Vol. 77 Wednesday, 

No. 177 September 12, 2012 

Part III 

Environmental Protection Agency 

40 CFR Parts 9 and 60 

Standards of Performance for Petroleum Refineries; Standards of 

Performance for Petroleum Refineries for Which Construction, 

Reconstruction, or Modification Commenced After May 14, 2007; Final Rule 

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56422 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 9 and 60 

[EPA–HQ–OAR–2007–0011; FRL–9672–3] 

RIN 2060–AN72 

Standards of Performance for 

Petroleum Refineries; Standards of 

Performance for Petroleum Refineries 

for Which Construction, 

Reconstruction, or Modification 

Commenced After May 14, 2007 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule; lift stay of effective 

date. 

SUMMARY: On June 24, 2008, the EPA 

promulgated amendments to the 

Standards of Performance for Petroleum 

Refineries and new standards of 

performance for petroleum refinery 

process units constructed, reconstructed 

or modified after May 14, 2007. The 

EPA subsequently received three 

petitions for reconsideration of these 

final rules. On September 26, 2008, the 

EPA granted reconsideration and issued 

a stay for the issues raised in the 

petitions regarding process heaters and 

flares. On December 22, 2008, the EPA 

addressed those specific issues by 

proposing amendments to certain 

provisions for process heaters and flares 

and extending the stay of these 

provisions until further notice. The EPA 

also proposed technical corrections to 

the rules for issues that were raised in 

the petitions for reconsideration. In this 

action, the EPA is finalizing those 

amendments and technical corrections 

and is lifting the stay of all the 

provisions granted on September 26, 

2008 and extended until further notice 

on December 22, 2008. 

DATES: The stay of the definition of 

‘‘flare’’ in 40 CFR 60.101a, paragraph (g) 

of 40 CFR 60.102a, and paragraphs (d) 

and (e) of 40 CFR 60.107a is lifted and 

this final rule is effective on November 

13, 2012. The incorporation by reference 

of certain publications listed in the final 

rule is approved by the Director of the 

Federal Register as of November 13, 

2012. 

ADDRESSES: The EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2007–0011. All 

documents in the docket are listed in 

the www.regulations.gov index. 

Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically in 

www.regulations.gov or in hard copy at 

the EPA Docket Center, Standards of 

Performance for Petroleum Refineries 

Docket, EPA West Building, Room 3334, 

1301 Constitution Ave. NW., 

Washington, DC. The Public Reading 

Room is open from 8:30 a.m. to 4:30 

p.m., Monday through Friday, excluding 

legal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744, and the telephone number for 

the Air Docket is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: Ms. 

Brenda Shine, Office of Air Quality 

Planning and Standards, Sector Policies 

and Programs Division, Refining and 

Chemicals Group (E143–01), 

Environmental Protection Agency, 

Research Triangle Park, NC 27711, 

telephone number: (919) 541–3608; fax 

number: (919) 541–0246; email address: 

shine.brenda@epa.gov. 

SUPPLEMENTARY INFORMATION: The 

information in this preamble is 

organized as follows: 

I. General Information 

A. Does this action apply to me? 

B. Where can I get a copy of this 

document? 

C. Judicial Review 

II. Background Information 

A. Executive Summary 

B. Background of the Refinery NSPS 

III. Summary of the Final Rules and Changes 

Since Proposal 

A. What are the final amendments to the 

standards of performance for petroleum 

refineries (40 CFR part 60, subpart J)? 

B. What are the final amendments to the 

standards of performance for process 

heaters (40 CFR part 60, subpart Ja)? 

C. What are the final amendments to the 

standards of performance for flares (40 

CFR part 60, subpart Ja)? 

D. What are the final amendments to the 

definitions in 40 CFR part 60, subpart Ja? 

E. What are the final technical corrections 

to 40 CFR part 60, subpart Ja? 

IV. Summary of Significant Comments and 

Responses 

A. Process Heaters 

B. Flares 

C. Other Comments 

V. Summary of Cost, Environmental, Energy 

and Economic Impacts 

A. What are the emission reduction and 

cost impacts for the final amendments? 

B. What are the economic impacts? 

C. What are the benefits? 

VI. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. General Information 

A. Does this action apply to me? 

Categories and entities potentially 

regulated by these final rules include: 

Category NAICS Code 1 Examples of regulated 

entities 

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

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

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

1 North American Industry Classification System. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by this action. To determine 

whether your facility would be 

regulated by this action, you should 

examine the applicability criteria in 40 

CFR 60.100 and 40 CFR 60.100a. If you 

have any questions regarding the 

applicability of this action to a 

particular entity, contact the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section. 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56423 

B. Where can I get a copy of this 

document? 

In addition to being available in the 

docket, an electronic copy of this final 

action is available on the World Wide 

Web (WWW) through the Technology 

Transfer Network (TTN). Following 

signature, a copy of this final action will 

be posted on the TTN’s policy and 

guidance page for newly proposed or 

promulgated rules at http:// 

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

provides information and technology 

exchange in various areas of air 

pollution control. 

The EPA has created a redline 

document comparing the existing 

regulatory text of 40 CFR part 60, 

subpart Ja and the final amendments to 

aid the public’s ability to understand 

the changes to the regulatory text. This 

document has been placed in the docket 

for this rulemaking (Docket ID No. EPA– 

HQ–OAR–2007–0011). 

C. Judicial Review 

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

Air Act (CAA), judicial review of these 

final rules is available only by filing a 

petition for review in the United States 

Court of Appeals for the District of 

Columbia Circuit by November 13, 

2012. Under section 307(b)(2) of the 

CAA, the requirements established by 

these final rules may not be challenged 

separately in any civil or criminal 

proceedings brought by the EPA to 

enforce these requirements. 

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

further provides that ‘‘[o]nly an 

objection to a rule or procedure which 

was raised with reasonable specificity 

during the period for public comment 

(including any public hearing) may be 

raised during judicial review.’’ This 

section also provides a mechanism for 

us to convene a proceeding for 

reconsideration, ‘‘[i]f the person raising 

an objection can demonstrate to the EPA 

that it was impracticable to raise such 

objection within [the period for public 

comment] or if the grounds for such 

objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of the rule.’’ Any person 

seeking to make such a demonstration to 

us should submit a Petition for 

Reconsideration to the Office of the 

Administrator, U.S. EPA, Room 3000, 

Ariel Rios Building, 1200 Pennsylvania 

Ave. NW., Washington, DC 20460, with 

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

preceding FOR FURTHER INFORMATION

CONTACT section, and the Associate 

General Counsel for the Air and 

Radiation Law Office, Office of General 

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

1200 Pennsylvania Ave. NW., 

Washington, DC 20460. 

II. Background Information 

A. Executive Summary 

1. Purpose of the Regulatory Action 

This action finalizes amendments that 

were proposed on December 22, 2008, to 

address reconsideration issues related to 

the promulgation of new source 

performance standards (NSPS) for flares 

and process heaters on June 24, 2008. 

This action also lifts the stay that was 

granted on September 26, 2008 (73 FR 

55751) and extended until further notice 

on December 22, 2008 (73 FR 78552) on 

the provisions at issue. 

2. Summary of Major Provisions 

Table 1 presents a summary of major 

changes to the rule since it was first 

promulgated on June 24, 2008. The 

following discussion is a summary of 

major provisions of this rule. 

TABLE 1—SUMMARY OF MAJOR CHANGES SINCE JUNE 24, 2008, PROMULGATION

Affected source Aspect NSPS Ja 

(June 24, 2008) NSPS Ja final 

All Process Heater NOX limits ....... Averaging time .............................. 24-hour rolling average ................ 30-day rolling average. 

Natural Draft Process Heaters ....... NOX Emission Limits .................... 40 ppmv ........................................ 40 ppmv or 0.04 lb/MM BTU. 

Forced Draft Process Heaters ....... NOX Emission Limits .................... 40 ppmv ........................................ 60 ppmv or 0.06 lb/MM BTU. 

Forced Draft Process Heaters with 

Co-fired (oil and gas) Burners.

NOX Emission Limits .................... 40 ppmv ........................................ 150 ppmv or Weighted average 

based on oil at 0.40 lb/MM BTU 

and gas at 0.11 lb/MM BTU. 

Natural Draft Process Heaters with 

Co-fired (oil and gas) Burners.

NOX Emission Limits .................... 40 ppmv ........................................ 150 ppmv or weighted average 

based on oil at 0.35 lb/MM BTU 

and gas at 0.06 lb/MM BTU. 

Process Heaters ............................ Alternate Emission Standards ...... None ............................................. Case by case approval for some 

circumstances. 

Flares ............................................. Applicability ................................... New or reconstructed flare systems or existing flare systems 

that are physically altered to increase flow or to add new connections.

Similar, except specific list of connections that do not trigger applicability. 

Fuel gas combustion devices ........ H2S concentration limit ................. 162 ppmv H2S (3-hour average); 

60 ppmv H2S (annual rolling average).

162 ppmv H2S (3-hour average); 

No 60 ppmv H2S long term 

concentration limit for flares. 

Flares ............................................. Compliance date for modified 

flares.

Comply with H2S limit at start-up, 

and all other requirements within 1 year.

Comply with H2S limit at start-up 

(except for modified flares not 

previously subject to the H2S 

limit in 40 CFR part 60, subpart 

J or those with monitoring alternatives, or those complying with 

subpart J as specified in a consent decree, which comply no 

later than 3 years) and all other 

requirements within 3 years. 

Flares ............................................. Flow limits ..................................... Flare system-wide flow limit of 

250,000 scfd.

No limits. 

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56424 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

TABLE 1—SUMMARY OF MAJOR CHANGES SINCE JUNE 24, 2008, PROMULGATION—Continued 

Affected source Aspect NSPS Ja 

(June 24, 2008) NSPS Ja final 

Flares ............................................. Root Cause Analysis and Corrective Action (RCA/CA).RCA/CA required on upsets or 

malfunctions in excess of 

500,000 scfd or 500 lbs/day 

SO2 from SSM.

RCA/CA required for 500,000 scfd 

above base load and 500 lbs 

SO2 in any 24-hour period. 

Flares ............................................. Flow monitoring ............................ Continuous .................................... Continuous except for intermittent/ 

emergency only flares with 

water seal monitoring and limited releases. 

Flares ............................................. Sulfur Monitoring .......................... Continuous Total Reduced Sulfur 

(TRS).

Continuous TRS, using reference 

method 15A (Total Sulfur). 

Affected process heaters are those that 

were modified, reconstructed or 

constructed after May 14, 2007. For 

these affected sources, these final 

amendments include concentrationbased nitrogen oxide (NOX) emissions 

limits and alternative heating valuebased NOX emissions limits, both 

determined daily on a 30-day rolling 

average basis. These final amendments 

establish limits of 40 parts per million 

by volume (ppmv) NOX (or 0.04 pounds 

per million British thermal units (lb/ 

MMBtu) and 60 ppmv NOX (or 0.06 lb/ 

MMBtu) for natural draft and forced 

draft process heaters, respectively. Cofired process heaters, designed to 

operate on gaseous and liquid fuel (e.g., 

oil), must meet either 150 ppmv NOX or 

alternative heating value-based limits, 

weighted based on oil and gas use. The 

NSPS also contains an alternative 

compliance option that allows owners 

and operators to obtain EPA approval 

for a site-specific NOX limit for process 

heaters that may have difficulty meeting 

the standards under certain situations. 

These final amendments also include 

monitoring, recordkeeping and 

reporting requirements necessary to 

demonstrate compliance with the NOX

emission standards. 

For flares, these final amendments 

define a flare as a separate affected 

facility rather than a type of fuel gas 

combustion device. As such, these final 

amendments remove requirements for 

flares to comply with the performance 

standards for sulfur dioxide (SO2) 

(expressed as a 162 ppmv short-term 

hydrogen sulfide (H2S) concentration 

limit) and, instead, establish a separate 

suite of standards for flares. We are not 

finalizing the requirement in the 

December 22, 2008, proposed 

amendments for flares to meet the longterm 60 ppmv H2S fuel gas 

concentration limit. As explained in 

section IV of this preamble, we 

determined that requiring refineries to 

ensure the fuel gas they send to their 

flares meets a long-term H2S 

concentration of 60 ppmv is not 

appropriate for flares. 

Affected flares are those that were 

modified, reconstructed or constructed 

after June 24, 2008. In general, a flare is 

modified if a connection is made into 

the flare header that can increase 

emissions from the flare. The NSPS 

specifically identifies certain 

connections to a flare that do not 

constitute a modification of the flare 

because they do not result in emissions 

increases. 

The final amendments for flares 

include a suite of standards that apply 

at all times. This suite of standards 

requires refineries to: (1) Develop and 

implement a flare management plan; (2) 

conduct root cause analyses and take 

corrective action when waste gas sent to 

the flare exceeds a flow rate of 500,000 

standard cubic feet per day (scfd) above 

the baseline flow or contains sulfur that, 

upon combustion, will emit more than 

500 pounds (lb) of SO2 in a 24-hour 

period; and (3) optimize management of 

the fuel gas by limiting the short-term 

concentration of H2S to 162 ppmv 

during normal operating conditions. 

The final amendments require that 

flares be equipped with flow and sulfur 

monitors except in cases where flares 

are used infrequently or are configured 

such that they cannot receive high 

sulfur gas. For flares that are configured 

such that they only receive inherently 

low sulfur gas streams, continuous 

sulfur monitors are not necessary 

because a root cause analysis will be 

triggered by an exceedance of the flow 

rate threshold long before they exceed 

the 500 lb SO2 trigger in a 24-hour 

period. 

For infrequently used flares, the NSPS 

allows for less burdensome monitoring, 

consisting of monitoring the differential 

pressure between the flare header and 

the flare water seal to determine if a gas 

release to the flare has occurred. Any 

instance where the pressure upstream of 

the water seal (expressed in inches of 

water) exceeds the water seal height 

triggers a requirement to perform a root 

cause analysis and corrective action 

analysis, unless the discharge is related 

to flare gas recovery system compressor 

cycling or a planned startup or 

shutdown (of a refinery process unit or 

ancillary equipment connected to the 

flare) following the procedures in the 

flare management plan. The NSPS also 

contains an alternative compliance 

option for refinery flares located in the 

South Coast Air Quality Management 

District (SCAQMD) or the Bay Area Air 

Quality Management District 

(BAAQMD). An affected flare subject to 

40 CFR part 60, subpart Ja may elect to 

comply with SCAQMD Rule 1118 or 

both BAAQMD Regulation 12, Rule 11 

and BAAQMD Regulation 12, Rule 12 as 

an alternative to complying with the 

requirements of subpart Ja. 

3. Costs and Benefits 

The provisions for flares and other 

fuel gas combustion devices (i.e., 

process heaters and boilers) from the 

final June 2008 standards were stayed. 

The analysis for this final rule includes 

the same unit costs for the flare 

provisions as the final June 2008 rule 

but reflects recalculated total costs using 

data collected in the March 2011 

information collection request (ICR) to 

update the number of flares. For the 

June 2008 standards, we estimated that 

40 flares would be affected. We now 

anticipate that there will be 400 affected 

flares that will be subject to this final 

rule. Table 2 includes the recalculated 

cost estimates based on the updated 

number of flares since 2008, broken out 

by specific flare requirements. For the 

other fuel gas combustion devices, the 

total annualized costs for those 

provisions were estimated at $24 

million (2006 dollars) in the June 2008 

rule and remain the same. As discussed 

below, because there are no additional 

incremental costs associated with the 

other fuel gas combustion device 

provisions, we consider those annual 

costs accounted for in the final June 

2008 standards. We are presenting these 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56425 

1 It is important to note that the EPA has 

implemented several substantial changes to the 

benefits methodology since 2008, which makes it 

challenging to compare the benefits of the June 

2008 rule to the benefits of the current rulemaking. 

The changes with the largest impact on the range 

of monetized benefits are the removal of the 

assumption of a threshold in the concentrationresponse function, the revision of the value-of-astatistical-life, and the range of risk estimates from 

epidemiology studies rather than the range of risk 

estimates supplied by experts. See the regulatory 

impact analysis for the current rulemaking for more 

information regarding these changes, which is 

available in the docket. 

costs and benefits here again, even 

though we estimate no changes to them, 

since these provisions will become 

effective upon this final action to lift the 

stay on certain provisions in the June 

2008 rule. For the June 2008 rule, we 

estimated the benefits to be $220 

million to $1.9 billion and $200 to $1.7 

billion at a 3-percent discount rate and 

7-percent discount rate, respectively.1

Cost impacts for flares are presented 

in Table 2. The estimated total capital 

cost of complying with the final 

amendments to 40 CFR part 60, subpart 

Ja for flares is $460 million dollars (2006 

dollars). The estimated annual cost, 

including annualized capital costs, is a 

cost savings of about $79 million (2006 

dollars) due to the replacement of some 

natural gas purchases with recovered 

flare gas and the retention of 

intermediate and product streams due to 

a reduction in the number of 

malfunctions associated with refinery 

process units and ancillary equipment 

connected to the flare. Note that not all 

refiners will realize a cost savings since 

we only estimate that refineries with 

high flare flows will install vapor 

recovery systems. Although the rule 

does not specifically require installation 

of flare gas recovery systems, we project 

that owners and operators of flares 

receiving high waste gas flows will 

conclude, upon installation of monitors, 

implementation of their flare 

management plans, and implementation 

of root causes analyses, that installing 

flare gas recovery would result in fuel 

savings by using the recovered flare gas 

where purchased natural gas is now 

being used to fire equipment such as 

boilers and process heaters. The flare 

management plan requires refiners to 

conduct a thorough review of the flare 

system so that flare gas recovery systems 

are installed and used where these 

systems are warranted. As part of the 

development of the flare management 

plan, refinery owners and operators 

must provide rationale and supporting 

evidence regarding the flare waste gas 

reduction options considered. In 

addition, consistent with Executive 

Order 13563 (Improving Regulation and 

Regulatory Review, issued on January 

18, 2011), for facilities implementing 

flare gas recovery, we are finalizing 

provisions that would allow the owner 

or operator to reduce monitoring costs 

and the number of root cause analyses, 

corrective actions, and corresponding 

recordkeeping and reporting they would 

need to perform. The costs calculated 

for this rule, however, do not account 

for potential savings due to these 

provisions (reduced monitoring, root 

cause analysis, etc.). We estimate that 

the final requirements for flares will 

reduce emissions of SO2 by 3,200 tons 

per year (tons/yr), NOX by 1,100 tons/ 

yr and volatile organic compounds 

(VOC) by 3,400 tons/yr from the 

baseline. The overall cost effectiveness 

is a cost savings of about $10,000 per 

ton of combined pollutants removed. 

We also estimate that the final 

requirements for flares will result in 

emissions reduction co-benefits of CO2

equivalents by 1,900,000 metric tonnes 

per year, predominantly as a result of 

our estimate of the largest flares 

employing flare gas recovery, and to a 

lesser extent, as a result of the flow rate 

root cause analyses and corrective 

actions applicable to all flares. 

TABLE 2—COST IMPACTS FOR PETROLEUM REFINERY FLARES SUBJECT TO AMENDED STANDARDS UNDER 40 CFR PART

60, SUBPART JA

[Fifth year after the effective date of these final rule amendments] 

Subpart Ja requirements 

Total capital 

cost 

($1,000) 

Total annual 

cost without 

credit 

($1,000/yr) 

Natural gas 

offset/product 

recovery credit 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Annual 

emission 

reductions 

(tons SO2/yr) 

Annual 

emission 

reductions 

(tons NOX/yr) 

Annual 

emission 

reductions 

(tons VOC/yr) 

Cost 

effectiveness 

($/ton emissions reduced) 

Majority of flares (approximately 360 flares) 

Flare Monitoring .......................... 72,000 12,000 0 12,000 0 0 0 ........................

Flare gas recovery ...................... 0 0 0 0 0 0 0 ........................

Flare Management ...................... 0 790 0 790 0 0 270 2,900 

SO2 RCA/CA ............................... 0 1,900 0 1,900 2,600 0 0 760 

Flowrate RCA/CA ........................ ...................... 900 (6,700 ) (5,800 ) 3.4 50 390 (13,000 ) 

Subtotal 1 .............................. 72,000 16,000 (6,700 ) 9,000 2,600 50 660 2,700 

Largest flares (approximately 40 flares) 2

Flare Monitoring .......................... 12,000 2,000 0 2,000 0 0 0 ........................

Flare gas recovery ...................... 380,000 78,000 (170,000 ) (90,000 ) 380 1,100 2,700 (22,000 ) 

Flare Management ...................... 0 88 0 88 0 0 30 2,900 

SO2 RCA/CA ............................... 0 220 0 220 290 0 0 760 

Flowrate RCA/CA ........................ 0 100 (740 ) (640 ) 0.4 6 43 (13,000 ) 

Subtotal 1 .............................. 390,000 81,000 (170,000 ) (88,000 ) 660 1,100 2,800 (20,000 ) 

Total 1 ............................ 460,000 96,000 (180,000 ) (79,000 ) 3,200 1,100 3,400 (10,000 ) 

1All estimates are rounded to two significant figures so numbers may not sum down columns. 

2The EPA has conducted an alternative analysis that presents the costs and benefits of the rule assuming that no refiners will opt to install flare gas recovery systems as part of their flare management strategy. This analysis is presented in the Regulatory Impact Analysis in the discussion provided in the executive summary 

and in Section 4.1, available in the docket for this rulemaking. 

We estimate the monetized benefits of 

this final regulatory action for all flares 

to be $260 million to $580 million (3- 

percent discount rate) and $240 million 

to $520 million (7-percent discount rate 

for health benefits and 3-percent 

discount rate for climate benefits). For 

small flares only, we estimate the 

monetized benefits are $170 million to 

$410 million (3-percent discount rate) 

and $150 million to $370 million (7- 

percent discount rate for health benefits 

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56426 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

2The September 26, 2008, Federal Register notice 

(73 FR 55751) described the first issue for which the 

EPA granted reconsideration as ‘‘the definition of 

‘modification.’’’ However, because what we are 

actually reconsidering is the specific flare 

modification provision that applies to flares at 

petroleum refineries rather than the more generally 

applicable definition of ‘‘modification,’’ we have 

revised the description of this issue as ‘‘the newly 

promulgated flare modification provision.’’ 

and 3-percent discount rate for climate 

benefits). For large flares only, we 

estimate the monetized benefits are $93 

million to $160 million (3-percent 

discount rate) and $88 million to $150 

million (7-percent discount rate for 

health benefits and 3-percent discount 

rate for climate benefits). Several 

benefits categories, including direct 

exposure to SO2 and NOX benefits, 

ozone benefits, ecosystem benefits and 

visibility benefits are not included in 

these monetized benefits. All estimates 

are in 2006 dollars for the year 2017. 

Although this final rule provides 

refiners with some additional 

compliance options and removes some 

requirements, such as the long-term H2S 

limit for flares, the cost savings due this 

increased flexibility have not been 

calculated for inclusion in the benefitcost analysis. 

B. Background of the Refinery NSPS 

Section 111(b)(1)(A) of the Clean Air 

Act (CAA) requires the EPA to establish 

federal standards of performance for 

new, modified and reconstructed 

sources for source categories which 

cause or contribute significantly to air 

pollution which may reasonably be 

anticipated to endanger public health or 

welfare. The standard of performance 

must reflect the application of the best 

system of emission reductions (BSER) 

that (taking into consideration the cost 

of achieving such emission reductions, 

any non-air quality health and 

environmental impact and energy 

requirements) the Administrator 

determines has been adequately 

demonstrated (CAA section 111(a)(1)). If 

it is not feasible to prescribe or enforce 

a standard of performance, the 

Administrator may instead promulgate a 

design, equipment, work practice or 

operational standard, or a combination 

of these types of standards (CAA section 

111(h)(1)). Since 1970, the NSPS have 

been successful in achieving long-term 

emissions reductions in numerous 

industries by assuring cost-effective 

controls are installed on newly 

constructed, reconstructed or modified 

sources. 

The level of control prescribed by 

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 in its rulemaking 

packages. See, e.g., 76 FR 52738, 52740 

(August 23, 2011); 76 FR 63878, 63879 

(October 14, 2011). As was done 

previously in analyzing BDT, the EPA 

uses available information and 

considers the emissions reductions 

achieved by the different systems 

available and the costs of achieving 

those reductions. The EPA also 

considers the ‘‘other factors’’ prescribed 

by the statute in its BSER analysis. After 

considering all of this information, the 

EPA then establishes the appropriate 

standard representative of BSER. 

Sources may use whatever system meets 

the standard. 

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

requires the EPA to periodically review 

and, as appropriate, revise the standards 

of performance to reflect improvements 

in methods for reducing emissions. As 

a result of our periodic review of the 

NSPS for petroleum refineries (40 CFR 

part 60, subpart J), we proposed 

amendments to the current standards of 

performance and separate standards of 

performance for new process units (40 

CFR part 60, subpart Ja) (72 FR 27278, 

May 14, 2007) and we subsequently 

promulgated those amendments and 

new standards (73 FR 35838, June 24, 

2008). Following promulgation, we 

received three separate petitions for 

reconsideration from: (1) The American 

Petroleum Institute (API), the National 

Petrochemical and Refiners Association 

(NPRA) and the Western States 

Petroleum Association (WSPA) 

(collectively referred to as ‘‘Industry 

Petitioners’’); (2) HOVENSA, LLC 

(‘‘HOVENSA’’); and (3) the 

Environmental Integrity Project, Sierra 

Club and Natural Resources Defense 

Council (collectively referred to as 

‘‘Environmental Petitioners’’). On 

September 26, 2008, the EPA issued a 

Federal Register notice (73 FR 55751) 

granting reconsideration of the 

following issues: (1) The newly 

promulgated flare modification 

provision2; (2) the ‘‘flare’’ definition; (3) 

the fuel gas combustion device sulfur 

limits as they apply to flares; (4) the 

flow limit for flares; (5) the total 

reduced sulfur and flow monitoring 

requirements for flares; and (6) the NOX

limit for process heaters. The EPA also 

granted Industry Petitioners’ and 

HOVENSA’s request for a 90-day stay 

for those same provisions under 

reconsideration. On December 22, 2008, 

three Federal Register notices (73 FR 

78260, 73 FR 78546 and 73 FR 78549) 

were published to extend this stay until 

a final decision is reached on those 

issues. 

In the September 26, 2008, Federal 

Register notice (73 FR 55751), we also 

identified other issues for which 

Petitioners requested reconsideration. 

We stated that, at that time, we were 

‘‘taking no action on all of the other 

issues raised in the petitions but will 

consider all of the outstanding issues in 

a future notice.’’ On December 29, 2009, 

we sent a letter to the Petitioners, 

through their counsel, stating that ‘‘[t]he 

Administrator has decided to grant 

reconsideration of all the remaining 

issues’’ and that ‘‘EPA will address the 

substantive aspects of the issues under 

reconsideration through notice and 

comment actions published in the 

Federal Register.’’ A copy of the letter 

to the Petitioners can be found in the 

docket for this rulemaking (Docket Item 

No. EPA–HQ–OAR–2007–0011–0318). 

In this action, we are finalizing the 

amendments for which we granted 

reconsideration and a stay as outlined in 

the September 26, 2008, notice and for 

which we proposed amendments on 

December 22, 2008. We are also 

addressing certain other minor issues 

raised by Industry Petitioners in this 

action, as discussed later in this 

preamble. We will take action on all of 

the remaining issues raised by 

Petitioners for reconsideration in future 

notices. 

We received a total of 22 comments 

from the following groups on the 

proposed amendments during the 

public comment period: (1) Refineries, 

industry trade associations and 

consultants; (2) state and local 

environmental and public health 

agencies; (3) environmental groups; and 

(4) other members of the public. These 

final amendments reflect our full 

consideration of all of the comments we 

received. Detailed responses to the 

comments not included in this 

preamble, as well as more detailed 

summaries of the comments addressed 

in this preamble, are contained in 

Standards of Performance for Petroleum 

Refineries: Background Information for 

Final Amendments—Summary of Public 

Comments and Responses, dated 

December 2011, which is included in 

Docket ID No. EPA–HQ–OAR–2007– 

0011. 

In summary, major comments on the 

proposed process heater requirements 

were related to the proposed NOX

concentration limits, the alternative 

heating value limits, consideration of 

turndown (i.e., when a process heater is 

operated at less than 50-percent design 

capacity) and other factors that 

influence the achievable emissions 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56427 

limits. In response, we are raising the 

limit for new forced draft process 

heaters from 40 ppmv NOX at proposal 

to 60 ppmv NOX. For both natural draft 

and forced draft process heaters, we are 

finalizing alternative heating value 

limits derived from a more direct 

numerical conversion of the NOX

concentration limit (i.e., 0.04 lb/MMBtu 

for natural draft and 0.06 lb/MMBtu for 

forced draft). For newly constructed, 

modified and reconstructed natural 

draft and forced draft process heaters, 

we are reducing the averaging time for 

compliance from a 365-day rolling 

average to a 30-day rolling average 

applicable during periods of normal 

operation. We are also finalizing an 

alternative case-specific compliance 

option that allows owners and operators 

to obtain EPA approval for a sitespecific NOX limit in certain conditions 

such as turndown. 

Major comments on the proposed 

requirements for flares were related to 

the definition of flare modification for 

purposes of triggering applicability to 

this rule, the proposed removal of the 

flare flow limit, clarification of flare 

monitoring requirements and 

clarification of the differences between 

the requirement for flares and the 

requirements for other fuel gas 

combustion devices. We address these 

comments by clarifying the definition of 

flare modification and by expanding the 

list included in the December 22, 2008, 

proposal, which specifies certain 

connections that do not constitute a 

modification of the flare because they 

do not result in emissions increases. We 

are finalizing the proposed removal of 

the flare flow limit and instead, we are 

promulgating a suite of work practice 

standards that apply to affected flares. 

Based on comments received on the 

December 22, 2008 proposal, we are 

finalizing definitions of ‘‘fuel gas 

combustion device’’ and ‘‘flare’’ to 

specify that a flare is a separate affected 

facility rather than a type of fuel gas 

combustion device. We are also 

finalizing amendments to clarify certain 

monitoring requirements and to provide 

additional monitoring alternatives 

under certain circumstances. 

III. Summary of the Final Rules and 

Changes Since Proposal 

NSPS for petroleum refineries (40 

CFR part 60, subpart J) apply to the 

affected facilities at the refinery, such as 

fuel gas combustion devices (which 

include process heaters, boilers and 

flares), that commence construction, 

reconstruction or modification after 

June 11, 1973, but on or before May 14, 

2007 (on or before June 24, 2008 for 

flares). The NSPS were originally 

promulgated on March 8, 1974, and 

have been amended several times. In 

this action, we are promulgating 

technical clarifications and corrections 

to subpart J. 

New standards of performance for 

petroleum refineries (40 CFR part 60, 

subpart Ja) apply to flares that 

commence construction, reconstruction 

or modification after June 24, 2008, and 

other affected facilities at petroleum 

refineries, including process heaters and 

other fuel gas combustion devices that 

commence construction, reconstruction 

or modification after May 14, 2007. In 

this action, we are finalizing 

amendments to subpart Ja to address the 

issues raised by Petitioners regarding 

flares and process heaters. We are also 

finalizing technical corrections to 

subpart Ja for certain issues that were 

identified by Industry Petitioners in 

their August 21, 2008, supplement to 

their original administrative 

reconsideration request (Docket Item 

No. EPA–HQ–OAR–2007–0011–0246). 

The following sections summarize the 

amendments in both 40 CFR part 60, 

subpart J and 40 CFR part 60, subpart Ja. 

Section IV contains the rationale for 

these amendments, while the 

amendments themselves follow the 

preamble. 

A. What are the final amendments to 

the standards of performance for 

petroleum refineries (40 CFR part 60, 

subpart J)? 

The final amendments add a new 

paragraph to 40 CFR 60.100 to allow 40 

CFR part 60, subpart J affected sources 

the option of complying with subpart J 

by following the requirements in 40 CFR 

part 60, subpart Ja. The subpart Ja 

requirements are at least as stringent as 

those in subpart J, so providing this 

option will allow all process units in a 

refinery to follow the same requirements 

and simplify compliance. We are also 

removing the reference to 40 CFR 

60.101a from the description of the 

applicability dates in 40 CFR 60.100(b) 

so as not to cause confusion over the 

definition of ‘‘flare’’ in subpart J. We are 

finalizing a correction to the value and 

units (in the metric system) for the 

allowable incremental rate of particulate 

matter (PM) emissions in 40 CFR 

60.106(c)(1). We amended the units for 

this constant in 40 CFR 60.102(b) on 

June 24, 2008, and we are now 

correcting 40 CFR 60.106(c)(1) 

accordingly. Finally, we are finalizing a 

definition of ‘‘fuel gas’’ that incorporates 

the same clarifications regarding vapors 

from wastewater treatment units and 

marine tank vessel loading operations 

identified in the subpart Ja definition of 

‘‘fuel gas’’ (described later in this 

preamble). 

B. What are the final amendments to the 

standards of performance for process 

heaters (40 CFR part 60, subpart Ja)? 

We proposed several amendments to 

the standards of performance for process 

heaters, including adding emission 

limits in units of lb/MMBtu, extending 

the emission limit averaging time from 

24 hours to 365 days, raising the 

emission limit for modified and 

reconstructed forced draft process 

heaters and raising the emission limit 

for co-fired process heaters. After 

consideration of all of the public 

comments and our own additional 

analyses, we are finalizing the process 

heater requirements, as described in this 

section. 

Table 3 presents a comparison of the 

proposed and final 40 CFR part 60, 

subpart Ja amendments for process 

heaters. The final amendments include 

four subcategories of process heaters: (1) 

Natural draft process heaters; (2) forced 

draft process heaters; (3) co-fired natural 

draft process heaters; and (4) co-fired 

forced draft process heaters. At 

proposal, all co-fired process heaters 

were included in one subcategory, for a 

total of three process heater 

subcategories, but, based on emissions 

data from co-fired process heaters, we 

divided natural draft and forced draft 

co-fired process heaters into separate 

subcategories with different emissions 

limits. 

For each of the first two subcategories, 

the final amendments include a 

concentration-based NOX emissions 

limit and a heating value-based NOX

emissions limit, both determined daily 

on a 30-day rolling average basis. For 

the natural draft process heater 

subcategory, the concentration-based 

NOX emissions limit for newly 

constructed, modified and reconstructed 

natural draft process heaters is 40 ppmv 

(dry basis, corrected to 0-percent excess 

air) determined daily on a 30-day rolling 

average basis. The heating value-based 

NOX emissions limit for newly 

constructed, modified and reconstructed 

natural draft process heaters is 0.040 lb/ 

MMBtu higher heating value basis 

determined daily on a 30-day rolling 

average basis. The averaging time for 

both of these limits is shorter than the 

365-day averaging time that was 

proposed, and the heating value-based 

NOX emissions limit differs from the 

proposed limit in that it is a more direct 

numerical conversion from 40 ppmv 

NOX. At proposal, we provided a longer 

averaging time so that short periods of 

turndown (i.e., when a process heater is 

operating at less than 50-percent design 

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56428 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

capacity) would not significantly affect 

the overall performance of the unit. Our 

analysis of the additional data that we 

obtained following the proposal 

supported revising all NOX emissions 

limits to be on a 30-day rolling average 

basis, which is achievable for process 

heaters during periods of normal 

operation. These data indicate that 

process heaters equipped with ultra low 

NOX burners meet the emission limits 

described above if compliance is 

determined on a 30-day rolling average 

basis. We are finalizing alternative 

compliance options that allow the 

owners and operator to establish sitespecific limits applicable during certain 

conditions such as turndown. Section 

IV.A of this preamble provides 

additional information regarding the 

rationale and analyses leading to these 

final amendments. 

For the second subcategory, forced 

draft process heaters, the concentrationbased NOX emissions limit for newly 

constructed, modified and reconstructed 

forced draft process heaters is 60 ppmv 

(dry basis, corrected to 0-percent excess 

air) determined daily on a 30-day rolling 

average basis. The heating value-based 

NOX emissions limit for newly 

constructed, modified and reconstructed 

forced draft process heaters is 0.060 lb/ 

MMBtu higher heating value basis 

determined daily on a 30-day rolling 

average basis. The higher limit for new 

forced draft process heaters (at proposal, 

the limit was 40 ppmv) is based on 

additional data and a re-evaluation of 

BSER, as described later in this 

preamble. As with natural draft process 

heaters, the averaging time for both of 

these limits is shorter than proposed, 

and the final heating value-based NOX

emissions limit is a more direct 

numerical conversion from 60 ppmv 

NOX. Section IV.A of this preamble 

provides additional information 

regarding the rationale and analyses 

leading to these final amendments. 

For each of these subcategories, a 

process heater need only meet either the 

concentration-based NOX emissions 

limit or the heating value-based NOX

emissions limit. The refinery owner or 

operator may choose to comply with 

either limit at any time, provided that 

they are monitoring the appropriate 

variables to assess the heating valuebased NOX emissions limit. If the 

refinery owner or operator does not 

choose to monitor fuel composition, 

then they must comply with the 

concentration-based NOX emissions 

limit. 

TABLE 3—PROPOSED AND FINAL AMENDMENTS FOR PROCESS HEATERS

Proposal 

(December 22, 2008) Final 

Averaging time ................................................... 365-day rolling average ................................... 30-day rolling average. 

Natural Draft NOX Emission Limits .................... 40 ppmv or 0.035 lb/MM BTU ......................... 40 ppmv or 0.04 lb/MM BTU. 

Forced Draft NOX Emission Limits .................... New: 40 ppmv or 0.035 lb/MM BTU ................

M/R: 60 ppmv or 0.055 lb/MM BTU 

60 ppmv or 0.06 lb/MM BTU. 

Co-fired Burner (oil and gas) NOX Emission 

Limits.

150 ppmv or Weighted average based on oil 

at 0.27 lb/MM BTU and gas at 0.08 lb/MM 

BTU.

150 ppmv or Weighted average based on oil 

at 0.40 lb/MM BTU and gas at 0.11 lb/MM 

BTU forced draft and weighted average 

based on oil at 0.35 lb/MM BTU and gas at 

0.06 lb/MM BTU for natural draft. 

As proposed, initial compliance with 

the heating value-based emissions limits 

will be demonstrated by conducting a 

performance evaluation of the 

continuous emission monitoring system 

(CEMS) in accordance with Performance 

Specification 2 in appendix B to 40 CFR 

part 60, with EPA Method 7 of 40 CFR 

part 60, appendix A–4 as the Reference 

Method, along with fuel flow 

measurements and fuel gas 

compositional analysis. The NOX

emission rate is calculated using the 

oxygen (O2)-based F factor, dry basis 

according to EPA Method 19 of 40 CFR 

part 60, appendix A–7. Ongoing 

compliance with this NOX emissions 

limit is determined using a NOX CEMS 

and at least daily sampling of fuel gas 

heat content or composition to calculate 

a daily average heating value-based 

emissions rate, which is subsequently 

used to determine the 30-day average. 

