From: Brenda Shine/RTP/USEPA/US@EPA

Sent: 02/28/2012 06:44 PM

To: "Higgins, Cortney" <Cortney_Higgins@omb.eop.gov>

Cc: Penny Lassiter/RTP/USEPA/US@EPA, William Nickerson/DC/USEPA/US@EPA

Subject: RE: Interagency Comments under EO 13563 on Petroleum Ja draft final rule

Cortney,

Here is the Response to Comments document.

Brenda Shine

Environmental Engineer

US Environmental Protection Agency

Research Triangle Park, NC 27711

(919) 541-3608, Mail Drop E143-01

<< Subpart Ja Draft Response to Comments-1-26-12_clean.doc>>

From: "Higgins, Cortney" <Cortney_Higgins@omb.eop.gov>

Sent: 02/28/2012 05:47 PM

To: Brenda Shine/RTP/USEPA/US@EPA

Cc: Penny Lassiter/RTP/USEPA/US@EPA, William Nickerson/DC/USEPA/US@EPA

Subject: RE: Interagency Comments under EO 13563 on Petroleum Ja draft final rule

Additionally, we also request the response to comments document (Standards of Performance for 

Petroleum Refineries: Background Information for Final Amendments - Summary of Public 

Comments and Responses, dated December 2011) referenced in the preamble.

Regards,

Cortney
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Standards of Performance for Petroleum 

Refineries

Background Information for Final Amendments

Summary of Public Comments and Responses
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Standards of Performance for

Petroleum Refineries

Background Information for Final Amendments

Summary of Public Comments and Responses

Contract No. EP-D-11-084

Work Assignment No. 0-11

Project No. 06/09 (438)

U.S. Environmental Protection Agency

Office of Air Quality Planning and Standards

Emission Standards Division

Research Triangle Park, North Carolina 27711

December 2011
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Disclaimer

This report has been reviewed by the Sector Policies and Programs Division of the Office of Air 

Quality Planning and Standards, EPA, and approved for publication. Mention of trade names or 

commercial products is not intended to constitute endorsement or recommendation for use.
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TABLE OF CONTENTS

1.0 Introduction.............................................................................................................................1

2.0 Applicability ...........................................................................................................................4

2.1 Applicability of Subpart Ja ............................................................................................4

2.1.1 Gasification........................................................................................................4

2.1.2 Crude Oil from Oil Shale and Tar Sands...........................................................8

2.1.3 Flares................................................................................................................10

2.1.4 Other Units.......................................................................................................12

2.2 Applicability Date........................................................................................................13

2.3 Flare Modification .......................................................................................................18

2.4 Notification Schedule...................................................................................................33

2.5 Overlap with and Effect on Other Subparts.................................................................34

2.6 Equivalence with State and Local Rules......................................................................35

3.0 Definitions.............................................................................................................................40

3.1 Air Preheat ...................................................................................................................40

3.2 Co-Fired Process Heater ..............................................................................................40

3.3 Corrective Action Analysis..........................................................................................41

3.4 Delayed Coking Unit ...................................................................................................42

3.5 Flare .............................................................................................................................43

3.6 Fuel Gas.......................................................................................................................45

3.7 Fuel Gas Combustion Device ......................................................................................48

3.8 Natural Draft and Forced Draft Process Heaters .........................................................48

3.9 Process Upset Gas........................................................................................................50

3.10 Refinery Process Unit ..................................................................................................52

3.11 Sulfur Recovery Plant..................................................................................................53

4.0 Fuel Gas Combustion Devices and Flares............................................................................57

4.1 Emissions Limits..........................................................................................................57

4.1.1 Long-Term H2S Concentration Limit for Fuel Gas Combusted in Flares.......57

4.1.2 Alternative Compliance Options......................................................................58

4.2 Elimination of Routine Flaring ....................................................................................61

4.3 Flare Flow Rate Limit..................................................................................................65

4.4 Other Standards for Flares...........................................................................................65

4.4.1 General Comments on Other Flare Standards .................................................65

4.4.2 Flare Management Plan Requirements............................................................67

4.4.3 Root Cause Analysis and Corrective Action Analysis ....................................69

4.5 Monitoring Fuel Gas Combustion Devices..................................................................76

4.6 Sulfur Monitoring for Flares........................................................................................77

4.7 Flow Monitoring for Flares..........................................................................................83

4.8 Compliance Schedule...................................................................................................86

4.9 Startup, Shutdown and Malfunction ............................................................................88

5.0 Process Heaters.....................................................................................................................98

5.1 Emissions Limits..........................................................................................................98

5.1.1 Equivalence of Emissions Limit Units ............................................................98

5.1.2 Limits for New, Modified and Reconstructed Forced Draft Process 

Heaters .............................................................................................................98
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5.1.3 Turndown.......................................................................................................100

5.1.4 Site-Specific Emissions Limit Clarifications.................................................102

5.1.5 Co-Fired Process Heaters...............................................................................108

5.2 Monitoring of Process Heaters...................................................................................110

5.3 Other Clarifications....................................................................................................115

6.0 Compliance Requirements and General Monitoring, Recordkeeping and Reporting ........116

6.1 Rolling Averages .......................................................................................................116

6.2 Excess Emissions.......................................................................................................117

6.3 Monitoring Methods ..................................................................................................118

6.4 Reporting Requirements ............................................................................................118

6.5 Impacts on Small Refineries......................................................................................118
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1.0 INTRODUCTION

On June 24, 2008 (73 FR 35838), the U.S. Environmental Protection Agency (EPA) 

issued: (1) final amendments to the existing refineries new source performance standards (NSPS) 

in 40 CFR part 60, subpart J (“subpart J”); and (2) new petroleum refinery NSPS in 40 CFR part 

60, subpart Ja (“subpart Ja”). On September 26, 2008 (73 FR 55751), the effective date of the 

NSPS in 40 CFR part 60, subpart Ja, the EPA published a notice granting the request for 

reconsideration and a 90-day stay of the following provisions of 40 CFR part 60, subpart Ja: (1) 

the flare modification provision; (2) the definition of “flare”; (3) the fuel gas combustion device 

sulfur limits; (4) the flow limit for flare systems; (5) the total reduced sulfur (TRS) and flow 

monitoring requirements for flares; and (6) the nitrogen oxides (NOX) emissions limit for process 

heaters. On December 22, 2008, the EPA proposed to extend the original 90-day stay until the 

agency has reached a final decision on all of the issues for which reconsideration was granted (73 

FR 78260, 73 FR 78546, 73 FR 78549).

Also on December 22, 2008 (73 FR 78522), the EPA proposed amendments to the NSPS 

in 40 CFR part 60, subparts J and Ja to address the reconsidered issues as well as technical 

corrections. The proposal provided a 45-day comment period, ending February 5, 2009. The 

EPA received 20 comments on the proposed amendments from refiners, industry trade 

associations and consultants, state environmental departments, environmental groups and other 

interested parties during the comment period. Following the close of the public comment period,

two additional comment letters were received. All 22 of these comments have been placed in the 

docket for this rulemaking (Docket No. EPA-HQ-OAR-2007-0011). Table 1 lists the names and 

affiliation of each comment and the assigned docket number.
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Table 1. List of Commenters on the Proposed Amendments to 40 CFR Part 60, Subpart Ja

Docket Item No.

EPA-HQ-OAR2007-0011- Commenter and Affiliation

0295 B. Lane, Environmental Consultant

0296 R.A. Cade, Marathon Petroleum Company LLC

0297 M. Resh, Linde North America, Inc.

0298 D. Copeland, P.E., Praxair Inc.

0299 B. Lane, Environmental Consultant

0300 C.M. Campbell, RTP Environmental Associates Inc., on behalf of 

Hyperion Refining, LLC

0301 C. Feerick, ExxonMobil Company

0302 S.L. Sherk, American Refining Group, Inc

0303 M.E. Pugh, Flint Hills Resources, LP (FHR)

0304 R.W. Hermanson, BP America, Inc.

0305 D.F. Hunter, ConocoPhillips Company

0306 L.B. Barry, Chevron Corporation

0307 (Attachments 

posted as 0317)

J.S. Peterson, Environmental Integrity Project (EIP), also on behalf of

Natural Resources Defense Council (NRDC) and Sierra Club

0308 C.S. Colman, HESS Corporation, on behalf of HOVENSA LLC

0309 T.K. Metrose, Tesoro Corporation

0310 K.A. Saffell, Valero Energy Corporation

0311

R. Chittim, American Petroleum Institute (API), National Petrochemical 

and Refiners Association (NPRA) and Western States Petroleum 

Association (WSPA)

0312 A. Pasquale, Thermo Fisher Scientific

0313 B.F. Bateman, Bay Area Air Quality Management District (BAAQMD)

0314 H.A. Green, CITGO Petroleum Corporation

0315 R. Chittim, API, NPRA and WSPA

0316 B.F. Bateman, BAAQMD
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Several commenters, in addition to providing specific comments, also expressed support 

for comments provided by other commenters (generally, individual companies indicating support 

for comments submitted by their trade organization). Specifically, Commenters 0295, 0301, 

0302, 0304, 0305, 0306, 0308 and 0310 supported comments submitted by Commenter 0311 

(API, NPRA and WSPA). By convention, the commenter numbers presented in the comment 

summaries throughout the rest of this document indicate the commenter(s) that specifically 

provided those comments and not the commenters who supported that comment.

All of the comments and the EPA’s responses to the comments are summarized in this 

document or the preamble to the final amendments. The EPA’s responses to these comments 

form part of the basis for the EPA’s final decisions.
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2.0 APPLICABILITY

2.1 Applicability of Subpart Ja

2.1.1 Gasification

Comment: Commenter 0300 stated that the EPA should exempt entrained flow 

gasification processes from subpart Ja. The commenter cited a recent applicability determination 

provided by the South Dakota Department of Environmental Resources that indicated syngas 

produced from coke gasification was not fuel gas subject to subpart Ja and questioned how the 

gasification process would be considered a refinery process unit and the associated flare a fuel 

gas combustion device under the proposed amendments. The commenter stated that the best 

system of emission reduction (BSER)

1 determination did not address entrained flow gasification 

processes or consider that gas with a low energy content (also referred to as low British thermal 

unit [Btu] content) is not suitable for recovery as fuel gas. The commenter noted that both 40 

CFR part 60, subpart Da and subpart Ja would apply to their gasification facility, causing 

redundant requirements, but the commenter’s only specific objection was to the requirement to 

conduct a root cause analysis (RCA) for planned startup and shutdown events when there is no

outlet for the low Btu gas other than the flare. The commenter did not express concern with the 

fuel gas sulfur limits because, according to the commenter, the syngas is desulfurized prior to 

combustion under normal operations.

Commenters 0310 and 0311 objected to the proposed amendments to the definition of 

“fuel gas” and “refinery process unit” to include coke gasification. The commenters cited a 

Delaware court case that an adjacent coke gasification plant was not part of the refinery, largely 

because coke gasification was not an integral refinery process operation, according to the 

commenters. Furthermore, the commenters contended that coke gasification was not considered 

in the original NSPS (40 CFR part 60, subpart J) because the technology was not developed until 

 1 The level of control prescribed by CAA section 111 historically has been referred to as “best demonstrated 

technology” or BDT. In order to better reflect that CAA 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. Therefore, while commenters referred to “BDT” in their comment letters, we use “BSER” throughout this 

document.
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the mid-1980s, and the subpart Ja rulemaking docket contains no BSER analysis specific to coke 

gasification. As such, the commenters asserted that the revision is more than a “clarification,” the 

rulemaking record failed to satisfy applicable procedural standards for establishing BSER and 

the EPA failed to afford interested parties with a meaningful opportunity to comment. According 

to Commenters 0310 and 0311, the inclusion of coke gasification under subpart Ja places 

unreasonable operational limitations and costs on these sources.

Commenter 0310 noted that much of the sulfur from the coke gasifier is in the form of 

carbonyl sulfide (COS) and provided a cost for systems to meet a TRS limit of 50 parts per 

million by volume (ppmv) that would comply with 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). The commenter stated 

that the control system is not BSER because the cost effectiveness of the system is roughly 

$20,000/ton of sulfur dioxide (SO2) reduced. The commenter also contended that flexicoking 

units are “materially different” than coke gasifiers by focusing on the upstream coking processes 

associated with a flexicoking unit rather the production and treatment of low energy gas from the 

flexicoking gasifier. The commenter noted that FLEXSORB amine treatment units achieve <10 

ppmv H2S on flexicoking gas but suggested that this performance is not applicable or 

representative of the performance achievable from coke gasification units because flexicoking 

gasifiers use air while coke gasification units use oxygen (so the flexicoking gas is diluted with 

nitrogen). According to Commenters 0310 and 0311, the proposed rule would discourage use of 

gasification technology, contrary to established national security objectives.

Response: The key issues here are: (1) whether the clarifications to the definition of “fuel 

gas” and “refinery process units” altered the historic applicability of the refinery fuel gas 

standards for coke gasifiers; and (2) whether low-Btu gas produced from coke gasification units 

should be subject to the fuel gas standards. With respect to the inclusion of “other gasifiers” in 

the definition of fuel gas, we reaffirm our position that this is a clarification rather than a new 

requirement. We note that the definition of “fuel gas” at 40 CFR 60.101a is “any gas which is 

generated at a petroleum refinery and which is combusted,” and the amendments do not alter that 

language. The definition does not require the gas to be generated by a “refinery process unit” but 

more broadly applies to any gas generated at a petroleum refinery. We also note that the 

definition of “petroleum refinery” at 40 CFR 60.101a is “any facility engaged in producing 
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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.” The primary subject in this definition is “any facility.” It is 

not “the group of refinery process units” or similarly limiting phrases. The definition of 

petroleum refinery includes the entire facility. If a coke gasifier is located at a 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,” then the coke gasifier is located at a 

petroleum refinery. As such, the gas produced from the coke gasification process would be 

considered “fuel gas” regardless of whether the gasification process itself is considered a refinery 

process unit (see next paragraph for discussion on this issue). Consequently, prior to the newly 

proposed clarification to the definition of “fuel gas” in subpart Ja, it appears that a flare or other 

unit that combusts gas for a coke gasifier would be a “fuel gas combustion device” and an 

affected facility under subpart J or Ja, provided that the gasifier is located at a petroleum 

refinery. Based on the background provided by Commenter 0300 (“the planned refinery is a 

400,000 barrel per day, highly complex, full conversion refinery that will produce clean, green 

transportation fuels such as ultra-low sulfur gasoline and ultra-low sulfur diesel”), the coke 

gasifier is located at a petroleum refinery and the gas generated by the gasifier meets the 

definition of “fuel gas” regardless of the proposed clarifications to subpart Ja. Consequently, we 

find that the coke gasification unit described by Commenter 0300 is located at a petroleum 

refinery, the syngas produced by the unit is “fuel gas” and the flare combusting the fuel gas is an 

affected source subject to subpart Ja. (See letter to Preston Phillips, Vice President, Hyperion 

Refining LLC, from Cynthia J. Reynolds, Director, Technical Enforcement Program, U.S. EPA, 

Region 8, dated November 20, 2008 (Applicability Determination Control Number: 0800090) 

for further detail on this determination.) In addition, we note that in Star Enterprise v. EPA, 235 

F.3d 139, 151 (3rd Cir. 2001), the decision referenced by Commenters 0310 and 0311, the reason 

the Court held that the coke gasification plant was not part of the refinery was because of the 

physical location of the coke gasification plant, i.e., it was located next door to the refinery rather 

than “in” the refinery (“[I]n determining what facilities are ‘affected facilities’ that can be 

regulated under Subpart J, and, specifically, in determining what facilities are ‘in petroleum 

refineries,’ the touchstone of such a determination is the physical location of the facilities in 
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question.”). The Court did not address the factual situation in which a coke gasifier and turbines 

are physically located “in” the petroleum refinery. See 40 CFR 60.100a(a); Star Enterprise, 235 

F.3d at 151-152.

With respect to the proposed clarification of “refinery process unit,” the original 

definition read as follows: “Refinery process unit means any segment of the petroleum refinery 

in which a specific processing operation is conducted.” As stated previously, the petroleum 

refinery includes the entire facility. 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 does not limit it to 

only those processes used to produce gasoline, kerosene, fuel oils, etc. As coke gasification is 

easily construed as a “specific processing operation,” this unit meets the definition of a refinery 

process unit if the unit is located at a petroleum refinery. Consequently, we considered the 

proposed inclusion of coke gasification (as well as product loading, sulfur recovery and 

wastewater treatment) as an example of a refinery process unit to be a clarification of the existing 

definition rather than an expansion of the definition. (See Section 3.10 for additional discussion 

on the definition of “refinery process unit.”)

The more overarching issue is whether or not low-Btu gas produced from coke 

gasification units should be subject to the fuel gas standards. The commenters suggest that a 

separate analysis of the BSER is needed for coke gasification units and that the requirements of 

subpart Ja are not cost effective for coke gasifiers. We find that both the long-term 60 ppmv H2S 

concentration limit and the 162 ppmv H2S concentration limit determined hourly on a 3-hour 

rolling average basis (hereafter referred to as the short-term 162 ppmv H2S concentration limit)

are achievable based on the information provided by Commenter 0300, as well as the

performance of other integrated gasification combined cycle (IGCC) units. Gasification systems 

have received support from the EPA and the U.S. Department of Energy (DOE) largely because 

they are considered “clean technologies” because sulfur can be efficiently removed prior to final 

combustion. Commenter 0300 only expressed concern regarding the flare flow RCA, simply 

stating that the syngas is desulfurized before being flared. Additionally, while we acknowledge 

that higher H2S concentrations can be expected from a gasification system using pure oxygen 
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rather than air, the fact that the FLEXSORB amine treatment units achieves <10 ppmv H2S on 

flexicoking gas appears to support the case that, correcting for the diluting nitrogen, oxygen-fired 

gasification systems should be able to achieve H2S concentrations below 60 ppmv, and this 

information was included in the rulemaking record.

Although Commenter 0310 provided cost estimates to support their claim that the longterm 60 ppmv H2S concentration limit and the short-term 162 ppmv H2S concentration limit in 

subpart Ja are not cost effective for gasification, the commenter focused on COS removal rather 

than on H2S removal and, as such, mischaracterized the subpart Ja requirements. The limits on 

sulfur content of fuel gas are based on the H2S concentration of the fuel gas. While we evaluated 

limiting the concentration of other reduced sulfur compounds in fuel gas when we originally 

proposed subpart Ja, we did not finalize those standards as BSER due to the high costs of the 

technologies needed to reduce the total sulfur content of the fuel gas. Although we encourage the 

use of these COS removal technologies, we fail to see how the subpart Ja requirements mandate 

them. The commenter provided no evidence that amine scrubbing cannot be used to meet the 

H2S concentration limits. Based on our analysis of the costs for amine scrubbing systems already 

in the docket, we conclude that amine scrubbing of the syngas from coke gasification to meet the 

long-term 60 ppmv H2S concentration limit and the short-term 162 ppmv H2S concentration limit 

is achievable and cost effective and therefore BSER. In addition, this information supports our 

decision to finalize the proposed clarification that fuel gas includes “gases from flexicoking unit 

gasifiers and other gasifiers.”

Regarding flares associated with coke gasification units, we note that as described in 

more detail in Section 4.4.3, we agree that a RCA is unnecessary for planned startups and 

shutdowns that are already subject to and following minimization requirements of the flare 

management plan (FMP) under 40 CFR 60.103a(a)(5). Eliminating the RCA requirement for 

planned startups and shutdowns of units following their FMP appears to adequately address 

Commenter 0300’s primary concern.

2.1.2 Crude Oil from Oil Shale and Tar Sands

Comment: Commenter 0307 stated that the EPA should regulate facilities that only 

produce crude oil from oil shale and tar sands. The commenter acknowledged that these facilities 

do not appear to fall within the regulatory definitions for “petroleum refinery” and “refinery 
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process unit,” but it is important for the EPA to set strict emissions limits and monitoring 

requirements to regulate emissions from these facilities. The commenter noted that extraction of 

oil from tar sands and oil shale are energy intensive processes, resulting in nearly three times 

more greenhouse gas emissions than extraction of conventional crude oil.

2 The commenter also 

noted that oil shale extraction releases emissions of SO2 and other sulfur compounds, particulate 

matter (PM), carbon monoxide (CO), carbon dioxide (CO2), ozone (O3), NOX, lead, silica, 

metals, ammonia (NH3), trace organics and trace elements.3 Commenter 0305 supported the 

change to the definition of “petroleum refinery” to exclude oil shale and tar sands-derived crude 

but requested that the definition specifically exclude oil production as well, either by referring to 

Standard Industrial Classification (SIC) 2911 or adding, “nor is the extraction or production of 

crude oil” to the end of the definition.

Response: The definition of “petroleum refinery” does not include, and could not be 

reasonably construed to include, conventional oil production facilities. While we also do not 

believe oil shale and tar sand processing facilities fall within the regulatory definitions for 

“petroleum refinery,” the presence of a distillation or separation unit at these oil shale and tar 

sands processing facilities led to ambiguities, which is why the clarification was included in the 

definition. It may be reasonable to apply certain subpart Ja standards, such as FMP, to these

types of facilities, but we have not completed a BSER analysis specific to these processes, 

especially when they are isolated from a refinery. As in the previous discussion regarding coke 

gasification, we do consider oil shale and tar sand-processing units that are co-located at a 

petroleum refinery facility to be part of the petroleum refinery and subject to the FMP, RCA and 

fuel gas and process heater emissions standards. However, more information is needed on the 

operations and emissions from these oil production facilities. We are continuing to look at these 

processes to determine if regulation of these emission sources is needed. We do note that 

upgrading units that employ coking units to process tar sands into a synthetic crude oil do not 

meet the exclusion from the definition of a petroleum refinery because these facilities do more 

than simply remove diluent from the heavy oil that was added to effect extraction or to improve 

flow characteristics for pipeline transport.

 2 Wakefield, Ben, and Matt Price, Environmental Integrity Project. Tar Sands: Feeding U.S. Refinery Expansions 

with Dirty Fuel. June 2008. 3 Bordetsky, Ann, et al., Natural Res. Def. Council et al. Driving it Home: Choosing the Right Path for Fueling 

North America’s Transportation Future. June 2007. Available at

http://www.nrdc.org/energy/drivingithome/drivingithome.pdf.
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2.1.3 Flares

Comment: Commenters 0305 and 0311 objected to the reference to the expanded subpart 

Ja definition of “flare” in subpart J and stated that it expands the applicability of subpart J 

retroactively. According to Commenter 0311, since subpart J does not specifically define “flare,” 

the cross-reference to the subpart Ja definition could be construed as the definition that should 

have been applied historically under subpart J.

