Tuesday, 

June 24, 2008 

Part IV 

Environmental 

Protection Agency 

40 CFR Part 60 

Standards of Performance for Petroleum 

Refineries; Final Rule 


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35838 Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2007–0011; FRL–8563–2] 

RIN 2060–AN72 

Standards of Performance for 

Petroleum Refineries 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: EPA is issuing final 

amendments to the current Standards of 

Performance for Petroleum Refineries. 

This action also promulgates separate 

standards of performance for new, 

modified, or reconstructed process units 

at petroleum refineries. The final 

standards for new process units include 

emissions limitations and work practice 

standards for fluid catalytic cracking 

units, fluid coking units, delayed coking 

units, fuel gas combustion devices, and 

sulfur recovery plants. These final 

standards reflect demonstrated 

improvements in emissions control 

technologies and work practices that 

have occurred since promulgation of the 

current standards. 

DATES: These final rules are effective on 

June 24, 2008. The incorporation by 

reference of certain publications listed 

in the final rules is approved by the 

Director of the Federal Register as of 

June 24, 2008. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2007–0011. All 

documents in the docket are listed in 

the www.regulations.gov index. 

Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

or other information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

is not placed on the Internet and will be 

publicly available only in hard copy 

form. Publicly available docket 

materials are available either 

electronically in www.regulations.gov 

or in hard copy at the EPA Docket 

Center, Standards of Performance for 

Petroleum Refineries Docket, EPA West 

Building, 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 Air Docket 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 these final rules 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 Industry 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. 

B. Where can I get a copy of this 

document? 

In addition to being available in the 

docket, an electronic copy of this final 

action is available on the Worldwide 

Web (WWW) through the Technology 

Transfer Network (TTN). Following 

signature, a copy of this final 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. 

C. Judicial Review 

Under section 307(b)(1) of the Clean 

Air Act (CAA), judicial review of these 

final rules is available only by filing a 

petition for review in the United States 

Court of Appeals for the District of 

Columbia Circuit by August 25, 2008. 

Under section 307(b)(2) of the CAA, the 

requirements established by these final 

rules may not be challenged separately 

in any civil or criminal proceedings 

brought by EPA to enforce these 

requirements. 

Section 307(d)(7)(B) of the CAA 

further provides that ‘‘[o]nly an 

objection to a rule or procedure which 

was raised with reasonable specificity 

during the period for public comment 

(including any public hearing) may be 

raised during judicial review.’’ This 

section also provides a mechanism for 

us to convene a proceeding for 

reconsideration, ‘‘[i]f the person raising 

an objection can demonstrate to the EPA 

that it was impracticable to raise such 

objection within [the period for public 

comment] or if the grounds for such 

objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of the rule.’’ Any person 

seeking to make such a demonstration to 

us should submit a Petition for 

Reconsideration to the Office of the 

Administrator, U.S. EPA, Room 3000, 

Ariel Rios Building, 1200 Pennsylvania 

Ave., NW., Washington, DC 20460, with 

a copy to both the person(s) listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section, and the Associate 

General Counsel for the Air and 

Radiation Law Office, Office of General 

Counsel (Mail Code 2344A), U.S. EPA, 

1200 Pennsylvania Ave., NW., 

Washington, DC 20460. 

D. How is this document organized? 

The information presented in this 

preamble is organized as follows: 

I. General Information 

A. Does this action apply to me? 

B. Where can I get a copy of this 

document? 

C. Judicial Review 

D. How is this document organized? 

II. Background Information 

III. Summary of the Final Rules and Changes 

Since Proposal 

A. What are the final amendments to the 

standards for petroleum refineries (40 

CFR part 60, subpart J)? 

B. What are the final requirements for new 

fluid catalytic cracking units and new 

fluid coking units (40 CFR part 60, 

subpart Ja)? 

C. What are the final requirements for new 

sulfur recovery plants (40 CFR part 60, 

subpart Ja)? 

D. What are the final requirements for new 

fuel gas combustion devices (40 CFR part 

60, subpart Ja)? 

E. What are the final work practice 

standards (40 CFR part 60, subpart Ja)? 

F. What are the modification and 

reconstruction provisions? 

IV. Summary of Significant Comments and 

Responses 

A. PM Limits for Fluid Catalytic Cracking 

Units 

B. SO2 Limits for Fluid Catalytic Cracking 

Units 

C. NOX Limit for Fluid Catalytic Cracking 

Units 


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D. PM and SO2 Limits for Fluid Coking 

Units 

E. NOX Limit for Fluid Coking Units 

F. SO2 Limits for Sulfur Recovery Plants 

G. NOX Limit for Process Heaters 

H. Fuel Gas Combustion Devices 

I. Flares 

J. Delayed Coking Units 

K. Other Comments 

V. 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? 

VI. 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 and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

II. Background Information 

New source performance standards 

(NSPS) implement 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 long-term 

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. As a 

result of our periodic review of the 

NSPS for petroleum refineries (40 CFR 

part 60, subpart J), we proposed 

amendments to the current standards of 

performance and separate standards of 

performance for new process units (72 

FR 27278, May 14, 2007). In response to 

several requests, we extended the 60- 

day comment period from July 13, 2007, 

to August 27, 2007 (72 FR 35375, June 

28, 2007). We also issued a notice of 

data availability (NODA) (72 FR 69175, 

December 7, 2007) to notify the public 

that additional information had been 

added to the docket; the NODA also 

extended the public comment period on 

the proposed rule to January 7, 2008. 

We received a total of 38 comments 

from refineries, industry trade 

associations, and consultants; State and 

local environmental and public health 

agencies; environmental groups; and 

members of the public during the 

extended comment period, and 8 

additional comments on the NODA. 

These final rules reflect our full 

consideration of all of the comments we 

received. Detailed responses to the 

comments not included in this preamble 

are contained in the Response to 

Comments document which is included 

in the docket for this rulemaking. 

III. Summary of the Final Rules and 

Changes Since Proposal 

We are promulgating 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 

final standards in 40 CFR part 60, 

subpart Ja. For example, we are revising 

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. Consequently, these 

vapors are exempt from the sulfur 

dioxide (SO2) treatment standard in 40 

CFR 60.104(a)(1) and are not required to 

be monitored. We are also finalizing 

certain monitoring exemptions that we 

proposed for fuel gases that are 

identified as inherently low sulfur or 

demonstrated to contain a low sulfur 

content. See 40 CFR 60.105(a)(4)(iv). 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 final standards in 40 CFR part 60, 

subpart Ja include emission limits for 

fluid catalytic cracking units (FCCU), 

fluid coking units (FCU), sulfur recovery 

plants (SRP), and fuel gas combustion 

devices. Subpart Ja also includes work 

practice standards for reducing 

emissions of volatile organic 

compounds (VOC) from flares, 

minimizing SO2 emissions from fuel gas 

combustion devices and SRP, and for 

reducing emissions of VOC from 

delayed coking units. Only those 

affected facilities that commence 

construction, modification, or 

reconstruction after May 14, 2007 will 

be affected by the standards in subpart 

Ja. Units for which construction, 

modification, or reconstruction 

commenced on or before May 14, 2007 

must continue to comply with the 

applicable standards under the current 

NSPS in 40 CFR part 60, subpart J, as 

amended. 

A. What are the final amendments to 

the standards for petroleum refineries 

(40 CFR part 60, subpart J)? 

As proposed, we are amending the 

definition of ‘‘fuel gas’’ to specifically 

exclude 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 are still considered to be 

affected fuel gas combustion devices if 

they combust other gases that meet the 

definition of fuel gas, and all auxiliary 

fuel gas fired to these devices are subject 

to the fuel gas limit; however, 

continuous monitoring is not required 

for the vapors collected from wastewater 

or marine vessel loading operations that 

are being incinerated because these 

gases are not considered to be fuel gases 

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

CFR part 60, subpart J. 

We are also finalizing exemptions for 

certain fuel gas streams from all 

continuous monitoring requirements. 

See 40 CFR 60.105(a)(4)(iv). Monitoring 

is not required for combustion in a flare 

of process upset gases or flaring of gases 

from relief valve leakage or emergency 

malfunctions since these streams are 

exempt from the standard under 40 CFR 

60.104(a)(1). Additionally, monitoring is 

not required for inherently low sulfur 

fuel gas streams since the emissions 

generated by combusting such streams 

will necessarily be well below the 

standard. These streams include pilot 

gas flames, gas streams that meet 

commercial-grade product 

specifications with a sulfur content of 

30 parts per million by volume (ppmv) 

or less, fuel gases produced by process 


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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 are required to document the 

exemption for which each fuel gas 

stream applies and ensure that the 

stream remains qualified for that 

exemption. 

For accuracy in the calculation of the 

coke burn-off rate, we are revising 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) 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). This revision adds a fourth term 

to the coke burn-off rate equation to 

account for the use of O2-enriched air. 

Other revisions to the equation change 

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). 

We proposed to amend the definition 

of ‘‘Claus sulfur recovery plant’’ in 40 

CFR 60.101(i) to clarify that the SRP 

may consist of multiple units and that 

primary sulfur pits are considered part 

of the Claus SRP consistent with the 

Agency’s current position. Commenters 

expressed concern that change to a 40 

CFR part 60, subpart J definition that 

could lead to retroactive noncompliance. We disagree with those 

concerns as we believe the definition as 

currently written provides for such 

coverage. Nonetheless, we are not 

amending this definition in the final 

amendments for subpart J and will 

continue to address individual 

applicability issues under our 

applicability determination procedures. 

Similarly, we proposed revisions to the 

subpart J definitions of ‘‘oxidation 

control system’’ and ‘‘reduction control 

system’’ in 40 CFR 60.101(j) and 40 CFR 

60.101(k), respectively, to clarify that 

these systems were intended to recycle 

the sulfur back to the Claus SRP. The 

proposed amendments needlessly limit 

the types of tail gas treatment systems 

that can be used; therefore, we are not 

amending these definitions in the final 

amendments for subpart J. 

The final amendments also include 

technical corrections to fix references 

and other miscellaneous errors in 40 

CFR part 60, subpart J. Table 1 of this 

preamble describes the miscellaneous 

technical corrections not previously 

described in this preamble that are 

included in the amendments to subpart 

J. 

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

Section Technical correction and reason 

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

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

for sulfur feed 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 (one date for flares and another date for all other affected facilities); sources beginning construction, reconstruction, or modification after this date will be subject to 40 

CFR part 60, subpart Ja. 

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

60.104(b)(1) ............... Replace ‘‘sulfur dioxide’’ with ‘‘SO2’’ and replace ‘‘50 ppm by volume (vppm)’’ with ‘‘50 ppm by volume (ppmv)’’ for consistency in unit and acronym 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; replace ‘‘sulfur dioxide’’ with 

‘‘SO2’’ for consistency in acronym definition. 

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 S2 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 and add ‘‘for fuel gas combustion devices subject 

to § 60.104(a)(1)’’ after ‘‘paragraph (a)(3) of this section’’ 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; replace ‘‘sulfur dioxide’’ with ‘‘SO2’’ for consistency in acronym definition. 

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); add ‘‘The 

method ANSI/ASME PTC 19.10–1981, ‘‘Flue and Exhaust Gas Analyses,’’ (incorporated by reference—see § 60.17) is 

an acceptable alternative to EPA Method 6 of Appendix A–4 to part 60.’’ after the first sentence of this paragraph to 

include a voluntary consensus method. 

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). 

B. What are the final requirements for 

new fluid catalytic cracking units and 

new fluid coking units (40 CFR part 60, 

subpart Ja)? 

The final standards for new FCCU 

include emission limits for particulate 

matter (PM), SO2, nitrogen oxides 

(NOX), and carbon monoxide (CO). The 

final standards include no universal 

opacity limit because the opacity limit 

in 40 CFR part 60, subpart J is intended 

to ensure compliance with the PM limit. 

40 CFR part 60, subpart Ja requires that 

sources use direct PM monitoring, bag 

leak detection systems, or parameter 

monitoring (along with annual emission 

tests) to ensure compliance with the PM 

limit. A provision for a site-specific 

opacity operating limit is provided for 

units that meet the PM emission limits 

using a cyclone. 

For PM emissions from new FCCU 

and new FCU, we proposed a PM limit 

of 0.5 pounds (lb)/1,000 lb coke burnoff 

in the regenerator or (if a PM continuous 

emission monitoring system (CEMS) is 


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used), 0.020 grains per dry standard 

cubic feet (gr/dscf) corrected to 0 

percent excess air. We have revised the 

final PM standards to establish separate 

limits for modified or reconstructed 

FCCU (1 lb/1,000 lb coke burn or 0.040 

gr/dscf corrected to 0 percent excess air) 

and newly constructed FCCU (0.5 lb/ 

1,000 lb coke burn or 0.020 gr/dscf 

corrected to 0 percent excess air). The 

final PM limit for new, modified, or 

reconstructed FCU is 1 lb/1,000 lb coke 

burn or 0.040 gr/dscf corrected to 0 

percent excess air. 

Initial compliance with the PM 

emission limits for FCCU and FCU is 

determined using EPA Method 5, 5B or 

5F (40 CFR part 60, appendix A–3) 

instead of being restricted to only EPA 

Method 5 as previously proposed. 

Procedures for computing the PM 

emission rate using the total PM 

concentration, effluent gas flow rate, 

and coke burn-off rate are the same as 

in 40 CFR part 60, subpart J, as 

amended. To demonstrate ongoing 

compliance, an owner or operator must 

monitor PM emission control device 

operating parameters and conduct 

annual PM performance tests, use a PM 

CEMS, or operate bag leak detection 

systems and conduct annual PM 

performance tests. A new alternative 

allows refineries with wet scrubbers as 

PM control devices to use the approved 

alternative in 40 CFR 63.1573(a) for 

determining exhaust gas flow rate 

instead of a continuous parameter 

monitoring system (CPMS). An 

alternative to the requirements for 

monitoring the pressure drop from wet 

scrubbers that are equipped with jet 

ejectors or atomizing spray nozzles is to 

conduct a daily check of the air or water 

pressure to the nozzles and record the 

results of each inspection. The final rule 

also includes procedures for 

establishing an alternative opacity 

operating limit for refiners that use 

continuous opacity monitoring systems 

(COMS); this alternative is allowed only 

for units that choose to comply with the 

PM limit using cyclones. If operating 

parameters are 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 three-run average of the 

values for the applicable parameters 

measured over the three test runs. If 

ongoing compliance is demonstrated 

using a PM CEMS, the CEMS must meet 

the conditions in Performance 

Specification 11 (40 CFR part 60, 

appendix B) and the quality assurance 

(QA) procedures in Procedure 2, 40 CFR 

part 60, appendix F. The relative 

response audits must be conducted 

annually (in lieu of annual performance 

tests for units not employing a PM 

CEMS) and response correlation audits 

must be conducted once every 5 years. 

For NOX emissions from the affected 

FCCU and FCU, we proposed a limit of 

80 ppmv based on a 7-day rolling 

average (dry basis corrected to 0 percent 

excess air) and co-proposed having no 

limit for FCU. We are adopting the 80 

ppmv NOX emission limits for FCCU 

and FCU as proposed. Initial 

compliance with the 80 ppmv emission 

limit is demonstrated by conducting a 

performance evaluation of the CEMS in 

accordance with Performance 

Specification 2 in 40 CFR part 60, 

appendix B, with Method 7 (40 CFR part 

60, appendix A–4) as the reference 

method. Ongoing compliance with these 

emission limits is determined using the 

CEMS to measure NOX emissions as 

discharged to the atmosphere, averaged 

over 7-day periods. 

No changes have been made to the 

proposed SO2 emission limits for 

affected FCCU and FCU. The final SO2

emission limits 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 final SO2

emission limits are demonstrated by 

conducting a performance evaluation of 

the SO2 CEMS in accordance with 

Performance Specification 2 (40 CFR 

part 60, Appendix B) with Method 6, 

6A, or 6C (40 CFR part 60, Appendix A–

4) as the reference method. Ongoing 

compliance with both SO2 emission 

limits is determined using the CEMS to 

measure SO2 emissions as discharged to 

the atmosphere, averaged over the 7-day 

and 365-day averaging periods. 

No changes have been made since 

proposal to the CO limits. The final CO 

emission limit for the affected FCCU 

and FCU is 500 ppmv (1-hour average, 

dry at 0 percent excess air). Initial 

compliance with this emission limit is 

demonstrated by conducting a 

performance evaluation for the CEMS in 

accordance with Performance 

Specification 4 (40 CFR part 60, 

appendix B) with Method 10 or 10A (40 

CFR part 60, Appendix A–4) as the 

reference method. For Method 10 (40 

CFR part 60, Appendix A–4), the 

integrated sampling technique is to be 

used. Ongoing compliance with this 

emission limit is determined on an 

hourly basis using the CEMS to measure 

CO emissions as discharged to the 

atmosphere. An exemption from 

monitoring may be requested for an 

FCCU or FCU if the owner or operator 

can demonstrate that ‘‘average CO 

emissions’’ are less than 50 ppmv (dry 

basis). As proposed, units that are 

exempted from the CO monitoring 

requirements must comply with control 

device operating parameter limits. 

C. What are the final requirements for 

new sulfur recovery plants (40 CFR part 

60, subpart Ja)? 

For new, modified, and reconstructed 

SRP with a capacity greater than 20 long 

tons per day (LTD) (large SRP), we 

proposed a limit of 250 ppmv total 

sulfur (combined SO2 and reduced 

sulfur compounds) as SO2 (dry basis at 

0 percent excess air determined on a 12- 

hour rolling average basis). The refinery 

could comply with the limit for each 

process train or release point or with a 

flow rate weighted average of 250 ppmv 

for all release points. For affected SRP 

with a capacity less than 20 LTD (small 

SRP), we proposed a mass emissions 

limit for total sulfur equal to 1 weight 

percent or less of sulfur recovered 

(determined hourly on a 12-hour rolling 

average basis). 

In this final rule, we are adopting the 

current limits in subpart J (which 

include separate emission limits for 

oxidative and reductive systems) for 

affected large SRP. For these affected 

SRP, the final limits for SRP having an 

oxidation control system or a reduction 

control system followed by incineration 

is 250 ppmv (dry basis) of SO2 at zero 

percent excess air. For an affected SRP 

with a reduction control system not 

followed by incineration, the final limit 

is 300 ppmv of reduced sulfur 

compounds and 10 ppmv of hydrogen 

sulfide (H2S), each calculated as ppm 

SO2 by volume (dry basis) at zero 

percent excess air. If the SRP consists of 

multiple process trains or release points, 

the refinery can comply with the limit 

for each process train or release point or 

with a flow rate weighted average of 250 

ppmv for all release points. A new 

alternative allows refineries to use a 

correlation to calculate their effective 

emission limit for Claus SRP that use 

oxygen enrichment in the Claus burner. 

For a small affected SRP, the sulfur 

recovery efficiency standard is based on 

a sulfur recovery efficiency of 99 

percent. However, due to the difficulties 

associated with on-going monitoring of 

SRP recovery efficiency, in this final 

rule, we are promulgating concentration 

limits that correlate with a sulfur 

recovery efficiency of 99 percent. For a 

Claus unit with an oxidative control 

system or any small SRP followed by an 

incinerator the emission limit is 2,500 


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ppmv (dry basis) of SO2 at zero percent 

excess air. For all other small SRP, the 

emission limit is 3,000 ppmv reduced 

sulfur compound and 100 ppmv H2S, 

each calculated as ppm SO2 by volume 

(dry basis) at zero percent excess air. A 

similar correlation is provided for small 

Claus SRP that use oxygen enrichment, 

similar to that provided for large SRP. 

The standards for small SRP apply to all 

release points from the SRP combined 

(note that secondary sulfur storage units 

are not considered part of the SRP). We 

are not promulgating the H2S limit of 10 

ppmv (dry basis, at 0 percent excess air 

determined on a 12-hour rolling average 

basis) or related operating limits that 

were included in § 60.102a(e) and (f) of 

the proposed rule. 

Initial compliance with the emission 

limit for large SRP is demonstrated by 

conducting a performance evaluation for 

the SO2 CEMS in accordance with either 

Performance Specification 2 (40 CFR 

part 60, Appendix B) for SRP with 

oxidation control systems or reduction 

control systems followed by 

incineration, or Performance 

Specification 5 (40 CFR part 60, 

Appendix B) for SRP with reduction 

control systems not followed by 

incineration. The owner or operator 

must operate and maintain oxygen 

monitors according to Performance 

Specification 3 (40 CFR part 60, 

Appendix B). 

Ongoing compliance with the SO2

limits for large SRP is determined using 

an SO2 CEMS (for oxidative or reductive 

systems followed by incineration) or 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 (for reductive systems not 

followed by incineration). An O2

monitor is also required for converting 

the measured combined SO2

concentration to the concentration at 0 

percent O2. 

Initial and ongoing compliance 

requirements for small SRP are the same 

as for large SRP. 

D. What are the final requirements for 

new fuel gas combustion devices (40 

CFR part 60, subpart Ja)? 

In the subpart Ja proposal, we divided 

fuel gas combustion devices into two 

separate affected sources: ‘‘process 

heaters’’ and ‘‘other fuel gas combustion 

devices.’’ In response to comments, we 

have eliminated the proposed definition 

of ‘‘other fuel gas combustion devices’’

and revised the standards to either refer 

to fuel gas combustion devices, which 

include process heaters, or to refer 

specifically to process heaters. This 

revision makes the definition of ‘‘fuel 

gas combustion devices’’ consistent 

with subpart J. Based on public 

comments, we have also added a 

definition of ‘‘flare’’ as a subcategory of 

fuel gas combustion devices. The owner 

or operator of an affected flare must 

comply with the fuel gas combustion 

device requirements as well as specific 

provisions for flares as described in 

section III.E of this preamble. 

We proposed a primary sulfur dioxide 

emission limit for fuel gas combustion 

devices of 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. We also 

proposed an alternative limit of 160 

ppmv H2S or, in the case of cokerderived fuel gas, 160 ppmv total 

reduced sulfur (TRS), on a 3-hour 

rolling average basis and 60 ppmv or 

less on a 365-day rolling average basis. 

We are promulgating the 20 ppmv and 

8 ppmv limits for SO2 as proposed. We 

are also promulgating the alternative 

limit except that the limits are 

expressed and measured as H2S in all 

cases. The alternative H2S limit is 162 

ppmv or less in the fuel gas on a 3-hour 

rolling average basis and 60 ppmv or 

less in the fuel gas on a 365-day rolling 

average basis. The alternative limit of 

162 ppmv is based on standard 

conditions, which are defined in the 

NSPS General Provisions at 40 CFR 60.2 

as being 68°F and 1 atmosphere. Using 

these as standard conditions, the 

subpart J emission limit is equivalent to 

162 ppmv H2S rather than 160 ppmv. 

The final rule does not include an 

alternative TRS limit for SO2. 

Initial compliance with the 20 ppmv 

SO2 limit or the 162 ppmv H2S 

concentration limits is demonstrated by 

conducting a performance evaluation for 

the CEMS. The performance evaluation 

for an SO2 CEMS is conducted in 

accordance with Performance 

Specification 2 in 40 CFR part 60, 

Appendix B. The performance 

evaluation for an H2S CEMS is 

conducted in accordance with 

Performance Specification 7 in 40 CFR 

part 60, Appendix B. Ongoing 

compliance with the sulfur oxides 

emission limits is determined using the 

applicable CEMS to measure either SO2

in the exhaust gas to the atmosphere or 

H2S in the fuel gas, averaged over the 3- 

hour and 365-day averaging periods. 

Similar to clarifications for 40 CFR 

part 60, subpart J, the definition of ‘‘fuel 

gas’’ includes exemptions for vapors 

collected and combusted in an air 

pollution control device installed to 

comply with specified wastewater or 

marine vessel loading provisions. We 

are also streamlining the process for an 

owner or operator to demonstrate that a 

fuel gas stream not explicitly exempted 

from continuous monitoring is 

inherently low sulfur. 

For new, modified, or reconstructed 

process heaters with a rated capacity 

greater than 20 million British thermal 

units per hour (MMBtu/hr), we 

proposed a NOX limit of 80 ppmv (dry 

basis, corrected to 0 percent excess air) 

on a 24-hour rolling average basis. The 

final NOX emission limit for affected 

process heaters is 40 ppmv on a 24-hour 

rolling average basis (dry at 0 percent 

excess air) for process heaters greater 

than 40 MMBtu/hr. For process heaters 

greater than 100 MMBtu/hr capacity, 

initial compliance with the 40 ppmv 

emission limit is demonstrated by 

conducting a performance evaluation of 

the CEMS in accordance with 

Performance Specification 2 in 40 CFR 

part 60, Appendix B. For process 

heaters between 40 MMBtu/hr and 100 

MMBtu/hr capacity, initial compliance 

is demonstrated using EPA Method 7 

(40 CFR part 60, Appendix A–4). For 

process heaters greater than 100 

MMBtu/hr capacity, ongoing 

compliance with this emission limit is 

determined using the CEMS to measure 

NOX emissions as discharged to the 

atmosphere, averaged over 24-hour 

periods. For process heaters between 40 

MMBtu/hr and 100 MMBtu/hr capacity, 

ongoing compliance with this emission 

limit is determined using biennial 

performance tests. 

E. What are the final work practice 

standards (40 CFR part 60, subpart Ja)? 

We proposed three work practice 

standards to reduce SO2, VOC, and NOX

emissions from flares and from startup, 

shutdown, and malfunction events and 

to reduce VOC and SO2 emissions from 

delayed coking units. We also coproposed to require only one of these 

work practice standards: the 

requirement to depressure delayed 

coking units. This proposed standard 

required new delayed coking units to 

depressure to 5 pounds per square inch 

gauge (psig) during reactor vessel 

depressuring and vent the exhaust gases 

to the fuel gas system. 

We are promulgating a work practice 

standard for delayed coking units and 

modified requirements to reduce 

emissions from flares. The final work 

practice standard for delayed cokers 

requires affected delayed coking units to 

depressure to 5 pounds per square inch 

gauge (psig) during reactor vessel 

depressuring. We are requiring the 

exhaust gases to be vented to the fuel 

gas system as proposed or to a flare. 