The third and fourth subcategories of 

process heaters are co-fired process 

heaters. A co-fired process heater is a 

process heater that employs burners that 

are designed to be supplied by both 

gaseous and liquid fuels. As described 

in more detail in section IV.A of this 

preamble, co-fired process heaters do 

not include gas-fired process heaters 

that have emergency oil back-up 

burners. There are two compliance 

options for each subcategory of co-fired 

process heaters: (1) 150 ppmv (dry basis, 

corrected to 0-percent excess air) 

determined daily on a 30 successive 

operating day rolling average basis; and 

(2) a source-specific daily average 

emissions limit. Unlike gas-fired process 

heaters, the owner or operator of a cofired process heater must choose one 

emissions limit and show compliance 

with that limit. For co-fired natural draft 

process heaters, the daily average 

emissions limit is based on a limit of 

0.06 lb/MMBtu for the gas portion of the 

firing and 0.35 lb/MMBtu for the oil 

portion of the firing. For co-fired forced 

draft process heaters, the daily average 

emissions limit is based on a limit of 

0.11 lb/MMBtu for the gas portion of the 

firing and 0.40 lb/MMBtu for the oil 

portion of the firing. These limits are 

different than proposed, based on a reevaluation of BSER with new data 

received during the public comment 

period. All of the requirements for 

emissions monitoring, recordkeeping 

and reporting for co-fired process 

heaters are the same as for the other 

process heater subcategories. 

We are also finalizing an alternative 

compliance option that allows owners 

and operators to obtain EPA approval 

for a site-specific NOX limit for certain 

process heaters. This compliance option 

was provided in the proposed 

amendments, but it was limited to (1) 

natural draft and forced draft modified 

or reconstructed process heaters that 

lack sufficient space to accommodate 

combustion modification-based 

technology and (2) natural draft and 

forced draft co-fired process heaters. In 

the final amendments, we are finalizing 

this compliance option for those process 

heaters mentioned above while also 

providing this compliance option for the 

following additional types of process 

heaters: (3) modified or reconstructed 

induced draft process heaters that have 

downwardly firing burners and (4) 

forced draft and natural draft process 

heaters that operate at low firing rates, 

or turndown, for an extended period of 

time. As we noted in the preamble to 

the proposed amendments, in limited 

cases, existing natural draft or forced 

draft process heaters have limited 

firebox size or other constraints such 

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that they cannot apply the BSER of 

ultra-low NOX burners or otherwise 

meet the applicable limit and some cofired units may not be able to achieve 

the NOX limitations even with ultra-low 

NOX burner control technology. In 

addition, commenters noted that 

downwardly fired process heaters with 

induced draft fans have similar NOX

control issues as forced draft heaters, 

but the definition of forced draft heater 

does not include these induced draft 

heaters (these are defined as natural 

draft process heaters). Therefore, we 

added a provision to allow induced 

draft process heaters with downwardlyfiring burners to use the alternative 

compliance option. 

Finally, we note that the emissions 

limits for forced draft and natural draft 

gas-fired process heaters are based on 

the performance of ultra-low NOX

burner control technologies. The ultralow NOX burner technology suppliers 

recommend operating with higher 

excess air rates at low firing rates (at or 

below approximately one-half of the 

maximum firing capacity), which causes 

higher NOX concentrations at low firing 

rates. Therefore, all types of process 

heaters with ultra-low NOX burner 

control technologies may be unable to 

meet the emissions limits if they are 

operated at low firing rates for an 

extended period of time. Requesting a 

site-specific emissions limit requires a 

detailed demonstration that the 

application of the ultra-low NOX burner 

technology is not feasible or that the 

technology cannot meet the NOX

emissions limits given the conditions of 

the process heater (downward fired 

induced draft, co-fired or prolonged 

turndown); the refinery must also 

conduct source tests in developing a 

site-specific emissions limit for its 

process heater. This analysis must be 

submitted to and approved by the 

Administrator. 

We are finalizing the proposed 

clarification that owners and operators 

of process heaters in any subcategory 

with a rated heating capacity of less 

than 100 million British thermal units 

per hour (MMBtu/hr) have the option of 

using CEMS. The final rule states that 

owners and operators of process heaters 

subject to 40 CFR part 60, subpart Ja 

should use CEMS to demonstrate 

compliance unless the heater is 

equipped with combustion 

modification-based technology (lowNOX burners or ultra-low NOX burners) 

with a rated heating capacity of less 

than 100 MMBtu/hr; owners and 

operators of those specific process 

heaters have the alternative option of 

biennial source testing to determine 

compliance. As requested by 

commenters, we have provided 

additional detail in the final rule 

regarding how to develop the O2

operating limit, including provisions on 

how to develop an O2 operating curve 

to ensure compliance with the NOX

emission limit at different process 

heater firing rates. We are requiring that 

owners and operators with process 

heaters in any subcategory that are 

complying using biennial source testing 

establish a maximum excess O2

concentration operating limit or 

operating curve that can be met at all 

times, even during turndown, and 

comply with the O2 monitoring 

requirements for ongoing compliance 

demonstration. 

C. What are the final amendments to the 

standards of performance for flares (40 

CFR part 60, subpart Ja)? 

We proposed several amendments to 

the standards of performance for flares, 

including, but not limited to, amending 

the flare modification provision, 

removing the numerical limit on the 

flow rate to the flare, revising the flare 

management plan requirements to 

include a list of connections to the flare 

and an identification of baseline 

conditions, clarifying when a root cause 

analysis is required, revising the sulfur 

and flow monitoring requirements and 

providing additional time for 

compliance. After consideration of all of 

the public comments, and our own 

additional analyses, we are finalizing 

the flare requirements, as described in 

this section. 

We did not propose to revise the 

definitions of ‘‘fuel gas combustion 

device’’ and ‘‘flare’’ on December 22, 

2008. However, based on public 

comment and changes to the flare 

requirements, as described later in this 

section, we have decided to finalize 

revisions to these definitions to specify 

that, for purposes of 40 CFR part 60, 

subpart Ja, a flare is a separate affected 

facility rather than a type of fuel gas 

combustion device. This change makes 

clearer the differences between the 

requirements for flares and the 

requirements for fuel gas combustion 

devices, particularly in terms of sulfur 

and flow rate monitoring requirements 

and thresholds for root cause analyses 

and corrective action analyses. We are 

also making corrections, as needed, in 

numerous paragraphs throughout 

subpart Ja for consistency with the 

amended definitions (e.g., adding ‘‘and 

flares,’’ where applicable, to paragraphs 

with requirements for ‘‘fuel gas 

combustion devices’’). 

We are finalizing the flare 

modification provision in 40 CFR 

60.100a(c), as described below, to 

specify certain connections to a flare 

that do not constitute a modification of 

the flare because they do not result in 

emissions increases. On December 22, 

2008, we proposed that the following 

types of connections to a flare would 

not be considered a modification of the 

flare: (1) Connections made to install 

monitoring systems to the flares; (2) 

connections made to install a flare gas 

recovery system; (3) connections made 

to replace or upgrade existing pressure 

relief or safety valves, provided the new 

pressure relief or safety valve has a set 

point opening pressure no lower and an 

internal diameter no greater than the 

existing equipment being replaced or 

upgraded; and (4) replacing piping or 

moving an existing connection from a 

refinery process unit to a new location 

in the same flare, provided the new pipe 

diameter is less than or equal to the 

diameter of the pipe/connection being 

replaced/moved. We are finalizing those 

proposed amendments and also adding 

the following types of connections to 

the list of connections to flares that are 

not modifications of flares: (1) 

Connections between flares; (2) 

connections for flare gas sulfur removal; 

and (3) connections made to install 

redundant flare equipment (such as a 

back-up compressor). We are also 

clarifying one of the proposed 

exemptions to indicate that connections 

made to upgrade or enhance 

components of flare gas recovery 

systems (e.g., additional compressors or 

recycle lines) are not modifications. 

We are not finalizing the proposed 

amendment to provide additional time 

for flares that need to install additional 

amine scrubbing and amine stripping 

columns to meet the requirement to 

limit the long-term concentration of H2S 

to 60 ppmv (determined daily on a 365 

successive calendar day rolling average 

basis) (hereafter referred to as the longterm 60 ppmv H2S fuel gas 

concentration limit). Instead, based on 

comments received during the public 

comment period for the proposed 

amendments and our own additional 

analyses, we are removing the 

requirement for flares to meet the longterm 60 ppmv H2S fuel gas 

concentration limit. As explained in 

section IV, we determined that requiring 

refineries to ensure the fuel gas they 

send to their flares meets a long-term 

H2S concentration of 60 ppmv is not 

appropriate for flares. 

We are promulgating final 

amendments for flares that include a 

suite of standards that apply at all times 

that are aimed at reducing SO2

emissions from flares. These 

amendments include several provisions 

that were proposed on December 22, 

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3Background Information for New Source 

Performance Standards, Vol. 3, Promulgated 

Standards (APTD–1352c; Publication No. EPA 450/ 

2–74–003), pg 127 (February 1974) (NSPS BID Vol. 

3). 

2008, as well as others that differ from 

those proposed, but are a logical 

outgrowth of the proposed amendments. 

This suite of standards requires 

refineries to: (1) Develop and implement 

a flare management plan; (2) conduct 

root cause analyses and take corrective 

action when waste gas sent to the flare 

exceeds a flow rate of 500,000 standard 

cubic feet (scf) above the baseline flow 

to a flare in any 24-hour period (rather 

than the proposed threshold of 500,000 

scf in any 24-hour period without 

considering the baseline); (3) conduct 

root cause analyses and take corrective 

action when the emissions from the 

flare exceed 500 lb of SO2 in a 24-hour 

period (instead of 500 lb SO2 above the 

emissions limit); and (4) optimize 

management of the fuel gas by limiting 

the short-term concentration of H2S to 

162 ppmv during normal operating 

conditions (determined hourly on a 3- 

hour rolling average basis). As 

explained further in preamble section 

IV.B, 40 CFR part 60, subpart J sets a 

performance standard for SO2

(expressed as a 162 ppmv short-term 

H2S concentration limit) in fuel gas 

entering fuel gas combustion devices. 

However, for this final rule, we have 

determined that flares should be treated 

separately from other fuel gas 

combustion devices because they meet 

the criteria set forth in CAA section 

111(h)(2)(A) since emissions from a flare 

do not occur ‘‘through a conveyance 

designed and constructed to emit or 

capture such pollutant.’’ The flare itself 

is not a ‘‘conveyance’’ that is ’’emitting’’ 

or ‘‘capturing’’ these pollutants. Instead, 

pollutants such as SO2 are created in the 

flame that burns outside the flare tip. 

Therefore, we have determined that this 

suite of work practice standards, which 

includes optimization of fuel gas 

management (based on limiting 

concentration of H2S to 160 ppmv) is 

more appropriate for flares, as opposed 

to the H2S performance standard in 

subpart J, applicable to fuel gas systems. 

See section IV.B of this preamble for a 

more detailed explanation of these 

requirements. In this rule, we are using 

the term ‘‘normal operating conditions’’ 

to describe situations where the process 

is operating in a routine, predictable 

manner, such that the gases from the 

process are predictable, as opposed to 

less-predictable swings related to 

emergency situations during which the 

flare begins to operate as a safety device. 

All of these requirements will apply 

during the vast majority of the time. 

Under a very narrow and limited set of 

circumstances, such as when a flare is 

used as a safety device under emergency 

conditions,3 the flare will be subject to 

all of these requirements except for the 

requirement to optimize management of 

the fuel gas. 

In addition, we are specifying that, if 

a discharge exceeding either or both of 

the SO2 or flow thresholds described 

above is the result of a planned startup 

or shutdown of a refinery process unit 

or ancillary equipment connected to the 

flare, and the flare management plan 

procedures for minimizing flow (which 

minimizes emissions) during that type 

of event are followed, a root cause 

analysis and corrective action analysis 

are not required. Finally, we are 

finalizing the proposed added 

provisions to ensure that owners and 

operators implement corrective actions 

on the findings of the SO2 or flow rate 

root cause analyses and to specify a 

deadline for performing the corrective 

actions. 

We are finalizing the proposed 

amendment to remove the 250,000 scfd 

30-day average flow rate limit. Our 

rationale for this decision is explained 

in the preamble to the proposed 

amendments (73 FR 78530) and also in 

section IV of this preamble. 

We are finalizing one proposed 

amendment to the flare management 

plan and adding several new 

requirements as a logical outgrowth of 

the proposed amendments, considering 

the public comments we received, to 

ensure compliance with the flare 

standards. First, as proposed, we are 

requiring a list of refinery process units 

and fuel gas systems connected to each 

affected flare. However, we are also 

adding a requirement for a simple 

process flow diagram showing the 

design of the flare, connections to the 

flare header and subheader system(s), 

and all gas lines associated with the 

flare. With these two requirements, we 

are clarifying that the flare management 

plan must include a diagram of the flare 

and connections, but the diagram need 

not be a detailed piping and 

instrumentation diagram that shows all 

process units and ancillary equipment 

connected to the flare. We are also 

requiring the owner and operator of an 

affected flare to assess and minimize 

flow to affected flares from these 

process units and fuel gas systems. 

Second, we are adding new 

requirements that the flare management 

plan include design and operation 

details about the affected flare, 

including tip diameter, type of flare, 

monitoring methods and a description 

of the flare gas recovery system, if 

present. The inclusion of these details 

will ensure that the rest of the flare 

management plan is reasonable and 

appropriate for that affected flare. 

Third, as a logical outgrowth of the 

proposed amendments, considering the 

public comments we received, we are 

adding a new requirement for owners 

and operators to determine the baseline 

flow to each flare, including purge and 

sweep gas, and include this baseline 

flow in the flare management plan. As 

described later in this preamble, 

developing the baseline is important 

because the final threshold for the flare 

flow root cause analysis takes this 

baseline flow into consideration. 

Finally, we are adding a new 

requirement to minimize the volume of 

gas flared during maintenance of a flare 

gas recovery system. 

We have decided to remove the 

requirement for the owner or operator to 

explain in the flare management plan 

how a root cause analysis and corrective 

action analysis will be conducted if the 

flow to the flare exceeds the specified 

threshold. Instead, all the requirements 

for determining when and how to 

conduct a root cause analysis and 

corrective action analysis, and the 

requirements for when and how to 

implement a corrective action, have 

been expanded, as described later in 

this section, and moved to 40 CFR 

60.103a(c) through (e). 

We are specifying that, for modified 

flares, the flare management plan must 

be developed and implemented by no 

later than November 11, 2015 or upon 

startup of the modified flare, whichever 

is later (the proposed amendments 

provided 18 months with an additional 

6 months if the owner or operator 

committed to installing a flare gas 

recovery system). In addition, because 

of the lack of a direct flow limit and the 

addition of the baseline flow value, we 

are adding a requirement that the flare 

management plan must be submitted to 

the Administrator. 

As with the flare management plan, 

the owner or operator of an affected 

flare must comply with the root cause 

analysis and corrective action analysis 

requirements within 3 years from the 

effective date of this final rule or upon 

startup of the modified flare, whichever 

is later. 

We are finalizing several proposed 

amendments to the sulfur monitoring 

requirements and revising other 

requirements as a logical outgrowth of 

the proposed amendments, considering 

the public comments we received. We 

consolidated the proposed alternatives 

to monitor reduced sulfur compounds 

and total sulfur compounds into a 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56431 

provision that allows the use of total 

reduced sulfur monitoring. We also 

clarified the span requirements for these 

monitors and are allowing the use of 

cylinder gas audits for relative accuracy 

assessments. We are finalizing the H2S 

monitoring alternative method for 

determining total sulfur content in the 

flare gas, as proposed, but we have 

clarified the span requirements for this 

monitor and are allowing the use of 

cylinder gas audits for relative accuracy 

assessments, similar to the total reduced 

sulfur monitor requirements. For 

refineries that measure SO2

concentrations in the exhaust from a 

fuel gas combustion device that 

combusts gas representative of the gas 

discharged to the flare, we added an 

alternative to allow the owner or 

operator to use the existing SO2 CEMS 

data to calculate the total sulfur content 

in the flare gas. 

We received public comments stating 

that the flow and sulfur monitoring 

requirements for flares were too 

burdensome for flares that are used 

infrequently or that are configured such 

that they cannot receive high sulfur flare 

gas. Based on our evaluation of these 

comments, we are providing new 

alternatives to continuous flow and 

sulfur monitoring for certain flares. 

First, for flares that are configured such 

that they only receive inherently low 

sulfur gas streams described in 40 CFR 

60.107a(a)(3)(i) through (iv) or (b), 

continuous sulfur monitors are not 

necessary because a root cause analysis 

will be triggered by an exceedance of 

the flow rate threshold long before they 

exceed the 500 lb SO2 trigger in a 24- 

hour period. 

Second, we are providing an 

alternative monitoring option for 

emergency flares, secondary flares and 

flares equipped with a flare gas recovery 

system designed, sized and operated to 

capture all flows (except flows resulting 

from planned startup and shutdown that 

are addressed in the flare management 

plan). If this option is applicable, the 

owner or operator may elect to 

continuously monitor the water seal 

height and the pressure in the flare 

header just upstream of the water seal 

rather than install total sulfur and flow 

monitoring systems. If this monitoring 

option is selected, any instance where 

the pressure upstream of the water seal 

(expressed in inches of water) exceeds 

the water seal height triggers a 

requirement to perform a root cause 

analysis and corrective action analysis, 

unless the discharge is related to flare 

gas recovery system compressor cycling 

or a planned startup or shutdown (of a 

refinery process unit or ancillary 

equipment connected to the flare) 

following the procedures in the flare 

management plan. An ‘‘emergency 

flare’’ is a flare that combusts gas 

exclusively released as a result of 

malfunctions (and not startup, 

shutdown, routine operations or any 

other cause) and is characterized as 

having four or fewer discharge events in 

any 365 consecutive calendar days. 

Owners or operators of affected flares 

that have flare gas recovery systems 

with staged compressors that elect to 

use this monitoring option must identify 

these flares in their flare management 

plan, identify the time period required 

for the staged compressors to actively 

start to recover gas and identify the 

operating parameters monitored and 

procedures employed to minimize the 

duration of flaring during compressor 

staging. If a pressure exceedance is 

caused during compressor staging and 

the duration of the pressure exceedance 

is less than the time specified in the 

flare management plan, then a root 

cause analysis is not required and the 

pressure exceedance is not required to 

be reported. If a pressure exceedance is 

not attributable to compressor staging 

(i.e., all staged compressors are active), 

if a pressure exceedance is the result of 

a planned startup and shutdown event 

during which the flare management 

plan is not followed or if the duration 

of a pressure exceedance attributable to 

compressor staging is greater than the 

time specified in the flare management 

plan, then a root cause analysis and 

corrective action analysis are required 

and the pressure exceedance must be 

reported. More than four pressure 

exceedances required to be reported, as 

described above and under 40 CFR 

60.108a(d)(5) (hereafter referred to as 

‘‘reportable pressure exceedances’’) in 

any 365 consecutive calendar days is an 

indication that the flare gas recovery 

system is not adequately sized, and the 

sulfur and flow monitors, as required in 

40 CFR 60.107a(e) and (f), must be 

installed if that occurs. 

Third, we are clarifying that monitors 

for flow and sulfur on the second flare 

in a staged flare configuration are not 

required where the water seal 

monitoring requirements adequately 

and appropriately address this scenario. 

Under most circumstances, the root 

cause analysis is expected to be 

triggered, based on the flow to or 

emissions from the primary flare. 

However, in cases where the capacity of 

the primary flare is small (less than 

500,000 scfd), this may not always be 

the case. Additionally, we consider the 

water seal monitoring on the secondary 

flare to be appropriate to ensure that 

gases are not released to the secondary 

flare inadvertently. We clarify in this 

final rule that if a root cause analysis is 

triggered for the primary flare, releases 

to the secondary flare do not trigger an 

additional root cause analysis (i.e., the 

releases may be treated as one event). 

However, if flow is diverted to the 

secondary flare, then a root cause 

analysis is required, even if a root cause 

analysis was not triggered for the 

primary flare, based on flow rate or SO2

emissions. In addition, if flow is 

diverted to the secondary flare five or 

more times in a 365-day period, flow 

monitoring of the secondary flare is 

required. We anticipate that the 

upstream sulfur monitor on the primary 

flare can be used to determine the sulfur 

content of the gas diverted to the 

secondary flare. 

In response to comments, we are also 

finalizing a new amendment providing 

an alternative compliance option in 40 

CFR 60.103a(g) and 40 CFR 60.107a(h) 

for certain flares. Specifically, for 

refineries located in the SCAQMD, an 

affected flare subject to 40 CFR part 60, 

subpart Ja may elect to comply with 

SCAQMD Rule 1118 as an alternative to 

complying with the requirements for 

flares in 40 CFR 60.103a(a) through (e) 

and the associated monitoring 

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

Similarly, for refineries located in the 

BAAQMD, an affected flare subject to 

subpart Ja may elect to comply with 

both BAAQMD Regulation 12, Rule 11 

and BAAQMD Regulation 12, Rule 12 as 

an alternative to complying with the 

requirements for flares in 40 CFR 

60.103a(a) through (e) and the 

associated monitoring provisions in 40 

CFR 60.107a(e) and (f). We are also 

finalizing specific provisions within the 

standards for owners or operators (and 

manufacturers of equipment) to submit 

a request for a determination of 

equivalence for ‘‘an alternative means of 

emission limitation’’ that will achieve a 

reduction in emissions at least 

equivalent to the reduction in emissions 

achieved under any of the final subpart 

Ja design, equipment, work practice or 

operational requirements in accordance 

with CAA section 111(h). 

For fuel gas combustion devices and 

sulfur recovery plants, we are correcting 

and clarifying the threshold for a root 

cause analysis and corrective action 

analysis. The proposed root cause 

analysis threshold for both types of 

process units was 500 lb SO2 above the 

emission limit, but the proposed 

amendments directed the owner or 

operator to compare the SO2 emissions 

to ‘‘the period of the exceedance’’ for 

fuel gas combustion devices and ‘‘the 

entire 24-hour period’’ for sulfur 

recovery plants. That language meant 

that if one 12-hour average for a sulfur 

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4As noted above, the proposed amendments used 

the term ‘‘period of the exceedance’’ for fuel gas 

combustion devices. That term was intended to 

have the same meaning as a period of excess 

emissions (or multiple consecutive periods of 

excess emissions), as defined in 40 CFR 60.106a(b) 

or 40 CFR 60.107a(i)). Therefore, the final 

amendments refer to ‘‘one or more consecutive 

periods of excess emissions’’ rather than ‘‘period of 

the exceedance.’’ 

recovery plant was above the emission 

limit, the owner or operator would have 

compared those emissions to the 

emissions allowed over an entire 24 

hours to determine if root cause analysis 

was required. However, although a 12- 

hour average above the emission limit 

clearly means that more SO2 was 

emitted than allowed by that emissions 

limit, it is possible that, since the time 

periods being compared were not 

analogous, the ‘‘allowed emissions’’ 

over 24 hours could be more than the 

actual emissions that made up the one 

12-hour average. Upon further 

consideration, we see no reason for the 

requirements to be different for fuel gas 

combustion devices and sulfur recovery 

plants. Therefore, we are finalizing an 

amendment that states that the 

threshold for a root cause analysis and 

corrective action analysis for both sulfur 

recovery plants and fuel gas combustion 

devices is 500 lb above the emission 

limit during one or more consecutive 

periods of excess emissions 4 or any 24- 

hour period, whichever is shorter. This 

clarifying amendment is needed to 

ensure that the magnitude of the 

emissions limit exceedance is properly 

compared to what would have been 

emitted if the emissions were equivalent 

to the emissions limit based on the 

averaging time allowed for that 

emissions limit. 

Finally, we are finalizing the 

amendments at 40 CFR 60.108a(c) and 

(d) mostly as proposed to clarify 

recordkeeping and reporting when a 

root cause analysis and corrective action 

analysis are required. These 

clarifications were needed to more 

clearly delineate the differences in the 

recordkeeping and reporting 

requirements for flares, fuel gas 

combustion devices and sulfur recovery 

plants. The differences between the 

proposed amendments and the final 

amendments are corrections to be 

consistent with changes to the root 

cause analysis and corrective action 

analysis requirements already 

described. We are also finalizing 40 CFR 

60.108a(c), as proposed, to add 

recordkeeping requirements for the 

proposed monitoring option that is 

based on periodic manual sampling and 

analysis to determine the total sulfur-toH2S ratio. 

D. What are the final amendments to the 

definitions in 40 CFR part 60, subpart 

Ja? 

We proposed amendments to a 

number of definitions in 40 CFR 

60.101a. This section describes whether 

we are finalizing the amendments as 

proposed, finalizing an amendment 

different than (but as a logical 

outgrowth of) what was proposed or not 

finalizing the proposed amendment. 

We are finalizing amendments to the 

definitions of ‘‘flexicoking unit’’ and 

‘‘fluid coking unit,’’ as proposed. 

We are finalizing a definition of 

‘‘delayed coking unit’’ that is different 

than the proposed amendments to 

clarify what pieces are included in a 

delayed coking unit. The final June 2008 

rule did not explicitly describe the 

pieces of a delayed coking unit. We 

proposed to amend the definition in 

December 2008 to specify that a delayed 

coking unit ‘‘consists of the coke drums 

and associated fractionator.’’ In the 

course of evaluating public comments 

on the proposed definition, we looked 

more closely at the operation of delayed 

coking units and determined that the 

fractionators, quench water system and 

coke cutting equipment are integral to 

the operation of a delayed coking unit. 

Therefore, we are revising the definition 

of ‘‘delayed coking unit’’ in these final 

amendments to include ‘‘the coke 

drums associated with a single 

fractionator and the associated 

fractionator; the coke drum cutting 

water and quench system, including the 

jet pump and coker quench water tank; 

process piping and associated 

equipment such as pumps, valves and 

connectors; and the coke drum 

blowdown recovery compressor 

system.’’ Finally, to avoid any potential 

retroactive compliance issues that could 

arise for certain delayed coking units 

because of the changes to the definition 

of ‘‘delayed coking unit’’ between the 

proposal and the final rule, we are 

moving the date for determining 

applicability of NSPS subpart Ja for 

those newly constructed, reconstructed 

and modified delayed coking units 

specifically affected by this change from 

the date of the proposal to the 

promulgation date of these final 

amendments. See CAA section 

111(a)(2). 

We are finalizing definitions of 

‘‘forced draft process heater,’’ ‘‘natural 

draft process heater’’ and ‘‘co-fired 

process heater,’’ which will enable 

owners and operators to determine the 

appropriate subcategory for each of their 

process heaters. Based on public 

comments, the final amendments have 

been revised slightly from the proposed 

definitions to clarify that induced draft 

systems are defined as natural draft 

process heaters and balanced draft 

systems are defined as forced draft 

process heaters. We are also revising the 

definition of ‘‘co-fired process heater’’ to 

clarify that this type of process heater 

does not include gas burners that have 

emergency oil back-up burners. We are 

finalizing the definition of ‘‘air 

preheat,’’ as proposed, except that we 

are substituting the term ‘‘sensible’’ for 

‘‘latent’’ to describe the heat recovered 

from exhaust gases. 

We are finalizing the definitions of 

‘‘flare gas recovery system’’ and 

‘‘process upset gas,’’ as proposed, and 

we are adding a new definition of ‘‘flare 

gas header system.’’ We are finalizing a 

revision to the definition of ‘‘flare’’ to 

refer to the ‘‘flare gas header system’’ 

rather than repeat the components of the 

flare gas header system within the 

definition of flare. In addition, we are 

clarifying in the definition of ‘‘flare’’ 

that, in the case of an interconnected 

flare gas header system (i.e., two or more 

flare tips share the same flare gas header 

system or are otherwise connected such 

that they receive flare gas from the same 

source), the ‘‘flare’’ includes each 

combustion device serviced by the 

interconnected flare gas header system 

and the interconnected flare gas header 

system. 

We are finalizing definitions of 

‘‘corrective action,’’ ‘‘corrective action 

analysis’’ and ‘‘root cause analysis’’ 

with minor changes from proposal to 

update section references and to expand 

upon the types of factors that should be 

taken into consideration for root cause 

and corrective action analyses. We are 

adding definitions of ‘‘purge gas’’ and 

‘‘sweep gas’’ to clarify the requirements 

of the flare minimization plan. We are 

also adding new definitions of 

‘‘emergency flare,’’ ‘‘cascaded flare 

system,’’ ‘‘non-emergency flare,’’ 

‘‘primary flare’’ and ‘‘secondary flare’’ to 

clarify the types of flares that are and 

are not allowed to use the water seal 

monitoring alternative for flares. 

We are finalizing the amendments to 

the definition of ‘‘petroleum refinery,’’ 

as proposed. As we noted in the 

preamble to the proposed amendments, 

facilities that only produce oil shale or 

tar sands-derived crude oil for further 

processing using only solvent extraction 

and/or distillation to recover diluent 

that is then sent to a petroleum refinery 

are not themselves petroleum refineries. 

Facilities that produce oil shale or tar 

sands-derived crude oil and then 

upgrade these materials and produce 

refined products would be petroleum 

refineries. Additionally, facilities that 

produce oil shale or tar sands-derived 

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crude oil using any cracking process 

would be considered petroleum 

refineries. 

We are not finalizing the proposed 

amendments to ‘‘refinery process unit’’ 

to avoid possible conflicts and 

confusion caused by having different 

definitions for ‘‘refinery process unit’’ in 

40 CFR part 60, subparts J and Ja, but 

we are adding a new definition of 

‘‘ancillary equipment’’ and using this 

term to clarify that the flare 

modification provisions and standards 

apply to the types of units listed in the 

proposed definition of ‘‘refinery process 

unit.’’ Specifically, we are defining 

ancillary equipment as equipment used 

in conjunction with or that serve a 

refinery process unit. Ancillary 

equipment includes, but is not limited 

to, storage tanks, product loading 

operations, wastewater treatment 

systems, steam- or electricity-producing 

units (including coke gasification units), 

pressure relief valves, pumps, sampling 

vents and continuous analyzer vents. 

We are amending the definition of 

‘‘fuel gas,’’ as proposed, to clarify that 

process units that gasify petroleum coke 

at a petroleum refinery are producing 

refinery fuel gases. We also proposed to 

amend the definition to state that gas 

generated by process units that calcine 

petroleum coke into anode grade coke is 

not fuel gas. Based on public comment, 

we are amending the definition to state 

that gas generated by coke calciners 

producing all premium grade coke 

(rather than just anode grade coke, as 

proposed) is not fuel gas. Also upon 

consideration of public comments, we 

are amending the definition of ‘‘fuel 

gas’’ to clarify which vapor streams we 

intended to exclude. The proposed 

definition indicated that vapors 

collected and combusted to comply 

with specific standards were not 

considered fuel gas. The final amended 

definition clarifies that vapors that are 

collected and combusted in a thermal 

oxidizer or flare installed to control 

emissions from wastewater treatment 

units other than those processing sour 

water, marine tank vessel loading 

operations and asphalt processing units 

are not considered fuel gas, regardless of 

whether the action is required by 

another standard. 

Finally, we are finalizing several 

proposed amendments to the definition 

of ‘‘sulfur recovery plant’’ to clarify the 

intent of the definition. We are 

correcting the spelling of ‘‘H2S.’’ We are 

also clarifying that multiple units 

recovering sulfur from a common source 

of sour gas produced at a refinery are 

considered one sulfur recovery plant. In 

addition, we are clarifying that loading 

facilities downstream of the sulfur pits 

are not part of the sulfur recovery plant 

(the proposed definition only specified 

secondary sulfur storage vessels). 

E. What are the final technical 

corrections to 40 CFR part 60, subpart 

Ja? 

See Table 4 of this preamble for 

miscellaneous technical corrections that 

we are finalizing throughout 40 CFR 

part 60, subpart Ja. As mentioned 

previously, some of these technical 

corrections are in response to 

straightforward issues raised by 

Industry Petitioners in their August 21, 

2008, supplement to their original 

petition for reconsideration (Docket 

Item No. EPA–HQ–OAR–2007–0011– 

0246). Other technical corrections are 

needed to correct typographical errors 

and to correct equation and paragraph 

designations. 

TABLE 4—TECHNICAL CORRECTIONS TO 40 CFR PART 60, SUBPART JA

Section Technical correction and reason 

60.102a(f)(1)(ii) ............................ Replace ‘‘300 ppm by volume of reduced sulfur compounds and 10 ppm by volume of hydrogen sulfide 

(HS2), each calculated as ppm SO2 by volume (dry basis) at zero percent excess air’’ with ‘‘300 ppmv of 

reduced sulfur compounds and 10 ppmv of H2S, each calculated as ppmv SO2 (dry basis) at 0-percent excess air’’ for consistency of units and to correct a typographical error. 

60.104a(d)(4)(ii) ........................... Redesignate Equation 3 as Equation 5 to provide for the addition of new Equations 3 and 4. 

60.104a(d)(4)(iii) .......................... Redesignate Equation 4 as Equation 6 to provide for the addition of new Equations 3 and 4. 

60.104a(d)(4)(v) ........................... Redesignate Equation 5 as Equation 7 to provide for the addition of new Equations 3 and 4. 

60.104a(d)(8) ............................... Redesignate Equation 6 as Equation 8 to provide for the addition of new Equations 3 and 4. 

60.104a(f)(3) ................................ Redesignate Equation 7 as Equation 9 to provide for the addition of new Equations 3 and 4. 

Replace ‘‘hourly’’ with ‘‘3-hour’’ in the definition of the new Equation 9 variable ‘‘Opacity limit’’ and replace 

‘‘source test runs’’ with ‘‘source test’’ in the definition of the new Equation 9 variable ‘‘Opacityst’’ to clarify 

the information required for new Equation 9. 

60.104a(h)(5)(iv) .......................... Redesignate the reference to Equation 6 as a reference to Equation 8 to provide for the addition of new 

Equations 3 and 4. 

60.105a(b) ................................... Replace ‘‘in § 60.102a(b)(1) shall comply with the requirements in paragraphs (b)(1) through (3) of this section’’ with ‘‘in § 60.102a(b)(1) that uses a control device other than fabric filter or cyclone shall comply with 

the requirements in paragraphs (b)(1) and (2) of this section’’ to clarify applicability of the requirements and 

remove the reference to a nonexistent paragraph. 

60.105a(b)(1) ............................... Replace ‘‘according to the requirements in paragraph (b)(1)(i) through (iii) of this section’’ with ‘‘according to 

the applicable requirements in paragraphs (b)(1)(i) through (v) of this section’’ to clarify and correct paragraph reference. 

60.105a(b)(1)(ii)(A) ...................... Replace ‘‘alterative’’ with ‘‘alternative’’ to correct the use of an incorrect word. 

60.105a(i)(5) ................................ Replace ‘‘Except as provided in paragraph (i)(7) of this section, all rolling 7-day periods’’ with ‘‘All rolling 7- 

day periods’’ to remove the reference to a nonexistent paragraph. 

60.107a(a)(2)(i) ............................ Replace ‘‘320 ppmv H2S’’ with ‘‘300 ppmv H2S’’ to make the span value for a H2S monitor consistent with the 

span value in 40 CFR part 60, subpart J. 

60.108a(d)(5) ............................... Replace ‘‘the information described in paragraph (e)(6) of this section’’ with ‘‘the information described in 

paragraph (c)(6) of this section’’ to correct the reference to a nonexistent paragraph. 

IV. Summary of Significant Comments 

and Responses 

As previously noted, we received a 

total of 22 comments addressing the 

proposed amendments. These 

comments were received from 

refineries, industry trade associations, 

consultants, state and local 

environmental and public health 

agencies, environmental groups and 

members of the public. Brief summaries 

of the major comments and our 

complete responses to those comments 

are included in the following sections. 

A summary of the remainder of the 

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56434 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

comments received during the comment 

period and responses thereto, as well as 

more detailed summaries of the 

comments addressed in this preamble, 

can be found in Standards of 

Performance for Petroleum Refineries: 

Background Information for Final 

Amendments—Summary of Public 

Comments and Responses, which is 

included in the docket for the final 

amendments (Docket ID No. EPA–OAR– 

HQ–2007–0011). The docket also 

contains further details on all the 

analyses summarized in the responses 

below. 

In responding to the public 

comments, we re-evaluated the cost and 

emission reduction impact estimates of 

some of the control options and reevaluated the related BSER 

determinations. In our BSER 

determinations, we took all relevant 

factors into account consistent with 

other agency decisions. 

A. Process Heaters 

Comment: Commenters stated that 

new forced draft process heaters cannot 

meet the proposed emissions limit of 40 

ppmv NOX, so the EPA should revise 

the emissions limits for new forced draft 

process heaters to be the same as the 

limit for modified and reconstructed 

forced draft process heaters (60 ppmv 

NOX). One commenter referenced a 

general technical document written by a 

process heater burner manufacturer 

regarding a new forced draft process 

heater at their refinery to support the 

assertion that new process heaters 

cannot meet the proposed limit without 

selective catalytic reduction or other 

add-on controls. Another commenter 

also requested higher emissions limits 

for new forced draft process heaters 

with air preheat. 

Response: The commenters provided 

only limited and theoretical data to 

support their argument that new forced 

draft process heaters cannot meet the 40 

ppmv (or 0.040 lb/MMBtu) NOX

emissions limit. Specifically, the John 

Zink white paper cited by the 

commenter (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 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.) 

Comment: Commenters asserted that 

the heating value-based emissions limits 

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

should be numerically equivalent to the 

concentration-based emissions limits 

(e.g., 40 ppmv should be equivalent to 

0.040 lb/MMBtu rather than 0.035 lb/ 

MMBtu). 

Response: In August 2008, Industry 

Petitioners provided 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 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 concentrationbased or heating value-based NOX limit. 

The heating value-based NOX emission 

rate is calculated using the oxygen (O2)- 

based F factor, which is the ratio of 

combustion gas volume to heat input. 

Ongoing compliance with this NOX

emissions limit is determined using a 

NOX CEMS and at least daily sampling 

of fuel gas heat content or composition 

to calculate a daily average heating 

value-based emissions rate, which is 

subsequently used to determine the 30- 

day average. 

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 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56435 

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. Generally, fuel gas heating 

value is important to the overall 

operation of refinery boilers and process 

heaters; as such, refiners maintain their 

fuel gas within an operating range that 

they need to fire these sources, often by 

mixing with natural gas, etc., so we 

anticipate that most, if not all, refiners 

will already have this information 

available on a daily basis. 

