6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 9 and 60

[EPA-HQ-OAR-2007-0011; FL- ]

RIN 2060-AN72

Standards of Performance for Petroleum Refineries; Standards of 

Performance for Petroleum Refineries for Which Construction, 

Reconstruction, or Modification Commenced After May 14, 2007

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule; lift stay of effective date.

SUMMARY: On June 24, 2008, EPA promulgated amendments to the 

Standards of Performance for Petroleum Refineries and new 

standards of performance for petroleum refinery process units 

constructed, reconstructed, or modified after May 14, 2007. EPA 

subsequently received three petitions for reconsideration of 

these final rules. On September 26, 2008, EPA granted 

reconsideration and issued a stay for the issues raised in the 

petitions regarding process heaters and flares. On December 22, 

2008, EPA addressed those specific issues by proposing 

amendments to certain provisions for process heaters and flares. 

EPA also proposed technical corrections to the rules for issues 

that were raised in the petitions for reconsideration. In this 

action, EPA is finalizing those amendments and technical 

corrections and is lifting the stay of all the provisions 

granted on September 26, 2008.
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DATES: The stay of all the provisions is lifted and the final 

rule is effective on [INSERT DATE 60 DAYS FROM DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. The incorporation by 

reference of certain publications listed in the final rule is 

approved by the Director of the Federal Register as of [INSERT 

DATE 60 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER].

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.
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FOR FURTHER INFORMATION CONTACT: Ms. Brenda Shine, Office of 

Air Quality Planning and Standards, Sector Policies and Programs 

Division, Refining and Chemicals Group (E143-01), Environmental 

Protection Agency, Research Triangle Park, NC 27711, telephone 

number: (919) 541-3608; fax number: (919) 541-0246; e-mail 

address: shine.brenda@epa.gov.

SUPPLEMENTARY INFORMATION:

The information 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

II. Background Information

III. Summary of the Final Rules and Changes Since Proposal

A. What are the final amendments to the standards of 

performance for petroleum refineries (40 CFR part 60, 

subpart J)?

B. What are the final amendments to the standards of 

performance for process heaters (40 CFR part 60, subpart 

Ja)?

C. What are the final amendments to the standards of 

performance for flares (40 CFR part 60, subpart Ja)?

D. What are the final amendments to the definitions in 40 CFR 

part 60, subpart Ja?

E. What are the final technical corrections to 40 CFR part 60, 

subpart Ja?

IV. Summary of Significant Comments and Responses

A. Process Heaters

B. Flares

C. Other Comments

V. Summary of Cost, Environmental, Energy, and Economic Impacts

A. What are the emission reduction and cost impacts for the 

final amendments?

B. What are the economic impacts?

C. 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
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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

I. General Information

A. Does this action apply to me?

Categories and entities potentially regulated by these 

final rules include:

Category NAICS 

Code1

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.
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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.

EPA has created a redline document comparing the existing 

regulatory text of 40 CFR part 60, subpart Ja and the final 

amendments to aid the public’s ability to understand the changes 

to the regulatory text. This document has been placed in the 

docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2007-0011).

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 [INSERT DATE 60 DAYS FROM 

DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 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.
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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.

II. Background Information

Section 111(b)(1)(A) of the Clean Air Act (CAA) requires 

the EPA to establish federal standards of performance for new, 

modified and reconstructed sources for source categories which 
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cause, or contribute significantly to, air pollution which may 

reasonably be anticipated to endanger public health or welfare. 

The standard of performance must reflect the application of the 

best system of emission reductions that (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 (CAA section 111(a)(1)). If it is not feasible to 

prescribe or enforce a standard of performance, the 

Administrator may instead promulgate a design, equipment, work 

practice, or operational standard, or a combination of these 

types of standards (CAA section 111(h)(1)). Since 1970, the New 

Source Performance Standards (NSPS) have been successful in 

achieving long-term emissions reductions in numerous industries 

by assuring cost-effective controls are installed on newly 

constructed, reconstructed, or modified sources. 

The level of control prescribed by section 111 historically 

has been referred to as “Best Demonstrated Technology” or BDT. 

In order to better reflect that section 111 was amended in 1990 

to clarify that “best systems” may or may not be “technology,” 

the EPA is now using the term “best system of emission 

reduction” or BSER. As was done previously in analyzing BDT, the 

EPA uses available information and considers the emissions 

reductions achieved by the different systems available and the 
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costs of achieving those reductions. EPA also considers the 

other factors prescribed by the statute in its BSER analysis.

After considering all of this information, the EPA then 

establishes the appropriate standard representative of BSER. 

Sources may generally use whatever system meets the standard.

Section 111(b)(1)(B) of the CAA requires EPA to 

periodically review and, as appropriate, revise the standards of 

performance 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 (40 CFR part 60, 

subpart Ja) (72 FR 27278, May 14, 2007), and we subsequently 

promulgated those amendments and new standards (73 FR 35838, 

June 24, 2008). Following promulgation, we received three 

separate petitions for reconsideration from: (1) the American 

Petroleum Institute (API), the National Petrochemical and 

Refiners Association (NPRA), and the Western States Petroleum 

Association (WSPA) (collectively referred to as “Industry 

Petitioners”); (2) HOVENSA, LLC (“HOVENSA”); and (3) the 

Environmental Integrity Project, Sierra Club, and Natural 

Resources Defense Council (collectively referred to as 

“Environmental Petitioners”). On September 26, 2008, EPA issued 

a Federal Register notice (73 FR 55751) granting reconsideration 
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of the following issues: (1) the newly promulgated flare 

modification provision;1 (2) the “flare” definition; (3) the fuel 

gas combustion device sulfur limits as they apply to flares; (4) 

the flow limit for flares; (5) the total reduced sulfur and flow 

monitoring requirements for flares; and (6) the nitrogen oxide 

(NOX) limit for process heaters. EPA also granted Industry 

Petitioners’ and HOVENSA’s request for a 90-day stay for those 

same provisions under reconsideration. On December 22, 2008, 

three Federal Register notices (73 FR 78260, 73 FR 78546, and 73 

FR 78549) were published to extend this stay until a final 

decision is reached on those issues. 

In the September 26, 2008, Federal Register notice (73 FR 

55751), we also identified other issues for which Petitioners 

requested reconsideration. We stated that at that time, we were 

“taking no action on all of the other issues raised in the

petitions but will consider all of the outstanding issues in a 

future notice.” On December 29, 2009, we sent a letter to the 

Petitioners, through their counsel, stating that “[t]he 

Administrator has decided to grant reconsideration of all the 

 

1 The September 26, 2008, Federal Register notice (73 FR 55751) 

described the first issue for which EPA granted reconsideration 

as “the definition of ‘modification.’” However, because what we 

are actually reconsidering is the specific flare modification 

provision that applies to flares at petroleum refineries rather 

than the more generally applicable definition of “modification,” 

we have revised the description of this issue as “the newly 

promulgated flare modification provision.”
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remaining issues” and that “EPA will address the substantive 

aspects of the issues under reconsideration through notice and 

comment actions published in the Federal Register.” A copy of 

the letter to the Petitioners can be found in the docket for 

this rulemaking (Docket ID No. EPA-HQ-OAR-2007-0011-0339). 

In this action, we are finalizing the amendments for which 

we granted reconsideration and a stay as outlined in the 

September 26 notice and for which we proposed amendments on 

December 22, 2008. We are also addressing certain other minor 

issues raised by Industry Petitioners in this action, as 

discussed later in this preamble. We will take action on all of 

the remaining issues raised by Petitioners for reconsideration 

in future notices. We plan to address a number of these issues, 

as well as conduct risk and technology reviews of our air toxics 

standards for refineries in a comprehensive manner, as described 

in the December 23, 2010, settlement agreement with the 

Environmental Petitioners (Docket Number EPA-HQ-OAR-2007-0011-

0340).

We received a total of 22 comments from the following 

groups on the proposed amendments during the public comment 

period: (1) refineries, industry trade associations, and 

consultants; (2) State and local environmental and public health 

agencies; (3) environmental groups; and (4) other members of the 

public. These final amendments reflect our full consideration 
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of all of the comments we received. Detailed responses to the 

comments not included in this preamble, as well as more detailed 

summaries of the comments addressed in this preamble, are 

contained in “Standards of Performance for Petroleum Refineries: 

Background Information for Final Amendments - Summary of Public 

Comments and Responses,” dated October 2011, which is included 

in Docket ID No. EPA-HQ-OAR-2007-0011.

III. Summary of the Final Rules and Changes Since Proposal 

NSPS for petroleum refineries (40 CFR part 60, subpart J) 

apply to the affected facilities at the refinery, such as fuel 

gas combustion devices (which include process heaters, boilers,

and flares), that commence construction, reconstruction, or 

modification after June 11, 1973, but on or before May 14, 2007 

(on or before June 24, 2008 for flares). The NSPS were 

originally promulgated on March 8, 1974, and have been amended 

several times. In this action, we are promulgating technical 

clarifications and corrections to subpart J.

New standards of performance for petroleum refineries (40 

CFR part 60, subpart Ja) apply to flares that commence 

construction, reconstruction, or modification after June 24, 

2008, and other affected facilities at petroleum refineries, 

including process heaters and other fuel gas combustion devices, 

that commence construction, reconstruction, or modification 

after May 14, 2007. In this action, we are finalizing 
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amendments to subpart Ja to address the issues raised by 

Petitioners regarding flares and process heaters. We are also 

finalizing technical corrections to subpart Ja for certain 

issues that were identified by Industry Petitioners in their 

August 21, 2008, supplement to their original administrative 

reconsideration request (Docket Item No. EPA-HQ-OAR-2007-0011-

0246).

The following sections summarize the amendments in both 40 

CFR part 60, subpart J and 40 CFR part 60, subpart Ja. Section 

IV contains the rationale for these amendments, while the 

amendments themselves follow the preamble.

A. What are the final amendments to the standards of 

performance for petroleum refineries (40 CFR part 60, subpart 

J)?

The final amendments add a new paragraph to 40 CFR 60.100 

to allow 40 CFR part 60, subpart J affected sources the option 

of complying with subpart J by following the requirements in 40 

CFR part 60, subpart Ja. The subpart Ja requirements are at 

least as stringent as those in subpart J, so providing this 

option will allow all process units in a refinery to follow the 

same requirements and simplify compliance. We are also 

finalizing a correction to the value and units (in the metric 

system) for the allowable incremental rate of particulate matter 

(PM) emissions in 40 CFR 60.106(c)(1). We amended the units for 
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this constant in 40 CFR 60.102(b) on June 24, 2008, and we are 

now correcting 40 CFR 60.106(c)(1) accordingly. Finally, we are 

finalizing a definition of “fuel gas” that incorporates the same 

clarifications regarding vapors from wastewater treatment units 

and marine tank vessel loading operations identified in the 

subpart Ja definition of “fuel gas” (described later in this 

preamble).

B. What are the final amendments to the standards of 

performance for process heaters (40 CFR part 60, subpart Ja)?

We proposed several amendments to the standards of 

performance for process heaters, including adding emission 

limits in units of pounds per million British thermal units 

(lb/MMBtu), extending the emission limit averaging time from 24 

hours to 365 days, raising the emission limit for modified and 

reconstructed forced draft process heaters, and raising the 

emission limit for co-fired process heaters. After 

consideration of all of the public comments, and our own 

additional analyses, we are finalizing the process heater 

requirements as described in this section.

The final amendments include four subcategories of process 

heaters: (1) natural draft process heaters; (2) forced draft 

process heaters; (3) co-fired natural draft process heaters; and 

(4) co-fired forced draft process heaters. At proposal, all cofired process heaters were included in one subcategory, for a 
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total of three process heater subcategories, but based on 

emissions data from co-fired process heaters, we divided natural 

draft and forced draft co-fired process heaters into separate 

subcategories with different emissions limits.

For each of the first two subcategories, the final 

amendments include a concentration-based NOX emissions limit and 

a heating value-based NOX emissions limit, both determined daily 

on a 30-day rolling average basis. For the natural draft 

process heater subcategory, the concentration-based NOX emissions 

limit for newly constructed, modified, and reconstructed natural 

draft process heaters is 40 parts per million by volume (ppmv) 

(dry basis, corrected to 0 percent excess air) determined daily 

on a 30-day rolling average basis. The heating value-based NOX

emissions limit for newly constructed, modified, and 

reconstructed natural draft process heaters is 0.040 pounds per 

million British thermal units (lb/MMBtu) higher heating value 

basis determined daily on a 30-day rolling average basis. The 

averaging time for both of these limits is shorter than the 365-

day averaging time that was proposed, and the heating valuebased NOX emissions limit differs from the proposed limit in that 

it is a more direct numerical conversion from 40 ppmv NOX. 

Section IV.A of this preamble provides additional information 

regarding the rationale and analyses leading to these final 

amendments.
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For the second subcategory, forced draft process heaters, 

the concentration-based NOX emissions limit for newly 

constructed, modified, and reconstructed forced draft process 

heaters is 60 ppmv (dry basis, corrected to 0 percent excess 

air) determined daily on a 30-day rolling average basis. The 

heating value-based NOX emissions limit for newly constructed, 

modified, and reconstructed forced draft process heaters is 

0.060 lb/MMBtu higher heating value basis determined daily on a 

30-day rolling average basis. The higher limit for new forced 

draft process heaters (at proposal, the limit was 40 ppmv) is 

based on additional data and a re-evaluation of BSER as 

described later in this preamble. As with natural draft process 

heaters, the averaging time for both of these limits is shorter 

than proposed, and the final heating value-based NOX emissions 

limit is a more direct numerical conversion from 60 ppmv NOX. 

Section IV.A of this preamble provides additional information 

regarding the rationale and analyses leading to these final 

amendments.

For each of these subcategories, a process heater need only 

meet either the concentration-based NOX emissions limit or the 

heating value-based NOX emissions limit. The refinery owner or 

operator may choose to comply with either limit at any time, 

provided that they are monitoring the appropriate variables to 

assess the heating value-based NOX emissions limit. If the 
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refinery owner or operator does not choose to monitor fuel 

composition, then they must comply with the concentration-based 

NOX emissions limit. 

As proposed, initial compliance with the heating valuebased emissions limits will be demonstrated by conducting a 

performance evaluation of the continuous emission monitoring 

system (CEMS) in accordance with Performance Specification 2 in 

appendix B to 40 CFR part 60, with Method 7 of 40 CFR part 60, 

appendix A-4 as the Reference Method, along with fuel flow 

measurements and fuel gas compositional analysis. The NOX

emission rate is calculated using the oxygen-based F factor, dry 

basis according to Method 19 of 40 CFR part 60, appendix A-7. 

Ongoing compliance with this NOX emissions limit is determined 

using a NOX CEMS and at least daily sampling of fuel gas heat 

content or composition to calculate a daily average heating 

value-based emissions rate, which is subsequently used to 

determine the 30-day average.

The third and fourth subcategories of process heaters are 

co-fired process heaters. A co-fired process heater is a 

process heater that employs burners that are designed to be 

supplied by both gaseous and liquid fuels. As described in more 

detail in Section IV.A of this preamble, co-fired process 

heaters do not include gas-fired process heaters that have 

emergency oil back-up burners. There are two compliance options 
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for each subcategory of co-fired process heaters: (1) 150 ppmv 

(dry basis, corrected to 0 percent excess air) determined daily 

on a 30 successive operating day rolling average basis; and (2) 

a source-specific daily average emissions limit. Unlike gasfired process heaters, the owner or operator of a co-fired 

process heater must choose one emissions limit and show 

compliance with that limit. For co-fired natural draft process 

heaters, the daily average emissions limit is based on a limit 

of 0.06 lb/MMBtu for the gas portion of the firing and 0.35 

lb/MMBtu for the oil portion of the firing. For co-fired forced 

draft process heaters, the daily average emissions limit is 

based on a limit of 0.11 lb/MMBtu for the gas portion of the 

firing and 0.40 lb/MMBtu for the oil portion of the firing. 

These limits are different than proposed based on a reevaluation of BSERwith new data received during the public 

comment period. All of the requirements for emissions

monitoring, recordkeeping, and reporting for co-fired process 

heaters are the same as for the other process heater 

subcategories.

We are also finalizing an alternative compliance option 

that allows owners and operators to obtain EPA approval for a 

site-specific NOX limit for certain process heaters. This 

compliance option was provided in the proposed amendments, but 

it was limited to (1) natural draft and forced draft modified or 
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reconstructed process heaters that lack sufficient space to 

accommodate combustion modification-based technology and (2) 

natural draft and forced draft co-fired process heaters. In the 

final amendments, we are finalizing this compliance option for 

those process heaters mentioned above while also providing this 

compliance option for the following additional types of process 

heaters: (3) modified or reconstructed induced draft process 

heaters that have downwardly firing burners and (4) forced draft 

and natural draft process heaters that operate at low firing 

rates, or turndown, for an extended period of time. As we noted 

in the preamble to the proposed amendments, in limited cases, 

existing natural draft or forced draft process heaters have 

limited firebox size or other constraints such that they cannot 

apply the BSER of ultra-low NOX burners or otherwise meet the 

applicable limit, and some co-fired units may not be able to 

achieve the NOX limitations even with ultra-low NOX burner 

control technology. In addition, commenters noted that 

downwardly fired process heaters with induced draft fans have 

similar NOX control issues as forced draft heaters, but the 

definition of forced draft heater does not include these induced 

draft heaters(these are defined as natural draft process 

heaters). Therefore, we added a provision to allow induced

draft process heaters with downwardly-firing burners to use the

alternative compliance option. 
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Finally, we note that the emissions limits for forced draft 

and natural draft gas-fired process heaters are based on the 

performance of ultra-low NOX burner control technologies. The 

ultra-low NOX burner technology suppliers recommend operating 

with higher excess air rates at low firing rates (at or below 

approximately one-half of the maximum firing capacity), which 

causes higher NOX concentrations at low firing rates. Therefore, 

all types of process heaters with ultra-low NOX burner control 

technologies may be unable to meet the emissions limits if they 

are operated at low firing rates for an extended period of time. 

Requesting a site-specific emissions limit requires a detailed 

demonstration that the application of the ultra-low NOX burner 

technology is not feasible or that the technology cannot meet 

the NOX emissions limits given the conditions of the process 

heater (downward fired induced draft, co-fired, or prolonged 

turndown); the refinery must also conduct source tests in 

developing a site-specific emissions limit for its process 

heater. This analysis must be submitted to and approved by the 

Administrator.

We are finalizing the proposed clarification that owners 

and operators of process heaters in any subcategory with a rated 

heating capacity of less than 100 million British thermal units 

per hour (MMBtu/hr) have the option of using CEMS. The final

rule states that owners and operators of process heaters subject 
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to subpart Ja should use CEMS to demonstrate compliance unless 

the heater is equipped with combustion modification-based 

technology (low-NOX burners or ultra-low NOX burners) with a 

rated heating capacity of less than 100 MMBtu/hr; owners and 

operators of those specific process heaters have the alternative 

option of biennial source testing to determine compliance. As 

requested by commenters, we have provided additional detail in 

the final rule regarding how to develop the O2 operating limit, 

including provisions on how to develop an O2 operating curve to 

ensure compliance with the NOX emission limit at different 

process heater firing rates. We are requiring that owners and 

operators with process heaters in any subcategory that are 

complying using biennial source testing establish a maximum 

excess oxygen (O2) concentration operating limit or operating 

curve that can be met at all times, even during turndown, and 

comply with the O2 monitoring requirements for ongoing compliance 

demonstration.

C. What are the final amendments to the standards of 

performance for flares (40 CFR part 60, subpart Ja)?

We proposed several amendments to the standards of 

performance for flares, including, but not limited to, amending 

the flare modification provision, removing the numerical limit 

on the flow rate to the flare, revising the flare management 

plan requirements to include a list of connections to the flare 
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and an identification of baseline conditions, clarifying when a 

root cause analysis is required, revising the sulfur and flow 

monitoring requirements, and providing additional time for 

compliance. After consideration of all of the public comments, 

and our own additional analyses, we are finalizing the flare 

requirements as described in this section.

We did not propose to revise the definitions of “fuel gas 

combustion device” and “flare” on December 22, 2008. However, 

based on public comment and changes to the flare requirements as 

described later in this section, we have decided to finalize 

revisions to these definitions to specify that for purposes of 

subpart Ja, a flare is a separate affected facility rather than 

a type of fuel gas combustion device. This change makes clearer 

the differences between the requirements for flares and the 

requirements for fuel gas combustion devices, particularly in 

terms of sulfur and flow rate monitoring requirements and 

thresholds for root cause analyses and corrective action 

analyses. We are also making corrections as needed in numerous 

paragraphs throughout subpart Ja for consistency with the 

amended definitions (e.g., adding “and flares” where applicable 

to paragraphs with requirements for “fuel gas combustion 

devices”).

We are finalizing the flare modification provision in 40 

CFR 60.100a(c) as described below to specify certain connections 
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to a flare that do not constitute a modification of the flare 

because they do not result in emissions increases. On December 

22, 2008, we proposed that the following types of connections to 

a flare would not be considered a modification of the flare: 

(1) connections made to install monitoring systems to the 

flares; (2) connections made to install a flare gas recovery 

system; (3) connections made to replace or upgrade existing 

pressure relief or safety valves, provided the new pressure 

relief or safety valve has a set point opening pressure no lower 

and an internal diameter no greater than the existing equipment 

being replaced or upgraded; and (4) replacing piping or moving 

an existing connection from a refinery process unit to a new 

location in the same flare, provided the new pipe diameter is 

less than or equal to the diameter of the pipe/connection being 

replaced/moved. We are finalizing those proposed amendments and 

also adding the following types of connections to the list of 

connections to flares that are not modifications of flares: (1) 

connections between flares; (2) connections for flare gas sulfur 

removal; and (3) connections made to install redundant flare 

equipment (such as a back-up compressor). We are also 

clarifying one of the proposed exemptions to indicate that 

connections made to upgrade or enhance components of flare gas 

recovery systems (e.g., additional compressors or recycle lines) 

are not modifications.
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We are not finalizing the proposed amendment to provide 

additional time for flares that need to install additional amine 

scrubbing and amine stripping columns to meet the 60 ppmv 

hydrogen sulfide (H2S) concentration limit determined daily on a 

365 successive calendar day rolling average basis (hereafter 

referred to as the long-term 60 ppmv H2S concentration limit). 

Instead, based on comments received during the public comment 

period for the proposed amendments, and our own additional 

analyses, we are removing the requirement for flares to meet the 

long-term 60 ppmv H2S concentration limit. As explained in 

Section IV, we determined that requiring refineries to ensure 

the fuel gas they send to their flares meets a long-term H2S 

concentration of 60 ppmv is not appropriate for flares. 

We are promulgating final amendments for flares that 

include a suite of standards that apply at all times that are 

aimed at reducing SO2 emissions from flares. These amendments 

include several that were proposed on December 22, 2008, as well 

as others that differ from those proposed but are a logical 

outgrowth of the proposed amendments. This suite of standards 

requires refineries to: (1) develop and implement a flare 

management plan; (2) conduct root cause analyses and take 

corrective action when waste gas sent to the flare exceeds a 

flow rate of 500,000 standard cubic feet (scf) above the 

baseline flow to a flare in any 24-hour period (rather than the 
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proposed threshold of 500,000 scf in any 24-hour period without 

considering the baseline); (3) conduct root cause analyses and 

take corrective action when the emissions from the flare exceed

500 pounds of SO2 in a 24-hour period (instead of 500 pounds SO2

above the emissions limit); and (4)optimize management of the 

fuel gas by limiting the short-term concentration of H2S to 162 

ppmv during normal operating conditions (determined hourly on a 

3-hour rolling average basis). See Section IV.B. for a more 

detailed explanation of these requirements. In this rule, we 

are using the term “normal operating conditions” to describe 

situations where the process is operating in a routine, 

predictable manner such that the gases from the process are 

predictable, as opposed to less-predictable swings related to 

emergency situations during which the flare begins to operate as 

a safety device. It is important to emphasize that the 

requirement to optimize management of the fuel gas by limiting 

the short-term concentration of H2S to 162 ppmv will apply during 

the vast majority of the time and any exemptions from this 

requirement should be very narrow and the number of occasions to 

which an exemption will apply is, and always has been, limited, 

such as when a flare is used as a safety device “under emergency 

conditions.”

2 

 

2 Background Information for New Source Performance Standards, Vol. 3, Promulgated Standards (APTD-1352c; 

Publication No. EPA 450/2-74-003), pg 127 (Feb. 1974) (“NSPS BID Vol. 3”). 
Page 25 of 269

In addition, we are specifying that if a discharge 

exceeding either or both of the SO2 or flow thresholds described 

above is the result of a planned startup or shutdown of a 

refinery process unit or ancillary equipment connected to the 

flare, and the flare management plan procedures for minimizing 

flow (which minimizes emissions) during that type of event are

followed, a root cause analysis and corrective action analysis 

are not required. Finally, we are finalizing the proposed added 

provisions to ensure that owners and operators implement 

corrective actions on the findings of the SO2 or flow rate root 

cause analyses and to specify a deadline for performing the 

corrective actions. 

We are finalizing the proposed amendment to remove the 

250,000 standard cubic feet per day (scfd) 30-day average flow 

rate limit. Our rationale for this decision is explained in the 

preamble to the proposed amendments (73 FR 78530)and also in 

Section IV of this preamble.

We are finalizing one proposed amendment to the flare 

management plan, and adding several new requirements as a 

logical outgrowth of the proposed amendments considering the 

public comments we received, to ensure compliance with the flare 

standards. First, as proposed, we are requiring a list of 

refinery process units and fuel gas systems connected to each 

affected flare. However, we are also adding a requirement for a 
Page 26 of 269

simple process flow diagram showing the design of the flare, 

connections to the flare header and subheader system(s), and all 

gas lines associated with the flare. With these two 

requirements, we are clarifying that the flare management plan 

must include a diagram of the flare and connections, but the 

diagram need not be a detailed piping and instrumentation 

diagram (P&ID) that shows all process units and ancillary 

equipment connected to the flare. We are also requiring the 

owner and operator of an affected flare to assess and minimize 

flow to affected flares from these process units and fuel gas 

systems. Second, we are adding new requirements that the flare 

management plan include design and operation details about the 

affected flare, including tip diameter, type of flare, 

monitoring methods, and a description of the flare gas recovery 

system, if present. The inclusion of these details will ensure 

that the rest of the flare management plan is reasonable and 

appropriate for that affected flare. 

Third, as a logical outgrowth of the proposed amendments

considering the public comments we received, we are adding a new 

requirement for owners and operators to determine the baseline 

flow to each flare, including purge and sweep gas, and include 

this baseline flow in the flare management plan. As described 

later in this preamble, developing the baseline is important 

because the final threshold for the flare flow root cause 
Page 27 of 269

analysis takes this baseline flow into consideration. Finally, 

we are adding a new requirement to minimize the volume of gas 

flared during maintenance of a flare gas recovery system.

We have decided to remove the requirement for the owner or 

operator to explain in the flare management plan how a root 

cause analysis and corrective action analysis will be conducted 

if the flow to the flare exceeds the specified threshold. 

Instead, all the requirements for determining when and how to 

conduct a root cause analysis and corrective action analysis,

and the requirements for when and how to implement a corrective 

action, have been expanded as described later in this section 

and moved to 40 CFR 60.103a(c) through (e).

We are specifying that for modified flares, the flare 

management plan must be developed and implemented by no later 

than [INSERT DATE 3 YEARS FROM DATE OF PUBLICATION IN THE 

FEDERAL REGISTER], 3 years from the date the modification 

commences, or upon startup of the modified flare, whichever is 

later (the proposed amendments provided 18 months with an 

additional 6 months if the owner or operator committed to 

installing a flare gas recovery system). In addition, because 

of the lack of a direct flow emissions limit and the addition of

the baseline flow value, we are adding a requirement that the 

flare management plan must be submitted to the Administrator.
Page 28 of 269

As with the flare management plan, the owner or operator of 

an affected flare must comply with the root cause analysis and 

corrective action analysis requirements within 3 years from the 

promulgation date, within 3 years from the date the modification 

commences, or upon startup of the modified flare, whichever is 

later. 

We are finalizing several proposed amendments to the sulfur 

monitoring requirements and revising other requirements as a 

logical outgrowth of the proposed amendments considering the 

public comments we received. We consolidated the proposed 

alternatives to monitor reduced sulfur compounds and total 

sulfur compounds, and we are amending the rule to allow the use 

of total reduced sulfur monitoring. We also clarified the span 

requirements for these monitors and are allowing the use of 

cylinder gas audits for relative accuracy assessments. We are 

finalizing the H2S monitoring alternative method for determining 

total sulfur content in the flare gas as proposed, but we have 

clarified the span requirements for this monitor and are 

allowing the use of cylinder gas audits for relative accuracy 

assessments, similar to the total reduced sulfur monitor 

requirements. For refineries that measure SO2 concentrations in 

the exhaust from a fuel gas combustion device that combusts gas 

representative of the gas discharged to the flare, we added an 

alternative to allow the owner or operator to use the existing 
Page 29 of 269

SO2 CEMS data to calculate the total sulfur content in the flare 

gas.

We received public comments stating that the flow and 

sulfur monitoring requirements for flares were too burdensome 

for flares that are used infrequently or that are configured

such that they cannot receive high sulfur flare gas. Based on 

our evaluation of these comments, we are providing new 

alternatives to continuous flow and sulfur monitoring for 

certain flares. First, for flares that are configured such that 

they only receive inherently low sulfur gas streams described in 

40 CFR 60.107a(a)(3)(i) through (iv) or (b), continuous sulfur 

monitors are not necessary because a root cause analysis will be 

triggered by an exceedance of the flow rate threshold long 

before they exceed the 500 lb SO2 trigger in a 24-hour period. 

Second, we are providing an alternative monitoring option 

for emergency flares, secondary flares, and flares equipped with 

a flare gas recovery system designed, sized, and operated to 

capture all flows (except flows resulting from planned startup

and shutdown that are addressed in the flare management plan). 

If this option is applicable, the owner or operator may elect to 

continuously monitor the water seal height and the pressure in 

the flare header just upstream of the water seal rather than 

install total sulfur and flow monitoring systems. If this 

monitoring option is selected, any instance where the pressure 
Page 30 of 269

upstream of the water seal (expressed in inches of water) 

exceeds the water seal height triggers a requirement to perform 

a root cause analysis and corrective action analysis, unless the 

discharge is related to flare gas recovery system compressor 

cycling or a planned startup or shutdown (of a refinery process 

unit or ancillary equipment connected to the flare) following 

the procedures in the flare management plan. An “emergency 

flare” is a flare that combusts gas exclusively released as a 

result of malfunctions (and not startup, shutdown, routine 

operations, or any other cause) and is characterized as having 

four or fewer discharge events in any 365 consecutive calendar 

days.

Owners or operators of affected flares that have flare gas 

recovery systems with staged compressors that elect to use this 

monitoring option must identify these flares in their flare 

management plan, identify the time period required for the 

staged compressors to actively start to recover gas, and 

identify the operating parameters monitored and procedures 

employed to minimize the duration of flaring during compressor 

staging. If a pressure exceedance is caused during compressor 

staging and the duration of the pressure exceedance is less than 

the time specified in the flare management plan, then a root 

cause analysis is not required and the pressure exceedance is 

not required to be reported. If a pressure exceedance is not 
Page 31 of 269

attributable to compressor staging (i.e., all staged compressors 

are active), if a pressure exceedance is the result of a planned 

startup and shutdown event during which the flare management 

plan is not followed, or if the duration of a pressure 

exceedance attributable to compressor staging is greater than 

the time specified in the flare management plan, then a root 

cause analysis and corrective action analysis are required and 

the pressure exceedance must be reported. More than four

pressure exceedances required to be reported as described above 

and under 40 CFR 60.108a(d)(5) (hereafter referred to as 

“reportable pressure exceedances”) in any 365 consecutive 

calendar days is an indication that the flare gas recovery 

system is not adequately sized, and the sulfur and flow monitors 

as required in 40 CFR 60.107a(e) and (f) must be installed if 

that occurs. 

Third, we are clarifying that monitors for flow and sulfur

on the second flare in a staged flare configuration are not 

required where the water seal monitoring requirements 

adequately and appropriately address this scenario. Under most 

circumstances, the root cause analysis is expected to be 

triggered based on the flow to or emissions from the primary 

flare. However, in cases where the capacity of the primary 

flare is small (less than 500,000 scfd), this may not always be 

the case. Additionally, we consider the water seal monitoring 
Page 32 of 269

on the secondary flare to be appropriate to ensure that gases 

are not released to the secondary flare inadvertently. We 

clarify in this final rule that if a root cause analysis is 

triggered for the primary flare, releases to the secondary flare 

do not trigger an additional root cause analysis (i.e., the 

releases may be treated as one event). However, if flow is 

diverted to the secondary flare, then a root cause analysis is 

required even if a root cause analysis was not triggered for the 

primary flare based on flow rate or SO2 emissions. In addition, 

if flow is diverted to the secondary flare five or more times in 

a 365-day period, flow monitoring of the secondary flare is 

required. We anticipate that the upstream sulfur monitor on the 

primary flare can be used to determine the sulfur content of the 

gas diverted to the secondary flare.

In response to comments, we are also finalizing a new 

amendment providing an alternative compliance option in 40 CFR 

60.103a(g) and 40 CFR 60.107a(h) for certain flares. 

Specifically, for refineries located in the South Coast Air 

Quality Management District (SCAQMD), an affected flare subject 

to subpart Ja may elect to comply with SCAQMD Rule 1118 as an 

alternative to complying with the requirements for flares in 40 

CFR 60.103a(a) through (e) and the associated monitoring 

provisions in 40 CFR 60.107a(e) and (f). Similarly, for 

refineries located in the Bay Area Air Quality Management 
Page 33 of 269

District (BAAQMD), an affected flare subject to subpart Ja may 

elect to comply with both BAAQMD Regulation 12, Rule 11 and 

BAAQMD Regulation 12, Rule 12 as an alternative to complying

with the requirements for flares in 40 CFR 60.103a(a) through 

(e) and the associated monitoring provisions in 40 CFR 

60.107a(e) and (f). We are also finalizing specific provisions 

within the standards for owners or operators (and manufacturers 

of equipment) to submit a request for a determination of 

equivalence for “an alternative means of emission limitation” 

that will achieve a reduction in emissions at least equivalent 

to the reduction in emissions achieved under any of the final 

subpart Ja design, equipment, work practice, or operational 

requirements in accordance with CAA section 111(h). 

For fuel gas combustion devices and sulfur recovery plants, 

we are correcting and clarifying the threshold for a root cause 

analysis and corrective action analysis. The proposed root 

cause analysis threshold for both types of process units was 500 

lb SO2 above the emission limit, but the proposed amendments 

directed the owner or operator to compare the SO2 emissions to 

“the period of the exceedance” for fuel gas combustion devices 

and “the entire 24-hour period” for sulfur recovery plants. 

That language meant that if one 12-hour average for a sulfur 

recovery plant was above the emission limit, the owner or 

operator would have compared those emissions to the emissions 
Page 34 of 269

allowed over an entire 24 hours to determine if root cause 

analysis was required. However, although a 12-hour average 

above the emission limit clearly means that more SO2 was emitted 

than allowed by that emissions limit, it is possible that since 

the time periods being compared were not analogous, the “allowed 

emissions” over 24 hours could be more than the actual emissions 

that made up the one 12-hour average. Upon further 

consideration, we see no reason for the requirements to be 

different for fuel gas combustion devices and sulfur recovery 

plants. Therefore, we are finalizing an amendment that states 

that the threshold for a root cause analysis and corrective 

action analysis for both sulfur recovery plants and fuel gas 

combustion devices is 500 lb above the emission limit during one 

or more consecutive periods of excess emissions3 or any 24-hour 

period, whichever is shorter. This clarifying amendment is 

needed to ensure that the magnitude of the emissions limit 

exceedance is properly compared to what would have been emitted 

if the emissions were equivalent to the emissions limit based on 

the averaging time allowed for that emissions limit.

 

3 As noted above, the proposed amendments used the term “period 

of the exceedance” for fuel gas combustion devices. That term 

was intended to have the same meaning as a period of excess 

emissions (or multiple consecutive periods of excess emissions) 

as defined in 40 CFR 60.106a(b) or 40 CFR 60.107a(i)). 

Therefore, the final amendments refer to “one or more 

consecutive periods of excess emissions” rather than “period of 

the exceedance.”
Page 35 of 269

Finally, we are finalizing the amendments at 40 CFR 

60.108a(c) and (d) mostly as proposed to clarify recordkeeping 

and reporting when a root cause analysis and corrective action 

analysis are required. These clarifications were needed to more 

clearly delineate the differences in the recordkeeping and 

reporting requirements for flares, fuel gas combustion devices, 

and sulfur recovery plants. The differences between the 

proposed amendments and the final amendments are corrections to 

be consistent with changes to the root cause analysis and 

corrective action analysis requirements already described. We 

are also finalizing 40 CFR 60.108a(c) as proposed to add 

recordkeeping requirements for the proposed monitoring option 

that is based on periodic manual sampling and analysis to 

determine the total sulfur-to-H2S ratio.

D. What are the final amendments to the definitions in 40 CFR 

part 60, subpart Ja?

We proposed amendments to a number of definitions in 40 CFR 

60.101a. This section describes whether we are finalizing the 

amendments as proposed, finalizing an amendment different than

(but as a logical outgrowth of) what was proposed, or not 

finalizing the proposed amendment.

