May 20, 2011

The Honorable Lisa P. Jackson

Administrator

U.S. Environmental Protection Agency

1200 Pennsylvania Avenue, NW

Washington, D.C. 20460

Re: Amended Request for Administrative Reconsideration of: (1) the 

National Emission Standards for Hazardous Air Pollutants for Major 

Sources: Industrial, Commercial, and Institutional Boilers and Process 

Heaters, 76 Fed. Reg. 15,554 (Mar. 21, 2011) (Docket No. EPA–HQ–

OAR–2002–0058), (2) the Standards of Performance for New Stationary 

Sources and Emission Guidelines for Existing Sources: Commercial and 

Industrial Solid Waste Incineration Units, 76 Fed. Reg. 15,704 (Mar. 21, 

2011) (Docket No. EPA–HQ–OAR–2003–0119) and (3) National 

Emission Standards for Hazardous Air Pollutants for Area Sources: 

Industrial, Commercial, and Institutional Boilers, 76 Fed. Reg. 15554 

(March 21, 2011) Docket ID No. EPA–HQ–OAR–2006–0790)

E-Docket No. EPA-HQ-OAR-2003-0058

Dear Administrator Jackson:

American Petroleum Institute (API)1 and the National Petrochemical and Refiners 

Association (NPRA)2 are writing to supplement our request for administrative 

reconsideration of several elements of the above referenced rules. On May 7, 2011, we 

filed a request for reconsideration and stay of certain aspects of the rule. In that petition 

we noted that we intended to supplement that request for reconsideration with additional 

issues. Today we are seeking reconsideration of the additional issues contained in the 

attached list.

 1 The American Petroleum Institute is a national trade association with over 470 member companies that 

are involved with all aspects of the oil and natural gas industry. 2 The National Petrochemical and Refiners Association is a national trade association whose members

comprise more than 450 companies, including virtually all United States refiners and petrochemical 

manufacturers. NPRA’s members supply consumers with a wide variety of products and services that 

are used daily in homes and businesses.
API/NPRA’s Petition for Reconsideration

May 20, 2011

Page 2

Pursuant to Clean Air Act § 307(d)(7)(B), 42 U.S.C. § 7607(d)(7)(B), where it 

was impracticable to raise an objection during the period of public comment or if the 

grounds for such an objection arise after the public comment period (but within the time 

specified for judicial review), and if such objections are of central relevance to the 

outcome of the rule, EPA is authorized to reconsider the rule. As we stated in our 

previous submissions, key provisions of the final rule were not raised in the proposed 

rule, leaving many companies with compliance deadlines that they had no opportunity to 

plan for and will have little or no ability to meet. Hence, there was no opportunity to 

raise objections to these provisions during the public comment period and they are of 

central relevance to the ability of the refining industry to comply.

API and NPRA strongly support many aspects of the rule. In particular, the 

adoption of a work practice for Gas 1 units is consistent with the Clean Air Act, 

supported by the record, and protects the environment while encouraging the use of this 

clean burning fuel. In addition, we strongly support the Agency’s decision to stay the 

Boiler major source and CISWI rules. Simply put, EPA needs more time to develop rules 

of the depth and breadth such as these. In that spirit, we believe that EPA reconsideration 

of the attached issues will make the rules clearer and easier to implement and comply 

with, while continuing to protect the environment. For this reason, we urge the agency to 

take quick action on the area source rule which is not subject to the recently promulgated 

stay.

Thank you for your time and attention. If you have any questions, please contact 

Matt Todd at 202-682-8319.

Sincerely,

/s/

Matthew Todd

API

toddm@api.org

202-682-8319

/s/

David Friedman

NPRA

dfriedman@npra.org

202-552-8461

Cc: Gina McCarthy (OAR)

Brian Shrager (OAQPS)

Robert Wayland (OAQPS)
API/NPRA Boiler and Process Heater Major Source Reconsideration Issues

Issue Comments

Rigorously address the “contained gas” issue. 

Add the original contained gas definition back 

into the CISWI rule, add it to the solid waste 

definition in 40 CFR §258,2, and add it to the 

Major Source rule.

If the historical definition of contained gas is 

not confirmed through rule language to assure 

gases in pipelines are never solid wastes, 

withdraw all portions of the major source 

BPH and CISWI rules dealing with gases and 

start over.

EPA’s May 16 letter on the contained gas issue does not override the notice 

and comment CISWI rule action of removing the contained gas definition in 

the existing CISWI rule or the response to comment explaining the reasons 

for removing that definition. Until regulatory action is taken, it remains 

unclear what gas combustion units are subject to the CAA 112 rules and 

which to the 129 rule. 

Pending such resolution, the BPH MACT gas fired unit database must be 

purged of the large number of potential CISWI units that it includes and all 

emission limits, costs, and impacts recalculated and the rule requirements 

for gas fired equipment must be reproposed.

