Document ID: EPA-HQ-OAR-2007-0011-0320
Agency: epa
Document Type: Rule
Title: Standards of Performance for Petroleum Refineries; Standards of Performance for Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007
Posted Date: 2012-09-12T04:00Z

[Federal Register Volume 77, Number 177 (Wednesday, September 12, 2012)]
[Rules and Regulations]
[Pages 56421-56480]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-20866]

[[Page 56421]]

Vol. 77

Wednesday,

No. 177

September 12, 2012

Part III

Environmental Protection Agency

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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

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

[[Page 56422]]

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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.

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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.

[[Page 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-  NOX Emission Limits....  40 ppmv................  150 ppmv or Weighted
 fired (oil and gas) Burners.                                                             average based on oil
                                                                                          at 0.40 lb/MM BTU and
                                                                                          gas at 0.11 lb/MM BTU.
Natural Draft Process Heaters with Co- NOX Emission Limits....  40 ppmv................  150 ppmv or weighted
 fired (oil and gas) Burners.                                                             average based on oil
                                                                                          at 0.35 lb/MM BTU and
                                                                                          gas at 0.06 lb/MM BTU.
Process Heaters......................  Alternate Emission       None...................  Case by case approval
                                        Standards.                                        for some
                                                                                          circumstances.
Flares...............................  Applicability..........  New or reconstructed     Similar, except
                                                                 flare systems or         specific list of
                                                                 existing flare systems   connections that do
                                                                 that are physically      not trigger
                                                                 altered to increase      applicability.
                                                                 flow or to add new
                                                                 connections.
Fuel gas combustion devices..........  H2S concentration limit  162 ppmv H2S (3-hour     162 ppmv H2S (3-hour
                                                                 average); 60 ppmv H2S    average); No 60 ppmv
                                                                 (annual rolling          H2S long term
                                                                 average).                concentration limit
                                                                                          for flares.
Flares...............................  Compliance date for      Comply with H2S limit    Comply with H2S limit
                                        modified flares.         at start-up, and all     at start-up (except
                                                                 other requirements       for modified flares
                                                                 within 1 year.           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   No limits.
                                                                 limit of 250,000 scfd.

[[Page 56424]]

 
Flares...............................  Root Cause Analysis and  RCA/CA required on       RCA/CA required for
                                        Corrective Action (RCA/  upsets or malfunctions   500,000 scfd above
                                        CA).                     in excess of 500,000     base load and 500 lbs
                                                                 scfd or 500 lbs/day      SO2 in any 24-hour
                                                                 SO2 from SSM.            period.
Flares...............................  Flow monitoring........  Continuous.............  Continuous except for
                                                                                          intermittent/emergency
                                                                                          only flares with water
                                                                                          seal monitoring and
                                                                                          limited releases.
Flares...............................  Sulfur Monitoring......  Continuous Total         Continuous TRS, using
                                                                 Reduced Sulfur (TRS).    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 concentration-based nitrogen 
oxide (NOX) emissions limits and alternative heating value-
based 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. Co-fired 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 long-term 
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

[[Page 56425]]

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\
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    \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 concentration-response 
function, the revision of the value-of-a-statistical-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.
---------------------------------------------------------------------------

    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]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  Natural gas                      Annual        Annual        Annual          Cost
                                        Total     Total annual  offset/product   Total annual     emission      emission      emission     effectiveness
      Subpart Ja requirements       capital cost  cost without     recovery      cost ($1,000/   reductions    reductions    reductions       ($/ton
                                       ($1,000)      credit         credit            yr)        (tons SO2/    (tons NOX/    (tons VOC/      emissions
                                                   ($1,000/yr)     ($1,000)                          yr)           yr)           yr)         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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ All estimates are rounded to two significant figures so numbers may not sum down columns.
\2\ The 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

[[Page 56426]]

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 benefit-cost 
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 
provision\2\; (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.
---------------------------------------------------------------------------

    \2\ The 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.''
---------------------------------------------------------------------------

    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

[[Page 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 site-specific 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

[[Page 56428]]

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 site-specific 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 
concentration-based NOX emissions limit for newly 
constructed, modified and reconstructed forced draft process heaters is 
60 ppmv (dry basis, corrected to 0-percent excess air) determined daily 
on a 30-day rolling average basis. The heating value-based 
NOX emissions limit for newly constructed, modified and 
reconstructed forced draft process heaters is 0.060 lb/MMBtu higher 
heating value basis determined daily on a 30-day rolling average basis. 
The higher limit for new forced draft process heaters (at proposal, the 
limit was 40 ppmv) is based on additional data and a re-evaluation of 
BSER, as described later in this preamble. As with natural draft 
process heaters, the averaging time for both of these limits is shorter 
than proposed, and the final heating value-based NOX 
emissions limit is a more direct numerical conversion from 60 ppmv 
NOX. Section IV.A of this preamble provides additional 
information regarding the rationale and analyses leading to these final 
amendments.
    For each of these subcategories, a process heater need only meet 
either the concentration-based NOX emissions limit or the 
heating value-based NOX emissions limit. The refinery owner 
or operator may choose to comply with either limit at any time, 
provided that they are monitoring the appropriate variables to assess 
the heating value-based NOX emissions limit. If the 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       30-day rolling
                               average.              average.
Natural Draft NOX Emission    40 ppmv or 0.035 lb/  40 ppmv or 0.04 lb/
 Limits.                       MM BTU.               MM BTU.
Forced Draft NOX Emission     New: 40 ppmv or       60 ppmv or 0.06 lb/
 Limits.                       0.035 lb/MM BTU.      MM BTU.
                              M/R: 60 ppmv or
                               0.055 lb/MM BTU.
Co-fired Burner (oil and      150 ppmv or Weighted  150 ppmv or Weighted
 gas) NOX Emission Limits.     average based on      average based on
                               oil at 0.27 lb/MM     oil at 0.40 lb/MM
                               BTU and gas at 0.08   BTU and gas at 0.11
                               lb/MM BTU.            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 co-fired process heater must choose 
one emissions limit and show compliance with that limit. For co-fired 
natural draft process heaters, the daily average emissions limit is 
based on a limit of 0.06 lb/MMBtu for the gas portion of the firing and 
0.35 lb/MMBtu for the oil portion of the firing. For co-fired forced 
draft process heaters, the daily average emissions limit is based on a 
limit of 0.11 lb/MMBtu for the gas portion of the firing and 0.40 lb/
MMBtu for the oil portion of the firing. These limits are different 
than proposed, based on a re-evaluation 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