We are finalizing amendments to the definitions of 

“flexicoking unit” and “fluid coking unit” as proposed. 
Page 36 of 269

We are finalizing a definition of “delayed coking unit” 

that is different than the proposed amendments to clarify what 

pieces are included in a delayed coking unit. The final June 

2008 rule did not explicitly describe the pieces of a delayed 

coking unit. We proposed to amend the definition in December 

2008 to specify that a delayed coking unit “consists of the coke 

drums and associated fractionator.” In the course of evaluating 

public comments on the proposed definition, we looked more 

closely at the operation of delayed coking units and determined 

that the fractionators, quench water system, and coke cutting 

equipment are integral to the operation of a delayed coking

unit. Therefore, we are revising the definition of “delayed 

coking unit” in these final amendments to include “the coke 

drums associated with a single fractionator and the associated 

fractionator; the coke drum cutting water and quench system,

including the jet pump and coker quench water tank; process 

piping and associated equipment such as pumps, valves and 

connectors; and the coke drum blowdown recovery compressor 

system.”

We are finalizing definitions of “forced draft process 

heater,” “natural draft process heater,” and “co-fired process 

heater,” which will enable owners and operators to determine the 

appropriate subcategory for each of their process heaters. 

Based on public comments, the final amendments have been revised 
Page 37 of 269

slightly from the proposed definitions to clarify that induced 

draft systems are defined as natural draft process heaters and 

balanced draft systems are defined as forced draft process 

heaters. We are also revising the definition of “co-fired 

process heater” to clarify that this type of process heater does 

not include gas burners that have emergency oil back-up burners.

We are finalizing the definition of “air preheat” as proposed.

We are finalizing the definitions of “flare gas recovery 

system” and “process upset gas” as proposed, and we are adding a 

new definition of “flare gas header system.” We are finalizing 

a revision to the definition of “flare” to refer to the “flare 

gas header system” rather than repeat the components of the 

flare gas header system within the definition of flare. In 

addition, we are clarifying in the definition of “flare” that in 

the case of an interconnected flare gas header system (i.e., two 

or more flare tips share the same flare gas header system or are 

otherwise connected such that they receive flare gas from the 

same source), the “flare” includes each combustion device 

serviced by the interconnected flare gas header system and the 

interconnected flare gas header system. 

We are finalizing definitions of “corrective action,” 

“corrective action analysis,” and “root cause analysis” with 

minor changes from proposal to update section references and to 

expand upon the types of factors that should be taken into 
Page 38 of 269

consideration for root cause and corrective action analyses. We 

are adding definitions of “purge gas” and “sweep gas” to clarify 

the requirements of the flare minimization plan. We are also 

adding new definitions of “emergency flare,” “cascaded flare 

system,” “non-emergency flare,” “primary flare,” and “secondary 

flare” to clarify the types of flares that are and are not 

allowed to use the water seal monitoring alternative for flares. 

We are finalizing the amendments to the definition of 

“petroleum refinery” as proposed. As we noted in the preamble 

to the proposed amendments, facilities that only produce oil 

shale or tar sands-derived crude oil for further processing 

using only solvent extraction and/or distillation to recover 

diluent that is then sent to a petroleum refinery are not 

themselves petroleum refineries. Facilities that produce oil 

shale or tar sands-derived crude oil and then upgrade these 

materials and produce refined products would be petroleum 

refineries. Additionally, facilities that produce oil shale or 

tar sands-derived crude oil using any cracking process would be 

considered petroleum refineries. 

We are not finalizing the proposed amendments to “refinery 

process unit” to avoid possible conflicts and confusion caused 

by having different definitions for “refinery process unit” in 

subparts J and Ja, but we are adding a new definition of 

“ancillary equipment” and using this term to clarify that the 
Page 39 of 269

flare modification provisions and standards apply to the types 

of units listed in the proposed definition of “refinery process 

unit.” Specifically, we are adding the following definition to 

subpart Ja:

Ancillary equipment means equipment used in conjunction 

with or that serve a refinery process unit. Ancillary 

equipment includes, but is not limited to, storage tanks, 

product loading operations, wastewater treatment systems, 

steam- or electricity-producing units (including coke 

gasification units), pressure relief valves, pumps, 

sampling vents, and continuous analyzer vents.

We are amending the definition of “fuel gas” as proposed to 

clarify that process units that gasify petroleum coke at a 

petroleum refinery are producing refinery fuel gases. We also 

proposed to amend the definition to state that gas generated by 

process units that calcine petroleum coke into anode grade coke 

is not fuel gas. Based on public comment, we are amending the

definition to state that gas generated by coke calciners 

producing all premium grade coke (rather than just anode grade 

coke, as proposed) is not fuel gas. Also upon consideration of 

public comments, we are amending the definition of “fuel gas” to 

clarify which vapor streams we intended to exclude. The 

proposed definition indicated that vapors collected and 

combusted to comply with specific standards were not considered 

fuel gas. The final amended definition clarifies that vapors 

that are collected and combusted in a thermal oxidizer or flare 
Page 40 of 269

installed to control emissions from wastewater treatment units, 

marine tank vessel loading operations, and asphalt processing 

units are not considered fuel gas, regardless of whether the 

action is required by another standard.

Finally, we are finalizing several proposed amendments to 

the definition of “sulfur recovery plant” to clarify the intent 

of the definition. We are correcting the spelling of “H2S.” We 

are also clarifying that multiple units recovering sulfur from a 

common source of sour gas produced at a refinery are considered 

one sulfur recovery plant. In addition, we are clarifying that 

loading facilities downstream of the sulfur pits are not part of 

the sulfur recovery plant (the proposed definition only

specified secondary sulfur storage vessels).

E. What are the final technical corrections to 40 CFR part 60, 

subpart Ja?

See Table 1 of this preamble for miscellaneous technical 

corrections that we are finalizing throughout 40 CFR part 60, 

subpart Ja. As mentioned previously, some of these technical 

corrections are in response to straightforward issues raised by 

Industry Petitioners in their August 21 supplement to their 

original petition for reconsideration (Docket Item No. EPA-HQOAR-2007-0011-0246). Other technical corrections are needed to 

correct typographical errors and to correct equation and 

paragraph designations.
Page 41 of 269

Table 1. Technical Corrections to 40 CFR part 60, Subpart Ja

Section Technical correction and reason

60.102a(f)(1)(ii) Replace “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” with “300 ppmv of 

reduced sulfur compounds and 10 ppmv of 

H2S, each calculated as ppmv SO2 (dry basis) 

at 0 percent excess air” for consistency of 

units and to correct a typographical error.

60.104a(d)(4)(ii) Redesignate Equation 3 as Equation 5 to 

provide for the addition of new Equations 3 

and 4.

60.104a(d)(4)(iii) Redesignate Equation 4 as Equation 6 to 

provide for the addition of new Equations 3 

and 4.

60.104a(d)(4)(v) Redesignate Equation 5 as Equation 7 to 

provide for the addition of new Equations 3 

and 4.

60.104a(d)(8) Redesignate Equation 6 as Equation 8 to 

provide for the addition of new Equations 3 

and 4.

60.104a(f)(3) Redesignate Equation 7 as Equation 9 to 

provide for the addition of new Equations 3 

and 4.

Replace “hourly” with “3-hour” in the 

definition of the new Equation 9 variable 

“Opacity limit” and replace “source test 

runs” with “source test” in the definition 

of the new Equation 9 variable “Opacityst” 

to clarify the information required for new 

Equation 9.

60.104a(h)(5)(iv) Redesignate the reference to Equation 6 as 

a reference to Equation 8 to provide for 

the addition of new Equations 3 and 4.
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60.105a(b) Replace “in §60.102a(b)(1) shall comply 

with the requirements in paragraphs (b)(1) 

through (3) of this section” with “in 

§60.102a(b)(1) that uses a control device 

other than fabric filter or cyclone shall 

comply with the requirements in paragraphs 

(b)(1) and (2) of this section” to clarify 

applicability of the requirements and 

remove the reference to a nonexistent 

paragraph.

60.105a(b)(1) Replace “according to the requirements in 

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

section” with “according to the applicable 

requirements in paragraphs (b)(1)(i) 

through (v) of this section” to clarify and 

correct paragraph reference.

60.105a(b)(1)(ii)(A) Replace “alterative” with “alternative” to 

correct the use of an incorrect word.

60.105a(i)(5) Replace “Except as provided in paragraph 

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

periods” with “All rolling 7-day periods” 

to remove the reference to a nonexistent 

paragraph.

60.107a(a)(2)(i) Replace “320 ppmv H2S” with “300 ppmv H2S” 

to make the span value for a H2S monitor 

consistent with the span value in subpart 

J.

60.108a(d)(5) Replace “the information described in 

paragraph (e)(6) of this section” with “the 

information described in paragraph (c)(6) 

of this section” to correct the reference 

to a nonexistent paragraph.

IV. Summary of Significant Comments and Responses

As previously noted, we received a total of 22 comments 

addressing the proposed amendments. These comments were 

received from refineries, industry trade associations, 

consultants, state and local environmental and public health 

agencies, environmental groups, and members of the public. 
Page 43 of 269

Brief summaries of the major comments and our complete responses 

to those comments are included in the following sections. A 

summary of the remainder of the comments received during the 

comment period, and responses thereto, as well as more detailed 

summaries of the comments addressed in this preamble, can be 

found in “Standards of Performance for Petroleum Refineries: 

Background Information for Final Amendments - Summary of Public 

Comments and Responses,” which is included in the docket for the 

final amendments (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 

cost and emission reduction impact estimates of some of the 

control options and re-evaluated the related BSER

determinations. In our BSER determinations, we took all 

relevant factors into account consistent with other Agency 

decisions.

A. Process Heaters

Comment: Commenters stated that new forced draft process 

heaters cannot meet the proposed emissions limit of 40 ppmv NOX, 

so EPA should revise the emissions limits for new forced draft 

process heaters to be the same as the limit for modified and 

reconstructed forced draft process heaters (60 ppmv NOX). One 

commenter referenced a John Zink white paper regarding a new 
Page 44 of 269

forced draft process heater at their refinery to support the 

assertion that new process heaters cannot meet the proposed 

limit without selective catalytic reduction or other add-on 

controls. Another commenter also requested higher emissions 

limits for new forced draft process heaters with air preheat.

Response: The commenters provided only limited and 

theoretical data to support their argument that new forced draft 

process heaters cannot meet the 40 ppmv (or 0.040 lb/MMBtu) NOX

emissions limit. Specifically, the John Zink white paper cited 

by the commenter (Docket Item No. EPA-HQ-2007-0011-0296.2) 

stated only that the 40 ppmv emissions limit could not be 

“guaranteed” for a new forced draft process heater based on the 

design conditions, which included air preheat. Actual NOX

performance data for that commenter’s new forced draft process 

heaters are not available as those particular process heaters 

are not yet operational. As such, the actual performance of 

these forced draft process heaters is still in question. 

However, we acknowledge that we only have data for one new

forced draft process heater without air preheat that is 

currently operating that could meet a 40 ppmv NOX emissions limit 

on a 365-day average. We conducted additional data evaluations 

to determine appropriate limits and averaging times for all 

process heaters at normal operating conditions while considering 

this and other public comments we received. As part of the data 
Page 45 of 269

analysis effort, we obtained a year’s worth of hourly CEMS data 

for the new forced draft process heater without air preheat 

capable of meeting 40 ppmv on a 365-day average. As discussed 

later in this section, our analysis of the additional data that 

we obtained following the proposal supported revising all NOX

emissions limits to be on a 30-day average basis. The data 

indicate that the 30-day averages for the new forced draft 

process heater without air preheat capable of meeting 40 ppmv on 

a 365-day average exceeded 40 ppmv 15 percent of the time, but 

none of the 30-day averages exceeded 60 ppmv NOX.

Consequently, we are raising the NOX emissions limit (while 

concurrently reducing the averaging time) for all new forced 

draft process heaters to be equivalent to the emissions limit 

for modified and reconstructed forced draft process heaters 

(i.e., 60 ppmv or 0.060 lb/MMBtu with a 30-day averaging 

period). Furthermore, based on the information provided by the 

commenters, as well as the available performance data for 

existing forced draft process heaters with air preheat that have 

been retrofitted with ultra-low NOX burners, we also conclude 

that the 60 ppmv (or 0.060 lb/MMBtu) on a 30-day rolling average 

basis adequately accommodates forced draft process heaters that 

use air preheat. Based on our review of CEMS data for new and 

retrofitted forced draft process heaters, we conclude that 60 

ppmv (or 0.060 lb/MMBtu) on a 30-day rolling average basis is 
Page 46 of 269

BSER for ultra-low NOX burners in new, reconstructed, or modified 

forced draft process heaters. (For additional details, see 

“Revised NOX Impact Estimates for Process Heaters” in Docket ID 

No. EPA-HQ-OAR-2007-0011.)

Comment: Commenters asserted that the heating value-based 

emissions limits (i.e., the limits in units of lb/MMBtu) should 

be numerically equivalent to the concentration-based emissions 

limits (e.g., 40 ppmv should be equivalent to 0.040 lb/MMBtu 

rather than 0.035 lb/MMBtu).

Response: In August 2008, Industry Petitioners provided 

EPA with suggestions for revising the process heater standards 

(Docket Item No. EPA-HQ-OAR-2007-0011-0257). One of their 

recommendations was to include emissions limits based on heating 

value (lb/MMBtu) to account for hydrogen content variations in 

the fuel gas. They suggested that on an annual basis, most 

natural draft process heaters could meet 0.035 lb/MMBtu and all 

other process heaters could meet 0.055 lb/MMBtu. We evaluated 

these suggested emissions limits and determined that they were 

reasonably equivalent to the concentration-based limits we were 

proposing. We also requested comment on their use and their 

equivalency as described in the preamble to the proposed 

amendments (see 73 FR 78527).

Industry commenters now assert that the emissions limit 

numerically equivalent to the 40 ppmv concentration limit is 
Page 47 of 269

0.040 lb/MMBtu and the emissions limit numerically equivalent to 

the 60 ppmv concentration limit is 0.060 lb/MMBtu. We note that 

as discussed in the preamble to the proposed amendments, the 

exact conversion from ppmv to lb/MMBtu depends on the hydrogen 

content of the fuel gas. However, our calculations generally 

support the more direct numerical conversion suggested by 

commenters over the typical range of hydrogen concentrations 

expected in the fuel gas (see “Revised NOX Impact Estimates for 

Process Heaters” in Docket ID No. EPA-HQ-OAR-2007-0011). 

Therefore, we are finalizing heating value-based emissions 

limits of 0.040 lb/MMBtu and 0.060 lb/MMBtu for natural draft 

process heaters and forced draft process heaters, respectively,

based on direct numerical conversions from the concentrationbased emissions limits.

We are also clarifying that the owner or operator must 

demonstrate that the process heater is in compliance with either 

the applicable concentration-based or heating value-based NOX

limit. Specifically, if the F factor is determined at least 

daily, the owner or operator may elect to calculate both a 30-

day rolling average NOX concentration (ppmv, dry basis, corrected 

to 0 percent excess air) and a 30-day rolling average NOX

emission factor (in lb/MMBtu) and demonstrate that the process 

heater is in compliance with either one of these limits. For 

most fuel gas systems, the alternative emissions limits are 
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expected to be identical; however, there may be instances where 

a process heater may be complying with one of the emissions 

limits and not the other. For example, a process heater 

combusting fuel gas with very high hydrogen content may have an 

average NOX concentration above the 60 ppmv limit but below the 

0.060 lb/MMBtu limit, largely due to the concentration limit 

being determined on a dry basis (and understanding that the 

combustion of hydrogen produces only water and not carbon 

dioxide). Provided that the appropriate monitoring is 

conducted, an affected source would only be out of compliance if 

it exceeds both the concentration-based limit and the heating 

value-based limit at the same time. However, to have the option 

to determine compliance with the alternative heating value-based 

emissions limit, the refinery owner or operator must, at least 

daily, determine the F factor (dry basis) for the fuel gas 

according to the monitoring provisions in 40 CFR 60.107a(d). If 

the F factor is not determined at least daily, the heating 

value-based alternative cannot be used.

Comment: Several commenters addressed the need for the 

rule to address turndown, which is a period of time when process 

heaters are firing below capacity. Commenters stated that 

during these periods, the NOX concentrations will likely be above 

the emissions limits, but the mass of NOX emissions is no greater 

than when the heater is operating at full capacity because the 
Page 49 of 269

lower firing rate results in a lower exhaust flow rate. 

Commenters noted that turndown conditions could exist for 

extended periods, so special provisions are needed for these 

conditions. Commenters requested a mass-based emission rate 

(lb/MMBtu limit multiplied by the heater’s rated capacity) that 

would apply when the process heater is firing at less than full 

capacity (some commenters suggested 50 percent of capacity; one 

commenter suggested 70 percent capacity as a cutoff). One 

commenter also noted that process heaters must often operate at 

higher O2 levels during turndown and requested that the proposed 

maximum O2 operating limit not apply when small furnaces that are 

not required to install CEMS are firing at less than full 

capacity.

Response: In our proposed amendments, we provided a longer 

averaging time (365-day average) so that short periods of turndown would not significantly affect the overall performance of 

the unit. However, according to the commenters, the longer 

averaging time does not adequately address turndown conditions. 

Therefore, we re-evaluated the available data, including our 

existing data and additional data provided by the industry, to 

determine the appropriate emissions limits during different 

types of operation, including turndown. The additional data 

provided by Industry and our evaluation of those data are 

included in the docket for the final amendments (Docket ID No. 
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EPA–OAR–HQ–2007–0011). Based on our analysis of the data 

(described in greater detail in the next paragraph), we 

concluded that a 30-day averaging period is appropriate for the 

NOX emission limits under most operating scenarios.

Upon examination of all available CEMS data, we determined 

that for periods of normal operation (i.e., firing at 50 percent 

or more of design capacity), the proposed NOX emissions limits of 

40 and 60 ppmv were not achievable for all process heaters using 

a 24-hour averaging period (the averaging period included in the 

final June 2008 rule). From the available data, short-term 

fluctuations in the NOX concentrations of process heaters using 

ultra-low NOX burners caused them to exceed a 24-hour average 

limit somewhat frequently, but a 30-day average provided 

adequate time to average out the short-term fluctuations. We 

note that a few of the process heaters operated at relatively 

high excess O2 concentrations at normal conditions (i.e., at 

exhaust O2 concentrations of 6 percent or more). These units had 

periods of excess emissions above the 30-day average emission 

limits, but we rejected the performance of these process heaters 

as BSER because of the high exhaust O2 concentrations for these 

units during normal (i.e., non-turndown) firing rates. That is, 

these process heaters were not being operated optimally for 

reducing NOX emissions. Furthermore, when these process heaters 

were operated at the lower range of exhaust concentrations for 
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the unit (although generally higher than what would be 

considered optimal excess O2 concentrations for reducing NOX

emissions), the process heater could meet the applicable 40 or 

60 ppmv emissions limit on a 30-day averaging period. Based on 

our review of CEMS data for process heaters with ultra-low NOX

burners that operated at excess O2 concentrations less than 6 

percent (i.e., operated in a manner consistent with proper low 

NOX burner operation), all such process heaters could comply with 

the final NOX emissions limits on a 30-day average basis. 

Consequently, we revised the basic emissions limits to be on a 

30-day average.

We note that in setting standards of performance under CAA 

section 111, EPA may set source-specific standards based on its 

reasonable assessments that the specific sources will be able to 

meet the standards using available technology. Portland Cement 

Ass'n. v. EPA, 486 F.2d 375, 391-392 (D.C. Cir. 1973); National 

Lime Ass'n v. EPA, 627 F.2d 416, 428-434 (D.C. Cir. 1980). As 

described previously in this section, we conclude that the 

applicable 40 or 60 ppmv emissions limit on a 30-day averaging 

period is achievable for process heaters during periods of 

normal operation. Our next step was to evaluate the 

achievability of the emissions limits during turndown conditions 

and alternative approaches for establishing emissions 

limitations where necessary. The following paragraphs describe 
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our analysis of the data, including our evaluation of 

alternative methods for accommodating turndown conditions and 

our rationale for providing the site-specific alternative for 

extended turndown conditions.

There were very limited CEMS data available for process 

heaters operating under turndown conditions (i.e., firing below 

50 percent of design capacity). However, two general trends 

were observed in the CEMS data that were available: 1) typical 

exhaust O2 concentrations increase at lower firing rates; and 2)

exhaust NOX concentrations (corrected to 0 percent excess O2) 

increase with increasing O2 concentration (regardless of firing 

rates). These data, along with the need to operate the process 

heater at higher O2 concentrations during low firing rates to 

maintain flame stability, suggest that an alternative NOX

emissions limit could, in some instances, be needed to address 

extended turndown conditions (turndown events lasting a majority 

of the 30-day averaging time). As such, we considered 

alternative compliance options to address turndown conditions.

One alternative compliance option considered to address 

turndown was a mass-based NOX emissions limit that would be 

equivalent to the mass of NOX emitted from a unit meeting the 

0.040 (or 0.060) lb/MMBtu limit while firing at 50 percent of 

capacity, as suggested by commenters. However, for most units 

for which CEMS data are available, the alternative mass-based 
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emissions limit did not improve the ability of the process 

heater to meet the emissions limit. We note that most of the 

process heaters were able to meet the applicable concentrationbased emissions limit (40/60 ppmv) or the heating value-based 

(0.040/0.060 lb/MMBtu) emissions limit during turndown. 

Therefore, the issue appears to be limited to a few of the 

process heaters that must operate at relatively high excess O2

concentrations during turndown conditions. For these units, the 

alternative mass-based emissions limit that we were considering 

rarely, if ever, provided a means for these units to comply with 

the performance standard. 

We understand that technology providers recommend operating 

process heaters that are turned down at higher excess O2

concentrations to improve flame stability and ensure safe 

operation of the process heater; however, based on the 

information provided by the technology providers, there is still 

an optimal excess O2 concentration at which flame stability is 

achieved while minimizing NOX formation. That is, even when a 

process heater is operating at less than 50 percent design 

capacity, excess O2 concentrations should still be controlled to 

minimize NOX formation within the safe operating constraints to 

maintain flame stability. We do not have specific data on 

process heaters that are near but below the concentration 

emissions limits when firing above 50 percent capacity, but 
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cannot meet the concentration limit when firing below 50 percent 

capacity, so we have no data that show that process heaters 

operating at less than 50 percent design capacity and 

controlling excess O2 concentrations cannot meet the emissions 

limits. However, we acknowledge that the correlations with 

firing rates and O2 and/or NOX concentrations and the need for 

higher O2 concentrations to maintain flame stability generally 

support the commenter’s argument that a few marginally compliant 

process heaters will have difficulty meeting the basic emissions 

limit when the unit is turned down. As such, we acknowledge 

that there may be periods of turndown in which a process heater 

is operating as recommended but may be unable to meet the 

concentration or heating value-based emissions limits in the 

final rule, especially when the unit is operated at turndown for 

extended periods (e.g., for 20 days or more compared to the 30-

day averaging time). As the need for an alternative limit 

appears to be limited to a few process heaters, and the optimal 

O2 concentration is expected to vary based on fuel gas 

composition, we determined that a site-specific emissions limit 

was the best approach to account for these extended turndown 

conditions. As such, the final rule provides owners and 

operators that have a process heater operating in turndown for 

an extended period of time the option of developing a sitespecific emissions limit that would apply to those operating 
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conditions and requesting approval from the Administrator to use 

that limit.

For process heaters between 40 and 100 MMBtu/hr capacity 

that do not install a NOX CEMS, turndown is also expected to be 

an issue with respect to achieving the O2 operating limit. As 

described above, higher O2 concentrations are generally needed to 

maintain flame stability at low firing rates. To address 

potential turndown compliance issues with the O2 operating limit, 

we have provided an allowance for process heater owners or 

operators to develop an O2 operating curve to provide different 

O2 operating limits based on the firing rate of the process 

heater. If a single O2 operating limit is established, it must 

be determined when the process heater is being fired at 70 

percent or more of capacity (i.e., far from turndown 

conditions). For process heaters that routinely operate at less 

than 50 percent of design capacity and require additional O2 to 

maintain flame stability, a separate O2 operating limit should be 

established for turndown by conducting a second performance test 

while the unit is operating at less than 50 percent of capacity. 

Additional performance tests can be conducted to develop O2

operating limits for additional operating ranges.

Comment: Several commenters requested that EPA revise the 

emissions limits for co-fired process heaters or remove the 

limits for co-fired process heaters from this rulemaking and 
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address them at a later date due to lack of sufficient data to 

set an achievable emissions limit. One commenter provided a 

white paper to support higher emissions limits. Commenters also 

asserted that the averaging time for the weighted average 

emission rate should be extended to 365 days. One commenter 

noted that the notation “ENOx,hour” in Equation 3 was confusing 

since the purpose of the equation was to determine the daily 

emission rate. 

Response: The final June 2008 rule included only one 

emissions limit for all co-fired process heaters, and Industry 

Petitioners asserted that differences in the configuration and 

operation of different types of process heaters warranted 

different emissions limits. The proposed amendments introduced 

two specific emissions limits for co-fired process heaters, one 

based on vendor guarantees for the burners and one based on an 

average NOX concentration for a combination of fuel gas and fuel 

oil. We note that for purposes of this rule, a co-fired process 

heater is defined as a process heater that employs burners that 

are designed to be supplied by both gaseous and liquid fuels. 

In other words, co-fired process heaters are designed to 

routinely fire both oil and gas in the same burner. These do 

not include burners that are designed to burn gas but have 

supplemental oil firing capability that is not routinely used

(i.e., emergency oil back-up).
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To respond to the comments requesting higher emissions 

limits for co-fired process heaters, we reviewed the white paper 

provided by one commenter (Docket Item No. EPA-HQ-OAR-2007-0011-

0308.1) as well as additional burner emissions test data

provided by another commenter4 (conducted under well-controlled 

conditions using best available ultra-low NOX burner technologies 

at the manufacturer’s testing facility). This information 

indicates that for co-fired natural draft process heaters, a 

daily average emissions limit calculated based on a limit of 

0.06 lb/MMBtu for the gas portion of the firing and 0.35 

lb/MMBtu for the oil portion of the firing is achievable. 

Similarly, the information indicates that for co-fired forced 

draft process heaters, a daily average emissions limit 

calculated based on a limit of 0.11 lb/MMBtu for the gas portion 

of the firing and 0.40 lb/MMBtu for the oil portion of the 

firing is achievable. As noted above, these values are based on 

burner performance tests, which are considered a better source 

of information than the vendor guarantees that were relied upon 

to develop the proposed emissions limit. Therefore, we are 

revising the NOX emissions limits for co-fired process heaters to 

those described above. We note that we have revised the 

concentration-based NOX emissions limits to be on a 30-day 

 

4 The commenter providing this data asserted that it is confidential business information (CBI). We will follow our 

CBI regulations in 40 CFR Part 2 in handling this data. The data has been placed in the docket but is not publicly 

available. 
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average basis (same as the limits for gas-fired process 

heaters). We have also revised the nomenclature of the daily 

average emissions limit in Equations 3 and 4 (proposed Equation 

3) to be clear that we intend the limit to be determined on a 

daily basis rather than on an hourly basis.

We also note that the burner performance tests were 

conducted in a controlled environment at the burner 

manufacturer’s full-scale facilities. While it is incumbent on 

the owner or operator of an affected process heater to control 

certain operating parameters, such as excess O2 concentrations, 

to the extent possible, we recognize that the performance limits 

in the final amendments are based on limited data, none of which

are direct test data for a co-fired process heater operated at a 

petroleum refinery. We conclude that the low-NOX burner 

technologies exist, are demonstrated, and are cost-effective for 

co-fired process heaters, and they are therefore BSER for cofired process heaters. However, as the performance limits are 

based on limited operational data, we also conclude that it is 

reasonable to provide an alternative, site-specific limit in the 

event that factors outside the influence of the burner design 

and operation (such as nitrogen content in the fuel oil) 

suggests the emission limits in the final rule are inappropriate 

for a specific application. Consequently, co-fired process 

heaters that cannot meet the limits specified above can request 
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approval for a site-specific emissions limit as allowed above 

for process heaters that operate for extended periods under 

turndown. 

B. Flares

Comment: Several commenters asserted that routine 

connections to a flare should not be considered modifications of 

the flare because they do not change the maximum physical 

capacity of the flare and do not generally increase emissions. 

One commenter asserted that the provisions in 40 CFR 60.14 can 

and should apply to flares, so a special modification provision 

for flares in subpart Ja is unnecessary. Commenters noted that 

some connections to the flare have the primary purpose of 

reducing emissions, which has been excluded under 40 CFR 

60.14(e)(5), a paragraph that is not limited to pollutants “to 

which the standard is applicable.” One commenter noted that a 

single project may remove some connections and add others such

that the net emissions could actually be reduced. Another 

commenter asserted that an increase in flow should not be 

considered a modification because flow is not a regulated 

pollutant.

Instead, commenters asserted that the modification 

provision for a flare should focus on physical and operational 

changes that increase emissions from the flare. One commenter 

suggested that EPA should focus the flare modification provision 
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on connections that provide a primary/routine flow from a 

process unit to the flare. Other commenters suggested that the 

flare modification provision should be focused on volatile 

organic compounds (VOC) and SO2 emissions and should only include 

connections that result in a net increase of those pollutants 

emitted “during normal operations” and connections that cause an 

increase in the total volume of gas containing VOC or sulfur 

compounds under standard conditions that could reach the flare.

Response: The Agency made a conscious decision to 

promulgate a separate provision for a flare modification in 

subpart Ja (see 40 CFR 60.14(f)) because flares are operated 

differently from other refinery process units, making it 

difficult to apply the modification provision in the General 

Provisions (40 CFR 60.14) to them. The physical capacity of a 

flare is based on the amount of gas potentially discharged to a 

flare as a result of emergency relief. Refiners frequently make 

connections to existing flares that result in emissions 

increases at the flares, but may never approach the physical 

capacity of the flare system. Contrary to commenters’ 

assertions, the flare modification provision in 40 CFR 

60.100a(c) does meet the statutory definition of “modification” 

in CAA section 111(a)(4) which is “any physical change in, or 

change in the method of operation of, a stationary source which 

increases the amount of any air pollutant emitted by such source 
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or which results in the emission of any air pollutant not 

previously emitted.” It is axiomatic that the connections to 

the flare described in 40 CFR 60.100a(c) qualify as physical or 

operational changes to the flare. Additionally, we explained in 

the proposed rule how these connections also resulted in 

emissions increases from the flare (see 73 FR 78529). Thus, 

these types of new connections of refinery process units

(including ancillary equipment) and fuel gas systems to the 

flare qualify as a “modification” of the flare and trigger 40 

CFR part 60, subpart Ja applicability for the flare.

Those connections we identified that do not increase 

emissions from the flare were specifically excluded from 

triggering subpart Ja applicability under this same provision 

(see 40 CFR 60.100a(c)(1)). Specifically, we proposed on 

December 22, 2008, that the following types of connections to a 

flare would not be considered a modification of the flare: (1) 

connections made to install monitoring systems to the flares; 

(2) connections made to install a flare gas recovery system; (3) 

connections made to replace or upgrade existing pressure relief 

or safety valves, provided the new pressure relief or safety 

valve has a set point opening pressure no lower and an internal

diameter no greater than the existing equipment being replaced 

or upgraded; and (4) replacing piping or moving an existing 

connection from a refinery process unit to a new location in the
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same flare, provided the new pipe diameter is less than or equal 

to the diameter of the pipe/connection being replaced/moved. 

While we agree that there may be other connections to a flare 

that would not result in an emissions increase from the flare 

(see response to the next comment for specific details), we 

disagree with the commenters that the flare modification 

provision should be further limited beyond what is already 

provided in the provision.

We disagree with commenters that we must consider the “net” 

emissions from the process unit and the flare when determining 

whether a flare is modified. The affected facility is the flare 

and does not include the process units that are tied into the 

flare header system. As such, using the flare as a VOC 

emissions control device may yield a net emissions decrease of 

VOC at the refinery, but it will result in an increase in VOC 

emissions at the flare, which is the affected source. We also 

disagree that a modification determination should be limited to 

emissions increases of VOC or SO2. Flares are known to emit VOC, 

SO2, carbon monoxide (CO), PM, and NOX, as well as other air 

pollutants, all of which are relevant when determining whether a 

flare has been modified. See CAA section 111(a)(4). That is, 

we consider the standards for flares to be emission standards 

for VOC, SO2, CO, PM, and NOX. Using the flare to control VOC 

emissions at other refinery process units will increase CO, PM, 
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and NOX emissions from the flare and are therefore considered 

modifications of the flare, even if there is a net reduction in 

VOC emissions at the refinery.

In evaluating whether a flare has been modified, we

consider increases in flow to the flare to be directly 

indicative of increased emissions from the flare. While we 

agree that “flow” is not a pollutant, we evaluated flow limits 

as a means to reduce SO2, VOC, CO, NOX, and other emissions from 

the flare. The emissions from the flare are very difficult, if 

not impossible, to measure accurately, but flow to the flare can 

be measured, and the flow to the flare generates SO2, VOC, CO,

PM, NOX, and other emissions. Therefore, a physical or 

operational change to a flare that causes an increase of flow to 

the flare will increase emissions of at least one of these 

pollutants and is considered a modification of the flare.

Comment: Many commenters responded to EPA’s request for 

comment on types of connections that do not result in an 

increase in emissions from a flare. The commenters suggested 

numerous specific connections that should not be considered 

modifications, including: 

(1) connections made to upgrade or enhance (not just to 

install) a flare gas recovery system;

(2) connections made for flare gas sulfur removal; 

(3) connections made to install back-up equipment;
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(4) flare interconnects;

(5) all emergency pressure relief valve connections from 

existing equipment;

(6) connections of monitoring system purge gases and 

analyzer exhausts or closed vent sampling systems; 

(7) purge and clearing vapors, block and bleeder vents, and 

other uncombusted vapors where the flare is the control device; 

(8) connections made to comply with other federal, State, 

or local rules where the flare is the control device; 

(9) connections of “unregulated gases” such as hydrogen, 

nitrogen, ammonia, other non-hydrocarbon gases, or natural gas 

or any connection that is not fuel gas; 

(10) new connections upstream of an existing flare gas 

recovery system, provided the new connections do not compromise 

or exceed the flare gas recovery system’s capacity; 

(11) any new, moved, or replaced piping or pressure relief 

valve connections that do not result in a net increase in 

emissions from the flare regardless of piping or pressure relief 

valve size; 

(12) vapors from tanks used to store sweet or treated 

products; 

(13) temporary connections for purging existing equipment 

as these are essentially “existing” connections; and 
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(14) connections of safety instrumentation systems (SIS) 

described under Occupational Safety and Health Administration 

(OSHA) process safety standards at 29 CFR 1910.119, EPA’s risk 

management program at 49 CFR 68, and/or American National 

Standards Institute (ANSI)/ International Society of Automation 

(ISA)-84.00.01-2004. 

Response: We carefully reviewed the commenters’ suggested 

changes to the flare modification provision to determine whether 

there are additional connections that should not be considered 

modifications to the flare. We agree that the first four

connections in the commenters’ list should not be considered 

modifications of a flare. Projects to upgrade or enhance 

components of a flare gas recovery system (e.g., addition of 

compressors or recycle lines) will improve the operation of the 

flare gas recovery system, and connections to these additional 

components will not result in increased emissions. Connections 

made for removal of sulfur from flare gas (Item 2 above) will

generally result in a slight decrease in volumetric flow and a 

large decrease in emissions of SO2. Connections made to install 

back-up or redundant equipment (Item 3 above), such as a back-up 

compressor, will result in fewer released emissions if there is 

a malfunction in the main equipment.

The request to exclude flare interconnections (Item 4 

above) is a complicated issue because interconnecting two 
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separate flares alters what we consider to be the affected 

facility. The definition of “flare” specifically includes the 

flare gas header system as part of the flare. Prior to 

interconnecting the flares, presumably each flare header system 

is independent, and there would be two separate “flares,” each 

of which could potentially be an affected facility subject to 

subpart Ja. However, because the flare includes the flare 

header system, we consider that an interconnected flare system 

is a single affected facility, and we have amended the 

definition of “flare” for clarity. We agree that 

interconnections between flares will not alter the cumulative 

amount of gas being flared (i.e., interconnecting two flares 

does not result in an emissions increase relative to the two 

single flares prior to interconnection). We also see cases 

where the emissions from a single flare tip will likely be 

reduced due to the flare interconnect. For example, when a 

large release event occurs, this gas will now flow to both of 

the interconnected flares rather than a single flare. The 

maximum emission rate for the original single flare actually 

decreases, while the combined emissions from both flares is the 

same quantity as prior to the interconnection. Considering 

this, we agree that the interconnection of two flares does not 

necessarily result in a modification of the flare, and we have 
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specifically excluded flare interconnections from the 

modification provisions. 

However, we also clarify in this response that when a flare 

that is subject to subpart Ja is interconnected with a flare 

that is not subject to subpart Ja, then the resulting 

interconnected flare is subject to subpart Ja. That is, the 

only case in which an interconnection between two (or more) 

flares results in a combined, interconnected flare that is not 

subject to subpart Ja is when none of the original individual 

flares were subject to subpart Ja. Additionally, we note that 

if a new connection is made to the interconnected flare, then 

the flare (including each individual flare tip within the 

interconnected flare header system) is modified and becomes an 

affected facility subject to subpart Ja. 