The fact that the EPA database for this rulemaking does not align with the 

Non-Hazardous Secondary Material rule definition, makes clear that the 

Agency did not provide adequate notice that this change was possible and, 

therefore, did not provide adequate notice for us to comment on this point 

during the BPH Major Source comment period.

Oil limits may be unattainable for oil fired 

units at island refineries.

See island refinery reconsideration and stay petition.

The data available does not support the limits 

for dioxin and furans for the oil subcategory 

and work practice requirements should be 

specified instead, as was done in the recent 

electric utility proposal.

The non-continental and continental oil subcategory’s dioxin/furan limits 

were derived from data that was derived from extremely limited data, most 

of which were non-detects. In addition, the analysis of that data failed to 

appropriately consider variability and particularly, variability in the 

detection limits. Overall, the emission limits for dioxin/furans are not 
Issue Comments

reflective of the subcategories and do not properly consider variability and 

thus should be reconsidered and work practice limits developed in their 

place as allowed under CAA 112(h).

Energy assessment requirements are 

unreasonable, not based on law and for sites 

using boilers and process heaters using less

than 1.0 trillion Btu per year, impossible to 

complete in the time allotted (i.e., 1 day or 

three days)..

No clear link to HAP emissions is established in the record. The 

energy assessment requirements do not account for safety, operability, 

capital availability or other considerations.

The energy assessment provisions go beyond the statutory 

authorization to regulate the affected source and deals with sources 

outside the BPH source category. The requirements also are ill-defined 

as to the timing for new sources added at a major source of HAP and 

have contradictory requirements that limit the time needed to conduct 

the assessment at complex sources such as petroleum refineries. For 

sites using <1 trillion BTU/year, the requirements specified for energy 

assessments cannot be completed in the maximum time allowed and for 

the source category as a whole the burdens imposed go far beyond the 

burdens included in the ICR. In an apparent effort reduce burdens, the 

final rule includes maximum times for certain assessments, however, 

those time (which were not proposed) are inadequate for even 

beginning an assessment as specified in the rule and those no purpose is 

served by even having the requirement sin the rule for those situations 

where a time limit is specified.

EPA added new language in the final rule that is not a logical 

outgrowth of the proposal and is not responsive to submitted 

comments. EPA responded “that [energy reductions] can be 

implemented to reduce the facility energy demand from the affected 

boiler, which would result in reduced fuel use. Reduced fuel use will 

result in a corresponding reduction in HAP, and non-HAP, emissions 

from the affected boiler.” In refinery operations, many of these 

proposed “efficiencies” would simply result in the transference of 
Issue Comments

emissions to outside the refinery boundary and increase overall 

emissions. One example is the shutdown of a steam turbine 

(decreasing refinery emissions) and replacing it with an electric driver 

(transferring the emissions outside the boundary of the refinery) and 

increasing US emissions. Furthermore, no consideration was given to 

the emissions resulting from reduced equipment reliability or the 

potential impacts of energy reduction steps on safety or operability.

Since there are no health impacts or other

benefits from the requirements for gas fired 

BPH, there should be no requirements. 

Alternately, gas fired BPH should be 

subcategorized and delisted.

While not separately discussed in the preamble, careful review of the record 

indicates there are essentially no benefits (HAP reductions) from imposing 

requirements on gas-fired equipment. While the work practice requirements 

for such units impose relatively small costs (in most cases) compared to the 

cost that would have been imposed by numerical emission limits, the work 

practice costs are still significant (particularly if they force extra process 

shutdowns as discussed separately) and there is no justification for

imposing even those costs since there are no HAP benefits.

Withdraw and reconsider the affirmative 

defense provisions.

These provisions were not proposed and are not a logical outgrowth of 

comments and must be withdrawn. If the Agency insists on continuing to 

include them in the final rule, these provisions must be proposed and 

comments taken on the handling of malfunctions in this rulemaking and the 

affirmative defense provisions and those comments must be seriously 

considered.

The 4 ppm H2S limit for “Other Gas” to be 

subject to the same requirements as refinery 

and natural gas is unreasonable and should be 

reconsidered.

Use of H2S criterion for classifying “Other Gas” as “Gas 1” was not 

proposed. None-the-less, use of such a criterion would be reasonable if it 

was set consistent with typical Gas 1 H2S levels. If such a criterion is 

imposed, it should be 162 ppmv determined on a 3-hour rolling average 

basis, the refinery gas criterion, since refinery gas is defined as a Group 1 
Issue Comments

gaseous fuel.

The exemption in BPH MACT for control 

devices should also apply to Part 60 and 61 

control devices.

The heat capacity basis for this exemption 

should be clarified as being an annual 

average.