Response: We find that the lack of a definition of “flare” in subpart J has lead to 

confusion and disagreement with what is included in the definition of a flare. As stated 

previously, we do not consider the reference in subpart J to the definition of flare in subpart Ja as 

changing the definition of flare under subpart J, regardless of there being no formal definition 

included in that subpart. The industry petitioners to the final rule and this commenter suggest that 

the definition of “flare” in subpart Ja is different from the general interpretation of a flare under 

subpart J, but we find no support for this position, and commenters have provided none. After 

again reviewing the available information, we maintain that the cross-reference in subpart J to 

the definition of “flare” in subpart Ja only changes the applicability date for flares. If 

disagreements exist regarding what parts of a flare are covered as fuel gas combustion devices 

under subpart J, these disagreements should be addressed through other available Clean Air Act 

(CAA) regulatory mechanisms, such as through Applicability Determinations under 40 CFR 

60.5.

Comment: Commenter 0311 stated that temporary flares (those placed in service for less 

than 6 months) should be excluded from subpart Ja. These temporary flares are needed for flare 

maintenance as well as for tank cleanings or similar activities in remote areas of the refinery.

Commenter 0315 clarified that temporary flares might be needed to handle emergency flows 

while the main flare is off-line for purposes of installing equipment needed for that main flare to 

comply with subpart Ja. According to the commenter, the EPA should encourage maintenance of 

existing flares, but these activities would be discouraged if the temporary flares were subject to 

the rule. Also, the commenter stated that the EPA did not consider the costs of subjecting 

temporary flares to subpart Ja.

Response: With respect to flare maintenance, if the flare being maintained is already 

subject to subpart Ja, it appears that the temporary flare should be able to comply with subpart 

Ja. If the temporary flare is considered a “new” flare, then routine maintenance of a flare not 
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currently subject to subpart Ja would effectively trigger the rule. We can see that this could 

create an unnecessary barrier to properly maintaining the flare. Given the importance of flares in 

the safe operation of the facility and in the destruction of flammable gases in the case of an upset 

or malfunction, we agree that a temporary flare installed for the purposes of conducting 

maintenance on an existing flare must meet the applicable limits of the flare that it is temporarily 

replacing and does not, in itself, trigger applicability to subpart Ja.

For tank cleaning operations, we believe that the gases generated can be considered 

process upset gases (produced as a result of startup or shutdown). Thus, the rule specifically 

allows the use of a flare to combust these gases without subjecting them to H2S concentration

requirements for fuel gas. As such, for tank cleaning operations, these flares would only be 

subject to RCA and FMP requirements. As discussed in Section 4.4.3, we have modified the 

requirements in 40 CFR 60.103a(d)(3) to exclude RCA for planned startups and shutdowns that 

follow the flare minimization procedures in 40 CFR 60.103a(a)(5). We have also modified the 

text in 40 CFR 60.103a(a)(5) regarding flare minimization to clarify that the provisions apply to

“planned startup and shutdown of the refinery process units and ancillary equipment that are 

connected to the affected flare.” We interpret “ancillary equipment” to include storage vessels.

After considering the options, we determined that including this phrase would best clarify our 

intent. Provided that the refinery owner or operator prepares FMP for tank cleaning operations 

and follows those plans, then the temporary flare would be compliant with the requirements of 

subpart Ja. Consequently, the question becomes whether preparing a FMP is necessary and 

appropriate (i.e., BSER) for storage vessel cleaning operations. The additional cost is minimal, as 

one flare management protocol can cover multiple storage vessels. While adequate purging of 

the storage vessels is necessary, protocols to minimize unnecessary purges to the flare are 

expected to reduce both SO2 and NOX emissions and minimize auxiliary natural gas use (needed 

to maintain Btu content of the high nitrogen content purge gas). As such, we find that it is 

reasonable to require temporary flares used for planned startup and shutdown of process units to 

comply with subpart Ja by preparing and following a FMP. Consequently, we are not providing a 

general exclusion for temporary flares. While there may be a myriad of reasons why a temporary 

flare may be used, given the examples provided by the commenter, we find that only the flares 

installed for routine maintenance of an existing flare warrants an exclusion from the applicability 

of subpart Ja.
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Comment: Commenter 0296 stated that the EPA ignored hydrogen flares in their analysis 

and stated that no volatile organic compound (VOC) emissions occur as a result of flaring 

hydrogen.

Response: While evaluating the impacts of the rule, we found that reducing flaring, 

whether it is a hydrogen flare or hydrocarbon flare, reduces NOX emissions. Hydrogen typically 

has value to the refinery (e.g., used in hydrotreating and hydrocracking units), and if the 

hydrogen is nearly pure, recovery and use of this stream has environmental benefits. If the 

hydrogen stream is not pure, then flaring reductions can also lead to emission reductions of SO2

and VOC. As such, the final requirements for flares do not specifically exclude hydrogen flares.

2.1.4 Other Units

Comment: Commenter 0311 stated that fluid catalytic cracking unit (FCCU) startup 

heaters should be excluded from the process heater definition. These in-line heaters are used for 

100 to 125 hours to heat air that then heats the catalyst and catalyst vessel during FCCU startup.

The commenter believes these are not process heaters as they do not “transfer heat indirectly to 

process stream materials” and requested that the EPA clarify the point by specifically excluding 

such heaters from the process heater definition.

Response: Based on the limited description of the startup FCCU heater provided by the 

commenter, it does appear that this type of unit does not meet the definition of process heater and 

would not be subject to the NOX emissions limits. Additional information obtained on an FCCU 

heater at the ConocoPhillips Trainer Refinery4 indicates that for at least one of these types of 

units, there is no process feed during the FCCU startup process, so there are no “process stream 

materials” to receive any heat. However, with respect to SO2 limits, if these in-line heaters use 

fuel gas to heat the air, they are unequivocally fuel gas combustion devices and would have to 

meet either the SO2 emissions limits or the H2S concentration limits.

We are not making any changes to the final rule to address these types of units. The 

owner or operator should use the definitions of “process heater” and “fuel gas combustion 

device” in 40 CFR 60.101a to determine whether the unit is an affected source and what actions 

are needed to meet the requirements of subpart Ja. If there is any question about whether a 

 4 Wallwork, James F. ConocoPhillips Trainer Refinery Additional Comments on Proposed Plan Approval 23-

0003P. Letter to Sachin Shankar, P.E., Pennsylvania Department of Environmental Protection. October 15, 2009.
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specific unit meets the definition of “process heater” in subpart Ja, the owner or operator should

contact their permitting authority or the EPA for assistance.

Comment: Commenter 0299 requested clarification as to whether the gas generated when 

degassing and cleaning a tank is considered fuel gas if it is combusted in an internal combustion 

engine or thermal oxidizer. The commenter recommended that subparts J and Ja not apply to 

these temporary controls.

Response: Based on the current definition of “fuel gas” in subpart J and Ja, these gases 

would be considered fuel gas and the internal combustion engine or thermal oxidizer would be a 

fuel gas combustion device. However, we believe that these gases can be considered process 

upset gases (produced as a result of startup or shutdown). Thus, the rule specifically allows the 

use of a flare to combust these gases, but the use of an internal combustion engine or thermal 

oxidizer would appear to be prohibited without monitoring the H2S concentration of the fuel gas 

and possibly treating the fuel gas to reduce the H2S concentration. The different treatment of 

these control systems is difficult to justify. We agree that it is preferable that these tank cleaning 

emissions be combusted rather than released directly to the atmosphere. We also find that 

internal combustion engines would provide a comparable level of control as a flare with the 

added advantage of producing useful work, which can further reduce emissions elsewhere in the 

refinery by reducing energy consumption demand. A thermal oxidizer, while providing a 

comparable level of control, has the disadvantage that it would require significant excess fuel to 

maintain proper temperature in the incinerator, so we find that the thermal oxidizer is a less 

advantageous control option. Finally, we agree that, for most tanks, based on distance to a fuel 

gas line and the frequency of degassing and cleaning (typically once every 5 to 10 years), it 

would not be cost effective to have to capture and treat the relatively small quantities of gas that 

are produced infrequently due to tank degassing and cleaning. As such, we have added a 

provision to 40 CFR 60.102a(g)(1)(iii) to specifically exempt “combustion in a portable 

generator of fuel gas released as a result of tank degassing and/or cleaning.”

2.2 Applicability Date

Comment: Commenters 0296, 0306, 0310, 0311 and 0314 suggested that December 22, 

2008 (the proposal date of the amendments to subpart Ja), should be the applicability date for the 

flare. The commenters stated that the December 22, 2008, proposal date is the date that industry 
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was provided adequate notice of the new requirements. Commenters 0310 and 0311 further 

asserted that the EPA has the discretion and authority to extend the applicability date to 

December 22, 2008. Commenter 0306 and 0311 stated that the June 24, 2008, trigger date for 

flares is inappropriate because the term “modification” was altered and would result in 

retroactive application of the rule. Commenter 0310 also stated that the June 24, 2008, trigger 

date for flares would be inconsistent with and interfere with consent decree obligations.

Commenter 0314 stated that setting an applicability date before the date the regulations were first 

published is “an arbitrary and capricious Agency action.”

Commenters 0296, 0311 and 0314 also suggested that the December 22, 2008, proposal 

date should be the applicability date for process heater provisions. The commenters stated that 

the original proposal date is inappropriate because the final standards were more stringent than 

those originally proposed on May 14, 2007. Commenter 0296 noted that the June 24, 2008, final 

rule notice included NOX limits of 40 ppmv but suggested that December 22, 2008, is the proper 

applicability date, as the NOX provisions in the final rule were stayed. Commenters 0311 and 

0314 suggested that the December 22, 2008, proposal date is appropriate because the proposed 

standards are fundamentally different than the promulgated standards (e.g., establishment of 

different classes of process heaters).

Of particular concern for Commenters 0296 and 0314 is that they began construction on a

new process heater after the original proposal date that was designed and permitted to meet 50 

ppmv NOX, as they expected the standard to be 80 ppmv NOX. Commenter 0296 cited an 

erroneous statement in the Regulatory Impact Analysis suggesting that 80 ppmv would be 

allowed for process heaters that commenced construction after May 14, 2007, but prior to June 

24, 2008. Although the unit has not started up yet, based on the design of the process heater, 

Commenter 0296 does not expect the unit to meet the 40 ppmv emissions limit. Similarly, 

Commenter 0314 noted that the only way for their process heater currently under construction to 

meet the 40 ppmv emissions limit is to install selective catalytic reduction (SCR), so they are 

making provisions to install SCR even though the EPA already determined that SCR is not 

BSER. According to both commenters, either changing the effective date of the requirement or 

changing the emissions limit for newly constructed forced draft process heaters would eliminate 

this “retroactive noncompliance” issue.
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Commenters 0310 and 0311 stated that, if the EPA imposes standards on syngas 

produced by coke gasification, then the applicability date of those requirements should be no 

earlier than the December 22, 2008, proposal date. Commenter 0311 also indicated that the 

trigger date for other newly defined refinery process units (e.g., wastewater treatment) should be 

the December 22, 2008, proposal date.

Response: Commenters raise two basic questions: (1) What date applies for determining 

whether a flare or a process heater is a “new source” and subject to subpart Ja? (2) When must 

that “new” flare or process heater be in compliance with the applicable requirements in subpart 

Ja?

Section 111(a)(2) of the CAA defines a “new source” as “any stationary source, the 

construction or modification of which is commenced after the publication of regulations (or, if 

earlier, proposed regulations) prescribing a standard of performance under this section which 

will be applicable to such source.” An important aspect of this definition is the “notice” it 

provides that NSPS will be prospectively applicable after construction, reconstruction or 

modification of an affected source. For NSPS subpart Ja, a “new” process heater is one that 

commences construction, reconstruction or modification after May 14, 2007, which is the date of 

the “proposed regulations.” For the reasons explained in the final rule preamble at 73 FR 35856-

35857, a “new” flare is one that commences construction, reconstruction or modification after 

June 24, 2008, which is the date of the “publication of regulations.” Therefore, in compliance 

with CAA section 111(a)(2), refineries are on “notice” that after these respective dates, “new” 

process heaters and “new” flares will be subject to subpart Ja. See 40 CFR 60.100a(b).

Commenters, however, are essentially asserting that refineries were not on “notice” and 

cannot now be required to “retroactively” comply with subpart Ja. They assert several legal 

arguments for this position, but their basic position boils down to a lack of “notice,” which they 

assert requires the EPA to move the “trigger date” for subpart Ja applicability to December 22, 

2008, the proposal date for the proposed amendments.

With respect to flares, we find no validity in the arguments that the June 24, 2008, 

applicability data is inappropriate. The limited changes in the flare modification provision 

proposed on December 22, 2008, only identified certain connections that are not considered 

modifications of a flare. As such, we see no scenario where the revised flare modification 

provision would trigger retroactive application of the rule.
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For process heaters, while we recognize that the emissions limits and form of the 

standard have changed based on the information gathered during the rulemaking process, the 

regulated community was notified that NOX standards were being considered for process heaters 

on May 14, 2007. The best system of emission reduction should be implemented at this time. We 

recognize that refinery owners and operators desire maximum operating flexibility, but the 

proposed rule clearly indicated that controlling excess oxygen amounts is part of BSER, and 

process heater design and operation at high excess oxygen content was not considered BSER.

While we acknowledge that the initially promulgated 40 ppmv 24-hour NOX emissions limit and 

even the final amendments to these standards may limit operator flexibility to a greater extent 

than the originally proposed emissions limits, we find that the emissions limits in the final 

amendments are achievable and appropriate for newly constructed process heaters.

As discussed in greater detail in Section 2.1.1, the proposed clarifications of fuel gas and 

refinery process units in no way impacted the applicability of subpart Ja standards to the units in 

question. As such, we see no reason to specify applicability dates for syngas (i.e., fuel gas) 

produced by coke gasification. The limitations on sulfur in fuel gas apply to the fuel gas 

combustion device or flare as the affected source, not the unit producing the fuel gas. In other 

words, if a fuel gas combustion device or flare is an affected source based on the date that 

construction, reconstruction or modification commenced, then all the fuel gas combusted by that 

device must meet the sulfur standards, regardless of its origin, so an applicability date for coke 

gasification is irrelevant. Similarly, we see no basis or need to specify applicability dates for 

wastewater treatment systems or loading operations. Gases generated from these units were

always considered to be fuel gas (unless they meet the newly established exemption from the 

definition of fuel gas for combustion of vapors in a flare or thermal oxidizer to control 

emissions). If these gases were not already considered fuel gas, than this exemption would have 

been unnecessary and the industry would not have provided so many comments to expand the 

exemptions for different types of fuel gases. Furthermore, as we did not specify any specific 

regulations for wastewater treatment units or loading racks under subpart Ja, we do not 

understand the commenters’ request to change the applicability date.

Comment: Commenter 0305 recommended that 40 CFR 60.100a(c) clarify that: “For the 

purpose of this subpart, all projects committed to and subject to compliance with a Consent 

Decree filed with the Department of Justice prior to May 14, 2007 are deemed to have 
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commenced prior to May 14, 2007.” The commenter stated that this clarification is needed 

because subpart Ja could significantly impact (or create uncertainty in) some projects which have 

been long planned and committed to in order to comply with a consent decree.

Response: We decline to make this change, which equates to a request that the EPA find

that the filing date of a consent decree is equivalent or should be deemed equivalent to the date 

construction “commences” for all refinery projects covered under consent decrees. Instead, 

sources should continue to use the following definitions from 40 CFR 60.2 in making this 

determination:

Commenced means, with respect to the definition of new source in section 

111(a)(2) of the Act, that an owner or operator has undertaken a continuous 

program of construction or modification or that an owner or operator has entered 

into a contractual obligation to undertake and complete, within a reasonable time, 

a continuous program of construction or modification.

Construction means fabrication, erection, or installation of an affected facility.

Modification5 means any physical change in, or change in the method of 

operation of, an existing facility which increases the amount of any air pollutant 

(to which a standard applies) emitted into the atmosphere by that facility or which 

results in the emission of any air pollutant (to which a standard applies) into the 

atmosphere not previously emitted.

The definitions provide a reasonable set of criteria for determining when construction or 

modification commenced and should be applied on a project-specific basis. Sources that have 

any questions regarding how the final amendments to subpart Ja may impact their compliance 

with their consent decree should contact the EPA personnel within EPA’s Office of Enforcement 

and Compliance Assurance (OECA) with whom they negotiated the consent decree.

Comment: Commenter 0315 requested clarification regarding the timing of potential 

modifications. The proposed rule text, read literally, could be interpreted to mean that the date 

the new piping is connected to the flare header is the date an owner or operator should use to 

determine if that connection is a modification. However, in most cases, most of the work on the 

project has occurred before the actual connection is made, partly because accomplishing the 

connection and allowing flare header hydrocarbon to flow into new equipment poses a major 

 5 Sources should also reference CAA section 111(a)(4) and 40 CFR 60.14 when determining whether a 

“modification” has occurred.
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safety risk. The commenter also noted that this literal interpretation of the date of a modification 

is inconsistent with the NSPS General Provisions at 40 CFR 60.2, which states: “Commenced 

means... that an owner or operator has undertaken a continuous program of construction or 

modification or that an owner or operator has entered into a contractual obligation to undertake 

and complete, within a reasonable time, a continuous program of construction or modification.”

The commenter requested that the final rule clearly specify that, for projects where a flare 

connection is part of an entire project, the potential flare modification is considered to have 

begun upon the commencement or contracting of the project (i.e., a continuous program of 

construction or modification that happens to include a new connection to a flare).

Response: It is not our intention to apply a definition of “commenced” to subpart Ja that 

is inconsistent with that term as it is defined in the General Provisions. As explained in the 

previous response above, sources should continue using the definitions of “commenced,” 

“construction” and “modification”6 from the General Provisions for determining when a 

particular project “commences.” Using those definitions, it already appears that the date a source 

would use for evaluating whether a new connection to a flare is a “modification” of that flare 

would be the date that the entire project “commences,” not necessarily the date the piping is 

physically connected to the flare header. However, we recognize that the “new connection”

language in the flare modification provision could be misconstrued in this context; therefore, we 

have added a sentence to 40 CFR 60.100a(b) that states: “For the purposes of this subpart, a 

modification to a flare commences when a project that includes any of the activities in 

paragraphs (c)(1) or (2) of this section is commenced.”

2.3 Flare Modification

Comment: Commenter 0308 objected to the special modification provision for flares in 

subpart Ja. The commenter stated that the provisions in 40 CFR 60.14 can and should apply to 

flares. Specifically, the EPA should consider the “...hourly emission rate, at maximum physical 

capacity, before and after an operational change” (57 FR 32316). Because the maximum physical 

capacity of the flare, even when considering the header system as part of the flare, is not changed 

by additional tie-ins, new tie-ins should not constitute a modification, according to 

Commenters 0308 and 0311. Furthermore, the commenters asserted that the NSPS program was 

 6 See footnote 4.
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never intended to apply across an entire industry based on minor changes of an affected facility.

Commenter 0310 stated that the flare modification provision is unlawful because routine 

connections generally do not result in an emissions increase and may be seen as having 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.” Commenter 0311 

suggested a narrower flare modification provision stating that only connections that “result in a 

net increase in the amount of VOC or SO2 emitted during normal operations” are considered 

modifications. Commenter 0308 noted that a single project may remove some tie-ins and add 

some tie-ins, so that the net emissions could actually be reduced, and requested clarification if it 

was the EPA’s intent for such projects to constitute a flare modification.

Commenter 0310 stated that the flare modification provision in 40 CFR 60.100a(c)(2) 

should specify that the increase in flow capacity is an increase in the total volume of gas under 

standard conditions that could reach the flare and that it is specific to flow increases of VOC or 

sulfur compounds. Commenter 0309 suggested that most of the exemptions could be reduced 

down by focusing the rule on SO2 emissions and exempting any connection of fuel gas that has a 

H2S concentration of less than 162 ppmv. Commenter 0305 stated that “flow” is not a regulated 

pollutant, so an increase in flow should not be considered a modification. Commenter 0314 

agreed that examining what is a flare modification is warranted and agreed that projects that 

increase production through new process vents to flares or projects that increase process vent 

flow rates to flares should be subject to subpart Ja. Commenter 0309 stated that the proposed 

flare modification provision is too broad and suggested that the EPA should focus the flare 

modification provision on connections that provide a primary/routine flow from a process unit to 

the flare, such as delayed coking unit offgas.

Response: The agency made a conscious decision to promulgate a separate provision for 

a flare modification in 40 CFR part 60, 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 
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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 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 subpart Ja applicability for the flare.

Those connections we identified that do not increase emissions from the flare were 

specifically excluded from triggering 40 CFR part 60, 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 (FGR) 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. 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, CO, PM and NOX, as well as 
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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. See, generally, 73 FR 35838, 35842, 35854-35856 

(June 24, 2008); 73 FR 78522, 78533 (December 22, 2008), as well as Table 3 of the preamble to 

the final amendments. Using the flare to control VOC emissions at other refinery process units 

will increase CO, PM 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: Commenters 0298, 0301, 0302, 0303, 0305, 0306, 0309, 0311 and 0314 

suggested that the EPA should specifically exempt the following situations from the flare 

modification provision:

(1) connections made to upgrade or enhance (not just to install) a FGR system 

(Commenters 0301 and 0311); 

(2) new flare header interconnect lines, since the connection is between flares and not 

from a process unit or fuel gas system to a flare (Commenters 0308, 0310 and 0311);

(3) connections made for flare gas sulfur removal (Commenter 0311; these reduce 

emissions); 

(4) connections made to install back-up equipment (Commenter 0311; no impact on 

emissions); 

(5) all emergency pressure relief valve (PRV) connections from existing equipment 

because the rule may create a disincentive to improving safety (Commenter 0298, 

0305 and 0311) and the upset gases released by these valves are exempt from the 

emissions standard (Commenter 0301); 

(6) connections of monitoring system purge gases and analyzer exhausts (Commenters 

0298 and 0301) or closed vent sampling systems (Commenter 0314); 

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

where the flare is the control device (Commenter 0301 and 0306); 
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(8) connections made to comply with other federal, state or local rules where the flare is 

the control device (Commenters 0301 and 0314); 

(9) connections of “unregulated gases” such as hydrogen, nitrogen, ammonia, other nonhydrocarbon gases or natural gas” (Commenters 0301, 0305, 0309 and 0311) or any 

connection that is not “fuel gas” (Commenter 0311); 

(10) new connections upstream of an existing FGR system (Commenters 0301, 0303, 

0305 and 0314), provided the new connections do not compromise or exceed the FGR 

system’s capacity (Commenter 0301); 

(11) any new, moved or replaced piping connections that do not result in a net increase in 

emissions (Commenter 0311 specifically indicated increases in VOC or SO2

emissions) from the flare, regardless of piping size (Commenter 0301, 0305, 0306, 

0311 and 0314); Commenter 0301 suggested a larger PRV is such an example, stating 

that the larger PRV does not change the source or mass emissions, it just allows the 

pressure to relieve more quickly; 

(12) vapors from tanks used to store sweet or treated products (Commenter 0309); 

(13) temporary connections for purging existing equipment (Commenters 0311 and 0314; 

these are essentially “existing” connections); and

(14) connections of safety instrumentation systems (SIS) described under Occupational 

Safety and Health Administration (OSHA) process safety standards at 29 CFR 

1910.119, the 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 (Commenter 0314; the purpose of these systems is for safety and can 

often minimize process upsets when they do happen).

