be slowed adoption of pellet fuels in 

stoves and boilers, which will undoubtedly translate to continued use of older, less efficient, 

higher emissions wood stoves in millions of households across the country. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. With the final limits, 

EPA is not providing preferential treatment for one biomass type over another.

Commenter Name: Robert L. Garfield

Commenter Affiliation: Food Industry Environmental Council

Document Control Number: EPA-HQ-OAR-2006-0790-1835.1

Comment Excerpt Number: 5

Comment: In fact, it could create an incentive for facilities to switch away from gas to other 

fuels. Both outcomes should be avoided. 

Response: The final rule includes revised MACT and GACT standards. With the changes it will 

reduce the burden for facilities to comply but will still provide a valuable environmental benefit.

Commenter Name: Chris Mello

Commenter Affiliation: Alaska Energy Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1653.1

Comment Excerpt Number: 5
Comment: Keeping cost impacts of federal regulations for boiler emissions to a minimum is 

important for the future of our villages. An increase in cost of the installation and operation of 

heating systems means people will continue to rely on the import of diesel for heating fuel and 

the export of local dollars. Unemployment will continue to be significant as biomass harvest jobs 

fail to materialize. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: David J. Prior

Commenter Affiliation: New York State Energy Research and Development Authority, 

NYSERDA

Document Control Number: EPA-HQ-OAR-2006-0790-1913.2

Comment Excerpt Number: 5

Comment: Fuel Switching Away From Wood and Oil- If petroleum, coal, and/or wood boilers 

are converted to natural gas in sufficient quantity, there could be an adverse impact within the 

electricity sector, particularly on peak gas days during winter months when hourly gas demand is 

at its highest level. The majority of New York’s natural gas electric generation fleet operates 

with interruptible fuel contracts. On peak gas days when the supply of natural gas for electric 

generators is diminished due to increased use by firm service end-use customers, dual-fueled 

units would be forced to switch to backup petroleum fuels. Certain gas-fired units would be 

unable to operate, and the unmet electricity requirements would have to be met by units that burn 

coal or oil. This would have an adverse impact on electricity prices, system reliability, and 

emissions. 

Liquid fuels, particularly in the downstate region (Long Island, New York City, and its northern 

suburbs), play a major role in serving heating demand. The proposed rules may lead to increased 

fuel conversions away from liquid fuels, where available. Rather than attempt to meet the 

requirements of the rules, some boiler owners may elect to convert to natural gas or propane, 

which are given a blanket exemption from the emissions monitoring requirements under the 

proposed rule. In some instances, increased fuel conversions may lead to localized or regional 

strain on the natural gas infrastructure, particularly during periods of sustained cold weather that 

promote high heating demand. Depending on the scope, location, and timing of fuel conversions, 

the capacity of the local, regional and interstate natural gas transmission and distribution system 

could be challenged to absorb any large scale transition. 

Propane is available in rural areas of NYS but not in NYC. However, propane is a more costly 

fuel and there would be minimal environmental benefits from switching from ultra-low S home 

heating oil to propane. 

Response: With the revised MACT and GACT standards for the final rule, EPA does not 

anticipate boiler operators will use fuel switching to natural gas as a compliance option.
Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 6

Comment: Attempting to meet the proposed CO limits will lead to increased NOx emissions and 

potentially increased PM2.5 and other pollutant emissions for many liquid-fired boilers. This 

could result in making those boilers subject to the NSPS D standards and require New Source 

Review and Prevention of Significant Deterioration analyses and offsets. None of these activities 

appear to have been addressed in this rulemaking’s cost or burden analyses or considered in 

establishing the time needed for compliance. We recommend these impacts be considered as the 

rule is finalized and that the Agency make clear that the Part 60 General Provision’s pollution 

exemption applies to emission increases of criteria pollutants due to modifications associated 

with complying with this regulation, provide a mechanism for extending compliance time where 

NSR or PSD permitting is needed, and incorporate the cost of that permitting and offsets in the 

economic and other analyses. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: William C. Scott

Commenter Affiliation: Collum's Lumber Products, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1796.1

Comment Excerpt Number: 6

Comment: The limits are so unreasonable that the impact analysis in the rule assumes that no 

new biomass boilers will ever be built at major sources. This is absurd given the fact that 

biomass is greenhouse gas-neutral and the government is pushing increased use of renewable 

energy. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. It is necessary to note that the limits of 

this rule were not a factor in projecting the number of new major source units. Rather, 

projections were based on the economic outlook of the energy sector.

Commenter Name: Jon Strimling

Commenter Affiliation: American Biomass Company

Document Control Number: EPA-HQ-OAR-2006-0790-1904.1
Comment Excerpt Number: 6

Comment: The biomass thermal industry has great potential to grow, innovate, and support local 

community energy independence and greenhouse gas reduction through the replacement of fossil 

fuel heating with high efficiency biomass boilers. As proposed, the only certainty is that the Area 

Source rule will devastate the biomass thermal industry and small businesses, and local 

government and schools will be forced to look for non-renewable fossil fuels for their heating 

needs. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Stephen E. Woock

Commenter Affiliation: Weyerhaeuser Company

Document Control Number: EPA-HQ-OAR-2006-0790-1984.1

Comment Excerpt Number: 6

Comment: For combination fuel boilers where biomass is routinely a large portion of the fuel 

heat input but coal is the regulated fuel subcategory, [Footnote: EPA defines the coal 

subcategory in this rule to be when coal makes up at least 10% of the heat input.] the proposed 

CO limit inadvertently incents increasing the proportion of coal heat input to more easily comply 

with the standard. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. The subcategory definitions have also 

been revised.

Commenter Name: Gary Rubenstein

Commenter Affiliation: Kauai Island Utility Cooperative, KIUC

Document Control Number: EPA-HQ-OAR-2006-0790-2028.1

Comment Excerpt Number: 10

Comment: The rulemaking assessment should also include the effect of boiler location when 

evaluating feasibility and cost of retrofit requirements. Fuel and infrastructure constraints must 

be considered. For example, Kauai’s electrical generation and consumption are restricted to the 

island; electrical interties between the Hawaiian islands do not exist. Also, there is no natural gas 

on Kauai. All of KIUC’s generating units at Port Allen are fueled on #2 Diesel fuel, which must 

be brought to the island by barge from refineries in Honolulu. All of these factors affect the cost 

and feasibility of measures that require the use of ultra-low sulfur fuel or alternative fuels. 
In addition, KIUC does not own its fuel storage facilities at Port Allen—KIUC leases tanks from 

Chevron at its nearby tank farm. A regulation requiring KIUC to use a lower sulfur fuel in one 

type of generating unit would increase KIUC’s costs for fuel storage, as well as for fuel, and thus 

would impose an additional cost factor. Also contributing to increased costs is that not only fuel 

but also everything used on the island must be transported by barge from the mainland or from 

other countries, via Honolulu. This increases the cost of living and the cost of doing business 

compared to typical costs on the mainland. Any evaluation of cost-effectiveness must account for 

the premiums that will be paid for materials, equipment, and labor at KIUC’s location. 

Response: The final rule includes revised MACT and GACT standards. With the changes it will 

reduce the burden for facilities to comply but will still provide a valuable environmental benefit.

Commenter Name: Robert L. Garfield

Commenter Affiliation: Food Industry Environmental Council

Document Control Number: EPA-HQ-OAR-2006-0790-1835.1

Comment Excerpt Number: 11

Comment: EPA’s focus on individual HAPs has resulted in a failure to recognize the critical 

interplay between emissions controls and emissions of other pollutants. For example, we are 

concerned that the controls necessary to meet the stringent emissions limitations for carbon 

monoxide (CO) will result in increased energy usage, with the concomitant increase in emissions 

of nitrogen oxide (NOx) and other pollutants. Further, EPA failed to account for this 

interrelationship in its economic analysis. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: Stephen E. Woock

Commenter Affiliation: Weyerhaeuser Company

Document Control Number: EPA-HQ-OAR-2006-0790-1984.1

Comment Excerpt Number: 14

Comment: To meet the proposed area source NESHAP limits may require controls in some 

circumstances, that will come into conflict with the effluent guidelines for wood products mills 

that prohibit discharge of process wastewaters. Certain air pollution control devices that generate 

process wastewater have previously been exempted from this effluent guideline when used at 

facilities also covered by the Plywood and Composite Wood Products (PCWP) MACT Rule 

(subpart DDDD). 40 CFR Part 429, the Timber Products Processing Point Source Category 

states that "there shall be no discharge of process wastewater pollutants into navigable waters" 

for facilities covered under subparts B, C, D and M (dry process hardboard, veneer, finishing, 

particleboard, sawmills and planing mills). In conjunction with the PCWP rule, these subparts 

were narrowly modified to allow discharge from air pollution control devices (APCD) associated 
with controlling HAP emissions covered by PCWP. However, mills in the wood products 

industry subject to Part 429 cannot legally discharge wet scrubber or other wet control device 

blowdown from APCD that are installed to comply with this area source NESHAP because they 

constitute process wastewaters. Scrubbers and wet electrostatic precipitators may be required by 

some wood product industry boilers subject to Part 429 in order to comply with these air 

standards. 

EPA could avoid this concern by adopting work practice standards to meet the GACT standard 

and drop the proposed MACT standards as previously discussed, so wood products facilities will 

not face the problem of a new and potentially high volume process wastewater that is difficult to 

manage and not possible to permit and discharge from the site. However, if EPA chooses to 

insist on setting numerical emissions limits, then the effluent guidelines definition of "process 

wastewater" in 40 CFR §429.11(c) must be amended to exclude wastewater from air pollution 

control devices on boilers complying with this area source NESHAP. We refer EPA to the AWC 

comments on this issue, which provide more detailed descriptions of the APCD wastewater 

volumes and other relevant information to support a similar recommendation. 

Response: There are not emission limits for existing biomass boilers in the final rule, and thus 

only new boilers would install control devices and would have the opportunity to design their 

system to comply with effluent wastewater guidelines.

Commenter Name: Chris Mello

Commenter Affiliation: Alaska Energy Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1653.1

Comment Excerpt Number: 15

Comment: Much of the biomass utilized in district heating system in Alaska is harvested in 

wildfire prevention measures and to improve forest health. In communities without biomass 

systems, wood harvested for firebreaks is usually burned in uncontrolled outdoor fires and results 

in significant air emissions. Emissions from uncontrolled wildfires are substantially greater than 

the smoke from biomass boiler use. 

Response: The EPA thanks the commenter for their input, but the EPA did not have ample time 

or data to analyze the potential impacts the rule may have on open burning. However, limits for 

existing biomass boilers are not included in the final rule, and new boilers must only meet a 

GACT PM limit thus minimizing the burden to facilities.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 26
Comment: Well recognized in combustion engineering is the tradeoff between CO and NOx 

emissions. Many state environmental standards recognize this and have placed far greater 

emphasis on the control of NOx in their SIP and state/local standards than CO since CO is rarely 

a non-attainment issue and ozone frequently is. An extremely low CO limit can be 

environmentally problematic. Again, the GACT language in the Clean Air Act allows for 

flexibility in this. The States of California and Maine commented on this issue with Maine 

providing a report to EPA in February that is referenced elsewhere in these comments: 

The Maine DEP is concerned that EPA’s dataset may be incomplete in regards to the types of 

boilers predominantly in Maine and to the types of fuels burned by these boilers. We are also 

concerned that EPA may develop standards that do not take into account the NOx controls 

required for many of the Maine facilities and the effect that controlling for CO, which inversely 

affects NOx, as well as other pollutants.” 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 54

Comment: AF&PA strongly supports EPA’s conclusion that fuel switching is not an appropriate 

MACT floor or beyond-the-floor control option. This conclusion is particularly apt with respect 

to wood products facilities, due to their need to employ a mix of fuels to control costs and their 

heavy reliance on residual biomass for fuel. Further, gas-firing requires a great deal of 

infrastructure, while many forest products facilities often are located in rural areas that lack the 

necessary gas infrastructure. More generally, gas supplies are limited and industrial uses are of 

lower priority than residential uses during times of supply shortfalls and cold weather. Industrial 

boilers also compete with utility boilers for gas supplies and increasing electricity demand in the 

coming years, coupled with increasing reliance on natural gas to meet that demand, will place 

further strain on limited gas supplies and distribution networks. We comment on this issue 

extensively in our submission for major source boilers (See Section XXII, docket EPA-HQOAR2002-0058; we incorporate those comments by reference). 

Response: EPA thanks the commenter for their input; fuel switching is not considered as an 

option.

Commenter Name: Paul Noe

Commenter Affiliation: American Forest and Paper Association, AF&PA

Document Control Number: EPA-HQ-OAR-2006-0790-1939.1

Comment Excerpt Number: 65
Comment: EPA has concluded that no additional water would be used or wastewater would be 

generated due to the controls required by GACT (see 75 Fed. Reg. page 31917). That may be 

true in most cases but there may be situations where a facility determines it can best meet the 

GACT requirements with a wet control device. In that event, wood products facilities would not 

be able to discharge the wastewater because the effluent limitations guidelines for the Timber 

Products Processing Point Source Category in 40 CFR part 429 subparts B (Veneer subcategory), 

C (Plywood subcategory), D (Dry Process Hardboard subcategory), and M (Particleboard 

Manufacturing subcategory) prohibit the discharge of process wastewater pollutants. "Process 

wastewater" is defined quite broadly, with only a few exclusions. (See 40 C.F.R. § 429.11(c)). 

Facilities within these source categories would be prohibited from discharging the blowdown 

from a wet control device installed on a boiler. 

EPA recognized this same problem when it established MACT standards for the Plywood and 

Composite Wood Products category and amended the definition of "process wastewater" in the 

Timber Products Processing effluent guidelines to exclude wastewater generated by the types of 

air pollution control equipment EPA had identified as the basis of MACT standards for those 

source categories subject to a zero discharge effluent guidelines. (See 40 C.F.R. § 429.11(c); 69 

Fed. Reg. 45,944 at 45,964). AF&PA/AWC commented extensively on this issue in the major 

source rules, which we refer you to for a complete discussion (See Section XXI, Docket 

EPAHQ-OAR-2002-0058; we incorporate those comments by reference) 

Response: There are not emission limits for existing biomass boilers in the final rule, and thus 

only new boilers would install control devices and would have the opportunity to design their 

system to comply with effluent wastewater guidelines.

Commenter Name: Jim Simon

Commenter Affiliation: American Sugar Cane League

Document Control Number: EPA-HQ-OAR-2006-0790-2281.1

Comment Excerpt Number: 1

Comment: The ASCL’s fundamental overarching comment is that the Proposed Rule, as it 

pertains to the combustion of biomass, is contrary to the efforts of the current Administration 

with regard to “green” energy initiatives. The Proposed Rule provides a disincentive for both the 

use of renewable resources and the reduction of our nation’s dependence on fossil fuels. 

The Proposed Rule (40 CFR 63, subpart JJJJJJ) establishes emission standards for coal-fired, oilfired, and biomass-fired boilers located at area sources. Bagasse meets the definition of 

“biomass” in the Proposed Rule. Therefore, all bagasse-fired boilers located at area sources are 

subject to the §112(d) standards of the CAA. The pollutants covered by subpart JJJJJJ are 

mercury, particulate matter (PM) (as a surrogate for non-mercury urban HAPs), and carbon 

monoxide (CO) (as a surrogate for polycyclic organic matter (POM) expressed as polycyclic 

aromatic hydrocarbons (7-PAH)). 
Response: Bagasse units are still in the biomass subcategory. However, limits for existing 

biomass boilers are not included in the final rule, and new boilers must only meet a GACT PM 

limit thus minimizing the burden to facilities. See the preamble for further discussion on the 

economic impacts of the rule.

Commenter Name: Arnold Schwarzenegger

Commenter Affiliation: Governor of the State of California

Document Control Number: EPA-HQ-OAR-2006-0790-1777.1

Comment Excerpt Number: 1

Comment: California has adopted some of the nation’s most ambitious renewable energy and 

greenhouse gas reductions goals and I am concerned that rule changes being considered by your 

agency will undermine the progress we are making. 

While I understand the need to update standards to reflect new technologies, U.S. EPA must 

carefully consider the trade-offs that must be made in meeting California’s ozone reduction and 

greenhouse gas reduction goals. The attached comments by our energy and environmental 

agencies outline major concerns about how your proposed boiler standards may cause 

California’s existing biomass-to-energy facilities to close. 

California’s 40 biomass plants provide approximately 800 megawatts of electricity generation 

capacity that last year produced 5,700 gigawatt-hours of electricity, representing about 

three percent of California’s total in-state power generation. In addition, these facilities employ 

750 people on-site and support 1,200 to 1,500 jobs in the fuel supply infrastructure. I know the 

Obama Administration is working as hard as we are to increase, not eliminate, green jobs. 

While I support your efforts to adopt national regulations to reduce hazardous air pollutants, I 

have significant concerns that these proposed standards would have adverse impacts on 

California’s environment and economy. Therefore, I strongly urge you to reconsider the 

proposed standards for existing biomass-to-energy facilities. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Charles R. Faulds

Commenter Affiliation: Texas Electric Cooperatives, Treating Division

Document Control Number: EPA-HQ-OAR-2006-0790-1641.1

Comment Excerpt Number: 1
Comment: Advantages of utilizing biomass will diminish under the EPA proposed rules at the 

same time other departments of the government are encouraging and even subsidizing biomass 

facilities. Under the proposed rules, facilities could spend millions of dollars on controls and still 

not meet emission standards. The additional costs will be passed on to consumers and the 

producer is no longer competitive. Production and jobs for many facilities could be relocated to 

foreign countries where little concern for the environment exists and will cause a greater 

detriment to the environment and our economy than burning legitimate fuels in properly 

functioning boilers. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Brad Hunter

Commenter Affiliation: GreenWood Resources

Document Control Number: EPA-HQ-OAR-2006-0790-2099.1

Comment Excerpt Number: 1

Comment: The proposed EPA ruling would effectively put a stop to additional investment in the 

United States as the biomass industry would move most of its capital to off-shore projects, 

especially Europe where there is a more balanced regulatory approach to biomass energy and 

emissions. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Ronald W. Gore

Commenter Affiliation: Alabama Department of Environmental Management

Document Control Number: EPA-HQ-OAR-2006-0790-1494.1

Comment Excerpt Number: 1

Comment: The proposed rules impose severe emission restrictions on the combustion of 

biomass. Since many facilities may not be able to afford the controls required to meet the 

proposed MACT limitations, it appears that the proposed rules will drive these facilities towards 

the combustion of natural gas to meet energy requirements. Since biomass is a renewable source 

of energy, this appears to run contrary to the current Administration’s stated desire to move away 

from fossil fuels and towards renewable sources of energy. 

Alabama, along with other States, is facing mandatory renewable energy targets in the future. 

For obvious reasons, wind, solar, geothermal, and many other renewable sources are not viable 
in Alabama. Biomass appears to be the primary alternative. Our State may not be able to meet its 

goals if biomass usage is discouraged. 

Additionally, given the current Administration’s desire to regulate Greenhouse Gas emissions, it 

is perplexing to the Department that the EPA would drive facilities away from utilizing what 

may be considered a ‘carbon neutral’ fuel. Furthermore, when combined with the recently 

proposed solid waste definition, it appears that the fate of wood residuals may be landfills, where 

it will decay into methane, which has a CO2 equivalence of 25:1. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: David P. Tenny

Commenter Affiliation: National Alliance of Forest Owners

Document Control Number: EPA-HQ-OAR-2006-0790-1884.1

Comment Excerpt Number: 2

Comment: The promotion of renewable energy is a national policy that EPA must follow. 

As described above, forests can play an important role in reducing and managing greenhouse gas 

emissions. Expanding the sources of renewable energy is a central feature of both national and 

international policy to reduce reliance on fossil fuels. 

The EPA, in considering approaches toward addressing climate change, has long recognized that 

responsibly managed forests are considered one of five key “groups of strategies that could 

substantially reduce emissions between now and 2030.” See Regulating Greenhouse Gas 

Emissions Under the CAA, 73 Fed. Reg. 44,354, 44,405 (July 30, 2008). Similarly, the United 

Nation’s Intergovernmental Panel on Climate Change (“IPCC”) report on mitigation 

technologies highlights forest management as a primary tool to reduce GHG emissions. Id. at 

44,405-06; see also NAFO, Carbon Mitigation Benefits of Working Forests (identifying trading 

platforms and registries that recognize forest management), available at 

http://nafoalliance.org/mitigation-benefits-working-forests/. 

President Obama has emphasized that renewable energy derived from feedstocks such as forest 

biomass hold the key to transitioning the nation to a “sustainable, low carbon energy future.” See 

Letter from President Barack Obama to Governors John Hoeven and Chet Culver (May 27, 

2009), available at 

http://www.governorsbiofuelscoalition.org/assets/files/President%20Obama’s%20Respo nse5-

27-09.pdf; see also President Barack Obama, Memorandum for the Secretary of Agriculture, the 

Secretary of Energy, and the Administrator of the Environmental Protection Agency, 74 Fed. 

Reg. 21531-32 (May 5, 2009). 
With Presidential endorsement, if not direction, of national renewable energy policy and the role 

of biomass in that policy, EPA must conduct its programs in a manner consistent with that 

policy. In light of this policy, EPA must not adopt any mandatory environmental controls, such 

as those set forth in the proposed rulemaking, that will require large expenditures of time and 

resources by industry, but are not necessary to protect human health and the environment. 

