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 H azardous 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 Emissi on 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:

Industria l, 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 Ref iners 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 nationa l trade association with over 47 0 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

c omprise 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/N PRA’s Petit ion 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 deadlin es 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 refini ng 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 t he 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 believ e 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 n ot 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 a ddress 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 confir med through rule language to assure gases in pipelines are never solid wastes

, withdraw all portions of the major source

BPH and CISWI rule s 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 a re 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

N on

- H azardous S econdary M aterial 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 rec onsideration 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

- cont inental 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 part icularly, variability in the detection limits. Overall, the emission limits for dioxin/furans are notIssue Comments

reflective of the subcategories and do not properly consider variability and thus should be reconsidered and work practice limits developed in their plac e as allowed under CAA 112(h).

Energy a ssessment 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

thr ee 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

auth orization 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 who le 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 a ssessment 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 re duction in HAP, and non

- HAP, emissions

from the affected boiler.” In refinery operations, many of these proposed “efficiencies” would simply result in the transference ofIssue Comments

emissions to outside the refinery boundary and increas e overall

emissions. One exam ple 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 e missions 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 requirem ents. 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 equi pment. 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 fo rce extra process shutdowns as discussed separately) and there is no justification for impos ing even those costs since there are no HAP benefits.

Withdraw and reconsider the affirmative defense provisions. These provisions were not proposed and are n ot 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 de fense provisions and those comments must be seriously

considered.

The 4 ppm H 2 S limit for “Other Gas” to be subject to the same requirements as refinery and natural gas is unreasonable and should be

reconsidered

. Use of H 2 S 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 H 2 S 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 1Issue 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 gas es 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 discouragin g 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 th e 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 e ven 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 costs and burdens since these small uni ts 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 un fired 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, o r 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 aIssue Comments

heaters, not boilers. Both the boiler definition and the process heater definition appear to

include hot w ater 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.

E xclude waste heat boilers from the process

heater definition as is done in the boiler

defin ition.

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 u nless the device is exempt from the definition of a solid waste

incinerat ion 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 i ndirectly 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

de vice combusting solid waste, as define d in § 241.3, is not a process hea ter 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 boile rs 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 hea ters. EPA is not clear on applicability for an asphalt tank heater: a small burner ( e.g
., < 1.75 MM Btu/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 du ring 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, i t is

unclear that the BPH is subject to the requirements for the type of gas being fired (i.e., subject to G as 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 liq uid 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 boiler s do not inadvertently slightly exceed the 10% criterion.

Address the interaction of BPH MACT with RCRA comparable fuels exemption. A number of compani es 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 propos ed, 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 wh ere 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 si gnificantly ameliorated if the inspection requir e ment 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. S hutdown of process heaters generally requires a process unit

shutdown and s ome process units operate for much longer than the three years EPA is allowing for delay of inspections

. Th us
, the BPH major

source rule should allow an ext ension 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 sh utdowns.

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 wi th 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. T he 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 theIssue Comments

burners are not accessible for physical inspection

. T he typi cally 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 alr eady 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 wil l 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 l imited use exemption from CO te sting 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 stea dy 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 ratedIssue 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 operat e 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 proc ess 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 O 2 average in the final rule rather than a 30

- day CO a verage, as in the proposal (Table 8, Item 8). As for CO, O 2 can vary significantly as process conditions and even ambient conditions change and it can take some time

for the O 2 level to settle down. An extended averaging time is needed to

obtain a true i ndication 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 O 2 is a surrogate is primarily cancer risk, which is not r elated to short term (e.g., 12 hour) exposures.

The BPH rule should allow use of CO CEMS for CO compliance as an alternate to O 2 CEMS, where CO CEMS are available. The r ule requires use of O 2 CEMS for demonstrating compliance with CO

limit. But CO C EMS are already in place on some units and their use should be allowed, at the sources option.

Reconsider the O 2 CEMS monitoring requirements. To show continuous compliance with numeric CO limits, the rule requires

use of an O 2 CEMS to demonstrate co mpliance on a 12

- hour block average

basis with the minimum O 2 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 wouldIssue 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 t o 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 units already use flue gas O 2 analyze rs 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 re consideration, 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 duplica tive 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.

## A PI/NPRA Boiler and Process Heater Area Source Reconsideration Issues

Issue Comments

Temporar y boiler exemption provided for boilers at major sources should be p rovided for area source

boilers as well. EPA correctly exempted temporary boilers from the major source

BPH rule. Consistent with th at rule and for the same reasons, EPA should exempt te mporary 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

temporar y 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 come s o n 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 man y 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 tempor ary 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 mill ion 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 impo se 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 an other Part

63 subpart and at least 50 % of the boiler heat input comes from gas es 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 n ot 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 Ampl e 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 uni ts 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

definitio n 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) ar e not subject to

the area source rule

.

Reconsider the compliance time and allow t hree years for compliance. While plain work practice standards probably can be implemented in less than three years, the area source work practice requires O 2 sampling at a particular location (not the normal location for existing

O 2 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 183,00 0 existing area source boilers and that approximately 7,000 new area source boilers are likely to come o nline in the next three years, facilities will be required in many cases, and combustion expertise will be in short supply (even for work practice

train ing) 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 t he added complication that exis t i ng air permits require tune

- ups for NOx emissions and now these sources will be req uired 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 per forming 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 requirem ent in the N otice

of C ompliance S tatus 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 th e 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 an y, 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 mus t 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 draft ing mistakes in the “less frequent testing” provisions of §§63.11220(b) and (c)

A llow use of CO CEMS for CO compliance as an alternate to O 2 CEMS, where CO CEMS are available. The r ule requires use of an O 2 CEMS for demonstrating compliance

with th e 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 a rea source s 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 inform ation 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 requir ement 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 assess ments 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 fo r 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 resp onsive to submittedIssue 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 re duction 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 increas e 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 incinerat ion 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

- f ired boilers is based on a 12

- hour O 2 average in the final rule rather than a 30

- day CO average, as in the proposal. As for CO, O 2 can vary significantly as process conditions and even ambient conditions change and it can take some

time for the O 2 level t o 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 surrogate s

.

Reconsider the O 2 CEMS monitoring requirements. To show continuous compliance with numeric CO limits, the rule requires use of an O 2 CEMS to demonstrate compliance on a 12

- hour block average basis with the minimum O 2 operating limit establishedIssue 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 i s 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 instal led, 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 unneces sary 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 partici pate 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 operatin g 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 definitio n in 40 CFR §258,2, and add it to the Major Source rule.

The CISWI de finition 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 a ny 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 rule s.

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 expand ed 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 n ot 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 notIssue Comments

considered in the rulemakings that imposed the requir ements 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 reacto rs (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 ga s 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 s mall 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 be cause 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 hum an wildlife interactions

. Potential impacts on w ildlife protected under E ndangered S pecies A ct 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

.
Discus sions with potential control equipment venders indicate s potential control technologies are not demonstrated in cold climates. Thus, b uildings would need to be constructed to keep the controls, supplies and waste from freezing. The footprint of oil and g as activities would increase

, resulting in greater environmental impact.Issue Comments

Fo r 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 So lid

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

in cinerators 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 drill ing 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 r ecommend use of the definition fromIssue 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, bu t 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 s ubject 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 CI SWI sources under the 2011 rule will be regulated.

Will these exi sting 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 t emporary use exemption is needed

. Temporary units are typically leased equipment and used fo r short periods of time. If a temporary unit come s 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 in formation on when it might have last been tested is not available. Additionally, i n many cases, testing activities would take more time than the time the

boiler is used.