Comment: Several commenters 

addressed the need for the rule to 

address turndown, which is a period of 

time when process heaters are firing 

below capacity. Commenters stated that 

during these periods, the NOX

concentrations will likely be above the 

emissions limits, but the mass of NOX

emissions is no greater than when the 

heater is operating at full capacity 

because the lower firing rate results in 

a lower exhaust flow rate. Commenters 

noted that turndown conditions could 

exist for extended periods, so special 

provisions are needed for these 

conditions. Commenters requested a 

mass-based emission rate (lb/MMBtu 

limit multiplied by the heater’s rated 

capacity) that would apply when the 

process heater is firing at less than full 

capacity (some commenters suggested 

50 percent of capacity; one commenter 

suggested 70-percent capacity as a 

cutoff). One commenter also noted that 

process heaters must often operate at 

higher O2 levels during turndown and 

requested that the proposed maximum 

O2 operating limit not apply when small 

furnaces that are not required to install 

CEMS are firing at less than full 

capacity. 

Response: In our proposed 

amendments, we provided a longer 

averaging time (365-day average) so that 

short periods of 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, 

short-term fluctuations in the NOX

concentrations of process heaters using 

ultra-low NOX burners caused them to 

exceed a 24-hour average limit 

somewhat frequently, but a 30-day 

average provided adequate time to 

average out the short-term fluctuations. 

We note that a few of the process 

heaters operated at relatively high 

excess O2 concentrations at normal 

conditions (i.e., at exhaust O2

concentrations of 6 percent or more). 

These units had periods of excess 

emissions above the 30-day average 

emission limits, but we rejected the 

performance of these process heaters as 

BSER because of the high exhaust O2

concentrations for these units during 

normal (i.e., non-turndown) firing rates. 

That is, these process heaters were not 

being operated optimally for reducing 

NOX emissions. Furthermore, when 

these process heaters were operated at 

the lower range of exhaust 

concentrations for the unit (although 

generally higher than what would be 

considered optimal excess O2

concentrations for reducing NOX

emissions), the process heater could 

meet the applicable 40 or 60 ppmv 

emissions limit on a 30-day averaging 

period. Based on our review of CEMS 

data for process heaters with ultra-low 

NOX burners that operated at excess O2

concentrations less than 6 percent (i.e., 

operated in a manner consistent with 

proper low NOX burner operation), all 

such process heaters could comply with 

the final NOX emissions limits on a 30- 

day average basis. Consequently, we 

revised the basic emissions limits to be 

on a 30-day average. 

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 mass-based 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 

concentration-based emissions limit 

(40/60 ppmv) or the heating value-based 

(0.040/0.060 lb/MMBtu) emissions limit 

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56436 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

5The commenter providing this data asserted that 

it is 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. 

during turndown. Therefore, the issue 

appears to be limited to a few of the 

process heaters that must operate at 

relatively high excess O2 concentrations 

during turndown conditions. For these 

units, the alternative mass-based 

emissions limit that we were 

considering rarely, if ever, provided a 

means for these units to comply with 

the performance standard. 

We understand that technology 

providers recommend operating process 

heaters that are turned down at higher 

excess O2 concentrations to improve 

flame stability and ensure safe operation 

of the process heater; however, based on 

the information provided by the 

technology providers, there is still an 

optimal excess O2 concentration at 

which flame stability is achieved while 

minimizing NOX formation. That is, 

even when a process heater is operating 

at less than 50-percent design capacity, 

excess O2 concentrations should still be 

controlled to minimize NOX formation 

within the safe operating constraints to 

maintain flame stability. We do not have 

specific data on process heaters that are 

near, but below, the concentration 

emissions limits when firing above 50- 

percent capacity, but 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 valuebased 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 MMBtu/hr capacity that do not 

install a NOX CEMS, turndown is also 

expected to be an issue with respect to 

achieving the O2 operating limit. As 

described above, higher O2

concentrations are generally needed to 

maintain flame stability at low firing 

rates. To address potential turndown 

compliance issues with the O2 operating 

limit, we have provided an allowance 

for process heater owners or operators to 

develop an O2 operating curve to 

provide different O2 operating limits 

based on the firing rate of the process 

heater. If a single O2 operating limit is 

established, it must be determined when 

the process heater is being fired at 70 

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

from turndown conditions). For process 

heaters that routinely operate at less 

than 50 percent of design capacity and 

require additional O2 to maintain flame 

stability, a separate O2 operating limit 

should be established for turndown by 

conducting a second performance test 

while the unit is operating at less than 

50 percent of capacity. Additional 

performance tests can be conducted to 

develop O2 operating limits for 

additional operating ranges. 

Comment: Several commenters 

requested that the EPA revise the 

emissions limits for co-fired process 

heaters or remove the limits for co-fired 

process heaters from this rulemaking 

and address them at a later date due to 

lack of sufficient data to set an 

achievable emissions limit. One 

commenter provided a white paper to 

support higher emissions limits. 

Commenters also asserted that the 

averaging time for the weighted average 

emission rate should be extended to 365 

days. One commenter noted that the 

notation ‘‘ENOx,hour’’ in Equation 3 was 

confusing since the purpose of the 

equation was to determine the daily 

emission rate. 

Response: The final June 2008 rule 

included only one emissions limit for 

all co-fired process heaters, and 

Industry Petitioners asserted that 

differences in the configuration and 

operation of different types of process 

heaters warranted different emissions 

limits. The proposed amendments 

introduced two specific emissions limits 

for co-fired process heaters, one based 

on vendor guarantees for the burners 

and one based on an average NOX

concentration for a combination of fuel 

gas and fuel oil. We note that, for 

purposes of this rule, a co-fired process 

heater is defined as a process heater that 

employs burners that are designed to be 

supplied by both gaseous and liquid 

fuels. In other words, co-fired process 

heaters are designed to routinely fire 

both oil and gas in the same burner. 

These do not include burners that are 

designed to burn gas, but have 

supplemental oil firing capability that is 

not routinely used (i.e., emergency oil 

back-up). 

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 commenter 5 (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 gasfired process heaters). We have also 

revised the nomenclature of the daily 

average emissions limit in Equations 3 

and 4 (proposed Equation 3) to be clear 

that we intend the limit to be 

determined on a daily basis rather than 

on an hourly basis. 

We also note that the burner 

performance tests were conducted in a 

controlled environment at the burner 

manufacturer’s full-scale facilities. 

While it is incumbent on the owner or 

operator of an affected process heater to 

control certain operating parameters, 

such as excess O2 concentrations, to the 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56437 

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 sitespecific emissions limit, as allowed 

above, for process heaters that operate 

for extended periods under turndown. 

B. Flares 

Comment: Several commenters 

asserted that routine connections to a 

flare should not be considered 

modifications of the flare because they 

do not change the maximum physical 

capacity of the flare and do not 

generally increase emissions. One 

commenter asserted that the 40 CFR part 

60, subpart A General Provisions in 40 

CFR 60.14 can and should apply to 

flares, so a special modification 

provision for flares in 40 CFR part 60, 

subpart Ja is unnecessary. Commenters 

noted that some connections to the flare 

have the primary purpose of reducing 

emissions, which has been excluded 

under 40 CFR 60.14(e)(5), a paragraph 

that is not limited to pollutants ‘‘to 

which the standard is applicable.’’ One 

commenter noted that a single project 

may remove some connections and add 

others such that the net emissions could 

actually be reduced. Another 

commenter asserted that an increase in 

flow should not be considered a 

modification because flow is not a 

regulated pollutant. 

Instead, commenters asserted that the 

modification provision for a flare should 

focus on physical and operational 

changes that increase emissions from 

the flare. One commenter suggested that 

the EPA should focus the flare 

modification provision on connections 

that provide a primary/routine flow 

from a process unit to the flare. Other 

commenters suggested that the flare 

modification provision should be 

focused on VOC and SO2 emissions and 

should only include connections that 

result in a net increase of those 

pollutants emitted ‘‘during normal 

operations’’ and connections that cause 

an increase in the total volume of gas 

containing VOC or sulfur compounds 

under standard conditions that could 

reach the flare. 

Response: The agency made a 

conscious decision to promulgate a 

separate provision for a flare 

modification in 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 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 

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. See 

Asarco v. EPA, 578 F.2d 319, 325 (D.C. 

Cir. 1978) (holding that emission 

increases had to be determined based on 

emissions from the affected facility). We 

also disagree that a modification 

determination should be limited to 

emissions increases of VOC or SO2. 

Flares are known to emit VOC, SO2, 

carbon monoxide (CO), PM and NOX, as 

well as other air pollutants, all of which 

are relevant when determining whether 

a flare has been modified. See CAA 

section 111(a)(4). That is, we consider 

the standards for flares to be emission 

standards for VOC, SO2, CO, PM and 

NOX. See, generally, 73 FR 35838, 

35842, 35854–35856 (June 24, 2008); 73 

FR 78522, 78533 (December 22, 2008), 

as well as Table 4 of this preamble. 

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: Many commenters 

responded to the EPA’s request for 

comment on types of connections that 

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56438 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

do not result in an increase in emissions 

from a flare. The commenters suggested 

numerous specific connections that 

should not be considered modifications, 

including: 

(1) Connections made to upgrade or 

enhance (not just to install) a flare gas 

recovery system; 

(2) Connections made for flare gas 

sulfur removal; 

(3) Connections made to install backup equipment; 

(4) Flare interconnects; 

(5) All emergency pressure relief 

valve connections from existing 

equipment; 

(6) Connections of monitoring system 

purge gases and analyzer exhausts or 

closed vent sampling systems; 

(7) Purge and clearing vapors, block 

and bleeder vents and other 

uncombusted vapors where the flare is 

the control device; 

(8) Connections made to comply with 

other federal, state or local rules where 

the flare is the control device; 

(9) Connections of ‘‘unregulated 

gases’’ such as hydrogen, nitrogen, 

ammonia, other non-hydrocarbon gases 

or natural gas or any connection that is 

not fuel gas; 

(10) New connections upstream of an 

existing flare gas recovery system, 

provided the new connections do not 

compromise or exceed the flare gas 

recovery system’s capacity; 

(11) Any new, moved or replaced 

piping or pressure relief valve 

connections that do not result in a net 

increase in emissions from the flare, 

regardless of piping or pressure relief 

valve size; 

(12) Vapors from tanks used to store 

sweet or treated products; 

(13) Temporary connections for 

purging existing equipment, as these are 

essentially ‘‘existing’’ connections; and 

(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. 

Response: We carefully reviewed the 

commenters’ suggested changes to the 

flare modification provision to 

determine whether there are additional 

connections that should not be 

considered modifications to the flare. 

We agree that the first four connections 

in the commenters’ list should not be 

considered modifications of a flare. 

Projects to upgrade or enhance 

components of a flare gas recovery 

system (e.g., addition of compressors or 

recycle lines) will improve the 

operation of the flare gas recovery 

system, and connections to these 

additional components will not result in 

increased emissions. Connections made 

for removal of sulfur from flare gas (Item 

2 above) will generally result in a slight 

decrease in volumetric flow and a large 

decrease in emissions of SO2. 

Connections made to install back-up or 

redundant equipment (Item 3 above), 

such as a back-up compressor, will 

result in fewer released emissions if 

there is a malfunction in the main 

equipment. 

The request to exclude flare 

interconnections (Item 4 above) is a 

complicated issue because 

interconnecting two 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. 

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 preamble, we are finalizing that 

amendment, as proposed. However, new 

connections, even if they are made to 

‘‘existing equipment,’’ will result in an 

increase in flow to the flare during 

periods of process upset that cause the 

pressure relief valve to open. 

Connections of monitoring system 

purge gases and analyzer exhausts or 

closed vent sampling systems (Item 6 

above) will increase the emissions from 

the flare. Similarly, connections of 

purge and clearing vapors and block and 

bleeder vents (Item 7 above), also trigger 

a modification of the flare because the 

increase of gas flow to the flare will 

increase the emissions from the flare. 

We recognize that connections to a 

flare may be made to comply with other 

federal, state or local rules where the 

flare is an emissions control device 

(Item 8 above). In fact, nearly all flares 

could be considered ‘‘control devices.’’ 

We agree that using a flare as an 

emissions control device is preferable to 

venting the process unit to the 

atmosphere. However, while using the 

flare as an emissions control device 

does decrease emissions from the 

process unit being controlled, the 

increase of gas flow to the flare will 

increase the emissions from the 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 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56439 

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 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 flare gas recovery system (Item 

10 above) will increase the likelihood of 

an event that would cause an 

exceedance of the flare gas recovery 

system’s capacity (even if the new 

connections ‘‘do not exceed the flare gas 

recovery system’s capacity’’ under 

normal conditions), and the amount of 

gases sent to the flare would 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 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 root cause 

analysis or other compliance purpose. 

For these sweet vapors, the flow rate 

root cause analysis threshold will be 

exceeded well before the SO2 root cause 

analysis threshold. 

We carefully considered temporary 

connections for purging existing 

equipment (Item 13 above), but we 

failed to see how these temporary 

connections are essentially ‘‘existing 

connections.’’ According to the 

commenters, ‘‘maintenance gases have 

been routed in some form or other to the 

flare for years, and the temporary tie-in 

to accomplish that is not a change and 

is not an increase in emissions when 

viewed from a before and after 

perspective.’’ If the connections already 

exist, then opening an existing valve to 

allow for this type of purging would not 

trigger a flare modification. If the 

connection is being relocated and the 

piping used is the same diameter as the 

pre-existing connection, then this 

scenario is adequately covered by the 

proposed exclusion for relocated 

connections. However, if a new 

connection is made specifically to purge 

an existing piece of equipment, this 

purge gas unequivocally represents 

additional gas flow sent to the flare that 

did not exist and could not exist prior 

to the connection being made. Again, 

we consider that the increase in gas flow 

to the flare will result in an increase in 

emissions of at least one pollutant from 

the flare. As such, no exemption is 

provided for new connections to 

existing equipment, regardless if these 

connections are temporary or 

permanent. We also find that these 

types of flows should be expressly 

considered in the flare management 

plan 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 caseby-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 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 flare 

gas recovery system or connections 

made to upgrade or enhance 

components of a flare gas recovery 

system (e.g., addition of compressors or 

recycle lines). 

(3) Connections made to replace or 

upgrade existing pressure relief or safety 

valves, provided the new pressure relief 

or safety valve has a set point opening 

pressure no lower and an internal 

diameter no greater than the existing 

equipment being replaced or upgraded. 

(4) Connections that interconnect two 

or more flares. 

(5) Connections made for flare gas 

sulfur removal. 

(6) Connections made to install backup (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 

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56440 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

6The 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 preamble 

is, therefore, focused on flares as distinguished from 

other types of fuel gas combustion devices that are 

required to comply at all times with the H2S 

concentration limits in 40 CFR 60.102a(g)(1). 

diameter of the pipe/connection being 

replaced/moved. 

Comment: Several commenters 

suggested that de minimis emission 

increases and net emission decreases 

resulting from new connections to a 

flare made to control and combust 

fugitive emissions such as leaks from 

compressor seals, valves or pumps, 

should not be considered modifications 

of a flare. One commenter suggested 

allowing site-specific exemptions for 

connections that do not increase 

emissions or that result in a de minimis 

emissions increase. However, another 

commenter objected to setting a de 

minimis emissions increase to 

determine whether a change to a flare is 

a modification and stated that allowing 

a de minimis approach would cause 

confusion over the applicability of 40 

CFR part 60, subpart Ja because flare 

emissions are difficult to estimate. 

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. 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 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: One commenter stated that 

exempting flares 6 from the H2S 

concentration limits during startup, 

shutdown and malfunction (SSM) 

events is illegal because the CAA 

requires continuous compliance with 

standards of performance promulgated 

under CAA section 111. See CAA 

sections 111(a)(1), 302(k). For support, 

the commenter cited Sierra Club v. EPA, 

551 F.3d 1019 (DC 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 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56441 

7The 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. 

8The 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 prevention measures 

eliminate the emission source, so that there are no 

emissions to capture and convey, or the emissions 

are so transient, and in some cases, occur so 

randomly, that the application of a measurement 

methodology to these sources is not technically and 

economically practical.’’ 72 FR 27178, 27194–27195 

(May 14, 2007). In response, the commenter stated: 

‘‘[T]he plain language of the Act recognizes that 

standards of performance leading to the ‘capture’ of 

emissions are not infeasible [citation omitted], and 

EPA has proposed to apply measurement 

methodologies to flares in spite of the transience of 

their emissions.’’ 

the CAA because the general duty to 

minimize emissions during SSM events 

is not a CAA section 112-compliant 

standard. The commenter asserted that 

the CAA also requires that a section 

111-compliant standard that reflects 

BSER7 be in effect at all times for flares. 

The commenter 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,8 so the EPA 

cannot set a work practice standard for 

flares. Thus, the commenter asserted 

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. 

Another commenter 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). The commenter 

noted that subpart J exempts a flare from 

the H2S concentration limits when 

combusting certain gases generated 

during SSM events (see 40 CFR 

60.104(a)(1), 60.101(e)) and stated that 

the record contains ‘‘ample evidence’’ to 

support maintaining that provision in 

subpart Ja. The commenter asserted that 

including these same provisions in 

subpart Ja is ‘‘an appropriate exercise of 

EPA’s authority to ‘not review’ this 

aspect of the existing standard in light 

of the efficacy of the existing standard.’’ 

See CAA section 111(b)(1)(B). 

Second, the commenter noted that the 

Sierra Club decision was largely 

grounded in the Court’s determination 

that Congress amended CAA section 112 

out of concern ‘‘about the slow pace of 

EPA’s regulation of HAPs,’’ eliminating 

much of 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’’ despite 

revisions to CAA section 111 in 1977 

and 1990. Therefore, the commenter 

asserted, Congress has ‘‘effectively 

ratified EPA’s longstanding approach to 

SSM under the NSPS program,’’ which 

includes the exemption for flares from 

the H2S concentration limits during 

SSM events. 

The commenter also asserted that, 

regardless of the above and despite the 

similar nature of the provisions in CAA 

sections 111 and 112, 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 (DC 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, the commenter asserted that 

requiring flares to meet the H2S 

concentration limits during SSM events 

does not represent BSER for this time 

period. According to the commenter, 

‘‘startup and shutdown gases are 

intermittent streams that cannot be 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, the commenter 

asserted that exempting a flare from the 

H2S concentration limits when 

combusting certain gases generated 

during SSM events is lawful under CAA 

section 111. 

Alternatively, the commenter stated 

that if a standard must apply during 

SSM events, the flare work practice 

standards are appropriate in lieu of the 

H2S concentration limit. 

Response: Regardless of whether or 

how the Sierra Club decision under 

CAA section 112 applies to 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 flare 

management plan; (2) conduct root 

cause analysis and take corrective action 

when waste gas sent to the flare exceeds 

a flow rate of 500,000 scf above the 

baseline; (3) conduct root cause analysis 

and take 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 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. CAA 

section 111(h)(2) defines the phrase 

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56442 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

9Turbulence 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. 

‘‘not feasible to prescribe or enforce a 

standard of performance’’ as ‘‘any 

situation in which the Administrator 

determines that * * * 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 

* * * 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 those devices is directly 

indicative of the SO2 emitted from the 

exhaust stacks of those other devices. As 

explained in section III of this preamble, 

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,9 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 flare gas recovery systems. Amine 

treatment removes the H2S from the 

flare gas that generates the pollutants 

before the gas is sent to the flare. Flare 

gas recovery systems remove the flare 

gas altogether and instead treat this gas 

in a fuel gas treatment system to be used 

elsewhere as fuel gas in the refinery. 

Requiring refineries to meet this 

concentration limit at the flare ensures 

that the fuel gas has been adequately 

treated and managed such that it can be 

used as fuel gas in the fuel gas system 

elsewhere in the refinery. We are not 

requiring refineries to meet this limit 

during other periods of operation 

because flare gas recovery systems that 

capture gases prior to amine treatment 

can be quickly overwhelmed and fail to 

properly function during high fuel gas 

flows. Thus, requiring that flares meet 

this H2S concentration limit during 

periods when high fuel gas flows would 

likely overwhelm these flare gas 

recovery systems would not fully 

address the circumstances refineries 

face in managing these high flow 

periods. Designing flare gas recovery 

systems to capture the full range of gas 

flows to the flare would not only require 

the ability to predict the full range of gas 

flows in the flare headers, but also 

would require refiners to install 

recovery compressors in a staged 

fashion such that all events causing high 

gas flows could be captured and 

managed, neither of which are practical. 

Therefore, promulgating flare 

requirements that include the H2S fuel 

gas concentration limit during normal 

operating conditions, coupled with 

requirements for refineries to develop 

and implement a flare management plan 

and conduct root cause analyses and 

take corrective action when waste gas 

sent to the flare exceeds a flow rate of 

500,000 scf above the baseline or 500 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 BSER 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 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56443 

particular group of sources in a 

particular location. 

Additionally, those four sources 

subject to the Billings/Laurel FIP 

demonstrate compliance with the 150 lb 

SO2/3-hour 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. 

Comment: Numerous commenters 

asserted that the long-term 60 ppmv H2S 

fuel gas concentration limit is not cost 

effective for flares and, therefore, not 

BSER for flares. The commenters noted 

that the EPA did not include costs for 

compressors, additional amine units 

and sulfur recovery units, and one 

commenter stated that the EPA did not 

consider the range of costs that are 

incurred by individual refineries. 

Commenters also asserted that the EPA 

overstated emission reductions by using 

162 ppmv H2S as a baseline because 

many refinery streams currently sent to 

the flare contain H2S concentrations 

below 162 ppmv, so 162 ppmv H2S does 

not reflect long-term performance. 

Commenters noted that the British 

thermal units (Btu) content of flare gas 

is highly variable and generally lower 

than that used by the EPA, so the EPA’s 

analysis overestimated the value of the 

recovered flare gas. One commenter 

noted that the EPA should have 

considered consent decree requirements 

in the baseline SO2 emissions estimates. 

One commenter stated that the longterm 60 ppmv H2S fuel gas 

concentration limit could preclude 

some refineries from processing highsulfur crude oils, thereby limiting 

refining production capacity. Another 

commenter noted that many flares will 

receive both fuel gas and process upset 

gas, so it would be impossible to 

determine if an exceedance is caused by 

the regulated fuel gas or by the exempt 

gas. The commenter recommended that 

the EPA apply the long-term 60 ppmv 

H2S fuel gas concentration limit only to 

fuel gas combusted in process heaters, 

boilers and similar fuel gas combustion 

devices, and not to flares, or that the 

EPA allow Alternative Monitoring Plans 

to demonstrate compliance with the 

emissions limits for non-exempt gas 

streams upstream of the flare header. 

Response: We acknowledge that, at 

proposal, we determined that a longterm 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 their fuel gas complies 

with a long-term H2S concentration of 

60 ppmv, refineries would have to 

install a flare gas recovery system 

(which was not needed for other fuel gas 

combustion devices) and then upgrade 

the fuel gas desulfurization system. 

Alternatively, refineries would have to 

treat the recovered fuel gas to limit the 

long-term concentration of H2S to 60 

ppmv with new amine treatment units 

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 longterm concentration of H2S to 60 ppmv 

is not cost effective for flares (see Table 

4 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 4—NATIONAL FIFTH YEAR IMPACTS OF MEETING A LONG-TERM 60 PPMV H2S CONCENTRATION FOR FLARES

SUBJECT TO 40 CFR PART 60, SUBPART JA

Capital cost 

($1,000) 

Total annual 

cost 

($1,000/yr) a

Emission 

reduction 

(tons SO2/yr) b

Emission 

reduction 

(tons NOX/yr) b

Emission 

reduction 

(tons VOC/ 

yr) b

Cost 

effectiveness 

($/ton) 

New .......................................................... 80,000 15,000 6 34 130 84,000 

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56444 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

TABLE 4—NATIONAL FIFTH YEAR IMPACTS OF MEETING A LONG-TERM 60 PPMV H2S CONCENTRATION FOR FLARES

SUBJECT TO 40 CFR PART 60, SUBPART JA—Continued 

Capital cost 

($1,000) 

Total annual 

cost 

($1,000/yr) a

Emission 

reduction 

(tons SO2/yr) b

Emission 

reduction 

(tons NOX/yr) b

Emission 

reduction 

(tons VOC/ 

yr) b

Cost 

effectiveness 

($/ton) 

Modified/Reconstructed ........................... 860,000 160,000 53 310 1,200 100,000 

aBecause of the heat content of recovered gas, each scf of recovered gas is assumed to offset one scf of natural gas; a value of $5/10,000 

scf of natural gas was used to estimate recovery credit. bThese 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). 

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 SCAQMD 

Rule 1118’’ and ‘‘whether EPA could 

deem a facility in compliance with 

subpart Ja as proposed to be amended 

today if that facility was found to be in 

compliance with SCAQMD Rule 1118, 

or other equivalent State or local rules’’ 

(73 FR 78532, December 22, 2008). One 

commenter disagreed with the EPA’s 

position, alleging that ‘‘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 

state and local requirements render the 

federal requirements irrelevant only 

confirms that EPA’s proposed flaring 

requirements do not reflect the best 

technological system of continuous 

emission reduction.’’ 42 U.S.C. 

7411(h)(1) (emphasis added). The 

commenter also stated that the CAA 

already provides a mechanism for 

implementation of alternative work 

practice standards in narrowly defined 

circumstances (42 U.S.C. 7411(h)(3)); an 

owner or operator may demonstrate to 

the Administrator that an alternative 

means of emissions limitation is 

equivalent to the federal standard on a 

case-by-case basis. Therefore, the 

commenter asserted, the CAA clearly 

states that ‘‘EPA’s authority to waive 

federal work practice standards is case 

specific.’’ Finally, the commenter stated 

that the EPA did not explain how 

emissions reductions achieved through 

compliance with SCAQMD Rule 1118 

are equivalent to 40 CFR part 60, 

subpart Ja. Further, the commenter 

asserted that the EPA neither identified 

other state or local rules that could be 

considered equivalent to subpart Ja, nor 

explained how the EPA would 

determine that a specific state or local 

rule is equivalent to subpart Ja. 

Therefore, the commenter asserted, it is 

impossible to fully assess the merit of 

the EPA’s idea and provide meaningful 

comments. 

Another commenter stated that ‘‘most 

stringent’’ is not one of the criteria that 

must be applied under the law to 

determine BSER. Therefore, the 

commenter asserted, it is not 

appropriate to argue that the EPA did 

not properly determine BSER simply 

because there exist state or local rules 

that are more stringent than federal 

requirements. The commenter also 

asserted that the EPA has full authority 

to establish alternative regulatory 

standards that are determined to be as 

stringent as or more stringent than 

BSER, and CAA section 111(h)(3) 

generally applies after the EPA has 

completed a national rulemaking and an 

owner or operator requests approval for 

a site-specific alternative at a later date. 

The commenter asserted that it is logical 

that, if an alternative method is 

identified during the rulemaking 

process, ‘‘the law would allow EPA to 

establish a site-specific alternative [in 

the rule itself] (especially, as under 

[CAA section 111], where the alternative 

would have to be determined through 

notice and comment rulemaking).’’ 

Other commenters recommended that 

refineries complying with SCAQMD 

Rule 1118 be deemed in compliance 

with 40 CFR part 60, subparts J and Ja. 

According to one commenter, SCAQMD 

Rule 1118 is ‘‘in all respects equivalent 

to or more stringent than the 

corresponding requirements’’ of 

subparts J and Ja. Commenters also 

recommended that refineries should be 

able to consider compliance with 

BAAQMD Regulation 12, Rule 11 and 

Regulation 12, Rule 12 as compliance 

with the appropriate provisions of 

subpart Ja. One commenter provided a 

table comparing each of the six 

proposed flare management plan 

requirements in 40 CFR 60.103a(a) to 

the SCAQMD and BAAQMD 

regulations. The table identified 

sections of BAAQMD Regulation 12, 

Rule 11 and Regulation 12, Rule 12 that 

are equivalent to the six subpart Ja flare 

management plan requirements. The 

commenter also noted that SCAQMD 

Rule 1118 is only equivalent to five of 

the proposed requirements; it does not 

require an owner or operator to identify 

procedures to reduce flaring in cases of 

fuel gas imbalance (although another 

commenter noted that SCAQMD Rule 

1118 requires minimization of all 

flaring, including fuel gas imbalance). 

While most commenters focused on the 

equivalence of the flare management 

plan requirements of the SCAQMD and 

BAAQMD rules and the flare 

management plan requirements of 

subpart Ja, one commenter requested 

that the periodic sampling of BAAQMD 

Regulation 12, Rule 11 be considered 

equivalent to the continuous sulfur 

monitoring requirements of subpart Ja 

for emergency flares. 

Response: First, we note that there 

seems to be some misunderstanding 

regarding how a determination that 

SCAQMD Rule 1118 or BAAQMD 

Regulation 12, Rule 11 and Regulation 

12, Rule 12 are equivalent to 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 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56445 

these rules to the 40 CFR part 60, 

subpart Ja requirements we are 

finalizing here. 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 flare 

management plan requirements. As a 

result of our analysis, we have amended 

subpart Ja, as described in the following 

paragraphs. 

We determined that SCAQMD Rule 

1118 is equivalent to the flare 

requirements and monitoring, 

recordkeeping and reporting 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 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 flare management plan 

requirements of 40 CFR 60.103a(a) and 

(b) and the root cause analysis and 

corrective action analysis requirements 

of 40 CFR 60.103a(c) through (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 flare management 

plan (if applicable), as specified in 40 

CFR 60.103a(g). 

We note that, as pointed out by 

commenters, an owner or operator 

maintains the ability under CAA section 

111(h)(3) to submit a request to 

establish, on a case-by-case basis, that 

‘‘an alternative means of emission 

limitation will achieve a reduction in 

emissions * * * at least equivalent to 

the reduction in emissions’’ achieved 

under the flare standards of 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. 

Comment: Commenters suggested that 

the requirement to minimize discharges 

to the flare in 40 CFR 60.103a(a)(1) 

should specifically address routine 

discharges, and the EPA should limit 

the minimization requirements to 

actions that: (1) Are ‘‘consistent with 

good engineering practices’’ and (2) 

consider costs and other health and 

environmental impacts, as required by 

section 111 of the CAA. 

Response: We agree that the language 

in proposed 40 CFR 60.103a(a)(1) 

appears to require an assessment of flare 

minimization irrespective of cost or 

other relevant considerations, as 

contained in CAA section 111, which 

was not our intent. We are clarifying, 

through this response, that cost, safety 

and emissions reductions may be 

considered when evaluating what 

actions should be taken to minimize 

discharges to a flare, but we disagree 

that the flare minimization assessment 

should be limited to ‘‘routine 

discharges.’’ We have revised the flare 

management plan requirements in 40 

CFR 60.103a(a) to more fully describe 

the types of information that must be 

evaluated and included in the plan. 

As noted in the summary of this rule 

(section III.C of this preamble), we are 

finalizing our proposed withdrawal of 

the 250,000 scfd 30-day rolling average 

flow limit for flares. This limitation 

does not adequately account for sitespecific 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 flare management plan. In the 

absence of the specific flow limitation, 

we have included additional 

requirements in the flare management 

plan to prompt a thorough review of the 

flare system so that, as an example, flare 

gas recovery systems are installed and 

used where these systems are 

warranted. We have also revised the 

flare minimization requirements to 

require the flare management plans to 

be submitted to the Administrator (40 

CFR 60.103a(b)). 

As part of the development of the 

flare management plan, refinery owners 

and operators can provide rationale and 

supporting evidence regarding the flare 

reduction options considered, the costs 

of each option, the quantity of flare gas 

that would be recovered or prevented by 

the option, the Btu content of the flare 

gas and the ability or inability of the 

reduction option to offset natural gas 

purchases. The plan will also include 

the rationale for the selected reduction 

option, including consideration of safety 

concerns. The owner or operator must 

comply with the plan, as 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 flare management plan will ensure 

that these factors are considered 

consistent with CAA section 111 and 

that the requirement to minimize 

discharges to the flare is implemented 

consistently across all affected sources. 

Comment: Commenters asserted that 

the flare flow root cause analysis 

threshold of 500,000 scf in any 24-hour 

period is arbitrary and cannot be fairly 

applied to all flares at all refineries. One 

commenter cited an ultracracker flare 

that routinely cycles from 5 million to 

25 million scfd as an example of a flare 

for which the threshold of 500,000 scf 

in any 24-hour period would result in 

constant and meaningless root cause 

analyses. The commenters suggested 

removing the numerical threshold and 

limiting root cause analysis to upsets 

and malfunctions as initially 

promulgated in June 2008 (because root 

cause analysis is generally only effective 

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56446 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

10Regarding 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. 

for reducing non-routine flows) or using 

a site- or flare-specific threshold 

instead. Even if the numerical threshold 

is revised, the commenters suggested 

that a number of streams be excluded 

from the calculation of flow, such as 

hydrogen and nitrogen, purge and 

sweep gas, natural gas added to increase 

the Btu content of the flare gas and gases 

regulated by other rules to avoid 

performing multiple root cause analyses 

for routine events. One commenter 

suggested that owners or operators 

should be able to use one root cause 

analysis report for an event that occurs 

routinely (as allowed in the consent 

decrees). 

Response: We proposed the flare flow 

root cause analysis threshold of 500,000 

scf in any 24-hour period because we 

projected that flare gas recovery would 

be a cost effective emission reduction 

technique for flares with fuel gas flows 

that routinely exceed 500,000 scfd, 

although we acknowledge that the 

threshold at which flare gas recovery 

becomes cost effective is strongly 

(inversely) correlated to the average Btu 

content of the flare gas (i.e., a relatively 

small reduction in the Btu content of the 

gas makes the recovery system 

significantly less cost effective). 

Although we did not specifically 

exclude sweep or purge gas from the 

flow, we expected that the flow rates of 

sweep or purge gas (i.e., gases needed to 

ensure the readiness of the flare and the 

safety of the flare gas system) would be 

negligible when compared to the root 

cause analysis threshold of 500,000 scf 

in any 24-hour period. In fact, in our 

original analysis of the appropriate flow 

rate root cause analysis threshold 

(Docket Item No. EPA–HQ–OAR–2007– 

0011–0246), we 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 scfd 10 is a reasonable 

base flow for a flare, we do acknowledge 

that the size of the flare, as well as the 

flare header system, will greatly impact 

the required flow needed to maintain 

the readiness of the flare. Although we 

can derive suitable flare flow thresholds 

for average conditions, these thresholds 

are not necessarily reasonable when 

applied to all flows, and we did not 

intend for on-going root cause analyses 

to be conducted on account of sweep or 

purge gas. 

Therefore, rather than specifying a 

one-size-fits-all threshold, the final rule 

requires facilities to develop their own 

base flare flow rates as part of their flare 

management plan. A flow-based root 

cause analysis is triggered if flows 

measured by the flow monitor exceed 

500,000 scf greater than the base flare 

flow rate in any 24-hour period. 

Evaluating the flow rate threshold above 

a baseline better reflects our original 

analysis of the impacts of flow-based 

root cause analyses when the sweep or 

purge gas flow rates are not negligible. 

We also note that 40 CFR 60.103a(d) 

allows a single root cause analysis to be 

conducted for any single continuous 

discharge that causes the flare to exceed 

either the root cause analysis threshold 

for SO2 or flow for two or more 

consecutive 24-hour periods. 

The final rule does not limit root 

cause analyses to upsets and 

malfunctions of refinery process units 

and ancillary equipment connected to 

the flare, nor does it explicitly allow 

owners or operators to use one root 

cause analysis report for an event that 

occurs routinely. When we decided to 

eliminate the numerical limit on flare 

flow rate, we specifically increased the 

scope of the flare flow root cause 

analysis to cover more than just upsets 

and malfunctions. We also decided not 

to explicitly allow owners or operators 

to use one root cause analysis report for 

an event that occurs routinely as a 

means to discourage routine flaring of 

recoverable gas. However, we recognize 

that there may be recurring discharges 

to the flare that are not recoverable for 

various reasons. Therefore, the final rule 

does allow for several base cases, which 

could include recurring maintenance; 

this provision will avoid multiple root 

cause analyses for a recurring event. As 

described above, the flare management 

plan (as well as significant revisions to 

the plan to include alternative 

baselines) must be submitted to the 

Administrator. The Administrator or 

delegated authority (e.g., the state) may 

review the plan, although formal 

approval of the plan is not required. Not 

specifying a formal approval process is 

intended to minimize the burden 

associated with reviewing flare 

management plans. Rather, the rule 

specifies elements of the plan that need 

to be addressed in order for the plan to 

be considered adequate and provides an 

opportunity for a delegated authority to 

find the plan not adequate if they 

choose to do so. 

We expect that a final flare 

management plan 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 unreasonable), the 

Administrator will notify the owner or 

operator of the apparent deficiencies. 

The owner or operator must either 

revise the plan to address the 

deficiencies or provide additional 

information to document the 

reasonableness of the plan. 

Comment: Commenters requested 

alternative monitoring options or an 

exemption from continuous flow 

monitoring for: (1) Flares designed to 

handle less than 500,000 scfd of gas; (2) 

pilot gas; (3) flares with flare gas 

recovery systems; (4) emergency flares; 

and (5) secondary flares. The 

commenters asserted that flow meters 

are costly and engineering calculations, 

which are currently used, are sufficient 

to evaluate when the flow to a flare 

exceeds 500,000 scf in any 24-hour 

period. One commenter stated that, for 

flares with flare gas recovery systems, 

the pressure drop across the flare seal 

drum can be used to calculate flow rate. 

Response: In the final rule, flow 

monitoring is used to determine 

whether a root cause analysis is 

required rather than to ensure 

compliance with a specific flow limit. 

We have reviewed the commenters’ 

suggestions and agree that, in certain 

specific cases, monitoring is not 

necessary and should not be required. 

However, as a general rule, we believe 

flow monitors are needed, not only to 

provide a verifiable measure of 

exceedances of the flow root cause 

analysis threshold, but also exceedances 

of the root cause analysis threshold of 

500 lb SO2 in any 24-hour period. In 

addition, when we evaluated local rules, 

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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 root cause analysis 

threshold (i.e., designed to handle less 

than 500,000 scfd of gas). However, 

these small flares could still exceed the 

root cause analysis threshold of 500 lb 

SO2 in any 24-hour period. As such, we 

did not provide an exemption from the 

monitoring requirements for these small 

flares. 