To reduce SO2 emissions from the 

combustion of sour fuel gases, the final 

rule requires refineries to conduct a root 


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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 

fuel gas combustion device or sulfur 

recovery plant subject to the provisions 

of subpart Ja that exceeds 500 pounds 

per day (lb/day) of SO2. Recordkeeping 

and reporting requirements apply in the 

event of such a discharge. Newly 

constructed and reconstructed flares 

must comply with these requirements 

immediately upon startup. Modified 

flares must comply no later than the 

first discharge that occurs after that flare 

has been an affected flare for 1 year. 

In response to comments regarding 

the work practice standards for fuel gas 

producing units and associated 

difficulties with no routine flaring, we 

re-evaluated the work practice standards 

and have decided not to promulgate a 

work practice standard for fuel gas 

producing units. Rather, we have 

decided to define a flare as an affected 

facility and adopt regulations applicable 

to it. Therefore, we are not promulgating 

the proposed definition of ‘‘fuel gas 

producing unit’’ and the proposed 

requirement for ‘‘no routine flaring.’’

Instead, we are promulgating the 

following requirements for flares that 

become affected facilities after June 24, 

2008: (1) Flare fuel gas flow rate 

monitoring; (2) a flare fuel gas flow rate 

limit; and (3) a flare management plan. 

Affected flares cannot exceed a flow rate 

of 250,000 standard cubic feet per day 

(scfd) on a 30-day rolling average basis. 

In cases where the flow would exceed 

this value, the owner or operator would 

install a flare gas recovery system or 

implement other methods to reduce 

flaring from the affected flare. To 

demonstrate compliance with the flow 

rate limitations, flow rate monitors must 

be installed and operated. Newly 

constructed and reconstructed flares 

must comply with the flow rate 

limitations and the monitoring 

requirements immediately upon startup. 

Modified flares must comply with the 

flow rate limitations and the associated 

monitoring provisions no later than 1 

year after the flare becomes an affected 

facility. A provision is provided for an 

exclusion from the flow limitation for 

times when the refinery can 

demonstrate that the refinery produces 

more fuel gas than it needs to fuel the 

refinery combustion devices (i.e., it is 

fuel gas rich) or that the flow is due to 

an upset or malfunction, provided the 

refinery follows procedures outlined in 

the flare management plan. The flare 

management plan should address 

potential causes of fuel gas imbalances 

(i.e., excess fuel gas) and records to be 

maintained to document these periods. 

As described in 40 CFR 60.103a(a), the 

flare management plan must include a 

diagram illustrating all connections to 

each affected flare, identification of the 

flow rate monitoring device and a 

detailed description of the 

manufacturer’s specifications regarding 

quality assurance procedures, 

procedures to minimize flaring during 

planned start-up and shut down events, 

and procedures for implementing root 

cause analysis when daily flow to the 

flare exceeds 500,000 scfd. The root 

cause analysis procedures should 

address the evaluation of potential 

causes of upsets or malfunctions and 

records to be maintained to document 

the cause of the upset or malfunction. 

Newly constructed and reconstructed 

flares must comply with the flare 

management plan requirements 

immediately upon startup. Modified 

flares must comply with the flare 

management plan requirements no later 

than 1 year after the flare becomes an 

affected facility. Additionally, as 

described above, the owner or operator 

of a modified flare must conduct the 

first root cause analysis no later than the 

first discharge that occurs after that flare 

has been an affected flare for 1 year. 

Excess emission events for the flow rate 

limit of 250,000 scfd and the result of 

root cause analysis must be reported in 

the semi-annual compliance reports. 

Because affected flares are also 

affected fuel gas combustion devices, 

the root cause analysis for SO2

emissions exceeding 500 lbs/day also 

applies to all affected flares. However, 

compliance with the 500 lb/day root 

cause analysis will also require 

continuous monitoring of total reduced 

sulfur of all gases flared. Although all 

fuel gas combustion devices are 

required to comply with continuous H2S 

monitoring of fuel gas, flares routinely 

accept gases from upsets, malfunctions 

and startup and shutdown events, and 

H2S or sulfur monitoring is not 

specifically required for these gases. In 

subpart Ja, we explicitly require TRS 

monitoring for flares that become 

affected facilities after June 24, 2008 to 

ensure that the 500 lb/day SO2 trigger is 

accurately measured. The owner or 

operator of a modified flare must install 

and operate the TRS monitoring 

instrument no later than 1 year after the 

flare becomes an affected facility. The 

owner or operator of a newly 

constructed or reconstructed flare must 

install and operate the TRS monitoring 

instrument no later than start-up of the 

flare. 

F. What are the modification and 

reconstruction provisions? 

Existing affected facilities that 

commence modification or 

reconstruction after May 14, 2007, are 

subject to the final standards in 40 CFR 

part 60, subpart Ja. A modification is 

any physical or operational change to an 

existing affected 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 affected 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. 

The intermittent operation of a flare 

makes it difficult to use the criteria of 

40 CFR 60.14 to determine when a flare 

is modified; therefore, we have specified 

in the final rule the criteria that define 

a modification to a flare. A flare is 

considered to be modified if: (1) Any 

piping from a refinery process unit or 

fuel gas system is newly connected to 

the flare or (2) the flare is physically 

altered to increase flow capacity. See 

section IV.I of this preamble for further 

explanation on the change in affected 

source from a fuel gas producing unit to 

the flare. 

Petroleum refinery process units are 

subject to the final standards in 40 CFR 

part 60, subpart Ja if they meet the 

criteria 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). 

IV. Summary of Significant Comments 

and Responses 

As previously noted, we received a 

total of 46 comments during the public 

comment periods associated with the 

proposed rule and NODA. These 

comments were received from 

refineries, industry trade associations, 

and consultants; State and local 

environmental and public health 

agencies; environmental groups; and 

members of the public. In response to 

these public comments, most of the cost 

and emission reduction impact 

estimates were recalculated, resulting in 

several changes to the final amendments 

and new standards. The major 

comments and our responses are 


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summarized in the following sections. A 

summary of the remainder of the 

comments received during the comment 

period and responses thereto can be 

found in the docket for the final 

amendments and new standards (Docket 

ID No. EPA–OAR–HQ–2007–0011). The 

docket also contains further details on 

all the analyses summarized in the 

responses below. 

In responding to the public 

comments, we re-evaluated the costs 

and cost-effectiveness of the control 

options and re-evaluated our BDT 

determinations. In our BDT 

determinations, we took all relevant 

factors into account consistent with 

other Agency decisions. It is important 

to note that, due to the different health 

and welfare effects associated with 

different pollutants, the acceptable costeffectiveness value of a control option is 

pollutant dependent. These pollutantspecific factors were considered along 

with other factors in our BDT 

determinations. 

A. PM Limits for Fluid Catalytic 

Cracking Units 

Comment: Several commenters 

opposed the proposed tightening of the 

FCCU PM standards relative to subpart 

J and the concurrent change in PM 

monitoring methods. Some commenters 

supported the co-proposal to keep the 1 

lb/1,000 lb coke burn PM emission limit 

based on Method 5B and/or 5F; other 

commenters either did not oppose or 

supported the 0.5 lb/1,000 lb coke burn 

emission limit for new ‘‘grassroots’’

units, provided EPA demonstrates it is 

cost-effective and that the limit is based 

on EPA Method 5B or 5F (40 CFR part 

60, Appendix A–3). 

Commenters stated that EPA should 

only impose the more stringent 

emission limits on new construction 

because it is much more difficult and 

costly to meet the proposed emission 

limits for modified or reconstructed 

equipment. Commenters suggested that 

if EPA does include more stringent 

limits on modifications, it should 

exclude certain actions (like projects 

implemented to meet consent decree 

requirements) from the definition of a 

modification. 

Several commenters suggested that 

the costs in Table 11 of the proposal 

preamble are significantly 

underestimated. Commenters contended 

that the single ‘‘model plant’’ approach 

used in EPA’s cost analysis does not 

realistically consider important factors 

such as the inherent sulfur content of 

the feed, partial-burn versus full-burn 

regeneration, FCCU/regenerator size, 

and sources that are already wellcontrolled due to other regulations. 

Commenters asserted that the purchased 

equipment costs escalated from 

estimates that are 20 to 30 years old are 

underestimated. Several commenters 

provided estimates of costs and 

emission reductions for several actual 

projects, which they stated indicate that 

EPA’s costs are significantly 

underestimated and that the proposed 

standards are much less cost-effective 

than presented by EPA. 

A number of commenters asserted 

that the PM standards should be based 

on EPA Methods 5B or 5F (40 CFR part 

60, Appendix A–3), and not on EPA 

Method 5 of Appendix A–3 to part 60. 

According to these commenters, the 

achievability of the proposed 0.5 lb/ 

1,000 lb coke burn PM limit based on 

EPA Method 5 is questionable because 

there are inadequate data on FCCU 

using EPA Method 5, and controlling 

combined condensable and filterable 

PM to the 0.5 lb/1,000 lb coke burn level 

has not been demonstrated to be costeffective. 

On the other hand, several 

commenters stated that any PM limit 

must include condensable and filterable 

PM as condensable PM account for a 

large portion of refinery PM emissions 

and all condensable PM is PM that is 

less than 2.5 micrometers in diameter 

(PM2.5), which has more adverse health 

impacts than larger particles; the 

commenters therefore agreed with the 

use of EPA Method 5 to determine 

filterable PM and requested that EPA 

consider Method 202 (40 CFR part 51, 

Appendix M) for condensable PM. 

Commenters also stated that the limits 

for PM and SO2 in subpart Ja should 

apply to all new, reconstructed, and 

modified FCCU. One commenter 

recommended that a total PM limit 

(filterable and condensable) be set at 1 

lb/1,000 coke burn; another stated that 

the total PM limit, including both 

filterable and condensable PM, should 

be 0.5 lb/1,000 lb coke burn, and EPA 

has not demonstrated that current BDT 

cannot achieve this limit. Finally, one 

commenter suggested that EPA should 

evaluate the cost of removing each 

pollutant (PM and SO2) separately. 

Response: In response to these 

comments, we have revised our analysis 

to consider each unique existing FCCU 

in the United States. By doing so, we 

fully account for plant size, partial-burn 

versus full-burn regeneration, existing 

control configuration, and specific 

consent decree requirements. (Details on 

the specific revisions to the analysis can 

be found in the docket.) With a revised 

analysis, we were able to more directly 

assess the impacts of process 

modifications or reconstruction of 

existing equipment. We also assessed 

the effects of PM and SO2 standards 

separately in this analysis. 

In our revised analysis, we considered 

three options for PM: (1) Maintain the 

existing subpart J standard of 1.0 lb/ 

1,000 lb of coke burn-off (filterable PM 

as measured by Method 5B or 5F); (2) 

0.5 lb/1,000 lb of coke burn-off 

(filterable PM as measured by Method 

5B or 5F of Appendix A–3 to part 60); 

and (3) 0.5 lb/1,000 lb of coke burn-off 

(filterable PM as measured by Method 5 

of Appendix A–3 to part 60). Similar to 

the analysis for the proposed standards, 

costs and emission reductions for each 

option were estimated as the increment 

between complying with subpart J and 

subpart Ja. We note that none of the 

available data suggest that a 0.5 lb/1,000 

lb coke burn emission limit that 

includes both filterable and condensable 

PM as measured using EPA Method 202 

is achievable in practice for the full 

range of facilities using BDT controls, so 

we disagree with the comments 

suggesting this level is appropriate to 

consider as an option for a total PM 

limit in this rulemaking. 

Option 1 includes the same emissions 

and requirements for PM as the current 

40 CFR part 60, subpart J, so it will 

achieve no additional emissions 

reductions. The PM limit in Option 2 is 

the same numerical limit that was 

proposed in subpart Ja, but the PM 

emissions are determined using 

Methods 5B and 5F (40 CFR part 60, 

Appendix A–3). These test methods are 

commonly used for PM tests of FCCU 

and are the methods that were used to 

generate a majority of the test data we 

reviewed. Option 3 is a limit of 0.5 lb/ 

1,000 lb coke burn using Method 5 and 

is the performance level that was 

proposed for subpart Ja. The impacts of 

these three options for new FCCU are 

presented in Table 2 to this preamble; 

the impacts for modified and 

reconstructed FCCU are presented in 

Table 3 to this preamble. 


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

CRACKING UNITS SUBJECT TO 40 CFR PART 60, SUBPART JAa

Option Capital cost 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Emission 

reduction 

(tons PM/yr) 

Cost effectiveness ($/ton) 

Overall Incremental 

2 ........................................................................................... 3,600 1,100 240 5,600 5,600 

3 ........................................................................................... 7,100 1,700 300 6,700 11,000 

aPM cost-effectiveness calculated for PM-fine; 83.3 percent of the PM is PM-fine. 

TABLE 3.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR PM LIMITS CONSIDERED FOR RECONSTRUCTED AND

MODIFIED FLUID CATALYTIC CRACKING UNITS SUBJECT TO 40 CFR PART 60, SUBPART JAa

Option Capital cost 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Emission 

reduction 

(tons PM/yr) 

Cost effectiveness ($/ton) 

Overall Incremental 

2 ........................................................................................... 75,000 12,000 690 21,000 21,000 

3 ........................................................................................... 100,000 15,000 810 23,000 37,000 

aPM cost-effectiveness calculated for PM-fine; 83.3 percent of the PM is PM-fine. 

The available data and impacts for the 

options considered suggest that BDT for 

new FCCU is different than BDT for 

modified and reconstructed FCCU. For 

new FCCU, the costs for Option 2 are 

reasonable compared to the emission 

reduction achieved. The incremental 

cost between Option 2 and Option 3 of 

$11,000 per ton PM-fine would 

generally be considered reasonable, but 

there are uncertainties in the 

achievability of Option 3. The estimated 

PM emission reduction achieved by 

Option 3 compared to Option 2 equals 

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 (40 

CFR part 60, Appendix A–3). 

Additionally, available test data indicate 

that electrostatic precipitators (ESP) and 

wet scrubbers can reduce total filterable 

PM to 0.5 lb/1,000 lb of coke burn or 

less, as measured by Method 5- 

equivalent test methods. Although there 

were few test data points using Method 

5-equivalent test methods, we 

concluded at proposal that both 

electrostatic precipitators and wet 

scrubbers can achieve this level of PM 

emissions. However, the data 

supporting Option 3 are not extensive, 

and it is unclear at this time whether a 

limit of 0.5 kg/Mg of coke burn as 

measured by Method 5 (40 CFR part 60, 

Appendix A–3) could be met by all 

configurations of FCCU. In addition, 

while the Agency supports reducing 

condensable PM emissions, the amount 

of condensable PM captured by Method 

5 is small relative to methods that 

specifically target condensable PM, such 

as Method 202 (40 CFR part 51, 

Appendix M). We prefer to develop a 

single performance standard that 

considers all condensable PM rather 

than implementing phased standards 

targeting different fractions of 

condensable PM. Such an approach 

would be costly and inefficient. 

Therefore, we conclude that Option 2, 

control of PM emissions (as measured 

by Methods 5B and 5F of Appendix A–

3 to part 60) to 0.5 lb/1,000 lb of coke 

burn or less, is BDT for newly 

constructed FCCU. This option achieves 

PM emission reductions of 240 tons per 

year (tons/yr) from a baseline of 910 

tons/yr at a cost of $5,600 per ton of PM. 

For modified and reconstructed 

FCCU, Option 1 is the baseline level of 

control established by the existing 

requirements of subpart J. It will achieve 

no additional cost or emission 

reduction. The overall costs and the 

incremental costs for Options 2 and 3 

are reasonable compared to the PM 

emission reduction; however, as with 

new FCCU, the performance of Option 

3 has not been demonstrated, so it is 

rejected. Most of the existing FCCU that 

could become subject to subpart Ja 

through modification or reconstruction 

are either already subject to subpart J or 

are covered by the consent decrees. The 

consent decrees are generally based on 

the existing subpart J. Industry has 

made significant investments in 

complying with these subpart J 

requirements which may be abandoned 

if they become subject to subpart Ja. In 

addition, the additional costs could 

create a disincentive to modernize 

FCCU to make them more energy 

efficient or to produce more refined 

products. For these reasons, we reject 

Option 2 for modified or reconstructed 

FCCU and conclude that control of PM 

emissions (as measured by Methods 5B 

and 5F of Appendix A–3 to part 60) is 

1.0 lb/1,000 lb of coke burn or less is 

BDT for reconstructed and modified 

FCCU. 

B. SO2 Limits for Fluid Catalytic 

Cracking Units 

Comment: Several commenters 

supported the co-proposal for modified 

and reconstructed FCCU to meet subpart 

J and not the 25 ppmv 365-day rolling 

average limit for SO2. Commenters 

provided data to suggest that the 

retrofits of existing sources are not cost 

effective, particularly if catalyst 

additives cannot be used. The current 

subpart J includes three compliance 

options: (1) If using an add-on 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. Several 

commenters objected to the elimination 

of the additional compliance options in 

the existing subpart J for subpart Ja 

because: (1) There are no data to show 

that the SO2 limits proposed in subpart 

Ja are BDT for all FCCU regenerator 

configurations; (2) the three options are 

already established as BDT and, 

therefore, the CAA requires that EPA 

make them available; and (3) the 

substantial cost and other burdens for a 

reconstructed or modified FCCU already 

complying with one of the alternative 

options in subpart J to change to daily 

monitoring by Method 8 (40 CFR part 

60, Appendix A–4) or to install CEMS 

were not addressed in the proposal. 

One commenter supported the 

proposed SO2 limit under Ja for new 

‘‘grassroots’’ FCCU if the standard is 

demonstrated to be cost-effective. 


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Response: As acknowledged in the 

previous response on PM standards for 

FCCU, we completely revised our 

impacts analysis to evaluate SO2

standards for every existing FCCU that 

may become subject to subpart Ja 

through modification or reconstruction. 

We did not have access to the inherent 

sulfur content of the feed for each FCCU 

so SO2 emissions are still estimated 

using average emission factors relevant 

to the type of control device used for 

FCCU not subject to consent decree 

requirements. Nonetheless, we 

significantly revised the impact analysis 

to fully account for FCCU-specific 

throughput, existing controls, and 

consent decree requirements. (Details on 

the specific revisions to the analysis can 

be found in Docket ID No. EPA–HQ–

OAR–2007–0011.) We evaluated two 

options: (1) Current subpart J, including 

all three compliance options; and (2) 50 

ppmv SO2 on a 7-day average and 25 

ppmv on a 365-day average. Data are not 

available on which to base a more 

stringent control level. 

Option 1 includes the same emissions 

and requirements as the current 40 CFR 

part 60, subpart J, so it will achieve no 

additional emissions reductions. Based 

on information provided by vendors and 

data submitted by petroleum refiners, 

Option 2 can be met with catalyst 

additives or a wet scrubber. Of 38 FCCU 

currently subject to a 50/25 ppmv SO2

limit through consent decrees, 26 used 

wet scrubbers and 12 used catalyst 

additives or other (unspecified) 

techniques. Given the number of FCCU 

currently meeting the 50/25 ppmv SO2

emission limit, we conclude that this 

limit is technically feasible. 

The data in the record suggest that all 

systems with wet scrubbers can meet 

the 50/25 ppmv SO2 emission limit with 

no additional cost. Further, based on 

information from the consent decrees, 

we believe that the owner or operator of 

an existing FCCU that does not already 

have a wet scrubber and is modified or 

reconstructed such that it becomes 

subject to subpart Ja can use catalyst 

additives to meet the 50/25 ppmv SO2

emission limit. Therefore, the cost of 

Option 2 is calculated using catalyst 

additives as the method facilities choose 

for meeting the standard. We reject the 

idea that the 90 percent control 

efficiency, the 9.8 kg/Mg coke burn-off 

limit, or the 0.3 weight percent sulfur 

content alternatives are equivalent to 

the 50/25 ppmv SO2 emission limit. 

Based on the original background 

document for the subpart J standards, 

these alternatives are expected to have 

outlet SO2 concentrations of 200 to 400 

ppmv. In reality the currently used wet 

scrubbers and catalyst additives achieve 

much higher SO2 removal efficiencies 

and much lower outlet SO2

concentrations. The impacts of these 

options are presented in Table 4 of this 

preamble. 

TABLE 4.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR SO2 LIMITS CONSIDERED FOR NEW, RECONSTRUCTED, AND

MODIFIED 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 SO2/yr) 

Cost effectiveness ($/ton) 

Overall Incremental 

2 ........................................................................................... 0 3,000 4,400 700 700 

Based on the data we reviewed to 

select the options and the estimated 

impacts of those options, we conclude 

that Option 2, control of SO2 emissions 

to 25 ppmv or less averaged over 365 

days and 50 ppmv or less averaged over 

7 days, is technically feasible and costeffective for new, reconstructed, and 

modified fluid catalytic cracking units. 

This option has no capital cost and 

achieves SO2 emission reductions of 

4,400 tons/yr from a baseline of 5,900 

tons/yr at a cost of $700 per ton of SO2. 

Therefore, we conclude that 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. 

C. NOX Limit for Fluid Catalytic 

Cracking Units 

Comment: Several commenters stated 

that they would support a NOX limit of 

80 ppmv for new sources only, provided 

a corrected impact analysis considers 

the different characteristics of FCCU 

and demonstrates that the NOX limit for 

new sources is truly cost-effective. 

Commenters supported the co-proposal 

for modified and reconstructed FCCU to 

meet subpart J and not be subject to a 

NOX emission limit. A few commenters 

provided cost data showing the cost of 

NOX controls is high for modified and 

reconstructed units due to the high cost 

and space needed for add-on controls. 

The commenters also stated that a large 

number of existing FCCU in the U.S. are 

covered by consent decrees, so 

significant NOX reductions have already 

been (or will soon be) achieved, and an 

additional incremental reduction to 20 

or 40 ppmv over a 365-day average are 

not widely demonstrated and would not 

be cost-effective. 

One commenter stated that selective 

noncatalytic reduction (SNCR), selective 

catalytic reduction (SCR), and catalyst 

additives have not been demonstrated 

over significant periods of operational 

life. Commenters also cited 

environmental side-effects, such as the 

generation of ammonia compounds that 

contribute to condensable PM 

emissions, as a reason not to require 

these types of controls. Commenters 

also asserted that technologies like flue 

gas recirculation or advanced burner 

design are typically only cost-effective 

for new units and may be technically 

infeasible for existing FCCU. 

One commenter suggested that if a 

limit is necessary for modified or 

reconstructed FCCU, recent catalyst 

additive trials support an emission limit 

of approximately 150 ppmv on a 7-day 

rolling average; this limit would only be 

achievable if a 24-hour CO averaging 

time was provided since lowering NOX

tends to increase CO emissions in 

FCCU. The commenter noted that this 

limit is equivalent to the 0.15 pounds 

per million British thermal units (lb/ 

MMBtu) standard for reconstructed and 

modified heaters and boilers in NSPS 

subpart Db. 

Other commenters supported the 

inclusion of a NOX limit for FCCU and 

opposed the co-proposal of no NOX

standard for modified and reconstructed 

FCCU. These commenters also 

recommended more stringent NOX

limits for FCCU and stated that 80 ppmv 

does not represent an adequate level of 

control given the evolution of emerging 

technologies. In addition, a BDT of 80 

ppmv on 7-day rolling average does not 

look ‘‘toward what may be fairly 

projected for the regulated future’’ as 

required by Portland Cement I (486 F. 

2d 375 at 384 (D.C. Cir. 1973)) and other 

court decisions. The commenters 

disagreed with the feasibility and cost 

analyses for modified and reconstructed 

FCCU and stated that FCCU under a 

consent decree are achieving lower 

levels than the 80 ppmv proposed by 

EPA. Given the significant hazards to 


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human health and the environment 

posed by NOX emissions, the 

commenters recommended limits of 20 

ppmv over a 365-day rolling average 

and 40 ppmv over a 7-day rolling 

average for all FCCU. The commenters 

noted that these limits have been 

successfully achieved under consent 

decrees and they are technically feasible 

on new units at reasonable costs 

without additional controls. 

Response: As shown by the disparate 

comments received, many commenters 

suggest lower NOX emission limits are 

achievable, while other commenters do 

not believe the proposed NOX emission 

limits are cost-effective. While we do 

acknowledge that lower NOX emission 

limits are technically achievable, the 

incremental cost of achieving these 

lower limits was high when we 

evaluated options for the proposed 

standards. Therefore, we concluded at 

proposal that 20 or 40 ppmv NOX limits 

were not BDT. In our BDT assessment, 

we evaluated the various methods to 

meet alternative NOX limits as BDT 

rather than identifying one technology. 

One of the reasons for this is that each 

technology has its own advantages and 

limitations. While non-platinum 

oxidation promoters and advanced 

oxidation controls do not achieve the 

same reduction in NOX emissions as 

add-on control devices such as SCR, 

they do so without any significant 

secondary impacts. The added NOX

reduction of SCR and SNCR must be 

balanced with these secondary impacts. 

Part of the basis for selecting control 

methods to achieve an 80 ppmv NOX

emission limit as BDT included both 

cost and secondary impacts. This 

approach is necessary when conducting 

our BDT analysis, thus ensuring the best 

overall environmental benefit from the 

subpart Ja standards. 

To ensure that we addressed the 

commenters’ concerns, we re-evaluated 

the impacts for FCCU NOX controls. We 

also collected additional data from 

continuous NOX monitoring systems for 

a variety of FCCU NOX control systems. 

These data suggest that as refiners gain 

more experience with the NOX control 

systems (including catalyst additive 

improvements), NOX control 

performance has improved over the past 

year or two. These data suggest that the 

achievable level for combustion controls 

and catalyst additives is 80 ppmv and 

the achievable level for add-on control 

systems is 20 ppmv. Therefore, we 

evaluated three outlet NOX emission 

level options as part of the BDT 

determination: (1) 150 ppmv; (2) 80 

ppmv; and (3) 20 ppmv. Each NOX

concentration is averaged over 7 days. 

