
[Federal Register: June 24, 2008 (Volume 73, Number 122)]
[Rules and Regulations]               
[Page 35837-35881]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr24jn08-12]                         


[[Page 35837]]

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Part IV





Environmental Protection Agency





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40 CFR Part 60



Standards of Performance for Petroleum Refineries; Final Rule


[[Page 35838]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2007-0011; FRL-8563-2]
RIN 2060-AN72

 
Standards of Performance for Petroleum Refineries

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: EPA is issuing final amendments to the current Standards of 
Performance for Petroleum Refineries. This action also promulgates 
separate standards of performance for new, modified, or reconstructed 
process units at petroleum refineries. The final standards for new 
process units include emissions limitations and work practice standards 
for fluid catalytic cracking units, fluid coking units, delayed coking 
units, fuel gas combustion devices, and sulfur recovery plants. These 
final standards reflect demonstrated improvements in emissions control 
technologies and work practices that have occurred since promulgation 
of the current standards.

DATES: These final rules are effective on June 24, 2008. The 
incorporation by reference of certain publications listed in the final 
rules is approved by the Director of the Federal Register as of June 
24, 2008.

ADDRESSES: EPA has established a docket for this action under Docket ID 
No. EPA-HQ-OAR-2007-0011. All documents in the docket are listed in the 
www.regulations.gov index. Although listed in the index, some 
information is not publicly available, e.g., confidential business 
information or other information whose disclosure is restricted by 
statute. Certain other material, such as copyrighted material, is not 
placed on the Internet and will be publicly available only in hard copy 
form. Publicly available docket materials are available either 
electronically in www.regulations.gov or in hard copy at the EPA Docket 
Center, Standards of Performance for Petroleum Refineries Docket, EPA 
West Building, Room 3334, 1301 Constitution Ave., NW., Washington, DC. 
The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday 
through Friday, excluding legal holidays. The telephone number for the 
Public Reading Room is (202) 566-1744, and the telephone number for the 
Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Mr. Robert B. Lucas, Office of Air 
Quality Planning and Standards, Sector Policies and Programs Division, 
Coatings and Chemicals Group (E143-01), Environmental Protection 
Agency, Research Triangle Park, NC 27711, telephone number: (919) 541-
0884; fax number: (919) 541-0246; e-mail address: lucas.bob@epa.gov.

SUPPLEMENTARY INFORMATION: 

I. General Information

A. Does this action apply to me?

    Categories and entities potentially regulated by these final rules 
include:

------------------------------------------------------------------------
                                                                Examples
                                                                   of
Category                     NAICS code \1\                    regulated
                                                                entities
------------------------------------------------------------------------
Industry  32411..............................................  Petroleum
                                                               refiners.
 Federal  ...................................................    Not
 governm                                                       affected.
      ent
  State/  ...................................................    Not
   local/                                                      affected.
   tribal
 governm
      ent
------------------------------------------------------------------------
\1\ North American Industry Classification System.

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be regulated by this 
action. To determine whether your facility would be regulated by this 
action, you should examine the applicability criteria in 40 CFR 60.100 
and 40 CFR 60.100a. If you have any questions regarding the 
applicability of this proposed action to a particular entity, contact 
the person listed in the preceding FOR FURTHER INFORMATION CONTACT 
section.

B. Where can I get a copy of this document?

    In addition to being available in the docket, an electronic copy of 
this final action is available on the Worldwide Web (WWW) through the 
Technology Transfer Network (TTN). Following signature, a copy of this 
final action will be posted on the TTN's policy and guidance page for 
newly proposed or promulgated rules at http://www.epa.gov/ttn/oarpg. 
The TTN provides information and technology exchange in various areas 
of air pollution control.

C. Judicial Review

    Under section 307(b)(1) of the Clean Air Act (CAA), judicial review 
of these final rules is available only by filing a petition for review 
in the United States Court of Appeals for the District of Columbia 
Circuit by August 25, 2008. Under section 307(b)(2) of the CAA, the 
requirements established by these final rules may not be challenged 
separately in any civil or criminal proceedings brought by EPA to 
enforce these requirements.
    Section 307(d)(7)(B) of the CAA further provides that ``[o]nly an 
objection to a rule or procedure which was raised with reasonable 
specificity during the period for public comment (including any public 
hearing) may be raised during judicial review.'' This section also 
provides a mechanism for us to convene a proceeding for 
reconsideration, ``[i]f the person raising an objection can demonstrate 
to the EPA that it was impracticable to raise such objection within 
[the period for public comment] or if the grounds for such objection 
arose after the period for public comment (but within the time 
specified for judicial review) and if such objection is of central 
relevance to the outcome of the rule.'' Any person seeking to make such 
a demonstration to us should submit a Petition for Reconsideration to 
the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios 
Building, 1200 Pennsylvania Ave., NW., Washington, DC 20460, with a 
copy to both the person(s) listed in the preceding FOR FURTHER 
INFORMATION CONTACT section, and the Associate General Counsel for the 
Air and Radiation Law Office, Office of General Counsel (Mail Code 
2344A), U.S. EPA, 1200 Pennsylvania Ave., NW., Washington, DC 20460.

