27178 Federal Register / Vol. 72, No. 92 / Monday, May 14, 2007 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2007–0011; FRL–8309–1] 

RIN 2060–AN72 

Standards of Performance for 

Petroleum Refineries 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rules. 

SUMMARY: EPA is proposing 

amendments to the current Standards of 

Performance for Petroleum Refineries. 

This action also proposes separate 

standards of performance for new, 

modified, or reconstructed process units 

at petroleum refineries. Unless 

otherwise noted, the term new includes 

modified or reconstructed units. The 

proposed standards for new process 

units include emissions limitations and 

work practice standards for fluid 

catalytic cracking units, fluid coking 

units, delayed coking units, process 

heaters and other fuel gas combustion 

devices, fuel gas producing units, and 

sulfur recovery plants. These proposed 

standards reflect demonstrated 

improvements in emissions control 

technologies and work practices that 

have occurred since promulgation of the 

current standards. 

DATES: Comments. Written comments 

must be received on or before July 13, 

2007. 

Public Hearing. If anyone contacts 

EPA by June 4, 2007 requesting to speak 

at a public hearing, a public hearing will 

be held on June 13, 2007. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2007–0011, by one of the 

following methods: 

• http://www.regulations.gov: Follow 

the on-line instructions for submitting 

comments. 

• E-mail: a-and-r-docket@epa.gov. 

• Fax: (202) 566–1741. 

• Mail: U.S. Postal Service, send 

comments to: EPA Docket Center 

(6102T), New Source Performance 

Standards for Petroleum Refineries 

Docket, 1200 Pennsylvania Ave., NW., 

Washington, DC 20460. Please include a 

total of two copies. In addition, please 

mail a copy of your comments on the 

information collection provisions to the 

Office of Information and Regulatory 

Affairs, Office of Management and 

Budget (OMB), Attn: Desk Officer for 

EPA, 725 17th St., NW., Washington, DC 

20503. 

• Hand Delivery: In person or by 

courier, deliver comments to: EPA 

Docket Center (6102T), New Source 

Performance Standards for Petroleum 

Refineries Docket, EPA West, Room 

3334, 1301 Constitution Avenue, NW., 

Washington, DC 20004. Such deliveries 

are only accepted during the Docket’s 

normal hours of operation, and special 

arrangements should be made for 

deliveries of boxed information. Please 

include a total of two copies. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2007– 

0011. EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http:// 

www.regulations.gov or e-mail. The 

http://www.regulations.gov website is 

an ‘‘anonymous access’’ system, which 

means EPA will not know your identity 

or contact information unless you 

provide it in the body of your comment. 

If you send an e-mail comment directly 

to EPA without going through http:// 

www.regulations.gov, your e-mail 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. 

Docket: All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 

the EPA Docket Center, Standards of 

Performance for Petroleum Refineries 

Docket, EPA West, Room 3334, 1301 

Constitution Ave., NW., Washington, 

DC. The Public Reading Room is open 

from 8:30 a.m. to 4:30 p.m., Monday 

through Friday, excluding legal 

holidays. The telephone number for the 

Public Reading Room is (202) 566–1744, 

and the telephone number for the 

Docket Center is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Robert B. Lucas, Office of Air Quality 

Planning and Standards, Sector Policies 

and Programs Division, Coatings and 

Chemicals Group (E143–01), 

Environmental Protection Agency, 

Research Triangle Park, NC 27711, 

telephone number: (919) 541–0884; fax 

number: (919) 541–0246; e-mail 

address: lucas.bob@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. General Information 

A. Does this action apply to me? 

Categories and entities potentially 

regulated by this proposed rule include: 

Category NAICS 

code 1

Examples of regulated 

entities 

Industry ............................................................................................................................................................ 32411 Petroleum refiners. 

Federal government ........................................................................................................................................ ................ Not affected. 

State/local/tribal government ........................................................................................................................... ................ Not affected. 

1 North American Industrial Classification System. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by this action. To determine 

whether your facility would be 

regulated by this action, you should 

examine the applicability criteria in 40 

CFR 60.100 and 40 CFR 60.100a. If you 

have any questions regarding the 

applicability of this proposed action to 

a particular entity, contact the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section. 


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B. What should I consider as I prepare 

my comments to EPA? 

Do not submit information containing 

CBI to EPA through http:// 

www.regulations.gov or e-mail. Send or 

deliver information identified as CBI 

only to the following address: Roberto 

Morales, OAQPS Document Control 

Officer (C404–02), Office of Air Quality 

Planning and Standards, Environmental 

Protection Agency, Research Triangle 

Park, NC 27711, Attention Docket ID 

No. EPA–HQ–OAR–2007–0011. Clearly 

mark the part or all of the information 

that you claim to be CBI. For CBI 

information in a disk or CD–ROM that 

you mail to EPA, mark the outside of the 

disk or CD–ROM as CBI and then 

identify electronically within the disk or 

CD–ROM the specific information that 

is claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, a 

copy of the comment that does not 

contain the information claimed as CBI 

must be submitted for inclusion in the 

public docket. Information so marked 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. 

C. Where can I get a copy of this 

document? 

In addition to being available in the 

docket, an electronic copy of this 

proposed action is available on the 

Worldwide Web (WWW) through the 

Technology Transfer Network (TTN). 

Following signature, a copy of this 

proposed action will be posted on the 

TTN’s policy and guidance page for 

newly proposed or promulgated rules at 

http://www.epa.gov/ttn/oarpg. The TTN 

provides information and technology 

exchange in various areas of air 

pollution control. 

D. When would a public hearing occur? 

If anyone contacts EPA requesting to 

speak at a public hearing by June 4, 

2007, a public hearing will be held on 

June 13, 2007. Persons interested in 

presenting oral testimony or inquiring 

as to whether a public hearing is to be 

held should contact Mr. Bob Lucas, 

listed in the FOR FURTHER INFORMATION

CONTACT section, at least 2 days in 

advance of the hearing. 

E. How is this document organized? 

The supplementary information 

presented in this preamble is organized 

as follows: 

I. General Information 

A. Does this action apply to me? 

B. What should I consider as I prepare my 

comments to EPA? 

C. Where can I get a copy of this 

document? 

D. When would a public hearing occur? 

E. How is this document organized? 

II. Background Information 

A. What is the statutory authority for the 

proposed standards and proposed 

amendments? 

B. What are the current petroleum refinery 

NSPS? 

III. Summary of the Proposed Standards and 

Proposed Amendments 

A. What are the proposed amendments to 

the standards for petroleum refineries 

(40 CFR part 60, subpart J)? 

B. What are the proposed requirements for 

new fluid catalytic cracking units and 

new fluid coking units (40 CFR part 60, 

subpart Ja)? 

C. What are the proposed requirements for 

new sulfur recovery plants (SRP) (40 

CFR part 60, subpart Ja)? 

D. What are the proposed requirements for 

new process heaters and other fuel gas 

combustion devices (40 CFR part 60, 

subpart Ja)? 

E. What are the proposed work practice 

and equipment standards (40 CFR part 

60, subpart Ja)? 

IV. Rationale for the Proposed Amendments 

(40 CFR part 60, subpart J) 

A. How is EPA proposing to change 

requirements for refinery fuel gas? 

B. How is EPA proposing to amend 

definitions? 

C. How is EPA proposing to revise the coke 

burn-off equation? 

D. What miscellaneous corrections are 

being proposed? 

V. Rationale for the Proposed Standards (40 

CFR part 60, subpart Ja) 

A. What is the performance of control 

technologies for fluid catalytic cracking 

units? 

B. What is the performance of control 

technologies for fuel gas combustion? 

C. What is the performance of control 

technologies for process heaters? 

D. What is the performance of control 

technologies for sulfur recovery systems? 

E. How did EPA determine the proposed 

standards for new petroleum refining 

process units? 

VI. Modification and Reconstruction 

Provisions 

VII. Request for Comments 

VIII. Summary of Cost, Environmental, 

Energy, and Economic Impacts 

A. What are the impacts for petroleum 

refineries? 

B. What are the secondary impacts? 

C. What are the economic impacts? 

D. What are the benefits? 

IX. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

II. Background Information 

A. What is the statutory authority for the 

proposed standards and proposed 

amendments? 

New source performance standards 

(NSPS) implement Clean Air Act (CAA) 

section 111(b) and are issued for 

categories of sources which cause, or 

contribute significantly to, air pollution 

which may reasonably be anticipated to 

endanger public health or welfare. The 

primary purpose of the NSPS is to attain 

and maintain ambient air quality by 

ensuring that the best demonstrated 

emission control technologies are 

installed as the industrial infrastructure 

is modernized. Since 1970, the NSPS 

have been successful in achieving longterm emissions reductions in numerous 

industries by assuring cost-effective 

controls are installed on new, 

reconstructed, or modified sources. 

Section 111 of the CAA requires that 

NSPS reflect the application of the best 

system of emission reductions which 

(taking into consideration the cost of 

achieving such emission reductions, any 

non-air quality health and 

environmental impact and energy 

requirements) the Administrator 

determines has been adequately 

demonstrated. This level of control is 

commonly referred to as best 

demonstrated technology (BDT). 

Section 111(b)(1)(B) of the CAA 

requires EPA to periodically review and 

revise the standards of performance, as 

necessary, to reflect improvements in 

methods for reducing emissions. 

B. What are the current petroleum 

refinery NSPS? 

NSPS for petroleum refiners (40 CFR 

part 60, subpart J) apply to fluid 

catalytic cracking unit catalyst 

regenerators and fuel gas combustion 

devices that commence construction or 

modification after June 11, 1973. Fluid 

catalytic cracking unit catalyst 

regenerators are subject to standards for 

particulate matter (PM), opacity, and 

carbon monoxide (CO). Fluid catalytic 

cracking unit catalyst regenerators that 

commence construction after January 

17, 1984 are also subject to standards for 

sulfur dioxide (SO2) (or a feed sulfur 

content limit). Fuel gas combustion 

devices are subject to concentration 

limits for hydrogen sulfide (H2S) as a 

surrogate for SO2 emissions. 


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27180 Federal Register / Vol. 72, No. 92 / Monday, May 14, 2007 / Proposed Rules 

The current NSPS also apply to all 

Claus sulfur recovery plants (SRP) of 

more than 20 long tons per day (LTD) 

that commence construction or 

modification after October 4, 1976. 

Claus SRP are subject to standards for 

either SO2 or both reduced sulfur 

compounds and H2S. 

The NSPS were originally 

promulgated on March 8, 1974 and have 

been amended several times. Significant 

changes to emission limits since the 

original promulgation date include the 

addition of the sulfur oxide standards 

for SRP and fluid catalytic cracking 

units (see 43 FR 10869, March 15, 1978 

and 54 FR 34027, August 17 1989). 

III. Summary of the Proposed 

Standards and Proposed Amendments 

We are proposing several 

amendments to provisions in the 

existing NSPS in 40 CFR part 60, 

subpart J. Many of these amendments 

are technical clarifications and 

corrections that are also included in the 

proposed standards in 40 CFR part 60, 

subpart Ja. For example, we are 

proposing language to change the 

definition of fuel gas to indicate that 

vapors collected and combusted to 

comply with certain wastewater and 

marine vessel loading provisions are not 

considered fuel gas and are exempt from 

40 CFR 60.104(a)(1). These gas streams 

are not required to be monitored. In a 

related amendment, we are proposing to 

clarify that monitoring is not required 

for fuel gases that are identified as 

inherently low sulfur or can 

demonstrate a low sulfur content. We 

are also revising the coke burn-off 

equation to account for oxygen (O2)- 

enriched air streams. Other amendments 

include clarification of definitions and 

correction of grammatical and 

typographical errors. 

The proposed standards in 40 CFR 

part 60, subpart Ja include emission 

limits for fluid catalytic cracking units, 

fluid coking units, SRP, and fuel gas 

combustion devices. They also include 

work practice standards for minimizing 

the quantity of fuel gas streams flared 

from all refinery process units and for 

minimizing the SO2 emissions from 

process units that are subject to 

standards of performance for SO2

emissions. Proposed equipment 

standards would reduce emissions of 

volatile organic compounds (VOC) from 

delayed coker units. Only those affected 

facilities that begin construction, 

modification, or reconstruction after 

May 14, 2007 would be affected by the 

proposed standards in 40 CFR part 60, 

subpart Ja. Units for which construction, 

modification, or reconstruction began 

on or before May 14, 2007 would 

continue to comply with the applicable 

standards under the current NSPS in 40 

CFR part 60, subpart J, as amended. 

A. What are the proposed amendments 

to the standards for petroleum refineries 

(40 CFR part 60, subpart J)? 

We are proposing to amend the 

definition of ‘‘fuel gas’’ to exempt 

vapors that are collected and combusted 

in an air pollution control device 

installed to comply with a specified 

wastewater or marine vessel loading 

emissions standard. The thermal 

combustion control devices themselves 

would still be considered affected fuel 

gas combustion devices, and all 

auxiliary fuel fired to these devices 

would be subject to the fuel gas limit; 

however, continuous monitoring would 

not be required for the collected vapors 

that are being incinerated because these 

gases would not be considered fuel 

gases under the proposed definition of 

‘‘fuel gas’’ in subpart J. 

We are also proposing to exempt 

certain fuel gas streams from all 

continuous monitoring requirements. 

Monitoring is currently not required for 

events that are exempt from the 

requirements in 40 CFR 60.104(a)(1) 

(flaring of process upset gases or flaring 

of gases from relief valve leakage or 

emergency malfunctions). Additionally, 

monitoring would not be required for 

inherently low sulfur fuel gas streams. 

These streams include pilot gas flames, 

gas streams that meet commercial-grade 

product specifications with a sulfur 

content 30 parts per million by volume 

(ppmv) or less, fuel gases produced by 

process units that are intolerant to 

sulfur contamination, and fuel gas 

streams that an owner or operator can 

demonstrate are inherently low-sulfur. 

Owners and operators would be 

required to document the exemption for 

which each fuel gas stream applies and 

ensure that the stream remains qualified 

for that exemption. 

We are proposing to amend the 

definitions of ‘‘Claus sulfur recovery 

plant,’’ ‘‘oxidation control system,’’ and 

‘‘reduction control system’’ to clarify 

that a SRP may consist of multiple 

units, that sulfur pits are part of the 

Claus SRP, and that the oxidized or 

reduced sulfur is recycled to the 

beginning of a sulfur recovery train 

within the SRP. We are also proposing 

to add a fourth term to the coke burnoff rate equation to account for the use 

of O2-enriched air. 

Finally, the proposed amendments 

include a few technical corrections to 

fix references and other miscellaneous 

errors in subpart J. The specific changes 

are detailed in section IV.D of this 

preamble. 

B. What are the proposed requirements 

for new fluid catalytic cracking units 

and new fluid coking units (40 CFR part 

60, subpart Ja)? 

The proposed standards for new fluid 

catalytic cracking units include 

emission limits for PM, SO2, nitrogen 

oxides (NOX), and CO. One difference 

from the existing standards in subpart J 

is that new fluid coking units would be 

subject to the same standards as fluid 

catalytic cracking units. Other 

differences from the existing standards 

are that the proposed PM and SO2

emission limits are more stringent and 

the NOX emission limit is a new 

requirement. Unlike the existing 

standards, the proposed standards 

include no opacity limit because the 

opacity limit was intended to ensure 

compliance with the PM limit and 

because we are now proposing that 

sources use direct PM monitoring or 

parameter monitoring to ensure 

compliance with the PM limit. 

The proposed PM emission limit for 

new fluid catalytic cracking units and 

new fluid coking units is 0.5 kilogram 

(kg) per Megagram (kg/Mg) (0.5 pound 

(lb)/1,000 lb) of coke burn-off in the 

regenerator. Initial compliance with this 

emission limit would be determined 

using Method 5 in Appendix A to 40 

CFR part 60. Procedures for computing 

the PM emission rate using the total PM 

concentration, effluent gas flow rate, 

and coke burn-off rate would be the 

same as in 40 CFR part 60, subpart J, as 

amended. To demonstrate ongoing 

compliance, an owner or operator must 

either monitor PM emission control 

device operating parameters or use a PM 

continuous emission monitoring system 

(CEMS). If operating parameters will be 

used to demonstrate ongoing 

compliance, the owner or operator must 

monitor the same parameters during the 

initial performance test, and develop 

operating parameter limits for the 

applicable parameters. The operating 

limits must be based on the lowest 

hourly average values for the applicable 

parameters measured over the three test 

runs. The owner or operator must also 

conduct additional performance tests at 

least once every 24 months to verify 

compliance with the PM emission limit 

and confirm or reestablish operating 

limits. If ongoing compliance will be 

demonstrated using a PM CEMS, the 

CEMS must meet the conditions in 

Performance Specification 11. Thus, 

separate performance tests are not 

required because the equivalent of an 

initial performance test will be part of 

the initial correlation test for the PM 

CEMS, and periodic response 

correlation audits (every 5 years) will 


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Federal Register / Vol. 72, No. 92 / Monday, May 14, 2007 / Proposed Rules 27181 

include the equivalent of performance 

tests. We are co-proposing requiring 

reconstructed and modified fluid 

catalytic cracking units to meet the 

current standards in 40 CFR part 60, 

subpart J, and we are requesting 

comments on the effects of the proposed 

PM standard on modified or 

reconstructed facilities and if it is 

appropriate to adopt a different standard 

for these sources. 

The proposed SO2 emission limits for 

new fluid catalytic cracking units and 

new fluid coking units are to maintain 

SO2 emissions to the atmosphere less 

than or equal to 50 ppmv on a 7-day 

rolling average basis, and less than or 

equal to 25 ppmv on a 365-day rolling 

average basis (both limits corrected to 0 

percent moisture and 0 percent excess 

air). Initial compliance with the 

proposed 50 ppmv SO2 emission limit 

would be demonstrated by conducting a 

performance evaluation of the SO2

CEMS in accordance with Performance 

Specification 2 in appendix B of 40 CFR 

part 60, with Method 6, 6A, or 6C of 40 

CFR part 60, appendix A as the 

reference method. Ongoing compliance 

with both proposed SO2 emission limits 

would be determined using the CEMS to 

measure SO2 emissions as discharged to 

the atmosphere, averaged over the 7-day 

and 365-day averaging periods. Rolling 

average concentrations would be 

calculated once per day using the 

applicable number of daily average 

values. We are co-proposing requiring 

reconstructed and modified fluid 

catalytic cracking units to meet the 

current standards in 40 CFR part 60, 

subpart J, and we are requesting 

comments on the effects of the proposed 

SO2 standard on modified or 

reconstructed facilities. 

The proposed NOX emission limits for 

new fluid catalytic cracking units and 

new fluid coking units are 80 ppmv on 

a 7-day rolling average basis (dry at 0 

percent excess air). Initial compliance 

with the 80 ppmv emission limit would 

be demonstrated by conducting a 

performance evaluation of the CEMS in 

accordance with Performance 

Specification 2 in appendix B to 40 CFR 

part 60, with Method 7 of 40 CFR part 

60, subpart A as the Reference Method. 

Ongoing compliance with this emission 

limit would be determined using the 

CEMS to measure NOX emissions as 

discharged to the atmosphere, averaged 

over 7-day periods. We are also coproposing no new standards for NOX

emissions from fluid coking units and 

for modified or reconstructed fluid 

catalytic cracking units. 

The proposed CO emission limit for 

new fluid catalytic cracking units and 

new fluid coking units is 500 ppmv (1- 

hour average, dry at 0 percent excess 

air). Initial compliance with this 

emission limit would be demonstrated 

by conducting a performance evaluation 

for the CEMS in accordance with 

Performance Specification 4 in 

appendix B to 40 CFR part 60, with 

Method 10 or 10A in 40 CFR part 60, 

appendix A as the Reference Method. 

For Method 10, the integrated sampling 

technique is to be used. Ongoing 

compliance with this emission limit 

would be determined on an hourly basis 

using the CEMS to measure CO 

emissions as discharged to the 

atmosphere. An exemption from 

monitoring may be requested if the 

owner or operator can demonstrate that 

average CO emissions are less than 50 

ppmv (dry basis). This limit and the 

compliance procedures are the same as 

in the existing NSPS for fluid catalytic 

cracking units. 

C. What are the proposed requirements 

for new sulfur recovery plants (SRP) (40 

CFR part 60, subpart Ja)? 

The proposed standards include SO2

emission limits for all SRP. The 

proposed emission limit for new SRP 

greater than 20 LTD is 250 ppmv or less 

of combined SO2 and reduced sulfur 

compounds as discharged to the 

atmosphere (reported as SO2 on a dry 

basis at 0 percent excess air). For a SRP 

with a capacity of 20 LTD or less, the 

proposed standard is mass emissions of 

combined SO2 and reduced sulfur 

compounds equal to 1 weight percent or 

less of sulfur recovered. In addition, the 

proposed standards include an H2S 

concentration limit of 10 ppmv or less 

(dry basis at 0 percent excess air) for all 

new SRP. Both SO2 and H2S 

concentration limits would be 

determined hourly on a 12-hour rolling 

average basis. As in the amendments to 

subpart J, the proposed definition of a 

SRP would include the sulfur pit. 

Initial compliance with the emission 

limit for combined SO2 and reduced 

sulfur compounds is demonstrated by 

conducting a performance evaluation for 

the SO2 CEMS in accordance with 

Performance Specification 2 in 

appendix B to 40 CFR part 60, with 

Method 6, 6A, or 6C in 40 CFR part 60, 

appendix A as the Reference Method to 

determine the SO2 concentration, and 

Method 15 in 40 CFR part 60, appendix 

A as the Reference Method to determine 

the SO2-equivalent concentration of the 

reduced sulfur compounds. The results 

of the test using Method 15 are also 

used to demonstrate initial compliance 

with the H2S concentration limit. Initial 

compliance with the mass sulfur 

emission limit is demonstrated by 

conducting a performance test as 

described above to determine the 

combined SO2 and SO2-equivalent 

concentration, and then converting that 

concentration to a mass fraction using 

the volumetric flow rate of effluent gas 

and the mass rate of sulfur recovery 

during the performance test. 

Ongoing compliance with the 

combined SO2 and reduced sulfur 

compounds emission limit would be 

determined using a CEMS that uses an 

air or O2 dilution and oxidation system 

to convert the reduced sulfur to SO2 and 

then measures the total resultant SO2

concentration. An O2 monitor would 

also be required for converting the 

measured combined SO2 concentration 

to the concentration at 0 percent O2. 

Ongoing compliance with the mass 

sulfur emission limit would be 

determined using the same types of 

CEMS. A flow monitor that 

continuously monitors the volumetric 

flow rate of gases released to the 

atmosphere would be required so that 

the mass emitted can be calculated. The 

hourly sulfur production rates would 

also have to be tracked so that mass 

fraction emitted can be calculated and 

compared with the proposed 1 percent 

emission limit. 

Ongoing compliance with the H2S 

concentration limit would be 

determined using either an H2S CEMS 

or, if the SRP is equipped with an 

oxidation control system or followed by 

incineration, by continuous monitoring 

of the operating temperature and O2

concentration. Minimum operating 

limits for the operating temperature and 

O2 concentration would be established 

during the performance test. 

D. What are the proposed requirements 

for new process heaters and other fuel 

gas combustion devices (40 CFR part 60, 

subpart Ja)? 

The proposed standards for new 

process heaters include both SO2 and 

NOX emission limits. Because of this, 

the fuel gas combustion units as defined 

in the existing subpart J standards were 

divided into two separate affected 

sources: ‘‘process heaters’’ and ‘‘other 

fuel gas combustion devices.’’ The 

primary sulfur oxides emission limit for 

new process heaters and other fuel gas 

combustion devices is 20 ppmv or less 

SO2 (dry at 0 percent excess air) on a 3- 

hour rolling average basis and 8 ppmv 

or less on a 365-day rolling average 

basis. For process heaters that use only 

fuel gas and other fuel gas combustion 

devices, we are proposing an alternative 

concentration limit of 160 ppmv or less 

H2S or total reduced sulfur (TRS) in the 

fuel gas on a 3-hour rolling average basis 

(as in the existing NSPS) and 60 ppmv 

or less H2S or TRS in the fuel gas on a 


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365-day rolling averaging basis. The 

TRS concentration limit is required for 

new fuel gas combustion devices that 

combust fuel gas generated from coking 

units (as either the only fuel or as a 

mixture of fuel gases from other units). 

On the other hand, new fuel gas 

combustion devices that do not combust 

fuel gas generated from coking units are 

required to monitor H2S concentrations. 

Compliance would be demonstrated 

either by measuring H2S (or TRS) in the 

fuel gas or by measuring SO2 in the 

exhaust gas. 

Initial compliance with the 20 ppmv 

SO2 limit or the 160 ppmv H2S or TRS 

concentration limits would be 

demonstrated by conducting a 

performance evaluation for the CEMS. 

The performance evaluation for an SO2

CEMS would be conducted in 

accordance with Performance 

Specification 2 in appendix B to 40 CFR 

part 60, with Method 6, 6A, or 6C as the 

Reference Method. The performance 

evaluation for an H2S CEMS would be 

conducted in accordance with 

Performance Specification 7 in 40 CFR 

part 60, with Method 11, 15, 15A, or 16 

as the Reference Method. The 

performance evaluation for a TRS CEMS 

would be conducted in accordance with 

Performance Specification 7 in 40 CFR 

part 60, with Method 16 as the 

Reference Method. Ongoing compliance 

with the proposed sulfur oxides 

emission limits would be determined 

using the applicable CEMS to measure 

either H2S or TRS in the fuel gas being 

used for combustion or SO2 in the 

exhaust gas to the atmosphere, averaged 

over the 3-hour and 365-day averaging 

periods. 

Similar to proposed clarifications for 

40 CFR part 60, subpart J, we are 

proposing a definition of ‘‘fuel gas’’ that 

includes exemptions for vapors 

collected and combusted in an air 

pollution control device installed to 

comply with specified wastewater or 

marine vessel loading provisions. Also 

similar to subpart J, we are proposing to 

exempt from continuous monitoring 

fuel gas streams exempt under 40 CFR 

60.102a(i) and fuel gas streams that are 

inherently low in sulfur. We are also 

proposing to streamline the process for 

an owner or operator to demonstrate 

that a fuel gas stream not explicitly 

exempted from continuous monitoring 

is inherently low sulfur. 

The proposed NOX emission limits for 

new process heaters is 80 ppmv on a 7- 

day rolling average basis (dry at 0 

percent excess air). Initial compliance 

with the 80 ppmv emission limit would 

be demonstrated by conducting a 

performance evaluation of the CEMS in 

accordance with Performance 

Specification 2 in appendix B to 40 CFR 

part 60, with Method 7 of 40 CFR part 

60, subpart A as the Reference Method. 

Ongoing compliance with this emission 

limit would be determined using the 

CEMS to measure NOX emissions as 

discharged to the atmosphere, averaged 

over 7-day periods. 

E. What are the proposed work practice 

and equipment standards (40 CFR part 

60, subpart Ja)? 

Three work practice standards are 

proposed to reduce both VOC and SO2

emissions from flares, start-up/ 

shutdown/malfunction events, and 

delayed coker units. First, the proposed 

rule requires all new fuel gas producing 

units at a refinery to be designed and 

operated in such a way that the fuel gas 

produced by the new process units does 

not routinely discharge to a flare. 

Second, a requirement for a start-up, 

shutdown and malfunction plan that 

includes procedures to minimize 

discharges either directly to the 

atmosphere or to the flare gas system 

during the planned startup or shutdown 

of these units, procedures to minimize 

emissions during malfunctions of the 

amine treatment system or sulfur 

recovery plant, and procedures for 

conducting a root-cause analysis of an 

emissions limit exceedance or process 

start-up, shutdown, upset, or 

malfunction that causes a discharge into 

the atmosphere, either directly or 

indirectly, from any refinery process 

unit subject to the provisions of this 

subpart in excess of 500 lb per day (lb/ 

d) of SO2. Third, the proposed rule 

would require delayed coking units to 

depressure to 5 lbs per square inch 

gauge (psig) during reactor vessel 

depressuring and vent the exhaust gases 

to the fuel gas system. For new, 

reconstructed, or modified units, we are 

co-proposing to require only the last of 

these work practice standards, the 

requirement to depressure coking units 

to the flare. 

IV. Rationale for the Proposed 

Amendments (40 CFR part 60, subpart 

J) 

Because we are proposing a new 

subpart to 40 CFR part 60 for affected 

sources at petroleum refineries 

beginning construction, reconstruction, 

or modification after May 14, 2007, our 

proposed amendments to subpart J of 40 

CFR part 60 would impact only those 

affected sources that are already subject 

to 40 CFR part 60, subpart J. The 

proposed amendments to this subpart 

include clarifications of the current 

requirements and technical corrections 

to the regulatory language. These 

changes to subpart J of 40 CFR part 60 

are discussed below. 

A. How is EPA proposing to change 

requirements for refinery fuel gas? 

As we conducted our review of 40 

CFR part 60, subpart J, we found that 

the definition of ‘‘fuel gas’’ has been 

broadly interpreted by States and EPA 

Regions over the last 30 years. Because 

of the increasing complexity of 

petroleum refineries, this interpretation 

may be more inclusive than originally 

intended in the 1970s. We agree that the 

interpretation ensures that all streams 

that could be considered fuel gas and 

have the potential for high-sulfur 

emissions are included in the regulatory 

requirements, but we recognize that this 

broad definition has resulted in 

application of the fuel gas concentration 

limits to fuel gas streams and 

combustion devices that were not 

originally considered in the standards 

development process. Furthermore, had 

these extended applications been 

considered in the standards 

development process, some of the 

applications would have been found to 

be either technically or economically 

infeasible. The existing requirements in 

subpart J of 40 CFR part 60 do recognize 

and limit the applicability of the fuel 

gas concentration limits to certain gas 

streams. For example, 40 CFR 60.101(d) 

excludes gases generated by catalytic 

cracking unit catalyst regenerators and 

fluid coking burners from the definition 

of ‘‘fuel gas.’’ These gases were 

excluded because the sulfur in the gases 

generated by the catalytic cracking unit 

catalyst regenerators and fluid coking 

burners is in the form of sulfur oxides 

rather than H2S. As such, these gases are 

not amenable to amine treatment, which 

was the primary treatment technique on 

which the fuel gas concentration limits 

were based. In addition, 40 CFR 

60.104(a)(1) exempts process upset 

gases or fuel gas released to the flare as 

a result of relief valve leakage or 

emergency malfunctions from the fuel 

gas H2S concentration limits. In this 

case, it was determined that requiring 

treatment of these gases was either 

technically or economically infeasible. 

Therefore, it is entirely in keeping with 

the regulatory intent of the NSPS and 

the specific requirements in 40 CFR part 

60, subpart J to exclude or exempt 

sources based on technical and 

economic considerations. 

Since the development of the refinery 

fuel gas concentration limits in the early 

1970s, EPA has developed numerous 

other standards in which incineration 

was promoted as a best air pollution 

management practice for certain organic 

vapors which had traditionally been 


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released directly to the atmosphere. 

These gas streams were never 

considered in the development of the 40 

CFR part 60, subpart J standards because 

they were not directed to a fuel gas 

combustion device at the time. As such, 

the technical and economical feasibility 

of meeting the fuel gas concentration 

limits was not specifically evaluated for 

these gas streams at that time. During 

our review, we evaluated the 

application of the fuel gas concentration 

limits to a variety of process gas streams 

that did not exist in the early 1970s. We 

concluded that most of these gas 

streams are amenable to amine 

treatment and that it is both technically 

and economically feasible to treat those 

gas streams to meet the fuel gas 

concentration limits. However, we 

identified a few specific streams that are 

not readily amenable to amine treatment 

(or direct diversion to the SRP) and/or 

are not cost-effective to amine treatment 

due to the typically low (but potentially 

variable) H2S content and the typical 

location of these gas streams in 

relationship to the primary processing 

units at the refinery. 

As a result of this evaluation, we are 

proposing to change the requirements of 

the fuel gas concentration limits in 

keeping with a broad definition of fuel 

gas, but recognizing the technical and 

economic issues related to certain fuel 

gas streams or combustion devices. 

Specifically, we are proposing to 

exempt from the definition of ‘‘fuel gas’’

vapors that are collected and combusted 

in an air pollution control device 

installed to comply with the Standards 

of Performance for VOC Emissions From 

Petroleum Refinery Wastewater Systems 

(40 CFR part 60, subpart QQQ), National 

Emission Standards for Benzene Waste 

Operations (40 CFR part 61, subpart FF), 

the National Emission Standards for 

Marine Tank Vessel Loading Operations 

(40 CFR part 63, subpart Y), or the 

National Emission Standards for 

Hazardous Air Pollutants From 

Petroleum Refineries (40 CFR part 63, 

subpart CC), specifically either 40 CFR 

63.647 or 40 CFR 63.651. The 

wastewater and marine vessel loading 

sources subject to these specific 

regulations are often located at the edge 

of the refinery property, if not off-site, 

and compliance with the regulations is 

generally demonstrated by capturing 

and combusting the organic vapors. The 

collected gases generally have low 

sulfur content, but variability in the 

products being loaded and in 

wastewater treatment process operations 

may result in the collected gases 

exceeding the current fuel gas 

concentration limits for short periods of 

time. Due to the typical low sulfur 

content of these gases, they are not 

generally suitable for amine treatment; 

due to the presence of O2 in these 

collected gases, they cannot be routed to 

the fuel gas system. Furthermore, these 

sources are typically far from amine 

treatment or the SRP, and it is not 

economically reasonable to propose 

control beyond the existing regulations 

for these sources (e.g., requiring these 

streams to be routed to sulfur treatment 

rather than being combusted). 