BPH MACT has an applicability exemption (§63.7491(i)) for BPH that are 

used as control devices to comply with another Part 63 subpart and at least 

50% of the BPH heat input comes from gases regulated under another Part 

63 subpart. This exemption should be extended to all part 60 and 61 control 

devices, since the basis for the part 60 and 61 emission limits did not and 

continue not to reflect controls that have to meet the BPH requirements and 

because EPA should not be discouraging combustion controls for organic 

pollutants. Without this change the Part 60 Best Demonstrated Control 

Technology and the Part 61 Ample Margin of Safety are retroactively 

invalidated. 

The 50% threshold in this exemption is not clear. Consistent with the basis 

for subcategory applicability, we recommend this threshold be clarified as 

being based on the annual average heat duty.

It is unreasonable to apply the same 

requirements to units of <2 million BTU/hr, as 

to larger units.

Emission limits and even tune-ups for such small units are not justified by 

the negligible benefits that might occur, particularly for gas and light liquidfired equipment. Placing any requirements on these units will impose 

significant costs and burdens since these small units typically are not 

permitted under Title V, but now would have to be. Had these very small 

BPH been evaluated separately from larger units, we are sure the Agency 

would have found that no requirements currently apply.

Confirm that both fired and unfired waste heat 

boilers are exempted from rule requirements. 

Specify that units that heat hot water as a 

process heat transfer medium are process 

Boiler means an enclosed device using controlled flame combustion and

having the primary purpose of recovering thermal energy in the form of

steam or hot water. Controlled flame combustion refers to a steady-state, or 

near steady-state, process wherein fuel and/or oxidizer feed rates are 

controlled. A device combusting solid waste, as defined in § 241.3, is not a 
Issue Comments

heaters, not boilers. Both the boiler definition 

and the process heater definition appear to 

include hot water heaters, regardless of the 

use of that hot water. Use of hot water to heat 

process materials should be distinguished 

from use of hot water for space heating.

Exclude waste heat boilers from the process 

heater definition as is done in the boiler 

definition.

A definition of waste heat process heater is 

provided in the rule, but never used. An 

exclusion for waste heat process heaters 

should be added to the process heater 

definition, along with the waste heat boiler 

exclusion. Process heats can include either of 

those waste heat functions.

boiler unless the device is exempt from the definition of a solid waste 

incineration unit as provided in section 129(g)(1) of the Clean Air Act.

Waste heat boilers are excluded from this definition.

Process heater means an enclosed device using controlled flame, and the

unit’s primary purpose is to transfer heat indirectly to a process material 

(liquid, gas, or solid) or to a heat transfer material for use in a process unit, 

instead of generating steam. Process heaters are devices in which the

combustion gases do not come into direct contact with process materials. A

device combusting solid waste, as defined in § 241.3, is not a process heater 

unless the device is exempt from the definition of a solid waste incineration 

unit as provided in section 129(g)(1) of the Clean Air Act. Process heaters 

do not include units used for comfort heat or space heat, food preparation 

for on-site consumption, or autoclaves.

Waste heat boiler means a device that recovers normally unused energy and

converts it to usable heat. Waste heat boilers are also referred to as heat 

recovery steam generators.

Waste heat process heater means an enclosed device that recovers normally

unused energy and converts it to usable heat. Waste heat process heaters 

are also referred to as recuperative process heaters.

Confirm open-flame heaters (e.g., asphalt tank 

heaters) are not process heaters.

EPA is not clear on applicability for an asphalt tank heater: a small burner 

(e.g., < 1.75 MMBtu/hr) on the side of the tank with a flue that runs through 

the asphalt to keep it hot.

It appears there was no data for this type of source considered during the 

rulemaking.

This is another example of why a “small” source cut-off is important.
Issue Comments

Confirm that a BPH fired with Gas 1 and 

Specify what requirements apply when a BPH 

transitions between firing <10% liquids to 

firing no liquid.

<10% liquid is a Gas 1 unit not a Gas 2 unit.

Allow liquids limits to be averaged.

The rule is unclear that a BPH firing < 10% liquid and

If you stop firing <10% liquid, but still have the ability to fire liquid, it is 

unclear that the BPH is subject to the requirements for the type of gas being 

fired (i.e., subject to Gas 1 or Gas 2). Rule language could be read to say 

the Gas 2 requirements apply even if the gas fired is Gas 1. If a BPH has 

been firing >10% liquid and goes to firing no liquid or <10% liquid (with a 

federally enforceable limit) it is unclear if the liquid requirements still apply 

or whether the gas requirements apply, since subcategorization is based on 

design. Nor is it clear which gas requirements would apply in such a case. 

Assuming the liquid requirements no longer apply, at what point do the new 

requirements apply (e.g., when liquid is no longer being fired? When the 

10% liquid limit becomes federally enforceable?) 

refinery fuel gas or 

natural gas (i.e., Gas 1) is subject to Gas 1 requirements. Some read the 

rule language to say that such a BPH is subject to Gas 2 requirements, even 

if the gas being fired is Gas 1.

If you have multiple boilers firing Gas 1 and liquid, the source should be 

allowed to average the liquid firing over the group of boilers. This will 

greatly reduce the recordkeeping associated with assuring individual boilers

do not inadvertently slightly exceed the 10% criterion.