[[Page 56429]]

that they cannot apply the BSER of ultra-low NOX burners or 
otherwise meet the applicable limit and some co-fired units may not be 
able to achieve the NOX limitations even with ultra-low 
NOX burner control technology. In addition, commenters noted 
that downwardly fired process heaters with induced draft fans have 
similar NOX control issues as forced draft heaters, but the 
definition of forced draft heater does not include these induced draft 
heaters (these are defined as natural draft process heaters). 
Therefore, we added a provision to allow induced draft process heaters 
with downwardly-firing burners to use the alternative compliance 
option.
    Finally, we note that the emissions limits for forced draft and 
natural draft gas-fired process heaters are based on the performance of 
ultra-low NOX burner control technologies. The ultra-low 
NOX burner technology suppliers recommend operating with 
higher excess air rates at low firing rates (at or below approximately 
one-half of the maximum firing capacity), which causes higher 
NOX concentrations at low firing rates. Therefore, all types 
of process heaters with ultra-low NOX burner control 
technologies may be unable to meet the emissions limits if they are 
operated at low firing rates for an extended period of time. Requesting 
a site-specific emissions limit requires a detailed demonstration that 
the application of the ultra-low NOX burner technology is 
not feasible or that the technology cannot meet the NOX 
emissions limits given the conditions of the process heater (downward 
fired induced draft, co-fired or prolonged turndown); the refinery must 
also conduct source tests in developing a site-specific emissions limit 
for its process heater. This analysis must be submitted to and approved 
by the Administrator.
    We are finalizing the proposed clarification that owners and 
operators of process heaters in any subcategory with a rated heating 
capacity of less than 100 million British thermal units per hour 
(MMBtu/hr) have the option of using CEMS. The final rule states that 
owners and operators of process heaters subject to 40 CFR part 60, 
subpart Ja should use CEMS to demonstrate compliance unless the heater 
is equipped with combustion modification-based technology (low-
NOX burners or ultra-low NOX burners) with a 
rated heating capacity of less than 100 MMBtu/hr; owners and operators 
of those specific process heaters have the alternative option of 
biennial source testing to determine compliance. As requested by 
commenters, we have provided additional detail in the final rule 
regarding how to develop the O2 operating limit, including 
provisions on how to develop an O2 operating curve to ensure 
compliance with the NOX emission limit at different process 
heater firing rates. We are requiring that owners and operators with 
process heaters in any subcategory that are complying using biennial 
source testing establish a maximum excess 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 long-term 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 long-term 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,

[[Page 56430]]

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.
---------------------------------------------------------------------------

    \3\ Background 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).
---------------------------------------------------------------------------

    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

[[Page 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

[[Page 56432]]

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.
---------------------------------------------------------------------------

    \4\ As noted above, the proposed amendments used the term 
``period of the exceedance'' for fuel gas combustion devices. That 
term was intended to have the same meaning as a period of excess 
emissions (or multiple consecutive periods of excess emissions), as 
defined in 40 CFR 60.106a(b) or 40 CFR 60.107a(i)). Therefore, the 
final amendments refer to ``one or more consecutive periods of 
excess emissions'' rather than ``period of the exceedance.''
---------------------------------------------------------------------------

    Finally, we are finalizing the amendments at 40 CFR 60.108a(c) and 
(d) mostly as proposed to clarify recordkeeping and reporting when a 
root cause analysis and corrective action analysis are required. These 
clarifications were needed to more clearly delineate the differences in 
the recordkeeping and reporting requirements for flares, fuel gas 
combustion devices and sulfur recovery plants. The differences between 
the proposed amendments and the final amendments are corrections to be 
consistent with changes to the root cause analysis and corrective 
action analysis requirements already described. We are also finalizing 
40 CFR 60.108a(c), as proposed, to add recordkeeping requirements for 
the proposed monitoring option that is based on periodic manual 
sampling and analysis to determine the total sulfur-to-H2S 
ratio.

D. What are the final amendments to the definitions in 40 CFR part 60, 
subpart Ja?

    We proposed amendments to a number of definitions in 40 CFR 
60.101a. This section describes whether we are finalizing the 
amendments as proposed, finalizing an amendment different than (but as 
a logical outgrowth of) what was proposed or not finalizing the 
proposed amendment.
    We are finalizing amendments to the definitions of ``flexicoking 
unit'' and ``fluid coking unit,'' as proposed.
    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

[[Page 56433]]

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
------------------------------------------------------------------------
                                                Technical correction and
                   Section                               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 Sec.
                                                60.102a(b)(1) shall
                                                comply with the
                                                requirements in
                                                paragraphs (b)(1)
                                                through (3) of this
                                                section'' with ``in Sec.
                                                  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

[[Page 56434]]

comments received during the comment period and responses thereto, as 
well as more detailed summaries of the comments addressed in this 
preamble, can be found in Standards of Performance for Petroleum 
Refineries: Background Information for Final Amendments--Summary of 
Public Comments and Responses, which is included in the docket for the 
final amendments (Docket ID No. EPA-OAR-HQ-2007-0011). The docket also 
contains further details on all the analyses summarized in the 
responses below.
    In responding to the public comments, we re-evaluated the cost and 
emission reduction impact estimates of some of the control options and 
re-evaluated the related BSER determinations. In our BSER 
determinations, we took all relevant factors into account consistent 
with other agency decisions.