Therefore, we are proposing to amend 

the definition of ‘‘fuel gas’’ in 40 CFR 

60.101(d) to exclude from the fuel gas 

concentration limits the vapors 

collected and combusted in air 

pollution control devices to comply 

with the specified regulations in 40 CFR 

part 60, subpart QQQ, 40 CFR part 61, 

subpart FF, or 40 CFR part 63, subparts 

Y or CC. The thermal combustion 

control devices would still be 

considered affected fuel gas combustion 

devices and all auxiliary fuel fired to 

these devices would be subject to the 

fuel gas concentration limit; however, 

continuous monitoring would not be 

required for the collected vapors that are 

being incinerated because these gases 

would not be considered fuel gases 

under the proposed definition of ‘‘fuel 

gas’’ in subpart J. 

We are also proposing to clarify that 

monitoring is not required for fuel gas 

streams that are exempt from the 

requirements in 40 CFR 60.104(a)(1). 

These streams include process upset 

gases or fuel gases that are released to 

the flare as a result of relief valve 

leakage or other emergency 

malfunctions. To clarify this point, the 

proposed introductory text for 40 CFR 

60.105(a)(4)(iv) specifies that 

continuous monitoring is not required 

for streams that are exempt from 40 CFR 

60.104(a)(1). We are also proposing to 

add the phrase ‘‘for fuel gas combustion 

devices subject to 40 CFR 60.104(a)(1)’’

after ‘‘Instead of the SO2 monitor in 

paragraph (a)(3) of this section’’ in 40 

CFR 60.105(a)(4). This proposed 

amendment is more consistent with the 

language in 40 CFR 60.105(a)(3). Given 

our intent not to require fuel gas 

monitoring of process upset gases, 

combustion devices such as emergency 

flares would likely not require 

monitoring unless sources other than 

process upset gases are burned, such as 

routine vents or sweep gas. We are 

aware of issues related to the 

identification and exemption of these 

units from fuel gas monitoring. We are 

requesting comment on the need to 

provide specific language exempting 

these units, and on appropriate methods 

for identifying emergency flares and 

verifying on an ongoing basis that no 

flaring of nonexempt gases is occurring. 

In addition to the exemptions 

described in the previous paragraphs, 

we are proposing to exempt certain fuel 

gas streams from all monitoring 

requirements. These streams would still 

be subject to the fuel gas concentration 

limits, but since we do not expect that 

these streams would exceed this limit 

(except in the case of a process upset or 

malfunction, in which case the fuel 

gases would be exempt from meeting 

the limit), continuous monitoring of 

these streams is unnecessary. We have 

divided these streams into four overall 

categories, as specified in proposed 40 

CFR 60.105(a)(4)(iv)(A) through (D). The 

first category includes pilot gas flames, 

which are fairly insignificant sources. 

Although previous determinations 

effectively excluded these gases from 

the requirements of the rule, we believe 

it is good air pollution control practice 

to fire pilot lights with natural gas or 

treated fuel gas. However, even when 

considering the pilot flame as part of the 

fuel gas combustion device, the 

potential for sulfur oxide emissions 

from these sources is insignificant and 

it is not cost-effective to require 

continuous monitoring of these gas 

streams. Therefore, we are changing in 

the monitoring requirements that 

monitoring of pilot flame fuel gas is not 

required. 

The second category includes gas 

streams that meet commercial-grade 

product specifications with a sulfur 

content of 30 ppmv or less. Placing a 

limit on the sulfur content of the 

products that we are proposing to 

exempt from monitoring ensures that 

only low-sulfur products are excluded. 

The 30 ppmv limit for commercial-grade 

gas products was selected because it 

provides a sufficient margin of safety to 

ensure continuous compliance with the 

proposed annual average H2S 

concentration limit of 60 ppmv 

regardless of normal fluctuations in the 

composition of commercial grade 

products. 

We are requesting comment on the 

appropriateness of an additional 

exemption for gas streams that were 

generated from certain commercialgrade liquid products (e.g., displaced 

vapors from a storage tank or loading 

rack for gasoline or diesel fuel). The 

most straightforward approach would be 

to exempt gas streams associated with 

commercial liquid products that contain 

sulfur below some specified weight 

percent level. For example, we expect 

that most of the sulfur-containing 

compounds in gasoline meeting the Tier 

2 sulfur standards or in diesel fuel 


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meeting the low-sulfur diesel fuel 

standards have high molecular weights 

and low vapor pressures such that gas 

streams in equilibrium with them would 

have sulfur contents below the proposed 

30 ppmv level. To confirm this 

assumption, we are asking for data on 

the typical concentrations and vapor 

pressures of the most prevalent 

mercaptans, thiophenes, and other 

sulfur-containing compounds in these 

or other commercial liquid products. 

We would use these data to calculate 

the corresponding vapor phase 

concentrations of gas streams in 

equilibrium with the liquid products 

using Raoult’s Law. Given the extremely 

low concentrations of the sulfurcontaining compounds in the liquid 

products, we are also seeking comment 

on whether Raoult’s Law gives a 

realistic estimate of their vapor phase 

partial pressures. We are also interested 

in any test data to support this 

approach, and we are interested in any 

other approaches to develop an 

exemption for gas streams associated 

with commercial-grade liquid products. 

The third category includes fuel gases 

produced by process units that are 

intolerant of sulfur contamination. 

There are a few process units within a 

refinery whose operation is dependent 

on keeping the sulfur content low. If 

there is too much sulfur in the gas 

streams entering these units, the process 

units could malfunction. Specifically, 

the methane reforming unit in the 

hydrogen plant, the catalytic reforming 

unit, and the isomerization unit are 

intolerant of sulfur in the process 

streams; therefore, these streams are 

treated to remove sulfur prior to 

processing in these units. Fuel gases 

subsequently formed in these process 

units are low in sulfur because the 

process feedstocks are necessarily low 

in sulfur. As such, we find that 

requiring continuous monitoring of the 

H2S content in these gas streams or 

requiring each individual refinery to 

develop and implement an alternative 

monitoring plan (AMP) is unnecessary 

and creates needless obstacles to using 

the produced fuel gas directly in the 

heaters associated with these process 

units. We are asking for comment on 

whether fuel gas is generated from any 

other process units that are intolerant of 

sulfur. Comments recommending the 

exemption of fuel gas streams from 

other units should identify the problems 

sulfur cause in the unit, procedures 

used to reduce sulfur in the gas stream 

before it is processed in the unit, and 

the expected sulfur content of the outlet 

fuel gas stream. 

For all of the above low-sulfur streams 

that an owner or operator determines 

are exempt from all monitoring 

requirements, the owner or operator 

must document which of the 

exemptions applies to each stream. If 

the refinery operations associated with 

an exempt stream change, the owner or 

operator must document the change and 

determine whether the stream continues 

to be exempt. If the refinery operations 

or the composition of an exempt stream 

change in such a way that the stream is 

no longer exempt from monitoring, the 

owner or operator must begin 

continuous monitoring within 15 days 

after the change occurs. 

In addition, we are proposing a 

standardized, streamlined procedure to 

exempt from continuous monitoring 

streams that an owner or operator can 

demonstrate are inherently low-sulfur 

(i.e., consistently 5 ppmv or less H2S) 

following the procedures specified in 

proposed 40 CFR 60.105(b). The 

information that an owner or operator 

must provide to EPA is similar to the 

information and items needed to apply 

for an AMP, as described in the EPA 

document ‘‘Alternative Monitoring Plan 

for NSPS Subpart J Refinery Fuel Gas.’’

In general, once an AMP is approved for 

an affected source, the owner or 

operator must continue to monitor the 

stream, although a methodology other 

than a continuous monitor may be used. 

For this specific exemption, however, 

once an application to demonstrate that 

a stream is inherently low-sulfur is 

approved by EPA, that stream is exempt 

from monitoring until there is a change 

in the refinery operation that affects the 

stream or the stream composition 

changes. If the sulfur content of the 

stream changes but is still within the 

range of concentrations included in the 

original application, the owner or 

operator will conduct H2S testing on a 

grab sample as proof and record the 

results of the test. If the sulfur content 

of the stream changes such that the 

sulfur concentration is outside the range 

provided in the original application, the 

owner or operator must submit a new 

application that must be approved in 

order for the stream to continue to be 

exempt from continuous monitoring. If 

a new application is not submitted, the 

owner or operator must begin 

continuous monitoring within 15 days. 

B. How is EPA proposing to amend 

definitions? 

We are proposing to amend the 

definition of ‘‘Claus sulfur recovery 

plant’’ in 40 CFR 60.101(i). These 

changes would clarify that the SRP may 

consist of multiple units, and the types 

of units that are part of a SRP would be 

listed within the definition. Note that 

sulfur pits would be included as one of 

the units, which is consistent with the 

Agency’s current interpretation of the 

existing definition. 

In conjunction with this amendment, 

we are also proposing to amend the 

definitions of ‘‘oxidation control 

system’’ and ‘‘reduction control system’’

in 40 CFR 60.101(j) and 40 CFR 

60.101(k), respectively. The amended 

definitions would specify that the 

oxidized or reduced sulfur is recycled to 

the beginning of a sulfur recovery train 

within the SRP and are consistent with 

the proposed definitions in 40 CFR 

60.101a of subpart Ja. This clarification 

would ensure that thermal oxidizers 

that convert the sulfur to SO2 but do not 

recycle and recover the oxidized sulfur 

are not considered oxidation control 

systems. 

C. How is EPA proposing to revise the 

coke burn-off equation? 

The current equation for calculating 

coke burn-off rate in 40 CFR 

60.106(b)(3) assumes that each fluid 

catalytic cracking unit is using air with 

21 percent O2. However, there are some 

fluid catalytic cracking units that use 

O2-enriched air, and for these units, the 

current equation is not completely 

accurate. Equation 1 in 40 CFR 

63.1564(b)(4)(i) of the National Emission 

Standards for Hazardous Air Pollutants 

for Petroleum Refineries: Catalytic 

Cracking Units, Catalytic Reforming 

Units, and Sulfur Recovery Units (40 

CFR part 63, subpart UUU) includes an 

additional term to account for the use of 

an O2-enriched air stream. For accuracy 

in the calculation of the coke burn-off 

rate, we are proposing to revise the coke 

burn-off rate equation in 40 CFR 

60.106(b)(3) to be consistent with the 

equation in 40 CFR 63.1564(b)(4)(i). 

This revision also includes changing the 

constant values and the units of the 

resulting coke burn-off rate from 

Megagrams per hour (Mg/hr) and tons 

per hour (tons/hr) to kilograms per hour 

(kg/hr) and pounds per hour (lb/hr). 

D. What miscellaneous corrections are 

being proposed? 

See Table 1 of this preamble for the 

miscellaneous technical corrections not 

previously described in this preamble 

that we are proposing throughout 40 

CFR part 60, subpart J. 


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TABLE 1.—PROPOSED TECHNICAL CORRECTIONS TO 40 CFR PART 60, SUBPART J 

Section Proposed technical correction and reason 

60.100 ..................................... Replace instances of ‘‘construction or modification’’ with ‘‘construction, reconstruction, or modification.’’ 

60.100(b) ................................. Replace ‘‘except Claus plants of 20 long tons per day (LTD) or less’’ with ‘‘except Claus plants with a design 

capacity of 20 long tons per day (LTD) or less’’ to clarify that the size cutoff is based upon design capacity 

and sulfur content in the inlet stream rather than the amount of sulfur produced. 

60.100(b) ................................. Insert ending date for applicability of 40 CFR part 60, subpart J; sources beginning construction, reconstruction, 

or modification after this date will be subject to 40 CFR part 60, subpart Ja. 

60.101 ..................................... Rearrange definitions alphabetically for ease in locating a specific definition. 

60.102(b) ................................. Replace ‘‘g/MJ’’ with ‘‘grams per Gigajoule (g/GJ)’’ to correct units. 

60.104(b)(1) ............................ Replace ‘‘50 ppm by volume (vppm)’’ with ‘‘50 ppm by volume (ppmv)’’ for consistency in unit definition. 

60.104(b)(2) ............................ Add ‘‘to reduce SO2 emissions’’ to the end of the phrase ‘‘Without the use of an add-on control device’’ at the 

beginning of the paragraph to clarify the type of control device to which this paragraph refers. 

60.105(a)(3) ............................ Add ‘‘either’’ before ‘‘an instrument for continuously monitoring’’ and replace ‘‘except where an H2S monitor is 

installed under paragraph (a)(4)’’ with ‘‘or monitoring as provided in paragraph (a)(4)’’ to more accurately refer 

to the requirements of § 60.105(a)(4) and clarify that there is a choice of monitoring requirements. 

60.105(a)(3)(iv) ....................... Replace ‘‘accurately represents the SO2 emissions’’ with ‘‘accurately represents the SO2 emissions’’ to correct a 

typographical error. 

60.105(a)(4) ............................ Replace ‘‘In place’’ with ‘‘Instead’’ at the beginning of this paragraph to clarify that there is a choice of monitoring requirements. 

60.105(a)(8) ............................ Replace ‘‘seeks to comply with § 60.104(b)(1)’’ with ‘‘seeks to comply specifically with the 90 percent reduction 

option under § 60.104(b)(1)’’ to clearly identify the emission limit option to which the monitoring requirement in 

this paragraph refers. 

60.105(a)(8)(i) ......................... Change ‘‘shall be set 125 percent’’ to ‘‘shall be set at 125 percent’’ to correct a grammatical error. 

60.106(e)(2) ............................ Replace the incorrect reference to 40 CFR 60.105(a)(1) with a correct reference to 40 CFR 60.104(a)(1). 

60.107(c)(1)(i) ......................... Replace both occurrences of ‘‘50 vppm’’ with ‘‘50 ppmv’’ for consistency in unit definition. 

60.107(f) .................................. Redesignate current 40 CFR 60.107(e) as 40 CFR 60.107(f) to allow space for a new paragraph (e). 

60.107(g) ................................. Redesignate current 40 CFR 60.107(f) as 40 CFR 60.107(g) to allow space for a new paragraph (e). 

60.108(e) ................................. Replace the incorrect reference to 40 CFR 60.107(e) with a correct reference to 40 CFR 60.107(f). 

60.109(b)(2) ............................ Add a reference to 40 CFR 60.106(e)(3) to specify that determining whether a fuel gas stream is low-sulfur may 

not be delegated to States. 

60.109(b)(3) ............................ Redesignate current 40 CFR 60.109(b)(2) as 40 CFR 60.109(b)(3) to allow space for a new paragraph (b)(2). 

V. Rationale for the Proposed 

Standards (40 CFR part 60, subpart Ja) 

A. What is the performance of control 

technologies for fluid catalytic cracking 

units? 

1. PM Control Technologies 

Filterable PM emissions from fluid 

catalytic cracking units are 

predominately fine catalyst particles 

generated from the mechanical grinding 

of catalyst particles as the catalyst is 

continuously recirculated between the 

fluid catalytic cracking unit and the 

catalyst regenerator. Control of PM 

emissions from fluid catalytic cracking 

units relies on the use of postcombustion controls to remove solid 

particles from the flue gases. 

Electrostatic precipitators (ESP) and wet 

scrubbers are the predominant 

technologies used to control PM from 

fluid catalytic cracking units. Either of 

these PM control technologies can be 

designed to achieve overall PM 

collection efficiencies in excess of 95 

percent. 

Electrostatic Precipitator (ESP). An 

ESP operates by imparting an electrical 

charge to incoming particles, and then 

attracting the particles to oppositely 

charged metal plates for collection. 

Periodically, the particles collected on 

the plates are dislodged in sheets or 

agglomerates (by rapping the plates) and 

fall into a collection hopper. The normal 

PM control efficiency range for an ESP 

is between 90 and 99+ percent. One of 

the major advantages of an ESP is that 

it operates with essentially little 

pressure drop in the gas stream. They 

are also capable of handling high 

temperature conditions. 

Wet Scrubbers. Wet scrubbers use a 

water spray to coat and agglomerate 

particles entrained in the flue gas. To 

improve wetting of fine particulates, 

either enhanced spray nozzles or 

venturi acceleration is used. The wetted 

particles are then removed from the flue 

gas through centrifugal separation. Wet 

scrubbers have similar collection 

efficiencies as dry ESP (90 to 98 

percent), but they are also effective in 

removing SO2 emissions. Wet scrubbers 

may also be more effective in 

controlling condensable PM as they 

often use water quench and thereby 

operate at lower temperatures than ESP 

used to control fluid catalytic cracking 

units. Wet scrubbers are generally more 

costly to operate than ESP due to higher 

pressure drops across the control device 

and because of water treatment and 

disposal costs. However, they become 

economically viable if significant SO2

emissions reductions are also needed. 

Fabric Filters. A fabric filter collects 

PM in the flue gases by passing the 

gases through a porous fabric material. 

The buildup of solid particles on the 

fabric surface forms a thin, porous layer 

of solids, which further acts as a 

filtration medium. Gases pass through 

this cake/fabric filter, and all but the 

finest-sized particles are trapped on the 

cake surface. Collection efficiencies of 

fabric filters can be as high as 99.99 

percent. Fabric filters tend to be more 

efficient for fine particles (those less 

than 2.5 microns in diameter) than ESP 

or wet scrubbers. 

The primary concern with fabric 

filters are maintenance requirements of 

the baghouses given the long run times 

of typical fluid catalytic cracking units. 

Small process upsets (e.g., pressure 

changes) in the fluid catalytic cracking 

unit and regenerator system can send 

high concentrations of particles to the 

control system. These particles would 

likely blind the filter bags, causing a 

shut-down of the unit to replace the 

filter bags. Wet scrubbers and ESP can 

more easily accommodate and control 

high concentrations of particles. 

2. SO2 Control Technologies 

During combustion, sulfur 

compounds present in the deposited 

coke are predominately oxidized to 

gaseous SO2. One approach to 

controlling SO2 emissions from catalytic 

cracking units is to limit the maximum 

sulfur content in the feedstock to the 


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catalytic cracking unit. This can be 

accomplished by processing crude oil 

that naturally contains low amounts of 

sulfur or a feedstock that has been pretreated to remove sulfur (i.e., 

hydrotreatment or 

hydrodesulfurization). A second 

approach is to use a post-combustion 

control technology that removes SO2

from the flue gases. These technologies 

rely on either absorption or adsorption 

processes that react SO2 with lime, 

limestone, or another alkaline material 

to form an aqueous or solid sulfur byproduct. A third approach is the use of 

catalyst additives, which capture sulfur 

oxides in the regenerator and return 

them to the fluid catalytic cracking 

reactor where they are transformed to 

H2S that is ultimately exhausted to the 

SRP. 

Feedstock Selection or Pre-Treatment. 

The SO2 emissions from the fluid 

catalytic cracking unit are directly 

related to the amount of sulfur 

deposited on the catalyst particles in the 

riser and reactor section of the unit. The 

amount of sulfur deposited on the 

catalyst is a function of both the amount 

of sulfur in the feedstocks and the 

relative composition of the sulfurcontaining compounds in the feedstocks 

(mercaptans, thiosulfates). As the 

concentration of sulfur in the feedstocks 

is reduced, the SO2 emissions from the 

regenerator portion of the unit are also 

reduced. Therefore, if a refinery 

processes ‘‘sweet’’ crude (oil naturally 

low in sulfur) or if a refinery removes 

sulfur from the feedstocks of the fluid 

catalytic cracking unit, the SO2

emissions from the catalyst regenerator 

will be lower than from refineries that 

process feedstocks that have higher 

sulfur content. At a petroleum refinery, 

the primary means of removing sulfur 

compounds in the liquid feedstocks is 

catalytic hydrotreatment. 

Hydrotreatment typically reduces the 

sulfur content in process streams to 

between 20 and 1,000 parts per million 

by weight. 

Alkali Wet Scrubbing. The SO2 in a 

flue gas can be removed by reacting the 

sulfur compounds with a solution of 

water and an alkaline chemical to form 

insoluble salts that are removed in the 

scrubber effluent. Wet scrubbing 

processes used to control SO2 are 

generally termed flue-gas 

desulfurization (FGD) processes. The 

normal SO2 control efficiency range for 

SO2 scrubbers is 80 percent to 90 

percent for low efficiency scrubbers and 

90 percent to 99 percent for high 

efficiency scrubbers. In recent fluid 

catalytic cracking unit applications, 

control guarantees of 25 ppmv SO2 are 

commonly provided by FGD suppliers. 

Spray Dryer Adsorption. An 

alternative to using wet scrubbers is to 

use spray dryer adsorber (SDA) 

technology. A SDA operates by the same 

principle as alkali wet scrubbing, except 

that instead of a bulk liquid (as in wet 

scrubbing) the flue gas containing SO2 is 

contacted with fine spray droplets of 

hydrated lime slurry in a spray dryer 

vessel. This vessel is located 

downstream of the air heater outlet 

where the gas temperatures are in the 

range of 120 °C to 180 °C (250 °F to 

350 °F). The SO2 is absorbed in the 

slurry and reacts with the hydrated lime 

reagent to form solid calcium sulfite and 

calcium sulfate. The water is evaporated 

by the hot flue gases and forms dry, 

solid particles containing the reacted 

sulfur. Most of the SO2 removal occurs 

in the spray dryer vessel itself, although 

some additional SO2 capture has also 

been observed in downstream 

particulate collection devices. The SO2

removal efficiencies of new lime spray 

dryer systems are generally greater than 

90 percent. Only one refinery has ever 

used an SDA to control SO2 from its 

fluid catalytic cracking unit; this system 

has since been removed in favor of 

feedstock hydrotreatment. 

Catalyst Additives. One common 

method used by refineries to reduce SO2

emissions from the fluid catalytic 

cracking unit is the use of catalyst 

additives (typically various types of 

metal oxides). The metal oxide reacts 

with some of the SO3 in the catalyst 

regenerator to form a metal sulfate. The 

metal sulfate is then returned to the 

cracking unit where the sulfur is 

converted to a metal sulfide and then to 

H2S and the original metal oxide. The 

H2S is subsequently recovered in the 

SRP, and the metal oxide returns to the 

catalyst regenerator to repeat the 

process. The control efficiency of 

catalyst additives is difficult to assess, 

but is generally around 50 percent 

(ranging from 20 to 70 percent, 

depending on the application). 

3. NOX Control Technologies 

NOX are formed in a catalyst 

regenerator (and downstream CO boiler, 

if present) by the oxidation of molecular 

nitrogen (N2) in the combustion air and 

any nitrogen compounds contained in 

the fuel (i.e., thermal NOX and fuel 

NOX). The formation of NOX from 

nitrogen in the combustion air is 

dependent on two conditions occurring 

simultaneously in the unit’s combustion 

zone: high temperature and an excess of 

combustion air. Under these conditions, 

significant quantities of NOX are 

formed, regardless of the fuel type 

burned. There are several NOX emission 

control strategies that can be considered 

combustion controls (e.g., low NOX

burners or flue gas recirculation) that 

reduce the amounts of NOX formed 

during combustion. These control 

technologies are primarily applicable to 

incomplete combustion fluid catalytic 

cracking units controlled by CO boilers. 

As there is limited or no direct flame in 

the catalyst regenerator during normal 

operations, these control strategies may 

be limited for complete combustion 

fluid catalytic cracking units. Most postcombustion control technologies 

involve converting the NOX in the flue 

gas to N2 and water using either a 

process that requires a catalyst (called 

selective catalytic reduction (SCR)) or a 

process that does not use a catalyst 

(called selective noncatalytic reduction 

(SNCR)). A recently developed postcombustion technology (LoTOxTM) uses 

ozone to oxidize NOX to nitric 

pentoxide, which is water soluble and 

easily removed in a water scrubber. 

NOX Combustion Controls. Flue gas 

recirculation (FGR) uses flue gas as an 

inert material to reduce flame 

temperatures. In a typical FGR system, 

flue gas is collected from the heater or 

stack and returned to the burner via a 

duct and blower. The addition of flue 

gas with the combustion air reduces the 

O2 content of the inlet air stream to the 

burner. The lower O2 level in the 

combustion zone reduces flame 

temperatures which in turn reduces 

NOX emissions. The normal NOX

control efficiency range for FGR is 30 

percent to 50 percent. When coupled 

with low-NOX burners (LNB), the 

control efficiency increases to 50–72 

percent. 

LNB technology utilizes advanced 

burner design to reduce NOX formation 

through the restriction of O2, flame 

temperature, and/or residence time. The 

two general types of LNB are staged fuel 

and staged air burners. Staged fuel LNB 

are particularly well suited for boilers 

and process heaters burning process and 

natural gas which generate higher 

thermal NOX. The estimated NOX

control efficiency for LNB when applied 

to petroleum refining fuel burning 

equipment is generally around 40 

percent. 

One NOX combustion control 

technique that is applicable to complete 

combustion fluid catalytic cracking 

units is the use of catalyst additives 

and/or combustion promoters. The 

control efficiency of these additives 

varies from 10 to 50 percent. 

Selective Catalytic Reduction (SCR) 

Technology. The SCR process uses a 

catalyst with ammonia (NH3) to reduce 

the nitrogen oxide (NO) and nitrogen 

dioxide (NO2) in the flue gas to N2 and 

water. Ammonia is diluted with air or 


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steam, and this mixture is injected into 

the flue gas upstream of a metal catalyst 

bed that typically is composed of 

vanadium, titanium, platinum, or 

zeolite. The SCR catalyst bed reactor is 

usually located between the economizer 

outlet and air heater inlet where 

temperatures range from 230 °C to 

400 °C (450 °F to 750 °F). The SCR 

technology is capable of NOX reduction 

efficiencies of 90 percent or higher. 

Selective Noncatalytic Reduction 

(SNCR) Technology. An SNCR process 

is based on the same basic chemistry of 

reducing the NO and NO2 in the flue gas 

to N2 and water, but it does not require 

the use of a catalyst to promote these 

reactions. Instead, the reducing agent is 

injected into the flue gas stream at a 

point where the flue gas temperature is 

within a specific temperature range of 

870°C to 1,090°C (1,600°F to 2,000°F). 

The NOX reduction levels for SNCR are 

in the range of approximately 30 to 50 

percent. 

LoTOxTM Technology. The LoTOxTM

process (i.e., low-temperature oxidation) 

is a patented technology that uses ozone 

to oxidize NOX to nitric pentoxide and 

other higher order NOX, all of which are 

water soluble and easily removed from 

exhaust gas in a wet scrubber. The 

system operates optimally at 

temperatures below 300°F. Thus, ozone 

is injected after scrubber inlet quench 

nozzles and before the first level of 

scrubbing nozzles. Outlet NOX emission 

levels have been reduced to less than 20 

ppmv, and often as low as 10 ppmv, 

when inlet NOX concentrations ranged 

from 50 to 200 ppmv. 

B. What is the performance of control 

technologies for fuel gas combustion? 

Refinery fuel gas is generally used in 

process heaters and boilers to meet the 

energy demands of the refinery. Excess 

refinery fuel gas is typically combusted 

using flares. Flares also serve an 

important safety function to destroy 

organics and convert H2S to SO2 during 

process upsets and malfunctions. 

Over the past several years, many 

refineries have reduced flaring episodes 

by adding flare gas recovery systems 

and/or by changing their start-up and 

shutdown procedures to limit flaring. 

Installing a flare gas recovery system 

and implementing new start-up and 

shutdown procedures are expected to 

reduce VOC, sulfur oxides, and NOX

emissions from flares. Improved amine 

scrubbing systems are expected to 

reduce sulfur oxide emissions from all 

fuel gas combustion systems. In 

addition, excess capacity in the SRP 

will help to minimize sour gas flaring 

that might be caused by a malfunction 

in the SRP. Each of these ‘‘control’’

techniques are described in the 

following paragraphs. 

Flare Gas Recovery Systems. Flare gas 

recovery systems recover fuel gas from 

the flare gas header prior to the flare’s 

liquid seal. A flare gas recovery system 

consists of a compressor, separator, and 

process controls (to maintain slight 

positive pressure on the flare header). 

Flare gas recovery systems are typically 

designed to recover fuel gas from 

miscellaneous processes that might 

regularly be relieved to the flare header 

system and can effectively recover 100 

percent of these fuel gases. However, 

flare gas recovery systems cannot 

recover large quantities of fuel gas that 

might be suddenly released to the flare 

header system as a result of a process 

upset or malfunction. These gases 

would still be flared as necessary to 

maintain the integrity of the process 

units and the safety of the plant 

personnel. 

Modified Start-up and Shutdown 

Procedures. Although flaring is 

necessary to ensure safety during 

process upsets and malfunctions, startup and shutdown procedures can be 

designed so as to minimize flaring. For 

example, depressurization of process 

vessels can be performed more slowly 

so as to not overwhelm the fuel gas 

needs of the refinery and/or the capacity 

of the flare gas recovery system. 

Depending on the number of units being 

shut down at a given time, nearly 100 

percent of flaring can be eliminated 

during start-up and shutdown. There are 

cases, such as emergency shutdowns for 

safety reasons or approaching 

hurricanes, where the timing of the 

shutdown and the magnitude of the 

number of processes needing to be shut 

down would warrant the use of flaring. 

However, modified procedures should 

be able to eliminate flaring associated 

with process start-ups and shutdowns 

due to routine maintenance of select 

processes. 

Amine Scrubbers. Amine scrubber 

systems remove H2S and other 

impurities from sour gas. Lean amine 

solution absorbs the H2S from the sour 

gas in an absorption tower. The acid gas 

is removed from the rich amine solution 

in a stripper, or still column. The 

resulting lean amine is recirculated to 

the absorption tower, and the stripped 

H2S is generally sent to the SRP. 

Vendors generally provide redundant 

pumps to ensure continuous operation 

of the system. Some refineries choose to 

store a day’s worth of lean amine 

solution in case the stripper fails; this 

allows the continuous operation of the 

absorption tower. This option also 

requires adequate empty storage space 

for the rich amine solution produced by 

the absorption tower while the stripper 

is out of service. 

Redundant Sulfur Recovery Capacity. 

When a sulfur recovery unit (SRU) 

malfunctions, the sour gas is typically 

flared to convert the highly toxic H2S to 

less toxic SO2. As many SRU recover 

more than 20 long tons of elemental 

sulfur per day, even short sulfur 

recovery process upsets can result in 

several tons of SO2 emissions. 

Furthermore, refineries often operate 

multiple Claus sulfur recovery processes 

in parallel. Having an extra Claus sulfur 

recovery train can dramatically reduce 

the likelihood of sour gas flaring. 

Depending on the severity of the process 

upset, having a redundant SRU can 

reduce these large SO2 releases by as 

much as 100 percent. 

C. What is the performance of control 

technologies for process heaters? 

The mechanisms by which NOX are 

formed in process heaters are the same 

as for their formation in catalyst 

regenerators. The possible control 

options are also the same. See section 

V.A.3 of this preamble for a discussion 

of these formation mechanisms and 

control technologies. 

D. What is the performance of control 

technologies for sulfur recovery 

systems? 

Sulfur recovery (the conversion of 

H2S to elemental sulfur) is typically 

accomplished using the modified-Claus 

process. In the Claus unit, one-third of 

the H2S is burned with air in a reaction 

furnace to yield SO2. The SO2 then 

reacts reversibly with H2S in the 

presence of a catalyst to produce 

elemental sulfur, water, and heat. This 

is a multi-stage catalytic reaction in 

which elemental sulfur is removed 

between each stage, thereby driving the 

reversible reaction towards completion. 

The gas from the final condenser of the 

Claus unit (referred to as the ‘‘tail gas’’) 

consists primarily of inert gases with 

less than 2 percent sulfur compounds. 

Additionally, the sulfur recovery pits 

used to store the recovered elemental 

sulfur also have a potential for fugitive 

H2S emissions. Typically a Claus unit 

recovers approximately 94 to 97 percent 

of the inlet sulfur load as elemental 

sulfur. 

There are some methods that extend 

the Claus reaction to improve the 

overall sulfur collection efficiency of the 

SRP. For example, the Superclaus SRU 

is similar to the Claus unit. It contains 

a thermal stage, followed by three to 

four catalytic reaction stages. The first 

two or three catalytic reactors use the 

Claus catalyst, while the last reactor 

uses a selective oxidation catalyst. The 


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catalyst in the last reactor oxidizes the 

H2S to sulfur at a very high efficiency, 

recovering 99 percent of the incoming 

sulfur. 

There are a few refineries that operate 

non-Claus type SRU. All of the 

refineries that use non-Claus SRU 

technologies have very low sulfur 

production rates (2 LTD or less). There 

are several different trade names for 

these ‘‘other’’ types of SRU, such as the 

LoCat, Sulferox, and NaSH processes. 

These processes can achieve sulfur 

recovery efficiencies of 99 percent or 

more, although they typically yield a 

sulfur product that has limited market 

value because the sulfur content is 

much lower than in the sulfur product 

from a Claus unit (50 to 70 percent 

sulfur compared to 99.9 percent sulfur 

from the Claus process). 