Commenter 0315 stated that for existing flares with sufficient FGR capacity, the EPA 

should make clear that sites are allowed to make new connections, tie-ins and other changes to 

their FGR systems as long as the new connections will not compromise or exceed the system's 

capacity to recover the new flow without triggering a flare modification. Commenter 0301 noted 

that a safety project to add a new pressure relief valve cannot carry the costs of a FGR system or 

additional amine treatment. According to the commenters, the EPA should encourage venting 

these gases to the flare rather than venting them to the atmosphere or compromising safety.

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 FGR system (e.g., addition of compressors or recycle lines) will improve the operation of 

the FGR system, and connections to these additional components will not result in increased 
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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 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 

40 CFR part 60, 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 specifically 

excluded flare interconnections from the modification provisions.

However, we also clarify in this response that when a flare that is subject to 40 CFR part 

60, 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.
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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 

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 document, 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 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.” Each of the streams mentioned by the commenter, when 

directed to a flare, will increase emissions of at least one pollutant (either PM, CO or NOX) from 

the flare (all of which the standard is intended to reduce). 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 
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do not agree that the types of gas streams suggested by the commenters should be exempt from 

the modification determination.

New connections upstream of an existing FGR system (Item 10 above) will increase the 

likelihood of an event that would cause an exceedance of the FGR system’s capacity (even if the 

new connections “do not exceed the FGR system’s capacity” under normal conditions), and the 

amount of gases sent to the flare would 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 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 on 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 
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flare, so we are not exempting these types of connections to the flare from the 40 CFR part 60, 

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 RCA or other compliance purpose. For these sweet vapors, the flow 

rate RCA threshold will be exceeded well before the SO2 RCA threshold.

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 FMP and that flaring 

from these “temporary” connections should be minimized to the extent practicable.

The impact of connections of SIS described under OSHA process safety standards at 29 

CFR 1910.119, the 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 “SIS” 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 
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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:

(1) Connections made to install monitoring systems to the flare.

(2) Connections made to install a FGR system or connections made to upgrade or 

enhance components of a FGR 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: Commenter 0309 stated that the flare modification provision in 

40 CFR 60.100a(c)(2) should explicitly exclude the following physical changes made to the 

flare: (1) change in flare pilot and igniter systems (including larger pilot lines or those that use 

more gas); (2) installation of sweep or purge gas reduction device (e.g., an internal ring or 

molecular seal); (3) increase in steam capacity (to limit smoke); (4) alteration of flare seal drum 

level or control scheme; and (5) connections to increase sweep or purge gas rates provided the 

sweep or purge gas has an H2S concentration of less than 162 ppmv on a 3-hour rolling average 

basis.

Response: Under 40 CFR 60.100a(c)(2), a flare is modified when it “is physically altered 

to increase the flow capacity of the flare.” We did not propose to revise this provision, nor do we 

think revisions are necessary. We do clarify in this response that the “flow capacity of the flare” 

is intended to refer to the capacity of flare gas (i.e., gas from the “flare gas header system,” 
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which is defined in the amended rule) that can be safely discharged to the flare because this kind 

of change most likely results in an emissions increase from the flare. This is consistent with the 

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 or which results in the emission of any air pollutant not 

previously emitted.” Alterations of the pilot and igniter systems or the steam system would not 

typically constitute a “modification” of the flare because these alterations do not typically

increase the flare gas flow capacity of the flare. However, if these physical alterations do

increase the flow capacity of the flare (e.g., larger pilots or increased steam ducts installed to 

allow higher flare gas flow rates to be handled by the flare, thereby increasing the flow capacity 

of the flare), which results in an emissions increase, then these alterations would be deemed a 

“modification” of the flare under 40 CFR 60.100a(c)(2). Similarly, installation of sweep or purge 

gas reduction devices or flare seal drum controls are not expected to increase the flare gas flow 

capacity of the flare and would not generally be a “modification” of the flare. However, if these 

physical changes do increase the flare gas flow capacity of the flare, which results in an 

emissions increase, then these alterations are “modifications” of the flare.

While the exemptions specified by the commenter may not be flare modifications under 

40 CFR 60.100a(c)(2), a few of these examples may be considered flare modifications under 

40 CFR 60.100a(c)(1). Specifically, Item 5, connections to increase sweep or purge gas rates,

would be considered a modification of the flare if these gases originate from a process unit or 

fuel gas system. However, if these connections are from a separate, independent natural gas line, 

for example, these connections would not be considered a flare modification under 

40 CFR 60.100a(c)(1). As noted in this response, we disagree that a blanket exemption of the 

modifications requested by the commenter is appropriate. This response, while clarifying the 

intent of the rule’s language, also indicates the need to evaluate potential modifications on a 

case-by-case basis. If there is any question about whether an alteration of the flare should be 

considered a modification of the flare based on the subpart Ja flare modification provision, the 

owner or operator should contact their permitting authority or the EPA for assistance.

Comment: Commenters 0298, 0301, 0302, 0309, 0311 and 0314 suggested that the EPA 

should specifically state that de minimis emission increases (or net emission decreases) resulting 

from new connections to a flare made to control and combust fugitive emissions such as leaks 
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from compressor seals, valves or pumps, are not flare modifications. Commenter 0302 suggested 

allowing site-specific exemptions for connections that do not increase emissions or that result in 

a de minimis emissions increase. Conversely, Commenter 0313 objected to setting a de minimis

emissions increase below which a modification would not trigger subpart Ja applicability. The 

commenter noted that the specific exclusions proposed by the EPA are acceptable because they 

arguably cause no emission increases. However, emissions from a flare are difficult to determine, 

particularly at low flow rates, and allowing a de minimis approach would cause confusion over 

the applicability of subpart Ja.

Response: In the preamble to our proposed amendments, the 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 40 CFR part 60, subpart Ja applicability. Id. The EPA acknowledged 

that these exceptions are “permissible but not required” under the modification provision in the 

CAA. Id. The 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 continue to recommend that any emissions increases resulting from 

“routine connections” to the flare system “will be de minimis” and should not trigger 40 CFR 

part 60, subpart Ja applicability at the flare, but they have not provided the comments or data 

requested in the proposal preamble that the EPA could consider to evaluate the impacts of such 

an approach. Docket Item No. EPA-HQ-OAR-2007-0011-0311 (second attachment), pg 20.

Industry Petitioners again suggest that the 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 the 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. 
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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, the 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 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. The EPA must exercise this authority cautiously, and only in those 

circumstances that truly warrant its application.

The EPA has found no basis for promulgating a de minimis exception to the flare 

modification provision. Despite its assertions, Industry Petitioners have still provided no data to 

support a finding that the emissions increases resulting from the alleged “routine connections” to 

a flare system are truly “trivial or [of] no value.” Docket Item No. EPA-HQ-OAR-2007-0011-

0311 (second attachment), 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 the EPA should promulgate a de minimis exception for the flare modification provision.

Docket Item No. EPA-HQ-OAR-2007-0011-0311 (second attachment), pg 21. As the District of 

Columbia Circuit specifically states in Shays, authority for promulgating a de 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” (Docket Item No. EPA-HQ-OAR-2007-0011-0311 (second attachment), pg 21, emphasis 
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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 

could be significant. On the other hand, the EPA sees a substantial environmental benefit in 

requiring controls that will reduce the cumulative emissions from a flare that becomes subject to 

40 CFR part 60, 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: Commenter 0315 expanded on their original comments (0311) and addressed 

the comparison between the flare modification provision in subpart Ja and modification of a 

municipal solid waste (MSW) landfill in the direct final amendments to Standards of 

Performance for New Stationary Sources and Guidelines for Control of Existing Sources: 

Municipal Solid Waste Landfills (63 FR 32743, June 16, 1998). The commenter noted that the 

preamble to that rule explains that the modification provision “is specific to landfills but is 

consistent with the intent of section 60.14 of the NSPS General Provisions.” “Production” is 

considered to be the amount of waste placed in the landfill, and “total ‘production’ for the entire 

life of the facility is controlled through the amount of design capacity specified in the permit.”

The commenter noted that according to the preamble, only “physical or operational changes that 

increase the size of the landfill beyond its permitted capacity” are considered modifications for 

purposes of NSPS. The preamble also stated that “operational changes” at a landfill are typically 

accomplished without capital expenditure; therefore, they are not included in the modification 

provision. Finally, the commenter noted that the preamble to the proposal stated that “if an MSW 

landfill increased its waste acceptance rate, such a change would be analogous to an increase in 

production rate at a manufacturing facility” which is excluded under 40 CFR 60.14. Therefore, 

the commenter asserted, the MSW modification provision is consistent with 40 CFR 60.14, while 

the subpart Ja flare modification provision is a departure from 40 CFR 60.14.

The commenter made several points in comparing the MSW landfill modification 

provision to their recommendations for the flare modification provision in subpart Ja. First, the 

commenter stated that the provision that a modification occurs only if the design capacity of the 
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landfill is changed is consistent with the suggestion that a new connection to a flare is only a 

modification if other changes are made to the flare system that would increase the capacity of the 

flare. Second, using the landfill in its intended function and continually adding new waste is not 

considered a series of physical changes, each adding a small increment to the potential emissions 

of the landfill; therefore, incremental additions to a flare system should not constitute 

modifications to the flare system for purposes of subpart Ja. Third, since the longstanding 

exclusions to the 40 CFR 60.14 definition of modification, such as excluding operational 

changes that do not require capital expenditure, were included in the MSW landfill modification 

provision, they should be available for the subpart Ja flare modification provision. (The 

commenter noted that the MSW landfill rule actually goes beyond the 40 CFR 60.14 exclusion 

by allowing any operational changes to be excluded whether or not they actually have a capital 

expenditure.) The commenter concluded that the EPA’s rationale for the MSW landfill 

modification provisions provides support for their suggested modifications to the flare 

modification provision in subpart Ja.

Response: In developing the modification provisions for MSW landfills, we evaluated the 

special circumstances associated with landfills and developed a modification provision specific 

to landfills. In exactly the same manner, we evaluated the special circumstances associated with 

flares and developed a modification provision specific to flares. In both cases, we considered the 

same underlying principles of what constitutes a “modification” based on the provisions in CAA 

section 111(a)(4), 40 CFR 60.2 and 40 CFR 60.14. We arrived at different modification 

provisions for MSW landfills and flares because of the many factual and operational differences 

for these two very different sources. We therefore do not consider it appropriate to make the 

changes to the flare modification provision that are suggested by the commenter.

Comment: Commenter 0308 requested clarification with respect to how the flare 

modification provision applies to flare interconnects, which are used to direct flow from one 

flare to another flare if one flare is temporarily out of service. The commenter requested 

concurrence that a new connection to “flare header system A” only modifies “flare A” and not to 

the interconnected “flare B” since the systems are generally operated independently.

Response: We disagree that only the first or primary flare in an interconnected flare 

system should be subject to subpart Ja when a new connection to a process unit or fuel gas 

system is made. New connections to the interconnected flare system would suggest that 
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additional gas could be sent to any of the flares in the interconnected system. In a cascaded 

system, the new connection increases the likelihood that gas will be sent to the secondary flare.

As such, a new connection to the flare gas system would trigger the applicability of subpart Ja 

for both (or all) interconnected flares.

For flares that are used only for back-up or redundant systems to the primary flare (i.e., 

for staged flares that are only triggered when the flare gas pressure at the primary flare exceeds a 

certain pressure), the final amendments provide a simplified water seal monitoring approach

under 40 CFR 60.107a(g) to ensure gas is not sent to the secondary flare. It is anticipated that 

any event that causes a release so large as to trigger gas flow to subsequent flares in the series 

would trigger a RCA on the primary flare. The root cause of the flaring event for the back-up 

flares would be the same as the primary flare, so it would be redundant to require additional 

RCA for the back-up flares. Therefore, the final amendments do not require duplicative RCA for 

the secondary flare if a RCA is triggered for the primary flare. However, if flare gas is sent to the 

secondary flare (as detected by the water seal monitoring) prior to triggering a RCA on the 

primary flare, then the indication of flow to the secondary flare automatically triggers a RCA for 

the primary flare. If the interconnection does not have a water seal or other device that prevents 

flow to the interconnected flare during normal operation, then a new connection to an 

interconnected flare header system would require flow and sulfur monitoring for each flare 

within the interconnected header system.

2.4 Notification Schedule

Comment: Commenter 0295 requested clarification that the 40 CFR 60.7 notifications for 

construction or startup are not due until the stay is lifted, even if these activities occur during the 

stay. Similarly, Commenter 0311 requested that the 40 CFR 60.108a and 40 CFR 60.7 

notifications for construction or startup be due 60 days after the stay is lifted and the final rule 

published.

Response: Notification for construction and startup should be provided at the time of 

construction or startup, as applicable. These requirements existed under subpart J and there is no 

reason to delay these notifications.
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2.5 Overlap with and Effect on Other Subparts

Comment: Commenter 0311 noted that 40 CFR part 63, subpart UUU (Refinery 

MACT 2) often references specific subpart J requirements, resulting in a refinery potentially 

having to meet both subparts J and Ja for many sources. Commenter 0311 suggested adding the 

following sentence to 40 CFR 60.100a(e) of subpart Ja: “Owners or operators may also choose to 

comply with the applicable provisions of Subpart Ja of this part to satisfy the requirements of 

Part 63 Subpart UUU of this chapter, where Subpart UUU references this subpart J or individual 

sections of this subpart.”

Response: While we understand the desire to allow compliance with subpart Ja to fulfill 

the requirements of Refinery MACT 2, it is inappropriate to effectively put the suggested 

Refinery MACT 2 alternative in subpart Ja. It is much more appropriate to include this 

alternative directly in subpart UUU. Refinery MACT 2 is currently under review, and we intend 

to include subpart Ja as a compliance option for subpart UUU (where appropriate) in future 

amendments to subpart UUU. 

Comment: Commenters 0304 and 0311 supported the EPA’s proposal at 

40 CFR 60.100(e) of subpart J to allow affected sources subject to subpart J to elect to comply 

with the corresponding provisions of subpart Ja. However, Commenter 0304 requested 

clarification as to whether the “election” is only available on a “whole refinery” basis or if the 

election can be made on an “affected source” basis.

Response: The election would be made on an individual affected facility basis, not the 

entire refinery. For example, if a facility has two FCCU subject to subpart J requirements, the

owner or operator may elect to comply with subpart J requirements for one FCCU and subpart Ja 

requirements for the second FCCU.

Comment: Commenter 0309 recommended that the EPA explicitly include in subpart J 

the fuel gas H2S concentration limit in units of ppmv that is equivalent to 230 milligrams per dry 

standard cubic meter (mg/dscm) (as it did in subpart Ja), since concentration is measured in units 

of ppmv and the proper conversion has been a source of significant debate.

Response: We specified the fuel gas combustion device H2S concentration limit in 

subpart Ja in units of ppmv because the continuous monitors used to demonstrate compliance 

generally output the H2S concentration in ppmv. We expect that the inclusion of the short-term 

162 ppmv H2S concentration limit in subpart Ja should help to resolve debates about the proper 
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conversion. However, we decided not to specifically include this limit in subpart J because many 

permits specify the H2S concentration limit in terms of ppmv and the concentration limits in 

these existing permits may range from 160 to 164 ppmv. We did not want to require repermitting of these facilities, reprogramming of monitoring equipment and/or potential 

retroactive non-compliance issues that could occur with this “new” emissions limit if we had 

specified the H2S concentration limit as 162 ppmv in subpart J.

Comment: Commenter 0311 stated that 40 CFR part 63, subpart LLLLL indicates at 

40 CFR 63.8681(e) that subpart J does not apply for asphalt blowing stills subject to subpart 

LLLLL. 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 H2S concentration limits (or alternative SO2 emissions limits). We 

reviewed 40 CFR 60.100a, but we feel a blanket exemption from 40 CFR part 60, 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).

2.6 Equivalence with State and Local Rules

Comment: Several commenters addressed the EPA’s request for comment on “the 

equivalency of the subpart Ja requirements as proposed to be amended today and the [South 

Coast Air Quality Management District (SCAQMD) Rule 1118]” and “whether the 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). Commenter 0307 disagreed with the EPA’s position, 

alleging that the “EPA’s suggestion that it can waive compliance with the NSPS in this manner is 

contrary to the Clean Air Act.” The commenter stated that the EPA’s suggestion “that existing 
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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 and request permission to comply with the alternative method in lieu of 

the federal standard. Therefore, the commenter asserted, the CAA clearly states that the “EPA’s 

authority to waive federal work practice standards is case specific.” Finally, the commenter 

stated that the EPA did not explain how emissions reductions achieved through compliance with 

SCAQMD Rule 1118 are equivalent to subpart Ja. Further, the commenter asserted that the EPA 

neither identified other state rules that could be considered equivalent, nor explained how the 

EPA would determine that a specific state or local rule is equivalent to subpart Ja. Therefore, the 

commenter stated, it is impossible to fully assess the merit of the EPA’s idea and provide 

meaningful comments.

Commenter 0315 responded to Commenter 0307’s comments. Commenter 0315 noted 

that it appears that Commenter 0307 argues that if state regulations are more stringent than the 

proposed requirements for subpart Ja, then the subpart Ja proposed requirements cannot be 

“best” demonstrated technology. The commenter stated that the existence of more stringent 

control measures is not per se fatal to an EPA BSER determination because “most stringent” is 

not the criteria that must be applied under the law to determine BSER. In response to Commenter 

0307’s statement that the EPA must grant permission to use alternative methodologies on a caseby-case basis, Commenter 0315 stated that the EPA has full authority to establish alternative 

regulatory standards that are determined to be as stringent as or more stringent than BSER. The 

commenter noted that CAA section 111(h)(3) generally applies after the EPA has completed a 

national rulemaking and an owner or operator requests approval for a site-specific alternative at a 

later date. In this instance, 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 – which, in essence, requires EPA to amend 

the regulation to accomplish the site-specific alternative).” Finally, Commenter 0315 noted that 
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Commenter 0307 did not consider the documents on record for the original proposal of subpart 

Ja, which demonstrate that the subpart Ja flare requirements are based on and almost entirely 

consistent with SCAQMD Rule 1118. The commenter noted that the EPA determined that 

SCAQMD Rule 1118 constituted BSER for flares and designed subpart Ja so that affected flares 

would be subject to similar requirements.

Commenters 0304, 0306 and 0311 recommended that refineries complying with 

California flare rules, specifically SCAQMD Rule 1118 (Commenters 0304 and 0311) and Bay 

Area Air Quality Management District (BAAQMD) Regulation 12-12 and 12-11

(Commenter 0311) be deemed in compliance with subparts J and Ja. According to Commenter 

0304, SCAQMD Rule 1118 is “in all respects equivalent to or more stringent than the 

corresponding requirements” of subparts J and Ja. Although Commenter 0311 did note that the 

FMP in SCAQMD Rule 1118 is only required for facilities that fail to achieve sulfur oxides 

(SOX) emission reduction targets, the commenter asserted the subpart Ja FMP provided no 

greater emission reduction incentive or mechanism than the SCAQMD Rule 1118. Commenter 

0311 recommended that the EPA add a paragraph (e) to 40 CFR 60.103a that states: “Local rules 

that are equivalent to these work practice standards (Section 60.103a) satisfy the requirements of 

this section, including South Coast AQMD Rule 1118 and Bay Area AQMD rules 12-11 and 12-

12.” The commenter also requested a similar paragraph be added to 40 CFR 60.107a(e) to allow 

the monitoring methods used in SCAQMD Rule 1118 and BAAQMD Regulation 12-12 and 12-

11 to be acceptable under subpart Ja.

Commenter 0315 provided a table comparing each of the six proposed FMP requirements 

in 40 CFR 60.103a(a) to the SCAQMD and BAAQMD regulations. The commenter’s table 

identified sections of BAAQMD Regulation 12-12 and 12-11 that are equivalent to the six 

subpart Ja FMP requirements, but 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 Commenter 0311 

noted that SCAQMD Rule 1118 requires minimization of all flaring, including fuel gas 

imbalance). Based on this information, the commenter stated that facilities already complying 

with SCAQMD Rule 1118 or BAAQMD Regulation 12-12 and 12-11 are already meeting 

requirements equivalent to or more stringent than BSER, so these facilities should not have to 

meet different requirements under subpart Ja.
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Commenter 0315 also noted that BAAQMD Regulation 12-11 allows periodic sampling, 

and the commenter stated that for flares used mostly for startup, shutdown and upset/malfunction 

(SSM) events, a sampling system accurately calculates the total sulfur emissions, is relatively 

cost effective and is more reliable than the continuous composition monitors in use for this 

purpose. Therefore, the commenter requested that the EPA consider BAAQMD Regulation 12-

11 to be equivalent to total sulfur monitoring for SSM 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 40 CFR part 60, subpart Ja would actually be implemented in 

subpart Ja. The EPA will not “waive” the obligation to comply with subpart Ja if the source is 

complying with SCAQMD Rule 1118 or BAAQMD Regulation 12, Rule 11 and Regulation 12, 

Rule 12. In other words, the 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 40 CFR part 60, 

subpart Ja requirements we are finalizing. 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 from the subpart Ja FMP 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 provisions for determining compliance with the flare 

requirements in 40 CFR part 60,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 
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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 to comply with the FMP requirements of 40 CFR 60.103a(a) 

and (b) and the RCA 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 elect to comply with the combined monitoring requirements of 

both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 to comply 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 FMP (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 40 CFR part 60, 

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.
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3.0 DEFINITIONS

3.1 Air Preheat

Comment: Commenter 0311 stated that the definition of “air preheat” is not used in the 

rule and should be deleted.