Similarly, to act consistently with this nation’s renewable energy policy, EPA must not impose 

restrictions on biomass boilers that are not legally required and that stand to disadvantage the use 

of biomass as a fuel source. The proposed rule lacks any justification for its departure from this 

policy and, as explained below, is thus arbitrary and capricious. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Arnold Schwarzenegger

Commenter Affiliation: Governor of the State of California

Document Control Number: EPA-HQ-OAR-2006-0790-1777.1

Comment Excerpt Number: 2

Comment: In California, BTE boilers are tuned to reduce oxides of nitrogen (NOx) emissions at 

the expense of some increased carbon monoxide (CO) emissions (an attainment pollutant) 

because of California’s ozone nonattainment problem. Modifying a biomass boiler to meet the 

CO emissions requirements used as a surrogate for non-dioxin organic hazardous air pollutants 

(HAP) will result in higher emissions of NOx that may trigger New Source Review (NSR) 

requirements for best available control technology and offsets. ARB believes U.S. EPA needs to 

re-evaluate the increased NOx emissions of this proposed standard and the impacts on states, 

such as California, in meeting the National Ambient Air Quality Standards for ozone. 

Response: Biomass boilers do not have CO limits in the final rule.

Commenter Name: Michael T. Palko

Commenter Affiliation: Pennsylvania Department of Conservation and Natural Resources

Document Control Number: EPA-HQ-OAR-2006-0790-1895.1

Comment Excerpt Number: 2

Comment: These new rules will directly impact both forest management and wood products 

industries. Forest management efforts across the nation will be impacted by reductions in 

markets for low quality wood thus further reducing a manager’s ability to influence forest 

composition and forest health. Elimination of such markets resulted in 300-400% increases in 

fuels reduction treatment costs in the western US. 
Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion.

Commenter Name: Brad Hunter

Commenter Affiliation: GreenWood Resources

Document Control Number: EPA-HQ-OAR-2006-0790-2099.1

Comment Excerpt Number: 3

Comment: The lack of coordination between EPA and other government agencies provides 

another red flag for all private companies that are interested in this space. The president and 

congress have repeatedly promoted the greater utilization of biomass to provide renewable heat 

and energy to reduce the countries reliance on imported oil and carbon dioxide emissions that 

contribute to climate change. 

Response: EPA is charged with regulating industrial, commercial, and institutional boilers and 

process heaters and many industrial boilers use biomass as a fuel. Consequently, we must 

regulate these units under this rule. We believe that the final rule should not discourage the 

beneficial use of renewable energy sources such as biomass. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 3

Comment: Importantly, as you reduce boiler CO emissions, under certain circumstances NOx 

emissions will increase. For this reason, we suggest that EPA further explore and discuss the 

relationships between CO and NOx and align its priorities so that the regulated community does 

not find itself in an untenable compliance challenge involving “technical dissonance.” This issue 

is more pressing given the fact that many states have non-attainment zones for ozone NAAQS, 

and NOx is an ozone precursor. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: Robert R. Scott

Commenter Affiliation: New Hampshire Department of Environmental Services

Document Control Number: EPA-HQ-OAR-2006-0790-1952.1

Comment Excerpt Number: 3
Comment: Balancing CO reductions with nitrogen oxide (NOx) reductions already in place in 

ozone non-attainment areas 

Many states that have been designated non-attainment for ozone, including New Hampshire, 

have worked diligently over the past 15 years to reduce ozone through the reduction of NOx 

emissions. Since forcing down CO emissions can result in increases in NOx emissions from fuel 

burning devices, this current effort to control organic HAPs through reductions in CO may 

negate the efforts conducted by states to improve ozone levels. NHDES encourages EPA to 

balance CO and NOx emission levels to achieve optimum boiler efficiency as well as minimize 

the impact on state’s efforts to reduce ozone. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: Edward J. Wilusz

Commenter Affiliation: Wisconsin Paper Council

Document Control Number: EPA-HQ-OAR-2006-0790-2133

Comment Excerpt Number: 4

Comment: If owners or operators of combination boilers anticipate difficulty complying with 

the proposed CO standard, they may have to switch away from biomass and burn more coal to be 

able to comply with the coal subcategory emission standards. This unintended consequence of 

replacing biomass with coal is contrary to national energy and climate policy, which encourages 

the use of more renewable biomass fuel. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Matthew Markee

Commenter Affiliation: IN Group Companies

Document Control Number: EPA-HQ-OAR-2006-0790-1965.1

Comment Excerpt Number: 4

Comment: IN does not believe such adverse consequences are EPA’s intent, however using CO 

as a surrogate for organic HAPs destruction would result in substantially higher NOx emissions 

and lower energy efficiency nationwide. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.
Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 4

Comment: Many states have adopted Renewable Portfolio Standards (RPS) expressly for the 

purpose of encouraging the development and deployment of biomass fired units as a matter of 

public policy. The MACT standards EPA has proposed for biomass-fired boilers will create a 

huge barrier to the development of renewable energy biomass projects, which will cause many to 

be cancelled because of the choices EPA has made in developing these proposed standards. As a 

matter of public policy, EPA should encourage the combustion of wood biomass. The 

combustion of biomass is becoming increasingly important to Duke Energy and other utilities as 

renewable energy laws are adopted by more states, and are possibly applied to all states as a 

result of federal mandates. Section 112 affords EPA great flexibility in how it establishes MACT 

standards for these sources even after considering the recent guidance EPA has received from the 

courts. The combustion of biomass has the beneficial effect of conserving natural resources. 

Unfortunately, the stringent MACT limits EPA has proposed for IBs burning biomass will 

greatly inhibit the combustion of biomass in the future. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Malcolm Milne

Commenter Affiliation: Durgin and Crowell Lumber Co. Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1987.1

Comment Excerpt Number: 4

Comment: Durgin & Crowell is in the lumber manufacturing business. We directly employ 

approximately eighty-five (85) people, and purchase raw material (i.e. logs) from almost two 

hundred (200) different suppliers each year. The vast majority of our lumber is sold to end-users 

outside the State of New Hampshire. The majority of the revenue derived from the sale of our 

products goes right back to the local community. Our existing wood-fired boiler has been in 

service for nearly thirty (30) years, over which time it has been upgraded and modified to run as 

efficiently as practicable. We perform annual tune-ups, pursuant to our New Hampshire Air 

Emissions permit. 

At some point, the company would like to install a wood-fired cogeneration plant at the mill to 

replace the old wood-fired boiler. If, as some claim, the proposed emissions limits are 

unreasonable and unachievable, it would certainly affect the feasibility (let alone the cost) of a

new cogeneration system at our facility. New standards may be necessary, but they should be 

reasonable. Unreasonable standards may lead to unmarketable costs for boiler manufacturers. 
Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion.

Commenter Name: Kevin F. Biernacki

Commenter Affiliation: Veolia Energy North America

Document Control Number: EPA-HQ-OAR-2006-0790-2273

Comment Excerpt Number: 5

Comment: This proposed regulation may force boilers that supply steam for heating/cooling 

purposes to large urban populations to transition off of fuel oil to natural gas. If this were to take 

place, energy prices may become inflated at times. It is unclear whether potentially inflated 

energy prices have been taken into consideration within the proposed regulation’s cost benefit 

analysis. 

Work closely with industry to develop representative oil firing CO emission limits to ensure that 

add-on controls or major capital improvements would not be required to meet the intent of the 

regulation as stated within this regulation’s background documentation. If certain boilers would 

not be able to satisfy the CO emission limit for fuel(s) regulated by this rule, facilities may be 

forced to fire a fuel that is not in the best economic interests of their energy customers (e.g. a 

facility may be forced to fire natural gas in lieu of fuel oil even if natural gas rates exceed those 

of fuel oil). 

Response: With the revised MACT and GACT standards for the final rule, EPA does not 

anticipate boiler operators will use fuel switching to natural gas as a compliance option.

Commenter Name: Jon Bolling

Commenter Affiliation: Prince of Wales Community Advisor Council

Document Control Number: EPA-HQ-OAR-2006-0790-1935.1

Comment Excerpt Number: 5

Comment: National studies are clear that biomass emissions impacts health. It is also clear that 

rural Alaskans suffer disproportionately from poor lung health. We cannot exclude a contribution

of biomass emissions to these health impacts. However, EPA must not overreach with its 

regulations and cause undue hardship for rural Alaska communities. The economic development 

and jobs creation from biomass heating systems will be stymied by the increased cost for the 

installation and operations of biomass systems under the new emissions regulations. To ask too 

much at too high of a cost may create unintended consequences, with communities forced to 

continue to import high cost petroleum fuels for heating. 
Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Robert Klemans

Commenter Affiliation: Florida Electric Power Coordinating Group

Document Control Number: EPA-HQ-OAR-2006-0790-1955.1

Comment Excerpt Number: 6

Comment: EPA HAP Regulation of Biomass: FCG believes that renewable fuels should be 

considered as part of a diverse energy supply portfolio, and our members are pursuing options, 

such as biomass, that can help us continue to provide reliable and affordable energy to our 

customers. 

Economic renewable energy resources are unevenly distributed across the United States and the 

Southeast. Currently, one of Florida’s most promising economic renewable resources is biomass. 

Most renewable resources provide an intermittent supply of energy, but biomass generation is 

capable of producing a reliable supply of baseload energy, making it extremely beneficial. 

However, the stringent limits and requirements in the proposed IB MACT decrease the prospect 

of producing reliable renewable energy from biomass. Florida needs the capability of producing 

renewable energy from biomass. FCG believes the proposed stringent emission limits within the 

proposed IB MACT may hinder the technologic and economic drivers for new and biomass 

conversion projects in Florida. 

EPA should encourage the combustion of biomass as substitute fuel for coal or oil as a matter of 

good public policy. The combustion of biomass will become increasingly important to utilities if 

renewable energy standards are adopted by more states and are possibly applied to all states as a 

result of federal mandates. Biomass is an abundant and renewable domestically-produced fuel 

that can help reduce reliance on foreign sources of fossil fuel. Prescribing stringent HAP 

emissions limitations on biomass boilers will create a significant barrier to the continued use and 

expansion of biomass fuels. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: David P. Tenny

Commenter Affiliation: National Alliance of Forest Owners

Document Control Number: EPA-HQ-OAR-2006-0790-1884.1

Comment Excerpt Number: 6

Comment: The combined effect of these arbitrary and unnecessary controls would substantially 

increase the cost of using biomass as a fuel source. As such, the proposed rule would negate the 

several government programs providing incentives to use biomass and to develop technologies 
reliant on biomass. With devalued incentives and increased costs, the nation would risk losing 

biomass as an integral part of renewable energy policy. The effect of the proposed rule would 

ultimately land at the foot of the forest landowner as biomass markets fail to grow or even 

disappear as heat and power facilities turn to other fuel sources. Most forest landowners calculate 

a return on their investment on a variety of markets for forest products. The elimination or 

dramatic reduction of a significant market such as biomass could affect the attractiveness of 

forestland ownership to the degree that owners look to use of the land for purposes other than 

forests in order to obtain an economic return. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: David Suess

Commenter Affiliation: DSG Solutions, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-1977.1

Comment Excerpt Number: 6

Comment: This proposed regulation may force boilers that supply steam for heating/cooling 

purposes to large urban populations to transition off of fuel oil to natural gas. If this were to take 

place, energy prices may become artificially inflated at times due to this regulation. Have larger 

societal economic concerns like inflated energy prices been taken into consideration within this 

proposed regulation’s cost benefit analysis. In addition, with more facilities transitioning to only 

firing natural gas and new facilities in certain regions being mandated to fire solely natural gas, 

regional over reliance on natural gas should be taken into consideration since regional fuel 

flexibility is of importance. 

Response: With the revised MACT and GACT standards for the final rule, EPA does not 

anticipate boiler operators will use fuel switching to natural gas as a compliance option.

Commenter Name: Michael T. Palko

Commenter Affiliation: Pennsylvania Department of Conservation and Natural Resources

Document Control Number: EPA-HQ-OAR-2006-0790-1895.1

Comment Excerpt Number: 7

Comment: The use of locally available, renewable biomass in thermal or combined heat and 

power applications provides thousands of jobs in the Northeast and other regions where nonrenewable, unpredictably priced heating oil and other fossil fuels are now used as the 

predominant source of heat. Biomass thermal energy has great promise, and we cannot 

emphasize enough how damaging this rule could be to current and future use of biomass for 

heating and CHP (combined heat and power). We are in favor of fair and effective regulation of 

biomass boiler emissions, but EPA’s proposed rule goes much too far. 
Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Arnold Schwarzenegger

Commenter Affiliation: Governor of the State of California

Document Control Number: EPA-HQ-OAR-2006-0790-1777.1

Comment Excerpt Number: 7

Comment: If implemented as proposed, the MACT regulations will have a significant impact on 

the ability of biomass-to-energy facilities to continue to operate in the State and the State’s 

ability to meet its 33 percent renewable energy goals by 2020. 

Development of biomass as an energy source is very important to the State of California. The 

State, through Governor Schwarzenegger’s Executive Order S-06-06, establishes a 20 percent 

target for biomass within its established State goals for renewable generation for 2010 and 2020. 

Currently, generation from biopower resources provides about 20 percent of California’s 

renewable energy or an estimated 

2.8 percent of California’s total in-state power generation. 

In order to support biomass facilities and other renewable energy resources, California imposes a 

public goods charge to provide incentives and financial support to make them economically 

viable. More than 70 percent of California’s biopower generation from solid-fuel biomass 

facilities in the State receives funding from this program. 

Despite State subsidies, the total generating capacity from solid fuel biomass has decreased from 

994 megawatts (MW) in the 1 990s to 667 MW today, despite a potential to generate 3,421 MW 

from biomass resources. Only one new facility has been developed since 2000. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: David P. Tenny

Commenter Affiliation: National Alliance of Forest Owners

Document Control Number: EPA-HQ-OAR-2006-0790-1884.1

Comment Excerpt Number: 8

Comment: In addition to an economic justification for adopting alternative compliance methods 

or reduced emission limitations for biomass boilers, there is an environmental justification. 

Biomass is a “clean” fuel and, as described in Section I above, the combustion of biomass is 
carbon neutral. As such, by encouraging the use of biomass boilers, this rulemaking could have a 

positive impact on the nation’s carbon footprint. In addition, as an abundant, renewable, 

domestic energy source, the use of biomass for energy has a positive contribution toward the 

nation’s energy security. NAFO is concerned that because the proposed rule’s stringent, numeric 

emissions limitations for biomass units are largely unachievable, it would create a disincentive to 

the continued and expanded use of biomass fuels and, in turn, could encourage the use of highercarbon fossil fuels. As described by Metso Power, the proposed rule would discourage, if not 

eliminate, new development of renewable biomass power. See Attachment 1 at 2. [See submittal 

for Attachment 1.] Notably, EPA’s own Regulatory Impact Analysis, at page 3-2, estimates zero 

new biomass units. Discouraging current or new enterprises from using biomass would be 

inconsistent with the CAA’s emissions reduction goals. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: J. Michael Geers

Commenter Affiliation: Duke Energy

Document Control Number: EPA-HQ-OAR-2006-0790-1861.1

Comment Excerpt Number: 8

Comment: The uncertainty to meet limits during SU/SD is causing biomass projects to be 

postponed and will lead to project cancellations and state renewable energy goals not being met. 

Response: See the preamble for discussion on startup and shutdown.

Commenter Name: Robert E. McKenna

Commenter Affiliation: Motor and Equipment Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1920.1

Comment Excerpt Number: 8

Comment: EPA’s focus on individual HAPs has resulted in a failure to recognize the critical 

interplay between emissions controls and emissions of other pollutants. For example, we are 

concerned that the controls necessary to meet the stringent emissions limitations for CO will 

result in increased energy usage, with the concomitant increase in emissions of NOx and other 

pollutants. Further, EPA failed to account for this interrelationship in its economic analysis. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.
Commenter Name: James P. Brooks

Commenter Affiliation: State of Maine Department of Environmental Protection

Document Control Number: EPA-HQ-OAR-2006-0790-1941.1

Comment Excerpt Number: 8

Comment: NOx vs CO [See submittal for all figures.] 

NOx and CO data obtained from Red Shield - Old Town, SAPPI - Somerset No.1 Power Boiler, 

and Verso Paper Androscoggin was compiled into Figures and the inverse correlation between 

and NOx and CO was evident. These Figures can be found in Appendix A. 

Verso Paper Androscoggin provided annual NOx and CO stack test data shown in Figure #1. 

This Figure indicates NOx decreases as CO increases and vice versa. 

SAPPI Somerset provided daily CO and NOx data from April through July (Figure #2); the 

correlation was seen again. 

This phenomenon was also seen in the data collected from the Red Shield facility; particularly 

when the facility was burning only whole tree chips (Figure #3). CO and NOx variability was 

much lower when CDW, a dry fuel, was included in Red Shield’s fuel mix as in September 2007 

(See Figure #4 — note the scale on this Figure is the same as the scale used for Figure #3). As 

shown by Figure #5, CO and the percent oxygen were much less variable when dry fuel such as 

CDW was part of the fuel mix; in turn NOx was higher. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: Arnold Schwarzenegger

Commenter Affiliation: Governor of the State of California

Document Control Number: EPA-HQ-OAR-2006-0790-1777.1

Comment Excerpt Number: 9

Comment: Continued operation of the biomass-to-energy facilities supports state and federal 

healthy forest initiatives, helps our agricultural sector, assists solid waste disposal, and enables 

utilities to meet renewable energy mandates. 

Response: EPA thanks the commenter for their input. Limits for existing biomass boilers are 

not included in the final rule, and new boilers must only meet a GACT PM limit thus minimizing 

the burden to facilities.

Commenter Name: Edward J. Wilusz

Commenter Affiliation: Wisconsin Paper Council
Document Control Number: EPA-HQ-OAR-2006-0790-2133

Comment Excerpt Number: 14

Comment: In addition, biomass is a “clean” fuel in many of the same respects as the Gas 1 fuels. 

Perhaps more importantly, biomass-fired boilers produce no net GHG emissions, which make the 

combustion of biomass an important tool in managing and reducing the Nation’s carbon 

footprint. Similarly, biomass is an abundant, renewable domestically-produced fuel that can help 

reduce reliance on foreign sources of fossil fuel and, thus, improve the Nation’s energy security. 

Prescribing stringent HAP emissions limitations on biomass boilers will create a significant 

barrier to the continued use and expansion of biomass fuels and incentivize the use of less 

desirable fossil fuel alternatives. 

In light of the inordinate costs of complying with the proposed HAP emissions limits for biomass 

boilers and the strong policy reasons for promoting the combustion of biomass, EPA has ample 

justification to prescribe work practices rather than HAP emissions limitations for biomass 

boilers. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on MACT versus GACT regulation.

Commenter Name: Arthur Blazer

Commenter Affiliation: Council of Western State Foresters

Document Control Number: EPA-HQ-OAR-2006-0790-1962.1

Comment Excerpt Number: 2

Comment: NASF has an interest in promoting markets for forest products including forest 

derived biomass. New markets for biomass have significant potential to improve the 

management of both private and public forest lands. We have concerns that the proposed Area 

Source rule will prevent new markets for forest biomass from developing. Unnecessarily 

stringent regulations in the proposed rule can be cost prohibitive and have the potential to 

prevent new investment in wood-based bioenergy facilities. This will cause boilers to increase 

their use of fossil fuels which runs counter to the nation’s renewable energy goals. Further, lack 

of markets for biomass will increase onsite open burning which can have negative public health 

impacts due to the release of methane and black carbon. We strongly encourage EPA to avoid 

finalizing regulations that have unintended consequences that limits forest role in delaying the 

nation’s shift to clean, renewable energy. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.
Commenter Name: Teresa Marks

Commenter Affiliation: Arkansas Department of Environmental Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2005

Comment Excerpt Number: 2

Comment: Arkansas has identified biomass as a legitimate and readily available alternative 

energy source. Many of the boilers in Arkansas that will be impacted by this rule use biomass as 

a fuel source. Biomass is a readily available "waste" product in Arkansas. Stringent requirements 

for biomass fueled boilers that do not pose a health risk, as addressed in the proposed rule, could 

very likely force these facilities to convert from biomass as a fuel to natural gas due to the costs 

related to monitoring and compliance demonstrations. The elimination of biomass as an 

alternative energy source would result in this waste material being abandoned or disposed of in 

landfills or incinerators. Although the Clean Air Act does not specifically require it, we assert 

that the overall impact to the environment through cross media transfer of pollutants from the air 

to the land and water resulting from the storage and disposal of biomass should be properly 

evaluated and addressed prior to finalization of this Boiler MACT. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Kevin Van De Wege

Commenter Affiliation: Washington House of Representatives

Document Control Number: EPA-HQ-OAR-2006-0790-2164.1

Comment Excerpt Number: 2

Comment: Such regulations would harm our vital forest products industry and hurt the prospects 

for expanding our nation’s green energy production and the jobs it brings. 

While we strongly support the goals of achieving strong protections for public health and high 

environmental performance, we are concerned that there will be unintended consequences with 

the current draft proposal. Without careful reconsideration these regulations may unnecessarily 

harm Washington’s critical forest products industry -- and that of other states in the union -- and 

our burgeoning efforts to utilize waste wood from the state’s forest lands for renewable energy 

production. 

The forest products industry is critical to all areas of Washington State, representing 11% of all 

manufacturing jobs and playing a particularly important role in rural, timber-dependent 

communities. 

The sector provided over 45,000 jobs in 2005, generated approximately $16 billion in gross 

business revenue, and paid out over $2 billion in wages and over $100 million in tax receipts. 
As the state has invested in the renewable energy field, we have looked to the forest products 

sector to take a leadership role. In particular we have focused on renewable biomass power as an 

arena where we have a competitive advantage and an ability to increase distributed domestic 

power generation and utilization of previously wasted forestry resources. 