The primary means of reducing sulfur 

oxide emissions from the SRU is to 

employ a tail gas treatment unit that 

recovers the sulfur compounds and 

recycles them back to the inlet of the 

Claus treatment train. There are three 

basic types of tail gas treatment units: 

(1) Direct amine adsorption of the Claus 

tail gas; (2) catalytic reduction of the tail 

gas to convert as much of the tail gas 

sulfur compounds to H2S (coupled with 

amine adsorption or Stretford solution 

eduction); and (3) oxidative tail gas 

treatment systems to convert the Claus 

tail gas sulfur compounds to SO2

(coupled with an SO2 recovery system). 

Direct Amine Adsorption. Direct 

amine adsorption of the Claus tail gas is 

the least efficient of the tail gas 

treatment methods because only about 

two-thirds of the sulfur in the direct 

Claus tail gas is amenable to scrubbing 

(i.e., in the form of H2S). Direct amine 

adsorption is therefore expected to 

increase the overall sulfur recovery 

efficiency of the sulfur plant to 

approximately 99 percent. However, 

direct amine adsorption alone is 

generally not expected to reduce sulfur 

oxide concentrations to below 250 

ppmv (i.e., enough to meet the existing 

NSPS emission limits for Claus units 

greater than 20 LTD). 

Reductive Tail Gas Catalytic Systems. 

The most common reductive tail gas 

catalytic systems in use at refineries 

include: (1) The Shell Claus Offgas 

Treatment (SCOT) unit; (2) the Beavon/ 

amine system; and (3) the Beavon/ 

Stretford system. Each of these systems 

consist of a catalytic reactor to convert 

the sulfur compounds remaining in the 

Claus tail gas to H2S and an H2S 

recovery system (an amine scrubber or 

a Stretford solution) to strip the H2S 

from the tail gas. The recovered H2S is 

then recycled to the front of the Claus 

unit. The overhead of the amine 

scrubber or Stretford unit (caustic 

scrubber) may be vented to the 

atmosphere or incinerated to convert 

any remaining H2S or other reduced 

sulfur compounds to SO2. The total 

sulfur recovery efficiency of a Claus/ 

catalytic tail gas treatment train is 

expected to be 99.7 to 99.9 percent. 

Oxidative Tail Gas Treatment 

Systems. The Wellman-Lord is the only 

oxidative tail gas treatment system used 

in the United States. The Wellman-Lord 

process uses thermal oxidation followed 

by scrubbing with a sodium sulfite and 

sodium bisulfite solution to remove 

SO2. The rich bisulfite solution is sent 

to an evaporator-recrystallizer where the 

bisulfite decomposes to SO2 and water 

and sodium sulfite is precipitated. The 

recovered SO2 is then recycled back to 

the Claus plant for sulfur recovery. The 

total sulfur recovery efficiency of a 

Claus/oxidative tail gas treatment train 

is expected to be 99.7 to 99.9 percent. 

E. How did EPA determine the proposed 

standards for new petroleum refining 

process units? 

Four sources of information were 

considered in reviewing the 

appropriateness of the current NSPS 

requirements for new sources: (1) 

Source test data from recently installed 

control systems; (2) applicable State and 

local regulations; (3) control vendor 

emission control guarantees; and (4) 

consent decrees. (A significant number 

of refineries, representing about 77 

percent of the national refining capacity, 

are subject to consent decrees that limit 

the emissions from subpart J process 

units.) Once we identified potential 

emission limits for various process 

units, we evaluated each limit in 

conjunction with control technology, 

costs, and emission reductions to 

determine BDT for each process unit. 

The cost methodology incorporates 

the calculation of annualized costs and 

emission reductions associated with 

each of the options presented. Costeffectiveness is the annualized cost of 

control divided by the annual emission 

reductions achieved. Incremental costeffectiveness refers to the difference in 

annualized cost from one option to the 

next divided by the difference in 

emission reductions from one option to 

the next. For NSPS regulations, the 

standard metric for expressing costs and 

emission reductions is the impact on all 

affected facilities accumulated over the 

first 5 years of the regulation. Details of 

the calculations can be found in the 

public docket. Our BDT determinations 

took all relevant factors into account, 

including cost considerations which 

were generally consistent with other 

Agency decisions. 

1. Fluid Catalytic Cracking Units 

Particulate Matter (PM) and Sulfur 

Dioxide (SO2). In order to determine the 

appropriate emission limits for PM and 

SO2, we evaluated PM and SO2 limits in 

conjunction with one another. One of 

the reasons for this is that wet scrubbers 

control both PM and SO2 emissions, and 

refineries will decide whether to choose 

a wet scrubber as opposed to an ESP 

with catalyst additives based on both 

the PM and the SO2 emission limit to be 

met. 

Currently, 40 CFR part 60, subpart J 

limits PM emissions from the fluid 

catalytic cracking unit to 1.0 kg/Mg of 

coke burn-off. The limit applies to 

filterable PM as measured by Method 5B 

or 5F in 40 CFR part 60, Appendix A. 

It excludes condensable PM such as 

sulfuric acid (under Method 5B), 

sulfates that condense at temperatures 

greater than 320 °F (under Method 5F), 

and all other condensables (using either 

Method). The measurement of 

condensable PM is important to EPA’s 

goal of reducing ambient air 

concentrations of fine PM. Since 

promulgation of Method 202 in 1991, 

EPA has been working to overcome 

problems associated with the accuracy 

of Method 202 and will promulgate 

improvements to the method in the 

future. The existing NSPS also requires 

opacity, as measured using a continuous 

opacity monitoring system, to be no 

more than 30 percent. 

The current standards in 40 CFR part 

60, subpart J for SO2 include three 

alternative formats: (1) If using an addon control device, reduce SO2 emissions 

by at least 90 percent or to less than 50 

ppmv, (2) if not using an add-on control 

device, limit sulfur oxides emissions 

(calculated as SO2) to no more than 9.8 

kg/Mg of coke burn-off, or (3) process in 

the fluid catalytic cracking unit fresh 

feed that has a total sulfur content no 

greater than 0.30 percent by weight. The 

90 percent reduction, 9.8 kg/Mg, and 0.3 

percent feed sulfur formats were 

determined to be equivalent for a unit 

operating with a feed that contains 3.5 

percent sulfur by weight before 

implementing a control measure. 

In reviewing the PM and SO2

emission limits, we evaluated five 

combined options and a baseline. The 

baseline is considered to be the current 

requirements, as described in the two 

previous paragraphs. The first option is 

to maintain the existing subpart J 

standard for PM and provide only the 50 

ppmv concentration limit for SO2. The 

additional options are a range of 

emission limits coupled with a change 

in the compliance test method to 

Method 5 to measure a portion of the 


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condensable PM. The second option is 

to combine Method 5 with the existing 

1.0 kg/Mg coke burn-off performance 

level, and a third option is to lower the 

PM emission limit to 0.5 kg/Mg. Both 

the second and third options include an 

SO2 limit of 50 ppmv. A fourth option 

includes the PM limit of 0.5 kg/Mg 

presented in the third option and a 

lower SO2 limit of 25 ppmv. The fifth 

option is to lower the PM emission limit 

to 0.15 kg/Mg with an SO2 limit of 25 

ppmv. Costs and emission reductions 

for each option were estimated as the 

increment between complying with 

subpart J and subpart Ja. 

Option 1 includes the same emissions 

and requirements for PM as the current 

40 CFR part 60, subpart J. For SO2, this 

option excludes the alternative 

compliance options of meeting a higher 

emission limit without an SO2 control 

device or meeting a limit on the sulfur 

content of the fresh feed. These two 

alternatives are less stringent than the 

outlet concentration limit, and available 

information indicates the concentration 

limits are achievable. An advantage of 

the proposed concentration limit is that 

ongoing compliance can be directly 

measured using a CEMS. The impacts of 

this option are limited to the impacts of 

removing those alternative compliance 

options for SO2 and are presented in 

Table 2 to this preamble. To comply 

with Option 1 (i.e., meet the 50 ppmv 

limit for SO2) we expect that the fraction 

of new sources choosing wet scrubbers 

instead of ESP would be greater than 

under the existing subpart J. Filterable 

PM emissions are assumed to be the 

same for both types of control devices 

because the PM performance levels are 

the same under both option 1 and the 

baseline subpart J requirements. 

However, because condensable PM 

emissions are lower from wet scrubbers 

than from ESP, this shift in the ratio of 

wet scrubbers to ESP would also result 

in an estimated reduction in total PM 

emissions of 17 tons per year, as shown 

in Table 2 to this preamble. 

Option 2 includes the same emission 

limit as current subpart J for PM but 

requires compliance using Method 5 

rather than Method 5B or Method 5F. As 

noted above, Methods 5B and 5F 

exclude all PM that condenses at 

temperatures below 320°F, and Method 

5F also excludes sulfates that condense 

at temperatures greater than 320°F. The 

PM measured by Method 5 includes 

filterable PM that condenses above 

250°F in the front half of the Method 5 

sampling train. Thus, the estimated PM 

emission reductions achieved by this 

option equal the amount of sulfates and 

other condensable PM between 250°F 

and 320°F that would be measured by 

Method 5 but not Method 5B or 5F. The 

baseline emissions were estimated 

assuming Method 5B is used for wet 

scrubbers and Method 5F is used for 

ESP. For SO2, Option 2 includes the 

same emission limit as described in 

Option 1, and the estimated SO2

emission reductions are also the same. 

The impacts of this option are presented 

in Table 2 to this preamble. 

Option 3 lowers the PM limit to 0.5 

kg/Mg coke burn, again using Method 5, 

and includes the same emission limit as 

described in Option 1 for SO2. The 

existing NSPS limit was based on 

control with ESP. Those ESP were rated 

at efficiencies of only 85 to 90 percent. 

More recently installed ESP have greater 

specific plate area, which should result 

in better control efficiencies. In 

addition, many refineries have installed 

wet scrubbers to control both PM and 

SO2. At petroleum refineries, wet 

scrubbers typically perform as well as, 

if not better than, ESP. Available test 

data indicate that at least one ESP and 

one wet scrubber are reducing total 

filterable PM to 0.5 kg/Mg of coke burn 

or less, as measured by Method 5- 

equivalent test methods. Based on this 

information, both ESP and wet 

scrubbers can achieve PM emission 

levels below the level of the existing PM 

standard, and a lower standard for new 

units is technically feasible. The 

impacts of this option are presented in 

Table 2 to this preamble. 

Option 4 includes the same PM limit 

as Option 3, and the discussion 

presented for Option 3 applies to Option 

4 as well. It also includes a long-term 

limit for SO2 of 25 ppmv, averaged over 

365 days, in addition to the current 

subpart J limit of 50 ppmv, averaged 

over 7 days. These limits have been 

shown to be readily achievable by flue 

gas desulfurization systems. Many fluid 

catalytic cracking units are now subject 

to consent decrees that require control 

to these levels. Petroleum refiners 

typically use wet scrubbers to control 

SO2 emissions, and test data indicate 

that outlet concentrations below 25 

ppmv are common. At least one wet 

scrubber manufacturer also provides 

performance guarantees to meet a 25 

ppmv emission limit. The incremental 

SO2 reductions for this option relative to 

Option 3 are achieved by using catalyst 

additives in the fluid catalytic cracking 

units that are assumed to be controlled 

with ESP; fluid catalytic cracking units 

controlled with wet scrubbers have the 

same SO2 emissions as under Option 3 

because wet scrubbers under all options 

are assumed to achieve SO2 emissions 

below 25 ppmv. The impacts of this 

option are presented in Table 2 to this 

preamble. 

The final option, Option 5, includes a 

lower PM limit, 0.15 kg/Mg of coke 

burn, measured using Method 5, and the 

same SO2 limits as Option 4. This PM 

limit is equivalent to the limit of 0.005 

gr/dscf required by California’s South 

Coast Air Quality Management District 

(SCAQMD). To meet this PM limit, we 

expect that a refinery would need an 

ESP rather than a wet scrubber because 

we are unaware of any wet scrubber that 

is meeting this PM limit (and as in 

Option 4, catalyst additives in the fluid 

catalytic cracking unit would be needed 

to meet the SO2 limit). In addition, the 

refinery would likely need ammonia 

injection to improve the performance of 

the ESP. Based on test data from at least 

three fluid catalytic cracking units, 

ammonia injection improves the control 

of filterable PM in ESP, but it also 

produces a considerable amount of 

condensable PM. Therefore, the 

estimated total PM reduction for this 

option is much lower (worse) than the 

reduction that would be achieved under 

Option 4. The shift to ESP for all new 

fluid catalytic cracking units under this 

option also slightly degrades the 

estimated SO2 emissions reduction 

relative to Option 4 because available 

data indicate that wet scrubbers achieve 

lower SO2 emissions than ESP and 

catalyst additives. In addition to 

reduced performance relative to Option 

4, the capital and annual costs of this 

option are considerably higher than for 

Option 4. The reduced performance of 

this option relative to Option 4 means 

that incremental cost-effectiveness is 

not meaningful for this option. The 

impacts of this option are presented in 

Table 2 to this preamble. 


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TABLE 2.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR PM AND SO2 LIMITS CONSIDERED FOR FLUID CATALYTIC

CRACKING UNITS SUBJECT TO 40 CFR PART 60, SUBPART JA

Option Capital cost 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Emission 

reduction 

(tons PM/ 

yr) a

Emission 

reduction 

(tons SO2/ 

yr) 

Cost-effectiveness ($/ton) 

Overall Incremental 

1 ....................................................................................... 500 3,100 17 6,800 460 

2 ....................................................................................... 670 3,600 350 6,800 500 1,400 

3 ....................................................................................... 40,000 9,200 1,200 7,200 1,100 4,400 

4 ....................................................................................... 40,000 9,500 1,200 8,300 1,000 220 

5 ....................................................................................... 140,000 30,000 460 7,900 3,600 N/A 

aBoth filterable and condensable PM. 

Based on our review of performance 

data and potential impacts, we have 

determined that control of PM 

emissions (as measured by Method 5) to 

0.5 kg/Mg of coke burn or less and 

control of SO2 emissions to 25 ppmv or 

less averaged over 365 days and 50 

ppmv or less averaged over 7 days is 

BDT for new, reconstructed, or modified 

fluid catalytic cracking units. The more 

stringent filterable PM control level in 

Option 5 is technically achievable, but 

we rejected this option because it results 

in higher total PM and SO2 emissions 

than Option 4. Option 4 was selected as 

BDT because it achieves the best 

performance of the remaining options, 

and both overall and incremental costs 

are reasonable. 

Table 3 to this preamble shows the 

impacts of Option 4 for modified and 

reconstructed sources. Although the 

impacts of Option 4 are reasonable, we 

are aware that there is some concern 

about the ability to retrofit reconstructed 

and modified sources to meet these 

emission limits. Specifically, there may 

be issues with physical space 

availability, process unit or control 

device configurations, or other factors 

that are not adequately included in our 

impacts analyses. Therefore, we are coproposing requiring reconstructed and 

modified units to meet the current 

standards in 40 CFR part 60, subpart J. 

We are requesting comment on specific 

examples, supported by data, of 

situations that would support this 

proposed option. 

TABLE 3.—NATIONAL FIFTH YEAR IMPACTS OF PROPOSED OPTION FOR PM AND SO2 LIMITS FOR RECONSTRUCTED AND

MODIFIED SOURCES

Capital cost ($1,000) 

Total annual 

cost 

($1,000/yr) 

Emission 

reduction 

(tons PM/yr) 

Emission 

reduction 

(tons SO2/yr) 

Cost-effectiveness ($/ton) 

31,000 .............................................................................................................. 6,200 700 3,700 1,400 

Finally, available test data indicate 

that the two control devices (an ESP and 

a wet scrubber) that reduce filterable PM 

to less than 0.5 kg/Mg coke burn (as 

well as at least one other ESP) also can 

meet a total PM limit, including 

condensables, of 1.0 kg/Mg of coke burn 

(i.e., demonstrate compliance using 

Method 5 for filterable PM and Method 

202 for condensable PM). Condensable 

sulfates and other condensable 

compounds measured by Method 5 and 

Method 202 vary widely, but the 

average is about 0.5 kg/Mg of coke burnoff. In an attempt to create some 

incentive to begin measuring 

condensables using improved Method 

202, we are considering establishing an 

alternative PM limit of 1 kg/Mg coke 

burn, including condensables. 

Therefore, we are asking for comments 

with rationale to either support or reject 

an alternative PM limit that would be 

based on both filterable PM and 

condensable PM. 

Carbon Monoxide. The current 

standards in 40 CFR part 60, subpart J 

limit CO emissions to 500 ppmv or less. 

This limit was established for fluid 

catalytic cracking units that operate in 

either ‘‘partial combustion’’ catalyst 

regeneration mode or ‘‘complete 

combustion’’ catalyst regeneration 

mode. In partial combustion mode, 

relatively large amounts of CO are 

generated in the regenerator. The 

resulting CO is then combusted in a CO 

or waste heat boiler. This operation 

results in nearly complete combustion 

of the CO, with outlet concentrations on 

the order of 25 to 50 ppmv being 

common. In complete combustion mode 

the CO emissions from the regenerator 

are much lower, and a downstream CO 

or waste heat boiler is impractical. 

However, complete combustion catalyst 

regeneration was a recent advance at the 

time the current NSPS was 

promulgated; test data were limited at 

that time, and a CO level of 500 ppmv 

was estimated to be a practical limit for 

the technology. 

After consideration of available 

information, we are proposing to retain 

the current CO standard for new fluid 

catalytic cracking units. Although test 

data show CO emissions from complete 

combustion regenerators can be less 

than 500 ppmv, the lower levels 

generally are achieved by operating with 

higher levels of excess air. 

Unfortunately, this operation is likely to 

result in higher NOX emissions. If a 

trade-off is necessary, limiting NOX

emissions is a higher priority than 

limiting CO emissions because NOX is a 

precursor to fine PM and ground-level 

ozone, both of which have more 

significant health impacts than CO. 

Available data also indicate that 

formaldehyde emissions tend to 

increase with the higher oxidation/ 

combustion conditions needed to 

reduce CO emissions. Therefore, we 

determined that control to 500 ppmv or 

less is still BDT for CO emissions, and 

the proposed standards are based on 

this emission limit. Accordingly, the 

proposed limit for 40 CFR part 60, 

subpart J poses no additional costs over 

those incurred to comply with the 

existing NSPS. 

NOX. NOX emissions are not subject to 

control under the existing NSPS in 40 

CFR part 60, subpart J. However, several 

petroleum refiners limit NOX emissions 

based on State regulations and consent 

decrees. The emission limits to which 

refineries are subject vary from facility 

to facility. We evaluated three options 


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as part of the BDT determination: Outlet 

NOX emission levels of 80 ppmv, 40 

ppmv, and 20 ppmv, each averaged over 

7 days or less. Each of these limits is 

technically feasible, but the technology 

needed to meet them depends on the 

current NOX concentrations in the 

vented gas streams, which are either 

uncontrolled or controlled to levels 

required by existing State and local 

requirements. 

The estimated fifth year emission 

reductions and costs for each of the 

options are summarized in Table 4. To 

estimate impacts for Option 1, we 

assumed that a few units have current 

NOX emissions below 80 ppmv, and 

many other units can meet this level 

with combustion controls (e.g., limiting 

excess O2 or using non-platinum 

catalyst combustion promoters in a 

complete combustion catalyst 

regenerator, or using flue gas 

recirculation or low-NOX burners in a 

CO boiler after a partial combustion 

catalyst regenerator). Other units with 

higher uncontrolled NOX emissions 

levels will need to install more costly 

control technology such as LoTOxTM or 

SCR in order to meet the 80 ppmv 

option. All units will also incur costs for 

a continuous NOX monitor. The costs 

for Options 2 and 3 are higher than for 

Option 1 because the ratio of add-on 

controls to combustion controls would 

increase in order to meet the lower 

limits of 40 and 20 ppmv. 

Based on the impacts shown in Table 

4, we determined that BDT is option 1, 

a NOX emission limit of 80 ppmv. The 

costs of option 1 are commensurate with 

the emission reductions while the more 

stringent options would impose 

compliance costs that are not warranted 

for the emissions reductions that would 

be achieved as shown by the 

incremental cost effectiveness impacts 

shown in table 4. In general, we expect 

that most sources will be able to meet 

the NOX limit through combustion 

controls. In cases where add-on controls 

would be necessary, however, there may 

be retrofit concerns for modified and 

reconstructed sources. Therefore, we are 

co-proposing no new standards for NOX

emissions on modified or reconstructed 

sources and are requesting comments on 

the necessity, feasibility and costs of 

retrofits to meet the 80 ppmv limit for 

modified and reconstructed sources. 

TABLE 4.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR NOX LIMITS CONSIDERED FOR FLUID CATALYTIC CRACKING

UNITS SUBJECT TO 40 CFR PART 60, SUBPART JA

Option 

Total capital 

cost, $ 

(millions) 

Total annual 

cost, $/yr 

(millions) 

Emission 

reduction, tons 

NOX/yr 

Cost effectiveness ($/ton) 

Overall Incremental 

1 ........................................................................................... 28 7.3 3,500 2,100 ........................

2 ........................................................................................... 80 20 5,200 4,200 7,600 

3 ........................................................................................... 120 30 5,800 5,500 16,000 

Available test data for units controlled 

with SCR indicate that emissions less 

than 20 ppmv are continuously 

achievable when averaged over long 

periods of time such as 365 days. 

Although we determined that the 

average costs to meet such a limit are 

unreasonable, we are requesting 

comment on whether there may be a 

subset of units for which costs would be 

reasonable to meet lower limits such as 

20 or 40 ppmv, averaged over 365 days. 

Opacity. The current standards 

require fluid catalytic cracking units to 

meet an opacity limit of 30 percent. This 

limit was included as a means of 

identifying failure of the PM control 

device. This objective is achieved much 

more effectively by monitoring control 

device operating parameters or by using 

a PM CEMS. These monitoring options 

are included in the proposed standards 

for PM. Therefore, the proposed 

standards do not include an opacity 

emissions limit. 

2. Fluid Coking Units 

The current NSPS includes no 

requirements for fluid coking units. 

There are few fluid coking units at 

refineries in the U.S., but data in the 

National Emission Inventory database 

shows the few existing units are 

significant sources of PM, SO2, and NOX

emissions. Therefore, we evaluated 

several options as part of a BDT 

determination for fluid coking units. All 

of the options we considered are 

comparable to options that we 

considered for fluid catalytic cracking 

units because of similarities in the 

function, operation, and emissions of 

the two types of units. 

Particulate Matter and Sulfur Dioxide. 

To determine BDT for PM and SO2

emissions we evaluated two options. 

Because control technology can reduce 

both pollutants simultaneously, the 

options also consider both pollutants. 

Option 1 is a PM limit of 1.0 kg/Mg coke 

burn and a short-term SO2 limit of 50 

ppmv, averaged over 7 days; and Option 

2 is a PM limit of 0.5 kg/Mg coke burn, 

a short-term SO2 limit of 50 ppmv, 

averaged over 7 days, and a long-term 

SO2 limit of 25 ppmv, averaged over 365 

days. (Because catalyst additives are not 

a feasible option for reducing SO2 from 

a fluid coking unit, we did not consider 

the fifth option evaluated for fluid 

catalytic cracking units.) 

The Energy Information 

Administration (EIA) Refinery Capacity 

Report 2006 lists six fluid coking units; 

at least two of these coking units are 

flexi-coking units that use the coking 

exhaust as a synthetic fuel gas. 

Therefore, there are at most four fluid 

coking units in the United States that 

could potentially become subject to the 

standard. Although coking capacity is 

expected to increase, most new units are 

expected to be delayed coking units. For 

this analysis, we assumed that one 

existing fluid coking unit becomes a 

modified or reconstructed source in the 

next 5 years. A wet scrubber is the most 

likely technology that would be used to 

meet either Option 1 or Option 2. To 

estimate the impacts, we estimated costs 

for a basic wet scrubber to meet Option 

1 and an enhanced wet scrubber to meet 

Option 2. The resulting emission 

reductions and costs for both of the 

options are shown in Table 5 to this 

preamble. The costs for both options are 

reasonable. Therefore, we determined 

that BDT is Option 2 which requires 

technology that reduces PM emissions 

to 0.5 kg/Mg of coke burn and reduces 

SO2 emissions to 50 ppmv, averaged 

over 7 days, and 25 ppmv, averaged 

over 365 days. We are proposing 

standards consistent with these levels. 


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TABLE 5.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR PM AND SO2 LIMITS CONSIDERED FOR FLUID COKING UNITS

SUBJECT TO 40 CFR PART 60, SUBPART JA

Option Capital cost 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Emission 

reduction 

(tons 

PM/yr) 

Emission 

reduction 

(tons 

SO2/yr) 

Cost-effectiveness 

($/ton) 

Overall Incremental 

1 ....................................................................................... 14,000 4,700 1,700 21,000 210 ....................

2 ....................................................................................... 14,000 4,800 2,000 21,000 210 120 

Nitrogen Oxides (NOX). To determine 

BDT for NOX emissions, we evaluated 

three options: Outlet NOX emission 

levels of 80 ppmv, 40 ppmv, and 20 

ppmv, each averaged over 7 days or less. 

The specific technology that will be 

needed to meet these levels will depend 

on the NOX concentration in the exhaust 

gas stream from uncontrolled fluid 

coking units. As noted in the discussion 

above for PM and SO2 options, we 

estimated that only one fluid coking 

unit will be modified or reconstructed 

in the next 5 years, and there will be no 

new units constructed. Because each 

unit is likely to have a different 

uncontrolled NOX concentration in its 

exhaust stream, we developed impacts 

for a composite model unit based on a 

weighted distribution of all the various 

types of controls (low-efficiency 

combustion controls, higher efficiency 

combustion controls, and add-on 

controls such as LoToxTM or SCR). As in 

the analysis for fluid catalytic cracking 

units, the ratio of add-on controls to 

combustions controls increases from 

Option 1 through Option 3. The results 

of this analysis are shown in Table 6 to 

this preamble. 

TABLE 6.—NATIONAL FIFTH YEAR IMPACTS OPTIONS FOR NOX LIMITS CONSIDERED FOR FLUID COKING UNITS SUBJECT

TO 40 CFR PART 60, SUBPART JA

Option 

Total capital 

cost, $ 

(millions) 

Total annual 

cost, $/yr 

(millions) 

Emission 

reduction, 

(tons 

NOX/yr) 

Cost-effectiveness 

($/ton) 

Overall Incremental 

1 ........................................................................................................... 4 .5 0 .97 760 1,300 

2 ........................................................................................................... 9 .5 2 .1 980 2,200 5,300 

3 ........................................................................................................... 13 2 .9 1,000 2,800 12,000 

The costs for option 1 are 

commensurate with the emission 

reductions, but the incremental impacts 

for options 2 and 3 are not reasonable, 

as shown in Table 6. Based on these 

potential impacts and available 

performance data, we have determined 

that BDT is technology needed to meet 

an outlet NOX concentration of 80 ppmv 

or less, and we are proposing this 

emission limit as the performance 

standard for NOX emissions from fluid 

coking units. However, there are 

uncertainties in this analysis. For 

example, if the few existing units are 

not readily amenable to retrofitting NOX

controls, the cost and emission 

reduction impacts might no longer be 

favorable, and we would conclude that 

no control is BDT. Therefore, we are coproposing no new standard for NOX

emissions from fluid coking units. 

3. Sulfur Recovery Plants 

Emission limits in the existing NSPS 

(40 CFR part 60, subpart J) apply to 

Claus SRP with a capacity greater than 

20 LTD. The emission limits are 

consistent with an overall sulfur 

recovery efficiency of 99.9 percent (i.e., 

250 ppmv SO2 for the Claus unit 

followed by oxidative tail gas treatment, 

and 10 ppmv H2S and 300 ppmv total 

reduced sulfur compounds for a Claus 

unit followed by reductive tail gas 

treatment). Although small SRP and 

non-Claus SRP are not subject to the 

existing NSPS, they are often subject to 

control. For example, Texas requires 

sulfur removal efficiencies of 99.8 

percent for SRP with capacities greater 

than 10 LTD and 96 percent to 98.5 

percent for SRP with capacities less 

than or equal to 10 LTD. In addition, a 

few consent decrees require 95 percent 

sulfur recovery for Claus SRP with 

capacities less than 20 LTD. 

To determine BDT we evaluated 4 

options. The options are based on 

various sulfur recovery efficiencies for 

SRP with capacities less than 20 LTD, 

and all of the options include the same 

99.9 percent efficiency as in the current 

standards for SRP with capacities 

greater than 20 LTD. Option 1 is based 

on 99 percent recovery for SRP with 

capacities between 10 LTD and 20 LTD, 

and 95 percent recovery for SRP with 

capacities less than 10 LTD. Option 2 is 

based on 99 percent recovery for all SRP 

with capacities less than 20 LTD. 

Option 3 is based on 99.9 percent 

recovery for SRP with capacities 

between 10 LTD and 20 LTD, and 99 

percent recovery for SRP with capacities 

less than 10 LTD. Option 4 is based on 

99.9 percent recovery for all SRP, 

regardless of size or design. All of the 

options include 99.9 percent recovery 

for SRP larger than 20 LTD (both Claus 

and non-Claus units) because we are not 

aware of a more effective SO2 control 

technology. The 95 percent option is 

equivalent to the efficiency of a twostage Claus unit without controls. The 

99 percent and 99.9 percent recovery 

levels are achievable for SRP of all sizes 

by various types of tail gas treatments, 

as discussed in section V.D of this 

preamble. 

The estimated fifth year emission 

reductions and costs for each of the 

options are summarized in Table 7. 

These values reflect the impacts only for 

SRP smaller than 20 LTD because we 

expect that all non-Claus units will be 

smaller than 20 LTD and because the 

impacts for larger Claus units would be 

the same as to comply with the existing 

standards in subpart J. The costs for 

Options 1, 2, and 3 are reasonable. We 

then evaluated the incremental costs 

and emission reductions between the 

options. We found that Option 2 is the 

most stringent option for which 

incremental costs are reasonable 

compared to the incremental emission 

reduction between the options. 

Based on the available performance 

data and cost considerations, we have 

concluded that tail gas treatments that 

achieve 99.9 percent control are still 


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BDT for SRP with capacities greater 

than 20 LTD, and tail gas treatments that 

achieve 99 percent recovery are BDT for 

SRP with capacities less than 20 LTD. 

Therefore, we are proposing standards 

for SO2 and H2S emissions from SRP 

with capacities larger than 20 LTD that 

are equivalent to the existing standards, 

and we are proposing standards for SRP 

with capacities smaller than 20 LTD that 

would limit emissions of sulfur to less 

than 1 percent by weight of the sulfur 

recovered. 

TABLE 7.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR SO2 LIMITS CONSIDERED FOR SULFUR RECOVERY PLANTS

SUBJECT TO 40 CFR PART 60, SUBPART JA

Option 

Total capital 

cost, $ 

(millions) 

Total annual 

cost, $/yr 

(millions) 

Emission 

reduction, 

(tons 

SO2/yr) 

Cost-effectiveness 

($/ton) 

Overall Incremental 

1 ........................................................................................................... 0 .27 0 .14 180 780 

2 ........................................................................................................... 1 .1 0 .68 550 1,200 1,500 

3 ........................................................................................................... 1 .9 1 .0 590 1,700 8,200 

4 ........................................................................................................... 4 .5 2 .3 670 3,400 15,000 

4. Process Heaters and Other Fuel Gas 

Combustion Devices Sulfur Dioxide 

The current NSPS in 40 CFR part 60, 

subpart J limits SO2 emissions from fuel 

gas combustion devices by specifying 

that the H2S content of fuel gas must be 

less than or equal to 230 mg/dscm, 

averaged over 3 hours (equivalent to 160 

ppmv averaged over 3 hours). 

Alternatively, any fuel gas may be 

combusted, provided the outlet SO2

emissions are controlled to no more 

than 20 ppmv (dry basis, 0 percent 

excess air). When the current NSPS was 

promulgated, we concluded that amine 

scrubbing as well as new processes that 

use other scrubbing media represented 

BDT for continuous reduction of H2S 

from fuel gas. The 160 ppmv 

concentration limit was consistent with 

good operation of such scrubbing 

processes. In addition, burning such 

fuel gas will result in an SO2

concentration in the exhaust gas of 

about 20 ppmv. 

After consideration of current 

operating practices, we concluded that 

amine scrubbing units are still the 

predominant technology for reduction 

of H2S in fuel gas (and SO2 emissions 

from subsequent fuel gas combustion). 

Considering the variability of the fuel 

gas streams from various refinery 

processing units, 160 ppmv also is still 

a realistic short term H2S concentration 

limit. However, one California Air 

Quality Management District rule sets a 

40 ppmv H2S limit in fuel gas (averaged 

over 4 hours), and several refiners have 

reported that the typical fuel gas H2S 

concentrations (after scrubbing) are in 

the same range. Additionally, amine 

scrubbing technology can be designed 

and is, in fact, being used to achieve 

much lower (1 to 5 ppmv) H2S 

concentrations in product gas 

applications. Based on this information, 

we concluded that additional SO2

control could be achieved by requiring 

SO2 emission limits with both long-term 

and short-term averaging periods. 