D. How is this document organized?

    The information presented in this preamble is organized as follows:

I. General Information
    A. Does this action apply to me?
    B. Where can I get a copy of this document?
    C. Judicial Review
    D. How is this document organized?
II. Background Information
III. Summary of the Final Rules and Changes Since Proposal
    A. What are the final amendments to the standards for petroleum 
refineries (40 CFR part 60, subpart J)?
    B. What are the final requirements for new fluid catalytic 
cracking units and new fluid coking units (40 CFR part 60, subpart 
Ja)?
    C. What are the final requirements for new sulfur recovery 
plants (40 CFR part 60, subpart Ja)?
    D. What are the final requirements for new fuel gas combustion 
devices (40 CFR part 60, subpart Ja)?
    E. What are the final work practice standards (40 CFR part 60, 
subpart Ja)?
    F. What are the modification and reconstruction provisions?
IV. Summary of Significant Comments and Responses
    A. PM Limits for Fluid Catalytic Cracking Units
    B. SO2 Limits for Fluid Catalytic Cracking Units
    C. NOX Limit for Fluid Catalytic Cracking Units

[[Page 35839]]

    D. PM and SO2 Limits for Fluid Coking Units
    E. NOX Limit for Fluid Coking Units
    F. SO2 Limits for Sulfur Recovery Plants
    G. NOX Limit for Process Heaters
    H. Fuel Gas Combustion Devices
    I. Flares
    J. Delayed Coking Units
    K. Other Comments
V. Summary of Cost, Environmental, Energy, and Economic Impacts
    A. What are the impacts for petroleum refineries?
    B. What are the secondary impacts?
    C. What are the economic impacts?
    D. What are the benefits?
VI. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions to Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act

II. Background Information

    New source performance standards (NSPS) implement CAA section 
111(b) and are issued for categories of sources which cause, or 
contribute significantly to, air pollution which may reasonably be 
anticipated to endanger public health or welfare. The primary purpose 
of the NSPS is to attain and maintain ambient air quality by ensuring 
that the best demonstrated emission control technologies are installed 
as the industrial infrastructure is modernized. Since 1970, the NSPS 
have been successful in achieving long-term emissions reductions in 
numerous industries by assuring cost-effective controls are installed 
on new, reconstructed, or modified sources.
    Section 111 of the CAA requires that NSPS reflect the application 
of the best system of emission reductions which (taking into 
consideration the cost of achieving such emission reductions, any non-
air quality health and environmental impact and energy requirements) 
the Administrator determines has been adequately demonstrated. This 
level of control is commonly referred to as best demonstrated 
technology (BDT).
    Section 111(b)(1)(B) of the CAA requires EPA to periodically review 
and revise the standards of performance, as necessary, to reflect 
improvements in methods for reducing emissions. As a result of our 
periodic review of the NSPS for petroleum refineries (40 CFR part 60, 
subpart J), we proposed amendments to the current standards of 
performance and separate standards of performance for new process units 
(72 FR 27278, May 14, 2007). In response to several requests, we 
extended the 60-day comment period from July 13, 2007, to August 27, 
2007 (72 FR 35375, June 28, 2007). We also issued a notice of data 
availability (NODA) (72 FR 69175, December 7, 2007) to notify the 
public that additional information had been added to the docket; the 
NODA also extended the public comment period on the proposed rule to 
January 7, 2008. We received a total of 38 comments from refineries, 
industry trade associations, and consultants; State and local 
environmental and public health agencies; environmental groups; and 
members of the public during the extended comment period, and 8 
additional comments on the NODA. These final rules reflect our full 
consideration of all of the comments we received. Detailed responses to 
the comments not included in this preamble are contained in the 
Response to Comments document which is included in the docket for this 
rulemaking.