To estimate impacts for Option 1, we 

estimated that some units have current 

NOX emissions below 150 ppmv, and all 

other units can meet this level with 

combustion controls such as limiting 

excess O2 or using non-platinum 

catalyst combustion promoters and 

other NOX-reducing catalyst additives in 

a complete combustion catalyst 

regenerator or a combination of NOXreducing combustion promoters and 

catalyst additives with low-NOX burners 

(LNB) in a CO boiler after a partial 

combustion catalyst regenerator. Data 

collected from FCCU complying with 

consent decrees show that Option 2 can 

also be met using combustion controls; 

therefore, we estimated impacts for 

Option 2 using a similar method as 

Option 1. The main difference is that a 

larger number of FCCU must use 

combustion controls to meet the 

emission limit (i.e., the FCCU with 

current NOX emissions between 150 and 

80 ppmv would not need controls under 

Option 1 but would need controls under 

Option 2). Option 3 is the level at which 

we expect all units to install more costly 

control technology such as LoTOxTM or 

SCR. The estimated fifth-year emission 

reductions and costs for each option for 

new FCCU are summarized in Table 5 

to this preamble; the impacts for 

modified and reconstructed FCCU are 

summarized in Table 6 to this preamble. 

TABLE 5.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR NOX LIMITS CONSIDERED FOR NEW 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 NOX/yr) 

Cost effectiveness ($/ton) 

Overall Incremental 

1 ........................................................................................... 860 320 370 880 880 

2 ........................................................................................... 1,200 640 860 750 650 

3 ........................................................................................... 12,000 3,600 1,400 2,600 5,800 

TABLE 6.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR NOX LIMITS CONSIDERED FOR MODIFIED AND

RECONSTRUCTED 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 NOX/yr) 

Cost-effectiveness ($/ton) 

Overall Incremental 

1 ........................................................................................... 2,800 1,000 860 1,200 1,200 

2 ........................................................................................... 3,700 1,600 1,800 920 660 

3 ........................................................................................... 45,000 11,000 3,200 3,600 6,800 

Options 1 and 2 provide cost-effective 

NOX control with limited or no 

secondary impacts. The costs of Option 

1 and Option 2 are commensurate with 

the emission reductions for new FCCU 

as well as modified and reconstructed 

FCCU. Option 3 would impose 

compliance costs that are not warranted 

for the emissions reductions that would 

be achieved, as shown by the 

incremental cost-effectiveness values of 

about $6,000 per ton of NOX emission 

reduction between Option 2 and Option 

3. 

In evaluating these options, we also 

considered the secondary impacts. In 

addition to the direct PM impacts of 

SNCR and SCR, SCR and LoTOxTM

units require additional electrical 

consumption. The increased energy 

consumption for Option 3 is 40,000 

MW-hr/yr for new, modified, and 

reconstructed units. We also evaluated 

the secondary PM, SO2, and NOX

emission impacts of the additional 

electrical consumption for Option 3. 

Based on the energy impacts, Option 3 

will generate secondary emissions of 

PM, SO2, and NOX of 6, 150, and 57 

tons/yr, respectively. 


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Based on the impacts shown in Table 

5 and Table 6, and taking secondary 

impacts into account, we conclude that 

BDT is Option 2, a NOX emission limit 

of 80 ppmv, for all affected FCCU. For 

new FCCU, this option achieves NOX

emission reductions of 860 tons/yr from 

a baseline of 1,500 tons/yr at a cost of 

$750 per ton of NOX. For modified and 

reconstructed FCCU, this option 

achieves NOX emission reductions of 

1,800 tons/yr from a baseline of 3,600 

tons/yr at a cost of $920 per ton of NOX. 

D. PM and SO2 Limits for Fluid Coking 

Units 

Comment: Several commenters stated 

that EPA’s proposed standards for FCU 

under subpart Ja are inappropriate and 

not cost-effective. Commenters asserted 

that based on the significant differences 

between FCU and FCCU operations, a 

separate BDT determination is needed 

for FCCU and FCU. Commenters stated 

that an FCU has higher particulate 

loading; a heavier feedstock that 

typically contains a higher 

concentration of sulfur, increasing the 

SO2 and sulfur trioxide (SO3) emissions; 

and a wider range of feedstocks with 

considerable variability in the nitrogen 

content. 

The commenters noted that the 

impacts analysis performed for the FCU 

has shortcomings similar to those in the 

impacts analysis for FCCU (e.g., the 

analysis did not properly consider the 

additional costs and technical 

difficulties of meeting the proposed 

emission limits for modified or 

reconstructed sources, existing units are 

already controlled and thus the 

emission reductions have already been 

achieved). One commenter provided 

site-specific engineering cost estimates 

to indicate that the PM controls are 

much less cost-effective than EPA 

estimates. The commenter requested 

that EPA consider instances when 

wastewater limitations require 

regenerative wet scrubbers and amend 

the impact estimates accordingly. One 

commenter stated that a newly installed 

regenerative wet scrubber system on an 

existing FCU could not meet the 

proposed Ja PM standards. 

Response: As described in the 

preamble to the proposed standards, the 

original analysis assumed that one of 

the larger existing FCU will become a 

modified or reconstructed source in the 

next 5 years. However, the two larger 

FCU in the U.S. are both subject to 

consent decrees: one has installed 

controls and the other is in the process 

of installing controls. The remaining 

two FCU are significantly smaller than 

the original model FCU; therefore, a 

new analysis was conducted using a 

smaller model FCU indicative of the 

size of the two remaining FCU that are 

not subject to consent decree 

requirements. In our new analysis, this 

FCU has approximately one-half the 

sulfur content as the larger FCU for 

which we have data, based on 

information received regarding the 

variability in sulfur content across 

different FCU in the public comments. 

In addition to revising our impact 

analysis, we also collected additional 

source test data from the one FCU 

operating a newly installed wet scrubber 

system to better characterize the control 

system’s performance. At proposal, we 

had one FCU source test from this 

source, which suggested that the FCU 

wet scrubber could meet a PM limit of 

0.5 lb/1,000 coke burn. However, 

following proposal, we received an 

additional performance test for this 

same FCU wet scrubber with an 

emission rate between 0.5 and 1.0 lb/ 

1,000 lb coke burn. There was no 

indication of unusual performance 

during either of these two tests, so we 

conclude that these tests demonstrate 

the variability of the emission source 

and control system. Based on the 

available data, therefore, we conclude 

that an appropriate PM performance 

level to consider for a BDT analysis is 

1.0 lb/1,000 lb coke burn using EPA 

Method 5B (40 CFR part 60, Appendix 

A–3) for a FCU with a wet scrubber. We 

also conclude that the PM emission 

limit initially proposed for FCU had not 

been adequately demonstrated as an 

emission limit with which one must 

comply at all times. 

Using our revised model FCU and 

based on the additional source test data, 

we re-evaluated BDT for PM and SO2

emissions from FCU based on two 

options: (1) No new standards, or 

current subpart J; and (2) a PM limit of 

1.0 lb/1,000 lb coke burn (as measured 

using Methods 5B and 5F of 40 CFR part 

60, Appendix A–3), 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. Unlike the 

FCCU, catalyst additives cannot be used 

in a FCU to reduce SO2, so a wet 

scrubber is the most likely technology 

(and the one demonstrated technology) 

that would be used to meet the PM and 

SO2 limits of Option 2. Therefore, we 

estimated costs for an enhanced wet 

scrubber to meet both the PM and SO2

limits. The resulting emission 

reductions and costs for both of the 

options are shown in Table 7 of this 

preamble. 

TABLE 7.—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 

PM and SO2) 

2 ........................................................................................... 10,000 3,200 1,000 5,900 460 

2a ......................................................................................... 100,000 18,600 1,000 5,900 2,700 

One commenter indicated that we 

should consider the costs of a 

regenerative wet scrubber. This type of 

system is not needed in most 

applications; however, in the event such 

a system were needed, we estimated the 

cost of a regenerative wet scrubber to 

meet Option 2. The results of this 

analysis are also provided in Table 7 as 

Option 2a. As presented in Table 7, 

even under the most conservative 

assumptions the costs associated with 

the PM and SO2 emission reductions are 

reasonable. 

Based on the available technology and 

the costs presented in Table 7 to this 

preamble, we conclude that BDT is 

Option 2, which requires technology 

that reduces PM emissions to 1.0 lb/ 

1,000 of coke burn and reduces SO2

emissions to 50 ppmv averaged over 7 

days and 25 ppmv averaged over 365 

days. This option achieves PM emission 

reductions of 1,000 tons/yr from a 

baseline of 1,100 tons/yr and SO2

emission reductions of 5,900 tons/yr 

from a baseline of 6,100 tons/yr at a cost 

of $460 per ton of PM and SO2

combined. 

E. NOX Limit for Fluid Coking Units 

Comment: A number of commenters 

opposed the co-proposal of no NOX

standard for FCU, and some disagreed 

with EPA’s 80 ppmv NOX limit for FCU. 

These commenters recommended limits 


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of 20 ppmv as a 365-day rolling average 

and 40 ppmv as a 7-day rolling average 

for FCU, as has been successfully 

achieved under consent decrees. The 

commenters noted that these limits are 

achievable on new units without 

additional controls. 

One commenter supported the coproposal that no new NOX standard be 

established for FCU. 

Response: Similar to the revised 

analysis for PM and SO2 impacts, we reevaluated BDT for the FCU NOX

controls for a smaller modified or 

reconstructed FCU. We evaluated three 

options: (1) No new standards, which is 

the current subpart J; (2) outlet NOX

concentration of 80 ppmv; and (3) outlet 

NOX concentration of 20 ppmv. Similar 

to the analysis for FCCU NOX and 

depending on the baseline emissions for 

the FCU, we anticipate that Option 2 

can be met using combustion controls 

and Option 3 will require add-on 

control technology. The results of this 

analysis are shown in Table 8 to this 

preamble. 

TABLE 8.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR NOX 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 NOX /yr) 

Cost-effectiveness ($/ton) 

Overall Incremental 

2 ........................................................................................... 3,700 850 660 1,300 1,300 

3 ........................................................................................... 6,000 1,300 750 1,700 5,000 

The costs for Option 1 and Option 2 

are commensurate with the emission 

reductions, but the incremental impacts 

for Option 3 are not reasonable, as 

shown in Table 8. Option 3 achieves an 

additional 90 tons per year NOX

reduction, but the incremental costs 

between options 2 and 3 of achieving 

this reduction is $5,000 per ton of NOX

removed. The cost of achieving this 12 

percent additional emission reduction 

nearly triples the total annualized cost 

of operating the controls. As with FCCU, 

the add-on NOX controls for FCU have 

increased energy requirements and 

secondary air pollution impacts. Based 

on these projected impacts, we support 

our original determination that BDT is 

Option 2, or technology needed to meet 

an outlet NOX concentration of 80 ppmv 

or less. This option achieves NOX

emission reductions of 660 tons/yr from 

a baseline of 800 tons/yr at a cost of 

$1,300 per ton of NOX. 

F. SO2 Limit for Small Sulfur Recovery 

Plants 

Comment: One commenter stated that 

no new requirements should be added 

for SRP less than 20 LTD (small SRP) 

because the controls are not costeffective. The commenter provided data 

on tail gas treatment projects but noted 

that these costs are for large SRP, and 

controls for small SRP will be less costeffective. Several commenters noted that 

if EPA does establish standards for 

small SRP, the monitoring and 

compliance evaluation methods for the 

99 percent control standard are not 

clearly specified in the rule and could 

create difficulties in documenting 

compliance for small Claus plants. 

Therefore, the small SRP should be 

allowed to comply with the 250 ppmv 

SO2 emission limit provided to large 

SRP. One commenter suggested that 

non-Claus units should be subject to a 

95 percent recovery efficiency standard. 

Response: To ensure that we 

addressed the commenters’ concerns 

regarding cost-effectiveness, we reevaluated the impacts for small SRP. We 

adjusted our cost estimates upward 

based on capital costs provided by 

industry representatives. We evaluated 

three SO2 control options as part of the 

BDT determination for small SRP: (1) 

No new standards, or current subpart J; 

(2) 99 percent sulfur recovery; and (3) 

99.9 percent sulfur recovery. As noted 

in the preamble to the proposed 

standards (section V.D), the 99 percent 

and 99.9 percent recovery levels are 

achievable for SRP of all sizes by 

various types of SRP or tail gas 

treatments. 

The estimated fifth-year emission 

reductions and costs for new SRP are 

summarized in Table 9 to this preamble; 

the impacts for modified and 

reconstructed SRP are summarized in 

Table 10 to this preamble. These values 

reflect the impacts only for small SRP; 

there are no additional cost impacts for 

large Claus units because they would 

already have to comply with the 

existing standards in subpart J. 

TABLE 9.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR SO2 LIMITS CONSIDERED FOR NEW SMALL SULFUR

RECOVERY PLANTS 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 

2 ........................................................................................... 130 63 42 1,500 1,500 

3 ........................................................................................... 590 230 52 4,500 18,000 

TABLE 10.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR SO2 LIMITS CONSIDERED FOR MODIFIED AND

RECONSTRUCTED SMALL SULFUR RECOVERY PLANTS 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 

2 ........................................................................................... 1,600 670 380 1,800 1,800 


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TABLE 10.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR SO2 LIMITS CONSIDERED FOR MODIFIED AND

RECONSTRUCTED SMALL SULFUR RECOVERY PLANTS SUBJECT TO 40 CFR PART 60, SUBPART JA—Continued 

Option Capital cost 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Emission 

reduction 

(tons SO2/yr) 

Cost-effectiveness 

($/ton) 

Overall Incremental 

3 ........................................................................................... 7,800 2,600 470 5,700 23,000 

The costs for Option 2 are reasonable 

considering the emission reductions 

achieved, but the incremental impacts 

shown in Table 9 and Table 10 for 

Option 3 are beyond the costs that the 

Agency believes are reasonable for these 

small units to achieve an additional 100 

tons per year of SO2 emission 

reductions. The additional equipment 

needed to achieve these reductions 

quadruples the capital costs. These 

smaller units would also generally be 

found at small refineries. Based on these 

projected impacts and available 

performance data, we support our 

original determination that BDT is 

Option 2, or 99 percent sulfur recovery. 

For new SRP, this option achieves SO2

emission reductions of 42 tons/yr from 

a baseline of 150 tons/yr at a cost of 

$1,500 per ton of SO2. For modified and 

reconstructed SRP, this option achieves 

SO2 emission reductions of 380 tons/yr 

from a baseline of 1,400 tons/yr at a cost 

of $1,800 per ton of SO2. 

We note that we are also revising the 

format of the standard in response to 

public comments in terms of sulfur 

outlet concentrations. Based on the 

Option 2 BDT selection of a recovery 

efficiency of 99 percent, the emission 

limit for small SRP is either 2,500 ppmv 

SO2 or 3,000 ppmv reduced sulfur 

compounds and 100 ppmv of H2S, both 

of which are determined on a dry basis, 

corrected to 0 percent O2. 

G. NOX Limit for Process Heaters 

Comment: Several commenters stated 

that the 80 ppmv NOX limit for process 

heaters is not stringent enough. 

Commenters stated that considering 

recent settlement negotiations and 

regulation development, NOX emissions 

reductions well below 80 ppmv can be 

achieved cost effectively. The 

commenters stated that NOX emissions 

of less than 40 ppmv at 0 percent O2 are 

achievable with combustion 

modifications such as LNB, ultra low—

NOX burners (ULNB), and flue gas 

recirculation technologies; postcombustion controls such as SCR, 

SNCR, and LoTOxTM achieve NOX

reductions an order of magnitude below 

those from combustion modifications. 

The commenters noted that Bay Area 

Air Quality Management District 

(BAAQMD) Regulation 9, Rule 10, 

requires process heaters to meet a 0.033 

lb/MMBtu NOX limit (roughly 32 ppmv 

NOX at 0 percent oxygen). One 

commenter stated that 30 ppmv has 

been demonstrated under consent 

decrees to be an achievable level and 

ample technology exists. The 

commenters also noted that 7 to 10 

ppmv NOX limits (at 3 percent oxygen) 

have been achieved in practice. One 

commenter stated that NSPS subparts J 

and Ja should impose NOX emission 

limits on all fuel gas combustion 

devices that are at least as stringent as 

the most stringent consent decree. Some 

consent decrees require next generation 

ULNB designed to achieve NOX

emissions rates of 0.012 to 0.020 lb/ 

MMBtu (12 to 20 ppmv NOX at 0 

percent oxygen). Commenters 

recommending more stringent 

requirements suggested limits ranging 

from 7 ppmv NOX (at 3 percent oxygen) 

to 30 ppmv for new process heaters 

fueled by refinery fuel gas. 

Other commenters stated that 

alternative monitoring options should 

be provided to small fuel gas 

combustion devices due to the high 

costs of CEMS relative to the emissions 

from the small devices. One commenter 

suggested an exemption from the fuel 

gas monitoring requirements for process 

heaters less than 50 MMBtu/hr. Another 

commenter recommended an exemption 

from the fuel gas monitoring 

requirements for process heaters less 

than 40 MMBtu/hr as used by South 

Coast Air Quality Management District 

(SCAQMD). 

Response: We revisited the BDT 

determination based on the public 

comments and revised the methodology 

used to calculate the cost and emission 

reduction impacts for the proposed 

standards. We evaluated three options 

as part of the BDT determination. Each 

option consists of a potential NOX

emission limit and applicability based 

on process heater size. These differ 

slightly from the proposal options based 

o n commenter suggestions. Option 1 

would limit NOX emissions to 80 ppmv 

or less for all process heaters with a 

capacity greater than 20 MMBtu/hr (the 

proposed standards). Option 2 would 

limit NOX emissions to 40 ppmv or less 

for all process heaters with a capacity 

greater than 40 MMBtu/hr. This option 

is similar to many consent decrees that 

set an emission limit of 0.040 lb/MMBtu 

(roughly 40 ppmv NOX at 0 percent 

oxygen) for process heaters greater than 

40 MMBtu/hr. Option 3 would limit 

NOX emissions to 20 ppmv or less for 

all process heaters with a capacity 

greater than 40 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 for 

new process heaters are summarized in 

Table 11 of this preamble; impacts for 

modified and reconstructed process 

heaters are summarized in Table 12 of 

this preamble. Similar to the proposal 

analysis, we considered LNB, ULNB, 

flue gas recirculation, SCR, SNCR, and 

LoTOxTM as feasible technologies. We 

believe that nearly all process heaters at 

refineries that will become subject to 

subpart Ja can meet Option 1 or Option 

2 using combustion controls (LNB or 

ULNB). Most process heaters would 

need to use more efficient control 

technologies, such as LoTOxTM or SCR, 

to meet the NOX concentration limit in 

Option 3. Per commenters’ request to 

focus on the larger units, Options 2 and 

3 do not include process heaters 

between 20 MMBtu/hr and 40 MMBtu/ 

hr. We evaluated the cost-effectiveness 

of NOX control options for these units 

to achieve the proposed standard of 80 

ppmv. For these process heaters with 

smaller capacities we found the costeffectiveness ranged from $3,500/ton to 

$4,200/ton of NOX reduced, which was 

determined not to be reasonable for 

these small heaters, which would 

primarily be located at small refineries. 


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TABLE 11.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR NOX LIMITS CONSIDERED FOR NEW PROCESS HEATERS

SUBJECT TO 40 CFR PART 60, SUBPART JA

Option Capital cost 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Emission 

reduction 

(tons NOX/yr) 

Cost-effectiveness 

($/ton) 

Overall Incremental 

1 ........................................................................................... 9,000 7,300 4,800 1,500 1,500 

2 ........................................................................................... 9,000 7,500 5,200 1,400 500 

3 ........................................................................................... 110,000 30,000 5,900 5,100 37,000 

TABLE 12.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR NOX LIMITS CONSIDERED FOR MODIFIED AND

RECONSTRUCTED PROCESS HEATERS SUBJECT TO 40 CFR PART 60, SUBPART JA

Option Capital cost 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Emission 

reduction 

(tons NOX/yr) 

Cost-effectiveness 

($/ton) 

Overall Incremental 

1 ........................................................................................... 12,000 4,000 2,100 1,900 1,900 

2 ........................................................................................... 14,000 4,300 2,200 1,900 2,100 

3 ........................................................................................... 64,000 15,000 2,500 5,900 39,000 

Based on the impacts in Table 11 and 

Table 12, the costs of Options 1 and 2 

are reasonable compared to the emission 

reductions. The incremental cost 

between Options 2 and 3 of almost 

$40,000/ton of NOX is not 

commensurate with the additional 1,000 

tons of emission reduction achieved for 

new and modified or reconstructed 

process heaters. Moreover, the capital 

costs of Option 3 are about $150 million 

greater than the capital costs for Option 

2, which are only $23 million. 

Therefore, we conclude that BDT for 

process heaters greater than 40 MMBtu/ 

hr is technology that achieves an outlet 

NOX concentration of 40 ppmv or less, 

or Option 2. For new process heaters, 

this option achieves NOX emission 

reductions of 5,200 tons/yr from a 

baseline of 7,500 tons/yr at a cost of 

$1,400 per ton of NOX. For modified 

and reconstructed process heaters, this 

option achieves NOX emission 

reductions of 2,200 tons/yr from a 

baseline of 3,200 tons/yr at a cost of 

$1,900 per ton of NOX. Although we 

agree that lower NOX concentrations are 

achievable, we determined that the 

incremental cost to achieve these lower 

NOX concentrations was not reasonable. 

H. Fuel Gas Combustion Devices 

Comment: Several commenters 

contended that the proposed standards 

for fuel gas combustion devices were 

not stringent enough; EPA should 

ensure that the best demonstrated 

emission control technologies are 

installed as the industry is modernized. 

Given the significant hazards to human 

health and the environment posed by 

SO2 emissions, the commenters 

suggested that the 365-day average 

limits should be 40 ppmv TRS and 5 

ppmv SO2. The commenters also 

recommended that EPA tighten the 3- 

hour concentration limit to 100 ppmv 

TRS. On the other hand, another 

commenter contended that although 

amine treatment applications for 

product gases can achieve H2S 

concentrations of 1 to 5 ppmv, a tighter 

standard is not BDT for refinery fuel gas. 

Several commenters objected to the 

addition of the 60 ppmv H2S and 8 

ppmv SO2 limits (365-day rolling 

average) in the proposed subpart Ja 

standards for fuel gas combustion 

devices because they are infeasible and/ 

or not cost-effective. According to 

commenters, EPA erroneously assumed 

that the additional reductions could be 

achieved with existing equipment. 

Although this may be true in some 

cases, commenters asserted that some 

refineries would need to add additional 

amine adsorber/regenerator capacity 

and some may also need to add 

additional sulfur recovery capacity (e.g., 

an additional Claus train and tail gas 

treatment unit). One commenter 

requested an exemption be provided for 

refineries that cannot meet the tighter 

long-term standard by simply increasing 

their amine circulation rates. One 

commenter stated that there will be 

little incremental environmental benefit 

from the long-term limit, and it 

unnecessarily penalizes refineries that 

designed their amine systems to treat to 

levels near the proposed annual 

standard. The commenters provided 

cost data for examples of projects 

requiring new amine adsorption units to 

show that the proposed standards are 

not cost-effective. 

A number of commenters particularly 

opposed the proposed revision to 

include TRS limits for fuel gas produced 

from coking units or any fuel gas mixed 

with fuel gas produced from coking 

units. One commenter noted that some 

State and local agencies have specific 

TRS standards, but these requirements 

were not based on a BDT assessment. 

According to commenters, EPA has 

included no technical basis for the 

achievability of the TRS fuel gas 

standard or explanation of why control 

of TRS is limited to fuel gas generated 

by coking units. The commenters 

recommended that EPA postpone 

adoption of a TRS limit until it has 

gathered and evaluated adequate data to 

conclude that the limit is technically 

feasible and cost effective. 

Commenters stated that EPA did not 

address the cost-effectiveness and nonair quality impacts of the TRS standards 

and did not define BDT for the removal 

of TRS. One commenter stated that 

without an established de minimis level, 

an entire fuel gas system could be 

subject to the TRS limits if any amount 

of coker gas enters the fuel gas system. 

Amine scrubbing systems are selective 

to H2S and are not suitable to other TRS 

compounds such as mercaptans, 

according to the commenters. 

Commenters stated that the non-H2S 

TRS compounds are not amenable to 

amine treating and there is no 

technology readily in-place at refineries 

for reducing non-H2S TRS compounds. 

Therefore, according to the commenters, 

removing these other TRS compounds 

would require significant capital outlay 

for new equipment, costs that were not 

considered in the impacts analysis. 


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35852 Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules and Regulations 

One commenter provided an example 

of a treatment system installed to meet 

a facility-wide fuel gas total sulfur 

standard of 40 ppmv; the commenter 

estimated the capital cost of the entire 

system to be $150 million. The 

commenter also indicated that low-BTU 

gas from flexicoking units would need 

to be specially treated at a capital cost 

of $61 million to achieve a total sulfur 

content of less than 150 ppmv, and the 

treatment would increase energy 

consumption, resulting in increases in 

NOX and CO emissions. Another 

commenter provided an order-ofmagnitude engineering estimate of $50 

million to treat TRS down to 45 ppmv 

(long-term average). Based on one 

commenter’s experience with a new fuel 

gas treating facility, non-acidic TRS 

cannot be treated down to the proposed 

levels utilizing Merox-amine treatment. 

A cost-effective solution could be 

natural gas blending at the affected 

combustion device; however, this 

option has the negative effect of 

reducing the production of refinery fuel 

gas and therefore reducing the refinery’s 

capacity for making gasoline. 