We agree that the monitoring of pilot 

gas flow is not needed. In the final rule, 

a root cause analysis is required if the 

gas flow to the flare exceeds 500,000 scf 

above the baseline in any 24-hour 

period. The flow of pilot gas is 

considered to be part of the baseline 

flow and is assumed to be constant. As 

such, monitoring of pilot gas would not 

be necessary to determine whether a 

flare has exceeded 500,000 scf above the 

baseline in any 24-hour period. In 

practice, the actual baseline flow set for 

the flare may or may not expressly 

include the pilot gas flow rate. 

Generally, the configuration of the flare 

header is such that the flare flow 

monitor would not measure pilot gas 

flow. In this case, the baseline flow 

determined for the flare would not 

expressly include the pilot gas flow rate. 

If the flare flow monitor is configured in 

such a way that it does measure pilot 

gas, then pilot gas would be considered 

part of the baseline conditions for that 

flare. 

We agree with commenters that flares 

with flare gas recovery systems do have 

unique conditions and these warrant 

alternative monitoring options. 

Additionally, we recognize that the 

monitoring requirements may be 

burdensome for flares that are truly 

‘‘emergency only’’ (i.e., flares that flare 

gas rarely, if at all, during a typical year) 

or for secondary flares in a cascaded 

flare system. These flares are expected 

to have a water seal that prevents flare 

use during normal operations and 

ensures that the pressure upstream of 

the water seal (expressed in inches of 

water) does not exceed the water seal 

height during normal operations 

(hereafter referred to as ‘‘properly 

maintain a water seal’’). We find that, 

for these select types of flares, water seal 

monitoring as an alternative to the flow 

(and sulfur) monitoring provisions is 

appropriate. 

For flares with a flare gas recovery 

system and other emergency or 

secondary flares that properly maintain 

a water seal, the final rule states that an 

owner or operator may elect to monitor 

the pressure in the gas header just 

before the water seal and monitor the 

water seal liquid height to verify that 

the flare header pressure is less than the 

water seal, which is an indication that 

no flow of gas occurs. If the flare header 

pressure exceeds the water seal liquid 

level, a root cause analysis is triggered 

unless the pressure exceedance is 

attributable to staging of compressors. 

This alternative reduces the costs 

associated with installing sulfur and 

flow monitoring systems for flares that 

rarely receive fuel gas. Engineering 

calculations can be used to estimate the 

emissions during the event, but not for 

determining whether or not a root cause 

analysis is required. 

To ensure that this option is only 

used for flares that are truly emergency 

flares and not for flares that are used for 

routine discharges, the final rule 

contains a limit on the number of 

pressure exceedances requiring root 

cause analyses that can occur in one 

year. Following the fifth reportable 

pressure exceedance in any consecutive 

365 days, the owner or operator must 

comply with the sulfur and flow 

monitoring requirements of 40 CFR 

60.107a(e) and (f). Based on a review of 

available flaring data, we expect that gas 

may be sent to an emergency flare three 

to four times per year, on average. 

Consistent with this information, we are 

providing in these final amendments 

that an ‘‘emergency flare’’ may receive 

up to four releases to the flare in any 

consecutive 365-day period to account 

for year-to-year variability. However, a 

flare receiving more than four 

discharges in a consecutive 365-day 

period can no longer be considered an 

‘‘emergency flare’’ and must install the 

required sulfur and flow monitors. 

Comment: Commenters requested an 

exemption from continuous sulfur 

monitoring or alternative monitoring 

options for flares handling only gases 

inherently low in sulfur content, 

emergency flares, flares with properly 

designed flare gas recovery systems and 

secondary flares. For flares handling 

gases low in sulfur, the commenters 

noted that continuous monitoring is 

unnecessary and certain fuel gas streams 

are already exempted from monitoring if 

they are combusted in a fuel gas 

combustion device. For flares that 

handle only gases exempt from the H2S 

concentration requirements and flares 

with properly designed flare gas 

recovery systems, commenters stated 

that engineering calculations are 

sufficient to determine if the SO2 root 

cause analysis threshold of 500 lb in any 

24-hour period is exceeded. One 

commenter requested that the EPA 

allow owners or operators to submit and 

use an alternative monitoring plan to 

demonstrate that the flare gas recovery 

system is operating within its capacity 

and to calculate SO2 emissions from 

engineering calculations and flare gas 

sampling. For secondary flares, one 

commenter noted that the continuous 

sulfur monitor on the primary flare 

could be used to determine the sulfur 

content of the gas being flared from the 

secondary flare. 

One commenter requested that the 

EPA allow the use of engineering 

calculations to determine the sulfur-toH2S ratio because sampling can be 

difficult for emergency flares. One 

commenter noted that the EPA should 

allow the use of an existing continuous 

monitoring system if the gas sent to the 

flare is already monitored elsewhere. As 

examples, the commenter cited fuel gas 

and pilot gas already monitored within 

the fuel gas system. 

For flares that rarely see flow, 

commenters particularly cited 

difficulties with performance tests. 

Commenters noted that, to meet the 

sulfur monitor performance test 

requirements, an owner or operator may 

have to intentionally flare gas that may 

not meet the H2S concentration limits. 

One commenter also stated that 

performing the required relative 

accuracy test audit (RATA) could cause 

the flare to exceed the root cause 

analysis threshold. The commenter 

recommended revising the performance 

test requirements for flares with flare 

gas recovery to require only a cylinder 

gas audit. 

Response: We have amended the final 

rule so that gases that are exempt from 

H2S monitoring due to low sulfur 

content are also exempt from sulfur 

monitoring requirements for flares. For 

low-sulfur gases, the flare root cause 

analysis will always be triggered by an 

exceedance of the flow rate threshold 

well before the SO2 threshold is 

exceeded, so no sulfur monitoring is 

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 

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56448 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

60.107a(a)(3), such as flares used for 

pressure relief of propane or butane 

product spheres (fuel gas streams 

meeting commercial grade product 

specifications for sulfur content of 30 

ppmv or less) or flares used to combust 

fuel gas streams produced in process 

units that are intolerant to sulfur 

contamination (e.g., hydrogen plant, 

catalytic reforming unit, isomerization 

unit or 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 root cause analysis 

and there is a limit to the number of 

exceedances in one year. Under this 

option, a root cause analysis is triggered, 

based on the monitored pressure and 

water seal height, so accurate 

measurements of flow rate and sulfur 

concentrations are less critical than for 

flares that must evaluate these 

parameters to determine if a root cause 

analysis is needed. Consequently, for 

these flares, engineering calculations 

can be used to estimate the reported 

emissions during the flaring event, but 

the root cause analysis must be 

performed regardless of the magnitude 

of these engineering estimates. Using 

this alternative monitoring option, 

emergency flares are not required to 

install continuous sulfur monitoring 

systems. Flares that do not meet the 

conditions of an emergency flare are 

required to install continuous sulfur 

monitoring systems and cannot elect 

this alternative monitoring option. 

We also agree that flaring solely for 

the purpose of a RATA or other 

performance test is not desirable. The 

‘‘cylinder gas audit’’ procedures 

requested by the commenter are 

described as alternative relative 

accuracy procedures in section 16.0 of 

Performance Specification 2 (referenced 

from Performance Specification 5). We 

reviewed the alternative relative 

accuracy procedures and considered 

how they may apply to flares, and we 

have determined that the alternative 

relative accuracy procedures are 

appropriate for flares. We expect that, 

for most affected flares, the variability in 

flow (including no flow conditions) and 

sulfur content of the gases discharged to 

the flare create significant barriers to the 

normally required relative accuracy 

assessments, particularly if those 

assessments need to be made over a 

range of sulfur concentrations 

potentially seen by the monitor. 

Therefore, we are amending 40 CFR 

60.107a(e)(1)(ii) and 40 CFR 

60.107a(e)(2)(ii) to specify that the 

owner or operator of a flare may elect 

to use the alternative relative accuracy 

procedures in section 16.0 of 

Performance Specification 2 of 

Appendix B to part 60. As required by 

40 CFR 60.108a(b), the owner or 

operator shall notify the Administrator 

of their intent to use the alternative 

relative accuracy procedures. 

Comment: One commenter requested 

that the EPA clarify whether the 

additionally proposed sulfur monitoring 

options for flares are for total reduced 

sulfur or total sulfur. The commenter 

noted that measuring total sulfur is the 

simplest and most inclusive 

measurement of SO2 emissions and it is 

the method included in SCAQMD Rule 

1118. The commenter also requested 

that methods for measuring total sulfur 

in gaseous fuels be included as 

acceptable options to perform the 

relative accuracy evaluations of the 

CEMS. 

One commenter requested that 

provisions be made in 40 CFR 

60.107a(e)(2) to develop a total sulfurto-H2S (or total reduced sulfur-to-H2S) 

ratio so that the total sulfur monitor can 

be used for both the root cause analysis 

requirements and for compliance with 

the requirement to limit short-term H2S 

concentration in fuel gas sent to a flare 

to 162 ppmv without the need for a 

duplicative continuous H2S monitor. 

Another commenter supported the 

addition of alternative monitoring 

methods for the sulfur content of flare 

gas, but noted that since the 

composition of flare gas is highly 

variable, the alternative methods must 

meet continuous monitoring 

requirements. 

Response: We have clarified and 

consolidated the monitoring 

requirements to allow total reduced 

sulfur monitoring for flares. For the 

purposes of evaluating the SO2 root 

cause analysis threshold, total sulfur 

monitoring provides the most accurate 

assessment. However, in most cases, the 

vast majority of sulfur contained in 

gases discharged to the flare is expected 

to be in the form of total reduced sulfur 

compounds, which include carbon 

disulfide, carbonyl sulfide and H2S. Our 

test method for measuring total reduced 

sulfur includes the use of EPA Method 

15A as a reference method, and because 

EPA Method 15A measures total sulfur, 

the total reduced sulfur monitoring 

requirement is equivalent to a total 

sulfur monitoring method. 

As discussed previously, we are 

relying on the suite of flare 

requirements we are promulgating to 

limit SO2 emissions at the flare. These 

include optimizing management of the 

fuel gas 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 total 

reduced sulfur concentration, it is 

acceptable to use the total reduced 

sulfur monitor to verify that the fuel gas 

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does not exceed the short-term H2S 

concentration of 162 ppmv. Therefore, 

we have provided for the use of total 

reduced sulfur monitors, provided the 

monitor can also meet the 300 ppmv 

span requirement. 

However, we have not provided a 

correction factor to scale down the total 

reduced sulfur concentration to H2S. 

The owner or operator using this 

method must essentially be able to 

demonstrate they can achieve a 162 

ppmv total reduced sulfur concentration 

in the fuel gas. The concentration ratio 

was provided for the purposes of the 

root cause analysis because of the costs 

of adding a total sulfur monitoring 

system when a dual range H2S monitor 

was already in-place, as well as the 

expected accuracy needed for the 

system to assess the SO2 root cause 

analysis threshold. As few cases would 

exist where the flaring event would be 

right at the SO2 root cause analysis 

threshold of 500 lb in any 24-hour 

period, inaccuracies associated with the 

average total sulfur-to-H2S ratio were 

not expected to be significant. 

On the other hand, the short-term 162 

ppmv H2S concentration in the fuel gas 

must be continuously maintained, and 

the total sulfur-to-H2S ratio at these low 

concentrations is expected to be highly 

variable, depending on the efficiency of 

the amine scrubber systems. As the 

amine scrubber systems, according to 

previous industry comments, are not 

effective for reduced sulfur compounds 

other than H2S, the non-H2S reduced 

sulfur concentration is expected to be 

fairly constant, with most of the 

fluctuations in total sulfur content being 

attributable to fluctuations in H2S 

concentrations. Consequently, we have 

determined that the inaccuracies of the 

ratio approach are not acceptable for 

continuously demonstrating that the 

short-term concentration in the fuel gas 

does not exceed 162 ppmv H2S. 

Therefore, owners or operators of 

affected flares may use the direct output 

of a total reduced sulfur monitor to 

assess compliance with the short-term 

162 ppmv H2S concentration in the fuel 

gas, or they must install a continuous 

H2S monitor. 

Comment: One commenter supported 

the proposed amendment revising the 

span value for fuel gas H2S analyzers to 

match the span requirements in 40 CFR 

part 60, subpart J, stating this will save 

time and money. However, the 

commenter stated that the span value 

for the flare H2S monitoring option is 

too restrictive and suggested that 

requirements in Appendix F to part 60 

provide sufficient quality assurance/ 

quality control (QA/QC) without the 

need for the rule to specify the span 

range. The commenter also requested 

clarification of the sulfur monitor span 

for flares, suggesting that it should be 

based on the H2S concentration limits 

and that engineering calculations can be 

used to assess exceedances of the SO2

root cause analysis threshold of 500 lb 

in any 24-hour period. 

Response: The H2S span value is at 

300 ppmv to verify compliance with the 

H2S concentration 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

root cause analysis threshold of 500 lb 

in any 24-hour period, a dual range 

monitor will be necessary. For the 

purposes of the SO2 root cause analysis 

threshold of 500 lb in any 24-hour 

period, we intended that the monitor be 

capable of accurately determining the 

sulfur concentration for the range of 

concentrations expected to be seen at 

the flare. We are particularly interested 

in quantifying the concentrations of 

high sulfur-containing streams as these 

would be the streams most likely to 

trigger a root-cause analysis at low 

flows. We proposed that the span for the 

flare sulfur monitor be selected from a 

range of 1 to 5 percent. We agree with 

the commenter that this may be too 

restrictive, and we have revised the 

span requirements to be determined, 

based on the maximum sulfur content of 

gas that can be discharged to the flare 

(e.g., roughly 1.1 to 1.3 times the 

maximum anticipated sulfur 

concentration), but no less than 5,000 

ppmv. A single dual range monitor may 

be used to comply with the short-term 

162 ppmv H2S concentration 

requirement for the fuel gas and the SO2

root cause analysis threshold 

monitoring requirement provided the 

applicable span specifications are met. 

In reviewing the span specifications, we 

noted that span requirements were 

inadvertently omitted from the total 

reduced sulfur compound monitoring 

alternative. The purpose of these 

monitors is identical to the H2S 

monitoring alternative, and the same 

span considerations apply for these 

monitors. 

We disagree that the QA/QC 

procedures in Appendix F to part 60 are 

sufficient without specifying the span 

values. Procedure 1 of Appendix F to 

part 60 defines ‘‘span value’’ as: ‘‘The 

upper limit of a gas concentration 

measurement range that is specified for 

affected source categories in the 

applicable subpart of the regulation.’’ 

The concentrations used for calibration 

are based on the span value. Several of 

the QA/QC procedures in Appendix F 

are undefined if the span value is not 

defined in the rule. 

Comment: Commenters stated that 

time is needed to install continuous 

monitors and to make other necessary 

changes (such as installing a flare gas 

recovery system or additional amine 

treatment) to comply with all the flare 

requirements (e.g., limiting short-term 

H2S concentration to 162 ppmv, longterm 60 ppmv H2S fuel gas 

concentration limit, flare management 

plan, root cause analysis and 

continuous monitoring), especially 

considering how quickly a flare may 

become a modified affected source. 

While most commenters focused on the 

amount of time needed to install 

equipment to comply with the long-term 

60 ppmv H2S fuel gas concentration 

limit, other commenters asserted that 

additional time for activities, such as 

planning and re-piping, would be 

needed to meet the standards. 

Commenters requested differing 

amounts of additional time generally 

ranging from 3 to 5 years. Commenters 

noted that the additional time would 

allow owners and operators to schedule 

any process unit shutdowns needed to 

install new equipment or monitors 

during a turnaround. One commenter 

recommended that the extra time to 

begin root cause analyses provided to 

refiners committing to install flare gas 

recovery systems should also be 

provided to refiners committing to 

expand an existing flare gas recovery 

system. Commenters also noted that 

experience implementing SCAQMD 

Rule 1118 suggests that there will be 

difficulty obtaining and installing 

continuous monitors in less than 3 years 

due to the availability of monitor 

manufacturers and the need to stage the 

installation of monitors at refineries 

with multiple affected flares. One 

commenter requested that the EPA 

consider a compliance schedule in 40 

CFR part 60, subpart Ja that is consistent 

with compliance schedules in consent 

decrees. Commenters objected to 

phasing out the additional time after the 

rule has been in place for 5 years. 

One commenter requested 

clarification regarding the trigger date 

from which the additional time to 

comply with the flare provisions (e.g., 2 

years when installing a flare gas 

recovery system) begins. The 

commenter questioned whether the 

trigger date is when construction starts, 

at startup or when the stay is removed 

(or whichever is later). Another 

commenter agreed that the EPA should 

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56450 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

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. 

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 process-related 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 

modified flares that already have 

adequate treatment and monitoring 

equipment in place to achieve a shortterm H2S concentration of 162 ppmv 

(resulting from compliance with 40 CFR 

part 60, subpart J) to continue to meet 

that concentration upon startup of the 

affected flare or the effective date of this 

final rule, whichever is later. However, 

some flares are not affected facilities 

subject to 40 CFR part 60, subpart J, and 

others are complying with subpart J 

requirements as specified in consent 

decrees or have received alternative 

monitoring plans by which to 

demonstrate compliance with the shortterm H2S concentration limit. In these 

cases, we find it appropriate to allow 

more time to comply with the shortterm H2S concentration limit and/or the 

associated monitoring requirements 

because additional amine treatment 

and/or monitoring systems will be 

required to comply with the rule. 

Therefore, the final rule requires all 

modified flares that are newly subject to 

40 CFR part 60, subpart Ja (but were not 

previously subject to 40 CFR part 60, 

subpart J) to comply with the short-term 

H2S concentration limit and applicable 

monitoring requirements no later than 3 

years after the effective date of this final 

rule or upon startup of the affected flare, 

whichever is later. Modified flares that 

have accepted applicability of subpart J 

under a federal consent decree shall 

comply with the subpart J requirements 

as specified in the consent decree but 

shall comply with the short-term H2S 

concentration limit and applicable 

monitoring requirements no later than 3 

years after the effective date of this final 

rule. Modified flares that are already 

subject to the 162 ppmv short-term H2S 

concentration limit under subpart J 

must meet the short-term H2S 

concentration limit under subpart Ja 

upon startup of the affected flare or the 

effective date of this final rule, 

whichever is later. Finally, modified 

flares that are already subject to the 

short-term H2S concentration limit but 

that have an approved monitoring 

alternative under subpart J and do not 

have the monitoring equipment in-place 

that is required under subpart Ja shall be 

given up to 3 years from the effective 

date of this final rule to install the 

monitors required by subpart Ja (or to 

obtain an approved monitoring 

alternative under subpart Ja). 

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 repiping) sulfur and flow monitors that 

are newly required by subpart Ja. Some 

refineries will elect to add flare gas 

recovery and/or sulfur treatment 

equipment to minimize their emissions 

as part of the evaluations conducted, as 

required by the new flare management 

plan requirements, and time will be 

needed for planning, designing, 

purchasing and installing these 

components as well. Given that many 

flares will become modified affected 

sources relatively quickly, owners and 

operators will be competing with one 

another for the services and products of 

a finite number of vendors who provide 

the necessary monitors and other 

equipment. Several commenters 

specifically noted availability of 

monitors as an issue when complying 

with SCAQMD Rule 1118. As such, we 

find that immediate compliance with 

the requirements for flares, such as the 

planning, designing, purchasing and 

installation of (including any necessary 

re-piping) sulfur and flow monitors, 

may be difficult for operators to meet, 

especially in situations where quick 

connections to the flare are made. A 

phased compliance schedule allows for 

the operators to comply with some 

requirements associated with flares, 

such as continuing to achieve a shortterm H2S concentration of 162 ppmv, if 

the flares are already subject to 40 CFR 

part 60, subpart J and have adequate 

monitoring in place to comply with this 

final rule, while allowing time to install 

treatment and processing equipment 

and monitoring equipment to comply 

with the standards where necessary. 

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 flare management 

plan. Because of the ability to plan 

ahead, flares that are modified as part of 

a large project will not have all of the 

difficulties meeting the subpart Ja flare 

requirements upon completion of the 

modification as those flares that are 

modified quickly. Therefore, we find 

that compliance with the flare 

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11For 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). 

requirements upon startup of the 

modified flare is appropriate and 

consistent with the best system of 

emissions reduction for large projects 

resulting in a modification of a flare. 

Thus, we determined that the 

appropriate time period for compliance 

with the flare standards is either: (1) 3 

years from the effective 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 the 

effective date of these amendments), 

will have up to 3 years from the 

effective date of these 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 owners and operators of 

modified flares to meet the short-term 

162 ppmv H2S concentration 

requirement by the effective date of 

these amendments or upon startup of 

the affected flare (whichever is later) 

only if they are already subject to the 

short-term 162 ppmv H2S concentration 

limit in 40 CFR part 60, subpart J. 

Modified flares that were not affected 

flares under subpart J prior to being 

modified facilities under subpart Ja 

must comply with the short-term 162 

ppmv H2S concentration requirement 

within 3 years of the effective date of 

these amendments or upon startup of 

the modified flare, whichever is later. 

Owners and operators of modified flares 

that are have accepted applicability of 

subpart J under a federal consent decree 

shall comply with the subpart J 

requirements as specified in the consent 

decree, but must meet the short-term 

162 ppmv H2S concentration limit no 

later than 3 years after the effective date 

of this final rule. Owners and operators 

of modified flares that are already 

subject to subpart J and that have an 

approved monitoring alternative and are 

unable to meet the applicable subpart Ja 

monitoring requirements for the shortterm H2S concentration limit must meet 

the short-term H2S concentration 

requirement upon startup of the affected 

flare or the effective date of this final 

rule, whichever is later, but shall be 

given up to 3 years from the effective 

date of this final rule to install the 

monitors required by subpart Ja. In this 

interim period, owners and operators of 

these modified flares shall demonstrate 

compliance with the short-term H2S 

concentration limit using the 

monitoring alternative approved under 

subpart J. 

Additionally, we are requiring owners 

and operators of modified flares to 

complete and implement the flare 

management plan under 40 CFR 

60.103a(a) by 3 years from the effective 

date of these amendments 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 

effective date of these amendments or 

the date of the startup of the modified 

flare, whichever is later, so that the 

facility can complete the flare 

management plan and establish baseline 

flow rates prior to performing the root 

cause and corrective action analyses. 

We are also requiring owners and 

operators of modified flares to install 

and begin operating the monitors 

necessary to demonstrate compliance 

with these provisions, as required under 

40 CFR 60.107a(e) through (g) within 3 

years from the effective date of these 

amendments 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. 

We note that the final rule does not 

provide a phased compliance schedule 

for new and reconstructed flares. The 

final rule requires owners and operators 

of new and reconstructed flares to meet 

all the flare requirements, including the 

short-term 162 ppmv H2S concentration 

requirement, upon the effective date of 

the requirements or upon startup of the 

affected flare, whichever is later. 

C. Other Comments 

Comment: Several commenters 

objected to the change to the definition 

of ‘‘refinery process unit.’’ The 

commenters objected to the proposed 

amendments to include coke 

gasification, loading and wastewater 

treatment, stating the change makes the 

term more expansive. The commenters 

stated that the EPA did not evaluate the 

impacts or explain the consequences of 

the revised definition. One commenter 

stated that product loading is generally 

considered part of the refinery process 

unit to which it is associated and that 

wastewater treatment is a utility. 

Another commenter suggested that the 

definition specify SIC 2911 (as in 

Refinery MACT 1). 

Response: The original definition of 

‘‘refinery process unit’’ in 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 

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56452 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

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 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 flare management plan 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 

flare management plan. We have 

included in the final amendments a 

definition of ‘‘ancillary equipment.’’ 

Specifically, ancillary equipment means 

equipment used in conjunction with or 

that serve a refinery process unit. 

Ancillary equipment includes, but is not 

limited to, storage tanks, product 

loading operations, wastewater 

treatment systems, steam- or electricityproducing units (including coke 

gasification units), pressure relief 

valves, pumps, sampling vents, and 

continuous analyzer vents. 

Sulfur recovery plants are also units 

from which a connection to a flare 

would trigger a flare modification and 

generate gas streams that should be 

considered in the flare management 

plan. We recognize that on-site sulfur 

recovery plants are considered refinery 

process units, and we proposed 

amendments to the definitions of 

‘‘refinery process unit’’ and ‘‘sulfur 

recovery plant’’ to clarify that we 

consider a sulfur recovery plant to be ‘‘a 

segment of the petroleum refinery in 

which a specific processing operation is 

conducted.’’ However, the strict 

definition of ‘‘refinery process unit’’ 

would only apply to sulfur recovery 

plants physically located at the refinery. 

As 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. 

Comment: Commenters supported the 

revised definition of ‘‘delayed coking 

unit,’’ but stated that, since 40 CFR part 

60, 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 fluid catalytic cracking unit 

(FCCU). For the FCCU, fresh feed is 

introduced in the riser, which is part of 

the affected facility in subpart Ja. As the 

feed to the delayed coking unit is to the 

fractionator, we find that the 

fractionator is an integral part of the 

delayed coking unit, so we specifically 

include it as part of the affected facility. 

While our proposed amendments 

covered only the major components of 

the delayed coking unit, upon our 

review of the definition based on the 

comments received, we note that there 

are several other components of the 

delayed coking unit that are integral to 

the operation of the delayed coking unit. 

Additionally, even though the standards 

are specific to the coke drum, many of 

these integral components are 

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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 mean 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. 

Since this definition is more specific 

than the definition included in the 

amendments proposed on December 22, 

2008, it could affect which delayed 

coking units are subject to subpart Ja. 

For example, an owner or operator may 

have made a change to a delayed coking 

unit that would not be considered a 

modification under the December 22, 

2008, definition, but that same change 

could make the delayed coking unit a 

modified facility subject to subpart Ja 

using the definition of ‘‘delayed coking 

unit’’ above. In other words, in changing 

the definition of ‘‘delayed coking unit’’ 

in the final rule, some delayed coking 

units that would not have been affected 

sources under the proposed 

requirements might now be covered by 

the final rule. Under CAA section 

111(a)(2), a ‘‘new source’’ is defined 

from the date of proposal only if there 

is a standard ‘‘which will be applicable 

to such source;’’ otherwise, a ‘‘new 

source’’ is defined based upon the final 

rule date. In this circumstance, using 

the proposal date as the new source date 

for determining applicability for this 

group of delayed coking units would be 

inappropriate as such units would not 

have been on notice that subpart Ja 

could apply to them. Accordingly, we 

moved the ‘‘new source’’ date for this 

group of delayed coking units so that 

delayed coking units that are only 

defined as such under the final rule are 

covered by the final rule only if they 

commence construction, reconstruction 

or modification after the promulgation 

date of these final amendments. The 

‘‘new source’’ date for other delayed 

coking units will depend on the 

previous definitions and when the 

activities involving the delayed coking 

unit occurred. See § 60.100a(b) for 

determining applicability of subpart Ja 

for delayed coking units. 

Comment: One commenter stated that 

40 CFR part 63, subpart LLLLL indicates 

at 40 CFR 63.8681(e) that 40 CFR part 

60, subpart J does not apply for asphalt 

blowing stills subject to subpart LLLLL, 

and the commenter requested similar 

clarification for 40 CFR part 60, 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). 

Comment: One commenter 

recommended that the exclusion from 

the definition of ‘‘fuel gas’’ be extended 

to vapors ‘‘from marine vessel loading 

operations or waste management units 

that are collected and combusted’’ 

without any reference to a federal 

requirement. At a minimum, the 

commenter stated that marine benzene 

loading under 40 CFR part 61, subpart 

BB; the wastewater provisions of 40 CFR 

part 63, subpart G; remediation efforts 

regulated under Resource Conservation 

and Recovery Act (RCRA) corrective 

action; and RCRA 7003 orders should be 

added to the exclusion. 

Response: We were originally 

concerned that removing the reference 

to a federal standard may inadvertently 

exempt the use of these vapors when 

used in process heaters or boilers. We 

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) Process heaters or boilers would 

not be ‘‘installed’’ to comply with these 

provisions, and it was not our intent to 

exclude vapors sent to these types of 

combustion units. However, the 

regulatory text is more ambiguous and 

appears to exclude any vapors collected 

and combusted, regardless of where 

they are combusted. As such, we are 

amending this exclusion to better 

represent our original intent. 

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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. 

V. Summary of Cost, Environmental, 

Energy and Economic Impacts 

A. What are the emission reduction and 

cost impacts for the final amendments? 

The emission reduction and cost 

impacts presented in this section for 

flares are revised estimates for the 

impacts of the final requirements of 40 

CFR part 60, subpart Ja for flares, as 

amended by this action. The table 

shows the differences in anticipated 

impacts between these final 

amendments to subpart Ja and the final 

June 2008 NSPS requirements of subpart 

Ja, which were estimated assuming only 

40 flares would trigger applicability to 

the rule. The impacts are presented for 

400 affected flares that commence 

construction, reconstruction or 

modification that will be required to 

comply with this final rule. We 

anticipate that most of the flares would 

become affected due to the modification 

provisions for flares set forth in the final 

June 2008 subpart Ja rule. For this 

analysis, we assumed that 90 percent of 

the flares will be modified or 

reconstructed and 10 percent of the 

flares will be newly constructed. 

Further, we estimate that 30 percent of 

the 400 affected flares, or 120 flares, 

either would meet the definition of 

‘‘emergency flare’’ in subpart Ja or 

would be equipped with a flare gas 

recovery system such that robust sulfur 

and flow monitoring would not be 

required. Therefore, the values in Table 

5 of this preamble include the costs and 

emissions reductions for 400 flares to 

comply with the flare management plan 

and root cause and corrective action 

analyses requirements and for 280 flares 

to comply with the sulfur and flow 

monitoring requirements. The cost and 

emissions reductions for the affected 

flares to comply with the short-term H2S 

concentration of 162 ppmv in the fuel 

gas are included in the baseline rather 

than the incremental impacts because 

this limit is unchanged from the 

requirements in 40 CFR part 60, subpart 

J. For further detail on the methodology 

of these calculations, see 

Documentation of Impact Estimates for 

Fuel Gas Combustion Device and Flare 

Regulatory Options for Amendments to 

the Petroleum Refinery NSPS, in Docket 

ID No. EPA–HQ–OAR–2007–0011. 

We estimate that the final 

requirements for flares will reduce 

emissions of SO2 by 3,200 tons/yr, NOX

by 1,100 tons/yr and VOC by 3,400 tons/ 

yr from the baseline. The estimated 

annual cost, including annualized 

capital costs, is a cost savings of about 

$79 million (2006 dollars) due to the 

replacement of some natural gas 

purchases with recovered flare gas and 

the retention of intermediate and 

product streams due to a reduction in 

the number of malfunctions associated 

with refinery process units and ancillary 

equipment connected to the flare. Note 

that not all refiners will realize a cost 

savings since we only estimate that 

refineries with high flare flows will 

install vapor recovery systems. 

Although the rule does not specifically 

require installation of flare gas recovery 

systems, we project that owners and 

operators of flares receiving high waste 

gas flows will conclude, upon 

installation of monitors, implementation 

of their flare management plans, and 

implementation of root causes analyses, 

that installing flare gas recovery would 

result in fuel savings by using the 

recovered flare gas where purchased 

natural gas is now being used to fire 

equipment such as boilers and process 

heaters. The flare management plan 

requires refiners to conduct a thorough 

review of the flare system so that flare 

gas recovery systems are installed and 

used where these systems are 

warranted. As part of the development 

of the flare management plan, refinery 

owners and operators must provide 

rationale and supporting evidence 

regarding the flare waste gas reduction 

options considered, 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. In addition, 

consistent with Executive Order 13563 

(Improving Regulation and Regulatory 

Review, issued on January 18, 2011), for 

facilities implementing flare gas 

recovery, we are finalizing provisions 

that would allow the owner or operator 

to reduce monitoring costs and the 

number of root cause analyses, 

corrective actions, and corresponding 

recordkeeping and reporting they would 

need to perform. We estimate that the 

final requirements for flares will reduce 

emissions of SO2 by 3,200 tons/yr, NOX

by 1,100 tons/yr and VOC by 3,400 tons/ 

yr from the baseline. The overall cost 

effectiveness is a cost savings of about 

$10,000 per ton of combined pollutants 

removed. The estimated nationwide 5- 

year emissions reductions and cost 

impacts for the final standards are 

summarized in Table 5 of this preamble. 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56455 

TABLE 5—NATIONAL EMISSION REDUCTIONS AND COST IMPACTS FOR PETROLEUM REFINERY FLARES SUBJECT TO

AMENDED STANDARDS UNDER 40 CFR PART 60, SUBPART JA

[Fifth year after the effective date of these final rule amendments] a

Subpart Ja requirements 

Total capital 

cost 

($1,000) 

Total annual 

cost without 

credit 

($1,000/yr) 

Natural gas 

offset/product recovery 

credit 

($1,000) 

Total annual 

cost 

($1,000/yr) 

Annual 

emission reductions 

(tons SO2/ 

yr) 

Annual 

emission reductions 

(tons NOX/ 

yr) 

Annual 

emission reductions 

(tons VOC/ 

yr) 

Cost effectiveness 

($/ton emissions reduced) 

Estimates from June 

2008 Final Rule ...... 40,000 .................... .................... (7,000) 80 6 200 (23,000) 

Revised Estimates for 

Amendments .......... 460,000 100,000 (180,000) (79,000) 3,200 1,100 3,400 (10,000) 

aAll costs in this table are relative to the baseline used for the 2008 final rule. 

We also estimate that the final 

requirements for flares will result in 

emissions reduction co-benefits of CO2

equivalents by 1,900,000 metric tonnes 

per year, predominantly as a result of 

our estimate of the largest flares 

employing flare gas recovery and to a 

lesser extent, as a result of the root 

cause analyses applicable to all flares. 

The cost, environmental and 

economic impacts for the final 

amendments to 40 CFR part 60, subpart 

Ja for process heaters are not expected 

to be different than those reported for 

the final June 2008 standards. We 

expect owners and operators to install 

the same technology to meet these final 

amendments that we anticipated they 

would install to meet the June 2008 

final subpart Ja requirements (i.e., ultralow NOX burners). We did revise our 

emission estimates based on the type of 

process heater, creating separate 

impacts for forced draft process heaters 

and natural draft process heaters. 

Dividing process heaters into separate 

subcategories, based on the draft type, 

required us to develop new 

distributions of baseline emissions for 

each type of process heater. The 

baseline emission estimates for natural 

draft process heaters are slightly lower 

than those developed for the existing 

subpart Ja requirements (per affected 

process heater), but the average 

emission reduction achieved by ultralow NOX burners was adjusted to 80 

percent (rather than 75 percent used for 

generic process heaters). For forced draft 

process heaters, the baseline (i.e., 

uncontrolled) emissions rate for forced 

draft process heaters was revised 

slightly upward, based on the available 

emissions data. Due to these differences, 

the mix of controls needed to meet a 40 

ppmv emissions limit was no longer 

cost effective for forced draft process 

heaters, but the emission reductions 

associated with process heaters 

complying with the 60 ppmv standard 

were higher than those previously 

estimated for generic process heaters. 

Thus, the creation of new subcategories 

of process heaters with different 

emissions limits for each subcategory 

did not impact the control or 

compliance methods used by the 

facilities (i.e., BSER in all cases was 

based on the performance of advanced 

combustion monitoring controls in 

conjunction with ultra-low NOX

burners) and did not change the 

estimated compliance costs. As we do 

not have adequate data regarding the 

prevalence of natural draft process 

heaters versus forced draft process 

heaters that will become subject to the 

rule, we used the emission reductions 

estimated for the two different types of 

process heaters as a means to bound the 

range of anticipated NOX emission 

reductions to be from 7,100 to 8,600 

tons/yr in the fifth year after the 

effective date of this final rule (see 

Revised NOX Impact Estimates for 

Process Heaters, in Docket ID No. EPA– 

HQ–OAR–2007–0011). We estimated 

the emission reductions to be 7,500 

tons/yr for the June 2008 final 

standards, which falls well within the 

anticipated range of emissions 

reductions for the standards we are 

finalizing here. Given the uncertainty in 

the emissions estimates, as well as the 

uncertainty in the relative number of 

natural draft process heaters versus 

forced draft process heaters, we 

concluded that the impacts previously 

developed for subpart Ja accurately 

represent the impacts for process 

heaters in these final amendments. 

We note that, in the preamble to the 

June 2008 final standards, we estimated 

costs and emissions reductions for 30 

fuel gas combustion devices, but we 

subsequently determined that those 

estimates did not fully account for the 

number of affected flares (which, at the 

time, were considered a subset of fuel 

gas combustion devices). Therefore, in 

the preamble to the December 2008 

proposed amendments, we presented 

revised emission reduction and cost 

estimates for affected fuel gas 

combustion devices. As previously 

explained, we are not finalizing the 

long-term 60 ppmv H2S fuel gas 

concentration limit for flares, as 

proposed, and we revised our cost 

estimates accordingly. Because these 

final amendments consider flares to be 

a separate affected source, the emission 

reductions and costs for fuel gas 

combustion devices are not affected by 

these final amendments and are not 

included in this preamble. Rather, the 

final emission reduction and cost 

estimates for fuel gas combustion 

devices are very close to the impacts 

presented in the June 2008 final rule; 

the details of the analysis and the final 

impacts are presented in Documentation 

of Impact Estimates for Fuel Gas 

Combustion Device and Flare 

Regulatory Options for Amendments to 

the Petroleum Refinery NSPS, in Docket 

ID No. EPA–HQ–OAR–2007–0011. 

The final amendments to 40 CFR part 

60, subpart J are technical corrections or 

clarifications to the existing rule and 

should have no negative emissions 

impacts. 

B. What are the economic impacts? 

The total annualized compliance costs 

are estimated to save about $79 million 

(2006 dollars) in the fifth year after the 

effective date of these final 

amendments. Note that not all refiners 

will realize a cost savings as only flare 

systems with high waste gas flows 

(about 10 percent of all flares) are 

expected to install vapor recovery 

systems. Alternatively, if no refineries 

install flare gas recovery systems, total 

annualized compliance costs are 

estimated to be $10.7 million (2006 

dollars) in the fifth year after proposal. 

Regardless of whether any refineries 

install flare gas recovery systems, we do 

not anticipate any adverse economic 

impacts associated with this regulatory 

action, as no increase in refined 

petroleum product prices or decrease in 

refined petroleum product output is 

expected. 

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56456 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

12Roman, et al., 2008. Expert Judgment 

Assessment of the Mortality Impact of Changes in 

Ambient Fine Particulate Matter in the U.S., 

Environ. Sci. Technol., 42, 7, 2268—2274. 

13Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. The 

Influence of Location, Source, and Emission Type 

in Estimates of the Human Health Benefits of 

Reducing a Ton of Air Pollution. Air Qual Atmos 

Health (2009) 2:169–176. 