Response: The term “air preheat” is used within the definition of “forced draft process 

heater” so we have retained the definition in the final amendments.

3.2 Co-Fired Process Heater

Comment: Commenters 0308 and 0311 stated that the definition of “co-fired process 

heater” should be revised to remove reference to “burners that are designed” to be supplied by 

both gaseous and liquid fuels because co-fired process heaters almost always use different burner 

tips. The commenters recommended: “Co-fired process heater means a process heater designed 

to be supplied by both gaseous and liquid fuels.”

Response: It appears that there is some confusion regarding what is meant by “burners”

within this definition. We intended that a “burner” refers to each location in the process heater 

designed to produce a flame to impart heat to the system. A single burner that is designed to be 

supplied with both gaseous and liquid fuels is expected to have separate burner tips within the 

burner, but both burner tips are part of the single burner location. If a process heater has some 

burners that can only be fired with gaseous fuels and other burners that can only be fired by 

liquid fuels, these process heaters are not considered co-fired process heaters. The gas burners in 

such a process heater can employ ultra-low NOX burners capable of meeting the emissions limit 

in the same manner as conventional gas-fired process heaters, and these process heaters should 

demonstrate compliance with the rule when firing only with the gas burners. Burners that are 

designed with multiple tips (so that the single burner can be supplied by both gaseous and liquid 

fuels) have different design considerations, because staged fuel is generally needed for reducing 

NOX in gas-fired burners, where staged air is used to reduce NOX in oil-fired burners. These

burners (i.e., those with both types of burner tips in the same burner) cannot be designed to stage 

both air and fuel. As such, these burners can be either designed for staged air to limit NOX while 
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firing oil but will have conventional gas-fired burners, or the burners can be designed for staged 

fuel to limit NOX when firing gaseous fuels but will have conventional burners for fuel oil. If a 

process heater has completely separate burners, some dedicated for gaseous fuels and some 

dedicated for liquid fuels, each individual burner could be designed and optimized for its fuel 

type. As such, we determined that it is inappropriate to revise the definition of co-fired process 

heater as requested by the commenter. Furthermore, we find that gas-fired process heaters that 

have emergency oil back-up burners in the event of a natural gas curtailment should employ gas 

burners that are optimized for firing gas using staged fuel ultra-low NOX burners because they do 

not routinely fire oil. Therefore, we revised the definition of co-fired process heaters to clarify 

that co-fired process heaters are process heaters that are designed to be supplied by both gaseous 

and liquid fuels on a routine basis. We further clarify in the definition that process heaters that 

have gas burners with emergency oil back-up burners are not considered co-fired process heaters.

We clarify in this response that a process heater that contains gas burners with emergency oil 

back-up burners must comply with the NOX limits for conventional gas-fired process heaters. 

3.3 Corrective Action Analysis

Comment: Commenter 0305 stated that the definition of “corrective action analysis” 

should not include the word “all” because it places unnecessary burden on the facility to 

document “all” potential corrective actions (and subjects the facility to liability if it does not

include all possible actions) rather than focusing on the most promising.

Response: We disagree that the proposed definition of “corrective action analysis” 

requires the facility to describe “all” potential corrective actions or otherwise puts undue burden 

on the refinery owner or operator. The actual definition requires “a description of all reasonable 

interim and long-term measures.” The inclusion of the word “reasonable” modifies and limits the 

term “all.” The phrase “all reasonable” clarifies the requirements to perform a comprehensive 

analysis while limiting the need to document unreasonable measures. Deleting the word “all” is 

unlikely to alter the agency’s interpretation of the requirement, and only acts to make the 

requirement less clear. Therefore, we respectfully disagree with the commenter and retain this 

portion of the definition of “corrective action analysis” as proposed. 
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3.4 Delayed Coking Unit

Comment: Commenters 0305 and 0311 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 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 40 CFR part 60, subpart Ja, such as the 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 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.
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3.5 Flare

Comment: Commenter 0308 and 0311 recommended deleting “knock-out pots, piping 

and header system” from the definition of “flare” because piping and header systems are not 

“equipment used to combust fuel gas” and should not be part of a fuel gas combustion device.

Commenter 0308 stated that, if the EPA retains this expanded definition, then the EPA should 

clarify that the other fuel gas combustion devices are limited to just the “equipment used to 

combust fuel gas” and do not include the fuel gas lines. Commenter 0311 stated that if “knockout pots, piping and header systems” are included, the flare’s knock-out pot, piping and header 

system must be clarified since numerous process units have knock-out pots and nearly all will be 

connected either directly or indirectly (via the fuel gas system) to a flare. As such, the entire fuel 

gas system could be considered part of the flare header system. The commenter also requested 

that the definition include a primary use clause so as to clarify the affected facility in cases of 

interconnected flare systems. Commenter 0311 recommended: “Flare means an open-flame fuel 

gas combustion device used for burning off unwanted gas or flammable gas and liquids. The 

flare includes the foundation, flare tip, structural support, burner, igniter, flare controls including 

air injection or steam injection systems, flame arrestors, and knockout pots, piping and header 

systems from process units, fuel gas systems or FGR systems to a flare tip. Knockout pots, 

piping and headers shared among multiple flares are assigned on a primary use basis.”

Commenter 0315 also stated that the flare should not include the piping within process 

units and fuel gas systems. The commenter recommended that the EPA clearly differentiate the 

boundary between the refinery process unit, the fuel gas system and the flare. The commenter 

noted that main lines from individual refinery process units and fuel gas systems to flares are 

generally equipped with battery limit isolation valves, and these valves define the “battery 

limits” of the process unit or fuel gas system. The commenter recommended that the EPA revise 

the flare definition to state that: (1) a “flare” includes only the knockout pots, piping and headers 

outside of a process unit’s or fuel gas system’s battery limits; and (2) any new piping or 

connections that are made inside the process unit's or fuel gas system’s battery limits are not 

modifications to the flare. The commenter noted that new piping that is added outside of the 

process unit’s battery limits or the fuel gas system that either results in a new connection from 

the process unit or fuel gas system to the flare or increases the capacity of an existing flare 

system to handle more flow (e.g. increasing the size of a flare header or a knock out pot) would 
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be a modification to the flare. The commenter provided a diagram of an example refinery to 

illustrate their points.

Response: We agree that a clarification is needed to distinguish between the flare header 

system and the fuel gas system. We have added a definition of “flare gas header system” to

clarify this issue; see the response to the next comment for further details. We have also listed 

flares as a completely separate affected facility, so we do not believe a clarification to the 

definition of fuel gas combustion device is needed to specifically state that the fuel gas system is 

not part of the fuel gas combustion device. With respect to interconnected flare systems, we 

disagree that a primary use clause is needed because we determined that each flare in an 

interconnected flare system is modified when a connection meeting those defined for a flare 

modification is made to such a system. Please see Section 2.3 of this document for more details.

Comment: Commenter 0313 requested that the definition of “flare” include the FGR

system. The commenter noted that in the BAAQMD, the flare header collects both the episodic 

gas that needs to be sent to the flare device for safe disposal as well as the routine gas that is sent 

back to the refinery fuel gas system. The commenter noted that refiners in the BAAQMD are 

submitting permit applications asserting that all flare header systems upstream of the seal pot are 

separate from the flare because during normal operation, these flare headers serve to collect the 

gas that is redirected to the fuel gas system by the FGR system. The commenter noted that this 

interpretation seems inconsistent with the EPA’s stated intention in the preamble to the proposed 

amendments to include the flare gas header system in the definition of “flare.” The commenter 

stated that the EPA should explicitly include the FGR system in the definition to eliminate any 

confusion and clarify the agency’s intent.

Response: We have added a definition to clarify what is included in the flare gas header 

system. We specify that all piping used to transport gas to a flare either directly from a process 

unit or directly from a pressure relief valve from the fuel gas system is part of the flare gas 

header system, regardless of whether or not the flare gas header system includes a FGR system

(i.e., regardless of whether or not a FGR system draws gas from the flare gas header system).

Consistent with this definition, we note that if a FGR system is present, it is considered to be part 

of the flare gas header system.
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3.6 Fuel Gas

Comment: Commenters 0304, 0305 and 0311 supported the amended definition of “fuel 

gas” as it pertains to coke calciners. Commenter 0304 suggested the same amendment be made 

to the definition of fuel gas in subpart J. Commenters 0305 and 0311 suggested that the 

definition be clarified to list all types of premium coke (specifically recarburizer coke, needle 

coke and metallurgical coke) in addition to anode grade coke.

Response: We agree that the final disposition of the premium grade coke is not important 

and have generalized the parenthetical to simply read “used to make premium grade coke.” As 

any new, modified or reconstructed fuel gas combustion device will be subject to subpart Ja 

rather than subpart J going forward, there is no need to revise the definition of fuel gas in subpart

J at this point in time.

Comment: Commenter 0309 suggested that the exclusion in the definition of “fuel gas” 

be extended to vapors combusted to comply with the storage vessel requirements in 40 CFR 60,

subparts K, Ka, Kb (NSPS for storage vessels) and 40 CFR part 63, subpart CC (Refinery 

MACT 1) because these are low pressure vapor streams and most have low sulfur content. The 

commenter stated that at least certain storage vessels (reformate, alkylate, gasoline) should be 

exempt due to low sulfur content.

Response: We disagree that the definition of fuel gas should exclude vapors from storage 

vessels. While some storage vessels may be remotely located, many of these storage vessels are 

located near refinery process units or each other so that combined collection and, if necessary, 

treatment of the gases can be accomplished cost effectively. The current provisions in subpart Ja 

(and subpart J) contain an exemption from the continuous H2S monitoring requirements for gases 

that are inherently low sulfur or can be determined to be low sulfur. As such, the current 

provisions for low sulfur fuel gas adequately address the commenter’s issue without needing to 

exempt certain types of storage vessels from the definition of fuel gas.

Comment: Commenter 0311 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, 

Commenter 0311 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 
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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 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 

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 
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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 considered air pollution control devices that were 

mandated by the EPA, we see no reason to discriminate against air pollution control devices that 

were installed voluntarily to reduce the emissions from these sources. Further, we intend to 

clarify that gases off the sour water system, including the sour water stripper, would likely 

contain higher amounts of reduced sulfur and would be economically viable to treat. Therefore,

we are also clarifying that the exemption does not extend to the sour water system. Therefore, the 

amended definition of “fuel gas” in both 40 CFR part 60, subparts J and 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 other than those processing sour water, 

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 40 CFR part 60, 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 a reasonable rationale 

as to why the vapors from these activities should be exempted.

Comment: Commenter 0311 noted that the reference to 40 CFR 60.692 was missing in 

the revised definition of “fuel gas” and that “through” was misspelled.

Response: We appreciate the comment and acknowledge that the proposed definition did 

include an inadvertent error. We have removed the section that contained the error from the final 

definition.
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3.7 Fuel Gas Combustion Device

Comment: Commenter 0308 recommended that the EPA delete flares from the definition 

of “fuel gas combustion devices” and create a separate affected facility covering only flares so 

that flares can be regulated in a targeted, coherent and consistent fashion.

Response: We agree. Due to the numerous special definitions and standards that apply to 

flares, we determined that the requirements for flares and for fuel gas combustion devices would 

be clarified if fuel gas combustion devices and flares were defined as separate affected facilities.

Therefore, the final rule defines a flare as an affected facility rather than including flares as a 

type of fuel gas combustion device.

Comment: Commenter 0305 suggested clarifying the definition of “fuel gas combustion 

device” to clarify that the fuel gas combustion device is located at the petroleum refinery.

Response: We do not agree that the requested clarification is necessary. A fuel gas 

combustion device is defined as “any equipment, such as process heaters and boilers, used to 

combust fuel gas.” Section 60.100a(a) states that “the provisions of this subpart apply to” fuel 

gas combustion devices (including process heaters) “in petroleum refineries” (emphasis added).

Therefore, the final rule already specifies that a fuel gas combustion device must be located at a 

petroleum refinery to be an affected source subject to subpart Ja.

We do note that the definition of “fuel gas” is “any gas which is generated at a petroleum 

refinery and which is combusted.” The definition does not specify that fuel gas must be 

combusted at a petroleum refinery, and it is not our intention for that definition to be interpreted 

as such.

3.8 Natural Draft and Forced Draft Process Heaters

Comment: Commenter 0296 indicated that there are four classes of process heaters and it 

is unclear whether balanced draft or induced draft process heaters are considered natural draft or 

forced draft process heaters. The commenter suggested that the EPA should clarify the definition 

of “forced draft process heater” to include these configurations. Commenter 0305 also requested 

clarification that induced draft process heaters are considered forced draft process heaters.

Commenter 0311 noted that in general, induced draft fans do not affect process heater NOX

controls, but for process heaters with downwardly firing burners, the induced draft fan is used to 

move the combustion gases through the entire process heater, not just the convection section, and 
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those process heaters experience NOX control issues similar to forced draft process heaters. As 

such, Commenter 0311 recommended that “process heaters with downward firing burners that 

are equipped with an induced draft fan” be included in the definition of “forced draft process 

heater.” Commenter 0311 also requested that the definition be clarified based on the design 

rather than the operation. The commenter noted that operators of some forced draft process 

heaters may shut down the fan to perform maintenance on the fan or preheat system while still 

operating the process heater and requested clarification on whether the process heater is still 

subject to the forced draft process heater NOX limits during those periods.

Response: There are essentially four types of process heaters: (1) natural draft process 

heaters with no fans; (2) induced draft process heaters with a fan on the exhaust line; (3) supplied 

draft process heaters with a fan on the inlet air (more commonly referred to as forced draft 

process heaters); and (4) balanced draft process heaters with fans on both the inlet air and on the 

exhaust air (typically used for air preheat). The definition of forced draft process heater clearly 

includes both “supplied draft” and “balanced draft” process heaters as these systems have fans in 

the inlet air line prior to the air entering the process heater or air preheat. The definition of forced 

draft process heater just as clearly excludes induced draft process heaters because these process 

heaters do not have a fan in the inlet air line. The definition of natural draft process heaters 

includes induced draft process heaters because induced draft process heaters do not have a fan on 

the inlet air (i.e., they are not “forced draft” process heaters). Nonetheless, the definitions are 

somewhat confusing given the inclusion of “under positive pressure” for forced draft systems 

and “under ambient pressure” for natural draft systems. We have clarified these definitions to 

more clearly indicate that, for the purposes of subpart Ja, balanced draft systems are considered 

forced draft process heaters and induced draft systems are considered natural draft process 

heaters.

The commenters provided no direct data on “downwardly firing burners” or specifics as 

to why these units could not meet the 40 ppmv NOX emissions limit. Based on the operations of 

these burners, we think that they can meet the same limits as natural draft units, but given the 

lack of data for this argument, we have included downwardly firing induced draft burners in the 

list of process heaters that that may apply for a site-specific NOX emissions limit. If a process 

heater equipped with downwardly firing burners is modified or reconstructed, the owner or 
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operator of the process heater should strive to meet the 40 ppmv emissions limit but may apply 

for a site-specific emissions limit if the process heater cannot meet that limit.

We intended the emissions limits and the definitions of the process heaters to be based on 

the operation of the heater (except for co-fired process heaters, the definition of which is design 

based). According to comments received, including design performance levels from low-NOX

burner vendors for process heaters that are designed to operate in both natural draft mode and 

forced draft mode, the burners can achieve the 40 ppmv (or 0.040 pounds per million British 

thermal unit [lb/MMBtu]) NOX emissions limit while operating under natural draft conditions 

even though it cannot meet this limit while operating in the forced draft mode, specifically 

because of the higher inlet air temperatures when using air preheat. Based on the available 

information, we conclude that the natural draft emissions limit is appropriate and BSER when 

the process heater is operating in natural draft mode even if the unit is “designed” to operate as a 

forced draft process heater. Therefore, we made no changes to the definitions of “forced draft 

process heater” and “natural draft process heater” as a result of this comment.

3.9 Process Upset Gas

Comment: Commenter 0303, 0305, 0306, 0308 and 0311 supported the amended 

definition of “process upset gas” to include startup and shutdown and stated that the FMP is 

effective in reducing SSM emissions. Commenter 0315 provided specific examples of planned 

startups and shutdowns in which flaring is necessary for the proper operation of the unit and the 

process train. Commenter 0302 requested that the definition of “process upset gas” include “gas 

generated during periods when the fuel gas desulfurization system is down for maintenance in 

accordance with the manufacturer’s recommendations and good operating practices” as it is 

unclear if these maintenance periods can be considered “malfunctions.” If this provision in not 

provided, the EPA should revise its cost analysis to include back-up desulfurization systems, 

which would be needed if these periods cannot be excluded.

On the other hand, Commenter 0313 requested that the EPA not finalize the addition of 

planned startups and shutdowns to the definition of “process upset gas.” The commenter stated 

that planned startups and shutdowns are a major cause of flare emissions, and unlike emergency 

situations, refineries have the ability and resources to mitigate flare emissions during a planned 

event. If the EPA adds startup and shutdown to the definition, then a large amount of the 
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emission reductions associated with subpart Ja will not be realized. In a subsequent letter 

(Comment 0316), the commenter clarified this comment, noting that while many refineries in the 

BAAQMD have found alternatives to flaring during planned startups and shutdowns by 

modifying the design of new flares, it may not be possible for all new flares to be designed to 

avoid flaring during all startups and shutdowns. The commenter also noted that BAAQMD

Regulation 12-12 is based on a FMP approach. The commenter stated that if the EPA concludes 

that it is not reasonable to promulgate the fuel gas combustion device sulfur standards for new 

flares as originally proposed (i.e., if startup and shutdown gases are included in the definition of 

process upset gas), then the FMP approach would be an alternative way to address flaring 

emissions from startups and shutdowns that would provide significant benefits.

Response: The only impact of including startup and shutdown gases within the definition 

of process upset gas is to exclude these gases from the H2S concentration requirement. As an 

example, the planned shutdown of a reactor vessel usually involves purging the vessel with 

nitrogen. After the first few purge sequences, the purge gas may have very little Btu content, so 

that the gas cannot be recovered in the fuel gas system, but the gas may contain concentrations of 

H2S that exceed 162 ppmv, depending on the reactor vessel contents. Flaring this gas to destroy 

H2S is the best environmental practice, and it is not feasible to recover this gas, nor is it cost

effective to treat this gas separately to reduce its H2S concentration to below 162 ppmv.

Therefore, we cannot conclude that requiring refiners to limit the short-term fuel gas 

concentration to 162 ppmv H2S determined hourly on a 3-hour rolling average basis is BSER for 

planned startup or shutdown for all refinery process units at a petroleum refinery. However, we 

have placed requirements on the flares to address releases during startups and shutdowns. The 

FMP effectively addresses flare flow from planned startup and shutdowns as it requires 

minimization of the amount of gas discharged to a flare under 40 CFR 60.103a(a)(5). The rule 

also requires RCA to be performed if more than 500 pounds (lb) of SO2 are discharged from a 

flare in a 24-hour period under 40 CFR 60.103a(c), and this requirement applies to process upset 

gas (including planned startup and shutdowns that do not follow the procedures in the FMP).7

These requirements effectively limit discharges of planned startup and shutdown gases to the 

flare, and these provisions in subpart Ja are expected to yield significant emission reductions 

 7 While we expect that most process upset gas will be combusted in flares, it is important to note that the rule also 

requires RCA to be performed if SO2 emissions exceed the short-term 162 ppmv H2S concentration limit for a 

fuel gas combustion device by more than 500 pounds.
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compared to the requirements in subpart J. Consequently, we conclude that the inclusion of 

startup and shutdown gases in the definition of “process upset gas” is necessary and aligned with 

our BSER assessment for flares, and that the BSER for startup and shutdown events is a standard 

for flares that requires the owner or operator to have and follow a FMP and to perform root cause 

and corrective action analyses when these procedures are not followed.

With respect to maintenance of fuel gas desulfurization units, we find that the fuel gas 

desulfurization unit is a control device used to meet the fuel gas standards. Continuing to operate 

fuel gas combustion devices unabated when the control system for fuel gas is down for any 

reason, including maintenance, startup, shutdown, malfunction or upset, is inconsistent with 

good air pollution control practices. The requested maintenance exemptions are not in subpart J, 

which is the baseline case for the cost analysis. Additional treatment capacity needed for these 

cases is expected to exist under subpart Ja; our cost analysis considered the additional costs of 

complying with subpart Ja (i.e., the additional long-term 60 ppmv H2S concentration limit) that 

were in addition to those costs already imposed due to subpart J requirements. In our cost 

analysis, we did assume some units would not have enough existing excess capacity to meet the 

long-term 60 ppmv H2S concentration limit, and would have to install additional amine treatment 

systems. We conclude that the cost analysis conducted for fuel gas combustion devices

adequately reflects the incremental costs of subpart Ja. Therefore, the final amendments to 

subpart Ja do not include the requested maintenance exemption. 

Comment: Commenter 0308 suggested that “startup” be used in the definition of “process 

upset gas” (rather than “start-up”) to conform with the term “startup” in 40 CFR 60.2.

Response: We agree that “startup” is consistent with the General Provisions of 40 CFR 

part 60, and it appears more frequently than “start-up” throughout subpart Ja. For consistency, 

we have revised the occurrences of “start-up” to read “startup.”

3.10 Refinery Process Unit

Comment: Commenters 0305 and 0311 objected to the change to the definition of 

“refinery process unit” to include coke gasification, loading and wastewater treatment, stating the 

change makes the term more expansive. The commenters stated that the EPA did not evaluate the 

impacts or explain the consequences of the revised definition. Commenter 0311 also stated that 

product loading is generally considered part of the refinery process unit to which it is associated 
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and wastewater treatment is a utility. Commenter 0305 suggested that the definition specify SIC 

2911 (as in Refinery MACT 1).

Response: The original definition of “refinery process unit” in 40 CFR part 60, subpart J

and the definition of “refinery process unit” promulgated in 40 CFR part 60, 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.