Several commenters stated that the 

original BDT determination was based 

on amine scrubbing of H2S and not on 

SO2; the SO2 standard was simply a 

compliance option that was calculated 

to be equivalent to the H2S 

concentration limit at 0 percent excess 

air. They also asserted that EPA cannot 

use the SO2 option as a basis for the TRS 

standard because the SO2 option is not 

BDT. On the other hand, one commenter 

requested that EPA clarify the fuel gas 

standards in subpart J to expressly 

indicate that the 20 ppmv SO2 limit is 

a valid compliance option (instead of 

including it only in the monitoring 

section). According to the commenter, 

focus has been on H2S due to the 

structure of the requirements of subpart 

J and permits rarely require that 

combustion sources demonstrate 

compliance with the 20 ppmv SO2 limit. 

The commenter stated that refiners 

clearly should be allowed to comply 

with the broader, more comprehensive 

SO2 limit. 

A few commenters noted that, as H2S 

is part of TRS, the TRS standard is even 

more stringent than the H2S standard. 

One commenter recommended that no 

change in the fuel gas standards be 

made or that the standards focus on H2S 

only with an alternative emission limit 

for SO2. One commenter stated that EPA 

developed the 160 ppmv H2S standard 

to be more stringent than the 20 ppmv 

SO2 standard specifically because H2S 

did not represent all of the sulfur in the 

fuel gas. Commenters stated that using 

an F-factor approach (Method 19, 40 

CFR part 60, Appendix A–7), the TRS 

limit that is equivalent to the 20 ppmv 

SO2 emission limit is 260 ppmv and the 

TRS limit that is equivalent to the 8 

ppmv SO2 emission limit is 104 ppmv. 

Response: We initially concluded that 

fuel gas generated by the coking unit 

was mixed with other fuel gases that 

were mostly H2S and that increasing the 

amine circulation rate would result in 

additional H2S removal that could be 

used to meet the proposed standard. 

However, based on a review of the 

available data, non-H2S sulfur content 

in coker fuel gas may be 300 to 500 

ppmv. At these levels, specific 

treatment to reduce these other sulfur 

compounds would be needed. As 

indicated by one commenter, a plantwide total sulfur limit of 40 ppmv has 

been achieved in practice in at least one 

refinery using a treatment train 

consisting of a Merox system, sponge oil 

absorbers, MEA absorbers, and caustic 

wash towers. Therefore, total sulfur fuel 

gas treatment methods are 

demonstrated. We evaluated the cost of 

this treatment based on information 

provided in the public comments. 

Based on the public comments and 

additional data, we revisited the BDT 

determination and assessed three 

options for increasing SO2 control of 

fuel gas combustion devices: (1) 20 

ppmv SO2 or 162 ppmv H2S averaged 

over 3 hours; (2) Option 1 plus 8 ppmv 

SO2 or 60 ppmv H2S averaged over 365 

days; and (3) a compliance option of 162 

ppmv TRS averaged over 3 hours and 60 

ppmv TRS averaged over 365 days for 

fuel gas combustion devices combusting 

fuel gas generated by a coking unit and 

Option 2 for combustion devices 

combusting fuel gas not generated by a 

coking unit. Option 1 includes the same 

limits that are in subpart J, so there are 

no additional costs or emission 

reductions beyond those expected from 

the application of subpart J. To address 

the commenters’ concerns that not all 

facilities have available amine capacity 

to ensure compliance with the new 

long-term limits, we revised our 

proposal analysis to include additional 

costs for the estimated 10 percent of the 

affected facilities that would increase 

their amine capacity to achieve Option 

2. We estimated costs for a separate 

treatment train that can treat TRS for 

Option 3 because, based on the public 

comments received, we have concluded 

that amine treatment systems are not 

effective for non-H2S components of 

TRS. The estimated fifth-year impacts of 

each of these options for new fuel gas 

combustion devices are presented in 

Table 13 of this preamble; the impacts 

for modified and reconstructed fuel gas 

combustion devices are presented in 

Table 14 of this preamble. 

TABLE 13.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR SO2 LIMITS CONSIDERED FOR NEW 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 

2 ........................................................................................... 1,200 720 510 1,400 1,400 

3 ........................................................................................... 100,000 13,000 770 17,000 47,000 

TABLE 14.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR SO2 LIMITS CONSIDERED FOR MODIFIED AND

RECONSTRUCTED 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 

2 ........................................................................................... 33,000 11,000 4,700 2,400 2,400 

3 ........................................................................................... 1,700,000 200,000 7,600 26,000 63,000 


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Overall costs for Options 1 and 2 are 

reasonable compared to the emission 

reduction achieved for new, modified 

and reconstructed fuel gas combustion 

devices. We further evaluated the 

incremental costs and reductions 

between the three options and found 

that they were reasonable for Options 1 

and 2, while the incremental cost for 

Option 3 is not. While Option 3 

provides significant additional SO2

emission reductions, the additional 

capital cost of $1.7 billion is high and 

could pose a significant barrier to future 

refinery upgrades and expansions. 

Based on these impacts and 

consideration of current operating 

practices, we conclude that BDT is use 

of technology that reduces the emissions 

from affected fuel gas combustion 

devices to 20 ppmv SO2 or 162 ppmv 

H2S averaged over 3 hours and 8 ppmv 

SO2 or 60 ppmv H2S averaged over 365 

days, or Option 2. For new fuel gas 

combustion devices, this option 

achieves SO2 emission reductions of 510 

tons/yr from a baseline of 1,000 tons/yr 

at a cost of $1,400 per ton of SO2. For 

modified and reconstructed fuel gas 

combustion devices, this option 

achieves SO2 emission reductions of 

4,700 tons/yr from a baseline of 10,000 

tons/yr at a cost of $2,400 per ton of 

SO2. 

We note that although we have 

determined that Option 3 is not BDT 

and we will not limit the amount of SO2

emissions from combustion of sulfur 

compounds other than H2S in subpart 

Ja, we plan to continue to work with the 

industry to understand the magnitude of 

these SO2 emissions and to identify 

technologies that can be cost effectively 

applied to reduce the emissions. We 

have learned through this process that 

the SO2 emissions from combustion of 

TRS in coker gas are generally not 

reflected in emission inventories and we 

plan to explore this issue in greater 

detail in the future to determine where 

SO2 emissions are underestimated and 

the best way to correct the inventories. 

Comment: Several commenters stated 

that it is impossible for a refinery owner 

or operator to specify, acquire, install, 

and calibrate a continuous monitoring 

system within 15 days of a change that 

increases the H2S concentration such 

that an exempt stream is no longer 

exempt. One commenter suggested 

quarterly stain tube sampling for 1 year 

prior to revoking an exemption from 

monitoring to confirm the change is 

permanent. The commenter suggested 

that after 1 year of confirmation, an 

additional 12 months be provided to 

specify, acquire, install, and calibrate 

the continuous monitoring system. One 

commenter suggested 1 year be 

provided for installing a CEMS, while 

another commenter suggested 180 days 

be provided (with an allowance for an 

additional extension) for installing a 

CEMS, rather than the 15 days 

proposed. 

Response: We believe that in most 

cases, the process change would be a 

deliberate, planned act and that the 

potential consequences of this 

deliberate change would be evaluated. 

That is, before the equipment is 

modified, the refinery owner or operator 

is expected to assess the impacts of this 

change on the exempted fuel gas stream. 

If the change is expected to increase the 

sulfur content of the fuel gas, than the 

owner or operator can plan to install the 

required CEMS when modifying the 

process. We recognize that some process 

changes may have unexpected 

consequences, and a modification that 

was not expected to increase the sulfur 

content of the fuel gas can result in an 

increase in sulfur content. In this case, 

it may be impossible to install the 

required CEMS within 15 days. 

However, quarterly sampling does not 

provide any basis by which the refinery 

owner or operator can demonstrate 

compliance with the H2S concentration 

standard. Instead, we have added 

provisions that require an owner or 

operator to install a CEMS as soon as 

practicable and no later than 180 days 

after a change that makes the stream no 

longer exempt. Between the process 

change and the time a CEMS is 

installed, the owner or operator must 

conduct daily stain tube sampling to 

demonstrate compliance with the H2S 

concentration standard. During this 

time, a single daily sample exceeding 

162 ppmv must be reported as an 

exceedance of the 3-hour H2S 

concentration limit and a rolling 365- 

day average concentration must be 

determined. A daily average H2S 

concentration of 5 ppmv is to be used 

for the days prior to the process change 

for the previously exempt stream in 

calculating the rolling 365-day average 

concentration. 

I. Flaring of Refinery Fuel Gas 

Comment: Several commenters 

supported the proposed work practice 

standards to eliminate routine flaring 

and develop startup, shutdown, and 

malfunction (SSM) plans; the 

commenters opposed the co-proposal of 

no standards. One commenter 

supported the determination that 

elimination of routine flaring is BDT, 

citing reductions in hydrocarbon, NOX, 

SO2, and carbon dioxide (CO2) 

emissions. One commenter stated that 

both subparts J and Ja should explicitly 

require that flaring be used only as a last 

resort in unusual circumstances, such as 

emergencies, and not on a routine basis. 

Commenters asserted that monitoring on 

an ongoing basis is needed to verify that 

no flaring of nonexempt gases occurs. 

Commenters stated that subpart Ja 

should also require refiners to install a 

flare gas recovery system, although such 

requirements should not preclude 

monitoring requirements. One 

commenter stated that the NSPS should 

require a SSM plan to eliminate venting 

or flaring during such planned start-up, 

shutdown, and maintenance activities 

and explicitly prohibit venting or flaring 

during these planned activities; proper 

operation and maintenance practices 

should completely eliminate the need to 

use flares during these activities. One 

commenter noted that those refineries 

that have evaluated their startup and 

shutdown procedures to reduce or 

eliminate direct venting or flaring 

during planned startup and shutdown 

events have demonstrated the best 

technology; therefore, their actions 

represent BDT and should be adopted in 

the NSPS. The commenters also 

supported conducting a root cause 

analysis (RCA) in the event of flaring 

and other venting releases of 500 lb/day 

SO2. 

A number of commenters generally 

supported the intent to reduce flaring 

and the idea of SSM plans to address 

flaring during planned startups and 

shutdowns (one commenter also 

included combustion of high sulfurcontaining fuel gases during a 

malfunction), flare management plans, 

and RCA for flare events in excess of 

500 lb/day. However, they opposed the 

work practice standard for elimination 

of routine flaring and the proposed 

creation of fuel gas producing units for 

subpart Ja. The commenters stated that 

the definition of ‘‘fuel gas producing 

unit’’ is overly broad, making it difficult 

to determine what constitutes a 

modification or reconstruction, and the 

proposed work practice standard for 

these units is infeasible, unnecessary, 

and not cost-effective. Facility operators 

and regulators would have difficulty 

discerning if a flaring event was caused 

by an affected fuel gas producing unit or 

a unit not subject to the standard. One 

commenter indicated that there is no de 

minimis level by which units that 

produce insignificant quantities of fuel 

gas can be excluded from the extensive 

work practice standards. 

Commenters recommended that the 

affected source be the flare which is 

already subject to the standard as a fuel 

gas combustion device. The commenters 

suggested that for each affected flare, the 

facility would develop a written Flare 

Management Plan designed to minimize 


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35854 Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules and Regulations 

flaring of fuel gas during all periods of 

operation. This plan, along with the 

RCA, would ensure that all flaring 

events with potential excess emissions 

will be minimized. One commenter 

noted that EPA could require a flare 

management plan for any flare tied to a 

fuel gas system that has an affected fuel 

gas combustion device as a better 

alternative to ‘‘fuel gas producing 

units.’’ One commenter noted that an 

exemption from the notification 

requirements for modified or 

reconstructed units could be provided 

as an incentive for early adoption of the 

flare management plan; another 

commenter suggested that regulatory 

incentives such as exemptions from 

monitoring and developing flare 

management plans should be provided 

for facilities that have installed flare gas 

recovery systems. One commenter 

supported this type of requirement for 

flares currently subject to subpart J, 

assuming a minimum of 9 months is 

provided for plan development and 

implementation. On the other hand, one 

commenter noted that the definitions of 

the affected facility under subparts J and 

Ja are different and recommended that 

the distinction be made stronger so that 

it is clear that existing process unit 

facilities are ‘‘grandfathered’’ and 

exempt from the flaring minimization 

standards. 

One commenter suggested that the 

work practices language should be 

clarified to indicate that routing offgas 

to the flare system would be acceptable 

if the system was equipped with a flare 

gas recovery system. The prohibition 

should be specific to the flare itself as 

some flare systems are equipped with 

recovery compressors, the use of which 

should be encouraged rather than 

discouraged. 

Commenters stressed the need for 

flares as safety devices; any flare 

minimization program must not 

interfere with the ability of the refinery 

owner or operator to use flares for safety 

reasons. The commenters stated that 

‘‘routine’’ flaring cannot be adequately 

defined in practice; therefore, 

restrictions on ‘‘routine’’ flaring will 

lead to unsafe operations in attempts to 

avoid enforcement actions. The 

commenters requested that EPA include 

language in the regulation, consistent 

with the preamble discussion, that: 

‘‘Nothing in this rule should be 

construed to compromise refinery 

operations and practices with regard to 

safety.’’

One commenter indicated that the 

proposed work practice standards for 

‘‘no routine flaring’’ interfere with flare 

minimization plans implemented in 

response to consent decrees. The 

proposed work practice standard could 

be interpreted as prohibiting flaring 

during start-up and shutdown, and EPA 

has not determined this to be BDT. The 

commenter stated that the BAAQMD 

analysis applies to eliminating flaring 

during normal operation [similar to 

proposed § 60.103a(b)], not during startup and shutdown as in proposed 

§ 60.103a(a). The commenter provided 

cost estimates for one refinery to install 

a recovery system to eliminate flaring 

during start-up and shutdowns; the 

costs ranged from $200,000 to $800,000 

per ton of VOC reduced and higher for 

other criteria pollutants. Therefore, they 

contend § 60.103a(a) should clearly 

exclude start-up and shutdown gases. 

A few commenters provided overall 

project costs for flare gas recovery 

projects indicating the annual costs are 

higher than those in the analysis 

supporting the proposed work practice. 

One commenter stated that EPA 

underestimated the cost of flare gas 

recovery systems and, given the 

uncertainty in emission reductions, 

contended that flare gas recovery 

systems for the no-flaring option are not 

cost-effective within the NSPS context. 

The commenter also stated that the 

regulation should include maintenance 

provisions for flare gas recovery systems 

(that allow flaring) during times of 

routine and non-routine maintenance, 

as no redundant capacity within the 

flare system exists. 

A number of commenters provided an 

alternative to EPA’s proposed work 

practice standards. The suggestions 

included a 500 lb/day SO2 standard tied 

with a flare management plan as an 

alternative compliance option (to the 

H2S concentration limit) for flares. The 

commenters recommended that this 

alternative compliance option be 

provided in both subparts J and Ja and 

noted that it could be used as an 

incentive for the flare management plan 

to cover all flares. One commenter also 

noted that these requirements should be 

applicable to flares that receive process 

gas, fuel gas, or process upset gas; they 

should not be applicable to flares used 

solely as an air pollution control device, 

such as a flare used exclusively to 

control emissions from a gasoline 

loading rack. Another commenter 

clarified that if the refinery elects to 

comply with this alternative for any 

flare, all flares at the refinery would 

need a flare management plan. The 

commenter noted that EPA could 

choose to set the 500 lb/day SO2 limit 

as a total for all flares for which the 

alternative compliance option is chosen 

(i.e., if the alternative compliance 

option is selected for two flares at a 

refinery, the total emissions from both 

flares would be limited to 500 lb/day). 

Response: Although commenters 

suggested that certain provisions be 

made applicable to facilities subject to 

subpart J, the following provisions are 

only applicable to facilities subject to 

subpart Ja as CAA section 111 provides 

that new requirements apply only to 

new sources. We considered these 

comments and agree that the standards 

are more straightforward when the 

affected facility is defined as the flare. 

Therefore, we have eliminated ‘‘fuel gas 

producing units’’ as an affected facility 

in this final rule, and we specifically 

define a flare as a subset of fuel gas 

combustion device, which is an affected 

facility in this final rule. A ‘‘flare’’

means ‘‘an open-flame fuel gas 

combustion device used for burning off 

unwanted gas or flammable gas and 

liquids. The flare includes the 

foundation, flare tip, structural support, 

burner, igniter, flare controls including 

air injection or steam injection systems, 

flame arrestors, knockout pots, piping 

and header systems.’’

There are three general work practice 

standards that were proposed for ‘‘fuel 

gas producing units,’’ which may be 

summarized as follows: (1) The ‘‘no 

routine flaring’’ requirement; (2) flare 

minimization plan for start-up, 

shutdown, and malfunction events; and 

(3) a root-cause analysis for SO2 releases 

exceeding 500 lb/day (which was 

proposed for all affected fuel gas 

producing units). The ‘‘no routine 

flaring’’ work practice was not intended 

to prohibit flaring during SSM events; 

the provisions were intended to apply 

only during normal operating 

conditions. We agree with the 

commenter that suggested that nothing 

in this rule should be construed to 

compromise refinery operations and 

practices with regard to safety. 

Additionally, as discussed in the 

preamble to the proposed rule, we 

specifically rejected a prohibition on 

flaring for planned start-up and 

shutdown events. We agree with the 

commenters that noted that numerous 

refineries have demonstrated that flare 

minimization during planned start-up 

and shutdown activities can greatly 

reduce flaring during these events. We 

do believe, however, that a complete 

elimination of flaring during these 

events is very site-specific and although 

it is reported to have been achieved at 

a limited number of refineries, we do 

not have information to suggest that it 

has been adequately demonstrated for 

universal application. As ‘‘no routine 

flaring’’ is difficult to define in practice, 

we have re-evaluated BDT using more 

specific options. 


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Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules and Regulations 35855 

Option 1 is no additional standards 

for flares. In Option 2, any routine 

emissions event or any process start-up, 

shutdown, upset or malfunction that 

causes a discharge into the atmosphere 

more than 500 pounds per day of SO2

(in excess of the allowable emission 

limit) from an affected fuel gas 

combustion device or sulfur recovery 

plant would require a root cause 

analysis to be performed. This approach 

is similar to what is included in most 

consent decrees. We are also including 

a requirement for continuous 

monitoring of TRS for all gases flared 

(including those from upsets, startups, 

shutdowns, and malfunction events), in 

order to accurately measure SO2

emissions from affected flares. 

Option 3 includes: (1) The SO2 root 

cause analysis in Option 2; (2) a limit on 

the fuel gas flow rate to the flare of 

250,000 scfd; and (3) a flare 

management plan for SSM events. The 

flow limit of 250,000 scfd is based on 

our cost analysis that indicates that for 

typical gas streams in quantities above 

this limit, the value of recovered fuel 

completely offsets the costs of installing 

and operating recovery systems. Many 

refineries have implemented flare gas 

recovery to reduce energy needs and 

save money. The flare management plan 

must: (1) Include a diagram illustrating 

all connections to each affected flare; (2) 

identify the flow rate monitoring device 

and a detailed description of 

manufacturer’s specifications regarding 

quality assurance procedures; (3) 

include standard operating procedures 

for planned start-ups and shutdowns of 

refinery process units that vent to the 

flare (such as staging of process 

shutdowns) to minimize flaring during 

these events; (4) include procedures for 

a root cause analysis of any process 

upset or equipment malfunction that 

causes a discharge to the flare in excess 

of 500,000 scfd; and (5) include an 

evaluation of potential causes of fuel gas 

imbalances (i.e., excess fuel gas), upsets 

or malfunctions and procedures to 

minimize their occurrence and records 

to be maintained to document periods of 

excess fuel gas. Excess emission events 

for the flow rate limit of 250,000 scfd 

and the result of root cause analysis 

must be reported in the semi-annual 

compliance reports. 

Option 4 is identical to Option 3 

except that flaring is limited to 50,000 

scfd. This level is estimated to be a 

baseline level that accounts for the flow 

requirement needed to maintain safe 

operations of the flare (i.e., flow of 

sweep gas and compressor cycle gas). 

For both Option 3 and Option 4, the 

limit on the flow rate does not apply 

during malfunctions and unplanned 

startups and shutdowns. The flow rate 

limits in Options 3 and 4 were 

developed to reduce VOC, SO2, and 

NOX emissions; the limits are based on 

30-day rolling average flow rate values. 

It is anticipated that a flare gas 

recovery system will be used to comply 

with Options 3 and 4 when a flare is 

currently used on a continuous basis, 

and the recovered flare gas offsets 

natural gas purchases. The costeffectiveness of the flare gas recovery 

system is primarily dependent on the 

quantity of gas that the system can 

recover. Many refineries have already 

implemented similar work practices 

through consent decrees and local rules 

(BAAQMD and SCAQMD), and these 

requirements have had a demonstrated 

reduction in flaring events. Flare gas 

recovery will reduce SO2, NOX, and 

VOC emissions. However, if a refinery 

produces more fuel gas than the refinery 

needs to power its equipment, there is 

no place the refinery can use the 

recovered fuel gas and there is no 

additional natural gas purchases to 

offset. In these cases, flare gas recovery 

is not considered technically feasible 

because the excess fuel gas will have to 

be flared. Therefore, we have included 

specific provision within the flare 

management plan to address instances 

of excess fuel gas. For periods when the 

refinery owner or operator can 

demonstrate, through records of natural 

gas purchases or other means as 

described in their flare management 

plan, that the refinery is fuel gas rich, 

compliance with the flow limit is 

demonstrated by implementing the 

procedures described in the flare 

management plan. 

Impacts for each of the four options 

are based on estimates of current flaring 

quantities and include the root cause 

analysis, flare management plan, and 

flare gas recovery systems when needed. 

The impacts for each option for new 

flares are presented in Table 15 to this 

preamble; impacts for modified and 

reconstructed flares are presented in 

Table 16 to this preamble. 

TABLE 15.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR WORK PRACTICES CONSIDERED FOR NEW FLARING

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) 

Emission 

reduction 

(tons NOX/yr) 

Emission 

reduction 

(tons VOC/yr) 

Cost-effectiveness ($/ton) 

Overall Incremental 

2 ................................... 0 23 15 0 0 1,600 1,600 

3 ................................... 8,800 (1,300) 16 1 41 (23,000) (31,000) 

4 ................................... 15,000 (840) 16 1 52 (12,000) 43,000 

TABLE 16.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR WORK PRACTICES CONSIDERED FOR MODIFIED AND

RECONSTRUCTED FLARING 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) 

Emission 

reduction 

(tons NOX/yr) 

Emission 

reduction 

(tons VOC/yr) 

Cost-effectiveness ($/ton) 

Overall Incremental 

2 ................................... 0 92 59 0 0 1,600 1,600 

3 ................................... 35,000 (5,300) 64 4 165 (23,000) (31,000) 

4 ................................... 59,000 (3,300) 66 6 207 (12,000) 43,000 

Based on these impacts and 

consideration of technically feasible 

operating practices, we conclude that 

BDT is Option 3. Option 3 includes a set 

of work practice standards that requires 

root cause analysis for a discharge into 

the atmosphere in excess of 500 pounds 

per day of SO2 (over the allowable 

emission limit) from a fuel gas 

combustion device or sulfur recovery 

plant or in excess of 500,000 scfd flow 

to a flare. It also includes a flare 


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management plan. Finally, fuel gas flow 

to the flare is limited to 250,000 scfd. To 

support implementation of these 

requirements, monitoring and reporting 

of the flow rate and sulfur content is 

required. For new flaring devices, this 

option achieves SO2 emission 

reductions of 16 tons/yr from a baseline 

of 32 tons/yr, NOX emission reductions 

of 1 tons/yr from a baseline of 2 tons/ 

yr, and VOC emission reductions of 41 

tons/yr from a baseline of 67 tons/yr 

with a net fuel savings of $23,000 per 

ton of combined SO2, NOX, and VOC. 

For modified and reconstructed flaring 

devices, this option achieves SO2

emission reductions of 64 tons/yr from 

a baseline of 129 tons/yr, NOX emission 

reductions of 4 tons/yr from a baseline 

of 7 tons/yr, and VOC emission 

reductions of 165 tons/yr from a 

baseline of 266 tons/yr with a net fuel 

savings of $23,000 per ton of combined 

SO2, NOX, and VOC. 

The flare gas minimization 

requirements included in the final 

standards are important to reduce 

criteria pollutant emissions and 

conserve energy. However, we recognize 

that owners and operators also need to 

be able to make quick changes to 

existing process units or flare systems to 

avoid unsafe conditions. It could take an 

owner or operator more time to 

implement the flare requirements, 

especially flow monitoring and any 

physical changes needed to comply 

with the limit on flow to the flare, than 

it took to implement the change to the 

flare that caused it to be an affected 

facility. There is the potential for 

serious safety concerns if the owner or 

operator must wait until compliance has 

been achieved with all of the flare gas 

minimization requirements prior to 

venting explosive vapors to the flare or 

modifying the flare system, such as 

adding a knockout pot for safety 

reasons. Moreover, avoiding unsafe 

conditions by requiring immediate 

shutdown of all process units connected 

to the potentially affected flare while 

the owner or operator takes steps to 

comply with the final provisions 

specific to flare gas minimization results 

in additional emissions, significant 

costs, and large lost production of 

refined products. By providing 1 year 

for modified flares to comply with these 

flare gas minimization provisions, 

refinery owners and operators have 

sufficient time to coordinate the 

installation of the flow rate and sulfur 

content monitors, to take whatever steps 

necessary to meet the flow limitations, 

to develop and implement the flare 

management plan, and to make other 

modifications, if needed, regarding 

safety and maintenance considerations 

for other process equipment tied to the 

flare. 

Considering the cost and the energy 

penalty from the reduction in refined 

products (e.g., the need to shut down 

the refinery until the flare gas 

minimization requirements can be met) 

and emissions associated with the 

immediate application of these 

requirements of the rule to modified 

flares, we determined that BDT was to 

phase in the requirements. The owner or 

operator of a modified flare would have 

to comply with the applicable H2S limit 

immediately and would have 1 year to 

implement the flare gas minimization 

requirements. Therefore, the final 

standards specify that for modified 

flares, the H2S limits for fuel gas 

combustion units apply immediately 

and the flare gas minimization 

requirements apply no later than 1 year 

after the flare becomes an affected 

facility. For newly constructed and 

reconstructed flares, the H2S limits and 

all of the flare gas minimization 

requirements apply immediately upon 

start-up of the affected flare. 