A. Process Heaters

    Comment: Commenters stated that new forced draft process heaters 
cannot meet the proposed emissions limit of 40 ppmv NOX, so 
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 
concentration-based 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

[[Page 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

[[Page 56436]]

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 value-based emissions limits in the final 
rule, especially when the unit is operated at turndown for extended 
periods (e.g., for 20 days or more compared to the 30-day averaging 
time). As the need for an alternative limit appears to be limited to a 
few process heaters and the optimal O2 concentration is 
expected to vary, based on fuel gas composition, we determined that a 
site-specific emissions limit was the best approach to account for 
these extended turndown conditions. As such, the final rule provides 
owners and operators that have a process heater operating in turndown 
for an extended period of time the option of developing a site-specific 
emissions limit that would apply to those operating conditions and 
requesting approval from the Administrator to use that limit.
    For process heaters between 40 and 100 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 gas-fired process heaters). We have also revised the nomenclature 
of the daily average emissions limit in Equations 3 and 4 (proposed 
Equation 3) to be clear that we intend the limit to be determined on a 
daily basis rather than on an hourly basis.
---------------------------------------------------------------------------

    \5\ The 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.
---------------------------------------------------------------------------

    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

[[Page 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 
site-specific emissions limit, as allowed above, for process heaters 
that operate for extended periods under turndown.

B. Flares

    Comment: Several commenters asserted that routine connections to a 
flare should not be considered modifications of the flare because they 
do not change the maximum physical capacity of the flare and do not 
generally increase emissions. One commenter asserted that the 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

[[Page 56438]]

do not result in an increase in emissions from a flare. The commenters 
suggested numerous specific connections that should not be considered 
modifications, including:
    (1) Connections made to upgrade or enhance (not just to install) a 
flare gas recovery system;
    (2) Connections made for flare gas sulfur removal;
    (3) Connections made to install back-up equipment;
    (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

[[Page 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 case-by-case basis to determine whether these 
connections result in a flare modification. We expect that, if these 
connections are made for flare monitoring purposes, these connections 
are already excluded in the exemption for flare monitoring systems. If 
the ``SIS'' are process unit analyzers and the new connections are 
being made to connect the analyzer exhaust to the flare, these 
connections would be considered a modification, as previously 
discussed. The commenter may also be referring to new connections 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 back-up (redundant) equipment 
associated with the flare (such as a back-up compressor) that does not 
increase the capacity of the flare.
    (7) Replacing piping or moving an existing connection from a 
refinery process unit to a new location in the same flare, provided the 
new pipe diameter is less than or equal to the

[[Page 56440]]

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

[[Page 56441]]

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 BSER \7\ be in effect at all times for flares.
---------------------------------------------------------------------------

    \6\ The comments submitted referenced ``fuel gas combustion 
devices'' as the affected source when describing the exemption 
during SSM events. However, the exemption only applies to flares. 
See 40 CFR 60.103a(h). The discussion in this 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).
    \7\ The commenter asserted, without providing support, that it 
is not BSER to exempt flares from the H2S concentration 
limits during startup and shutdown events. The commenter also stated 
that the EPA, at a minimum, must demonstrate how the exemption from 
the H2S concentration limits during SSM events does, in 
fact, represent BSER, but the commenter stated that the EPA has 
failed to make this demonstration.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \8\ The commenter cited the EPA's rationale for proposing work 
practice standards for flaring in which we state: ``It is not 
feasible to prescribe or enforce a standard of performance for these 
sources because either the pollution 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.''
---------------------------------------------------------------------------

    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

[[Page 56442]]

``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.
---------------------------------------------------------------------------

    \9\ Turbulence is needed to insure good mixing at the flare, but 
is affected by whether the flare is assisted with air or steam or 
non-assisted.
---------------------------------------------------------------------------

    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 source-specific 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

[[Page 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 long-term 60 ppmv H2S fuel 
gas concentration limit could preclude some refineries from processing 
high-sulfur crude oils, thereby limiting refining production capacity. 
Another commenter noted that many flares will receive both fuel gas and 
process upset gas, so it would be impossible to determine if an 
exceedance is caused by the regulated fuel gas or by the exempt gas. 
The commenter recommended that 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 
long-term 60 ppmv H2S fuel gas concentration limit was cost 
effective primarily for process heaters, boilers and other fuel gas 
combustion devices that are fed by the refinery's fuel gas system. 
Based on the typical configuration at a refinery, adding one new fuel 
gas combustion device to the fuel gas system would essentially require 
the owner or operator to limit the long-term concentration of 
H2S in the entire fuel gas system to 60 ppmv, so emission 
reductions would result from all fuel gas combustion devices tied to 
that fuel gas system. Upon review of the BSER analysis conducted at 
proposal for fuel gas combustion devices, we now realize that the 
analysis is not applicable to flares (See Docket Item No. EPA-HQ-OAR-
2007-0011-0289).
    Moreover, since we are regulating flares separately from other fuel 
gas combustion devices in this final rule, we should separately 
consider whether a long-term H2S concentration limit is 
appropriate for fuel gas sent to flares.
    In developing the suite of CAA section 111(h) standards for flares, 
we considered whether refineries should be required to optimize 
management of their fuel gas by limiting the long-term H2S 
concentration to 60 ppmv in addition to the short-term H2S 
concentration of 162 ppmv during normal operating conditions. We 
determined that, for refineries to demonstrate that 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 long-term 
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                             Emission        Emission        Emission
                                                           Capital cost    Total annual      reduction       reduction       reduction         Cost
                                                             ($1,000)     cost  ($1,000/   (tons SO2/yr)   (tons NOX/yr)   (tons VOC/yr)   effectiveness
                                                                              yr) \a\           \b\             \b\             \b\           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
New.....................................................          80,000          15,000               6              34             130          84,000

[[Page 56444]]

 
Modified/Reconstructed..................................         860,000         160,000              53             310           1,200         100,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Because 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.
\b\ These emission reductions are based on flares already meeting the short-term 162 ppmv H2S fuel gas concentration limit in 40 CFR part 60, subpart J
  (i.e., these are the incremental emission reductions achieved from a baseline of optimizing management of the fuel gas system to limit the short-term
  H2S concentration in the fuel gas to 162 ppmv to the originally proposed combined short-term 162 ppmv H2S concentration and long-term 60 ppmv H2S
  concentration in the fuel gas).