We reviewed the impact of the proposed revision of this definition on 40 CFR part 60, 

subpart Ja as well as its historic use in 40 CFR part 60, 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,” the 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 the EPA considered “refinery process units” and “process units in a refinery” to 
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have the same meaning, and there is no mention of limiting what is considered 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), 60.103a(h). 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 requirement 

to limit short-term H2S concentration in fuel gas to 162 ppmv 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 40 CFR part 60, 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 FMP consider 

flare 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 40 

CFR part 60, 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 FMP. We have included in the final 

amendments a definition of “ancillary equipment.” Specifically:
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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.

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 FMP. 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 40 CFR 

part 60, 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 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 40 CFR part 60, subpart Ja.
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3.11 Sulfur Recovery Plant

Comment: Commenter 0305 requested a clarification in the definition of “sulfur recovery 

plant” to exclude loading facilities (in addition to secondary storage vessels).

Response: We agree and have revised the final definition. We also corrected an 

inadvertent omission of the word “produced” in the definition. The “sulfur recovery plant” need 

not be located at a petroleum refinery, but, for the purposes of subpart Ja, is limited to units that 

recover sulfur from sour gases “produced at a petroleum refinery.”
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4.0 FUEL GAS COMBUSTION DEVICES AND FLARES

4.1 Emissions Limits

4.1.1 Long-Term H2S Concentration Limit for Fuel Gas Combusted in Flares

Comment: Commenters 0296, 0301, 0305, 0310 and 0311 asserted that the EPA did not 

properly demonstrate that the long-term 60 ppmv H2S fuel gas concentration limit is BSER for 

flares as fuel gas combustion devices because the EPA underestimated the cost of treating the 

flare gas and overstated emissions reductions. According to Commenter 0296, flare gas treatment 

would require a compressor system for each flare header and would be more likely to require 

additional amine treatment systems and/or sulfur recovery units than the EPA estimated. The 

commenters also suggested that the EPA overestimated the value of the recovered flare gas 

because the Btu content of flare gas is highly variable and generally lower than that used by the 

EPA. Commenter 0311 stated that many refinery streams currently sent to the flare contain H2S 

concentrations between 60 and 162 ppmv, and requiring fuel gas to meet a long-term 60 ppmv 

H2S concentration limit would result in significant re-piping and capital investment for minimal 

emission reductions, which the EPA’s impact analysis did not consider. Commenter 0311 also 

asserted that the emission reductions were overstated (i.e., the EPA should not use 162 ppmv as 

current long-term performance at baseline) and that the model analysis was oversimplified and 

neglected to account for the range of costs that are incurred by individual refineries.

Commenter 0301 asserted that the long-term 60 ppmv fuel gas H2S concentration limit for flares 

does not meet the BSER cost effectiveness test as required by the CAA, particularly when 

evaluating the SO2 reductions incremental to those achieved by consent decrees.

Commenter 0301 suggested that a long-term 60 ppmv fuel gas H2S concentration limit 

for flares would cost $360-460 million and only reduce SO2 emissions by 190 tons per year 

(tons/yr), which the commenter estimated to be a cost effectiveness of $326,000 per ton of SO2

reduced. Commenter 0310 provided costs estimates for: (1) additional amine systems of actual 

projects showing cost effectiveness of $44,000 to $63,000 per ton of SO2 reduced; (2) FGR

systems with cost effectiveness of $25,000 to $65,000 per ton of SO2 reduced (details of the 
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58

commenter’s estimate are confidential); and (3) FGR system expansions, which included an 

additional compressor, surge storage capacity, and amine scrubber capacity, showing cost

effectiveness of recovery system expansions to be $300,000 to $400,000 per ton of SO2 reduced.

While most of their comments focused on flares, Commenter 0310 also stated that a long-term 

60 ppmv fuel gas H2S concentration limit is improper for fuel gas combustion devices in general 

because it could preclude some refineries from processing high-sulfur crude oils, thereby 

limiting refining production capacity.

Commenter 0296 noted that the flare will receive both “fuel gas” and exempt gas streams 

(“process upset gas” as well as gas from pressure relief valve leakage), so it is impossible to 

determine if any emissions limit exceedance is caused by the regulated “fuel gas” or by the

exempt gas. Commenter 0296 recommended that the EPA allow Alternative Monitoring Plans to 

demonstrate compliance with the fuel gas emissions limits for non-exempt gas streams upstream 

of the flare header. Alternatively, Commenter 0296 recommended that the long-term 60 ppmv 

H2S fuel gas concentration limit be applicable only to the refinery fuel gas system and not to the 

refinery flare system.

Response: We acknowledge that, at proposal, we determined that a long-term 60 ppmv 

H2S fuel gas concentration limit was cost effective 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 Docket Item No. 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 fuel gas sent to flares.

In developing the suite of CAA 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 demonstrate that 
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their fuel gas complies with a long-term H2S concentration of 60 ppmv, refineries would have to 

install a FGR 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 on each 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 cost effective 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, 40 CFR part 60, 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 

($1000/ 

yr)

Emission 

reduction 

(tons 

SO2/yr)a

Emission 

reduction 

(tons 

NOX/yr)a

Emission 

reduction 

(tons 

VOC/yr)a

Cost

effectiveness 

($/ton)

New 80,000 15,000 6 34 130 84,000

Modified / 

Reconstructed 860,000 160,000 53 310 1,200 100,000

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 (i.e., these are the incremental emission reductions achieved from a baseline of 

optimizing management of the fuel gas system to limit the short-term H2S concentration in the fuel gas to 162 

ppmv to the originally proposed combined short-term 162 ppmv H2S concentration and long-term 60 ppmv H2S 

concentration in the fuel gas).
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4.1.2 Alternative Compliance Options

Comment: Commenter 0301 requested that the EPA specifically allow alternative means 

of compliance included in consent decrees as acceptable compliance alternatives for subpart Ja.

Specifically, certain flares have an alternative 500 pounds per day (lb/day) SO2 emissions limit 

in lieu of a requirement to limit the short-term concentration of H2S in fuel gas combusted in a 

flare to 162 ppmv, and the commenter requested assurance that this alternative is sufficient to 

demonstrate compliance with subpart Ja.

Response: The requirements in consent decrees are negotiated settlements and are not 

based on an analysis of BSER, as several commenters have pointed out (although typically to 

argue why certain consent decree requirements should not be the basis of subpart Ja 

requirements). The BSER analysis conducted for this final rule package supports the 

requirements in this national rulemaking. As with any national standard, there will be units 

where the costs to reduce a ton of pollutant emissions (in this case SO2) will be less than the 

average costs projected for the industry and there will be units where the costs are higher than 

the average costs projected for the industry. While we try to consider and, if appropriate, 

minimize the impact of the less cost effective units, we generally base our decision on the 

nationwide costs and emissions reductions achieved. As such, we do not feel compelled to loosen 

the national standard based on the poor cost effectiveness of a very limited number (less than 

1 percent) of flares.

We have conducted specific analyses that consider flares as separate and distinct affected 

facilities from fuel gas combustion devices. While we concluded that a long-term 60 ppmv fuel 

gas H2S concentration limit is not cost effective for flares, we maintain that the requirement to 

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

ppmv H2S during normal operating conditions is cost effective for flares. We also find that the 

500 lb/day SO2 limit is not, in any way, equivalent to the long-standing short-term 162 ppmv 

H2S concentration requirement for these units in subpart J. At 500,000 standard cubic feet (scf) 

in a 24-hour period, the threshold at which a RCA is triggered for flare flow, the fuel gas could 

contain 6,000 ppmv H2S. With a 500 lb/day standard, flares with flow rates below the RCA 

threshold of 500,000 scf in any 24-hour period could exceed the short-term 162 ppmv H2S
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concentration requirement by a factor of 40 without exceeding the 500 lb/day SO2 emissions 

limit requested by the commenters. We do not see this to be, in any way, equivalent to the 

existing limit contained in subpart J, and we are not including this significant exemption from the 

short-term 162 ppmv H2S concentration requirement in subpart Ja.

4.2 Elimination of Routine Flaring

Comment: Commenter 0307 stated that the EPA’s proposed amendments for flares are 

illegal and arbitrary. The commenter noted that when the EPA originally proposed subpart Ja for 

petroleum refineries (see 72 FR 27178, May 14, 2007), the EPA determined that elimination of 

routine flaring through the use of available technologies such as FGR is technologically feasible, 

cost effective and BSER under CAA section 111. However, the final rule (see 73 FR 35838, June 

24, 2008) did not include those requirements, and the commenter asserted that the EPA did not 

adequately explain why the BSER determination for the final rule changed (see 73 FR 35838, 

June 24, 2008). The commenter stated that the EPA did not provide rationale for dismissing 

technology that the agency determined was demonstrated and cost effective in favor of standards 

such as the FMP to manage flare emissions. The commenter also noted that in the June 2008 

final rule, the EPA stated that the prohibition on routine flaring was removed because the EPA 

“could not determine how to define ‘routine’ events.” However, the same final rule included a 

limit on flow to the flare applicable to “normal” operations (i.e., excluding SSM). The 

commenter asserted that “all of these concepts in the final rule require distinguishing between 

routine and exceptional events,” so the EPA’s explanation for the change is “internally 

inconsistent.”

Commenter 0307 asserted that there is no question that FGR is demonstrated technology; 

FGR is commonly used in existing refineries to capture and recycle process gases. Existing 

refineries have been able to significantly reduce or eliminate routine flaring through the use of 

FGR, and other refineries are planning installations, so FGR “may fairly be projected for the 

regulated future.”8 Further, recovery technology can significantly reduce air pollution as well as 

save owners and operators money through recovery of useful flare gas components such as 

hydrocarbons that a refinery can burn as fuel and hydrogen, which is used in several processes 

 8 Lignite Energy Council v. USEPA, 198 F.3d 930,934 (D.C. Cir. 1999) (citing Portland Cement Ass’n v. 

Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973))
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and expensive to make.9 In addition, demand for steam generation is reduced when steamassisted flaring is reduced. The commenter stated that the EPA, the DOE, the Valero refinery in 

Texas and the SCAQMD have found FGR systems to be cost effective. The commenter noted 

that the revised emission estimates presented in the preamble to the proposed amendments do 

more accurately represent emissions from flares than the estimates in the preamble to the final 

standards, but given that increase in emission reductions, the EPA did not explain why both 

eliminating routine flaring and reducing flaring via a limit on flare flow rate are suddenly not 

cost effective. The commenter stated that the EPA should revise the rule to return to the 

originally proposed standard prohibiting all routine flaring because the CAA section 111 

standards must reflect the best technology capable of capturing and eliminating the pollutants of 

concern. At the least, the EPA must provide a new analysis to clearly demonstrate why a 

prohibition on routine flaring using FGR and other technologies is not feasible or cost effective 

when considering the revised emissions reductions.

Commenter 0307 also noted that in the preamble to the final standards, the EPA stated 

that FGR is not technically feasible if a refinery produces more fuel gas than it needs to operate, 

but the commenter stated that the EPA provided no data or rationale to support that claim. The 

commenter also stated that even if the refinery produces more fuel gas than needed, there are 

alternatives to flaring that the EPA did not consider, such as the possibilities of building on-site 

storage for excess gas or selling the gas to third parties; in fact, the EPA stated in the preamble to 

the original proposed rule that the agency believed “other options exist, such as building an 

electric co-generating unit.”

Response: We note that our original proposal (see 72 FR 27178, May 14, 2007) did not 

eliminate all routine flaring, only routine flaring from new “fuel gas producing units.” The 

affected facility in the original proposal was not the flare, but the fuel gas producing unit. For a 

new fuel gas producing unit, the proposed requirements were to minimize releases to the flare 

during startup and shutdown and to eliminate routine flaring of gases from the fuel gas producing 

unit during normal operation. For units that produce significant quantities of fuel gas, refinery 

owners and operators routinely install FGR systems to recover the gas for use as fuel gas in the 

 9 John Zink Company. “Environmental Control With Serious Payback.” Printed February 4, 2009, and included as 

Attachment A to Comment 0307 (Docket Item No. EPA-HQ-OAR-2007-0011-0317).
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63

refinery, so a gas recovery system (compressor) at the fuel gas producing unit was the expected 

method of compliance for an affected fuel gas producing unit at the time of the original proposal.

The problems with the initial proposal were that there were ambiguities in the definition 

of a fuel gas producing unit and in what was meant by “no routine flaring.” As we evaluated the 

proposed rule based on the comments received, we determined that it would be more 

straightforward to make the flare the affected facility in the final rule (see 73 FR 35838, June 24, 

2008). By regulating the flare, given the specific flare modification provision in subpart Ja, we 

actually increased the projected emission reductions of the rule as compared to the reductions 

achieved by regulating only new fuel gas producing units. In other words, the initial proposal 

affected only a portion of the gas sent to a flare, while the final rule affects all of the gas sent to a 

flare. As such, we find that the “flare as the affected facility” paradigm being finalized today is 

environmentally superior to the “no routine flaring from new fuel gas producing units” paradigm 

we originally proposed (see 72 FR 27178, May 14, 2007).

The evaluation of FGR systems included in the docket demonstrates that FGR below 

certain flow rates is not cost effective; therefore, a complete ban on “routine” flaring is not 

BSER (see the “Flare Options Calculator” included as an attachment to Docket Item No. EPAHQ-OAR-2007-0011-0223 and the flare impact memoranda included as Docket Item No. EPAHQ-OAR-2007-0011-0223 and Docket Item No. EPA-HQ-OAR-2007-0011-0289). We do agree 

with the commenter that FGR systems are technically effective at reducing flare emissions. We 

also maintain that it is cost effective to install FGR systems when the flow rate of flare gas 

exceeds a certain threshold. However, the flow threshold at which FGR becomes cost effective is 

dependent on a number of factors, many of which are variable (such as the Btu content of the 

flare gas). The flare gas options calculator was developed to evaluate a range of flow rates, flare 

gas Btu content and other factors to determine the likely range of flows above which FGR would 

be cost effective. Based on the data available at the time, a recoverable flare gas flow rate of 

between 250,000 and 500,000 standard cubic feet per day (scfd) was determined to be the 

threshold at which FGR would be cost effective. In the proposed amendments (see 73 FR 78522, 

December 22, 2008), we proposed to remove the 250,000 scfd flow limit, but we also proposed 

to expand the applicability of the flare flow RCA requirement to routine flaring discharges in an 

effort to address uncertainties on how to define “normal operations” and to account for high 
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daily flow rates that might cause exceedances of the 30-day limit even though “routine” flow is 

low.

The cost effectiveness analysis provided in the docket is not really applicable to fuel gas 

rich facilities because it assumes that the recovered flare gas can be combusted on-site in existing 

process heaters. When we consider the flare as the affected facility, it is necessary to provide 

provisions for flaring during periods when the facility produces more fuel gas than it needs (i.e., 

is fuel gas rich). If a refinery has no place to use the recovered gas, the recovery compressors 

will only re-circulate the gas back to the flare. To eliminate flaring during times when the facility 

is fuel gas rich, the owner or operator would have to find somewhere else to send the fuel gas 

besides the flare. The owner or operator may be able to store the fuel gas until it is needed, which 

would require additional storage tanks, but this alternative has many drawbacks, such as strict 

limitations on excess storage capacity and safety hazards associated with storing the explosive 

gases. Alternatively, the owner or operator could purchase additional boilers, turbines or other 

electric co-generation equipment to extract useful work when combusting the excess gas. In this 

alternative, the excess fuel gas can be turned into steam or electricity that could either be used 

on-site or sent off-site (e.g., electricity supplied to the electric power grid). The additional costs 

associated with the steam- or electricity-generating equipment greatly increases the amount of 

flare gas that would need to be recovered for a FGR/co-generation system to be cost effective, 

and this additional gas would be needed on a routine basis. However, a refinery is not typically 

fuel gas rich consistently all year long. Consequently, it is not cost effective to require FGR

during periods when the refinery is fuel gas rich because of the limited time periods when this 

excess gas is available and the costs associated with purchasing steam or electricity generating 

equipment needed to utilize the excess fuel gas. Furthermore, the few facilities that are 

consistently fuel gas rich typically have made arrangements to sell their excess fuel gas, have 

already installed co-generation units or have made other arrangements to utilize this economic 

asset. We did not fully evaluate a maximum flow rate or other criteria limiting the applicability 

of the fuel gas rich exemption, both because we did not have the data to do so and because we 

did not consider this a likely situation. Additionally, there are a significant number of variables 

to consider when determining the cost and cost effectiveness of a co-generation unit or other type 

of potential control system, making the development of a single national standard highly 

problematic. The agency collected additional data from the petroleum refinery industry through 
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an information collection request during the course of 2011 (see Docket ID No. EPA-HQ-OAR2010-0682), and we are in the process of analyzing the collected data. If fuel gas rich situations 

are found to be more common than we anticipate, we will consider additional emission reduction 

opportunities for these situations at that time. However, based on the information currently 

available, when we considered the flare as the affected source (rather than the fuel gas producing 

unit) and the technology needs to eliminate “routine flaring” during periods when a refinery is 

fuel gas rich, we determined that a “no routine flaring” requirement is not BSER because it is not 

cost effective. Rather, we determined that the development and adherence to a FMP that 

minimizes flaring during periods when the refinery is fuel gas rich is cost effective and therefore 

BSER for occasional times when a refinery is fuel gas rich.

4.3 Flare Flow Rate Limit

Comment: Commenter 0303, 0306, 0308 and 0311 supported the removal of the flow rate 

limit for flares because the FMP and other requirements will reduce flare flow, and flexibility is 

needed in order to accommodate sweep gas requirements for different flares and 

weather/seasonal conditions.

Response: We appreciate these comments; however, as seen by the comments received 

on the flare flow RCA requirements, there remain issues regarding sweep gas requirements, flare 

configurations and weather/seasonal conditions that still need to be addressed with respect to the 

flow RCA. These issues are discussed in detail in Section 4.4.3 of this document. 

4.4 Other Standards for Flares

4.4.1 General Comments on Other Flare Standards

Comment: Commenters 0305 and 0311 were critical of the impact analysis performed for 

the flare standards, stating that: (1) the 2002 National Emissions Inventory (NEI) CO data are not 

representative of process flow (Commenter 0305); (2) the flows or recovery rates were not 

adjusted to consider upsets that would not be recovered and continuous sweep gas flows

(Commenter 0305); (3) the heating value of the waste gas was too high (Commenters 0305 and 

0311); (4) the EPA did not consider net costs when no offset is possible (e.g., when the refinery 

is long on fuel gas or flare gas is poor quality) (Commenters 0305 and 0311); (5) the EPA 

underestimated capital costs for recovery systems (Commenter 0311); (6) the EPA 
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underestimated capital costs for monitoring systems (Commenter 0311); (7) the EPA did not 

consider that for certain types of flares, no sulfur emission reductions are possible (e.g., liquefied 

petroleum gas (LPG) tank, hydrogen or emergency-only flares), but owners and operators still 

incur the cost of installing sulfur monitors on those flares (Commenter 0305); and (8) limited 

data were used to assess emission reductions from RCA (Commenters 0305 and 0311).

Response: We generally disagree with these criticisms of the impact analysis for the flare 

standards. As stated in the preamble to the final amendments, we recognized that the flow 

threshold at which FGR becomes cost effective is dependent on a number of factors, many of 

which are variable (such as the Btu content and flow rate of the flare gas). The flare gas options 

calculator was developed to evaluate a range of flow rates, flare gas Btu content and other factors 

to determine the likely range of flows above which FGR would be cost effective. The costs of the 

systems and monitors came from vendor-reported costs. These costs agree well with or tend to be 

slightly higher than costs for FGR systems collected by the BAAQMD, many of which came 

from refinery industry representatives to support their flare management requirements. We have 

acknowledged that cost credits were used predicated on the ability to productively use the 

recovered flare gas, but we have provided specific exemptions from the flow RCA for periods 

when the refinery may be fuel gas rich. We did apply an 80-percent flare gas recovery efficiency 

to account for upsets that could not be reduced. We have also amended the flare flow RCA 

threshold in 40 CFR 60.103a(c)(1)(ii) to be 500,000 scf above a defined baseline in any 24-hour 

period to account for sweep and purge gas flow.

The flare requirements were established to reduce SO2, VOC, CO and NOX emissions, so 

the analysis was not limited to just sulfur-containing streams. The analysis assumed that the 

average H2S concentration of the recovered flare gas was 60 ppmv, which is well below the 

short-term H2S concentration of 162 ppmv that we are finalizing for fuel gas combusted in flares, 

so this assumption adequately accounts for recovery of gases with very low sulfur content, such 

as LPG. Based on the BAAQMD experience with requiring flare flow monitoring, as well as

recent Differential Absorption LIDAR (DIAL) observations, it appears that the flare flow rates 

extrapolated from the NEI data may seriously underestimate actual flare usage. While this does 

not impact the threshold flow rate at which FGR becomes cost effective, it does impact the 

number of flares and the quantity of emissions reduced as a result of the rule. Based on our 

review of the impact analyses, we find no merit in the criticism suggested by the commenters. If 
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anything, we find that the flare standards may achieve more emission reductions than previously 

projected. We uphold our analysis and the conclusion that the flare standards are cost effective 

and BSER.

4.4.2 Flare Management Plan Requirements

Comment: Commenter 0309 suggested that the EPA’s intention in promulgating a 

different definition of “affected facility” in subpart Ja than the existing definition in subpart J 

was to indicate that existing process units are not subject to the flare standards. The commenter

suggested that the EPA should further clarify this point so that it is clear that existing affected 

facilities are exempt from the flare standards.

Response: The affected facility discussion is different primarily because the flare 

provisions were first published at a different date than the other rule requirements, not to denote 

that the FMP does not cover existing sources connected to a newly modified flare. The FMP

covers all refinery process units and ancillary emission sources (existing and new units) that are 

connected to an affected flare.