III. Summary of the Final Rules and Changes Since Proposal

    We are promulgating several amendments to provisions in the 
existing NSPS in 40 CFR part 60, subpart J. Many of these amendments 
are technical clarifications and corrections that are also included in 
the final standards in 40 CFR part 60, subpart Ja. For example, we are 
revising the definition of ``fuel gas'' to indicate that vapors 
collected and combusted to comply with certain wastewater and marine 
vessel loading provisions are not considered fuel gas. Consequently, 
these vapors are exempt from the sulfur dioxide (SO2) 
treatment standard in 40 CFR 60.104(a)(1) and are not required to be 
monitored. We are also finalizing certain monitoring exemptions that we 
proposed for fuel gases that are identified as inherently low sulfur or 
demonstrated to contain a low sulfur content. See 40 CFR 
60.105(a)(4)(iv). We are also revising the coke burn-off equation to 
account for oxygen (O2)--enriched air streams. Other 
amendments include clarification of definitions and correction of 
grammatical and typographical errors.
    The final standards in 40 CFR part 60, subpart Ja include emission 
limits for fluid catalytic cracking units (FCCU), fluid coking units 
(FCU), sulfur recovery plants (SRP), and fuel gas combustion devices. 
Subpart Ja also includes work practice standards for reducing emissions 
of volatile organic compounds (VOC) from flares, minimizing 
SO2 emissions from fuel gas combustion devices and SRP, and 
for reducing emissions of VOC from delayed coking units. Only those 
affected facilities that commence construction, modification, or 
reconstruction after May 14, 2007 will be affected by the standards in 
subpart Ja. Units for which construction, modification, or 
reconstruction commenced on or before May 14, 2007 must continue to 
comply with the applicable standards under the current NSPS in 40 CFR 
part 60, subpart J, as amended.

A. What are the final amendments to the standards for petroleum 
refineries (40 CFR part 60, subpart J)?

    As proposed, we are amending the definition of ``fuel gas'' to 
specifically exclude vapors that are collected and combusted in an air 
pollution control device installed to comply with a specified 
wastewater or marine vessel loading emissions standard. The thermal 
combustion control devices themselves are still considered to be 
affected fuel gas combustion devices if they combust other gases that 
meet the definition of fuel gas, and all auxiliary fuel gas fired to 
these devices are subject to the fuel gas limit; however, continuous 
monitoring is not required for the vapors collected from wastewater or 
marine vessel loading operations that are being incinerated because 
these gases are not considered to be fuel gases under the definition of 
``fuel gas'' in 40 CFR part 60, subpart J.
    We are also finalizing exemptions for certain fuel gas streams from 
all continuous monitoring requirements. See 40 CFR 60.105(a)(4)(iv). 
Monitoring is not required for combustion in a flare of process upset 
gases or flaring of gases from relief valve leakage or emergency 
malfunctions since these streams are exempt from the standard under 40 
CFR 60.104(a)(1). Additionally, monitoring is not required for 
inherently low sulfur fuel gas streams since the emissions generated by 
combusting such streams will necessarily be well below the standard. 
These streams include pilot gas flames, gas streams that meet 
commercial-grade product specifications with a sulfur content of 30 
parts per million by volume (ppmv) or less, fuel gases produced by 
process

[[Page 35840]]

units that are intolerant to sulfur contamination, and fuel gas streams 
that an owner or operator can demonstrate are inherently low-sulfur. 
Owners and operators are required to document the exemption for which 
each fuel gas stream applies and ensure that the stream remains 
qualified for that exemption.
    For accuracy in the calculation of the coke burn-off rate, we are 
revising the coke burn-off rate equation in 40 CFR 60.106(b)(3) to be 
consistent with the equation in 40 CFR 63.1564(b)(4)(i) of the National 
Emission Standards for Hazardous Air Pollutants for Petroleum 
Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and 
Sulfur Recovery Units (40 CFR part 63, subpart UUU). This revision adds 
a fourth term to the coke burn-off rate equation to account for the use 
of O2-enriched air. Other revisions to the equation change 
the constant values and the units of the resulting coke burn-off rate 
from Megagrams per hour (Mg/hr) and tons per hour (tons/hr) to 
kilograms per hour (kg/hr) and pounds per hour (lb/hr).
    We proposed to amend the definition of ``Claus sulfur recovery 
plant'' in 40 CFR 60.101(i) to clarify that the SRP may consist of 
multiple units and that primary sulfur pits are considered part of the 
Claus SRP consistent with the Agency's current position. Commenters 
expressed concern that change to a 40 CFR part 60, subpart J definition 
that could lead to retroactive non-compliance. We disagree with those 
concerns as we believe the definition as currently written provides for 
such coverage. Nonetheless, we are not amending this definition in the 
final amendments for subpart J and will continue to address individual 
applicability issues under our applicability determination procedures. 
Similarly, we proposed revisions to the subpart J definitions of 
``oxidation control system'' and ``reduction control system'' in 40 CFR 
60.101(j) and 40 CFR 60.101(k), respectively, to clarify that these 
systems were intended to recycle the sulfur back to the Claus SRP. The 
proposed amendments needlessly limit the types of tail gas treatment 
systems that can be used; therefore, we are not amending these 
definitions in the final amendments for subpart J.
    The final amendments also include technical corrections to fix 
references and other miscellaneous errors in 40 CFR part 60, subpart J. 
Table 1 of this preamble describes the miscellaneous technical 
corrections not previously described in this preamble that are included 
in the amendments to subpart J.