We considered three options for 

increasing SO2 control of fuel gas 

combustion units: Outlet SO2 emission 

levels of 10 ppmv, 8 ppmv, and 5 ppmv 

SO2, each averaged over 365 days. Each 

of the options also includes the same 20 

ppmv 3-hour SO2 concentration limit as 

in the current NSPS. To achieve each of 

these options, we expect that petroleum 

refiners will increase their amine 

recirculation rates to reduce the H2S 

concentration in the fuel gas. We 

estimate that meeting the options will 

increase steam consumption for a 

typical scrubbing unit by about 5, 7, and 

10 percent, respectively. No new 

equipment or other capital expenditures 

would be necessary. The estimated fifthyear impacts of each of these options are 

presented in Table 8 to this preamble. 

Overall costs for all the options are 

reasonable compared to the emission 

reduction achieved. We further 

evaluated the incremental costs and 

reductions between the 3 options and 

found that they were reasonable for 

Options 1 and 2, while the incremental 

cost for Option 3 is not. 

TABLE 8.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR SO2 LIMITS CONSIDERED FOR PROCESS HEATERS AND

OTHER FUEL GAS COMBUSTION DEVICES SUBJECT TO 40 CFR PART 60, SUBPART JA

Option Capital cost 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Emission 

reduction 

(tons 

SO2/yr) 

Cost-effectiveness 

($/ton) 

Overall Incremental 

1 ........................................................................................................... 0 2,000 1,000 1,900

2 ........................................................................................................... 0 2,900 1,300 2,200 3,500 

3 ........................................................................................................... 0 4,100 1,600 2,600 4,700 

Based on these impacts and 

consideration of current operating 

practices, we concluded that BDT is use 

of technology that reduces the SO2

emissions from fuel gas combustion 

units to 8 ppmv or less averaged over 

365 days and 20 ppmv or less averaged 

over 3 hours. Therefore, we are 

proposing SO2 standards consistent 

with this determination. We are also 

requesting comment on the proposed 

long-term concentration limit and the 

length of the averaging period. 

Although the proposed emission 

limits are based primarily on the fuel 

gas desulfurization technologies (e.g., 

amine scrubbing), new process heaters, 

regardless of fuel type, also would be 

subject to these emission limits. New 

process heaters can elect to meet these 

emission limits by using treated fuel 

gas, low sulfur distillate fuel oils, or flue 

gas desulfurization or other SO2 add-on 

controls. Considering the low sulfur fuel 

standards and available control 

technologies, we believe the 20 ppmv 3- 

hour average SO2 emission limit and an 


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8 ppmv 365-day average emission limit 

represent the performance of BDT 

regardless of whether the new process 

heaters use gaseous or liquid fuels. 

The current NSPS allows refineries to 

demonstrate compliance with fuel gas 

concentration limits for H2S as a 

surrogate for SO2 emission limits. This 

approach is reasonable when H2S is the 

only sulfur-containing compound in the 

fuel gas because the H2S concentration 

in the fuel gas that is equivalent to the 

SO2 concentration in the exhaust from 

the fuel gas combustion unit can be 

easily estimated. However, based on 

available data, we understand that a 

significant portion of the sulfur in fuel 

gas from coking units is in the form of 

methyl mercaptan and other reduced 

sulfur compounds. These compounds 

will also be converted to SO2 in the fuel 

gas combustion unit, which means the 

SO2 emissions will be higher than the 

amount predicted when H2S is the only 

sulfur-containing compound in the fuel 

gas. Therefore, for process heaters and 

other fuel gas combustion devices that 

burn only fuel gas, we are proposing 

two alternatives to the SO2 emission 

limit. The first option would require 

measurement of H2S if none of the fuel 

gas is from a coking unit. The H2S 

concentration limits that would be 

equivalent to the SO2 emission limits 

are 160 ppmv, averaged over 3 hours, 

and 60 ppmv averaged over 365-days. 

The second option would require 

measurement of TRS instead of H2S 

when any of the fuel gas burned in the 

process heater or other fuel gas 

combustion unit is from a coking unit. 

The TRS concentration limits would be 

the same as the H2S concentration 

limits. We are requesting comment on 

the proposed requirement to measure 

the TRS concentration. We are 

interested in any technological 

limitations of this option and whether 

there are other fuel gas streams that 

contain reduced sulfur compounds that 

should not be subject to the same 

requirement. 

In addition to the proposed SO2

emission limits and H2S and TRS 

concentration limits, we are also 

proposing to include the same 

exemptions from fuel gas continuous 

monitoring requirements that we are 

proposing for subpart J. See section IV.A 

of this preamble for a discussion of our 

rationale for these proposed 

exemptions. 

NOX. NOX emissions from process 

heaters are not subject to control under 

the existing NSPS in 40 CFR part 60, 

subpart J. However, several petroleum 

refiners are subject to NOX control 

requirements for process heaters in their 

consent decrees and State regulations. 

The emission limits to which refineries 

are subject vary from facility to facility. 

We evaluated four options as part of the 

BDT determination. Each option 

consists of a potential NOX emission 

limit and applicability based on process 

heater size. Option 1 would limit NOX

emissions to 80 ppmv or less for all 

process heaters with a capacity greater 

than 20 million British thermal units 

per hour (MMBtu/hr). Option 2 would 

limit NOX emissions to 40 ppmv or less 

for all process heaters with a capacity 

greater than 20 MMBtu/hr. Option 3 

would limit NOX emissions to 30 ppmv 

or less for all process heaters with a 

capacity greater than 40 MMBtu/hr. 

Option 4 would limit NOX emissions to 

40 ppmv or less for process heaters with 

a capacity greater than 20 MMBtu/hr or 

less than or equal to 100 MMBtu/hr, and 

to 20 ppmv or less for process heaters 

with a capacity greater than 100 

MMBtu/hr. In each option, the NOX

concentration is based on a 24-hour 

rolling average. 

The estimated fifth year emission 

reductions and costs for each option are 

summarized in Table 9. We believe that 

nearly all process heaters at refineries 

that will become subject to subpart Ja 

can meet Option 1 using combustion 

controls (low NOX burners or ultra low 

NOX burners). Stepping from Option 1 

through Option 4 increases the fraction 

of process heaters that would need to 

use more efficient control technologies, 

such as LoTOxTM or SCR, to meet the 

NOX concentration limit. The options 

include a minimum 20 MMBtu/hr size 

threshold because none of the control 

technologies are cost effective for units 

with smaller capacities. 

TABLE 9.—NATIONAL FIFTH YEAR IMPACTS OPTIONS FOR NOX LIMITS CONSIDERED FOR PROCESS HEATERS SUBJECT TO

40 CFR PART 60, SUBPART JA

Option 

Total capital 

cost, $ 

(millions) 

Total annual 

cost, $/yr 

(millions) 

Emission 

reduction, 

(tons 

NOX/yr) 

Cost effectiveness 

($/ton) 

Overall Incremental 

1 ............................................................................................................... 140 28 17,000 1,600 ....................

2 ............................................................................................................... 200 38 20,000 1,900 3,100 

3 ............................................................................................................... 280 52 21,000 2,600 85,000 

4 ............................................................................................................... 470 88 22,000 4,000 27,000 

Based on the impacts in Table 9, the 

overall costs of option 1 and option 2 

are reasonable compared to the emission 

reductions. The incremental cost, 

however, between options 1 and 2 is not 

commensurate with the additional 

emission reduction achieved. Therefore, 

BDT for process heaters greater than 20 

MMBtu/hr was determined to be 

technology that achieves an outlet NOX

concentration of 80 ppmv or less, and 

we are proposing standards for NOX

emissions from process heaters 

consistent with this determination. 

5. Work Practice Standards for Fuel Gas 

Production Units 

We reviewed applicable state and 

local regulations and consent decree 

requirements and met with individual 

refinery representatives regarding their 

pollution prevention practices. The 

pollution prevention practices 

identified included flare minimization 

plans, fuel gas recovery requirements, 

start-up and shutdown requirements, 

and sulfur shedding plans (including 

redundant sulfur recovery capacity). 

Based on our review, all of these 

approaches could be expected to reduce 

emissions of VOC and SO2 to the 

atmosphere. As described in the 

following subsections, we reviewed 

these pollution prevention practices and 

are proposing three different work 

practice standards. Work practice 

standards are being proposed because it 

is not feasible to prescribe or enforce a 

standard of performance for these 

emission sources. As provided in 

section 111(h) of the Clean Air Act, we 

may promulgate design, equipment, 

work practice, or operational standards 

when it is not feasible to prescribe or 

enforce a standard of performance. It is 

not feasible to prescribe or enforce a 

standard of performance for these 


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sources because either the pollution 

prevention measures eliminates the 

emission source, so that there are no 

emissions to capture and convey, or the 

emissions are so transient, and in some 

cases, occur so randomly, that the 

application of a measurement 

methodology to these sources is not 

technically and economically practical. 

Elimination of Routine Flaring. Flares 

are first and foremost a safety device 

used to reduce emissions from 

emergency pressure relief of gases from 

refinery process units. We in no way 

want to limit the use of flares for 

emergency releases. However, many 

refineries also routinely use flares as an 

emission control device under normal 

operating conditions. 

Fuel gases produced within the 

refinery can be roughly divided into two 

categories based on the fuel gas stream 

pressure. Fuel gases produced in 

processes operated at higher pressures 

are easily routed to the fuel gas system; 

however, fuel gases that are produced 

from units operated near atmospheric 

pressures are not as easily routed to the 

fuel gas system. These ‘‘low pressure’’

fuel gases are often routed to flares 

because the flare gas system operates at 

a much lower pressure than the fuel gas 

system. Flare gas recovery systems are 

designed to compress the low pressure 

fuel gases, creating a high pressure fuel 

gas stream that can readily be added to 

the fuel gas system. 

In 1998, the South Coast Air Quality 

Management District developed a rule 

requiring refineries to measure the flow 

rate and hydrocarbon content of the 

gases sent to a flare. This South Coast 

rule, although it did not set prescriptive 

emission limits, led to reduced flaring 

as refinery operators, armed with the 

monitoring results, identified costeffective flare gas minimization or 

recovery projects. In 2005, South Coast 

amended this rule and established a no 

routine flaring goal based on the cost 

and anticipated emission reductions of 

flare gas recovery systems. The Bay Area 

Air Quality Management District also 

adopted a rule requiring flare 

monitoring in 2003 and adopted a rule 

to minimize flaring in 2006. 

We considered adopting the South 

Coast and Bay Area rules for this NSPS 

for new flare systems. However, many 

refinery flares operate for 50 years, so 

very few flares or flare systems are 

expected to become subject to NSPS 

requirements, even after several 

decades. Instead, we are proposing to 

add ‘‘fuel gas producing units’’ as a new 

affected source under subpart Ja and 

focus the requirement on eliminating 

routine flaring of fuel gas at the process 

units producing the fuel gas. A refinery 

owner or operator installing a new 

process unit that produces low pressure 

fuel gas has options for eliminating 

routine flaring, including, but not 

limited to, diverting the fuel gas to a 

nearby low-pressure heater or boiler, 

pressurizing the fuel gas so that it can 

be diverted to the fuel gas system, or 

installing a flare gas recovery system. 

The proposed work practice standard is 

designed to allow flexibility in 

compliance approaches without 

imposing undue restrictions on the use 

of flares during malfunctions or other 

conditions wherein flaring is the best 

environmental management practice 

considering the safety of the plant 

personnel and surrounding people. 

Additionally, several new fuel gas 

producing units are expected to be 

installed every year, so by regulating the 

fuel gas producing units we not only 

provide flexibility, but we also increase 

the rate at which the no routine flaring 

requirement is implemented within the 

industry. 

The impacts for this work practice are 

highly dependent on the amount of fuel 

gas generated by different fuel gas 

combustion units. Recovered fuel gas 

reduces the amount of natural gas a 

refinery must purchase to operate their 

process heaters. For example, fuel gases 

generated by fluid catalytic cracking 

units and coking units are routinely 

recovered into the fuel gas system due 

to the quantity of fuel gas generated in 

the process. For these systems, the 

savings associated with the recovered 

fuel gas provides a return on the capital 

investment associated with the 

compressor and ancillary equipment 

needed to recover the fuel gas. For other 

fuel gas producing units, such as 

reforming units, it is possible to route 

the fuel gas directly to the unit’s process 

heater without additional gas 

compression. For a few refineries, a flare 

gas recovery system may be used. 

We estimated planning and design 

costs for assessing methods to recover or 

otherwise avoid the release of fuel gas 

from new fuel gas producing units. As 

described previously, for many fuel gas 

producing units, the cost savings 

associated with the recovered fuel 

recovers the costs of the recovery 

equipment within the life-span on the 

equipment so that the annualized cost of 

controls is zero or slightly negative 

(indicating a cost savings). As a worstcase scenario, we used the impacts 

developed by the Bay Area for a systemwide flare gas recovery system. The total 

annualized cost of the system was 

estimated to be approximately $2 

million; no credit was provided for the 

heating value of the flare gas recovered. 

VOC emission reductions were 

estimated to be approximately 1,000 

tons per year and SO2 emissions were 

estimated to be 3,500 tons per year. The 

cost-effectiveness on the flare gas 

recovery system was estimated to be 

approximately $2,000/ton of VOC 

removed and approximately $570/ton of 

SO2 removed, assuming total costs are 

assigned to each pollutant. Therefore, 

even when fuel credits are not 

considered, flare gas recovery is costeffective as an emissions control device. 

When properly sized, these flare gas 

recovery systems can eliminate all 

routine flaring. Therefore, eliminating 

routine flaring by use of fuel gas 

recovery, in-process fuel use, or system 

wide flare gas recovery is determined to 

be BDT. 

We request comment on alternative 

means of eliminating routine flaring. As 

noted previously, a simple requirement 

to monitor gas flow and composition of 

gases sent to the flares resulted in 

reduced use of flares. An exemption 

from this monitoring requirement for 

flare systems that install flare gas 

recovery could provide refineries an 

incentive to install flare gas recovery 

systems. We request comment on this 

alternative and on the need to monitor 

flares that have flare gas recovery 

systems to ensure that the flare gas 

recovery system is properly sized and 

that no routine flaring is occurring. 

Additionally, we understand that 

there are a limited number of refineries 

that produce more fuel gas than they 

can use in the refinery process heaters 

or steam boilers. These ‘‘fuel gas rich’’

refineries contend that flaring is BDT for 

these refineries. Although we believe 

that other options exist, such as 

building an electric co-generating unit, 

the cost-effectiveness of such an 

endeavor is very site-specific. We 

cannot conclude at this time that cogeneration or other projects that use fuel 

gas are BDT. Therefore, we are coproposing no requirement for fuel gas 

producing units. We request comment 

on the actual number and location of 

‘‘fuel gas rich’’ refineries. We also 

request comment and data regarding the 

technical and economical feasibility of 

alternatives for ‘‘fuel gas rich’’ refineries 

to avoid routine flaring. 

Emission Prevention During Start-up, 

Shutdown, and Malfunctions. The 

current NSPS includes no requirements 

for a start-up, shutdown, and 

malfunction plan. We identified three 

emission prevention methods that can 

be addressed within the context of a 

start-up, shutdown, and malfunction 

plan. These are: Flare minimization 

during planned start-ups and 

shutdowns; flare minimization during 

malfunctions of the sour gas amine 


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treatment units and sulfur recovery 

plants; and performing root-cause 

analyses of malfunctions that release in 

excess of 500 lb per day of SO2. Our 

rationale for including each of these 

three emission prevention methods are 

described in the following paragraphs. 

Flaring and direct venting of certain 

gas streams have been routinely used 

during planned start-up and shutdown 

of process units to quickly bring a 

process unit online or offline. These 

flaring and venting episodes have 

traditionally been exempt from any 

emission limitations. Nonetheless, some 

refineries have chosen to evaluate their 

start-up and shutdown emissions and 

alter their procedures so as to reduce or 

eliminate direct venting or flaring 

during planned start-up and shutdown 

events. 

Typically, alternative start-up and 

shutdown procedures that reduce 

atmospheric emissions or flaring require 

more time to complete than 

conventional procedures. Therefore, 

there is a cost associated with the 

alternative procedures in terms of 

potential product/productivity loss. For 

refineries that have system-wide flare 

gas recovery systems, it may be a simple 

matter of scheduling the start-up or 

shutdown during a time when limited 

other flare gas is being generated so as 

to not overwhelm the flare gas recovery 

system. The cost-effectiveness of the 

alternative procedures would depend on 

the amount of gas flared or vented using 

the traditional procedures, the amount 

of these emissions that can be avoided 

using alternative procedures, the 

amount of product lost due to the 

increased start-up/shutdown time 

period, and the value of that product. As 

such, it is difficult to conclude that 

significant or complete emission 

reductions during planned start-up or 

shutdown events will be cost-effective 

under all conditions; therefore, we 

chose not to set a specific venting or 

flaring limit (or prohibition). 

We estimate that the engineering 

review revision of a unit’s start-up and 

shutdown plan would require 

approximately 20 engineering hours per 

process unit, at total cost of $1,300 to 

$1,500 per process unit (one-time costs). 

Assuming the unit requires maintenance 

shut-down only once every 5 years and 

the revised procedures only reduce VOC 

and SO2 emissions by 1 ton each per 

event, the cost-effectiveness of the 

engineering review is $1,300 to $1,500 

per ton of VOC and the same for SO2. 

Based on this simplistic analysis, we 

are proposing that implementing a startup and shutdown plan focused on 

reducing emissions during planned 

start-up and shutdown events would be 

BDT. 

We evaluated several different 

requirements to promote continuous 

compliance with the SO2 emission 

limits associated with fuel gas 

combustion devices and sulfur recovery 

plants even during times of process 

upsets or malfunctions associated with 

the amine system or sulfur recovery 

plant. ‘‘Process upset gas’’ is ‘‘gas 

generated by a petroleum refinery 

process unit as a result of upset or 

malfunction.’’ Process upset gas is 

exempt from the SO2 emission limits. 

However, when there is a malfunction 

of the amine treatment system or the 

sulfur recovery plant, there has been 

some uncertainty as to whether 

combustion or flaring of the sour gas is 

considered to be exempt from the SO2

emission limit. This is because the 

amine treatment system or sulfur 

recovery plant is not ‘‘generating’’ the 

gas stream, it is merely treating it. As 

such, the amine treatment system and 

sulfur recovery plant are essentially 

control devices, and refinery owners 

and operators are required to minimize 

emissions during these control system 

malfunctions, up to and including the 

shutdown of the emissions generating 

units. 

A variety of prescriptive requirements 

were reviewed, such as requiring 24- 

hour storage capacity of lean amine 

solution and empty tank storage 

capacity to receive 24 hours worth of 

rich amine solution, requiring inventory 

of critical spare parts, and requiring 

redundant amine scrubbing and sulfur 

recovery capacity. While these are all 

viable options that a plant can employ 

to minimize malfunction emissions 

associated with the amine treatment 

system or sulfur recovery plant, the 

most cost-effective means to minimize 

these emissions are highly site-specific, 

being dependent on the number and 

location of the amine units or sulfur 

recovery trains within the sulfur 

recovery plant. 

We evaluated two alternatives, which 

are not mutually exclusive, for 

minimizing flaring of H2S-rich fuel gas 

in the event of a malfunction in the 

amine stripper or sulfur recovery plant. 

Option 1 is to store 24 hours worth of 

lean amine solution in case of a 

malfunction in the amine stripper. We 

estimate that this alternative would 

require a capital cost of approximately 

$10 million (for 2 storage tanks and 

excess amine) for a 50 long LTD SRU 

system, resulting in an annualized cost 

of $1 million/year. If the 24 hours of 

excess amine was used one time per 

year for an entire day, 50 LTD of sulfur 

would have resulted in 110 tons of SO2

emissions avoided. If there are three 

occurrences per year where the excess 

amine solution is used, 330 tons of 

emissions would be reduced. This 

scenario results in a cost-effectiveness 

ranging from $3,000 to 9,000 per ton of 

SO2 reduced. 

Option 2 is to have a redundant Claus 

unit. The capital cost of a 50 LTD Claus 

unit is also approximately $10 million, 

resulting in an annualized cost of $1 

million/year. Again, if there are one to 

three days of emissions avoided, this 

option results in a cost-effectiveness 

ranging from $3,000 to $9,000 per ton of 

SO2 reduced. For sulfur recovery plants 

consisting of multiple Claus units, the 

likelihood of needing the additional 

Claus train more than three times per 

year increases significantly, making the 

redundant Claus unit a cost-effective 

option. 

It is difficult to predict the quantity of 

emissions avoided as they are 

dependent on random malfunction 

events of variable durations. While the 

cost-effectiveness values of these 

options are not necessarily compelling 

given the uncertainty in the emissions 

avoided, the options evaluated are 

expected to be extreme measures. It is 

likely, for example, that maintaining 

appropriate spare parts for the system 

would provide a cost-effective means of 

reducing emissions. This, along with 

short-term reductions in high-sulfur fuel 

gas production could be used to 

eliminate the need to flare or otherwise 

combust these high sulfur-containing 

fuel gases. 

Based on this analysis, we are 

proposing that a start-up, shutdown, 

and malfunction plan that specifically 

addresses the minimization of fuel gas 

combustion of high sulfur-containing 

fuel gases during malfunctions of an 

amine treatment system or sulfur 

recovery plant is BDT. The start-up, 

shutdown, and malfunction plan will 

address specific process upset and 

malfunction events associated with the 

amine treatment system and sulfur 

recovery plant and the standard 

operating procedures to follow to 

minimize emissions during these 

events. Compliance is demonstrated by 

following the procedures in the plan. As 

previously mentioned, we are proposing 

a work practice standard rather than an 

equipment standard to provide 

flexibility to the refinery owner or 

operator regarding the best way to 

minimize malfunction emissions given 

the refinery’s specific configuration and 

sulfur loads. 

Finally, we evaluated a requirement 

for performing root-cause analyses as a 

means to minimize the frequency of 

process malfunctions and thereby 


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reduce malfunction emissions. Even 

though process upset gas is exempt from 

the SO2 emission limits associated with 

fuel gas combustion units, we believe it 

is good air pollution practice to 

investigate the causes of significant 

atmospheric releases caused by process 

upsets or malfunctions to determine if 

similar upsets or malfunctions can be 

reasonably prevented from recurring. 

Similarly, we believe it is good 

pollution control practice to investigate 

significant emission exceedances to 

determine the cause of the exceedance 

and to implement procedures to prevent 

its recurrence. The cost-effectiveness of 

these investigations is dependent on the 

frequency and magnitude of the 

emission episodes; for very small 

emission episodes, the manpower 

required to perform the investigations 

do not justify the potential emission 

reductions that might be realized from 

the root-cause analysis. We estimate that 

a root-cause analysis would cost 

approximately $2,500 to perform. For 

emissions of less than 500 pounds per 

day, the cost-effectiveness of the rootcause analysis, even assuming it would 

completely eliminate a future 

recurrence, would be approximately 

$10,000 per ton of SO2 reduced. 

Similarly, for emissions of 1,000 pounds 

per day, the cost-effectiveness would be 

on the order of $5,000 per ton of SO2

reduced. As the probability of 

successfully identifying a means to 

avoid future emissions from each rootcause analysis performed is certainly 

less than 100 percent, we determined 

that it was not cost effective to perform 

root-cause analyses for SO2 emissions 

exceedances of 500 pounds per day or 

less and request comment on alternative 

thresholds in the range of 500 to 1,000 

lbs per day. 

For SO2 releases of greater than 500 

pounds per day, the emissions 

reductions potential of the root-cause 

analyses increases and the costeffectiveness improves, so we are 

proposing that performing root-cause 

analyses for SO2 releases of greater than 

500 pounds per day would be BDT. Any 

emission limit exceedance or any 

process start-up, shutdown, upset or 

malfunction that causes a discharge into 

the atmosphere in excess of 500 pounds 

per day of SO2 would require a root 

cause analysis to be performed. We also 

considered a similar requirement for 

hydrocarbon flaring events with the 

purpose of reducing VOC emissions. 

However, we expect refinery owners 

and operators to investigate large 

hydrocarbon releases as these releases 

represent lost revenues. Furthermore, as 

flares are efficient in destroying VOC, 

the potential to significantly reduce 

VOC emissions by performing rootcause analysis is much less than the 

potential for reducing SO2 emissions. 

We request comment on the need to 

include root cause analyses for 

hydrocarbon releases. If root-cause 

analyses are recommended, please 

provide in your comments the 

recommended release quantities that 

would trigger the root-cause analysis 

and justification for the 

recommendation. If root cause analyses 

are not recommended, please provide in 

your comments the rationale for not 

requiring root-cause analysis for any 

VOC (hydrocarbon) releases. 

The proposed rule is intended to 

provide flexibility for each refinery 

owner and operator to develop 

procedures that are efficient and 

effective for their process configuration. 

The scope of these requirements is 

limited to affected facilities under this 

rule. We request comment on the need 

to implement this requirement to all 

new process units at the refinery, not 

just fuel gas producing units such as 

fluid catalytic cracking units, fluid 

coking units, fuel gas combustion 

devices, and sulfur recovery plants. 

On the other hand, based on sitespecific conditions and given the nature 

of the types of emissions events that are 

being addressed by the start-up, 

shutdown, and malfunction plan, it is 

impossible to conclusively determine 

that one or all of the emission reduction 

methods addressed in the start-up, 

shutdown, and malfunction plan will 

achieve any set level of emissions 

reduction or that those reductions, if 

any, will be cost-effective. Therefore, we 

are co-proposing no requirement for a 

start-up, shutdown, and malfunction 

plan. We request comments and 

supporting data that indicate the 

emission reductions that could be 

reasonably expected from a flare 

minimization plan for planned start-up 

and shutdown events, the number of 

planned events that occur per year (or 

over a 5 year period), and any other 

information that can be used to justify 

either the inclusion or exclusion of this 

provision in the final rule. We also 

request comments and supporting data 

that indicate the number and duration 

of malfunctions in the amine stripper 

and sulfur recovery plants, the costs 

associated with alternative sulfur 

shedding practices, and other 

information that can be used to justify 

either the inclusion or exclusion of this 

provision in the final rule. 

Finally, we request comment, along 

with supporting data, that indicate the 

frequency of emission events exceeding 

500 pounds per day, the percentage of 

times the root-cause analysis results in 

positive steps that may avoid future 

recurrence of the event, and other 

information that can be used to justify 

either the inclusion or exclusion of this 

provision in the final rule. 

Delayed Coking Unit 

Depressurization. The primary emission 

releases from delayed coking units 

occur as the coking vessels are 

depressurized and petroleum coke is 

removed from the unit. When the 

delayed coking cycle is completed, the 

coke-filled vessel is steam stripped. 

Most of the gases from this process 

continue to be sent to the coking unit 

distillation column. At some point in 

time, the steam gas discharge is diverted 

to the blow-down system. The delayed 

coking unit typically has a fuel gas 

recovery system (compressor) due to the 

quantity of fuel gas produced by the 

unit. Therefore, it is cost-effective to 

require the blow-down system gases to 

be recovered in the unit’s fuel gas 

recovery system, in keeping with the 

proposed work practice standard that 

fuel gas from fuel gas producing units 

will not be routinely flared. 

As the process unit continues to 

depressurize, there is a point where the 

gases can no longer be discharged to the 

blow-down system or fuel gas recovery 

line, at which point the remaining steam 

and gases are vented to the atmosphere. 

To achieve maximum reduction of 

uncontrolled releases, the unit should 

be depressurized to as low a pressure as 

possible before venting to the 

atmosphere. Below a pressure of 5 

pounds per square inch gauge (psig) in 

the delayed coking unit drum, it is not 

technically feasible to divert the 

emissions for recovery. Above a vessel 

pressure of 5 psig, it is technically 

feasible to divert the emissions for 

recovery. Furthermore, as the unit 

already has a gas compressor, the costs 

associated with recovering these gases is 

minimal. 

We estimate that this practice can 

reduce VOC emissions by 120 tons per 

year and SO2 emissions by at 200 tons 

per year. The total annualized costs are 

expected to be minimal for new units, 

but installing the appropriate piping for 

a modified or reconstructed unit may 

result in annualized costs of up to 

$100,000 per year. Even under this 

extreme condition, the cost effectiveness 

of the requirement is about $800 per ton 

of VOC reduced and $500 per ton of SO2

reduced. Therefore, we conclude that a 

work practice standard that requires a 

delayed coking unit to depressure to 5 

psig during reactor vessel depressuring 

and vent the exhaust gases to the fuel 

gas system for recovery is BDT. Note 

this determination is independent of the 


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work practice to eliminate routine 

flaring from fuel gas producing units 

and requires flare gas recovery of 

depressurization gases even under the 

option of no work practice requirement 

to minimize flaring. 

In addition to the depressurization 

emissions, we also identified at least 

one refinery that has designed an 

enclosed system for their coke-cutting 

operations. Coke cutting operations 

were identified as a significant VOC 

emission source at refineries during an 

Alberta Research Council study, with an 

estimated VOC emissions rate of 1,300 

tons per year. We do not have any data 

regarding the effectiveness of the cokecutting enclosure system, whether the 

enclosure seals are air tight or if they 

allow some percentage of the emissions 

escape. The enclosure may simply 

suppress the emissions until the coke is 

removed from the unit, at which time 

the emissions are released. 

Additionally, we do not have any data 

on the costs of these systems and 

whether or not existing units can be 

retrofitted if the delayed coking unit is 

modified or reconstructed. Therefore, 

we cannot conclude that an enclosed 

coke cutting system is BDT, but we 

request comment and additional 

information on coke-cutting system 

controls, their cost, their effectiveness, 

and their limitations. 

VI. Modification and Reconstruction 

Provisions 

Existing affected sources that are 

modified or reconstructed would be 

subject to the proposed standards in 40 

CFR part 60, subpart Ja. A modification 

is any physical or operational change to 

an existing facility which results in an 

increase in the emission rate to the 

atmosphere of any pollutant to which a 

standard applies (see 40 CFR 60.14). 

Changes to an existing facility that do 

not result in an increase in the emission 

rate, as well as certain changes that have 

been exempted under the General 

Provisions (see 40 CFR 60.14(e)) are not 

considered modifications. 

Rebuilt petroleum refinery process 

units would become subject to the 

proposed standards in 40 CFR part 60, 

subpart Ja under the reconstruction 

provisions, regardless of changes in 

emission rate. Reconstruction means the 

replacement of components of an 

existing facility such that (1) the fixed 

capital cost of the new components 

exceeds 50 percent of the fixed capital 

cost that would be required to construct 

a comparable entirely new facility; and 

(2) it is technologically and 

economically feasible to meet the 

applicable standards (40 CFR 60.15). 

With the exception of the standards 

for fluid catalytic cracking units, we are 

proposing that modified or 

reconstructed sources be subject to the 

same proposed standards in 40 CFR part 

60, subpart Ja, as new sources. The 

decision to maintain consistent 

standards for both new and modified or 

reconstructed sources was based on an 

evaluation of the cost-effectiveness and 

incremental cost-effectiveness of the 

proposed standards on both types of 

sources and on the feasibility of 

retrofitting existing units. We have 

included in the docket a table (Impacts 

Summary) which summarizes our 

estimates costs for different control 

options for both new and reconstructed 

or modified process units. We request 

comment on these cost estimates and on 

specific issues related to the feasibility 

of retrofitting existing units, as well as 

our assessment that cost-effectiveness 

numbers are similar enough such that it 

is appropriate to have identical 

standards for both new and modified or 

reconstructed sources. 

VII. Request for Comments 

Table 10 summarizes the topics on 

which we have specifically requested 

comment throughout this preamble. We 

note, however, that comments on all 

aspects of this proposal are welcome. 

TABLE 10.—SUMMARY OF TOPICS ON WHICH COMMENT IS REQUESTED

Topic 

Section in this 

preamble where 

topic is discussed 

Effects of proposed PM, SO2 and NOX standard on modified or reconstructed fluid catalytic cracking units. Also co-proposed 40 CFR part 60, Subpart J standards for SO2 and PM and no NOX limits for modified and reconstructed sources.III.B. and V.E.1. 

Exemption for emergency flares .................................................................................................................................................. IV.A. 

Exemption from monitoring for fuel gas streams related to commercial liquid products ............................................................ IV.A. 

Exemption from monitoring for fuel gas streams generated by process units that are intolerant of sulfur ................................ IV.A. 

Alternative PM limit for fluid catalytic cracking units based on condensable PM as well as filterable PM ................................ V.E.1. 

Alternative lower (20 ppmv, 40 ppmv) NOX limit, averaged over 365 days, for fluid catalytic cracking units ............................ V.E.1. 

Co-propose no new NOX standard for fluid coking units ............................................................................................................ V.E.2. 

Appropriate long-term average H2S concentration limit for fuel gas combustion units, and requirement to monitor TRS instead of H2S for fuel gas from coker units.V.E.4. 

Various aspects of work practice standards to minimize routine flaring and enhance SO2 control versus no standards: alternative means of eliminating flaring, number of ‘‘fuel gas rich’’ refineries, need for a startup, shutdown, and malfunction 

plan (SSMP), including rationale for or against requiring a root cause analysis for hydrocarbon releases and sulfur shedding practices, and information about emission control systems for coke cutting operations. Also co-propose no requirements for routine flaring and no SSMP.