    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

[[Page 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 site-specific factors regarding flare gas 
Btu content, ability to offset natural gas purchase and other 
considerations. We find that these factors need to be addressed in a 
site-specific basis and are more appropriately addressed through the 
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

[[Page 56446]]

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.
---------------------------------------------------------------------------

    \10\ Regarding commenter's cited ultracracker flare example, it 
is difficult to believe that sweep gas alone accounts for 5 million 
scfd of flare gas flow. Additionally, a compositional analysis of 
the base flare gas from the normal flow, based on data provided from 
a DIAL study of this refinery, suggests that the base flare gas is 
of sufficient quality to recover. It also appears, based on the data 
provided by the commenter, that the hydrogen stream recycle 
compressor was off-line approximately half the year. For such huge 
gas flows, considering the cost of purchasing or producing 
additional hydrogen and the emissions associated with that process, 
it is reasonable to expect that the facility would have a back-up 
compressor if the primary compressor is unreliable.
---------------------------------------------------------------------------

    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,

[[Page 56447]]

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-to-H2S 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

[[Page 56448]]

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 sulfur-to-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

[[Page 56449]]

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, long-term 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

[[Page 56450]]

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 
short-term 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 short-term H2S concentration 
limit. In these cases, we find it appropriate to allow more time to 
comply with the short-term 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 re-
piping) sulfur and flow monitors that are newly required by subpart Ja. 
Some refineries will elect to add flare gas recovery and/or sulfur 
treatment equipment to minimize their emissions as part of the 
evaluations conducted, as required by the new flare management plan 
requirements, and time will be needed for planning, designing, 
purchasing and installing these components as well. Given that many 
flares will become modified affected sources relatively quickly, owners 
and operators will be competing with one another for the services and 
products of a finite number of vendors who provide the necessary 
monitors and other equipment. Several commenters specifically noted 
availability of monitors as an issue when complying with SCAQMD Rule 
1118. As such, we find that immediate compliance with 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 
short-term 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

[[Page 56451]]

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.
---------------------------------------------------------------------------

    \11\ For the purposes of this subpart, startup of the modified 
flare occurs when any of the activities in 40 CFR 60.100a(c)(1) or 
(2) is completed (e.g., when a new connection is made to a flare 
such that flow from a refinery process unit or ancillary equipment 
can flow to the flare via that new connection).
---------------------------------------------------------------------------

    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 short-term 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

[[Page 56452]]

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 electricity-producing units (including coke 
gasification units), pressure relief valves, pumps, sampling vents, and 
continuous analyzer vents.
    Sulfur recovery plants are also units from which a connection to a 
flare would trigger a flare modification and generate gas streams that 
should be considered in the flare management plan. We recognize that 
on-site sulfur recovery plants are considered refinery process units, 
and we proposed amendments to the definitions of ``refinery process 
unit'' and ``sulfur recovery plant'' to clarify that we consider a 
sulfur recovery plant to be ``a segment of the petroleum refinery in 
which a specific processing operation is conducted.'' However, the 
strict definition of ``refinery process unit'' would only apply to 
sulfur recovery plants physically located at the refinery. As 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

[[Page 56453]]

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 Sec.  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.

[[Page 56454]]

    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.

[[Page 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\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Natural gas
                                                 Total        Total       offset/       Total        Annual       Annual       Annual          Cost
                                                capital    annual cost    product    annual cost    emission     emission     emission    effectiveness
           Subpart Ja requirements                cost       without      recovery     ($1,000/    reductions   reductions   reductions       ($/ton
                                                ($1,000)      credit       credit        yr)       (tons SO2/   (tons NOX/   (tons VOC/     emissions
                                                           ($1,000/yr)    ($1,000)                    yr)          yr)          yr)          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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ All 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., ultra-low NOX burners). We did revise our emission 
estimates based on the type of process heater, creating separate 
impacts for forced draft process heaters and natural draft process 
heaters. Dividing process heaters into separate subcategories, based on 
the draft type, required us to develop new distributions of baseline 
emissions for each type of process heater. The baseline emission 
estimates for natural draft process heaters are slightly lower than 
those developed for the existing subpart Ja requirements (per affected 
process heater), but the average emission reduction achieved by ultra-
low NOX burners was adjusted to 80 percent (rather than 75 
percent used for generic process heaters). For forced draft process 
heaters, the baseline (i.e., uncontrolled) emissions rate for forced 
draft process heaters was revised slightly upward, based on the 
available emissions data. Due to these differences, the mix of controls 
needed to meet a 40 ppmv emissions limit was no longer cost effective 
for forced draft process heaters, but the emission reductions 
associated with process heaters complying with the 60 ppmv standard 
were higher than those previously estimated for generic process 
heaters. Thus, the creation of new subcategories of process heaters 
with different emissions limits for each subcategory did not impact the 
control or compliance methods used by the facilities (i.e., BSER in all 
cases was based on the performance of advanced combustion monitoring 
controls in conjunction with ultra-low NOX burners) and did 
not change the estimated compliance costs. As we do not have adequate 
data regarding the prevalence of natural draft process heaters versus 
forced draft process heaters that will become subject to the rule, we 
used the emission reductions estimated for the two different types of 
process heaters as a means to bound the range of anticipated 
NOX emission reductions to be from 7,100 to 8,600 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.

[[Page 56456]]

    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.
---------------------------------------------------------------------------

    \12\ Roman, et al., 2008. Expert Judgment Assessment of the 
Mortality Impact of Changes in Ambient Fine Particulate Matter in 
the U.S., Environ. Sci. Technol., 42, 7, 2268--2274.