      Table 1.--Technical Corrections to 40 CFR Part 60, Subpart J
------------------------------------------------------------------------
           Section                  Technical correction and reason
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60.100......................  Replace instances of ``construction or
                               modification'' with ``construction,
                               reconstruction, or modification.''
60.100(a)...................  Replace ``except Claus plants of 20 long
                               tons per day (LTD) or less'' with
                               ``except Claus plants with a design
                               capacity for sulfur feed of 20 long tons
                               per day (LTD) or less'' to clarify that
                               the size cutoff is based upon design
                               capacity and sulfur content in the inlet
                               stream rather than the amount of sulfur
                               produced.
60.100(b)...................  Insert ending date for applicability of 40
                               CFR part 60, subpart J (one date for
                               flares and another date for all other
                               affected facilities); sources beginning
                               construction, reconstruction, or
                               modification after this date will be
                               subject to 40 CFR part 60, subpart Ja.
60.102(b)...................  Replace ``g/MJ'' with ``grams per
                               Gigajoule (g/GJ)'' to correct units.
60.104(b)(1)................  Replace ``sulfur dioxide'' with ``SO2''
                               and replace ``50 ppm by volume (vppm)''
                               with ``50 ppm by volume (ppmv)'' for
                               consistency in unit and acronym
                               definition.
60.104(b)(2)................  Add ``to reduce SO2 emissions'' to the end
                               of the phrase ``Without the use of an add-
                               on control device'' at the beginning of
                               the paragraph to clarify the type of
                               control device to which this paragraph
                               refers; replace ``sulfur dioxide'' with
                               ``SO2'' for consistency in acronym
                               definition.
60.105(a)(3)................  Add ``either'' before ``an instrument for
                               continuously monitoring'' and replace
                               ``except where an H2S monitor is
                               installed under paragraph (a)(4)'' with
                               ``or monitoring as provided in paragraph
                               (a)(4)'' to more accurately refer to the
                               requirements of Sec.   60.105(a)(4) and
                               clarify that there is a choice of
                               monitoring requirements.
60.105(a)(3)(iv)............  Replace ``accurately represents the S2
                               emissions'' with ``accurately represents
                               the SO2 emissions'' to correct a
                               typographical error.
60.105(a)(4)................  Replace ``In place'' with ``Instead'' at
                               the beginning of this paragraph and add
                               ``for fuel gas combustion devices subject
                               to Sec.   60.104(a)(1)'' after
                               ``paragraph (a)(3) of this section'' to
                               clarify that there is a choice of
                               monitoring requirements.
60.105(a)(8)................  Replace ``seeks to comply with Sec.
                               60.104(b)(1)'' with ``seeks to comply
                               specifically with the 90-percent
                               reduction option under Sec.
                               60.104(b)(1)'' to clearly identify the
                               emission limit option to which the
                               monitoring requirement in this paragraph
                               refers.
60.105(a)(8)(i).............  Change ``shall be set 125 percent'' to
                               ``shall be set at 125 percent'' to
                               correct a grammatical error; replace
                               ``sulfur dioxide'' with ``SO2'' for
                               consistency in acronym definition.
60.106(e)(2)................  Replace the incorrect reference to 40 CFR
                               60.105(a)(1) with a correct reference to
                               40 CFR 60.104(a)(1); add ``The method
                               ANSI/ASME PTC 19.10-1981, ``Flue and
                               Exhaust Gas Analyses,'' (incorporated by
                               reference--see Sec.   60.17) is an
                               acceptable alternative to EPA Method 6 of
                               Appendix A-4 to part 60.'' after the
                               first sentence of this paragraph to
                               include a voluntary consensus method.
60.107(c)(1)(i).............  Replace both occurrences of ``50 vppm''
                               with ``50 ppmv'' for consistency in unit
                               definition.
60.107(f)...................  Redesignate current 40 CFR 60.107(e) as 40
                               CFR 60.107(f) to allow space for a new
                               paragraph (e).
60.107(g)...................  Redesignate current 40 CFR 60.107(f) as 40
                               CFR 60.107(g) to allow space for a new
                               paragraph (e).
60.108(e)...................  Replace the incorrect reference to 40 CFR
                               60.107(e) with a correct reference to 40
                               CFR 60.107(f).
------------------------------------------------------------------------