Comment: Several commenters 

requested clarification of how one 

would assess a flare ‘‘modification.’’

Questions included: (1) How the 

emission basis of a flare should be 

calculated; (2) if the modification 

determination would be based on flare 

capacity or increase in discharge 

capability of units connected to the 

flare; (3) whether the modification 

determination would include all 

possible flaring events or just nonemergency flaring; (4) whether adding a 

new line to a flare is considered to 

increase the capacity of the flare and 

cause a modification; (5) whether flare 

tip replacements are considered routine 

maintenance instead of a modification 

of the flare, even if the new flare tip has 

a different geometry (e.g., a larger 

diameter to reduce noise); and (6) how 

SSM streams are considered when 

calculating baseline emissions for a 

modification determination. The 

commenters also suggested that EPA 

should clarify whether and how the 

exemption in § 60.14(e)(2) applies to a 

flare, including how the production rate 

for a flare would be defined. 

Response: Section 60.14(a) defines 

modification as follows: ‘‘Except as 

provided in paragraphs (e) and (f) of this 

section, 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 shall be 

considered a modification.’’ Section 

60.14(e) provides exclusions for 

maintenance activities, increased 

production rates, increased hours of 

operation, etc. However, except for the 

maintenance exclusion, the other 

exemptions are either not applicable or 

ambiguous when applied to a flare. 

More importantly, § 60.14(f) states that 

‘‘Applicable provisions set forth under 

an applicable subpart of this part shall 

supersede any conflicting provisions of 

this section.’’ Therefore, to eliminate 

ambiguity, we specifically define what 

constitutes a flare modification in 

subpart Ja. 

A flare is considered to be modified 

in one of two ways. First, a flare is 

considered to be modified when any 

piping from a refinery process unit or 

fuel gas system is newly connected to 

the flare. This new piping could allow 

additional gas to be sent to the flare, 

consequently increasing emissions from 

the flare. Second, a flare is considered 

to be modified if that flare is physically 

altered to increase flow capacity. 

While in most cases an affected 

facility must comply with the final 

standard if it commences construction, 

reconstruction or modification after the 

proposal date, section 111(a)(2) of the 

CAA also provides that in certain 

circumstances such a source only need 

comply with the standard if it 

commences construction after the final 

date. Given the number of changes 

between proposal and final, we have 

concluded that this is one of the rare 

cases in which the final, rather than 

proposal, date applies. 

In this case, we are promulgating a 

newly defined affected facility, adding a 

new provision specifically defining 

what constitutes a modification of a 

flare, adding several new requirements, 

and adding a definition of a flare. All of 

these changes significantly alter what 

would be an affected facility and the 

obligations of the affected facility for 

purposes of reducing flaring. 

Furthermore, while some of the 

requirements that were proposed for the 

fuel gas producing unit were transferred 

to the flare as an affected source, the 

scope of these requirements changed 

significantly when they were applied to 

a flare rather than a fuel gas producing 

unit. Specifically, under the proposal, 

only the gas stream from the modified 

fuel gas producing unit was barred from 

routine flaring. Under the final rule, 

however all of the units connected to 

the flare are now addressed, not just the 

fuel gas producing unit that was new, 

modified, or reconstructed. 

Accordingly, we are providing in the 

final standards that only those flares 

commencing construction, 

reconstruction, or modification after 

June 24, 2008 must meet the 

requirements in subpart Ja. Flares 


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commencing construction, 

reconstruction, or modification after 

June 11, 1973, and on or before June 24, 

2008 must meet the requirements in 

subpart J regarding fuel gas combustion 

devices (i.e., the H2S fuel gas limit). 

J. Delayed Coking Units 

Comment: Several commenters 

supported the proposal that requires 

delayed coking units to depressure the 

coke drums to the fuel gas system down 

to 5 psig. One commenter supported 

venting the delayed coker gas to a flare 

or to the atmosphere at pressures less 

than 5 psig; at pressures greater than 5 

psig, the commenter suggested that the 

rule should only prohibit gases from 

being sent to a flare and allow any other 

disposition. That is, the commenter 

stated that EPA should not restrict the 

disposition of the coker 

depressurization gas to only the fuel gas 

system. 

One commenter supported inclusion 

of a coke drum pressure limit above 

which the coke drum exhaust gases 

must be sent to a recovery system, 

disagreed that it is technically infeasible 

to divert emissions for recovery at 

pressures below 5 psig, and urged EPA 

to require venting until the pressure 

drops below 2 psig. The commenter 

recently issued a permit including the 2 

psig level, and although the 

modification has not been completed, 

the commenter believes the requirement 

is technically feasible. 

A number of commenters objected to 

the finding that BDT is to depressure 

delayed coking units to the fuel gas 

system down to 5 psig. Commenters 

provided examples of coking units 

whose current mode of operations (e.g., 

set points or timed cycles) may divert to 

a flare or to the atmosphere at pressures 

of approximately 10 to 20 psig and that 

it would not be cost-effective to modify 

these units to comply with the proposed 

work practice standard. One commenter 

supported the premise that it is costeffective for delayed coking discharge to 

be routed to fuel gas blowdown, but 

depressurization down to 5 psig may 

not be feasible with existing equipment; 

the commenter recommended that the 

work practice simply require a closed 

blow down system following procedures 

described in the facility’s SSM plan. At 

a minimum, an alternative is needed for 

existing units that would require capital 

expenditure to meet the 5 psig proposal. 

One commenter stated that compressors 

cannot recover blowdown system gases 

at pressures below the fuel gas recovery 

compressor suction pressure. The 

minimum pressure at which a suction 

compressor can operate depends on the 

design of the coking unit and the 

blowdown management system. 

Because there is uncertainty 

surrounding the available emission 

information, the costs are not minimal 

in most cases, and the emissions are 

difficult to measure, the commenter 

stated that EPA cannot determine that 

controls on coker vents is BDT. 

Response: Based on the public 

comments, we re-evaluated BDT for 

delayed coking units. We considered 

three options: (1) Depressurization 

down to 15 psig; (2) depressurization 

down to 5 psig; and (3) depressurization 

down to 2 psig. We estimated that the 

baseline is, on average, depressurization 

down to 15 psig and then venting to the 

atmosphere. Therefore, there are no 

impacts for Option 1. Impacts for 

Options 2 and 3 were estimated based 

on the baseline conditions, the size of 

typical coke drums, and cost 

information provided in public 

comments. We also collected emissions 

test data to support and verify the 

projected emissions and emission 

reductions. The impacts for each option 

for new delayed coking units are 

presented in Table 17 to this preamble; 

impacts for modified and reconstructed 

delayed coking units are presented in 

Table 18 to this preamble. 

TABLE 17.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR WORK PRACTICES CONSIDERED FOR NEW DELAYED

COKING UNITS SUBJECT TO 40 CFR PART 60, SUBPART JA

Option Capital cost 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Emission 

reduction 

(tons SO2/yr) 

Emission 

reduction 

(tons VOC/yr) 

Cost-effectiveness ($/ton) 

Overall Incremental 

2 ............................................................... 2,400 230 170 2 1,300 1,300 

3 ............................................................... 24,000 2,300 230 3 9,900 38,000 

TABLE 18.—NATIONAL FIFTH YEAR IMPACTS OF OPTIONS FOR WORK PRACTICES CONSIDERED FOR MODIFIED AND

RECONSTRUCTED DELAYED COKING UNITS SUBJECT TO 40 CFR PART 60, SUBPART JA

Option Capital cost 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Emission 

reduction 

(tons SO2/yr) 

Emission 

reduction 

(tons VOC/yr) 

Cost-effectiveness ($/ton) 

Overall Incremental 

2 ............................................................... 14,000 1,400 260 4 5,100 5,100 

3 ............................................................... 54,000 5,100 340 5 15,000 47,000 

Based on these impacts and 

consideration of technically feasible 

operating practices, we confirmed our 

conclusion at proposal that BDT is 

depressurization down to 5 psig, or 

Option 2. For new delayed coking units, 

this option achieves SO2 emission 

reductions of 170 tons/yr from a 

baseline of 520 tons/yr and VOC 

emission reductions of 2 tons/yr from a 

baseline of 7 tons/yr at a cost of $1,300 

per ton of combined SO2 and VOC. For 

modified and reconstructed delayed 

coking units, this option achieves SO2

emission reductions of 260 tons/yr from 

a baseline of 780 tons/yr and VOC 

emission reductions of 4 tons/yr from a 

baseline of 11 tons/yr at a cost of $5,100 

per ton of combined SO2 and VOC. 

Although Option 3 has been established 

in one refiner’s permit, this level of 

depressurization has not been 

demonstrated in practice. Additionally, 

the difference in the quantity of gas 

released when the set point is 2 psig 

rather than 5 psig is relatively small, 80 

tons of SO2 and 4 tons of VOC, and the 

resulting incremental cost-effectiveness 

from Option 2 to Option 3 is about 

$40,000/ton, which is much greater. 

Therefore, Option 3, or depressurization 

down to 2 psig, is not BDT. 

K. Other Comments 

Comment: One commenter contested 

the criteria EPA used in its Regulatory 

Flexibility Act/Small Business 

Regulatory Enforcement Fairness Act 

(RFA/SBREFA) analysis for defining a 


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small refiner as one with no more than 

1,500 employees or more than 125,000 

barrels per day (BPD) average crude 

capacity and requested that EPA use 

what the commenter alleged is the 

commonly recognized definition in 

other EPA programs of no more than 

1,500 employees or more than 155,000 

BPD average crude capacity. The 

commenter noted that EPA did not 

make any effort in the Regulatory 

Impact Analysis or in the proposal 

preamble to support its selection or 

explain why it adopted this definition. 

Response: Under the SBA regulations, 

a small refiner is defined as a refinery 

with no more than 1,500 employees. See 

Table in 13 CFR 121.201, NAICS code 

324110. Additionally, for government 

procurement purposes only, footnote 4 

to that Table further provides that a 

small refinery must meet a certain 

capacity threshold as follows: ‘‘For 

purposes of Government procurement, 

the petroleum refiner must be a concern 

that has no more than 1,500 employees 

nor more than 125,000 barrels per 

calendar day total Operable 

Atmospheric Crude Oil Distillation 

capacity.’’ After reviewing our analysis, 

we realized that we inadvertently used 

the capacity limit to evaluate the 

impacts on small refiners; the definition 

that should have been used is 1,500 

employees with no capacity limit. We 

have recalculated the economic impact 

on the small entities using the corrected 

definition of small refiner, and our 

conclusion that the rule will not have a 

significant economic impact on a 

substantial number of small entities has 

not changed. See section VI.C of this 

preamble and the Regulatory Impacts 

Analysis (RIA) in the docket for 

additional details. 

The commenter is incorrect in 

asserting that EPA uses any other 

definition for small refiner than the SBA 

definition when conducting its RFA/ 

SBREFA analysis in other rulemakings. 

EPA consistently uses the SBA 

definition of a small refiner for such 

purposes. However, in promulgating 

regulations, EPA may define a small 

refiner differently when deciding what 

standards and requirements apply to 

these facilities. For example, in the fuel 

standards promulgated by EPA (e.g., 

Control of Air Pollution From New 

Motor Vehicles: Tier 2 Motor Vehicle 

Emissions Standards and Gasoline 

Sulfur Control Requirements (65 FR 

6698)), EPA set different requirements 

for small refiners than for all other 

refiners, and the 155,000 BPD capacity 

cutoff cited by the commenter is one of 

the criteria used to define a small refiner 

in those standards. See 40 CFR 80.225. 

However, the RFA/SBREFA analysis 

conducted in that rulemaking regarding 

whether those rules had a significant 

economic impact on a substantial 

number of small entities was not 

conducted based on any capacity cutoff. 

See 65 FR 6817. 

Comment: One commenter stated that 

EPA is required under section 111 of the 

CAA to promulgate NSPS for each of the 

pollutants emitted by the source 

category that cause or contribute 

significantly to air pollution which may 

reasonably be anticipated to endanger 

public health or welfare. The 

commenter stated that there is scientific 

consensus that greenhouse gases are a 

leading cause of global warming, and 

anthropogenic emissions of greenhouse 

gases (GHG) such as CO2 and methane 

(CH4) are increasing and driving the 

warming. Petroleum refineries are a 

significant source of fossil fuel CO2

emissions because they consume large 

quantities of energy, and in fact, U.S. 

petroleum refineries consume over 3.2 

percent of the total U.S. energy 

consumption. Petroleum refineries also 

emit CH4 and are responsible for an 

additional 0.6 teragrams of CO2

equivalence via CH4 emissions. 

Therefore, the commenter believes that 

EPA must set NSPS for CO2 and CH4

because petroleum refineries’ emissions 

of CO2 and CH4 cause and contribute 

significantly to air pollution which may 

reasonably be anticipated to endanger 

public health and welfare. 

Two commenters cited the Supreme 

Court decision in Massachusetts v. EPA, 

where the Court found that carbon 

dioxide and other GHG fit into the 

statutory definition of ‘‘air pollutant’’ in 

the CAA. Commenter 0128 stated that in 

Massachusetts v. EPA, the Supreme 

Court rejected EPA’s overly narrow 

interpretation that greenhouse gases do 

not fall under the definition. The Court 

also voided EPA’s term ‘‘air pollution’’

and noted that because greenhouse 

gases both enter the ambient air and 

warm the atmosphere, they are 

unquestionably agents of air pollution. 

Another commenter contended that 

while the decision in Massachusetts v. 

EPA states that GHG are ‘‘air pollutants’’

as that term is used in CAA section 111, 

section 111 does not require EPA to 

address all air pollutants in NSPS. 

Therefore, the Supreme Court’s decision 

does not mean that EPA necessarily 

must regulate GHG through NSPS. 

Instead of beginning to address GHG in 

specific NSPS, the commenter stated 

that EPA should develop a 

comprehensive plan for addressing GHG 

that ensures that ‘‘any necessary 

reductions in GHG emissions are 

achieved in a consistent and equitable 

manner across all industry sectors.’’ The 

commenter further stated that since the 

issue of GHG emissions was not raised 

in the proposal preamble for subparts J 

and Ja, it would be inappropriate for 

EPA to promulgate GHG standards in 

those subparts without first proposing 

the new standards. 

Response: While section 111(b)(1)(B) 

of the CAA permits EPA, under 

appropriate circumstances, to add new 

standards of performance for additional 

pollutants concurrent with the 8-year 

review of existing standards, for the 

reasons set forth below, EPA declines to 

promulgate performance standards for 

GHG, including CO2 and CH4, from 

petroleum refineries as part of this 8- 

year review cycle. 

Section 111(b)(1)(B) imposes two 

obligations upon EPA for a source 

category listed under section 

111(b)(1)(A). First, within 1 year of 

listing a source category, section 

111(b)(1)(B) requires the Administrator 

to ‘‘publish proposed regulations, 

establishing Federal standards of 

performance for new sources’’ within 

such category. After providing 

‘‘interested persons an opportunity for 

written comment on such proposed 

regulations,’’ EPA must then 

‘‘promulgate, within one year after such 

publication, such standards’’ as the 

Administrator ‘‘deems appropriate.’’

The Agency has always interpreted this 

initial requirement as providing the 

Administrator with significant 

flexibility in determining which 

pollutants are appropriate for regulation 

under section 111(b)(1)(B). See National 

Lime Assoc. v. EPA, 627 F.2d 416, 426 

(DC Cir. 1980) (explaining reasons for 

not promulgating standards for NOX, 

SO2, and CO from lime plants); see also 

National Assoc. of Clean Air Agencies v. 

EPA, 489 F.3d 1221, 1228–1230 (DC Cir. 

2007) (finding that the ‘‘deems 

appropriate’’ language in CAA section 

231 provides a ‘‘delegation of authority’’

that is ‘‘both explicit and extraordinarily 

broad,’’ giving EPA’s regulation 

‘‘controlling weight unless it is 

manifestly contrary to the statute’’). 

Second, the statute requires that: 

‘‘The Administrator shall, at least every 8 

years, review and, if appropriate, revise such 

standards following the procedure required 

by this subsection for promulgation of such 

standards. Notwithstanding the requirements 

of the previous sentence, the Administrator 

need not review any such standard if the 

Administrator determines that such review is 

not appropriate in light of readily available 

information on the efficacy of such 

standard.’’

Nothing in the 8-year review 

provision mandates that EPA include a 

new standard of performance for an air 

pollutant not already covered by the 


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1Commenters assert that ‘‘the term ‘such 

standards’ incorporates the inclusive ‘any’ air 

pollutant language in the definition of a ‘standard 

of performance’ ’’ and therefore contemplates new 

standards of performance during the 8-year review. 

See Comments, pg. 3. However, the word ‘‘any’’

does not appear in the definition of ‘‘standard of 

performance’’ in the manner quoted by 

commenters. See CAA section 111(a)(1). 

2Commenters assert that EPA must develop 

performance standards during the 8-year review 

‘‘for any air pollutant’’ emitted by a source 

‘‘provided that EPA finds those emissions cause or 

contribute to air pollution’’ that may endanger 

public health or welfare. See Comments, pg. 2. To 

the extent any such finding were required, EPA 

notes that no such finding has been made regarding 

GHG emitted from refineries. Indeed, 111(b)(1)(A), 

which contains the only endangerment finding 

requirement in section 111, gives the Administrator 

significant discretion on the timing of 

endangerment findings after the initial set of source 

category listings (‘‘from time to time thereafter shall 

revise’’). Nothing in the statute ties the 

endangerment and 8-year review requirements. 

Hence, commenters’ own arguments lack merit and 

EPA is under no obligation for promulgating GHG 

performance standards for refineries. 

3Commenters again predicate their assertions on 

a prerequisite endangerment finding. See 

Comments, pg. 4. As explained in footnote 2, EPA 

has made no such finding and therefore under 

petitioners’ interpretation is under no obligation to 

promulgate GHG performance standards for this 

source category. 

4Because of the unique nature of landfill related 

air pollutants the Agency determined it was 

appropriate to define the air pollutants at issue as 

emissions from landfills and thus limited the 

potential implications for other programs. See 56 

FR 24468, 24470 (May 30, 1991). In other words, 

only landfills emit these particular air pollutants; 

thus, it was appropriate that only this source 

category was subject to the PSD program for this air 

pollutant. 

standard of performance under review. 

Instead, the 8-year review provision can 

be reasonably understood as requiring 

‘‘review’’ of only ‘‘such standards’’ 1 as 

were previously promulgated. As there 

would be no standard to review for an 

air pollutant not already subject to the 

standard, there would be no 

requirement for promulgating a new 

standard of performance since the 

‘‘review’’ requirement in section 

111(b)(1)(B) cannot be transformed into 

a ‘‘promulgation’’ requirement.2

Moreover, as noted above, even if the 8- 

year review provision were a 

‘‘promulgation’’ requirement, such a 

requirement still would not mandate 

that EPA set performance standards for 

all air pollutants emitted from the 

source category. In the 1990 CAA 

Amendments, Congress amended the 

definition of ‘‘standard of performance’’

to be ‘‘a standard for emissions of air 

pollutants,’’ specifically deleting the 

word ‘‘any’’ from the phrase ‘‘any air 

pollutant’’ that was contained in the 

1977 definition. This amendment 

restored the definition to the 1970 

version. This deliberate change 

demonstrates that Congress was aware 

that the 1970 definition did not require 

EPA to cover all air pollutants emitted 

from a source category. Additionally, by 

reinstating the 1970 definition through 

the 1990 CAA amendments, Congress 

was also indicating its understanding 

that EPA is not required to regulate all 

air pollutants emitted from a source 

under section 111. 

EPA has promulgated new 

performance standards for pollutants 

not previously covered concurrent with 

some previous 8-year review 

rulemakings. See 52 FR 24672, 24710 

(July 1, 1987) (considering PM10

controls in future rulemakings); 71 FR 

9866 (February 27, 2006) (new PM 

standards for boilers). Additionally, as 

commenters correctly point out, EPA is 

promulgating a new standard of 

performance for NOX emissions from 

certain affected facilities at refineries in 

this rulemaking. However, contrary to 

commenters’ assertions,3 these actions 

were discretionary; EPA may, but is not 

required to, promulgate new standards 

of performance concurrent with its 8- 

year review. While it may often be 

appropriate for EPA to exercise its 

discretion by promulgating new 

standards of performance concurrent 

with an 8-year review, because it is in 

the process of gathering information and 

reviewing controls for an industry, for 

the reasons set forth above, EPA 

reasonably interprets section 

111(b)(1)(B) to not mandate such a 

result. 

In this instance, it is reasonable for 

EPA not to promulgate performance 

standards for GHG emissions as part of 

this 8-year review cycle. We believe that 

the nature of GHG emissions renders 

them readily distinguishable from other 

air pollutants for which we have 

previously promulgated new 

performance standards concurrent with 

an 8-year review of the existing 

standards. Indeed, GHG emissions 

present issues that we have never had 

to address in the context of even an 

initial NSPS rulemaking for a source 

category. These differences warrant 

proceeding initially through a more 

deliberate process, i.e., the announced 

advanced notice of proposed 

rulemaking (ANPR), than in this source 

category-specific rulemaking. While 

commenters correctly note that we have 

previously exercised our discretion to 

promulgate new performance standards 

concurrent with an 8-year review, and 

indeed are doing so here with respect to 

NOX, the exercise of that discretion had 

limited impact as those air pollutants 

were either already regulated elsewhere 

under the Act or were emitted by a 

sufficiently limited subset of source 

categories. Here, promulgating new 

performance standards for these air 

pollutants in this one source category 

could potentially mandate regulation for 

numerous other source categories under 

several other parts of the Act. Similarly, 

our initial decision to regulate nonNational Ambient Air Quality Standards 

(NAAQS) air pollutants in an NSPS has 

generally raised issues limited to the 

source category before us. For example, 

with the exception of landfill related air 

pollutants,4 our decisions to regulate 

non-NAAQS air pollutants were reached 

at a time prior to the enactment of the 

statutory Prevention of Significant 

Deterioration (PSD) program and 

accordingly did not implicate the many 

complexities that we are struggling with 

today and which we intend to address 

in the ANPR discussed below. See 45 

FR 52,676, 52,708–10 (Aug. 7, 1980). 

In contrast to those circumstances, the 

regulation of GHG emissions raises 

numerous issues that are not well suited 

to initial resolution in a rulemaking 

directed at an individual source 

category. To that end, as Administrator 

Johnson announced on March 27, 2008, 

in letters to Senator Barbara Boxer and 

Representative John Dingell, it is his 

intent to issue an ANPR in the very near 

future that explores and seeks public 

comment on the many complex 

interconnections between the relevant 

sections of the Clean Air Act, including 

section 111, and lays the foundation for 

a comprehensive path forward with 

respect to regulation of all GHG. 

We have previously noted that at this 

stage it is most appropriate to address 

these complexities in an ANPR 

addressing a variety of interconnected 

statutory provisions. In his April 10, 

2008, testimony before the 

Subcommittee on Energy and Air 

Quality, Committee on Energy and 

Commerce, U.S. House of 

Representatives, Robert J. Meyers, 

Principal Deputy Assistant 

Administrator of the Office of Air and 

Radiation, further elaborated on the 

reasons for and anticipated content of 

an ANPR and discussed some of these 

complexities. For example, he noted the 

potential complexities resulting from 

implementation of the PSD 

preconstruction review permitting 

program: 

For PSD purposes, major stationary sources 

are those with the potential to emit 100 tons 

per year of a regulated air pollutant in the 

case of certain statutorily-listed source 

categories, and 250 tons per year in the case 

of all other source categories. New large 

schools, nursing homes, and hospitals could 

be considered a ‘‘major source’’ under this 

section of the Clean Air Act. For 

modifications, only those that increase 


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emissions above a tonnage threshold 

established by EPA for each regulated 

pollutant through rulemaking triggers PSD. 

Until EPA establishes this so-called 

‘‘significance’’ level, however, any increase 

in a regulated pollutant at a major stationary 

source undergoing a modification would 

trigger PSD permitting. 

As noted previously, PSD sources are 

required to install best available control 

technology (BACT). BACT must be at least as 

stringent as any applicable NSPS, and is to 

reflect the maximum degree of emissions 

reduction achievable for such a facility, 

taking into account energy, environment and 

economic impacts and other costs. 

Controlling GHG emissions under any 

section of the Clean Air Act could 

significantly increase the number of 

stationary sources subject to PSD permitting. 

Because CO2 is typically emitted in larger 

quantities than criteria and other traditional 

air pollutants from combustion sources, 

facilities not previously subject to Clean Air 

Act permitting—such as large commercial 

and residential buildings heated by natural 

gas boilers—could qualify as major stationary 

sources for PSD purposes. In addition, some 

small industrial sources not now covered by 

PSD could be expected to become subject to 

PSD due to their GHG emissions. 

Currently, our best estimate of the potential 

impact of including GHG in the PSD program 

is that the number of PSD permits issued 

annually nationwide could rise by an order 

of magnitude above the current 200–300 a 

year. Such estimates are subject to significant 

uncertainty. At present, we do not have 

comprehensive information on GHG 

emissions from the many categories of 

stationary sources of such emissions; instead 

we have relied on available information and 

general engineering estimates. 

Such a broadening of the PSD program 

could pose significant implementation issues 

for covered facilities (particularly newly 

covered facilities) and permitting agencies. 

EPA is examining the scope of these potential 

difficulties and whether, for GHG, the 

program could be limited to larger sources, 

at least temporarily, in view of the very 

substantial increase in administrative burden 

that might otherwise occur. However, at 

present it is unclear as to whether EPA has 

the legal discretion to exempt sources above 

the statutory thresholds. In addition, EPA is 

exploring concepts for streamlining 

implementation of the PSD program for 

smaller sources, such as guidance on general 

permits or source definitions for BACT 

determinations and model permits for use by 

permitting agencies. EPA will address 

permitting issues in greater detail in the 

planned ANPR. 