A 2005 state biomass inventory found that as a state we are “blessed with a vast and diverse, 

annually renewable biomass, which although in places is presently utilized for energy, fertilizer 

and feed, in other places is still quite underutilized and capable of being a significant factor in 

bioenergy, biofuel, or bioproduct production.” The inventory found that Washington State has an 

annual production of over 16.9 million dry tons of underutilized biomass which could be capable 

of creating 15.5 billion kWh of electrical energy, or almost 50% of the state’s annual residential 

energy consumption. 

This focus on biomass power has resulted in significant levels of public and private investment. 

In 2006 the state energy freedom fund provided $6 million to the Grays Harbor PUD to invest in 

a new biomass boiler used by the Grays Harbor Paper Company to generate process steam for 

the 100% recycled green paper plant and electrical power for the PUD. 

In 2009 the Port Townsend Paper Company received a $2 million dollar stimulus grant to 

upgrade its biomass boiler. This grant is being matched by $2 million in private funds generated 

by other energy saving projects in the mill. This boiler is now a part of a proposed $55 million 

cogeneration project that will provide the equivalent of 35 construction jobs for one year and will 

create 30 new jobs. In addition, it helps sustain the 290 permanent mill jobs. 

Also in 2009, the Nippon Paper Company in Port Angeles received a combination of loans and 

grants of $2 million to support a planned $71 million investment to replace an existing steam 

boiler with a biomass boiler retaining 234 permanent jobs and adding 10 temporary jobs.4 

A 2009 state study on pulp and paper boilers showed great opportunities for reduced fossil fuel 

usage and increased renewable energy production – but old boilers will need to be upgraded. 

With the capital costs involved and the current state of the market, it would be unfortunate if 

limited capital resources went into short term investments to meet unattainable standards rather 

than a longer term strategy of investing in aging infrastructure that can continue to create jobs

and meet core business objectives while increasing renewable energy generation and 

environmental performance. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Troy Runge

Commenter Affiliation: Wisconsin Bioenergy Initiative

Document Control Number: EPA-HQ-OAR-2006-0790-2245
Comment Excerpt Number: 2

Comment: The stringent emission limits on biomass units may force new biomass fuel boiler 

projects either to significantly upgrade their existing pollution-control equipment or consider 

switching to natural gas. Ultimately, this additional hurdle for the use of biomass will increase 

the use of fossil fuels, which is counterproductive to President Obama’s energy policy and 

Wisconsin’s investment in bioenergy. The rule may severely limit and/or potentially eliminate 

the use of agricultural biomass fuels, threatening the development of a new local, renewable 

energy market. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Arie Verloop

Commenter Affiliation: Jansen Combustion and Boiler Technologies, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1856.1

Comment Excerpt Number: 2

Comment: The proposed MACT/GACT/CISWI rules promote natural gas firing over renewable 

biomass and establish limits based on arbitrary statistics rather than health risk. The current 

administration is promoting the use of renewable energy, such as bioenergy and biopower. In 

contrast, the new proposed rules are more stringent for the bioenergy approach than for 

traditional fossil fuels such as oil and coal. These rules will harm new enterprises and help push 

the country toward using fossil fuels, while making it difficult to build new boilers, especially 

biomass boilers that support renewable energy and greenhouse reduction initiatives. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. Please note that 

greenhouse gas emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Joseph M. Cloutier

Commenter Affiliation: RE-Gen, LLC

Document Control Number: EPA-HQ-OAR-2006-0790-2284.1

Comment Excerpt Number: 3

Comment: We are especially concerned that the proposed changes make take affect as the

Administration’s support of biomass has been unwavering and involves almost every member of 

the Cabinet from the White House, USDA, DOE, Interior, Council on Environment Quality, 

EPA, DOJ, Treasury and Commerce. As well, in Congress biomass has been included in every 

single piece of renewable energy legislation beginning with the Public Utility Policy Act of 
1978. Support for biomass is universal, bi-partisan, and spans the scope of virtually every major 

energy policy enacted by the Congress. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Gailyn Messersmith

Commenter Affiliation: Messersmith Manufacturing, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1949.1

Comment Excerpt Number: 3

Comment: The proposed emission limits and testing requirements will dramatically increase the 

cost of biomass boilers and discourage the use of renewable biomass fuel. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Eric Trauner

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2286

Comment Excerpt Number: 3

Comment: It is not sound policy to put such demands on modestly-size boilers burning fuel 

other than natural gas. Placing such demands on modestly-sized solid/ liquid fuel boilers will 

create a rush for conversion to natural gas, to the point where natural gas supplies could be 

strained. US-EPA itself acknowledges this reality 

Response: The final rule includes revised MACT and GACT standards. With the changes it will 

reduce the burden for facilities to comply but will still provide a valuable environmental benefit.

Commenter Name: Mike Beebe

Commenter Affiliation: Governor, State of Arkansas

Document Control Number: EPA-HQ-OAR-2006-0790-2001

Comment Excerpt Number: 3

Comment: We understand that it is often difficult for the EPA to consider and address broad 

environmental effects when dealing with specific media-related rulemaking. However, I feel that 
the time is ripe with this rulemaking to do just that. The EPA has promoted the development of 

alternative energy sources for a number of reasons, including the protection of air quality. 

Unfortunately, when one looks at EPA’s specific rulemaking, the impact has been to discourage 

that very goal. This proposed rule is an example. 

Arkansas has considered the overall impact to the environment of energy production in our State. 

We have identified and promoted biomass as a legitimate and readily available alternative energy 

source. Many of the boilers in Arkansas that will be affected by this rule use biomass as a fuel 

source. Biomass is a readily available "waste" product in Arkansas. Using this "waste" as a fuel 

source eliminates many environmental issues that would otherwise have a crippling effect on this 

State and its citizens. The overly stringent requirements for biomass-fueled boilers that do not 

pose a health risk, as addressed in the proposed rule, could very likely force these facilities to 

convert from biomass as a fuel to natural gas, due to the costs related to monitoring and 

compliance demonstrations. The elimination of biomass as an alternative energy source would 

have a cascading impact on the State and the environment by this material either being 

abandoned or by forcing the disposal of this heretofore useable commodity in landfills or 

incinerators. Although the Clean Air Act does not specifically require it, we assert that the 

overall impact to the environment through cross-media transfer of pollutants from the air to the 

land and water, resulting from the storage and disposal of biomass, should be properly evaluated 

and addressed prior to finalization of this Boiler MACT. This is simply sound public policy. 

Response: EPA is charged with regulating industrial, commercial, and institutional boilers and 

process heaters and many industrial boilers use biomass as a fuel. Consequently, we must 

regulate these units under this rule. We believe that the final rule should not discourage the 

beneficial use of renewable energy sources such as biomass.

Commenter Name: Christopher S. Bond

Commenter Affiliation: Missouri, United States Senate

Document Control Number: EPA-HQ-OAR-2006-0790-2200.1

Comment Excerpt Number: 3

Comment: Ironically, EPA’s imposition of standards so expensive that they force forest-product 

facilities to abandon their use of biomass to power their operations would drive those that 

survive to more carbon-intensive energy sources such as coal, predominant in Missouri, or 

propane. Not only would facilities release more carbon from their energy sources, but the carbon 

from the biomass byproduct would still be released into the atmosphere after it is discarded. 

Thus, EPA’s proposal threatens both the administration’s goal of encouraging renewable, lowercarbon fuels and reducing carbon emissions. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.
Commenter Name: George M. Israel

Commenter Affiliation: Georgia Chamber of Commerce

Document Control Number: EPA-HQ-OAR-2006-0790-1996.1

Comment Excerpt Number: 3

Comment: Discouraging the use of biomass-fueled boilers would be particularly punitive to 

Georgia. Biomass is a locally sourced, abundant, and renewable fuel that is crucial to 

maintaining and improving the Nation’s energy security as well as the economies of the areas 

where they are located. This fact is particularly important in Georgia and the rest of the southeast 

with our somewhat limited options for generating renewable energy. 

The net result of this rule would be to discourage the development and utilization of 

environmentally-beneficial energy alternatives. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Alicia Oman

Commenter Affiliation: National Association of Manufacturers

Document Control Number: EPA-HQ-OAR-2006-0790-2234.1

Comment Excerpt Number: 3

Comment: Biomass is a “clean” fuel in many of the same respects as the Gas 1 fuels. Biomassfired boilers produce no net GHG emissions, which makes the combustion of biomass an 

important tool in managing and reducing the Nation’s carbon footprint. Similarly, biomass is an 

abundant, renewable domestically-produced fuel that can help reduce reliance on foreign sources 

of fossil fuel and, thus, improve the Nation’s energy security. Prescribing stringent HAP 

emissions limitations on biomass boilers will create a significant barrier to the continued use and 

expansion of biomass fuels and incentivize the use of less desirable fossil fuel alternatives. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Kevin P. Bundy

Commenter Affiliation: Center for Biological Diversity

Document Control Number: EPA-HQ-OAR-2006-0790-2009.1

Comment Excerpt Number: 3
Comment: More particularly, we understand that industry representatives have submitted, and 

are likely to submit, comments in each of these dockets asking that sources combusting biomass 

be treated differently from sources burning other fuels. Some of these comments seek either 

broad exemptions, or less stringent forms of regulation, under sections 112 and 129 on the basis 

that biomass combustion is purportedly “carbon neutral,” renewable, or otherwise 

environmentally beneficial. 

Response: EPA is charged with regulating industrial, commercial, and institutional boilers and 

process heaters and many industrial boilers use biomass as a fuel. Consequently, we must 

regulate these units under this rule. We believe that the final rule should not discourage the 

beneficial use of renewable energy sources such as biomass.

Commenter Name: Keith A. Craig

Commenter Affiliation: Pennsylvania Hardwoods Development Council

Document Control Number: EPA-HQ-OAR-2006-0790-2017.1

Comment Excerpt Number: 3

Comment: Additionally, many wood products manufacturers currently use wood waste to fuel 

their own processes and facilities. The proposed rule would in many cases force these companies 

to return to fossil fuels and add that useable waste to landfills. Adoption of the proposed rule is 

counterproductive to the federal and state goals of increasing production of alternative renewable 

biomass energy. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Troy Runge

Commenter Affiliation: Wisconsin Bioenergy Initiative

Document Control Number: EPA-HQ-OAR-2006-0790-2245

Comment Excerpt Number: 3

Comment: The rule may increase either the facility costs and/or agricultural biomass fuel costs 

(e.g. fuel may have to be processed to remove minerals) so significantly that these homegrown 

fuels could not compete with imported fossil fuels like coal or natural gas. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.
Commenter Name: Paolo Maffei

Commenter Affiliation: Tuolumne County

Document Control Number: EPA-HQ-OAR-2006-0790-2276

Comment Excerpt Number: 3

Comment: It seems senseless that co-gen facilities, which burn forest or ag waste should be 

subjected to emission requirements similar to larglesil-fuel burning power plants. Coal, oil or 

natural gas that has been safely seq alGinNitiround for millions of years is equated to forest 

waste, which had a life cycle of decades, rarely centuries and in our area is subjected to fire on a 

regular basis. The material entering a co-gen plant is destined for incineration, either in a 

controlled burn, a timber or thinning operation burn-pile or, often, in a catastrophic wildfire. 

Why would the intrinsic benefit of a co-gen plant, both from the aspect of a cleaner burn and the 

equivalent unburned fossil fuel be ignored? I have direct knowledge of lost co-gen opportunities 

due to current policies. 

The greatest concern in much of California, especially in our County, is fire. Forests need to be 

thinned and the value of the timber is rarely sufficient to cover the cost. We also believe that a 

viable forest industry is important for the economy, watershed protection and also the 

environment. A good policy would require all power distributors in California to purchase 

enough electricity from co-gen plants to drive up the price of the feedstock. Giving economic 

value to forest waste would help pay for trucking and thinning. Many to whom the free market is 

a mantra seem reluctant to trust the allocation of resources to the invisible hand of the market to 

achieve a desired objective (such as with a carbon tax). They often prefer the taxpayer directly 

subsidize industries. Insurance and firefighting costs would be greatly reduced by passing on to 

the consumer an imperceptible* cost increase to reduce the cost of fighting wildfire. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Troy Runge

Commenter Affiliation: Wisconsin Bioenergy Initiative

Document Control Number: EPA-HQ-OAR-2006-0790-2245

Comment Excerpt Number: 4

Comment: Without agricultural biomass fuels, additional pressure would be put on wood 

resources (as a substitute for coal), potentially increasing the cost of woody fuels and distorting 

existing forest products markets, thereby threatening sustainability of harvesting. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for

further discussion on the economic impacts of the rule.
Commenter Name: Eric Trauner

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2286

Comment Excerpt Number: 4

Comment: In an era of debate about anthropogenic global warming, it’s unwise to put excessive 

demands on use of biomass and energy-intensive solid waste. US-EPA acknowledges that 

biomass is a carbon-neutral fuel source. Furthermore, there will be increased landfilling of 

biomass as well as energy-intensive solid waste under this proposal. Not only will this strain 

landfill space, but anaerobic decay of biomass and solid waste produces methane gas, a 

decidedly more potent greenhouse gas than carbon dioxide. Indeed, a strong case can be made 

that US-EPA should be encouraging use of biomass and solid waste as fuel rather than 

landfilling, in order to reduce net greenhouse gas impact. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. Please note that 

greenhouse gas emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: W. Randall Rawson

Commenter Affiliation: American Boiler Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1897.1

Comment Excerpt Number: 4

Comment: If properly designed to reflect the broad range of boiler designs and operational 

conditions, as well as manufacturers’ emission guarantee levels, the Proposed Area Source Rule 

will stimulate the creation of jobs in the boiler and boiler-related equipment industry. To the 

extent that EPA develops an Area Source Rule rulemaking that is achievable in practice for 

boiler owners and operators, the proposal will create solid, well-paid, professional, skilled and 

unskilled manufacturing jobs attendant to the upgrade, optimization and replacement of existing 

boilers around the United States. In addition, service jobs associated with the installation and 

maintenance of these systems, as well as service jobs associated with required tune-ups and 

energy assessments will be created. These jobs will be significant contributions to our local, state 

and national economies – contributions that must not be overlooked or minimized. 

Response: EPA thanks the commenter for their input.

Commenter Name: Kyle Gibeault

Commenter Affiliation: Biomass Thermal Energy Council, BTEC

Document Control Number: EPA-HQ-OAR-2006-0790-1914.1

Comment Excerpt Number: 4
Comment: We, as manufacturers, want to be on record that we support reasonable emission 

limits, but we believe the EPA’s approach in determining the currently proposed limits is flawed 

and will have severely negative impacts on the biomass boiler industry if implemented as 

proposed. Already, the uncertainty caused by the Draft Rule has brought the commercial wood 

boiler market to a virtual standstill until the final rule is determined, the industry, which is 

composed overwhelmingly of small businesses, is suffering severe economic strain due to the 

EPA’s approach to the Area Source Boiler Rule. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Mat Ehrhardt

Commenter Affiliation: California Air Pollution Control Officers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1995.1

Comment Excerpt Number: 4

Comment: Carbon monoxide vs. nitrogen oxides: 

Much of California is designated nonattainment for the National Ambient Air Quality Standards 

(NAAQS) for ozone; however, most of the state is in attainment of the carbon monoxide (CO) 

standard. Therefore permitting practices and emissions-reducing regulations have been 

historically aimed at reducing nitrogen oxides (NOx), an ozone precursor, often at the expense of 

increasing CO. This well-understood CO vs. NOx trade-off has been openly discussed, 

acknowledged, and accepted as a valuable tool in California’s battle against ozone. 

Implementation of a straightforward CO standard as a surrogate for HAPs, without making other 

risk assessment and reduction options available, has the potential to seriously damage the ability 

of California air districts to meet these very important clean-air requirements. As discussed 

below, we believe this damage comes without a corresponding benefit to the public in risk 

reduction. 

For instance, twelve BTE facilities operate in the San Joaquin Valley, a largely rural area with 

some of the most stringent air quality regulations in the nation. These facilities were all subject 

to new source review (NSR) requirements during their initial permitting processes and were all 

found to be meeting Best Available Control Technology (BACT) requirements through the 

implementation of selective non-catalytic reduction (SNCR). Consequently, all twelve have very 

low NOx emissions. In addition, each of these operations has been found, through California’s 

facility-specific “Air Toxics Hot Spots” program, to have an insignificant risk on the residents of 

the San Joaquin Valley. However, five of them would violate the proposed area source CO limit. 

Imposing the proposed CO limits on these facilities would undoubtedly cause increases in NOx, 

either from tuning of the existing equipment to reduce CO or the installation of additional COcontrol combustion equipment, as suggested by EPA. In either case, any increase in NOx is 

unacceptable in many ozone nonattainment air basins in California. Businesses in California’s 
ozone nonattainment areas have spent billions of dollars to meet the state’s very stringent NOx 

control requirements, and any increase in NOx must be countered by additional NOx controls on 

other sources. Unfortunately, there are no stationary NOx sources that can be further controlled 

with existing technologies in many areas. Both the South Coast Air Quality Management District 

and the San Joaquin Valley Air Pollution Control District are “extreme” nonattainment areas for 

federal ozone standards. Both have produced ozone attainment plans that rely on “black-box” 

technologies that have yet to be developed, without which attainment is not possible. Thus, ANY 

increase in NOx from stationary sources in these areas must be carefully considered. 

Similarly, attempts to limit the growth in NOx emissions resulting from the control of CO may 

also result in additional ammonia emissions. SNCR controls NOx via the injection of ammonia, 

and increasing NOx calls for increasing ammonia injection and, inevitably, additional ammonia 

emissions from the stack. This ammonia slip then can cause downwind toxic health risk 

situations that would not otherwise exist, and potentially increases in secondary PM 2.5 creation 

in the form of ammonia sulfates and nitrates. 

In the case of the MACT standards in question, insufficient consideration has been given to the 

potential public health impacts of the inevitable NOx increases and probable ammonia emissions 

increases that would result. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: George M. Israel

Commenter Affiliation: Georgia Chamber of Commerce

Document Control Number: EPA-HQ-OAR-2006-0790-1996.1

Comment Excerpt Number: 5

Comment: The use of biomass as a fuel should be promoted as one of the fundamental elements 

of a smart and effective national environmental and energy strategy. Unfortunately, given the 

costs and technical difficulties of meeting the proposed emissions limitations for new biomass 

boilers, the proposed rule would have exactly the opposite effect – it would erect a significant 

and potentially insurmountable barrier to the construction of new biomass boilers. The proposed 

standards would create a strong disincentive to building biomass boilers. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Douglas I. Greenhaus

Commenter Affiliation: National Automobile Dealers Association
Document Control Number: EPA-HQ-OAR-2006-0790-2047.1

Comment Excerpt Number: 5

Comment: Heaters regulated by Part 279 are used by tens of thousands of facilities, the majority 

of whom are small businesses seeking to avoid the use of and to reduce their dependence on 

fossil fuels, to avoid potential off-site used oil mismanagement (with its attendant environmental 

harms and liabilities), and to save money. The use of these heaters serves as an effective 

incentive to accept do-it-yourselfer oils whose well known potential for mismanagement often 

threatens environmental harm. Modern used oil space heaters are very clean burning with 

emissions even cleaner than those assessed by EPA in conjunction with the State of Vermont in 

their 1994/96 report. 

Response: Classification of used oil pertains to the Identification of Non-Hazardous Materials 

That Are Solid Waste and it is out of scope for this boiler rulemaking.

Commenter Name: Martha E. Rudolph

Commenter Affiliation: Colorado Department of Public Health and Environment

Document Control Number: EPA-HQ-OAR-2006-0790-1979.1

Comment Excerpt Number: 5

Comment: Just as EPA should not overlook the alternative fate of landfill gas and biogas should 

combustion of these fuels be discouraged by the proposed rules, EPA should also not overlook 

possible deleterious environmental effects of new regulations that overly constrain existing and 

emerging technologies that use woody biomass for the production of renewable energy and other 

purposes. As Governor Ritter and the Western Governors’ Association have repeatedly 

communicated, Colorado and the Inter-mountain West face forest health problems of 

monumental proportion. Landscape-scale insect infestations, disease, decades of fire 

suppression, and persistent drought have left Colorado forests in a state of elevated risk for 

catastrophic wildfire. Not only do such intense fires compromise ecological health and watershed 

functionality, they pose risk for people, their communities and public infrastructure located 

within or adjacent to forested land. Importantly, they also are sources of PM, CO2, CO, NOx, 

S02, and other pollutants in amounts and concentrations that dwarf emissions typically 

associated with biomass boilers and other means of controlled combustion of woody biomass. 

Since public financial resources are insufficient to underwrite large scale hazardous fuels 

reduction and forest thinning projects that are critical to reducing these risks and to restoring 

forested landscapes to healthier conditions within generally accepted ranges of natural 

variability, private investment tied to the potentially profitable use of woody biomass is a vital 

public policy objective. Unfortunately, more stringent air quality standards, if not clearly 

warranted from a public health standpoint, could dramatically impact the ability of private 

operators and local communities to use locally harvested materials for heating or small scale 

power generation since the cost of the advanced control technologies are, in many instances, 

more expensive than the entire project. EPA should thus take a very rigorous look at whether, 

and if so in what instances, woody biomass should be included in, or excluded from, these 

proposed rules. 
To further underscore the importance of the role of woody biomass use in managing Colorado’s 

forest health issues, see the attached August 10, 2010 letter from Governor Ritter to the U.S. 