B. What are the final requirements for new fluid catalytic cracking 
units and new fluid coking units (40 CFR part 60, subpart Ja)?

    The final standards for new FCCU include emission limits for 
particulate matter (PM), SO2, nitrogen oxides 
(NOX), and carbon monoxide (CO). The final standards include 
no universal opacity limit because the opacity limit in 40 CFR part 60, 
subpart J is intended to ensure compliance with the PM limit. 40 CFR 
part 60, subpart Ja requires that sources use direct PM monitoring, bag 
leak detection systems, or parameter monitoring (along with annual 
emission tests) to ensure compliance with the PM limit. A provision for 
a site-specific opacity operating limit is provided for units that meet 
the PM emission limits using a cyclone.
    For PM emissions from new FCCU and new FCU, we proposed a PM limit 
of 0.5 pounds (lb)/1,000 lb coke burnoff in the regenerator or (if a PM 
continuous emission monitoring system (CEMS) is

[[Page 35841]]

used), 0.020 grains per dry standard cubic feet (gr/dscf) corrected to 
0 percent excess air. We have revised the final PM standards to 
establish separate limits for modified or reconstructed FCCU (1 lb/
1,000 lb coke burn or 0.040 gr/dscf corrected to 0 percent excess air) 
and newly constructed FCCU (0.5 lb/1,000 lb coke burn or 0.020 gr/dscf 
corrected to 0 percent excess air). The final PM limit for new, 
modified, or reconstructed FCU is 1 lb/1,000 lb coke burn or 0.040 gr/
dscf corrected to 0 percent excess air.
    Initial compliance with the PM emission limits for FCCU and FCU is 
determined using EPA Method 5, 5B or 5F (40 CFR part 60, appendix A-3) 
instead of being restricted to only EPA Method 5 as previously 
proposed. Procedures for computing the PM emission rate using the total 
PM concentration, effluent gas flow rate, and coke burn-off rate are 
the same as in 40 CFR part 60, subpart J, as amended. To demonstrate 
ongoing compliance, an owner or operator must monitor PM emission 
control device operating parameters and conduct annual PM performance 
tests, use a PM CEMS, or operate bag leak detection systems and conduct 
annual PM performance tests. A new alternative allows refineries with 
wet scrubbers as PM control devices to use the approved alternative in 
40 CFR 63.1573(a) for determining exhaust gas flow rate instead of a 
continuous parameter monitoring system (CPMS). An alternative to the 
requirements for monitoring the pressure drop from wet scrubbers that 
are equipped with jet ejectors or atomizing spray nozzles is to conduct 
a daily check of the air or water pressure to the nozzles and record 
the results of each inspection. The final rule also includes procedures 
for establishing an alternative opacity operating limit for refiners 
that use continuous opacity monitoring systems (COMS); this alternative 
is allowed only for units that choose to comply with the PM limit using 
cyclones. If operating parameters are used to demonstrate ongoing 
compliance, the owner or operator must monitor the same parameters 
during the initial performance test, and develop operating parameter 
limits for the applicable parameters. The operating limits must be 
based on the three-run average of the values for the applicable 
parameters measured over the three test runs. If ongoing compliance is 
demonstrated using a PM CEMS, the CEMS must meet the conditions in 
Performance Specification 11 (40 CFR part 60, appendix B) and the 
quality assurance (QA) procedures in Procedure 2, 40 CFR part 60, 
appendix F. The relative response audits must be conducted annually (in 
lieu of annual performance tests for units not employing a PM CEMS) and 
response correlation audits must be conducted once every 5 years.
    For NOX emissions from the affected FCCU and FCU, we 
proposed a limit of 80 ppmv based on a 7-day rolling average (dry basis 
corrected to 0 percent excess air) and co-proposed having no limit for 
FCU. We are adopting the 80 ppmv NOX emission limits for 
FCCU and FCU as proposed. Initial compliance with the 80 ppmv emission 
limit is demonstrated by conducting a performance evaluation of the 
CEMS in accordance with Performance Specification 2 in 40 CFR part 60, 
appendix B, with Method 7 (40 CFR part 60, appendix A-4) as the 
reference method. Ongoing compliance with these emission limits is 
determined using the CEMS to measure NOX emissions as 
discharged to the atmosphere, averaged over 7-day periods.
    No changes have been made to the proposed SO2 emission 
limits for affected FCCU and FCU. The final SO2 emission 
limits are to maintain SO2 emissions to the atmosphere less 
than or equal to 50 ppmv on a 7-day rolling average basis, and less 
than or equal to 25 ppmv on a 365-day rolling average basis (both 
limits corrected to 0 percent moisture and 0 percent excess air). 
Initial compliance with the final SO2 emission limits are 
demonstrated by conducting a performance evaluation of the 
SO2 CEMS in accordance with Performance Specification 2 (40 
CFR part 60, Appendix B) with Method 6, 6A, or 6C (40 CFR part 60, 
Appendix A-4) as the reference method. Ongoing compliance with both 
SO2 emission limits is determined using the CEMS to measure 
SO2 emissions as discharged to the atmosphere, averaged over 
the 7-day and 365-day averaging periods.
    No changes have been made since proposal to the CO limits. The 
final CO emission limit for the affected FCCU and FCU is 500 ppmv (1-
hour average, dry at 0 percent excess air). Initial compliance with 
this emission limit is demonstrated by conducting a performance 
evaluation for the CEMS in accordance with Performance Specification 4 
(40 CFR part 60, appendix B) with Method 10 or 10A (40 CFR part 60, 
Appendix A-4) as the reference method. For Method 10 (40 CFR part 60, 
Appendix A-4), the integrated sampling technique is to be used. Ongoing 
compliance with this emission limit is determined on an hourly basis 
using the CEMS to measure CO emissions as discharged to the atmosphere. 
An exemption from monitoring may be requested for an FCCU or FCU if the 
owner or operator can demonstrate that ``average CO emissions'' are 
less than 50 ppmv (dry basis). As proposed, units that are exempted 
from the CO monitoring requirements must comply with control device 
operating parameter limits.