While we agree that connections that do not increase the 

emissions from the flare should not trigger a modification, we 

disagree with the commenter that their other suggested 

connections do not increase the flare’s emissions at the time 

gases are discharged via the new connection. Each of the 

commenters’ suggestions is discussed in the following 

paragraphs. 

We previously proposed an exemption for emergency pressure 

relief valve connections from existing equipment (Item 5 above) 

if they replace or upgrade existing equipment and do not 
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increase the instantaneous release rate to the flare (i.e., the 

new pressure relief valve has a pressure set point and diameter 

no greater than the equipment being replaced). As stated 

previously in this preamble, we are finalizing that amendment as 

proposed. However, new connections, even if they are made to 

“existing equipment,” will result in an increase in flow to the 

flare during periods of process upset that cause the pressure 

relief valve to open.

Connections of monitoring system purge gases and analyzer 

exhausts or closed vent sampling systems (Item 6 above) will 

increase the emissions from the flare. Similarly, connections 

of purge and clearing vapors and block and bleeder vents (Item 7 

above), also trigger a modification of the flare because the 

increase of gas flow to the flare will increase the emissions 

from the flare. 

We recognize that connections to a flare may be made to 

comply with other federal, State, or local rules where the flare 

is an emissions control device (Item 8 above). In fact, nearly 

all flares could be considered “control devices.” We agree that 

using a flare as an emissions control device is preferable to 

venting the process unit to the atmosphere. However, while 

using the flare as an emissions control device does decrease 

emissions from the process unit being controlled, the increase 

of gas flow to the flare will increase the emissions from the 
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flare. Therefore, a connection from a process unit to a flare 

for use as an emissions control device results in a modification 

of that flare.

Comments suggesting that connections of “unregulated gases” 

such as hydrogen, nitrogen, ammonia, other non-hydrocarbon gases 

or natural gas, or connections that are not “fuel gas,” should 

not be considered a modification of the flare (Item 9 above) are 

in conflict with the statutory definition of “modification.” As 

defined above, CAA section 111(a)(4) requires that we consider 

any pollutant emitted by the flare when determining whether the 

flare has been modified. Each of the streams mentioned by the 

commenter, when directed to a flare, will increase emissions of 

at least one regulated pollutant (either PM, CO, or NOX) from the 

flare. That is, we reiterate that we consider the standards for 

flares to be emission standards for VOC, SO2, CO, PM, and NOX. 

As such, we reject the idea that the types of gas streams 

suggested by the commenters should be exempt from the 

modification determination.

New connections upstream of an existing flare gas recovery 

system (Item 10 above) will increase the likelihood of an event 

that would cause an exceedance of the flare gas recovery 

system’s capacity (even if the new connections “do not exceed 

the flare gas recovery system’s capacity” under normal 

conditions), and the amount of gases sent to the flare would 
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increase as a result of such an event, thereby increasing the 

emissions from the flare. 

We reiterate that we proposed an exemption for any moved or 

replaced piping or pressure relief valve connections of the same 

size. However, we disagree with the commenter’s suggestion that

any “new, moved, or replaced piping or pressure relief valve 

connections that do not result in a net increase in emissions 

from the flare regardless of piping or pressure relief valve 

size” should be exempted (Item 11 above). The premise of the 

suggested amendment is that new or larger connections somehow 

will not increase emissions from the flare. We have discussed 

new connections previously, so we will concentrate on the 

“regardless of piping or pressure relief valve size” comment in 

this paragraph. First, the size of the pressure relief valve or

piping does correlate to the discharge rate to the flare, with 

larger pressure relief valves or larger diameter piping allowing 

higher discharge rates to the flare at a given pressure. In 

fact, larger pressure relief valves and larger diameter pipes

are specifically designed to allow higher flow rates to the 

flare. Second, higher flow rates will lead to higher emission 

rates. For a pressure relief event that occurs for several 

hours, the flow rate to the flare during the first hour of 

relief using the larger pressure relief valve or larger diameter 

piping will be larger than the flow rate experienced using the 
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smaller pressure relief valve or smaller diameter piping, and 

will result in higher emissions from the flare. Therefore, we 

reject the notion that larger diameter pipes and larger pressure 

relief valves do not increase the emissions rate from the flare 

during a release event. We are finalizing the proposed 

exemptions for moved or replaced piping or pressure relief 

valves with the size and design restrictions for the new piping 

or pressure relief valves as proposed in December 22, 2008.

Commenters suggested that connections of vapors from tanks 

used to store sweet or treated products (Item 12 above) should 

not be modifications because those gas streams have less than 

162 ppmv H2S. We reiterate that SO2 is not the only pollutant 

emitted from flares and that the additional flow of sweet gases 

will increase the emissions of at least one pollutant from the 

flare, so we are not exempting these types of connections to the 

flare from the subpart Ja flare modification provision. 

However, we have amended the sulfur monitoring requirements for 

flares to exempt vapors from tanks used to store sweet or 

treated products from the flare sulfur monitoring requirements. 

This monitoring exemption is justified because it is not needed 

for the purposes of a root cause analysis or other compliance 

purpose. For these sweet vapors, the flow rate root cause 

analysis threshold will be exceeded well before the SO2 root 

cause analysis threshold.
Page 72 of 269

We carefully considered temporary connections for purging 

existing equipment (Item 13 above), but we failed to see how 

these temporary connections are essentially “existing 

connections.” According to the commenters, “maintenance gases 

have been routed in some form or other to the flare for years, 

and the temporary tie-in to accomplish that is not a change and 

is not an increase in emissions when viewed from a before and 

after perspective.” If the connections already exist, then 

opening an existing valve to allow for this type of purging 

would not trigger a flare modification. If the connection is 

being relocated and the piping used is the same diameter as the 

pre-existing connection, then this scenario is adequately 

covered by the proposed exclusion for relocated connections. 

However, if a new connection is made specifically to purge an 

existing piece of equipment, this purge gas unequivocally 

represents additional gas flow sent to the flare that did not 

exist and could not exist prior to the connection being made. 

Again, we consider that the increase in gas flow to the flare 

will result in an increase in emissions of at least one 

pollutant from the flare. As such, no exemption is provided for 

new connections to existing equipment, regardless if these 

connections are temporary or permanent. We also find that these 

types of flows should be expressly considered in the flare 
Page 73 of 269

management plan and that flaring from these “temporary” 

connections should be minimized to the extent practicable. 

The impact of connections of safety instrumentation systems 

(SIS) described under OSHA process safety standards at 29 CFR 

1910.119, EPA’s risk management program at 49 CFR 68, and 

ANSI/ISA-84.00.01-2004 (Item 14 above) should be evaluated on a 

case-by-case basis to determine whether these connections result 

in a flare modification. We expect that, if these connections 

are made for flare monitoring purposes, these connections are 

already excluded in the exemption for flare monitoring systems. 

If the “safety instrumentation systems” are process unit 

analyzers, and the new connections are being made to connect the 

analyzer exhaust to the flare, these connections would be 

considered a modification as previously discussed. The 

commenter may also be referring to new connections for 

additional pressure relief valves identified in the safety 

reviews required by the cited rules, which we would consider to 

be a modification of the flare. 

Following all of the above review and analysis, we are 

finalizing three of the connections as proposed, adding three of 

the connections requested by commenters, and revising one of the 

proposed connections as requested by commenters in 40 CFR 

60.100a(c)(1). Thus, the following seven types of connections 

are not considered a modification of the flare:
Page 74 of 269

(1) Connections made to install monitoring systems to the 

flare.

(2) Connections made to install a flare gas recovery 

system or connections made to upgrade or enhance components of a 

flare gas recovery system (e.g., addition of compressors or 

recycle lines).

(3) Connections made to replace or upgrade existing 

pressure relief or safety valves, provided the new pressure 

relief or safety valve has a set point opening pressure no lower 

and an internal diameter no greater than the existing equipment 

being replaced or upgraded.

(4) Connections that interconnect two or more flares. 

(5) Connections made for flare gas sulfur removal. 

(6) Connections made to install back-up (redundant) 

equipment associated with the flare (such as a back-up 

compressor) that does not increase the capacity of the flare.

(7) Replacing piping or moving an existing connection from 

a refinery process unit to a new location in the same flare, 

provided the new pipe diameter is less than or equal to the 

diameter of the pipe/connection being replaced/moved.

Comment: Several commenters suggested that de minimis

emission increases and net emission decreases resulting from new 

connections to a flare made to control and combust fugitive 

emissions, such as leaks from compressor seals, valves, or 
Page 75 of 269

pumps, should not be considered modifications of a flare. One 

commenter suggested allowing site-specific exemptions for

connections that do not increase emissions or that result in a 

de minimis emissions increase. However, another commenter 

objected to setting a de minimis emissions increase to determine 

whether a change to a flare is a modification and stated that 

allowing a de minimis approach would cause confusion over the 

applicability of subpart Ja because flare emissions are 

difficult to estimate. 

Response: In the preamble to our proposed amendments, EPA 

specifically requested comment on using the de minimis exception 

in the flare modification provision. 73 FR 78522, 78529. 

Industry Petitioners had suggested some type of de minimis

emissions increase should be allowed without triggering subpart 

Ja applicability. Id. EPA acknowledged that these exceptions 

are “permissible but not required” under the modification 

provision in the Clean Air Act (CAA). Id. EPA also stated: 

“We request comments on a de minimis approach and on specific 

changes that may occur to flares that will result in de minimis

increases in emissions. We also request comments on the type, 

number, and amount of emissions that would be considered de

minimis.” Id.

Industry Petitioners did not provide the comments or data 

requested in the proposal preamble. Yet, without supporting 
Page 76 of 269

data, Industry Petitioners continue to insist that any emissions 

increases resulting from “routine connections” to the flare 

system “will be de minimis” and should not trigger subpart Ja 

applicability at the flare. EPA-HQ-OAR-2007-0011-0311.1, pg 20. 

Industry Petitioners again suggest that EPA exercise its 

authority and “authorize exceptions from otherwise clear 

statutory mandates” by promulgating de minimis exemptions for 

the flare modification provision. Id.; Alabama Power Co. v. 

Costle, 636 F.2d 323, 360 (D.C. Cir. 1979). As explained in 

Alabama Power, the de minimis exception allows Agency 

flexibility in interpreting a statute to prevent “pointless 

expenditures of effort.” Id. However, as Industry Petitioners 

recognize, nothing mandates that EPA use its de minimis

authority in any given instance, and courts especially recognize 

the significant deference due an Agency’s use of a de minimis

exception. Id. at 400; Shays v. Federal Election Com’n, 414 

F.3d 76, 113 (D.C. Cir. 2005); Environmental Defense Fund, Inc. 

v. EPA, 82 F.3d 451, 466 (D.C. Cir. 1996); Ass’n of Admin. Law 

Judges v. Fed. Labor Relations Auth., 397 F.3d 957, 961 (D.C. 

Cir. 2005).

In exercising that discretion, EPA must consider the 

cautionary advice it received from the Alabama Court regarding 

its use of the de minimis exception: “EPA must take into 

account in any action. . .that this exemption authority is 
Page 77 of 269

narrow in reach and tightly bounded by the need to show that the 

situation is genuinely de minimis.” Id. at 361. The Court also 

noted that exemptions from “the clear commands of a regulatory 

statute, though sometimes permitted, are not favored.” Id. at 

358. EPA must exercise this authority cautiously, and only in 

those circumstances that truly warrant its application.

EPA has no reason for promulgating a de minimis exception 

to the flare modification provision. Despite its assertions, 

Industry Petitioners have still provided no data that 

establishes that the emissions increases resulting from the 

alleged “routine connections” to a flare system are truly 

“trivial or [of] no value.” EPA-HQ-OAR-2007-0011-0311.1, pg 20. 

Without the requested information showing that “the situation is 

genuinely de minimis,” Alabama Power, 636 F.2d at 361, and 

therefore warrants this kind of exception, we believe such an 

exemption would be inappropriate.

Additionally, Industry Petitioners’ example that “venting a 

new small storage tank to a flare system. . .easily would cost a 

typical refinery tens of millions of dollars” since “the entire

flare system” (emphasis in original) would be subject to subpart 

Ja is unavailing for its argument that EPA should promulgate a 

de minimis exception for the flare modification provision. EPAHQ-OAR-2007-0011-0311.1, pg 21. As the D.C. Circuit

specifically states in Shays, authority for promulgating a de
Page 78 of 269

minimis exception “does not extend to a situation where the 

regulatory function does provide benefits, in the sense of 

furthering regulatory objectives, but the agency concludes the 

acknowledged benefits are exceeded by the costs.” Shays, 414 

F.3d 76, 114 (emphasis added). By focusing solely on cost, 

Industry Petitioners are effectively asking the Agency to engage 

in the type of cost-benefit analysis prohibited by the Shays

Court. Such cost analyses are improper in these types of 

decisions. Industry Petitioners generally focus their 

discussion on VOC emissions and effectively admit that 

connecting the small storage tank to the flare system increases 

emissions from the flare (e.g., “uncontrolled tank emissions 

would be essentially eliminated by combustion in a flare” (EPAHQ-OAR-2007-0011-0311.1, pg 21, emphasis added)). Furthermore, 

they disregard additional emissions of NOX and CO resulting from 

the combustion of these gases at the flare. Industry 

Petitioners also provide no data quantifying these emissions 

increases, and therefore cannot demonstrate that they are 

“trivial or [of] no value,” or in other words, that the 

emissions increases are in fact de minimis. As releases to the 

flare are often event driven, one can envision situations where 

the release from even a small storage tank can be significant. 

On the other hand, EPA sees a substantial environmental benefit 

in requiring controls that will reduce the cumulative emissions 
Page 79 of 269

from a flare that becomes subject to subpart Ja because of any

of these alleged “routine connections.” Thus, given the nature 

of releases to the flare, we determined that a de minimis

exemption from the modification provisions for flares is 

unworkable and unwarranted.

Comment: One commenter stated that exempting flares5 from 

the H2S concentration limits during SSM events is illegal because 

the CAA requires continuous compliance with standards of 

performance promulgated under CAA section 111. See CAA sections 

111(a)(1), 302(k). For support, the commenter cited Sierra Club 

v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), in which the Court 

stated: “When sections 112 and 302(k) are read together, then, 

Congress has required that there must be continuous section 112-

compliant standards.” The commenter noted that the court found 

that the exemption from compliance with CAA section 112 

standards during SSM events violates the CAA because the general 

duty to minimize emissions during SSM events is not a section 

112-compliant standard. The commenter asserted that the CAA 

 

5 The comments submitted referenced “fuel gas combustion devices” 

as the affected source when describing the exemption during SSM 

events. However, the exemption only applies to flares. See 40 

CFR 60.102a(g). The discussion in this preamble is therefore 

focused on flares as distinguished from other types of fuel gas 

combustion devices that are required to comply at all times with 

the H2S concentration limits in 40 CFR 60.102a(h)(1).
Page 80 of 269

also requires that a section 111-compliant standard that 

reflects BSER6 be in effect at all times for flares.

The commenter further asserted that work practice standards 

for flares are not section 111-compliant standards because this 

is not one of those “limited instances” in which CAA section 

111(h) authorizes such standards. The commenter stated that EPA 

must show that a standard of performance for flares is “not 

feasible to prescribe or enforce” because “(A) a pollutant. . 

.cannot be emitted through a conveyance designed and constructed 

to emit or capture such pollutant, or that any requirement for, 

or use of, such a conveyance would be inconsistent with any 

Federal, State, or local law, or (B) the application of 

measurement methodology to a particular class of sources is not 

practicable due to technological or economic limitations.” See 

CAA section 111(h)(2). The commenter stated that neither of 

these exemptions appear to apply, and EPA cannot claim that it 

is infeasible to promulgate a standard of performance for 

flares,

7 so EPA cannot set a work practice standard for flares. 

 

6 The commenter asserted, without providing support, that it is 

not BDT to exempt flares from the H2S concentration limits during 

startup and shutdown events. The commenter also stated that 

EPA, at a minimum, must demonstrate how the exemption from the 

H2S concentration limits during SSM events does in fact represent 

BDT, but the commenter stated that EPA has failed to make this 

demonstration.

7 The commenter cited EPA’s rationale for proposing work practice 

standards for flaring in which we state: "It is not feasible to 

prescribe or enforce a standard of performance for these sources 
Page 81 of 269

Thus, the commenter asserted that a section 111-compliant 

standard does not continuously apply to flares since both the 

exemption from the H2S concentration limits during SSM events and 

the flare work practice standards are not lawful under the CAA.

Another commenter disagreed and provided several reasons 

why they believe EPA may lawfully exempt flares from the H2S 

concentration limits during SSM events. First, the commenter 

noted that subpart Ja was promulgated as part of the mandatory 

periodic review of subpart J required by CAA section 

111(b)(1)(B). The commenter noted that subpart J exempts a 

flare from the H2S concentration limits when combusting certain 

gases generated during SSM events (see 40 CFR 60.104(a)(1), 

60.101(e)) and stated that the record contains “ample evidence” 

to support maintaining that provision in subpart Ja. The 

commenter asserted that including these same provisions in 

subpart Ja is “an appropriate exercise of EPA’s authority to 

‘not review’ this aspect of the existing standard in light of 

 

because either the pollution prevention measures eliminate the

emission source, so that there are no emissions to capture and 

convey, or the emissions are so transient, and in some cases, 

occur so randomly, that the application of a measurement 

methodology to these sources is not technically and economically 

practical." 72 FR 27178, 27194-27195 (May 14, 2007). In 

response, the commenter stated: “[T]he plain language of the Act 

recognizes that standards of performance leading to the 

‘capture’ of emissions are not infeasible [citation omitted], 

and EPA has proposed to apply measurement methodologies to 

flares in spite of the transience of their emissions.”
Page 82 of 269

the efficacy of the existing standard.” See CAA section 

111(b)(1)(B).

Second, the commenter noted that the Sierra Club decision 

was largely grounded in the Court’s determination that Congress 

amended CAA section 112 out of concern “about the slow pace of 

EPA’s regulation of HAPs,” eliminating much of EPA’s discretion 

and requiring sources to “meet the strictest standards” without 

variance “based on different time periods.” The commenter 

further explained that the Court pointed to CAA section 

112(d)(1) regarding EPA’s authority to “distinguish among 

classes, types, and sizes of sources” when promulgating CAA 

section 112 standards as further evidence for constraining EPA’s 

ability to adopt different standards applicable during SSM 

events. In contrast, the commenter asserted that “Congress has 

expressed no such concern about EPA’s efforts to implement 

section 111” despite revisions to CAA section 111 in 1977 and 

1990. Therefore, the commenter asserted, Congress has 

“effectively ratified EPA’s longstanding approach to SSM under 

the NSPS program,” which includes the exemption for flares from 

the H2S concentration limits during SSM events. 

The commenter also asserted that regardless of the above, 

and despite the similar nature of the provisions in CAA sections 

111 and 112, EPA has the discretion to implement them 

differently “under the markedly differently context of the NSPS 
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program v. the MACT program.” See Environmental Defense v. Duke 

Energy Corp., 549 U.S. 561, 575-576 (2007). For example, the 

commenter asserted that the word “continuous” as used in the 

NSPS program could be interpreted and applied differently as 

acknowledged by the Court in National Lime Ass’n v. EPA, 627 

F.2d 416, 434 (D.C. Cir. 1980) (deferring to Agency regarding 

the effect of “the perplexing implications of Congress’ new 

requirement of systems of continuous emission reduction” on the 

Agency’s longstanding “regulations permitting flexibility to 

account for startups, shutdowns, and malfunctions”). The 

commenter urged EPA to exercise this discretion and “reassert 

the many practical, technical and economic factors” that justify 

promulgating separate standards for SSM events in the NSPS 

program.

Third, the commenter asserted that requiring flares to meet 

the H2S concentration limits during SSM events does not represent 

BSER for this time period. According to the commenter, “startup 

and shutdown gases are intermittent streams that cannot be costeffectively treated for sulfur removal because of their 

infrequent occurrence, their scattered points of generation and 

their variability.” Therefore, for all of the above reasons, 

the commenter asserted that exempting a flare from the H2S 

concentration limits when combusting certain gases generated 

during SSM events is lawful under CAA section 111. 
Page 84 of 269

Alternatively, the commenter stated that if a standard must 

apply during SSM events, the flare work practice standards are 

appropriate in lieu of the H2S concentration limit.

Response: Regardless of whether or how the Sierra Club

decision under CAA section 112 applies to new source performance 

standards promulgated under CAA section 111, we are promulgating 

final amendments for flares that include a suite of standards 

that apply at all times and are aimed at reducing SO2 emissions 

from flares. As described previously, this suite of standards 

requires refineries to: (1) develop and implement a flare 

management plan; (2) conduct root cause analysis and take 

corrective action when waste gas sent to the flare exceeds a 

flow rate of 500,000 scf above the baseline; (3) conduct root 

cause analysis and take correct action when SO2 emissions exceed

500 pounds in a 24-hour period; and (4) optimize management of 

the fuel gas by limiting the short-term concentration of H2S to 

162 ppmv during normal operating conditions. Additionally, 

refineries must install and operate monitors for measuring 

sulfur and flow at the inlet of all of their flares. Together, 

these requirements provide section 111-compliant standards that 

collectively cover all operating conditions of the flare. 

As the commenter notes, CAA section 111(h)(1) allows EPA to 

promulgate a design, equipment, work practice, or operational 

standard, or “combination thereof,” when “it is not feasible to 
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prescribe or enforce a standard of performance” which reflects 

BSER for the particular affected source. Section 111(h)(2) 

defines the phrase “not feasible to prescribe or enforce a 

standard of performance” as follows:

[A]ny situation in which the Administrator determines that 

(A) a pollutant or pollutants cannot be emitted through a 

conveyance designed and constructed to emit or capture such 

pollutant, or that any requirement for, or use of, such a 

conveyance would be inconsistent with any Federal, State, 

or local law, or (B) the application of measurement 

methodology to a particular class of sources is not 

practicable due to technological or economic limitations.

We have determined that flares meet the criteria set forth 

in CAA section 111(h)(2)(A) because emissions from a flare do 

not occur “through a conveyance designed and constructed to emit 

or capture such pollutant.” Gases are conveyed to the flare for 

destruction, and combustion products, such as SO2, are not 

created until combustion occurs, which happens in the flame that 

burns outside of the flare tip. In other words, the SO2, NOX, PM, 

CO, VOC and other pollutants generated from burning the gases 

are only created once the gases pass through the flare and come 

into contact with the flame burning on the outside of the flare. 

The flare itself is not a “conveyance” that is “emitting” or 

“capturing” these pollutants; instead, it is a structure 

designed to combust the gases in the open air. Thus, setting a 

standard of performance for SO2 is not “feasible,” allowing EPA 
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to instead promulgate standards under section 111(h) which will

collectively limit SO2 emissions from the flare.

EPA previously promulgated a standard of performance for SO2

emissions for fuel gas combustion devices which also applied to 

flares. 39 FR 9308, 9315 (March 8, 1974). The standard is 

expressed as an H2S concentration limit because it was developed 

as an alternative to measuring the SO2 concentration in the stack 

gases exiting fuel gas combustion devices other than flares

(i.e. boilers and process heaters). That approach is

appropriate for fuel gas combustion devices other than flares

because measuring the H2S in the fuel gas combusted in those 

devices is directly indicative of the SO2 emitted from the 

exhaust stacks of those other devices. As explained above in 

Section III, we are for the first time designating flares as 

their own affected facility. As such, in finalizing these 

amendments for flares, we considered whether we could also apply

a standard of performance for SO2 emissions, expressed as an H2S 

concentration limit or a total sulfur limit at the inlet to the 

flare. However, as explained above, flares are substantially 

different from other fuel gas combustion devices so that this 

approach is not workable for flares. For example, SO2 emissions 

from a flare are dependent on many factors, including the flow 

rates of all gases sent to the flare, the total sulfur content 

of all gases sent to the flare, and the combustion efficiency at 
Page 87 of 269

the flare. Each of these factors is also dependent on many 

variables. For example, combustion efficiency at the flare is 

dependent upon the flammability of the gases entering the flare, 

the turbulence at the flare8, the wind speed and wind direction, 

and the presence of other pollutants in the gases that can react 

with the sulfur to form sulfur-containing pollutants other than 

SO2. Since so many factors affect the potential formation of SO2

emissions outside the flare tip, we realized that we could not 

properly derive an H2S concentration limit or a total sulfur 

limit at the flare inlet that would directly correlate with 

those SO2 emissions. Thus, we determined that we cannot set a 

standard of performance for SO2 emissions at the flare. 

However, we still recognize that reducing the amount of 

sulfur that is sent to a flare will reduce the SO2 emissions at 

the flare. Even with the uncertainty described above, we 

understand the importance of refineries managing the fuel gas 

sent to their flares in a way that minimizes the sulfur content 

so as to ultimately minimize the SO2 emissions. Rather than 

eliminate the H2S concentration limit altogether, we are instead 

requiring under section 111(h) that refineries limit the shortterm concentration of H2S to 162 ppmv in the fuel gas sent to 

flares during normal operating conditions. Refineries rely on 

 

8 Turbulence is needed to insure good mixing at the flare, but is affected by whether the flare is assisted with air or 

steam or non-assisted.
Page 88 of 269

various methods for optimizing the management of fuel gas, 

including the use of amine treatment and flare gas recovery 

systems. Amine treatment removes the H2S from the flare gas that 

generates the pollutants before the gas is sent to the flare. 

Flare gas recovery systems remove the flare gas altogether and 

instead treat this gas in a fuel gas treatment system to be used

elsewhere as fuel gas in the refinery. Requiring refineries to 

meet this concentration limit at the flare ensures that the fuel 

gas has been adequately treated and managed such that it can be 

used as fuel gas in the fuel gas system elsewhere in the 

refinery.We are not requiring refineries to meet this limit 

during other periods of operation because flare gas recovery 

systems that capture gases prior to amine treatment can be 

quickly overwhelmed and fail to properly function during high 

fuel gas flows. Thus, requiring that flares meet this H2S 

concentration limit during periods when high fuel gas flows

would likely overwhelm these flare gas recovery systems would 

not fully address the circumstances refineries face in managing 

these high flow periods. Designing flare gas recovery systems 

to capture the full range of gas flows to the flare would not 

only require the ability to predict the full range of gas flows 

in the flare headers, but also would require refiners to install 

recovery compressors in a staged fashion such that all events 

causing high gas flows could be captured and managed, neither of 
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which are practical. Therefore, promulgating flare requirements

that include the H2S fuel gas concentration limit during normal

operating conditions, coupled with requirements for refineries 

to develop and implement a flare management plan and conduct 

root cause analyses and take corrective action when waste gas 

sent to the flare exceeds a flow rate of 500,000 scf above the 

baseline or 500 pounds of SO2 in a 24-hour period, recognizes 

these unique circumstances while still requiring the refinery to 

take all reasonable measures for reducing or eliminating the 

flow and sulfur content of gases being sent to the flares.

We are aware that numeric SO2 emission limits for flares

have been established under state law and in Federal 

Implementation Plan (FIP) regulatory requirements. Those 

source-specific circumstances differ markedly from this 

nationally applicable rulemaking, necessitating different 

decisions in two very different circumstances. For example, 

EPA's SO2 FIP for the Billings/Laurel Montana area includes a SO2

emission limit of 150 pounds of SO2 per 3 hours for four sources 

that apply to the flares at all times. See 40 CFR 

52.1392(d)(2)(i), (e)(2)(i), (f)(2)(i), and (g)(2)(i). These 

source-specific limits were appropriately based on dispersion 

modeling in the Billings/Laurel area to determine what was
Page 90 of 269

needed to meet national ambient air quality standards (NAAQS) 

for SO2 in the Billings/Laurel area. In contrast, the nationally

applicable standards and requirements we are promulgating in 

this rule must represent the best system of emission reduction 

achievable for an entire industry sector scattered across the 

entire country. This requires that we consider costs and other 

non-air quality factors that affect all petroleum refineries 

nationwide in making that decision and not just as applied to a 

particular group of sources in a particular location. 

Additionally, those four sources subject to the 

Billings/Laurel FIP demonstrate compliance with the 150 pounds 

SO2/3 hours emission limit by measuring the total sulfur 

concentration and volumetric flow rate of the gas stream at the 

inlet to the flare. See 40 CFR 52.1392(d)(2)(ii), (e)(2)(ii), 

(f)(2)(ii), (g)(2)(ii), and (h). Since the FIP must include 

emissions limits that insure attainment and maintenance of the 

NAAQS in the Billings/Laurel area, it was appropriate, in 

setting the standards for the Billings/Laurel FIP, to 

conservatively assume that 100 percent of the sulfur in the 

gases discharged to the flare is converted to SO2, and based on 

this conversion set the numeric limit as a value that is not to 

be exceeded. However, that same assumption is not appropriate 

when setting national standards for flares. Instead, we must 

consider the many factors affecting the formation of SO2 at the 
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flare tip, and how these factors affect how much of the sulfur 

in the gases sent into the flare actually converts to SO2. EPA 

does not presently have the data to better correlate the

relationship between the sulfur and the SO2. Without that 

information, EPA cannot set a SO2 emission limit, expressed as a 

sulfur concentration limit, which is applicable to all flares 

nationwide. Therefore, although setting such source-specific 

limits was appropriate to satisfy what the modeling showed was 

necessary to meet the SO2 NAAQS in the Billings/Laurel area, a 

different analysis and standard is appropriate for a national 

rulemaking.

Therefore, for the reasons discussed above, EPA is 

finalizing this collective set of section 111(h)-compliant 

standards for flares based on our interpretation of CAA section 

111(h) as it applies to flares. We also note that we will 

address other issues relating to flare combustion efficiency in 

the near future, under a comprehensive strategy to address air 

toxics, criteria pollutants, and greenhouse gases.

Comment: Numerous commenters asserted that the long-term 

60 ppmv H2S concentration limit is not cost-effective for flares 

and, therefore, not BSER for flares. The commenters noted that 

EPA did not include costs for compressors, additional amine 
Page 92 of 269

units, and sulfur recovery units, and one commenter stated that 

EPA did not consider the range of costs that are incurred by 

individual refineries. Commenters also asserted that EPA 

overstated emission reductions by using 162 ppmv H2S as a 

baseline because many refinery streams currently sent to the 

flare contain H2S concentrations below 162 ppmv, so 162 ppmv H2S 

does not reflect long-term performance. Commenters noted that 

the Btu content of flare gas is highly variable and generally 

lower than that used by EPA, so EPA’s analysis overestimated the 

value of the recovered flare gas. One commenter noted that EPA 

should have considered consent decree requirements in the 

baseline SO2 emissions estimates.

One commenter stated that the long-term 60 ppmv H2S 

concentration limit for fuel gas could preclude some refineries 

from processing high-sulfur crude oils, thereby limiting 

refining production capacity. Another commenter noted that many 

flares will receive both fuel gas and process upset gas, so it 

would be impossible to determine if an exceedance is caused by 

the regulated fuel gas or by the exempt gas. The commenter 

recommended that EPA apply the long-term 60 ppmv H2S 

concentration limit only to fuel gas combusted in process 

heaters, boilers, and similar fuel gas combustion devices and 

not to flares or that EPA allow Alternative Monitoring Plans to 
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demonstrate compliance with the emissions limits for non-exempt 

gas streams upstream of the flare header.

Response: We acknowledge that at proposal, we determined 

that a long-term 60 ppmv H2S concentration limit was costeffective primarily for process heaters, boilers, and other fuel 

gas combustion devices that are fed by the refinery’s fuel gas 

system. Based on the typical configuration at a refinery, 

adding one new fuel gas combustion device to the fuel gas system 

would essentially require the owner or operator to limit the 

long-term concentration of H2S in the entire fuel gas system to 

60 ppmv, so emission reductions would result from all fuel gas 

combustion devices tied to that fuel gas system. Upon review of 

the BSER analysis conducted at proposal for fuel gas combustion 

devices, we now realize that the analysis is not applicable to 

flares (See EPA-HQ-OAR-2007-0011-0289). 

Moreover, since we are regulating flares separately from 

other fuel gas combustion devices in this final rule, we should

separately consider whether a long-term H2S concentration limit 

is appropriate for flares. In developing the suite of section 

111(h) standards for flares, we considered whether refineries

should be required to optimize management of their fuel gas by 

limiting the long-term H2S concentration to 60 ppmv in addition 

to the short-term H2S concentration of 162 ppmv during normal 

operating conditions. We determined that for refineries to 
Page 94 of 269

demonstrate that their fuel gas complies with a long-term H2S 

concentration of 60 ppmv, refineries would have to install a 

flare gas recovery system (which was not needed for other fuel 

gas combustion devices) and then upgrade the fuel gas 

desulfurization system. Alternatively, refineries would have to 

treat the recovered fuel gas to limit the long-term 

concentration of H2S to 60 ppmv with new amine treatment units 

oneach flare. 

While some of the costs provided by the commenters did not 

include the value of the recovered gas and appeared, at times, 

to include equipment not necessarily required by the regulation, 

we generally agree with the commenters, based on our own cost 

estimates, that optimizing management of the fuel gas system to 

limit the long-term concentration of H2S to 60 ppmv is not costeffective for flares(see Table 2 below). We note that the costs 

provided by the commenters and the costs and emissions 

reductions in our analysis are the incremental costs and

emissions reductions of going from the short-term 162 ppmv H2S 

concentration to a combined short-term 162 ppmv H2S concentration 

and long-term 60 ppmv H2S concentration. While we are aware that 

some consent decrees require refineries to limit the 

concentration of H2S in the fuel gas to levels lower than the 

short-term 162 ppmv H2S concentration , our baseline when 

evaluating the impacts of a national standard (in this case, 
Page 95 of 269

subpart Ja) is the national set of requirements to which an 

affected flare would be subject in the absence of subpart Ja 

(i.e., the short-term 162 ppmv H2S concentration limit in 40 CFR 

part 60, subpart J).

Table 2. National Fifth Year Impacts of Meeting a Long-Term 60 

ppmv H2S Concentration for Flares Subject to 40 CFR Part 60, 

Subpart Ja

Capital 

cost

($1,000)

Total 

annual 

cost 

($1,000/ 

yr)

Emission 

reduction 

(tons 

SO2/yr)a

Costeffectiveness 

($/ton)

New 86,000 14,000 6 2,160,000

Modified / 

Reconstructed 410,000 68,000 25 2,660,000

a These emission reductions are based on flares already meeting 

the short-term 162 ppmv H2S fuel gas concentration limit in 40 

CFR part 60, subpart J or the incremental emission reductions 

achieved by optimizing management of the fuel gas system to 

limit short-term 162 ppmv H2S concentration in the fuel gas to a 

combined short-term 162 ppmv H2S concentration and long-term 60 

ppmv H2S concentration in the fuel gas.

Comment: Several commenters addressed EPA’s request for 

comment on “the equivalency of the subpart Ja requirements as 

proposed to be amended today and the SCAQMD Rule 1118” and 

“whether EPA could deem a facility in compliance with subpart Ja 

as proposed to be amended today if that facility was found to be 

in compliance with SCAQMD Rule 1118, or other equivalent State 

or local rules” (73 FR 78532, December 22, 2008). One commenter 

disagreed with EPA’s position, alleging that “EPA’s suggestion
Page 96 of 269

that it can waive compliance with the NSPS in this manner is 

contrary to the Clean Air Act.” The commenter stated that EPA’s 

suggestion “that existing state and local requirements render 

the federal requirements irrelevant only confirms that EPA’s

proposed flaring requirements do not reflect the “best

technological system of continuous emission reduction.” 42 

U.S.C. § 7411(h)(1) (emphasis added). The commenter also stated

that the CAA already provides a mechanism for implementation of 

alternative work practice standards in narrowly defined 

circumstances (42 U.S.C. § 7411(h)(3)); an owner or operator may 

demonstrate to the Administrator that an alternative means of 

emissions limitation is equivalent to the federal standard on a 

case-by-case basis. Therefore, the commenter asserted, the CAA 

clearly states that “EPA’s authority to waive federal work 

practice standards is case specific.” Finally, the commenter 

stated that EPA did not explain how emissions reductions 

achieved through compliance with SCAQMD Rule 1118 are equivalent 

to subpart Ja. Further, the commenter asserted that EPA neither 

identified other State or local rules that could be considered 

equivalent to subpart Ja nor explained how EPA would determine 

that a specific State or local rule is equivalent to subpart Ja. 

Therefore, the commenter asserted, it is impossible to fully 

assess the merit of EPA’s idea and provide meaningful comments.
Page 97 of 269

Another commenter stated that “most stringent” is not one 

of the criteria that must be applied under the law to determine 

BSER. Therefore, the commenter asserted, it is not appropriate 

to argue that EPA did not properly determine BSER simply because 

there exist State or local rules that are more stringent than 

federal requirements. The commenter also asserted that EPA has 

full authority to establish alternative regulatory standards 

that are determined to be as stringent as or more stringent than 

BSER, and CAA section 111(h)(3) generally applies after EPA has 

completed a national rulemaking and an owner or operator 

requests approval for a site-specific alternative at a later 

date. The commenter asserted that it is logical that if an 

alternative method is identified during the rulemaking process, 

“the law would allow EPA to establish a site-specific 

alternative [in the rule itself] (especially, as under [CAA

section 111], where the alternative would have to be determined 

through notice and comment rulemaking).”