Secretary of Agriculture, Thomas Vilsack. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Martin T. Booher

Commenter Affiliation: Ethan Allen Interiors, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1974.1

Comment Excerpt Number: 5

Comment: EPA should consider the degree to which the rule is in conflict with the national 

policy of promoting distributed generation and the use of biomass as a domestically-sourced 

renewable fuel. 

Response: Please note that greenhouse gas emissions from boilers are not within the scope of 

this rulemaking.

Commenter Name: C.A. Vandersteen

Commenter Affiliation: Louisiana Forestry Association

Document Control Number: EPA-HQ-OAR-2006-0790-2246

Comment Excerpt Number: 6

Comment: LFA strongly supports the use of biomass as a renewable source of energy in an 

effort to reduce our dependence on fossil fuels and emission of greenhouse gases. There are 

numerous forest products industries that have postponed their plans to build biomass-fired 

boilers because of unclear regulations and the possibility of stringent emission requirements that 

will shut down the facilities once constructed. 

As EPA turns to developing final rules, we hope you will carefully consider sustainable 

approaches that protect the environment and public health while fostering economic recovery 

and jobs. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.
Commenter Name: Michael Wagner

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2271

Comment Excerpt Number: 6

Comment: I have several other major concerns regarding the financial and logistical burdens 

that the proposed area source boiler rule would impose on affected facilities for insignificant 

benefits on human health and the environment. I am concerned with the absence of a heat input 

size threshold for applicability of the proposed emission limits to new boilers and the extensive 

stack testing requirements in the rule. The absence of a minimum size exemption for new boilers 

in the rule will create a huge roadblock to the use of locally available biomass as boiler fuel. 

Many small entities (schools, businesses, office buildings, etc.) in rural areas rely on small wood 

fired boilers for heating and/ or steam generation. For example, several small school districts in 

my area have wood fired boilers in the 6 to 8 million BTU per hour range to heat their schools 

for most of the school year. When these boilers reach the end of their useful lives, the affected 

schools would need to switch to natural gas or propane boilers because they would be unable to 

afford the cost of control to meet the proposed limits for new biomass boilers and they could not 

afford the cost of annual stack testing on the boiler. 

The restrictive nature of the emission limits coupled with extensive stack testing requirements in 

the proposed version of 40 C.F.R. Part 63, Subpart JJJJJJ — National Emission Standards for 

Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers at Area Sources 

are disproportionate to the level of air pollution generated by the affected area source facilities. 

My perspective as a state regulator in a rural area is that the proposed rule contains many 

unrealistic and unachievable requirements, discourages the use of locally available biomass as a 

fuel source, would impose significant additional costs on small facilities, and would force many 

small companies to go out of business. As a result, I must recommend that U.S. EPA make 

sweeping changes to the proposed area source boiler rule so that the limitations and requirements 

in the rule better reflect the financial, economic, and operational realities that are faced by the 

small commercial, institutional, and industrial facilities that would be affected by the proposed 

rule. 

Response: New and existing small boilers less than 10 mmBtu/hr do not have applicable limits 

in the final rule but must perform tune-ups, minimizing the burden to boiler operators.

Commenter Name: Darrell Soyars

Commenter Affiliation: Avista Corp.

Document Control Number: EPA-HQ-OAR-2006-0790-1989.1

Comment Excerpt Number: 6

Comment: The Proposed MACT CO Emission Limits for Area Source Biomass Boilers May 

Result in Increased NOx Emissions 

By setting an emission limit for CO at 160 ppm at 7% 02 as a means of reducing organic HAP 

emissions, boiler operators will be forced to focus on reducing CO emissions. This may have the 
unintended consequence of increasing collateral NOx emissions within the bounds of their 

existing permits, requiring a modification to permitted emissions limits, and/or the installation of 

additional emission controls to maintain compliance with permit limits. Industry boiler 

manufacturers typically recommend that the best way to reduce CO in a wood waste stoker 

boiler is the use of an over-fire air system and operations at higher levels of excess air. Both of 

these techniques result in decreased efficiency and increased NOx emissions. 

Response: CO limits for existing biomass boilers are not included in the final rule. 

Commenter Name: Martha E. Rudolph

Commenter Affiliation: Colorado Department of Public Health and Environment

Document Control Number: EPA-HQ-OAR-2006-0790-1979.1

Comment Excerpt Number: 6

Comment: The proposals will hinder the re-use of other byproducts that currently have a viable 

use as a fuel or ingredient (i.e. waste oil - when used at the facility that generated that oil, waste 

tire bead/cord, etc.), as well as hinder the re-use of materials that may have a future use as a fuel 

or ingredient. For example, requiring that the metal wire bead/cord in the tires be removed and 

the tires be shredded prior to the burning of waste tires in cement kilns is both unnecessary and 

wasteful. Cement kilns can easily burn whole tires as fuel — the BTU content of whole tires and 

shredded tires is the same. Perhaps more significant, ASTM 5.2 suggests that cement kilns burn 

waste auto tires at sufficient temperatures to oxidize the wire from tire beadkord. Not only does 

the cement kiln benefit from the energy released from this oxidation, but it benefits from the iron 

oxide created because iron oxide is a critical component in cement chemistry. Removing the 

metal from the tires not only increases processing time and resources, it reduces the incentive for 

beneficial energy recovery, Since whole tires can be burned in cement kilns, the shredding of, 

and metal removal from waste tires provides no benefit and should not be required. 

Response: This comment is out of scope to the Area Source Boiler rule.

Commenter Name: Sheila C. Holman

Commenter Affiliation: North Carolina Department of Environment and Natural Resources

Document Control Number: EPA-HQ-OAR-2006-0790-2222.1

Comment Excerpt Number: 6

Comment: NC DAQ understands that EPA’s interpretation of its normal MACT floor setting 

protocol is to identify the top performing facilities for each regulated HAP individually. In 

general, pollutant control of one HAP is normally not in conflict with control of other HAPs, and 

in some cases there are co-benefits of collecting another HAP while controlling the initial HAP. 

However, for carbon monoxide (CO) and nitrogen oxide (NOx), there is a conflicting means of 

control in terms of temperature, a key driver for each pollutant. For example, combustion zone 

temperature increases that reduce CO emissions generally raise NOx emissions, and conversely, 
lower combustion temperatures reduce NOx emissions but with a tradeoff of raising CO 

emissions. While neither CO nor NOx are HAPs and CO is being proposed as a surrogate for 

POM, both are regulated criteria air pollutants and should be controlled. In actual practice, 

combustion adjustments to minimize both CO and NOx emissions must be balanced with the 

need to maximize boiler efficiency. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: Trent A. Dougherty

Commenter Affiliation: Ohio Environmental Council

Document Control Number: EPA-HQ-OAR-2006-0790-1922.1

Comment Excerpt Number: 7

Comment: With these rules, the EPA can encourage the development of constant, consistent, 

and reliable sustainabilitiy standards for biomass and co-generation proposals. States such as 

Ohio, which are in the early stages of strong renewable energy mandates from Investor Owned 

Utilities, have been inundated with applications for conversions of coal plants, or to allow cofiring with pulversied coal. This is also a product of very broad definition of renewable “biomass 

energy” that includes little guidance to IEUs or Public Utility Commissions as to where and how 

this biomass is generated/harvested in order to truly be a cleaner and renewable energy source. 

CleanEnergy advocates, such as OEC, see renewable energy and clean energy as synonymous –

meaning that a renewable source must also have a carbon dioxide and other criteria pollutant 

emission much greater than its fossil fuel counterpart. Such a concept of clean energy demands a 

full life cycle analysis of the fuel stock for biomass. Important considerations in a life cycle 

analysis include where the biomass comes from, how quickly it is replenished, and how it must 

travel from source to boiler. Each of these factors has a direct and significant impact on the total 

pollution emitted. 

Response: Please note that greenhouse gas emissions from biomass boilers are not within the 

scope of this rulemaking.

Commenter Name: Elizabeth E. Bass

Commenter Affiliation: Tuolumne County

Document Control Number: EPA-HQ-OAR-2006-0790-2250

Comment Excerpt Number: 7

Comment: Tuolumne County as with many counties in California, have very large forested 

areas and wildlands. There are also significant amounts of biomass associated with these lands, 

creating the obvious potential for catastrophic wildfires. A general concern with the adoption of 

this rule is that the required technologies and work practice standards may be so expensive and 

onerous that it may cause existing biomass boilers to stop utilizing biomass waste, and new 
boilers to not be built at all. The loss of these boilers could result in biomass emanating from 

public and private lands being burned in an uncontrolled manner (open burning), rather than in 

properly designed and controlled facilities. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Jay C. Moon

Commenter Affiliation: Mississippi Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-2000

Comment Excerpt Number: 7

Comment: EPA’s focus on individual HAPs has resulted in a failure to recognize the critical 

interplay between emissions controls and emissions of other pollutants. For example, we are 

concerned that the controls necessary to meet the stringent emissions limitations for CO will 

result in increased energy usage, with the concomitant increase in emissions of NOx and other 

pollutants. Further, EPA failed to account for this interrelationship in its economic analysis. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: Scott Manley

Commenter Affiliation: Wisconsin Manufacturers and Commerce

Document Control Number: EPA-HQ-OAR-2006-0790-2258.1

Comment Excerpt Number: 7

Comment: EPA’s focus on individual HAPs has resulted in a failure to recognize the critical 

interplay between emissions controls and emissions of other pollutants. For example, we are 

concerned that the controls necessary to meet the stringent emissions limitations for CO will 

result in increased energy usage, with the concomitant increase in emissions of NOx and other 

pollutants. Further, EPA failed to account for this interrelationship in its economic analysis. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: Mat Ehrhardt

Commenter Affiliation: California Air Pollution Control Officers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1995.1

Comment Excerpt Number: 7
Comment: California needs biomass to energy facilities. 

CAPCOA believes the ability to continue to operate and site BTE projects is critical to 

California’s efforts to address multiple environmental issues. Renewable energy and greenhouse 

gas emissions reduction considerations are creating a strong impetus for such facilities. 

Landfilling of agricultural and forest organic waste is not an option in California, where landfill 

diversion goals are increasing from 50% to 80%. BTEs are a necessary option for diversion of 

waste that has historically been burned in the open: the well-controlled combustion emissions 

from a California BTE reduce emissions by 50% to 90+% when compared to open burning, 

depending on the pollutant. 

In fact, in the San Joaquin Valley, where the near-elimination of open burning is an important 

attainment measure, open burning has already been banned by regulation, to the extent possible. 

The factor that has limited the ban to something less than 100% is the cost-effectiveness of 

burning all waste in a BTE. Regulations that increase the cost of operating a BTE will make it 

more costly for producers, such as farmers and forest land managers, to divert their biomass to a 

BTE, and therefore increasing NOx and other combustion emissions due to the increase in open 

burning. 

California’s biomass boilers utilize biomass materials that are produced from operations 

independent of the fuel value; in fact, significant quantities of biomass wastes are currently open 

burned for disposal where the existing economics of alternative uses is not favorable. These 

economics would become even less favorable if existing boilers were to shutdown as a result of 

the proposed MACT rule. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Robert G. Hedden

Commenter Affiliation: Oilheat Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-2249

Comment Excerpt Number: 7

Comment: The area source standards proposed for boilers include different standards for 

existing versus new boilers. As opposed to major sources, which establishes separate minimum 

thresholds for new and existing sources, the Clean Air Act standards required for area sources 

does not have a mandate to distinguish between new and existing sources: 

(5) Alternative standard for area sources 

With respect only to categories and subcategories of area sources listed pursuant to subsection 

(c) of this section, the Administrator may, in lieu of the authorities provided in paragraph (2) and 

subsection (f) of this 
section, elect to promulgate standards or requirements applicable to sources in such categories or 

subcategories which provide for the use of generally available control technologies or 

management practices by such 

sources to reduce emissions of hazardous air pollutants. {Emphasis Added) 

We believe that setting a much more stringent emissions standard for new or reconstructed 

boilers will discourage the use and introduction of more efficient and less polluting boilers and 

encourage "band aid" fixes to avoid the more restrictive standards. The effect will be to increase, 

not decrease, pollution. 

Response: See the preamble for discussion on MACT versus GACT standards.

Commenter Name: A. Steven Young

Commenter Affiliation: Association of Independent Corrugated Converters

Document Control Number: EPA-HQ-OAR-2006-0790-1994.1

Comment Excerpt Number: 8

Comment: EPA’s focus on individual HAPs has resulted in a failure to recognize the critical 

interplay between emissions controls and emissions of other pollutants. For example, we are 

concerned that the controls necessary to meet the stringent emissions limitations for CO will 

result in increased energy usage, with the concomitant increase in emissions of NOx and other 

pollutants. Further, EPA failed to account for this interrelationship in its economic analysis. 

Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Commenter Name: Martin Lunde

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2065.1

Comment Excerpt Number: 9

Comment: Disastrous effect on rural communities 

Response: The final rule includes revised MACT and GACT standards. With the changes it will 

reduce the burden for facilities to comply and should not hinder rural communities.

Commenter Name: Charlie Cary

Commenter Affiliation: Biomass Combustion Systems, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1990.1

Comment Excerpt Number: 14
Comment: Encouraging increased dependence on fossil fuels for thermal needs impedes federal, 

state and local renewable energy and greenhouse gas reduction goals. Forest products industries 

and other businesses alike rely on renewable, low cost wood residue for heating. Restricting 

biomass thermal applications through unreasonably expensive and compliance measures of 

questionable value will serve the counterproductive purpose of encouraging nonrenewable fossil 

fuels use and reduce local self-reliance. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule. Please note that greenhouse gas 

emissions from biomass boilers are not within the scope of this rulemaking.

Commenter Name: Christy Sammon

Commenter Affiliation: Southeastern Lumber Manufacturers Association

Document Control Number: EPA-HQ-OAR-2006-0790-1954.1

Comment Excerpt Number: 14

Comment: The rules as proposed create a disincentive to the combustion of biomass and an 

incentive to burn natural gas. 

The wood products industry uses a higher percentage of renewable energy than any other 

industry. The bark, sawdust, and other byproducts generated in the manufacturing process 

typically provide enough fuel to fire the boilers and meet the steam demands of the facility. The 

combustion of these biomass fuels is greenhouse-gas-neutral, and if these materials are not 

burned for fuel they will be hauled to a landfill where they will anaerobically decompose to 

methane gas which has 21 times the greenhouse gas impact of CO2. Substituting a traditional fuel 

such as natural gas for this use will increase operating costs by as much as 30%, and if the entire 

wood products industry changed to natural gas, it would consume a significant percentage of the 

total U.S. natural gas production. 

The proposed rule concludes that no new biomass boilers will ever be constructed at major 

sources in the United States as a result of the stringency of the rules. Given the government’s 

push for the use of renewable energy, this outcome would be absurd. A greenhouse-gas-neutral 

fuel would be turned into a waste which would degrade into methane gas creating 21 times the 

global warming potential when compared to its combustion as fuel. Solar and wind are not 

reliable renewable energy sources in the southeastern United States, so biomass provides the 

only viable option for renewable energy in this part of the country. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. With this reduced 

burden it is not anticipated that facilities would switch to natural gas as a compliance option. See 

the preamble for further discussion on the economic impacts of the rule. Please note that 

greenhouse gas emissions from biomass boilers are not within the scope of this rulemaking.
Commenter Name: Charlie Cary

Commenter Affiliation: Biomass Combustion Systems, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1990.1

Comment Excerpt Number: 15

Comment: American needs more, not less, wood energy. Since hand fired wood combustion 

systems are less efficient than automated ones, the proposed regulations would eliminate the 

opportunity for hand firing in the commercial, industrial and institutional markets. If these 

standards are adopted, users of wood fuel in these markets will be required to use chips or 

pellets. Since chipper and pelletizers are not commonplace, these regulations will eliminate the 

opportunity for people to harvest their own fuel. A tree on someone’s property will no longer be 

a fuel without the added cost of chipping or pelletizing. Wood brings energy security and 

independence and deserves a fairer hearing than it is currently getting in these proposed 

regulations. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Kyle Gibeault

Commenter Affiliation: Biomass Thermal Energy Council, BTEC

Document Control Number: EPA-HQ-OAR-2006-0790-1914.1

Comment Excerpt Number: 15

Comment: Encouraging increased dependence on fossil fuels for thermal needs impedes federal, 

state and local renewable energy and greenhouse gas reduction goals. Forest products industries 

and other businesses alike rely on renewable, low cost wood residue for heating. Restricting 

biomass thermal applications through unreasonably expensive and compliance measures of 

questionable value will serve the counterproductive purpose of encouraging nonrenewable fossil 

fuels use and reduce local self-reliance. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Steven A. Brink

Commenter Affiliation: California Forestry Association

Document Control Number: EPA-HQ-OAR-2006-0790-2026.1

Comment Excerpt Number: 16
Comment: Without substantial adjustment to the proposed rules, the biomass powerplant 

industry cannot comply and will cause a shift of heat and power generation back toward 

nonrenewable fossil fuels destroying the opportunity for States to have a strong component of 

biomass as part of their renewable portfolio. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Charlie Cary

Commenter Affiliation: Biomass Combustion Systems, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1990.1

Comment Excerpt Number: 16

Comment: America needs to get off its dependence on imported fossil fuel. To this end the 

Federal government has invested billions of dollars to expand the use of renewable, low/no 

carbon fuel, Biomass fuel is more dependable than wind or solar and has the added benefit of a 

more beneficial impact on the local economy. The cost of all air emissions needs to be balanced 

by the impacts created by those emissions. Every alternative energy has its NIMBY’s who stand 

in the way of increased market penetration. As someone who is convinced that renewable wood 

fuel will help increase the longevity of the resources on our “spaceship earth” while 

strengthening our communities by making them more energy independent, I see this draconian 

proposed MACT standard as lacking the balance this Country’s energy policy so desperately 

needs. Are the marginal environmental benefits of these regulations really worth the cost? 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Lee B. Zeugin

Commenter Affiliation: Utility Air Regulatory Group

Document Control Number: EPA-HQ-OAR-2006-0790-1957.1

Comment Excerpt Number: 18

Comment: The combustion of biomass will become increasingly important to utilities as 

renewable energy standards are adopted by more states and are possibly applied to all states as a 

result of federal mandates. The combustion of biomass has the beneficial effect of conserving 

natural resources. Unfortunately, the stringent MACT limits EPA has proposed for industrial 

boilers burning biomass will greatly inhibit the combustion of biomass in the future. 
Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Martin Lunde

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2065.1

Comment Excerpt Number: 20

Comment: If this proposal goes through as written, it will effectively eliminate all small 

commercial, industrial and farm related wood heating equipment. Moreover, it will devastate the 

industry and force the rural user onto fossil fuels at a significantly higher yearly operating cost. 

Response: All biomass boilers with heat input capacity less than 10 mmBtu/hr do not have limits 

but must conduct tune-ups, the revisions will reduce the burden for facilities to comply with the 

final rule.

Commenter Name: Arthur Blazer

Commenter Affiliation: Council of Western State Foresters

Document Control Number: EPA-HQ-OAR-2006-0790-1962.1

Comment Excerpt Number: 21

Comment: Comparing Table 2 to Table 5 [SEE PDF FOR TABLES] above demonstrates that 

the proposed EPA standard is significantly lower than current European standards. Significant 

research and development funding as well as support for biomass energy implementation have 

resulted in AWC systems that can perform to these standards. The implementation of 

significantly more rigorous standards in the US without support of technological improvement 

will have substantial impacts on both the biomass boiler industry and the current and potential 

users of biomass systems. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. 

Commenter Name: Martin T. Booher

Commenter Affiliation: Ethan Allen Interiors, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1974.1

Comment Excerpt Number: 22

Comment: As the EPA has acknowledged, Congress has enacted a number of programs in 

recent years evidencing the strong national policy in support of the development and use of 

renewable sources of energy, including biomass and biomass-derived fuels. Solid Waste Rule, 75 
Fed. Reg. at 31,887 (citing Energy Independence and Security Act of 2007 (“EISA”) (Pub. L. 

110–140)). Among other federal incentives, tax credits are available for investment in and 

production of biomass-based energy. 26 U.S.C. §§ 48, 45. In addition, nearly every State also 

promotes the development of renewables, including the use of biomass and biomass-based fuels. 

See generally DSIRE: Database of State Incentives for Renewables & Efficiency, at 

http://www.dsireusa.org. This broad policy support for the increased use of alternative fuels 

stems in part from the recognized need to diversify domestic fuels and offset imports from 

abroad, increasing national security through energy independence. 

A number of other federal agencies have policies or programs to specifically incentivize the use 

of biomass. For example, the National Renewable Energy Laboratory conducts extensive 

biomass research in an effort to develop biomass-based fuels that will reduce national 

dependence on foreign oil, improve air quality and support rural economies. The U.S. 

Department of Energy (“DOE”) and U.S. Department of Agriculture (“USDA”) also have 

expressed a strong commitment to expanding the use of biomass as a source of energy. DOE & 

USDA, Biomass as Feedstock for a Bioenergy and Bioproducts Industry: The Technical 

Feasibility of a Billion-Ton Annual Supply (Apr. 2005); see also Memorandum of 

Understanding On Policy Principles for Woody Biomass Utilization (June 2003) (signed by the 

DOE, USDA and DOI) (demonstrating interdepartmental commitment to develop and apply 

consistent and complementary policies and procedures to encourage use of woody biomass 

byproducts). The USDA’s Biomass Crop Assistance Program (“BCAP”) provides financial 

assistance to biomass producers for use at designated facilities as heat, power, biobased products 

or biofuels. 75 Fed. Reg. 6264 (Feb. 8, 2010) (proposed rule). 