Address the interaction of BPH MACT with 

RCRA comparable fuels exemption.

A number of companies seem to understand that if they are burning 

comparable fuels, as defined under RCRA, they do not have to meet BPH 

requirements for those units. Is that correct?

Confirm input and output standards are 

alternatives.

Output standards were not proposed, but are included in Table 1. Rule 

language and the Table 1 headings are unclear that the heat input and steam 

output limits are alternatives and that the output requirements only apply to 

boilers. This should be corrected.
Issue Comments

For process heaters where required burner 

inspections cannot be done while the heater is 

in service, it is unreasonable to require a

process unit shutdown every 36 months to 

perform these inspections. This limitation 

should be reconsidered and removed.

This problem would be significantly 

ameliorated if the inspection requirement was 

aligned with current practice as discussed in 

the next item.

A significant number of process heaters are constructed in such a way that 

the burners cannot be physically inspected while the process heater is in 

service. Shutdown of process heaters generally requires a process unit 

shutdown and some process units operate for much longer than the three 

years EPA is allowing for delay of inspections. Thus, the BPH major 

source rule should allow an extension of the burner inspection requirement 

until the next planned

Forcing unnecessary, extra process unit outages increases emissions,

increases safety and operating risk, and wastes money and energy. The 

BPH rule should not be forcing such outages.

shutdown if the inspection cannot be performed with 

the process heater in service, to reduce the emissions and costs associated 

with unneeded process unit and process heater startups and shutdowns. 

Costs which, we might add, were not included in EPA’s evaluation of this 

requirement.

Inspections during unplanned shutdowns are not generally possible, because 

it takes many days to safely cool down a process heater, perform the 

inspection, and then safely bring the heater up to operating temperature 

again. 

The regulation should also clarify the timing for the rest of the tune-up 

procedure (i.e., CO measurements). We recommend that the rule specify 

that CO adjustments can be completed within 30 days after heater startup. 

Clearly the CO testing cannot be done with the unit down for visual 

inspection and it can take some time for the process heater and process unit 

to settle out after startup.

The burner inspection requirement for process 

heaters should be aligned with common 

practice.

The burner inspection requirement in §63.7540(a)(10)(i) should be deleted 

in recognition that §63.7540(a)(10)(ii) performs the same function,

represents the practice in the field and can be performed on BPH where the 
Issue Comments

burners are not accessible for physical inspection. The typically used 

approach to assuring optimum burner performance is inference of cleaned 

and properly adjusted burners from visual observation of the overall

conditions in the firebox (e.g., flame patterns), rather than requiring 

individual burner inspections. This is how it's done now in the field - you 

look for deficiencies in the combustion zone and if they are significant 

enough, you pull and repair the burner or repair the burner at the next 

planned process heater outage. Use of this approach, which is already 

required by §63.7540(a)(10)(ii) makes the (i) paragraph unnecessary and 

would allow tune-ups of most process heaters with inaccessible burners.

Consistent with the general provisions

(§63.7(a)(2)), 180 days should be allowed for 

the initial tune-up for a new BPH.

For new BPH, it can take some time to bring the unit to full rates, complete 

post-startup construction items, adjust burners and add-on pollution controls 

learn how to operate the BPH most efficiently. Furthermore, performance 

tests will typically be required for many pollutants. The BPH tune-up 

requirement needs to allow for all of this typical startup activity and thus 

should be required on the same schedule as other initial performance tests. 

A limited use exemption from CO testing is 

needed where BPH is not operating more than 

a few hours per year.

Some BPHs only operate for short periods, perhaps for only a few days per 

year or for only a few days, several times per year. In such cases, the BPH 

hardly has time to reach steady state conditions before it is shutdown and 

any CO or adjustments would have no impact, since the unit would be 

shutdown immediately after the adjustments. Such units should be 

exempted from the CO portion of the tune-up requirements. We 

recommend that the CO tune-up requirement only apply to a BPH that has 

operated continuously for at least one week. 

The definition of limited use should be 

adjusted to allow for very low rate operations.

A limited-use boiler or process heater is defined as “any boiler or process 

heater that burns any amount of solid, liquid, or gaseous fuels, has a rated 
Issue Comments

capacity of greater than 10 MMBtu per hour heat input, and has a federally 

enforceable limit of no more than 876 hours per year of operation.” Some 

units operate essentially continuously, but at very low rates, to allow for 

rapid response when needed in an emergency. Thus, we believe the limited 

use definition should be extended to units that only fire the equivalent of 

876 hours per year (i.e., boilers and process heaters that average <10% of 

design firing per year.)

The averaging time for CO compliance should 

be changed to 30 days.