For more information, please refer to 

the Regulatory Impact Analysis (RIA) 

that is in the docket for this final rule. 

C. What are the benefits? 

Emission controls installed to meet 

the requirements of this rule will 

generate benefits by reducing emissions 

of criteria pollutants and their 

precursors, including SO2, NOX and 

VOC as well as CO2. SO2, NOX and VOC 

are precursors to PM2.5 (particles smaller 

than 2.5 microns), and NOX and VOC 

are precursors to ozone. For this rule, 

we were only able to quantify the health 

benefits associated with reduced 

exposure to PM2.5 from emission 

reductions of SO2 and NOX and the 

climate benefits associated with CO2

emission reductions. We estimate the 

monetized benefits of this final 

regulatory action to be $270 million to 

$580 million (2006 dollars, 3-percent 

discount rate) in the fifth year (2017). 

The benefits at a 7-percent discount rate 

for health benefits and 3-percent 

discount rate for climate benefits are 

$240 million to $530 million (2006 

dollars). For small flares only, we 

estimate the monetized benefits are 

$170 million to $410 million (3-percent 

discount rate) and $150 million to $370 

million (7-percent discount rate for 

health benefits and 3-percent discount 

rate for climate benefits). For large flares 

only, we estimate the monetized 

benefits are $93 million to $160 million 

(3-percent discount rate) and $88 

million to $150 million (7-percent 

discount rate for health benefits and 3- 

percent discount rate for climate 

benefits). Using alternate relationships 

between PM2.5 and premature mortality 

supplied by experts, higher and lower 

benefits estimates are plausible, but 

most of the expert-based estimates fall 

between these two estimates.12 A 

summary of the monetized benefits 

estimates by pollutant for all flares at 

discount rates of 3 percent and 7 

percent is in Table 6 of this preamble. 

Several benefits categories, including 

direct exposure to SO2 and NOX

benefits, ozone benefits, ecosystem 

benefits and visibility benefits are not 

included in these monetized benefits. 

All estimates are in 2006 dollars for the 

year 2017. 

TABLE 6—SUMMARY OF THE MONETIZED PM2.5 AND CO2 BENEFITS FOR AMENDED PETROLEUM REFINERIES STANDARDS

[Millions of 2006 dollars] a

Pollutant Emission reductions (tons per 

year) 

Total monetized 

benefits 

(3-percent discount) 

Total monetized 

benefits 

(7-percent discount) 

With Flare Gas Recovery 

PM2.5 Benefitsb: 

SO2 ......................................... 3,200 ............................................. $210 to $510 ................................ $190 to $460. 

NOX ........................................ 1,100 ............................................. $7.1 to $18 ................................... $6.4 to $16. 

PM Total ................................. ....................................................... $220 to $530 ................................ $190 to $480. 

CO2 Benefitsc .......................... 1,900,000d .................................... $46 ................................................ $46. 

Total Monetized Benefits: ....................................................... $260 to $580 ................................ $240 to $520. 

Without Flare Gas Recovery 

PM2.5 Benefitsb: 

SO2 ......................................... 2,900 ............................................. $190 to $450 ................................ $170 to $410. 

NOX ........................................ 56 .................................................. $0.36 to $0.87 .............................. $0.32 to $0.78. 

PM Total ................................. ....................................................... $190 to $460 ................................ $170 to $410. 

CO2 Benefitsc .......................... 110,000d ....................................... $2.6 ............................................... $2.6. 

Total Monetized Benefits ....................................................... $190 to $460 ................................ $170 to $410. 

aAll estimates are for the analysis year (2017) and are rounded to two significant figures so numbers may not sum across rows. The total 

monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5 precursors, such as 

NOX and SO2, as well as CO2. It is important to note that the monetized benefits do not include reduced health effects from direct exposure to 

SO2 and NOX, ozone exposure, ecosystem effects or visibility impairment. bPM benefits are shown as a range from Pope, et al. (2002) to Laden, et al. (2006). These models assume that all fine particles, regardless of 

their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effects estimates by particle type. cThe CO2 emission reductions (shown in metric tonnes) have been reduced to reflect the anticipated emission increases associated with the 

energy disbenefits. CO2-related benefits were calculated using the social cost of carbon (SCC), which is discussed further in the RIA. The net 

present value of reduced CO2 emissions is calculated differently than other benefits. This table shows monetized climate benefits using the global average SCC estimate at a 3-percent discount rate because the interagency workgroup deemed the SCC at a 3-percent discount rate to be 

the central value. In the RIA, we also provide the monetized CO2 benefits using discount rates of 5 percent (average), 2.5 percent (average) and 

3 percent (95th percentile). d Metric tonnes 

These benefits estimates represent the 

total monetized human health benefits 

for populations exposed to less PM2.5 in 

2017 from controls installed to reduce 

air pollutants in order to meet this rule. 

To estimate human health benefits of 

this rule, the EPA used benefit-per-ton 

factors to quantify the changes in PM2.5- 

related health impacts and monetized 

benefits based on changes in SO2 and 

NOX emissions. These benefit-per-ton 

factors were derived using the general 

approach and methodology laid out in 

Fann, Fulcher, and Hubbell (2009).13

This approach uses a model to convert 

emissions of PM2.5 precursors into 

changes in ambient PM2.5 levels and 

another model to estimate the changes 

in human health associated with that 

change in air quality, which are then 

divided by the emission reductions to 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56457 

14U.S. Environmental Protection Agency. 2011. 

Technical Support Document: Estimating the 

Benefit per Ton of Reducing PM2.5 Precursors from 

the Petroleum Refineries Sector. EPA, Research 

Triangle Park, NC. 

15Pope, et al., 2002. Lung Cancer, 

Cardiopulmonary Mortality, and Long-term 

Exposure to Fine Particulate Air Pollution. Journal 

of the American Medical Association 287:1132– 

1141. 

16Laden, et al., 2006. Reduction in Fine 

Particulate Air Pollution and Mortality. American 

Journal of Respiratory and Critical Care Medicine 

173: 667–672. 

17U.S. Environmental Protection Agency, 2006. 

Final Regulatory Impact Analysis: PM2.5 NAAQS. 

Prepared by Office of Air and Radiation. October. 

Available on the Internet at http://www.epa.gov/ttn/ 

ecas/ria.html. 

create the benefit-per-ton estimates. 

However, for this rule, we use air 

quality modeling data specific to the 

petroleum refineries sector.14 The 

primary difference between the 

estimates used in this analysis and the 

estimates reported in Fann, Fulcher, and 

Hubbell (2009) is the air quality 

modeling data utilized. While the air 

quality data used in Fann, Fulcher, and 

Hubbell (2009) reflects broad pollutant/ 

source category combinations, such as 

all non-electric generating unit 

stationary point sources, the air quality 

modeling data used in this analysis is 

sector-specific. In addition, the updated 

air quality modeling data reflects more 

recent emissions data (2005 rather than 

2001) and has a higher spatial resolution 

(12 kilometers (km) rather than 36 km 

grid cells). As a result, the benefit-perton estimates presented herein better 

reflect the geographic areas and 

populations likely to be affected by this 

sector. The benefits methodology, such 

as health endpoints assessed, risk 

estimates applied and valuation 

techniques applied did not change. 

However, these updated estimates still 

have similar limitations as all nationalaverage benefit-per-ton estimates in that 

they reflect the geographic distribution 

of the modeled emissions, which may 

not exactly match the emission 

reductions in this rulemaking, and they 

may not reflect local variability in 

population density, meteorology, 

exposure, baseline health incidence 

rates or other local factors for any 

specific location. 

We apply these national benefit-perton estimates calculated for this sector 

separately for SO2 and NOX and 

multiply them by the corresponding 

emission reductions. The sector-specific 

modeling does not provide estimates of 

the PM2.5-related benefits associated 

with reducing VOC emissions, but these 

unquantified benefits are generally 

small compared to other PM2.5

precursors. More information regarding 

the derivation of the benefit-per-ton 

estimates for the petroleum refining 

sector is available in the technical 

support document, which is available in 

the docket. 

These models assume that all fine 

particles, regardless of their chemical 

composition, are equally potent in 

causing premature mortality because the 

scientific evidence is not yet sufficient 

to allow differentiation of effects 

estimates by particle type. The main 

PM2.5 precursors affected by this rule are 

SO2 and NOX. Even though we assume 

that all fine particles have equivalent 

health effects, the benefit-per-ton 

estimates vary between precursors 

depending on the location and 

magnitude of their impact on PM2.5

levels, which drive population 

exposure. For example, SO2 has a lower 

benefit-per-ton estimate than direct 

PM2.5 because it does not form as much 

PM2.5, thus, the exposure would be 

lower, and the monetized health 

benefits would be lower. 

It is important to note that the 

magnitude of the PM2.5 benefits is 

largely driven by the concentration 

response function for premature 

mortality. Experts have advised the EPA 

to consider a variety of assumptions, 

including estimates based both on 

empirical (epidemiological) studies and 

judgments elicited from scientific 

experts, to characterize the uncertainty 

in the relationship between PM2.5

concentrations and premature mortality. 

We cite two key empirical studies, one 

based on the American Cancer Society 

cohort study 15 and the extended Six 

Cities cohort study.16 In the RIA for this 

final rule, which is available in the 

docket, we also include benefits 

estimates derived from the expert 

judgments and other assumptions. 

The EPA strives to use the best 

available science to support our benefits 

analyses. We recognize that 

interpretation of the science regarding 

air pollution and health is dynamic and 

evolving. After reviewing the scientific 

literature, we have determined that the 

no-threshold model is the most 

appropriate model for assessing the 

mortality benefits associated with 

reducing PM2.5 exposure. Consistent 

with this finding, we have conformed 

the previous threshold sensitivity 

analysis to the current state of the PM 

science by incorporating a new ‘‘Lowest 

Measured Level’’ (LML) assessment in 

the RIA accompanying this rule. While 

an LML assessment provides some 

insight into the level of uncertainty in 

the estimated PM mortality benefits, the 

EPA does not view the LML as a 

threshold and continues to quantify PMrelated mortality impacts using a full 

range of modeled air quality 

concentrations. 

Most of the estimated PM-related 

benefits in this rule would accrue to 

populations exposed to higher levels of 

PM2.5. For this analysis, policy-specific 

air quality data is not available due to 

time or resource limitations, thus, we 

are unable to estimate the percentage of 

premature mortality associated with this 

specific rule’s emission reductions at 

each PM2.5 level. As a surrogate measure 

of mortality impacts, we provide the 

percentage of the population exposed at 

each PM2.5 level using the source 

apportionment modeling used to 

calculate the benefit-per-ton estimates 

for this sector. Using the Pope, et al. 

(2002) study, 77 percent of the 

population is exposed to annual mean 

PM2.5 levels at or above the LML of 7.5 

micrograms per cubic meter (mg/m3). 

Using the Laden, et al. (2006) study, 25 

percent of the population is exposed 

above the LML of 10 mg/m3. It is 

important to emphasize that we have 

high confidence in PM2.5-related effects 

down to the lowest LML of the major 

cohort studies. This fact is important, 

because, as we model avoided 

premature deaths among populations 

exposed to levels of PM2.5, we have 

lower confidence in levels below the 

LML for each study. 

Every benefit analysis examining the 

potential effects of a change in 

environmental protection requirements 

is limited, to some extent, by data gaps, 

model capabilities (such as geographic 

coverage) and uncertainties in the 

underlying scientific and economic 

studies used to configure the benefit and 

cost models. Despite these uncertainties, 

we believe the benefit analysis for this 

rule provides a reasonable indication of 

the expected health benefits of the 

rulemaking under a set of reasonable 

assumptions. This analysis does not 

include the type of detailed uncertainty 

assessment found in the 2006 PM2.5

NAAQS RIA because we lack the 

necessary air quality input and 

monitoring data to run the benefits 

model. In addition, we have not 

conducted air quality modeling for this 

rule, and using a benefit-per-ton 

approach adds another important source 

of uncertainty to the benefits estimates. 

The 2006 PM2.5 NAAQS benefits 

analysis 17 provides an indication of the 

sensitivity of our results to various 

assumptions. 

This rule is expected to reduce CO2

emissions from the electricity sector. 

The EPA has assigned a dollar value to 

reductions in CO2 emissions using 

recent estimates of the ‘‘social cost of 

carbon’’ (SCC). The SCC is an estimate 

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56458 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

18 Docket ID EPA–HQ–OAR–2009–0472–114577, 

Technical Support Document: Social Cost of 

Carbon for Regulatory Impact Analysis Under 

Executive Order 12866, Interagency Working Group 

on Social Cost of Carbon, with participation by 

Council of Economic Advisers, Council on 

Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, 

Department of Transportation, Environmental 

Protection Agency, National Economic Council, 

Office of Energy and Climate Change, Office of 

Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury 

(February 2010). Also available at http://epa.gov/ 

otaq/climate/regulations.htm. 

of the monetized damages associated 

with an incremental increase in carbon 

emissions in a given year or the per 

metric ton benefit estimate relating to 

decreases in CO2 emissions. It is 

intended to include (but is not limited 

to) changes in net agricultural 

productivity, human health, property 

damage from increased flood risk, and 

the value of ecosystem services due to 

climate change. 

The SCC estimates used in this 

analysis were developed through an 

interagency process that included the 

EPA and other executive branch 

entities, and that concluded in February 

2010. We first used these SCC estimates 

in the benefits analysis for the final joint 

EPA/DOT Rulemaking to establish 

Light-Duty Vehicle Greenhouse Gas 

Emission Standards and Corporate 

Average Fuel Economy Standards; see 

the rule’s preamble for discussion about 

application of the SCC (75 FR 25324; 

May 7, 2010). The SCC Technical 

Support Document (SCC TSD) provides 

a complete discussion of the methods 

used to develop these SCC estimates.18

The interagency group selected four 

SCC values for use in regulatory 

analyses, which we have applied in this 

analysis: $5.9, $24.3, $39, and $74.4 per 

metric ton of CO2 emissions in 2016, in 

2007 dollars. The first three values are 

based on the average SCC from three 

integrated assessment models, at 

discount rates of 5, 3 and 2.5 percent, 

respectively. Social cost of carbon 

values at several discount rates are 

included because the literature shows 

that the SCC is quite sensitive to 

assumptions about the discount rate, 

and because no consensus exists on the 

appropriate rate to use in an 

intergenerational context. The fourth 

value is the 95th percentile of the SCC 

from all three values at a 3-percent 

discount rate. It is included to represent 

higher-than-expected impacts from 

temperature change further out in the 

extremes of the SCC distribution. Low 

probability, high impact events are 

incorporated into all of the SCC values 

through explicit consideration of their 

effects in two of the three values as well 

as the use of a probability density 

function for equilibrium climate 

sensitivity. Treating climate sensitivity 

probabilistically results in more high 

temperature outcomes, which in turn 

leads to higher projections of damages. 

Applying the global SCC estimates 

using a 3-percent discount rate, we 

estimate the value of the climate related 

benefits of this rule in 2017 is $49 

million (2006$), as shown in Table 6. 

See the RIA for more detail on the 

methodology used to calculate these 

benefits and additional estimates of 

climate benefits using different discount 

rates and the 95th percentile of the 3- 

percent discount rate SCC. Important 

limitations and uncertainties of the SCC 

approach are also described in the RIA. 

It should be noted that the monetized 

benefits estimates provided above do 

not include benefits from several 

important benefit categories, including 

direct exposure to SO2 and NOX, ozone 

exposure, ecosystem effects and 

visibility impairment. Although we do 

not have sufficient information or 

modeling available to provide 

monetized estimates for this 

rulemaking, we include a qualitative 

assessment of these unquantified 

benefits in the RIA for this final rule. 

Although this final rule provides 

refiners with some additional 

compliance options and removes some 

requirements, such as the long-term H2S 

limit for flares, these are non-monetized 

benefits of the rule. 

For more information on the benefits 

analysis, please refer to the RIA for this 

rulemaking, which is available in the 

docket. 

VI. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

Under section 3(f)(1) of Executive 

Order 12866 (58 FR 51735, October 4, 

1993), this action is an ‘‘economically 

significant regulatory action’’ because it 

is likely to have an annual effect on the 

economy of $100 million or more. 

Accordingly, the EPA submitted this 

action to the Office of Management and 

Budget (OMB) for review under 

Executive Order 12866 and Executive 

Order 13563 (76 FR 3821, January 21, 

2011), and any changes made in 

response to OMB recommendations 

have been documented in the docket for 

this action. In addition, the EPA 

prepared a RIA of the potential costs 

and benefits associated with this action. 

A summary of the monetized benefits, 

compliance costs and net benefits for 

the final rule at discount rates of 3 

percent and 7 percent is in Table 7 of 

this preamble. 

TABLE 7—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS AND NET BENEFITS FOR THE FINAL PETROLEUM

REFINERIES NSPS IN 2017 

[Millions of 2006 dollars] a

3-Percent discount rate 7-Percent discount rate 

Total Monetized Benefits b .................................. $270 to $580 .................................................... $240 to $530. 

Total Compliance Costs c ................................... ¥$79 ................................................................ ¥$79. 

Net Benefits ........................................................ $340 to $660 .................................................... $320 to $610. 

Non-Monetized Benefits ..................................... Health effects from direct exposure to SO2 and NO2. 

Health effects from PM2.5 exposure from VOC 

Ecosystem effects. 

Visibility impairment. 

aAll estimates are for the implementation year (2017) and are rounded to two significant figures. 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56459 

bThe total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5 precursors such as NOX and SO2, as well as CO2 benefits. It is important to note that the monetized benefits do not include the reduced health effects from direct exposure to SO2 and NOX, ozone exposure, ecosystem effects or visibility impairment. Human health benefits are shown as a 

range from Pope, et al. (2002) to Laden, et al. (2006). These models assume that all fine particles, regardless of their chemical composition, are 

equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effects estimates by 

particle type. The net present value of reduced CO2 emissions is calculated differently than other benefits. This table includes monetized climate 

benefits using the global average social cost of carbon (SCC) estimated at a 3-percent discount rate because the interagency work group 

deemed the SCC estimate at a 3-percent discount rate to be the central value. cThe engineering compliance costs are annualized using a 7-percent discount rate. 

To support the determination of BSER 

for the June 24, 2008, final rule, we 

considered a number of regulatory 

options and their costs and benefits. 

Those results are presented in the RIA 

for the June 24, 2008, final rulemaking, 

which is available in the docket. These 

final rule amendments are in response 

to comments received on the December 

22, 2008, proposed rule amendments. 

Costs and benefits associated with the 

amendments in this final rule differ 

from the June 24, 2008, final rule and 

the December 22, 2008, proposed rule 

amendments primarily as a result of 

correcting the number of flares projected 

to have to comply with this rule (i.e., 

400 affected flares in this rule compared 

to 40 estimated in the June 24, 2008, 

final rule and 150 in the December 22, 

2008, proposed amendments). In 

addition, the amendments in this final 

rule to address comments received for 

the other fuel gas combustion devices 

do not affect the projected costs and 

benefits from the December 22, 2008, 

proposal, which also did not change 

from the June 24, 2008, final rule. 

Therefore, for purposes of developing 

these final rule amendments, we did not 

re-evaluate the suite of regulatory 

options for flares and other fuel gas 

combustion devices considered to 

support the June 24, 2008, final rule. 

However, even with the flare count 

adjustment, this final rule is consistent 

with Executive Order 13563 (Improving 

Regulation and Regulatory Review) 

because the monetized benefits of this 

final rule exceed the costs. In addition, 

for facilities implementing flare gas 

recovery, we are reducing regulatory 

burden by finalizing provisions that 

would allow the owner or operator to 

reduce monitoring costs and the number 

of root cause analyses, corrective actions 

and corresponding recordkeeping and 

reporting they would need to perform. 

For more information on the costbenefits analysis, please refer to the RIA 

for this rulemaking, which is available 

in the docket. 

B. Paperwork Reduction Act 

The final amendments to the 

Standards of Performance for Petroleum 

Refineries (40 CFR part 60, subpart J) do 

not impose any new information 

collection burden. The final 

amendments are clarifications and 

technical corrections that do not affect 

the estimated burden of the existing 

rule. Therefore, we have not revised the 

ICR for the existing rule. However, OMB 

has previously approved the 

information collection requirements 

contained in the existing rule (40 CFR 

part 60, subpart J) under the provisions 

of the Paperwork Reduction Act, 44 

U.S.C. 3501, et seq., and has assigned 

OMB control number 2060–0022. The 

OMB control numbers for the EPA’s 

regulations are listed in 40 CFR part 9. 

The OMB has approved the 

information collection requirements in 

the amendments to the Standards of 

Performance for Petroleum Refineries 

for Which Construction, Reconstruction, 

or Modification Commenced After May 

14, 2007 (40 CFR part 60, subpart Ja) 

under the provisions of the Paperwork 

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

and has assigned OMB control number 

2060–0602. 

The information requirements in 

these final amendments add new 

compliance options, provide more time 

to comply with the requirements for 

flares, clarify the flare management plan 

requirements and clarify the flare 

modification provision. Overall, these 

changes are expected to reduce the costs 

associated with testing, monitoring, 

recording and reporting, so they will not 

result in any increase in burden for the 

affected facilities for which the EPA 

previously estimated the burden. 

However, the EPA has revised the 

number of flares expected to become 

subject to the rule over the first 3 years 

of the ICR. Therefore, the annual burden 

was estimated for the additional affected 

facilities. The total burden for 40 CFR 

part 60, subpart Ja can be estimated by 

summing the previously approved 

annual burden for OMB control number 

2060–0602 (5,340 labor-hours per year 

at a cost of $481,249 per year, 

annualized capital costs of $2,052,000 

per year, and operation and 

maintenance costs of $1,117,440 per 

year) and the annual burden for this 

ICR, as described below. 

The annual burden for this 

information collection averaged over the 

first 3 years of this ICR is estimated to 

total 54,572 labor-hours per year at a 

cost of $4,918,110 per year. The 

annualized capital costs are estimated at 

$11,266,000 per year and operation and 

maintenance costs are estimated at 

$8,750,000 per year. We note that the 

capital costs, as well as the operation 

and maintenance costs, are for the 

continuous monitors; these costs are 

also included in the cost impacts 

presented in section V.A of this 

preamble. Therefore, the burden costs 

associated with the continuous monitors 

presented in the ICR are not additional 

costs incurred by affected sources 

subject to final 40 CFR part 60, subpart 

Ja. Burden is defined at 5 CFR 1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for the EPA’s regulations are 

listed in 40 CFR part 9. The EPA is 

amending the table in 40 CFR part 9 of 

currently approved ICR control numbers 

for various regulations to list regulatory 

citations for the information 

requirements contained in this final 

rule. This amendment updates the table 

to list the information collection 

requirements being promulgated here as 

amendments to the NSPS for petroleum 

refineries. 

The EPA will continue to present 

OMB control numbers in a consolidated 

table format to be codified in 40 CFR 

part 9 of the agency’s regulations and in 

each CFR volume containing the EPA 

regulations. The table lists the section 

numbers with reporting and 

recordkeeping requirements and the 

current OMB control numbers. This 

listing of the OMB control numbers and 

their subsequent codification in the CFR 

satisfy the requirements of the 

Paperwork Reduction Act (44 U.S.C. 

3501, et seq.) and OMB’s implementing 

regulations at 5 CFR part 1320. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule would not have a 

significant economic impact on a 

substantial number of small entities. 

Small entities include small businesses, 

small organizations and small 

governmental jurisdictions. 

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56460 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

For purposes of assessing the impact 

of this final action on small entities, 

small entity is defined as: (1) A small 

business whose parent company has no 

more than 1,500 employees, that is 

primarily engaged in refining crude 

petroleum into refined petroleum as 

defined by NAICS code 32411 (as 

defined by Small Business 

Administration size standards); (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

While we estimated the natural gas 

recovery offsets or credit at a national 

level and believe that larger firms are 

more likely to offset natural gas 

purchases, the revenues from natural 

gas recovery offsets might mask 

disproportionate impacts on small 

refiners. To better identify 

disproportionate impacts, we examined 

the potential impacts on refiners based 

on a scenario where no firms adopt flare 

gas recovery systems and comply with 

the NSPS through flare monitoring and 

flare management and root cause 

analysis actions. The incremental 

compliance costs imposed on small 

refineries are not estimated to create 

significant impacts on a cost-to-sales 

ratio basis at the firm level. Therefore, 

no adverse economic impacts are 

expected for any small or large entity. 

After considering the economic 

impacts of these final amendments on 

small entities, I certify that this action 

will not have a significant economic 

impact on a substantial number of small 

entities. The small entities directly 

regulated by these final amendments are 

small petroleum refineries. We have 

determined that 31 small refiners, or 55 

percent of total refiners, will experience 

an impact of between less than 0.01 

percent up to 0.63 percent of revenues. 

D. Unfunded Mandates Reform Act 

This rule does not contain a federal 

mandate that may result in expenditures 

of $100 million or more for state, local 

and tribal governments, in the aggregate, 

or the private sector in any one year. 

The costs of the final amendments 

would not increase costs associated 

with the final rule. Thus, this rule is not 

subject to the requirements of sections 

202 or 205 of the UMRA. 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. The 

final amendments contain no 

requirements that apply to such 

governments and impose no obligations 

upon them. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This action does 

not modify existing responsibilities or 

create new responsibilities among EPA 

Regional offices, states or local 

enforcement agencies. Thus, Executive 

Order 13132 does not apply to this 

action. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). The final amendments impose no 

requirements on tribal governments. 

Thus, Executive Order 13175 does not 

apply to this action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

The EPA interprets Executive Order 

13045 (62 FR 19885, April 23, 1997) as 

applying to those regulatory actions that 

concern health or safety risks, such that 

the analysis required under section 5– 

501 of the Executive Order has the 

potential to influence the regulation. 

This action is not subject to Executive 

Order 13045 because it is based solely 

on technology performance. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a ‘‘significant 

energy action’’ as defined in Executive 

Order 13211 (66 FR 28355, May 22, 

2001), because it is not likely to have a 

significant adverse effect on the supply, 

distribution or use of energy. The final 

amendments would not increase the 

level of energy consumption required 

for the final rule and may decrease 

energy requirements. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

113, 12(d) (15 U.S.C. 272 note) directs 

the EPA to use voluntary consensus 

standards (VCS) in its regulatory 

activities, unless to do so would be 

inconsistent with applicable law or 

otherwise impractical. VCS are 

technical standards (e.g., materials 

specifications, test methods, sampling 

procedures and business practices) that 

are developed or adopted by VCS 

bodies. NTTAA directs the EPA to 

provide Congress, through OMB, 

explanations when the agency decides 

not to use available and applicable VCS. 

This rulemaking involves technical 

standards. The EPA has decided to use 

the following VCS for determining the 

higher heating value of fuel fed to 

process heaters: ASTM D240–02 

(Reapproved 2007), Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter; ASTM D1826–94 

(Reapproved 2003), Standard Test 

Method for Calorific (Heating) Value of 

Gases in Natural Gas Range by 

Continuous Recording Calorimeter; 

ASTM D3588–98 (Reapproved 2003), 

Standard Practice for Calculating Heat 

Value, Compressibility Factor, and 

Relative Density of Gaseous Fuels; 

ASTM D4809–06, Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (Precision Method); ASTM 

D4891–89 (Reapproved 2006), Standard 

Test Method for Heating Value of Gases 

in Natural Gas Range by Stoichiometric 

Combustion; ASTM D1945–03 

(Reapproved 2010), Standard Method 

for Analysis of Natural Gas by Gas 

Chromatography; and ASTM D1946–90 

(Reapproved 2006), Standard Method 

for Analysis of Reformed Gas by Gas 

Chromatography. 

The EPA has decided to use the 

following VCS as acceptable alternatives 

to EPA Methods 2, 2A, 2B, 2C or 2D for 

conducting relative accuracy 

evaluations of fuel gas flow monitors: 

American Society of Mechanical 

Engineers (ASME) MFC–3M–2004, 

Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi; 

ANSI/ASME MFC–4M–1986 

(Reaffirmed 2008), Measurement of Gas 

Flow by Turbine Meters; ASME MFC– 

6M–1998 (Reaffirmed 2005), 

Measurement of Fluid Flow in Pipes 

Using Vortex Flowmeters; ASME/ANSI 

MFC–7M–1987 (Reaffirmed 2006), 

Measurement of Gas Flow by Means of 

Critical Flow Venturi Nozzles; ASME 

MFC–11M–2006, Measurement of Fluid 

Flow by Means of Coriolis Mass 

Flowmeters; ASME MFC–14M–2003, 

Measurement of Fluid Flow Using Small 

Bore Precision Orifice Meters; and 

ASME MFC–18M–2001, Measurement 

of Fluid Flow Using Variable Area 

Meters. 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56461 

The EPA has also decided to use the 

following VCS as acceptable alternatives 

to EPA Methods 2, 2A, 2B, 2C or 2D for 

conducting relative accuracy 

evaluations of fuel oil flow monitors: 

ANSI/ASME MFC–5M–1985 

(Reaffirmed 2006), Measurement of 

Liquid Flow in Closed Conduits Using 

Transit-Time Ultrasonic Flowmeters; 

ASME/ANSI MFC–9M–1988 

(Reaffirmed 2006), Measurement of 

Liquid Flow in Closed Conduits by 

Weighing Method; ASME MFC–16– 

2007, Measurement of Liquid Flow in 

Closed Conduits with Electromagnetic 

Flowmeters; ASME MFC–22–2007, 

Measurement of Liquid by Turbine 

Flowmeters; and ISO 8316: 

Measurement of Liquid Flow in Closed 

Conduits—Method by Collection of the 

Liquid in a Volumetric Tank (1987–10– 

01)—First Edition. 

The EPA has decided to use the 

following VCS as acceptable alternatives 

to EPA Method 15A and 16A for 

conducting relative accuracy 

evaluations of monitors for reduced 

sulfur compounds, total sulfur 

compounds, and H2S: ANSI/ASME PTC 

19.10–1981, Flue and Exhaust Gas 

Analyses. The EPA has decided to use 

the following VCS as acceptable 

alternatives to EPA Method 16A for 

analysis of total sulfur samples: ASTM 

D4468–85 (Reapproved 2006), Standard 

Test Method for Total Sulfur in Gaseous 

Fuels by Hydrogenolysis and 

Rateometric Colorimetry; and ASTM 

D5504–08, Standard Test Method for 

Determination of Sulfur Compounds in 

Natural Gas and Gaseous Fuels by Gas 

Chromatography and 

Chemiluminescence. 

The EPA has decided to use the 

following VCS as acceptable alternatives 

to EPA Method 18 for relative accuracy 

evaluations of gas composition 

analyzers for gas-fired process heaters: 

ASTM D1945–03 (Reapproved 2010), 

Standard Method for Analysis of 

Natural Gas by Gas Chromatography; 

ASTM D1946–90 (Reapproved 2006), 

Standard Method for Analysis of 

Reformed Gas by Gas Chromatography; 

ASTM UOP539–97, Refinery Gas 

Analysis by Gas Chromatography; and 

ASTM D6420–99 (Reapproved 2004), 

Standard Test Method for 

Determination of Gaseous Organic 

Compounds by Direct Interface Gas 

Chromatography-Mass Spectrometry. 

However, ASTM D6420–99 is a suitable 

alternative to EPA Method 18 only 

where: 

(1) The target compound(s) are those 

listed in Section 1.1 of ASTM D6420– 

99, and 

(2) The target concentration is 

between 150 parts per billion by volume 

and 100 ppmv. 

For target compound(s) not listed in 

Section 1.1 of ASTM D6420–99, but 

potentially detected by mass 

spectrometry, the regulation specifies 

that the additional system continuing 

calibration check after each run, as 

detailed in Section 10.5.3 of the ASTM 

method, must be followed, met, 

documented and submitted with the 

data report even if there is no moisture 

condenser used or the compound is not 

considered water soluble. For target 

compound(s) not listed in Section 1.1 of 

ASTM D6420–99 and not amenable to 

detection by mass spectrometry, ASTM 

D6420–99 does not apply. 

These above-listed VCS are 

incorporated by reference (see 40 CFR 

60.17). 

The EPA has also decided to use 

American Gas Association Report No. 3: 

Orifice Metering for Natural Gas and 

Other Related Hydrocarbon Fluids, Part 

1: General Equations and Uncertainty 

Guidelines (1990), American Gas 

Association Report No. 3: Orifice 

Metering for Natural Gas and Other 

Related Hydrocarbon Fluids, Part 2: 

Specification and Installation 

Requirements (2000), American Gas 

Association Report No. 11: 

Measurement of Natural Gas by Coriolis 

Meter (2003), American Gas Association 

Transmission Measurement Committee 

Report No. 7, Measurement of Natural 

Gas by Turbine Meters (Revised 

February 2006) and API’s Manual of 

Petroleum Measurement Standards, 

Chapter 22—Testing Protocol, Section 

2—Differential Pressure Flow 

Measurement Devices, First Edition, 

August 2005, for conducting relative 

accuracy evaluations of fuel gas flow 

monitors; Gas Processors Association 

(GPA) Standard 2261–00, Analysis for 

Natural Gas and Similar Gaseous 

Mixtures by Gas Chromatography 

(2000), for relative accuracy evaluations 

of gas composition analyzers for gasfired process heaters; and GPA 2172–09, 

Calculation of Gross Heating Value, 

Relative Density, Compressibility and 

Theoretical Hydrocarbon Liquid Content 

for Natural Gas Mixtures for Custody 

Transfer, for determining the higher 

heating value of fuel fed to process 

heaters. These methods are also 

incorporated by reference (see 40 CFR 

60.17). 

While the agency has identified five 

VCS as being potentially applicable to 

this rule, we have decided not to use 

these VCS in this rulemaking. The use 

of these VCS would be impractical 

because they do not meet the objectives 

of the standards cited in this rule. See 

the docket for this rule for the reasons 

for these determinations. 

Under 40 CFR 60.13(i) of the NSPS 

General Provisions, a source may apply 

to the EPA for permission to use 

alternative test methods or alternative 

monitoring requirements in place of any 

required testing methods, performance 

specifications or procedures in the final 

rule and amendments. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies and activities on minority 

populations and low-income 

populations in the United States. 

The EPA has determined that this 

final rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it does not affect the level of 

protection provided to human health or 

the environment. The final amendments 

are either clarifications or compliance 

alternatives which will neither increase 

or decrease environmental protection. 

K. Congressional Review Act 

The Congressional Review Act, 5 

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

Small Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of 

Congress and to the Comptroller General 

of the United States. The EPA will 

submit a report containing these final 

rules and other required information to 

the United States Senate, the United 

States House of Representatives and the 

Comptroller General of the United 

States prior to publication of the final 

rules in the Federal Register. A major 

rule cannot take effect until 60 days 

after it is published in the Federal 

Register. This action is a ‘‘major rule’’ 

as defined by 5 U.S.C. 804(2). This final 

rule will be effective on November 13, 

2012. 

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56462 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

List of Subjects 

40 CFR Part 9 

Environmental protection, Reporting 

and recordkeeping requirements. 

40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Incorporation by 

reference, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 

Dated: June 1, 2012. 

Lisa P. Jackson, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, of the Code 

of Federal Regulations is amended as 

follows: 

PART 9—[AMENDED] 

■ 1. The authority citation for part 9 

continues to read as follows: 

Authority: 7 U.S.C. 135, et seq., 136–136y; 

15 U.S.C. 2001, 2003, 2005, 2006, 2601–2671; 

21 U.S.C. 331j, 346a, 348; 31 U.S.C. 9701; 33 

U.S.C. 1251, et seq., 1311, 1313d, 1314, 1318, 

1321, 1326, 1330, 1342, 1344, 1345(d) and 

(e), 1361; E.O. 11735, 38 FR 21243, 3 CFR, 

1971–1975 Comp. p. 973; 42 U.S.C. 241, 

242b, 243, 246, 300f, 300g, 300g–1, 300g–2, 

300g–3, 300g–4, 300g–5, 300g–6, 300j–1, 

300j–2, 300j–3, 300j–4, 300j–9, 1857, et seq., 

6901–6992k, 7401–7671q, 7542, 9601–9657, 

11023, 11048. 

■ 2. The table in Section 9.1 is amended 

by adding an entry in numerical order 

for 60.103a–60.108a under the heading 

‘‘Standards of Performance for New 

Stationary Sources’’ to read as follows: 

§ 9.1 OMB Approvals under the Paperwork 

Reduction Act. 

* * * * * 

40 CFR citation OMB control 

No. 

* * * * * 

Standards of Performance for New 

Stationary Sources 1

* * * * * 

60.103a–60.108a .................. 2060–0602 

* * * * * 

1The ICRs referenced in this section of the 

table encompass the applicable general provisions contained in 40 CFR part 60, subpart A, 

which are not independent information collection requirements. 

* * * * * 

PART 60—[AMENDED] 

■ 3. The authority citation for part 60 

continues to read as follows: 

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

Subpart A—[AMENDED] 

■ 4. Section 60.17 is amended by: 

■ a. Revising paragraphs (a)(84), (a)(95), 

(a)(96), (a)(97), and (a)(98); 

■ b. Adding paragraphs (a)(100) through 

(a)(108); 

■ c. Adding paragraph (c)(2); 

■ d. Revising paragraph (h)(4) and 

adding paragraphs (h)(5) through 

(h)(15); 

■ e. Adding paragraphs (m)(2) and 

(m)(3); and 

■ f. Adding paragraphs (p) and (q) to 

read as follows: 

§ 60.17 Incorporations by reference. 

* * * * * 

(a) * * * 

(84) ASTM D6420–99 (Reapproved 

2004), Standard Test Method for 

Determination of Gaseous Organic 

Compounds by Direct Interface Gas 

Chromatography-Mass Spectrometry, 

(Approved October 1, 2004), IBR 

approved for § 60.107a(d) of subpart Ja 

and table 2 of subpart JJJJ of this part. 

* * * * * 

(95) ASTM D3588–98 (Reapproved 

2003), Standard Practice for Calculating 

Heat Value, Compressibility Factor, and 

Relative Density of Gaseous Fuels, 

(Approved May 10, 2003), IBR approved 

for §§ 60.107a(d) and 60.5413(d). 

(96) ASTM D4891–89 (Reapproved 

2006), Standard Test Method for 

Heating Value of Gases in Natural Gas 

Range by Stoichiometric Combustion, 

(Approved June 1, 2006), IBR approved 

for §§ 60.107a(d) and 60.5413(d). 

(97) ASTM D1945–03 (Reapproved 

2010), Standard Method for Analysis of 

Natural Gas by Gas Chromatography, 

(Approved January 1, 2010), IBR 

approved for §§ 60.107a(d) and 

60.5413(d). 