At the very least, and as recognized by the EPA, energy from biomass, including wood and other 

biogenic materials, is generally preferable to fossil fuels. 75 Fed. Reg. at 31,888. Indeed, 

biomass will be a critical component of the fuel mix as the United States transitions 

away from use of fossil fuels. Ethan Allen believes that the Area Source Boiler MACT, if 

finalized as proposed, will undermine these national policies. 

Response: EPA is charged with regulating industrial, commercial, and institutional boilers and 

process heaters and many industrial boilers use biomass as a fuel. Consequently, we must 

regulate these units under this rule. We believe that the final rule should not discourage the 

beneficial use of renewable energy sources such as biomass.

Commenter Name: Martin T. Booher

Commenter Affiliation: Ethan Allen Interiors, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1974.1

Comment Excerpt Number: 24

Comment: Ethan Allen also is concerned that EPA’s rules will have the effect of promoting the 

increased use of fossil fuels, particularly natural gas. The capital costs required to control carbon 

monoxide emissions from wood- and oil-fired boilers, the uncertainty over whether materials 

would be considered solid waste and the increased cost of sourcing fuel from traditional fuel 
suppliers will result in industrial and commercial boilers being shut down or converted so that 

they can fire natural gas. The subsequent decrease in the demand for biomass likely would cause 

prices to drop, undermining the pricing supports needed to sustain future investment and growth 

in biomass-derived fuels development. This also will have a negative impact on the development 

of renewable distributed generation, which will have widespread consequences for grid 

reliability in rural and urban communities. 

In light of the foregoing, Ethan Allen believes that EPA’s proposed rules will work in concert to 

foster a result that is inconsistent with the current national policy of promoting the use of 

renewable fuels such as biomass. It is imperative that EPA further consider the potential effect 

that the proposed rules will have on the use of biomass and other biogenic fuels, including the 

likelihood that it will encourage the increased use of fossil fuels such as natural gas. 

Response: The final rule includes revised MACT and GACT standards, minimizing the burden 

on facilities. As such, it is not anticipated that facilities would switch to natural gas as a 

compliance option.

Commenter Name: Kyle Gibeault

Commenter Affiliation: Biomass Thermal Energy Council, BTEC

Document Control Number: EPA-HQ-OAR-2006-0790-1914.1

Comment Excerpt Number: 24

Comment: Therefore, the limits will also impact the nation’s goals to depend more on 

alternative energy and less on fossil fuels. Most of Maine is rural with many trees and recently a 

depressed forest industry. Using wood fuel will help the local economy and decrease the use of 

fossil fuels. 

Response: Limits for existing biomass boilers are not included in the final rule, and new boilers 

must only meet a GACT PM limit thus minimizing the burden to facilities. See the preamble for 

further discussion on the economic impacts of the rule.

Commenter Name: Martin T. Booher

Commenter Affiliation: Ethan Allen Interiors, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1974.1

Comment Excerpt Number: 26

Comment: Aside from the potential impairment of national energy policy, Ethan Allen is 

concerned that EPA’s proposed rules also will impact landfill capacities. As discussed above, by 

reducing the volume of biomass and non-hazardous secondary materials consumed in 

commercial and industrial boilers on a national scale, the proposed rules will have the 

unintended effect of directing that same volume of material to landfills. Before finalizing the 

proposed rules, EPA should further consider the potential impact on landfills, including both the 
effect on landfill capacities and the potential emissions that may be produced as the landfilled 

materials decompose. 

Response: The EPA thanks the commenter for their input, but the EPA did not have ample time 

to analyze the potential impacts the rule may have on landfills. However, limits for existing 

biomass boilers are not included in the final rule, and new boilers must only meet a GACT PM 

limit thus minimizing the burden to facilities.

Commenter Name: Kyle Gibeault

Commenter Affiliation: Biomass Thermal Energy Council, BTEC

Document Control Number: EPA-HQ-OAR-2006-0790-1914.1

Comment Excerpt Number: 27

Comment: There are different means of controlling particulate matter in the gas stream of a 

wood fired boiler. The most simple and basic of these is to use a Multiple cyclone in order to 

take the particulate out of the gas stream trough the use of centrifugal force. This method is very 

cost effective and eliminates approximately 75% of the particulate in the gas stream. This piece 

of equipment alone will not be sufficient to reach the new proposed limits. An Electrostatic 

Precipitator or a bag house has to be added to the energy system in order to bring the particulate 

even further down. Adding these types of filtering equipment will add significant cost to the 

projects. In most cases, especially in smaller applications, it can greatly compromise project 

economics thus hindering North American efforts to transition from fossil fuels to greener 

heating alternatives. A limit of 0.25 lbs/MMBTU would be more reasonable and achievable with 

the multiple cyclone units alone, especially when dealing with area source sized projects with 

limited funding. 

Response: See the preamble for discussion on the revised PM GACT limits.

Commenter Name: Myra C. Reece

Commenter Affiliation: South Carolina Department of Health and Environmental Control

Document Control Number: EPA-HQ-OAR-2006-0790-1859.1

Comment Excerpt Number: 28

Comment: We believe that the EPA should take into consideration how this rule could affect the 

emissions of non-HAP pollutants and whether the rule produces the greatest overall air quality 

and public health improvement. For example, the Area Source Boiler Rule requirements for 

carbon monoxide (CO) may cause increases in greenhouse gas and nitrogen oxide (NOx) 

emissions. The EPA’s current approach to regulating air emissions does not prioritize pollutants 

for comprehensive air quality management and in some cases may exacerbate air quality issues. 
Response: The final rule only includes CO limits for coal boilers; see the preamble for 

discussion on CO limits.

Health Benefits

Commenter Name: Charles Niebling

Commenter Affiliation: New England Wood Pellet

Document Control Number: EPA-HQ-OAR-2006-0790-0836

Comment Excerpt Number: 7

Comment: EPA’s model for calculating health costs overstates the health impacts of emissions 

in rural areas with lower population density (which is the location of most biomass boilers), 

because the model and data were developed based on densely populated urban areas [See 

submittal for Reference 3]. This bias causes the EPA impact model to overvalue emissions 

reductions from rural biomass boilers in its cost-benefit analysis. 

Response: The methodology used to estimate the health benefits associated with the proposed 

rule presumes the existing geographic distribution of these emission sources, which includes 

both urban and rural sources. Specifically, EPA estimated the national average health benefits 

associated with reducing one ton of a PM2.5 precursor emission (such as direct PM2.5 or SO2) 

from the existing sources. Because available data show that a large majority of area source 

boilers occur either in urban areas (67%) or in commercial/institutional applications in close 

proximity to susceptible populations (99%), using national average estimates probably 

underestimate the magnitude of the associated health benefits. 

Location-specific benefits estimates depend on many factors, including population density, air 

pollution mixtures, meteorology, exposure patterns, baseline health incidence rates, and other 

local factors. At a national level, EPA has high confidence in the magnitude of total monetized 

benefits, but the benefits for specific locations may vary.

Commenter Name: Arlington Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0396

Comment Excerpt Number: 26

Comment: These boilers and incinerators produce particulate matter -– tiny bits of solids and 

aerosols formed by the sulfur dioxide and nitrogen oxide emissions. Particulate matter is the 

most dangerous of the widespread air pollutants. Particulate matter triggers asthma attacks, heart 

attacks, and strokes, among other damage, but most critically, particulate matter kills. Breathing 

find particles increases the risk that children with asthma and older adults with chronic 
obstructive pulmonary disease or cardiovascular disease will end up in the emergency room or 

the hospital. 

These units also spread mercury and lead, hazardous metals that can harm children’s brains, 

hurting their IQ and limiting their ability to learn and to remember what they have learned. Many 

of the other toxic pollutants spewing from these sources cause cancer, including formaldehyde, 

dioxin, cadmium, furans, and hydrochloric acid. Because these devices are so numerous and so 

widespread, their toxic pollution infiltrates communities across the nation. Their harm to health 

settles heaviest on those who live near them, communities that are often poorer, less well 

educated, and minorities. 

Study after study finds that pollution harms these folks far more than it does others. Cleaning up 

these boilers and incinerators will save lives. EPA estimates that between 2,000 and 5,000 lives 

will be saved every year because of the changes put in place by these requirements beginning in 

2013. 

But that’s only part of the benefits. Having less pollution to breathe should benefit –- should 

prevent over 3,000 non-fatal heart attacks, avoid over 35,000 cases of worsened asthma, and 

eliminate nearly 3,400 hospital and emergency room visits each year –- each year. 

Response: EPA agrees that exposure to fine particulates and toxic air pollutants is associated 

with severe health effects and reducing exposure to these pollutants is associated with substantial 

public health benefits.

Commenter Name: Arlington Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0396

Comment Excerpt Number: 29

Comment: We urge EPA to not allow industry to burn waste in uncontrolled and unmonitored 

facilities. We see today powerful and vocal industry lobbies here opposing these rules. We’re not

that powerful and, certainly today, not that vocal; but we represent children with asthma and the 

communities next door to these facilities. We speak for the adults on oxygen who cannot be here 

to say that we must have air that does not make it harder for them to breathe. We speak for those 

whose lives are threatened by the pollution spewing from these boilers and incinerators. All of us 

deserve to breathe clean air. We are counting on EPA to deliver cleaner, healthier air in every 

community. Too many people have suffered too long. Now is the time to require all of these 

plants to clean up. 

Response: EPA agrees that exposure to fine particulates and toxic air pollutants is associated 

with severe health effects and reducing exposure to these pollutants is associated with substantial 

public health benefits.
Commenter Name: Los Angeles Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0397

Comment Excerpt Number: 56

Comment: We object to the U.S. EPA using only health risk assessments as its only measure of 

public health impacts. HRAs are not based on any public health baseline from a scientifically 

conducted health survey of impacted environmental justice communities. HRAs do not identify 

all public health impacts by illness category; do not identify how many people are afflicted, and 

cannot tell you if cancer is increasing or decreasing. 

We request the U.S. EPA include a health impact assessment to provide information not 

provided in a health impact assessment. EPA also failed to include an assessment of individual 

hot spot EJ communities. Wilmington is one of those communities that should have been looked 

at more thoroughly to identify what the standard in an appropriate measure to protect a hot spot 

EJ community, and we ask that you do that. 

Your standard identifies specific chemicals that we feel is not adequate. There are over 100 plus 

toxic HAP chemicals that have been identified and we want a standard to be applied to every 

single one of them. You have stated in there that you have identified or called a category of a 

surrogate or CO, for example. Well, you can’t compare a thousand pounds of benzene to a 

thousand pounds of CO by average in. 

You quote in there -- as one of my final things -- that you would be avoiding 110 to 300 

premature deaths in 2003. Obviously, the staff did not look at our figures in the harbor. We 

average that number of deaths every single day in the L.A. harbor community. So before quoting 

a number you need to look at the actual data, which you’re going to get from the Los Angeles 

County Department of Health and the California Department of Health. And those will provide 

you reliable numbers. 

[Panelist question] With regard to the health assessments you will be describing, will you have 

some further description as to what those assessments should be considering? 

MR. MARQUEZ: Yes. There is a provided consulting firm, Health Impact Partners, that 

conducts these. And U.C.L.A. and U.C. Berkeley both have institutes or departments within the 

universities that also specialize in health assessments. 

So that you do know, U.S. EPA Region 9 last year attended a class and sent about six to seven 

members. As well as L.A. County Department of Health sent about four to five staff members, in 

addition to about of us E.J. organizations and attended a class here in Los Angeles. Actually, it 

was about two years ago. And in all of the public comments that have been made regarding that 

course and movement, they have recommended a health impact assessment to perform in 

addition to an HRA. 
Response: A agrees that it is informative to estimate how many fewer people would experience 

air pollution-related health effects as a result of this regulation. The regulatory impact analysis 

conducted as part of the rule includes a health impact assessment, which quantifies a variety of 

health effects avoided by the rule, including mortality, hospital visits, asthma attacks, school loss 

days, among others at the national level. It is important to note that air pollution is only one of 

many contributing causes of mortality and morbidity.

Commenter Name: Arlington Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0396

Comment Excerpt Number: 67

Comment: I wanted to come as a private citizen because, I mean, I live in D.C. When you look 

around, we are impacted by petrochemical industries and chemical industries not because they’re 

right here in our back yard but because they’re basically upwind and because we’re downwind, 

we’re failing at our air toxics tests. 

There are reasons why basically our lungs are being poisoned and they’re not because of 

emissions that are happening right here in our back yards. And a lot of it are coming from boilers 

and incinerators that aren’t being regulated with off-the-shelf technology. And for us, it’s just 

really important to see communities protected. 

I’m a person who’s of childbearing age. I am probably going to be having kids in the next five 

years. I have no idea what pollutants are going into my lungs, what those pollutants are going to 

have on my reproductive system, what they are going to have on my potential children down the 

line. And as I get older, it just gets more distressing that the EPA basically has the authority to 

move forward with promulgating protective rules, yet we’re seeing things like the definition of 

solid waste that genuinely are not protective of people. 

Response: EPA agrees that exposure to fine particulates and toxic air pollutants is associated 

with severe health effects and reducing exposure to these pollutants is associated with substantial 

public health benefits.

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 53

Comment: I think it can go without saying that often these things can go past the 

regulations that not everyone obeys the regulations; they do what they can to protect the bottom 

dollar, and in the long run, a healthy society will do more to -- without missing workdays or sick 

days -- sick days will do more for the economy than being allowed to burn more 

substances close to home. 
Response: EPA agrees that exposure to fine particulates and toxic air pollutants is associated 

with severe health effects and reducing exposure to these pollutants is associated with substantial 

public health benefits.

Commenter Name: Michael Wagner

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2271

Comment Excerpt Number: 5

Comment: The preamble of the proposed rule makes several references to a group of 30 "urban 

air toxics" that U.S. EPA is using as justification for some of the emission limits in the proposed 

rule. Most area sources in Wisconsin with biomass (wood) boilers are located in rural areas with 

limited population so concerns about "urban air toxics" are irrelevant. The amount of air 

pollution generated by biomass (wood) boilers at area sources in Wisconsin is significantly less 

than the amount of air pollution generated from open burning, residential wood stoves, and 

outdoor wood burning units. As a result, stringent regulation of area source boilers will have 

little if any impact on the air quality in Wisconsin other than forcing some companies to go out 

of business. 

Response: See responses to Document Control Number: EPA-HQ-OAR-2006-0790-0397, 

Comment Excerpt Number: 42, Document Control Number: EPA-HQ-OAR-2006-0790-0609, 

Comment Excerpt Number: 1, Document Control Number: EPA-HQ-OAR-2006-0790-0985, 

Comment Excerpt Number: 58, and Document Control Number: EPA-HQ-OAR-2006-0790-

0836, Comment Excerpt Number: 10.

Commenter Name: Michael Hutcheson

Commenter Affiliation: Ameren Corp.

Document Control Number: EPA-HQ-OAR-2006-0790-2012.1

Comment Excerpt Number: 13

Comment: The use of the Fann et al. (2009) methodology to estimate reduction in ambient 

levels of PM2.5 is improper. The Fann et al. methodology has not undergone a rigorous peer 

review as should be required for any methodology utilized by US EPA for estimating the effects 

of a regulatory scheme on the health of the US population. The Fann, et al. methodology uses a 

flawed emission inventory (US EPA’s 2001 National Emissions Inventory) and projects that 

inventory out to 2015. The 2001 inventory has been replaced with a newer inventory which 

should have been utilized. Because Fann does not include the revised inventory in the open 

sourced study, it is impossible to see how Fann projected emissions out to 2015. He only makes 

a vague statement that the projected inventory includes several federal regulatory programs such 

as CAIR. 
Fann utilizes the CMAQ version 4.4 regional air quality model to estimate PM2.5 ambient air 

quality levels associated with various regulatory schemes. The CMAQ version 4.4 model has 

several flaws which render it’s use to estimate PM2.5 levels inappropriate without a comparison 

to actual PM2.5 levels in modeled areas. This version of CMAQ significantly overestimates 

PM2.5 levels when compared to actual measured PM2.5 levels. Because CMAQ overestimates 

PM2.5, several updates to this model have been made to correct these known deficiencies. 

Despite these known problems, Fann et al. make no effort to correct for this overestimation or 

make any comparison to actual measured PM2.5 levels. Consequently, it can be presumed that 

the model as used by Fann, overestimates PM2.5 ambient air quality levels resulting from each 

ton of direct PM2.5 and PM2.5 precursors. This will necessarily result in an overestimation of 

the change in PM2.5 level resulting from the reduction of each ton of 

direct PM2.5 and PM2.5 precursors. Similarly, by overestimating the change in PM2.5 ambient 

air quality levels, the Fann et al. methodology also overestimates the benefits of the associated 

reductions. 

US EPA should not utilize outdated versions of regional air quality models which over estimate 

impacts when analyzing the economic impacts associated with the proposed regulations. US 

EPA should revise this analysis to properly account for the deficiencies of the Fann methodology 

and the associated inventory and regional air quality model. 

Response: Thank you for the comment.

Commenter Name: N/A

Commenter Affiliation: Mercatus Center, George Mason University

Document Control Number: EPA-HQ-OAR-2006-0790-1837.1

Comment Excerpt Number: 1

Comment: To calculate the expected benefits of reducing emissions of the fine-grained 

particulate matter known as PM2.5, EPA uses a “benefit per ton” approach, meaning the agency 

assumes that each ton of pollution has the same health effects. The best practice in regulatory 

analysis is to use marginal benefit analysis: each ton of pollution is treated separately.[ 2 See 

OMB Circular A-4 (2003), available at 

http://www.whitehouse.gov/sites/default/files/omb/assets/omb/circulars/a004/a-4.pdf. 

] For many pollutants and other hazardous substances, the health effects from a small amount of 

exposure are not proportional to those from a larger exposure.[ See e.g. Werner Lutz, “Doseresponse relationship and low dose extrapolation in chemical carcinogenesis,” Carcinogenesis 

11, no. 8 (1990): 1243–1247.] In some cases, a small amount of exposure have the reverse effect 

of a larger exposure.[ See e.g. Edward Calabrese and Linda Baldwin, “U-shaped dose—

responses in biology, toxicology, and public health,” Annual Review of Public Health 22 

(2001):15 –33.] 

EPA cites evidence that there is no safe threshold for PM2.5 (i.e. exposure to any amount has 

negative health effects) and that the health effects of exposure to PM2.5 are directly proportional 

to the amount of exposure. These studies did not prove a linear relationship exists but found that 

there was insufficient data to disprove either the assumption of a linear relationship or the 
nonexistence of a threshold. Thus, many relationships which were not tested may be equally 

valid. Only one study looked at whether other relationships might better explain the health 

effects over different levels of exposure—finding a non-linear relationship. However, national 

PM2.5 levels have only been measured since 1999 and most counties have levels so low that 

measurement is not possible.[ Tom Walton, Regulatory Impact Analysis: National Emission 

Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and 

Process Heaters Draft Report, EPA (2010).] 

Response: Based on the conclusions of EPA's Integrated Science Assessment on Particulate 

Matter (U.S. EPA, 2009), long term exposure to fine particles has a causal link to premature 

mortality, even at low ambient levels. In addition, exposure to fine particles is associated with 

cardiovascular and respiratory health effects. The methodology for estimating the health benefits 

associated with reducing PM2.5 and precursor emissions is based on peer-reviewed publications 

(see Fann, Fulcher, and Hubbell, 2009). 

In 2006, EPA solicited expert opinions on the relationship between PM2.5 exposure and 

premature mortality, which concluded that the benefits of reducing exposure to PM2.5 is 

substantial. 

The weight of scientific evidence strongly supports modeling PM-related mortality and 

morbidity by using concentration-response functions that do not incorporate an assumed 

threshold. In 2009, the final Integrated Science Assessment for Particulate Matter indicated that 

“[o]verall, the studies evaluated further support the use of a no-threshold log-linear model...” 

(U.S. EPA, 2009). In 2010, the Health Effects Subcommittee of the Science Advisory Board 

“fully supports EPA’s decision to use a no-threshold model to estimate mortality reductions. This 

decision is supported by the data, which are quite consistent in showing effects down to the 

lowest measured levels. Analyses of cohorts using data from more recent years, during which 

time PM concentrations have fallen, continue to report strong associations with mortality. 

Therefore, there is no evidence to support a truncation of the CRF” (EPA-SAB-COUNCIL- 10-

001). Our approach to estimating PM-related health impacts is consistent with the key findings in 

these reports. In addition, our approach is consistent with the on-going PM NAAQS review. 

In conjunction with the commenter’s concern and consistent with recent scientific advice, we 

have replaced the previous threshold sensitivity analysis with a new “lowest measured level” 

(LML) assessment. While an LML assessment provides some insight into the level of uncertainty 

in the estimated PM mortality benefits, EPA does not view the LML as a threshold and continues 

to quantify the PM-related mortality impacts using the full range of modeled air quality 

concentrations. 