Other commenters recommended that refineries complying with 

SCAQMD Rule 1118 be deemed in compliance with subparts J and Ja. 

According to one commenter, SCAQMD Rule 1118 is “in all respects 

equivalent to or more stringent than the corresponding 

requirements” of subparts J and Ja. Commenters also recommended 

that refineries should be able to consider compliance with

BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12 as 
Page 98 of 269

compliance with the appropriate provisions of subpart Ja. One 

commenter provided a table comparing each of the six proposed 

flare management plan requirements in 40 CFR 60.103a(a) to the 

SCAQMD and BAAQMD regulations. The table identified sections of 

BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12 that 

are equivalent to the six subpart Ja flare management plan 

requirements. The commenter also noted that SCAQMD Rule 1118 is 

only equivalent to five of the proposed requirements; it does 

not require an owner or operator to identify procedures to 

reduce flaring in cases of fuel gas imbalance (although another 

commenter noted that SCAQMD Rule 1118 requires minimization of 

all flaring, including fuel gas imbalance). While most 

commenters focused on the equivalence of the flare management 

plan requirements of the SCAQMD and BAAQMD rules and the flare 

management plan requirements of subpart Ja, one commenter 

requested that the periodic sampling of BAAQMD Regulation 12, 

Rule 11 be considered equivalent to the continuous sulfur 

monitoring requirements of subpart Ja for emergency flares.

Response: First, we note that there seems to be some 

misunderstanding regarding how a determination that SCAQMD Rule 

1118 or BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12

are equivalent to subpart Ja would actually be implemented in 

subpart Ja. EPA will not “waive” the obligation to comply with 

subpart Ja if the source is complying with SCAQMD Rule 1118 or 
Page 99 of 269

BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12. In 

other words, EPA will not allow the owner or operator to 

“choose” to comply with SCAQMD Rule 1118 or BAAQMD Regulation 

12, Rule 11 and Regulation 12, Rule 12 instead of subpart Ja. 

Rather, the source must always demonstrate compliance with 

subpart Ja. If SCAQMD Rule 1118 or BAAQMD Regulation 12, Rule 

11 and Regulation 12, Rule 12 are determined to be equivalent to 

subpart Ja, then these requirements would be provided as an 

alternative within subpart Ja for the source to demonstrate that 

it is meeting the requirements of subpart Ja. 

To assess the comments, we reviewed SCAQMD Rule 1118, 

BAAQMD Regulation 12, Rule 11, and BAAQMD Regulation 12, Rule 12 

and compared these rules to the subpart Ja requirements we are 

finalizing today. We have included documentation of this review 

in Docket ID No. EPA-HQ-OAR-2007-0011 that shows the sections of 

each of those rules that we consider are equivalent to the 

subpart Ja requirements. We determined that SCAQMD Rule 1118 

and BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12 

will result in equivalent to or greater than the emissions 

reductions resulting fromthe subpart Ja flare management plan 

requirements. As a result of our analysis, we have amended 

subpart Ja as described in the following paragraphs.

We determined that SCAQMD Rule 1118 is equivalent to the 

flare requirements and monitoring, recordkeeping, and reporting 
Page 100 of 269

provisions for determining compliance with the flare 

requirements in subpart Ja. We also determined that the 

combined provisions of BAAQMD Regulation 12, Rule 11 and BAAQMD 

Regulation 12, Rule 12 are equivalent to the flare requirements 

and monitoring, recordkeeping, and reporting provisions for 

determining compliance with the flare requirements in subpart 

Ja. Therefore, we have added specific compliance options for 

flares that are located in the SCAQMD and are in compliance with 

SCAQMD Rule 1118, as well as for flares that are located in the 

BAAQMD and are in compliance with both BAAQMD Regulation 12, 

Rule 11 and BAAQMD Regulation 12, Rule 12. Flares that are in 

compliance with these alternative compliance options are in

compliance with the flare standards in subpart Ja. 

Specifically, 40 CFR 60.103a(g) specifies that flares that are 

located in the SCAQMD may elect to comply with SCAQMD Rule 1118

and flares that are located in the BAAQMD may elect to comply

with both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 

12, Rule 12 as an alternative to complying with the flare 

management plan requirements of 40 CFR 60.103a(a) and (b) and

the root cause analysis and corrective action analysis 

requirements of 40 CFR 60.103a(c) though (e). In addition, 40 

CFR 60.107a(h) indicates that flares that are located in the 

SCAQMD may elect to comply with the monitoring requirements of 

SCAQMD Rule 1118 and flares that are located in the BAAQMD may 
Page 101 of 269

elect to comply with the combined monitoring requirements of 

both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, 

Rule 12 as an alternative to complying with the monitoring 

requirements of 40 CFR 60.107a(e) and (f). The owner or 

operator must notify the Administrator as specified in 40 CFR 

60.103a(g) that the flare is in compliance with SCAQMD Rule 1118

or both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, 

Rule 12. The owner or operator must also submit a copy of the 

existing flare management plan (if applicable) as specified in 

40 CFR 60.103a(g). 

We note that as pointed out by commenters, an owner or 

operator maintains the ability under CAA section 111(h)(3) to 

submit a request to establish, on a case-by-case basis, that “an 

alternative means of emission limitation will achieve a 

reduction in emissions. . .at least equivalent to the reduction 

in emissions” achieved under the flare standards of subpart Ja. 

Pursuant to CAA section 111(h)(3), we also included specific 

provisions within 40 CFR 60.103a for owners or operators to 

submit a request for “an alternative means of emission 

limitation” that will achieve a reduction in emissions at least 

equivalent to the reduction in emissions achieved under the 

final standards in subpart Ja.

Comment: Commenters suggested that the requirement to 

minimize discharges to the flare in 40 CFR 60.103a(a)(1) should 
Page 102 of 269

specifically address routine discharges, and EPA should limit 

the minimization requirements to actions that: (1) are 

“consistent with good engineering practices” and (2) consider 

costs and other health and environmental impacts, as required by 

section 111 of the CAA.

Response: We agree that the language in proposed 40 CFR 

60.103a(a)(1) appears to require an assessment of flare 

minimization irrespective of cost or other relevant 

considerations as contained in CAA section 111, which was not 

our intent. We are clarifying through this response that cost, 

safety, and emissions reductions may be considered when 

evaluating what actions should be taken to minimize discharges 

to a flare, but we disagree that the flare minimization 

assessment should be limited to “routine discharges.” We have 

revised the flare management plan requirements in 40 CFR 

60.103a(a) to more fully describe the types of information that 

must be evaluated and included in the plan. 

As noted in the summary of today’s rule (Section III.C of 

this preamble), we are finalizing our proposed withdrawal of the 

250,000 scfd 30-day rolling average flow limit for flares. This 

limitation does not adequately account for site-specific factors 

regarding flare gas Btu content, ability to off-set natural gas 

purchase, and other considerations. We find that these factors 

need to be addressed in a site-specific basis and are more 
Page 103 of 269

appropriately addressed through the flare management plan. In 

the absence of the specific flow limitation, we have included 

additional requirements in the flare management plan to prompt a 

thorough review of the flare system so that, as an example, 

flare gas recovery systems are installed and used where these 

systems are warranted. We have also revised the flare 

minimization requirements to require the flare management plans

to be submitted to the Administrator (40 CFR 60.103a(b)). 

As part of the development of the flare management plan, 

refinery owners and operators can provide rationale and 

supporting evidence regarding the flare reduction options 

considered, the costs of each option, the quantity of flare gas 

that would be recovered or prevented by the option, the Btu 

content of the flare gas, and the ability or inability of the 

reduction option to offset natural gas purchases. The plan will

also include the rationale for the selected reduction option,

including consideration of safety concerns. The owner or 

operator must comply with the plan as written and submitted to

the Administrator. Major revisions to the plan, such as the 

addition of an alternative baseline (see next comment for 

further detail on baselines), must also be submitted to the 

Administrator.

In summary, although we did not incorporate the commenter’s 

suggested language for limiting the scope of the minimization 
Page 104 of 269

requirements to actions that are “consistent with good 

engineering practices” and that “consider costs and other health 

and environmental impacts,” we acknowledge that these are valid 

considerations in the selection of the minimization alternatives 

available for a given affected flare. We find that the process 

of developing and submitting the flare management plan will 

ensure that these factors are considered consistent with CAA 

section 111 and that the requirement to minimize discharges to 

the flare is implemented consistently across all affected 

sources. 

Comment: Commenters asserted that the flare flow root 

cause analysis threshold of 500,000 scf in any 24-hour period is 

arbitrary and cannot be fairly applied to all flares at all 

refineries. One commenter cited an ultracracker flare that 

routinely cycles from 5 million to 25 million scfd as an example

of a flare for which the threshold of 500,000 scf in any 24-hour 

period would result in constant and meaningless root cause 

analyses. The commenters suggested removing the numerical 

threshold and limiting root cause analysis to upsets and 

malfunctions as initially promulgated in June 2008 (because root 

cause analysis is generally only effective for reducing nonroutine flows) or using a site- or flare-specific threshold 

instead. Even if the numerical threshold is revised, the 

commenters suggested that a number of streams be excluded from 
Page 105 of 269

the calculation of flow, such as hydrogen and nitrogen, purge 

and sweep gas, natural gas added to increase the Btu content of 

the flare gas, and gases regulated by other rules to avoid 

performing multiple root cause analyses for routine events. One 

commenter suggested that owners or operators should be able to 

use one root cause analysis report for an event that occurs 

routinely (as allowed in the consent decrees).

Response: We proposed the flare flow root cause analysis 

threshold of 500,000 scf in any 24-hour period because we 

projected that flare gas recovery would be a cost-effective 

emission reduction technique for flares with fuel gas flows that 

routinely exceed 500,000 scfd, although we acknowledge that the 

threshold at which flare gas recovery becomes cost-effective is 

strongly (inversely) correlated to the average Btu content of 

the flare gas (i.e., a relatively small reduction in the Btu 

content of the gas makes the recovery system significantly less 

cost effective). Although we did not specifically exclude sweep 

or purge gas from the flow, we expected that the flow rates of 

sweep or purge gas (i.e., gases needed to ensure the readiness 

of the flare and the safety of the flare gas system) would be 

negligible when compared to the root cause analysis threshold of 

500,000 scf in any 24-hour period. In fact, in our original 

analysis of the appropriate flow rate root cause analysis

threshold (Docket Item No. EPA-HQ-OAR-2007-0011-0246), we 
Page 106 of 269

essentially assumed that the sweep and purge gas flow rates were 

zero, and we estimated costs and emissions reductions of the 

500,000 scf in any 24-hour period threshold based on recovering 

that amount of gas or eliminating recurring events of that size 

(rather than 500,000 scf minus the sweep or purge gas flow). 

However, while we do not believe that 5 million scfd9 is a 

reasonable base flow for a flare, we do acknowledge that the 

size of the flare, as well as the flare header system, will 

greatly impact the required flow needed to maintain the 

readiness of the flare. Although we can derive suitable flare 

flow thresholds for average conditions, these thresholds are not 

necessarily reasonable when applied to all flows, and we did not 

intend for on-going root cause analyses to be conducted on 

account of sweep or purge gas. 

Therefore, rather than specifying a one-size-fits-all 

threshold, the final rule requires facilities to develop their 

own base flare flow rates as part of their flare management 

 

9 Regarding commenter’s cited ultracracker flare example, it is 

difficult to believe that sweep gas alone accounts for 5 million 

scfd of flare gas flow. Additionally, a compositional analysis 

of the base flare gas from the normal flow, based on data 

provided from a DIAL study of this refinery, suggests that the 

base flare gas is of sufficient quality to recover. It also 

appears, based on the data provided by the commenter, that the 

hydrogen stream recycle compressor was off-line approximately 

half the year. For such huge gas flows, considering the cost of 

purchasing or producing additional hydrogen, and the emissions 

associated with that process, it is reasonable to expect that 

the facility would have a back-up compressor if the primary 

compressor is unreliable.
Page 107 of 269

plan. A flow-based root cause analysis is triggered if flows 

measured by the flow monitor exceed 500,000 scf greater than the 

base flare flow rate in any 24-hour period. Evaluating the flow 

rate threshold above a baseline better reflects our original 

analysis of the impacts of flow-based root cause analyses when 

the sweep or purge gas flow rates are not negligible. We also 

note that 40 CFR 60.103a(d) allows a single root cause analysis 

to be conducted for any single continuous discharge that causes 

the flare to exceed either the root cause analysis threshold for 

SO2 or flow for two or more consecutive 24-hour periods.

The final rule does not limit root cause analyses to upsets 

and malfunctions of refinery process units and ancillary 

equipment connected to the flare, nor does it explicitly allow 

owners or operators to use one root cause analysis report for an 

event that occurs routinely. When we decided to eliminate the 

numerical limit on flare flow rate, we specifically increased 

the scope of the flare flow root cause analysis to cover more 

than just upsets and malfunctions. We also decided not to 

explicitly allow owners or operators to use one root cause 

analysis report for an event that occurs routinely as a means to 

discourage routine flaring of recoverable gas. However, we 

recognize that there may be recurring discharges to the flare 

that are not recoverable for various reasons. Therefore, the 

final rule does allow for several base cases, which could 
Page 108 of 269

include recurring maintenance; this provision will avoid 

multiple root cause analyses for a recurring event. As 

described above, the flare management plan (as well as 

significant revisions to the plan to include alternative 

baselines) must be submitted to the Administrator. 

We expect that a final flare management plan in compliance 

with subpart Ja will possess the following characteristics: (1) 

completeness (all gas streams are considered, all required 

elements are included, and all appropriate flare reduction 

measures are evaluated); (2) accuracy (the emission reductions 

and cost estimates for the different options are accurate); and 

(3) reasonableness (the selection of reduction options is 

correct and the baseline flow value is reasonable). If the 

Administrator identifies deficiencies in the plan (e.g., the 

plan does not contain all the required elements, alternative 

flare reduction options were not evaluated or selected when 

reasonable, the baseline or alternative baseline flow rates are 

considered unreasonable), the Administrator will notify the 

owner or operator of the apparent deficiencies. The owner or 

operator must either revise the plan to address the deficiencies

or provide additional information to document the reasonableness 

of the plan.

Comment: Commenters requested alternative monitoring 

options or an exemption from continuous flow monitoring for: 
Page 109 of 269

(1) flares designed to handle less than 500,000 scfd of gas; (2) 

pilot gas; (3) flares with flare gas recovery systems; (4) 

emergency flares; and (5) secondary flares. The commenters 

asserted that flow meters are costly and engineering 

calculations, which are currently used, are sufficient to 

evaluate when the flow to a flare exceeds 500,000 scf in any 24-

hour period. One commenter stated that for flares with flare 

gas recovery systems, the pressure drop across the flare seal 

drum can be used to calculate flow rate.

Response: In the final rule, flow monitoring is used to 

determine whether a root cause analysis is required rather than 

to ensure compliance with a specific flow limit. We have 

reviewed the commenters’ suggestions and agree that in certain 

specific cases, monitoring is not necessary and should not be 

required. However, as a general rule, we believe flow monitors 

are needed not only to provide a verifiable measure of 

exceedances of the flow root cause analysis threshold, but also 

exceedances of the root cause analysis threshold of 500 lb SO2 in 

any 24-hour period. In addition, when we evaluated local rules 

such as the initial BAAQMD rule for flare monitoring, we saw 

that the measured flare flow rates were several times greater 

than previously projected by the facilities. 

Consequently, we find great value in the flow monitoring 

requirements for flares. These monitoring requirements will 
Page 110 of 269

greatly improve the accuracy of emissions estimates from these 

flares. The resulting improved accuracy of flare emissions 

estimates will also lead to better decision-making as we conduct 

future reviews of rules applicable to petroleum refineries. We 

did consider each of the commenters’ suggested exemptions in 

light of this fact; our specific considerations follow. 

We did not specifically consider that some flares would not 

be capable of exceeding the flow root cause analysis threshold 

(i.e., designed to handle less than 500,000 scfd of gas). 

However, these small flares could still exceed the root cause 

analysis threshold of 500 lb SO2 in any 24-hour period. As such, 

we did not provide an exemption from the monitoring requirements 

for these small flares.

We agree that the monitoring of pilot gas flow is not 

needed. In the final rule, a root cause analysis is required if 

the gas flow to the flare exceeds 500,000 scf above the baseline

in any 24-hour period. The flow of pilot gas is considered to 

be part of the baseline flow and is assumed to be constant. As 

such, monitoring of pilot gas would not be necessary to

determine whether a flare has exceeded 500,000 scf above the 

baseline in any 24-hour period. In practice, the actual 

baseline flow set for the flare may or may not expressly include 

the pilot gas flow rate. Generally, the configuration of the 

flare header is such that the flare flow monitor would not 
Page 111 of 269

measure pilot gas flow. In this case, the baseline flow 

determined for the flare would not expressly include the pilot 

gas flow rate. If the flare flow monitor is configured in such 

a way that it does measure pilot gas, then pilot gas would be 

considered part of the baseline conditions for that flare.

We agree with commenters that flares with flare gas 

recovery systems do have unique conditions and these warrant 

alternative monitoring options. Additionally, we recognize that 

the monitoring requirements may be burdensome for flares that 

are truly “emergency only” (i.e., flares that flare gas rarely, 

if at all, during a typical year) or for secondary flares in a 

cascaded flare system. These flares are expected to have a 

water seal that prevents flare use during normal operations and 

ensures that the pressure upstream of the water seal (expressed 

in inches of water) does not exceed the water seal height during 

normal operations (hereafter referred to as “properly maintain a 

water seal”). We find that, for these select types of flares, 

water seal monitoring as an alternative to the flow (and sulfur) 

monitoring provisions is appropriate. 

For flares with a flare gas recovery system, and other 

emergency or secondary flares that properly maintain a water 

seal, the final rule states that an owner or operator may elect 

to monitor the pressure in the gas header just before the water 

seal and monitor the water seal liquid height to verify that the 
Page 112 of 269

flare header pressure is less than the water seal, which is an 

indication that no flow of gas occurs. If the flare header 

pressure exceeds the water seal liquid level, a root cause 

analysis is triggered unless the pressure exceedance is 

attributable to staging of compressors. This alternative 

reduces the costs associated with installing sulfur and flow 

monitoring systems for flares that rarely receive fuel gas. 

Engineering calculations can be used to estimate the emissions 

during the event, but not for determining whether or not a root 

cause analysis is required.

To ensure that this option is only used for flares that are 

truly emergency flares and not for flares that are used for 

routine discharges, the final rule contains a limit on the 

number of pressure exceedances requiring root cause analyses 

that can occur in one year. Following the fifth reportable 

pressure exceedance in any consecutive 365 days, the owner or 

operator must comply with the sulfur and flow monitoring 

requirements of 40 CFR 60.107a(e) and (f). Based on a review of 

available flaring data, we expect that gas may be sent to an 

emergency flare three to four times per year, on average. 

Consistent with this information, we are providing in these 

final amendments that an “emergency flare” may receive up to 

four releases to the flare in any consecutive 365 day period to 

account for year-to-year variability. However, a flare 
Page 113 of 269

receiving more than four discharges in a consecutive 365 day 

period can no longer be considered an “emergency flare” and must 

install the required sulfur and flow monitors.

Comment: Commenters requested an exemption from continuous 

sulfur monitoring or alternative monitoring options for flares 

handling only gases inherently low in sulfur content, emergency 

flares flares with properly designed flare gas recovery systems, 

and secondary flares. For flares handling gases low in sulfur, 

the commenters noted that continuous monitoring is unnecessary 

and certain fuel gas streams are already exempted from 

monitoring if they are combusted in a fuel gas combustion 

device. For flares that handle only gases exempt from the H2S

concentration limits and flares with properly designed flare gas 

recovery systems, commenters stated that engineering 

calculations are sufficient to determine if the SO2 root cause 

analysis threshold of 500 lb in any 24-hour period is exceeded. 

One commenter requested that EPA allow owners or operators to 

submit and use an alternative monitoring plan to demonstrate 

that the flare gas recovery system is operating within its 

capacity and to calculate SO2 emissions from engineering 

calculations and flare gas sampling. For secondary flares, one 

commenter noted that the continuous sulfur monitor on the 

primary flare could be used to determine the sulfur content of 

the gas being flared from the secondary flare.
Page 114 of 269

One commenter requested that EPA allow the use of 

engineering calculations to determine the sulfur-to-H2S ratio 

because sampling can be difficult for emergency flares. One 

commenter noted that EPA should allow the use of an existing 

continuous monitoring system if the gas sent to the flare is 

already monitored elsewhere. As examples, the commenter cited 

fuel gas and pilot gas already monitored within the fuel gas 

system.

For flares that rarely see flow, commenters particularly 

cited difficulties with performance tests. Commenters noted 

that to meet the sulfur monitor performance test requirements, 

an owner or operator may have to intentionally flare gas that 

may not meet the H2S concentration limits. One commenter also 

stated that performing the required relative accuracy test audit 

(RATA) could cause the flare to exceed the root cause analysis 

threshold. The commenter recommended revising the performance 

test requirements for flares with flare gas recovery to require 

only a cylinder gas audit.

Response: We have amended the final rule so that gases 

that are exempt from H2S monitoring due to low sulfur content are 

also exempt from sulfur monitoring requirements for flares. For 

low-sulfur gases, the flare root cause analysis will always be 

triggered by an exceedance of the flow rate threshold well 

before the SO2 threshold is exceeded, so no sulfur monitoring is 
Page 115 of 269

required. However, this exemption can only be used for flares 

that are configured to receive only fuel gas streams that are 

inherently low in sulfur content as described in 40 CFR 

60.107a(a)(3), such as flares used for pressure relief of 

propane or butane product spheres (fuel gas streams meeting 

commercial grade product specifications for sulfur content of 30 

ppmv or less) or flares used to combust fuel gas streams 

produced in process units that are intolerant to sulfur 

contamination (e.g., hydrogen plant, catalytic reforming unit,

isomerization unit, or HF alkylation unit). We already 

clarified that flare pilot gas is not required to be monitored. 

Also, subpart Ja already allows for H2S monitoring at a central 

location, such as the fuel mix drum, for all fuel gas combustion 

devices (and we are finalizing amendments to ensure it is clear 

that H2S monitoring at a central location is allowed for flares 

as well). Thus, we agree that if a flare only burns natural 

gas, fuel gas monitored elsewhere, or fuel gas streams that are 

inherently low in sulfur content (as defined in 40 CFR 

60.107a(a)(3)), then no H2S monitor is needed.

The remaining issue is whether or not sulfur monitoring is 

necessary for “emergency only” flares (i.e., an emergency flare 

is defined as a flare that combusts gas exclusively released as 

a result of malfunctions (and not startup, shutdown, routine 

operations, or any other cause) on four or fewer occasions in a 
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rolling 365 day period. For purposes of the rule, a flare 

cannot be categorized as an emergency flare unless it maintains 

a water seal.). We acknowledge that there are difficulties and 

costs with installing monitors on flares that rarely operate. 

However, we are concerned about how the owner or operator will 

detect emissions above 500 lb SO2 in any 24-hour period during an

upset or malfunction of a refinery process unit or ancillary 

equipment connected to the flare. Commenters appear to have 

conflicting opinions regarding the ability to sample the flare 

gas to determine the sulfur content (or total sulfur-to-H2S

ratio) during a flaring event. If samples could be taken during 

the flaring events, then that would be a potential option. 

However, during a process upset or malfunction, focus should be 

on alleviating the problem rather than taking a special sample. 

Also, given the duration of some of these events, it appears 

unlikely that representative samples can be manually collected. 

Taking the difficulties discussed above into account, we 

have developed an alternative monitoring option for emergency 

flares. As noted in the previous response, emergency flares are 

expected to properly maintain a water seal. We provide pressure 

and water seal liquid level monitoring as previously described 

as an alternative to the sulfur and flow monitors. As described 

in more detail above, any fuel gas pressure exceeding the water 

seal liquid level triggers a root cause analysis, and there is a 
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limit to the number of exceedances in one year. Under this 

option, a root cause analysis is triggered based on the 

monitored pressure and water seal height, so accurate 

measurements of flow rate and sulfur concentrations are less 

critical than for flares that must evaluate these parameters to 

determine if a root cause analysis is needed. Consequently, for 

these flares, engineering calculations can be used to estimate 

the reported emissions during the flaring event, but the root 

cause analysis must be performed regardless of the magnitude of 

these engineering estimates. Using this alternative monitoring 

option, emergency flares are not required to install continuous 

sulfur monitoring systems. Flares that do not meet the 

conditions of an emergency flare are required to install 

continuous sulfur monitoring systems and cannot elect this 

alternative monitoring option.

We also agree that flaring solely for the purpose of a RATA 

or other performance test is not desirable. The “cylinder gas 

audit” procedures requested by the commenter are described as 

alternative relative accuracy procedures in section 16.0 of 

Performance Specification 2 (referenced from Performance 

Specification 5). We reviewed the alternative relative accuracy 

procedures and considered how they may apply to flares, and we 

have determined that the alternative relative accuracy 

procedures are appropriate for flares. We expect that for most 
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affected flares, the variability in flow (including no flow 

conditions) and sulfur content of the gases discharged to the 

flare create significant barriers to the normally required 

relative accuracy assessments, particularly if those assessments 

need to be made over a range of sulfur concentrations 

potentially seen by the monitor. Therefore, we are amending 40 

CFR 60.107a(e)(1)(ii) and 40 CFR 60.107a(e)(2)(ii) to specify 

that the owner or operator of a flare may elect to use the 

alternative relative accuracy procedures in section 16.0 of 

Performance Specification 2 of Appendix B to part 60. As 

required by 40 CFR 60.108a(b), the owner or operator shall 

notify the Administrator of their intent to use the alternative 

relative accuracy procedures.

Comment: One commenter requested that EPA clarify whether 

the additionally proposed sulfur monitoring options for flares 

are for total reduced sulfur or total sulfur. The commenter 

noted that measuring total sulfur is the simplest and most 

inclusive measurement of SO2 emissions and it is the method 

included in SCAQMD Rule 1118. The commenter also requested that 

methods for measuring total sulfur in gaseous fuels be included 

as acceptable options to perform the relative accuracy 

evaluations of the CEMS.

One commenter requested that provisions be made in 40 CFR 

60.107a(e)(2) to develop a total sulfur- (or total reduced 
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sulfur-) to-H2S ratio so that the total sulfur monitor can be 

used for both the root cause analysis requirements and for 

compliance with the short-term 162 ppmv H2S concentration limit 

without the need for a duplicative continuous H2S monitor. 

Another commenter supported the addition of alternative 

monitoring methods for the sulfur content of flare gas but noted 

that since the composition of flare gas is highly variable, the 

alternative methods must meet continuous monitoring 

requirements.

Response: We have clarified and consolidated the 

monitoring requirements to allow total reduced sulfur monitoring 

for flares. Forthe purposes of evaluating the SO2 root cause 

analysis threshold, total sulfur monitoring provides the most 

accurate assessment. However, in most cases, the vast majority 

of sulfur contained in gases discharged to the flare is expected 

to be in the form of total reduced sulfur compounds, which 

include CS2, COS, and H2S. Our test method for measuring total 

reduced sulfur includes the use of Method 15A as a reference 

method, and because Method 15A measures total sulfur, the total 

reduced sulfur monitoring requirement is equivalent to a total 

sulfur monitoring method.

As discussed previously, we are relying on the suite of 

flare requirements we are promulgating to limit SO2 emissions at 

the flare. These include optimizing management of the fuel gas
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by limiting the short-term concentration of H2S to 162 ppmv

during normal operating conditions. We expected most refineries 

would already have the H2S monitor and did not consider the use 

of a total sulfur monitor for use in complying with the shortterm 162 ppmv H2S concentration in the fuel gas. As the H2S 

concentration will always be less than the total reduced sulfur 

concentration, it is acceptable to use the total reduced sulfur 

monitor to verify that the fuel gas does not exceed the shortterm H2S concentration of 162 ppmv. Therefore, we have provided

for the use of total reduced sulfur monitors, provided the 

monitor can also meet the 300 ppmv span requirement. 

However, we have not provided a correction factor to scale 

down the total reduced sulfur concentration to H2S. The owner or 

operator using this method must essentially be able to 

demonstrate they can achieve a 162 ppmv total reduced sulfur 

concentration in the fuel gas. The concentration ratio was 

provided for the purposes of the root cause analysis because of 

the costs of adding a total sulfur monitoring system when a dual 

range H2S monitor was already in-place as well as the expected 

accuracy needed for the system to assess the SO2 root cause 

analysis threshold. As few cases would exist where the flaring 

event would be right at the SO2 root cause analysis threshold of 

500 lb in any 24-hour period, inaccuracies associated with the 
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average total sulfur-to-H2S ratio were not expected to be 

significant. 

On the other hand, the short-term 162 ppmv H2S concentration 

in the fuel gas must be continuously maintained, and the total 

sulfur-to-H2S ratio at these low concentrations is expected to be 

highly variable, depending on the efficiency of the amine 

scrubber systems. As the amine scrubber systems, according to 

previous industry comments, are not effective for reduced sulfur 

compounds other than H2S, the non-H2S reduced sulfur

concentration is expected to be fairly constant, with most of 

the fluctuations in total sulfur content being attributable to 

fluctuations in H2S concentrations. Consequently, we have 

determined that the inaccuracies of the ratio approach are not 

acceptable for continuously demonstrating that the short-term 

concentration in the fuel gas does not exceed 162 ppmv H2S. 

Therefore, owners or operators of affected flares may use the 

direct output of a total reduced sulfur monitor to assess 

compliance with the short-term 162 ppmv H2S concentration in the 

fuel gas, or they must install a continuous H2S monitor.

Comment: One commenter supported the proposed amendment 

revising the span value for fuel gas H2S analyzers to match the 

span requirements in subpart J, stating this will save time and 

money. However, the commenter stated that the span value for 

the flare H2S monitoring option is too restrictive and suggested 
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that requirements in Appendix F to part 60 provide sufficient 

quality assurance/quality control (QA/QC) without the need for 

the rule to specify the span range. The commenter also 

requested clarification of the sulfur monitor span for flares, 

suggesting that it should be based on the H2S concentration 

limits and that engineering calculations can be used to assess 

exceedances of the SO2 root cause analysis threshold of 500 lb in 

any 24-hour period.

Response: The H2S span value is at 300 ppmv to verify 

compliance with the H2S concentration in the fuel gas; the span 

of the total sulfur monitor needs to be much greater than that 

to be able to quantify the sulfur content in streams containing 

several percent sulfur. For units that use the H2S analyzers 

both to assess compliance with the short-term 162 ppmv H2S 

concentration in the fuel gas and to assess exceedances of the 

SO2 root cause analysis threshold of 500 lb in any 24-hour 

period, a dual range monitor will be necessary. For the 

purposes of the SO2 root cause analysis threshold of 500 lb in 

any 24-hour period, we intended that the monitor be capable of 

accurately determining the sulfur concentration for the range of 

concentrations expected to be seen at the flare. We are 

particularly interested in quantifying the concentrations of 

high sulfur-containing streams as these would be the streams 

most likely to trigger a root-cause analysis at low flows. We 
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proposed that the span for the flare sulfur monitor be selected 

from a range of 1 to 5 percent. We agree with the commenter 

that this may be too restrictive, and we have revised the span 

requirements to be determined based on the maximum sulfur

content of gas that can be discharged to the flare (e.g., 

roughly 1.1 to 1.3 times the maximum anticipated sulfur 

concentration) but no less than 5,000 ppmv. A single dual range 

monitor may be used to comply with the short-term 162 ppmv H2S 

concentration in the fuel gas and the SO2 root cause analysis

threshold monitoring requirement provided the applicable span 

specifications are met. In reviewing the span specifications, 

we noted that span requirements were inadvertently omitted from 

the total reduced sulfur compound monitoring alternative. The 

purpose of these monitors is identical to the H2S monitoring 

alternative, and the same span considerations apply for these 

monitors.

We disagree that the QA/QC procedures in Appendix F to part 

60 are sufficient without specifying the span values. Procedure 

1 of Appendix F to part 60 defines “span value” as: “The upper 

limit of a gas concentration measurement range that is specified 

for affected source categories in the applicable subpart of the 

regulation.” The concentrations used for calibration are based 

on the span value. Several of the QA/QC procedures in Appendix 

F are undefined if the span value is not defined in the rule.
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Comment: Commenters stated that time is needed to install 

continuous monitors and to make other necessary changes (such as 

installing a flare gas recovery system or additional amine 

treatment) to comply with all the flare requirements (e.g., 

short-term 162 ppmv H2S concentration limit, long-term 60 ppmv 

H2S concentration limit, flare management plan, root cause 

analysis, and continuous monitoring), especially considering how 

quickly a flare may become a modified affected source. While 

most commenters focused on the amount of time needed to install 

equipment to comply with the long-term 60 ppmv H2S concentration 

limit, other commenters asserted that additional time for 

activities such as planning and re-piping would be needed to 

meet the standards. Commenters requested differing amounts of 

additional time generally ranging from 3 to 5 years. Commenters 

noted that the additional time would allow owners and operators 

to schedule any process unit shutdowns needed to install new 

equipment or monitors during a turnaround. One commenter 

recommended that the extra time to begin root cause analyses 

provided to refiners committing to install flare gas recovery 

systems should also be provided to refiners committing to expand 

an existing flare gas recovery system. Commenters also noted 

that experience implementing SCAQMD Rule 1118 suggests that 

there will be difficulty obtaining and installing continuous 

monitors in less than 3 years due to the availability of monitor 
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manufacturers and the need to stage the installation of monitors 

at refineries with multiple affected flares. One commenter 

requested that EPA consider a compliance schedule in subpart Ja 

that is consistent with compliance schedules in consent decrees. 

Commenters objected to phasing out the additional time after the 

rule has been in place for 5 years.

One commenter requested clarification regarding the trigger 

date from which the additional time to comply with the flare 

provisions (e.g., 2 years when installing a flare gas recovery 

system) begins. The commenter questioned whether the trigger 

date is when construction starts, at startup, or when the stay 

is removed (or whichever is later). Another commenter agreed 

that EPA should set the compliance time based on the initial 

startup of the modification. The commenter noted that EPA 

should follow the 40 CFR part 60 General Provisions for 

performance test timing and the 40 CFR part 63 General 

Provisions for compliance timing.

Response: As we are no longer applying the long-term 

60 ppmv H2S concentration limit to flares, the comments related 

to the amount of time needed to comply with a long-term 60 ppmv 

H2S concentration limit are moot. We do, however, recognize that 

a flare modification can occur much more quickly than 

modifications of traditional process-related emission sources. 

Therefore, we evaluated the comments regarding the amount of 
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time needed to meet the various requirements for flares while 

keeping the subpart Ja flare modification provision in mind. We 

discuss each requirement and the time for demonstrating 

compliance with that requirement in the following paragraphs.

We find it appropriate to require flares to meet the H2S 

concentration upon startup of the affected flare because, as 

indicated by earlier comments, it is likely that most refiners 

are already operating their fuel gas collection and treatment 

systems to achieve a short term H2S concentration of 162 ppmv. 

Thus, fuel gas discharged to the flare during normal operations 

will have already been treated to meet this limit in the 

existing refinery fuel gas collection and treatment system.e 

also note that consent decrees typically require immediate 

compliance with this requirement. Therefore, the final rule 

requires all refineries with new, modified, and reconstructed

flares to manage the fuel gas sent to these flares such that 

they meet the short-term H2S concentration of 162 ppmv upon 

startup of the affected flare. 

As we noted in the preamble to the proposed amendments, 

many of the connections that would trigger applicability to 40 

CFR part 60, subpart Ja are critical to the safe and efficient 

operation of the refinery. These connections can and often must 

be installed quickly. At the same time, nearly all refineries 

will need time for planning, designing, purchasing, and 
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installing (including any necessary re-piping) sulfur and flow 

monitors that are newly required by subpart Ja. Some refineries 

will elect to add flare gas recovery and/or sulfur treatment 

equipment to minimize their emissions as part of the evaluations 

conducted as required by the new flare management plan 

requirements, and time will be needed for planning, designing, 

purchasing, and installing these components as well. Given that 

many flares will become modified affected sources relatively 

quickly, owners and operators will be competing with one another 

for the services and products of a finite number of vendors who 

provide the necessary monitors and other equipment. Several 

commenters specifically noted availability of monitors as an 

issue when complying with SCAQMD Rule 1118. As such, we find 

that immediate compliance with some of the requirements for 

flares, such as the planning, designing, purchasing, and 

installation of (including any necessary re-piping) sulfur and 

flow monitors, may be difficult for operators to meet,

especially in situations where quick connections to the flare 

are made. A phased compliance schedule allows for the operators 

to comply with some work practice requirements associated with 

flares, such as optimizing their fuel gas system to achieve a 

short-term H2S concentration of 162 ppmv immediately, while 

allowing time to install monitoring equipment to comply with the 

other elements of the work practices standards. 
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A phased compliance schedule will also allow owners and 

operators to minimize process interruption by coordinating the 

installation of monitoring equipment with process shutdowns or 

turnarounds. In addition to providing operating flexibility to 

the refinery, we are taking into consideration the fact that a 

process shutdown and subsequent startup can generate significant 

emissions, even if the refinery is taking care to minimize those 

emissions. We consider a phased compliance schedule that allows 

owners and operators to avoid startups and shutdowns that are 

not necessary to maintain the equipment and process to be 

environmentally beneficial overall and the best system of 

emissions reduction for a quickly modified flare. Considering 

the time needed to complete engineering specifications, order, 

and install the required monitoring equipment, and considering 

the need to coordinate this installation with process unit 

shutdown or turnarounds, we determined that completion of these 

activities within 3 years is consistent with the best system of 

emissions reductions for quickly modified flares. 