       Table 6--Summary of the Monetized PM2.5 and CO2 Benefits for Amended Petroleum Refineries Standards
                                         [Millions of 2006 dollars] \a\
----------------------------------------------------------------------------------------------------------------
                                                                    Total monetized          Total monetized
              Pollutant                  Emission reductions      benefits (3-percent      benefits (7-percent
                                           (tons per year)             discount)                discount)
----------------------------------------------------------------------------------------------------------------
                                             With Flare Gas Recovery
----------------------------------------------------------------------------------------------------------------
PM2.5 Benefits\b\:
    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 Benefits\c\..................  1,900,000\d\...........  $46....................  $46.
                                      --------------------------------------------------------------------------
        Total Monetized Benefits:....  .......................  $260 to $580...........  $240 to $520.
----------------------------------------------------------------------------------------------------------------
                                           Without Flare Gas Recovery
----------------------------------------------------------------------------------------------------------------
PM2.5 Benefits\b\:
    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 Benefits\c\..................  110,000\d\.............  $2.6...................  $2.6.
        Total Monetized Benefits.....  .......................  $190 to $460...........  $170 to $410.
----------------------------------------------------------------------------------------------------------------
\a\ All 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.
\b\ PM 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.
\c\ The 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

[[Page 56457]]

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-per-ton 
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 national-average 
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.
---------------------------------------------------------------------------

    \13\ Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. The Influence 
of Location, Source, and Emission Type in Estimates of the Human 
Health Benefits of Reducing a Ton of Air Pollution. Air Qual Atmos 
Health (2009) 2:169-176.
    \14\ U.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.
---------------------------------------------------------------------------

    We apply these national benefit-per-ton 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.
---------------------------------------------------------------------------

    \15\ Pope, et al., 2002. Lung Cancer, Cardiopulmonary Mortality, 
and Long-term Exposure to Fine Particulate Air Pollution. Journal of 
the American Medical Association 287:1132-1141.
    \16\ Laden, et al., 2006. Reduction in Fine Particulate Air 
Pollution and Mortality. American Journal of Respiratory and 
Critical Care Medicine 173: 667-672.
---------------------------------------------------------------------------

    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 PM-related mortality impacts using a full range of modeled air 
quality concentrations.
    Most of the estimated PM-related benefits in this rule would accrue 
to populations exposed to higher levels of PM2.5. 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 ([micro]g/m\3\). Using the Laden, et al. 
(2006) study, 25 percent of the population is exposed above the LML of 
10 [micro]g/m\3\. 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.
---------------------------------------------------------------------------

    \17\ U.S. Environmental Protection Agency, 2006. Final 
Regulatory Impact Analysis: PM2.5 NAAQS. Prepared by Office of Air 
and Radiation. October. Available on the Internet at http://www.epa.gov/ttn/ecas/ria.html.
---------------------------------------------------------------------------

    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

[[Page 56458]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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    7-Percent discount
                                      rate                  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.
------------------------------------------------------------------------
\a\ All estimates are for the implementation year (2017) and are rounded
  to two significant figures.

[[Page 56459]]

 
\b\ 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 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.
\c\ The 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 cost-benefits analysis, please refer to 
the RIA for this rulemaking, which is available in the docket.

B. Paperwork Reduction Act

    The final amendments to the Standards of Performance for Petroleum 
Refineries (40 CFR part 60, subpart J) do not impose any new 
information collection burden. The final amendments are clarifications 
and technical corrections that do not affect the estimated burden of 
the existing rule. Therefore, we have not revised the 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.

[[Page 56460]]

    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-for-profit 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.

[[Page 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 gas-fired process heaters; and GPA 2172-09, 
Calculation of Gross Heating Value, Relative Density, Compressibility 
and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for 
Custody Transfer, for determining the higher heating value of fuel fed 
to process heaters. These methods are also incorporated by reference 
(see 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.

[[Page 56462]]

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]

0
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.

0
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:

Sec.  9.1  OMB Approvals under the Paperwork Reduction Act.

* * * * *

------------------------------------------------------------------------
                                                            OMB control
                     40 CFR citation                            No.
------------------------------------------------------------------------
 
                                * * * * *
------------------------------------------------------------------------
         Standards of Performance for New Stationary Sources \1\
------------------------------------------------------------------------
 
                                * * * * *
------------------------------------------------------------------------
60.103a-60.108a.........................................       2060-0602
 
                                * * * * *
------------------------------------------------------------------------
\1\ The ICRs referenced in this section of the table encompass the
  applicable general provisions contained in 40 CFR part 60, subpart A,
  which are not independent information collection requirements.

* * * * *

PART 60--[AMENDED]

0
3. The authority citation for part 60 continues to read as follows:

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

Subpart A--[AMENDED]

0
4. Section 60.17 is amended by:
0
a. Revising paragraphs (a)(84), (a)(95), (a)(96), (a)(97), and (a)(98);
0
b. Adding paragraphs (a)(100) through (a)(108);
0
c. Adding paragraph (c)(2);
0
d. Revising paragraph (h)(4) and adding paragraphs (h)(5) through 
(h)(15);
0
e. Adding paragraphs (m)(2) and (m)(3); and
0
f. Adding paragraphs (p) and (q) to read as follows:

Sec.  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 Sec.  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 Sec. Sec.  
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 Sec. Sec.  
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 Sec. Sec.  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 
Sec. Sec.  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 Sec.  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 Sec.  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 Sec.  
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 Sec.  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 Sec.  60.107a(d).
    (105) ASTM UOP539-97, Refinery Gas Analysis by Gas Chromatography, 
(Copyright 1997), IBR approved for Sec.  60.107a(d).
    (106) ASTM D3699-08, Standard Specification for Kerosine, including 
Appendix X1, (Approved September 1, 2008), IBR approved for Sec. Sec.  
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 Sec. Sec.  
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 Sec. Sec.  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 Sec.  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 Sec.  60.56c(b), Sec.  60.63(f), Sec.  60.106(e), Sec.  60.104a(d), 
(h), (i), and (j), Sec.  60.105a(d), (f), and (g), Sec.  60.106a(a), 
Sec.  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, Sec. Sec.  
60.4415(a), 60.2145(s), 60.2145(t),