Given the complexity of PSD issues 

arising from regulation of GHG 

emissions, among other complex issues 

of regulating a pollutant—particularly a 

pollutant global in nature—for the first 

time under the CAA, it is reasonable for 

the Agency to proceed first by 

evaluating these issues, and other 

potential complexities, in the previously 

announced ANPR rather than by taking 

action to promulgate performance 

standards for GHG emissions in this 

rulemaking. 

In addition to the reasons set forth 

above, it is appropriate for EPA to 

decline to promulgate performance 

standards for GHG emissions concurrent 

with this 8-year review as section 

111(b)(1)(B) does not require that the 

Agency revise the standards when 

essential information becomes available 

too late in the review period. The 8-year 

review provision itself conditions the 

need to review a standard on ‘‘readily 

available information on the efficacy of 

such standard.’’ CAA section 

111(b)(1)(B). The legislative history of 

the 1970 CAA predecessor for the 

review provision also states that the 

review obligation depends on the 

availability of ‘‘new technology 

processes or operating methods.’’ 1970 

Sen. Comm. Rep. at 17. Additionally, 

the Massachusetts decision, which held 

that GHG are air pollutants, was handed 

down merely four weeks before the 

court-ordered deadline to propose the 

standards for this 8-year review period. 

As explained above, section 111(b)(1)(B) 

contemplates a two-year period for 

NSPS promulgation, and, as noted 

below, the consent decree under which 

EPA was acting contemplated a twoand-a-half year period for this 8-year 

review; hence, EPA did not have 

sufficient time within this rulemaking 

for proposing and promulgating 

performance standards for GHG 

emissions from refineries. The following 

discussion provides more information 

regarding the timeline of events for this 

particular rulemaking’s review period. 

EPA entered into a consent decree 

with the Sierra Club and Our Children’s 

Earth Foundation on October 31, 2005, 

that required EPA to conduct its review 

of 40 CFR part 60, subpart J and propose 

revisions by April 30, 2007, and to 

promulgate a final rule by April 30, 

2008. EPA began its review of subpart 

J and drafted a proposal package. 

Shortly before EPA sent the proposed 

rule package to OMB for its review, the 

U.S. Supreme Court, on April 2, 2007, 

issued its decision in Massachusetts v. 

EPA, holding that GHG are air 

pollutants under the CAA, and 

remanding the case for the Agency to 

take action consistent with the Court’s 

opinion. Less than one month later, EPA 

was obligated under the terms of its 

consent decree to propose revisions to 

subpart J by April 30, 2007; this 

proposed rule did not include 

performance standards for GHG 

emissions. On August 27, 2007, EPA 

received comments from Earthjustice 

asserting that EPA, as part of its 8-year 

review under section 111(b)(1)(B), must 

promulgate GHG emissions limits for 

petroleum refineries. On September 14, 

2007, the Massachusetts case was 

officially remanded to the Agency by 

the DC Circuit Court of Appeals. Under 

the terms of the consent decree, EPA 

was obligated to finalize its subpart J 

revisions by April 30, 2008. Considering 

this timeline of events, and the 

complexities of the issues involved, 

EPA would not have had sufficient time 

during this particular 8-year review of 

subpart J to propose and promulgate 

GHG performance standards for 

refineries even if the Agency had 

deemed such action appropriate. As 

explained above, the Agency will use 

the information it gathers through the 

ANPR for determining what may be 

appropriate for future rulemakings. 

V. Summary of Cost, Environmental, 

Energy, and Economic Impacts 

A. What are the impacts for petroleum 

refinery process units? 

We are presenting estimates of the 

impacts for the final requirements of 

subpart Ja that change the performance 

standards for the following: (1) The 

emission limits for fluid catalytic 

cracking units, sulfur recovery plants, 

fluid coking units, fuel gas combustion 

devices, and process heaters; and (2) the 

work practice standards for flares and 

delayed coking units. The final 

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 

differences between the impacts of 

petroleum refinery process units 

complying with the final subpart Ja and 

the current NSPS requirements of 

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

presented for petroleum refinery 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 

final 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 final subpart Ja. Sources 

that are modified or reconstructed over 

the next 5 years must comply with 

subpart J in the absence of final subpart 

Ja. Prior to reconstruction or 

modification, these sources will either 

be subject to a consent decree 


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(equivalent to about 77 percent of the 

industry by capacity), complying with 

subpart J or equivalent limits, and/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 final subpart 

Ja were estimated from those starting 

points as well. 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 final rule, we 

evaluated the cost-effectiveness of each 

option for new sources separately from 

reconstructed and modified sources. In 

most cases, our selections for each 

process unit and pollutant were 

consistent for modified and 

reconstructed units and new units. In 

this section, we are presenting our costs 

and emission reductions for the overall 

rule. We estimate that the final 

amendments will reduce emissions of 

PM by 1,300 tons/yr, SO2 by 17,000 

tons/yr, NOX by 11,000 tons/yr, and 

VOC by 200 tons/yr from the baseline. 

The estimated increase in annual cost, 

including annualized capital costs, is 

about $31 million (2006 dollars). The 

overall cost-effectiveness is about 

$1,070 per ton of combined pollutants 

removed. The estimated nationwide 5- 

year incremental emissions reductions 

and cost impacts for the final standards 

are summarized in Table 19 of this 

preamble. 

TABLE 19.—NATIONAL INCREMENTAL EMISSION REDUCTIONS AND COST IMPACTS FOR PETROLEUM REFINERY UNITS

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

Process unit 

Total capital 

cost 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Annual 

emission 

reductions 

(tons PM/yr) 

Annual 

emission 

reductions 

(tons SO2/yr) 

Annual 

emission 

reductions 

(tons NOX/yr) 

Annual 

emission 

reductions 

(tons VOC/yr) 

Cost 

effectiveness 

($/ton) 

FCCU ........................... 8,500 6,400 240 4,300 2,600 ........................ 890 

FCU .............................. 14,000 4,000 1,000 5,900 660 ........................ 530 

SRP .............................. 1,700 730 ........................ 420 ........................ ........................ 1,700 

Fuel gas combustion 

devices ..................... 34,000 12,000 ........................ 5,200 ........................ ........................ 2,300 

Process heaters ........... 23,000 12,000 ........................ ........................ 7,500 ........................ 1,600 

Flaring .......................... 40,000 ¥7,000 ........................ 80 6 200 ¥23,000 

Delayed coking units .... 17,000 1,600 ........................ 440 ........................ 25 3,400 

Sulfur pits ..................... 8,300 1,000 ........................ 300 ........................ ........................ 3,400 

Total ...................... 150,000 31,100 1,300 17,000 11,000 1,400 1,070 

B. What are the secondary impacts? 

Indirect or secondary air quality 

impacts of this final rule will result 

from the increased electricity usage 

associated with the operation of control 

devices. If plants purchase electricity 

from a power plant, we estimate that the 

final standards will increase secondary 

emissions of criteria pollutants, 

including PM, SO2, NOX, and CO from 

power plants. For new, modified or 

reconstructed sources, this final rule 

will increase secondary PM emissions 

by 56 Megagrams per year (Mg/yr) (62 

tons/yr); secondary SO2 emissions by 

about 1,400 Mg/yr (1,500 tons/yr); and 

secondary NOX emissions by about 530 

Mg/yr (580 tons/yr) 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 FCU 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 final rule will generate 1.6 

billion gallons of water per year for the 

5 years following proposal. We also 

estimate that this final rule will generate 

2,200 Mg/yr (2,400 tons/yr) of solid 

waste over those 5 years. 

Energy impacts as defined in this 

preamble section consist of the 

electricity and steam needed to operate 

control devices and other equipment 

that would be required under the final 

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 final rule 

will increase overall energy demand by 

about 410 gigawatt-hours per year (1,400 

billion British thermal units per year). 

An analysis of energy impacts that 

accounts for reactions in affected 

markets to the costs of this final rule can 

be found in the section on Executive 

Order 13211 found later in this 

preamble. 

C. What are the economic impacts? 

Our economic impact analysis 

estimated the impacts on product price 

and output that the final NSPS would 

have on five petroleum products—

motor gasoline, jet fuel, distillate fuel 

oil, residual fuel oil, and liquefied 

petroleum gases. This analysis estimates 

in the fifth year after proposal that the 

price of these petroleum products will 

increase less than 0.01 percent 

nationally along with a corresponding 

reduction in output of less than 0.01 

percent. The overall total annual social 

costs, which reflect changes in 

consumer and producer behavior in 

response to the compliance costs, are 

$27 million ($2006) in the fifth year 

after proposal or almost identical to the 

compliance costs incurred by affected 

producers of these petroleum products. 

For more information, please refer to 

the regulatory impact analysis (RIA) that 

is in the docket for this final rule. 

D. What are the benefits? 

We estimate the monetized benefits of 

this final rule to be $220 million to $1.9 

billion (2006$) in the fifth year after 

proposal. We base the benefits estimate 

derived from the PM2.5 and PM2.5

precursor emission reductions on the 

approach and methodology laid out in 

the Technical Support Document that 

accompanied the recently completed 

Regulatory Impact Analysis (RIA) for the 

revision to the National Ambient Air 

Quality Standard for Ground-level 

Ozone (NAAQS), March 2008. We 

generated estimates that represent the 

total monetized human health benefits 

(the sum of premature mortality and 

premature morbidity) of reducing one 

ton of PM2.5 and PM2.5 precursor 


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emissions. A summary of the range of 

benefits estimates at discount rates of 

3% and 7% is in Table 20 of this 

preamble. 

TABLE 20.—SUMMARY OF THE RANGE OF BENEFITS ESTIMATES FOR FINAL REFINERIES NSPS 

Pollutant 

Monetized benefits 

per ton emission 

reduction 

(3% discount) 

Monetized benefits 

per ton emission 

reduction 

(7% discount) 

Emission 

reductions 

(tons) 

Total monetized 

benefits (millions of 

2006 dollars, 

3% discount) 1

Total monetized 

benefits (millions of 

2006 dollars, 

7% discount) 1

Direct PM2.5 ............................................ $68,000 to 

$570,000.

$63,000 to 

$520,000.

1,054 $72 to $600 ........... $66 to $540. 

PM2.5 Precursor: 

SO2 .................................................. $8,000 to $68,000 $7,400 to $62,000 16,714 $130 to $1,100 ...... $120 to $1,000. 

NOX ................................................. $1,300 to $11,000 $1,200 to $9,600 ... 10,786 $14 to $110 ........... $13 to $100. 

VOC ................................................. $210 to $1,700 ...... $190 to $1,500 ...... 230 $0.05 to $.38 ......... $0.04 to $.35. 

Grand total $220 to $1,900 ...... $200 to $1,700. 

1All estimates are for the analysis year (fifth year after proposal, 2012), and are rounded to two significant figures so numbers may not sum 

across columns. Emission reductions reflect the combination of selected options for both new and reconstructed/modified sources. The PM2.5

fraction of total PM emissions is estimated at 83.3%, and only the reduction in the PM2.5 fraction is monetized in this analysis. All fine particles 

are assumed to have equivalent health effects, but the benefit per ton estimates vary because each ton of precursor reduced has a different propensity to become PM2.5. The monetized benefits incorporate the conversion from precursor emissions to ambient fine particles. 

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 PM Expert Elicitation study 

(Industrial Economics, Inc., September 

2006. Expanded Expert Judgment 

Assessment of the ConcentrationResponse Relationship Between PM2.5

Exposure and Mortality. Prepared for 

the U.S. EPA, Office of Air Quality 

Planning and Standards). The preamble 

for the proposal indicated that EPA 

would update the benefits estimates to 

incorporate the results of the expert 

elicitation for the final rule, and we 

have done so. The range of benefits 

estimates presented above represents 

the range from the lowest expert 

estimate to the highest expert estimate 

to characterize the uncertainty in the 

concentration response function. To 

generate the benefit-per-ton estimates, 

we used a model to convert emissions 

of direct PM2.5 and PM2.5 precursors into 

changes in PM2.5 air quality and another 

model to estimate the changes in human 

health based on that change in air 

quality. Finally, the monetized health 

benefits were divided by the emission 

reductions to create the benefit-per-ton 

estimates. Even though all fine particles 

are assumed to have equivalent health 

effects, the benefit-per-ton estimates 

vary because each ton of precursor 

reduced has a different propensity to 

become PM2.5. For example, NOX has a 

lower benefit-per-ton estimate than 

direct PM2.5 because it does not form as 

much PM2.5, thus the exposure would be 

lower, and the monetized health 

benefits would be lower. 

This analysis does not include the 

type of detailed uncertainty assessment 

found in the PM NAAQS RIA because 

we lack the necessary air quality input 

and monitoring data to run the benefits 

model. However, the 2006 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 PM expert elicitation study. 

The annualized costs of this 

rulemaking are estimated at $31 million 

(2006 dollars) in the fifth year after 

proposal, and the benefits are estimated 

at $220 million to $1.9 billion (2006 

dollars) for that same year. Thus, net 

benefits of this rulemaking are estimated 

at $190 million to $1.8 billion (2006 

dollars). 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. It should be 

noted that the range of benefits 

estimates provided above does not 

include ozone-related benefits from the 

reductions in VOC and NOX emissions 

expected to occur as a result of this final 

rule, nor does this range include 

benefits from the portion of total PM 

emissions reduction that is not PM2.5. 

We do not have sufficient information 

or modeling available to provide such 

estimates for this rulemaking. For more 

information, please refer to the RIA for 

this final rule that is available in the 

docket. 

VI. 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 

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 RIA for the 

Final Petroleum Refinery NSPS. 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 as 

a range from $220 million to $1.9 billion 

(2006 dollars), and the annualized costs 

of this action are $31.1 million (2006 

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 final amendments to the 

standards of performance for petroleum 

refineries (40 CFR part 60, subpart J) do 

not impose any new information 

collection burden. The final 

amendments add a monitoring 

exemption for fuel gas streams 

combusted in a fuel gas combustion 

device that are inherently low in sulfur 

content. The exemption applies 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 is required to 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 


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will occur as a result of the exemption 

is not 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. 

However, 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 1054.09. The OMB control 

numbers for EPA’s regulations are listed 

in 40 CFR part 9. 

The information collection 

requirements in the final 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 information collection 

requirements are not enforceable until 

OMB approves them. 

The information collection 

requirements in this final rule are 

needed by the Agency to determine 

compliance with the standards. 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 final standards of performance for 

petroleum refineries include work 

practice requirements for delayed 

coking reactor vessel depressuring and 

written plans to minimize emissions 

from flares. Plants also are required to 

analyze the cause of any exceedance 

that releases more than 500 pounds per 

day of SO2 from an affected fuel gas 

combustion device. The final standards 

also include testing, monitoring, 

recordkeeping, and reporting 

provisions. Monitoring requirements 

include control device operating 

parameters, bag leak detection systems, 

or CEMS, depending on the type of 

process, pollutant, and control device. 

Exemptions are also included for small 

emitters. 

The annual burden for this 

information collection averaged over the 

first 3 years of this ICR is estimated to 

total 5,340 labor-hours per year at a cost 

of $481,249 per year. The annualized 

capital costs are estimated at $2,052,000 

per year and operation and maintenance 

costs are estimated at $1,117,440 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 V.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 final subpart Ja. Burden is 

defined at 5 CFR 1320.3(b). 

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. When this ICR is 

approved by OMB, the Agency will 

publish a technical amendment to 40 

CFR part 9 in the Federal Register to 

display the OMB control number for the 

approved information collection 

requirements contained in this final 

rule. 

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 

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 this final action on small entities, 

small entity is defined as: (1) A small 

business whose parent company has no 

more than 1,500 employees, 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 this final rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

The small entities directly regulated by 

the current standards of performance for 

petroleum refineries are small refineries. 

After reviewing the small business 

analysis for the proposed NSPS, we 

realized that we inadvertently used the 

capacity limit of 125,000 barrels/day 

production as part of the small business 

size standard to evaluate the impacts on 

small refiners; the definition that should 

have been used is 1,500 employees for 

an ultimate parent entity with no 

capacity limit in the United States. The 

effect of this change in the small 

business size standard for this analysis 

is one additional small refiner. This 

change in the small business size 

standard does not lead to any effect on 

the certification that there is no 

significant economic impact on a 

substantial number of small entities 

resulting from today’s action. We have 

determined that, of the 58 entities that 

are in the affected industry, 25 of these 

(or 43 percent) are classified as small 

according to the SBA small business 

size standard listed previously. Of these 

25 affected entities, three are expected 

to be affected by today’s action. None of 

these three small entities is expected to 

incur an annualized compliance cost of 

more than 1.0 percent to comply with 

this final action. For more information, 

please refer to the economic impact 

analysis that is in the public docket for 

this rulemaking. 

Although this final action will not 

have a significant economic impact on 

a substantial number of small entities, 

EPA nonetheless has tried to reduce the 

impact of this final 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. 

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 one 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 


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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 final 

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 one year. As 

discussed earlier in this preamble, the 

estimated expenditures for the private 

sector in the fifth year after proposal are 

an annualized cost of $31.1 million 

(2006 dollars). Thus, this final action is 

not subject to the requirements of 

section 202 and 205 of the UMRA. In 

addition, EPA has determined that this 

final action contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. This 

final 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 one 

year or any disproportionate impacts on 

them. Therefore, this final 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 final 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 final 

action. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175 (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 final 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 final rules impose requirements on 

owners and operators of specified 

industrial facilities and not tribal 

governments. Thus, Executive Order 

13175 does not apply to this final 

action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

EPA interprets Executive Order 13045 

(62 FR 19885, April 23, 1997) as 

applying to those regulatory actions that 

concern health or safety risks, such that 

the analysis required under section 5–

501 of the Executive Order has the 

potential to influence the regulation. 

This action is not subject to Executive 

Order 13045 because it is based solely 

on technology performance. 

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 RIA for 

this final action. This analysis accounts 

for the increase in electricity generation 

occurring due to additional control 

requirements associated with this final 

action. Our analysis shows that there is 

a reduction in gasoline output of less 

than 0.75 million gallons per year, or 

less than 50 barrels of gasoline 

production per day in the fifth year after 

proposal of this final action. In addition, 

our analysis shows that there is no 

increase in gasoline prices in the fifth 

year after proposal of this final action. 

With no increase in domestic gasoline 

prices, no significant increase in our 

dependence on foreign energy supplies 

should take place. Finally, this final 

action will have no adverse effect on 

crude oil supply, coal production, 

electricity production, and energy 

distribution. Further, we conclude that 

this final action is not likely to have any 

adverse energy effects. For more 

information on this analysis, please 

refer to the RIA available in the docket 

for this rulemaking. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law No. 

104–113 (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. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, and 

business practices) that are developed or 

adopted by VCS bodies. NTTAA directs 

EPA to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable VCS. 

This rulemaking involves technical 

standards. EPA has decided to use the 

VCS ANSI/ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses,’’ for 

its manual methods of measuring the 

content of the exhaust gas. These parts 

of ANSI/ASME PTC 19.10–1981 are 

acceptable alternatives to EPA Methods 

3B, 6, 6A, 7, 7C, and 15A. This standard 

is available from the American Society 

of Mechanical Engineers (ASME), Three 

Park Avenue, New York, NY 10016–

5990. 

The EPA has also decided to use EPA 

methods 1, 2, 3, 3A, 3B, 5, 5B, 5F, 5I, 

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

10B, 11, 15, 15A, 16, and 17 (40 CFR 

part 60, Appendices A–1 through A6); 

Performance Specifications 1, 2, 3, 4, 

4A, 5, 7, and 11 (40 CFR part 60, 

Appendix B); quality assurance 

procedures in 40 CFR part 60, Appendix 

F; and the Gas Processors Association 

Standard 2377–86, ‘‘Test for Hydrogen 


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Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules and Regulations 35865 

Sulfide and Carbon Dioxide in Natural 

Gas Using Length of Stain Tubes,’’ 1986 

Revision. While the Agency has 

identified 22 VCS as being potentially 

applicable to this rule, we have decided 

not to use these VCS in this rulemaking. 

The use of these VCS would have been 

impractical because they do not meet 

the objectives of the standards cited in 

this rule. See the docket for this rule for 

the reasons for these determinations. 

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 final 

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, 

February 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 these final 

amendments to 40 CFR part 60, subpart 

J will 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 final 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. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801, et seq., as added by the 

Small Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of 

Congress and to the Comptroller General 

of the United States. The EPA will 

submit a report containing these final 

rules and other required information to 

the U.S. Senate, the U.S. House of 

Representatives, and the Comptroller 

General of the United States prior to 

publication of the final rules in the 

Federal Register. A major rule cannot 

take effect until 60 days after it is 

published in the Federal Register. This 

action is not a ‘‘major rule’’ as defined 

by 5 U.S.C. 804(2). This final rule will 

be effective on June 24, 2008. 

List of Subjects in 40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Incorporations by 

reference, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 

Dated: April 30, 2008. 

Stephen L. Johnson, 

Administrator. 

■ For the reasons stated in the preamble, 

title 40, chapter I of the Code of Federal 

Regulations is 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 § 60.106(e)(2) of subpart J, 

§§ 60.104a(d)(3), (d)(5), (d)(6), (h)(3), 

(h)(4), (h)(5), (i)(3), (i)(4), (i)(5), (j)(3), 

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

(g)(2), and (g)(4), 60.106a(a)(1)(iii), 

(a)(2)(iii), (a)(2)(v), (a)(2)(viii), (a)(3)(ii), 

and (a)(3)(v), and 60.107a(a)(1)(ii), 

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

(d)(2) of subpart Ja, Tables 1 and 3 of 

subpart EEEE, Tables 2 and 4 of subpart 

FFFF, Table 2 of subpart JJJJ, 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 

Standard 2377–86, Test for Hydrogen 

Sulfide and Carbon Dioxide in Natural 

Gas Using Length of Stain Tubes, 1986 

Revision, 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 for sulfur feed 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 other than a flare as 

defined in § 60.101a which commences 

construction, reconstruction, or 

modification after June 11, 1973, and on 

or before May 14, 2007, or any fuel gas 

combustion device under paragraph (a) 

of this section that meets the definition 

of a flare as defined in § 60.101a which 

commences construction, 

reconstruction, or modification after 

June 11, 1973, and on or before June 24, 

2008, 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 paragraph (d) to read as 

follows: 

§ 60.101 Definitions. 

* * * * * 

(d) Fuel gas means any gas which is 

generated at a petroleum refinery and 


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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. 

* * * * * 

■ 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

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, zero 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 fuel gas 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) Fuel gas streams that meet a 

commercial-grade product specification 

for sulfur content of 30 ppmv or less. In 

the case of a liquefied petroleum gas 

(LPG) product specification in the 

pressurized liquid state, the gas phase 

sulfur content should be evaluated 

assuming complete vaporization of the 

LPG and sulfur containing-compounds 

at the product specification 

concentration. 

(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, the 

isomerization unit, and HF alkylation 

process units. 

(D) Other fuel gas streams that an 

owner or operator demonstrates are lowsulfur 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 fuel 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 fuel 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 fuel gas 

stream/system to be considered, 

including submission of a portion of the 

appropriate piping diagrams indicating 

the boundaries of the fuel 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 fuel 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 

fuel gas stream (i.e., control equipment 

or product specifications) at all times; 

(iv) The supporting test results from 

sampling the requested fuel gas stream/ 

system demonstrating that the sulfur 

content is less than 5 ppmv. Sampling 

data must include, at minimum, 2 

weeks of daily monitoring (14 grab 

samples) for frequently operated fuel gas 

streams/systems; for infrequently 

operated fuel gas streams/systems, 


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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 

Processors Association Standard 2377–

86, 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 fuel gas stream 

for H2S; and 

(v) A description of how the 2 weeks 

(or seven samples for infrequently 

operated fuel gas streams/systems) of 

monitoring results compares to the 

typical range of H2S concentration (fuel 

quality) expected for the fuel 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 

fuel gas stream going to the loading rack 

flare). 

(2) The effective date of the 

exemption is the date of submission of 

the information required in paragraph 

(b)(1) of this section). 

(3) No further action is required 

unless refinery operating conditions 

change in such a way that affects the 

exempt fuel 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)(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 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 new information 

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 new 

information to support an exemption, 

the owner or operator must begin H2S 

monitoring using daily stain sampling to 

demonstrate compliance. The owner or 

operator must begin monitoring 

according to the requirements in 

paragraphs (a)(1) or (a)(2) of this section 

as soon as practicable but in no case 

later than 180 days after the operation 

change. During daily stain tube 

sampling, a daily sample exceeding 162 

ppmv is an exceedance of the 3-hour 

H2S concentration limit. The owner or 

operator must determine a rolling 365- 

day average using the stain sampling 

results; an average H2S concentration of 

5 ppmv must be used for days prior to 

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 ANSI/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 fuel gas 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 fuel gas 

stream, the owner or operator shall 

maintain records of the specific 

exemption chosen for each fuel gas 

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. Part 60 is amended by adding 

subpart Ja to read as follows: 


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35868 Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules and Regulations 

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 

(FCU). 

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 (FCU), delayed coking units, fuel 

gas combustion devices, including flares 

and process heaters, 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) Except for flares, 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. For flares, the provisions 

of this subpart apply only to flares 

which commence construction, 

modification, or reconstruction, after 

June 24, 2008. 

(c) For the purposes of this subpart, 

under § 60.14, a modification to a flare 

occurs if: 

(1) Any new piping from a refinery 

process unit or fuel gas system is 

physically connected to the flare (e.g., 

for direct emergency relief or some form 

of continuous or intermittent venting); 

or 

(2) A flare is physically altered to 

increase the flow capacity of the flare. 

(d) 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 

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 refinery process units in which 

high molecular weight petroleum 

derivatives are thermally cracked and 

petroleum coke is produced in a series 

of closed, batch system reactors. 

Flare means an open-flame fuel gas 

combustion device used for burning off 

unwanted gas or flammable gas and 

liquids. The flare includes the 

foundation, flare tip, structural support, 

burner, igniter, flare controls including 

air injection or steam injection systems, 

flame arrestors, knockout pots, piping 

and header systems. 