Compliance with the CO limit for liquid-fired BPH is based on 12-hour O2

average in the final rule rather than a 30-day CO average, as in the proposal 

(Table 8, Item 8). As for CO, O2 can vary significantly as process 

conditions and even ambient conditions change and it can take some time 

for the O2 level to settle down. An extended averaging time is needed to 

obtain a true indication of the average oxygen level and thus for it to 

provide a true indication of organic HAP emissions, for which it is a 

surrogate. Additionally, the risk from the organic HAPs for which the O2 is 

a surrogate is primarily cancer risk, which is not related to short term (e.g., 

12 hour) exposures.

The BPH rule should allow use of CO CEMS 

for CO compliance as an alternate to O2

CEMS, where CO CEMS are available.

The rule requires use of O2 CEMS for demonstrating compliance with CO 

limit. But CO CEMS are already in place on some units and their use 

should be allowed, at the sources option.

Reconsider the O2 CEMS monitoring 

requirements.

To show continuous compliance with numeric CO limits, the rule requires 

use of an O2 CEMS to demonstrate compliance on a 12-hour block average 

basis with the minimum O2 operating limit established during performance 

testing. 

We support EPA’s rejection of the proposed requirement that every unit 

install a CO CEMS, especially when the proposed CO emission limit would
Issue Comments

have been based on stack test data obtained at full load conditions, but 

applied at all times. However, we do not believe it is appropriate or 

necessary to require that O2 levels be monitored in the stack or ductwork 

leading to the stack (versus the firebox) in order to ensure continuous 

compliance, nor is it appropriate or necessary for EPA to require that each 

O2 CEMS be installed, operated and maintained pursuant to Performance 

Specification 3. 

Many existing units already use flue gas O2 analyzers for indication, alarm, 

and O2 trim control, often with automatic air to fuel or draft control and it is 

unreasonable and unnecessary to force sources to add additional O2

analyzers or impose excessive analyzer QA/QC requirements. EPA should, 

through reconsideration, gather information on current O2 monitoring 

practices and give the regulated community’s experts a chance to participate 

in developing these provisions in a way that minimizes wasted efforts and 

eliminated unnecessary and potentially duplicative O2 CEMS installations

and requirements.

Furthermore, it is unsafe and technically impractical to limit O2 at turndown 

operating rates to the level achievable at performance test conditions and 

that limit should not apply below 50% of firing capacity.
API/NPRA Boiler and Process Heater Area Source Reconsideration Issues

Issue Comments

Temporary boiler exemption provided for boilers at 

major sources should be provided for area source 

boilers as well.

EPA correctly exempted temporary boilers from the major source

BPH rule. Consistent with that rule and for the same reasons, EPA 

should exempt temporary boilers from the area source boiler rule. 

EPA indicates the agency did not include temporary boilers in the area 

source rule because only a work practice standard is mandated. 

However, even the work practice requirement is problematic for 

temporary boilers. Temporary boilers are typically leased for short 

periods of time and are not owned by the stationary source 

owner/operator.

The work practice standards do not consider the possibility of the 

boiler being temporary. If a temporary boiler comes on to a facility,

the facility owner/operator, not the boiler owner, becomes responsible 

for compliance. This frequent transfer of compliance responsibility 

would be confusing and make compliance difficult. Obtaining records 

and ensuring compliance for a boiler where the compliance 

responsibility passes through many hands is not practical.

Additionally, it appears a new energy assessment would be required 

for the entire site whenever a temporary boiler is used. Such a 

requirement is unreasonable. For many sites the reason the temporary 

boiler is used is because there are no permanent boilers or consumers 

or because there is a temporary need for additional steam, so there is 

no value in doing an energy assessment, because the need for steam 

from the temporary boiler will end shortly. Nor would any 

adjustments made to the temporary boiler have any long term value, 

since the boiler would shortly be relocated and its operation changed.
Issue Comments

It is unreasonable to apply the same requirements to 

units of <2 million BTU/hr, as to larger units.

Emission limits and even tune-ups for such small units are not 

justified by the negligible benefits that might occur, particularly for 

gas and light liquid-fired equipment. Placing any requirements on 

these units will impose significant and unjustified costs. Had these 

very small BPH been evaluated separately from larger units, we are 

sure the Agency would have found that no requirements currently 

apply.

The exemption in BPH MACT for control devices 

should also apply to Part 60 and 61 control devices.

The heat capacity basis for this exemption should be 

clarified as being an annual average.

The area source rule has an applicability exemption (§63.11195(g)) 

for boilers that are used as control devices to comply with another Part 

63 subpart and at least 50% of the boiler heat input comes from gases

regulated under another Part 63 subpart. This exemption should be 

extended to all part 60 and 61 control devices, since the basis for the 

part 60 and 61 emission limits did not and continue not to reflect 

controls that have to meet the BPH requirements and because EPA 

should not be discouraging combustion controls for organic pollutants. 

Without this change the Part 60 Best Demonstrated Control 

Technology and the Part 61 Ample Margin of Safety are retroactively 

invalidated. 