[[Page 56463]]

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, 
Sec. Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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 Sec.  
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 Sec.  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 Sec.  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 Sec.  
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 Sec.  60.107a(d) of subpart Ja of this 
part.
    (15) ASME MFC-22-2007, Measurement of Liquid by Turbine Flowmeters, 
IBR approved for Sec.  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 Sec.  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 Sec.  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 Sec.  
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 Sec.  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 Sec.  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 Sec.  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 Sec.  60.107a(d) of subpart Ja of this part.
    (2) [Reserved]

Subpart J--[AMENDED]

0
5. Section 60.100 is amended by:
0
a. Revising paragraph (b);
0
b. Redesignating paragraph (e) as (f); and
0
c. Adding a new paragraph (e) to read as follows:

Sec.  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.
* * * * *

0
6. Section 60.101 is amended by revising paragraph (d) to read as 
follows:

Sec.  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.
* * * * *

0
7. Section 60.106 is amended by revising paragraph (c)(1) to read as 
follows:

Sec.  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).
* * * * *

[[Page 56464]]

Subpart Ja--[AMENDED]

0
7. In Sec.  60.100a, lift the stay on paragraph (c) published December 
22, 2008 (73 FR 78552).

0
8. Section 60.100a is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraph (b);
0
c. Revising paragraph (c) introductory text and paragraph (c)(1); and
0
d. Revising paragraph (d).
    The revisions read as follows:

Sec.  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 Sec.  60.101a.
    (c) For all affected facilities other than flares, the provisions 
in Sec.  60.14 regarding modification apply. As provided in Sec.  
60.14(f), the special provisions set forth under this subpart shall 
supersede the provisions in Sec.  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 back-up (redundant) equipment 
associated with the flare (such as a back-up compressor) that does not 
increase the capacity of the flare.
    (vi) Replacing piping or moving an existing connection from a 
refinery process unit to a new location in the same flare, provided the 
new pipe diameter is less than or equal to the diameter of the pipe/
connection being replaced/moved.
    (vii) Connections that interconnect two or more flares.
* * * * *
    (d) For purposes of this subpart, under Sec.  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.

0
9. In Sec.  60.101a, lift the stay on the definition of ``flare'' 
published December 22, 2008 (73 FR 78552).

0
10. Section 60.101a is amended by:
0
a. Revising the introductory text;
0
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
0
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:

Sec.  60.101a  Definitions.

    Terms used in this subpart are defined in the Clean Air Act (CAA), 
in Sec.  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 electricity-producing 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

[[Page 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 sands-derived crude oil for further processing at a 
petroleum refinery using only solvent extraction and/or distillation to 
recover diluent is not a petroleum refinery.
    Primary flare means the first flare in a cascaded flare system.
* * * * *
    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

[[Page 56466]]

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.

0
11. In Sec.  60.102a, lift the stay on paragraph (g) published December 
22, 2008 (73 FR 78552).

0
12. Section 60.102a is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraph (f)(1)(ii);
0
c. Revising paragraph (g);
0
d. Removing and reserving paragraph (h); and
0
e. Revising paragraph (i).
    The revisions read as follows:

Sec.  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 Sec.  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 Sec.  60.107a; if fuel gas composition is not monitored as specified 
in Sec.  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 Sec.  60.107a; if fuel gas composition is not monitored as specified 
in Sec.  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:
[GRAPHIC] [TIFF OMITTED] TR12SE12.001

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.

[[Page 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:
[GRAPHIC] [TIFF OMITTED] TR12SE12.002

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 modification-based technology (e.g., ultra-low 
NOX burners); or
    (ii) A modified or reconstructed process heater that has downwardly 
firing induced draft burners; or
    (iii) A co-fired process heater; or
    (iv) A process heater operating at reduced firing conditions for an 
extended period of time (i.e., operating in turndown mode). The site-
specific NOX emissions limit will only apply for those 
operating conditions.
    (2) The request shall include sufficient and appropriate data, as 
determined by the Administrator, to allow the Administrator to confirm 
that the process heater is unable to comply with the applicable 
NOX emissions limit in paragraph (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 Sec.  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.

0
13. Section 60.103a is revised to read as follows:

Sec.  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.

[[Page 56468]]

    (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

[[Page 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 re-submitted to the 
Administrator only if the owner or operator adds an alternative 
baseline flow rate, revises an existing baseline as described in 
paragraph (a)(4) of this section, installs a flare gas recovery system 
or is required to change flare designations and monitoring methods as 
described in Sec.  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 (m\3\) (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 Sec.  60.107a(g) is elected, 
any period when the flare gas line pressure exceeds the water seal 
liquid depth, except for periods attributable to compressor staging 
that do not exceed the staging time specified in paragraph 
(a)(3)(vii)(C) of this section.
    (2) For a fuel gas combustion device, each exceedance of an 
applicable short-term emissions limit in Sec.  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 Sec.  
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 Sec.  60.108a(c)(6) and reported as described 
in Sec.  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 Sec.  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 
Sec.  60.108a(c)(6)(x).

[[Page 56470]]

    (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 Sec.  60.100a shall comply with the 
requirements of paragraph (h) of this section and the requirements of 
Sec.  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 Sec.  60.100a shall comply with the requirements of 
paragraph (h) of this section and the requirements of Sec.  
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 Sec.  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.

