Summary of Interagency Working Comments on Draft Language under 

EO12866 Interagency Review. Subject to Further Policy Review.

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AREA SOURCE BOILER RULE 

Comments:

 Page 18, Item B.4: It is stated that a boiler is not temporary if it is moved from one location to 

another in an attempt to circumvent the residence time (maximum consecutive 12 months) 

requirements of the definition of a temporary boiler. Further clarification of this requirement 

would be very helpful. If a facility requires a boiler for 10 months of a year and decides to rent a 

mobile unit, would it be allowed to use the same mobile unit at some other location within the 

same plant or another plant in the system?

 Revise the emission limit tables by changing “Particulate Matter” to “Particulate Matter 

(Filterable)” as was done in the CISWI rules so that it will be clear that the limits do not include 

condensable particulate matter.

 Change “less than” to “equal to or less than” in section VI end of first paragraph (page 57) and 

in two places in 63.11223(d). Rationale: The proposal is not consistent as to whether an oil-fired 

unit rated 5 MMBtu/hr or more is subject to a biennial tune-up or five-year tune-up. At the end 

of the paragraph in section IV G.1. (page 24) it says "We are proposing ... to change the 

requirement for subsequent tune-ups only for oil-fired boilers equal to or less than 5 MMBtu/hr 

to a tune-up once every 5 years." This is consistent with Table 2 to subpart JJJJJJ, items 4, 5, 8, 

and 9 (page 90) which indicates biennial tune-ups are required for units greater than 5 

MMBtu/hr and five-year tune-ups for units 5 MMBtu/hr and below. However at the end of first 

paragraph in section VI and in the proposed revision to 63.11223(d) (in two places) it refers to 

oil-fired units "less than 5 million Btu/hr". 

 Change definition of “fossil fuel-fired” to “fossil fuel-fired EGU” or delete this term and merge 

with the definition of EGU. Note: this comment is consistent with comments on the EGU. We 

suggest these definitions be consistent in all of the rules. We note that the definition of EGU was 

added to the major source rule but not the definition of “fossil fuel-fired.” Rationale: Definition 

of “fossil fuel-fired” does not seem to be necessary. If it remains it should probably be “fossil 

fuel-fired EGU.” The only place that term is used in the rule is in the definition of “electric utility 

steam generating unit (EGU)” which was also added. It does not seem appropriate to limit the 

definition of “fossil fuel-fired” to EGUs. Two options for addressing this comment follow:

Option 1: Consider changing as follows (some changes are to make the definition consistent with the 

draft EGU rule): 

Fossil fuel-fired EGU means an electric utility steam generating unit (EGU) that is capable of 

combusting more than 25 MW of fossil fuels. To be “capable of combusting” fossil fuels, an EGU 

would need to have these fuels allowed in their operating permits and have the appropriate fuel 

handling facilities on-site or otherwise available ( (e.g., coal handling equipment, including coal 

storage area, belts and conveyers, pulverizers, etc.; oil storage facilities). In addition, fossil fuelfired EGU means any EGU that fired fossil fuels for more than 10.0 percent of the average annual 

heat input in any 3 consecutive calendar years or for more than 15.0 percent of the annual heat 

input during any one calendar year after [COMPLIANCE DATE OF THE FINAL EGU RULE].
Summary of Interagency Working Comments on Draft Language under 

EO12866 Interagency Review. Subject to Further Policy Review.

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Option 2: Alternatively, instead of adding this definition, recommend deleting the term “fossil fuelfired EGU” and merge the relevant text with the definition of EGU as follow (some changes are to 

make the definition consistent with the draft EGU rule):

Electric utility steam generating unit (EGU) means a fossil fuel-fired combustion unit of more than 25 

megawatts that serves a generator that produces electricity for sale. A fossil fuel-fired unit that 

cogenerates steam and electricity and supplies more than one-third of its potential electric output 

capacity and more than 25 megawatts electrical output to any utility power distribution system for sale 

is considered an electric utility steam generating unit. To be “capable of combusting” fossil fuels, an EGU 

would need to have these fuels allowed in their operating permits and have the appropriate fuel 

handling facilities on-site or otherwise available (e.g., coal handling equipment, including coal storage 

area, belts and conveyers, pulverizers, etc.; oil storage facilities). In addition, fossil fuel-fired EGU means 

any EGU that fired fossil fuels for more than 10.0 percent of the average annual heat input in any 3 

consecutive calendar years or for more than 15.0 percent of the annual heat input during any one 

calendar year after [COMPLIANCE DATE OF THE FINAL EGU RULE].