We note, however, that this phased compliance schedule for

the flare requirements in subpart Ja is intended for those 

situations when a flare modification occurs quickly and the 

owner or operator does not have significant planning 

opportunities to install the required monitors or implement the 

selected flare minimization options without significant process 
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interruptions. For a large project on a schedule that includes 

time for planning, designing, purchasing, and installing 

equipment and monitors, we expect that the owner and operator 

will have time to assess whether or not the refinery flares will 

become affected sources through modification. If a project will 

result in the modification of a flare, we expect that the owner 

or operator will then plan how to meet the standards in subpart 

Ja as part of the project itself, including the installation of 

the monitoring systems and the development of a flare management 

plan. Because of the ability to plan ahead, flares that are 

modified as part of a large project will not have all of the 

difficulties meeting the subpart Ja flare requirements upon 

completion of the modification as those flares that are modified 

quickly. For projects that require 3 years from commencement to 

completion, we find that compliance with the flare requirements 

upon startup of the modified flare is appropriate and consistent 

with the best system of emissions reduction for large projects 

resulting in a modification of a flare. Thus, we determined 

that the appropriate time period for compliance with the flare 

standards is either: (1) 3 years from the promulgation date of 

these amendments; (2) 3 years from the date the modification 

commences or (3) upon startup of the modified flare, whichever 

is later.

10 In this manner, flares that become subject to 

 

10 For the purposes of this subpart, a modification to a flare 
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subpart Ja quickly based on a small safety-related connection 

will have up to 3 years to fully comply with all the flare 

standards, but flares that are modified as the result of a 

significant project, such as the installation of a new process 

unit that will be tied into an existing flare, will effectively 

be required to comply with the flare standards at the startup of 

the new process unit. 

Therefore, for the reasons described above, we are 

providing flares that become affected facilities subject to 

subpart Ja through modification with a phased compliance 

schedule for the flare standards as described in this paragraph.

The final rule requires all new, modified, and reconstructed 

flares to meet the short-term 162 ppmv H2S concentration 

requirementupon startup of the affected flare. Additionally, we 

are requiring owners and operators of modified flares to 

complete and implement the flare management plan under 40 CFR 

60.103a(a) by 3 years from the promulgation date, 3 years from 

the date the modification commences, or upon startup of the 

modified flare, whichever is later. We are requiring owners and 

operators of modified flares to begin conducting root cause and 

 

commences when a project that includes any of the activities in 

40 CFR 60.100a(c)(1) or (2) is commenced. Startup of the 

modified flare occurs when any of the activities in 40 CFR 

60.100a(c)(1) or (2) is completed (e.g., when a new connection 

is made to a flare such that flow from a refinery process unit 

or ancillary equipment can flow to the flare via that new 

connection).
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corrective action analyses under 40 CFR 60.103a(c) and (d) no 

later than 3 years from the promulgation date, 3 years after the 

date the modification commences, or the date of the startup of 

the modified flare, whichever is later, so that the facility can 

complete the flare management plan and establish baseline flow 

rates prior to performing the root cause and corrective action 

analyses. We are also requiring owners and operators of 

modified flares to install and begin operating the monitors 

necessary to demonstrate compliance with these provisions as 

required under 40 CFR 60.107a(e) through (g) within 3 years from 

the promulgation date, within 3 years from the date a 

modification commences, or by the startup date of the modified 

flare, whichever is later, when the monitors are not already in 

place. Compliance with the phased compliance schedule 

constitutes compliance with the flare standards as of the 

effective date.

C. Other Comments

Comment: Several commenters objected to the change to the 

definition of “refinery process unit.” The commenters objected 

to the proposed amendments to include coke gasification,

loading, and wastewater treatment, stating the change makes the 

term more expansive. The commenters stated that EPA did not

evaluate the impacts or explain the consequences of the revised 

definition. One commenter stated that product loading is 
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generally considered part of the refinery process unit to which 

it is associated and that wastewater treatment is a utility. 

Another commenter suggested that the definition specify SIC 2911 

(as in Refinery MACT 1).

Response: The original definition of “refinery process 

unit” in subpart J and the definition of “refinery process unit”

promulgated in subpart Ja in June 2008 read as follows: 

“Refinery process unit means any segment of the petroleum 

refinery in which a specific processing operation is conducted.” 

Thus, to be considered a refinery process unit, only two 

criteria are needed: (1) the unit must be located at a 

petroleum refinery; and (2) the unit must be used to conduct “a 

specific processing operation.” The definition does not 

directly limit the scope of “processing operations.” That is, 

the definition of refinery process unit does not limit process 

operations to distillation, re-distillation, cracking, or 

reforming, and it is not limited to only those processes used to 

produce gasoline, kerosene, fuel oils, etc. In the proposed 

amendment to this definition, we listed “operations” that we 

construed as conducting a “specific processing operation” when 

these operations are located at a petroleum refinery. 

Consequently, we considered the proposed inclusion of examples 

of refinery process units to be a clarification of the existing 

definition rather than an expansion of the original definition.
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We reviewed the impact of the proposed revision of this 

definition on subpart Ja as well as its historic use in 

subpart J. The term “refinery process unit” is used primarily 

in the definitions of certain affected facilities, “process 

gas,” and “process upset gas” in subparts J and Ja. The term is 

also used in the flare provisions in subpart Ja. With respect 

to the definitional terms, there can be no issue with including 

the designation of “refinery process unit” within the 

definitions for specific process units. “Process gas” is not 

used at all in either rule, although it was revised between 

proposal and promulgation of subpart J. In response to a 

comment that the definition of “process gas” “should have 

included the non-hydrocarbon gases produced by various process 

units in a refinery,” EPA responded: “The definition has been 

revised to include all gases produced by process units in a 

refinery except fuel gas and process upset gas.” (See page 127 

of Background Information For New Source Performance Standards, 

Volume 3, Promulgated Standards (BID Vol. 3), EPA 450/2-74-003 

(Feb. 1974), Docket Item No. EPA-HQ-OAR-2007-0011-0082). The 

definition had actually been revised to include “any gas 

generated by a petroleum refinery process unit.” The response 

in BID Vol. 3 suggests that EPA considered “refinery process 

units” and “process units in a refinery” to have the same 

meaning, and there is no mention of limiting what is considered 
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to be a “refinery process unit” or a “process units in a 

refinery.” 

“Process upset gas” is used only to provide an exemption to 

the H2S concentration limit for process upset gas sent to a 

flare. See 40 CFR 60.104(a)(1), 60.102a(g). Therefore, a 

narrow definition of “refinery process unit” would only limit 

those gases sent to a flare that would qualify as “process upset 

gas.” For example, if a coke gasifier is not a refinery process 

unit, then gases generated during the startup, shutdown, or 

malfunction of a coke gasifier located at the refinery would not 

be “process upset gas” and would be required to comply with the 

short-term 162 ppmv H2S concentration limit if sent to a flare. 

We find that the historical application of the “process upset 

gas” exclusion has considered a broad definition of what 

constitutes a “refinery process unit.” 

For subpart Ja, the definition of “refinery process unit” 

also impacts the flare provisions. Based on the proposed 

revisions of “refinery process unit,” it was clearly our intent 

that a broad definition of “refinery process unit” should apply 

to the flare requirements. Specifically, we intended that a 

flare modification occurs when a wide range of equipment at the 

petroleum refinery is newly connected to the flare. It was also 

our intent that the flare management plan consider flare 
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minimization methods for this broadly defined range of equipment 

referred to collectively as “refinery process units.”

Based on our review of the impacts of changes to the 

definition of “refinery process unit,” and considering all of 

the comments received, we maintain that the existing definition 

of “refinery process unit” is broad and should be broadly 

interpreted. For consistency between subparts J and Ja, we have 

elected to maintain the existing definition and not include an 

example list of refinery process units within the definition. 

However, to clarify that a modification to a flare occurs when 

these types of equipment are connected to the flare, we revised 

the language in the flaring provisions to refer to “refinery 

process units, including ancillary equipment.” This revision is 

made to clarify our original intent that coke gasification 

units, storage tanks, product loading operations, and wastewater 

treatment systems, as well as pressure relief valves, pumps, 

sampling vents, continuous analyzer vents, and other similar 

equipment are units from which a connection to a flare would 

trigger a flare modification and generate gas streams that 

should be considered in the flare management plan. We have 

included in the final amendments a definition of “ancillary 

equipment.” Specifically:

Ancillary equipment means equipment used in conjunction 

with or that serve a refinery process unit. Ancillary 

equipment includes, but is not limited to, storage tanks, 
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product loading operations, wastewater treatment systems, 

steam- or electricity-producing units (including coke 

gasification units), pressure relief valves, pumps, 

sampling vents, and continuous analyzer vents.

Sulfur recovery plants are also units from which a 

connection to a flare would trigger a flare modification and 

generate gas streams that should be considered in the flare 

management plan. We recognize that on-site sulfur recovery 

plants are considered refinery process units, and we proposed 

amendments to the definitions of “refinery process unit” and 

“sulfur recovery plant” to clarify that we consider a sulfur 

recovery plant to be “a segment of the petroleum refinery in 

which a specific processing operation is conducted.” However, 

the strict definition of “refinery process unit” would only 

apply to sulfur recovery plants physically located at the 

refinery. As subpart Ja also applies to off-site sulfur 

recovery plants (see 40 CFR 60.100(a) and 40 CFR 60.100a(a)), we 

found it potentially contradictory to define a sulfur recovery 

plant located outside the refinery as a “refinery process unit,”

so we are also not finalizing the proposed amendment to include

the term “all refinery process units” in the definition of 

“sulfur recovery plant.” However, while connections to a 

refinery flare from an off-site sulfur recovery plant are not 

expected to be common, off-site sulfur recovery plants are 

subject to subpart Ja. We clarify in this response that we 
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would consider such a connection to a flare to be from a 

“refinery process unit, including ancillary equipment” such that 

connecting an off-site sulfur recovery plant that is subject to 

subpart Ja to a flare at a refinery would cause that flare to be 

a modified flare subject to subpart Ja.

Further, in reviewing the definition of “sulfur recovery 

plant,” we noticed an inadvertent error that also suggests that 

the sulfur recovery plant must be located at a petroleum 

refinery, which is not consistent with the applicability 

provisions in 40 CFR 60.100(a) and 40 CFR 60.100a(a). 

Specifically, we inadvertently omitted the word “produced” in 

this first sentence, so we are amending the definition of 

“sulfur recovery plant” to clarify that a sulfur recovery plant 

recovers sulfur from sour gases “produced at the petroleum 

refinery.” Thus, we are amending the definition of “sulfur 

recovery plant” to correct inadvertent errors and to clarify 

that off-site sulfur recovery plants are included in the 

definition of “sulfur recovery plant,” as these plants are 

expressly considered to be affected facilities in subpart Ja. 

Comment: Commenters supported the revised definition of 

“delayed coking unit” but stated that since subpart Ja only sets 

standards for the coke drums, the definition should just include 

the coke drums associated with a single fractionator. The 

commenters stated that the definition should not include the 
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fractionator itself because VOC emissions from the fractionator 

are covered by NSPS for equipment leaks.

Response: The proposed amendments to the definition of 

“delayed coking unit” specifically listed the primary components 

of the delayed coking unit. In particular, based on the 

operation of the delayed coking unit, we find that the 

fractionator is an integral part of the delayed coking unit. 

The fresh feed to the delayed coking unit is generally 

introduced in the fractionator tower bottoms receiver. This 

integral use of the fractionator is different than the use of 

fractionators used for other units defined in subpart Ja, such 

as the fluid catalytic cracking unit (FCCU). For the FCCU, 

fresh feed is introduced in the riser, which is part of the 

affected facility in subpart Ja. As the feed to the delayed 

coking unit is to the fractionator, we find that the 

fractionator is an integral part of the delayed coking unit, so 

we specifically include it as part of the affected facility. 

While our proposed amendments covered only the major components 

of the delayed coking unit, upon our review of the definition 

based on the comments received, we note that there are several 

other components of the delayed coking unit that are integral to 

the operation of the delayed coking unit. Additionally, even 

though the standards are specific to the coke drum, many of 

these integral components are interconnected and necessary for 
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the delayed coking unit to meet the applicable standards. Based 

on our review of the operation of a delayed coking unit, we also 

include coke cutting and blowdown recovery equipment in the 

final definition because this equipment is also integral to the 

overall cyclical operation of the process unit. The definition 

of “delayed coking unit” has been amended in the final rule to 

read as follows:

Delayed coking unit means a refinery process unit in which 

high molecular weight petroleum derivatives are thermally 

cracked and petroleum coke is produced in a series of 

closed, batch system reactors. A delayed coking unit

includes but is not limited to all of the coke drums 

associated with a single fractionator; the fractionator, 

including bottoms receiver and overhead condenser; the coke 

drum cutting water and quench system, including the jet 

pump and coker quench water tank; process piping and 

associated equipment such as pumps, valves and connectors; 

and the coke drum blowdown recovery compressor system.

Comment: One commenter stated that 40 CFR part 63, subpart 

LLLLL indicates at 40 CFR 63.8681(e) that 40 CFR part 60, 

subpart J does not apply for asphalt blowing stills subject to 

subpart LLLLL, and the commenter requested similar clarification 

for subpart Ja by exempting this process in 40 CFR 60.100a.

Response: We reviewed the requirement in 40 CFR part 63, 

subpart LLLLL. Due to the O2 content of this process gas, we 

agree that it is not suitable for recovery as fuel gas and 

subsequent amine treatment; therefore, it is not BSER for 

combustion controls used on asphalt blowing stills to meet the 
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H2S concentration limits (or alternative SO2 emissions limits). 

We reviewed 40 CFR 60.100a, but we feel a blanket exemption from 

subpart Ja is not necessary. Instead, we have included an 

exemption within the definition of fuel gas similar to the 

exemptions included for combustion controls on vapors collected 

and combusted from wastewater treatment and marine vessel 

loading operations. Specifically, we amended the definition of 

fuel gas in 40 CFR 60.101a to clarify that fuel gas does not 

include vapors that are collected and combusted to control 

emissions from asphalt processing units (i.e., asphalt blowing 

stills).

Comment: One commenter recommended that the exclusion from 

the definition of “fuel gas” be extended to vapors “from marine 

vessel loading operations or waste management units that are 

collected and combusted” without any reference to a federal 

requirement. At a minimum, the commenter stated that marine 

benzene loading under 40 CFR part 61, subpart BB; the wastewater 

provisions of 40 CFR part 63, subpart G; remediation efforts 

regulated under Resource Conservation and Recovery Act (RCRA) 

corrective action; and RCRA 7003 orders should be added to the 

exclusion. 

Response: We were originally concerned that removing the 

reference to a federal standard may inadvertently exempt the use 

of these vapors when used in process heaters or boilers. We 
Page 141 of 269

determined that it was not BSER to require thermal oxidizers 

used to comply with the cited federal standards to comply with 

the H2S concentration limits due to the typically remote location 

of the combustion sources (control devices) relative to refinery 

process units (see technical memorandum entitled “Fuel Gas 

Treatment of Marine Vessel Loading and Wastewater Treatment Unit

Off-gas” in Docket ID No. EPA-HQ-OAR-2007-0011). However, if 

these gases are currently routed to a fuel gas system or 

directly to a process heater or boiler, treatment of the fuel 

gas to meet the SO2 emissions limits or the H2S concentration

limits is expected to be economically viable. Additionally, 

these gases are expected to be only a small portion of the fuel 

gas combusted in these units, and the refinery has an option to 

over-treat the primary fuel gas so that gases from the 

wastewater treatment system or marine vessel loading operation 

can remain untreated while the fuel gas combustion device itself 

can comply with the SO2 emissions limits or the H2S concentration 

limits based on the mixture of fuels used in the device. 

In reviewing the rules suggested by the commenter, as well 

as those we originally listed, we noted that acceptable “control 

devices” or “combustion units” in these rules include process 

heaters and boilers. We did not intend to exclude vapors that 

are collected and routed to a process heater or boiler to be 

exempt from the definition of fuel gas. In other words, when 
Page 142 of 269

developing this exclusion, we specifically considered the 

combustion of these gases via a thermal oxidizer or flare 

currently located at the marine vessel loading or wastewater 

treatment location. These remote combustion devices were really 

the subject of the analysis, but we did not want to exclude 

these combustion units themselves because other fuel gas is 

often fed to these units to ensure adequate combustion of the 

vapors being controlled. It is clear from our rationale and the 

description of the exemption included in the preamble of the 

proposed rule that the exemption was intended “to exempt vapors 

that are collected and combusted in an air pollution control 

device installed to comply with” specific wastewater or marine 

vessel loading emissions standards. (72 FR 27180 and also at 

27183; emphasis added). Process heaters or boilers would not be 

“installed” to comply with these provisions, and it was not our 

intent to exclude vapors sent to these types of combustion 

units. However, the regulatory text is more ambiguous, and 

appears to exclude any vapors collected and combusted, 

regardless of where they are combusted. As such, we are 

amending this exclusion to better represent our original intent. 

Additionally, with the added clarity in the regulatory 

text, it seems appropriate to extend this exclusion to control 

devices used at these locations regardless of why the emission 

controls were installed. That is, while we originally 
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considered air pollution control devices that were mandated by 

EPA, we see no reason to discriminate against air pollution 

control devices that were installed voluntarily to reduce the 

emissions from these sources. Therefore, the amended definition 

of “fuel gas” in both subpart J and subpart Ja states that fuel 

gas “does not include vapors that are collected and combusted in 

a thermal oxidizer or flare installed to control emissions from 

wastewater treatment units, marine tank vessel loading 

operations, or asphalt processing units (i.e., asphalt blowing 

stills).” 

With respect to remediation efforts conducted under RCRA 

corrective actions, we are unwilling to grant such an exclusion 

from the definition of “fuel gas” in subpart Ja. First, we 

anticipate that most vapors from remediation efforts would be 

low in sulfur and, if so, the owner or operator could apply for 

the alternative monitoring methods provided in the rule. Also, 

although some remediation efforts may occur in remote locations, 

many of the remediation efforts are conducted in reasonable 

proximity to existing process units. Finally, the range of 

activities included in RCRA remediation efforts is broad, and we 

have little information regarding the number and types of RCRA 

remediation activities that are being conducted. The commenter 

provided no description of such activities, nor did they provide 
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a reasonable rationale as to why the vapors from these 

activities should be exempted.

V. Summary of Cost, Environmental, Energy, and Economic Impacts

A. What are the emission reduction and cost impacts for the 

final amendments?

The emission reduction and cost impacts presented in this 

section for flares are revised estimates for the impacts of the 

final requirements of 40 CFR part 60, subpart Ja for flares as 

amended by this action. The impacts are expressed as 

incremental differences between the impacts of petroleum 

refinery process units complying with the final amendments to 

subpart Ja and the current NSPS requirements of subpart J (i.e., 

baseline). The impacts are presented for petroleum refinery 

flares that commence construction, reconstruction, or 

modification over the next 5 years. We anticipate that there 

will be 150 affected flares over the next 5 years, or about one 

flare per refinery, and 80 percent of those will be modified or 

reconstructed. The values in Table 3 of this preamble include 

the costs for 150 flares to comply with the flare management 

plan, sulfur and flow monitoring requirements, and root cause 

and corrective action analyses. The cost and emissions 

reductions for the 150 flares to comply with the short-term H2S 

concentration of 162 ppmv are included in the baseline rather 

than the incremental impacts because this limit is unchanged 
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from the requirements in subpart J. For further detail on the 

methodology of these calculations, see “Documentation of Impact 

Estimates for Fuel Gas Combustion Device and Flare Regulatory 

Options for Amendments to the Petroleum Refinery NSPS” in Docket 

ID No. EPA-HQ-OAR-2007-0011.

We estimate that the final requirements for flares will 

reduce emissions of SO2 by 3,000 tons per year (tons/yr), NOX by

450 tons/yr, and VOC by 1,600 tons/yr from the baseline. The 

estimated annual cost, including annualized capital costs, is a 

cost savings of about $57 million (2006 dollars) due to the 

replacement of some natural gas purchases with recovered flare 

gas and the retention of intermediate and product streams due to 

a reduction in the number of malfunctions associated with

refinery process units and ancillary equipment connected to the 

flare. The overall cost-effectiveness is a cost savings of 

about $11,000 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 3 

of this preamble.
Page 146 of 269

Table 3. National Incremental Emission Reductions and Cost 

Impacts for Petroleum Refinery Flares Subject to Amended 

Standards Under 40 CFR part 60, subpart Ja (Fifth Year After 

Applicability Date)

Subpart Ja 

Requirements

Total 

capital 

cost 

($1,000)

Total 

annual

cost 

without 

credit

($1,000/ 

yr)

Natural 

gas 

offset/ 

product 

recovery 

credit 

($1,000)

Total 

annual

cost

($1,000/ 

yr)

Annual 

emission 

reductions 

(tons 

SO2/yr)

Annual 

emission 

reductions 

(tons 

NOX/yr)

Annual 

emission 

reductions 

(tons 

VOC/yr)

Cost 

effectiveness 

($/ton 

emissions

reduced)

Estimates 

from June 

2008 Final 

Rule

40,000 (7,000) 80 6 200 (23,000)

Revised 

Estimates 

for 

Amendments 

190,000 40,000 (97,000) (57,000) 3,000 450 1,600 (11,000)

The cost, environmental, and economic impacts for the final 

amendments to 40 CFR part 60, subpart Ja for process heaters are 

not expected to be different than those reported for the final 

June 2008 standards. We expect owners and operators to install 

the same technology to meet these final amendments that we 

anticipated they would install to meet the June 2008 final 

subpart Ja requirements (i.e., ultra-low NOX burners). We did 

revise our emission estimates based on the type of process 

heater, creating separate impacts for forced draft process 

heaters and natural draft process heaters. Dividing process 

heaters into separate subcategories based on the draft type

required us to develop new distributions of baseline emissions 

for each type of process heater. The baseline emission 

estimates for natural draft process heaters are slightly lower
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than those developed for the existing subpart Ja requirements 

(per affected process heater), but the average emission 

reduction achieved by ultra-low NOX burners was adjusted to 80 

percent (rather than 75 percent used for generic process 

heaters). For forced draft process heaters, the baseline (i.e., 

uncontrolled) emissions rate for forced draft process heaters 

was revised slightly upward based on the available emissions 

data. Due to these differences, the mix of controls needed to 

meet a 40 ppmv emissions limit was no longer cost-effective for 

forced draft process heaters, but the emission reductions 

associated with process heaters complying with the 60 ppmv 

standard were higher than those previously estimated for generic

process heaters. Thus, the creation of new subcategories of 

process heaters with different emissions limits for each 

subcategory did not impact the control or compliance methods 

used by the facilities (i.e., BSER in all cases was based on the 

performance of advanced combustion monitoring controls in 

conjunction with ultra-low NOX burners) and did not change the 

estimated compliance costs. As we do not have adequate data 

regarding the prevalence of natural draft process heaters 

versus forced draft process heaters that will become subject to 

the rule, we used the emission reductions estimated for the two 

different types of process heaters as a means to bound the range 

of anticipated NOX emission reductions to be from 7,100 to 8,600 
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tons per year in the fifth year after promulgation (see “Revised 

NOX Impact Estimates for Process Heaters” in Docket ID No. EPAHQ-OAR-2007-0011). We estimated the emission reductions to be 

7,500 tons per year for the June 2008 final standards, which 

falls well within the anticipated range of emissions reductions 

for the standards we are finalizing today. Given the 

uncertainty in the emissions estimates as well as the 

uncertainty in the relative number of natural draft process 

heaters versus forced draft process heaters, we concluded that 

the impacts previously developed for subpart Ja accurately 

represent the impacts for process heaters in today’s final 

amendments. 

We note that in the preamble to the June 2008 final 

standards, we estimated costs and emissions reductions for 30 

fuel gas combustion devices, but we subsequently determined that 

those estimates did not fully account for the number of affected 

flares (which, at the time, were considered a subset of fuel gas 

combustion devices). Therefore, in the preamble to the December 

2008 proposed amendments, we presented revised emission 

reduction and cost estimates for affected fuel gas combustion 

devices, including 150 affected flares at refineries. Because 

these final amendments consider flares to be a separate affected 

source, the emission reductions and costs for fuel gas 

combustion devices are not affected by these final amendments 
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and are not included in this preamble. Rather, the final 

emission reduction and cost estimates for fuel gas combustion 

devices are very close to the impacts presented in the June 2008 

final rule; the details of the analysis and the final impacts 

are presented in “Documentation of Impact Estimates for Fuel Gas 

Combustion Device and Flare Regulatory Options for Amendments to 

the Petroleum Refinery NSPS” in Docket ID No. EPA-HQ-OAR-2007-

0011. 

The final amendments to 40 CFR part 60, subpart J are 

technical corrections or clarifications to the existing rule and 

should have no negative emissions impacts.

B. What are the economic impacts?

Our economic impact analysis estimated the impacts on 

product price and output that the final regulatory action would 

have on five petroleum products — motor gasoline, jet fuel, 

distillate fuel oil, residual fuel oil, and liquefied petroleum 

gases. The overall total annual social costs, which reflect 

changes in consumer and producer behavior in response to the 

compliance costs, are a savings of $57 million ($2006) in the 

fifth year after proposal, or almost identical to the compliance 

costs incurred by affected producers of these petroleum 

products. With the total annual social costs estimated to be a 

savings since they are negative, there is no adverse economic 
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impact associated with this regulatory action for there is no 

increase in product price or decrease in output expected.

For more information, please refer to the Regulatory Impact 

Analysis (RIA) that is in the docket for this final rule.

C. What are the benefits?

We estimate the monetized benefits of this final regulatory 

action to be $87 million to $210 million (2006$, 3 percent 

discount rate) in the fifth year (2016). The benefits at a 7 

percent discount rate are $79 million to $190 million (2006$). 

Using alternate relationships between PM2.5 and premature 

mortality supplied by experts, higher and lower benefits 

estimates are plausible, but most of the expert-based estimates 

fall between these two estimates.11 A summary of the monetized 

benefits estimates at discount rates of 3 percent and 7 percent 

is in Table 4 of this preamble.

 

11 Roman et al, 2008. Expert Judgment Assessment of the 

Mortality Impact of Changes in Ambient Fine Particulate Matter 

in the U.S. Environ. Sci. Technol., 42, 7, 2268 – 2274.
Page 151 of 269

Table 4. Summary of the Monetized PM2.5 Co-Benefits for Amended 

Petroleum Refineries Standards (millions of 2006$)a

Pollutant

Emission 

reductions 

(tons)

Total monetized 

benefits

(3% Discount)

Total monetized 

benefits

(7% Discount)

PM2.5 Precursors

SO2 3,000 $83 to $200 $75 to $180

NOX 450 $2.0 to $5.0 $1.9 to $4.5

VOC 1,600 $1.8 to $4.5 $1.7 to $4.0

Total: $87 to $210 $79 to $190

a All estimates are for the analysis year (2016) and are rounded 

to two significant figures so numbers may not sum across rows. 

PM2.5 precursors reflect emission reductions of SO2, NOX, and VOC. 

All fine particles are assumed to have equivalent health

effects, but the benefit-per-ton estimates vary between 

precursors because each ton of precursor reduced has a different 

propensity to form PM2.5.

These co-benefits estimates represent the total monetized 

human health benefits for populations exposed to less PM2.5 in 

2014 from controls installed to reduce air pollutants in order 

to meet these standards. These estimates are calculated as the 

sum of the monetized value of avoided premature mortality and 

morbidity associated with reducing a ton of PM2.5 and PM2.5

precursor emissions. To estimate the human health co-benefits 

derived from reducing PM2.5 precursor emissions, we used the 

general approach and methodology laid out in Fann, Fulcher, and 

Hubbell. (2009).12

 

12 Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. “The influence 

of location, source, and emission type in estimates of the human 

health benefits of reducing a ton of air pollution.” Air Qual 

Atmos Health (2009) 2:169–176.
Page 152 of 269

To generate the benefit-per-ton estimates, we used a model 

to convert emissions of PM2.5 precursors into changes in ambient 

PM2.5 levels and another model to estimate the changes in human 

health associated with that change in air quality. Finally, the 

monetized health benefits were divided by the emission 

reductions to create the benefit-per-ton estimates. These 

models assume that all fine particles, regardless of their 

chemical composition, are equally potent in causing premature 

mortality because there is no clear scientific evidence that 

would support the development of differential effects estimates 

by particle type. The primary PM2.5 precursors affected by this 

rule are SO2, NOX, and VOC. Even though we assume that all fine 

particles have equivalent health effects, the benefit-per-ton 

estimates vary between precursors because each ton of precursor 

reduced has a different propensity to form PM2.5. For example, 

SO2 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.

For context, it is important to note that the magnitude of 

the PM benefits is largely driven by the concentration response 

function for premature mortality. Experts have advised EPA to 

consider a variety of assumptions, including estimates based 

both on empirical (epidemiological) studies and judgments 

elicited from scientific experts, to characterize the 
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uncertainty in the relationship between PM2.5 concentrations and 

premature mortality. For this final rule, we cite two key 

empirical studies, one based on the American Cancer Society 

cohort study13 and the extended Six Cities cohort study.14 In the 

RIA for this final rule, which is available in the docket, we 

also include benefits estimates derived from expert judgments 

and other assumptions.

EPA strives to use the best available science to support 

our benefits analyses. We recognize that interpretation of the 

science regarding air pollution and health is dynamic and 

evolving. After reviewing the scientific literature, we have 

determined that the no-threshold model is the most appropriate 

model for assessing the mortality benefits associated with 

reducing PM2.5 exposure. Consistent with this finding, we have 

conformed the previous threshold sensitivity analysis to the 

current state of the PM science by incorporating a new “Lowest 

Measured Level” (LML) assessment. While an LML assessment 

provides some insight into the level of uncertainty in the 

estimated PM mortality benefits, EPA does not view the LML as a 

 

13 Pope et al, 2002. “Lung Cancer, Cardiopulmonary Mortality, 

and Long-term Exposure to Fine Particulate Air Pollution.” 

Journal of the American Medical Association 287:1132-1141

14 Laden et al, 2006. “Reduction in Fine Particulate Air 

Pollution and Mortality.” American Journal of Respiratory and 

Critical Care Medicine. 173: 667-672
Page 154 of 269

threshold and continues to quantify PM-related mortality impacts 

using a full range of modeled air quality concentrations.

Most of the estimated PM-related benefits in this rule 

would accrue to populations exposed to higher levels of PM2.5. 

Using the Pope et al. (2002) study, 85 percent of the population 

is exposed to annual mean PM2.5 levels at or above the LML of 7.5 

μg/m3. Using the Laden et al. (2006) study, 40 percent of the 

population is exposed above the LML of 10 μg/m3. It is important 

to emphasize that we have high confidence in PM2.5-related 

effects down to the lowest LML of the major cohort studies. 

This fact is important, because as we estimate PM-related 

mortality among populations exposed to levels of PM2.5 that are 

successively lower, our confidence in the results diminishes. 

However, our analysis shows that the great majority of the 

impacts occur at higher exposures.

This analysis does not include the type of detailed 

uncertainty assessment found in the 2006 PM2.5 National Ambient 

Air Quality Standard (NAAQS) RIA because we lack the necessary 

air quality input and monitoring data to run the benefits model. 

In addition, we have not conducted air quality modeling for this 

rule. The 2006 PM2.5 NAAQS benefits analysis15 provides an 

 

15 U.S. Environmental Protection Agency, 2006. Final Regulatory 

Impact Analysis: PM2.5 NAAQS. Prepared by Office of Air and 

Radiation. October. Available on the Internet at 

http://www.epa.gov/ttn/ecas/ria.html.
Page 155 of 269

indication of the sensitivity of our results to various 

assumptions.

It should be noted that the monetized co-benefits estimates 

provided above do not include benefits from several important 

benefit categories, including improved visibility, reduced 

aquatic and terrestrial acidification, and reduced ozone 

concentrations. Although we do not have sufficient information 

or modeling available to provide monetized estimates for this 

rulemaking, we include a qualitative assessment of the health 

effects of these air pollutants in the RIA for this final rule, 

which is available in the docket.

The costs of this rulemaking are estimated to be a cost 

savings of $57 million (2006$) in the fifth year, and the cobenefits are estimated at $87 million to $210 million (2006$, 3 

percent discount rate) for that same year. The co-benefits at a 

7 percent discount rate are $79 million to $190 million (2006$). 

Thus, net benefits of this rulemaking are estimated at $140

million to $270 million (2006$, 3 percent discount rate) and 

$140 million to $250 million (2006$, 7 percent discount rate). 

Using alternate relationships between PM2.5 and premature 

mortality supplied by experts, higher and lower benefits 

estimates are plausible, but most of the expert-based estimates 

fall between the two estimates we present above. EPA believes 

that the co-benefits are likely to exceed the costs by a 
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significant margin even when taking into account the 

uncertainties in the cost and benefit estimates.

For more information on the benefits analysis, please refer 

to the RIA for this rulemaking, which 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 a Regulatory Impact Analysis (RIA) of the 

potential costs and benefits associated with this action.

When estimating the PM2.5- and ozone-related human health 

benefits and compliance costs in Table 5 below, EPA applied 

methods and assumptions consistent with the state-of-the-science 

for human health impact assessment, economics and air quality 

analysis. EPA applied its best professional judgment in 

performing this analysis and believes that these estimates 

provide a reasonable indication of the expected benefits and 
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costs to the nation of this rule. The RIA available in the 

docket describes in detail the empirical basis for EPA's 

assumptions and characterizes the various sources of 

uncertainties affecting the estimates below. 

When characterizing uncertainty in the PM-mortality 

relationship, EPA has historically presented a sensitivity 

analysis applying alternate assumed thresholds in the PM 

concentration-response relationship. In its synthesis of the 

current state of the PM science, EPA’s 2009 Integrated Science 

Assessment (ISA) for Particulate Matter concluded that a nothreshold log-linear model most adequately portrays the PMmortality concentration-response relationship. In the RIA 

accompanying this rule, rather than segmenting out impacts 

predicted to be associated levels above and below a ‘bright 

line’ threshold, EPA includes a “lowest-measured-level (LML)” 

that illustrates the increasing uncertainty that characterizes 

exposure attributed to levels of PM2.5 below the LML for each 

study. Figures provided in the RIA show the distribution of 

baseline exposure to PM2.5, as well as the lowest air quality 

levels measured in each of the epidemiology cohort studies. 

This information provides a context for considering the likely 

portion of PM-related mortality benefits occurring above or 

below the LML of each study; in general, our confidence in the 

size of the estimated reduction PM2.5-related premature mortality 
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diminishes as baseline concentrations of PM2.5 are lowered. 

Using the Pope et al. (2002) study, 85 percent of the population 

is exposed to annual mean PM2.5 levels at or above the LML of 7.5 

μg/m3. Using the Laden et al. (2006) study, 40 percent of the 

population is exposed above the LML of 10 μg/m3. While the LML 

analysis provides some insight into the level of uncertainty in 

the estimated PM mortality benefits, EPA does not view the LML

as a threshold and continues to quantify PM-related mortality 

impacts using a full range of modeled air quality 

concentrations.

A summary of the monetized benefits, social costs, and net 

benefits for the proposed option, as well as a less stringent 

option and more stringent option, at discount rates of 3 percent 

and 7 percent is in Table 5 of this preamble. 

Table 5. Summary of the Monetized Co-Benefits, Social Costs, 

and Net benefits for the Final Petroleum Refineries NSPS in 2014 

(millions of 2006$)a

3 Percent Discount 

Rate

7 Percent Discount 

Rate

Total Monetized 

Benefitsb $87 to $210 $79 to $190

Total Social Costsc -$57 -$57

Net Benefits $140 to $270 $140 to $250

Non-monetized Benefits Health effects from NO2 exposure

Ecosystem effects 

Visibility impairment 

a All estimates are for the implementation year (2014) and are 

rounded to two significant figures.

b The total monetized co-benefits reflect the human health cobenefits associated with reducing exposure to PM2.5 through 
Page 159 of 269

reductions of PM2.5 precursors such as NOX and SO2. It is 

important to note that the monetized co-benefits include many 

but not all health effects associated with PM2.5 exposure. It is 

important to note that the monetized benefits include many but 

not all health effects associated with PM2.5 exposure. Benefits 

are shown as a range from Pope et al. (2002) to Laden et al. 

(2006). These models assume that all fine particles, regardless 

of their chemical composition, are equally potent in causing 

premature mortality because there is no clear scientific 

evidence that would support the development of differential 

effects estimates by particle type.

c The annual cost savings serve as a proxy for the annual social 

costs of this rule.

For more information on the benefits analysis, please refer 

to the RIA for this rulemaking, which is available in the 

docket.

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 are 

clarifications and technical corrections that do not affect the 

estimated burden of 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 contained 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. The OMB control numbers 

for EPA’s regulations are listed in 40 CFR part 9.
Page 160 of 269

The OMB has approved the information collection 

requirements in the amendments to the Standards of Performance 

for Petroleum Refineries for Which Construction, Reconstruction, 

or Modification Commenced After May 14, 2007 (40 CFR part 60, 

subpart Ja) under the provisions of the Paperwork Reduction Act, 

44 U.S.C. 3501, et seq., and has assigned OMB control number 

2060–0602.