0
14. Section 60.104a is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraphs (d)(4)(ii), (d)(4)(iii), (d)(4)(v) and (d)(8);
0
c. Revising paragraph (f)(3);
0
d. Revising paragraph (h)(5)(iv);
0
e. Revising paragraph (i) introductory text;
0
f. Adding paragraphs (i)(6) through (i)(8);
0
g. Revising paragraph (j) introductory text and paragraph (j)(4) 
introductory text; and
0
h. Revising paragraph (j)(4)(iv) to read as follows:

Sec.  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

[[Page 56471]]

demonstrate initial compliance with each applicable emissions limit in 
Sec.  60.102a according to the requirements of Sec.  60.8. The 
notification requirements of Sec.  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:
[GRAPHIC] [TIFF OMITTED] TR12SE12.003

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:
[GRAPHIC] [TIFF OMITTED] TR12SE12.004

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 (lb-min)/(hr-dscf-%)];
K2 = Material balance and conversion factor, 2.088 (kg-
min)/(hr-dscm) [0.1303 (lb-min)/(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 Sec.  60.105a(b)(2), if applicable, using Equation 7 of 
this section:
[GRAPHIC] [TIFF OMITTED] TR12SE12.005

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 Sec.  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:

[[Page 56472]]

[GRAPHIC] [TIFF OMITTED] TR12SE12.006

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:
[GRAPHIC] [TIFF OMITTED] TR12SE12.007

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 Sec.  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 Sec.  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 co-fired process heaters based only on overall 
firing rates (and not by fuel mixtures), conduct at least one of the 
test runs for each test while the process heater is being supplied by 
both fuel gas and fuel oil and conduct at least one of the test runs 
while the process heater is being supplied solely by fuel gas.
    (D) Determine the average O2 concentration for each test 
run of a valid test.
    (E) Calculate the O2 operating limit for each operating 
range as the average O2 concentration of the three test runs 
from 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 Sec.  
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

[[Page 56473]]

elects to demonstrate continuous compliance with a maximum excess 
O2 limit, as provided in Sec.  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 Sec.  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 Sec.  60.102a(g)(1) for a 
fuel gas combustion device or the concentration requirement in Sec.  
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 Sec.  60.107a(a)(2). The method ANSI/ASME PTC 19.10-
1981 (incorporated by reference--see Sec.  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 Sec.  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.
0
15. Section 60.105a is amended by:
0
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
0
b. Revising paragraph (i)(5) to read as follows:

Sec.  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 
Sec.  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 Sec.  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 Sec.  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.
* * * * *
0
16. In Sec.  60.107a, lift the stay on paragraphs (d) and (e) published 
December 22, 2008 (73 FR 78552).
0
17. Section 60.107a is amended by:
0
a. Revising the section heading;
0
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;
0
c. Adding paragraphs (a)(2)(v) and (a)(2)(vi);
0
d. Revising paragraph (b) introductory text and paragraphs (b)(1)(i), 
(b)(1)(v) and (b)(3)(iii);
0
e. Revising paragraph (c) introductory text and paragraphs (c)(1) and 
(c)(6);
0
f. Redesignating paragraphs (d), (e), and (f) as paragraphs (e), (f) 
and (i), respectively;
0
g. Adding a new paragraph (d);
0
h. Revising newly redesignated paragraph (e);
0
i. Revising newly redesignated paragraph (f);
0
j. Adding a new paragraph (g);
0
k. Adding a new paragraph (h); and
0
l. Revising newly redesignated paragraph (i).
    The revisions and additions read as follows:

Sec.  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 Sec.  60.102a(g)(1) and elects to comply with the 
SO2 emission limits in Sec.  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 Sec.  
60.102a(g)(1) and elects to comply with the H2S 
concentration limits in Sec.  60.102a(g)(1)(ii) or a flare that is 
subject to the H2S concentration requirement in Sec.  
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 Sec.  
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 Sec.  
60.102a(g)(1)(ii) or a flare that is subject to the H2S 
concentration requirement in Sec.  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

[[Page 56474]]

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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  60.100a.
    (B) The owner or operator had an approved alternative monitoring 
plan or plans pursuant to Sec.  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 Sec. Sec.  
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 Sec.  60.102a(g)(2) 
and electing to comply with the applicable emissions limit in Sec.  
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 Sec.  60.104a(i), establish a maximum excess 
O2 operating limit or operating curve according to the 
requirements in Sec.  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 mass-based limit. The owner or operator of a process 
heater subject to the NOX emissions limit in Sec.  
60.102a(g)(2) and electing to comply with the applicable emissions 
limit in Sec.  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

[[Page 56475]]

atmosphere and shall determine the F factor of the fuel gas stream no 
less frequently than once per day according to the monitoring 
requirements in paragraphs (d)(1) through (4) of this section. The 
owner or operator of a co-fired process heater subject to the 
NOX emissions limit in Sec.  60.102a(g)(2) and electing to 
comply with the heating value-based limit in Sec.  
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 gas-fired 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).
[GRAPHIC] [TIFF OMITTED] TR12SE12.008

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 
Sec.  60.17);
    (iii) ASTM D1946-90 (Reapproved 2006)(incorporated by reference-see 
Sec.  60.17);
    (iv) ASTM D6420-99 (Reapproved 2004)(incorporated by reference-see 
Sec.  60.17);
    (v) GPA 2261-00 (incorporated by reference-see Sec.  60.17); or
    (vi) ASTM UOP539-97 (incorporated by reference-see Sec.  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 
[deg]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 [deg]F and 1 
atmosphere). The owner or operator shall conduct performance 
evaluations of each fuel gas flow monitor according to the requirements 
in Sec.  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 Sec.  60.17);
    (iii) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008) (incorporated by 
reference-see Sec.  60.17);
    (iv) ASME MFC-6M-1998 (Reaffirmed 2005) (incorporated by reference-
see Sec.  60.17);
    (v) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006) (incorporated by 
reference-see Sec.  60.17);
    (vi) ASME MFC-11M-2006 (incorporated by reference-see Sec.  60.17);
    (vii) ASME MFC-14M-2003 (incorporated by reference-see Sec.  
60.17);
    (viii) ASME MFC-18M-2001 (incorporated by reference-see Sec.  
60.17);
    (ix) AGA Report No. 3, Part 1 (incorporated by reference-see Sec.  
60.17);
    (x) AGA Report No. 3, Part 2 (incorporated by reference-see Sec.  
60.17);
    (xi) AGA Report No. 11 (incorporated by reference-see Sec.  60.17);
    (xii) AGA Report No. 7 (incorporated by reference-see Sec.  60.17); 
and
    (xiii) API Manual of Petroleum Measurement Standards, Chapter 22, 
Section 2 (incorporated by reference-see Sec.  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 Sec.  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 Sec.  60.17);