Flexicoking unit means one or more 

refinery process units in which high 

molecular weight petroleum derivatives 

are thermally cracked and petroleum 

coke is continuously produced and then 

gasified to produce a synthetic fuel gas. 

Fluid catalytic cracking unit means a 

refinery process unit 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. When fluid catalyst cracking 

unit regenerator exhaust from two 

separate fluid catalytic cracking units 

share a common exhaust treatment (e.g., 

CO boiler or wet scrubber), the fluid 

catalytic cracking unit is a single 

affected facility. 

Fluid coking unit means one or more 

refinery process units in which high 

molecular weight petroleum derivatives 

are thermally cracked and petroleum 

coke is continuously produced in a 

fluidized bed system. The fluid coking 

unit includes equipment for controlling 

air pollutant emissions and for heat 

recovery on the fluid coking burner 

exhaust vent. 

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 combustion device means 

any equipment, such as process heaters, 

boilers, and flares, used to combust fuel 

gas, except facilities in which gases are 

combusted to produce sulfur or sulfuric 

acid. 

Fuel gas system means a system of 

compressors, piping, knock-out pots, 

mix drums, and units used to remove 

sulfur contaminants from the fuel gas 

(e.g., amine scrubbers) that collects 

refinery fuel gas from one or more 

sources for treatment as necessary prior 

to combusting in process heaters or 

boilers. A fuel gas system may have an 

overpressure vent to a flare but the 

primary purpose for a fuel gas system is 

to provide fuel to the refinery. 

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 or converting the SO2 to 

a sulfur product. 

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) 


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Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules and Regulations 35869 

or other products through distillation of 

petroleum or through redistillation, 

cracking, or reforming of unfinished 

petroleum derivatives. 

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 either recycling the H2S to the 

reactor furnace or the first-stage 

catalytic reactor of the Claus sulfur 

recovery plant or converting the H2S to 

a sulfur product. 

Refinery process unit means any 

segment of the petroleum refinery in 

which a specific processing operation is 

conducted. 

Sulfur pit means the storage vessel in 

which sulfur that is condensed after 

each Claus catalytic reactor is initially 

accumulated and stored. A sulfur pit 

does not include secondary sulfur 

storage vessels downstream of the initial 

Claus reactor sulfur pits. 

Sulfur recovery plant means all 

process units which recover sulfur from 

HS2 and/or SO2 at a petroleum refinery. 

The sulfur recovery plant also includes 

sulfur pits used to store the recovered 

sulfur product, but it does not include 

secondary sulfur storage vessels 

downstream of the sulfur pits. 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. Multiple sulfur 

recovery units are a single affected 

facility only when the units share the 

same source of sour gas. Sulfur recovery 

plants that receive source gas from 

completely segregated sour gas 

treatment systems are separate affected 

facilities. 

§ 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. 

(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 FCU: 

(1) Particulate matter (PM) in excess 

of the limits in paragraphs (b)(1)(i), (ii), 

or (iii) of this section. 

(i) 1.0 kilogram per Megagram (kg/ 

Mg)(1 pound (lb) per 1,000 lb) coke 

burn-off or, if a PM continuous emission 

monitoring system (CEMS) is used, 

0.040 grain per dry standard cubic feet 

(gr/dscf) corrected to 0 percent excess 

air for each modified or reconstructed 

FCCU. 

(ii) 0.5 gram per kilogram (g/kg) coke 

burn-off (0.5 lb PM/1,000 lb coke burnoff) or, if a PM CEMS is used, 0.020 gr/ 

dscf corrected to 0 percent excess air for 

each newly constructed FCCU. 

(iii) 1.0 kg/Mg (1 lb/1,000 lb) coke 

burn-off; or if a PM CEMS is used, 0.040 

grain per dry standard cubic feet (gr/ 

dscf) corrected to 0 percent excess air 

for each affected FCU. 

(2) Nitrogen oxides (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. 

(3) Sulfur dioxide (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. 

(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 FCU that uses a continuous 

parameter monitoring system (CPMS) 

according to § 60.105a(b)(1) shall 

comply with the applicable control 

device parameter operating limit in 

paragraph (c)(1) or (2) of this section. 

(1) If the FCCU or FCU is controlled 

using an electrostatic precipitator: 

(i) The 3-hour rolling average total 

power and secondary current to the 

entire system must not fall below the 

level established during the most recent 

performance test; and 

(ii) The daily average exhaust coke 

burn-off rate must not exceed the level 

established during the most recent 

performance test. 

(2) If the FCCU or FCU is controlled 

using a wet scrubber: 

(i) The 3-hour rolling average pressure 

drop must not fall below the level 

established during the most recent 

performance test; and 

(ii) The 3-hour rolling average liquidto-gas ratio must not fall below the level 

established during the most recent 

performance test. 

(d) If an FCCU or FCU uses a 

continuous opacity monitoring system 

(COMS) according to the alternative 

monitoring option in § 60.105a(e), the 3- 

hour rolling average opacity of 

emissions from the FCCU or FCU as 

measured by the COMS must not exceed 

the site-specific opacity limit 

established during the most recent 

performance test. 

(e) The owner or operator of a FCCU 

or FCU that is exempted from the 

requirement for a CO continuous 

emissions monitoring system under 

§ 60.105a(h)(3) shall comply with the 

parameter operating limits in paragraph 

(e)(1) or (2) of this section. 

(1) For a FCCU or FCU with no postcombustion control device: 

(i) The hourly average temperature of 

the exhaust gases exiting the FCCU or 

FCU 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 FCU must not fall 

below the level established during the 

most recent performance test. 

(2) For a FCCU or FCU with a postcombustion 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. 

(f) Except as provided in paragraph 

(f)(3), each owner or operator of an 

affected sulfur recovery plant shall 

comply with the applicable emission 

limits in paragraphs (f)(1) or (2) of this 

section. 

(1) For a sulfur recovery plant with a 

capacity greater than 20 long tons per 

day (LTD): 

(i) For a sulfur recovery plant with an 

oxidation control system or a reduction 

control system followed by incineration, 

the owner or operator shall not 

discharge or cause the discharge of any 

gases into the atmosphere in excess of 

250 ppm by volume (dry basis) of sulfur 

dioxide (SO2) at zero percent excess air. 

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; or 


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35870 Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules and Regulations 

(ii) For sulfur recovery plant with a 

reduction control system not followed 

by incineration, the owner or operator 

shall not discharge or cause the 

discharge of any gases into the 

atmosphere in excess of 300 ppm by 

volume of reduced sulfur compounds 

and 10 ppm by volume of hydrogen 

sulfide (HS2), each calculated as ppm 

SO2 by volume (dry basis) at zero 

percent excess air; or 

(iii) For systems using oxygen 

enrichment, the owner or operator shall 

calculate the applicable emission limit 

using Equation 1 of this section: 

Ek O O LS = ×− ∗ 1 2 ( ) ( ) + ∗+ 2

2 0 038 11 53 25 6 . % . % . (Eq. 1)

Where: 

ELS = Emission rate of SO2 for large sulfur 

recovery plant, ppmv; 

k1 = Constant factor for emission limit 

conversion: k1 = 1 for converting to SO2

limit and k1 = 1.2 for converting to the 

reduced sulfur compounds limit; and 

%O2 = O2 concentration to the SRP, percent 

by volume (dry basis). 

(2) For a sulfur recovery plant with a 

capacity of 20 LTD or less: 

(i) For a sulfur recovery plant with an 

oxidation control system or a reduction 

control system followed by incineration, 

the owner or operator shall not 

discharge or cause the discharge of any 

gases into the atmosphere in excess of 

2,500 ppm by volume (dry basis) of SO2

at zero percent excess air. If the sulfur 

recovery plant consists of multiple 

process trains or release points the 

owner or operator shall comply with the 

2,500 ppmv limit for each process train 

or release point or comply with a flow 

rate weighted average of 2,500 ppmv for 

all release points from the sulfur 

recovery plant; or 

(ii) For sulfur recovery plant with a 

reduction control system not followed 

by incineration, the owner or operator 

shall not discharge or cause the 

discharge of any gases into the 

atmosphere in excess of 3,000 ppm by 

volume of reduced sulfur compounds 

and 100 ppm by volume of hydrogen 

sulfide (H2S), each calculated as ppm 

SO2 by volume (dry basis) at zero 

percent excess air; or 

(iii) For systems using oxygen 

enrichment, the owner or operator shall 

calculate the applicable emission limit 

using Equation 2 of this section: 

Ek O O SS = ×− ∗ 1 2 ( ) ( ) + ∗+ 2

2 0 38 115 3 256 . % . % (Eq. 2)

Where: 

ESS = Emission rate of SO2 for small sulfur 

recovery plant, ppmv. 

(3) Periods of maintenance of the 

sulfur pit, during which the emission 

limits in paragraphs (f)(1) and (2) shall 

not apply, shall not exceed 240 hours 

per year. The owner or operator must 

document the time periods during 

which the sulfur pit vents were not 

controlled and measures taken to 

minimize emissions during these 

periods. Examples of these measures 

include not adding fresh sulfur or 

shutting off vent fans. 

(g) Each owner or operator of an 

affected fuel gas combustion device 

shall comply with the emission limits in 

paragraphs (g)(1) through (3) of this 

section. 

(1) For each fuel gas combustion 

device, the owner or operator shall 

comply with either the emission limit in 

paragraph (g)(1)(i) of this section or the 

fuel gas concentration limit in 

paragraph (g)(1)(ii) of this section. 

(i) The owner or operator shall not 

discharge or cause the discharge of any 

gases into the atmosphere that contain 

SO2 in excess of 20 ppmv (dry basis, 

corrected to 0 percent excess air) 

determined hourly on a 3-hour rolling 

average basis and SO2 in excess of 8 

ppmv (dry basis, corrected to 0 percent 

excess air), determined daily on a 365 

successive day rolling average basis; or 

(ii) The owner or operator shall not 

burn in any fuel gas combustion device 

any fuel gas that contains H2S in excess 

of 162 ppmv determined hourly on a 3- 

hour rolling average basis and H2S in 

excess of 60 ppmv determined daily on 

a 365 successive calendar day rolling 

average basis. 

(2) For each process heater with a 

rated capacity of greater than 40 million 

British thermal units per hour (MMBtu/ 

hr), the owner or operator shall not 

discharge to the atmosphere any 

emissions of NOX in excess of 40 ppmv 

(dry basis, corrected to 0 percent excess 

air) on a 24-hour rolling average basis. 

(3) Except as provided in paragraphs 

(h) and (i) of this section, the owner or 

operator of an affected flare shall not 

allow flow to each affected flare during 

normal operations of more than 7,080 

standard cubic meters per day (m3/day) 

(250,000 standard cubic feet per day 

(scfd)) on a 30-day rolling average. The 

owner or operator of a newly 

constructed or reconstructed flare shall 

comply with the emission limit in this 

paragraph by no later than the date that 

flare becomes an affected flare subject to 

this subpart. The owner or operator of 

a modified flare shall comply with the 

emission limit in this paragraph by no 

later than 1 year after that flare becomes 

an affected flare subject to this subpart. 

(h) 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 paragraph 

(g) of this section. 

(i) In periods of fuel gas imbalance 

that are described in the flare 

management plan required in section 

60.103a(a), compliance with the 

emission limit in paragraph (g)(3) of this 

section is demonstrated by following the 

procedures and maintaining records 

described in the flare management plan 

to document the periods of excess fuel 

gas. 

§ 60.103a Work practice standards. 

(a) Each owner or operator that 

operates a flare that is subject to this 

subpart shall develop and implement a 

written flare management plan. The 

owner or operator of a newly 

constructed or reconstructed flare must 

develop and implement the flare 

management plan by no later than the 

date that flare becomes an affected flare 

subject to this subpart. The owner or 

operator of a modified flare must 

develop and implement the flare 

management plan by no later than 1 

year after the flare becomes an affected 

flare subject to this subpart. The plan 

must include: 

(1) A diagram illustrating all 

connections to the flare; 

(2) Methods for monitoring flow rate 

to the flare, including a detailed 


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description of the manufacturer’s 

specifications, including but not limited 

to, make, model, type, range, precision, 

accuracy, calibration, maintenance, and 

quality assurance procedures for flare 

gas monitoring devices; 

(3) Procedures to minimize discharges 

to the flare gas system during the 

planned start-up and shutdown of the 

refinery process units that are connected 

to the affected flare; 

(4) Procedures to conduct a root cause 

analysis of any process upset or 

malfunction that causes a discharge to 

the flare in excess of 14,160 m3/day 

(500,000 scfd); 

(5) Procedures to reduce flaring in 

cases of fuel gas imbalance (i.e., excess 

fuel gas for the refinery’s energy needs); 

and 

(6) Explanation of procedures to 

follow during times that the flare must 

exceed the limit in § 60.102a(g)(3) (e.g., 

keep records of natural gas purchases to 

support assertion that the refinery is 

producing more fuel gas than needed to 

operate the processes). 

(b) Each owner or operator that 

operates a fuel gas combustion device or 

sulfur recovery plant subject to this 

subpart shall conduct a root cause 

analysis of any emission limit 

exceedance or process start-up, 

shutdown, upset, or malfunction that 

causes a discharge to the atmosphere in 

excess of 227 kilograms per day (kg/day) 

(500 lb per day (lb/day)) of SO2. For any 

root cause analysis performed, the 

owner or operator shall record the 

identification of the affected facility, the 

date and duration of the discharge, the 

results of the root cause analysis, and 

the action taken as a result of the root 

cause analysis. The first root cause 

analysis for a modified flare must be 

conducted no later than the first 

discharge that occurs after the flare has 

been an affected flare subject to this 

subpart for 1 year. 

(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 

combustion in a fuel gas combustion 

device. 

§ 60.104a Performance tests. 

(a) The owner or operator shall 

conduct a performance test for each 

FCCU, FCU, sulfur recovery plant, and 

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. 

(b) The owner or operator of a FCCU 

or FCU that elects to monitor control 

device operating parameters according 

to the requirements in § 60.105a(b), to 

use bag leak detectors according to the 

requirements in § 60.105a(c), or to use 

COMS according to the requirements in 

§ 60.105a(e) shall conduct a PM 

performance test at least once every 12 

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, Appendices 

A–1 through A–8 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 FCU using 

the following methods and procedures: 

(1) Method 1 of Appendix A–1 to part 

60 for sample and velocity traverses. 

(2) Method 2 of Appendix A–1 to part 

60 for velocity and volumetric flow rate. 

(3) Method 3, 3A, or 3B of Appendix 

A–2 to part 60 for gas analysis. The 

method ANSI/ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B of Appendix A–2 to part 60. 

(4) Method 5, 5B, or 5F of Appendix 

A–3 to part 60 for determining PM 

emissions and associated moisture 

content from a FCCU or FCU without a 

wet scrubber subject to the emissions 

limit in § 63.102a(b)(1). Use Method 5 or 

5B of Appendix A–3 to part 60 for 

determining PM emissions and 

associated moisture content from a 

FCCU or FCU with a wet scrubber 

subject to the emissions limit in 

§ 63.102a(b)(1). 

(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 

3 of this section: 

E c Q

K R

s sd

c

= (Eq. 3)

Where: 

E = Emission rate of PM, 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 

4 of this section: 

R K Q CO CO K Q K Q c r a r oxy oxy = + 1 2 2 3 2 23 ( ) +− + + ( ) CO CO O K Q O + ( ) 2 % % % % % % (Eq. 4)

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-dsc-%) [0.0186 (lbmin)/(hr-dscf-%)]; 

K2 = Material balance and conversion factor, 

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


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35872 Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules and Regulations 

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 of Appendix 

A–1 to part 60. 

(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 5 of this 

section: 

Q Q Oxy Q

CO CO O r

a oxy = ×+ − ×

− −−

79 100

100 2 2

( %)

% %% ( ) Eq. 5

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 6, 6A, or 6C of Appendix 

A–4 to part 60 for moisture content and 

for the concentration of SO2; the 

duration of each test run must be no less 

than 4 hours. The method ANSI/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 of Appendix A–

4 to part 60. 

(6) Method 7, 7A, 7C, 7D, or 7E of 

Appendix A–4 to part 60 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. The 

method ANSI/ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 7 or 7C of Appendix A–4 to part 

60. 

(7) Method 10, 10A, or 10B of 

Appendix A–4 to part 60 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 6 of this 

section: 

C C adj meas O = c

( ) −





 



 20 9

20 9 2

.

. % (Eq. 6)

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. 

(e) The owner or operator of a FCCU 

or FCU that is controlled by an 

electrostatic precipitator or wet scrubber 

and that is subject to control device 

operating parameter limits in 

§ 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 hourly average 

operating limit for each required 

parameter as the average of the three test 

runs. 

(f) The owner or operator of an FCCU 

or FCU that uses cyclones to comply 

with the PM limit in § 60.102a(b)(1) and 

elects to comply with the COMS 

alternative monitoring option in 

§ 60.105a(d) shall establish a sitespecific opacity operating limit 

according to the procedures in 

paragraphs (f)(1) through (3) of this 

section. 

(1) Collect COMS data every 10 

seconds during the entire period of the 

PM performance test and reduce the 

data to 6-minute averages. 

(2) Determine and record the hourly 

average opacity from all the 6-minute 

averages. 

(3) Compute the site-specific limit 

using Equation 7 of this section: 

Opacity Limit = Opacity x lb lb coke burn

PMEmR st

st

1 /1,000 



 



 (Eq. 7)

Where: 

Opacity limit = Maximum permissible hourly 

average opacity, percent, or 10 percent, 

whichever is greater; 

Opacityst = Hourly average opacity measured 

during the source test runs, percent; and 

PMEmRst = PM emission rate measured 

during the source test, lb/1,000 lbs coke 

burn. 

(g) The owner or operator of a FCCU 

or FCU that is exempt from the 

requirement to install and operate a CO 

CEMS pursuant to § 60.105a(h)(3) and 

that is subject to control device 

operating parameter limits in 

§ 60.102a(c) shall establish the limits 

based on the performance test results 


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using the procedures in paragraphs 

(g)(1) and (2) of this section. 

(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 average of the average temperature 

and O2 concentration for the three test 

runs. 

(h) The owner or operator shall 

determine compliance with the SO2 and 

H2S emissions limits for sulfur recovery 

plants in §§ 60.102a(f)(1)(i), 

60.102a(f)(1)(iii), 60.102a(f)(1)(iii), 

60.102a(f)(2)(i), and 60.102a(f)(2)(iii) 

and the reduced sulfur compounds and 

H2S emissions limits for sulfur recovery 

plants in § 60.102a(f)(1)(ii) and 

§ 60.102a(f)(2)(ii) using the following 

methods and procedures: 

(1) Method 1 of Appendix A–1 to part 

60 for sample and velocity traverses. 

(2) Method 2 of Appendix A–1 to part 

60 for velocity and volumetric flow rate. 

(3) Method 3, 3A, or 3B of Appendix 

A–2 to part 60 for gas analysis. The 

method ANSI/ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B of Appendix A–2 to part 60. 

(4) Method 6, 6A, or 6C of Appendix 

A–4 to part 60 to determine the SO2

concentration. The method ANSI/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 of Appendix A–

4 to part 60. 

(5) Method 15 or 15A of Appendix A–

5 to part 60 or Method 16 of Appendix 

A–6 to part 60 to determine the reduced 

sulfur compounds and H2S 

concentrations. The method ANSI/ 

ASME PTC 19.10–1981, ‘‘Flue and 

Exhaust Gas Analyses,’’ (incorporated 

by reference—see § 60.17) is an 

acceptable alternative to EPA Method 

15A of Appendix A–5 to part 60. 

(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 6 of this section to adjust 

pollutant concentrations to 0 percent O2

or 0 percent excess air. 

(i) The owner or operator shall 

determine compliance with the SO2 and 

NOX emissions limits in § 60.102a(g) for 

a fuel gas combustion device according 

to the following test methods and 

procedures: 

(1) Method 1 of Appendix A–1 to part 

60 for sample and velocity traverses; 

(2) Method 2 of Appendix A–1 to part 

60 for velocity and volumetric flow rate; 

(3) Method 3, 3A, or 3B of Appendix 

A–2 to part 60 for gas analysis. The 

method ANSI/ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B of Appendix A–2 to part 60; 

(4) Method 6, 6A, or 6C of Appendix 

A–4 to part 60 to determine the SO2

concentration. The method ANSI/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 of Appendix A–

4 to part 60. 

(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)(1)(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 of 

Appendix A–4 to part 60 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. The method ANSI/ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 7 or 7C of Appendix A–

4 to part 60. 

(j) The owner or operator shall 

determine compliance with the H2S 

emissions limit in § 60.102a(g) for a fuel 

gas combustion device according to the 

following test methods and procedures: 

(1) Method 1 of Appendix A–1 to part 

60 for sample and velocity traverses; 

(2) Method 2 of Appendix A–1 to part 

60 for velocity and volumetric flow rate; 

(3) Method 3, 3A, or 3B of Appendix 

A–2 to part 60 for gas analysis. The 

method ANSI/ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B of Appendix A–2 to part 60; 

(4) Method 11, 15, or 15A of 

Appendix A–5 to part 60 or Method 16 

of Appendix A–6 to part 60 for 

determining the H2S concentration for 

affected plants using an H2S monitor as 

specified in § 60.107a(a)(2). The method 

ANSI/ASME PTC 19.10–1981, ‘‘Flue 

and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 15A of Appendix A–5 to part 

60. The owner or operator may 

demonstrate compliance based on the 

mixture used in the fuel gas combustion 

device or for each individual fuel gas 

stream used in the fuel gas combustion 

device. 

(i) For Method 11 of Appendix A–5 to 

part 60, 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 constitutes 

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 of Appendix A–5 

to part 60, at least three injects over a 

1-hour period constitutes a run. 

(iii) For Method 15A of Appendix A–

5 to part 60, a 1-hour sample constitutes 

a run. The method ANSI/ASME PTC 

19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 15A of Appendix A–5 

to part 60. 

(iv) If monitoring is conducted at a 

single point in a common source of fuel 

gas as allowed under § 60.107a(a)(2)(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 (FCU). 

(a) FCCU and FCU subject to PM 

emissions limit. Each owner or operator 

subject to the provisions of this subpart 

shall monitor each FCCU and FCU 

subject to the PM emissions limit in 

§ 60.102a(b)(1) according to the 

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

or (e) of this section. 

(b) Control device operating 

parameters. Each owner or operator of 

a FCCU or FCU subject to the PM per 

coke burn-off emissions limit in 

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

requirements in paragraphs (b)(1) 

through (3) of this section. 


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35874 Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules and Regulations 

(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 

entire system. 

(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. As 

an alternative to a CPMS, the owner or 

operator must comply with the 

requirements in either paragraph 

(b)(1)(ii)(A) or (B) of this section. 

(A) As an alterative to pressure drop, 

the owner or operator of a jet ejector 

type wet scrubber or other type of wet 

scrubber equipped with atomizing spray 

nozzles must conduct a daily check of 

the air or water pressure to the spray 

nozzles and record the results of each 

check. 

(B) As an alternative to exhaust gas 

flow rate, the owner or operator shall 

comply with the approved alternative 

for monitoring exhaust gas flow rate in 

40 CFR 63.1573(a) of the National 

Emission Standards for Hazardous Air 

Pollutants for Petroleum Refineries: 

Catalytic Cracking Units, Catalytic 

Reforming Units, and Sulfur Recovery 

Units. 

(iii) The owner or operator shall 

install, operate, and maintain each 

CPMS according to the manufacturer’s 

specifications and requirements. 

(iv) The owner or operator shall 

determine and record the average coke 

burn-off rate and hours of operation for 

each FCCU or FCU using the procedures 

in § 60.104a(d)(4)(iii). 

(v) If you use a control device other 

than an electrostatic precipitator, wet 

scrubber, fabric filter, or cyclone, you 

may request approval to monitor 

parameters other than those required in 

paragraph (b)(1) of this section by 

submitting an alternative monitoring 

plan to the Administrator. The request 

must include the information in 

paragraphs (b)(1)(v)(A) through (E) of 

this section. 

(A) A description of each affected 

facility and the parameter(s) to be 

monitored to determine whether the 

affected facility will continuously 

comply with the emission limitations 

and an explanation of the criteria used 

to select the parameter(s). 

(B) A description of the methods and 

procedures that will be used to 

demonstrate that the parameter(s) can be 

used to determine whether the affected 

facility will continuously comply with 

the emission limitations and the 

schedule for this demonstration. The 

owner or operator must certify that an 

operating limit will be established for 

the monitored parameter(s) that 

represents the conditions in existence 

when the control device is being 

properly operated and maintained to 

meet the emission limitation. 

(C) The frequency and content of the 

recordkeeping, recording, and reporting, 

if monitoring and recording are not 

continuous. The owner or operator also 

must include the rationale for the 

proposed monitoring, recording, and 

reporting requirements. 

(D) Supporting calculations. 

(E) Averaging time for the alternative 

operating parameter. 

(2) For use in determining the coke 

burn-off rate for an FCCU or FCU, 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 of Appendix B to part 60. 

(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 of 

Appendix B to part 60. The owner or 

operator shall use Method 3 of 

Appendix A–3 to part 60 for conducting 

the relative accuracy evaluations. 

(iii) The owner or operator shall 

comply with the quality assurance 

requirements of procedure 1 of 

Appendix F to part 60, including 

quarterly accuracy determinations for 

CO2 and CO monitors, annual accuracy 

determinations for O2 monitors, and 

daily calibration drift tests. 

(c) Bag leak detection systems. Each 

owner or operator shall install, operate, 

and maintain a bag leak detection 

system for each baghouse or similar 

fabric filter control device that is used 

to comply with the PM per coke burnoff emissions limit in § 60.102a(b)(1) for 

an FCCU or FCU 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 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 

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. 