The information requirements in these final amendments add 

new compliance options, provide more time to comply with the 

requirements for flares, clarify the flare management plan 

requirements, and clarify the flare modification provision. 

Overall, these changes are expected to reduce the costs 

associated with testing, monitoring, recording, and reporting, 

so they will not result in any increase in burden for the 

affected facilities for which EPA previously estimated the 

burden. However, EPA has revised the number of flares expected 

to become subject to the rule over the first 3 years of the ICR. 

Therefore, the annual burden was estimated for the additional 

affected facilities. The total burden for 40 CFR part 60, 

subpart Ja can be estimated by summing the previously approved 

annual burden for OMB control number 2060–0602 (5,340 laborhours per year at a cost of $481,249 per year, annualized 

capital costs of $2,052,000 per year, and operation and 
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maintenance costs of $1,117,440 per year) and the annual burden 

for this ICR as described below.

The annual burden for this information collection averaged 

over the first 3 years of this ICR is estimated to total 21,264

labor-hours per year at a cost of $1,916,344 per year. The 

annualized capital costs are estimated at $6,192,000 per year 

and operation and maintenance costs are estimated at $4,800,000 

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 40 CFR part 60, 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. EPA 

is amending the table in 40 CFR part 9 of currently approved ICR 

control numbers for various regulations to list regulatory 

citations for the information requirements contained in this 

final rule. This amendment updates the table to list the 
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information collection requirements being promulgated today as 

amendments to the NSPS for petroleum refineries.

EPA will continue to present OMB control numbers in a 

consolidated table format to be codified in 40 CFR part 9 of the 

Agency’s regulations and in each CFR volume containing EPA 

regulations. The table lists the section numbers with reporting 

and recordkeeping requirements and the current OMB control 

numbers. This listing of the OMB control numbers and their 

subsequent codification in the CFR satisfy the requirements of 

the Paperwork Reduction Act (44 U.S.C. 3501, et seq.) and OMB’s 

implementing regulations at 5 CFR part 1320.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act 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 would not have a significant 

economic impact on a substantial number of small entities. 

Small entities include small businesses, small organizations, 

and small governmental jurisdictions.

For purposes of assessing the impact of today’s final 

action on small entities, small entity is defined as: (1) a 

small business whose parent company has no more than 1,500 

employees, that is primarily engaged in refining crude petroleum 
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into refined petroleum as defined by NAICS code 32411 (as 

defined by Small Business Administration 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 impacts of these final 

amendments on small entities, I certify that this action will 

not have a significant economic impact on a substantial number 

of small entities. In determining whether a rule has a 

significant economic impact on a substantial number of small 

entities, the impact of concern is any significant adverse

economic impact on small entities, since the primary purpose of 

the regulatory flexibility analyses is to identify and address 

regulatory alternatives “which minimize any significant economic 

impact of the rule on small entities.” 5 U.S.C. 603 and 604. 

Thus, an agency may certify that a rule will not have a 

significant economic impact on a substantial number of small 

entities if the rule relieves regulatory burden or otherwise has 

a positive economic effect on all of the small entities subject 

to the rule.

Our analyses indicate that the final amendments will not 

increase the costs associated with the final rule and may 
Page 164 of 269

decrease costs. Therefore, no adverse economic impacts are 

expected for any small or large entity.

D. Unfunded Mandates Reform Act

This rule contains no Federal mandates 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. The costs of the final amendments would not 

increase costs associated with the final rule. Thus, this rule 

is not subject to the requirements of sections 202 or 205 of the 

Unfunded Mandates Reform Act of 1995 (UMRA).

This rule is also not subject to the requirements of 

section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments. The final amendments contain no requirements that 

apply to such governments, and impose no obligations upon them.

E. Executive Order 13132: Federalism

This 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. This action does not modify existing responsibilities or 

create new responsibilities among EPA Regional offices, States, 
Page 165 of 269

or local enforcement agencies. Thus, Executive Order 13132 does 

not apply to this action.

In the spirit of Executive Order 13132, and consistent with 

EPA policy to promote communications between EPA and State and 

local governments, EPA specifically solicited comment on the 

proposed action from State and local officials.

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

This action does not have tribal implications, as specified 

in Executive Order 13175 (65 FR 67249, November 9, 2000). The 

final amendments impose no requirements on tribal governments. 

Thus, Executive Order 13175 does not apply to this 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
Page 166 of 269

This action is not a “significant energy action” as defined 

in Executive Order 13211 (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. The final amendments 

would not increase the level of energy consumption required for 

the final rule and may decrease energy requirements.

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, 12(d) 

(15 U.S.C. 272 note) directs EPA to use voluntary consensus 

standards (VCS) in its regulatory activities, unless to do so 

would be inconsistent with applicable law or otherwise 

impractical. VCS 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 following VCS for determining the higher

heating value of fuel fed to process heaters: ASTM D240-02 

(Reapproved 2007), “Standard Test Method for Heat of Combustion 

of Liquid Hydrocarbon Fuels by Bomb Calorimeter”; ASTM D1826-94 

(Reapproved 2003), “Standard Test Method for Calorific (Heating) 

Value of Gases in Natural Gas Range by Continuous Recording 
Page 167 of 269

Calorimeter”; ASTM D3588-98 (Reapproved 2003), “Standard 

Practice for Calculating Heat Value, Compressibility Factor, and 

Relative Density of Gaseous Fuels”; ASTM D4809-06, “Standard 

Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels 

by Bomb Calorimeter (Precision Method)”; ASTM D4891-89 

(Reapproved 2006), “Standard Test Method for Heating Value of 

Gases in Natural Gas Range by Stoichiometric Combustion”; ASTM 

D1945-03, “Standard Method for Analysis of Natural Gas by Gas 

Chromatography”; and ASTM D1946-90 (Reapproved 2006), “Standard 

Method for Analysis of Reformed Gas by Gas Chromatography.”

EPA has decided to use the following VCS as acceptable 

alternatives to Methods 2, 2A, 2B, 2C, or 2D for conducting 

relative accuracy evaluations of fuel gas flow monitors: 

American Society of Mechanical Engineers (ASME) MFC-3M-2004, 

“Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and 

Venturi”; ANSI/ASME MFC-4M-1986 (Reaffirmed 2008), “Measurement 

of Gas Flow by Turbine Meters”; ASME MFC-6M-1998 (Reaffirmed 

2005), “Measurement of Fluid Flow in Pipes Using Vortex 

Flowmeters”; ASME/ANSI MFC-7M-1987 (Reaffirmed 2006), 

“Measurement of Gas Flow by Means of Critical Flow Venturi 

Nozzles”; ASME MFC-11M-2006, “Measurement of Fluid Flow by Means 

of Coriolis Mass Flowmeters”; ASME MFC-14M-2003, “Measurement of 

Fluid Flow Using Small Bore Precision Orifice Meters”; and ASME 
Page 168 of 269

MFC-18M-2001, “Measurement of Fluid Flow Using Variable Area 

Meters.”

EPA has also decided to use the following VCS as acceptable 

alternatives to Methods 2, 2A, 2B, 2C, or 2D for conducting 

relative accuracy evaluations of fuel oil flow monitors: 

ANSI/ASME MFC-5M-1985 (Reaffirmed 2006), “Measurement of Liquid 

Flow in Closed Conduits Using Transit-Time Ultrasonic 

Flowmeters”; ASME/ANSI MFC-9M-1988 (Reaffirmed 2006), 

“Measurement of Liquid Flow in Closed Conduits by Weighing 

Method”; ASME MFC-16-2007, “Measurement of Liquid Flow in Closed 

Conduits with Electromagnetic Flowmeters”; ASME MFC-22-2007, 

“Measurement of Liquid by Turbine Flowmeters”; and ISO 8316: 

“Measurement of Liquid Flow in Closed Conduits — Method by 

Collection of the Liquid in a Volumetric Tank (1987–10–01) —

First Edition.”

EPA has decided to use the following VCS as acceptable 

alternatives to EPA Method 15A and 16A for conducting relative 

accuracy evaluations of monitors for reduced sulfur compounds, 

total sulfur compounds, and H2S: ANSI/ASME PTC 19.10-1981, “Flue 

and Exhaust Gas Analyses.” EPA has decided to use the following 

VCS as acceptable alternatives to EPA Method 16A for analysis of 

total sulfur samples: ASTM D4468-85 (Reapproved 2006), 

“Standard Test Method for Total Sulfur in Gaseous Fuels by 

Hydrogenolysis and Rateometric Colorimetry”; and ASTM D5504-08, 
Page 169 of 269

“Standard Test Method for Determination of Sulfur Compounds in 

Natural Gas and Gaseous Fuels by Gas Chromatography and 

Chemiluminescence.” 

EPA has decided to use the following VCS as acceptable 

alternatives to Method 18 for relative accuracy evaluations of

gas composition analyzers for gas-fired process heaters: ASTM 

D1945-03, “Standard Method for Analysis of Natural Gas by Gas 

Chromatography”; ASTM D1946-90 (Reapproved 2006), “Standard 

Method for Analysis of Reformed Gas by Gas Chromatography”; ASTM 

UOP539-97, “Refinery Gas Analysis by Gas Chromatography”; and 

ASTM D6420-99 (Reapproved 2004), ”Standard Test Method for 

Determination of Gaseous Organic Compounds by Direct Interface 

Gas Chromatography-Mass Spectrometry.” However, ASTM D6420-99 

is a suitable alternative to Method 18 only where:

(1) the target compound(s) are those listed in Section 1.1 

of ASTM D6420-99, and 

(2) the target concentration is between 150 parts per 

billion by volume and 100 ppmv. 

For target compound(s) not listed in Section 1.1 of ASTM 

D6420-99, but potentially detected by mass spectrometry, the 

regulation specifies that the additional system continuing 

calibration check after each run, as detailed in Section 10.5.3 

of the ASTM method, must be followed, met, documented, and 

submitted with the data report even if there is no moisture 
Page 170 of 269

condenser used or the compound is not considered water soluble. 

For target compound(s) not listed in Section 1.1 of ASTM D6420-

99, and not amenable to detection by mass spectrometry, ASTM 

D6420-99 does not apply.

These above-listed VCS are incorporated by reference (see 

§60.17).

EPA has also decided to use American Gas Association 

“Report No. 3: Orifice Metering for Natural Gas and Other 

Related Hydrocarbon Fluids, Part 1: General Equations and 

Uncertainty Guidelines (1990),” American Gas Association “Report 

No. 3: Orifice Metering for Natural Gas and Other Related 

Hydrocarbon Fluids, Part 2: Specification and Installation 

Requirements (2000)”, American Gas Association “Report No. 11: 

Measurement of Natural Gas by Coriolis Meter (2003),” American 

Gas Association “Transmission Measurement Committee Report No. 

7, Measurement of Natural Gas by Turbine Meters (Revised 

February 2006),” and American Petroleum Institute’s “Manual of 

Petroleum Measurement Standards, Chapter 22-Testing Protocol, 

Section 2-Differential Pressure Flow Measurement Devices, First

Edition, August 2005,” for conducting relative accuracy 

evaluations of fuel gas flow monitors; Gas Processors

Association (GPA) Standard 2261-00, “Analysis for Natural Gas 

and Similar Gaseous Mixtures by Gas Chromatography” (2000), for 

relative accuracy evaluations of gas composition analyzers for 
Page 171 of 269

gas-fired process heaters; and GPA 2172-09, “Calculation of 

Gross Heating Value, Relative Density, Compressibility and 

Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures 

for Custody Transfer,” for determining the higher heating value 

of fuel fed to process heaters. These methods are also 

incorporated by reference (see §60.17).

While the Agency has identified five 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 be 

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 
Page 172 of 269

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 this final rule will not have 

disproportionately high and adverse human health or 

environmental effects on minority or low-income populations 

because it does not affect the level of protection provided to 

human health or the environment. The final amendments are 

either clarifications or compliance alternatives which will 

neither increase or decrease environmental protection.

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. EPA will 

submit a report containing these final rules and other required 

information to the United States Senate, the United States 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 
Page 173 of 269

it is published in the Federal Register. This action is a 

“major rule” as defined by 5 U.S.C. 804(2). This final rule 

will be effective on [INSERT DATE 60 DAYS FROM DATE OF 

PUBLICATION IN THE FEDERAL REGISTER].
Final Amendments to Standards of Performance for Petroleum 

Refineries--Page 174 of 269

List of Subjects in 40 CFR Parts 9 and 60

Environmental protection, Administrative practice and 

procedure, Air pollution control, Incorporations by reference, 

Intergovernmental relations, Reporting and recordkeeping 

requirements.

 

Dated:

Lisa P. Jackson,

Administrator.
Page 175 of 269

For the reasons stated in the preamble, title 40, chapter 

I, of the Code of Federal Regulations is amended as follows:

PART 9--[AMENDED]

1. The authority citation for part 9 continues to read as 

follows:

Authority: 7 U.S.C. 135, et seq., 136–136y; 15 U.S.C. 

2001, 2003, 2005, 2006, 2601–2671; 21 U.S.C. 331j, 346a, 348; 31 

U.S.C. 9701; 33 U.S.C. 1251, et seq., 1311, 1313d, 1314, 1318, 

1321, 1326, 1330, 1342, 1344, 1345(d) and (e), 1361; E.O. 11735, 

38 FR 21243, 3 CFR, 1971–1975 Comp. p. 973; 42 U.S.C. 241, 242b, 

243, 246, 300f, 300g, 300g–1, 300g–2, 300g–3, 300g–4, 300g–5, 

300g–6, 300j–1, 300j–2, 300j–3, 300j–4, 300j–9, 1857, et seq., 

6901–6992k, 7401–7671q, 7542, 9601–9657, 11023, 11048.

2. The table in Section 9.1 is amended by adding an entry 

in numerical order for 60.103a–60.108a under the heading 

“Standards of Performance for New Stationary Sources” to read as 

follows:

§9.1 OMB Approvals under the Paperwork Reduction Act.

* * * * *

40 CFR citation OMB control No.

* * * * *

Standards of Performance for New Stationary Sources1

* * * * *

60.103a–60.108a 2060–0602

* * * * *

1 The ICRs referenced in this section of the table encompass the 

applicable general provisions contained in 40 CFR part 60, 

subpart A, which are not independent information collection 

requirements.

* * * * *

PART 60--[AMENDED]
Page 176 of 269

3. The authority citation for part 60 continues to read as 

follows:

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

Subpart A--[AMENDED]

4. Section 60.17 is amended by:

a. Revising paragraphs (a)(68) and (a)(84);

b. Adding paragraphs (a)(93) through (a)(101);

c. Adding paragraph (c)(2);

d. Revising paragraph (h)(4) and adding paragraphs (h)(5) 

through (h)(15);

e. Revising paragraph (m)(2) and adding paragraph (m)(3); 

and

f. Adding paragraphs (o) and (p) to read as follows:

§60.17 Incorporations by reference.

* * * * *

(a) * * *

(68) ASTM D4468-85 (Reapproved 2006), Standard Test Method 

for Total Sulfur in Gaseous Fuels by Hydrogenolysis and 

Rateometric Colorimetry, IBR approved for §§60.107a(e)(2)(v), 

60.335(b)(10)(ii), and 60.4415(a)(1)(ii).

* * * * *

(84) ASTM D6420–99 (Reapproved 2004), Standard Test Method 

for Determination of Gaseous Organic Compounds by Direct 

Interface Gas Chromatography-Mass Spectrometry, IBR approved for 
Page 177 of 269

§60.107a(d)(4)(iv) of subpart Ja and table 2 of subpart JJJJ of 

this part.

* * * * *

(93) ASTM D240-02 (Reapproved 2007), Standard Test Method 

for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb 

Calorimeter, IBR approved for §60.107a(d)(7)(i).

(94) ASTM D1826-94 (Reapproved 2003), Standard Test Method 

for Calorific (Heating) Value of Gases in Natural Gas Range by 

Continuous Recording Calorimeter, IBR approved for 

§60.107a(d)(7)(ii).

(95) ASTM D1945–03, Standard Method for Analysis of 

Natural Gas by Gas Chromatography, IBR approved for 

§§60.107a(d)(4)(ii) and 60.107a(d)(7)(iii).

(96) ASTM D1946–90 (Reapproved 2006), Standard Method for 

Analysis of Reformed Gas by Gas Chromatography, IBR approved for 

§§60.107a(d)(4)(iii) and 60.107a(d)(7)(iv).

(97) ASTM D3588-98 (Reapproved 2003), Standard Practice 

for Calculating Heat Value, Compressibility Factor, and Relative 

Density of Gaseous Fuels, IBR approved for §60.107a(d)(7)(v).

(98) ASTM D4809-06, Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter 

(Precision Method), IBR approved for §60.107a(d)(7)(vi).
Page 178 of 269

(99) ASTM D4891-89 (Reapproved 2006), Standard Test Method 

for Heating Value of Gases in Natural Gas Range by 

Stoichiometric Combustion, IBR approved for §60.107a(d)(7)(vii).

(100) ASTM D5504-08, Standard Test Method for 

Determination of Sulfur Compounds in Natural Gas and Gaseous 

Fuels by Gas Chromatography and Chemiluminescence, IBR approved 

for §60.107a(e)(2)(v). 

(101) ASTM UOP539-97, Refinery Gas Analysis by Gas 

Chromatography, IBR approved for §60.107a(d)(4)(vi).

* * * * *

(c) * * *

(2) Manual of Petroleum Measurement Standards, Chapter 22-

Testing Protocol, Section 2-Differential Pressure Flow 

Measurement Devices, First Edition, August 2005, IBR approved 

for §60.107a(d)(5)(xiii) of subpart Ja of this part.

* * * * *

(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), 
Page 179 of 269

(a)(2)(ii), (c)(2), (c)(4), (e)(1)(iii), and (e)(2)(ii) 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.

(5) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi, IBR approved for 

§60.107a(d)(5)(ii) of subpart Ja of this part.

(6) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008), Measurement 

of Gas Flow by Turbine Meters, IBR approved for 

§60.107a(d)(5)(iii) of subpart Ja of this part. 

(7) ANSI/ASME-MFC-5M-1985 (Reaffirmed 2006), Measurement 

of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic 

Flowmeters, IBR approved for §60.107a(d)(6)(ii) of subpart Ja of 

this part. 

(8) ASME MFC-6M-1998 (Reaffirmed 2005), Measurement of 

Fluid Flow in Pipes Using Vortex Flowmeters, IBR approved for 

§60.107a(d)(5)(iv) of subpart Ja of this part. 

(9) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006), Measurement 

of Gas Flow by Means of Critical Flow Venturi Nozzles, IBR 

approved for §60.107a(d)(5)(v) of subpart Ja of this part.

(10) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006), Measurement 

of Liquid Flow in Closed Conduits by Weighing Method, IBR 

approved for §60.107a(d)(6)(iii) of subpart Ja of this part.
Page 180 of 269

(11) ASME MFC-11M-2006, Measurement of Fluid Flow by Means 

of Coriolis Mass Flowmeters, IBR approved for §60.107a(d)(5)(vi) 

of subpart Ja of this part.

(12) ASME MFC-14M-2003, Measurement of Fluid Flow Using 

Small Bore Precision Orifice Meters, IBR approved for 

§60.107a(d)(5)(vii) of subpart Ja of this part.

(13) ASME MFC-16-2007, Measurement of Liquid Flow in 

Closed Conduits with Electromagnetic Flowmeters, IBR approved

for §60.107a(d)(6)(iv) of subpart Ja of this part.

(14) ASME MFC-18M-2001, Measurement of Fluid Flow Using 

Variable Area Meters, IBR approved for §60.107a(d)(5)(viii) of 

subpart Ja of this part.

(15) ASME MFC-22-2007, Measurement of Liquid by Turbine 

Flowmeters, IBR approved for §60.107a(d)(6)(v) of subpart Ja of 

this part.

* * * * *

(m) * * *

(2) Gas Processors Association Standard 2172-09, 

Calculation of Gross Heating Value, Relative Density, 

Compressibility and Theoretical Hydrocarbon Liquid Content for 

Natural Gas Mixtures for Custody Transfer (2009), IBR approved 

for §60.107a(d)(7)(viii) of subpart Ja of this part.

(3) Gas Processors Association Standard 2261-00, Analysis 

for Natural Gas and Similar Gaseous Mixtures by Gas 
Page 181 of 269

Chromatography (2000), IBR approved for §60.107a(d)(4)(v) of 

subpart Ja of this part.

* * * * *

(o) The following American Gas Association material is 

available for purchase from the following address: ILI 

Infodisk, 610 Winters Avenue, Paramus, New Jersey 07652:

(1) American Gas Association Report No. 3: Orifice 

Metering for Natural Gas and Other Related Hydrocarbon Fluids, 

Part 1: General Equations and Uncertainty Guidelines (1990), IBR 

approved for §60.107a(d)(5)(ix) of subpart Ja of this part.

(2) American Gas Association Report No. 3: Orifice 

Metering for Natural Gas and Other Related Hydrocarbon Fluids, 

Part 2: Specification and Installation Requirements (2000), IBR 

approved for §60.107a(d)(5)(x) of subpart Ja of this part.

(3) American Gas Association Report No. 11: Measurement 

of Natural Gas by Coriolis Meter (2003), IBR approved for 

§60.107a(d)(5)(xi) of subpart Ja of this part.

(4) American Gas Association Transmission Measurement 

Committee Report No. 7: Measurement of Gas by Turbine Meters 

(Revised February 2006), IBR approved for §60.107a(d)(5)(xii) of 

subpart Ja of this part.

(p) The following material is available for purchase from 

the International Standards Organization (ISO), 1, ch. de la 
Page 182 of 269

Voie-Creuse, Case postale 56, CH–1211 Geneva 20, Switzerland, 

+41 22 749 01 11, http://www.iso.org/iso/home.htm.

(1) ISO 8316: Measurement of Liquid Flow in Closed 

Conduits — Method by Collection of the Liquid in a Volumetric 

Tank (1987–10–01) — First Edition, IBR approved for 

§60.107a(d)(6)(vi) of subpart Ja of this part.

(2) [Reserved]

Subpart J--[AMENDED]

5. Section 60.100 is amended by:

a. Redesignating paragraph (e) as (f); and

b. Adding a new paragraph (e) to read as follows:

§60.100 Applicability, designation of affected facility, and 

reconstruction.

* * * * *

(e) Owners or operators may choose to comply with the 

applicable provisions of subpart Ja of this part to satisfy the 

requirements of this subpart for an affected facility.

* * * * *

6. 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 which is combusted. Fuel gas includes 
Page 183 of 269

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 in a thermal 

oxidizer or flare installed to control emissions from wastewater 

treatment units or marine tank vessel loading operations.

* * * * *

7. Section 60.106 is amended by revising paragraph (c)(1) 

to read as follows:

§60.106 Test methods and procedures.

* * * * *

(c) * * *

(1) The allowable emission rate (Es) of PM shall be 

computed for each run using the following equation:

Es = F + A (H/Rc)

Where:

Es = Emission rate of PM allowed, kg/Mg (lb/ton) of coke burnoff in catalyst regenerator.

F = Emission standard, 1.0 kg/Mg (2.0 lb/ton) of coke burn-off 

in catalyst regenerator.

A = Allowable incremental rate of PM emissions, 43 g/GJ (0.10 

lb/million Btu).

H = Heat input rate from solid or liquid fossil fuel, GJ/hr 

(million Btu/hr).

Rc = Coke burn-off rate, Mg coke/hr (ton coke/hr).

* * * * *

Subpart Ja--[AMENDED]
Page 184 of 269

7. In §60.100a, lift the stay on paragraph (c) published 

December 22, 2008 (73 FR 78552).

8. Section 60.100a is amended by:

a. Revising paragraph (a);

b. Revising paragraph (b); and

c. Revising paragraph (c) introductory text and paragraph 

(c)(1) to read as follows:

§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 process heaters), 

flares, 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. For the purposes of this subpart, a modification to a 
Page 185 of 269

flare commences when a project that includes any of the 

activities in paragraphs (c)(1) or (2) of this section is 

commenced.

(c) For all affected facilities other than flares, the 

provisions in §60.14 regarding modification apply. As provided 

in §60.14(f), the special provisions set forth under this 

subpart shall supersede the provisions in §60.14 with respect to 

flares. For the purposes of this subpart, a modification to a 

flare occurs as provided in paragraphs (c)(1) or (2) of this 

section. 

(1) Any new piping from a refinery process unit, including 

ancillary equipment, or a fuel gas system is physically 

connected to the flare (e.g., for direct emergency relief or 

some form of continuous or intermittent venting). However, the 

connections described in paragraphs (c)(1)(i) through (vi) of 

this section are not considered modifications of a flare.

(i) Connections made to install monitoring systems to the 

flare.

(ii) Connections made to install a flare gas recovery 

system or connections made to upgrade or enhance components of a 

flare gas recovery system (e.g., addition of compressors or 

recycle lines).

(iii) Connections made to replace or upgrade existing 

pressure relief or safety valves, provided the new pressure 
Page 186 of 269

relief or safety valve has a set point opening pressure no lower 

and an internal diameter no greater than the existing equipment 

being replaced or upgraded.

(iv) Connections made for flare gas sulfur removal. 

(v) Connections made to install back-up (redundant) 

equipment associated with the flare (such as a back-up 

compressor) that does not increase the capacity of the flare.

(vi) Replacing piping or moving an existing connection 

from a refinery process unit to a new location in the same 

flare, provided the new pipe diameter is less than or equal to 

the diameter of the pipe/connection being replaced/moved.

(vii) Connections that interconnect two or more flares.

* * * * *

9. In §60.101a, lift the stay on the definition of “flare”

published December 22, 2008 (73 FR 78552).

10. Section 60.101a is amended by:

a. Adding, in alphabetical order, definitions of “Air 

preheat,” “Ancillary equipment,” “Cascaded flare system,” “Cofired process heater,” “Corrective action,” “Corrective action 

analysis,” “Emergency flare,” “Flare gas header system,” “Flare 

gas recovery system,” “Forced draft process heater,” “Natural 

draft process heater,” “Non-emergency flare,” “Primary flare,” 

“Purge gas,” “Root cause analysis,” and “Secondary flare,” and 

“Sweep gas”; and
Page 187 of 269

b. Revising the definitions of “Delayed coking unit,” 

“Flare,” “Flexicoking unit,” “Fluid coking unit,” “Fuel gas,” 

“Fuel gas combustion device,” “Petroleum refinery,” “Process 

upset gas,” and “Sulfur recovery plant” to read as follows: 

§60.101a Definitions.

Air preheat means a device used to heat the air supplied to 

a process heater generally by use of a heat exchanger to recover 

the latent heat of exhaust gas from the process heater. 

Ancillary equipment means equipment used in conjunction 

with or that serve a refinery process unit. Ancillary equipment

includes, but is not limited to, storage tanks, product loading 

operations, wastewater treatment systems, steam- or electricityproducing units (including coke gasification units), pressure 

relief valves, pumps, sampling vents, and continuous analyzer 

vents.

Cascaded flare system means a series of flares connected to 

one flare gas header system arranged with increasing pressure 

set points so that discharges will be initially directed to the 

first flare in the series (i.e., the primary flare). If the 

discharge pressure exceeds a set point at which the flow to the 

primary flare would exceed the primary flare’s capacity, flow 

will be diverted to the second flare in the series. Similarly, 

flow would be diverted to a third (or fourth) flare if the 

pressure in the flare gas header system exceeds a threshold 
Page 188 of 269

where the flow to the first two (or three) flares would exceed 

their capacities. 

Co-fired process heater means a process heater that employs 

burners that are designed to be supplied by both gaseous and 

liquid fuels on a routine basis. Process heaters that have gas 

burners with emergency oil back-up burners are not considered 

co-fired process heaters.

* * * * *

Corrective action means the design, operation, and 

maintenance changes that one takes consistent with good 

engineering practice to reduce or eliminate the likelihood of

the recurrence of the primary cause and any other contributing 

cause(s) of an event identified by a root cause analysis as 

having resulted in a discharge of gases to an affected flare in 

excess of specified thresholds. 

Corrective action analysis means a description of all 

reasonable interim and long-term measures, if any, that are 

available, and an explanation of why the selected corrective 

action(s) is/are the best alternative(s), including, but not 

limited to, considerations of cost-effectiveness, technical 

feasibility, safety, and secondary impacts.

Delayed coking unit means a refinery process unit in which 

high molecular weight petroleum derivatives are thermally 

cracked and petroleum coke is produced in a series of closed, 
Page 189 of 269

batch system reactors. A delayed coking unit includes but is 

not limited to all of the coke drums associated with a single 

fractionator; the fractionator, including the bottoms receiver 

and the overhead condenser; the coke drum cutting water and 

quench system, including the jet pump and coker quench water 

tank; process piping and associated equipment such as pumps, 

valves and connectors; and the coke drum blowdown recovery 

compressor system.

Emergency flare means a flare that combusts gas exclusively 

released as a result of malfunctions (and not startup, shutdown, 

routine operations, or any other cause) on four or fewer 

occasions in a rolling 365 day period. For purposes of this 

rule, a flare cannot be categorized as an emergency flare unless 

it maintains a water seal.

Flare means a combustion device that uses an uncontrolled 

volume of air to burn gases. The flare includes the foundation, 

flare tip, structural support, burner, igniter, flare controls 

including air injection or steam injection systems, flame 

arrestors, and the flare gas header system. In the case of an 

interconnected flare gas header system, the flare includes each 

individual flare serviced by the interconnected flare gas header 

system and the interconnected flare gas header system.

Flare gas header system means all piping and knockout pots, 

including those in a subheader system, used to collect and
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transport gas to a flare either from a process unit or a 

pressure relief valve from the fuel gas system, regardless of 

whether or not a flare gas recovery system draws gas from the 

flare gas header system. The flare gas header system includes 

piping inside the battery limit of a process unit if the purpose 

of the piping is to transport gas to a flare or knockout pot 

that is part of the flare. 

Flare gas recovery system means a system of one or more 

compressors, piping, and the associated water seal, rupture 

disk, or similar device used to divert gas from the flare and 

direct the gas to the fuel gas system or to a fuel gas 

combustion device. 

Flexicoking unit means a refinery process unit 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 coking unit means a refinery process unit 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 the coking 

reactor, the coking burner, and equipment for controlling air 

pollutant emissions and for heat recovery on the fluid coking 

burner exhaust vent.
Page 191 of 269

Forced draft process heater means a process heater in which 

the combustion air is supplied under positive pressure produced 

by a fan at any location in the inlet air line prior to the 

point where the combustion air enters the process heater or air 

preheat. For the purposes of this subpart, a process heater 

that uses fans at both the inlet air side and the exhaust air 

side (i.e., balanced draft system) is considered to be a forced 

draft process heater.

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, coke calciners (used to make premium grade coke), 

and fluid coking burners, but does include gases from 

flexicoking unit gasifiers and other gasifiers. Fuel gas does 

not include vapors that are collected and combusted in a thermal 

oxidizer or flare installed to control emissions from wastewater 

treatment units, marine tank vessel loading operations, or 

asphalt processing units (i.e., asphalt blowing stills). 

Fuel gas combustion device means any equipment, such as 

process heaters and boilers, used to combust fuel gas. For the 

purposes of this subpart, fuel gas combustion device does not 
Page 192 of 269

include flares or facilities in which gases are combusted to 

produce sulfur or sulfuric acid.

* * * * *

Natural draft process heater means any process heater in 

which the combustion air is supplied under ambient or negative 

pressure without the use of an inlet air (forced draft) fan. 

For the purposes of this subpart, a natural draft process heater

is any process heater that is not a forced draft process heater, 

including induced draft systems.

Non-emergency flare means any flare that is not an 

emergency flare as defined in this subpart.

* * * * *

Petroleum refinery means any facility engaged in producing 

gasoline, kerosene, distillate fuel oils, residual fuel oils, 

lubricants, asphalt (bitumen) or other products through 

distillation of petroleum or through redistillation, cracking, 

or reforming of unfinished petroleum derivatives. A facility 

that produces only oil shale or tar sands-derived crude oil for 

further processing at a petroleum refinery using only solvent 

extraction and/or distillation to recover diluent is not a 

petroleum refinery.

Primary flare means the first flare in a cascaded flare 

system.

* * * * *
Page 193 of 269

Process upset gas means any gas generated by a petroleum 

refinery process unit or by ancillary equipment as a result of 

startup, shutdown, upset or malfunction.

Purge gas means gas introduced between a flare’s water seal 

and a flare’s tip to prevent oxygen infiltration (backflow) into 

the flare tip. For flares with no water seals, the function of 

purge gas is performed by sweep gas (i.e., flares without water 

seals do not use purge gas).

* * * * *

Root cause analysis means an assessment conducted through a 

process of investigation to determine the primary cause, and any 

other contributing cause(s), of a discharge of gases in excess 

of specified thresholds.

Secondary flare means a flare in a cascaded flare system 

that provides additional flare capacity and pressure relief to a 

flare gas system when the flare gas flow exceeds the capacity of 

the primary flare. For purposes of this subpart, a secondary 

flare is characterized by infrequent use and must maintain a 

water seal.

* * * * *

Sulfur recovery plant means all process units which recover 

sulfur from H2S and/or SO2 from a common source of sour gas 

produced at a petroleum refinery. The sulfur recovery plant

also includes sulfur pits used to store the recovered sulfur 
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product, but it does not include secondary sulfur storage 

vessels or loading facilities 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.

Sweep gas means the gas introduced in a flare gas header 

system to maintain a constant flow of gas to prevent oxygen 

buildup in the flare header. For flares with no water seals, 

sweep gas also performs the function of preventing oxygen 

infiltration (backflow) into the flare tip.

11. In §60.102a, lift the stay on paragraph (g) published 

December 22, 2008 (73 FR 78552).

12. Section 60.102a is amended by:

a. Revising paragraph (a);

b. Revising paragraph (f)(1)(ii);

c. Revising paragraph (g); 

d. Revising paragraph (h); and

e. Revising paragraph (i) to read as follows:
Page 195 of 269

§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 (i) 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. 

* * * * *

(f) * * *

(1) * * *

(ii) For a 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 ppmv of reduced sulfur compounds and 

10 ppmv of hydrogen sulfide (H2S), each calculated as ppmv SO2

(dry basis) at 0 percent excess air; or

* * * * *

(g) Reserved. 

(h) Each owner or operator of an affected fuel gas 

combustion device shall comply with the emissions limits in 

paragraphs (h)(1) and (2) of this section.
Page 196 of 269

(1) Except as provided in (h)(1)(iii) of this section, for 

each fuel gas combustion device, the owner or operator shall 

comply with either the emission limit in paragraph (h)(1)(i) of 

this section or the fuel gas concentration limit in paragraph 

(h)(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.

(iii) The combustion in a portable generator of fuel gas 

released as a result of tank degassing and/or cleaning is exempt 

from the emissions limits in paragraphs (h)(1)(i) and (ii).

(2) For each process heater with a rated capacity of 

greater than 40 million British thermal units per hour 

(MMBtu/hr) on a higher heating value basis, the owner or 

operator shall not discharge to the atmosphere any emissions of 
Page 197 of 269

NOX in excess of the applicable limits in paragraphs (h)(2)(i) 

through (h)(2)(iv) of this section.

(i) For each natural draft process heater, comply with the 

limit in either paragraph (h)(2)(i)(A) or (h)(2)(i)(B) of this 

section. The owner or operator may comply with either limit at 

any time, provided that the appropriate parameters for each 

alternative are monitored as specified in §60.107a; if fuel gas 

composition is not monitored as specified in §60.107a(d), the 

owner or operator must comply with the concentration limits in 

paragraph (h)(2)(i)(A) of this section. 

(A) 40 ppmv (dry basis, corrected to 0 percent excess air) 

determined daily on a 30-day rolling average basis; or

(B) 0.040 pounds per million British thermal units 

(lb/MMBtu) higher heating value basis determined daily on a 30-

day rolling average basis.

(ii) For each forced draft process heater, comply with the 

limit in either paragraph (h)(2)(ii)(A) or (h)(2)(ii)(B) of this 

section. The owner or operator may comply with either limit at 

any time, provided that the appropriate parameters for each 

alternative are monitored as specified in §60.107a; if fuel gas 

composition is not monitored as specified in §60.107a(d), the 

owner or operator must comply with the concentration limits in 

paragraph (h)(2)(ii)(A) of this section.
Page 198 of 269

(A) 60 ppmv (dry basis, corrected to 0 percent excess air) 

determined daily on a 30-day rolling average basis; or

(B) 0.060 lb/MMBtu higher heating value basis determined 

daily on a 30-day rolling average basis.

(iii) For each co-fired natural draft process heater, 

comply with the limit in either paragraph (h)(2)(iii)(A) or 

(h)(2)(iii)(B) of this section. The owner or operator must 

choose one of the emissions limits with which to comply at all 

times:

(A) 150 ppmv (dry basis, corrected to 0 percent excess 

air) determined daily on a 30 successive operating day rolling 

average basis; or

(B) The daily average emissions limit calculated using 

Equation 3 of this section:

gas gas oil oil

gas gas oil oil

NOx Q HHV Q HHV

Q HHV Q HHV

ER







0.06 0.35

(Eq. 3)

Where:

ERNOx = Daily allowable average emission rate of NOX, lb/MMBtu 

(higher heating value basis);

Qgas = Daily average volumetric flow rate of fuel gas, standard 

cubic feet per day (scf/day);

Qoil = Daily average volumetric flow rate of fuel oil, scf/day;

HHVgas = Daily average higher heating value of gas fired to the 

process heater, MMBtu/scf; and

HHVoil = Daily average higher heating value of fuel oil fired to 

the process heater, MMBtu/scf.