Commenter Name: N/A

Commenter Affiliation: Mercatus Center, George Mason University

Document Control Number: EPA-HQ-OAR-2006-0790-1837.1

Comment Excerpt Number: 2
Comment: To estimate total health effects, EPA used mortality data from two studies looking at 

the effects of PM2.5 on urban populations.[ Francine Laden, Joel Schwartz, Frank E. Speizer, 

and Douglas W. Dockery, “Reduction in Fine Particulate Air Pollution and Mortality: Extended 

Follow-up of the Harvard Six Cities Study,” American Journal Of Respiratory And Critical Care 

Medicine 173 (2006); C. Arden Pope III, Richard T. Burnett, and Michael J. Thun et al. “Lung 

Cancer, Cardiopulmonary Mortality, and Long-term Exposure to Fine Particulate Air Pollution,” 

Journal of the American Medical Association 287, no.9 (2002):1132–1141.] The first was 

published in the Journal of the American Medical Association by a team led by Arden Pope, 

using data from the American Cancer Association. The second was published in the American 

Journal of Respiratory and Critical Care Medicine by a team led by Francine Laden and funded 

by EPA. There are substantial differences between the results of the two studies: premature 

mortality would be reduced by the proposed rule from 300 incidences according to Laden’s study 

but by only 110 incidences according to Pope’s study. In addition to substantial differences 

between the two studies, there were also substantial differences within each study for different 

cities. An earlier study by an EPA team which devised the methodology used to calculate 

benefits used for this rule, found that a one ton reduction in area source carbon (using Laden’s 

methodology) would generate $2.5 million in benefits in Phoenix but only $280,000 in Denver. 

The study’s authors hypothesize that the differences result not only from different population 

density but also from environmental factors such as wind and temperature, and from differences 

in the underlying health of residents of different regions. 

EPA’s method only identifies costs for nine separate cities and merges the remainder of the 

country into a single national region. For the national region, benefits per ton from reducing area 

source carbon were estimated at $720,000, more than small urban areas like Salt Lake City 

($140,000) but also more than Atlanta ($610,000), Chicago ($510,000), and New York and 

Philadelphia ($570,000).[ Neal Fann, Charles M. Fulcher and Bryan J. Hubbell, “The influence 

of location, source, and emission type in estimates of the human health benefits of reducing a ton 

of air pollution,” Air Quality, Atmosphere and Health 2 (2009):169–176.] This figure is almost 

certainly high for rural areas with low populations, but this may be masked in the averages by 

many larger urban areas which are included in the national region. The team who originally 

devised the methodology also cautioned against attempting to apply their research to urban areas 

other than those already studied.[Id.] 

The original EPA study identifies several factors that may explain large differences in the 

benefits from reducing PM2.5. First, even among fine-grained particulate matter, there are 

different types which have different effects on mortality. Reducing area source carbon by one ton 

in Atlanta creates $670,000 while removing a ton of volatile organic compounds (VOC) creates 

only $1,200 in benefits. Reducing a ton of area source ammonia is harmful, creating a negative 

benefit (or social cost) of $4,100 .[Id.] 

Different sources may emit the same type of particulate matter but differences in the height of 

the exhaust stack or the velocity at which particles leave the stack may affect how many people 

are exposed.[Id.] For example, reducing area source carbon creates greater benefits than reducing 

mobile source carbon.[Id.] Additionally, different locations have different mortality rates, which 

the authors theorize may be due to different population densities and the initial health of people 

living in different locations. 
EPA combines all the regional benefit per ton statistics to create an average benefit per ton for 

the entire country for each regulated source. This would be the benefit per ton if emissions levels 

fell equally across the country. The analysis does not consider how benefits would vary if 

emissions are not reduced equally across the country, or how different regulations might 

differently affect different regions. The proposed rule indicates that EPA preferred more 

stringent regulations if the source was more likely to be found in urban areas, but because the 

economic analysis uses a national benefit per ton and only addresses the rule as a whole, the 

agency has no information to indicate whether this decision improved the quality of the 

rulemaking. As the evidence presented by EPA demonstrates, it not only matters whether a 

source is urban but in which urban area it is sited. By looking at benefits by region and 

separating out individual regulatory actions the analysis could show how each alternative affects 

each region, thus guiding policy makers to the best outcome rather than justifying the regulation 

after the fact. 

The analysis should also address any uncertainty over where reductions are likely to occur. The 

agency addresses uncertainty over how much benefits a reduction in emissions would create by 

reporting benefits using the mortality estimates from both studies. However, EPA does not 

estimate any uncertainty about the location or type of pollution to be reduced. Overall, the 

agency likely underestimates uncertainty surrounding benefits. This does not necessarily mean 

the agency has overestimated or underestimated benefits, but accurately measuring uncertainty 

can help policy makers improve the quality of decision making. For example, EPA might 

consider phasing in new regulations more gradually (starting in areas where net benefits are 

likely to be highest or are most certain) and measure how accurate initial estimates were. This 

information can then inform policy going forward. 

Calculating the additional benefits and costs from each ton of each pollutant reduced also helps 

the agency to improve the quality of rulemaking. The current regulatory impact analysis only 

tells policy makers whether the rule is likely to generate net benefits. A marginal benefit analysis 

would allow policy makers to decide if a more or less stringent rule would increase net benefits, 

or if an alternative approach would be better. 

Response: The methodology used to estimate the health benefits associated with the proposed 

rule presumes the existing geographic distribution of these emission sources, which includes 

both urban and rural sources. Specifically, EPA estimated the national average health benefits 

associated with reducing one ton of a PM2.5 precursor emission (such as direct PM2.5 or SO2) 

from the existing sources. Because available data show that a large majority of area source 

boilers occur either in urban areas (67%) or in commercial/institutional applications in close 

proximity to susceptible populations (99%), using national average estimates probably 

underestimate the magnitude of the associated health benefits. 

Location-specific benefits estimates depend on many factors, including population density, air 

pollution mixtures, meteorology, exposure patterns, baseline health incidence rates, and other 

local factors. At a national level, EPA has high confidence in the magnitude of total monetized 

benefits, but the benefits for specific locations may vary. 
Commenter Name: Bruce Coffee

Commenter Affiliation: Hurst Boiler and Welding Co

Document Control Number: EPA-HQ-OAR-2006-0790-1873.1

Comment Excerpt Number: 3

Comment: The justification for the action is admirable, but short-sighted, as the detrimental 

effect of the loss of work and the decrease in quality of life caused by this action will more than 

offset the few lives and discomforts the proponents enumerate as justification AND 

ACTUALLY COST LIVES! One would have to believe, based on the justification, that most of 

these solid-fuel-burning sources are all placed in urban settings, in reality, most are in rural, lowpopulation areas. 

It has been widely discussed, researched and proven that UNEMPLOYMENT causes far more 

deaths, drug use, domestic violence, smoking, dependency, etc than this list. So, it will have the 

opposite effect than that they hope to achieve. According to the CDC reports that the deaths per 

100,000 rose from an all-time low of 760 in 2007 to 838 in 2009 due to the economic downturn, 

essentially unemployment. That is an increase of 234,000. This occurred even as the emissions 

from boilers were decreased by a large percentage due also to the economic downturn. I believe 

this correlation essentially negates the justification and exposes the projection of mortality 

improvements as a myopic grasp that ends up being a rounding error. This is certain. 

Response: The methodology used to estimate the health benefits associated with the proposed 

rule presumes the existing geographic distribution of these emission sources, which includes 

both urban and rural sources. Specifically, EPA estimated the national average health benefits 

associated with reducing one ton of a PM2.5 precursor emission (such as direct PM2.5 or SO2) 

from the existing sources. Because available data show that a large majority of area source 

boilers occur either in urban areas (67%) or in commercial/institutional applications in close 

proximity to susceptible populations (99%), using national average estimates probably 

underestimate the magnitude of the associated health benefits. 

Location-specific benefits estimates depend on many factors, including population density, air 

pollution mixtures, meteorology, exposure patterns, baseline health incidence rates, and other 

local factors. At a national level, EPA has high confidence in the magnitude of total monetized 

benefits, but the benefits for specific locations may vary.

Commenter Name: N/A

Commenter Affiliation: Mercatus Center, George Mason University

Document Control Number: EPA-HQ-OAR-2006-0790-1837.1

Comment Excerpt Number: 5

Comment: The evidence presented by EPA suggests that the greatest benefits from reducing 

emissions will come from reducing emissions in urban areas where higher population density is 

greatest means a larger number of people would be affected by the pollution.[ Supra note 10.] 
Further, there is more evidence of the benefits from urban areas than from rural areas where 

particulate matter levels are 

frequently too low to measure. There is thus less uncertainty about the benefits from reducing 

emissions around cities. Establishing an emissions standard for metropolitan areas would be less 

costly because fewer emitters would be affected and because some emitters would be able to 

choose to locate in areas where the standard did not apply. This could potentially increase 

benefits if moving emissions away from the urban areas reduces human exposure to PM2.5, even 

if total emissions fell by less. 

Response: The methodology used to estimate the health benefits associated with the proposed 

rule presumes the existing geographic distribution of these emission sources, which includes 

both urban and rural sources. Specifically, EPA estimated the national average health benefits 

associated with reducing one ton of a PM2.5 precursor emission (such as direct PM2.5 or SO2) 

from the existing sources. Because available data show that a large majority of area source 

boilers occur either in urban areas (67%) or in commercial/institutional applications in close 

proximity to susceptible populations (99%), using national average estimates probably 

underestimate the magnitude of the associated health benefits.

Commenter Name: N/A

Commenter Affiliation: Mercatus Center, George Mason University

Document Control Number: EPA-HQ-OAR-2006-0790-1837.1

Comment Excerpt Number: 6

Comment: Even among cities, the benefits from reducing PM2.5 vary greatly. Establishing 

separate standards depending on location could increase benefits by making standards more 

stringent where the benefits are highest and less stringent where benefits are lowest. As with 

urban standards, emitters could locate in areas where the social costs of pollution are less, to 

avoid the most stringent regulations, reducing costs and increasing benefits from the regulation. 

Response: Location-specific benefits estimates depend on many factors, including population 

density, air pollution mixtures, meteorology, exposure patterns, baseline health incidence rates, 

and other local factors. At a national level, EPA has high confidence in the magnitude of total 

monetized benefits, but the benefits for specific locations may vary.

Commenter Name: Chris Mello

Commenter Affiliation: Alaska Energy Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1653.1

Comment Excerpt Number: 14

Comment: EPA makes a statement regarding the number of lives saved per year by applying 

emission restrictions but does not specially identify which areas of the country that such 

reduction of emissions would affect the saving of lives. In addition, there is no discernable way 
that EPA can prove their statement and it is only stated as an estimation. No area or areas are 

identified where air quality is affected to the extent that such purported emissions could cause 

death. 

Response: The methodology used to estimate the health benefits associated with the proposed 

rule presumes the existing geographic distribution of these emission sources, which includes 

both urban and rural sources. Specifically, EPA estimated the national average health benefits 

associated with reducing one ton of a PM2.5 precursor emission (such as direct PM2.5 or SO2) 

from the existing sources. Because available data show that a large majority of area source 

boilers occur either in urban areas (67%) or in commercial/institutional applications in close 

proximity to susceptible populations (99%), using national average estimates probably 

underestimate the magnitude of the associated health benefits. 

Location-specific benefits estimates depend on many factors, including population density, air 

pollution mixtures, meteorology, exposure patterns, baseline health incidence rates, and other 

local factors. At a national level, EPA has high confidence in the magnitude of total monetized 

benefits, but the benefits for specific locations may vary. 

It should be noted that we have not modeled the benefits for areas outside of the continental 

United States.

Commenter Name: Matthew Todd and David Friedman

Commenter Affiliation: American Petroleum Institute (API) and National Petrochemical and 

Refiners Association (NPRA)

Document Control Number: EPA-HQ-OAR-2006-0790-2025.1

Comment Excerpt Number: 59

Comment: The claimed health benefits resulting from this proposal are significantly overstated. 

The preamble indicates that the Agency cannot estimate the benefits from the HAP reductions 

resulting from this rule, but that they estimate the rule will result in reductions of 2,700 tons of 

PM2.5 and 1,500 tons of SO2 per year. EPA estimates the monetized benefits in 2013 associated 

with these reductions at between $1.0 billion (2008 dollars) and $2.4 billion (2008 dollars) when 

using a 3 percent discount rate (or from $0.9 billion (2008 dollars) to $2.2 billion (2008 dollars) 

when using a 7 percent discount rate. For the PM2.5 portion of these estimates EPA has not 

provided scientific justification for its proposed approach of extrapolating PM mortality risks to 

the lowest modeled ambient levels. An examination of the expert group advice cited by EPA in 

support of this approach reveals mostly the opposite, i.e., preference for the use of a threshold or 

apparent threshold for PM risk assessment. A critical review of the published literature also fails 

to provide support for EPA’s proposed new method for PM risk assessment. Many of the 

published studies cite evidence for nonlinearity and thresholds. Therefore, we do not believe that 

EPA’s new approach to extrapolate mortality risks attributed to exposure to ambient PM linearly 

to the lowest modeled levels is or can be scientifically supported. As a result, the alleged 

economic benefits attributed to reductions in exposure to PM2.5 also fail because they are built 

on a faulty foundation. 
Additionally, EPA claimed the PM2.5 and SO2 credits for the NAAQS standards and it is 

unreasonable to claim them again. Under the NAAQS program, the NSPS and SIP programs 

would lead to optimizing the ways in which PM2.5 and SO2 are reduced and it is unlikely minor 

reductions from very small sources, such as is proposed for regulation here would be ranked 

highly in the overall hierarchy. 

Response: The weight of scientific evidence strongly supports modeling PM-related mortality 

and morbidity by using concentration-response functions that do not incorporate an assumed 

threshold. In 2009, the final Integrated Science Assessment for Particulate Matter indicated that 

“[o]verall, the studies evaluated further support the use of a no-threshold log-linear model...” 

(U.S. EPA, 2009). In 2010, the Health Effects Subcommittee of the Science Advisory Board 

“fully supports EPA’s decision to use a no-threshold model to estimate mortality reductions. This 

decision is supported by the data, which are quite consistent in showing effects down to the 

lowest measured levels. Analyses of cohorts using data from more recent years, during which 

time PM concentrations have fallen, continue to report strong associations with mortality. 

Therefore, there is no evidence to support a truncation of the CRF” (EPA-SAB-COUNCIL- 10-

001). Our approach to estimating PM-related health impacts is consistent with the key findings in 

these reports. In addition, our approach is consistent with the on-going PM NAAQS review. 

In conjunction with the commenter’s concern and consistent with recent scientific advice, we 

have replaced the previous threshold sensitivity analysis with a new “lowest measured level” 

(LML) assessment. While an LML assessment provides some insight into the level of uncertainty 

in the estimated PM mortality benefits, EPA does not view the LML as a threshold and continues 

to quantify the PM-related mortality impacts using the full range of modeled air quality 

concentrations. 

EPA anticipates PM and SO2 emission reductions as a result of this rule, and the benefits 

associated with these emission reductions are appropriate to include in this RIA. These emission 

reductions would occur regardless of an area’s attainment status under the NAAQS, but these 

emission reductions might help those areas that are in non-attainment to reach attainment.

Commenter Name: Jon Bolling

Commenter Affiliation: Prince of Wales Community Advisor Council

Document Control Number: EPA-HQ-OAR-2006-0790-1935.1

Comment Excerpt Number: 9

Comment: Health Considerations 

EPA makes a statement regarding the number of lives saved per year by applying emission 

restrictions but does not specially identify which areas of the country that such reduction of 

emissions would affect the saving of lives. In addition, there is no discernable way that EPA can 

prove their statement and it is only stated as an estimation. No area or areas are identified where 

air quality is affected to the extent that such purported emissions could cause death. Therefore, 
such unscientific statements regarding the saving of lives without context regarding air quality 

emissions for implementation for such a sweeping regulatory authorization is specious and lacks 

definition. 

Response: Based on the conclusions of EPA's Integrated Science Assessment on Particulate 

Matter (U.S. EPA, 2009), long term exposure to fine particles has a causal link to premature 

mortality, even at low ambient levels. 

The methodology used to estimate the health benefits associated with the proposed rule 

presumes the existing geographic distribution of these emission sources, which includes both 

urban and rural sources. Specifically, EPA estimated the national average health benefits 

associated with reducing one ton of a PM2.5 precursor emission (such as direct PM2.5 or SO2) 

from the existing sources. Because available data show that a large majority of area source 

boilers occur either in urban areas (67%) or in commercial/institutional applications in close 

proximity to susceptible populations (99%), using national average estimates probably 

underestimate the magnitude of the associated health benefits. 

Location-specific benefits estimates depend on many factors, including population density, air 

pollution mixtures, meteorology, exposure patterns, baseline health incidence rates, and other 

local factors. At a national level, EPA has high confidence in the magnitude of total monetized 

benefits, but the benefits for specific locations may vary. 

It is important to note that EPA has only modeled the benefits for the continental United States.

Commenter Name: Martin Lunde

Commenter Affiliation: Citizen

Document Control Number: EPA-HQ-OAR-2006-0790-2065.1

Comment Excerpt Number: 7

Comment: Inaccurate assessment of health effects from biomass boiler particulate matter 

Response: Based on the conclusions of EPA's Integrated Science Assessment on Particulate 

Matter (U.S. EPA, 2009), long term exposure to fine particles has a causal link to premature 

mortality, even at low ambient levels. In addition, exposure to fine particles is associated with 

cardiovascular and respiratory health effects. The methodology for estimating the health benefits 

associated with reducing PM2.5 and precursor emissions is based on peer-reviewed publications 

(see Fann, Fulcher, and Hubbell, 2009).

Commenter Name: Charlie Cary

Commenter Affiliation: Biomass Combustion Systems, Inc

Document Control Number: EPA-HQ-OAR-2006-0790-1990.1

Comment Excerpt Number: 8
Comment: The positive impacts of these proposed standards are significantly overstated. The 

EPA rule making is to reduce “urban” HAPs. Accordingly, EPA has modeled its calculations of 

health costs on data obtained from areas of high density. As a result, the agency incorrectly 

overstates the value of emission reductions in the rural areas where most wood boilers are 

located. 

Response: The methodology used to estimate the health benefits associated with the proposed 

rule presumes the existing geographic distribution of these emission sources, which includes 

both urban and rural sources. Specifically, EPA estimated the national average health benefits 

associated with reducing one ton of a PM2.5 precursor emission (such as direct PM2.5 or SO2) 

from the existing sources. Because available data show that a large majority of area source 

boilers occur either in urban areas (67%) or in commercial/institutional applications in close 

proximity to susceptible populations (99%), using national average estimates probably 

underestimate the magnitude of the associated health benefits. 

Location-specific benefits estimates depend on many factors, including population density, air 

pollution mixtures, meteorology, exposure patterns, baseline health incidence rates, and other 

local factors. At a national level, EPA has high confidence in the magnitude of total monetized 

benefits, but the benefits for specific locations may vary.

Commenter Name: Kyle Gibeault

Commenter Affiliation: Biomass Thermal Energy Council, BTEC

Document Control Number: EPA-HQ-OAR-2006-0790-1914.1

Comment Excerpt Number: 11

Comment: Furthermore, EPA’s model for calculating health costs overstates the health impacts 

of emissions in rural areas with lower population density (which is the location of most biomass 

boilers), because the model and data were developed based on densely populated urban areas. 

[Footnote: Fann, Fulcher, and Hubbell, “The Influence of Location, Source, and Emission Type 

In Estimates of Human Health Benefits of Reducing a Ton of Air Pollution,” June 2009.] This 

bias causes the EPA impact model to overvalue emissions reductions from rural biomass boilers 

in its cost-benefit analysis. 

Based on weak correlation of CO and POMs, the lower toxicity of PM from completely 

combusted biomass vs. petroleum PM, and the likely overstatement of health impacts in areas of 

low population density, BTEC believes there is a good basis that the exceptionally strict 

standards proposed in the rule are unwarranted. 

Response: The methodology used to estimate the health benefits associated with the proposed 

rule presumes the existing geographic distribution of these emission sources, which includes 

both urban and rural sources. Specifically, EPA estimated the national average health benefits 

associated with reducing one ton of a PM2.5 precursor emission (such as direct PM2.5 or SO2) 
from the existing sources. Because available data show that a large majority of area source 

boilers occur either in urban areas (67%) or in commercial/institutional applications in close 

proximity to susceptible populations (99%), using national average estimates probably 

underestimate the magnitude of the associated health benefits. 

Location-specific benefits estimates depend on many factors, including population density, air 

pollution mixtures, meteorology, exposure patterns, baseline health incidence rates, and other 

local factors. At a national level, EPA has high confidence in the magnitude of total monetized 

benefits, but the benefits for specific locations may vary.

Commenter Name: Steven A. Brink

Commenter Affiliation: California Forestry Association

Document Control Number: EPA-HQ-OAR-2006-0790-2026.1

Comment Excerpt Number: 7

Comment: Further Biomass Thermal Energy Council shows EPA’s health cost model does not 

account for lower human population density in rural areas (which is where most biomass boilers 

are located) creating a higher value for emissions reduction, which affects the cost-benefit 

analysis. 

Response: Thank you for your comment.

Other - Impact Analysis

Commenter Name: Michael Hutcheson

Commenter Affiliation: Ameren Corp.

Document Control Number: EPA-HQ-OAR-2006-0790-2012.1

Comment Excerpt Number: 11

Comment: The US EPA improperly overestimates energy and fuel savings associated with 

required energy audits, annual tune-ups and required combustion controls. US EPA should not 

include any energy savings associated with energy audits as these audits will not guarantee any 

energy savings. They are only assessments. Similary, US EPA’s own data shows that affected 

units are already conducting boiler tune-ups (page 32025 of preamble which states, “The data we 

have suggests that units typically conduct tune-ups”). Consequently, US EPA should expect little 

benefit from boiler tune-ups as these are already normal practice throughout industry. As a result, 

Ameren believes that the fuel savings estimate of 1 % of annual fuel consumption is an 

overestimate and should be revised downward to reflect realistic estimates of fuel savings. 
Response: The fuel savings estimated for the final rule are those associated with the required 

tune-up requirement. There are several references in the docket that show the benefit in 

improved energy efficiency and fuel savings of a tune-up.