Comment: Commenters 0308 and 0311 suggested that the requirement to minimize 

discharges to the flare in proposed 40 CFR 60.103a(a)(1) should specifically address routine 

discharges and include a clause to limit the minimization of flaring to those that: (1) are 

“consistent with good engineering practices” and (2) consider “the cost of achieving such 

emission reduction, and any non-air quality health and environmental impact and energy 

requirements.” These revisions are needed, according to Commenter 0308, because non-routine 

discharges are covered under the RCA and so that the requirement is compliant with the need to 

consider cost under 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 FMP

requirements in 40 CFR 60.103a(a) to more fully describe the types of information that must be 

evaluated and included in the plan.
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As noted in section III.C of the preamble to the final amendments, 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 offset natural gas purchase and other considerations. We find that these factors need to 

be addressed in a site-specific basis and are more appropriately addressed through the FMP. In 

the absence of the specific flow limitation, we have included additional requirements in the FMP

to prompt a thorough review of the flare system so that, as an example, FGR systems are 

installed and used where these systems are warranted. We have also revised the flare 

minimization requirements to require the FMP to be submitted to the Administrator (40 CFR 

60.103a(b)).

As part of the development of the FMP, 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 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 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 

FMP 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: Commenter 0308 requested confirmation that the requirement to include 

procedures to reduce flaring during periods of fuel imbalance in 40 CFR 60.103a(a)(6) does not 

require curtailed production of key fuel gas producing units, which would not be cost effective, 

even though it may be the only means of reducing flaring.
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Response: We agree that the procedures to reduce flaring in cases of fuel gas imbalance 

are not intended to require refineries to curtail production of key fuel gas producing units such as 

the atmospheric distillation column, the FCCU, coking unit or similar processes. We expect that 

refinery owners and operators will consider plans such as procedures for reducing overhead 

condenser temperatures (by increased cooling water recirculation or using refrigerated 

condensers) to minimize the amount of C3 or C4 hydrocarbons that are introduced to the fuel gas 

system, procedures for temporary fuel gas storage if appropriate storage vessels are available onsite or agreements to sell excess fuel gas to neighboring industrial plants. Owners or operators of 

affected flares should document the viable flaring reduction alternatives in their FMP. It is also 

recommended that the owner or operator keep records of the alternatives evaluated, including

why certain options were not considered viable options for inclusion in the FMP.

4.4.3 Root Cause Analysis and Corrective Action Analysis

Comment: Commenter 0296 supported the RCA requirements but noted that 45 days, 

while reasonable, is a short time period for many complex events and this time period should not 

be shortened. Commenters 0301, 0305 and 0311 requested clarification that the RCA was to be 

conducted within 45 days but that not all of the corrective actions would have to be completed 

within 45 days. Commenter 0301 recommended replacing the word “implement” with the word 

“identify” in proposed 40 CFR 60.103a(a)(5), suggesting that this appears to be the EPA’s intent 

based on the implementation schedule described in proposed 40 CFR 60.103a(c). Commenter 

0311 also requested that a provision be added for up to a 6-month extension, with approval, to 

perform RCA evaluations for complicated events or disasters.

Response: We consider the 45-day time period to complete the RCA to be appropriate, 

and we do not believe that an effective RCA can be conducted 6 months after the event. We do 

agree with commenters that some corrective actions may require more time to fully implement. It 

is our intent, however, that the corrective actions that can be implemented within the 45-day 

period be implemented within that timeframe. Therefore, simply replacing the word “implement” 

with the word “identify” in 40 CFR 60.103a(e) (formerly part of 40 CFR 60.103a(a)(5)) does not 

comport with our intent. Instead, we have added 40 CFR 60.103a(e)(2) to cover corrective 

actions that cannot be implemented within 45 days as follows: “For corrective actions that cannot 

be fully implemented within 45 days following the discharge for which the root cause and 
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corrective action analyses were required, the owner or operator shall develop an implementation 

schedule to complete the corrective action(s) as soon as practicable.”

Comment: Commenter 0311 stated that the SO2 and flow RCA should not be triggered on 

a per flare basis, but rather a per upset event basis. The commenter contended that flares 

complying with the short-term 162 ppmv H2S concentration requirement for fuel gas could 

exceed or approach 500 lb SO2 during 24 hours of normal use, and that the per-flare limit 

penalizes facilities with consolidated flare systems (larger individual flares). The commenter also 

noted that the proposed language for flow RCA could be interpreted to require a RCA for every 

minute when a 24-hour accumulation exceeds a threshold and suggested that if the trigger is not 

changed to an event, then it should be evaluated on a calendar day basis, which is much easier to 

implement.

Response: As the flare is the affected facility, triggering the RCA on a per flare basis is 

an obvious and rational approach. With respect to the SO2 RCA, we found that the consent 

decree requirements for a RCA did not consider the allowable SO2 emissions from the flare but 

rather the direct mass emissions (uncorrected for “allowable” emissions). Furthermore, the 

expected “allowable” mass emission correction based on 162 ppmv H2S will be negligible for 

events that trigger the SO2 RCA but not the flow RCA. We disagree with the commenter that 

fuel gas compliant with the requirement to limit the short-term H2S concentration of fuel gas to 

162 ppmv would exceed or approach 500 lb SO2 in any 24-hour period during normal operating

conditions. The flare gas flow rate would have to be 20 million scfd at 162 ppmv H2S to exceed 

500 lb SO2 in any 24-hour period, and in that case, the flare would have already triggered a RCA 

based on the flow rate. We do note that the final rule provides for the establishment of a base 

flow rate per flare under 40 CFR 60.103a(a)(4), which we expect to be higher for larger flares. In 

this manner, the flare flow RCA considers flow above the baseline, effectively considering

“flaring events” and, to the extent possible, eliminating disincentives for large individual flares.

However, we see no reason why flare gas flow rates of the magnitude described above would be 

considered normal operation or baseline flow rates compliant with the FMP requirements in the 

final rule, as amended.

We do clarify in the rule under 40 CFR 60.103a(d) that multiple RCA are not required for 

a single event. This includes both events that last for more than 24 hours or events that exceed 

both the flow and SO2 RCA thresholds. Although not noted by the commenter, the per event 
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method would seem to require accounting for the emissions across all affected flares at the 

refinery. We considered this approach, but we concluded that the allowance to develop a flarespecific baseline flow adequately addresses the disincentives for large individual flares with 

respect to the flow limit. However, the final rule does continue to require evaluation of the SO2

and flow RCA thresholds on a 24-hour basis rather than a calendar day to more accurately 

consider the emissions from a single discharge that lasts less than 24 hours but occurs over 2 

calendar days. For all of the above reasons, we conclude that the final rule requirements (as 

amended) appropriately consider different refinery configurations with respect to the number and 

size of flares and, although the RCA is evaluated on a per flare basis, the final rule, as amended, 

effectively considers the emissions “event” from that flare.

Comment: Commenters 0304 and 0305 stated that the flare flow rate threshold for RCA 

of 500,000 scf in any 24-hour period is arbitrary and cannot be fairly applied to all refineries.

The commenters suggested that the flow threshold should be either deleted (Commenter 0304) or 

replaced with a site-specific limit which appropriately reflects the size and complexity of the 

individual flare system (Commenters 0304 and 0305). Commenter 0304 cited an ultracracker 

flare that cycles from 5 million to 25 million scfd. According to the commenter, this would result 

in meaningless daily RCA, and the commenter asked if this was the EPA’s intent. If the flow 

threshold remains, Commenter 0304 suggested that the following gases should be excluded from 

the calculation of 500,000 scf: (1) hydrogen and nitrogen (i.e., compounds that are not 

hydrocarbons); (2) purge and sweep gas; (3) natural gas added to increase the Btu content of the 

flare gas; and (4) gases regulated by other rules (where the flare is the control device).

Commenter 0315 added that pilot gas should be excluded from the calculation of 500,000 scf gas 

flow. Commenters 0308 and 0311 requested that the EPA clarify that the flow RCA be restricted 

to upsets and malfunctions as initially promulgated on June 24, 2008, because pilot gas, sweep

gas, purge gas and other routine flows would trigger a RCA automatically or with a nominal 

release event and because a RCA can only effectively reduce non-routine flows. Commenters 

0308 and 0311 also noted that the requirements in proposed 40 CFR 60.103a(a)(1) and (4) 

should not be duplicative; proposed 40 CFR 60.103a(a)(1) should focus on routine flows and 

proposed 40 CFR 60.103a(a)(4) should focus on non-routine events.

Commenter 0311 suggested the flow meters required in the rule could be used to identify 

step changes caused by an event from routine flow. Commenter 0315 recommended that the 
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EPA adopt the approach used in the refinery consent decrees to address RCA for recurring 

events. For each “flaring device,” sites may prepare and submit a single RCA for one or more 

root causes found by that analysis to routinely occur. The consent decrees include a provision 

that the owner or operator must inform the EPA that it is electing to report only once on that root 

cause, and unless the EPA objects within 30 days of receipt of the RCA, such election is

effective. Examples cited by the commenter include routine maintenance activities such as 

purging vessels or clearing equipment, maintenance of a FGR system, flow from alkylation units 

which cannot be recycled due to contamination issues, fuel gas imbalance issues and high 

concentrations of hydrogen or nitrogen (either with or without FGR since these streams would 

not be suitable for fuel gas).

Response: We proposed the flare flow RCA threshold of 500,000 scf in any 24-hour 

period because we projected that FGR 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 FGR 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 RCA threshold of 500,000 scf in any 24-hour period. In fact, in 

our original analysis of the appropriate flow rate RCA threshold (Docket Item No. EPA-HQOAR-2007-0011-0246), we 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 scfd10 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 

 10 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.
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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 RCA 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 FMP. A flow-based RCA 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 RCA when the sweep or purge gas 

flow rates are not negligible. We also note that 40 CFR 60.103a(d) allows a single RCA to be 

conducted for any single continuous discharge that causes the flare to exceed either the RCA

threshold for SO2 or flow for two or more consecutive 24-hour periods.

The final rule does not limit RCA 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 RCA 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 RCA to 

cover more than just upsets and malfunctions. We also decided not to explicitly allow owners or 

operators to use one RCA 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 include recurring maintenance; this provision will avoid multiple 

RCA for a recurring event. As described above, the FMP (as well as significant revisions to the 

plan to include alternative baselines) must be submitted to the Administrator.

We expect that a final FMP in compliance with 40 CFR part 60, 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 
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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 0298, 0300 and 0304 requested that an exemption from the flare 

flow RCA requirement be provided for planned startup and shutdown events that are consistent 

with the facility’s FMP because it is redundant and unnecessary.

Response: We agree. There will be some units whose startup and/or shutdown gas flow to 

the flare will exceed the flow RCA threshold even though the gas flow to the flare has been 

minimized to the extent possible. For example, a hydrotreater may receive most or all of its 

hydrogen from a catalytic reforming unit. If this hydrotreater is shut down, the refinery will be 

producing significant quantities of hydrogen. While some of this hydrogen may be used in the 

fuel gas system, the amount of hydrogen that can be effectively redirected is limited by the 

heating value needs of the fuel gas combustion units (hydrogen has a low higher heating value 

compared to hydrocarbons; too much hydrogen may adversely affect performance of the process 

heaters due to low heat input rates) and the amount of fuel gas that is needed by the refinery (if 

the refinery has a fuel gas balance (i.e., limited or no natural gas needs prior to the unit 

shutdown), the excess hydrogen caused by the shutdown cannot be used to reduce natural gas 

purchases and some amount of hydrogen and/or fuel gas would then have to be flared). As long 

as planned startup and shutdowns are performed according to the FMP requirements, a RCA is 

not required, and we have revised the regulatory language to exclude these circumstances.

Comment: Commenter 0311 requested clarification regarding the RCA and corrective 

action analysis requirements for sulfur recovery plants. The commenter asked the EPA to specify 

if the 500 lb of SO2 above the emission limit are to be calculated per calendar day or per 24 hour 

period. In addition, the commenter noted that sulfur recovery plants with reduction control 

systems emit reduced sulfur and not SO2, so a RCA threshold based on mass of SO2 is not 

logical. Instead, the commenter recommended that the RCA threshold for these systems be set at 

500 lb reduced sulfur or total sulfur (depending on the type of CMS used for monitoring the 

emissions) above the emission limit.

Response: As stated previously, we elected to evaluate the SO2 RCA threshold on a 24-

hour basis rather than a calendar day to more accurately consider the emissions from a single 

discharge that lasts less than 24 hours but occurs over 2 calendar days. However, we agree that
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the description of the threshold for conducting RCA for sulfur recovery plants was confusing as 

proposed, particularly when the RCA threshold for sulfur recovery plants was compared to the 

RCA threshold for fuel gas combustion devices. The proposed RCA threshold for both types of 

process units was 500 lb 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. Upon further 

consideration, we see no reason for these requirements to be different for fuel gas combustion 

devices and sulfur recovery plants. In addition, “period of the exceedance” was intended to have 

the same meaning as “period of excess emissions” under 40 CFR 60.105a(i) and 

40 CFR 60.106a(b); to avoid confusion, we have decided to use the already-defined term “period 

of excess emissions.” Therefore, under 40 CFR 60.103a(c)(3) of the final amendments, the 

owner or operator is required to conduct RCA as described in 40 CFR 60.103a(d) “any time the 

SO2 emissions are more than [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 

40 CFR 60.102a(f)(1) or (2) during one or more consecutive periods of excess emissions or any 

24 hour period, whichever is shorter.” This clarifying amendment is needed to ensure that the 

magnitude of the emission 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. In other words, if the owner or operator calculates four 

consecutive 3- or 12- hour averages (as applicable) that are above the applicable emission limit, 

the owner or operator should compare the total emissions from those four averages with the 

amount that would have been emitted if the applicable emissions limit had been met over the 

duration of those four averages.

The following is an example application of this provision. Consider a sulfur recovery 

plant with an emission limit of 250 ppmv SO2 on a 12-hour rolling average basis. The emissions 

are constant such that the hourly averages and the 12-hour rolling averages are typically about 

175 ppmv. Something then causes the hourly emissions to reach 1,000 ppmv SO2 for two 

consecutive hours. When the operator calculates the 12-hour averages to determine compliance, 

he finds that the high concentrations caused a total of 11 12-hour averages to be above the 250 

ppmv SO2 emissions limit. To determine whether a RCA is required, the operator must compare 

the mass emissions from those 11 averages with the mass that would have been emitted if the 12-
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hour average for each of those 11 periods had been 250 ppmv SO2. If the difference is 500 lb, 

then RCA is required.

With respect to sulfur recovery plants with reductive control systems, we acknowledge 

that the SO2 RCA threshold is somewhat contrived for these systems; however, we conclude that 

it is appropriate so that the magnitude of the event that triggers a RCA is essentially the same 

regardless of whether an oxidative or reductive control system is used. Specifically, the 

concentration measurement for the reduced sulfur compounds is determined as ppm SO2 by 

volume. To convert the concentration into mass emissions, the molecular weights of the 

pollutants are needed. Most reduced sulfur compound monitors do not determine the 

concentration of individual reduced sulfur compounds; they determine the amount of SO2

produced when the reduced sulfur compounds are oxidized. The mass of reduced sulfur 

compounds emitted cannot be directly determined from the monitored values. One must either 

calculate the mass of sulfur emitted in the reduced sulfur compounds and/or calculate the 

equivalent mass of SO2 emitted. The molecular weight for sulfur is half that of SO2. If units with

reductive control systems were allowed to calculate the excess emissions in terms of pounds of 

sulfur per day rather than pounds of SO2 (equivalents) per day, an event would have to be twice 

as large to exceed a 500 lb SO2 RCA threshold as compared to units with an oxidative systems.

Such a discrepancy is not appropriate considering that the emission limits for both systems are 

based on the same overall sulfur recovery efficiency. Consequently, we are not revising the RCA 

threshold for sulfur recovery plants that employ reductive control systems. Through this 

response, we clarify that the SO2 RCA threshold must be determined considering the mass of 

SO2 equivalent emissions above the applicable emissions limit for all sulfur recovery plants, 

including those with reductive control systems.

4.5 Monitoring Fuel Gas Combustion Devices

Comment: Commenter 0305 recommended that the EPA allow alternative monitoring 

plans for fuel gas combustion devices approved under subpart J to be deemed compliant with 

subpart Ja.

Response: The alternative monitoring plans in subpart Ja were developed based on the 

alternative monitoring plan requirements in subpart J, but with the additional intent to ensure 

compliance with the long-term 60 ppmv H2S concentration limit. For flares, which are not 
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required to meet the long-term 60 ppmv H2S concentration limit, alternative monitoring plans 

approved under subpart J are deemed compliant with subpart Ja. However, for fuel gas 

combustion devices, which are required to meet the long-term 60 ppmv H2S concentration limit, 

the subpart Ja criteria must be used to develop a new alternative monitoring plan.

4.6 Sulfur Monitoring for Flares

Comment: Commenter 0301 stated that flares that handle only exempt gases, specifically 

flares with FGR systems, should be exempt from H2S monitoring. According to Commenter 

0301, process knowledge and engineering calculations are sufficient to determine if the SO2

RCA threshold of 500 lb in any 24-hour period is exceeded. If H2S monitoring is required, 

Commenter 0301 requested that the rule allow engineering estimates of the TRS-to-H2S 

correction factor due to safety concerns and inability to collect samples for “emergency only” 

flares. Commenter 0314 agreed that monitoring is unnecessary for flares with adequately 

designed and operated FGR systems and that there are data at the flare gas source to calculate the 

amount of SO2 emitted and determine if RCA is needed. Commenter 0303 stated that continuous 

sulfur monitoring is unreasonable for flares that generally see little or no gas flow, and sulfur 

emissions can be calculated based on sampling the flare gas (although the commenter also stated 

that 42 percent of their flaring events were less than 10 minutes in duration). Commenter 0303 

requested that 40 CFR 60.107a(e) and (f) and 40 CFR 60.108a(6)(iii), (iv) and (v) be modified to 

allow owners or operators to submit and use an alternative monitoring plan to demonstrate that 

the FGR system is operating within its capacity and to calculate SO2 emissions from engineering 

calculations and flare gas sampling. Commenters 0305 and 0311 agreed that “emergency only” 

or “SSM only” flares should be exempt from sulfur monitoring requirements. Commenter 0315 

noted that it is common practice to configure flare systems such that one flare handles normal 

loads and another flare receives gas only when the primary flare is overloaded during periods of 

SSM. The commenter noted that, in this situation, the continuous sulfur monitor on the primary 

flare would often provide data on the sulfur content of the flared gas (depending on the exact 

configuration). The commenter asserted that the burdens related to a continuous sulfur analyzer 

are not justified for flares where flows are very intermittent and event-related and where sulfur 

data is easily available by other means (e.g., grab samples, process data). Commenters 0301, 

0305 and 0311 recommended that monitoring exemptions be provided for flares in low sulfur 
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service (less than 5 ppmv or sulfur-intolerant streams), similar to the exemptions provided in 

40 CFR 60.107a(a)(3).

Commenter 0296 stated that properly designed FGR systems should exempt a flare from 

the H2S concentration requirements in subpart Ja as only exempt gas streams would be 

combusted by the flares. Commenter 0296 also stated that the EPA should provide incentives for 

refineries to install costly FGR systems. For example, the EPA should eliminate the TRS 

monitoring requirements for flares with FGR systems, allow the use of an existing fuel gas 

continuous monitoring system (CMS) if the refinery is long on fuel gas and subsequently must 

flare some of the recovered gas and allow 5 years for installation of a FGR system.

Commenter 0305 requested clarification that when sweep gas is routed to an emergencyonly flare, it is not required to be monitored if it meets one of the definitions of streams that do 

not require monitoring or is monitored elsewhere (for example within the fuel gas system).

Similarly, Commenter 0305 requested clarification that flare pilot gas is not required to be 

monitored for sulfur or flow if it is routed from natural gas or from refinery fuel gas monitored 

elsewhere for compliance with subpart J or Ja, nor is it required to be included in the flare flow 

for the purposes of RCA.

Commenter 0314 noted that, to meet the performance test requirements on flare sulfur 

monitors as proposed at 40 CFR 60.107a(e)(1)(ii) or (e)(2)(ii), the owner or operator of a flare 

with FGR may have to intentionally flare sour gas. The commenter also noted that the relative 

accuracy test audit (RATA) may be enough to trigger RCA. Therefore, the commenter 

recommended revising the performance test requirements for flares with FGR to require only a 

Cylinder Gas Audit. Commenter 0311 also noted that flares with occasional flows, such as flares 

handling only SSM events, would have to flare intentionally to perform required testing.

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 RCA will always be triggered by an exceedance of the flow 

rate threshold well before the SO2 threshold is exceeded, so no sulfur monitoring is 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 
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combust fuel gas streams produced in process units that are intolerant to sulfur contamination 

(e.g., hydrogen plant, catalytic reforming unit, isomerization unit, hydrogen fluoride alkylation 

unit). We already clarified that flare pilot gas is not required to be monitored. Also, 40 CFR part 

60, 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. (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 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 RCA and there is a limit to the number of exceedances in one year. Under this option, 

a RCA 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 RCA is needed. Consequently, for these flares, 
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engineering calculations can be used to estimate the reported emissions during the flaring event, 

but the RCA 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 

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: Commenter 0312 requested that the EPA clarify whether the additionally 

proposed sulfur monitoring options for flares are for TRS 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 CMS.

Commenter 0311 requested that provisions be made in 40 CFR 60.107a(e)(2) to develop 

a total sulfur-to-H2S (or TRS-to-H2S) ratio so that the total sulfur monitor can be used for both 

the RCA and for compliance with the requirement to limit the short-term H2S concentration in

fuel gas sent to a flare to 162 ppmv without the need for a duplicative H2S CMS. Commenter 
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0313 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 TRS

monitoring for flares. For the purposes of evaluating the SO2 RCA 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 TRS compounds, 

which include carbon disulfide, COS and H2S. Our test method for measuring TRS includes the 

use of EPA Method 15A as a reference method, and because EPA Method 15A measures total 

sulfur, the TRS 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 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 short-term 162 ppmv H2S 

concentration in the fuel gas. As the H2S concentration will always be less than the TRS

concentration, it is acceptable to use the TRS monitor to verify that the fuel gas does not exceed 

the short-term H2S concentration of 162 ppmv. Therefore, we have provided for the use of TRS

monitors, provided the monitor can also meet the 300 ppmv span requirement. 

However, we have not provided a correction factor to scale down the TRS concentration 

to H2S. The owner or operator using this method must essentially be able to demonstrate they 

can achieve a 162 ppmv TRS concentration in the fuel gas. The concentration ratio was provided 

for the purposes of the RCA 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 RCA threshold. As few cases would exist where the flaring 

event would be right at the SO2 RCA threshold of 500 lb in any 24-hour period, inaccuracies 

associated with the 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 
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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 TRS 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: Commenter 0311 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, Commenter 0301 stated that the span value for the flare H2S monitoring 

option is too restrictive and suggested that the Appendix F requirements provide sufficient 

quality assurance/quality control (QA/QC) without the need for the rule to specify the span 

range.