V.D.5. 

VIII. Summary of Cost, Environmental, 

Energy, and Economic Impacts 

In setting standards, the CAA requires 

us to consider alternative emission 

control approaches, taking into account 

the estimated costs as well as impacts 

on energy, solid waste, and other effects. 

We request comment on whether we 

have identified the appropriate 

alternatives and whether the proposed 

standards adequately take into 

consideration the incremental effects in 

terms of emission reductions, energy, 

and other effects of these alternatives. 

We will consider the available 

information in developing the final rule. 

A. What are the impacts for petroleum 

refining process units? 

We are presenting estimates of the 

impacts for the proposed requirements 

of subpart Ja that change the 

performance standards: the emission 

limits for fluid catalytic cracking units, 

sulfur recovery plants, fluid coking 

units, fuel gas combustion devices, and 

process heaters, as well as the work 

practice standards. The proposed 

amendments to 40 CFR part 60, subpart 

J are clarifications to the existing rule, 

and they have no emission reduction 

impacts. The cost, environmental, and 

economic impacts presented in this 

section are expressed as incremental 


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differences between the impacts of 

petroleum refining process units 

complying with the proposed subpart Ja 

and the current NSPS requirements of 

subpart J (i.e., baseline). The impacts are 

presented for petroleum refining process 

units that commence construction, 

reconstruction, or modification over the 

next 5 years. The analyses and the 

documents referenced below can be 

found in Docket ID No. EPA–HQ–OAR–

2007–0011. 

In order to determine the incremental 

costs and emission reductions of this 

proposed rule, we first estimated 

baseline impacts. For new sources, 

baseline costs and emission reductions 

were estimated for complying with 

subpart J; incremental impacts for 

subpart Ja were estimated as the costs to 

comply with subpart J subtracted from 

the costs to comply with proposed 

subpart Ja. Sources that are modified or 

reconstructed over the next 5 years 

would comply with subpart J in the 

absence of proposed subpart Ja. We 

assumed that prior to reconstruction or 

modification, these sources would 

either be subject to a consent decree 

(equivalent to about 77 percent of the 

industry by capacity), complying with 

subpart J or equivalent limits, or 

complying with 40 CFR part 63, subpart 

UUU (MACT II). Baseline costs and 

emission reductions were estimated as 

the effort needed to comply with 

subpart J from one of those three starting 

points. The costs and emission 

reductions to comply with proposed 

subpart Ja were estimated from those 

starting points as well. The estimated 

costs presented for work practice 

standards include only the labor cost to 

prepare the required plan or analysis; 

we did not attempt to quantify costs and 

emission reductions for the variety of 

ways a facility may choose to 

implement those plans. We assumed 

that each facility would evaluate their 

options and choose the most costeffective option for the facility’s unique 

position. For further detail on the 

methodology of these calculations, see 

Docket ID No. EPA–HQ–OAR–2007–

0011. 

When considering and selecting 

emission limits for the proposed rule, 

we evaluated the cost-effectiveness of 

each option for new sources separately 

from reconstructed and modified 

sources. However, since our selections 

for each process unit and pollutant were 

consistent for all units, we are 

presenting our costs and emission 

reductions for the overall rule. We 

estimate that the proposed amendments 

will reduce combined emissions of PM, 

SO2, and NOX about 55,800 tons/yr from 

the baseline. The estimated increase in 

annual cost, including annualized 

capital costs, is about $54,100,000. The 

overall cost-effectiveness is about $970 

per ton of pollutants removed. The 

estimated nationwide 5-year 

incremental emissions reductions and 

cost impacts for the proposed 

amendments are summarized in Table 

11 of this preamble. 

TABLE 11.—NATIONAL INCREMENTAL EMISSION REDUCTIONS AND COST IMPACTS FOR PETROLEUM REFINERY UNITS

SUBJECT TO PROPOSED STANDARDS UNDER 40 CFR PART 60, SUBPART JA (FIFTH YEAR AFTER PROPOSAL) 

Process unit Pollutant 

Total capital 

cost 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Annual 

emission 

reductions 

(tons/yr) 

Costeffectiveness 

($/ton) 

FCCU ................................................ PM and SO2 ..................................... 40,000 9,500 9,500 1,000 

FCCU ................................................ NOX .................................................. 28,000 7,300 3,500 2,100 

Fluid Coker ........................................ PM and SO2 ..................................... 14,000 4,800 23,000 210 

Fluid Coker ........................................ NOX .................................................. 4,500 970 760 1,300 

SRP ................................................... SO2 ................................................... 1,100 680 550 1,200 

Process Heaters and Fuel Gas 

Combustion.

SO2 ................................................... 0 2,880 1,300 2,200 

Process Heaters ............................... NOX .................................................. 140,000 28,000 17,000 1,600 

Work Practices .................................. ........................................................... ........................ 250 ........................

Total ........................................... ........................................................... 230,000 54,000 56,000 970 

B. What are the secondary impacts? 

Indirect or secondary air quality 

impacts of this proposed rule would 

result from the increased electricity 

usage associated with the operation of 

control devices. Assuming that plants 

would purchase electricity from a power 

plant, we estimate that the standards as 

proposed would increase secondary 

emissions of criteria pollutants, 

including PM, SO2, NOX, and CO from 

power plants. For new, modified or 

reconstructed sources, this proposed 

rule would increase secondary PM 

emissions by 24 Mg/yr (27 tpy); 

secondary SO2 emissions by about 970 

Mg/yr (1,100 tpy); secondary NOX

emissions by about 480 Mg/yr (530 tpy); 

and secondary CO emissions by about 

16 Mg/yr (17 tpy) for the 5 years 

following proposal. 

As explained earlier, we expect that 

affected facilities will control emissions 

from fluid catalytic cracking units by 

installing and operating ESP or wet gas 

scrubbers. We also expect that the 

emissions from the affected fluid coker 

will be controlled with a wet scrubber. 

For these process units, we estimated 

solid waste impacts for both types of 

control devices and water impacts for 

wet gas scrubbers. In addition, the 

controls needed by small sulfur 

recovery plants will generate 

condensate. We project that this 

proposed rule will generate 4.5 billion 

gallons of water per year for the 5 years 

following proposal. We also estimate 

that this proposed rule will generate 

8,600 Mg/yr (7,800 tpy) of solid waste 

over those 5 years. 

Energy impacts consist of the 

electricity and steam needed to operate 

control devices and other equipment 

that would be required under the 

proposed rule. Our estimate of the 

increased energy demand includes the 

electricity needed to produce the 

required amounts of steam as well as 

direct electricity demand. We project 

that this proposed rule would increase 

overall energy demand by about 170 

gigawatt-hours per year (590 billion 

British thermal units per year). 

C. What are the economic impacts? 

This proposal affects certain new and 

reconstructed/modified sources found at 

petroleum refineries as defined earlier 

in this preamble. We performed an 

economic impact analysis that estimates 

changes in prices and output for 

gasoline nationally using the annual 

compliance costs estimated for this 

proposal. The methodology for this 


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1We use the SO2 benefits/ton estimate derived 

from the Industrial Boilers MACT benefit analysis 

based on the factors listed above. We also note that 

the SO2 benefits/ton estimate derived from the 

CAIR benefits analysis is $18,000 in 2010 and 

$22,000 in 2015, both of which are quite close to 

the estimate we use in this analysis. We use the 

NOX benefits/ton estimate from the CAIR Boilers 

MACT benefits analysis (no NOX reductions take 

place as a result of the Industrial Boilers MACT). 

analysis incorporates changes in 

producer and consumer behavior by 

considering passthrough of increased 

production costs from producers to 

consumers. All estimates are for the fifth 

year after proposal since this is the year 

for which the compliance cost impacts 

are estimated. 

The analysis estimates a price 

increase in gasoline of less than 0.02 

percent nationally will take place along 

with a corresponding reduction in 

gasoline output of less than 0.004 

percent (or less than 6 million gallons 

a year). The overall total annual social 

costs, which reflect changes in 

consumer and producer behavior in 

response to the compliance costs, are 

$53.0 million (2005 dollars) or almost 

identical to the compliance costs. 

For more information, please refer to 

the economic impact analysis report 

that is in the public docket for this 

proposed rule. 

D. What are the benefits? 

We estimate the monetized benefits of 

this proposed rule to be $957 million 

(2005$) in the fifth year after proposal. 

We base the portion of the benefits 

estimate derived from the PM2.5 and SO2

emission reductions on the approach 

and methodology laid out in EPA’s 2004 

benefits analysis supporting the 

regulation of emissions from the 

Industrial Boilers MACT (included in 

the Regulatory Impact Analysis (RIA) for 

the Industrial Boilers and Process 

Heaters NESHAP, February 2004). We 

chose the benefit analysis contained in 

this RIA as the basis for estimating the 

benefits from emission reductions of 

these two pollutants since most of the 

elements in that rule are similar to those 

covered here. These elements, which are 

the stack height, a number of the 

controls applied, and the pollutants 

affected—PM2.5 and SO2, but not NOX—

are similar to those covered by the 

Industrial Boiler MACT standard. 

We base the portion of the benefits 

estimate derived from the NOX emission 

reductions on the approach and 

methodology laid out in EPA’s 2005 

benefits analysis supporting the 

regulation of emissions from the Clean 

Air Interstate Rule (CAIR) (included in 

the Regulatory Impact Analysis for the 

Clean Air Interstate Rule, March 2005). 

We chose the CAIR analysis as the basis 

for estimating the benefits from 

emission reductions of this pollutant 

since most of the elements in CAIR are 

similar to those covered here. These 

elements, which are the stack height, a 

number of the controls applied, and the 

pollutant affected—in this case, NOX

only—are similar to those covered by 

CAIR. These three factors lead us to 

believe that we might reasonably 

estimate benefits for this proposed rule 

using a benefits transfer approach and 

values from the Industrial Boilers 

MACT analysis for estimating the SO2

and PM2.5 benefits of this rule, and the 

CAIR analysis for the NOX benefits of 

the rule. Specifically, these estimates 

are based on application of the benefits 

scaling approach derived from the 

benefits analyses completed for these 

rulemakings. As mentioned above, the 

methodologies are laid out in the 

Industrial Boilers MACT and CAIR RIA. 

A summary of the benefits estimates is 

in Table 12 below.1

TABLE 12.—SUMMARY OF BENEFITS ESTIMATES FOR PROPOSED NSPS 

Pollutant 

Monetized 

benefits per 

ton emission 

reduction 

Emission 

reductions 

(tons) 

Total monetized benefits* 

(millions of 

2005 dollars) 

PM2.5 ............................................................................................................................................ $88,000 3,221 $283.4 

SO2 .............................................................................................................................................. 20,000 31,358 627.2 

NOX .............................................................................................................................................. 2,200 21,266 46.8 

Grand Total: .......................................................................................................................... ........................ ........................ $957.4 

* All estimates are for the analysis year (fifth year after proposal). Emission reductions reflect the combination of proposed options for both new 

and reconstructed/modified sources. 

The specific estimates of benefits per 

ton of pollutant reductions included in 

this analysis are largely driven by the 

concentration response function for 

premature mortality, which is based on 

the American Cancer Society cohort 

(ACS) (Pope, C.A. III, et al., ‘‘Lung 

Cancer, Cardiopulmonary Mortality, and 

Long-Term Exposure to Fine Particulate 

Air Pollution,’’ JAMA, 2002). Since the 

publication of CAIR, the EPA’s Office of 

Air and Radiation has adopted a 

different format for its benefits analysis 

in which characterization of the 

uncertainty in the concentration 

response function is integrated into the 

main benefits analysis. The PM NAAQS 

analysis provides an indication of the 

sensitivity of our results to the use of 

alternative concentration response 

functions, including those derived from 

the recently completed expert elicitation 

study. Specifically, compared to the 

final PM NAAQS estimate of the mean 

mortality from the ACS cohort, the 

expert-based premature mortality 

incidence ranged from 50 percent of the 

mean ACS estimate to more than five 

times the size of the ACS mean estimate. 

The Agency is currently updating the 

estimates used here to calculate the 

benefits of the proposed NSPS and 

intends to consider using these updated 

benefits estimates as part of an approach 

similar to that used in the PM NAAQS 

RIA in the benefits analyses for the final 

NSPS. 

With the annualized costs of this 

rulemaking estimated at $54 million 

(2005$) in the fifth year after proposal 

and with estimated benefits of $957 

million (2005$) for that same year, EPA 

believes that the benefits are likely to 

exceed the costs by a significant margin 

even when taking into account the 

uncertainties in the cost and benefit 

estimates. For more information, please 

refer to the RIA for this proposed rule 

that is available in the docket. 

IX. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under section 3(f)(1) of Executive 

Order 12866 (58 FR 51735, October 4, 

1993), this action is an ‘‘economically 

significant regulatory action’’ because it 

is likely to have an annual effect on the 


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economy of $100 million or more. 

Accordingly, EPA submitted this action 

to the Office of Management and Budget 

(OMB) for review under Executive 

Order 12866 and any changes made in 

response to OMB recommendations 

have been documented in the docket for 

this action. 

In addition, EPA prepared an analysis 

of the potential costs and benefits 

associated with this action. This 

analysis is contained in the Regulatory 

Impact Analysis (RIA) for the Proposed 

Petroleum Refinery NSPS, EPA–452/R–

07–006. A copy of the analysis is 

available in the docket for this action 

and the analysis is briefly summarized 

here. The monetized benefits of this 

action are estimated at $957 million 

(2005 dollars), and the annualized costs 

of this action are estimated at $54 

million (2005 dollars). We also 

estimated the economic impacts, small 

business impacts, and energy impacts 

associated with this action. These 

analyses are included in the RIA and are 

summarized elsewhere in this preamble. 

B. Paperwork Reduction Act 

The proposed amendments to the 

existing standards of performance for 

petroleum refineries would add a 

monitoring exemption for fuel gas 

streams combusted in a fuel gas 

combustion device that are inherently 

low in sulfur content. The exemption 

would apply to fuel gas streams that 

meet specified criteria or that the owner 

or operator demonstrates are low sulfur 

according to the rule requirements. The 

owner or operator would submit a 

written application for the exemption 

containing information needed to 

document the low sulfur content. The 

application is not a mandatory 

requirement and the incremental 

reduction in monitoring burden that 

would occur as a result of the 

exemption would not be significant 

compared to the baseline burden 

estimates for the existing rule. 

Therefore, we have not revised the 

information collection request (ICR) for 

the existing rule. The OMB has 

previously approved the information 

collection requirements in the existing 

rule (40 CFR part 60, subpart J) under 

the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501, et seq. 

and has assigned OMB control number 

2060–0022, EPA ICR number 1054.07. 

A copy of the OMB-approved ICR for 

the Standards of Performance for 

Petroleum Refineries may be obtained 

from Susan Auby, Collection Strategies 

Division, Environmental Protection 

Agency (2822T), 1200 Pennsylvania 

Ave., NW., Washington, DC 20460, by 

e-mail at auby.susan@epa.gov, or by 

calling (292) 566–1672. 

The information collection 

requirements in the proposed standards 

of performance for petroleum refineries 

(40 CFR part 60, subpart Ja) have been 

submitted for approval to OMB under 

the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. The ICR document prepared 

by EPA has been assigned EPA ICR 

number 2263.01. 

The proposed standards of 

performance for petroleum refineries 

include work practice requirements for 

delayed coking reactor vessel 

depressuring and written plans to 

minimize emissions during startups, 

shutdowns, and malfunctions. Plants 

also would be required to analyze the 

cause of any exceedance that releases 

more than 500 pounds per day of SO2

above an allowable limit. EPA is coproposing work practice standards that 

would include the requirement for 

delayed coking reactor vessel 

depressuring but exclude the 

requirements for written plans and rootcause analyses for SO2 emissions 

discharges exceeding allowable limits 

by at least 500 pounds per day. The 

proposed standards also include testing, 

monitoring, recordkeeping, and 

reporting provisions. Monitoring 

requirements may include control 

device operating parameters, bag leak 

detection systems, or CEMS, depending 

on the type of process, pollutant, and 

control device. Exemptions are also 

proposed for small emitters. These 

requirements are based on 

recordkeeping and reporting 

requirements in the NSPS General 

Provisions in 40 CFR part 60, subpart A, 

and on specific requirements in subpart 

J or subpart Ja which are mandatory for 

all operators subject to new source 

performance standards. These 

recordkeeping and reporting 

requirements are specifically authorized 

by section 114 of the CAA (42 U.S.C. 

7414). All information submitted to EPA 

pursuant to the recordkeeping and 

reporting requirements for which a 

claim of confidentiality is made is 

safeguarded according to EPA policies 

set forth in 40 CFR part 2, subpart B. 

The annual burden for this 

information collection averaged over the 

first 3 years of this ICR is estimated to 

total 6,084 labor-hours per year at a cost 

of $526,241 per year. The annualized 

capital costs are estimated at $2,736,000 

per year and operation and maintenance 

costs are estimated at $1,627,200 per 

year. We note that the capital costs as 

well as the operation and maintenance 

costs are for the continuous monitors; 

these costs are also included in the cost 

impacts presented in section VIII.A of 

this preamble. Therefore, the burden 

costs associated with the continuous 

monitors presented in the ICR are not 

additional costs incurred by affected 

sources subject to proposed subpart Ja. 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purposes of 

collecting, validating, and verifying 

information, processing and 

maintaining information, and disclosing 

and providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations are listed 

in 40 CFR part 9. 

To comment on the Agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, including the use of 

automated collection techniques, EPA 

has established a public docket for this 

rule, which includes this ICR, under 

Docket ID number EPA–HQ–OAR–

2007–0011. Submit any comments 

related to the ICR for this proposed rule 

to EPA and OMB. See ADDRESSES

section at the beginning of this 

document for where to submit 

comments to EPA. Send comments to 

OMB at the Office of Information and 

Regulatory Affairs, Office of 

Management and Budget, 725 17th 

Street, NW., Washington, DC 20503, 

Attention: Desk Office for EPA. Since 

OMB is required to make a decision 

concerning the ICR between 30 and 60 

days after May 14, 2007, a comment to 

OMB is best assured of having its full 

effect if OMB receives it by June 13, 

2007. The final rule will respond to any 

OMB or public comments on the 

information collection requirements 

contained in this proposal. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 


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other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impact 

of today’s proposed action on small 

entities, small entity is defined as: (1) A 

small business whose parent company 

has no more than 1,500 employees and 

no more than 125,000 barrels per day 

total operable atmospheric crude oil 

distillation capacity, depending on the 

size definition for the affected NAICS 

code (as defined by Small Business 

Administration (SBA) size standards); 

(2) a small governmental jurisdiction 

that is a government of a city, county, 

town, school district, or special district 

with a population of less than 50,000; 

and (3) a small organization that is any 

not-for-profit enterprise which is 

independently owned and operated and 

is not dominant in its field. 

After considering the economic 

impact of today’s proposed action on 

small entities, I certify that this action 

will not have a significant economic 

impact on a substantial number of small 

entities. Of the 58 entities that we 

expect could be affected by today’s 

proposed action, 24 of these (or 41 

percent) are classified as small 

according to the SBA small business 

size standard listed previously. Of these 

24 affected entities, one small entity is 

expected to incur an annualized 

compliance cost of more than 1.0 

percent to comply with today’s 

proposed action. In addition, the impact 

on gasoline prices nationwide is 

expected to be less than 0.02 percent of 

the baseline gasoline price, and this 

represents less than a 1 cent increase in 

the price per gallon of gasoline. Also, 

the output of gasoline in the U.S. is 

expected to fall by less than 0.004 

percent, or less than 6 million gallons 

per year in the U.S. For more 

information, please refer to the 

economic impact analysis that is in the 

public docket for this rulemaking. 

Although this proposed action would 

not have a significant economic impact 

on a substantial number of small 

entities, EPA nonetheless has tried to 

reduce the impact of this proposed 

action on small entities by incorporating 

specific standards for small sulfur 

recovery plants and streamlining 

procedures for exempting inherently 

low-sulfur fuel gases from continuous 

monitoring. We continue to be 

interested in the potential impacts of 

this proposed action on small entities 

and welcome comments on issues 

related to such impacts. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act (UMRA) of 1995, Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and tribal governments and the private 

sector. Under section 202 of the UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures by State, local, 

and tribal governments, in the aggregate, 

or to the private sector, of $100 million 

or more in any 1 year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of the UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective, or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of section 

205 do not apply when they are 

inconsistent with applicable law. 

Moreover, section 205 allows EPA to 

adopt an alternative other than the least 

costly, most cost-effective, or least 

burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including tribal 

governments, it must have developed 

under section 203 of the UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

EPA has determined that this 

proposed action does not contain a 

Federal mandate that may result in 

expenditures of $100 million or more 

for State, local, and tribal governments, 

in the aggregate, or the private sector in 

any 1 year. As discussed earlier in this 

preamble, the estimated expenditures 

for the private sector in the fifth year 

after proposal are $54 million. Thus, 

this proposed action is not subject to the 

requirements of section 202 and 205 of 

the UMRA. In addition, EPA has 

determined that this proposed action 

contains no regulatory requirements that 

might significantly or uniquely affect 

small governments. This proposed 

action contains no requirements that 

apply to such governments, imposes no 

obligations upon them, and would not 

result in expenditures by them of $100 

million or more in any 1 year or any 

disproportionate impacts on them. 

Therefore, this proposed action is not 

subject to the requirements of section 

203 of the UMRA. 

E. Executive Order 13132: Federalism 

Executive Order 13132 (64 FR 43255, 

August 10, 1999) requires EPA to 

develop an accountable process to 

ensure ‘‘meaningful and timely input by 

State and local officials in the 

development of regulatory policies that 

have federalism implications.’’ ‘‘Policies 

that have federalism implications’’ is 

defined in the Executive Order to 

include regulations that have 

‘‘substantial direct effects on the States, 

on the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government.’’

This proposed action does not have 

federalism implications. It will not have 

substantial direct effects on the States, 

on the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. None of the 

affected facilities are owned or operated 

by State governments. Thus, Executive 

Order 13132 does not apply to this 

proposed action. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between EPA 

and State and local governments, EPA 

specifically solicits comment on this 

proposed action from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination with Indian Tribal 

Governments 

Executive Order 13175, entitled (65 

FR 67249, November 9, 2000), requires 

EPA to develop an accountable process 

to ensure ‘‘meaningful and timely input 

by tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ This proposed action 

does not have tribal implications, as 

specified in Executive Order 13175. It 

will not have substantial direct effects 

on tribal governments, on the 

relationship between the Federal 

government and Indian tribes, or on the 

distribution of power and 

responsibilities between the Federal 

government and Indian tribes, as 

specified in Executive Order 13175. The 

proposed rules impose requirements on 

owners and operators of specified 


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industrial facilities and not tribal 

governments. Thus, Executive Order 

13175 does not apply to this proposed 

action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045 ‘‘Protection of 

Children from Environmental Health 

Risks and Safety Risks’’ (62 FR 19885, 

April 23, 1997) applies to any rule that: 

(1) Is determined to be ‘‘economically 

significant’’ as defined under Executive 

Order 12866, and (2) concerns an 

environmental health or safety risk that 

EPA has reason to believe may have a 

disproportionate effect on children. If 

the regulatory action meets both criteria, 

the Agency must evaluate the 

environmental health or safety effects of 

the planned rule on children, and 

explain why the planned regulation is 

preferable to other potentially effective 

and reasonably feasible alternatives 

considered by the Agency. 

EPA interprets Executive Order 13045 

as applying to those regulatory actions 

that concern health or safety risks, such 

that the analysis required under section 

5–501 of the Order has the potential to 

influence the regulation. This proposed 

action is not subject to Executive Order 

13045 because it is based on technology 

performance and not on health or safety 

risks. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This rule is not a ‘‘significant energy 

action’’ as defined in Executive Order 

13211, ‘‘Actions Concerning Regulations 

That Significantly Affect Energy Supply, 

Distribution, or Use’’ (66 FR 28355, May 

22, 2001) because it is not likely to have 

a significant adverse effect on the 

supply, distribution, or use of energy. 

We prepared an analysis of the impacts 

on energy markets as part of our 

economic impact analysis for today’s 

proposed action. Our analysis shows 

that there is a reduction in gasoline 

output of less than 6 million gallons per 

year, or less than 400 barrels of gasoline 

production per day, in the fifth year 

after proposal of this proposed action. In 

addition, our analysis shows that there 

is an increase in gasoline prices of less 

than 0.02 percent in the fifth year after 

proposal of this proposed action. Given 

this degree of increase in domestic 

gasoline prices, no significant increase 

in our dependence on foreign energy 

supplies should take place. Finally, 

today’s proposed action will have no 

adverse effect on crude oil supply, coal 

production, electricity production, and 

energy distribution. Based on the 

findings from the analysis of impacts on 

energy markets, we conclude that 

today’s proposed action is not a 

‘‘significant energy action’’ as defined in 

Executive Order 13211. For more 

information on this analysis, please 

refer to the economic impact analysis 

for this rulemaking. This analysis is 

found in the public docket. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act (NTTAA) of 1995 (Public Law No. 

104–113, Section 12(d), 15 U.S.C. 272 

note) directs EPA to use voluntary 

consensus standards (VCS) in its 

regulatory activities, unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. The VCS 

are technical standards (e.g., materials 

specifications, test methods, sampling 

procedures, and business practices) that 

are developed or adopted by VCS 

bodies. The NTTAA directs EPA to 

provide Congress, through OMB, 

explanations when the Agency does not 

use available and applicable VCS. 

Today’s proposed rule (subpart Ja) 

involves technical standards. The EPA 

cites the following standards: EPA 

Methods 1, 2, 3, 3A, 3B, 5, 6, 6A, 6B, 

6C, 7, 7A, 7C, 7D, 7E, 10, 10A, 11, 15, 

15A, and 16 of 40 CFR part 60, 

appendix A; Performance Specifications 

2, 3, 4, 5, 7, and 11 in 40 CFR part 60, 

appendix B; and Appendix F to 40 CFR 

Part 60. This rule also cites ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ for its manual methods of 

measuring the content of the exhaust 

gas. This part of ASME PTC 19.10–1981 

is an acceptable alternative to EPA 

Methods 3B, 6, 6A, 6B, 7, 7C, and 15A. 

Consistent with the NTTAA, EPA 

conducted searches to identify VCS in 

addition to these methods. No 

applicable VCS were identified for EPA 

Methods 7D and 11; EPA Performance 

Specifications 3, 4, 5, and 7; and 

Appendix F to 40 CFR part 60. The 

search and review results are in the 

docket for this rule. 

The search for emissions 

measurement procedures identified 22 

other VCS. The EPA determined that 

these 22 standards identified for 

measuring emissions of the targeted 

pollutants or surrogates subject to 

emission standards in this rule were 

impractical alternatives to EPA test 

methods for the purposes of this rule. 

Therefore, EPA does not intend to adopt 

these standards for this purpose. The 

reasons for the determinations for the 22 

standards are discussed in the 

memorandum submitted to the docket 

to this rule. 

Both the proposed amendments for 

subpart J and the proposed rule (subpart 

Ja) cite the Gas Processor’s Association 

Method 2377–86, ‘‘Test for Hydrogen 

Sulfide and Carbon Dioxide in Natural 

Gas Using Length of Stain Tubes’’

(incorporated by reference-see 40 CFR 

60.17) as an acceptable method for 

determining the H2S content of low 

sulfur streams. The amendments to 

subpart J do not include any other 

technical standards. 

Consistent with the NTTAA, EPA 

conducted searches to identify VCS in 

addition to Gas Processor’s Association 

Method 2377–86. No applicable 

voluntary consensus standards were 

identified for Gas Processor’s 

Association Method 2377–86. The 

search and review results are in the 

docket for this rule. 

Under 40 CFR 60.13(i) of the NSPS 

General Provisions, a source may apply 

to EPA for permission to use alternative 

test methods or alternative monitoring 

requirements in place of any required 

testing methods, performance 

specifications, or procedures in the 

proposed rule and amendments. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629 

(Feb. 16, 1994)) establishes Federal 

executive policy on environmental 

justice. Its main provision directs 

Federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. EPA 

has determined that the proposed 

amendments would not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because they do not affect the level of 

protection provided to human health or 

the environment. The proposed 

amendments are clarifications which do 

not relax the control measures on 

sources regulated by the rule and 

therefore will not cause emissions 

increases from these sources. EPA has 

determined that the proposed standards 

would not have disproportionately high 

and adverse human health or 

environmental effects on minority or 

low-income populations because they 

would increase the level of 


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environmental protection for all affected 

populations without having any 

disproportionately high and adverse 

human health or environmental effects 

on any population, including any 

minority or low-income population. 

These proposed standards would reduce 

emissions of criteria pollutants from all 

new, reconstructed, or modified sources 

at petroleum refineries, decreasing the 

amount of such emissions to which all 

affected populations are exposed. 

List of Subjects in 40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Intergovernmental 

relations, Reporting and recordkeeping 

requirements. 

Dated: April 30, 2007. 

Stephen L. Johnson, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I of the Code 

of Federal Regulations is proposed to be 

amended as follows: 

PART 60—[AMENDED] 

1. The authority citation for part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

Subpart A—[Amended] 

2. Section 60.17 is amended by: 

a. Revising paragraph (h)(4), 

b. Revising the last sentence of 

paragraph (m) introductory text, and 

c. Revising paragraph (m)(1) to read as 

follows: 

§ 60.17 Incorporations by reference. 

* * * * * 

(h) * * * 

(4) ANSI/ASME PTC 19.10–1981, 

Flue and Exhaust Gas Analyses [Part 10, 

Instruments and Apparatus], IBR 

approved for Tables 1 and 3 of subpart 

EEEE, Tables 2 and 4 of subpart FFFF, 

§ 60.106(e)(2) of subpart J, 

§§ 60.104a(d)(3), (d)(6), (g)(3), (g)(4), 

(g)(6), (i)(3), (i)(4), (j)(3), (j)(4), (j)(4)(iii), 

and 60.105a(d)(4), (e)(4), (f)(2), and 

(f)(4), and 60.106a(a)(1)(ii), (a)(1)(iv), 

(a)(2)(ii), (a)(2)(iv), (a)(3)(ii), (a)(3)(iv), 

and (a)(4)(iii), and 60.107a(a)(1)(ii), 

(a)(1)(iv), (a)(2)(ii), (c)(2), and (c)(4) of 

subpart Ja, and §§ 60.4415(a)(2) and 

60.4415(a)(3) of subpart KKKK of this 

part. 

* * * * * 

(m) * * * You may inspect a copy at 

EPA’s Air and Radiation Docket and 

Information Center, Room 3334, 1301 

Constitution Ave., NW., Washington, 

DC 20460. 

(1) Gas Processors Association 

Method 2377–86, Test for Hydrogen 

Sulfide and Carbon Dioxide in Natural 

Gas Using Length of Stain Tubes, IBR 

approved for §§ 60.105(b)(1)(iv), 

60.107a(b)(1)(iv), 60.334(h)(1), 60.4360, 

and 60.4415(a)(1)(ii). 

* * * * * 

Subpart J—[Amended] 

3. Section 60.100 is amended by 

revising the first sentence in paragraph 

(a) and revising paragraphs (b) through 

(d) to read as follows: 

§ 60.100 Applicability, designation of 

affected facility, and reconstruction. 

(a) The provisions of this subpart are 

applicable to the following affected 

facilities in petroleum refineries: fluid 

catalytic cracking unit catalyst 

regenerators, fuel gas combustion 

devices, and all Claus sulfur recovery 

plants except Claus plants with a design 

capacity of 20 long tons per day (LTD) 

or less. * * * 

(b) Any fluid catalytic cracking unit 

catalyst regenerator or fuel gas 

combustion device under paragraph (a) 

of this section which commences 

construction, reconstruction, or 

modification after June 11, 1973, and on 

or before May 14, 2007, or any Claus 

sulfur recovery plant under paragraph 

(a) of this section which commences 

construction, reconstruction, or 

modification after October 4, 1976, and 

on or before May 14, 2007, is subject to 

the requirements of this subpart except 

as provided under paragraphs (c) and 

(d) of this section. 

(c) Any fluid catalytic cracking unit 

catalyst regenerator under paragraph (b) 

of this section which commences 

construction, reconstruction, or 

modification on or before January 17, 

1984, is exempted from § 60.104(b). 

(d) Any fluid catalytic cracking unit 

in which a contact material reacts with 

petroleum derivatives to improve 

feedstock quality and in which the 

contact material is regenerated by 

burning off coke and/or other deposits 

and that commences construction, 

reconstruction, or modification on or 

before January 17, 1984, is exempt from 

this subpart 

* * * * * 

4. Section 60.101 is amended by 

revising paragraphs (d), (i), (j), and (k) 

to read as follows: 

§ 60.101 Definitions. 