Executive Orders

Executive Order 12866, Regulatory Planning and Review

Commenter Name: Michael A. Livermore

Commenter Affiliation: Institute for Policy Integrity New York University School of Law

Document Control Number: EPA-HQ-OAR-2006-0790-1899.1

Comment Excerpt Number: 3

Comment: Given the mandate from Executive Order 12,866, EPA’s default practice should be 

to design regulations that maximize net social welfare, unless directly forbidden by statute. Since 

Section 112(d)(2) cannot be read to prohibit such a goal, the agency should pursue any beyondthe-floor regulations where benefits justify the costs. This interpretation is not forbidden by the 

D.C. Circuit opinion in Sierra Club v. EPA (2004), and EPA’s regulatory impact analysis 

indicates that, particularly for the Major Source Proposal, more stringent emission standards than 

those currently proposed would increase social welfare. 

Response: EPA thanks the commenter for their input See preamble for response to comments 

on how CO limits were modified.

See preamble for response to comments on the pollutant-by-pollutant approach. See the 

Preamble for discussion on how we addressed and revised CO limits.

Thank you for your comment.

Commenter Name: Ben Brandes

Commenter Affiliation: National Mining Association

Document Control Number: EPA-HQ-OAR-2006-0790-1980.1

Comment Excerpt Number: 1

Comment: NMA believes that the regulatory analysis supporting the proposed rules is fatally 

flawed because it fails to take into account the cumulative impact of all of EPA’s now-numerous 

completed, pending and expected rulemakings that are intended to and will have the effect of 

substantially reducing the usage of coal in the United States. These rulemakings include those 

affecting the use of coal for electric generation, where EPA is implementing a coordinated 

program to create, in its words, a ?clean, efficient, and completely modern power sector, those 

affecting the use of coal for industrial, commercial and institutional purposes, such as the two 

rules specifically at issue here, and those directly affecting coal mining. 
All of these rulemakings together will produce a dramatic and cascading series of effects not 

only in the coal industry but throughout the economy. There will be direct effects on coal 

employment and indirect effects on employment generally in the economy as a result of higher 

energy prices. Higher energy prices will also affect GDP and economic activity generally. 

American competitiveness will also be affected, as higher prices undermine the ability of 

American business to compete, with resulting off-shoring of American business and jobs. 

Impact analysis performed by EPA now proceeds on a rulemaking-by-rulemaking basis, as if one 

rulemaking is unconnected to the next and as if the regulatory consequences are not cumulative. 

As a result, EPA’s impact analyses mask the cumulative effect of the Agency‘s overall 

regulatory program. Individual-regulation impact analyses often predict limited effects, when in 

truth the compounding effects of the overall program may produce extremely large 

consequences. 

This Balkanized approach to impact analysis impairs the public’s right to notice and comment 

regarding EPA regulation. For instance, EPA’s Regulatory Impact Analysis for the Boiler 

MACT rule shows relatively minor effects, which might lead the public to believe that the rule is 

relatively innocuous. Cumulative analysis, on the other hand, is likely to lead to a far different 

conclusion—that coal usage will decline dramatically as a result of the combined effect of 

numerous EPA rulemakings with attendant serious economic consequences. Armed with that 

information, the public would likely provide significantly different comment on the rule. EPA 

and other cooperating agencies rely upon similar cumulative impact assessments when analyzing 

proposed federal actions subject to the National Environmental Procedure Act, and the public 

should be afforded the same opportunity here. 

Analyzing cumulative impacts is not just good policy, it is required by Executive Order 12866 

and the notice and comment rulemaking provisions of the Clean Air Act (?CAA). NMA 

therefore urges EPA to defer final action on the two rules at issue here until the necessary 

cumulative impact assessment is produced. The specific type of analysis that NMA recommends 

is set forth

Response: EPA thanks the commenter for their input. See the revised Regulatory Impacts 

Analysis report, that is located in the docket, on how we may have addressed this comment. 

Executive Order 13132, Federalism

Commenter Name: Chris Mello

Commenter Affiliation: Alaska Energy Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1653.1

Comment Excerpt Number: 13

Comment: EPA maintains this proposed rule is not a "significant energy action" as it will not 

have significant adverse impact on supply, distribution, or use of energy. This may be true for 

urban areas of the continental U.S., but for rural Alaska, this proposed rule will most likely be a 

"significant energy action". Nationwide, the proposed rule impacts less than 0.7 percent of 

revenue. While "percent of revenue" may provide a meaningful benchmark in the urban U.S., 
due to the excessively high cost of fuel and maintenance and the small market base over which to 

amortize these costs in rural Alaska communities — -percent of revenue" is not a relevant 

benchmark. While annualized costs of this rule are estimated to exceed 1% of operating revenue 

in rural Alaska, compliance costs could easily exceed 50% of net annual operating revenues. 

While biomass is not the most significant source of heating in rural Alaska, in many areas of 

Alaska it is the only alternative to extremely high costs petroleum fuels. Thus, the State of 

Alaska feels this proposed rule is onerous and unnecessary considering the reality of space 

heating in bush Alaska. 

Response: EPA thanks the commenter for their input. See the Preamble on how we may have 

addressed this comment.

Commenter Name: John Lyons

Commenter Affiliation: Kentucky Division for Air Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2218.1

Comment Excerpt Number: 8

Comment: There will be a significant increase in fuel sample analysis. This would place a huge 

burden on state agencies to analyze the fuel for compliance. 

Response: EPA thanks the commenter for their input. The fuel analysis that is conducted is in 

place of stack testing. This should not increase the burden on state agencies.

Commenter Name: John Lyons

Commenter Affiliation: Kentucky Division for Air Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2218.1

Comment Excerpt Number: 9

Comment: Burden to State and Local Agencies 

There will be a substantial increase in the number of compliance tests and CEMS certification 

tests. We currently have 4 positions available for reviewing test protocols, observing the tests 

and reviewing test reports. The Division’s workload is going to increase and current budget 

constraints simply mean that the agency will not be able to witness all tests. 

Response: The revisions to the final rule will result in fewer area source boilers conducting 

compliance tests. In addition, the frequency of compliance tests has been reduced from annual to 

triennial.
Commenter Name: John Lyons

Commenter Affiliation: Kentucky Division for Air Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2218.1

Comment Excerpt Number: 10

Comment: Burden to State and Local Agencies 

New or existing boilers are required to conduct initial and annual performance tests as well as 

CEMs compliance testing. The increase in compliance tests will impact the state financially. The 

state currently spends approximately 3 business days per compliance test observation, per source. 

The work load includes reviewing compliance test protocols, observing the test, and reviewing 

the final test report. EPA estimates there are currently 183,000 area source boilers and the 

potential for 6,800 new sources in the next 3 years. 

Response: In the final rule, the only existing area source boilers subject to emission limits and, 

thus, performance tests are large coal-fired boilers of which there are an estimated 572 boilers. 

In addition, the frequency of performance tests has been reduced from annual to triennial. 

Therefore, the burden to state and local agencies has been reduced. 

Commenter Name: John Lyons

Commenter Affiliation: Kentucky Division for Air Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2218.1

Comment Excerpt Number: 11

Comment: Burden to State and Local Agencies 

The required ASTM methods listed in the tables 4 and 5 to Subpart JJJJJJ of Part 63 are not 

available free of charge. In order for state, local, or tribal agencies to observe and review testing 

methods following the ASTM methodology, the agencies would be required to purchase copies 

of the testing methods. A free resource library such as the online EMC website would be 

beneficial to financially strapped agencies seeking the method information. 

Response: EPA thanks the commenter for their suggestion.

Commenter Name: John Lyons

Commenter Affiliation: Kentucky Division for Air Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2218.1

Comment Excerpt Number: 12

Comment: Burden to State and Local Agencies 
This proposed area source rule will have a major impact on the regulated community and the 

Division through added regulatory burden to sources that have otherwise avoided direct 

regulation under the CAA. The number of sources that will require ongoing compliance 

monitoring in the form of inspections and testing oversight will increase significantly if this 

proposed rule is promulgated in its current form. 

Response: In the final rule, the only existing area source boilers subject to emission limits and, 

thus, performance tests are large coal-fired boilers of which there are an estimated 572 boilers. 

In addition, the frequency of performance tests has been reduced from annual to triennial. 

Therefore, the burden to state and local agencies has been reduced.

Commenter Name: John Lyons

Commenter Affiliation: Kentucky Division for Air Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2218.1

Comment Excerpt Number: 13

Comment: Burden to State and Local Agencies 

Many of the coal, biomass, and (primary) oil fired units located at these area sources may also be 

regulated by the 40 CFR 60 Subparts Db and Dc of the NSPS, however this proposed rule adds a 

significant additional testing and management practice requirements to units over 10 MMBtu/hr 

input ratings. This will be a huge additional burden on the Division since compliance with the 

emission limits is largely based in this testing and will require inspector involvement, 

supervisory oversight, and management coordination of the review and compliance 

determination of these new requirements. 

Response: In the final rule, the only existing area source boilers subject to emission limits and, 

thus, performance tests are large coal-fired boilers of which there are an estimated 572 boilers. 

In addition, the frequency of performance tests has been reduced from annual to triennial. 

Therefore, the burden to state and local agencies has been reduced.

Commenter Name: John Lyons

Commenter Affiliation: Kentucky Division for Air Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2218.1

Comment Excerpt Number: 14

Comment: Burden to State and Local Agencies 

The additional work practice standards and management practice standards include, at a 

minimum, a biennial tune-up requirement for every non-gas fired boiler. Combined with annual 

CO testing of all non-gas boilers over 10 MMBtu, the impact on the Division resource will be 
devastating. Tracking, inspection, and oversight of these requirements alone would require 

additional full time staff in every field office in the state. 

Response: In the final rule, the only existing area source boilers subject to emission limits and, 

thus, performance tests are large coal-fired boilers of which there are an estimated 572 boilers. 

In addition, the frequency of performance tests has been reduced from annual to triennial. 

Therefore, the burden to state and local agencies has been reduced.

Commenter Name: John Lyons

Commenter Affiliation: Kentucky Division for Air Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2218.1

Comment Excerpt Number: 15

Comment: Burden to State and Local Agencies 

Since many of these units will be at facilities that do not have a permit from the Division there 

will be an additional burden of educating these sources. These sources typically require a larger 

amount of time to explain the requirements and to provide basic compliance assistance to 

achieve compliance with the rule. 

Response: EPA thanks the commenter for their input. EPA is planning on implementing an 

outreach effort to these small facilities.

Commenter Name: John Lyons

Commenter Affiliation: Kentucky Division for Air Quality

Document Control Number: EPA-HQ-OAR-2006-0790-2218.1

Comment Excerpt Number: 16

Comment: Burden to State and Local Agencies 

The Division recommends that the annual CO testing requirement be reduced to biennial or even 

less frequent as a way of reducing the burden on both the Division and regulated sources. 

Response: In the final rule, the frequency of performance tests has been reduced from annual to 

triennial. 
Executive Order 13175, Consultation and Coordination with Indian Tribal 

Governments

Commenter Name: Chris Mello

Commenter Affiliation: Alaska Energy Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1653.1

Comment Excerpt Number: 17

Comment: EPA states this proposed rule does not have tribal implications as it does not have 

substantial direct effects on tribal governments, on the relationship between Federal government 

and Indian tribes, or on the distribution of power and responsibilities between Federal 

government and Indian tribes. 

The State of Alaska questions how EPA knows whether this rule has direct impacts on tribal 

governments without EPA having -consulted" Alaska tribes to begin with. This is a significant 

consideration in rural Alaska where this rule will have significant cost impacts to members of 

Alaska tribes, From the perspective of AEA, who interacts and works with Alaska tribes on a 

regular basis, this federal proposed rule DOES have substantial direct effects on tribal 

governments responsible for the well being of their tribal members -made more difficult with the 

cost impacts of this rule. 

In particular, section 3, parts (b) and (c) of the executive order speak to providing tribal 

governments the maximum administrative discretion possible and encouraging tribes to develop 

their own policies to meet rule objectives, defer to tribal standards, and most importantly, consult 

with tribes as to the need for alternatives that would limit the scope of the federal standard. In 

section 5 on the specifics of consultation, federal agencies must, for any regulation that has tribal 

implications, have consulted with tribal officials early in the process of developing the proposed 

regulation and provide documentation of that consultation. 

AEA does not ‘Know if ‘EPA has taken these steps with Alaskan tribes, or -ventured to 

determine if this proposed rule even has an impact on Alaskan tribes. AEA believes EPA should 

consider farther tribal input on these rules even if it means developing a separate rulemaking for 

the "rural" part of Alaska. 

Response: EPA thanks the commenter for their input. 

Executive Order 13045, Protection of Children from Environmental Health Risks 

and Safety Risks

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 12
Comment: MR. THOMAS: How are you defining "environmental justice communities"? You 

have to -- I know it’s a very complicated issue. 

MR. TEJADA: Yeah, the EPA doesn’t even really have a good definition of environmental 

justice communities, and I think that’s one of the things that NEJAC is -- is struggling with, as 

well, finding exactly what it means to take environmental justice and give it its full measure in 

the decision-making process, exactly where that comes into the decision-making process, exactly 

who are environmental justice communities. 

That’s one of the things that I think that is most challenging about Houston, is that it’s not just 

the usual suspects. I think most of the ten-point communities of major industry in the Houston 

area are obviously environmental justice communities following the regular interpretations of 

low socioeconomic levels, the racial profile of the community, its proximity to major sources, is 

a good start. 

But especially in Houston, one of the things that my organization has been struggling with a lot 

over the past year is that we are finding small, yet major sources of pollution buried within our 

entire community from unusual suspects, such as automotive mechanics, things such as metal 

fabrication or foundries. 

So I think these sorts of rules that deal very specifically and are very well defined in things 

such as a boiler versus an incinerator or solid waste, especially in the Houston region, which I 

think even by a narrow definition of environmental justice community would probably have 

more EJ communities than anywhere else in the United States; that is further multiplied 

when you look at Houston itself being the largest city without any form of zoning in the United 

States. 

If you actually pull back the cover of Houston, you start to find many communities sprinkled 

throughout the entire region that face very specific, but very serious threats from air emissions. 

We’re dealing with one about a half mile from downtown right now. A historic black 

community that has a boundary in the center of the community, and that boundary from its 

permit, which was only taken out a few years ago, its historic operational practices, the emissions 

and locations of the different units within the facility that, that community has been very poorly 

served by a poor regulatory definition of how a boundary of that size should operate. 

And this rule or these rules are exactly the sort that need to be very specific and very well 

defined in order to better protect exactly those sorts of communities that don’t have the profile of 

Manchester or Galena Park or Baytown. 

Response: EPA thanks the commenter for their input. See the document “Review of

Environmental Justice Impacts for the following Proposed Rules: Standards of Performance for 

New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration (CISWI) Units; National Emission Standards for Hazardous 

Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; National 

Emission Standards for Hazardous Air Pollutants for Industrial/Commercial/Institutional Boilers 

and Process Heaters; and Identification of Non-hazardous Secondary Materials (NHSM) that are 

Solid Waste” that is located in the docket on how we addressed environmental justice.

Commenter Name: Arthur N. Marin

Commenter Affiliation: Northeast States for Coordinated Air Use Management, NESCAUM

Document Control Number: EPA-HQ-OAR-2006-0790-2137.1
Comment Excerpt Number: 28

Comment: Numerous health studies have linked exposure to elevated PM levels to a wide range 

of detrimental heart and lung health effects, including increased risk of premature death. 

Children in particular may be at greater risk in some respects than adults from exposure to air 

pollution for a number of reasons. Those under the age of 17 have a higher resting metabolic rate 

and oxygen consumption rate per unit of body weight than adults, which results in a relatively 

greater volume of air passing through the lungs. Children engage in activities such as playing 

outdoors that could increase the amount of air pollutants they take into their bodies. Children are 

growing and can sustain permanent damage if toxic exposures are high enough during critical 

growth stages, with children under the age of 17 years old at greater risk of hospitalization due to 

respiratory disease with increased PM-10 exposure. 

With these types of relatively greater risks for children from exposure to air pollution, 

NESCAUM is concerned about the various efforts being pursued by government agencies and 

the private sector to encourage use of small biomass boilers in institutional settings, specifically 

schools and hospitals (the latter setting also affects sensitive adults, such as those with 

respiratory disease). Typically, these boilers have not had to comply with emission limits. 

Implementing a strong area source standard, specifically for PM and CO emissions, will better 

protect the health of these sensitive populations. 

Response: EPA thanks the commenter for their input. See the Preamble for discussion on how 

we addressed and revised CO and PM limits.

Unfunded Mandates Reform Act of 1995

Commenter Name: Chris Mello

Commenter Affiliation: Alaska Energy Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1653.1

Comment Excerpt Number: 16

Comment: The UMRA requires, where feasible, consideration of future compliance costs 

imposed by the rule and any disproportionate budgetary effects. EPA states their estimates of 

future compliance costs of the proposed rule would not have disproportionate budgetary effects 

on any particular areas of the country, state, or local governments, or types of communities (e.g. 

urban or rural). This position does not contemplate rural Alaska. It is difficult to find the citation 

for this estimate or data offered to show this demonstration in either the federal register notice or 

Regulatory Impact Analysis. Alaska Energy Authority has not been contacted by EPA as part of 

this estimate and to their knowledge, tribes and rural communities have not been contacted as 

well. AEA has solid financial reasons to believe this proposed rule WILL have disproportionate 

impact on rural Alaska communities depending on biomass heating. AEA encourages EPA, 
under the auspices of the UMRA, to bring its considerable resource to bear on a cost impact 

determination of this proposed rule on rural Alaska communities. 

Response: EPA thanks the commenter for their input. See preamble on how we may have 

addressed this comment.

Commenter Name: Jon Bolling

Commenter Affiliation: Prince of Wales Community Advisor Council

Document Control Number: EPA-HQ-OAR-2006-0790-1935.1

Comment Excerpt Number: 10

Comment: Unfunded Mandates Reform Act 

The UMRA requires, where feasible, consideration of future compliance costs imposed by the 

rule and any disproportionate budgetary effects. EPA states their estimates of future compliance 

costs of the proposed rule would not have disproportionate budgetary effects on any particular 

areas of the country, state, or local governments, or types of communities (e.g. urban or rural). It 

is difficult to find the citation for this estimate or data offered to show this demonstration in 

either the federal register notice or Regulatory Impact Analysis. The Alaska Energy Authority, 

part of the State of Alaska, and the entity that oversees most energy projects and implements 

energy policy in the state, has not been contacted by EPA as part of this estimate and to their 

knowledge, tribes and rural communities have not been contacted as well. AEA has solid 

financial reasons to believe this proposed rule WILL have disproportionate impact on rural 

Alaska communities depending on biomass heating. AEA encourages EPA, under the auspices of 

the UMRA, to bring its considerable resource to bear on a cost impact determination of this 

proposed rule on rural Alaska communities. 

Response: EPA thanks the commenter for their input. See preamble for on how we addressed 

and revised requirements for biomass-fired area source boilers.

Regulatory Flexibility Act as Amended by the Small Business Regulatory 

Enforcement Fairness Act (RFA) of 1996 SBREFA), 5 U.S.C. 601 et Seq.

Commenter Name: Mike Hubbard

Commenter Affiliation: National Council of Textile Organizations

Document Control Number: EPA-HQ-OAR-2006-0790-1062

Comment Excerpt Number: 2

Comment: Much higher costs than those estimated by EPA: The testing, reporting, and record 

keeping costs (due to a mercury limit) will be significant. Most minor source companies are 

small, so the effect will be greater on their overall operational costs. 
Response: EPA thanks the commenter for their input. See preamble on how we addressed and 

revised the final rule to reduce the burden on area source facilities.

Commenter Name: Susan Eckerly

Commenter Affiliation: National Federation of Independent Business, NFIB

Document Control Number: EPA-HQ-OAR-2006-0790-1631.1

Comment Excerpt Number: 1

Comment: Regulation affects small businesses in a substantially different way than it does large 

businesses. When a large business needs to comply with a new regulation, it designates its 

regulatory compliance officer — or officers — with the task. These individuals know their way 

around regulatory technicalities that most lay persons do not easily understand. 

For the small business owner, there is no regulatory compliance officer. This burden falls 

squarely on the owner, who, more times than not, is responsible for everything from ordering 

inventory and hiring employees, to taking out the trash at the end of the day. And while they may 

be expert in their craft, comprehending regulations, formalizing plans for their implementation 

and filling out paperwork is an extremely burdensome exercise. 

Even beyond the significant time regulations take away from a small business owner trying to 

make a living, the per-employee cost of regulation is significantly greater for small businesses. A 

study performed by economist Mark Crain for the U.S. Small Business Administration estimated 

that regulations cost Americans $1.1 trillion annually. Importantly, the study also showed that 

small businesses face a 45 percent greater regulatory burden than their larger counterparts. 

[Footnote: Crain, W. Mark, The Impact of Regulatory Costs on Small Firms, 2005, 

http://www.sba.gov/advo/research/rs264.pdf.] The compliance burdens presented by these rules 

are great because small business owners will need to spend significant time to understand these 

rules, make expenditures to expensive consultants to bring the facility up to compliance, and 

greatly increase the amount of time he or she spends on paperwork compliance. 

EPA has aimed for the platinum standard with this rule when the gold standard would be 

effective. The result will have serious and harmful consequences for the small businesses forced 

to comply with this rule. 