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Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules and Regulations 35875 

(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) 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 action(s) are 

necessary. 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). An owner or operator 

subject to the PM concentration 

emission limit (in gr/dscf) in 

§ 60.102a(b)(1) for an FCCU or FCU 

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 appendix B to part 

60. 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 of 

appendix B to part 60. The owner or 

operator shall use EPA Methods 5 or 5I 

of Appendix A–3 to part 60 or Method 

17 of Appendix A–6 to part 60 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 appendix B to part 60. 

The span value of this O2 monitor must 

be selected between 10 and 25 percent, 

inclusive. 

(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 of 

Appendix B to part 60. Method 3, 3A, 

or 3B of Appendix A–2 to part 60 shall 

be used for conducting the relative 

accuracy evaluations. The method 

ANSI/ASME PTC 19.10–1981, ‘‘Flue 

and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B of Appendix A–2 to part 60. 

(5) The owner or operator shall 

comply with the quality assurance 

requirements of Procedure 2 of 

Appendix B to part 60 for each PM 

CEMS and Procedure 1 of Appendix F 

to part 60 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) Alternative monitoring option for 

FCCU and FCU—COMS. Each owner or 

operator of an FCCU or FCU that uses 

cyclones to comply with the PM 

emission limit in § 60.102a(b)(1) shall 

monitor the opacity of emissions 

according to the requirements in 

paragraphs (e)(1) through (3) of this 

section. 

(1) The owner or operator shall 

install, operate, and maintain an 

instrument for continuously monitoring 

and recording the opacity of emissions 

from the FCCU or the FCU exhaust vent. 

(2) The owner or operator shall 

install, operate, and maintain each 

COMS according to Performance 

Specification 1 of Appendix B to part 

60. The instrument shall be spanned at 

20 to 60 percent opacity. 

(3) The owner or operator shall 

conduct performance evaluations of 

each COMS according to § 60.13(c) and 

Performance Specification 1 of 

Appendix B to part 60. 

(f) FCCU and FCU subject to NOX

limit. Each owner or operator subject to 

the NOX emissions limit in 

§ 60.102a(b)(2) for an FCCU or FCU 

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 of Appendix B to part 

60. 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 of 

Appendix B to part 60. The owner or 

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

7D, or 7E of Appendix A–4 to part 60 

for conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 


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Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 7 or 7C of Appendix A–

4 to part 60. 

(3) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of Appendix B to part 

60. The span value of this O2 monitor 

must be selected between 10 and 25 

percent, inclusive. 

(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 of 

Appendix B to part 60. Method 3, 3A, 

or 3B of Appendix A–2 to part 60 shall 

be used for conducting the relative 

accuracy evaluations. The method 

ANSI/ASME PTC 19.10–1981, ‘‘Flue 

and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B of Appendix A–2 to part 60. 

(5) The owner or operator shall 

comply with the quality assurance 

requirements of Procedure 1 of 

Appendix F to part 60 for each NOX and 

O2 monitor, including quarterly 

accuracy determinations for NOX

monitors, annual accuracy 

determinations for O2 monitors, and 

daily calibration drift tests. 

(g) FCCU and FCU subject to SO2

limit. The owner or operator subject to 

the SO2 emissions limit in 

§ 60.102a(b)(3) for an FCCU or an FCU 

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 of Appendix B to part 

60. 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 of 

Appendix B to part 60. The owner or 

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

of Appendix A–4 to part 60 for 

conducting the relative accuracy 

evaluations. The method ANSI / 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 of Appendix A–

4 to part 60. 

(3) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of Appendix B to part 

60. The span value of this O2 monitor 

must be selected between 10 and 25 

percent, inclusive. 

(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 of 

Appendix B to part 60. Method 3, 3A, 

or 3B of Appendix A–2 to part 60 shall 

be used for conducting the relative 

accuracy evaluations. The method 

ANSI/ASME PTC 19.10–1981, ‘‘Flue 

and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B of Appendix A–2 to part 60. 

(5) The owner or operator shall 

comply with the quality assurance 

requirements in Procedure 1 of 

Appendix F to part 60 for each SO2 and 

O2 monitor, including quarterly 

accuracy determinations for SO2

monitors, annual accuracy 

determinations for O2 monitors, and 

daily calibration drift tests. 

(h) FCCU and fluid coking units 

subject to CO emissions limit. Except as 

specified in paragraph (h)(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 FCU 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 or 4A of Appendix B to 

part 60. 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 or 4A of 

Appendix B to part 60. The owner or 

operator shall use Methods 10, 10A, or 

10B of Appendix A–4 to part 60 for 

conducting the relative accuracy 

evaluations. 

(3) A CO CEMS need not be installed 

if the owner or operator demonstrates 

that all hourly average CO emissions are 

and will remain less than 50 ppmv (dry 

basis) corrected to 0 percent excess air. 

The Administrator may revoke this 

exemption from monitoring upon a 

determination that CO emissions on an 

hourly average basis have exceeded 50 

ppmv (dry basis) corrected to 0 percent 

excess air, in which case a CO CEMS 

shall be installed within 180 days. 

(i) The demonstration shall consist of 

continuously monitoring CO emissions 

for 30 days using an instrument that 

meets the requirements of Performance 

Specification 4 or 4A of Appendix B to 

part 60. 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 of Appendix A–4 to part 60 and 

employ the sample conditioning system 

of Method 10A of Appendix A–4 to part 

60, the alternative relative accuracy test 

procedure in section 10.1 of 

Performance Specification 2 of 

Appendix B to part 60 may be used in 

place of the relative accuracy test. 

(ii) The owner or operator must 

submit the following information to the 

Administrator: 

(A) The measurement data specified 

in paragraph (h)(3)(i) of this section 

along with all other operating data 

known to affect CO emissions; and 

(B) Descriptions of the CPMS for 

exhaust gas temperature and O2 monitor 

required in paragraph (h)(4) of this 

section and operating limits for those 

parameters to ensure combustion 

conditions remain similar to those that 

exist during the demonstration period. 

(iii) The effective date of the 

exemption from installation and 

operation of a CO CEMS is the date of 

submission of the information and data 

required in paragraph (h)(3)(ii) of this 

section. 

(4) The owner or operator of a FCCU 

or FCU that is exempted from the 

requirement to install and operate a CO 

CEMS in paragraph (h)(3) of this section 

shall install, operate, calibrate, and 

maintain CPMS to measure and record 

the operating parameters in paragraph 

(h)(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 FCU with no postcombustion control device, the 

temperature and O2 concentration of the 

exhaust gas stream exiting the unit. 

(ii) For a FCCU or FCU with a postcombustion control device, the 

temperature and O2 concentration of the 

exhaust gas stream exiting the control 

device. 

(i) Excess emissions. For the purpose 

of reports required by § 60.7(c), periods 

of excess emissions for a FCCU or FCU 

subject to the emissions limitations in 

§ 60.102a(b) are defined as specified in 

paragraphs (i)(1) through (6) of this 

section. Note: Determine all averages, 

except for opacity, 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. 


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(1) If a CPMS is used according to 

§ 60.105a(b)(1), all 3-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. 

(2) 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(d) 

exceeds 0.040 gr/dscf corrected to 0 

percent excess air for a modified or 

reconstructed FCCU, 0.020 gr/dscf 

corrected to 0 percent excess air for a 

newly constructed FCCU, or 0.040 gr/ 

dscf for an affected fluid coking unit. 

(3) If a COMS is used according to 

§ 60.105a(e), all 3-hour periods during 

which the average opacity, as measured 

by the COMS under § 60.105a(e), 

exceeds the site-specific limit 

established during the most recent 

performance test. 

(4) All rolling 7-day periods during 

which the average concentration of NOX

as measured by the NOX CEMS under 

§ 60.105a(f) exceeds 80 ppmv for an 

affected FCCU or FCU. 

(5) Except as provided in paragraph 

(i)(7) of this section, all rolling 7-day 

periods during which the average 

concentration of SO2 as measured by the 

SO2 CEMS under § 60.105a(g) 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. 

(6) All 1-hour periods during which 

the average CO concentration as 

measured by the CO continuous 

monitoring system under §1A60.105a(h) 

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(h)(4) fall below the operating 

limits established during the 

performance test. 

§ 60.106a Monitoring of emissions and 

operations for sulfur recovery plants. 

(a) The owner or operator of a sulfur 

recovery plant that is subject to the 

emissions limits in § 60.102a(f)(1) or 

§ 60.102a(f)(2) shall: 

(1) For sulfur recovery plants subject 

to the SO2 emission limit in 

§ 60.102a(f)(1)(i) or § 60.102a(f)(2)(i), the 

owner or operator shall install, operate, 

calibrate, and maintain an instrument 

for continuously monitoring and 

recording the concentration (dry basis, 

zero percent excess air) of any SO2

emissions into the atmosphere. The 

monitor shall include an oxygen 

monitor for correcting the data for 

excess air. 

(i) The span values for this monitor 

are two times the applicable SO2

emission limit and between 10 and 25 

percent O2, inclusive. 

(ii) The owner or operator shall 

install, operate, and maintain each SO2

CEMS according to Performance 

Specification 2 of Appendix B to part 

60. 

(iii) The owner or operator shall 

conduct performance evaluations of 

each SO2 monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 2 of 

Appendix B to part 60. The owner or 

operator shall use Methods 6 or 6C of 

Appendix A–4 to part 60 and Method 3 

or 3A of Appendix A–2 of part 60 for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 6. 

(2) For sulfur recovery plants that are 

subject to the reduced sulfur compound 

and H2S emission limit in 

§ 60.102a(f)(1)(ii) or § 60.102a(f)(2)(ii), 

the owner or operator shall install, 

operate, calibrate, and maintain an 

instrument for continuously monitoring 

and recording the concentration of 

reduced sulfur, H2S, and O2 emissions 

into the atmosphere. The reduced sulfur 

emissions shall be calculated as SO2

(dry basis, zero percent excess air). 

(i) The span values for this monitor 

are two times the applicable reduced 

sulfur emission limit, two times the H2S 

emission limit, and between 10 and 25 

percent O2, inclusive. 

(ii) The owner or operator shall 

install, operate, and maintain each 

reduced sulfur CEMS according to 

Performance Specification 5 of 

Appendix B to part 60. 

(iii) The owner or operator shall 

conduct performance evaluations of 

each reduced sulfur monitor according 

to the requirements in § 60.13(c) and 

Performance Specification 5 of 

Appendix B to part 60. The owner or 

operator shall use Methods 15 or 15A of 

Appendix A–5 to part 60 for conducting 

the relative accuracy evaluations. The 

method ANSI/ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 15A of Appendix A–5 to part 

60. 

(iv) The owner or operator shall 

install, operate, and maintain each H2S 

CEMS according to Performance 

Specification 7 of Appendix B to part 

60. 

(v) The owner or operator shall 

conduct performance evaluations of 

each reduced sulfur monitor according 

to the requirements in § 60.13(c) and 

Performance Specification 5 of 

Appendix B to part 60. The owner or 

operator shall use Methods 11, 15, or 

15A of Appendix A–5 to part 60 or 

Method 16 of Appendix A–6 to part 60 

for conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 15A of Appendix A–5 

to part 60. 

(vi) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of Appendix B to part 

60. 

(vii) The span value for the O2

monitor must be selected between 10 

and 25 percent, inclusive. 

(viii) The owner or operator shall 

conduct performance evaluations for the 

O2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 3 of 

Appendix B to part 60. The owner or 

operator shall use Methods 3, 3A, or 3B 

of Appendix A–2 to part 60 for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 3B of Appendix A–2 to 

part 60. 

(ix) The owner or operator shall 

comply with the applicable quality 

assurance procedures of Appendix F to 

part 60 for each monitor, including 

annual accuracy determinations for each 

O2 monitor, and daily calibration drift 

determinations. 

(3) In place of the reduced sulfur 

monitor required in paragraph (a)(2) of 

this section, the owner or operator shall 

install, calibrate, operate, 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 span value for this monitor is 

two times the applicable SO2 emission 

limit. 

(ii) The owner or operator shall 

conduct performance evaluations of 

each SO2 monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 5 of 

Appendix B to part 60. The owner or 

operator shall use Methods 15 or 15A of 


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Appendix A–5 to part 60 for conducting 

the relative accuracy evaluations. The 

method ANSI/ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 15A of Appendix A–5 to part 

60. 

(iii) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of Appendix B to part 

60. 

(iv) The span value for the O2 monitor 

must be selected between 10 and 25 

percent, inclusive. 

(v) The owner or operator shall 

conduct performance evaluations for the 

O2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 3 of 

Appendix B to part 60. The owner or 

operator shall use Methods 3, 3A, or 3B 

of Appendix A–2 to part 60 for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 3B of Appendix A–2 to 

part 60. 

(vi) The owner or operator shall 

comply with the applicable quality 

assurance procedures of Appendix F to 

part 60 for each monitor, including 

quarterly accuracy determinations for 

each SO2 monitor, annual accuracy 

determinations for each O2 monitor, and 

daily calibration drift determinations. 

(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(f) 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 12-hour average as 

the arithmetic average of 12 contiguous 

1-hour averages. 

(1) All 12-hour periods during which 

the average concentration of SO2 as 

measured by the SO2 continuous 

monitoring system required under 

paragraph (a)(1) of this section exceeds 

the applicable emission limit (dry basis, 

zero percent excess air); or 

(2) All 12-hour periods during which 

the average concentration of reduced 

sulfur (as SO2) as measured by the 

reduced sulfur continuous monitoring 

system required under paragraph (a)(2) 

of this section exceeds the applicable 

emission limit; or 

(3) All 12-hour periods during which 

the average concentration of H2S as 

measured by the H2S continuous 

monitoring system required under 

paragraph (a)(2) of this section exceeds 

the applicable emission limit (dry basis, 

0 percent excess air). 

§ 60.107a Monitoring of emissions and 

operations for fuel gas combustion devices. 

(a) Fuel gas combustion devices 

subject to SO2 or H2S limit. The owner 

or operator of a fuel gas combustion 

device that is subject to the 

requirements in § 60.102a(g) shall 

comply with the requirements in 

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

emissions or paragraph (a)(2) of this 

section for H2S emissions. 

(1) The owner or operator of a fuel gas 

combustion device subject to the SO2

emissions limits in § 60.102a(g)(1)(i) 

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 of Appendix B to part 60. The span 

value 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 of 

Appendix B to part 60. The owner or 

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

of Appendix A–4 to part 60 for 

conducting the relative accuracy 

evaluations. The method ANSI/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 of Appendix A–

4 to part 60. Samples taken by Method 

6 of Appendix A–4 to part 60 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 of Appendix B to part 

60. The span value for the O2 monitor 

must be selected between 10 and 25 

percent, inclusive. 

(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 of 

Appendix B to part 60. The owner or 

operator shall use Methods 3, 3A, or 3B 

of Appendix A–2 to part 60 for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 3B of Appendix A–2 to 

part 60. 

(v) The owner or operator shall 

comply with the applicable quality 

assurance procedures in Appendix F to 

part 60, including quarterly accuracy 

determinations for SO2 monitors, annual 

accuracy determinations for O2

monitors, and daily calibration drift 

tests. 

(vi) 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(g)(1)(ii) 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 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 of Appendix B to part 60. The span 

value for this instrument is 320 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 of 

Appendix B to part 60. The owner or 

operator shall use Method 11, 15, or 

15A of Appendix A–5 to part 60 or 

Method 16 of Appendix A–6 to part 60 

for conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 15A of Appendix A–5 

to part 60. 

(iii) The owner or operator shall 

comply with the applicable quality 

assurance procedures in Appendix F to 

part 60 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 is not required to 

comply with paragraph (a)(1) or (2) of 

this section for fuel gas streams that are 


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exempt under § 60.102a(h) 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)(3)(i) 

through (iv) of this section will be 

considered inherently low in sulfur 

content. 

(i) Pilot gas for heaters and flares. 

(ii) Fuel gas streams that meet a 

commercial-grade product specification 

for sulfur content of 30 ppmv or less. In 

the case of a liquefied petroleum gas 

(LPG) product specification in the 

pressurized liquid state, the gas phase 

sulfur content should be evaluated 

assuming complete vaporization of the 

LPG and sulfur containing-compounds 

at the product specification 

concentration. 

(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, isomerization 

unit, and HF alkylation process units. 

(iv) Other fuel gas streams that an 

owner or operator demonstrates are lowsulfur according to the procedures in 

paragraph (b) of this section. 

(4) If the composition of an exempt 

fuel gas stream changes, the owner or 

operator must follow the procedures in 

paragraph (b)(3) of this section. 

(b) Exemption from H2S monitoring 

requirements for low-sulfur fuel 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 for a fuel gas stream that is 

inherently low in sulfur content. A fuel 

gas stream that is demonstrated to be 

low-sulfur is exempt from the 

monitoring requirements of paragraphs 

(a)(1) and (2) 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 fuel gas 

stream/system to be considered, 

including submission of a portion of the 

appropriate piping diagrams indicating 

the boundaries of the fuel 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 fuel 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 

fuel gas stream (i.e., control equipment 

or product specifications) at all times; 

(iv) The supporting test results from 

sampling the requested fuel gas stream/ 

system demonstrating that the sulfur 

content is less than 5 ppm H2S. 

Sampling data must include, at 

minimum, 2 weeks of daily monitoring 

(14 grab samples) for frequently 

operated fuel gas streams/systems; for 

infrequently operated fuel 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 Processors Association Standard 

2377–86, 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 fuel gas stream 

for H2S; and 

(v) A description of how the 2 weeks 

(or seven samples for infrequently 

operated fuel gas streams/systems) of 

monitoring results compares to the 

typical range of H2S concentration (fuel 

quality) expected for the fuel 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 

fuel gas stream going to the loading rack 

flare). 

(2) The effective date of the 

exemption is the date of submission of 

the information required in paragraph 

(b)(1) of this section. 

(3) No further action is required 

unless refinery operating conditions 

change in such a way that affects the 

exempt fuel 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 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 new information 

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 new 

information to support an exemption, 

the owner or operator must begin H2S 

monitoring using daily stain sampling to 

demonstrate compliance. The owner or 

operator must begin monitoring 

according to the requirements in 

paragraphs (a)(1) or (a)(2) of this section 

as soon as practicable but in no case 

later than 180 days after the operation 

change. During daily stain tube 

sampling, a daily sample exceeding 162 

ppmv is an exceedance of the 3-hour 

H2S concentration limit. The owner or 

operator must determine a rolling 365- 

day average using the stain sampling 

results; an average H2S concentration of 

5 ppmv must be used for days prior to 

the operation change. 

(c) Process heaters subject to NOX

limit. The owner or operator of a process 

heater subject to the NOX emission limit 

in § 60.102a(g)(2) 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 of Appendix B to part 

60. 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 of 

Appendix B to part 60. The owner or 

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

7D, or 7E of Appendix A–4 to part 60 

for conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference—

see § 60.17) is an acceptable alternative 

to EPA Method 7 or 7C of Appendix A–

4 to part 60. 

(3) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of Appendix B to part 

60. The span value of this O2 monitor 

must be selected between 10 and 25 

percent, inclusive. 

(4) The owner or operator shall 

conduct performance evaluations of 

each O2 monitor according to the 

requirements in § 60.13(c) and 


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35880 Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules and Regulations 

Performance Specification 3 of 

Appendix B to part 60. Method 3, 3A, 

or 3B of Appendix A–2 to part 60 shall 

be used for conducting the relative 

accuracy evaluations. The method 

ANSI/ASME PTC 19.10–1981, ‘‘Flue 

and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 3B of Appendix A–2 to part 60. 

(5) The owner or operator shall 

comply with the quality assurance 

requirements in Procedure 1 of 

Appendix F to part 60 for each NOX and 

O2 monitor, including quarterly 

accuracy determinations for NOX

monitors, annual accuracy 

determinations for O2 monitors, and 

daily calibration drift tests. 

(6) The owner or operator of a process 

heater that has a rated heating capacity 

of less than 100 MMBtu and is equipped 

with low-NOX burners (LNB) or ultra 

low-NOX burners (ULNB) is not subject 

to the monitoring requirements in 

paragraphs (c)(1) through (5) of this 

section. The owner or operator of such 

a process heater must conduct biennial 

performance tests to demonstrate 

compliance. 

(d) Sulfur monitoring for affected 

flares. The owner or operator of an 

affected flare subject to § 60.103a(b) 

shall install, operate, calibrate, and 

maintain an instrument for 

continuously monitoring and recording 

the concentration of reduced sulfur in 

flare gas. The owner or operator of a 

modified flare shall install this 

instrument by no later than 1 year after 

the flare becomes an affected flare 

subject to this subpart. 

(1) The owner or operator shall 

install, operate, and maintain each 

reduced sulfur CEMS according to 

Performance Specification 5 of 

Appendix B to part 60. 

(2) The owner or operator shall 

conduct performance evaluations of 

each reduced sulfur monitor according 

to the requirements in § 60.13(c) and 

Performance Specification 5 of 

Appendix B to part 60. The owner or 

operator shall use Methods 15 or 15A of 

Appendix A–5 to part 60 for conducting 

the relative accuracy evaluations. The 

method ANSI/ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses,’’

(incorporated by reference—see § 60.17) 

is an acceptable alternative to EPA 

Method 15A of Appendix A–5 to part 

60. 

(3) The owner or operator shall 

comply with the applicable quality 

assurance procedures in Appendix F to 

part 60 for each reduced sulfur monitor. 

(e) Flow monitoring for flares. The 

owner or operator of an affected flare 

subject to § 60.102a(g)(3) shall install, 

operate, calibrate, and maintain CPMS 

to measure and record the exhaust gas 

flow rate. The owner or operator of a 

modified flare shall install this 

instrument by no later than 1 year after 

the flare becomes an affected flare 

subject to this subpart. 

(1) The CPMS must be able to correct 

for the temperature and pressure of the 

system and output flow in standard 

conditions as defined in § 60.2. 

(2) The owner or operator shall 

install, operate, and maintain each 

CPMS according to the manufacturer’s 

specifications and requirements. 

(f) Excess emissions. For the purpose 

of reports required by § 60.7(c), periods 

of excess emissions for fuel gas 

combustion devices subject to the 

emissions limitations in § 60.102a(g) are 

defined as specified in paragraphs (f)(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 rolling 3-hour periods during 

which the average concentration of SO2

as measured by the SO2 continuous 

monitoring system required 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 required 

under paragraph (a)(1) of this section 

exceeds 8 ppmv; or 

(2) All rolling 3-hour periods during 

which the average concentration of H2S 

as measured by the H2S continuous 

monitoring system required under 

paragraph (a)(2) of this section exceeds 

162 ppmv, all days in which the 

concentration of H2S as measured by 

daily stain tube sampling required 

under paragraph (b)(3)(iii) of this 

section exceeds 162 ppmv, and all 

rolling 365-day periods during which 

the average concentration as measured 

by the H2S continuous monitoring 

system under paragraph (a)(2) 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 required under 

paragraph (c) of this section exceeds 40 

ppmv. 

(4) All rolling 30-day periods during 

which the average flow rate to an 

affected flare as measured by the 

monitoring system required under 

paragraph (e) of this section exceeds 

250,000 scfd. 

§ 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). 

(c) The owner or operator shall 

maintain the following records: 

(1) A copy of the flare management 

plan and each root cause analysis of a 

discharge; 

(2) Records of information to 

document conformance with bag leak 

detection system operation and 

maintenance requirements in 

§ 60.105a(c). 

(3) Records of bag leak detection 

system alarms and actions according to 

§ 60.105a(c). 

(4) For each FCCU and fluid coking 

unit subject to the monitoring 

requirements in § 60.105a(b)(1), records 

of the average coke burn-off rate and 

hours of operation. 

(5) For each fuel gas stream to which 

one of the exemptions listed in 

§ 60.107a(a)(3) applies, records of the 

specific exemption determined to apply 

for each fuel stream. If the owner or 

operator applies for the exemption 

described in § 60.107a(a)(3)(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. 

(6) The owner or operator shall record 

and maintain records of discharges 

greater than 500 lb/day SO2 from any 

affected fuel gas combustion device or 

sulfur recovery plant and discharges to 

an affected flare in excess of 500,000 

scfd. These records shall include: 

(i) A description of the discharge. 

(ii) For discharges greater than 500 lb/ 

day SO2, the date and time the discharge 

was first identified and the duration of 

the discharge. 

(iii) 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 for fuel gas 

combustion devices other than flares. 

(iv) For discharges greater than 500 

lb/day SO2, the measured or estimated 


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Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules and Regulations 35881 

concentration of H2S, TRS and SO2 of 

the stream discharged. Process 

knowledge can be used to make these 

estimates for fuel gas combustion 

devices other than flares. 

(v) For discharges greater than 500 lb/ 

day SO2, the cumulative quantity of H2S 

and SO2 released into the atmosphere. 

For releases controlled by flares, assume 

99 percent conversion of reduced sulfur 

to SO2. For other fuel gas combustion 

devices, assume 99 percent conversion 

of H2S to SO2. 

(vi) Results of any root-cause analysis 

conducted as required in § 60.103a(a)(4) 

and § 60.103a(b). 

(d) 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 (d)(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 an affected facility or 

control system; and 

(4) A description of the action taken, 

if any. 

(5) A root-cause summary report that 

provides the information described in 

paragraph (e)(6) of this section for all 

discharges for which a root-cause 

analysis was required by § 60.103a(a)(4) 

and § 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. 

(7) A written statement, signed by a 

responsible official, certifying the 

accuracy and completeness of the 

information contained in the report. 

§ 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 (3) 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 a major change to test 

methods under § 60.8(b). A ‘‘major 

change to test method’’ is defined in 40 

CFR 63.90. 

(2) Approval of a major change to 

monitoring under § 60.13(i). A ‘‘major 

change to monitoring’’ is defined in 40 

CFR 63.90. 

(3) Approval of a major change to 

recordkeeping/reporting under § 60.7(b) 

through (f). A ‘‘major change to 

recordkeeping/reporting’’ is defined in 

40 CFR 63.90. 

[FR Doc. E8–13498 Filed 6–23–08; 8:45 am] 

BILLING CODE 6560–50–P 


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