* * * * * 

(d) Fuel gas means any gas which is 

generated at a petroleum refinery and 

which is combusted. Fuel gas also 

includes natural gas when the natural 

gas is combined and combusted in any 

proportion with a gas generated at a 

refinery. Fuel gas does not include gases 

generated by catalytic cracking unit 

catalyst regenerators and fluid coking 

burners. Fuel gas does not include 

vapors that are collected and combusted 

to comply with the wastewater 

provisions in § 60.692, 40 CFR 61.343 

through 61.348, or 40 CFR 63.647, or the 

marine tank vessel loading provisions in 

40 CFR 63.562 or 40 CFR 63.651. 

* * * * * 

(i) Claus sulfur recovery plant means 

a series of process units which recover 

sulfur from hydrogen sulfide (H2S) by a 

vapor-phase catalytic reaction of sulfur 

dioxide and H2S. The Claus sulfur 

recovery plant includes the reactor 

furnace and waste heat boiler, catalytic 

reactors, sulfur pits, and, if present, 

oxidation or reduction control systems. 

One Claus sulfur recovery plant may 

consist of multiple trains. 

(j) Oxidation control system means an 

emission control system which reduces 

emissions from sulfur recovery plants 

by converting these emissions to sulfur 

dioxide and recycling the sulfur dioxide 

to the reactor furnace or the first-stage 

catalytic reactor of the Claus sulfur 

recovery plant. 

(k) Reduction control system means 

an emission control system which 

reduces emissions from sulfur recovery 

plants by converting these emissions to 

H2S and recycling the H2S to the reactor 

furnace or the first-stage catalytic 

reactor of the Claus sulfur recovery 

plant. 

* * * * * 

5. Section 60.102 is amended by 

revising paragraph (b) to read as follows: 

§ 60.102 Standard for particulate matter. 

* * * * * 

(b) Where the gases discharged by the 

fluid catalytic cracking unit catalyst 

regenerator pass through an incinerator 

or waste heat boiler in which auxiliary 

or supplemental liquid or solid fossil 

fuel is burned, particulate matter in 

excess of that permitted by paragraph 

(a)(1) of this section may be emitted to 

the atmosphere, except that the 

incremental rate of particulate matter 

emissions shall not exceed 43 grams per 

Gigajoule (g/GJ) (0.10 lb/million British 

thermal units (Btu)) of heat input 

attributable to such liquid or solid fossil 

fuel. 

6. Section 60.104 is amended by 

revising paragraphs (b)(1) and (b)(2) to 

read as follows: 

§ 60.104 Standards for sulfur oxides. 

* * * * * 

(b) * * * 

(1) With an add-on control device, 

reduce SO2 emissions to the atmosphere 

by 90 percent or maintain SO2


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emissions to the atmosphere less than or 

equal to 50 ppm by volume (ppmv), 

whichever is less stringent; or 

(2) Without the use of an add-on 

control device to reduce SO2 emissions, 

maintain sulfur oxides emissions 

calculated as SO2 to the atmosphere less 

than or equal to 9.8 kg/Mg (20 lb/ton) 

coke burn-off; or 

* * * * * 

7. Section 60.105 is amended by: 

a. Revising the first sentence of 

paragraph (a)(3) introductory text; 

b. Revising paragraph (a)(3)(iv); 

c. Revising paragraph (a)(4) 

introductory text; 

d. Adding paragraph (a)(4)(iv); 

e. Revising paragraph (a)(8) 

introductory text; 

f. Revising paragraph (a)(8)(i); and 

g. Adding paragraph (b) to read as 

follows: 

§ 60.105 Monitoring of emissions and 

operations. 

(a) * * * 

(3) For fuel gas combustion devices 

subject to § 60.104(a)(1), either an 

instrument for continuously monitoring 

and recording the concentration by 

volume (dry basis, 0 percent excess air) 

of SO2 emissions into the atmosphere or 

monitoring as provided in paragraph 

(a)(4) of this section). * * * 

* * * * * 

(iv) Fuel gas combustion devices 

having a common source of fuel gas may 

be monitored at only one location (i.e., 

after one of the combustion devices), if 

monitoring at this location accurately 

represents the SO2 emissions into the 

atmosphere from each of the 

combustion devices. 

(4) Instead of the SO2 monitor in 

paragraph (a)(3) of this section for fuel 

gas combustion devices subject to 

§ 60.104(a)(1), an instrument for 

continuously monitoring and recording 

the concentration (dry basis) of H2S in 

fuel gases before being burned in any 

fuel gas combustion device. 

* * * * * 

(iv) The owner or operator of a fuel 

gas combustion device is not required to 

comply with paragraph (a)(3) or (4) of 

this section for streams that are exempt 

under § 60.104(a)(1) and fuel gas 

streams combusted in a fuel gas 

combustion device that are inherently 

low in sulfur content. Fuel gas streams 

meeting one of the requirements in 

paragraphs (a)(4)(iv)(A) through (D) of 

this section will be considered 

inherently low in sulfur content. If the 

composition of a fuel gas stream 

changes such that it is no longer exempt 

under § 60.104(a)(1) or it no longer 

meets one of the requirements in 

paragraphs (a)(4)(iv)(A) through (D) of 

this section, the owner or operator must 

begin continuous monitoring under 

paragraph (a)(3) or (4) of this section 

within 15 days of the change. 

(A) Pilot gas for heaters and flares. 

(B) Gas streams that meet commercialgrade product specifications and have a 

sulfur content of 30 ppmv or less. 

(C) Fuel gas streams produced in 

process units that are intolerant to 

sulfur contamination, such as fuel gas 

streams produced in the hydrogen plant, 

the catalytic reforming unit, and the 

isomerization unit. 

(D) Other streams that an owner or 

operator demonstrates are low-sulfur 

according to the procedures in 

paragraph (b) of this section. 

* * * * * 

(8) An instrument for continuously 

monitoring and recording 

concentrations of SO2 in the gases at 

both the inlet and outlet of the SO2

control device from any fluid catalytic 

cracking unit catalyst regenerator for 

which the owner or operator seeks to 

comply specifically with the 90 percent 

reduction option under § 60.104(b)(1). 

(i) The span value of the inlet monitor 

shall be set at 125 percent of the 

maximum estimated hourly potential 

SO2 emission concentration entering the 

control device, and the span value of the 

outlet monitor shall be set at 50 percent 

of the maximum estimated hourly 

potential SO2 emission concentration 

entering the control device. 

* * * * * 

(b) An owner or operator may 

demonstrate that a gas stream 

combusted in a fuel gas combustion 

device subject to § 60.104(a)(1) that is 

not specifically exempted in 

§ 60.105(a)(4)(iv) is inherently low in 

sulfur. A gas stream that is determined 

to be low-sulfur is exempt from the 

monitoring requirements in paragraphs 

(a)(3) and (4) of this section until there 

are changes in operating conditions or 

stream composition. 

(1) The owner or operator shall 

submit to the Administrator a written 

application for an exemption from 

monitoring. The application must 

contain the following information: 

(i) A description of the gas stream/ 

system to be considered, including 

submission of a portion of the 

appropriate piping diagrams indicating 

the boundaries of the gas stream/system, 

and the affected fuel gas combustion 

device(s) to be considered; 

(ii) A statement that there are no 

crossover or entry points for sour gas 

(high H2S content) to be introduced into 

the gas stream/system (this should be 

shown in the piping diagrams); 

(iii) An explanation of the conditions 

that ensure low amounts of sulfur in the 

gas stream (i.e., control equipment or 

product specifications) at all times; 

(iv) The supporting test results from 

sampling the requested gas stream/ 

system demonstrating that the sulfur 

content is less than 5 ppmv. Minimum 

sampling data must consist of 2 weeks 

of daily monitoring (14 grab samples) 

for frequently operated gas streams/ 

systems; for infrequently operated gas 

streams/systems, seven grab samples 

must be collected unless other 

additional information would support 

reduced sampling. The owner or 

operator shall use detector tubes 

(‘‘length-of-stain tube’’ type 

measurement) following the Gas 

Processor Association’s Test for 

Hydrogen Sulfide and Carbon Dioxide 

in Natural Gas Using Length of Stain 

Tubes, 1986 revision with ranges 0–10/ 

0–100 ppm (N = 10/1) to test the 

applicant stream (incorporated by 

reference—see § 60.17). 

(v) A description of how the 2 weeks 

(or seven samples for infrequently 

operated gas streams/systems) of 

monitoring results compares to the 

typical range of H2S concentration (fuel 

quality) expected for the gas stream/ 

system going to the affected fuel gas 

combustion device (e.g., the 2 weeks of 

daily detector tube results for a 

frequently operated loading rack 

included the entire range of products 

loaded out, and, therefore, should be 

representative of typical operating 

conditions affecting H2S content in the 

gas stream going to the loading rack 

flare). 

(2) Once EPA receives a complete 

application, the Administrator will 

determine whether an exemption is 

granted. The owner or operator shall 

continue to comply with the monitoring 

requirements in paragraph (a)(3) or 

paragraph (a)(4) of this section until an 

exemption is granted. 

(3) Once an exemption from 

continuous monitoring is granted, no 

further action is required unless refinery 

operating conditions change in such a 

way that affects the exempt gas stream/ 

system (e.g., the stream composition 

changes). If such a change occurs, the 

owner or operator will follow the 

procedures in paragraph (b)(2)(i), 

(b)(2)(ii), or (b)(2)(iii) of this section. 

(i) If the operation change results in 

a sulfur content that is still within the 

range of concentrations included in the 

original application, the owner or 

operator shall conduct an H2S test on a 

grab sample and record the results as 

proof that the concentration is still 

within the range. 


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(ii) If the operation change results in 

a sulfur content that is outside the range 

of concentrations included in the 

original application, the owner or 

operator may submit a new application 

following the procedures of paragraph 

(b)(1) of this section within 60 days (or 

within 30 days after the seventh grab 

sample is tested for infrequently 

operated process units). 

(iii) If the operation change results in 

a sulfur content that is outside the range 

of concentrations included in the 

original application and the owner or 

operator chooses not to submit a new 

application, the owner or operator must 

begin continuous monitoring as 

specified in paragraphs (a)(3) or (a)(4) of 

this section within 60 days of the 

operation change. 

* * * * * 

8. Section 60.106 is amended by 

revising paragraph (b)(3) introductory 

text and revising the first sentence of 

paragraph (e)(2) to read as follows: 

§ 60.106 Test methods and procedures. 

* * * * * 

(b) * * * 

(3) The coke burn-off rate (Rc) shall be 

computed for each run using the 

following equation: 

Rc = K1Qr (%CO2 + %CO) + 

K2Qa¥K3Qr(%CO/2 + %CO2 + 

%O2) + K3Qoxy (%Ooxy) 

Where: 

Rc = Coke burn-off rate, kilograms per hour 

(kg/hr) (lb/hr). 

Qr = Volumetric flow rate of exhaust gas from 

fluid catalytic cracking unit regenerator 

before entering the emission control 

system, dscm/min (dscf/min). 

Qa = Volumetric flow rate of air to fluid 

catalytic cracking unit regenerator, as 

determined from the fluid catalytic 

cracking unit control room 

instrumentation, dscm/min (dscf/min). 

Qoxy = Volumetric flow rate of O2 enriched 

air to fluid Catalytic cracking unit 

regenerator, as determined from the fluid 

catalytic cracking unit control room 

instrumentation, dscm/min (dscf/min). 

%CO2 = Carbon dioxide concentration in 

fluid catalytic cracking unit regenerator 

exhaust, percent by volume (dry basis). 

%CO = CO concentration in FCCU 

regenerator exhaust, percent by volume 

(dry basis). 

%O2 = O2 concentration in fluid catalytic 

cracking unit regenerator exhaust, 

percent by volume (dry basis). 

%Ooxy = O2 concentration in O2 enriched air 

stream inlet to the fluid catalytic 

cracking unit regenerator, percent by 

volume (dry basis). 

K1 = Material balance and conversion factor, 

0.2982 (kg-min)/(hr-dscm-%) [0.0186 (lbmin)/(hr-dscf-%)]. 

K2 = Material balance and conversion factor, 

2.088 (kg-min)/(hr-dscm-%) [0.1303 (lbmin)/(hr-dscf-%)]. 

K3 = Material balance and conversion factor, 

0.0994 (kg-min)/(hr-dscm-%) [0.00624 

(lb-min)/(hr-dscf-%)]. 

* * * * * 

(e) * * * 

(2) Where emissions are monitored by 

§ 60.105(a)(3), compliance with 

§ 60.104(a)(1) shall be determined using 

Method 6 or 6C and Method 3 or 3A. 

The method ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 6. * * * 

* * * * * 

9. Section 60.107 is amended by: 

a. Revising the first sentence of 

paragraph (c)(1)(i); 

b. Redesignating paragraphs (e) and (f) 

as (f) and (g); and 

c. Adding paragraph (e) to read as 

follows: 

§ 60.107 Reporting and recordkeeping 

requirements. 

* * * * * 

(c) * * * 

(1) * * * 

(i) The average percent reduction and 

average concentration of sulfur dioxide 

on a dry, O2-free basis in the gases 

discharged to the atmosphere from any 

fluid cracking unit catalyst regenerator 

for which the owner or operator seeks 

to comply with § 60.104(b)(1) is below 

90 percent and above 50 ppmv, as 

measured by the continuous monitoring 

system prescribed under § 60.105(a)(8), 

or above 50 ppmv, as measured by the 

outlet continuous monitoring system 

prescribed under § 60.105(a)(9). * * * 

* * * * * 

(e) For each stream combusted in a 

fuel gas combustion device subject to 

§ 60.104(a)(1), if an owner or operator 

determines that one of the exemptions 

listed in § 60.105(a)(4)(iv) applies to that 

stream, the owner or operator shall 

maintain records of the specific 

exemption chosen for each stream. If the 

owner or operator applies for the 

exemption described in 

§ 60.105(a)(4)(iv)(D), the owner or 

operator must keep a copy of the 

application as well as the letter from the 

Administrator granting approval of the 

application. 

* * * * * 

10. Section 60.108 is amended by 

revising the last sentence of paragraph 

(e) to read as follows: 

§ 60.108 Performance test and compliance 

provisions. 

* * * * * 

(e) * * * The owner or operator shall 

furnish the Administrator with a written 

notification of the change in the 

semiannual report required by 

§ 60.107(f). 

11. Section 60.109 is amended by 

redesignating paragraph (b)(2) as (b)(3) 

and adding paragraph (b)(2) to read as 

follows: 

§ 60.109 Delegation of authority. 

* * * * * 

(b) * * * 

(1) * * * 

(2) Section 60.105(b), and 

* * * * * 

12. Part 60 is amended by adding 

subpart Ja to read as follows: 

Subpart Ja—Standards of Performance for 

Petroleum Refineries for Which 

Construction, Reconstruction, or 

Modification Commenced After May 14, 

2007 

Sec. 

60.100a Applicability, designation of 

affected facility, and reconstruction. 

60.101a Definitions. 

60.102a Emissions limitations. 

60.103a Work practice standards. 

60.104a Performance tests. 

60.105a Monitoring of emissions and 

operations for fluid catalytic cracking 

units (FCCU) and fluid coking units. 

60.106a Monitoring of emissions and 

operations for sulfur recovery plants. 

60.107a Monitoring of emissions and 

operations for process heaters and other 

fuel gas combustion devices. 

60.108a Recordkeeping and reporting 

requirements. 

60.109a Delegation of authority. 

Subpart Ja—Standards of Performance 

for Petroleum Refineries for Which 

Construction, Reconstruction, or 

Modification Commenced After May 14, 

2007 

§ 60.100a Applicability, designation of 

affected facility, and reconstruction. 

(a) The provisions of this subpart 

apply to the following affected facilities 

in petroleum refineries: Fluid catalytic 

cracking units (FCCU), fluid coking 

units, delayed coking units, process 

heaters, other fuel gas combustion 

devices, fuel gas producing units, and 

sulfur recovery plants. The sulfur 

recovery plant need not be physically 

located within the boundaries of a 

petroleum refinery to be an affected 

facility, provided it processes gases 

produced within a petroleum refinery. 

(b) The provisions of this subpart 

apply only to affected facilities under 

paragraph (a) of this section which 

commence construction, modification, 

or reconstruction after May 14, 2007. 

(c) For purposes of this subpart, under 

§ 60.15, the ‘‘fixed capital cost of the 

new components’’ includes the fixed 

capital cost of all depreciable 

components which are or will be 

replaced pursuant to all continuous 


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programs of component replacement 

which are commenced within any 2- 

year period following May 14, 2007. For 

purposes of this paragraph, 

‘‘commenced’’ means that an owner or 

operator has undertaken a continuous 

program of component replacement or 

that an owner or operator has entered 

into a contractual obligation to 

undertake and complete, within a 

reasonable time, a continuous program 

of component replacement. 

§ 60.101a Definitions. 

Terms used in this subpart are 

defined in the Clean Air Act, in § 60.2, 

and in this section. 

Coke burn-off means the coke 

removed from the surface of the FCCU 

catalyst by combustion in the catalyst 

regenerator. The rate of coke burn-off is 

calculated by the formula specified in 

§ 60.104a. 

Contact material means any substance 

formulated to remove metals, sulfur, 

nitrogen, or any other contaminant from 

petroleum derivatives. 

Delayed coking unit means one or 

more coking units in which high 

molecular weight petroleum derivatives 

are thermally cracked and petroleum 

coke is produced in a series of closed, 

batch system reactors. 

Flexicoking unit means one or more 

coking units in which high molecular 

weight petroleum derivatives are 

thermally cracked and petroleum coke 

is produced then gasified to produce a 

synthetic fuel gas. 

Fluid catalytic cracking unit means 

one or more units in which petroleum 

derivatives are continuously charged 

and hydrocarbon molecules in the 

presence of a catalyst suspended in a 

fluidized bed are fractured into smaller 

molecules, or react with a contact 

material suspended in a fluidized bed to 

improve feedstock quality for additional 

processing and the catalyst or contact 

material is continuously regenerated by 

burning off coke and other deposits. The 

unit includes the riser, reactor, 

regenerator, air blowers, spent catalyst 

or contact material stripper, catalyst or 

contact material recovery equipment, 

and regenerator equipment for 

controlling air pollutant emissions and 

for heat recovery. 

Fluid coking unit means one or more 

coking units in which high molecular 

weight petroleum derivatives are 

thermally cracked and petroleum coke 

is continuously produced in a fluidized 

bed system and in which the fluid 

coking burner exhaust gas is 

continuously released to the 

atmosphere. The fluid coking unit 

includes equipment for controlling air 

pollutant emissions and for heat 

recovery on the fluid coking burner 

exhaust vent. Flexicoking units that use 

gasifiers to generate a synthetic fuel gas 

for use in other processes and that do 

not exhaust to the atmosphere are not 

considered fluid coking units under this 

subpart. 

Fresh feed means any petroleum 

derivative feedstock stream charged 

directly into the riser or reactor of a 

FCCU except for petroleum derivatives 

recycled within the FCCU, fractionator, 

or gas recovery unit. 

Fuel gas means any gas which is 

generated at a petroleum refinery and 

which is combusted. Fuel gas includes 

natural gas when the natural gas is 

combined and combusted in any 

proportion with a gas generated at a 

refinery. Fuel gas does not include gases 

generated by catalytic cracking unit 

catalyst regenerators and fluid coking 

burners, but does include gases from 

flexicoking unit gasifiers. Fuel gas does 

not include vapors that are collected 

and combusted to comply with the 

wastewater provisions in § 60.692, 40 

CFR 61.343 through 61.348, 40 CFR 

63.647, or the marine tank vessel 

loading provisions in 40 CFR 63.562 or 

40 CFR 63.651. 

Fuel gas producing unit means any 

refinery process unit that produces fuel 

gas as a routine part of normal 

operations. A fuel gas producing unit 

includes, but is not limited to, the 

atmospheric distillation unit, the FCCU, 

the catalytic hydrocracking unit, all 

types of coking units, and the catalytic 

reforming unit. 

Other fuel gas combustion device 

means any equipment, such as boilers 

and flares, used to combust fuel gas, 

except process heaters and facilities in 

which gases are combusted to produce 

sulfur or sulfuric acid. 

Oxidation control system means an 

emission control system which reduces 

emissions from sulfur recovery plants 

by converting these emissions to sulfur 

dioxide (SO2) and recycling the SO2 to 

the reactor furnace or the first-stage 

catalytic reactor of the Claus sulfur 

recovery plant. 

Petroleum means the crude oil 

removed from the earth and the oils 

derived from tar sands, shale, and coal. 

Petroleum refinery means any facility 

engaged in producing gasoline, 

kerosene, distillate fuel oils, residual 

fuel oils, lubricants, asphalt (bitumen) 

or other products through distillation of 

petroleum or through redistillation, 

cracking, or reforming of unfinished 

petroleum derivatives. 

Process gas means any gas generated 

by a petroleum refinery process unit, 

except fuel gas and process upset gas as 

defined in this section. 

Process heater means an enclosed 

combustion device used to transfer heat 

indirectly to process stream materials 

(liquids, gases, or solids) or to a heat 

transfer material for use in a process 

unit instead of steam. 

Process upset gas means any gas 

generated by a petroleum refinery 

process unit as a result of upset or 

malfunction. 

Reduced sulfur compounds means 

hydrogen sulfide (H2S), carbonyl 

sulfide, and carbon disulfide. 

Reduction control system means an 

emission control system which reduces 

emissions from sulfur recovery plants 

by converting these emissions to H2S 

and recycling the H2S to the reactor 

furnace or the first-stage catalytic 

reactor of the Claus sulfur recovery 

plant. 

Refinery process unit means any 

segment of the petroleum refinery in 

which a specific processing operation is 

conducted. 

Sulfur recovery plant means all 

process units which recover sulfur from 

H2S and/or SO2 at a petroleum refinery. 

The sulfur recovery plant also includes 

vessels, tanks, or pits used to store the 

recovered sulfur product. For example, 

a Claus sulfur recovery plant includes: 

reactor furnace and waste heat boiler, 

catalytic reactors, sulfur pits, and, if 

present, oxidation or reduction control 

systems, or incinerator, thermal 

oxidizer, or similar combustion device. 

§ 60.102a Emissions limitations. 

(a) Each owner or operator that is 

subject to the requirements of this 

subpart shall comply with the emissions 

limitations in paragraphs (b) through (h) 

of this section on and after the date on 

which the initial performance test, 

required by § 60.8, is completed, but not 

later than 60 days after achieving the 

maximum production rate at which the 

affected facility will be operated, or 180 

days after initial startup, whichever 

comes first. 

Option 1 for Paragraph (b): 

(b) An owner or operator subject to 

the provisions of this subpart shall not 

discharge or cause the discharge into the 

atmosphere from any FCCU or fluid 

coking unit: 

(1) Particulate matter (PM) in excess 

of 0.5 gram per kilogram (g/kg) coke 

burn-off (0.5 pound (lb) PM/1,000 lbs 

coke burn-off) or 0.020 grains per dry 

standard cubic feet (gr/dscf) corrected to 

0 percent excess air; and 

(2) NOX in excess of 80 parts per 

million by volume (ppmv), dry basis 

corrected to 0 percent excess air, on a 

7-day rolling average basis; and 


ycherry on PROD1PC64 with PROPOSALS2
27208 Federal Register / Vol. 72, No. 92 / Monday, May 14, 2007 / Proposed Rules 

(3) SO2 in excess of 50 ppmv dry basis 

corrected to 0 percent excess air, on a 

7-day rolling average basis and 25 

ppmv, dry basis corrected to 0 percent 

excess air, on a 365-day rolling average 

basis; and 

(4) Carbon monoxide (CO) in excess of 

500 ppmv, dry basis corrected to 0 

percent excess air, on an hourly average 

basis. 

Option 2 for Paragraph (b) 

(b) Except as provided in paragraph 

(b)(2) of this section, an owner or 

operator subject to the provisions of this 

subpart shall not discharge or cause the 

discharge into the atmosphere from any 

FCCU or fluid coking unit: 

(1) Particulate Matter (PM) in excess 

of 0.5 gram per kilogram (g/kg) coke 

burn-off (0.5 lb PM/1,000 lbs coke burnoff) or 0.020 grains per dry standard 

cubic feet (gr/dscf) corrected to 0 

percent excess air; and 

(2) NOX in excess of 80 parts per 

million by volume (ppmv), dry basis 

corrected to 0 percent excess air, on a 

7-day rolling average basis. This 

emissions limit does not apply to a fluid 

coking unit subject to this subpart; 

(3) SO2 in excess of 50 ppmv dry basis 

corrected to 0 percent excess air, on a 

7-day rolling average basis and 25 

ppmv, dry basis corrected to 0 percent 

excess air, on a 365-day rolling average 

basis; and 

(4) Carbon monoxide (CO) in excess of 

500 ppmv, dry basis corrected to 0 

percent excess air, on an hourly average 

basis. 

(c) The owner or operator of a FCCU 

or fluid coking unit that uses 

continuous parameter monitoring 

systems (CPMS) according to 

§ 60.105a(b)(1) shall comply with the 

applicable control device parameter 

operating limit in paragraph (c)(1) or 

(c)(2) of this section. 

(1) If the FCCU or fluid coking unit is 

controlled using an electrostatic 

precipitator: 

(i) The hourly average total power and 

secondary current to the control device 

must not fall below the level established 

during the most recent performance test; 

and 

(ii) The exhaust coke burn-off rate 

must not exceed the level established 

during the most recent performance test. 

(2) If the FCCU or fluid coking unit is 

controlled using a wet scrubber: 

(i) The hourly average pressure drop 

must not fall below the level established 

during the most recent performance test; 

and 

(ii) The hourly average liquid-to-gas 

ratio must not fall below the level 

established during the most recent 

performance test. 

(d) The owner or operator of a FCCU 

or fluid coking unit that is exempted 

from the requirement for a CO 

continuous emissions monitoring 

system (CEMS) under § 60.105a(g)(3) 

shall comply with the parameter 

operating limits in paragraph (d)(1) or 

(d)(2) of this section. 

(1) For a FCCU or fluid coking unit 

with no post-combustion control device: 

(i) The hourly average temperature of 

the exhaust gases exiting the FCCU or 

fluid coking unit must not fall below the 

level established during the most recent 

performance test. 

(ii) The hourly average oxygen (O2) 

concentration of the exhaust gases 

exiting the FCCU or fluid coking unit 

must not fall below the level established 

during the most recent performance test. 

(2) For a FCCU or fluid coking unit 

with a post-combustion control device: 

(i) The hourly average temperature of 

the exhaust gas vent stream exiting the 

control device must not fall below the 

level established during the most recent 

performance test. 

(ii) The hourly average O2

concentration of the exhaust gas vent 

stream exiting the control device must 

not fall below the level established 

during the most recent performance test. 

(e) Each owner or operator that is 

subject to the provisions of this subpart 

shall comply with the following 

emissions limits for each sulfur recovery 

plant: 

(1) For a sulfur recovery plant with a 

capacity greater than 20 long tons per 

day (LTD), the owner or operator shall 

not discharge or cause the discharge of 

any gases into the atmosphere 

containing a combined SO2 and reduced 

sulfur compounds concentration in 

excess of 250 ppmv as SO2 (dry basis) 

at 0 percent excess air determined 

hourly on a 12-hour rolling average 

basis. If the sulfur recovery plant 

consists of multiple process trains or 

release points the owner or operator 

shall comply with the 250 ppmv limit 

for each process train or release point or 

comply with a flow rate weighted 

average of 250 ppmv for all release 

points from the sulfur recovery plant. 

(2) For a sulfur recovery plant with a 

capacity of 20 LTD or less, the owner or 

operator shall not discharge or cause the 

discharge of any gases into the 

atmosphere containing combined SO2

and reduced sulfur compounds mass 

emissions in excess of 1 percent by 

weight of sulfur recovered, measured as 

the mass ratio of sulfur emitted (from all 

release points combined) to sulfur 

recovered determined hourly on a 12- 

hour rolling average basis. 

(3) For all sulfur recovery plants, 

regardless of size, the owner or operator 

shall not discharge or cause the 

discharge of any gases into the 

atmosphere containing H2S in excess of 

10 ppmv (dry basis) at 0 percent excess 

air determined hourly on a 12-hour 

rolling average basis. 

(f) The owner or operator of a sulfur 

recovery plant subject to the H2S 

emissions limit in paragraph (e)(3) of 

this section and that uses CPMS 

pursuant to § 60.106a(a)(4) shall comply 

with the following operating limits: 

(1) The hourly average temperature of 

the exhaust gases exiting the sulfur 

recovery plant must not fall below the 

level established during the most recent 

performance test. 

(2) The hourly average O2

concentration of the exhaust gases 

exiting the sulfur recovery plant must 

not fall below the level established 

during the most recent performance test. 

(g) Each owner or operator subject to 

the provisions of this subpart shall 

comply with the emission limitations in 

paragraphs (g)(1) through (3) for each 

process heater and other fuel gas 

combustion device, except as provided 

in paragraph (h) and (i) of this section. 

(1) SO2 in excess of 20 ppmv (dry 

basis, corrected to 0 percent excess air) 

on a 3-hour rolling average basis; and 

(2) SO2 in excess of 8 ppmv (dry basis, 

corrected to 0 percent excess air), 

determined daily on a 365 successive 

day rolling average basis; and 

(3) For process heaters with a rated 

capacity of greater than 20 million 

British thermal units per hour, NOX in 

excess of 80 ppmv (dry basis, corrected 

to 0 percent excess air) on a 24-hour 

rolling average basis. 

(h) For process heaters that combust 

only fuel gas and for other fuel gas 

combustion devices, the following 

emission limitations may be used 

instead of the SO2 emission limits in 

paragraph (g)(1) and (2) of this section: 

(1) For process heaters and other fuel 

gas combustion devices that do not 

combust fuel gas generated from a 

coking unit: 

(i) H2S in excess of 160 ppmv 

determined hourly on a 3-hour rolling 

average basis; and 

(ii) H2S in excess of 60 ppmv 

determined daily on a 365 successive 

calendar day rolling average basis. 

(2) For process heaters and other fuel 

gas combustion devices that combust 

fuel gas generated from a coking unit or 

fuel gas that is mixed with fuel gas 

generated from a coking unit: 

(i) Total reduced sulfur (TRS) in 

excess of 160 ppmv determined hourly 

on a 3-hour rolling average basis; and 

(ii) TRS in excess of 60 ppmv 

determined daily on a 365 successive 

calendar day rolling average basis. 


ycherry on PROD1PC64 with PROPOSALS2
Federal Register / Vol. 72, No. 92 / Monday, May 14, 2007 / Proposed Rules 27209 

(i) The combustion in a flare of 

process upset gases or fuel gas that is 

released to the flare as a result of relief 

valve leakage or other emergency 

malfunctions is exempt from paragraphs 

(g) and (h) of this section. 

Option 1 for § 60.103a: 

§ 60.103a Work practice standards. 

(a) Each owner or operator subject to 

the provisions of this subpart shall not 

routinely release fuel gas to a flare from 

any fuel gas producing unit. The 

combustion in a flare of process upset 

gases or fuel that that is released to the 

flare as a result of relief valve leakage 

or other emergency malfunctions is 

exempt from this paragraph. 

(b) The owner or operator shall 

develop a written startup, shutdown, 

and malfunction plan that describes, in 

detail, procedures for operating and 

maintaining each affected facility during 

periods of startup, shutdown, and 

malfunction; and a program of 

corrective action for malfunctioning 

process, air pollution control, and 

monitoring equipment used to comply 

with the requirements of this subpart. 

The owner or operator may use the 

affected source’s standard operating 

procedures (SOP) manual, or an 

Occupational Safety and Health 

Administration (OSHA) or other plan, 

provided the alternative plans meet all 

the requirements of this section and are 

made available for inspection or 

submitted when requested by the 

Administrator. 

(1) The written plan must cover fluid 

catalytic cracking units, fluid coking 

units, sulfur recovery plants (including 

tail gas treatment system), amine 

treatment system, and fuel process 

heaters and other gas combustion 

devices. The written plan must include 

procedures to minimize discharges 

either directly to the atmosphere or to 

the flare gas system during the planned 

startup or shutdown of these units, 

procedures to minimize emissions 

during malfunctions of the amine 

treatment system or sulfur recovery 

plant, and procedures for conducting a 

root-cause analysis of any emissions 

limit exceedance or process start-up, 

shutdown, upset, or malfunction that 

causes a discharge into the atmosphere, 

either directly or indirectly, from any 

refinery process unit subject to the 

provisions of this subpart in excess of 

500 lb per day (lb/d) of SO2. 

(2) When actions taken by the owner 

or operator during a startup or 

shutdown (and the startup or shutdown 

causes the source to exceed any 

applicable emission limitation in the 

relevant emission standards), or 

malfunction (including actions taken to 

correct a malfunction) are consistent 

with the procedures specified in the 

startup, shutdown, and malfunction 

plan, the owner or operator must keep 

records for that event which 

demonstrate that the procedures 

specified in the plan were followed. 

These records may take the form of a 

‘‘checklist,’’ or other effective form of 

recordkeeping that confirms 

conformance with the startup, 

shutdown, and malfunction plan and 

describes the actions taken for that 

event. The owner or operator must 

identify the exceedance in the 

semiannual excess emissions report and 

certify that the actions taken during the 

startup, shutdown, or malfunction were 

consistent with the procedures in the 

startup, shutdown, and malfunction 

plan. 

(3) If an action taken by the owner or 

operator during a startup, shutdown, or 

malfunction (including an action taken 

to correct a malfunction) is not 

consistent with the procedures specified 

in the startup, shutdown, and 

malfunction plan, and the source 

exceeds any applicable emission 

limitation, then the owner or operator 

must record the actions taken for that 

event and identify the exceedance in the 

semiannual excess emissions report. 