C. What are the final requirements for new sulfur recovery plants (40 
CFR part 60, subpart Ja)?

    For new, modified, and reconstructed SRP with a capacity greater 
than 20 long tons per day (LTD) (large SRP), we proposed a limit of 250 
ppmv total sulfur (combined SO2 and reduced sulfur 
compounds) as SO2 (dry basis at 0 percent excess air 
determined on a 12-hour rolling average basis). The refinery could 
comply with the limit for each process train or release point or with a 
flow rate weighted average of 250 ppmv for all release points. For 
affected SRP with a capacity less than 20 LTD (small SRP), we proposed 
a mass emissions limit for total sulfur equal to 1 weight percent or 
less of sulfur recovered (determined hourly on a 12-hour rolling 
average basis).
    In this final rule, we are adopting the current limits in subpart J 
(which include separate emission limits for oxidative and reductive 
systems) for affected large SRP. For these affected SRP, the final 
limits for SRP having an oxidation control system or a reduction 
control system followed by incineration is 250 ppmv (dry basis) of 
SO2 at zero percent excess air. For an affected SRP with a 
reduction control system not followed by incineration, the final limit 
is 300 ppmv of reduced sulfur compounds and 10 ppmv of hydrogen sulfide 
(H2S), each calculated as ppm SO2 by volume (dry 
basis) at zero percent excess air. If the SRP consists of multiple 
process trains or release points, the refinery can comply with the 
limit for each process train or release point or with a flow rate 
weighted average of 250 ppmv for all release points. A new alternative 
allows refineries to use a correlation to calculate their effective 
emission limit for Claus SRP that use oxygen enrichment in the Claus 
burner. For a small affected SRP, the sulfur recovery efficiency 
standard is based on a sulfur recovery efficiency of 99 percent. 
However, due to the difficulties associated with on-going monitoring of 
SRP recovery efficiency, in this final rule, we are promulgating 
concentration limits that correlate with a sulfur recovery efficiency 
of 99 percent. For a Claus unit with an oxidative control system or any 
small SRP followed by an incinerator the emission limit is 2,500