(iv) For each co-fired forced draft process heater, comply 

with the limit in either paragraph (h)(2)(iv)(A) or 
Page 199 of 269

(h)(2)(iv)(B) of this section. The owner or operator must 

choose one of the emissions limits with which to comply at all 

times:

(A) 150 ppmv (dry basis, corrected to 0 percent excess 

air) determined daily on a 30 successive operating day rolling 

average basis; or

(B) The daily average emissions limit calculated using 

Equation 4 of this section:

gas gas oil oil

gas gas oil oil

NOx Q HHV Q HHV

Q HHV Q HHV

ER







0.11 0.40

(Eq. 4)

Where:

ERNOx = Daily allowable average emission rate of NOX, lb/MMBtu 

(higher heating value basis);

Qgas = Daily average volumetric flow rate of fuel gas, scf/day;

Qoil = Daily average volumetric flow rate of fuel oil, scf/day;

HHVgas = Daily average higher heating value of gas fired to the 

process heater, MMBtu/scf; and

HHVoil = Daily average higher heating value of fuel oil fired to 

the process heater, MMBtu/scf.

(i) For a process heater that meets any of the criteria of 

paragraphs (i)(1)(i) through (iv) of this section, an owner or 

operator may request approval from the Administrator for a NOX

emissions limit which shall apply specifically to that affected 

facility. The request shall include information as described in 

paragraph (i)(2) of this section. The request shall be 

submitted and followed as described in paragraph (i)(3) of this 

section.
Page 200 of 269

(1) A process heater that meets one of the criteria in 

paragraphs (i)(1)(i) through (iv) of this section may apply for 

a site-specific NOX emissions limit:

(i) A modified or reconstructed process heater that lacks 

sufficient space to accommodate installation and proper 

operation of combustion modification-based technology (e.g., 

ultra-low NOX burners); or

(ii) A modified or reconstructed process heater that has 

downwardly firing induced draft burners; or

(iii) A co-fired process heater; or

(iv) A process heater operating at reduced firing 

conditions for an extended period of time (i.e., operating in 

turndown mode). The site-specific NOX emissions limit will only 

apply for those operating conditions.

(2) The request shall include sufficient and appropriate 

data, as determined by the Administrator, to allow the 

Administrator to confirm that the process heater is unable to 

comply with the applicable NOX emissions limit in paragraph 

(h)(2) of this section. At a minimum, the request shall contain 

the information described in paragraphs (i)(2)(i) through (iv) 

of this section.

(i) The design and dimensions of the process heater, 

evaluation of available combustion modification-based 

technology, description of fuel gas and, if applicable, fuel oil 
Page 201 of 269

characteristics, information regarding the combustion conditions

(temperature, oxygen content, firing rates), and other 

information needed to demonstrate that the process heater meets 

one of the four classes of process heaters listed in paragraph 

(i)(1) of this section.

(ii) An explanation of how the data in paragraph (i)(2)(i) 

demonstrate that ultra-low NOX burners, flue gas recirculation, 

control of excess air, or other combustion modification-based 

technology (including combinations of these combustion 

modification-based technologies) cannot be used to meet the 

applicable emissions limit in paragraph (h)(2) of this section.

(iii) Results of a performance test conducted under 

representative conditions using the applicable methods specified 

in §60.104a(i) to demonstrate the performance of the technology 

the owner or operator will use to minimize NOX emissions.

(iv) The means by which the owner or operator will 

document continuous compliance with the site-specific emissions 

limit.

(3) The request shall be submitted and followed as 

described in paragraphs (i)(3)(i) through (iii) of this section.

(i) The owner or operator of a process heater that meets 

one of the criteria in paragraphs (i)(1)(i) through (iv) of this 

section may request approval from the Administrator within 180 

days after initial startup of the process heater for a NOX
Page 202 of 269

emissions limit which shall apply specifically to that affected 

facility.

(ii) The request must be submitted to the Administrator 

for approval. The owner or operator must comply with the 

request as submitted until it is approved.

(iii) The request shall also be submitted to the following 

address: U.S. Environmental Protection Agency, Office of Air 

Quality Planning and Standards, Sector Policies and Programs 

Division, US EPA Mailroom (E143-01), Attention: Refinery Sector 

Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 

27711. Electronic copies in lieu of hard copies may also be 

submitted to refinerynsps@epa.gov.

(4) The approval process for a request for a facilityspecific NOX emissions limit is described in paragraphs (i)(4)(i) 

through (iii) of this section.

(i) Approval by the Administrator of a facility-specific 

NOX emissions limit request will be based on the completeness, 

accuracy, and reasonableness of the request. Factors that EPA 

will consider in reviewing the request for approval include, but 

are not limited to, the following:

(A) A demonstration that the process heater meets one of 

the four classes of process heaters outlined in paragraphs 

(i)(1) of this section;
Page 203 of 269

(B) A description of the low-NOX burner designs and other 

combustion modifications considered for reducing NOX emissions;

(C) The combustion modification option selected; and 

(D) The operating conditions (firing rate, heater box 

temperature, and excess oxygen concentration) at which the NOX

emission level was established. 

(ii) If the request is approved by the Administrator, a 

facility-specific NOX emissions limit will be established at the 

NOX emission level demonstrated in the approved request.

(iii) If the Administrator finds any deficiencies in the 

request, the request must be revised to address the deficiencies 

and be re-submitted for approval.

13. Section 60.103a is amended by:

a. Revising paragraph (a);

b. Revising paragraph (b);

c. Revising paragraph (c); and

d. Adding new paragraphs (d) through (j) to read as 

follows:

§60.103a Design, equipment, work practice, or operational 

standards.

(a) Except as provided in paragraph (g) of this section, 

each owner or operator that operates a flare that is subject to 

this subpart shall develop and implement a written flare 

management plan no later than the date specified in paragraph 
Page 204 of 269

(b) of this section. The flare management plan must include the 

information described in paragraphs (a)(1) through (7) of this 

section. 

(1) A listing of all refinery process units, ancillary 

equipment, and fuel gas systems connected to the flare for each 

affected flare. 

(2) An assessment of whether discharges to affected flares

from these process units, ancillary equipment, and fuel gas 

systems can be minimized. The flare minimization assessment 

must (at a minimum) consider the items in paragraphs (a)(2)(i) 

through (iv) of this section. The assessment must provide clear 

rationale in terms of costs (capital and annual operating), 

natural gas offset credits (if applicable), technical 

feasibility, secondary environmental impacts, and safety 

considerations for the selected minimization alternative(s) or a 

statement, with justifications, that flow reduction could not be 

achieved. Based upon the assessment, each owner or operator of 

an affected flare shall identify the minimization alternatives 

that it has implemented by the due date of the flare management 

plan and shall include a schedule for the prompt implementation 

of any selected measures that cannot reasonably be completed as 

of that date.

(i) Elimination of process gas discharge to the flare 

through process operating changes or gas recovery at the source.
Page 205 of 269

(ii) Reduction of the volume of process gas to the flare 

through process operating changes.

(iii) Installation of a flare gas recovery system or, for 

facilities that are fuel gas rich, a flare gas recovery system 

and a co-generation unit or combined heat and power unit.

(iv) Minimization of sweep gas flow rates, and, for flares 

with water seals, purge gas flow rates.

(3) A description of each affected flare containing the 

information in paragraphs (a)(3)(i) through (vii) of this 

section.

(i) A general description of the flare, including the 

information in paragraphs (a)(3)(i)(A) through (G) of this 

section. 

(A) Whether it is a ground flare or elevated (including 

height).

(B) The type of assist system (e.g., air, steam, pressure, 

non-assisted).

(C) Whether it is simple or complex flare tip (e.g., 

staged, sequential).

(D) Whether the flare is part of a cascaded flare system 

(and if so, whether the flare is primary or secondary).

(E) Whether the flare serves as a backup to another flare.

(F) Whether the flare is an emergency flare or a nonemergency flare.
Page 206 of 269

(G) Whether the flare is equipped with a flare gas 

recovery system.

(ii) Description and simple process flow diagram showing 

the interconnection of the following components of the flare: 

flare tip (date installed, manufacturer, nominal and effective 

tip diameter, tip drawing); knockout or surge drum(s) or pot(s) 

(including dimensions and design capacities); flare header(s) 

and subheader(s); assist system; and ignition system.

(iii) Flare design parameters, including the maximum vent 

gas flow rate; minimum sweep gas flow rate; minimum purge gas 

flow rate (if any); maximum supplemental gas flow rate; maximum 

pilot gas flow rate; and, if the flare is steam-assisted, 

minimum total steam rate.

(iv) Description and simple process flow diagram showing 

all gas lines (including flare, purge (if applicable), sweep, 

supplemental, and pilot gas) that are associated with the flare. 

For purge, sweep, supplemental, and pilot gas, identify the type 

of gas used. Designate which lines are exempt from sulfur, H2S, 

or flow monitoring and why (e.g., natural gas, inherently low 

sulfur, pilot gas). Designate which lines are monitored and 

identify on the process flow diagram the location and type of 

each monitor. 

(v) For each flow rate, H2S, sulfur content, pressure, or 

water seal monitor identified in paragraph (a)(3)(iv) of this 
Page 207 of 269

section, provide a detailed description of the manufacturer's 

specifications, including, but not limited to, make, model, 

type, range, precision, accuracy, calibration, maintenance, and 

quality assurance procedures.

(vi) For emergency flares, secondary flares, and flares 

equipped with a flare gas recovery system designed, sized, and 

operated to capture all flows except those resulting from 

startup, shutdown, or malfunction:

(A) Description of the water seal, including the operating 

range for the liquid level.

(B) Designation of the monitoring option elected (flow and 

sulfur monitoring or pressure and water seal liquid level 

monitoring). 

(vii) For flares equipped with a flare gas recovery 

system:

(A) A description of the flare gas recovery system, 

including number of compressors and capacity of each compressor.

(B) A description of the monitoring parameters used to 

quantify the amount of flare gas recovered.

(C) For systems with staged compressors, the maximum time 

period required to begin gas recovery with the secondary 

compressor(s), the monitoring parameters and procedures used to 

minimize the duration of releases during compressor staging, and 
Page 208 of 269

a justification for why the maximum time period cannot be 

further reduced.

(4) An evaluation of the baseline flow to the flare. The 

baseline flow to the flare must be determined after implementing 

the minimization assessment in paragraph (a)(2) of this section. 

Baseline flows do not include pilot gas flow or purge gas flow 

(i.e., gas introduced after the flare’s water seal) provided 

these gas flows remain reasonably constant (i.e., separate flow 

monitors for these streams are not required). Separate baseline 

flow rates may be established for different operating conditions 

provided that the management plan includes:

(i) A primary baseline flow rate that will be used as the 

default baseline for all conditions except those specifically 

delineated in the plan;

(ii) A description of each special condition for which an 

alternate baseline is established, including the rationale for 

each alternate baseline, the daily flow for each alternate 

baseline, and the expected duration of the special conditions 

for each alternate baseline; and

(iii) Procedures to minimize discharges to the affected 

flare during each special condition described in paragraph 

(a)(4)(ii) of this section, unless procedures are already 

developed for these cases under paragraph (a)(5) through (7) of 

this section, as applicable. 
Page 209 of 269

(5) Procedures to minimize or eliminate discharges to the 

flare during the planned startup and shutdown of the refinery 

process units and ancillary equipment that are connected to the 

affected flare, together with a schedule for the prompt 

implementation of any procedures that cannot reasonably be 

implemented as of the date of the submission of the flare 

management plan.

(6) Procedures to reduce flaring in cases of fuel gas 

imbalance (i.e., excess fuel gas for the refinery's energy 

needs), together with a schedule for the prompt implementation 

of any procedures that cannot reasonably be implemented as of 

the date of the submission of the flare management plan.

(7) For flares equipped with flare gas recovery systems, 

procedures to minimize the frequency and duration of outages of 

the flare gas recovery system and procedures to minimize the 

volume of gas flared during such outages, together with a 

schedule for the prompt implementation of any procedures that 

cannot reasonably be implemented as of the date of the 

submission of the flare management plan.

(b) Except as provided in paragraph (g) of this section, 

each owner or operator required to develop and implement a 

written flare management plan as described in paragraph (a) of

this section must submit the plan to the Administrator as 

described in paragraphs (b)(1) through (4) of this section. 
Page 210 of 269

(1) 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 the flare becomes 

an affected facility subject to this subpart, except for the 

selected minimization alternatives in paragraph (a)(2) and/or 

the procedures in paragraphs (a)(5) though (a)(7) of this 

section that cannot reasonably be implemented by that date, 

which the owner or operator must implement in accordance with 

the schedule in the flare management plan. The owner or 

operator of a modified flare must develop and implement the 

flare management plan by no later than [INSERT DATE 3 YEARS FROM 

DATE OF PUBLICATION IN THE FEDERAL REGISTER], 3 years from the 

date the modification commences, or upon startup of the modified 

flare, whichever is later.

(2) The owner or operator must comply with the plan as 

submitted by the date specified in paragraph (b)(1). The plan 

should be updated periodically to account for changes in the 

operation of the flare, such as new connections to the flare or 

the installation of a flare gas recovery system, but the plan 

need be re-submitted to the Administrator only if the owner or 

operator adds an alternative baseline flow rate, revises an 

existing baseline as described in paragraph (a)(4) of this 

section, installs a flare gas recovery system, or is required to 

change flare designations and monitoring methods as described in 
Page 211 of 269

§60.107a(g). The owner or operator must comply with the updated 

plan as submitted.

(3) All versions of the plan submitted to the 

Administrator shall also be submitted to the following address: 

U.S. Environmental Protection Agency, Office of Air Quality 

Planning and Standards, Sector Policies and Programs Division, 

US EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 

T.W. Alexander Drive, Research Triangle Park, NC 27711.

Electronic copies in lieu of hard copies may also be submitted 

to refinerynsps@epa.gov.

(c) Except as provided in paragraphs (f) and (g) of this 

section, each owner or operator that operates a fuel gas 

combustion device, flare, or sulfur recovery plant subject to 

this subpart shall conduct a root cause analysis and a 

corrective action analysis for each of the conditions specified 

in paragraphs (c)(1) through (3) of this section.

(1) For a flare:

(i) Any time the SO2 emissions exceed 227 kilograms (kg) 

(500 pounds (lb)) in any 24-hour period; or

(ii) Any discharge to the flare in excess of 14,160 

standard cubic meters (m3) (500,000 standard cubic feet (scf)) 

above the baseline, determined in paragraph (a)(4) of this 

section, in any 24-hour period; or
Page 212 of 269

(iii) If the monitoring alternative in §60.107a(g) is 

elected, any period when the flare gas line pressure exceeds the 

water seal liquid depth, except for periods attributable to 

compressor staging that do not exceed the staging time specified 

in paragraph (a)(3)(vii)(C) of this section.

(2) For a fuel gas combustion device, each exceedance of 

an applicable short-term emissions limit in §60.102a(h)(1) if 

the SO2 discharge to the atmosphere is 227 kg (500 lb) greater 

than the amount that would have been emitted if the emissions 

limits had been met during one or more consecutive periods of 

excess emissions or any 24-hour period, whichever is shorter.

(3) For a sulfur recovery plant, each time the SO2

emissions are more than 227 kg (500 lb) greater than the amount 

that would have been emitted if the SO2 or reduced sulfur 

concentration was equal to the applicable emissions limit in 

§60.102a(f)(1) or (2) during one or more consecutive periods of 

excess emissions or any 24-hour period, whichever is shorter.

(d) Except as provided in paragraphs (f) and (g) of this 

section, a root cause analysis and corrective action analysis 

must be completed as soon as possible, but no later than 45 days 

after a discharge meeting one of the conditions specified in 

paragraphs (c)(1) through (3) of this section. Special 

circumstances affecting the number of root cause analyses and/or 
Page 213 of 269

corrective action analyses are provided in paragraphs (d)(1) 

through (5) of this section.

(1) If a single continuous discharge meets any of the 

conditions specified in paragraphs (c)(1) through (3) of this

section for 2 or more consecutive 24-hour periods, a single root 

cause analysis and corrective action analysis may be conducted.

(2) If a single discharge from a flare triggers a root 

cause analysis based on more than one of the conditions 

specified in paragraphs (c)(1)(i) through (iii) of this section, 

a single root cause analysis and corrective action analysis may 

be conducted.

(3) If the discharge from a flare is the result of a 

planned startup or shutdown of a refinery process unit or 

ancillary equipment connected to the affected flare and the 

procedures in paragraph (a)(5) of this section were followed, a 

root cause analysis and corrective action analysis is not 

required; however, the discharge must be recorded as described 

in §60.108a(c)(6) and reported as described in §60.108a(d)(5).

(4) If both the primary and secondary flare in a cascaded 

flare system meet any of the conditions specified in paragraphs 

(c)(1)(i) through (iii) of this section in the same 24-hour 

period, a single root cause analysis and corrective action 

analysis may be conducted.
Page 214 of 269

(5) Except as provided in paragraph (d)(4) of this 

section, if discharges occur that meet any of the conditions 

specified in paragraphs (c)(1) through (3) of this section for 

more than one affected facility in the same 24-hour period, 

initial root cause analyses shall be conducted for each affected 

facility. If the initial root cause analyses indicate that the 

discharges have the same root cause(s), the initial root cause 

analyses can be recorded as a single root cause analysis and a 

single corrective action analysis may be conducted.

(e) Except as provided in paragraphs (f) and (g) of this 

section, each owner or operator of a fuel gas combustion device, 

flare, or sulfur recovery plant subject to this subpart shall 

implement the corrective action(s) identified in the corrective 

action analysis conducted pursuant to paragraph (d) of this 

section in accordance with the applicable requirements in 

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

(1) All corrective action(s) must be implemented within 45 

days of the discharge for which the root cause and corrective 

action analyses were required or as soon thereafter as 

practicable. If an owner or operator concludes that corrective 

action should not be conducted, the owner or operator shall 

record and explain the basis for that conclusion no later than 

45 days following the discharge as specified in 

§60.108a(c)(6)(ix).
Page 215 of 269

(2) For corrective actions that cannot be fully 

implemented within 45 days following the discharge for which the 

root cause and corrective action analyses were required, the 

owner or operator shall develop an implementation schedule to 

complete the corrective action(s) as soon as practicable. 

(3) No later than 45 days following the discharge for 

which a root cause and corrective action analyses were required,

the owner or operator shall record the corrective action(s) 

completed to date, and, for action(s) not already completed, a 

schedule for implementation, including proposed commencement and 

completion dates as specified in §60.108a(c)(6)(x). 

(f) Modified flares shall comply with the requirements of 

paragraphs (c) through (e) of this section by [INSERT DATE 3 

YEARS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER], 3 years 

after the date the modification commences, or at startup of the 

modified flare, whichever is later.

(g) An affected flare subject to this subpart located in 

the Bay Area Air Quality Management District (BAAQMD) may elect 

to comply with both BAAQMD Regulation 12, Rule 11 and BAAQMD 

Regulation 12, Rule 12 as an alternative to complying with the 

requirements of paragraphs (a) through (e) of this section. An 

affected flare subject to this subpart located in the South 

Coast Air Quality Management District (SCAQMD) may elect to 

comply with SCAQMD Rule 1118 as an alternative to complying with 
Page 216 of 269

the requirements of paragraphs (a) through (e) of this section. 

The owner or operator of an affected flare must notify the 

Administrator that the flare is in compliance with BAAQMD 

Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 or 

SCAQMD Rule 1118. The owner or operator of an affected flare 

shall also submit the existing flare management plan to the 

following address: U.S. Environmental Protection Agency, Office 

of Air Quality Planning and Standards, Sector Policies and 

Programs Division, US EPA Mailroom (E143-01), Attention: 

Refinery Sector Lead, 109 T.W. Alexander Drive, Research 

Triangle Park, NC 27711. Electronic copies in lieu of hard 

copies may also be submitted to refinerynsps@epa.gov.

(h) Each owner or operator of a delayed coking unit shall 

depressure each coke drum to 5 lb per square inch gauge (psig)

or less prior to discharging the coke drum steam exhaust to the 

atmosphere. Until the coke drum pressure reaches 5 psig, the

coke drum steam exhaust must be managed in an enclosed blowdown 

system and the uncondensed vapor must either be recovered (e.g., 

sent to the delayed coking unit fractionators) or vented to the 

fuel gas system, a fuel gas combustion device, or a flare.

(i) Each owner or operator shall not burn in any affected 

flare any fuel gas that contains H2S in excess of 162 ppmv 

determined hourly on a 3-hour rolling average basis. The 

combustion in a flare of process upset gases or fuel gas that is 
Page 217 of 269

released to the flare as a result of relief valve leakage or 

other emergency malfunctions is exempt from this limit.

(j) Alternative means of emission limitation. (1) Each 

owner or operator subject to the provisions of this section may 

apply to the Administrator for a determination of equivalence 

for any means of emission limitation that achieves a reduction 

in emissions of a specified pollutant at least equivalent to the 

reduction in emissions of that pollutant achieved by the 

controls required in this section.

(2) Determination of equivalence to the design, equipment, 

work practice, or operational requirements of this section will 

be evaluated by the following guidelines:

(i) Each owner or operator applying for a determination of 

equivalence shall be responsible for collecting and verifying 

test data to demonstrate the equivalence of the alternative

means of emission limitation.

(ii) For each affected facility for which a determination 

of equivalence is requested, the emission reduction achieved by 

the design, equipment, work practice, or operational 

requirements shall be demonstrated.

(iii) For each affected facility for which a determination 

of equivalence is requested, the emission reduction achieved by 
Page 218 of 269

the alternative means of emission limitation shall be 

demonstrated.

(iv) Each owner or operator applying for a determination 

of equivalence to a work practice standard shall commit in 

writing to work practice(s) that provide for emission reductions 

equal to or greater than the emission reductions achieved by the 

required work practice.

(v) The Administrator will compare the demonstrated 

emission reduction for the alternative means of emission 

limitation to the demonstrated emission reduction for the 

design, equipment, work practice, or operational requirements 

and, if applicable, will consider the commitment in paragraph 

(i)(2)(iv) of this section.

(vi) The Administrator may condition the approval of the 

alternative means of emission limitation on requirements that 

may be necessary to ensure operation and maintenance to achieve 

the same emissions reduction as the design, equipment, work 

practice, or operational requirements.

(3) An owner or operator may offer a unique approach to 

demonstrate the equivalence of any equivalent means of emission 

limitation.

(4) Approval of the application for equivalence to the 

design, equipment, work practice, or operational requirements of 

this section will be evaluated by the following guidelines:
Page 219 of 269

(i) After a request for determination of equivalence is 

received, the Administrator will publish a notice in the Federal 

Register and provide the opportunity for public hearing if the 

Administrator judges that the request may be approved.

(ii) After notice and opportunity for public hearing, the 

Administrator will determine the equivalence of a means of 

emission limitation and will publish the determination in the

Federal Register.

(iii) Any equivalent means of emission limitations 

approved under this section shall constitute a required work 

practice, equipment, design, or operational standard within the 

meaning of section 111(h)(1) of the CAA.

(5) Manufacturers of equipment used to control emissions

may apply to the Administrator for determination of equivalence 

for any alternative means of emission limitation that achieves a 

reduction in emissions achieved by the equipment, design, and 

operational requirements of this section. The Administrator 

will make an equivalence determination according to the 

provisions of paragraphs (i)(2) through (4) of this section.

14. Section 60.104a is amended by:

a. Revising paragraph (a);

b. Revising paragraphs (d)(4)(ii), (d)(4)(iii), (d)(4)(v), 

and (d)(8);

c. Revising paragraph (f)(3); 
Page 220 of 269

d. Revising paragraph (h)(5)(iv); 

e. Adding paragraphs (i)(6) through (i)(8);

f. Revising paragraph (j) introductory text and paragraph 

(j)(4) introductory text; and

g. Revising paragraph (j)(4)(iv) to read as follows:

§60.104a Performance tests.

(a) The owner or operator shall conduct a performance test 

for each FCCU, FCU, sulfur recovery plant, flare, 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.

* * * * *

(d) * * *

(4) * * *

(ii) The emissions rate of PM (EPM) is computed for each 

run using Equation 5 of this section:
Page 221 of 269

c

s sd

K R

c Q

E  (Eq. 5)

Where:

E = Emission rate of PM, g/kg (lb/1,000 lb) 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) [lb per 

hour (lb/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 6 of this section:

      c r a r CO O K Qoxy Ooxy R KQ CO CO K Q K Q CO % % % 2

% % %  1 2   2  3  2  2  3

(Eq. 6)

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);
Page 222 of 269

%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 (kgmin)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)];

K2 = Material balance and conversion factor, 2.088 (kgmin)/(hr-dscm) [0.1303 (lb-min)/(hr-dscf)]; and

K3 = Material balance and conversion factor, 0.0994 (kgmin)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].

* * * * *

(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 required in §60.105a(b)(2), if applicable, using 

Equation 7 of this section:

 

100 % 2 % % 2

79 100 %

CO CO O

Q Oxy Q

Q

a oxy

r

  

   

 (Eq. 7)

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(h)(3), assume 

%CO to be zero;

%O2 = O2 concentration in FCCU regenerator or fluid coking 

burner exhaust, percent by volume (dry basis); and
Page 223 of 269

%Ooxy = O2 concentration in O2 enriched air stream inlet to the 

FCCU regenerator or fluid coking burner, percent by 

volume (dry basis).

* * * * *

(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 8 of this section:

 









 % 2

20.9

20.9

O

C C c

adj meas (Eq. 8)

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.

* * * * *

(f) * * *

(3) Compute the site-specific limit using Equation 9 of 

this section:



















st

st PMEmR

Opacity Limit Opacity x

1lb /1,000 lb coke burn (Eq. 9)

Where:

Opacity limit = Maximum permissible 3-hour average opacity, 

percent, or 10 percent, whichever is greater;

Opacityst = Hourly average opacity measured during the 

source test, percent; and

PMEmRst = PM emission rate measured during the source 

test, lb/1,000 lb coke burn.
Page 224 of 269

* * * * *

(h) * * *

(5) * * *

(iv) The owner or operator shall use Equation 8 of this 

section to adjust pollutant concentrations to 0 percent O2 or 0 

percent excess air.

(i) * * *

(6) For process heaters with a rated heat capacity between 

40 and 100 MMBtu/hr that elect to demonstrate continuous 

compliance with a maximum excess oxygen limit as provided in 

§60.107a(c)(6) or (d)(8), the owner or operator shall establish 

the O2 operating limit or O2 operating curve based on the 

performance test results according to the requirements in 

paragraphs (i)(6)(i) or (ii) of this section, respectively.

(i) If a single O2 operating limit will be used:

(A) Conduct the performance test following the methods 

provided in paragraphs (i)(1), (2), (3) and (5) of this section 

when the process heater is firing at no less than 70 percent of 

the rated heat capacity. For co-fired process heaters, conduct 

at least one of the test runs while the process heater is being 

supplied by both fuel gas and fuel oil and conduct at least one 

of the test runs while the process heater is being supplied 

solely by fuel gas.
Page 225 of 269

(B) Each test will consist of three test runs. Calculate 

the NOX concentration for the performance test as the average of 

the NOX concentrations from each of the three test runs. If the 

NOX concentration for the performance test is less than or equal 

to the numerical value of the applicable NOX emissions limit 

(regardless of averaging time), then the test is considered to 

be a valid test.

(C) Determine the average O2 concentration for each test 

run of a valid test.

(D) Calculate the O2 operating limit as the average O2

concentration of the three test runs from a valid test. 

(ii) If an O2 operating curve will be used:

(A) Conduct a performance test following the methods 

provided in paragraphs (i)(1), (2), (3) and (5) of this section 

at a representative condition for each operating range for which 

different O2 operating limits will be established. Different 

operating conditions may be defined as different firing rates 

(e.g., above 50 percent of rated heat capacity and at or below 

50 percent of rated heat capacity) and/or, for co-fired process 

heaters, different fuel mixtures (e.g., primarily gas fired, 

primarily oil fired, and equally co-fired, i.e., approximately 

50 percent of the input heating value is from fuel gas and 

approximately 50 percent of the input heating value is from fuel 
Page 226 of 269

oil). Performance tests for different operating ranges may be 

conducted at different times.

(B) Each test will consist of three test runs. Calculate 

the NOX concentration for the performance test as the average of 

the NOX concentrations from each of the three test runs. If the 

NOX concentration for the performance test is less than or equal 

to the numerical value of the applicable NOX emissions limit 

(regardless of averaging time), then the test is considered to 

be a valid test. 

(C) If an operating curve is developed for different 

firing rates, conduct at least one test when the process heater 

is firing at no less than 70 percent of the rated heat capacity 

and at least one test under turndown conditions (i.e., when the 

process heater is firing at 50 percent or less of the rated heat 

capacity). If O2 operating limits are developed for co-fired 

process heaters based only on overall firing rates (and not by 

fuel mixtures), conduct at least one of the test runs for each 

test while the process heater is being supplied by both fuel gas 

and fuel oil and conduct at least one of the test runs while the 

process heater is being supplied solely by fuel gas.

(D) Determine the average O2 concentration for each test 

run of a valid test.

(E) Calculate the O2 operating limit for each operating 

range as the average O2 concentration of the three test runs from 
Page 227 of 269

a valid test conducted at the representative conditions for that 

given operating range. 

(F) Identify the firing rates for which the different 

operating limits apply. If only two operating limits are 

established based on firing rates, the O2 operating limits 

established when the process heater is firing at no less than 70 

percent of the rated heat capacity must apply when the process 

heater is firing above 50 percent of the rated heat capacity and 

the O2 operating limits established for turndown conditions must 

apply when the process heater is firing at 50 percent or less of 

the rated heat capacity.

(G) Operating limits associated with each interval will be 

valid for 2 years or until another operating limit is 

established for that interval based on a more recent performance 

test specific for that interval, whichever occurs first. Owners 

and operators must use the operating limits determined for a 

given interval based on the most recent performance test 

conducted for that interval.

(7) The owner or operator of a process heater complying 

with a NOX limit in terms of lb/MMBtu as provided in 

§60.102a(h)(2)(i)(B), (h)(2)(ii)(B), (h)(2)(iii)(B), or 

(h)(2)(iv)(B) or a process heater with a rated heat capacity 

between 40 and 100 MMBtu/hr that elects to demonstrate 

continuous compliance with a maximum excess oxygen limit as 
Page 228 of 269

provided in §60.107a(c)(6) or (d)(8) shall determine heat input 

to the process heater in MMBtu/hr during each performance test 

run by measuring fuel gas flow rate, fuel oil flow rate (as 

applicable), and heating value content according to the methods 

provided in §60.107a(d)(5), (d)(6), and (d)(4) or (d)(7), 

respectively. 

(8) The owner or operator shall use Equation 8 of this 

section to adjust pollutant concentrations to 0 percent O2 or 0 

percent excess air.

(j) The owner or operator shall determine compliance with 

the applicable H2S emissions limit in §60.102a(h)(1) for a fuel 

gas combustion device or §60.102a(g) for a flare according to 

the following test methods and procedures:

* * * * *

(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 facilities 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 flare, or for each individual fuel gas 

stream used in the fuel gas combustion device or flare.
Page 229 of 269

* * * * *

(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 or flare is added to a common source of fuel gas that 

previously demonstrated compliance.

15. Section 60.105a is amended by:

a. Revising paragraph (b) introductory text, and paragraph 

(b)(1) introductory text, and paragraphs (b)(1)(ii)(A), 

(b)(2)(i) and (b)(2)(ii); and

b. Revising paragraph (i)(5) to read as follows:

§60.105a Monitoring of emissions and operations for fluid 

catalytic cracking units (FCCU) and fluid coking units (FCU).

* * * * *

(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) that uses a control device 

other than fabric filter or cyclone shall comply with the 

requirements in paragraphs (b)(1) and (2) of this section.

(1) The owner or operator shall install, operate, and 

maintain continuous parameter monitor systems (CPMS) to measure 

and record operating parameters for each control device 
Page 230 of 269

according to the applicable requirements in paragraphs (b)(1)(i) 

through (v) of this section.

* * * * *

(ii) * * *

(A) As an alternative 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.

* * * * *

(2) * * *

(i) The owner or operator shall install, operate, and 

maintain each monitor according to Performance Specifications 3 

and 4 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 Specifications 3 and 4 

of Appendix B to part 60. The owner or operator shall use 

Method 3 of Appendix A–3 to part 60 and Method 10, 10A, or 10B 

of Appendix A–4 to part 60 for conducting the relative accuracy 

evaluations.

* * * * *

(i) * * *
Page 231 of 269

(5) 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.

* * * * *

16. In §60.107a, lift the stay on paragraphs (d) and (e)

published December 22, 2008 (73 FR 78552).

17. Section 60.107a is amended by:

a. Revising the section heading;

b. Revising paragraph (a) introductory text, paragraph 

(a)(1) introductory text, paragraph (a)(2) introductory text, 

(a)(2)(i), (a)(2)(iv), and paragraph (a)(3) introductory text;

c. Adding paragraph (a)(2)(v);

d. Revising paragraph (b) introductory text and paragraphs 

(b)(1)(i), (b)(1)(v), and (b)(3)(iii);

e. Revising paragraph (c) introductory text and paragraphs 

(c)(1) and (c)(6);

f. Redesignating paragraphs (d), (e), and (f) as 

paragraphs (e), (f), and (i), respectively;

g. Adding a new paragraph (d);

h. Revising newly redesignated paragraph (e);

i. Revising newly redesignated paragraph (f);

j. Adding a new paragraph (g);
Page 232 of 269

k. Adding a new paragraph (h); and

l. Revising newly redesignated paragraph (i) to read as 

follows:

§60.107a Monitoring of emissions and operations for fuel gas 

combustion devices and flares.

(a) Fuel gas combustion devices subject to SO2 or H2S limit

and flares subject to H2S limit. The owner or operator of a fuel 

gas combustion device that is subject to §60.102a(h)(1) and 

elects to comply with the SO2 emission limits in 

§60.102a(h)(1)(i) shall comply with the requirements in 

paragraph (a)(1) of this section. The owner or operator of a 

fuel gas combustion device that is subject to §60.102a(h)(1) and 

elects to comply with the H2S concentration limits in 

§60.102a(h)(1)(ii) or a flare that is subject to the H2S 

concentration requirement in §60.103a(i) shall comply with 

paragraph (a)(2) of this section.

(1) The owner or operator of a fuel gas combustion device 

that elects to comply with the SO2 emissions limits in 

§60.102a(h)(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.

* * * * *
Page 233 of 269

(2) The owner or operator of a fuel gas combustion device 

that elects to comply with the H2S concentration limits in 

§60.102a(h)(1)(ii) or a flare that is subject to the H2S 

concentration requirement in §60.103a(i) 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 or flare.

(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 300 ppmv H2S.

* * * * *

(iv) Fuel gas combustion devices or flares 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 in the 

respective fuel gas combustion devices or flares.

(v) The owner or operator of a flare subject to 

§60.103a(c) through (e) may use the instrument required in 

paragraph (e)(1) of this section to demonstrate compliance with 

the H2S concentration requirement in §60.103a(i) if the owner or 

operator complies with the requirements of paragraph (e)(1)(i) 

through (iv) and if the instrument has a span (or dual span, if 
Page 234 of 269

necessary) capable of accurately measuring concentrations 

between 20 and 300 ppmv. If the instrument required in 

paragraph (e)(1) is used to demonstrate compliance with the H2S 

concentration requirement, the concentration directly measured 

by the instrument must meet the numeric concentration in

§60.103a(i).

(3) The owner or operator of a fuel gas combustion device 

or flare is not required to comply with paragraph (a)(1) or (2) 

of this section for fuel gas streams that are exempt under 

§60.102a(i) or (h)(1)(iii) or for fuel gas streams combusted in 

a process heater, other fuel gas combustion device, or flare 

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.

* * * * *

(b) Exemption from H2S monitoring requirements for lowsulfur fuel gas streams. The owner or operator of a fuel gas 

combustion device or flare 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 
Page 235 of 269

(2) of this section until there are changes in operating 

conditions or stream composition.

(1) * * *

(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) or 

flare(s) to be considered;

* * * * *

(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 or flare (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).

* * * * *

(3) * * *

(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 
Page 236 of 269

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 of a fuel gas combustion device must also determine a 

rolling 365-day average using the stain sampling results; an 

average H2S concentration of 5 ppmv must be used for days within 

the rolling 365-day period prior to the operation change.

(c) Process heaters complying with the NOX concentrationbased limit. The owner or operator of a process heater subject 

to the NOX emissions limit in §60.102a(h)(2) and electing to 

comply with the applicable emissions limit in 

§60.102a(h)(2)(i)(A), (h)(2)(ii)(A), (h)(2)(iii)(A), or 

(h)(2)(iv)(A) 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 according to the requirements in paragraphs 

(c)(1) through (5) of this section, except as provided in 

paragraph (c)(6) of this section. The monitor must include an O2

monitor for correcting the data for excess air. 
Page 237 of 269

(1) Except as provided in paragraph (c)(6) of this 

section, 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 

must be between 2 and 3 times the applicable emissions limit, 

inclusive.