The 50% threshold in this exemption is not clear. Consistent with the 

basis for subcategory applicability, we recommend this threshold be 

clarified as being based on the annual average heat duty.

Add a definition of process heater is needed in the area 

source rule and process heaters need to be clearly 

exempted in the boiler definition. 

Confirm that both fired and unfired waste heat boilers 

There is a lack of clarity around which units are boilers and which are 

not and that needs to be addressed. Also, see the discussion on the 

similar point in the major source list.
Issue Comments

are exempted from the boiler definition. 

Specify that units that heat hot water as a process heat 

transfer medium are process heaters, not boilers. Use 

of hot water to heat process materials should be 

distinguished from use of hot water for space heating.

Specify that “hot water” as used in the boiler 

definition is limited to pure water and does not include 

heating of mixtures of water with organics (e.g., water 

glycol mixtures used as process fluids or heat transfer 

media), acids or bases (e.g., sulfuric acid, sodium 

hydroxide), etc.

Confirm that boilers on a mobile source (e.g., drilling 

rig or hydrofracture completion unit) are not subject to 

the area source rule.

Reconsider the compliance time and allow three years 

for compliance.

While plain work practice standards probably can be implemented in 

less than three years, the area source work practice requires O2

sampling at a particular location (not the normal location for existing 

O2 monitors) and for many facilities sample ports and platforms will 

therefore have to be installed. 

A 3-year time frame is not unreasonable given the fact that EPA 

estimates there are 183,000 existing area source boilers and that 

approximately 7,000 new area source boilers are likely to come online 

in the next three years, facilities will be required in many cases, and 

combustion expertise will be in short supply (even for work practice 

training) because of the demands of this rule, the major source rule, 

the CISWI rule and the electric utility rule.
Issue Comments

Some sources will also have the added complication that existing air 

permits require tune-ups for NOx emissions and now these sources 

will be required to tune-up the boiler to minimize both NOx and CO 

emissions to the extent practicable and will have to revise their 

permits ( a slow process).

Finally, for many boilers, annual overhaul times might have already 

occurred or been scheduled and thus performing the initial area source 

tune-up requirements might require an extra shutdown to meet the one 

year timetable.

The duplicative and unnecessary requirement at 

§63.11214(d) to certify compliance with the startup 

and shutdown work practice requirement in the Notice 

of Compliance Status should be deleted.

The second part of §63.11214(d) requires “You must submit a signed 

statement in the Notification of Compliance Status report that 

indicates that you conducted startups and shutdowns according to the

manufacturer’s recommended procedures or procedures specified for a

boiler of similar design if manufacturer’s recommended procedures 

are not available.” Since the NCS is due only 120 days after the 

compliance date there will have been only a few, if any, startups and 

shutdowns to report. Furthermore, §63.11225(b)(2) and (3) requires 

annual reporting of deviations and a certification of compliance, 

making this NCS requirement duplicative and unnecessary. Thus, this 

requirement should be deleted. 

Withdraw and reconsider the affirmative defense 

provisions.

These provisions were not proposed and are not a logical outgrowth of 

comments and must be withdrawn. If the Agency insists on 

continuing to include them in the final rule, these provisions must be 

proposed and comments taken on the handling of malfunctions in this 

rulemaking and the affirmative defense provisions and those 

comments must be seriously considered.
Issue Comments

Revise the “subsequent performance test” 

requirements to fix the apparent drafting mistakes in 

the “less frequent testing” provisions of §§63.11220(b) 

and (c)

Allow use of CO CEMS for CO compliance as an 

alternate to O2 CEMS, where CO CEMS are available.

The rule requires use of an O2 CEMS for demonstrating compliance 

with the numeric CO limit, where one applies. But CO CEMS are 

already in place on some units and their use should be allowed, at the 

sources option.

Reconsider the requirement for area sources to submit 

the energy assessment report; clarify the scope of the

energy assessment; and, explain how “maximum” time 

frames for conducting an energy assessment is 

intended to work.

The short time frames (1 day or 3 days) provided for the energy 

assessment at smaller energy consumers means there will be no 

useful information gathered by this assessment and the specified 

assessment activities will not be accomplished. Thus, the 

assessment requirement should be dropped for all sources where 

time limits have been imposed. Even for big sources, the energy 

assessment requirement is unreasonable. No clear link to HAP 

emissions is established in the record. The energy assessment 

requirements do not account for safety, operability, capital 

availability or other considerations. Nor are the burdens 

associated with these assessments adequately reflected in the ICR.

The energy assessment provisions go beyond the statutory 

authorization to regulate the affected source and deals with 

sources outside the BPH source category. The requirements also 

are ill-defined as to the timing for new sources and have 

contradictory requirements that limit the time needed to conduct 

the assessment at complex sources such as petroleum refineries.