[[Page 35842]]

ppmv (dry basis) of SO2 at zero percent excess air. For all 
other small SRP, the emission limit is 3,000 ppmv reduced sulfur 
compound and 100 ppmv H2S, each calculated as ppm 
SO2 by volume (dry basis) at zero percent excess air. A 
similar correlation is provided for small Claus SRP that use oxygen 
enrichment, similar to that provided for large SRP. The standards for 
small SRP apply to all release points from the SRP combined (note that 
secondary sulfur storage units are not considered part of the SRP). We 
are not promulgating the H2S limit of 10 ppmv (dry basis, at 
0 percent excess air determined on a 12-hour rolling average basis) or 
related operating limits that were included in Sec.  60.102a(e) and (f) 
of the proposed rule.
    Initial compliance with the emission limit for large SRP is 
demonstrated by conducting a performance evaluation for the 
SO2 CEMS in accordance with either Performance Specification 
2 (40 CFR part 60, Appendix B) for SRP with oxidation control systems 
or reduction control systems followed by incineration, or Performance 
Specification 5 (40 CFR part 60, Appendix B) for SRP with reduction 
control systems not followed by incineration. The owner or operator 
must operate and maintain oxygen monitors according to Performance 
Specification 3 (40 CFR part 60, Appendix B).
    Ongoing compliance with the SO2 limits for large SRP is determined 
using an SO2 CEMS (for oxidative or reductive systems followed by 
incineration) or a CEMS that uses an air or O2 dilution and oxidation 
system to convert the reduced sulfur to SO2 and then measures the total 
resultant SO2 concentration (for reductive systems not followed by 
incineration). An O2 monitor is also required for converting the 
measured combined SO2 concentration to the concentration at 0 percent 
O2.
    Initial and ongoing compliance requirements for small SRP are the 
same as for large SRP.

D. What are the final requirements for new fuel gas combustion devices 
(40 CFR part 60, subpart Ja)?

    In the subpart Ja proposal, we divided fuel gas combustion devices 
into two separate affected sources: ``process heaters'' and ``other 
fuel gas combustion devices.'' In response to comments, we have 
eliminated the proposed definition of ``other fuel gas combustion 
devices'' and revised the standards to either refer to fuel gas 
combustion devices, which include process heaters, or to refer 
specifically to process heaters. This revision makes the definition of 
``fuel gas combustion devices'' consistent with subpart J. Based on 
public comments, we have also added a definition of ``flare'' as a 
subcategory of fuel gas combustion devices. The owner or operator of an 
affected flare must comply with the fuel gas combustion device 
requirements as well as specific provisions for flares as described in 
section III.E of this preamble.
    We proposed a primary sulfur dioxide emission limit for fuel gas 
combustion devices of 20 ppmv or less SO2 (dry at 0 percent excess air) 
on a 3-hour rolling average basis and 8 ppmv or less on a 365-day 
rolling average basis. We also proposed an alternative limit of 160 
ppmv H2S or, in the case of coker-derived fuel gas, 160 ppmv total 
reduced sulfur (TRS), on a 3-hour rolling average basis and 60 ppmv or 
less on a 365-day rolling average basis. We are promulgating the 20 
ppmv and 8 ppmv limits for SO2 as proposed. We are also promulgating 
the alternative limit except that the limits are expressed and measured 
as H2S in all cases. The alternative H2S limit is 162 ppmv or less in 
the fuel gas on a 3-hour rolling average basis and 60 ppmv or less in 
the fuel gas on a 365-day rolling average basis. The alternative limit 
of 162 ppmv is based on standard conditions, which are defined in the 
NSPS General Provisions at 40 CFR 60.2 as being 68[deg]F and 1 
atmosphere. Using these as standard conditions, the subpart J emission 
limit is equivalent to 162 ppmv H2S rather than 160 ppmv. The final 
rule does not include an alternative TRS limit for SO2.
    Initial compliance with the 20 ppmv SO2 limit or the 162 ppmv H2S 
concentration limits is demonstrated by conducting a performance 
evaluation for the CEMS. The performance evaluation for an SO2 CEMS is 
conducted in accordance with Performance Specification 2 in 40 CFR part 
60, Appendix B. The performance evaluation for an H2S CEMS is conducted 
in accordance with Performance Specification 7 in 40 CFR part 60, 
Appendix B. Ongoing compliance with the sulfur oxides emission limits 
is determined using the applicable CEMS to measure either SO2 in the 
exhaust gas to the atmosphere or H2S in the fuel gas, averaged over the 
3-hour and 365-day averaging periods.
    Similar to clarifications for 40 CFR part 60, subpart J, the 
definition of ``fuel gas'' includes exemptions for vapors collected and 
combusted in an air pollution control device installed to comply with 
specified wastewater or marine vessel loading provisions. We are also 
streamlining the process for an owner or operator to demonstrate that a 
fuel gas stream not explicitly exempted from continuous monitoring is 
inherently low sulfur.
    For new, modified, or reconstructed process heaters with a rated 
capacity greater than 20 million British thermal units per hour (MMBtu/
hr), we proposed a NOX limit of 80 ppmv (dry basis, corrected to 0 
percent excess air) on a 24-hour rolling average basis. The final NOX 
emission limit for affected process heaters is 40 ppmv on a 24-hour 
rolling average basis (dry at 0 percent excess air) for process heaters 
greater than 40 MMBtu/hr. For process heaters greater than 100 MMBtu/hr 
capacity, initial compliance with the 40 ppmv emission limit is 
demonstrated by conducting a performance evaluation of the CEMS in 
accordance with Performance Specification 2 in 40 CFR part 60, Appendix 
B. For process heaters between 40 MMBtu/hr and 100 MMBtu/hr capacity, 
initial compliance is demonstrated using EPA Method 7 (40 CFR part 60, 
Appendix A-4). For process heaters greater than 100 MMBtu/hr capacity, 
ongoing compliance with this emission limit is determined using the 
CEMS to measure NOX emissions as discharged to the atmosphere, averaged 
over 24-hour periods. For process heaters between 40 MMBtu/hr and 100 
MMBtu/hr capacity, ongoing compliance with this emission limit is 
determined using biennial performance tests.