Fossil fuel-fired means an electric utility steam generating unit (EGU) that is capable of 

combusting more than 25 MW of fossil fuels. To be “capable of combusting” fossil fuels, an EGU 

would need to have these fuels allowed in their operating permits and have the appropriate fuel 

handling facilities on-site (e.g., coal handling equipment, including coal storage area, belts and 

conveyers, pulverizers, etc.; oil storage facilities).

Corrections:

 Page 69. Revise instructions for amendment 2 to clarify that paragraph (c) is being changed. Also 

the amended introductory text for 63.11195 says "(a) through (i) " but should say "(a) through (k)."

 Page 77. 63.11223(d) Change "oil-fire" to "oil-fired" in two places in this paragraph.

 Page 78. Revise instructions for amendment 11 to clarify that paragraph (a)(5) is being changed.

 Page 81. Revise instructions for amendment 12 to clarify that paragraph (g) is being added.

 Page 84: Revise instructions for amendment 13 to include the definitions added to the rule in the 

redline version.

 Page 91/92. Definition of Qualified Energy Assessor is followed by "mean" which should be changed 

to "means". The first part of the definition is awkward; too many prepositions. It appears that the 

entire change in the definition consists of changing "to opportunity" to "for opportunity” in the 

introductory sentence. Perhaps the sentence can be more simply stated as "(1) someone who has 

demonstrated capabilities to evaluate energy savings opportunities for steam generation and major 

energy using systems, including, but not limited to:"
Summary of Interagency Working Comments on Draft Language under 

EO12866 Interagency Review. Subject to Further Policy Review.

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Major Sources

 Can EPA explain how it would establish a limited use subcategory based on a capacity factor 

approach (10% CF), rather than 10% of the time in a year?

 Define natural gas curtailment.

 In the Background section that begins on page 11, EPA should consider providing a summary of 

the issues that it reconsidering in this action, to assist the public in understanding this rule.

 Page 15, 2nd Paragraph: This paragraph establishes the criteria under which a multi-fueled 

combustion unit would be subjected to either liquid or solid fuel-based emission limits for fuelbased pollutants. The criteria appear to cover only those units that co-fire liquid and solid fuels. 

Are there units in your database that co-fire liquid and gaseous fuels? Specifically, if a unit fires 

less than 10 percent liquid fuel and the rest as gaseous fuel, would it be covered under the 

emission limits for gas?

 Page 16, 2nd Paragraph: Same question for the combustion-based pollutants as in above Item 1.

 Pages 18 – 20, Table 1: We are requesting further clarifications on the following items:

o In several places, the emission limit for a particular pollutant and source subcategory is 

indicated by “NA.” It is not clear as to what “NA” stands for. For example, for HCl and 

Hg emission limits, it appears that the emission limits shown for existing solid fuel 

boilers may apply to all other subcategories of solid fuel boilers. However, for the 

existing biomass kiln-dried stokers, the same “NA” shown for the alternate CO CEMS 

limit, may mean no applicable emission limit. Please confirm.

o A 3-run average test requirement (Note a) is shown for particulate matter and CO? 

Since this note does not appear for HCl and Hg, does it mean that a compliance test is 

not required for these two pollutants?

o On Page 15, it is stated that a liquid-fueled unit firing less than 10 percent solid fuel 

would have to meet the required liquid fuel emission limits. Do these emission limits 

(e.g., for HCl and Hg) still apply, if this unit fires solid fuel only for a short period? 

 Page 24, 2nd Paragraph: It would be very helpful if the points of measurement for the pressure 

drop are defined, i.e., from what point to what point in the scrubber?

 Pages 17-21, Table 1: We understand the establishment of a compliance option that allows the 

use of CO CEMS as an alternative to CO stack testing and oxygen monitoring. If an affected 

source currently uses CO CEMS, it seems unreasonable to require that they install additional 

monitoring equipment for CO stack testing. However, we note that the CO CEMS limits appear to 

be very different in some instances than the CO stack testing limits (e.g., 1400 ppm versus 58 

ppm for Biomass Dutch Ovens for the CO CEMS and CO stack testing limits respectively). We 

request further information and explanation on the reasons and implications of these very 

different limits.