(4) The owner or operator must 

maintain at the affected facility a 

current startup, shutdown, and 

malfunction plan and must make the 

plan available to the Administrator 

upon request. 

(5) The Administrator may require the 

owner or operator to make changes to 

the startup, shutdown, and malfunction 

plan if the Administrator finds: 

(i) The plan does not address a 

startup, shutdown, or malfunction event 

that has occurred; 

(ii) The plan fails to provide for the 

minimization of emissions during 

operation of the source (including 

associated air pollution control and 

monitoring equipment) during a startup, 

shutdown, or malfunction event; 

(iii) The plan does not provide 

adequate procedures for correcting 

malfunctioning process and/or air 

pollution control and monitoring 

equipment as quickly as practicable; or 

(6) The owner or operator may 

periodically revise the startup, 

shutdown, and malfunction plan as 

necessary to satisfy the requirements of 

this subpart or to reflect changes in 

equipment or procedures at the affected 

facility. However, each such revision to 

a startup, shutdown, and malfunction 

plan must be reported in the semiannual 

report. 

(c) Each owner or operator of a 

delayed coking unit shall depressure to 

5 lb per square inch gauge (psig) during 

reactor vessel depressuring and vent the 

exhaust gases to the fuel gas system for 

recovery. 

Option 2 for § 60.103a: 

§ 60.103a Work practice standards. 

Each owner or operator of a delayed 

coking unit shall depressure to 5 lb per 

square inch gauge (psig) during reactor 

vessel depressuring and vent the 

exhaust gases to the fuel gas system for 

recovery. 

§ 60.104a Performance tests. 

(a) The owner or operator shall 

conduct a performance test for a FCCU, 

fluid coking unit, sulfur recovery plant, 

process heater and other fuel gas 

combustion device to demonstrate 

initial compliance with each applicable 

emissions limit in § 60.102a according 

to the requirements of § 60.8. The 

notification requirements of § 60.8(d) 

apply to the initial performance test and 

to subsequent performance tests 

required by paragraph (b) of this section 

(or as required by the Administrator), 

but does not apply to performance tests 

conducted for the purpose of obtaining 

supplemental data because of 

continuous monitoring system 

breakdowns, repairs, calibration checks, 

and zero and span adjustments as 

provided in § 60.105a(l). 

(b) The owner or operator of a FCCU 

or fluid coking unit that elects to 

monitor control device operating 

parameters according to the 

requirements in § 60.105a(b) shall 

conduct a PM performance test at least 

once every 24 months and furnish the 

Administrator a written report of the 

results of each test. 

(c) In conducting the performance 

tests required by this subpart (or as 

requested by the Administrator), the 

owner or operator shall use the test 

methods in 40 CFR part 60, appendix A 

or other methods as specified in this 

section, except as provided in § 60.8(b). 

(d) The owner or operator shall 

determine compliance with the PM, 

NOX, SO2, and CO emissions limits in 

§ 60.102a(b) for FCCU and fluid coking 

units using the following methods and 

procedures: 

(1) Method 1 for sample and velocity 

traverses. 

(2) Method 2 for velocity and 

volumetric flow rate. 

(3) Method 3, 3A, or 3B for gas 

analysis. The method ASME PTC 19.10–

1981, ‘‘Flue and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B. 


ycherry on PROD1PC64 with PROPOSALS2
27210 Federal Register / Vol. 72, No. 92 / Monday, May 14, 2007 / Proposed Rules 

(4) Method 5 for determining PM 

emissions and associated moisture 

content from affected facilities. 

(i) The PM performance test consists 

of 3 valid test runs; the duration of each 

test run must be no less than 60 

minutes. 

(ii) The emissions rate of PM (EPM) is 

computed for each run using Equation 

1 of this section: 

E C

K PM

PM = ( ) Q

 R Eq. 1 sd

c

Where: 

E = Emission rate of PM (EPM), g/kg, lbs per 

1,000 lbs (lb/1,000 lbs) of coke burn-off; 

Cs = Concentration of total PM, grams per dry 

standard cubic meter (g/dscm), gr/dscf; 

Qsd = Volumetric flow rate of effluent gas, dry 

standard cubic meters per hour, dry 

standard cubic feet per hour; 

Rc = Coke burn-off rate, kilograms per hour 

(kg/hr), lbs per hour (lbs/hr) coke; and 

K = Conversion factor, 1.0 grams per gram 

(7,000 grains per lb). 

(iii) The coke burn-off rate (Rc) is 

computed for each run using Equation 

2 of this section: 

R K Q CO CO K Q K Q CO CO O K Q O Eq c r a r oxy oxy = + 1 2 2 3 2 23 ( ) +− + + ( ) + ( ) 2 % % % % % % . 2 ( )

Where: 

Rc = Coke burn-off rate, kg/hr (lb/hr); 

Qr = Volumetric flow rate of exhaust gas from 

FCCU regenerator or fluid coking burner 

before any emissions control or energy 

recovery system that burns auxiliary 

fuel, dry standard cubic meters per 

minute (dscm/min), dry standard cubic 

feet per minute (dscf/min); 

Qa = Volumetric flow rate of air to FCCU 

regenerator or fluid coking burner, as 

determined from the unit’s control room 

instrumentation, dscm/min (dscf/min); 

Qoxy = Volumetric flow rate of O2 enriched 

air to FCCU regenerator or fluid coking 

unit, as determined from the unit’s 

control room instrumentation, dscm/min 

(dscf/min); 

%CO2 = Carbon dioxide concentration in 

FCCU regenerator or fluid coking burner 

exhaust, percent by volume (dry basis); 

%CO = CO concentration in FCCU 

regenerator or fluid coking burner 

exhaust, percent by volume (dry basis); 

%O2 = O2 concentration in FCCU regenerator 

or fluid coking burner exhaust, percent 

by volume (dry basis); 

%Ooxy = O2 concentration in O2 enriched air 

stream inlet to the FCCU regenerator or 

fluid coking burner, percent by volume 

(dry basis); 

K1 = Material balance and conversion factor, 

0.2982 (kg-min)/(hr-dscm-%) [0.0186 (lbmin)/(hr-dscf-%)]; 

K2 = Material balance and conversion factor, 

2.088 (kg-min)/(hr-dscm-%) [0.1303 (lbmin)/(hr-dscf-%)]; and 

K3 = Material balance and conversion factor, 

0.0994 (kg-min)/(hr-dscm-%) [0.00624 

(lb-min)/(hr-dscf-%)]. 

(iv) During the performance test, the 

volumetric flow rate of exhaust gas from 

catalyst regenerator (Qr) before any 

emission control or energy recovery 

system that burns auxiliary fuel is 

measured using Method 2. 

(v) For subsequent calculations of 

coke burn-off rates or exhaust gas flow 

rates, the volumetric flow rate of Qr is 

calculated using average exhaust gas 

concentrations as measured by the 

monitors in § 60.105a(b)(2), if 

applicable, using Equation 3 of this 

section: 

Q Q Oxy Q

CO CO O r

a oxy = ×+ − ( )×

− −− ( ) 79 100100 2 2

%

% %% Eq. 3

Where: 

Qr = Volumetric flow rate of exhaust gas from 

FCCU regenerator or fluid coking burner 

before any emission control or energy 

recovery system that burns auxiliary 

fuel, dscm/min (dscf/min); 

Qa = Volumetric flow rate of air to FCCU 

regenerator or fluid coking burner, as 

determined from the unit’s control room 

instrumentation, dscm/min (dscf/min); 

Qoxy = Volumetric flow rate of O2 enriched 

air to FCCU regenerator or fluid coking 

unit, as determined from the unit’s 

control room instrumentation, dscm/min 

(dscf/min); 

%CO2 = Carbon dioxide concentration in 

FCCU regenerator or fluid coking burner 

exhaust, percent by volume (dry basis); 

%CO = CO concentration FCCU regenerator 

or fluid coking burner exhaust, percent 

by volume (dry basis). When no auxiliary 

fuel is burned and a continuous CO 

monitor is not required in accordance 

with § 60.105a(g)(3), assume %CO to be 

zero; 

%O2 = O2 concentration in FCCU regenerator 

or fluid coking burner exhaust, percent 

by volume (dry basis); and 

%Ooxy = O2 concentration in O2 enriched air 

stream inlet to the FCCU regenerator or 

fluid coking burner, percent by volume 

(dry basis). 

(5) Method 7, 7A, 7C, 7D, or 7E for 

moisture content and for the 

concentration of NOX calculated as 

nitrogen dioxide (NO2); the duration of 

each test run must be no less than 4 

hours. 

(6) Method 6, 6A, or 6C for moisture 

content and for the concentration of 

SO2; the duration of each test run must 

be no less than 4 hours. The method 

ASME PTC 19.10–1981, ‘‘Flue and 

Exhaust Gas Analyses,’’ (incorporated 

by reference—see § 60.17) is an 

acceptable alternative to EPA Method 6 

or 6A. 

(7) Method 10, 10a, or 10B for 

moisture content and for the 

concentration of CO. The sampling time 

for each run must be 60 minutes. 

(8) The owner or operator shall adjust 

PM, NOX, SO2, and CO pollutant 

concentrations to 0 percent excess air or 

0 percent O2 using Equation 4 of this 

section: 

C C adj meas O = c

( ) −





 



 ( ) 20 9

20 9 2

.

. % Eq. 4

Where: 

Cadj = pollutant concentration adjusted to 0 

percent excess air or O2, parts per 

million (ppm) or g/dscm; 

Cmeas = pollutant concentration measured on 

a dry basis, ppm or g/dscm; 

20.9c = 20.9 percent O2–0.0 percent O2

(defined O2 correction basis), percent; 

20.9 = O2 concentration in air, percent; and 

%O2 = O2 concentration measured on a dry 

basis, percent. 


ycherry on PROD1PC64 with PROPOSALS2EP14MY07.000</MATH> EP14MY07.001</MATH> EP14MY07.002</MATH> EP14MY07.003</MATH>
Federal Register / Vol. 72, No. 92 / Monday, May 14, 2007 / Proposed Rules 27211 

(e) The owner or operator of a FCCU 

or fluid coking unit that is controlled by 

an electrostatic precipitator or wet 

scrubber and that is subject to control 

device operating parameter limits 

§ 60.102a(c) shall establish the limits 

based on the performance test results 

according to the following procedures: 

(1) Reduce the parameter monitoring 

data to hourly averages for each test run; 

(2) Determine the operating limit for 

each required parameter as the lowest 

hourly average voltage and secondary 

current and the highest coke burn-off 

rate (if you use an electrostatic 

precipitator) or the lowest average 

pressure drop and liquid-to-gas ratio (if 

you use a wet scrubber) measured 

during a test run that achieves the 

applicable PM emission limit. 

(f) The owner or operator of a FCCU 

or fluid coking unit that is exempt from 

the requirement to install and operate a 

CO CEMS pursuant to § 60.105a(g)(3) 

and that is subject to control device 

operating parameter limits in 

§ 60.102a(d) shall establish the limits 

based on the performance test results 

using the following procedures: 

(1) Reduce the temperature and O2

concentrations from the parameter 

monitoring systems to hourly averages 

for each test run. 

(2) Determine the operating limit for 

temperature and O2 concentrations as 

the lowest hourly average temperature 

and O2 concentration measured during 

a test run achieving the emission 

limitation. 

(g) The owner or operator shall 

determine compliance with the SO2 and 

H2S emissions limits for sulfur recovery 

plants in § 60.102a(e) using the 

following methods and procedures: 

(1) Method 1 for sample and velocity 

traverses. 

(2) Method 2 for velocity and 

volumetric flow rate. 

(3) Method 3, 3A, or 3B for gas 

analysis. The method ASME PTC 19.10–

1981, ‘‘Flue and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B. 

(4) Method 6, 6A, or 6C to determine 

the SO2 concentration. The method 

ASME PTC 19.10–1981, ‘‘Flue and 

Exhaust Gas Analyses,’’ (incorporated 

by reference—see § 60.17) is an 

acceptable alternative to EPA Method 6 

or 6A. 

(5) Method 15 or 15A to determine the 

reduced sulfur compounds and H2S 

concentrations. 

(i) Each run consists of 16 samples 

taken over a minimum of 3 hours. 

(ii) The owner or operator shall 

calculate the average H2S concentration 

after correcting for moisture and O2 as 

the arithmetic average of the H2S 

concentration for each sample during 

the run (ppmv, dry basis, corrected to 0 

percent excess air). 

(iii) The owner or operator shall 

calculate the SO2 equivalent for each 

run after correcting for moisture and O2

as the arithmetic average of the SO2

equivalent of reduced sulfur compounds 

for each sample during the run (ppmv, 

dry basis, corrected to 0 percent excess 

air). 

(iv) The owner or operator shall use 

Equation 4 of this section to adjust 

pollutant concentrations to 0 percent O2

or 0 percent excess air. 

(6) The owner or operator shall 

calculate the combined SO2 and 

reduced sulfur compound 

concentrations for a sulfur recovery 

plant with a capacity greater than 20 

LTD that is subject to the emissions 

limit in § 60.102a(e)(1) using Equation 5 

of this section: 

C CC combined SO M SO eq M = + 2 6 2 15 , _, ( ) Eq. 5

Where: 

Ccombined = Cmbined SO2 and reduced sulfur 

compounds concentration, ppmv, dry 

basis, at 0 percent excess air; 

CSO2,M6 = SO2 concentration in the exhaust 

stream measured using Method 6, 6A, or 

6C as required in paragraph (c)(4) of this 

section, ppmv, dry basis at 0 percent 

excess air; The method ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 6 or 6A. 

CSO2_eq,M15 = SO2 equivalent concentration of 

reduced sulfur compounds in the 

exhaust stream measured using Method 

15 or 15A as required in paragraph (c)(5) 

of this section, ppmv, dry basis at 0 

percent excess air. The method ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 15A. 

(7) The owner or operator shall 

calculate the mass sulfur emission 

percentage for a sulfur recovery plant 

with a capacity of 10 LTD or less that 

is subject to the emissions limit in 

§ 60.102a(e)(2) using the following 

procedures: 

(i) Calculate the combined SO2 and 

reduced sulfur compound concentration 

using Equation 5 of this section. 

(ii) Calculate the mass sulfur 

emissions percentage using Equation 6 

of this section: 

F

K

M S emit

sulfur

, = × % ( ) 4 100 C Q Eq. 6 combined sd

Where: 

FS,emit = Mass fraction of sulfur emitted, 

weight percent; 

K4 = Conversion factor, 0.5 [lbs S/lb SO2] × 

60 [min/hr] × 1.66E–7 [lbs/dscf per 

ppmv]/2,240 [lbs/long ton] = 2.22E–9 

(lbs S·min·long ton·lbs/dscf)/(lbs 

SO2·hr·lb·ppmv); 

Ccombined = Combined SO2 and reduced sulfur 

compounds concentration, ppmv, dry 

basis at 0 percent excess air; 

Qsd = Volumetric flow rate of effluent gas 

dscf/min; and 

Msulfur = Mass rate of sulfur recovery, long 

tons/hr. 

(h) The owner or operator of a sulfur 

recovery plant that is subject to the 

operating limits in § 60.102a(f) shall 

establish the limits based on the results 

of the performance test according to the 

following procedures: 

(1) Reduce the temperature and O2

concentrations from the CPMS to hourly 

averages for each test run; 

(2) Determine the operating limit for 

temperature and O2 concentrations as 

the lowest hourly average temperature 

and O2 concentration measured during 

a test run achieving the H2S emissions 

limit. 

(i) The owner or operator shall 

determine compliance with the SO2 and 

NOX emissions limits in § 60.102a(g) for 

a process heater or other fuel gas 

combustion device according to the 

following test methods and procedures: 


ycherry on PROD1PC64 with PROPOSALS2EP14MY07.004</MATH> EP14MY07.005</MATH>
27212 Federal Register / Vol. 72, No. 92 / Monday, May 14, 2007 / Proposed Rules 

(1) Method 1 for sample and velocity 

traverses; 

(2) Method 2 for velocity and 

volumetric flow rate; 

(3) Method 3, 3A, or 3B for gas 

analysis. The method ASME PTC 19.10–

1981, ‘‘Flue and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B.; 

(4) Method 6, 6A, or 6C to determine 

the SO2 concentration. The method 

ASME PTC 19.10–1981, ‘‘Flue and 

Exhaust Gas Analyses,’’ (incorporated 

by reference—see § 60.17) is an 

acceptable alternative to EPA Method 6 

or 6A. 

(i) The performance test consists of 3 

valid test runs; the duration of each test 

run must be no less than 1 hour. 

(ii) If a single fuel gas combustion 

device having a common source of fuel 

gas is monitored as allowed under 

§ 60.107a(a)(2)(v), only one performance 

test is required. That is, performance 

tests are not required when a new 

affected fuel gas combustion device is 

added to a common source of fuel gas 

that previously demonstrated 

compliance. 

(5) Method 7, 7A, 7C, 7D, or 7E for 

moisture content and for the 

concentration of NOX calculated as NO2; 

the duration of each test run must be no 

less than 4 hours. 

(j) The owner or operator shall 

determine compliance with the H2S or 

TRS emissions limit in § 60.102a(h) for 

a process heater or other fuel gas 

combustion device according to the 

following test methods and procedures: 

(1) Method 1 for sample and velocity 

traverses; 

(2) Method 2 for velocity and 

volumetric flow rate; 

(3) Method 3, 3A, or 3B for gas 

analysis. The method ASME PTC 19.10–

1981, ‘‘Flue and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B.; 

(4) Method 11, 15, 15A, or 16 for 

determining the H2S concentration for 

affected plants using an H2S monitor as 

specified in § 60.107a(a)(1) or Method 

16 for determining the TRS 

concentration. The method ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 15A. 

(i) For Method 11, the sampling time 

and sample volume must be at least 10 

minutes and 0.010 dscm (0.35 dscf). 

Two samples of equal sampling times 

must be taken at about 1-hour intervals. 

The arithmetic average of these two 

samples constitute a run. For most fuel 

gases, sampling times exceeding 20 

minutes may result in depletion of the 

collection solution, although fuel gases 

containing low concentrations of H2S 

may necessitate sampling for longer 

periods of time. 

(ii) For Method 15 or 16, at least three 

injects over a 1-hour period constitutes 

a run. 

(iii) For Method 15A, a 1-hour sample 

constitutes a run. The method ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 15A. 

(iv) If monitoring is conducted at a 

single point in a common source of fuel 

gas as allowed under § 60.107a(a)(1)(iv), 

only one performance test is required. 

That is, performance tests are not 

required when a new affected fuel gas 

combustion device is added to a 

common source of fuel gas that 

previously demonstrated compliance. 

§ 60.105a Monitoring of emissions and 

operations for fluid catalytic cracking units 

(FCCU) and fluid coking units. 

(a) FCCU and fluid coking units 

subject to PM emissions limit. Each 

owner or operator subject to the 

provisions of this subpart shall monitor 

each FCCU and fluid coking unit subject 

to the PM emissions limit in 

§ 60.102a(b)(1) according to the 

requirements in paragraph (b), (c), or (d) 

of this section. 

(b) Control device operating 

parameters. Each owner or operator of 

a FCCU or fluid coking unit subject to 

the PM emissions limit in 

§ 60.102a(b)(1) shall comply with the 

requirements in paragraphs (b)(1) 

through (3) of this section. 

(1) The owner or operator shall 

install, operate, and maintain 

continuous parameter monitor systems 

(CPMS) to measure and record operating 

parameters for each control device 

according to the requirements in 

paragraph (b)(1)(i) through (iii) of this 

section. 

(i) For units controlled using an 

electrostatic precipitator, the owner or 

operator shall use CPMS to measure and 

record the hourly average total power 

input and secondary voltage to the 

control device. 

(ii) For units controlled using a wet 

scrubber, the owner or operator shall 

use CPMS to measure and record the 

hourly average pressure drop, liquid 

feed rate, and exhaust gas flow rate. 

(iii) The owner or operator shall 

install, operate, and maintain each 

CPMS according to the manufacturer’s 

specifications and requirements. 

(2) The owner or operator shall 

install, operate, calibrate, and maintain 

an instrument for continuously 

monitoring the concentrations of CO2, 

O2 (dry basis), and if needed, CO in the 

exhaust gases prior to any control or 

energy recovery system that burns 

auxiliary fuels. 

(i) The owner or operator shall install, 

operate, and maintain each monitor 

according to Performance Specification 

3 (40 CFR part 60, appendix B). 

(ii) The owner or operator shall 

conduct performance evaluations of 

each CO2, O2, and CO monitor according 

to the requirements in § 60.13(c) and 

Performance Specification 3. The owner 

or operator shall use Method 3 for 

conducting the relative accuracy 

evaluations. 

(iii) The owner or operator shall 

comply with the quality assurance 

requirements of procedure 1 in 40 CFR 

part 60, appendix F, including quarterly 

accuracy determinations for CO2 and CO 

monitors, annual accuracy 

determinations for O2 monitors, and 

daily calibration drift tests. 

(3) The owner or operator shall 

determine and record the average coke 

burn-off rate and hours of operation for 

each FCCU or fluid coking unit using 

the procedures in § 60.104a(d)(4)(vii). 

(c) Bag leak detection systems. Each 

owner or operator of a FCCU or fluid 

coking unit shall install, operate, and 

maintain a bag leak detection system for 

each baghouse that is used to comply 

with the PM emissions limit in 

§ 60.102a(b)(1) according to paragraph 

(c)(1) of this section; prepare and 

operate by a site-specific monitoring 

plan according to paragraph (c)(2) of 

this section; take corrective action 

according to paragraph (c)(3) of this 

section; and record information 

according to paragraph (c)(4) of this 

section. 

(1) Each bag leak detection system 

must meet the specifications and 

requirements in paragraphs (c)(1)(i) 

through (viii) of this section. 

(i) The bag leak detection system must 

be certified by the manufacturer to be 

capable of detecting PM emissions at 

concentrations of 0.00044 grains per 

actual cubic foot or less. 

(ii) The bag leak detection system 

sensor must provide output of relative 

PM loadings. The owner or operator 

shall continuously record the output 

from the bag leak detection system using 

electronic or other means (e.g., using a 

strip chart recorder or a data logger). 

(iii) The bag leak detection system 

must be equipped with an alarm system 

that will sound when the system detects 

an increase in relative particulate 

loading over the alarm set point 

established according to paragraph 

(c)(1)(iv) of this section, and the alarm 

must be located such that it can be 


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heard by the appropriate plant 

personnel. 

(iv) In the initial adjustment of the bag 

leak detection system, the owner or 

operator must establish, at a minimum, 

the baseline output by adjusting the 

sensitivity (range) and the averaging 

period of the device, the alarm set 

points, and the alarm delay time. 

(v) Following initial adjustment, the 

owner or operator shall not adjust the 

averaging period, alarm set point, or 

alarm delay time without approval from 

the Administrator or delegated authority 

except as provided in paragraph 

(c)(1)(vi) of this section. 

(vi) Once per quarter, the owner or 

operator may adjust the sensitivity of 

the bag leak detection system to account 

for seasonal effects, including 

temperature and humidity, according to 

the procedures identified in the sitespecific monitoring plan required by 

paragraph (c)(2) of this section. 

(vii) The owner or operator shall 

install the bag leak detection sensor 

downstream of the baghouse and 

upstream of any wet scrubber. 

(viii) Where multiple detectors are 

required, the system’s instrumentation 

and alarm may be shared among 

detectors. 

(2) The owner or operator shall 

develop and submit to the 

Administrator for approval a sitespecific monitoring plan for each 

baghouse and bag leak detection system. 

The owner or operator shall operate and 

maintain each baghouse and bag leak 

detection system according to the sitespecific monitoring plan at all times. 

Each monitoring plan must describe the 

items in paragraphs (c)(2)(i) through 

(vii) of this section. 

(i) Installation of the bag leak 

detection system; 

(ii) Initial and periodic adjustment of 

the bag leak detection system, including 

how the alarm set-point will be 

established; 

(iii) Operation of the bag leak 

detection system, including quality 

assurance procedures; 

(iv) How the bag leak detection 

system will be maintained, including a 

routine maintenance schedule and spare 

parts inventory list; 

(v) How the bag leak detection system 

output will be recorded and stored; 

(vi) Corrective action procedures as 

specified in paragraph (c)(3) of this 

section. In approving the site-specific 

monitoring plan, the Administrator or 

delegated authority may allow owners 

and operators more than 3 hours to 

alleviate a specific condition that causes 

an alarm if the owner or operator 

identifies in the monitoring plan this 

specific condition as one that could lead 

to an alarm, adequately explains why it 

is not feasible to alleviate this condition 

within 3 hours of the time the alarm 

occurs, and demonstrates that the 

requested time will ensure alleviation of 

this condition as expeditiously as 

practicable; and 

(vii) How the baghouse system will be 

operated and maintained, including 

monitoring of pressure drop across 

baghouse cells and frequency of visual 

inspections of the baghouse interior and 

baghouse components such as fans and 

dust removal and bag cleaning 

mechanisms. 

(3) For each bag leak detection 

system, the owner or operator shall 

initiate procedures to determine the 

cause of every alarm within 1 hour of 

the alarm. Except as provided in 

paragraph (c)(2)(vi) of this section, the 

owner or operator shall alleviate the 

cause of the alarm within 3 hours of the 

alarm by taking whatever corrective 

action(s) are necessary. Corrective 

actions may include, but are not limited 

to the following: 

(i) Inspecting the baghouse for air 

leaks, torn or broken bags or filter 

media, or any other condition that may 

cause an increase in particulate 

emissions; 

(ii) Sealing off defective bags or filter 

media; 

(iii) Replacing defective bags or filter 

media or otherwise repairing the control 

device; 

(iv) Sealing off a defective baghouse 

compartment; 

(v) Cleaning the bag leak detection 

system probe or otherwise repairing the 

bag leak detection system; or 

(vi) Shutting down the process 

producing the particulate emissions. 

(4) The owner or operator shall 

maintain records of the information 

specified in paragraphs (c)(4)(i) through 

(iii) of this section for each bag leak 

detection system. 

(i) Records of the bag leak detection 

system output; 

(ii) Records of bag leak detection 

system adjustments, including the date 

and time of the adjustment, the initial 

bag leak detection system settings, and 

the final bag leak detection system 

settings; and 

(iii) The date and time of all bag leak 

detection system alarms, the time that 

procedures to determine the cause of the 

alarm were initiated, the cause of the 

alarm, an explanation of the actions 

taken, the date and time the cause of the 

alarm was alleviated, and whether the 

alarm was alleviated within 3 hours of 

the alarm. 

(d) Continuous emissions monitoring 

systems (CEMS). The owner or operator 

of a FCCU or fluid coking unit subject 

to the PM emissions limit (gr/dscf) in 

§ 60.102a(b)(1) shall install, operate, 

calibrate, and maintain an instrument 

for continuously monitoring and 

recording the concentration (0 percent 

excess air) of PM in the exhaust gases 

prior to release to the atmosphere. The 

monitor must include an O2 monitor for 

correcting the data for excess air. 

(1) The owner or operator shall 

install, operate, and maintain each PM 

monitor according to Performance 

Specification 11 of 40 CFR part 60, 

appendix B. The span value of this PM 

monitor is 0.08 gr/dscf PM. 

(2) The owner or operator shall 

conduct performance evaluations of 

each PM monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 11. The 

owner or operator shall use Method 5 

for conducting the relative accuracy 

evaluations. 

(3) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of 40 CFR part 60, 

appendix B. The span value of this O2

monitor is 25 percent. 

(4) The owner or operator shall 

conduct performance evaluations of 

each O2 monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 3. Method 3, 

3A, or 3B shall be used for conducting 

the relative accuracy evaluations. The 

method ASME PTC 19.10–1981, ‘‘Flue 

and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B. 

(5) The owner or operator shall 

comply with the quality assurance 

requirements of procedure 2 in 40 CFR 

part 60, appendix F for each PM CEMS 

and procedure 1 in 40 CFR part 60, 

appendix F for each O2 monitor, 

including quarterly accuracy 

determinations for each PM monitor, 

annual accuracy determinations for each 

O2 monitor, and daily calibration drift 

tests. 

(e) FCCU and fluid coking units 

subject to NOX limit. Each owner or 

operator of a FCCU or fluid coking unit 

subject to the NOX emissions limit in 

§ 60.102a(b)(2) shall install, operate, 

calibrate, and maintain an instrument 

for continuously monitoring and 

recording the concentration by volume 

(dry basis, 0 percent excess air) of NOX

emissions into the atmosphere. The 

monitor must include an O2 monitor for 

correcting the data for excess air. 

(1) The owner or operator shall 

install, operate, and maintain each NOX

monitor according to Performance 

Specification 2 (40 CFR part 60, 


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appendix B). The span value of this 

NOX monitor is 200 ppmv NOX. 

(2) The owner or operator shall 

conduct performance evaluations of 

each NOX monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 2. The owner 

or operator shall use Methods 7, 7A, 7C, 

7D, or 7E (40 CFR part 60, appendix A) 

for conducting the relative accuracy 

evaluations. 

(3) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of 40 CFR part 60, 

appendix B. The span value of this O2

monitor is 25 percent. 

(4) The owner or operator shall 

conduct performance evaluations of 

each O2 monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 3. Method 3, 

3A, or 3B shall be used for conducting 

the relative accuracy evaluations. The 

method ASME PTC 19.10–1981, ‘‘Flue 

and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B. 

(5) The owner or operator shall 

comply with the quality assurance 

requirements of procedure 1 in 40 CFR 

part 60, appendix F for each SO2 and O2

monitor, including quarterly accuracy 

determinations for SO2 monitors, annual 

accuracy determinations for O2

monitors, and daily calibration drift 

tests. 

(f) FCCU and fluid coking units 

subject to SO2 limit. The owner or 

operator a FCCU and fluid coking unit 

subject to the SO2 emissions limit in 

§ 60.102a(b)(3) shall install, operate, 

calibrate, and maintain an instrument 

for continuously monitoring and 

recording the concentration by volume 

(dry basis, corrected to 0 percent excess 

air) of SO2 emissions into the 

atmosphere. The monitor shall include 

an O2 monitor for correcting the data for 

excess air. 

(1) The owner or operator shall 

install, operate, and maintain each SO2

monitor according to Performance 

Specification 2 (40 CFR part 60, 

appendix B). The span value of this SO2

monitor is 200 ppmv SO2. 

(2) The owner or operator shall 

conduct performance evaluations of 

each SO2 monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 2. The owner 

or operator shall use Methods 6, 6A, or 

6C (40 CFR part 60, appendix A) for 

conducting the relative accuracy 

evaluations. The method ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 6 or 6A. 

(3) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of 40 CFR part 60, 

appendix B. The span value of this O2

monitor is 10 percent. 

(4) The owner or operator shall 

conduct performance evaluations of 

each O2 monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 3. Method 3, 

3A, or 3B shall be used for conducting 

the relative accuracy evaluations. The 

method ASME PTC 19.10–1981, ‘‘Flue 

and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B. 

(5) The owner or operator shall 

comply with the quality assurance 

requirements of procedure 1 in 40 CFR 

part 60, appendix F for each SO2 and O2

monitor, including quarterly accuracy 

determinations for SO2 monitors, annual 

accuracy determinations for O2

monitors, and daily calibration drift 

tests. 

(g) FCCU and fluid coking units 

subject to CO emissions limit. Except as 

specified in paragraph (g)(3) of this 

section, the owner or operator shall 

install, operate, calibrate, and maintain 

an instrument for continuously 

monitoring and recording the 

concentration by volume (dry basis) of 

CO emissions into the atmosphere from 

each FCCU and fluid coking unit subject 

to the CO emissions limit in 

§ 60.102a(b)(4). 

(1) The owner or operator shall 

install, operate, and maintain each CO 

monitor according to Performance 

Specification 4 (40 CFR part 60, 

appendix B). The span value for this 

instrument is 1,000 ppm CO. 

(2) The owner or operator shall 

conduct performance evaluations of 

each CO monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 4 (40 CFR 

part 60, appendix A). The owner or 

operator shall use Methods 10, 10A, or 

10B for conducting the relative accuracy 

evaluations using the procedures 

specified in § 60.106a(b). 

(3) A CO CEMS need not be installed 

if the owner or operator demonstrates 

that the average CO emissions are less 

than 50 ppm (dry basis) and also 

submits a written request for exemption 

to the Administrator and receives such 

an exemption. 

(i) The demonstration shall consist of 

continuously monitoring CO emissions 

for 30 days using an instrument that 

meets the requirements of Performance 

Specification 4 (40 CFR part 60, 

appendix B). The span value shall be 

100 ppm CO instead of 1,000 ppm, and 

the relative accuracy limit shall be 10 

percent of the average CO emissions or 

5 ppm CO, whichever is greater. For 

instruments that are identical to Method 

10 and employ the sample conditioning 

system of Method 10A, the alternative 

relative accuracy test procedure in 

section 10.1 of Performance 

Specification 2 may be used in place of 

the relative accuracy test. 

(ii) The written request for exemption 

must include descriptions of the CPMS 

for exhaust gas temperature and O2

monitor required in paragraph (g)(4) of 

this section and operating limits for 

those parameters to ensure combustion 

conditions remain similar to those that 

exist during the demonstration period. 