(98) ASTM D5504–08, Standard Test 

Method for Determination of Sulfur 

Compounds in Natural Gas and Gaseous 

Fuels by Gas Chromatography and 

Chemiluminescence, (Approved June 

15, 2008), IBR approved for 

§§ 60.107a(e) and 60.5413(d). 

* * * * * 

(100) ASTM D4468–85 (Reapproved 

2006), Standard Test Method for Total 

Sulfur in Gaseous Fuels by 

Hydrogenolysis and Rateometric 

Colorimetry (Approved June 1, 2006), 

IBR approved for § 60.107a(e). 

(101) ASTM D240–02 (Reapproved 

2007), Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon 

Fuels by Bomb Calorimeter, (Approved 

May 1, 2007), IBR approved for 

§ 60.107a(d). 

(102) ASTM D1826–94 (Reapproved 

2003), Standard Test Method for 

Calorific (Heating) Value of Gases in 

Natural Gas Range by Continuous 

Recording Calorimeter, (Approved May 

10, 2003), IBR approved for 

§ 60.107a(d). 

(103) ASTM D1946–90 (Reapproved 

2006), Standard Method for Analysis of 

Reformed Gas by Gas Chromatography, 

(Approved June 1, 2006), IBR approved 

for § 60.107a(d). 

(104) ASTM D4809–06, Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (Precision Method), 

(Approved December 1, 2006), IBR 

approved for § 60.107a(d). 

(105) ASTM UOP539–97, Refinery 

Gas Analysis by Gas Chromatography, 

(Copyright 1997), IBR approved for 

§ 60.107a(d). 

(106) ASTM D3699–08, Standard 

Specification for Kerosine, including 

Appendix X1, (Approved September 1, 

2008), IBR approved for §§ 60.41b of 

subpart Db and 60.41c of subpart Dc of 

this part. 

(107) ASTM D6751–11b, Standard 

Specification for Biodiesel Fuel Blend 

Stock (B100) for Middle Distillate Fuels, 

including Appendices X1 through X3, 

(Approved July 15, 2011), IBR approved 

for §§ 60.41b of subpart Db and 60.41c 

of subpart Dc of this part. 

(108) ASTM D7467–10, Standard 

Specification for Diesel Fuel Oil, 

Biodiesel Blend (B6 to B20), including 

Appendices X1 through X3, (Approved 

August 1, 2010), IBR approved for 

§§ 60.41b of subpart Db and 60.41c of 

subpart Dc of this part. 

* * * * * 

(c) * * * 

(2) American Petroleum Institute 

(API) Manual of Petroleum 

Measurement Standards, Chapter 22- 

Testing Protocol, Section 2-Differential 

Pressure Flow Measurement Devices, 

First Edition, August 2005, IBR 

approved for § 60.107a(d) of subpart Ja 

of this part. 

* * * * * 

(h) * * * 

(4) ANSI/ASME PTC 19.10–1981, 

Flue and Exhaust Gas Analyses [Part 10, 

Instruments and Apparatus], (Issued 

August 31, 1981), IBR approved for 

§ 60.56c(b), § 60.63(f), § 60.106(e), 

§ 60.104a(d), (h), (i), and (j), 

§ 60.105a(d), (f), and (g), § 60.106a(a), 

§ 60.107a(a), (c), and (e), tables 1 and 3 

of subpart EEEE, tables 2 and 4 of 

subpart FFFF, table 2 of subpart JJJJ, 

§§ 60.4415(a), 60.2145(s), 60.2145(t), 

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60.2710(s), 60.2710(t), 60.2710(w), 

60.2730(q), 60.4900(b), 60.5220(b), 

tables 1 and 2 to subpart LLLL, tables 2 

and 3 to subpart MMMM, §§ 60.5406(c) 

and 60.5413(b). 

(5) ASME MFC–3M–2004, 

Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi, IBR 

approved for § 60.107a(d) of subpart Ja 

of this part. 

(6) ANSI/ASME MFC–4M–1986 

(Reaffirmed 2008), Measurement of Gas 

Flow by Turbine Meters, IBR approved 

for § 60.107a(d) of subpart Ja of this part. 

(7) ANSI/ASME–MFC–5M–1985 

(Reaffirmed 2006), Measurement of 

Liquid Flow in Closed Conduits Using 

Transit-Time Ultrasonic Flowmeters, 

IBR approved for § 60.107a(d) of subpart 

Ja of this part. 

(8) ASME MFC–6M–1998 (Reaffirmed 

2005), Measurement of Fluid Flow in 

Pipes Using Vortex Flowmeters, IBR 

approved for § 60.107a(d) of subpart Ja 

of this part. 

(9) ASME/ANSI MFC–7M–1987 

(Reaffirmed 2006), Measurement of Gas 

Flow by Means of Critical Flow Venturi 

Nozzles, IBR approved for § 60.107a(d) 

of subpart Ja of this part. 

(10) ASME/ANSI MFC–9M–1988 

(Reaffirmed 2006), Measurement of 

Liquid Flow in Closed Conduits by 

Weighing Method, IBR approved for 

§ 60.107a(d) of subpart Ja of this part. 

(11) ASME MFC–11M–2006, 

Measurement of Fluid Flow by Means of 

Coriolis Mass Flowmeters, IBR 

approved for § 60.107a(d) of subpart Ja 

of this part. 

(12) ASME MFC–14M–2003, 

Measurement of Fluid Flow Using Small 

Bore Precision Orifice Meters, IBR 

approved for § 60.107a(d) of subpart Ja 

of this part. 

(13) ASME MFC–16–2007, 

Measurement of Liquid Flow in Closed 

Conduits with Electromagnetic 

Flowmeters, IBR approved for 

§ 60.107a(d) of subpart Ja of this part. 

(14) ASME MFC–18M–2001, 

Measurement of Fluid Flow Using 

Variable Area Meters, IBR approved for 

§ 60.107a(d) of subpart Ja of this part. 

(15) ASME MFC–22–2007, 

Measurement of Liquid by Turbine 

Flowmeters, IBR approved for 

§ 60.107a(d) of subpart Ja of this part. 

* * * * * 

(m) * * * 

(2) Gas Processors Association 

Standard 2172–09, Calculation of Gross 

Heating Value, Relative Density, 

Compressibility and Theoretical 

Hydrocarbon Liquid Content for Natural 

Gas Mixtures for Custody Transfer 

(2009), IBR approved for § 60.107a(d) of 

subpart Ja of this part. 

(3) Gas Processors Association 

Standard 2261–00, Analysis for Natural 

Gas and Similar Gaseous Mixtures by 

Gas Chromatography (2000), IBR 

approved for § 60.107a(d) of subpart Ja 

of this part. 

* * * * * 

(p) The following American Gas 

Association material is available for 

purchase from the following address: ILI 

Infodisk, 610 Winters Avenue, Paramus, 

New Jersey 07652: 

(1) American Gas Association Report 

No. 3: Orifice Metering for Natural Gas 

and Other Related Hydrocarbon Fluids, 

Part 1: General Equations and 

Uncertainty Guidelines (1990), IBR 

approved for § 60.107a(d) of subpart Ja 

of this part. 

(2) American Gas Association Report 

No. 3: Orifice Metering for Natural Gas 

and Other Related Hydrocarbon Fluids, 

Part 2: Specification and Installation 

Requirements (2000), IBR approved for 

§ 60.107a(d) of subpart Ja of this part. 

(3) American Gas Association Report 

No. 11: Measurement of Natural Gas by 

Coriolis Meter (2003), IBR approved for 

§ 60.107a(d) of subpart Ja of this part. 

(4) American Gas Association 

Transmission Measurement Committee 

Report No. 7: Measurement of Gas by 

Turbine Meters (Revised February 

2006), IBR approved for § 60.107a(d) of 

subpart Ja of this part. 

(q) The following material is available 

for purchase from the International 

Standards Organization (ISO), 1, ch. de 

la Voie-Creuse, Case postale 56, CH– 

1211 Geneva 20, Switzerland, +41 22 

749 01 11, http://www.iso.org/iso/ 

home.htm. 

(1) ISO 8316: Measurement of Liquid 

Flow in Closed Conduits—Method by 

Collection of the Liquid in a Volumetric 

Tank (1987–10–01)—First Edition, IBR 

approved for § 60.107a(d) of subpart Ja 

of this part. 

(2) [Reserved] 

Subpart J—[AMENDED] 

■ 5. Section 60.100 is amended by: 

■ a. Revising paragraph (b); 

■ b. Redesignating paragraph (e) as (f); 

and 

■ c. Adding a new paragraph (e) to read 

as follows: 

§ 60.100 Applicability, designation of 

affected facility, and reconstruction. 

* * * * * 

(b) Any fluid catalytic cracking unit 

catalyst regenerator or fuel gas 

combustion device under paragraph (a) 

of this section other than a flare which 

commences construction, reconstruction 

or modification after June 11, 1973, and 

on or before May 14, 2007, or any fuel 

gas combustion device under paragraph 

(a) of this section that is also a flare 

which commences construction, 

reconstruction or modification after 

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

2008, or any Claus sulfur recovery plant 

under paragraph (a) of this section 

which commences construction, 

reconstruction or modification after 

October 4, 1976, and on or before May 

14, 2007, is subject to the requirements 

of this subpart except as provided under 

paragraphs (c) through (e) of this 

section. 

* * * * * 

(e) Owners or operators may choose to 

comply with the applicable provisions 

of subpart Ja of this part to satisfy the 

requirements of this subpart for an 

affected facility. 

* * * * * 

■ 6. Section 60.101 is amended by 

revising paragraph (d) to read as 

follows: 

§ 60.101 Definitions. 

* * * * * 

(d) Fuel gas means any gas which is 

generated at a petroleum refinery and 

which is combusted. Fuel gas includes 

natural gas when the natural gas is 

combined and combusted in any 

proportion with a gas generated at a 

refinery. Fuel gas does not include gases 

generated by catalytic cracking unit 

catalyst regenerators and fluid coking 

burners. Fuel gas does not include 

vapors that are collected and combusted 

in a thermal oxidizer or flare installed 

to control emissions from wastewater 

treatment units or marine tank vessel 

loading operations. 

* * * * * 

■ 7. Section 60.106 is amended by 

revising paragraph (c)(1) to read as 

follows: 

§ 60.106 Test methods and procedures. 

* * * * * 

(c) * * * 

(1) The allowable emission rate (Es) of 

PM shall be computed for each run 

using the following equation: 

Es = F + A (H/Rc) 

Where: 

Es = Emission rate of PM allowed, kg/Mg (lb/ 

ton) of coke burn-off in catalyst 

regenerator. 

F = Emission standard, 1.0 kg/Mg (2.0 lb/ton) 

of coke burn-off in catalyst regenerator. 

A = Allowable incremental rate of PM 

emissions, 43 g/GJ (0.10 lb/million Btu). 

H = Heat input rate from solid or liquid fossil 

fuel, GJ/hr (million Btu/hr). 

Rc = Coke burn-off rate, Mg coke/hr (ton 

coke/hr). 

* * * * * 

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56464 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

Subpart Ja—[AMENDED] 

■ 7. In § 60.100a, lift the stay on 

paragraph (c) published December 22, 

2008 (73 FR 78552). 

■ 8. Section 60.100a is amended by: 

■ a. Revising paragraph (a); 

■ b. Revising paragraph (b); 

■ c. Revising paragraph (c) introductory 

text and paragraph (c)(1); and 

■ d. Revising paragraph (d). 

The revisions read as follows: 

§ 60.100a Applicability, designation of 

affected facility, and reconstruction. 

(a) The provisions of this subpart 

apply to the following affected facilities 

in petroleum refineries: fluid catalytic 

cracking units (FCCU), fluid coking 

units (FCU), delayed coking units, fuel 

gas combustion devices (including 

process heaters), flares and sulfur 

recovery plants. The sulfur recovery 

plant need not be physically located 

within the boundaries of a petroleum 

refinery to be an affected facility, 

provided it processes gases produced 

within a petroleum refinery. 

(b) Except for flares and delayed 

coking units, the provisions of this 

subpart apply only to affected facilities 

under paragraph (a) of this section 

which commence construction, 

modification or reconstruction after May 

14, 2007. For flares, the provisions of 

this subpart apply only to flares which 

commence construction, modification or 

reconstruction after June 24, 2008. For 

the purposes of this subpart, a 

modification to a flare commences when 

a project that includes any of the 

activities in paragraphs (c)(1) or (2) of 

this section is commenced. For delayed 

coking units, the provisions of this 

subpart apply to delayed coking units 

that commence construction, 

reconstruction or modification on the 

earliest of the following dates: 

(1) May 14, 2007, for such activities 

that involve a ‘‘delayed coking unit’’ 

defined as follows: one or more refinery 

process units in which high molecular 

weight petroleum derivatives are 

thermally cracked and petroleum coke 

is produced in a series of closed, batch 

system reactors; 

(2) December 22, 2008, for such 

activities that involve a ‘‘delayed coking 

unit’’ defined as follows: 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 

consists of the coke drums and 

associated fractionator; 

(3) September 12, 2012, for such 

activities that involve a ‘‘delayed coking 

unit’’ as defined in § 60.101a. 

(c) For all affected facilities other than 

flares, the provisions in § 60.14 

regarding modification apply. As 

provided in § 60.14(f), the special 

provisions set forth under this subpart 

shall supersede the provisions in § 60.14 

with respect to flares. For the purposes 

of this subpart, a modification to a flare 

occurs as provided in paragraphs (c)(1) 

or (2) of this section. 

(1) Any new piping from a refinery 

process unit, including ancillary 

equipment, or a fuel gas system is 

physically connected to the flare (e.g., 

for direct emergency relief or some form 

of continuous or intermittent venting). 

However, the connections described in 

paragraphs (c)(1)(i) through (vii) of this 

section are not considered modifications 

of a flare. 

(i) Connections made to install 

monitoring systems to the flare. 

(ii) Connections made to install a flare 

gas recovery system or connections 

made to upgrade or enhance 

components of a flare gas recovery 

system (e.g., addition of compressors or 

recycle lines). 

(iii) Connections made to replace or 

upgrade existing pressure relief or safety 

valves, provided the new pressure relief 

or safety valve has a set point opening 

pressure no lower and an internal 

diameter no greater than the existing 

equipment being replaced or upgraded. 

(iv) Connections made for flare gas 

sulfur removal. 

(v) Connections made to install backup (redundant) equipment associated 

with the flare (such as a back-up 

compressor) that does not increase the 

capacity of the flare. 

(vi) Replacing piping or moving an 

existing connection from a refinery 

process unit to a new location in the 

same flare, provided the new pipe 

diameter is less than or equal to the 

diameter of the pipe/connection being 

replaced/moved. 

(vii) Connections that interconnect 

two or more flares. 

* * * * * 

(d) For purposes of this subpart, 

under § 60.15, the ‘‘fixed capital cost of 

the new components’’ includes the fixed 

capital cost of all depreciable 

components which are or will be 

replaced pursuant to all continuous 

programs of component replacement 

which are commenced within any 2- 

year period following the relevant 

applicability date specified in paragraph 

(b) of this section. 

■ 9. In § 60.101a, lift the stay on the 

definition of ‘‘flare’’ published 

December 22, 2008 (73 FR 78552). 

■ 10. Section 60.101a is amended by: 

■ a. Revising the introductory text; 

■ b. Adding, in alphabetical order, 

definitions of ‘‘Air preheat,’’ ‘‘Ancillary 

equipment,’’ ‘‘Cascaded flare system,’’ 

‘‘Co-fired process heater,’’ ‘‘Corrective 

action,’’ ‘‘Corrective action analysis,’’ 

‘‘Emergency flare,’’ ‘‘Flare gas header 

system,’’ ‘‘Flare gas recovery system,’’ 

‘‘Forced draft process heater,’’ ‘‘Natural 

draft process heater,’’ ‘‘Non-emergency 

flare,’’ ‘‘Primary flare,’’ ‘‘Purge gas,’’ 

‘‘Root cause analysis,’’ ‘‘Secondary 

flare,’’ and ‘‘Sweep gas’’; and 

■ c. Revising the definitions of ‘‘Delayed 

coking unit,’’ ‘‘Flare,’’ ‘‘Flexicoking 

unit,’’ ‘‘Fluid coking unit,’’ ‘‘Fuel gas,’’ 

‘‘Fuel gas combustion device,’’ 

‘‘Petroleum refinery,’’ ‘‘Process upset 

gas’’ and ‘‘Sulfur recovery plant’’ 

The revisions and additions read as 

follows: 

§ 60.101a Definitions. 

Terms used in this subpart are 

defined in the Clean Air Act (CAA), in 

§ 60.2 and in this section. 

Air preheat means a device used to 

heat the air supplied to a process heater 

generally by use of a heat exchanger to 

recover the sensible heat of exhaust gas 

from the process heater. 

Ancillary equipment means 

equipment used in conjunction with or 

that serve a refinery process unit. 

Ancillary equipment includes, but is not 

limited to, storage tanks, product 

loading operations, wastewater 

treatment systems, steam- or electricityproducing units (including coke 

gasification units), pressure relief 

valves, pumps, sampling vents and 

continuous analyzer vents. 

Cascaded flare system means a series 

of flares connected to one flare gas 

header system arranged with increasing 

pressure set points so that discharges 

will be initially directed to the first flare 

in the series (i.e., the primary flare). If 

the discharge pressure exceeds a set 

point at which the flow to the primary 

flare would exceed the primary flare’s 

capacity, flow will be diverted to the 

second flare in the series. Similarly, 

flow would be diverted to a third (or 

fourth) flare if the pressure in the flare 

gas header system exceeds a threshold 

where the flow to the first two (or three) 

flares would exceed their capacities. 

Co-fired process heater means a 

process heater that employs burners that 

are designed to be supplied by both 

gaseous and liquid fuels on a routine 

basis. Process heaters that have gas 

burners with emergency oil back-up 

burners are not considered co-fired 

process heaters. 

* * * * * 

Corrective action means the design, 

operation and maintenance changes that 

one takes consistent with good 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56465 

engineering practice to reduce or 

eliminate the likelihood of the 

recurrence of the primary cause and any 

other contributing cause(s) of an event 

identified by a root cause analysis as 

having resulted in a discharge of gases 

to an affected flare in excess of specified 

thresholds. 

Corrective action analysis means a 

description of all reasonable interim and 

long-term measures, if any, that are 

available, and an explanation of why the 

selected corrective action(s) is/are the 

best alternative(s), including, but not 

limited to, considerations of cost 

effectiveness, technical feasibility, 

safety and secondary impacts. 

Delayed coking unit means a refinery 

process unit in which high molecular 

weight petroleum derivatives are 

thermally cracked and petroleum coke 

is produced in a series of closed, batch 

system reactors. A delayed coking unit 

includes, but is not limited to, all of the 

coke drums associated with a single 

fractionator; the fractionator, including 

the bottoms receiver and the overhead 

condenser; the coke drum cutting water 

and quench system, including the jet 

pump and coker quench water tank; 

process piping and associated 

equipment such as pumps, valves and 

connectors; and the coke drum 

blowdown recovery compressor system. 

Emergency flare means a flare that 

combusts gas exclusively released as a 

result of malfunctions (and not startup, 

shutdown, routine operations or any 

other cause) on four or fewer occasions 

in a rolling 365-day period. For 

purposes of this rule, a flare cannot be 

categorized as an emergency flare unless 

it maintains a water seal. 

Flare means a combustion device that 

uses an uncontrolled volume of air to 

burn gases. The flare includes the 

foundation, flare tip, structural support, 

burner, igniter, flare controls, including 

air injection or steam injection systems, 

flame arrestors and the flare gas header 

system. In the case of an interconnected 

flare gas header system, the flare 

includes each individual flare serviced 

by the interconnected flare gas header 

system and the interconnected flare gas 

header system. 

Flare gas header system means all 

piping and knockout pots, including 

those in a subheader system, used to 

collect and transport gas to a flare either 

from a process unit or a pressure relief 

valve from the fuel gas system, 

regardless of whether or not a flare gas 

recovery system draws gas from the flare 

gas header system. The flare gas header 

system includes piping inside the 

battery limit of a process unit if the 

purpose of the piping is to transport gas 

to a flare or knockout pot that is part of 

the flare. 

Flare gas recovery system means a 

system of one or more compressors, 

piping and the associated water seal, 

rupture disk or similar device used to 

divert gas from the flare and direct the 

gas to the fuel gas system or to a fuel 

gas combustion device. 

Flexicoking unit means a refinery 

process unit in which high molecular 

weight petroleum derivatives are 

thermally cracked and petroleum coke 

is continuously produced and then 

gasified to produce a synthetic fuel gas. 

* * * * * 

Fluid coking unit means a refinery 

process unit in which high molecular 

weight petroleum derivatives are 

thermally cracked and petroleum coke 

is continuously produced in a fluidized 

bed system. The fluid coking unit 

includes the coking reactor, the coking 

burner, and equipment for controlling 

air pollutant emissions and for heat 

recovery on the fluid coking burner 

exhaust vent. 

Forced draft process heater means a 

process heater in which the combustion 

air is supplied under positive pressure 

produced by a fan at any location in the 

inlet air line prior to the point where the 

combustion air enters the process heater 

or air preheat. For the purposes of this 

subpart, a process heater that uses fans 

at both the inlet air side and the exhaust 

air side (i.e., balanced draft system) is 

considered to be a forced draft process 

heater. 

Fuel gas means any gas which is 

generated at a petroleum refinery and 

which is combusted. Fuel gas includes 

natural gas when the natural gas is 

combined and combusted in any 

proportion with a gas generated at a 

refinery. Fuel gas does not include gases 

generated by catalytic cracking unit 

catalyst regenerators, coke calciners 

(used to make premium grade coke) and 

fluid coking burners, but does include 

gases from flexicoking unit gasifiers and 

other gasifiers. Fuel gas does not 

include vapors that are collected and 

combusted in a thermal oxidizer or flare 

installed to control emissions from 

wastewater treatment units other than 

those processing sour water, marine 

tank vessel loading operations or 

asphalt processing units (i.e., asphalt 

blowing stills). 

Fuel gas combustion device means 

any equipment, such as process heaters 

and boilers, used to combust fuel gas. 

For the purposes of this subpart, fuel gas 

combustion device does not include 

flares or facilities in which gases are 

combusted to produce sulfur or sulfuric 

acid. 

* * * * * 

Natural draft process heater means 

any process heater in which the 

combustion air is supplied under 

ambient or negative pressure without 

the use of an inlet air (forced draft) fan. 

For the purposes of this subpart, a 

natural draft process heater is any 

process heater that is not a forced draft 

process heater, including induced draft 

systems. 

Non-emergency flare means any flare 

that is not an emergency flare as defined 

in this subpart. 

* * * * * 

Petroleum refinery means any facility 

engaged in producing gasoline, 

kerosene, distillate fuel oils, residual 

fuel oils, lubricants, asphalt (bitumen) 

or other products through distillation of 

petroleum or through redistillation, 

cracking or reforming of unfinished 

petroleum derivatives. A facility that 

produces only oil shale or tar sandsderived crude oil for further processing 

at a petroleum refinery using only 

solvent extraction and/or distillation to 

recover diluent is not a petroleum 

refinery. 

Primary flare means the first flare in 

a cascaded flare system. 

* * * * * 

Process upset gas means any gas 

generated by a petroleum refinery 

process unit or by ancillary equipment 

as a result of startup, shutdown, upset 

or malfunction. 

Purge gas means gas introduced 

between a flare’s water seal and a flare’s 

tip to prevent oxygen infiltration 

(backflow) into the flare tip. For flares 

with no water seals, the function of 

purge gas is performed by sweep gas 

(i.e., flares without water seals do not 

use purge gas). 

* * * * * 

Root cause analysis means an 

assessment conducted through a process 

of investigation to determine the 

primary cause, and any other 

contributing cause(s), of a discharge of 

gases in excess of specified thresholds. 

Secondary flare means a flare in a 

cascaded flare system that provides 

additional flare capacity and pressure 

relief to a flare gas system when the 

flare gas flow exceeds the capacity of 

the primary flare. For purposes of this 

subpart, a secondary flare is 

characterized by infrequent use and 

must maintain a water seal. 

* * * * * 

Sulfur recovery plant means all 

process units which recover sulfur from 

H2S and/or SO2 from a common source 

of sour gas produced at a petroleum 

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56466 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

refinery. The sulfur recovery plant also 

includes sulfur pits used to store the 

recovered sulfur product, but it does not 

include secondary sulfur storage vessels 

or loading facilities downstream of the 

sulfur pits. For example, a Claus sulfur 

recovery plant includes: Reactor furnace 

and waste heat boiler, catalytic reactors, 

sulfur pits and, if present, oxidation or 

reduction control systems or 

incinerator, thermal oxidizer or similar 

combustion device. Multiple sulfur 

recovery units are a single affected 

facility only when the units share the 

same source of sour gas. Sulfur recovery 

plants that receive source gas from 

completely segregated sour gas 

treatment systems are separate affected 

facilities. 

Sweep gas means the gas introduced 

in a flare gas header system to maintain 

a constant flow of gas to prevent oxygen 

buildup in the flare header. For flares 

with no water seals, sweep gas also 

performs the function of preventing 

oxygen infiltration (backflow) into the 

flare tip. 

■ 11. In § 60.102a, lift the stay on 

paragraph (g) published December 22, 

2008 (73 FR 78552). 

■ 12. Section 60.102a is amended by: 

■ a. Revising paragraph (a); 

■ b. Revising paragraph (f)(1)(ii); 

■ c. Revising paragraph (g); 

■ d. Removing and reserving paragraph 

(h); and 

■ e. Revising paragraph (i). 

The revisions read as follows: 

§ 60.102a Emissions limitations. 

(a) Each owner or operator that is 

subject to the requirements of this 

subpart shall comply with the emissions 

limitations in paragraphs (b) through (i) 

of this section on and after the date on 

which the initial performance test, 

required by § 60.8, is completed, but not 

later than 60 days after achieving the 

maximum production rate at which the 

affected facility will be operated or 180 

days after initial startup, whichever 

comes first. 

* * * * * 

(f) * * * 

(1) * * * 

(ii) For a sulfur recovery plant with a 

reduction control system not followed 

by incineration, the owner or operator 

shall not discharge or cause the 

discharge of any gases into the 

atmosphere in excess of 300 ppmv of 

reduced sulfur compounds and 10 

ppmv of H2S, each calculated as ppmv 

SO2 (dry basis) at 0-percent excess air; 

or 

* * * * * 

(g) Each owner or operator of an 

affected fuel gas combustion device 

shall comply with the emissions limits 

in paragraphs (g)(1) and (2) of this 

section. 

(1) Except as provided in (g)(1)(iii) of 

this section, for each fuel gas 

combustion device, the owner or 

operator shall comply with either the 

emission limit in paragraph (g)(1)(i) of 

this section or the fuel gas concentration 

limit in paragraph (g)(1)(ii) of this 

section. 

(i) The owner or operator shall not 

discharge or cause the discharge of any 

gases into the atmosphere that contain 

SO2 in excess of 20 ppmv (dry basis, 

corrected to 0-percent excess air) 

determined hourly on a 3-hour rolling 

average basis and SO2 in excess of 8 

ppmv (dry basis, corrected to 0-percent 

excess air), determined daily on a 365 

successive calendar day rolling average 

basis; or 

(ii) The owner or operator shall not 

burn in any fuel gas combustion device 

any fuel gas that contains H2S in excess 

of 162 ppmv determined hourly on a 3- 

hour rolling average basis and H2S in 

excess of 60 ppmv determined daily on 

a 365 successive calendar day rolling 

average basis. 

(iii) The combustion in a portable 

generator of fuel gas released as a result 

of tank degassing and/or cleaning is 

exempt from the emissions limits in 

paragraphs (g)(1)(i) and (ii) of this 

section. 

(2) For each process heater with a 

rated capacity of greater than 40 million 

British thermal units per hour (MMBtu/ 

hr) on a higher heating value basis, the 

owner or operator shall not discharge to 

the atmosphere any emissions of NOX in 

excess of the applicable limits in 

paragraphs (g)(2)(i) through (iv) of this 

section. 

(i) For each natural draft process 

heater, comply with the limit in either 

paragraph (g)(2)(i)(A) or (B) of this 

section. The owner or operator may 

comply with either limit at any time, 

provided that the appropriate 

parameters for each alternative are 

monitored as specified in § 60.107a; if 

fuel gas composition is not monitored as 

specified in § 60.107a(d), the owner or 

operator must comply with the 

concentration limits in paragraph 

(g)(2)(i)(A) of this section. 

(A) 40 ppmv (dry basis, corrected to 

0-percent excess air) determined daily 

on a 30-day rolling average basis; or 

(B) 0.040 pounds per million British 

thermal units (lb/MMBtu) higher 

heating value basis determined daily on 

a 30-day rolling average basis. 

(ii) For each forced draft process 

heater, comply with the limit in either 

paragraph (g)(2)(ii)(A) or (B) of this 

section. The owner or operator may 

comply with either limit at any time, 

provided that the appropriate 

parameters for each alternative are 

monitored as specified in § 60.107a; if 

fuel gas composition is not monitored as 

specified in § 60.107a(d), the owner or 

operator must comply with the 

concentration limits in paragraph 

(g)(2)(ii)(A) of this section. 

(A) 60 ppmv (dry basis, corrected to 

0-percent excess air) determined daily 

on a 30-day rolling average basis; or 

(B) 0.060 lb/MMBtu higher heating 

value basis determined daily on a 30- 

day rolling average basis. 

(iii) For each co-fired natural draft 

process heater, comply with the limit in 

either paragraph (g)(2)(iii)(A) or (B) of 

this section. The owner or operator must 

choose one of the emissions limits with 

which to comply at all times: 

(A) 150 ppmv (dry basis, corrected to 

0-percent excess air) determined daily 

on a 30 successive operating day rolling 

average basis; or 

(B) The daily average emissions limit 

calculated using Equation 3 of this 

section: 

Where: 

ERNOx = Daily allowable average emission 

rate of NOX, lb/MMBtu (higher heating 

value basis); 

Qgas = Daily average volumetric flow rate of 

fuel gas, standard cubic feet per day (scf/ 

day); 

Qoil = Daily average volumetric flow rate of 

fuel oil, scf/day; 

HHVgas = Daily average higher heating value 

of gas fired to the process heater, 

MMBtu/scf; and 

HHVoil = Daily average higher heating value 

of fuel oil fired to the process heater, 

MMBtu/scf. 


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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56467 

(iv) For each co-fired forced draft 

process heater, comply with the limit in 

either paragraph (g)(2)(iv)(A) or (B) of 

this section. The owner or operator must 

choose one of the emissions limits with 

which to comply at all times: 

(A) 150 ppmv (dry basis, corrected to 

0-percent excess air) determined daily 

on a 30 successive operating day rolling 

average basis; or 

(B) The daily average emissions limit 

calculated using Equation 4 of this 

section: 

Where: 

ERNOx = Daily allowable average emission 

rate of NOX, lb/MMBtu (higher heating 

value basis); 

Qgas = Daily average volumetric flow rate of 

fuel gas, scf/day; 

Qoil = Daily average volumetric flow rate of 

fuel oil, scf/day; 

HHVgas = Daily average higher heating value 

of gas fired to the process heater, 

MMBtu/scf; and 

HHVoil = Daily average higher heating value 

of fuel oil fired to the process heater, 

MMBtu/scf. 

(h) [Reserved] 

(i) For a process heater that meets any 

of the criteria of paragraphs (i)(1)(i) 

through (iv) of this section, an owner or 

operator may request approval from the 

Administrator for a NOX emissions limit 

which shall apply specifically to that 

affected facility. The request shall 

include information as described in 

paragraph (i)(2) of this section. The 

request shall be submitted and followed 

as described in paragraph (i)(3) of this 

section. 

(1) A process heater that meets one of 

the criteria in paragraphs (i)(1)(i) 

through (iv) of this section may apply 

for a site-specific NOX emissions limit: 

(i) A modified or reconstructed 

process heater that lacks sufficient space 

to accommodate installation and proper 

operation of combustion modificationbased technology (e.g., ultra-low NOX

burners); or 

(ii) A modified or reconstructed 

process heater that has downwardly 

firing induced draft burners; or 

(iii) A co-fired process heater; or 

(iv) A process heater operating at 

reduced firing conditions for an 

extended period of time (i.e., operating 

in turndown mode). The site-specific 

NOX emissions limit will only apply for 

those operating conditions. 

(2) The request shall include 

sufficient and appropriate data, as 

determined by the Administrator, to 

allow the Administrator to confirm that 

the process heater is unable to comply 

with the applicable NOX emissions limit 

in paragraph (g)(2) of this section. At a 

minimum, the request shall contain the 

information described in paragraphs 

(i)(2)(i) through (iv) of this section. 

(i) The design and dimensions of the 

process heater, evaluation of available 

combustion modification-based 

technology, description of fuel gas and, 

if applicable, fuel oil characteristics, 

information regarding the combustion 

conditions (temperature, oxygen 

content, firing rates) and other 

information needed to demonstrate that 

the process heater meets one of the four 

classes of process heaters listed in 

paragraph (i)(1) of this section. 

(ii) An explanation of how the data in 

paragraph (i)(2)(i) demonstrate that 

ultra-low NOX burners, flue gas 

recirculation, control of excess air or 

other combustion modification-based 

technology (including combinations of 

these combustion modification-based 

technologies) cannot be used to meet the 

applicable emissions limit in paragraph 

(g)(2) of this section. 

(iii) Results of a performance test 

conducted under representative 

conditions using the applicable methods 

specified in § 60.104a(i) to demonstrate 

the performance of the technology the 

owner or operator will use to minimize 

NOX emissions. 

(iv) The means by which the owner or 

operator will document continuous 

compliance with the site-specific 

emissions limit. 

(3) The request shall be submitted and 

followed as described in paragraphs 

(i)(3)(i) through (iii) of this section. 

(i) The owner or operator of a process 

heater that meets one of the criteria in 

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

section may request approval from the 

Administrator within 180 days after 

initial startup of the process heater for 

a NOX emissions limit which shall 

apply specifically to that affected 

facility. 

(ii) The request must be submitted to 

the Administrator for approval. The 

owner or operator must comply with the 

request as submitted until it is 

approved. 

(iii) The request shall also be 

submitted to the following address: U.S. 

Environmental Protection Agency, 

Office of Air Quality Planning and 

Standards, Sector Policies and Programs 

Division, U.S. EPA Mailroom (E143–01), 

Attention: Refinery Sector Lead, 109 

T.W. Alexander Drive, Research 

Triangle Park, NC 27711. Electronic 

copies in lieu of hard copies may also 

be submitted to refinerynsps@epa.gov. 

(4) The approval process for a request 

for a facility-specific NOX emissions 

limit is described in paragraphs (i)(4)(i) 

through (iii) of this section. 

(i) Approval by the Administrator of 

a facility-specific NOX emissions limit 

request will be based on the 

completeness, accuracy and 

reasonableness of the request. Factors 

that the EPA will consider in reviewing 

the request for approval include, but are 

not limited to, the following: 

(A) A demonstration that the process 

heater meets one of the four classes of 

process heaters outlined in paragraphs 

(i)(1) of this section; 

(B) A description of the low-NOX

burner designs and other combustion 

modifications considered for reducing 

NOX emissions; 

(C) The combustion modification 

option selected; and 

(D) The operating conditions (firing 

rate, heater box temperature and excess 

oxygen concentration) at which the NOX

emission level was established. 

(ii) If the request is approved by the 

Administrator, a facility-specific NOX

emissions limit will be established at 

the NOX emission level demonstrated in 

the approved request. 

(iii) If the Administrator finds any 

deficiencies in the request, the request 

must be revised to address the 

deficiencies and be re-submitted for 

approval. 

■ 13. Section 60.103a is revised to read 

as follows: 

§ 60.103a Design, equipment, work 

practice or operational standards. 

(a) Except as provided in paragraph 

(g) of this section, each owner or 

operator that operates a flare that is 

subject to this subpart shall develop and 

implement a written flare management 

plan no later than the date specified in 

paragraph (b) of this section. The flare 

management plan must include the 

information described in paragraphs 

(a)(1) through (7) of this section. 


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56468 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

(1) A listing of all refinery process 

units, ancillary equipment, and fuel gas 

systems connected to the flare for each 

affected flare. 

(2) An assessment of whether 

discharges to affected flares from these 

process units, ancillary equipment and 

fuel gas systems can be minimized. The 

flare minimization assessment must (at 

a minimum) consider the items in 

paragraphs (a)(2)(i) through (iv) of this 

section. The assessment must provide 

clear rationale in terms of costs (capital 

and annual operating), natural gas offset 

credits (if applicable), technical 

feasibility, secondary environmental 

impacts and safety considerations for 

the selected minimization alternative(s) 

or a statement, with justifications, that 

flow reduction could not be achieved. 

Based upon the assessment, each owner 

or operator of an affected flare shall 

identify the minimization alternatives 

that it has implemented by the due date 

of the flare management plan and shall 

include a schedule for the prompt 

implementation of any selected 

measures that cannot reasonably be 

completed as of that date. 

(i) Elimination of process gas 

discharge to the flare through process 

operating changes or gas recovery at the 

source. 

(ii) Reduction of the volume of 

process gas to the flare through process 

operating changes. 

(iii) Installation of a flare gas recovery 

system or, for facilities that are fuel gas 

rich, a flare gas recovery system and a 

co-generation unit or combined heat and 

power unit. 

(iv) Minimization of sweep gas flow 

rates and, for flares with water seals, 

purge gas flow rates. 

(3) A description of each affected flare 

containing the information in 

paragraphs (a)(3)(i) through (vii) of this 

section. 

(i) A general description of the flare, 

including the information in paragraphs 

(a)(3)(i)(A) through (G) of this section. 

(A) Whether it is a ground flare or 

elevated (including height). 

(B) The type of assist system (e.g., air, 

steam, pressure, non-assisted). 

(C) Whether it is simple or complex 

flare tip (e.g., staged, sequential). 

(D) Whether the flare is part of a 

cascaded flare system (and if so, 

whether the flare is primary or 

secondary). 

(E) Whether the flare serves as a 

backup to another flare. 

(F) Whether the flare is an emergency 

flare or a non-emergency flare. 

(G) Whether the flare is equipped 

with a flare gas recovery system. 

(ii) Description and simple process 

flow diagram showing the 

interconnection of the following 

components of the flare: flare tip (date 

installed, manufacturer, nominal and 

effective tip diameter, tip drawing); 

knockout or surge drum(s) or pot(s) 

(including dimensions and design 

capacities); flare header(s) and 

subheader(s); assist system; and ignition 

system. 