 Pages 220-224, §63.7533 “Can I use emission credits earned from implementation of energy 

conservation measures to comply with this subpart?” While we understand EPA’s desire to 

recognize facilities that implement energy efficiency measures that improve the efficiency of or 
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impact the steam required from affected units, we are concerned over the lack of guidelines and 

specific requirements for the emissions credits. Specifically, we are concerned with directing the 

source to create criteria for determining the energy savings from each measure implemented, as 

well as requiring an applicable delegated authority to review and approve this. We believe it will 

be difficult to adequately estimate the impact of many potential efficiency measures without 

detailed guidelines and requirements. We also question the validity of recognizing efficiency 

measures that may have been implemented as far back as 2008. It would seem that the 

establishment of an output-based emissions limit option itself would already incorporate the 

value of these past efficiency measures. We are concerned that the way this subpart is 

structured, it could a) create national inconsistency in how emissions credits are created and 

applied (possibly creating gaming), and b) burden the “applicable delegated authority” who do 

not have expertise on energy efficiency measures in industrial facilities. We recommend EPA 

explicitly take comment on the emission credit concept, how to administer it consistently 

across the country.

o Page 49: “Legal Authority for Emission Credits. One petitioner questioned the legal 

authority of the emission credit system and stated that it should be removed from the 

final rule. However, the petitioner provided no support for its position, and the EPA 

continues to believe that the emission credit system is legal as promulgated. Therefore, 

no changes are being proposed.” We request additional information from EPA on the 

legal authority for the emission credit system as proposed. Does EPA outline the legal 

rationale for these emissions credits somewhere else? Can this be explained again here?

- In anticipation of public comments requesting health-based emissions limits for acid gases (and 

because this issue was raised in the petitions for reconsideration), we believe this proposed rule 

would be strengthened by clearly articulating EPA’s reasoning for not proposing health-based 

emissions limits for acid gases.

 Revise the emission limit tables by changing “Particulate Matter” to “Particulate Matter 

(Filterable)” as was done in the CISWI rules so that it will be clear that the limits do not include 

condensable particulate matter. This clarification would be consistent with the preamble which 

refers to “the filterable PM emission limits” on pages 46 and 115.

 Double check the alternate CO CEMS 10-day average emission limits. Many of the limits are 

higher than the 3-run average limit which would be expected. However, some of the limits are 

lower (some by a factor of 6).

Corrections:

 Table 2 to subpart DDDDD: 1) In 4th column, delete “(lb per MMBtu of steam output)” from the 

heading row since limits in this column of the table are not all in these units. 2) The sample 

volume in the last column of item 1a should probably be 120 liters (should match item 1a of 

Table 1 to subpart DDDDD since the limits are identical). 3) In the last column for item 10c, the 

footnote after D6784 should be b instead of a.

 Table 6 to subpart DDDDD: Based on alignment of methods for item 3, it is not clear if they all 

apply to both a and b or if the first method applies to item a and the rest to item b.

 Table 8 to subpart DDDDD: Delete the word “block” from item 7b. Also item 11c should be 11b.

 Table 10 to subpart DDDDD: Add “§” in front of 63.8(g).
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RIA

REGULATORY IMPACT ANALYSIS: NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS FOR INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL BOILERS AND PROCESS HEATERS

General Comment:

We appreciate EPA’s efforts to provide an update to the Boilers RIA. We appreciate the updated 

information provided at the beginning of the RIA. We request that the current organization be 

maintained, with the previous RIA included as an Attachment (e.g. Attachment A). For the updated 

material at the front, we’d suggest for both the costs and the benefits that the changes be delimited in 

the following way, and presented in a summary CBA table:

- Methodological/Estimate changes

- Rule changes

With the approach outlined above, it should be easier for the reader to understand how/why the costs 

and benefits estimates have changed.

Specific Comments

Section 2.1.3.8, Page 2-14, Table 2-10; Section 2.2.3.8, Page 2-30, Table 2-18; Section 2.3.3.5, Page 2-

47, Table 2-28; Section 2.4.3.9, Page 2-66, Table 2-39: The employment total is far higher than the total 

calculated by adding up the various columns. For example, in Table 2-39, employment totals 827,430, 

but adding up the various columns only results in around 300,000 employees. Therefore, unless there 

are around 500,000 employees in the 1,500+-employee category, then there is an error.