EPA added new language in the final rule that is not a logical 

outgrowth of the proposal and is not responsive to submitted 
Issue Comments

comments. EPA responded to comments “that [energy reductions] 

can be implemented to reduce the facility energy demand from the 

affected boiler, which would result in reduced fuel use. Reduced fuel 

use will result in a corresponding reduction in HAP, and non-HAP, 

emissions from the affected boiler.” In petroleum operations, many of 

these proposed “efficiencies” would simply result in the transference 

of emissions to outside the site boundary and increase overall 

emissions. One example is the shutdown of a steam turbine 

(decreasing refinery emissions) and replacing it with an electric driver 

(transferring the emissions outside the boundary of the refinery) and 

increasing US emissions overall. Furthermore, no consideration was 

given to the emissions resulting from reduced equipment reliability or 

the potential impacts of energy reduction steps on safety or 

operability. Furthermore, at some point, reduced onsite fuel use will 

mean process byproducts will have to be destroyed by incineration or 

otherwise disposed of without beneficial recovery of their fuel value, 

resulting in net increases in energy consumption and emissions.

The averaging time for CO compliance should be 

changed to 30 days.

Compliance with the CO limit for liquid-fired boilers is based on a 12-

hour O2 average in the final rule rather than a 30-day CO average, as 

in the proposal. As for CO, O2 can vary significantly as process 

conditions and even ambient conditions change and it can take some 

time for the O2 level to settle down. An extended averaging time is 

needed to obtain a true indication of the average oxygen level and thus 

for it to provide a true indication of organic HAP emissions, for which 

it, and CO, are surrogates.

Reconsider the O2 CEMS monitoring requirements. To show continuous compliance with numeric CO limits, the rule 

requires use of an O2 CEMS to demonstrate compliance on a 12-hour 

block average basis with the minimum O2 operating limit established 
Issue Comments

during performance testing. 

We support EPA’s rejection of the proposed requirement that every 

unit install a CO CEMS, especially when the proposed CO emission 

limit would have been based on stack test data obtained at full load 

conditions, but applied at all times. However, we do not believe it is 

appropriate or necessary to require that O

2 levels be monitored in the 

stack or ductwork leading to the stack (versus the firebox) in order to 

ensure continuous compliance, nor is it appropriate or necessary for 

EPA to require that each O

2 CEMS be installed, operated and 

maintained pursuant to Performance Specification 3. 

Many existing boilers already use flue gas O

2 analyzers for indication, 

alarm, and O

2 trim control, often with automatic air to fuel or draft 

control and it is unreasonable and unnecessary to force sources to add 

additional O

2 analyzers or impose excessive analyzer QA/QC 

requirements. EPA should, through reconsideration, gather 

information on current O

2 monitoring practices and give the regulated 

community’s experts a chance to participate in developing these 

provisions in a way that minimizes wasted efforts and eliminated 

unnecessary and potentially duplicative O

2 CEMS installations and 

requirements.

Furthermore, it is unsafe and technically impractical to limit O

2 at 

turndown operating rates to the level achievable at performance test 

conditions and that limit should not apply below 50% of firing 

capacity.
API/NPRA CISWI and NHSM Definition Reconsideration Issues

Issue Comments

Rigorously address the “contained gas” issue. Add the 

original contained gas definition back into the CISWI 

rule, add it to the solid waste definition in 40 CFR 

§258,2, and add it to the Major Source rule.

The CISWI definition in §60.2265, references §241.2, 

which in turn references the solid waste definition in 

§258.2. If the definition of solid waste in §258.2 is 

not clarified by defining contained gas, §60.2265 can 

be read to make any unit that does not burn traditional 

fuel as defined in §241.2 as a CISWI unit.

If the historical definition of contained gas is not 

confirmed through rule language to be clear gases in 

pipe are not solid wastes under any circumstances, 

withdraw all portions of the major source BPH rule 

and the CISWI rule dealing with gases and start over.

EPA’s May 16 letter on the contained gas issue does not override the 

notice and comment CISWI rule action of removing the contained gas 

definition in the existing CISWI rule or the response to comment 

explaining the reasons for removing that definition. Until regulatory 

action is taken, it remains unclear what gas combustion units are 

subject to the CAA 112 rules and which to CAA 129 rules.

The CISWI database used for the current rule is not representative of 

CISWI units as defined in the rule and in the Non-Hazardous 

Secondary Material (NHSM) rule and the number of CISWI sources 

appears to have been expanded by orders of magnitude and be 

dominated by gas-fired units and air pollution control devices 

combusting gaseous streams. All CISWI emission limits and 

compliance requirements, costs, impacts and burden estimates will 

need to be revised to match the new applicability. In this case, the 

current rule must be withdrawn and a new proposal presented for 

comment.

The fact that the EPA database for this rulemaking does not align with 

the NHSM rule definition, makes clear that the Agency did not 

provide adequate notice that this change was possible and, therefore, 

did not provide adequate notice for us to comment on this point during 

the CISWI comment period.

Control devices should be exempted from CISWI as 

they are in the major source BPH rule, if the new 

contained gas definition is not changed.