* * * * *

(6) The owner or operator of a process heater that has a 

rated heating capacity of less than 100 MMBtu and is equipped 

with combustion modification-based technology to reduce NOX

emissions (i.e., low-NOX burners, ultra-low-NOX burners) may 

elect to comply with the monitoring requirements in paragraphs 

(c)(1) through (5) of this section or, alternatively, the owner 

or operator of such a process heater shall conduct biennial 

performance tests according to the requirements in §60.104a(i), 

establish a maximum excess O2 operating limit or operating curve 

according to the requirements in §60.104a(i)(6), and comply with 

the O2 monitoring requirements in paragraphs (c)(3) through (5) 

of this section to demonstrate compliance. If an O2 operating 

curve is used (i.e., if different O2 operating limits are 

established for different operating ranges), the owner or 

operator of the process heater must also monitor fuel gas flow 

rate, fuel oil flow rate (as applicable), and heating value 
Page 238 of 269

content according to the methods provided in paragraphs (d)(5), 

(d)(6), and (d)(4) or (d)(7) of this section, respectively.

(d) Process heaters complying with the NOX heating valuebased or mass-based limit. The owner or operator of a process 

heater subject to the NOX emissions limit in §60.102a(h)(2) and 

electing to comply with the applicable emissions limit in 

§60.102a(h)(2)(i)(B) or (h)(2)(ii)(B) 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 and shall 

determine the F factor of the fuel gas stream no less frequently 

than once per day according to the monitoring requirements in 

paragraphs (d)(1) through (4) of this section. The owner or 

operator of a co-fired process heater subject to the NOX

emissions limit in §60.102a(h)(2) and electing to comply with 

the heating value-based limit in §60.102a(h)(2)(iii)(B) or 

(h)(2)(iv)(B) 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 according to the monitoring requirements in 

paragraph (d)(1) of this section; install, operate, calibrate, 

and maintain an instrument for continuously monitoring and 

recording the flow rate of the fuel gas and fuel oil fed to the 

process heater according to the monitoring requirements in 
Page 239 of 269

paragraph (d)(5) and (6) of this section; for fuel gas streams, 

determine gas composition according to the requirements in 

paragraph (d)(4) of this section or the higher heating value

according to the requirements in paragraph (d)(7) of this 

section; and for fuel oil streams, determine the heating value 

according to the monitoring requirements in paragraph (d)(7) of 

this section. 

(1) Except as provided in paragraph (d)(8) of this 

section, the owner or operator shall install, operate, and 

maintain each NOX monitor according to the requirements in 

paragraphs (c)(1) through (5) of this section. The monitor must 

include an O2 monitor for correcting the data for excess air. 

(2) Except as provided in paragraph (d)(3) of this 

section, the owner or operator shall sample and analyze each 

fuel stream fed to the process heater using the methods and 

equations in section 12.3.2 of Method 19 of Appendix A-7 to part 

60 to determine the F factor on a dry basis. If a single fuel 

gas system provides fuel gas to several process heaters, the F 

factor may be determined at a single location in the fuel gas 

system provided it is representative of the fuel gas fed to the 

affected process heater(s). 

(3) As an alternative to the requirements in paragraph 

(d)(2) of this section, the owner or operator of a gas-fired 

process heater shall install, operate, and maintain a gas 
Page 240 of 269

composition analyzer and determine the average F factor of the 

fuel gas using the factors in Table 1 of this subpart and 

Equation 10 of this section. If a single fuel gas system 

provides fuel gas to several process heaters, the F factor may 

be determined at a single location in the fuel gas system 

provided it is representative of the fuel gas fed to the 

affected process heater(s).

 

 





 



i i

i i

d

X MHC

X MEV

F

1,000,000

(Eq. 10)

Where:

Fd = F factor on dry basis at 0% excess air, dscf/MMBtu.

Xi = mole or volume fraction of each component in the 

fuel gas.

MEVi = molar exhaust volume, dry standard cubic feet per 

mole (dscf/mol).

MHCi = molar heat content, Btu per mole (Btu/mol).

1,000,000 = unit conversion, Btu per MMBtu.

(4) The owner or operator shall conduct performance 

evaluations of each compositional monitor according to the 

requirements in Performance Specification 9 of Appendix B to 

part 60. Any of the following methods shall be used for 

conducting the relative accuracy evaluations:

(i) Method 18 of Appendix A–6 to part 60;

(ii) ASTM D1945–03, Standard Method for Analysis of 

Natural Gas by Gas Chromatography (incorporated by reference-see 

§60.17); 
Page 241 of 269

(iii) ASTM D1946–90 (Reapproved 2006), Standard Method for 

Analysis of Reformed Gas by Gas Chromatography (incorporated by 

reference-see §60.17); 

(iv) ASTM D6420–99 (Reapproved 2004), Standard Test Method 

for Determination of Gaseous Organic Compounds by Direct 

Interface Gas Chromatography-Mass Spectrometry (incorporated by 

reference-see §60.17);

(v) Gas Processors Association Standard 2261-00, Analysis 

for Natural Gas and Similar Gaseous Mixtures by Gas 

Chromatography (2000) (incorporated by reference-see §60.17); or

(vi) ASTM UOP539-97, Refinery Gas Analysis by Gas 

Chromatography (incorporated by reference-see §60.17). 

(5) The owner or operator shall install, operate, and 

maintain fuel gas flow monitors according to the manufacturer’s 

recommendations. For volumetric flow meters, temperature and 

pressure monitors must be installed in conjunction with the flow 

meter or in a representative location to correct the measured 

flow to standard conditions (i.e., 68°F and 1 atmosphere). For 

mass flow meters, use gas compositions determined according to 

paragraph (d)(4) of this section to determine the average 

molecular weight of the fuel gas and convert the mass flow to a 

volumetric flow at standard conditions (i.e., 68°F and 1 

atmosphere). The owner or operator shall conduct performance 

evaluations of each fuel gas flow monitor according to the 
Page 242 of 269

requirements in §60.13 and Performance Specification 6 of 

Appendix B to part 60. Any of the following methods shall be 

used for conducting the relative accuracy evaluations:

(i) Method 2, 2A, 2B, 2C, or 2D of Appendix A–2 to part 

60;

(ii) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi (incorporated by referencesee §60.17);

(iii) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008), Measurement 

of Gas Flow by Turbine Meters (incorporated by reference-see 

§60.17); 

(iv) ASME MFC-6M-1998 (Reaffirmed 2005), Measurement of 

Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by 

reference-see §60.17); 

(v) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006), Measurement 

of Gas Flow by Means of Critical Flow Venturi Nozzles 

(incorporated by reference-see §60.17);

(vi) ASME MFC-11M-2006, Measurement of Fluid Flow by Means 

of Coriolis Mass Flowmeters (incorporated by reference-see 

§60.17);

(vii) ASME MFC-14M-2003, Measurement of Fluid Flow Using 

Small Bore Precision Orifice Meters (incorporated by referencesee §60.17);
Page 243 of 269

(viii) ASME MFC-18M-2001, Measurement of Fluid Flow Using 

Variable Area Meters (incorporated by reference-see §60.17);

(ix) American Gas Association (AGA) Report No. 3: Orifice 

Metering for Natural Gas and Other Related Hydrocarbon Fluids, 

Part 1: General Equations and Uncertainty Guidelines (1990)

(incorporated by reference-see §60.17);

(x) AGA Report No. 3: Orifice Metering for Natural Gas 

and Other Related Hydrocarbon Fluids, Part 2: Specification and 

Installation Requirements (2000) (incorporated by reference-see 

§60.17);

(xi) AGA Report No. 11: Measurement of Natural Gas by 

Coriolis Meter (2003) (incorporated by reference-see §60.17);

(xii) American Gas Association Transmission Measurement 

Committee Report No. 7: Measurement of Gas by Turbine Meters 

(Revised February 2006) (incorporated by reference-see §60.17); 

and

(xiii) American Petroleum Institute (API) Manual of 

Petroleum Measurement Standards, Chapter 22-Testing Protocol, 

Section 2-Differential Pressure Flow Measurement Devices, First

Edition, August 2005 (incorporated by reference-see §60.17).

(6) The owner or operator shall install, operate, and 

maintain each fuel oil flow monitor according to the 

manufacturer’s recommendations. The owner or operator shall 

conduct performance evaluations of each fuel oil flow monitor 
Page 244 of 269

according to the requirements in §60.13 and Performance 

Specification 6 of Appendix B to part 60. Any of the following 

methods shall be used for conducting the relative accuracy 

evaluations:

(i) Any one of the methods listed in paragraph (d)(5) of 

this section that are applicable to fuel oil (i.e., “fluids”);

(ii) ANSI/ASME-MFC-5M-1985 (Reaffirmed 2006), Measurement 

of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic 

Flowmeters (incorporated by reference-see §60.17);

(iii) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006), Measurement 

of Liquid Flow in Closed Conduits by Weighing Method 

(incorporated by reference-see §60.17);

(iv) ASME MFC-16-2007, Measurement of Liquid Flow in 

Closed Conduits with Electromagnetic Flowmeters (incorporated by 

reference-see §60.17);

(v) ASME MFC-22-2007, Measurement of Liquid by Turbine 

Flowmeters (incorporated by reference-see §60.17); or

(vi) ISO 8316: Measurement of Liquid Flow in Closed 

Conduits—Method by Collection of the Liquid in a Volumetric Tank 

(1987–10-01)—First Edition (incorporated by reference-see 

§60.17).

(7) The owner or operator shall determine the higher 

heating value of each fuel fed to the process heater using any 

of the applicable methods included in paragraphs (d)(7)(i) 
Page 245 of 269

through (ix) of this section. If a common fuel supply system 

provides fuel gas or fuel oil to several process heaters, the 

higher heating value of the fuel in each fuel supply system may 

be determined at a single location in the fuel supply system 

provided it is representative of the fuel fed to the affected 

process heater(s). The higher heating value of each fuel fed to 

the process heater must be determined no less frequently than 

once per day except as provided in paragraph (d)(7)(x) of this 

section.

(i) ASTM D240-02 (Reapproved 2007), Standard Test Method 

for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (incorporated by reference-see §60.17).

(ii) ASTM D1826-94 (Reapproved 2003), Standard Test Method 

for Calorific (Heating) Value of Gases in Natural Gas Range by 

Continuous Recording Calorimeter (incorporated by reference-see 

§60.17).

(iii) ASTM D1945-03, Standard Method for Analysis of 

Natural Gas by Gas Chromatography (incorporated by reference-see 

§60.17).

(iv) ASTM D1946-90 (Reapproved 2006), Standard Method for 

Analysis of Reformed Gas by Gas Chromatography (incorporated by 

reference-see §60.17).
Page 246 of 269

(v) ASTM D3588-98 (Reapproved 2003), Standard Practice for 

Calculating Heat Value, Compressibility Factor, and Relative 

Density of Gaseous Fuels (incorporated by reference-see §60.17).

(vi) ASTM D4809-06, Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter 

(Precision Method) (incorporated by reference-see §60.17). 

(vii) ASTM D4891-89 (Reapproved 2006), Standard Test 

Method for Heating Value of Gases in Natural Gas Range by 

Stoichiometric Combustion (incorporated by reference-see 

§60.17).

(viii) Gas Processors Association Standard 2172-09, 

Calculation of Gross Heating Value, Relative Density, 

Compressibility and Theoretical Hydrocarbon Liquid Content for 

Natural Gas Mixtures for Custody Transfer (2009) (incorporated 

by reference-see §60.17).

(ix) Any of the methods specified in section 2.2.7 of 

Appendix D to part 75. 

(x) If the fuel oil supplied to the affected co-fired 

process heater originates from a single storage tank, the owner 

or operator may elect to use the storage tank sampling method in 

section 2.2.4.2 of Appendix D to part 75 instead of daily 

sampling, except that the most recent value for heating content

must be used. 
Page 247 of 269

(8) The owner or operator of a process heater that has a 

rated heating capacity of less than 100 MMBtu and is equipped 

with combustion modification based technology to reduce NOX

emissions (i.e., low-NOX burners or ultra-low NOX burners) may 

elect to comply with the monitoring requirements in paragraphs 

(d)(1) through (7) of this section or, alternatively, the owner 

or operator of such a process heater shall conduct biennial 

performance tests according to the requirements in §60.104a(i), 

establish a maximum excess O2 operating limit or operating curve 

according to the requirements in §60.104a(i)(6), and comply with 

the O2 monitoring requirements in paragraphs (c)(3) through (5) 

of this section to demonstrate compliance. If an O2 operating 

curve is used (i.e., if different O2 operating limits are 

established for different operating ranges), the owner or 

operator of the process heater must also monitor fuel gas flow 

rate, fuel oil flow rate (as applicable), and heating value 

content according to the methods provided in paragraphs (d)(5), 

(d)(6), and (d)(4) or (d)(7) of this section, respectively.

(e) Sulfur monitoring for assessing root cause analysis 

threshold for affected flares. Except as described in 

paragraphs (e)(4) and (h) of this section, the owner or operator 

of an affected flare subject to §60.103a(c) through (e) shall 

determine the total reduced sulfur concentration for each gas 

line directed to the affected flare in accordance with either 
Page 248 of 269

paragraph (e)(1), (e)(2), or (e)(3) of this section. Different 

options may be elected for different gas lines. If a monitoring 

system is in place that is capable of complying with the 

requirements related to either paragraph (e)(1), (e)(2), or 

(e)(3) of this section, the owner or operator of a modified 

flare must comply with the requirements related to either 

paragraph (e)(1), (e)(2), or (e)(3) of this section upon startup 

of the modified flare. If a monitoring system is not in place 

that is capable of complying with the requirements related to 

either paragraph (e)(1), (e)(2), or (e)(3) of this section, the

owner or operator of a modified flare must comply with the 

requirements related to either paragraph (e)(1), (e)(2), or 

(e)(3) of this section no later than [INSERT DATE 3 YEARS FROM 

DATE OF PUBLICATION IN THE FEDERAL REGISTER], 3 years from the 

date the modification commences, or upon startup of the modified

flare, whichever is later.

(1) Total reduced sulfur monitoring requirements. The 

owner or operator shall install, operate, calibrate, and 

maintain an instrument for continuously monitoring and recording 

the concentration of total reduced sulfur in gas discharged to 

the flare. 

(i) The owner or operator shall install, operate, and 

maintain each total reduced sulfur monitor according to 

Performance Specification 5 of Appendix B to part 60. The span 
Page 249 of 269

value should be determined based on the maximum sulfur content 

of gas that can be discharged to the flare (e.g., roughly 1.1 to 

1.3 times the maximum anticipated sulfur concentration), but may 

be no less than 5,000 ppmv. A single dual range monitor may be 

used to comply with the requirements of this paragraph and 

paragraph (a)(2) of this section provided the applicable span 

specifications are met.

(ii) The owner or operator shall conduct performance 

evaluations of each total reduced sulfur monitor according to 

the requirements in §60.13(c) and Performance Specification 5 of 

Appendix B to part 60. For flares that routinely have flow, the 

owner or operator of each total reduced sulfur monitor shall use 

Method 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. The alternative relative 

accuracy procedures described in section 16.0 of Performance 

Specification 2 of Appendix B to part 60 (cylinder gas audits) 

may be used for conducting the relative accuracy evaluations. 

For flares that do not receive routine flow, the alternative 

relative accuracy procedures described in section 16.0 of 

Performance Specification 2 of Appendix B to part 60 (cylinder 

gas audits) may be used for conducting the relative accuracy 
Page 250 of 269

evaluations, except that it is not necessary to include as much 

of the sampling probe or sampling line as practical.

(iii) The owner or operator shall comply with the 

applicable quality assurance procedures in Appendix F to part 60 

for each total reduced sulfur monitor.

(2) H2S monitoring requirements. The owner or operator 

shall install, operate, calibrate, and maintain an instrument 

for continuously monitoring and recording the concentration of 

H2S in gas discharged to the flare according to the requirements 

in paragraphs (e)(2)(i) through (iii) of this section and shall

collect and analyze samples of the gas and calculate total 

sulfur concentrations as specified in paragraphs (e)(2)(iv) 

through (ix) of this section.

(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 should be determined 

based on the maximum sulfur content of gas that can be 

discharged to the flare (e.g., roughly 1.1 to 1.3 times the 

maximum anticipated sulfur concentration), but may be no less 

than 5,000 ppmv. A single dual range H2S monitor may be used to 

comply with the requirements of this paragraph and paragraph 

(a)(2) of this section provided the applicable span 

specifications are met.
Page 251 of 269

(ii) The owner or operator shall conduct performance 

evaluations of each H2S monitor according to the requirements in 

§60.13(c) and Performance Specification 7 of Appendix B to part 

60. For flares that routinely have flow, the owner or operator 

shall use Method 11, 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. The 

alternative relative accuracy procedures described in section 

16.0 of Performance Specification 2 of Appendix B to part 60 

(cylinder gas audits) may be used for conducting the relative 

accuracy evaluations. For flares that do not receive routine 

flow, the alternative relative accuracy procedures described in 

section 16.0 of Performance Specification 2 of Appendix B to 

part 60 (cylinder gas audits) may be used for conducting the 

relative accuracy evaluations, except that it is not necessary 

to include as much of the sampling probe or sampling line as 

practical.

(iii) The owner or operator shall comply with the 

applicable quality assurance procedures in Appendix F to part 60 

for each H2S monitor.

(iv) In the first 10 operating days after the date the 

flare must begin to comply with §60.103a(c)(1) of this subpart, 
Page 252 of 269

the owner or operator shall collect representative daily samples 

of the gas discharged to the flare. The samples may be grab 

samples or integrated samples. The owner or operator shall take 

subsequent representative daily samples at least once per week 

or as required in paragraph (e)(2)(ix) of this section.

(v) The owner or operator shall analyze each daily sample 

for total sulfur using either Method 15A of Appendix A-5 to part 

60, Method 16A of Appendix A-6 to part 60, ASTM Method D4468-85 

(Reapproved 2006) “Standard Test Method for Total Sulfur in 

Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry” 

(incorporated by reference—see §60.17), or ASTM Method D5504-08 

“Standard Test Method for Determination of Sulfur Compounds in 

Natural Gas and Gaseous Fuels by Gas Chromatography and 

Chemiluminescence” (incorporated by reference—see §60.17).

(vi) The owner or operator shall develop a 10-day average 

total sulfur-to-H2S ratio and 95 percent confidence interval as 

follows:

(A) Calculate the ratio of the total sulfur concentration 

to the H2S concentration for each day during which samples are 

collected.

(B) Determine the 10-day average total sulfur-to-H2S ratio 

as the arithmetic average of the daily ratios calculated in 

paragraph (e)(2)(vi)(A) of this section.
Page 253 of 269

(C) Determine the acceptable range for subsequent weekly 

samples based on the 95 percent confidence interval for the 

distribution of daily ratios based on the 10 individual daily 

ratios using Equation 11 of this section.

AR Ratio SDev  Avg  2.262 (Eq. 11)

Where:

AR = Acceptable range of subsequent ratio determinations, 

unitless.

RatioAvg = 10-day average total sulfur-to-H2S concentration

ratio, unitless.

2.262 = t-distribution statistic for 95 percent 2-sided 

confidence interval for 10 samples (9 degrees of 

freedom).

SDev = Standard deviation of the 10 daily average total 

sulfur-to-H2S concentration ratios used to develop 

the 10-day average total sulfur-to-H2S concentration 

ratio, unitless.

(vii) For each day during the period when data are being 

collected to develop a 10-day average, the owner or operator 

shall estimate the total sulfur concentration using the measured 

total sulfur concentration measured for that day.

(viii) For all days other than those during which data are 

being collected to develop a 10-day average, the owner or 

operator shall multiply the most recent 10-day average total 

sulfur-to-H2S ratio by the daily average H2S concentrations 

obtained using the monitor as required by paragraph (e)(2)(i)

through (iii) of this section to estimate total sulfur 

concentrations.
Page 254 of 269

(ix) If the total sulfur-to-H2S ratio for a subsequent 

weekly sample is outside the acceptable range for the most 

recent distribution of daily ratios, the owner or operator shall 

develop a new 10-day average ratio and acceptable range based on 

data for the outlying weekly sample plus data collected over the 

following 9 operating days.

(3) SO2 monitoring requirements. The owner or operator 

shall install, operate, calibrate, and maintain an instrument 

for continuously monitoring and recording the concentration of 

SO2 from a process heater or other fuel gas combustion device 

that is combusting gas representative of the fuel gas in the 

flare gas line according to the requirements in paragraph (a)(1) 

of this section, determine the F factor of the fuel gas at least 

daily according to the requirements in paragraphs (d)(2) through 

(4) of this section, determine the higher heating value of the 

fuel gas at least daily according to the requirements in 

paragraph (d)(7) of this section, and calculate the total sulfur 

content (as SO2) in the fuel gas using Equation 12 of this 

section. 

TS FG  CSO2 Fd  HHVFG (Eq. 12)

Where:

TSFG = Total sulfur concentration, as SO2, in the fuel gas, 

ppmv.

CSO2 = Concentration of SO2 in the exhaust gas, ppmv (dry basis 

at 0% excess air).

Fd = F factor gas on dry basis at 0% excess air, dscf/MMBtu.
Page 255 of 269

HHVFG = Higher heating value of the fuel gas, MMBtu/scf.

(4) Exemptions from sulfur monitoring requirements. 

Flares identified in paragraphs (e)(4)(i) through (iv) of this 

section are exempt from the requirements in paragraphs (e)(1) 

through (3) of this section. For each such flare, except as 

provided in paragraph (e)(4)(iv), engineering calculations shall 

be used to calculate the SO2 emissions in the event of a 

discharge that may trigger a root cause analysis under 

§60.103a(c)(1).

(i) Flares that can only receive:

(A) Fuel gas streams that are inherently low in sulfur 

content as described in paragraph (a)(3)(i) through (iv) of this 

section; and/or 

(B) Fuel gas streams that are inherently low in sulfur 

content for which the owner or operator has applied for an 

exemption from the H2S monitoring requirements as described in 

paragraph (b) of this section.

(ii) Emergency flares, provided that for each such flare, 

the owner or operator complies with the monitoring alternative 

in paragraph (g) of this section.

(iii) Flares equipped with flare gas recovery systems 

designed, sized, and operated to capture all flows except those 

resulting from startup, shutdown, or malfunction, provided that 
Page 256 of 269

for each such flare, the owner or operator complies with the 

monitoring alternative in paragraph (g) of this section.

(iv) Secondary flares that receive gas diverted from the 

primary flare. In the event of a discharge from the secondary 

flare, the sulfur content measured by the sulfur monitor on the 

primary flare should be used to calculate SO2 emissions, 

regardless of whether or not the monitoring alternative in 

paragraph (g) of this section is selected for the secondary 

flare.

(f) Flow monitoring for flares. Except as provided in 

paragraphs (f)(2) and (h) of this section, the owner or operator 

of an affected flare subject to §60.103a(c) through (e) shall 

install, operate, calibrate, and maintain, in accordance with 

the specifications in paragraph (f)(1) of this section, a 

continuous parameter monitoring system (CPMS) to measure and 

record the flow rate of gas discharged to the flare. If a flow 

monitor is not already in place, the owner or operator of a 

modified flare shall comply with the requirements of this 

paragraph by no later than [INSERT DATE 3 YEARS FROM DATE OF 

PUBLICATION IN THE FEDERAL REGISTER], 3 years from the date the 

modification commences, or upon startup of the modified flare, 

whichever is later.

(1) The owner or operator shall install, calibrate, 

operate and maintain each flow monitor according to the 
Page 257 of 269

manufacturer’s procedures and specifications and the following 

requirements.

(i) Locate the monitor in a position that provides a 

representative measurement of the total gas flow rate.

(ii) Use a flow sensor with a measurement sensitivity of 

no more than 5 percent of the flow rate or 10 cubic feet per 

minute, whichever is greater.

(iii) Use a flow monitor that is maintainable online, is 

able to continuously correct for temperature and pressure, and 

is able to record flow in standard conditions (as defined in 

§60.2) over one-minute averages.

(iv) At least quarterly, perform a visual inspection of 

all components of the monitor for physical and operational 

integrity and all electrical connections for oxidation and 

galvanic corrosion if the flow monitor is not equipped with a 

redundant flow sensor. 

(v) Recalibrate the flow monitor in accordance with the 

manufacturer's procedures and specifications biennially (every 

two years) or at the frequency specified by the manufacturer.

(2) Emergency flares, secondary flares, and flares 

equipped with flare gas recovery systems designed, sized, and 

operated to capture all flows except those resulting from 

startup, shutdown, or malfunction are not required to install 

continuous flow monitors; provided however, that for any such 
Page 258 of 269

flare, the owner or operator shall comply with the monitoring 

alternative in paragraph (g) of this section.

(g) Alternative monitoring for certain flares equipped 

with water seals. The owner or operator of an affected flare 

subject to §60.103a(c) through (e) that can be classified as 

either an emergency flare, a secondary flare, or a flare 

equipped with a flare gas recovery system designed, sized, and 

operated to capture all flows except those resulting from 

startup, shutdown, or malfunction may, as an alternative to the 

sulfur and flow monitoring requirements of paragraphs (e) and 

(f) of this section, install, operate, calibrate, and maintain, 

in accordance with the requirements in paragraphs (g)(1) through 

(7) of this section, a CPMS to measure and record the pressure 

in the flare gas header between the knock-out pot and water seal 

and to measure and record the water seal liquid level. If the 

required monitoring systems are not already in place, the owner 

or operator of a modified flare shall comply with the 

requirements of this paragraph by no later than [INSERT DATE 3 

YEARS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER], 3 years 

from the date the modification commences, or upon startup of the 

modified flare, whichever is later.

(1) Locate the pressure sensor(s) in a position that 

provides a representative measurement of the pressure and locate 
Page 259 of 269

the liquid seal level monitor in a position that provides a 

representative measurement of the water column height.

(2) Minimize or eliminate pulsating pressure, vibration, 

and internal and external corrosion.

(3) Use a pressure sensor and level monitor with a minimum 

tolerance of 1.27 centimeters of water.

(4) Using a manometer, check pressure sensor calibration 

quarterly.

(5) Conduct calibration checks any time the pressure 

sensor exceeds the manufacturer's specified maximum operating 

pressure range, or install a new pressure sensor.

(6) In a cascaded flare system that employs multiple 

secondary flares, pressure and liquid level monitoring is 

required only on the first secondary flare in the system (i.e., 

the secondary flare with the lowest pressure release set point).

(7) This alternative monitoring option may be elected only 

for flares with four or fewer pressure exceedances required to 

be reported under §60.108a(d)(5) (“reportable pressure 

exceedances”) in any 365 consecutive calendar days. Following 

the fifth reportable pressure exceedance in a 365-day period, 

the owner or operator must comply with the sulfur and flow 

monitoring requirements of paragraphs (e) and (f) of this 

section as soon as practical, but no later than 180 days after 

the fifth reportable pressure exceedance in a 365-day period.
Page 260 of 269

(h) Alternative monitoring for flares located in the 

BAAQMD or SCAQMD. An affected flare subject to this subpart 

located in the BAAQMD may elect to comply with the monitoring 

requirements in both BAAQMD Regulation 12, Rule 11 and BAAQMD 

Regulation 12, Rule 12 as an alternative to complying with the 

requirements of paragraphs (e) and (f) of this section. An 

affected flare subject to this subpart located in the SCAQMD may 

elect to comply with the monitoring requirements in SCAQMD Rule 

1118 as an alternative to complying with the requirements of 

paragraphs (e) and (f) of this section.

(i) 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(h) and 

flares subject to the emissions limitations in §60.102a(g) are 

defined as specified in paragraphs (i)(1) through (5) of this 

section. Determine a rolling 3-hour or a rolling daily average 

as the arithmetic average of the applicable 1-hour averages 

(e.g., a rolling 3-hour average is the arithmetic average of 

three contiguous 1-hour averages). Determine a rolling 30-day 

or a rolling 365-day average as the arithmetic average of the 

applicable dai1y averages (e.g., a rolling 30-day average is the 

arithmetic average of 30 contiguous daily averages).

(1) SO2 or H2S limits for fuel gas combustion devices. 

(i) If the owner or operator of a fuel gas combustion device 
Page 261 of 269

elects to comply with the SO2 emission limits in 

§60.102a(h)(1)(i) each rolling 3-hour period 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 each rolling 365-day period during 

which the average concentration of SO2 as measured by the SO2

continuous monitoring system required under paragraph (a)(1) of 

this section exceeds 8 ppmv.

(ii) If the owner or operator of a fuel gas combustion 

device elects to comply with the H2S concentration limits in 

§60.102a(h)(1)(ii), each rolling 3-hour period 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, and each rolling 365-day period during 

which the average concentration as measured by the H2S continuous 

monitoring system under paragraph (a)(2) of this section exceeds 

60 ppmv.

(iii) If the owner or operator of a fuel gas combustion 

device becomes subject to the requirements of daily stain tube 

sampling in paragraph (b)(3)(iii) of this section, each day 

during which the daily concentration of H2S exceeds 162 ppmv and 

each rolling 365-day period during which the average 

concentration of H2S exceeds 60 ppmv.
Page 262 of 269

(2) H2S concentration limits for flares. (i) Each rolling 

3-hour period 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.

(ii) If the owner or operator of a flare becomes subject 

to the requirements of daily stain tube sampling in paragraph 

(b)(3)(iii) of this section, each day during which the daily 

concentration of H2S exceeds 162 ppmv.

(3) Rolling 30-day average NOX limits for fuel gas 

combustion devices. Each rolling 30-day period during which the 

average concentration of NOX as measured by the NOX continuous 

monitoring system required under paragraph (c) or (d) of this 

section exceeds:

(i) For a natural draft process heater, 40 ppmv and, if 

monitored according to §60.107a(d), 0.040 lb/MMBtu;

(ii) For a forced draft process heater, 60 ppmv and, if 

monitored according to §60.107a(d), 0.060 lb/MMBtu; and

(iii) For a co-fired process heater electing to comply 

with the NOX limit in §60.102a(h)(2)(iii)(A) or (h)(2)(iv)(A), 

150 ppmv.

(iv) The site-specific limit determined by the 

Administrator under §60.102a(i).

(4) Daily NOX limits for fuel gas combustion devices. Each 

day during which the concentration of NOX as measured by the NOX
Page 263 of 269

continuous monitoring system required under paragraph (d) of 

this section exceeds the daily average emissions limit 

calculated using Equation 3 in §60.102a(h)(2)(iii)(B) or 

Equation 4 in §60.102a(h)(2)(iv)(B).

(5) Daily O2 limits for fuel gas combustion devices. Each

days during which the concentration of O2 as measured by the O2

continuous monitoring system required under paragraph (c)(6) of 

this section exceeds the O2 operating limit or operating curve 

determined during the most recent biennial performance test.

18. Section 60.108a is amended by:

a. Revising paragraph (b);

b. Revising paragraph (c)(1);

c. Revising paragraph (c)(6) introductory text and 

paragraphs (c)(6)(ii) through (vi);

d. Adding paragraphs (c)(6)(vii), (viii), (ix), (x) and 

(xi);

e. Adding paragraph (c)(7); and

f. Revising paragraph (d)(5) to read as follows:

§60.108a Recordkeeping and reporting requirements.

* * * * *

(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 intends to comply. 
Page 264 of 269

Each owner or operator of a co-fired process heater subject to 

an emissions limitation in §60.102a(h)(2)(iii) or (iv) shall 

submit to the Administrator documentation showing that the 

process heater meets the definition of a co-fired process heater 

in §60.101a. Notifications required by this paragraph shall be 

submitted with the notification of initial startup required by 

§60.7(a)(3).

(c) * * *

(1) A copy of the flare management plan.

* * * * *

(6) Records of discharges greater than 500 lb SO2 in any 

24-hour period from any affected flare, discharges greater than 

500 lb SO2 in excess of the allowable limits from a fuel gas 

combustion device or sulfur recovery plant, and discharges to an 

affected flare in excess of 500,000 scf above baseline in any 

24-hour period as required by §60.103a(c). If the monitoring 

alternative provided in §60.107a(g) is selected, the owner or 

operator shall record any instance when the flare gas line 

pressure exceeds the water seal liquid depth, except for periods 

attributable to compressor staging that do not exceed the 

staging time specified in §60.103a(a)(3)(vii)(C). The following 

information shall be recorded no later than 45 days following 

the end of a discharge exceeding the thresholds:

* * * * *
Page 265 of 269

(ii) 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. For a flare, record the measured or 

calculated cumulative quantity of gas discharged to the flare 

over the discharge duration. If the discharge duration exceeds 

24 hours, record the quantity of gas discharged to the flare for 

each 24-hour period. Engineering calculations are allowed for 

fuel gas combustion devices but are not allowed for flares 

except for those complying with the alternative monitoring 

requirements in §60.107a(g).

(iv) For each discharge greater than 500 lb SO2 in any 24-

hour period from a flare, the measured total sulfur 

concentration or both the measured H2S concentration and the 

estimated total sulfur concentration in the fuel gas at a 

representative location in the flare inlet.

(v) For each discharge greater than 500 lb SO2 in excess of 

the applicable short-term emissions limit in §60.102a(g)(1) from 

a fuel gas combustion device and for each discharge greater than 

500 lb SO2 in excess of the emissions limit in §60.102a(g) from a 

flare, either the measured concentration of H2S in the fuel gas 

or the measured concentration of SO2 in the stream discharged to 
Page 266 of 269

the atmosphere. Process knowledge can be used to make these 

estimates for fuel gas combustion devices but cannot be used to 

make these estimates for flares except as provided in 

§60.107a(e)(4).

(vi) For each discharge greater than 500 lb SO2 in excess 

of the allowable limits from a sulfur recovery plant, either the 

measured concentration of reduced sulfur or SO2 discharged to the 

atmosphere.

(vii) For each discharge greater than 500 lb SO2 in any 24-

hour period from any affected flare or discharge greater than 

500 lb SO2 in excess of the allowable limits from a fuel gas 

combustion device or sulfur recovery plant, the cumulative 

quantity of H2S and SO2 released into the atmosphere. For 

releases controlled by flares, assume 99 percent conversion of 

reduced sulfur or total sulfur to SO2. For fuel gas combustion 

devices, assume 99 percent conversion of H2S to SO2.

(viii) The steps that the owner or operator took to limit 

the emissions during the discharge.

(ix) The root cause analysis and corrective action 

analysis conducted as required in §60.103a(d), including an 

identification of the affected facility, the date and duration 

of the discharge, a statement noting whether the discharge 

resulted from the same root cause(s) identified in a previous 

analysis, and either a description of the recommended corrective 
Page 267 of 269

action(s) or an explanation of why corrective action is not 

necessary under §60.103a(e).

(x) For any corrective action analysis for which 

corrective actions are required in §60.103a(e), a description of 

the corrective action(s) completed within the first 45 days 

following the discharge, and, for action(s) not already 

completed, a schedule for implementation, including proposed 

commencement and completion dates.

(xi) For each discharge from any affected flare that is 

the result of a planned startup or shutdown of a refinery 

process unit or ancillary equipment connected to the affected 

flare, a statement that a root cause analysis and corrective 

action analysis are not necessary because the owner or operator 

followed the flare management plan.

(7) If the owner or operator elects to comply with 

§60.107a(e)(2) for a flare, records of the H2S and total sulfur 

analyses of each grab or integrated sample, the calculated daily 

total sulfur-to-H2S ratios, the calculated 10-day average total 

sulfur-to-H2S ratios, and the 95 percent confidence intervals for 

each 10-day average total sulfur-to-H2S ratio.

(d) * * *

(5) The information described in paragraph (c)(6) of this 

section for all discharges listed in paragraph (c)(6) of this 

section. For a flare complying with the monitoring alternative 
Page 268 of 269

under §60.107a(g), following the fifth discharge required to be 

recorded under paragraph (c)(6) of this section and reported 

under this paragraph, the owner or operator shall include 

notification that monitoring systems will be installed according 

to §60.107a(e) and (f) within 180 days following the fifth

discharge.

* * * * *

19. Section 60.109a is amended by by revising paragraph 

(b) introductory text and adding paragraph (b)(4) to read as 

follows:

§60.109a Delegation of authority.

* * * * *

(b) In delegating implementation and enforcement authority 

of this subpart to a State, local, or tribal agency, the 

approval authorities contained in paragraphs (b)(1) through (4) 

of this section are retained by the Administrator of the U.S. 

EPA and are not transferred to the State, local, or tribal 

agency.

* * * * *

(4) Approval of an application for an alternative means of 

emission limitation under §60.103a(i) of this subpart.

20. Table 1 to subpart Ja is added to read as follows:

Tables to Subpart Ja of Part 60
Page 269 of 269

Table 1 to Subpart Ja of Part 60--Molar Exhaust Volumes and 

Molar Heat Content of Fuel Gas Constituents

Constituent

MEVa

dscf/mol

MHCb

Btu/mol

Methane (CH4) 7.29 842

Ethane (C2H6) 12.96 1,475

Hydrogen (H2) 1.61 269

Ethene (C2H4) 11.34 1,335

Propane (C3H8) 18.62 2,100

Propene (C3H6) 17.02 1,947

Butane (C4H10) 24.30 2,717

Butene (C4H8) 22.69 2,558

Inerts 0.85 0

a MEV = molar exhaust volume, dry standard cubic feet per grammole (dscf/g-mol) at standard conditions of 68°F and 1 

atmosphere

b MHC = molar heat content (higher heating value basis), Btu per 

gram-mole (Btu/g-mol)