Section 4.1.2.4.1, Page 4-11, Table 4-3: Since the overall results of the Morgenstern et al. study are 

statistically insignificant, it seems more practical to not provide corresponding job estimates, but to 

simply indicate the overall employment impacts were found to be statistically insignificant.

Section 7.2.5, Page 7-14, top and bottom paragraphs: It seems a range for value of statistical life should 

be used rather than the mean value. Making this adjustment would provide an improved measure of 

uncertainty in the benefits calculations.

Section 7.3, Page 7-21, Table 7-2 and Table 7-3: The table shows the estimated reductions in health 

incidences for both SO2 and Direct PM 2.5. Since some studies have found no significant effect of 

PM2.5 on mortality, perhaps zero should be included in the PM 2.5 and SO2 range (since SO2 is included 

because it is a precursor to PM 2.5), as Electric Power Research Institute has suggested. EPRI indicated: 

“Since some models in some studies do not find a statistically significant effect of PM2.5 on mortality, 

the effects range could even include zero...” (Source: EPRI PM2.5 Reductions and Impact on Premature 

Death: An EPRI perspective; Issue Brief 1018632.) In addition, the same EPRI briefing states the EPRIWashington University Veterans Study did not find any statistically significant mortality associations with 

PM2.5, but found some PM components that were significantly associated with mortality. The EPRI 

briefing goes on to say: “Of great significance for CAIR, this study did not find a significant association 

between the sulfate component of PM and mortality...if this study were used to derive estimates of 

health benefits attributable to reductions in SO2 emissions, the numbers would differ from those 

derived from the Pope et al...some studies have shown that estimated impacts of PM diminish when 

other co-pollutants are considered in the analyses. If the co-pollutants are indeed associated with 

increased mortality and are correlated with PM levels, then the PM effects estimated from this single 

pollutant model approach can be biased upwards.”

Additionally, why does the study focus on the mortality estimates of fine particulate matter from two 

studies? Given that there are a number of studies available, these studies should be used to develop 
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the estimates for the RIA. An EPRI study (Issue Brief 1018632, “PM2.5 Reductions and Impact on

Premature Death: An EPRI Perspective”) includes the following statements.

“Since some models in some studies do not find a statistically significant effect of PM2.5 on 

mortality, the effects range could even include zero...” 

“The EPRI-Washington University Veterans study did not find any statistically significant 

mortality associations with PM2.5, but found some PM components that were significantly 

associated with mortality.”

“Of great significance for CAIR, this study did not find a significant association between sulfate 

component PM and mortality ... if this study were used to derive estimates of health benefits 

attributable to reductions in SO2 emissions, the numbers would differ from those derived from 

the Pope, et al study.”

“Some studies have shown that estimated impacts of PM diminish when other co-pollutants are 

considered in the analyses. If the co-pollutants are indeed associated with increased mortality 

and are correlated with PM levels, then the PM effects estimated from this single pollutant 

model approach can be biased upwards.”

Section 7.3, Page 7-22, Table 7-4: It would be useful to indicate the average (or a range) number of 

years for avoided premature mortality (i.e., on average, those with who would otherwise experience 

premature mortality, would be expected to live X number of years longer.)

The following comments refer to the preamble for the major sources rule, but are also applicable to the 

area sources rule.

- On page 122, the preamble addresses the US trade deficit. For clarity, we recommend revising 

the sentence that reads, “The change in US surplus is now -1.93 billion dollars (2006$)” with the 

following sentence, “The increase in US trade deficit is now 1.93 billion dollars (2006$).”

- In the discussion of economic impacts on page 124, over what time frame do the estimated 

employment changes occur and what is the primary driver for the estimated change in benefits?

- On page 125, the preamble states, “These monetized benefits are approximately 23 percent 

higher than the final rule benefits due to the increase in SO2 emission reductions.” Are these 

net of the increased SO2 secondary emissions mentioned in the following section on secondary 

benefits?

- How does EPA define the term “secondary air impacts” on page 127? Additionally, EPA notes on 

page 127 that it does not estimate an “increase in secondary air impacts for this final rule from 

additional electricity demand.” Does the RIA count the benefits from reduced emissions of 

these pollutants? Should this sentence refer to “proposed” rule, rather than “final” rule?