Under the new contained gas definition, most control devices would 

be considered CISWI units. However, that was never considered in 

the CISWI rulemaking and the CISWI requirements were not 
Issue Comments

considered in the rulemakings that imposed the requirements that led 

to use of the control devices. Thus, to avoid invalidating the 

provisions of most existing air rules, control devices should be 

excluded from CISWI requirements if the new contained gas 

definition is maintained.

Exempt ethylene reactors (furnaces) as is done in the 

major source rule.

Olefin Plant reactors (furnaces) are specifically exempt from the BPH 

major source rule. It is not clear if these heaters would also be exempt 

from CISWI if they combust any gas that is determined to be a “solid 

waste” under the new contained gas interpretation, because it is 

discarded or does not meet the legitimacy criteria.

The small remote incinerator subcategory 

requirements cannot be met and should be 

reconsidered.

The emission limits for this subcategory may result in the shutdown of 

garbage and trash incinerators in remote locations and garbage and 

trash being flown by small airplanes or lifted by helicopter or barged 

from remote sites. These alternative options are only marginally 

viable because barging is limited to the ice free season and both 

alternatives are limited by weather conditions. Also, stockpiling the 

waste to reach economic transportation levels will attract animals and 

increase the number of unsafe human wildlife interactions. Potential 

impacts on wildlife protected under Endangered Species Act results in 

additional complexity. In Alaska, at least, an inability to use 

incinerators violates State and federal lease requirements to incinerate 

the waste whenever possible.

Discussions with potential control equipment venders indicates

potential control technologies are not demonstrated in cold climates.

Thus, buildings would need to be constructed to keep the controls, 

supplies and waste from freezing. The footprint of oil and gas 

activities would increase, resulting in greater environmental impact. 
Issue Comments

For smaller facilities, waste may still need to be stockpiled for days to 

provide adequate waste volume to meet the minimal efficiency 

requirements of the control technology. Again, stockpiling of waste 

will increase wildlife and safety concerns. 

These small remote incinerators primarily burn kitchen and other 

municipal solid waste along with some industrial waste. Under 40 

CFR 60 Subpart EEEE, Standards of Performance for Other Solid 

Waste Incineration Units for Which Construction is Commenced After 

December 9, 2004, or for Which Modification or Reconstruction is 

Commenced on or After June 16, 2005 (the OSWI Rule), EPA 

provided exemptions for certain incinerators and air curtain 

incinerators in isolated areas of Alaska. These exemptions were 

included in the OSWI rule because “alternative disposal options are 

not available or are economically infeasible.” (see Federal Register 

Vol. 70, No. 241, p. 74878 and 74879.) Exempting small remote 

CISWI incinerators is appropriate for those incinerators that combust 

at least 30 percent municipal solid waste. These units are combusting 

essentially the same materials that are combusted in OSWI units and 

are similarly situated with respect to alternative disposal options not 

being available or economically infeasible.

The CISWI rule did not address portable incinerators. This set of 

small incinerators is used to support remote construction sites 

including, but not limited to oil and gas drilling and seismic work 

camps. Installation of controls at temporary construction sites is not 

practical and increases the project footprint and environmental impact.

A definition of refinery gas needs to be included or 

referenced in the NHSM and CISWI rules. The 

definition should be the same as the definition in the 

The definition of “traditional fuels” in the NHSM rule includes 

refinery gas. However, refinery gas is not defined and is open to 

considerable interpretation. We recommend use of the definition from 
Issue Comments

major source BPH rule. the BPH major source rule (i.e., Refinery gas means any gas that is

generated at a petroleum refinery and is combusted. Refinery gas 

includes natural gas when the natural gas is combined and combusted 

in any proportion with a gas generated at a refinery. Refinery gas 

includes gases generated from other facilities when that gas is 

combined and combusted in any proportion with gas generated at a

refinery.)

Specify how existing units that come under the 2011 

CISWI, but were not under the 2000 CISWI rule, are 

classified. Are they “new” or “existing” sources? 

Assure no retroactivity is implied by the new CISWI 

language.

The 2000 CISWI rule included standards of performance for “new” 

CISWI units. Existing CISWI were subject to State plans required by 

the Emissions Guidelines. The 2011 rule is similarly structured. It is 

not clear how existing boilers, process heaters, and control devices 

that become CISWI sources under the 2011 rule will be regulated. 

Will these existing units, which were not regulated under the 2000 

CISWI, be “new” units under the 2011 CISWI or “existing” units 

subject to 2011 Emission Guidelines?

A temporary use exemption is needed. Temporary units are typically leased equipment and used for short 

periods of time. If a temporary unit comes on to a facility, the 

operator not the lease company, is responsible for compliance. 

Obtaining records and ensuring compliance is not practical, when 

most of the year the boiler was somewhere else and information on 

when it might have last been tested is not available. Additionally, in 

many cases, testing activities would take more time than the time the 

boiler is used.