Commenter 0311 requested clarification of the sulfur monitor span for flares, suggesting 

that it should be based on the 162 ppmv H2S concentration requirement and that engineering 

calculations can be used to assess exceedances of the SO2 RCA 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 requirement for 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 requirement for the fuel gas and to assess exceedances of the SO2 RCA

threshold of 500 lb in any 24-hour period, a dual range monitor will be necessary. For the 

purposes of the SO2 RCA 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 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 
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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 requirement for 

the fuel gas and the SO2 RCA 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 TRS 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.

4.7 Flow Monitoring for Flares

Comment: Commenters 0305 and 0311 stated that “emergency only” or “SSM only” 

flares should be exempt from flow monitoring requirements, and Commenter 0311 also 

requested clarification that secondary and “malfunction only” flares are exempt from the flow 

meter requirement. Commenter 0311 stated that flare flow meters are costly and unnecessary 

because engineering calculations, which are currently used, are sufficient to evaluate whether the 

flare flow rate exceeds the RCA threshold of 500,000 scf in any 24-hour period. At a minimum, 

flares that are designed to handle flows less than 500,000 scfd should be excluded from the flow 

monitoring requirements, as there is no justification for flow monitors in this case. Commenter 

0315 also noted that flow monitors are unnecessary for pilot gas, which has no significant 

increase or decrease potential and which does not flow through the main flare header and thus 

would require a separate flow monitor. Commenter 0303 stated that, for flares with FGR

systems, the pressure drop across the flare seal drum can be used to calculate flow rate and this 

method is a cost effective alternative to continuous flow monitors for these flares.

Response: In the final rule, flow monitoring is used to determine whether a RCA 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 
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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 RCA threshold, but also 

exceedances of the RCA 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 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 RCA threshold (i.e., designed to handle less than 500,000 scfd of gas). However, these 

small flares could still exceed the RCA 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 RCA 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 

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 FGR 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 
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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 FGR 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 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 RCA 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 RCA 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 RCA 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 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: Commenter 0305 expressed concern regarding the flow meter range for 

emergency-only flares and suggested that for existing monitors, the flow range currently being 

used should be deemed acceptable, even if it means additional engineering and process 

information must supplement the readings to estimate emissions. The commenter also suggested 

that the range for new meters should be determined as appropriate for the specific flare.

Commenter 0311 suggested that the flow meter range requirements should be clarified to 
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accommodate an average flow rate of 500,000 scfd, and multiple flow meters should not be 

required to measure very high or very low flows.

Response: Flow meters for flares are considered continuous parameter monitoring 

systems (CPMS) and no specific span is specified in the rule. The rule requires that the flow 

monitor be placed in a position to provide a representative measurement of the total gas flow rate 

and it specifies a minimum sensitivity and calibration requirements. We agree that the flow 

meter should accommodate an average flow rate of 500,000 scfd and we did not intend to require 

multiple flow monitors to measure exceedingly low or high flow rates. It is our understanding 

that ultrasonic flow monitoring systems are typically used for flares and that these devices can 

accurately measure flow rates over a large span (e.g., velocities from 1 to 3,000 feet per second 

[ft/s]). As such, we anticipate that a single flow meter installed for flares will be able to measure 

a wide range of flow rates accurately and that the range measured by a single flow meter device 

will be sufficient to assess both the sulfur and flow rate RCA thresholds.

Comment: Commenter 0311 noted that the newly proposed Appendix F QA/QC 

procedure (P-4) for CPMS will likely result in significant periods of monitor outages if 

applicable to fuel gas flow meters.

Response: This comment lacks any detail supporting the commenter’s position.

Presumably, if this is a legitimate concern, the comment should have also provided direct and 

more substantive comments on the proposed Procedure 4 to Appendix F. We defer to the

supporting material and responses to comment document for that action; please see Docket No. 

EPA-HQ-OAR-2006-0640 for more details regarding that particular rulemaking.

4.8 Compliance Schedule

Comment: Commenters 0296, 0301, 0304, 0306, 0310 and 0311 stated that compliance 

with a long-term 60 ppmv H2S concentration limit on fuel gas combusted in flares would require 

a much longer time period than 2 years. The commenters suggested that 3 to 5 years would be 

needed to install a FGR system and/or additional amine treatment needed for compliance.

Commenter 0310 further stated that the compliance schedule in subpart Ja for installing 

additional sulfur removal equipment should be consistent with (or allow) established consent 

decree schedules. Both Commenters 0310 and 0311 objected to phasing out the additional time 

after the rule has been in place for 5 years.
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Commenter 0311 stated that all flares should be given 3 years from the date of final 

promulgation and lifting of the stay to comply with the flare standards (regardless of whether 

new amine or FGR systems are being installed) to allow time for planning, re-piping and other 

necessary activities, and the EPA should provide an optional additional 2 years for capital 

installation projects (e.g., for permitting, equipment installation). Commenter 0305 stated that 

any capital project (not just amine treatment) required to meet any of the subpart Ja flare 

standards (not just the long-term 60 ppmv H2S concentration) should trigger a compliance 

deadline of up to 3 years after the effective date of the rule, with an allowance provided for 

refineries to request an additional 2 years if needed to correspond with an affected-unit 

turnaround because of the huge operating costs and product disruptions associated with 

unscheduled turnarounds. Commenter 0301 recommended that the extra time to begin RCA

provided to refiners committing to install FGR systems in proposed 40 CFR 60.103a(a)(4) and 

(b)(1) should also be provided to refiners committing to expand an existing FGR system.

Commenter 0315 agreed that additional time is needed since a number of the flare requirements 

will require shutdowns. The commenter also stated that since not all flares are currently subject 

to subpart J, additional time would be needed for all fuel gas combusted in those flares to meet 

the short-term H2S concentration requirement of 162 ppmv.

Commenter 0304 stated that the 18-month compliance deadline for sulfur CMS for flares 

is not adequate for large refineries with multiple flares because the installation of the CMS will 

typically need to be staggered (based on availability of CMS equipment and crew). Commenter 

0310 similarly asserted that 3 years would be needed to install monitors due to design and 

installation considerations together with the constraints on manufacturers by the sudden demand 

for several hundred flow and sulfur monitors. Both commenters cited delays experienced in 

obtaining monitors to comply with SCAQMD Rule 1118.

Commenter 0295 requested clarification regarding the trigger date from which the 

additional time to comply with the flare provisions (e.g., 2 years when installing a FGR system) 

begins. The commenter asked whether the trigger date is when construction starts, at startup or 

when the stay is removed (or whichever is later). Commenter 0315 agreed that the EPA should 

set the compliance time based on the initial startup of the modification. The commenter noted 

that the 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.
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Response: As we are no longer applying the long-term 60 ppmv H2S fuel gas 

concentration limit to flares, the comments related to the amount of time needed to comply with 

a long-term 60 ppmv H2S fuel gas concentration limit are moot. We do, however, recognize that 

a flare modification can occur much more quickly than modifications of traditional processrelated emission sources. Therefore, we evaluated the comments regarding the amount of time 

needed to meet the various requirements for flares while keeping the 40 CFR part 60, 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. We 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 installing 

(including any necessary re-piping) sulfur and flow monitors that are newly required by subpart 

Ja. Some refineries will elect to add FGR and/or sulfur treatment equipment to minimize their 

emissions as part of the evaluations conducted as required by the new FMP 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) 
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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 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 standards.

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 40 

CFR part 60, 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 

interruptions. For a future 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 FMP. 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. Therefore, we find that compliance with the flare 

requirements upon startup of the modified flare is appropriate and consistent with the best system 
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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 or (2) upon startup of the modified 

flare, whichever is later.11 In this manner, flares that become subject to subpart Ja quickly, based 

on a small safety-related connection (or have already become subject to subpart Ja based on a 

modification prior to promulgation of the amendments) will have up to 3 years from the 

promulgation date of the amendments to comply fully with 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 40 CFR part 60, 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 

requirement upon startup of the affected flare. Additionally, we are requiring owners and 

operators of modified flares to complete and implement the FMP under 40 CFR 60.103a(a) by 

3 years from the promulgation date 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 

corrective action analyses under 40 CFR 60.103a(c) and (d) no later than 3 years from the 

promulgation date or the date of the startup of the modified flare, whichever is later, so that the 

facility can complete the FMP 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 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.

 11 For the purposes of this subpart, 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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4.9 Startup, Shutdown and Malfunction

Comment: Commenter 0307 stated that exempting flares12 from the H2S concentration 

limits during SSM events is illegal because the CAA requires continuous compliance with 

standards issued under CAA section 111. See CAA sections 111(a)(1), 302(k). Therefore, the 

commenter asserted that it is not BSER to allow startup and shutdown events to be exempt from 

compliance, and these emissions may not be regulated through work practice standards. 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 section 111 general duty to minimize emissions during SSM 

events (see 40 CFR 60.11(d)) is not a CAA section 112-complaint standard. The commenter 

asserted that the CAA also requires that a section 111-compliant standard that reflects BSER13 be 

in effect at all times for flares.

Commenter 0307 further asserted that work practice standards for flares are not CAA 

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 the 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 the EPA cannot claim that it is infeasible to promulgate a standard of performance for 

flares,

14

so the EPA cannot set a work practice standard for flares. Thus, the commenter asserted 

 12 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 60.103a(h). The 

discussion in this document 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 limits in 40 CFR 60.102a(g)(1). 13 The commenter asserted, without providing support, that it is not BSER to exempt flares from the H2S 

concentration limits during startup and shutdown events. The commenter also stated that the EPA, at a minimum, 

must demonstrate how the exemption from the H2S concentration limits during SSM events does in fact represent 

BSER, but the commenter stated that the EPA has failed to make this demonstration. 14 The commenter cited the 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 because either the pollution 
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that a CAA 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.

Commenter 0315 disagreed and provided several reasons why they believe the EPA may 

lawfully exempt flares from the H2S concentration limits during SSM events. First, the 

commenter noted that 40 CFR part 60, subpart Ja was promulgated as part of the mandatory 

periodic review of 40 CFR part 60, subpart J required by CAA section 111(b)(1)(B), which states 

that “the Administrator need not review any such [existing] standard if the Administrator 

determines that such review is not appropriate in light of readily available information on the 

efficacy of such [existing] standard.” 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 the EPA’s authority to ‘not review’ this 

aspect of the existing standard in light of the efficacy of the existing standard.” See CAA section 

111(b)(1)(B).

Second, Commenter 0315 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” (551 F.3d at 1028), eliminating much of the 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 the EPA’s authority to “distinguish among classes, types, and sizes of 

sources” when promulgating CAA section 112 standards as further evidence for constraining the 

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” of the CAA despite revisions to CAA section 111 in 1977 and 1990.

Therefore, the commenter asserted, Congress has “effectively ratified EPA’s longstanding 

 

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 states: “[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.”
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approach to SSM under the NSPS program,” which includes the exemption for flares from the 

H2S concentration requirements during SSM events.

Commenter 0315 also asserted that, regardless of the above and despite the similar nature 

of the provisions in CAA sections 111 and 112, the EPA has the discretion to implement them 

differently “under the markedly differently context of the NSPS 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 the 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, Commenter 0315 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 cost-effectively 

treated for sulfur removal because of their infrequent occurrence, their scattered points of 

generation and their variability.” Therefore, for all of the above reasons, Commenter 0315 

asserted that exempting a flare from the H2S concentration limits when combusting certain gases 

generated during SSM events is lawful under CAA section 111.

Alternatively, Commenter 0315 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 NSPS 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 FMP; (2) conduct RCA and take corrective action 

when waste gas sent to the flare exceeds a flow rate of 500,000 scf above the baseline; (3) 

conduct RCA and take corrective action when SO2 emissions exceed 500 lb in a 24-hour period; 

and (4) optimize management of the fuel gas by limiting the short-term concentration of H2S to 
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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 CAA section 111-compliant standards that collectively cover all operating 

conditions of the flare.

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

equipment, work practice or operational standard or “combination thereof,” when “it is not 

feasible to prescribe or enforce a standard of performance” which reflects BSER for the 

particular affected source. Section 111(h)(2) of the CAA 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 (and other 

pollutants) is not “feasible,” allowing the EPA to instead promulgate standards under CAA 

section 111(h), which will collectively limit emissions from the flare.

The 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 
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those devices is directly indicative of the SO2 emitted from the exhaust stacks of those other 

devices. As explained in section III of the preamble to the final amendments, 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 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 

flare,

15 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 CAA section 111(h) that refineries 

limit the short-term concentration of H2S to 162 ppmv in the fuel gas sent to flares during normal 

operating conditions. Refineries rely on various methods for optimizing the management of fuel 

gas, including the use of amine treatment and FGR 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 

 15 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.
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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 FGR systems that 

capture gases prior to amine treatment can be quickly overwhelmed 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 FGR systems would not fully address the circumstances 

refineries face in managing these high flow periods. Designing FGR 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 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 FMP and conduct RCA and take corrective action when 

waste gas sent to the flare exceeds a flow rate of 500,000 scf above the baseline or 500 lb 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 sourcespecific circumstances differ markedly from this nationally applicable rulemaking, necessitating 

different decisions in two very different circumstances. For example, the EPA's SO2 FIP for the 

Billings/Laurel Montana area includes a SO2 emission limit of 150 lb 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 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.
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Additionally, those four sources subject to the Billings/Laurel FIP demonstrate 

compliance with the 150 lb 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 flare tip and how these factors 

affect how much of the sulfur in the gases sent into the flare actually converts to SO2. 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, the EPA is finalizing this collective set of 

CAA 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 the range of 

regulated air pollutants.

Comment: Commenter 0299 requested that the EPA provide provisions for fuel gas 

compressor preventative maintenance to reduce compressor outages as compared to running the 

compressor until it fails. Commenter 0311 stated that FGR system outages may occur for safety 

reasons (e.g., if oxygen gets in the flare gas) and requested clarification that proposed 

40 CFR 60.103a(a)(6) specifically acknowledge this possibility by inclusion of “flare gas 

recovery system outages (e.g., for maintenance or for safety reasons).”

Response: We expect that refineries will properly maintain the compressors, and RCA 

will need to be conducted for FGR outages and systems put in place to eliminate the recurrence 

of such events. Maintenance of the FGR does not constitute a process SSM event that excludes 

the fuel gas from the H2S concentration limits. However, inclusion of procedures in the FMP to 

minimize the volume of gas flared during FGR system maintenance is reasonable and we have 

added this requirement to 40 CFR 60.103a(a)(7) as requested by the commenter.
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5.0 PROCESS HEATERS

5.1 Emissions Limits

5.1.1 Equivalence of Emissions Limit Units

Comment: Commenters 0296, 0305 and 0311 stated that the limits for the concentration 

and heating value emissions limits should be the same numerically; i.e., the process heat rate 

limit numerically equivalent to the 40 ppmv concentration limit is 0.04 lb/MMBtu and the 

process heat rate limit numerically equivalent to the 60 ppmv concentration limit is 0.06 

lb/MMBtu.

Response: In August 2008, Industry Petitioners to the final rule provided the 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 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 
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forced draft process heaters, respectively, based on direct numerical conversions from the 

concentration-based 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 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.

5.1.2 Limits for New, Modified and Reconstructed Forced Draft Process Heaters

Comment: Commenters 0296, 0311 and 0314 suggested that newly constructed forced 

draft process heaters should have the same 60 ppmv emissions limit as modified and 

reconstructed forced draft process heaters. Commenter 0296 stated that the emissions limit for 

newly constructed forced draft process heaters was based on only two data points and that it does

not fully consider the operating range of newly constructed units. The commenter included a 

John Zink white paper and asserted that this white paper shows that newly constructed forced 

draft process heaters (particularly those that use air preheat) cannot meet the 40 ppmv NOX

emissions limit. Commenter 0314 agreed, noting that they designed a new forced draft process 

heater with air preheat to meet 50 ppmv NOX, and the “heater vendor and burner supplier have 
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determined that they cannot get appreciably lower emissions than the current design achieves.”

The commenter noted that since burner modifications alone will not be able to achieve 40 ppmv, 

this heater would need SCR to meet the 40 ppmv NOX limit, and they provided costs and 

emission reductions to support the EPA’s finding that SCR is not cost effective. Commenter 

0314 also suggested that the EPA could return to the proposed limit of 80 ppmv NOX.

Similarly, Commenter 0297 supported higher emissions limits for process heaters with air 

preheat. The commenter noted that meeting a 40 ppmv limit for new forced draft process heaters 

with combustion air preheat “and allowing for a comfortable margin to ensure compliance is 

extremely difficult, if not impossible, without the use of add-on controls.” The commenter also 

suggested that the mass emissions of NOX from units with air preheat would not be higher than 

units without air preheat due to the reduced flue gas flow rate and recommended the 60 ppmv 

NOX limit be extended to new forced draft process heaters equipped with combustion 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 0296 

(submitted as an attachment to Docket Item No. EPA-HQ-OAR-2007-0011-0296) 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 

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 
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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 BSER for 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.)

5.1.3 Turndown

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. Commenter 0296 stated 

that turndown conditions can extend over a full year, so special provisions are needed for these 

turndown conditions. Commenters 0296 and 0305 suggested that a mass emission cap be used as 

the sole compliance requirement (lb/MMBtu limit multiplied by the heater’s rated capacity).

Alternatively, Commenter 0296 suggested that a mass emission cap be provided for “turndown 

operations,” which the commenter suggested be defined as operating at 50 percent of the rated 

capacity or less. Commenter 0311 requested that the proposed emissions limits only apply to 

furnaces that are firing at or above 50 percent of design rates. Days when firing rates are below 

50 percent of capacity would not be included in the 365-day average and the units would meet a 

mass emission rate (pounds per hour [lb/hr]) based on the emissions limit at design capacity, 

according to the commenter. Also, according to Commenter 0311, process heaters must often 

operate at higher oxygen (O2) levels during turndown, so the proposed maximum O2 operating 

limit should not apply when small furnaces (those not required to install continuous emission 

monitoring systems [CEMS]) are firing at less than 50 percent of design rates. Commenter 0315 
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added that limited new data suggest that meeting a NOX concentration limit becomes problematic 

at 70 percent of capacity, so the mass limit should apply when a process heater is firing below 70 

percent of capacity and the emissions limit should be calculated as the allowed emission factor 

for that heater multiplied by the 70-percent firing rate.

Response: In our proposed amendments, we provided a longer averaging time (365-day

average) so that short periods of turn-down 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. 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, shortterm 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 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 
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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.

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 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 massbased 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 
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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 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 site-specific emissions limit that would apply to those operating 

conditions and requesting approval from the Administrator to use that limit.

For process heaters between 40 and 100 million British thermal units per hour 

(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 
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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.

5.1.4 Site-Specific Emissions Limit Clarifications

Comment: Commenters 0302, 0305, 0308 and 0311 supported the provision in 

40 CFR 60.102a(i) for a site-specific NOX emissions limit for process heaters that cannot be

retrofit with ultra-low NOX burners. Commenters 0308 and 0311 suggested expanding the 

applicability of the paragraph to include process heaters for which it may be physically possible

to install ultra-low NOX burners, but other “structural or operability reasons” would prevent the 

process heaters from operating properly. Commenter 0308 also noted that island refineries that 

have difficulty obtaining natural gas may have fuel gas with higher levels of olefins and propane, 

which contribute to higher NOX emissions. The commenter suggested allowing process heaters 

that cannot meet the NOX limits for “fuel gas quality reasons” to apply for a site-specific 

emissions limit. Commenter 0311 stated that the provisions should also apply to new forced draft 

process heaters, especially those using air preheat, that might have trouble meeting a 40 ppmv 

limit.

Commenter 0311 also stated that the General Provisions provides 180 days to achieve 

full process rates, test the unit and submit the results, and this timeframe, rather than the 90-day 

time frame proposed, is needed to file the petition. Finally, Commenter 0311 stated that the rule 

should specify that the petition’s limit applies to the process heater until the petition is acted 

upon since the petition is being submitted because the facility cannot meet the emissions limit.
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Response: We appreciate the commenters’ support of the option to petition for a sitespecific emissions limit. We have clarified the site-specific emissions limit provisions under 

40 CFR 60.102a(i) to address most of the commenters’ concerns as described in this response.

Regarding process heaters that cannot properly operate ultra-low NOX burners, the 

preamble to the proposed rule notes that owners and operators may seek EPA approval for a sitespecific limit for “modified or reconstructed natural draft and forced draft process heaters that 

have limited firebox size or other limitations and therefore cannot apply the [BSER] of ultra-low 

NOX burners.” Our intention was to accommodate process heaters that cannot install and

properly operate combustion modification-based technology due to structural limitations of the 

process heater (e.g., size of the heater box, flame impingement on tubes containing process 

fluids, spacing of the individual burners). In other words, if ultra-low NOX burners can

physically fit in a process heater but the process heater cannot be operated safely or the ultra-low 

NOX burners themselves cannot operate as recommended by the manufacturer, then we consider 

there to be physical limitations preventing the use of combustion modification-based technology.

We agree that the proposed language in 40 CFR 60.102a(i) could be interpreted more narrowly 

than intended, so we revised the language in 40 CFR 60.102a(i)(1)(i) to specify that “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)” 

may submit a petition for a site-specific limit.

This provision, while considering “proper operation,” was specifically included to 

address process heaters with physical (i.e., “structural”) constraints in retrofitting a process 

heater with ultra-low NOX burners. This provision is not intended to provide unlimited 

operational flexibility for the burners. Further, we find that the requested “operability” provision 

undermines part of the BSER analysis. As seen by several of the comments received, the process 

heater specifications often include maximum radiant section temperatures, maximum preheat 

temperatures, maximum excess oxygen content and flexibility in burner design to allow both 

natural draft or forced draft operation. We recognize that, for existing process heaters, some of 

these parameters are fixed, but the question is: should the design and operation of the process 

heater be cognizant and reflective of the NOX emissions limits? In developing our BSER

analysis, we included limiting the amount of excess oxygen employed and included costs for 

excess oxygen measurement and control. We do not expect that process heaters that are subject 
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to subpart Ja will operate exactly like process heaters that are not subject to subpart Ja, just with 

different burner designs. For example, in reviewing NOX emissions data, we found that several 

process heaters were operating with excess oxygen concentrations of 6 to 8 percent while firing 

at or near capacity. Discussions with technology vendors, however, suggest that “proper 

operation” of a low-NOX burner firing at or near burner capacity would be to operate at excess 

oxygen concentrations of 2 to 4 percent. We recognize that there are several factors that 

contribute to NOX formation, and it is incumbent on the owner or operator of an affected process 

heater to control, to the extent possible, these various parameters so as to minimize NOX

emissions and to comply with the NOX emissions limits. Thus, while we recognize that certain 

low-NOX burner retrofits may be infeasible due to structural limitations, we do not want to open 

the door for refinery owners and operators to disregard the emissions limits when operating 

modified process heaters or when designing new process heaters and then contend that the 

emissions limits in 40 CFR 60.102a(g)(2) are not achievable for “operability” reasons.