Response: EPA thanks the commenter for their input. See the revised Regulatory Impacts 

Analysis report, located in the docket, on the revised costs and impacts on small businesses 

resulting from the changes made in the final rule.

Commenter Name: Randy Bush

Commenter Affiliation: Virginia Forest Products Association

Document Control Number: EPA-HQ-OAR-2006-0790-1492.1

Comment Excerpt Number: 1
Comment: The Virginia Forest Products Association is a non-profit organization representing 

members engaged in or supporting the forest products industry in the Commonwealth of 

Virginia. While our membership includes companies of varying sizes, our typical member would 

best be classed as a small business, with the majority being family owned and operated. 

Recent economic conditions have placed a severe toll on the industry ... easily the worst since the 

Depression, with many facilities closing their doors either temporarily or permanently. As an 

example, studies have shown the number of sawmills in the State in 2009 is one-half of the total 

found in 1999, just 10 years previously. Any additional regulatory burdens, particularly those 

that have questionable cost vs. benefit ratios, placed on the industry will put many more facilities 

at risk. 

We believe the proposed Area Source Boiler Standard is far more stringent than needed to assure 

protection of health and the environment due to HAP emissions from the affected boilers. As 

mentioned earlier, the membership of the Virginia Forest Products Association faces a withering 

economic slump (both global and domestic) with fierce competition from overseas 

manufacturers. Therefore, it is imperative for mandatory environmental controls such as these 

standards to be tailored as closely as possible such that health and the environment are protected 

without requiring unnecessary expenditures of time and resources. 

Response: EPA thanks the commenter for their input. See the revised Regulatory Impacts 

Analysis report, located in the docket, on the revised costs and impacts on small businesses 

resulting from the changes made in the final rule.

Commenter Name: Elizabeth E. Bass

Commenter Affiliation: Tuolumne County

Document Control Number: EPA-HQ-OAR-2006-0790-2250

Comment Excerpt Number: 1

Comment: The economic impact of this proposed rule as it is currently written does not support 

the Small Business Advocacy Review Panel’s recommendation that the EPA carefully weigh the 

potential burden of compliance requirements and consider options for small entities. Several 

elements of the proposed rule are believed to be too stringent and too costly, and may not protect 

ambient air quality or public health, as described, if boiler operations are forced to shut down and 

biomass waste disposal is conducted through open burning. 

Response: EPA thanks the commenter for their input. See the revised Regulatory Impacts 

Analysis report, located in the docket, on the revised costs and impacts on small businesses 

resulting from the changes made in the final rule.
Executive Order 13211, Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use

Commenter Name: Jon Bolling

Commenter Affiliation: Prince of Wales Community Advisor Council

Document Control Number: EPA-HQ-OAR-2006-0790-1935.1

Comment Excerpt Number: 8

Comment: Executive Order 13211: Actions Concerning Regulations that Significantly Affect 

Energy Supply, Distribution, or Use 

EPA maintains this proposed rule is not a “significant energy action” as it will not have 

significant adverse impact on supply, distribution, or use of energy. This may be true for urban 

areas of the continental U.S., but for rural Alaska, this proposed rule has a very large potential to 

be a “significant energy action”. Nationwide, the proposed rule impacts less than 0.7 percent of 

revenue. While “percent of revenue” may provide a meaningful benchmark in the urban U.S., 

due to the excessively high cost of fuel and maintenance and the small market base over which to 

amortize these costs in rural Alaska communities – “percent of revenue” is not a relevant 

benchmark. According to the Alaska Energy Authority, while annualized costs of this rule are 

estimated to exceed 1% of operating revenue in rural Alaska, compliance costs could easily 

exceed 50% of net annual operating revenues. While biomass is not the most significant source 

of heating in rural Alaska, in many areas of Alaska it is the only alternative to extremely high 

costs petroleum fuels. Thus, the State of Alaska feels this proposed rule is onerous and 

unnecessary considering the reality of power production and distribution in rural Alaska. 

Response: EPA thanks the commenter for their input. See preamble for revised discussion on 

impact on energy supply based on the changes made to the final rule.

Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations

Commenter Name: Los Angeles Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0397

Comment Excerpt Number: 30

Comment: We are concerned about the open process with regard to the chemicals and the things 

that are being put into these boilers. Our concern goes to the regulatory officials, the EPA and all 

of the other agencies. We have been dealing as environmental justice advocates for years over 

regulations and the enforcement of rules. Very often our communities suffer because laws are 

not enforced, rules are not applied, and community members are not informed about the process 

as the process unfolds. 
We think that in order for us to have a fair opportunity to have clean air, to have a safe 

environment, to have a place where our children can grow and we can trust our air quality, we 

have to have strongly regulated boilers. This is an attempt to -- as we see it, to allow industry to 

get away with burning a lot of chemicals that they can’t otherwise get rid of. 

Response: EPA thanks the commenter for their input. See the document “Review of

Environmental Justice Impacts for the following Proposed Rules: Standards of Performance for 

New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration (CISWI) Units; National Emission Standards for Hazardous 

Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; National 

Emission Standards for Hazardous Air Pollutants for Industrial/Commercial/Institutional Boilers 

and Process Heaters; and Identification of Non-hazardous Secondary Materials (NHSM) that are 

Solid Waste” that is located in the docket on how we addressed environmental justice. 

Commenter Name: Arlington Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0396

Comment Excerpt Number: 48

Comment: So, how is EPA evaluating the environmental justice impacts of these rules? In the 

documents that were provided for the webinar that the Agency conducted last Wednesday -- the 

rather excellent webinar I might add -– in those documents it described the demographic 

evaluation of population distribution around the sources impacted by the Boiler MACT CISWI 

rule and the definition of non-solid hazardous waste. 

EPA’s demographic analysis of the industrial boilers rule clearly shows that 33 percent of the 

population around these existing facilities are people of color, and 29 percent of the population 

around the CISWI incinerators are people of color. Both analyses demonstrate that areas in 

closest proximity to these two categories of facilities exceed the percentage of people of color in 

the nation’s population at large, which is 25 percent. 

I want to note that while the demographic analysis represents a significant step forward by EPA 

in determining the potential impacts of its rulemaking, it is nonetheless an insufficient analysis of 

adverse impact of the operations of these facilities on the nearby communities. 

The demographic analysis also shows that surrounding communities also have higher levels of 

people living at or below the national poverty levels. EPA’s determination of benefits of these 

rules to environmental justice communities outweighing impacts is spotty and needs to be 

expanded to include public health impacts that extend beyond the simple and mere demographic 

analysis. 

Response: EPA thanks the commenter for their input. See the document “Review of

Environmental Justice Impacts for the following Proposed Rules: Standards of Performance for 
New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration (CISWI) Units; National Emission Standards for Hazardous 

Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; National 

Emission Standards for Hazardous Air Pollutants for Industrial/Commercial/Institutional Boilers 

and Process Heaters; and Identification of Non-hazardous Secondary Materials (NHSM) that are 

Solid Waste” that is located in the docket on how we addressed environmental justice.

Commenter Name: Arlington Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0396

Comment Excerpt Number: 64

Comment: I really wanted to talk a little bit more about the stories of communities that I’ve 

been in in terms of there are all kinds of things that are thrown in boilers that are small, mediumsized, large, and essentially exempting facilities across this country from having to install 

protective controls on those facilities, has continued to put those communities at risk. 

Response: EPA thanks the commenter for their input. See the document “Review of

Environmental Justice Impacts for the following Proposed Rules: Standards of Performance for 

New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration (CISWI) Units; National Emission Standards for Hazardous 

Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; National 

Emission Standards for Hazardous Air Pollutants for Industrial/Commercial/Institutional Boilers 

and Process Heaters; and Identification of Non-hazardous Secondary Materials (NHSM) that are 

Solid Waste” that is located in the docket on how we addressed environmental justice.

Commenter Name: Margaret E. Sheehan

Commenter Affiliation: Energy Justice Network

Document Control Number: EPA-HQ-OAR-2006-0790-1053.1

Comment Excerpt Number: 6

Comment: A Request That the EPA Further Study the Effect of Biomass Emissions on 

Environmental Justice Issues. 

The EPA should continue to consider the disproportionate impact that incinerators have on poor 

and minority communities. According to the EPA’s webinar on national emission standards for 

boilers, process heaters and incinerators27 ,for populations living near disposal and processing 

facilities that may receive wastes diverted from incinerators, the results suggest that percentages 

of low-income and minority populations are slightly higher than national average. These results 

should not be used to justify avoidance of heightened standards for incinerators because lowincome communities are already disproportionately affected by pollution. [See Reference 28 in 

submittal.] The pollution from industrial air pollution sources, such as incinerators, accumulates 

in places where minority populations are disproportionately affected. Id. 
The EPA should do more studies to test the background levels of already existing pollution of 

communities affected by incinerator emissions. Background levels of air pollution in these 

communities are often higher than in other areas because, in general, low -income neighborhoods 

experience more of all forms of pollution (including air and water pollution, as well as toxic 

waste pollution) than do neighborhoods that maintain higher levels of income. [See Reference 29 

in submittal.] 

For example, a biomass incinerator was planned to be built in Springfield, Massachusetts, a city 

described as already having “an ‘F’ in air quality.” [See Reference 30 in submittal.] In fact, 

Springfield ranks number fourteen on the Asthma and Allergy Foundation of America’s ranking 

of U.S. Metropolitan areas according to prevalence of asthma. [See Reference 31 in submittal.] 

The EPA should use the results of studies of background emissions to strengthen regulation of 

emissions; for example, if an inner-city community already has high dioxin emissions, emission 

standards should be higher. 

Response: EPA thanks the commenter for their input. See the document “Review of

Environmental Justice Impacts for the following Proposed Rules: Standards of Performance for 

New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration (CISWI) Units; National Emission Standards for Hazardous 

Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; National 

Emission Standards for Hazardous Air Pollutants for Industrial/Commercial/Institutional Boilers 

and Process Heaters; and Identification of Non-hazardous Secondary Materials (NHSM) that are 

Solid Waste” that is located in the docket on how we addressed environmental justice.

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 9

Comment: There has been a lot of talk over the past couple of years from EPA about protecting 

environmental justice communities ensuring that environmental justice is a part of the decisionmaking process of everything that EPA takes on. 

I think that this is a clear example where better protecting and better serving environmental 

justice communities would be better served by a stricter interpretation of what is a solid waste; as 

well, using carbon monoxide as a surrogate for other sorts of VOCs, especially those which we 

struggle so mildly with in the Houston area. I don’t think that, again, is going to serve 

environmental justice communities well. 

Response: EPA thanks the commenter for their input. See the document “Review of

Environmental Justice Impacts for the following Proposed Rules: Standards of Performance for 

New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration (CISWI) Units; National Emission Standards for Hazardous 
Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; National 

Emission Standards for Hazardous Air Pollutants for Industrial/Commercial/Institutional Boilers 

and Process Heaters; and Identification of Non-hazardous Secondary Materials (NHSM) that are 

Solid Waste” that is located in the docket on how we addressed environmental justice.

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 82

Comment: Many of the other air toxics pollutants seen from these sources cause cancer 

including, formaldehyde, dioxin, furans, and hydrochloric acid. My mother is battling cancer, 

and I hope to do all I can to shelter myself and the rest of our family from such a 

cruel disease. Because these devices are so numerous and so widespread the air pollution 

infiltrates communities across the nation. 

Their harm settles heaviest on those who live near them, communities often that are poor, less 

educated and populated by minorities. Study after study confirms that it can harm these 

individuals far more than it does others. 

Response: EPA thanks the commenter for their input. See the document “Review of

Environmental Justice Impacts for the following Proposed Rules: Standards of Performance for 

New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration (CISWI) Units; National Emission Standards for Hazardous 

Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; National 

Emission Standards for Hazardous Air Pollutants for Industrial/Commercial/Institutional Boilers 

and Process Heaters; and Identification of Non-hazardous Secondary Materials (NHSM) that are 

Solid Waste” that is located in the docket on how we addressed environmental justice.

Commenter Name: Houston Public Hearing Transcript

Commenter Affiliation: See transcript for detailed list of commenters

Document Control Number: EPA-HQ-OAR-2006-0790-0985

Comment Excerpt Number: 91

Comment: At the same time, as well, there is another study going on in Corpus Christi 

concerning benzine releases from current existing refineries in the area. This is conducted by a 

local group called the Citizens for Environmental Justice, conducted after ten years of refusal to 

bond the Texas commissioner on environmental quality to conduct such a study. That 

year-end study determined there were absorbantly high benzine levels in people living in the 

Hillcrest community immediately adjacent to several refineries in the northern part of Corpus 

Christi. 

In Addition to that, as we determine now, as a consequence of that study, that hundreds of 
millions of dollars worth of hydrocarbons are in the ground and the groundwater beneath the 

Hillcrest neighborhood currently right now seeping into people’s homes and into their 

bloodstreams. We would urge that the EPA -- TCEQ, as well, and specifically the EPA move 

toward a more cumulative study of emissions -- to look at the emissions not just at any one plant, 

but of all those in the immediate vicinity, whether it be looking at SO2 or mercury or lead or 

particulate matter or what have you. 

Response: EPA thanks the commenter for their input. See the document “Review of

Environmental Justice Impacts for the following Proposed Rules: Standards of Performance for 

New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration (CISWI) Units; National Emission Standards for Hazardous 

Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; National 

Emission Standards for Hazardous Air Pollutants for Industrial/Commercial/Institutional Boilers 

and Process Heaters; and Identification of Non-hazardous Secondary Materials (NHSM) that are 

Solid Waste” that is located in the docket on how we addressed environmental justice.

Commenter Name: Robert H. Colby and G. Vinson Hellwig

Commenter Affiliation: National Association of Clean Air Agencies (NACAA)

Document Control Number: EPA-HQ-OAR-2006-0790-2022.1

Comment Excerpt Number: 30

Comment: In its discussion of environmental justice issues, EPA asserts that the rule meets 

environmental justice concerns because it does not increase HAP emissions in minority and low 

income areas. We suggest that this is too low a test for disparate impact. If this rule reduced HAP 

emissions broadly across the country, except in minority and low-income areas, a disparate 

impact might result. Here, it has been established that industrial boilers are often located in 

minority/low-income communities and that the reductions in HAPs from the proposed rule will 

in fact disproportionally impact those communities – but in a beneficial way. EPA’s preamble 

should reflect this fact. 

Response: EPA thanks the commenter for their input. See the document “Review of

Environmental Justice Impacts for the following Proposed Rules: Standards of Performance for 

New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration (CISWI) Units; National Emission Standards for Hazardous 

Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; National 

Emission Standards for Hazardous Air Pollutants for Industrial/Commercial/Institutional Boilers 

and Process Heaters; and Identification of Non-hazardous Secondary Materials (NHSM) that are 

Solid Waste” that is located in the docket on how we addressed environmental justice.

Commenter Name: N/A

Commenter Affiliation: Sierra Club, Earth Justice, Clean Air Task Force, Natural Resources 

Defense Council
Document Control Number: EPA-HQ-OAR-2006-0790-1982.1

Comment Excerpt Number: 35

Comment: EPA HAS FAILED TO ADEQUATELY CONSIDER ENVIRONMENTAL 

JUSTICE. 

EPA says it can’t examine environmental justice issues in the area source rule for boilers, but 

believes the "substantial" emission reductions will have benefits for "all persons" living near area 

source boilers. 75 Fed. Reg. at 31294. But if these boilers go from burning natural gas to plastics 

and spent solvents, clearly emissions will rise for those boilers. Environmental justice is about 

affording equal protection to everyone, so even though for the entire class of thousands of area 

source boilers emissions will have been reduced, clearly at the boilers burning waste emissions 

will have risen. 

In the major source and CISWI rules, EPA admits that minorities are disproportionately 

impacted but claims that because the rule does not "allow emissions increases" it won’t have EJ 

impacts. 75 Fed. Reg. at 32048 and 75 Fed reg. at 31973. Burning waste instead of natural gas or 

oil or coal will make emissions of air toxics rise, so EPAs claim that emissions cannot rise is 

fiction. The fact is that it will be the boilers who need the added economic benefit of replacing 

their fuel costs with waste burning that are most likely to burn waste, such as schools, hospitals, 

low-income apartment buildings, etc. The result of this is that air toxics emissions will rise at 

precisely places where reductions should occur (schools, hospitals, and residences). 

Response: EPA thanks the commenter for their input. See the document “Review of

Environmental Justice Impacts for the following Proposed Rules: Standards of Performance for 

New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration (CISWI) Units; National Emission Standards for Hazardous 

Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; National 

Emission Standards for Hazardous Air Pollutants for Industrial/Commercial/Institutional Boilers 

and Process Heaters; and Identification of Non-hazardous Secondary Materials (NHSM) that are 

Solid Waste” that is located in the docket on how we addressed environmental justice.

Commenter Name: Cheryl Johncox

Commenter Affiliation: Minneapolis Neighbors for Clean Air

Document Control Number: EPA-HQ-OAR-2006-0790-1971

Comment Excerpt Number: 12

Comment: The EPA should continue to consider the disproportionate impact that incinerators 

have on poor and minority communities. According to the EPA’s webinar on national emission 

standards for boilers, process heaters and incinerators, [Environmental Protection Agency. 

Background on National Emission Standards for Industrial, Commercial, and Institutional 

Boilers and Process Heaters; and Commercial/Industrial Solid Waste Incinerator (CISWI) Units. 

(2010). Retrieved from http://www.epa.gov/apti/webinars/20100609combustion.pdf] for 

populations living near disposal and processing facilities that may receive wastes diverted from 

incinerators, the results suggest that percentages of low-income and minority populations are 

slightly higher than national average. These results should not be used to justify avoidance of 
heightened standards for incinerators because low-income communities are already 

disproportionately affected by air pollution. [Ash, Michael & Boyce, James. (2009). Tracking 

Toxic Pollution from America’s Industries and Companies to our States, Cities and 

Neighborhoods. Pg. 8. Retrieved from 

http://college.usc.edu/pere/documents/justice_in_the_air_web.pdf.] The pollution from industrial 

air pollution sources, such as incinerators, accumulates in places where minority populations are 

disproportionately affected. Id. The EPA should do more studies to test the background levels of 

already existing pollution of communities affected by incinerator emissions. Background levels 

of air pollution in these communities are often higher than in other areas because, in general, 

low-income neighborhoods experience more of all forms of pollution (including air and water 

pollution, as well as toxic waste pollution) than do neighborhoods that maintain higher levels of 

income. [Morello-Frosch, Rachel. “Discrimination and the Political Economy of Environmental 

Inequity.” Environment and Planning C: Government and Policy. 2002, Vol. 20, pp.477-496.] 

For example, a biomass incinerator was planned to be built in Springfield, Massachusetts, a city 

described as already having “an ‘F’ in air quality.” [Mobilization for Climate Justice. (2010). 

Coaltion of Activists Protest Biomass Incinerators at State Global Warming Hearing in 

Springfield, Massachusetts. Retrieved from 

http://www.actforclimatejustice.org/2010/06/coalition-of-activists-protest-biomass-incineratorsat-state-g lobal-warming-hearing-in-springfield-massachusetts/#more-2973.] In fact, Springfield 

ranks number fourteen on the Asthma and Allergy Foundation of America’s ranking of U.S. 

Metropolitan areas according to prevalence of asthma. [Human Resources. Business and Legal 

Resources. (2004). Asthma Group Ranks Worst Metro Areas. Retrieved from 

http://hr.blr.com/newsAlternate.aspx?category=5&topic=66&id=9412.] The EPA should use the 

results of studies of background emissions to strengthen regulation of emissions; for example, if 

an inner-city community already has high dioxin emissions, emission standards should be higher. 

Response: EPA thanks the commenter for their input. See the document “Review of

Environmental Justice Impacts for the following Proposed Rules: Standards of Performance for 

New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration (CISWI) Units; National Emission Standards for Hazardous 

Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; National 

Emission Standards for Hazardous Air Pollutants for Industrial/Commercial/Institutional Boilers 

and Process Heaters; and Identification of Non-hazardous Secondary Materials (NHSM) that are 

Solid Waste” that is located in the docket on how we addressed environmental justice.

Commenter Name: Chris Mello

Commenter Affiliation: Alaska Energy Authority

Document Control Number: EPA-HQ-OAR-2006-0790-1653.1

Comment Excerpt Number: 18

Comment: This rule will unnecessarily raise heating costs for rural Alaska populations that are 

predominantly Alaska Native and have incomes predominantly below the poverty level. If these 

communities cannot manage their energy costs, the sustainability of this lifestyle is in peril. This 

unintended consequence of increased costs to install and operate biomass district heating systems 
will force communities to continue to use antiquated and inefficient diesel heating fuels and will 

force them to continue to pay the highest fuels costs in the nation. Unemployment will continue 

as biomass harvest jobs do not materialize. This rule will hinder the ongoing and substantive 

effort to move rural power generation and heating in Alaska to renewable sources. We do see the 

potential for an environmental justice problem associated with this rule unnecessarily increasing 

power and heating costs. 

Response: EPA thanks the commenter for their input. See the document “Review of

Environmental Justice Impacts for the following Proposed Rules: Standards of Performance for 

New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration (CISWI) Units; National Emission Standards for Hazardous 

Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; National 

Emission Standards for Hazardous Air Pollutants for Industrial/Commercial/Institutional Boilers 

and Process Heaters; and Identification of Non-hazardous Secondary Materials (NHSM) that are 

Solid Waste” that is located in the docket on how we addressed environmental justice.
Table 1