(iii) Flare design parameters, 

including the maximum vent gas flow 

rate; minimum sweep gas flow rate; 

minimum purge gas flow rate (if any); 

maximum supplemental gas flow rate; 

maximum pilot gas flow rate; and, if the 

flare is steam-assisted, minimum total 

steam rate. 

(iv) Description and simple process 

flow diagram showing all gas lines 

(including flare, purge (if applicable), 

sweep, supplemental and pilot gas) that 

are associated with the flare. For purge, 

sweep, supplemental and pilot gas, 

identify the type of gas used. Designate 

which lines are exempt from sulfur, H2S 

or flow monitoring and why (e.g., 

natural gas, inherently low sulfur, pilot 

gas). Designate which lines are 

monitored and identify on the process 

flow diagram the location and type of 

each monitor. 

(v) For each flow rate, H2S, sulfur 

content, pressure or water seal monitor 

identified in paragraph (a)(3)(iv) of this 

section, provide a detailed description 

of the manufacturer’s specifications, 

including, but not limited to, make, 

model, type, range, precision, accuracy, 

calibration, maintenance and quality 

assurance procedures. 

(vi) For emergency flares, secondary 

flares and flares equipped with a flare 

gas recovery system designed, sized and 

operated to capture all flows except 

those resulting from startup, shutdown 

or malfunction: 

(A) Description of the water seal, 

including the operating range for the 

liquid level. 

(B) Designation of the monitoring 

option elected (flow and sulfur 

monitoring or pressure and water seal 

liquid level monitoring). 

(vii) For flares equipped with a flare 

gas recovery system: 

(A) A description of the flare gas 

recovery system, including number of 

compressors and capacity of each 

compressor. 

(B) A description of the monitoring 

parameters used to quantify the amount 

of flare gas recovered. 

(C) For systems with staged 

compressors, the maximum time period 

required to begin gas recovery with the 

secondary compressor(s), the 

monitoring parameters and procedures 

used to minimize the duration of 

releases during compressor staging and 

a justification for why the maximum 

time period cannot be further reduced. 

(4) An evaluation of the baseline flow 

to the flare. The baseline flow to the 

flare must be determined after 

implementing the minimization 

assessment in paragraph (a)(2) of this 

section. Baseline flows do not include 

pilot gas flow or purge gas flow (i.e., gas 

introduced after the flare’s water seal) 

provided these gas flows remain 

reasonably constant (i.e., separate flow 

monitors for these streams are not 

required). Separate baseline flow rates 

may be established for different 

operating conditions provided that the 

management plan includes: 

(i) A primary baseline flow rate that 

will be used as the default baseline for 

all conditions except those specifically 

delineated in the plan; 

(ii) A description of each special 

condition for which an alternate 

baseline is established, including the 

rationale for each alternate baseline, the 

daily flow for each alternate baseline 

and the expected duration of the special 

conditions for each alternate baseline; 

and 

(iii) Procedures to minimize 

discharges to the affected flare during 

each special condition described in 

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

unless procedures are already 

developed for these cases under 

paragraph (a)(5) through (7) of this 

section, as applicable. 

(5) Procedures to minimize or 

eliminate discharges to the flare during 

the planned startup and shutdown of 

the refinery process units and ancillary 

equipment that are connected to the 

affected flare, together with a schedule 

for the prompt implementation of any 

procedures that cannot reasonably be 

implemented as of the date of the 

submission of the flare management 

plan. 

(6) Procedures to reduce flaring in 

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

fuel gas for the refinery’s energy needs), 

together with a schedule for the prompt 

implementation of any procedures that 

cannot reasonably be implemented as of 

the date of the submission of the flare 

management plan. 

(7) For flares equipped with flare gas 

recovery systems, procedures to 

minimize the frequency and duration of 

outages of the flare gas recovery system 

and procedures to minimize the volume 

of gas flared during such outages, 

together with a schedule for the prompt 

implementation of any procedures that 

cannot reasonably be implemented as of 

the date of the submission of the flare 

management plan. 

(b) Except as provided in paragraph 

(g) of this section, each owner or 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56469 

operator required to develop and 

implement a written flare management 

plan as described in paragraph (a) of 

this section must submit the plan to the 

Administrator as described in 

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

section. 

(1) The owner or operator of a newly 

constructed or reconstructed flare must 

develop and implement the flare 

management plan by no later than the 

date that the flare becomes an affected 

facility subject to this subpart, except 

for the selected minimization 

alternatives in paragraph (a)(2) and/or 

the procedures in paragraphs (a)(5) 

though (a)(7) of this section that cannot 

reasonably be implemented by that date, 

which the owner or operator must 

implement in accordance with the 

schedule in the flare management plan. 

The owner or operator of a modified 

flare must develop and implement the 

flare management plan by no later than 

November 11, 2015 or upon startup of 

the modified flare, whichever is later. 

(2) The owner or operator must 

comply with the plan as submitted by 

the date specified in paragraph (b)(1) of 

this section. The plan should be 

updated periodically to account for 

changes in the operation of the flare, 

such as new connections to the flare or 

the installation of a flare gas recovery 

system, but the plan need be resubmitted to the Administrator only if 

the owner or operator adds an 

alternative baseline flow rate, revises an 

existing baseline as described in 

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

a flare gas recovery system or is required 

to change flare designations and 

monitoring methods as described in 

§ 60.107a(g). The owner or operator 

must comply with the updated plan as 

submitted. 

(3) All versions of the plan submitted 

to the Administrator shall also be 

submitted to the following address: U.S. 

Environmental Protection Agency, 

Office of Air Quality Planning and 

Standards, Sector Policies and Programs 

Division, U.S. EPA Mailroom (E143–01), 

Attention: Refinery Sector Lead, 109 

T.W. Alexander Drive, Research 

Triangle Park, NC 27711. Electronic 

copies in lieu of hard copies may also 

be submitted to refinerynsps@epa.gov. 

(c) Except as provided in paragraphs 

(f) and (g) of this section, each owner or 

operator that operates a fuel gas 

combustion device, flare or sulfur 

recovery plant subject to this subpart 

shall conduct a root cause analysis and 

a corrective action analysis for each of 

the conditions specified in paragraphs 

(c)(1) through (3) of this section. 

(1) For a flare: 

(i) Any time the SO2 emissions exceed 

227 kilograms (kg) (500 lb) in any 24- 

hour period; or 

(ii) Any discharge to the flare in 

excess of 14,160 standard cubic meters 

(m3) (500,000 standard cubic feet (scf)) 

above the baseline, determined in 

paragraph (a)(4) of this section, in any 

24-hour period; or 

(iii) If the monitoring alternative in 

§ 60.107a(g) is elected, any period when 

the flare gas line pressure exceeds the 

water seal liquid depth, except for 

periods attributable to compressor 

staging that do not exceed the staging 

time specified in paragraph (a)(3)(vii)(C) 

of this section. 

(2) For a fuel gas combustion device, 

each exceedance of an applicable shortterm emissions limit in § 60.102a(g)(1) if 

the SO2 discharge to the atmosphere is 

227 kg (500 lb) greater than the amount 

that would have been emitted if the 

emissions limits had been met during 

one or more consecutive periods of 

excess emissions or any 24-hour period, 

whichever is shorter. 

(3) For a sulfur recovery plant, each 

time the SO2 emissions are more than 

227 kg (500 lb) greater than the amount 

that would have been emitted if the SO2

or reduced sulfur concentration was 

equal to the applicable emissions limit 

in § 60.102a(f)(1) or (2) during one or 

more consecutive periods of excess 

emissions or any 24-hour period, 

whichever is shorter. 

(d) Except as provided in paragraphs 

(f) and (g) of this section, a root cause 

analysis and corrective action analysis 

must be completed as soon as possible, 

but no later than 45 days after a 

discharge meeting one of the conditions 

specified in paragraphs (c)(1) through 

(3) of this section. Special 

circumstances affecting the number of 

root cause analyses and/or corrective 

action analyses are provided in 

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

section. 

(1) If a single continuous discharge 

meets any of the conditions specified in 

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

section for 2 or more consecutive 24- 

hour periods, a single root cause 

analysis and corrective action analysis 

may be conducted. 

(2) If a single discharge from a flare 

triggers a root cause analysis based on 

more than one of the conditions 

specified in paragraphs (c)(1)(i) through 

(iii) of this section, a single root cause 

analysis and corrective action analysis 

may be conducted. 

(3) If the discharge from a flare is the 

result of a planned startup or shutdown 

of a refinery process unit or ancillary 

equipment connected to the affected 

flare and the procedures in paragraph 

(a)(5) of this section were followed, a 

root cause analysis and corrective action 

analysis is not required; however, the 

discharge must be recorded as described 

in § 60.108a(c)(6) and reported as 

described in § 60.108a(d)(5). 

(4) If both the primary and secondary 

flare in a cascaded flare system meet 

any of the conditions specified in 

paragraphs (c)(1)(i) through (iii) of this 

section in the same 24-hour period, a 

single root cause analysis and corrective 

action analysis may be conducted. 

(5) Except as provided in paragraph 

(d)(4) of this section, if discharges occur 

that meet any of the conditions 

specified in paragraphs (c)(1) through 

(3) of this section for more than one 

affected facility in the same 24-hour 

period, initial root cause analyses shall 

be conducted for each affected facility. 

If the initial root cause analyses indicate 

that the discharges have the same root 

cause(s), the initial root cause analyses 

can be recorded as a single root cause 

analysis and a single corrective action 

analysis may be conducted. 

(e) Except as provided in paragraphs 

(f) and (g) of this section, each owner or 

operator of a fuel gas combustion 

device, flare or sulfur recovery plant 

subject to this subpart shall implement 

the corrective action(s) identified in the 

corrective action analysis conducted 

pursuant to paragraph (d) of this section 

in accordance with the applicable 

requirements in paragraphs (e)(1) 

through (3) of this section. 

(1) All corrective action(s) must be 

implemented within 45 days of the 

discharge for which the root cause and 

corrective action analyses were required 

or as soon thereafter as practicable. If an 

owner or operator concludes that 

corrective action should not be 

conducted, the owner or operator shall 

record and explain the basis for that 

conclusion no later than 45 days 

following the discharge as specified in 

§ 60.108a(c)(6)(ix). 

(2) For corrective actions that cannot 

be fully implemented within 45 days 

following the discharge for which the 

root cause and corrective action 

analyses were required, the owner or 

operator shall develop an 

implementation schedule to complete 

the corrective action(s) as soon as 

practicable. 

(3) No later than 45 days following the 

discharge for which a root cause and 

corrective action analyses were 

required, the owner or operator shall 

record the corrective action(s) 

completed to date, and, for action(s) not 

already completed, a schedule for 

implementation, including proposed 

commencement and completion dates as 

specified in § 60.108a(c)(6)(x). 

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56470 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

(f) Modified flares shall comply with 

the requirements of paragraphs (c) 

through (e) of this section by November 

11, 2015 or at startup of the modified 

flare, whichever is later. Modified flares 

that were not affected facilities subject 

to subpart J of this part prior to 

becoming affected facilities under 

§ 60.100a shall comply with the 

requirements of paragraph (h) of this 

section and the requirements of 

§ 60.107a(a)(2) by November 11, 2015 or 

at startup of the modified flare, 

whichever is later. Modified flares that 

were affected facilities subject to 

subpart J of this part prior to becoming 

affected facilities under § 60.100a shall 

comply with the requirements of 

paragraph (h) of this section and the 

requirements of § 60.107a(a)(2) by 

November 13, 2012 or at startup of the 

modified flare, whichever is later, 

except that modified flares that have 

accepted applicability of subpart J under 

a federal consent decree shall comply 

with the subpart J requirements as 

specified in the consent decree, but 

shall comply with the requirements of 

paragraph (h) of this section and the 

requirements of § 60.107a(a)(2) by no 

later than November 11, 2015. 

(g) An affected flare subject to this 

subpart located in the Bay Area Air 

Quality Management District 

(BAAQMD) may elect to comply with 

both BAAQMD Regulation 12, Rule 11 

and BAAQMD Regulation 12, Rule 12 as 

an alternative to complying with the 

requirements of paragraphs (a) through 

(e) of this section. An affected flare 

subject to this subpart located in the 

South Coast Air Quality Management 

District (SCAQMD) may elect to comply 

with SCAQMD Rule 1118 as an 

alternative to complying with the 

requirements of paragraphs (a) through 

(e) of this section. The owner or 

operator of an affected flare must notify 

the Administrator that the flare is in 

compliance with BAAQMD Regulation 

12, Rule 11 and BAAQMD Regulation 

12, Rule 12 or SCAQMD Rule 1118. The 

owner or operator of an affected flare 

shall also submit the existing flare 

management plan to the following 

address: U.S. Environmental Protection 

Agency, Office of Air Quality Planning 

and Standards, Sector Policies and 

Programs Division, U.S. EPA Mailroom 

(E143–01), Attention: Refinery Sector 

Lead, 109 T.W. Alexander Drive, 

Research Triangle Park, NC 27711. 

Electronic copies in lieu of hard copies 

may also be submitted to 

refinerynsps@epa.gov. 

(h) Each owner or operator shall not 

burn in any affected flare any fuel gas 

that contains H2S in excess of 162 ppmv 

determined hourly on a 3-hour rolling 

average basis. The combustion in a flare 

of process upset gases or fuel gas that is 

released to the flare as a result of relief 

valve leakage or other emergency 

malfunctions is exempt from this limit. 

(i) Each owner or operator of a 

delayed coking unit shall depressure 

each coke drum to 5 lb per square inch 

gauge (psig) or less prior to discharging 

the coke drum steam exhaust to the 

atmosphere. Until the coke drum 

pressure reaches 5 psig, the coke drum 

steam exhaust must be managed in an 

enclosed blowdown system and the 

uncondensed vapor must either be 

recovered (e.g., sent to the delayed 

coking unit fractionators) or vented to 

the fuel gas system, a fuel gas 

combustion device or a flare. 

(j) Alternative means of emission 

limitation. (1) Each owner or operator 

subject to the provisions of this section 

may apply to the Administrator for a 

determination of equivalence for any 

means of emission limitation that 

achieves a reduction in emissions of a 

specified pollutant at least equivalent to 

the reduction in emissions of that 

pollutant achieved by the controls 

required in this section. 

(2) Determination of equivalence to 

the design, equipment, work practice or 

operational requirements of this section 

will be evaluated by the following 

guidelines: 

(i) Each owner or operator applying 

for a determination of equivalence shall 

be responsible for collecting and 

verifying test data to demonstrate the 

equivalence of the alternative means of 

emission limitation. 

(ii) For each affected facility for which 

a determination of equivalence is 

requested, the emission reduction 

achieved by the design, equipment, 

work practice or operational 

requirements shall be demonstrated. 

(iii) For each affected facility for 

which a determination of equivalence is 

requested, the emission reduction 

achieved by the alternative means of 

emission limitation shall be 

demonstrated. 

(iv) Each owner or operator applying 

for a determination of equivalence to a 

work practice standard shall commit in 

writing to work practice(s) that provide 

for emission reductions equal to or 

greater than the emission reductions 

achieved by the required work practice. 

(v) The Administrator will compare 

the demonstrated emission reduction for 

the alternative means of emission 

limitation to the demonstrated emission 

reduction for the design, equipment, 

work practice or operational 

requirements and, if applicable, will 

consider the commitment in paragraph 

(j)(2)(iv) of this section. 

(vi) The Administrator may condition 

the approval of the alternative means of 

emission limitation on requirements 

that may be necessary to ensure 

operation and maintenance to achieve 

the same emissions reduction as the 

design, equipment, work practice or 

operational requirements. 

(3) An owner or operator may offer a 

unique approach to demonstrate the 

equivalence of any equivalent means of 

emission limitation. 

(4) Approval of the application for 

equivalence to the design, equipment, 

work practice or operational 

requirements of this section will be 

evaluated by the following guidelines: 

(i) After a request for determination of 

equivalence is received, the 

Administrator will publish a notice in 

the Federal Register and provide the 

opportunity for public hearing if the 

Administrator judges that the request 

may be approved. 

(ii) After notice and opportunity for 

public hearing, the Administrator will 

determine the equivalence of a means of 

emission limitation and will publish the 

determination in the Federal Register. 

(iii) Any equivalent means of 

emission limitations approved under 

this section shall constitute a required 

work practice, equipment, design or 

operational standard within the 

meaning of section 111(h)(1) of the 

CAA. 

(5) Manufacturers of equipment used 

to control emissions may apply to the 

Administrator for determination of 

equivalence for any alternative means of 

emission limitation that achieves a 

reduction in emissions achieved by the 

equipment, design and operational 

requirements of this section. The 

Administrator will make an equivalence 

determination according to the 

provisions of paragraphs (j)(2) through 

(4) of this section. 

■ 14. Section 60.104a is amended by: 

■ a. Revising paragraph (a); 

■ b. Revising paragraphs (d)(4)(ii), 

(d)(4)(iii), (d)(4)(v) and (d)(8); 

■ c. Revising paragraph (f)(3); 

■ d. Revising paragraph (h)(5)(iv); 

■ e. Revising paragraph (i) introductory 

text; 

■ f. Adding paragraphs (i)(6) through 

(i)(8); 

■ g. Revising paragraph (j) introductory 

text and paragraph (j)(4) introductory 

text; and 

■ h. Revising paragraph (j)(4)(iv) to read 

as follows: 

§ 60.104a Performance tests. 

(a) The owner or operator shall 

conduct a performance test for each 

FCCU, FCU, sulfur recovery plant, flare 

and fuel gas combustion device to 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56471 

demonstrate initial compliance with 

each applicable emissions limit in 

§ 60.102a according to the requirements 

of § 60.8. The notification requirements 

of § 60.8(d) apply to the initial 

performance test and to subsequent 

performance tests required by paragraph 

(b) of this section (or as required by the 

Administrator), but does not apply to 

performance tests conducted for the 

purpose of obtaining supplemental data 

because of continuous monitoring 

system breakdowns, repairs, calibration 

checks and zero and span adjustments. 

* * * * * 

(d) * * * 

(4) * * * 

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

computed for each run using Equation 

5 of this section: 

Where: 

E = Emission rate of PM, g/kg (lb/1,000 lb) 

of coke burn-off; 

cs = Concentration of total PM, grams per dry 

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

Qsd = Volumetric flow rate of effluent gas, dry 

standard cubic meters per hour (dry 

standard cubic feet per hour); 

Rc = Coke burn-off rate, kilograms per hour 

(kg/hr) [lb per hour (lb/hr)] coke; and 

K = Conversion factor, 1.0 grams per gram 

(7,000 grains per lb). 

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

computed for each run using Equation 

6 of this section: 

Where: 

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

Qr = Volumetric flow rate of exhaust gas from 

FCCU regenerator or fluid coking burner 

before any emissions control or energy 

recovery system that burns auxiliary 

fuel, dry standard cubic meters per 

minute (dscm/min) [dry standard cubic 

feet per minute (dscf/min)]; 

Qa = Volumetric flow rate of air to FCCU 

regenerator or fluid coking burner, as 

determined from the unit’s control room 

instrumentation, dscm/min (dscf/min); 

Qoxy = Volumetric flow rate of O2 enriched 

air to FCCU regenerator or fluid coking 

unit, as determined from the unit’s 

control room instrumentation, dscm/min 

(dscf/min); 

%CO2 = Carbon dioxide (CO2) concentration 

in FCCU regenerator or fluid coking 

burner exhaust, percent by volume (dry 

basis); 

%CO = CO concentration in FCCU 

regenerator or fluid coking burner 

exhaust, percent by volume (dry basis); 

%O2 = O2 concentration in FCCU regenerator 

or fluid coking burner exhaust, percent 

by volume (dry basis); 

%Ooxy = O2 concentration in O2 enriched air 

stream inlet to the FCCU regenerator or 

fluid coking burner, percent by volume 

(dry basis); 

K1 = Material balance and conversion factor, 

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

K2 = Material balance and conversion factor, 

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

K3 = Material balance and conversion factor, 

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

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

* * * * * 

(v) For subsequent calculations of 

coke burn-off rates or exhaust gas flow 

rates, the volumetric flow rate of Qr is 

calculated using average exhaust gas 

concentrations as measured by the 

monitors required in § 60.105a(b)(2), if 

applicable, using Equation 7 of this 

section: 

Where: 

Qr = Volumetric flow rate of exhaust gas from 

FCCU regenerator or fluid coking burner 

before any emission control or energy 

recovery system that burns auxiliary 

fuel, dscm/min (dscf/min); 

Qa = Volumetric flow rate of air to FCCU 

regenerator or fluid coking burner, as 

determined from the unit’s control room 

instrumentation, dscm/min (dscf/min); 

Qoxy = Volumetric flow rate of O2 enriched 

air to FCCU regenerator or fluid coking 

unit, as determined from the unit’s 

control room instrumentation, dscm/min 

(dscf/min); 

%CO2 = Carbon dioxide concentration in 

FCCU regenerator or fluid coking burner 

exhaust, percent by volume (dry basis); 

%CO = CO concentration FCCU regenerator 

or fluid coking burner exhaust, percent 

by volume (dry basis). When no auxiliary 

fuel is burned and a continuous CO 

monitor is not required in accordance 

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

zero; 

%O2 = O2 concentration in FCCU regenerator 

or fluid coking burner exhaust, percent 

by volume (dry basis); and 

%Ooxy = O2 concentration in O2 enriched air 

stream inlet to the FCCU regenerator or 

fluid coking burner, percent by volume 

(dry basis). 

* * * * * 

(8) The owner or operator shall adjust 

PM, NOX, SO2 and CO pollutant 

concentrations to 0-percent excess air or 

0-percent O2 using Equation 8 of this 

section: 


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Where: 

Cadj = pollutant concentration adjusted to 0- 

percent excess air or O2, parts per 

million (ppm) or g/dscm; 

Cmeas = pollutant concentration measured on 

a dry basis, ppm or g/dscm; 

20.9c = 20.9 percent O2¥0.0 percent O2

(defined O2 correction basis), percent; 

20.9 = O2 concentration in air, percent; and 

%O2 = O2 concentration measured on a dry 

basis, percent. 

* * * * * 

(f) * * * 

(3) Compute the site-specific limit 

using Equation 9 of this section: 

Where: 

Opacity limit = Maximum permissible 3-hour 

average opacity, percent, or 10 percent, 

whichever is greater; 

Opacityst = Hourly average opacity measured 

during the source test, percent; and 

PMEmRst = PM emission rate measured 

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

burn. 

* * * * * 

(h) * * * 

(5) * * * 

(iv) The owner or operator shall use 

Equation 8 of this section to adjust 

pollutant concentrations to 0-percent O2

or 0- percent excess air. 

(i) The owner or operator shall 

determine compliance with the SO2 and 

NOX emissions limits in § 60.102a(g) for 

a fuel gas combustion device according 

to the following test methods and 

procedures: 

* * * * * 

(6) For process heaters with a rated 

heat capacity between 40 and 100 

MMBtu/hr that elect to demonstrate 

continuous compliance with a 

maximum excess oxygen limit as 

provided in § 60.107a(c)(6) or (d)(8), the 

owner or operator shall establish the O2

operating limit or O2 operating curve 

based on the performance test results 

according to the requirements in 

paragraph (i)(6)(i) or (ii) of this section, 

respectively. 

(i) If a single O2 operating limit will 

be used: 

(A) Conduct the performance test 

following the methods provided in 

paragraphs (i)(1), (2), (3) and (5) of this 

section when the process heater is firing 

at no less than 70 percent of the rated 

heat capacity. For co-fired process 

heaters, conduct at least one of the test 

runs while the process heater is being 

supplied by both fuel gas and fuel oil 

and conduct at least one of the test runs 

while the process heater is being 

supplied solely by fuel gas. 

(B) Each test will consist of three test 

runs. Calculate the NOX concentration 

for the performance test as the average 

of the NOX concentrations from each of 

the three test runs. If the NOX

concentration for the performance test is 

less than or equal to the numerical value 

of the applicable NOX emissions limit 

(regardless of averaging time), then the 

test is considered to be a valid test. 

(C) Determine the average O2

concentration for each test run of a valid 

test. 

(D) Calculate the O2 operating limit as 

the average O2 concentration of the 

three test runs from a valid test. 

(ii) If an O2 operating curve will be 

used: 

(A) Conduct a performance test 

following the methods provided in 

paragraphs (i)(1), (2), (3) and (5) of this 

section at a representative condition for 

each operating range for which different 

O2 operating limits will be established. 

Different operating conditions may be 

defined as different firing rates (e.g., 

above 50 percent of rated heat capacity 

and at or below 50 percent of rated heat 

capacity) and/or, for co-fired process 

heaters, different fuel mixtures (e.g., 

primarily gas fired, primarily oil fired, 

and equally co-fired, i.e., approximately 

50 percent of the input heating value is 

from fuel gas and approximately 50 

percent of the input heating value is 

from fuel oil). Performance tests for 

different operating ranges may be 

conducted at different times. 

(B) Each test will consist of three test 

runs. Calculate the NOX concentration 

for the performance test as the average 

of the NOX concentrations from each of 

the three test runs. If the NOX

concentration for the performance test is 

less than or equal to the numerical value 

of the applicable NOX emissions limit 

(regardless of averaging time), then the 

test is considered to be a valid test. 

(C) If an operating curve is developed 

for different firing rates, conduct at least 

one test when the process heater is 

firing at no less than 70 percent of the 

rated heat capacity and at least one test 

under turndown conditions (i.e., when 

the process heater is firing at 50 percent 

or less of the rated heat capacity). If O2

operating limits are developed for cofired process heaters based only on 

overall firing rates (and not by fuel 

mixtures), conduct at least one of the 

test runs for each test while the process 

heater is being supplied by both fuel gas 

and fuel oil and conduct at least one of 

the test runs while the process heater is 

being supplied solely by fuel gas. 

(D) Determine the average O2

concentration for each test run of a valid 

test. 

(E) Calculate the O2 operating limit for 

each operating range as the average O2

concentration of the three test runs from 

a valid test conducted at the 

representative conditions for that given 

operating range. 

(F) Identify the firing rates for which 

the different operating limits apply. If 

only two operating limits are 

established based on firing rates, the O2

operating limits established when the 

process heater is firing at no less than 

70 percent of the rated heat capacity 

must apply when the process heater is 

firing above 50 percent of the rated heat 

capacity and the O2 operating limits 

established for turndown conditions 

must apply when the process heater is 

firing at 50 percent or less of the rated 

heat capacity. 

(G) Operating limits associated with 

each interval will be valid for 2 years or 

until another operating limit is 

established for that interval based on a 

more recent performance test specific 

for that interval, whichever occurs first. 

Owners and operators must use the 

operating limits determined for a given 

interval based on the most recent 

performance test conducted for that 

interval. 

(7) The owner or operator of a process 

heater complying with a NOX limit in 

terms of lb/MMBtu as provided in 

§ 60.102a(g)(2)(i)(B), (g)(2)(ii)(B), 

(g)(2)(iii)(B) or (g)(2)(iv)(B) or a process 

heater with a rated heat capacity 

between 40 and 100 MMBtu/hr that 


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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56473 

elects to demonstrate continuous 

compliance with a maximum excess O2

limit, as provided in § 60.107a(c)(6) or 

(d)(8), shall determine heat input to the 

process heater in MMBtu/hr during each 

performance test run by measuring fuel 

gas flow rate, fuel oil flow rate (as 

applicable) and heating value content 

according to the methods provided in 

§ 60.107a(d)(5), (d)(6), and (d)(4) or 

(d)(7), respectively. 

(8) The owner or operator shall use 

Equation 8 of this section to adjust 

pollutant concentrations to 0-percent O2

or 0- percent excess air. 

(j) The owner or operator shall 

determine compliance with the 

applicable H2S emissions limit in 

§ 60.102a(g)(1) for a fuel gas combustion 

device or the concentration requirement 

in § 60.103a(h) for a flare according to 

the following test methods and 

procedures: 

* * * * * 

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

Appendix A–5 to part 60 or EPA 

Method 16 of Appendix A–6 to part 60 

for determining the H2S concentration 

for affected facilities using an H2S 

monitor as specified in § 60.107a(a)(2). 

The method ANSI/ASME PTC 19.10– 

1981 (incorporated by reference—see 

§ 60.17) is an acceptable alternative to 

EPA Method 15A of Appendix A–5 to 

part 60. The owner or operator may 

demonstrate compliance based on the 

mixture used in the fuel gas combustion 

device or flare or for each individual 

fuel gas stream used in the fuel gas 

combustion device or flare. 

* * * * * 

(iv) If monitoring is conducted at a 

single point in a common source of fuel 

gas as allowed under § 60.107a(a)(2)(iv), 

only one performance test is required. 

That is, performance tests are not 

required when a new affected fuel gas 

combustion device or flare is added to 

a common source of fuel gas that 

previously demonstrated compliance. 

■ 15. Section 60.105a is amended by: 

■ a. Revising paragraph (b) introductory 

text, and paragraph (b)(1) introductory 

text, and paragraphs (b)(1)(ii)(A), 

(b)(2)(i) and (b)(2)(ii); and 

■ b. Revising paragraph (i)(5) to read as 

follows: 

§ 60.105a Monitoring of emissions and 

operations for fluid catalytic cracking units 

(FCCU) and fluid coking units (FCU). 

* * * * * 

(b) Control device operating 

parameters. Each owner or operator of 

a FCCU or FCU subject to the PM per 

coke burn-off emissions limit in 

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

other than fabric filter or cyclone shall 

comply with the requirements in 

paragraphs (b)(1) and (2) of this section. 

(1) The owner or operator shall 

install, operate and maintain continuous 

parameter monitor systems (CPMS) to 

measure and record operating 

parameters for each control device 

according to the applicable 

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

through (v) of this section. 

* * * * * 

(ii) * * * 

(A) As an alternative to pressure drop, 

the owner or operator of a jet ejector 

type wet scrubber or other type of wet 

scrubber equipped with atomizing spray 

nozzles must conduct a daily check of 

the air or water pressure to the spray 

nozzles and record the results of each 

check. 

* * * * * 

(2) * * * 

(i) The owner or operator shall install, 

operate and maintain each monitor 

according to Performance Specifications 

3 and 4 of Appendix B to part 60. 

(ii) The owner or operator shall 

conduct performance evaluations of 

each CO2, O2 and CO monitor according 

to the requirements in § 60.13(c) and 

Performance Specifications 3 and 4 of 

Appendix B to part 60. The owner or 

operator shall use EPA Method 3 of 

Appendix A–3 to part 60 and EPA 

Method 10, 10A or 10B of Appendix A– 

4 to part 60 for conducting the relative 

accuracy evaluations. 

* * * * * 

(i) * * * 

(5) All rolling 7-day periods during 

which the average concentration of SO2

as measured by the SO2 CEMS under 

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

rolling 365-day periods during which 

the average concentration of SO2 as 

measured by the SO2 CEMS exceeds 25 

ppmv. 

* * * * * 

■ 16. In § 60.107a, lift the stay on 

paragraphs (d) and (e) published 

December 22, 2008 (73 FR 78552). 

■ 17. Section 60.107a is amended by: 

■ a. Revising the section heading; 

■ b. Revising paragraph (a) introductory 

text, paragraph (a)(1) introductory text, 

paragraph (a)(2) introductory text, 

(a)(2)(i), (a)(2)(iv) and paragraph (a)(3) 

introductory text; 

■ c. Adding paragraphs (a)(2)(v) and 

(a)(2)(vi); 

■ d. Revising paragraph (b) introductory 

text and paragraphs (b)(1)(i), (b)(1)(v) 

and (b)(3)(iii); 

■ e. Revising paragraph (c) introductory 

text and paragraphs (c)(1) and (c)(6); 

■ f. Redesignating paragraphs (d), (e), 

and (f) as paragraphs (e), (f) and (i), 

respectively; 

■ g. Adding a new paragraph (d); 

■ h. Revising newly redesignated 

paragraph (e); 

■ i. Revising newly redesignated 

paragraph (f); 

■ j. Adding a new paragraph (g); 

■ k. Adding a new paragraph (h); and 

■ l. Revising newly redesignated 

paragraph (i). 

The revisions and additions read as 

follows: 

§ 60.107a Monitoring of emissions and 

operations for fuel gas combustion devices 

and flares. 

(a) Fuel gas combustion devices 

subject to SO2 or H2S limit and flares 

subject to H2S concentration 

requirements. The owner or operator of 

a fuel gas combustion device that is 

subject to § 60.102a(g)(1) and elects to 

comply with the SO2 emission limits in 

§ 60.102a(g)(1)(i) shall comply with the 

requirements in paragraph (a)(1) of this 

section. The owner or operator of a fuel 

gas combustion device that is subject to 

§ 60.102a(g)(1) and elects to comply 

with the H2S concentration limits in 

§ 60.102a(g)(1)(ii) or a flare that is 

subject to the H2S concentration 

requirement in § 60.103a(h) shall 

comply with paragraph (a)(2) of this 

section. 

(1) The owner or operator of a fuel gas 

combustion device that elects to comply 

with the SO2 emissions limits in 

§ 60.102a(g)(1)(i) shall install, operate, 

calibrate and maintain an instrument for 

continuously monitoring and recording 

the concentration (dry basis, 0-percent 

excess air) of SO2 emissions into the 

atmosphere. The monitor must include 

an O2 monitor for correcting the data for 

excess air. 

* * * * * 

(2) The owner or operator of a fuel gas 

combustion device that elects to comply 

with the H2S concentration limits in 

§ 60.102a(g)(1)(ii) or a flare that is 

subject to the H2S concentration 

requirement in § 60.103a(h) shall install, 

operate, calibrate and maintain an 

instrument for continuously monitoring 

and recording the concentration by 

volume (dry basis) of H2S in the fuel 

gases before being burned in any fuel 

gas combustion device or flare. 

(i) The owner or operator shall install, 

operate and maintain each H2S monitor 

according to Performance Specification 

7 of Appendix B to part 60. The span 

value for this instrument is 300 ppmv 

H2S. 

* * * * * 

(iv) Fuel gas combustion devices or 

flares having a common source of fuel 

gas may be monitored at only one 

location, if monitoring at this location 

accurately represents the concentration 

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56474 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

of H2S in the fuel gas being burned in 

the respective fuel gas combustion 

devices or flares. 

(v) The owner or operator of a flare 

subject to § 60.103a(c) through (e) may 

use the instrument required in 

paragraph (e)(1) of this section to 

demonstrate compliance with the H2S 

concentration requirement in 

§ 60.103a(h) if the owner or operator 

complies with the requirements of 

paragraph (e)(1)(i) through (iv) and if the 

instrument has a span (or dual span, if 

necessary) capable of accurately 

measuring concentrations between 20 

and 300 ppmv. If the instrument 

required in paragraph (e)(1) of this 

section is used to demonstrate 

compliance with the H2S concentration 

requirement, the concentration directly 

measured by the instrument must meet 

the numeric concentration in 

§ 60.103a(h). 

(vi) The owner or operator of 

modified flare that meets all three 

criteria in paragraphs (a)(2)(vi)(A) 

through (C) of this section shall comply 

with the requirements of paragraphs 

(a)(2)(i) through (v) of this section no 

later than November 11, 2015. The 

owner or operator shall comply with the 

approved alternative monitoring plan or 

plans pursuant to § 60.13(i) until the 

flare is in compliance with requirements 

of paragraphs (a)(2)(i) through (v) of this 

section. 

(A) The flare was an affected facility 

subject to subpart J of this part prior to 

becoming an affected facility under 

§ 60.100a. 

(B) The owner or operator had an 

approved alternative monitoring plan or 

plans pursuant to § 60.13(i) for all fuel 

gases combusted in the flare. 

(C) The flare did not have in place on 

or before September 12, 2012 an 

instrument for continuously monitoring 

and recording the concentration by 

volume (dry basis) of H2S in the fuel 

gases that is capable of complying with 

the requirements of paragraphs (a)(2)(i) 

through (v) of this section. 

(3) The owner or operator of a fuel gas 

combustion device or flare is not 

required to comply with paragraph 

(a)(1) or (2) of this section for fuel gas 

streams that are exempt under 

§§ 60.102a(g)(1)(iii) or 60.103a(h) or, for 

fuel gas streams combusted in a process 

heater, other fuel gas combustion device 

or flare that are inherently low in sulfur 

content. Fuel gas streams meeting one of 

the requirements in paragraphs (a)(3)(i) 

through (iv) of this section will be 

considered inherently low in sulfur 

content. 

* * * * * 

(b) Exemption from H2S monitoring 

requirements for low-sulfur fuel gas 

streams. The owner or operator of a fuel 

gas combustion device or flare may 

apply for an exemption from the H2S 

monitoring requirements in paragraph 

(a)(2) of this section for a fuel gas stream 

that is inherently low in sulfur content. 

A fuel gas stream that is demonstrated 

to be low-sulfur is exempt from the 

monitoring requirements of paragraphs 

(a)(1) and (2) of this section until there 

are changes in operating conditions or 

stream composition. 

(1) * * * 

(i) A description of the fuel gas 

stream/system to be considered, 

including submission of a portion of the 

appropriate piping diagrams indicating 

the boundaries of the fuel gas stream/ 

system and the affected fuel gas 

combustion device(s) or flare(s) to be 

considered; 

* * * * * 

(v) A description of how the 2 weeks 

(or seven samples for infrequently 

operated fuel gas streams/systems) of 

monitoring results compares to the 

typical range of H2S concentration (fuel 

quality) expected for the fuel gas 

stream/system going to the affected fuel 

gas combustion device or flare (e.g., the 

2 weeks of daily detector tube results for 

a frequently operated loading rack 

included the entire range of products 

loaded out and, therefore, should be 

representative of typical operating 

conditions affecting H2S content in the 

fuel gas stream going to the loading rack 

flare). 

* * * * * 

(3) * * * 

(iii) If the operation change results in 

a sulfur content that is outside the range 

of concentrations included in the 

original application and the owner or 

operator chooses not to submit new 

information to support an exemption, 

the owner or operator must begin H2S 

monitoring using daily stain sampling to 

demonstrate compliance. The owner or 

operator must begin monitoring 

according to the requirements in 

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

as soon as practicable, but in no case 

later than 180 days after the operation 

change. During daily stain tube 

sampling, a daily sample exceeding 162 

ppmv is an exceedance of the 3-hour 

H2S concentration limit. The owner or 

operator of a fuel gas combustion device 

must also determine a rolling 365-day 

average using the stain sampling results; 

an average H2S concentration of 5 ppmv 

must be used for days within the rolling 

365-day period prior to the operation 

change. 