Therefore, we reject the request to expand the scope of the site-specific emissions limit eligibility 

to include “operability” issues per se unconstrained by the “proper operation” of low-NOX

burners.

Similarly, we reject the request to expand the scope of the site-specific emissions limit 

eligibility to include fuel gas quality constraints. Based on our analysis of the available data, the 

final NOX emissions limits are achievable over a wide range of refinery fuel gas compositions.

Furthermore, we have added alternative NOX emissions limits determined on a heating value 

basis, which provides flexibility for times when the composition of refinery fuel gas varies (e.g., 

high hydrogen content).

Regarding new forced draft process heaters, the preamble to the final amendments

explains that we have finalized amendments that do not include new forced draft process heaters 

in the list of process heaters eligible to submit a petition for a site-specific emissions limit. As 

noted in the preamble to the final amendments, we have revised the NOX emission limit for new 

forced draft process heaters to be 60 ppmv (on a 30-day rolling average basis), rather than 40 

ppmv (on a 365-day average) as provided in the proposed amendments. Based on available 

emission data and ultra-low NOX burner performance guarantees, we conclude that all new 

forced draft process heaters can meet an emissions limit of 60 ppmv NOX on a 30-day rolling 
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average basis; therefore, site-specific emissions limits are not warranted for new forced draft 

process heaters.

Regarding the specifics of submitting the petition, we agree with the commenter that it is 

appropriate to allow an owner or operator up to 180 days after startup to submit a petition for a 

site-specific limit. As the commenter noted, 180 days is consistent with the General Provisions, 

and it is also consistent with similar performance level determinations for boilers 

(40 CFR 60.44b(f)). We also agree with the commenter that clarification is needed regarding 

compliance during the time between submittal of the petition and approval by the Administrator.

We have clarified in the final amendments that the owner or operator should comply with the 

site-specific limit identified in the submitted petition until the petition is approved by the 

Administrator.

5.1.5 Co-Fired Process Heaters

Comment: Commenter 0308 requested clarification regarding the parenthetical qualifier

“(applicable only when the process heater is being co-fired)” in proposed 

40 CFR 60.102a(g)(2)(iv)(A). The commenter stated that it is unclear if proposed

40 CFR 60.102a(g)(2)(i)-(iii) apply to these process heaters when they are not co-firing or if only 

proposed 40 CFR 60.102a(g)(2)(iv)(B) must be applied. Based on the limitations of co-fired 

burner design, the emission limitations in proposed 40 CFR 60.102a(g)(2)(i)-(iii) are 

unachievable for co-fired process heaters, and clarifying language is needed to ensure that these 

limits are not enforced for co-fired process heaters when only gaseous fuels are used. If the 

parenthetical was intended to exclude only those times when 100-percent fuel oil is being 

burned, then the parenthetical should be clarified as follows: “(applicable only when the process 

heater is being fired in whole or in part with fuel gas).” Commenter 0311 likewise suggested that 

the EPA clarify that process heaters with co-firing capabilities (including those with separate 

burners dedicated to gas and liquid fuels) would have to meet either 150 ppmv or 0.08 

lb/MMBtu when firing only gaseous fuels.

Commenters 0308 and 0311 requested that the introductory text in proposed 

40 CFR 60.102a(g)(2)(iv) be clarified to clearly state that a co-fired process heater must “comply 

with either” proposed 40 CFR 60.102a(g)(2)(iv)(A) or (B) as some might interpret the current 

language to mean that co-fired process heaters must comply with both paragraphs (A) and (B).
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Response: We agree that the language concerning co-fired process heaters is ambiguous, 

and we have revised this language to clarify the requirements. The final rule provides two 

subcategories of co-fired process heaters: natural draft and forced draft. Each subcategory 

includes two options for emissions limits, one on a concentration basis and the other on a mass 

basis. The mass-based emissions limit considers the daily average amounts of gas and fuel oil 

fired by the heater, but the language no longer includes a qualifier addressing the type of fuel that 

must be fired for the limits to apply. In other words, the applicability of the emissions limits is 

based on the design of the process heaters and not on the type of fuel being fired at any given 

time. As stated previously (see Section 3.2), we do not consider process heaters that have 

completely separate gas and oil burners to meet the definition of co-fired process heaters. These 

units must demonstrate compliance with the NOX emissions limits when they are fired only with 

gaseous fuels. Additionally, the final amendments clarify that the owner or operator of an 

affected co-fired process heater may elect to comply with either the heating value-based or the 

concentration-based emissions limit, but the owner or operator must comply with the selected

limit at all times. That is, the owner or operator cannot switch back and forth between 

compliance methods depending on the fuel burned. 

We also note that the final rule does not address process heaters designed to fire only fuel 

oil. Because we did not propose requirements specific to oil-fired process heaters, the final rule 

does not include amendments addressing oil-fired process heaters. However, we will evaluate 

adding requirements for oil-fired process heaters in a future rulemaking.

Comment: Commenter 0308 stated that the emissions limits in proposed 

40 CFR 60.102a(g)(2)(iv)(A) and (B) are not achievable “...for the conditions that exist at 

HOVENSA...” and submitted a white paper to support higher emissions limits, which the 

commenter recommended be adopted, especially in light of a daily averaging period.

Alternatively, the commenter suggested the EPA defer the promulgation of NOX limits for cofired process heaters due to the lack of adequate data to “adequately demonstrate” an achievable 

emissions limit under section 111 of the CAA. Commenter 0311 stated that the 0.27 lb/MMBtu 

limit is not achievable when firing residual fuel oil.

Commenters 0308 and 0311 recommended that the emissions limit alternative in 

proposed 40 CFR 60.102a(g)(2)(iv)(B) be determined on a 365-day average as these process 

heaters will have the same issues with respect to turndown and variability as other process 
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heaters. Commenter 0311 also stated that the notation “ENOx,hour” in proposed Equation 3 was 

confusing and that the “hour” subscript should be dropped or changed to “daily.”

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).

To respond to the comments requesting higher emissions limits for co-fired process 

heaters, we reviewed the white paper provided by one commenter (submitted as an attachment to 

Docket Item No. EPA-HQ-OAR-2007-0011-0308), as well as additional burner emissions test 

data provided by another commenter16 (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 average basis (same as the limits for 

gas-fired process heaters). We have also revised the nomenclature of the daily average emissions 

 16 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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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 co-fired 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 approval for a site-specific emissions limit, as allowed above, for 

process heaters that operate for extended periods under turndown.

5.2 Monitoring of Process Heaters

Comment: Commenters 0305 and 0311 noted that CEMS compliance requirements in 40 

CFR part 75 are similar to those in 40 CFR part 60, but not identical. The commenters requested 

an exemption from the 40 CFR part 60 monitoring and QA requirements for any process heater 

or boiler subject to and complying with 40 CFR part 75 monitoring required by Acid Rain rules, 

a NOX State Implementation Plan (SIP) call, or other rules. Alternatively, the commenters 

requested that the EPA specifically provide 40 CFR part 75 monitoring and QA provisions to be 

compliant with 40 CFR part 60, subpart Ja.

Response: We reviewed the QA/QC requirements in 40 CFR part 75. It appears that the 

40 CFR part 75 NOX emissions limits (provided predominantly for coal-fired units) are much 

higher than those provided in these final amendments (which are predominantly for gas-fired 

process heaters). The accuracy requirement for the RATA on NOX is ±0.015 or 0.020 lb/MMBtu, 

depending on the RATA frequency. We find that these accuracies are not appropriate given the 

NOX emissions limits that are in the final rule. Consequently, we do not consider the 40 CFR 
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112

part 75 QA/QC requirements sufficient for compliance with the final rule and we are not 

amending the rule to allow 40 CFR part 75 monitoring and QA provisions.

Comment: Commenter 0311 asserted that daily determination of fuel oil heating value to 

comply with the co-fired process heater NOX emissions limit is excessive and unnecessary if the 

fuel oil is fed from a tank because the heating value does not vary that much. The commenter 

requested that the EPA allow the 40 CFR part 75 sampling protocols (Sections 2.2.3 and 2.2.4.1 

through 2.2.4.3 of Appendix D) instead of daily sampling. The commenter stated that 

40 CFR 60.4370 (40 CFR part 60, subpart KKKK) allows these protocols for sulfur sampling of 

liquid fuels to turbines.

Response: We reviewed the referenced sections in 40 CFR part 75. While we do not 

understand the reference to Section 2.2.3, which seems to indicate daily sampling, we recognize 

that heating value of fuel oil fed from a common storage tank is not expected to vary unless 

additional shipments are received. As many of the alternatives in the cited sections are sulfurcentric, we have provided similar alternatives in 40 CFR 60.107a(d)(7)(viii) to reduce the burden 

associated with daily sampling when daily sampling will not improve the accuracy of the 

measurements.

Comment: Commenter 0307 stated that the EPA should require CEMS for all process 

heaters to demonstrate compliance with the NOX emissions limit. The proposed amendments 

allow the option of biennial source testing for certain process heaters with low-NOX or ultra-low

NOX burners; however, commenters assert that biennial source testing is not sufficient for 

ensuring that these process heaters are meeting their NOX emissions limits. The commenter 

stated that section 504(c) of the CAA requires that Title V permits include monitoring 

requirements that “assure compliance with the permit terms and conditions,” and in Sierra Club 

v. USEPA,

17 the D.C. Circuit held that the EPA and state permitting agencies must include 

additional monitoring requirements in Title V permits if the existing requirements are 

insufficient to ensure compliance with an emissions limit. The commenter stated that biennial 

source testing for process heaters is not sufficient to demonstrate compliance; instead, the 

commenter asserted that CEMS are needed for demonstrating that all process heaters are in 

continuous compliance with the NOX emissions limit. The commenter also noted that if the EPA 

 17 536 F.3d 673 (D.C. Cir. 2008).
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relies on CEMS data provided by industry to weaken the NOX emissions limits, then the EPA 

should at least require CEMS to ensure industry is complying with that weaker limit.

Commenter 0315 countered that subpart Ja does require CEMS for process heaters firing 

more than 100 MMBtu/hr. The commenter also noted that Commenter 0307 did not provide data 

supporting their assertion that biennial source testing is insufficient for small process heaters, and 

the EPA has discretion in determining what monitoring is adequate. Commenter 0315 noted that 

the EPA originally proposed CEMS on all process heaters, but based on public comments 

received through the subpart Ja rulemaking process, the EPA revised the evaluation and 

determined that CEMS were not justified for small process heaters (see Docket Item No. EPAHQ-OAR-2007-0011-0222 and the third attachment to Docket Item No. EPA-HQ-OAR-2007-

0011-0222). The commenter noted that the EPA’s determination was reasonable and consistent 

with the agency’s longstanding approach for assuring continuous compliance, and the 

commenter cited several sections of 40 CFR part 64 for support.

Commenter 0311 supported the more flexible span range for NOX and the ability for 

process heaters between 40 and 100 MMBtu/hr to use either a CEMS or biennial test.

Response: We consider the monitoring requirements in the final rule sufficient for all 

process heaters to demonstrate continuous compliance with their applicable emissions limits. The 

final rule requires that owners or operators install CEMS for demonstrating compliance with the 

NOX emissions limits for all process heaters (40 CFR 60.107a(c) and (d)). As an alternative to 

this general requirement, the rule also provides that small process heaters—those with rated heat 

capacities of less than 100 MMBtu/hr—may instead conduct biennial testing for demonstrating 

compliance with their NOX emissions limits. Commenter 0307 did not make this distinction in 

their comments. Thus, we want to reiterate that only smaller process heaters (those with rated 

heat capacities of less than 100 MMBtu/hr) may choose the option of biennial tests. This 

provision was included after considering available data on these small process heaters as well as 

the cost of applying a CEMS for these smaller process heaters. For the available data 

summarized in the process heater memorandum, only one of 29 process heaters with data 

obtained via CEMS has less than 100 MMBtu/hr capacity. For the data from small process 

heaters summarized in the process heater memorandum, 9 of 10 data points are a result of onetime source tests. Regarding the monitoring costs for small process heaters, we reviewed the 

estimated costs supporting the process heater impacts memorandum (see the third attachment to 
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Docket Item No. EPA-HQ-OAR-2007-0011-0222). The cost of a CEMS is fixed, regardless of 

the process heater size, so it is a larger portion of the cost for smaller process heaters, and the 

effect is to make the control option less cost effective for that process heater. For modified 

forced draft process heaters, for example, the CEMS contributes an additional 50 percent to the 

annualized cost of the burner retrofits. The cost effectiveness of ultra-low NOX burner retrofits 

for a 200 MMBtu/hr process heater with and without CEMS is approximately $1,000 per ton of 

NOX reduced and $1,500 per ton of NOX reduced, respectively. In contrast, the cost effectiveness 

for a modified 70 MMBtu/hr forced draft process heater (the mid-point of the range of small 

process heaters) at a medium-sized refinery with and without a CEMS is about $3,600 and 

$2,300 per ton of NOX, reduced, respectively.

Additionally, this option for small process heaters is not without its own continuous 

monitoring requirements. This option is provided specifically for units that use low-NOX or 

ultra-low NOX burner technologies because the performance of these control systems is generally 

quite stable. As noted previously, one important variable that affects the performance of these 

burners is the level of excess oxygen supplied. To verify continuous performance that is 

indicative of the conditions present during the biennial source tests, the owner or operator must 

establish a maximum excess oxygen operating limit or operating curve during the performance 

test and monitor the oxygen content in the exhaust on a continuous basis. What was inadvertently 

left out of the requirements for this option is the inclusion of this CPMS operating limit in the list 

of conditions that define reportable excess emissions. We are adding that requirement in these 

final amendments at 40 CFR 60.107a(h)(5); the effect of this amendment is that the owner or 

operator of a small process heater that elects to use biennial testing for compliance must report 

any daily average oxygen concentration that exceeds the maximum excess oxygen operating 

limit or operating curve as an exceedance of the NOX emissions limit, just as an owner or 

operator electing to comply using a CEMS must report any 30-day period during which the 

average concentration of NOX exceeds the applicable emissions limit. Thus, considering all of 

the above, the monitoring requirements for process heaters—both large and small—are 

appropriate and sufficient for an owner or operator to demonstrate continuous compliance with 

the applicable NOX emissions limits.
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5.3 Other Clarifications

Comment: Commenter 0311 requested that the term “other means” in 

40 CFR 60.102a(i)(2) be replaced with “other combustion modification based technology” to 

clarify that evaluation or use of post-combustion technologies, such as SCR, are not required.

Response: We agree that the language in 40 CFR 60.102a(i)(2), as worded, could be 

interpreted to mean that the petitioner would have to evaluate SCR technology and provide 

evidence as to why the emissions limit could not be met using an add-on control technology.

This was not our intent. We meant for the evaluation to include potential combustion 

modifications. We have clarified the language in 40 CFR 60.102a(i)(2)(ii) to require that the 

owner or operator “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.”
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6.0 COMPLIANCE REQUIREMENTS AND GENERAL 

MONITORING, RECORDKEEPING AND REPORTING

6.1 Rolling Averages

Comment: Commenter 0309 requested clarification regarding how to calculate rolling 

averages during periods when a CMS (including CEMS) exceeds the maximum prescribed span 

range in the rule. The commenter suggested that the EPA’s policy was that the maximum 

prescribed span range provided in the rule be used. For example, the commenter noted, for 

periods when the fuel gas monitor exceeds 300 ppmv H2S, 300 ppmv should be used in 

calculating the average for that time period, regardless of the monitor’s reading.

Response: We do not agree that it is the EPA’s policy, at least within 40 CFR part 60, to 

use the maximum prescribed span range when the monitor’s reading exceeds the maximum 

prescribed span when calculating rolling averages. It is our policy that sources with CMS data 

outside the certified span should report the CMS “out of control” and declare their compliance 

status as other than continuous. Additionally, for the purposes of calculating rolling averages, the 

direct monitor reading should be used for all periods that the CMS is operational, except for 

periods when the CMS data are invalidated according to 40 CFR 60.13((h)(2)(iv). The CMS 

must be operational for all periods except for system breakdowns, repairs, calibration checks and 

zero and span adjustments as specified in 40 CFR 60.13(e).

Comment: Commenter 0311 requested clarification on how the “365 successive calendar 

day rolling average” in 40 CFR 60.102a(g)(1)(ii) and the “rolling 365 successive operating day 

average” in 40 CFR 60.102a(g)(2) is to be calculated when: a) the unit is not operating; b) when 

the monitor is unavailable (or “out of control” according to Appendix F); and c) turndown occurs 

(if a separate emissions limit does not apply to these periods as recommended by the 

commenter). According to the commenter, a fixed 365 calendar day period is easier to calculate 

than having to determine which days are to be included and having a different and changing 

number of calendar days in the calculation of the average.

Response: The final rule includes a requirement in 40 CFR 60.102a(g)(1)(ii) to limit the 

long-term H2S concentration of fuel gas “determined daily on a 365 successive calendar day 
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average basis.” The final rule also includes NOX limits for process heaters determined on a “30-

day rolling average basis” in 40 CFR 60.102a(g)(2). It is our intention that each 365-day average

would be based on 365 calendar days. Similarly, it is our intention that each 30-day average 

would be based on 30 calendar days, regardless of whether the process heater is operating at full 

capacity or in turndown. Only the hours that the fuel gas combustion device is operating should 

be used when calculating the daily average for a given calendar day. If the fuel gas combustion 

device did not operate at all during a given calendar day, that day would have a null value and 

would not be counted in the 30-day or 365-day average. As such, the 30-day rolling average may 

only contain 20 days of values if the process heater was not operating for 10 days during this 30-

day period. Similarly, CMS “out of control” periods would be considered null values for the 

purposes of calculating the 30-day or 365-day average. See also the previous comment and 

response regarding CMS “out of control” periods.

6.2 Excess Emissions

Comment: Commenter 0309 requested clarification of “all 12-hour periods” for excess 

emissions reporting because the note in 40 CFR 60.106a(b) conflicts with guidance provided by 

EPA Region 3 on April 14, 2000. If the April 2000 guidance is the preferred methodology, then 

the EPA should delete the note and 3-hour standards should be expressed as 180-minute 

averages.

Response: First, we note that the guidance provided by EPA Region 3 is based on the 

language as it was in subpart J prior to amendments, where no additional guidance in the rule 

was provided on how to calculate the 12-hour averages. As such, Region 3’s interpretation is 

justified based on the language used in subpart J. However, requiring 12-hour averages to be 

calculated every minute greatly increases the computational and data storage requirements for 

the refinery with little to no environmental benefit. It is extremely unlikely that a 12-hour 

average excursion will be “seen” when evaluating “by minute” 12-hour averages and not “seen”

when calculating hourly averages. While the hourly averages should be calculated using the 

continuous data (i.e., by minute), there is no need to store these “by minute” data for 12 hours, 

increasing the storage needs by an order of magnitude. We note that the sections describing 

excess emissions (e.g., 40 CFR 60.106a(b), 40 CFR 60.107a(h)) already specify that the 3-hour 

or 12-hour periods are to be determined by first calculating hourly averages and then taking the 
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arithmetic average of the appropriate number of contiguous hourly averages, and we do not find 

it necessary to amend the rule to provide further guidance.

6.3 Monitoring Methods

Comment: Commenter 0311 stated that the reference to Gas Processors Association 

(GPA) Standard 2172-96 in 40 CFR 60.17(m)(2) and 40 CFR 60.107a(d)(7)(v) should be 

updated to GPA 2172-09 because the standard has been updated.

Response: We agree, and both 40 CFR 60.17(m)(2) and 40 CFR 60.107a(d)(7)(viii) have 

been updated to reference the latest version of the standard.

6.4 Reporting Requirements

Comment: Commenter 0311 suggested that the reporting requirement in 

40 CFR 60.108a(c)(6) for RCA be revised to quarterly rather than per event.

Response: First, 40 CFR 60.108a(c)(6) includes recordkeeping requirements and should 

not be confused with reporting requirements. Section 60.108a(c)(6) requires refinery owners and 

operators to keep records of all the RCA info, but it does not specifically require submission of

reports. We also note that 40 CFR 60.103a(d) and (e) use the term “record” or “record and 

explain.” While the latter suggests reporting, neither of these specifically requires submission of 

the record. The actual reporting requirements are summarized in 40 CFR 60.108a(d), which 

requires refinery owners and operators to submit excess emission reports on the schedule 

required by 40 CFR 60.7(c) and describes the information to be included in the report. Section 

60.7(c) requires excess emission reports to be submitted semi-annually: “Each owner or operator 

required to install a continuous monitoring device shall submit excess emissions and monitoring 

systems performance report (excess emissions are defined in applicable subparts)...to the 

Administrator semiannually....All reports shall be postmarked by the 30th day following the end 

of each six-month period.” Therefore, while the report must detail each event that occurred 

during the reporting period, these reports only need to be submitted on a semi-annual basis.

6.5 Impacts on Small Refineries

Comment: Commenter 0302 stated that much of the monitoring, recordkeeping and 

reporting requirements are independent of the size of the refinery, and small refineries, especially 
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those not subject to a consent decree, will have a greater burden in terms of “cost per gallon” 

than larger refineries.

Response: We expect smaller refineries will have fewer flares and fewer process heaters 

above 40 MMBtu/hr and/or 100 MMBtu/hr thresholds that require monitoring. The alternative 

monitoring for process heaters less than 100 MMBtu was specifically included at 

40 CFR 60.107a(c)(6) and 40 CFR 60.107a(d)(8) based on the costs of the NOX CEMS, and

should provide significant relief for small refineries. We were unable to identify reasonable 

alternatives to direct monitoring for flares, given the expected variability in flow and 

composition of flare gas. As such, we require the same level of monitoring for flares regardless 

of the size of the flare or the refinery.