[[Page 56476]]

    (iii) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006) (incorporated by 
reference-see Sec.  60.17);
    (iv) ASME MFC-16-2007 (incorporated by reference-see Sec.  60.17);
    (v) ASME MFC-22-2007 (incorporated by reference-see Sec.  60.17); 
or
    (vi) ISO 8316 (incorporated by reference-see Sec.  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 
Sec.  60.17).
    (ii) ASTM D1826-94 (Reapproved 2003) (incorporated by reference-see 
Sec.  60.17).
    (iii) ASTM D1945-03 (Reapproved 2010) (incorporated by reference-
see Sec.  60.17).
    (iv) ASTM D1946-90 (Reapproved 2006) (incorporated by reference-see 
Sec.  60.17).
    (v) ASTM D3588-98 (Reapproved 2003) (incorporated by reference-see 
Sec.  60.17).
    (vi) ASTM D4809-06 (incorporated by reference-see Sec.  60.17).
    (vii) ASTM D4891-89 (Reapproved 2006) (incorporated by reference-
see Sec.  60.17).
    (viii) GPA 2172-09 (incorporated by reference-see Sec.  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 Sec.  60.104a(i), establish a maximum 
excess O2 operating limit or operating curve according to 
the requirements in Sec.  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 
Sec.  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 
Sec.  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 Sec.  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

[[Page 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 Sec.  
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 Sec.  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 Sec.  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 Sec.  60.17) or ASTM Method 
D5504-08 (incorporated by reference--see Sec.  60.17).
    (vi) The owner or operator shall develop a 10-day average total 
sulfur-to-H2S ratio and 95-percent confidence interval as 
follows:
    (A) Calculate the ratio of the total sulfur concentration to the 
H2S concentration for each day during which samples are 
collected.
    (B) Determine the 10-day average total sulfur-to-H2S 
ratio as the arithmetic average of the daily ratios calculated in 
paragraph (e)(2)(vi)(A) of this section.
    (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.
[GRAPHIC] [TIFF OMITTED] TR12SE12.009

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.
[GRAPHIC] [TIFF OMITTED] TR12SE12.010

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 Sec.  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.

[[Page 56478]]

    (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 Sec.  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 Sec.  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 Sec.  
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 Sec.  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 Sec.  
60.7(c), periods of excess emissions for fuel gas combustion devices 
subject to the emissions limitations in Sec.  60.102a(g) and flares 
subject to the concentration requirement in Sec.  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 Sec.  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 Sec.  
60.102a(g)(1)(ii), each rolling 3-hour period during which the average 
concentration of H2S as measured by the

[[Page 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 Sec.  60.107a(d), 0.040 lb/MMBtu;
    (ii) For a forced draft process heater, 60 ppmv and, if monitored 
according to Sec.  60.107a(d), 0.060 lb/MMBtu; and
    (iii) For a co-fired process heater electing to comply with the 
NOX limit in Sec.  60.102a(g)(2)(iii)(A) or (g)(2)(iv)(A), 
150 ppmv.
    (iv) The site-specific limit determined by the Administrator under 
Sec.  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 Sec.  60.102a(g)(2)(iii)(B) or Equation 
4 in Sec.  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.

0
18. Section 60.108a is amended by:
0
a. Revising paragraph (b);
0
b. Revising paragraph (c)(1);
0
c. Revising paragraph (c)(6) introductory text and paragraphs 
(c)(6)(ii) through (vi);
0
d. Adding paragraphs (c)(6)(vii), (viii), (ix), (x) and (xi);
0
e. Adding paragraph (c)(7); and
0
f. Revising paragraph (d)(5).
    The revisions and additions read as follows:

Sec.  60.108a  Recordkeeping and reporting requirements.

* * * * *
    (b) Each owner or operator subject to an emissions limitation in 
Sec.  60.102a shall notify the Administrator of the specific monitoring 
provisions of Sec. Sec.  60.105a, 60.106a and 60.107a with which the 
owner or operator intends to comply. Each owner or operator of a co-
fired process heater subject to an emissions limitation in Sec.  
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 Sec.  60.101a. Notifications required by 
this paragraph shall be submitted with the notification of initial 
startup required by Sec.  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 Sec.  60.103a(c). If the monitoring alternative 
provided in Sec.  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 Sec.  
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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  60.103a(e).
    (x) For any corrective action analysis for which corrective actions 
are required in Sec.  60.103a(e), a description of the corrective 
action(s) completed within the first 45 days following the discharge

[[Page 56480]]

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 Sec.  
60.107a(e)(2) for a flare, records of the H2S and total 
sulfur analyses of each grab or integrated sample, the calculated daily 
total sulfur-to-H2S ratios, the calculated 10-day average 
total sulfur-to-H2S ratios and the 95-percent confidence 
intervals for each 10-day average total sulfur-to-H2S ratio.
    (d) * * *
    (5) The information described in paragraph (c)(6) of this section 
for all discharges listed in paragraph (c)(6) of this section. For a 
flare complying with the monitoring alternative under Sec.  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 Sec.  60.107a(e) and (f) within 180 days 
following the fifth discharge.
* * * * *
0
19. Section 60.109a is amended by revising paragraph (b) introductory 
text and adding paragraph (b)(4) to read as follows:

Sec.  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 Sec.  60.103a(j) of this subpart.
0
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
------------------------------------------------------------------------
                                                      MEV\a\     MHC\b\
                    Constituent                      dscf/mol   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[emsp14][deg]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