(c) Process heaters complying with the 

NOX concentration-based limit. The 

owner or operator of a process heater 

subject to the NOX emissions limit in 

§ 60.102a(g)(2) and electing to comply 

with the applicable emissions limit in 

§ 60.102a(g)(2)(i)(A), (g)(2)(ii)(A), 

(g)(2)(iii)(A) or (g)(2)(iv)(A) shall install, 

operate, calibrate and maintain an 

instrument for continuously monitoring 

and recording the concentration (dry 

basis, 0-percent excess air) of NOX

emissions into the atmosphere 

according to the requirements in 

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

section, except as provided in paragraph 

(c)(6) of this section. The monitor must 

include an O2 monitor for correcting the 

data for excess air. 

(1) Except as provided in paragraph 

(c)(6) of this section, the owner or 

operator shall install, operate and 

maintain each NOX monitor according 

to Performance Specification 2 of 

Appendix B to part 60. The span value 

of this NOX monitor must be between 2 

and 3 times the applicable emissions 

limit, inclusive. 

* * * * * 

(6) The owner or operator of a process 

heater that has a rated heating capacity 

of less than 100 MMBtu and is equipped 

with combustion modification-based 

technology to reduce NOX emissions 

(i.e., low-NOX burners, ultra-low-NOX

burners) may elect to comply with the 

monitoring requirements in paragraphs 

(c)(1) through (5) of this section or, 

alternatively, the owner or operator of 

such a process heater shall conduct 

biennial performance tests according to 

the requirements in § 60.104a(i), 

establish a maximum excess O2

operating limit or operating curve 

according to the requirements in 

§ 60.104a(i)(6) and comply with the O2

monitoring requirements in paragraphs 

(c)(3) through (5) of this section to 

demonstrate compliance. If an O2

operating curve is used (i.e., if different 

O2 operating limits are established for 

different operating ranges), the owner or 

operator of the process heater must also 

monitor fuel gas flow rate, fuel oil flow 

rate (as applicable) and heating value 

content according to the methods 

provided in paragraphs (d)(5), (d)(6), 

and (d)(4) or (d)(7) of this section, 

respectively. 

(d) Process heaters complying with 

the NOX heating value-based or massbased limit. The owner or operator of a 

process heater subject to the NOX

emissions limit in § 60.102a(g)(2) and 

electing to comply with the applicable 

emissions limit in § 60.102a(g)(2)(i)(B) 

or (g)(2)(ii)(B) shall install, operate, 

calibrate and maintain an instrument for 

continuously monitoring and recording 

the concentration (dry basis, 0-percent 

excess air) of NOX emissions into the 

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atmosphere and shall determine the F 

factor of the fuel gas stream no less 

frequently than once per day according 

to the monitoring requirements in 

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

section. The owner or operator of a cofired process heater subject to the NOX

emissions limit in § 60.102a(g)(2) and 

electing to comply with the heating 

value-based limit in 

§ 60.102a(g)(2)(iii)(B) or (g)(2)(iv)(B) 

shall install, operate, calibrate and 

maintain an instrument for 

continuously monitoring and recording 

the concentration (dry basis, 0-percent 

excess air) of NOX emissions into the 

atmosphere according to the monitoring 

requirements in paragraph (d)(1) of this 

section; install, operate, calibrate and 

maintain an instrument for 

continuously monitoring and recording 

the flow rate of the fuel gas and fuel oil 

fed to the process heater according to 

the monitoring requirements in 

paragraph (d)(5) and (6) of this section; 

for fuel gas streams, determine gas 

composition according to the 

requirements in paragraph (d)(4) of this 

section or the higher heating value 

according to the requirements in 

paragraph (d)(7) of this section; and for 

fuel oil streams, determine the heating 

value according to the monitoring 

requirements in paragraph (d)(7) of this 

section. 

(1) Except as provided in paragraph 

(d)(8) of this section, the owner or 

operator shall install, operate and 

maintain each NOX monitor according 

to the requirements in paragraphs (c)(1) 

through (5) of this section. The monitor 

must include an O2 monitor for 

correcting the data for excess air. 

(2) Except as provided in paragraph 

(d)(3) of this section, the owner or 

operator shall sample and analyze each 

fuel stream fed to the process heater 

using the methods and equations in 

section 12.3.2 of EPA Method 19 of 

Appendix A–7 to part 60 to determine 

the F factor on a dry basis. If a single 

fuel gas system provides fuel gas to 

several process heaters, the F factor may 

be determined at a single location in the 

fuel gas system provided it is 

representative of the fuel gas fed to the 

affected process heater(s). 

(3) As an alternative to the 

requirements in paragraph (d)(2) of this 

section, the owner or operator of a gasfired process heater shall install, operate 

and maintain a gas composition 

analyzer and determine the average F 

factor of the fuel gas using the factors in 

Table 1 of this subpart and Equation 10 

of this section. If a single fuel gas system 

provides fuel gas to several process 

heaters, the F factor may be determined 

at a single location in the fuel gas 

system provided it is representative of 

the fuel gas fed to the affected process 

heater(s). 

Where: 

Fd = F factor on dry basis at 0-percent excess 

air, dscf/MMBtu. 

Xi = mole or volume fraction of each 

component in the fuel gas. 

MEVi = molar exhaust volume, dry standard 

cubic feet per mole (dscf/mol). 

MHCi = molar heat content, Btu per mole 

(Btu/mol). 

1,000,000 = unit conversion, Btu per MMBtu. 

(4) The owner or operator shall 

conduct performance evaluations of 

each compositional monitor according 

to the requirements in Performance 

Specification 9 of Appendix B to part 

60. Any of the following methods shall 

be used for conducting the relative 

accuracy evaluations: 

(i) EPA Method 18 of Appendix A–6 

to part 60; 

(ii) ASTM D1945–03 (Reapproved 

2010)(incorporated by reference-see 

§ 60.17); 

(iii) ASTM D1946–90 (Reapproved 

2006)(incorporated by reference-see 

§ 60.17); 

(iv) ASTM D6420–99 (Reapproved 

2004)(incorporated by reference-see 

§ 60.17); 

(v) GPA 2261–00 (incorporated by 

reference-see § 60.17); or 

(vi) ASTM UOP539–97 (incorporated 

by reference-see § 60.17). 

(5) The owner or operator shall 

install, operate and maintain fuel gas 

flow monitors according to the 

manufacturer’s recommendations. For 

volumetric flow meters, temperature 

and pressure monitors must be installed 

in conjunction with the flow meter or in 

a representative location to correct the 

measured flow to standard conditions 

(i.e., 68 °F and 1 atmosphere). For mass 

flow meters, use gas compositions 

determined according to paragraph 

(d)(4) of this section to determine the 

average molecular weight of the fuel gas 

and convert the mass flow to a 

volumetric flow at standard conditions 

(i.e., 68 °F and 1 atmosphere). The 

owner or operator shall conduct 

performance evaluations of each fuel gas 

flow monitor according to the 

requirements in § 60.13 and 

Performance Specification 6 of 

Appendix B to part 60. Any of the 

following methods shall be used for 

conducting the relative accuracy 

evaluations: 

(i) EPA Method 2, 2A, 2B, 2C or 2D 

of Appendix A–2 to part 60; 

(ii) ASME MFC–3M–2004 

(incorporated by reference-see § 60.17); 

(iii) ANSI/ASME MFC–4M–1986 

(Reaffirmed 2008) (incorporated by 

reference-see § 60.17); 

(iv) ASME MFC–6M–1998 

(Reaffirmed 2005) (incorporated by 

reference-see § 60.17); 

(v) ASME/ANSI MFC–7M–1987 

(Reaffirmed 2006) (incorporated by 

reference-see § 60.17); 

(vi) ASME MFC–11M–2006 

(incorporated by reference-see § 60.17); 

(vii) ASME MFC–14M–2003 

(incorporated by reference-see § 60.17); 

(viii) ASME MFC–18M–2001 

(incorporated by reference-see § 60.17); 

(ix) AGA Report No. 3, Part 1 

(incorporated by reference-see § 60.17); 

(x) AGA Report No. 3, Part 2 

(incorporated by reference-see § 60.17); 

(xi) AGA Report No. 11 (incorporated 

by reference-see § 60.17); 

(xii) AGA Report No. 7 (incorporated 

by reference-see § 60.17); and 

(xiii) API Manual of Petroleum 

Measurement Standards, Chapter 22, 

Section 2 (incorporated by reference-see 

§ 60.17). 

(6) The owner or operator shall 

install, operate and maintain each fuel 

oil flow monitor according to the 

manufacturer’s recommendations. The 

owner or operator shall conduct 

performance evaluations of each fuel oil 

flow monitor according to the 

requirements in § 60.13 and 

Performance Specification 6 of 

Appendix B to part 60. Any of the 

following methods shall be used for 

conducting the relative accuracy 

evaluations: 

(i) Any one of the methods listed in 

paragraph (d)(5) of this section that are 

applicable to fuel oil (i.e., ‘‘fluids’’); 

(ii) ANSI/ASME–MFC–5M–1985 

(Reaffirmed 2006) (incorporated by 

reference-see § 60.17); 


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(iii) ASME/ANSI MFC–9M–1988 

(Reaffirmed 2006) (incorporated by 

reference-see § 60.17); 

(iv) ASME MFC–16–2007 

(incorporated by reference-see § 60.17); 

(v) ASME MFC–22–2007 

(incorporated by reference-see § 60.17); 

or 

(vi) ISO 8316 (incorporated by 

reference-see § 60.17). 

(7) The owner or operator shall 

determine the higher heating value of 

each fuel fed to the process heater using 

any of the applicable methods included 

in paragraphs (d)(7)(i) through (ix) of 

this section. If a common fuel supply 

system provides fuel gas or fuel oil to 

several process heaters, the higher 

heating value of the fuel in each fuel 

supply system may be determined at a 

single location in the fuel supply system 

provided it is representative of the fuel 

fed to the affected process heater(s). The 

higher heating value of each fuel fed to 

the process heater must be determined 

no less frequently than once per day 

except as provided in paragraph 

(d)(7)(x) of this section. 

(i) ASTM D240–02 (Reapproved 2007) 

(incorporated by reference-see § 60.17). 

(ii) ASTM D1826–94 (Reapproved 

2003) (incorporated by reference-see 

§ 60.17). 

(iii) ASTM D1945–03 (Reapproved 

2010) (incorporated by reference-see 

§ 60.17). 

(iv) ASTM D1946–90 (Reapproved 

2006) (incorporated by reference-see 

§ 60.17). 

(v) ASTM D3588–98 (Reapproved 

2003) (incorporated by reference-see 

§ 60.17). 

(vi) ASTM D4809–06 (incorporated by 

reference-see § 60.17). 

(vii) ASTM D4891–89 (Reapproved 

2006) (incorporated by reference-see 

§ 60.17). 

(viii) GPA 2172–09 (incorporated by 

reference-see § 60.17). 

(ix) Any of the methods specified in 

section 2.2.7 of Appendix D to part 75. 

(x) If the fuel oil supplied to the 

affected co-fired process heater 

originates from a single storage tank, the 

owner or operator may elect to use the 

storage tank sampling method in section 

2.2.4.2 of Appendix D to part 75 instead 

of daily sampling, except that the most 

recent value for heating content must be 

used. 

(8) The owner or operator of a process 

heater that has a rated heating capacity 

of less than 100 MMBtu and is equipped 

with combustion modification based 

technology to reduce NOX emissions 

(i.e., low-NOX burners or ultra-low NOX

burners) may elect to comply with the 

monitoring requirements in paragraphs 

(d)(1) through (7) of this section or, 

alternatively, the owner or operator of 

such a process heater shall conduct 

biennial performance tests according to 

the requirements in § 60.104a(i), 

establish a maximum excess O2

operating limit or operating curve 

according to the requirements in 

§ 60.104a(i)(6) and comply with the O2

monitoring requirements in paragraphs 

(c)(3) through (5) of this section to 

demonstrate compliance. If an O2

operating curve is used (i.e., if different 

O2 operating limits are established for 

different operating ranges), the owner or 

operator of the process heater must also 

monitor fuel gas flow rate, fuel oil flow 

rate (as applicable) and heating value 

content according to the methods 

provided in paragraphs (d)(5), (d)(6), 

and (d)(4) or (d)(7) of this section, 

respectively. 

(e) Sulfur monitoring for assessing 

root cause analysis threshold for 

affected flares. Except as described in 

paragraphs (e)(4) and (h) of this section, 

the owner or operator of an affected 

flare subject to § 60.103a(c) through (e) 

shall determine the total reduced sulfur 

concentration for each gas line directed 

to the affected flare in accordance with 

either paragraph (e)(1), (e)(2) or (e)(3) of 

this section. Different options may be 

elected for different gas lines. If a 

monitoring system is in place that is 

capable of complying with the 

requirements related to either paragraph 

(e)(1), (e)(2) or (e)(3) of this section, the 

owner or operator of a modified flare 

must comply with the requirements 

related to either paragraph (e)(1), (e)(2) 

or (e)(3) of this section upon startup of 

the modified flare. If a monitoring 

system is not in place that is capable of 

complying with the requirements 

related to either paragraph (e)(1), (e)(2) 

or (e)(3) of this section, the owner or 

operator of a modified flare must 

comply with the requirements related to 

either paragraph (e)(1), (e)(2) or (e)(3) of 

this section no later than November 11, 

2015 or upon startup of the modified 

flare, whichever is later. 

(1) Total reduced sulfur monitoring 

requirements. The owner or operator 

shall install, operate, calibrate and 

maintain an instrument for 

continuously monitoring and recording 

the concentration of total reduced sulfur 

in gas discharged to the flare. 

(i) The owner or operator shall install, 

operate and maintain each total reduced 

sulfur monitor according to Performance 

Specification 5 of Appendix B to part 

60. The span value should be 

determined based on the maximum 

sulfur content of gas that can be 

discharged to the flare (e.g., roughly 1.1 

to 1.3 times the maximum anticipated 

sulfur concentration), but may be no 

less than 5,000 ppmv. A single dual 

range monitor may be used to comply 

with the requirements of this paragraph 

and paragraph (a)(2) of this section 

provided the applicable span 

specifications are met. 

(ii) The owner or operator shall 

conduct performance evaluations of 

each total reduced sulfur monitor 

according to the requirements in 

§ 60.13(c) and Performance 

Specification 5 of Appendix B to part 

60. For flares that routinely have flow, 

the owner or operator of each total 

reduced sulfur monitor shall use EPA 

Method 15A of Appendix A–5 to part 60 

for conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981 (incorporated by 

reference-see § 60.17) is an acceptable 

alternative to EPA Method 15A of 

Appendix A–5 to part 60. The 

alternative relative accuracy procedures 

described in section 16.0 of Performance 

Specification 2 of Appendix B to part 60 

(cylinder gas audits) may be used for 

conducting the relative accuracy 

evaluations. For flares that do not 

receive routine flow, the alternative 

relative accuracy procedures described 

in section 16.0 of Performance 

Specification 2 of Appendix B to part 60 

(cylinder gas audits) may be used for 

conducting the relative accuracy 

evaluations, except that it is not 

necessary to include as much of the 

sampling probe or sampling line as 

practical. 

(iii) The owner or operator shall 

comply with the applicable quality 

assurance procedures in Appendix F to 

part 60 for each total reduced sulfur 

monitor. 

(2) H2S monitoring requirements. The 

owner or operator shall install, operate, 

calibrate, and maintain an instrument 

for continuously monitoring and 

recording the concentration of H2S in 

gas discharged to the flare according to 

the requirements in paragraphs (e)(2)(i) 

through (iii) of this section and shall 

collect and analyze samples of the gas 

and calculate total sulfur concentrations 

as specified in paragraphs (e)(2)(iv) 

through (ix) of this section. 

(i) The owner or operator shall install, 

operate and maintain each H2S monitor 

according to Performance Specification 

7 of Appendix B to part 60. The span 

value should be determined based on 

the maximum sulfur content of gas that 

can be discharged to the flare (e.g., 

roughly 1.1 to 1.3 times the maximum 

anticipated sulfur concentration), but 

may be no less than 5,000 ppmv. A 

single dual range H2S monitor may be 

used to comply with the requirements of 

this paragraph and paragraph (a)(2) of 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56477 

this section provided the applicable 

span specifications are met. 

(ii) The owner or operator shall 

conduct performance evaluations of 

each H2S monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 7 of 

Appendix B to part 60. For flares that 

routinely have flow, the owner or 

operator shall use EPA Method 11, 15 or 

15A of Appendix A–5 to part 60 for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981 (incorporated by 

reference—see § 60.17) is an acceptable 

alternative to EPA Method 15A of 

Appendix A–5 to part 60. The 

alternative relative accuracy procedures 

described in section 16.0 of Performance 

Specification 2 of Appendix B to part 60 

(cylinder gas audits) may be used for 

conducting the relative accuracy 

evaluations. For flares that do not 

receive routine flow, the alternative 

relative accuracy procedures described 

in section 16.0 of Performance 

Specification 2 of Appendix B to part 60 

(cylinder gas audits) may be used for 

conducting the relative accuracy 

evaluations, except that it is not 

necessary to include as much of the 

sampling probe or sampling line as 

practical. 

(iii) The owner or operator shall 

comply with the applicable quality 

assurance procedures in Appendix F to 

part 60 for each H2S monitor. 

(iv) In the first 10 operating days after 

the date the flare must begin to comply 

with § 60.103a(c)(1), the owner or 

operator shall collect representative 

daily samples of the gas discharged to 

the flare. The samples may be grab 

samples or integrated samples. The 

owner or operator shall take subsequent 

representative daily samples at least 

once per week or as required in 

paragraph (e)(2)(ix) of this section. 

(v) The owner or operator shall 

analyze each daily sample for total 

sulfur using either EPA Method 15A of 

Appendix A–5 to part 60, EPA Method 

16A of Appendix A–6 to part 60, ASTM 

Method D4468–85 (Reapproved 2006) 

(incorporated by reference—see § 60.17) 

or ASTM Method D5504–08 

(incorporated by reference—see § 60.17). 

(vi) The owner or operator shall 

develop a 10-day average total sulfur-toH2S ratio and 95-percent confidence 

interval as follows: 

(A) Calculate the ratio of the total 

sulfur concentration to the H2S 

concentration for each day during 

which samples are collected. 

(B) Determine the 10-day average total 

sulfur-to-H2S ratio as the arithmetic 

average of the daily ratios calculated in 

paragraph (e)(2)(vi)(A) of this section. 

(C) Determine the acceptable range for 

subsequent weekly samples based on 

the 95-percent confidence interval for 

the distribution of daily ratios based on 

the 10 individual daily ratios using 

Equation 11 of this section. 

Where: 

AR = Acceptable range of subsequent ratio 

determinations, unitless. 

RatioAvg = 10-day average total sulfur-to-H2S 

concentration ratio, unitless. 

2.262 = t-distribution statistic for 95-percent 

2-sided confidence interval for 10 

samples (9 degrees of freedom). 

SDev = Standard deviation of the 10 daily 

average total sulfur-to-H2S concentration 

ratios used to develop the 10-day average 

total sulfur-to-H2S concentration ratio, 

unitless. 

(vii) For each day during the period 

when data are being collected to 

develop a 10-day average, the owner or 

operator shall estimate the total sulfur 

concentration using the measured total 

sulfur concentration measured for that 

day. 

(viii) For all days other than those 

during which data are being collected to 

develop a 10-day average, the owner or 

operator shall multiply the most recent 

10-day average total sulfur-to-H2S ratio 

by the daily average H2S concentrations 

obtained using the monitor as required 

by paragraph (e)(2)(i) through (iii) of this 

section to estimate total sulfur 

concentrations. 

(ix) If the total sulfur-to-H2S ratio for 

a subsequent weekly sample is outside 

the acceptable range for the most recent 

distribution of daily ratios, the owner or 

operator shall develop a new 10-day 

average ratio and acceptable range based 

on data for the outlying weekly sample 

plus data collected over the following 9 

operating days. 

(3) SO2 monitoring requirements. The 

owner or operator shall install, operate, 

calibrate and maintain an instrument for 

continuously monitoring and recording 

the concentration of SO2 from a process 

heater or other fuel gas combustion 

device that is combusting gas 

representative of the fuel gas in the flare 

gas line according to the requirements 

in paragraph (a)(1) of this section, 

determine the F factor of the fuel gas at 

least daily according to the 

requirements in paragraphs (d)(2) 

through (4) of this section, determine 

the higher heating value of the fuel gas 

at least daily according to the 

requirements in paragraph (d)(7) of this 

section and calculate the total sulfur 

content (as SO2) in the fuel gas using 

Equation 12 of this section. 

Where: 

TSFG = Total sulfur concentration, as SO2, in 

the fuel gas, ppmv. 

CSO2 = Concentration of SO2 in the exhaust 

gas, ppmv (dry basis at 0-percent excess 

air). 

Fd = F factor gas on dry basis at 0-percent 

excess air, dscf/MMBtu. 

HHVFG = Higher heating value of the fuel gas, 

MMBtu/scf. 

(4) Exemptions from sulfur 

monitoring requirements. Flares 

identified in paragraphs (e)(4)(i) through 

(iv) of this section are exempt from the 

requirements in paragraphs (e)(1) 

through (3) of this section. For each 

such flare, except as provided in 

paragraph (e)(4)(iv), engineering 

calculations shall be used to calculate 

the SO2 emissions in the event of a 

discharge that may trigger a root cause 

analysis under § 60.103a(c)(1). 

(i) Flares that can only receive: 

(A) Fuel gas streams that are 

inherently low in sulfur content as 

described in paragraph (a)(3)(i) through 

(iv) of this section; and/or 

(B) Fuel gas streams that are 

inherently low in sulfur content for 

which the owner or operator has 

applied for an exemption from the H2S 

monitoring requirements as described in 

paragraph (b) of this section. 

(ii) Emergency flares, provided that 

for each such flare, the owner or 

operator complies with the monitoring 

alternative in paragraph (g) of this 

section. 


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56478 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

(iii) Flares equipped with flare gas 

recovery systems designed, sized and 

operated to capture all flows except 

those resulting from startup, shutdown 

or malfunction, provided that for each 

such flare, the owner or operator 

complies with the monitoring 

alternative in paragraph (g) of this 

section. 

(iv) Secondary flares that receive gas 

diverted from the primary flare. In the 

event of a discharge from the secondary 

flare, the sulfur content measured by the 

sulfur monitor on the primary flare 

should be used to calculate SO2

emissions, regardless of whether or not 

the monitoring alternative in paragraph 

(g) of this section is selected for the 

secondary flare. 

(f) Flow monitoring for flares. Except 

as provided in paragraphs (f)(2) and (h) 

of this section, the owner or operator of 

an affected flare subject to § 60.103a(c) 

through (e) shall install, operate, 

calibrate and maintain, in accordance 

with the specifications in paragraph 

(f)(1) of this section, a CPMS to measure 

and record the flow rate of gas 

discharged to the flare. If a flow monitor 

is not already in place, the owner or 

operator of a modified flare shall 

comply with the requirements of this 

paragraph by no later than November 

11, 2015 or upon startup of the modified 

flare, whichever is later. 

(1) The owner or operator shall 

install, calibrate, operate and maintain 

each flow monitor according to the 

manufacturer’s procedures and 

specifications and the following 

requirements. 

(i) Locate the monitor in a position 

that provides a representative 

measurement of the total gas flow rate. 

(ii) Use a flow sensor with a 

measurement sensitivity of no more 

than 5 percent of the flow rate or 10 

cubic feet per minute, whichever is 

greater. 

(iii) Use a flow monitor that is 

maintainable online, is able to 

continuously correct for temperature 

and pressure and is able to record flow 

in standard conditions (as defined in 

§ 60.2) over one-minute averages. 

(iv) At least quarterly, perform a 

visual inspection of all components of 

the monitor for physical and operational 

integrity and all electrical connections 

for oxidation and galvanic corrosion if 

the flow monitor is not equipped with 

a redundant flow sensor. 

(v) Recalibrate the flow monitor in 

accordance with the manufacturer’s 

procedures and specifications biennially 

(every two years) or at the frequency 

specified by the manufacturer. 

(2) Emergency flares, secondary flares 

and flares equipped with flare gas 

recovery systems designed, sized and 

operated to capture all flows except 

those resulting from startup, shutdown 

or malfunction are not required to 

install continuous flow monitors; 

provided, however, that for any such 

flare, the owner or operator shall 

comply with the monitoring alternative 

in paragraph (g) of this section. 

(g) Alternative monitoring for certain 

flares equipped with water seals. The 

owner or operator of an affected flare 

subject to § 60.103a(c) through (e) that 

can be classified as either an emergency 

flare, a secondary flare or a flare 

equipped with a flare gas recovery 

system designed, sized and operated to 

capture all flows except those resulting 

from startup, shutdown or malfunction 

may, as an alternative to the sulfur and 

flow monitoring requirements of 

paragraphs (e) and (f) of this section, 

install, operate, calibrate and maintain, 

in accordance with the requirements in 

paragraphs (g)(1) through (7) of this 

section, a CPMS to measure and record 

the pressure in the flare gas header 

between the knock-out pot and water 

seal and to measure and record the 

water seal liquid level. If the required 

monitoring systems are not already in 

place, the owner or operator of a 

modified flare shall comply with the 

requirements of this paragraph by no 

later than November 11, 2015 or upon 

startup of the modified flare, whichever 

is later. 

(1) Locate the pressure sensor(s) in a 

position that provides a representative 

measurement of the pressure and locate 

the liquid seal level monitor in a 

position that provides a representative 

measurement of the water column 

height. 

(2) Minimize or eliminate pulsating 

pressure, vibration and internal and 

external corrosion. 

(3) Use a pressure sensor and level 

monitor with a minimum tolerance of 

1.27 centimeters of water. 

(4) Using a manometer, check 

pressure sensor calibration quarterly. 

(5) Conduct calibration checks any 

time the pressure sensor exceeds the 

manufacturer’s specified maximum 

operating pressure range or install a new 

pressure sensor. 

(6) In a cascaded flare system that 

employs multiple secondary flares, 

pressure and liquid level monitoring is 

required only on the first secondary 

flare in the system (i.e., the secondary 

flare with the lowest pressure release set 

point). 

(7) This alternative monitoring option 

may be elected only for flares with four 

or fewer pressure exceedances required 

to be reported under § 60.108a(d)(5) 

(‘‘reportable pressure exceedances’’) in 

any 365 consecutive calendar days. 

Following the fifth reportable pressure 

exceedance in a 365-day period, the 

owner or operator must comply with the 

sulfur and flow monitoring 

requirements of paragraphs (e) and (f) of 

this section as soon as practical, but no 

later than 180 days after the fifth 

reportable pressure exceedance in a 365- 

day period. 

(h) Alternative monitoring for flares 

located in the BAAQMD or SCAQMD. 

An affected flare subject to this subpart 

located in the BAAQMD may elect to 

comply with the monitoring 

requirements in both BAAQMD 

Regulation 12, Rule 11 and BAAQMD 

Regulation 12, Rule 12 as an alternative 

to complying with the requirements of 

paragraphs (e) and (f) of this section. An 

affected flare subject to this subpart 

located in the SCAQMD may elect to 

comply with the monitoring 

requirements in SCAQMD Rule 1118 as 

an alternative to complying with the 

requirements of paragraphs (e) and (f) of 

this section. 

(i) Excess emissions. For the purpose 

of reports required by § 60.7(c), periods 

of excess emissions for fuel gas 

combustion devices subject to the 

emissions limitations in § 60.102a(g) 

and flares subject to the concentration 

requirement in § 60.103a(h) are defined 

as specified in paragraphs (i)(1) through 

(5) of this section. Determine a rolling 

3-hour or a rolling daily average as the 

arithmetic average of the applicable 1- 

hour averages (e.g., a rolling 3-hour 

average is the arithmetic average of 

three contiguous 1-hour averages). 

Determine a rolling 30-day or a rolling 

365-day average as the arithmetic 

average of the applicable daily averages 

(e.g., a rolling 30-day average is the 

arithmetic average of 30 contiguous 

daily averages). 

(1) SO 2 or H2S limits for fuel gas 

combustion devices. (i) If the owner or 

operator of a fuel gas combustion device 

elects to comply with the SO2 emission 

limits in § 60.102a(g)(1)(i), each rolling 

3-hour period during which the average 

concentration of SO2 as measured by the 

SO2 continuous monitoring system 

required under paragraph (a)(1) of this 

section exceeds 20 ppmv, and each 

rolling 365-day period during which the 

average concentration of SO2 as 

measured by the SO2 continuous 

monitoring system required under 

paragraph (a)(1) of this section exceeds 

8 ppmv. 

(ii) If the owner or operator of a fuel 

gas combustion device elects to comply 

with the H2S concentration limits in 

§ 60.102a(g)(1)(ii), each rolling 3-hour 

period during which the average 

concentration of H2S as measured by the 

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Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 56479 

H2S continuous monitoring system 

required under paragraph (a)(2) of this 

section exceeds 162 ppmv and each 

rolling 365-day period during which the 

average concentration as measured by 

the H2S continuous monitoring system 

under paragraph (a)(2) of this section 

exceeds 60 ppmv. 

(iii) If the owner or operator of a fuel 

gas combustion device becomes subject 

to the requirements of daily stain tube 

sampling in paragraph (b)(3)(iii) of this 

section, each day during which the 

daily concentration of H2S exceeds 162 

ppmv and each rolling 365-day period 

during which the average concentration 

of H2S exceeds 60 ppmv. 

(2) H2S concentration limits for flares. 

(i) Each rolling 3-hour period during 

which the average concentration of H2S 

as measured by the H2S continuous 

monitoring system required under 

paragraph (a)(2) of this section exceeds 

162 ppmv. 

(ii) If the owner or operator of a flare 

becomes subject to the requirements of 

daily stain tube sampling in paragraph 

(b)(3)(iii) of this section, each day 

during which the daily concentration of 

H2S exceeds 162 ppmv. 

(3) Rolling 30-day average NOX limits 

for fuel gas combustion devices. Each 

rolling 30-day period during which the 

average concentration of NOX as 

measured by the NOX continuous 

monitoring system required under 

paragraph (c) or (d) of this section 

exceeds: 

(i) For a natural draft process heater, 

40 ppmv and, if monitored according to 

§ 60.107a(d), 0.040 lb/MMBtu; 

(ii) For a forced draft process heater, 

60 ppmv and, if monitored according to 

§ 60.107a(d), 0.060 lb/MMBtu; and 

(iii) For a co-fired process heater 

electing to comply with the NOX limit 

in § 60.102a(g)(2)(iii)(A) or (g)(2)(iv)(A), 

150 ppmv. 

(iv) The site-specific limit determined 

by the Administrator under § 60.102a(i). 

(4) Daily NOX limits for fuel gas 

combustion devices. Each day during 

which the concentration of NOX as 

measured by the NOX continuous 

monitoring system required under 

paragraph (d) of this section exceeds the 

daily average emissions limit calculated 

using Equation 3 in 

§ 60.102a(g)(2)(iii)(B) or Equation 4 in 

§ 60.102a(g)(2)(iv)(B). 

(5) Daily O2 limits for fuel gas 

combustion devices. Each day during 

which the concentration of O2 as 

measured by the O2 continuous 

monitoring system required under 

paragraph (c)(6) of this section exceeds 

the O2 operating limit or operating curve 

determined during the most recent 

biennial performance test. 

■ 18. Section 60.108a is amended by: 

■ a. Revising paragraph (b); 

■ b. Revising paragraph (c)(1); 

■ c. Revising paragraph (c)(6) 

introductory text and paragraphs 

(c)(6)(ii) through (vi); 

■ d. Adding paragraphs (c)(6)(vii), (viii), 

(ix), (x) and (xi); 

■ e. Adding paragraph (c)(7); and 

■ f. Revising paragraph (d)(5). 

The revisions and additions read as 

follows: 

§ 60.108a Recordkeeping and reporting 

requirements. 

* * * * * 

(b) Each owner or operator subject to 

an emissions limitation in § 60.102a 

shall notify the Administrator of the 

specific monitoring provisions of 

§§ 60.105a, 60.106a and 60.107a with 

which the owner or operator intends to 

comply. Each owner or operator of a cofired process heater subject to an 

emissions limitation in 

§ 60.102a(g)(2)(iii) or (iv) shall submit to 

the Administrator documentation 

showing that the process heater meets 

the definition of a co-fired process 

heater in § 60.101a. Notifications 

required by this paragraph shall be 

submitted with the notification of initial 

startup required by § 60.7(a)(3). 

(c) * * * 

(1) A copy of the flare management 

plan. 

* * * * * 

(6) Records of discharges greater than 

500 lb SO2 in any 24-hour period from 

any affected flare, discharges greater 

than 500 lb SO2 in excess of the 

allowable limits from a fuel gas 

combustion device or sulfur recovery 

plant and discharges to an affected flare 

in excess of 500,000 scf above baseline 

in any 24-hour period as required by 

§ 60.103a(c). If the monitoring 

alternative provided in § 60.107a(g) is 

selected, the owner or operator shall 

record any instance when the flare gas 

line pressure exceeds the water seal 

liquid depth, except for periods 

attributable to compressor staging that 

do not exceed the staging time specified 

in § 60.103a(a)(3)(vii)(C). The following 

information shall be recorded no later 

than 45 days following the end of a 

discharge exceeding the thresholds: 

* * * * * 

(ii) The date and time the discharge 

was first identified and the duration of 

the discharge. 

(iii) The measured or calculated 

cumulative quantity of gas discharged 

over the discharge duration. If the 

discharge duration exceeds 24 hours, 

record the discharge quantity for each 

24-hour period. For a flare, record the 

measured or calculated cumulative 

quantity of gas discharged to the flare 

over the discharge duration. If the 

discharge duration exceeds 24 hours, 

record the quantity of gas discharged to 

the flare for each 24-hour period. 

Engineering calculations are allowed for 

fuel gas combustion devices, but are not 

allowed for flares, except for those 

complying with the alternative 

monitoring requirements in § 60.107a(g). 

(iv) For each discharge greater than 

500 lb SO2 in any 24-hour period from 

a flare, the measured total sulfur 

concentration or both the measured H2S 

concentration and the estimated total 

sulfur concentration in the fuel gas at a 

representative location in the flare inlet. 

(v) For each discharge greater than 

500 lb SO2 in excess of the applicable 

short-term emissions limit in 

§ 60.102a(g)(1) from a fuel gas 

combustion device, either the measured 

concentration of H2S in the fuel gas or 

the measured concentration of SO2 in 

the stream discharged to the 

atmosphere. Process knowledge can be 

used to make these estimates for fuel gas 

combustion devices, but cannot be used 

to make these estimates for flares, 

except as provided in § 60.107a(e)(4). 

(vi) For each discharge greater than 

500 lb SO2 in excess of the allowable 

limits from a sulfur recovery plant, 

either the measured concentration of 

reduced sulfur or SO2 discharged to the 

atmosphere. 

(vii) For each discharge greater than 

500 lb SO2 in any 24-hour period from 

any affected flare or discharge greater 

than 500 lb SO2 in excess of the 

allowable limits from a fuel gas 

combustion device or sulfur recovery 

plant, the cumulative quantity of H2S 

and SO2 released into the atmosphere. 

For releases controlled by flares, assume 

99-percent conversion of reduced sulfur 

or total sulfur to SO2. For fuel gas 

combustion devices, assume 99-percent 

conversion of H2S to SO2. 

(viii) The steps that the owner or 

operator took to limit the emissions 

during the discharge. 

(ix) The root cause analysis and 

corrective action analysis conducted as 

required in § 60.103a(d), including an 

identification of the affected facility, the 

date and duration of the discharge, a 

statement noting whether the discharge 

resulted from the same root cause(s) 

identified in a previous analysis and 

either a description of the recommended 

corrective action(s) or an explanation of 

why corrective action is not necessary 

under § 60.103a(e). 

(x) For any corrective action analysis 

for which corrective actions are required 

in § 60.103a(e), a description of the 

corrective action(s) completed within 

the first 45 days following the discharge 

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56480 Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012 / Rules and Regulations 

and, for action(s) not already completed, 

a schedule for implementation, 

including proposed commencement and 

completion dates. 

(xi) For each discharge from any 

affected flare that is the result of a 

planned startup or shutdown of a 

refinery process unit or ancillary 

equipment connected to the affected 

flare, a statement that a root cause 

analysis and corrective action analysis 

are not necessary because the owner or 

operator followed the flare management 

plan. 

(7) If the owner or operator elects to 

comply with § 60.107a(e)(2) for a flare, 

records of the H2S and total sulfur 

analyses of each grab or integrated 

sample, the calculated daily total sulfurto-H2S ratios, the calculated 10-day 

average total sulfur-to-H2S ratios and the 

95-percent confidence intervals for each 

10-day average total sulfur-to-H2S ratio. 

(d) * * * 

(5) The information described in 

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

discharges listed in paragraph (c)(6) of 

this section. For a flare complying with 

the monitoring alternative under 

§ 60.107a(g), following the fifth 

discharge required to be recorded under 

paragraph (c)(6) of this section and 

reported under this paragraph, the 

owner or operator shall include 

notification that monitoring systems 

will be installed according to 

§ 60.107a(e) and (f) within 180 days 

following the fifth discharge. 

* * * * * 

■ 19. Section 60.109a is amended by 

revising paragraph (b) introductory text 

and adding paragraph (b)(4) to read as 

follows: 

§ 60.109a Delegation of authority. 

* * * * * 

(b) In delegating implementation and 

enforcement authority of this subpart to 

a state, local or tribal agency, the 

approval authorities contained in 

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

section are retained by the 

Administrator of the U.S. EPA and are 

not transferred to the state, local or 

tribal agency. 

* * * * * 

(4) Approval of an application for an 

alternative means of emission limitation 

under § 60.103a(j) of this subpart. 

■ 20. Table 1 to subpart Ja is added to 

read as follows: 

TABLE 1 TO SUBPART JA OF PART

60—MOLAR EXHAUST VOLUMES AND

MOLAR HEAT CONTENT OF FUEL

GAS CONSTITUENTS

Constituent MEVa

dscf/mol 

MHCb

Btu/mol 

Methane (CH4) .......... 7.29 842 

Ethane (C2H6) ........... 12.96 1,475 

Hydrogen (H2) ........... 1.61 269 

Ethene (C2H4) ........... 11.34 1,335 

Propane (C3H8) ......... 18.62 2,100 

Propene (C3H6) ......... 17.02 1,947 

Butane (C4H10) ......... 24.30 2,717 

Butene (C4H8) ........... 22.69 2,558 

Inerts ......................... 0.85 0 

a MEV = molar exhaust volume, dry standard cubic feet per gram-mole (dscf/g-mol) at 

standard conditions of 68 °F and 1 atmosphere. b MHC = molar heat content (higher heating 

value basis), Btu per gram-mole (Btu/g-mol). 

[FR Doc. 2012–20866 Filed 9–11–12; 8:45 am] 

BILLING CODE 6560–50–P 

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