(4) The owner or operator of a FCCU 

or fluid coking unit that is exempted 

from the requirement to install and 

operate a CO CEMS in paragraph (g)(3) 

of this section shall install, operate, 

calibrate, and maintain CPMS to 

measure and record the operating 

parameters in paragraph (g)(4)(i) or (ii) 

of this section. The owner or operator 

shall install, operate, and maintain each 

CPMS according to the manufacturer’s 

specifications. 

(i) For a FCCU or fluid coking unit 

with no post-combustion control device, 

the temperature and O2 concentration of 

the exhaust gas stream exiting the unit. 

(ii) For a FCCU or fluid coking unit 

with a post-combustion control device, 

the temperature and O2 concentration of 

the exhaust gas stream exiting the 

control device. 

(h) Excess emissions. For the purpose 

of reports required by § 60.7(c), periods 

of excess emissions for a FCCU or fluid 

coking unit subject to the emissions 

limitations in § 60.102a(b) are defined as 

specified in paragraphs (h)(1) through 

(4) of this section. Note: Determine all 

averages as the arithmetic average of the 

applicable 1-hour averages, e.g., 

determine the rolling 3-hour average as 

the arithmetic average of three 

contiguous 1-hour averages. 

(1) All 24-hour periods during which 

the average PM control device operating 

characteristics, as measured by the 

continuous monitoring systems under 

§ 60.105a(b)(1), fall below the levels 

established during the performance test. 

Alternatively, if a PM CEMS is used 

according to § 60.105a(d), all 7-day 

periods during which the average PM 

emission rate, as measured by the 

continuous PM monitoring system 

under § 60.105a(a)(2) exceeds 0.020 gr/ 

dscf. 

(2) All rolling 7-day periods during 

which the average concentration of NOX


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as measured by the NOX CEMS under 

§ 60.105a(e) exceeds 80 ppmv. 

(3) All rolling 7-day periods during 

which the average concentration of SO2

as measured by the SO2 CEMS under 

§ 60.105a(f) exceeds 50 ppmv, and all 

rolling 365-day periods during which 

the average concentration of SO2 as 

measured by the SO2 CEMS exceeds 25 

ppmv. 

(4) All 1-hour periods during which 

the average CO concentration as 

measured by the CO continuous 

monitoring system under § 60.105a(g) 

exceeds 500 ppmv or, if applicable, all 

1-hour periods during which the 

average temperature and O2

concentration as measured by the 

continuous monitoring systems under 

§ 60.105a(g)(4) fall below the operating 

limits established during the 

performance test. 

§ 60.106a Monitoring of emissions and 

operations for sulfur recovery plants. 

(a) Sulfur recovery plants. The owner 

or operator of a sulfur recovery plant 

shall comply with the applicable 

requirements in paragraphs (a)(1) 

through (5) of this section. 

(1) The owner or operator of a sulfur 

recovery plant with a capacity greater 

than 20 LTD that is subject to an SO2

emissions limit in § 60.102a(e)(1) shall 

install, operate, calibrate, and maintain 

an instrument using an air or O2

dilution and oxidation system to 

convert any reduced sulfur to SO2 for 

continuously monitoring and recording 

the concentration (dry basis, 0 percent 

excess air) of the total resultant SO2. 

The monitor must include an O2

monitor for correcting the data for 

excess O2. 

(i) The owner or operator shall install, 

operate, and maintain each SO2 CEMS 

according to Performance Specification 

2 (40 CFR part 60, appendix B). The 

span value for this monitor is 500 ppm 

SO2. 

(ii) The owner or operator shall 

conduct performance evaluations of 

each SO2 monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 2 (40 CFR 

part 60, appendix B). The owner or 

operator shall use Methods 6 or 6C and 

15 or 15A (40 CFR part 60, appendix A) 

for conducting the relative accuracy 

evaluations. The method ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by referencesee § 60.17) is an acceptable alternative 

to EPA Method 6 or 15A. 

(iii) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 (40 CFR part 60, 

appendix B). The span value for the O2

monitor is 25 percent O2. 

(iv) The owner or operator shall 

conduct performance evaluations for the 

O2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 3. The owner 

or operator shall use Methods 3, 3A, or 

3B for conducting the relative accuracy 

evaluations. The method ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by referencesee § 60.17) is an acceptable alternative 

to EPA Method 3B. 

(v) The owner or operator shall 

comply with the applicable quality 

assurance procedures of 40 CFR part 60, 

appendix F for each monitor, including 

quarterly accuracy determinations for 

each SO2 monitor, annual accuracy 

determinations for each O2 monitor, and 

daily calibration drift determinations. 

(2) The owner or operator of a sulfur 

recovery plant with a capacity of less 

than 20 LTD that is subject to an SO2

emissions limit in § 60.102a(e)(2) shall 

install, operate, calibrate, and maintain 

an instrument using an air or O2

dilution and oxidation system to 

convert any reduced sulfur to SO2 for 

continuously monitoring and recording 

the concentration of the total resultant 

SO2 and an instrument for continuously 

monitoring the volumetric flow rate of 

gases released to the atmosphere. The 

SO2 monitor must include an O2

monitor for correcting the data for 

excess O2. 

(i) The owner or operator shall install, 

operate, and maintain each SO2 monitor 

according to Performance Specification 

2 (40 CFR part 60, appendix B). The 

span value for the SO2 monitor shall be 

set at 125 percent of the maximum 

estimated hourly potential SO2 emission 

concentration that translates to the 

applicable emission limit at full sulfur 

production capacity. 

(ii) The owner or operator shall 

conduct performance evaluations for the 

SO2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 2 (40 CFR 

part 60, appendix B). Methods 6, 6A, 

6C, 15, or 15A (40 CFR part 60, 

appendix A) shall be used for 

conducting the relative accuracy 

evaluations. The method ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by referencesee § 60.17) is an acceptable alternative 

to EPA Method 6, 6A, or 15A. 

(iii) The owner or operator shall 

install, operate, and maintain each O2

monitor and flow monitor according to 

Performance Specification 3 (40 CFR 

part 60, appendix B). The span value for 

the O2 monitor is 25 percent O2. The 

span value for the volumetric flow 

monitor shall be set at 125 percent of 

the maximum estimated volumetric 

flow rate when the unit is operating at 

full process capacity. 

(iv) The owner or operator shall 

conduct performance evaluations for the 

O2 monitor and flow monitor according 

to the requirements of § 60.13(c) and 

Performance Specification 3. The owner 

or operator shall use Methods 3, 3A, or 

3B for conducting the relative accuracy 

evaluations. The method ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by referencesee § 60.17) is an acceptable alternative 

to EPA Method 3B. 

(v) The owner or operator shall 

comply with the applicable quality 

assurance requirements in 40 CFR part 

60, appendix F for each monitor, 

including quarterly accuracy 

determinations for SO2 and flow 

monitors, annual accuracy 

determinations for O2 monitors, and 

daily calibration drift tests. 

(3) Except as provided under 

paragraph (a)(4) of this section, the 

owner or operator of a sulfur recovery 

plant that is subject to the H2S 

emissions limit in § 60.102a(e)(3) shall 

install, operate, calibrate, and maintain 

an instrument for continuously 

monitoring and recording the 

concentration of H2S (dry basis, 0 

percent excess air) emissions into the 

atmosphere. The H2S monitor must 

include an O2 monitor for correcting the 

data for excess O2. 

(i) The owner or operator shall install, 

operate, and maintain each H2S monitor 

according to Performance Specification 

7 (40 CFR part 60, appendix B). The 

span value for this instrument is 20 

ppmv H2S. 

(ii) The owner or operator shall 

conduct performance evaluations for 

each H2S monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 7 (40 CFR 

part 60, appendix B). The owner or 

operator shall use Method 11, 15, 15A, 

or 16 (40 CFR part 60, appendix A) for 

conducting the relative accuracy 

evaluations. The method ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 15A. 

(iii) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of 40 CFR part 60, 

appendix B. The span value of this O2

monitor is 25 percent. 

(iv) The owner or operator shall 

conduct performance evaluations of 

each O2 monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 3. Method 3, 


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3A, or 3B shall be used for conducting 

the relative accuracy evaluations. The 

method ASME PTC 19.10–1981, ‘‘Flue 

and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B. 

(v) The owner or operator shall 

comply with the quality assurance 

requirements of procedure 1 in 40 CFR 

part 60, appendix F for each monitor, 

including quarterly accuracy 

determinations and daily calibration 

drift tests. 

(4) In place of the H2S monitor 

required in paragraph (a)(3) of this 

section, the owner or operator of a 

sulfur recovery plant that is subject to 

the H2S emissions limit in 

§ 60.102a(e)(3) and that is equipped 

with an oxidation control system, 

incinerator, thermal oxidizer, or similar 

combustion device can use a CPMS for 

continuously monitoring and recording 

the temperature of the exhaust gases and 

an O2 monitor for continuously 

monitoring and recording the O2

concentration of the exhaust gases. 

(i) The span values for the 

temperature monitor is 1,500 °F. 

(ii) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 (40 CFR part 60, 

appendix B). The span value for the O2

monitor is 25 percent O2. 

(iii) The owner or operator shall 

conduct performance evaluations for the 

O2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 3. The owner 

or operator shall use Methods 3, 3A, or 

3B for conducting the relative accuracy 

evaluations. The method ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 3B. 

(iv) The owner or operator shall 

comply with the applicable quality 

assurance procedures in 40 CFR part 60, 

appendix F for each O2 monitor, 

including annual accuracy 

determinations. 

(5) The owner or operator of a sulfur 

recovery plant subject to an emissions 

limit in § 60.102a(b) shall determine and 

record the hourly sulfur production rate 

and hours of operation for each sulfur 

recovery plant. 

(b) Excess emissions. For the purpose 

of reports required by § 60.7(c), periods 

of excess emissions for sulfur recovery 

plants subject to the emissions 

limitations in § 60.102a(b) are defined as 

specified in paragraphs (b)(1) through 

(3) of this section. 

Note: Determine all averages as the 

arithmetic average of the applicable 1-hour 

averages, e.g., determine the rolling 3-hour 

average as the arithmetic average of three 

contiguous 1-hour averages. 

(1) For sulfur recovery plants with a 

capacity greater than 20 LTD, all 12- 

hour periods during which the average 

concentration of SO2 and reduced sulfur 

compounds as measured by the SO2

continuous monitoring system under 

paragraph (a)(1) of this section exceeds 

250 ppmv (dry basis, 0 percent excess 

air). 

(2) For sulfur recovery plants with a 

capacity of 20 LTD or less, all 12-hour 

periods during which the mass rate of 

SO2 and reduced sulfur compounds as 

measured by the continuous monitoring 

systems under paragraph (a)(2) of this 

section exceeds 1 percent of sulfur 

recovered. 

(3) All 1-hour periods during which 

the average concentration of H2S as 

measured by the H2S continuous 

monitoring system under paragraph 

(a)(3) of this section exceeds 10 ppm 

(dry basis, 0 percent excess air) or, if 

applicable, all 1-hour periods during 

which the average temperature and O2

concentration as measured by the 

continuous monitoring systems under 

paragraph (a)(4) of this section fall 

below the operating limits established 

during the performance test. 

§ 60.107a Monitoring of emissions and 

operations for process heaters and other 

fuel gas combustion devices. 

(a) Process heaters and other fuel gas 

combustion devices subject to SO2, H2S, 

or TRS limit. The owner or operator of 

a process heater or other fuel gas 

combustion device that is subject to the 

requirements in § 60.102(a)(g) shall 

comply with the requirements in 

paragraph (a)(1) of this section for SO2

emissions. Alternatively, the owner or 

operator of a process heater or other fuel 

gas combustion device who elects to 

satisfy the requirements of § 60.102(a)(h) 

shall comply with the requirements in 

paragraph (a)(2) of this section for H2S 

concentration limits or paragraph (a)(3) 

of this section for TRS concentration 

limits. Certain exceptions to all of these 

requirements are provided in paragraph 

(a)(4) of this section. 

(1) The owner or operator of a process 

heater or other fuel gas combustion 

device subject to the SO2 emissions 

limits in § 60.102a(g)(i) and (ii) shall 

install, operate, calibrate, and maintain 

an instrument for continuously 

monitoring and recording the 

concentration (dry basis, 0 percent 

excess air) of SO2 emissions into the 

atmosphere. The monitor must include 

an O2 monitor for correcting the data for 

excess air. 

(i) The owner or operator shall install, 

operate, and maintain each SO2 monitor 

according to Performance Specification 

2 (40 CFR part 60, appendix B). The 

span values for the SO2 monitor is 50 

ppm SO2. 

(ii) The owner or operator shall 

conduct performance evaluations for the 

SO2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 2 (40 CFR 

part 60, appendix B). The owner or 

operator shall use Methods 6, 6A, or 6C 

(40 CFR part 60, appendix A) for 

conducting the relative accuracy 

evaluations. The method ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by referencesee § 60.17) is an acceptable alternative 

to EPA Method 6 or 6A. Method 6 

samples shall be taken at a flow rate of 

approximately 2 liters/min for at least 

30 minutes. The relative accuracy limit 

shall be 20 percent or 4 ppm, whichever 

is greater, and the calibration drift limit 

shall be 5 percent of the established 

span value. 

(iii) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 (40 CFR part 60, 

appendix B). The span value for the O2

monitor is 25 percent O2. 

(iv) The owner or operator shall 

conduct performance evaluations for the 

O2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 3. The owner 

or operator shall use Methods 3, 3A, or 

3B for conducting the relative accuracy 

evaluations. The method ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by referencesee § 60.17) is an acceptable alternative 

to EPA Method 3B. 

(v) The owner or operator shall 

comply with the applicable quality 

assurance procedures in 40 CFR part 60, 

appendix F, including quarterly 

accuracy determinations for SO2

monitors, annual accuracy 

determinations for O2 monitors, and 

daily calibration drift tests. 

(vi) Process heaters or other fuel gas 

combustion devices having a common 

source of fuel gas may be monitored at 

only one location (i.e., after one of the 

combustion devices), if monitoring at 

this location accurately represents the 

SO2 emissions into the atmosphere from 

each of the combustion devices. 

(2) The owner or operator of a fuel gas 

combustion device subject to the H2S 

concentration limits in § 60.102a(h)(1) 

shall install, operate, calibrate, and 

maintain an instrument for 

continuously monitoring and recording 

the concentration by volume (dry basis) 

of H2S in the fuel gases before being 


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burned in any fuel gas combustion 

device. 

(i) The owner or operator shall install, 

operate, and maintain each H2S monitor 

according to Performance Specification 

7 (40 CFR part 60, appendix B). The 

span value for this instrument is 425 

ppmv H2S. 

(ii) The owner or operator shall 

conduct performance evaluations for 

each H2S monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 7 (40 CFR 

part 60, appendix B). The owner or 

operator shall use Method 11, 15, 15A, 

or 16 (40 CFR part 60, appendix A) for 

conducting the relative accuracy 

evaluations. The method ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by referencesee § 60.17) is an acceptable alternative 

to EPA Method 15A. 

(iii) The owner or operator shall 

comply with the applicable quality 

assurance procedures in 40 CFR part 60, 

appendix F for each H2S monitor. 

(iv) Fuel gas combustion devices 

having a common source of fuel gas may 

be monitored at only one location, if 

monitoring at this location accurately 

represents the concentration of H2S in 

the fuel gas being burned. 

(3) The owner or operator of a fuel gas 

combustion device subject to the TRS 

concentration limits in § 60.102a(h)(2) 

shall install, operate, calibrate, and 

maintain an instrument for 

continuously monitoring and recording 

the concentration by volume (dry basis) 

of TRS in the fuel gases before being 

burned in any fuel gas combustion 

device. 

(i) The owner or operator shall install, 

operate, and maintain each TRS monitor 

according to Performance Specification 

5 (40 CFR part 60, appendix B). The 

span value for this instrument is 425 

ppmv TRS. 

(ii) The owner or operator shall 

conduct performance evaluations for 

each TRS monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 5 (40 CFR 

part 60, appendix B). The owner or 

operator shall use Method 16 (40 CFR 

part 60, appendix A) for conducting the 

relative accuracy evaluations. 

(iii) The owner or operator shall 

comply with the applicable quality 

assurance procedures in 40 CFR part 60, 

appendix F for each TRS monitor. 

(iv) Fuel gas combustion devices 

having a common source of fuel gas may 

be monitored at only one location, if 

monitoring at this location accurately 

represents the concentration of TRS in 

the fuel gas being burned. 

(4) The owner or operator of a process 

heater or other fuel gas combustion 

device is not required to comply with 

paragraph (a)(1), paragraph (a)(2), or 

paragraph (a)(3) of this section for 

streams that are exempt under 

§ 60.102(a)(i) and fuel gas streams 

combusted in a process heater or other 

fuel gas combustion device that are 

inherently low in sulfur content. Fuel 

gas streams meeting one of the 

requirements in paragraphs (a)(4)(i) 

through (iv) of this section will be 

considered inherently low in sulfur 

content. 

(i) Pilot gas for heaters and flares. 

(ii) Gas streams that meet commercialgrade product specifications and have a 

sulfur content of 30 ppmv or less. 

(iii) Fuel gas streams produced in 

process units that are intolerant to 

sulfur contamination, such as fuel gas 

streams produced in the hydrogen plant, 

catalytic reforming unit, and 

isomerization unit. 

(iv) Other streams that an owner or 

operator demonstrates are low-sulfur 

according to the procedures in 

paragraph (b) of this section. 

(5) If the composition of an exempt 

stream changes such that it is no longer 

exempt under § 60.102(a)(i) or it no 

longer meets one of the criteria in 

paragraph (a)(4)(i) through (iv) of this 

section, the owner or operator must 

begin continuously monitoring the 

stream within 15 days of the change. 

(b) Exemption from H2S monitoring 

requirements for low-sulfur gas streams. 

The owner or operator of a fuel gas 

combustion device may apply for an 

exemption from the H2S monitoring 

requirements in paragraph (a)(2) of this 

section or the TRS monitoring 

requirements in paragraph (a)(3) of this 

section for a gas stream that is 

inherently low in sulfur content. A gas 

stream that is demonstrated to be lowsulfur is exempt from the monitoring 

requirements of paragraph (a)(2) or (a)(3) 

of this section until there are changes in 

operating conditions or stream 

composition. 

(1) The owner or operator shall 

submit to the Administrator a written 

application for an exemption from the 

H2S or TRS monitoring requirements. 

The owner or operator shall include the 

following information in the 

application: 

(i) A description of the gas stream/ 

system to be considered, including 

submission of a portion of the 

appropriate piping diagrams indicating 

the boundaries of the gas stream/system, 

and the affected fuel gas combustion 

device(s) to be considered; 

(ii) A statement that there are no 

crossover or entry points for sour gas 

(high H2S content) to be introduced into 

the gas stream/system (this should be 

shown in the piping diagrams); 

(iii) An explanation of the conditions 

that ensure low amounts of sulfur in the 

gas stream (i.e., control equipment or 

product specifications) at all times; 

(iv) The supporting test results from 

sampling the requested gas stream/ 

system demonstrating that the sulfur 

content is less than 5 ppm H2S or TRS. 

Sampling data must include, at 

minimum, 2 weeks of daily monitoring 

(14 grab samples) for frequently 

operated gas streams/systems; for 

infrequently operated gas streams/ 

systems, seven grab samples must be 

collected unless other additional 

information would support reduced 

sampling. The owner or operator shall 

use detector tubes (‘‘length-of-stain 

tube’’ type measurement) following the 

‘‘Gas Processor Association’s Test for 

Hydrogen Sulfide and Carbon Dioxide 

in Natural Gas Using Length of Stain 

Tubes,’’ 1986 Revision (incorporated by 

reference—see § 60.17) with ranges 0–

10/0–100 ppm (N =10/1) to test the 

applicant stream for H2S or Method 16 

(40 CFR part 60, appendix A) for TRS. 

(v) A description of how the 2 weeks 

(or seven samples for infrequently 

operated gas streams/systems) of 

monitoring results compares to the 

typical range of H2S concentration (fuel 

quality) expected for the gas stream/ 

system going to the affected fuel gas 

combustion device (e.g., the 2 weeks of 

daily detector tube results for a 

frequently operated loading rack 

included the entire range of products 

loaded out, and, therefore, should be 

representative of typical operating 

conditions affecting H2S or TRS content 

in the gas stream going to the loading 

rack flare). 

(2) Once EPA receives a complete 

application, the Administrator will 

determine whether an exemption is 

granted. The owner or operator shall 

continue to comply with the monitoring 

requirements in paragraph (a)(2) or 

paragraph (a)(3) of this section until an 

exemption is granted. 

(3) Once an exemption from H2S or 

TRS monitoring is granted, no further 

action is required unless refinery 

operating conditions change in such a 

way that affects the exempt gas stream/ 

system (e.g., the stream composition 

changes). If such a change occurs, the 

owner or operator shall follow the 

procedures in paragraph (b)(3)(i), 

(b)(3) (ii), or (b)(3)(iii) of this section. 

(i) If the operation change results in 

a sulfur content that is still within the 

range of concentrations included in the 

original application, the owner or 

operator shall conduct an H2S test on a 

grab sample (or TRS test, if applicable) 


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and record the results as proof that the 

concentration is still within the range. 

(ii) If the operation change results in 

a sulfur content that is outside the range 

of concentrations included in the 

original application, the owner or 

operator may submit a new application 

following the procedures of paragraph 

(b)(1) of this section within 60 days (or 

within 30 days after the seventh grab 

sample is tested for infrequently 

operated process units). 

(iii) If the operation change results in 

a sulfur content that is outside the range 

of concentrations included in the 

original application, and the owner or 

operator chooses not to submit a new 

application, the owner or operator must 

begin continuous H2S or TRS 

monitoring as required in paragraph 

(a)(2) or paragraph (a)(3) of this section 

within 15 days of the operation change. 

(c) Process heaters subject to NOX

limit. The owner or operator of a process 

heater subject to the NOX emissions 

limits in § 60.102a(g)(iii) shall install, 

operate, calibrate, and maintain an 

instrument for continuously monitoring 

and recording the concentration (dry 

basis, 0 percent excess air) of NOX

emissions into the atmosphere. The 

monitor must include an O2 monitor for 

correcting the data for excess air. 

(1) The owner or operator shall 

install, operate, and maintain each NOX

monitor according to Performance 

Specification 2 (40 CFR part 60, 

appendix B). The span value of this 

NOX monitor is 200 ppmv NOX. 

(2) The owner or operator shall 

conduct performance evaluations of 

each NOX monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 2. The owner 

or operator shall use Methods 7, 7A, 7C, 

7D, or 7E (40 CFR part 60, appendix A) 

for conducting the relative accuracy 

evaluations. The method ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by referencesee § 60.17) is an acceptable alternative 

to EPA Method 7 or 7C. 

(3) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of 40 CFR part 60, 

appendix B. The span value of this O2

monitor is 25 percent. 

(4) The owner or operator shall 

conduct performance evaluations of 

each O2 monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 3. Method 3, 

3A, or 3B shall be used for conducting 

the relative accuracy evaluations. The 

method ASME PTC 19.10–1981, ‘‘Flue 

and Exhaust Gas Analyses,’’

(incorporated by reference-see § 60.17) 

is an acceptable alternative to EPA 

Method 3B. 

(5) The owner or operator shall 

comply with the quality assurance 

requirements of procedure 1 in 40 CFR 

part 60, appendix F for each SO2 and O2

monitor, including quarterly accuracy 

determinations for SO2 monitors, annual 

accuracy determinations for O2

monitors, and daily calibration drift 

tests. 

(d) Excess emissions. For the purpose 

of reports required by § 60.7(c), periods 

of excess emissions for process heaters 

and other fuel gas combustion devices 

subject to the emissions limitations in 

§ 60.102a(g) or § 60.102a(h) are defined 

as specified in paragraphs (d)(1) and (3) 

of this section. Note: Determine all 

averages as the arithmetic average of the 

applicable 1-hour averages, e.g., 

determine the rolling 3-hour average as 

the arithmetic average of three 

contiguous 1-hour averages. 

(1) All rolling 3-hour periods during 

which the average concentration of SO2

as measured by the SO2 continuous 

monitoring system under paragraph 

(a)(1) of this section exceeds 20 ppmv, 

and all rolling 365-day periods during 

which the average concentration as 

measured by the SO2 continuous 

monitoring system under paragraph 

(a)(1) of this section exceeds 8 ppmv. 

(2) All rolling 3-hour periods during 

which the average concentration of H2S 

as measured by the H2S continuous 

monitoring system under paragraph 

(a)(2) of this section or the average 

concentration of TRS as measured by 

the TRS continuous monitoring system 

under paragraph (a)(3) of this section 

exceeds 160 ppmv, and all rolling 365- 

day periods during which the average 

concentration as measured by the H2S 

continuous monitoring system under 

paragraph (a)(2) or the average 

concentration as measured by the TRS 

continuous monitoring system under 

paragraph (a)(3) of this section exceeds 

60 ppmv. 

(3) All rolling 24-hour periods during 

which the average concentration of NOX

as measured by the NOX continuous 

monitoring system under paragraph (c) 

of this section exceeds 80 ppmv (dry 

basis, 0 percent excess air). 

§ 60.108a Recordkeeping and reporting 

requirements. 

(a) Each owner or operator subject to 

the emissions limitations in § 60.102a 

shall comply with the notification, 

recordkeeping, and reporting 

requirements in § 60.7 and other 

requirements as specified in this 

section. 

(b) Each owner or operator subject to 

an emissions limitation in § 60.102a 

shall notify the Administrator of the 

specific monitoring provisions of 

§§ 60.105a, 60.106a, and 60.107a with 

which the owner or operator seeks to 

comply. Notification shall be submitted 

with the notification of initial startup 

required by § 60.7(a)(3). 

Option 1 for paragraph (c): 

(c) The owner or operator shall 

maintain the following records: 

(1) A copy of the startup and 

shutdown plan required in § 60.103a(b). 

(2) Records of information to 

document conformance with operation 

and maintenance requirements in 

§ 60.105a(c). 

(3) Records of bag leak detection 

system alarms and corrective actions 

according to § 63.105a(c). 

(4) For each catalytic cracking unit or 

fluid coking unit subject to the 

monitoring requirements in 

§ 60.105a(b)(3), records of the average 

coke burn-off rate and hours of 

operation. 

(5) For each sulfur recovery plant 

subject to monitoring requirements in 

§ 60.106a(a)(5), records of the hourly 

sulfur production rate and hours of 

operation for each sulfur recovery plant. 

(6) For each fuel gas stream to which 

one of the exemptions listed in 

§ 60.107a(a)(4) applies, records of the 

specific exemption determined to apply 

for each stream. If the owner or operator 

applies for the exemption described in 

§ 60.107a(a)(4)(iv), the owner or 

operator must keep a copy of the 

application as well as the letter from the 

Administrator granting approval of the 

application. 

Option 2 for paragraph (c): 

(c) The owner or operator shall 

maintain the following records: 

(1) Records of information to 

document conformance with operation 

and maintenance requirements in 

§ 60.105a(c). 

(2) Records of bag leak detection 

system alarms and corrective actions 

according to § 63.105a(c). 

(3) For each catalytic cracking unit or 

fluid coking unit subject to the 

monitoring requirements in 

§ 60.105a(b)(3), records of the average 

coke burn-off rate and hours of 

operation. 

(4) For each sulfur recovery plant 

subject to monitoring requirements in 

§ 0.106a(a)(5), records of the hourly 

sulfur production rate and hours of 

operation for each sulfur recovery plant. 

(5) For each fuel gas stream to which 

one of the exemptions listed in 

§ 60.107a(a)(4) applies, records of the 

specific exemption determined to apply 

for each stream. If the owner or operator 

applies for the exemption described in 

§ 60.107a(a)(4)(iv), the owner or 


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operator must keep a copy of the 

application as well as the letter from the 

Administrator granting approval of the 

application. 

Option 1 for paragraph (d): 

(d) The owner or operator shall record 

and maintain records of discharges from 

any affected unit to the flare gas system. 

These records shall include: 

(1) A description of the discharge; 

(2) The date and time the discharge 

was first identified and the duration of 

the discharge; 

(3) The measured or calculated 

cumulative quantity of gas discharged 

over the discharge duration. If the 

discharge duration exceeds 24 hours, 

record the discharge quantity for each 

24 hour period. Engineering 

calculations are allowed. 

(4) The measured or estimated 

concentration of H2S and SO2 of the 

stream discharged. Process knowledge 

can be used to make these estimates; 

(5) The cumulative quantity of H2S 

and SO2 released into the atmosphere. 

For releases controlled by flares or other 

fuel gas combustion units, assume 99 

percent conversion of H2S to SO2 and no 

reduction of SO2. 

(6) Results of any root-cause analysis 

conducted as required in § 60.103a(b). 

Option 2 for paragraph (d): 

(d) The owner or operator shall record 

and maintain records of discharges from 

any affected unit to the flare gas system. 

These records shall include: 

(1) A description of the discharge; 

(2) The date and time the discharge 

was first identified and the duration of 

the discharge; 

(3) The measured or calculated 

cumulative quantity of gas discharged 

over the discharge duration. If the 

discharge duration exceeds 24 hours, 

record the discharge quantity for each 

24 hour period. Engineering 

calculations are allowed. 

(4) The measured or estimated 

concentration of H2S and SO2 of the 

stream discharged. Process knowledge 

can be used to make these estimates; 

(5) The cumulative quantity of H2S 

and SO2 released into the atmosphere. 

For releases controlled by flares or other 

fuel gas combustion units, assume 99 

percent conversion of H2S to SO2 and no 

reduction of SO2. 

Option 1 for paragraph (e): 

(e) Each owner or operator subject to 

this subpart shall submit an excess 

emissions report for all periods of 

excess emissions according to the 

requirements of § 60.7(c) except that the 

report shall contain the information 

specified in paragraphs (e)(1) through 

(7) of this section. 

(1) The date that the exceedance 

occurred; 

(2) An explanation of the exceedance; 

(3) Whether the exceedance was 

concurrent with a startup, shutdown, or 

malfunction of a process unit or control 

system; and 

(4) A description of the corrective 

action taken, if any. 

(5) A root-cause summary report that 

provides the information described in 

paragraphs (d)(1) through (4) of this 

section for all discharges for which a 

root-cause analysis was required by 

§ 60.103a(b). 

(6) For any periods for which 

monitoring data are not available, any 

changes made in operation of the 

emission control system during the 

period of data unavailability which 

could affect the ability of the system to 

meet the applicable emission limit. 

Operations of the control system and 

affected facility during periods of data 

unavailability are to be compared with 

operation of the control system and 

affected facility before and following the 

period of data unavailability; and 

(7) A written statement, signed by a 

responsible official, certifying the 

accuracy and completeness of the 

information contained in the report. 

Option 2 for paragraph (e): 

(e) Each owner or operator subject to 

this subpart shall submit an excess 

emissions report for all periods of 

excess emissions according to the 

requirements of § 60.7(c) except that the 

report shall contain the information 

specified in paragraphs (e)(1) through 

(6) of this section. 

(1) The date that the exceedance 

occurred; 

(2) An explanation of the exceedance; 

(3) Whether the exceedance was 

concurrent with a startup, shutdown, or 

malfunction of a process unit or control 

system; 

(4) A description of the corrective 

action taken, if any. 

(5) For any periods for which 

monitoring data are not available, any 

changes were made in operation of the 

emission control system during the 

period of data unavailability which 

could affect the ability of the system to 

meet the applicable emission limit. 

Operations of the control system and 

affected facility during periods of data 

unavailability are to be compared with 

operation of the control system and 

affected facility before and following the 

period of data unavailability; 

(6) A written statement, signed by a 

responsible official, certifying the 

accuracy and completeness of the 

information contained in the report. 

(f) The owner or operator of an 

affected facility shall submit the reports 

required under this subpart to the 

Administrator semiannually for each 6- 

month period. All semiannual reports 

shall be postmarked by the 30th day 

following the end of each 6-month 

period. 

§ 60.109a Delegation of authority. 

(a) This subpart can be implemented 

and enforced by the U.S. EPA or a 

delegated authority such as a State, 

local, or tribal agency. You should 

contact your U.S. EPA Regional Office 

to find out if this subpart is delegated 

to a State, local, or tribal agency within 

your State. 

(b) In delegating implementation and 

enforcement authority of this subpart to 

a State, local, or tribal agency, the 

approval authorities contained in 

paragraphs (b)(1) through (4) of this 

section are retained by the 

Administrator of the U.S. EPA and are 

not transferred to the State, local, or 

tribal agency. 

(1) Approval of an alternative nonopacity emissions standard. 

(2) Approval of a major change to test 

methods under 40 CFR 60.8(b). A 

‘‘major change to test method’’ is 

defined in § 63.90. 

(3) Approval of a major change to 

monitoring under 40 CFR 60.13(i). A 

‘‘major change to monitoring’’ is defined 

in § 63.90. 

(4) Approval of a major change to 

recordkeeping/reporting under 40 CFR 

60.7(b) through (f). A ‘‘major change to 

recordkeeping/reporting’’ is defined in 

§ 63.90. 

[FR Doc. E7–8547 Filed 5–11–07; 8:45 am] 

BILLING CODE 6560–50–P 


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