E. What are the final work practice standards (40 CFR part 60, subpart 
Ja)?

    We proposed three work practice standards to reduce SO2, VOC, and 
NOX emissions from flares and from startup, shutdown, and malfunction 
events and to reduce VOC and SO2 emissions from delayed coking units. 
We also co-proposed to require only one of these work practice 
standards: the requirement to depressure delayed coking units. This 
proposed standard required new delayed coking units to depressure to 5 
pounds per square inch gauge (psig) during reactor vessel depressuring 
and vent the exhaust gases to the fuel gas system.
    We are promulgating a work practice standard for delayed coking 
units and modified requirements to reduce emissions from flares. The 
final work practice standard for delayed cokers requires affected 
delayed coking units to depressure to 5 pounds per square inch gauge 
(psig) during reactor vessel depressuring. We are requiring the exhaust 
gases to be vented to the fuel gas system as proposed or to a flare.
    To reduce SO2 emissions from the combustion of sour fuel gases, the 
final rule requires refineries to conduct a root

[[Page 35843]]

cause analysis of any emissions limit exceedance or process start-up, 
shutdown, upset, or malfunction that causes a discharge into the 
atmosphere, either directly or indirectly, from any fuel gas combustion 
device or sulfur recovery plant subject to the provisions of subpart Ja 
that exceeds 500 pounds per day (lb/day) of SO2. Recordkeeping and 
reporting requirements apply in the event of such a discharge. Newly 
constructed and reconstructed flares must comply with these 
requirements immediately upon startup. Modified flares must comply no 
later than the first discharge that occurs after that flare has been an 
affected flare for 1 year.
    In response to comments regarding the work practice standards for 
fuel gas producing units and associated difficulties with no routine 
flaring, we re-evaluated the work practice standards and have decided 
not to promulgate a work practice standard for fuel gas producing 
units. Rather, we have decided to define a flare as an affected 
facility and adopt regulations applicable to it. Therefore, we are not 
promulgating the proposed definition of ``fuel gas producing unit'' and 
the proposed requirement for ``no routine flaring.'' Instead, we are 
promulgating the following requirements for flares that become affected 
facilities after June 24, 2008: (1) Flare fuel gas flow rate 
monitoring; (2) a flare fuel gas flow rate limit; and (3) a flare 
management plan. Affected flares cannot exceed a flow rate of 250,000 
standard cubic feet per day (scfd) on a 30-day rolling average basis. 
In cases where the flow would exceed this value, the owner or operator 
would install a flare gas recovery system or implement other methods to 
reduce flaring from the affected flare. To demonstrate compliance with 
the flow rate limitations, flow rate monitors must be installed and 
operated. Newly constructed and reconstructed flares must comply with 
the flow rate limitations and the monitoring requirements immediately 
upon startup. Modified flares must comply with the flow rate 
limitations and the associated monitoring provisions no later than 1 
year after the flare becomes an affected facility. A provision is 
provided for an exclusion from the flow limitation for times when the 
refinery can demonstrate that the refinery produces more fuel gas than 
it needs to fuel the refinery combustion devices (i.e., it is fuel gas 
rich) or that the flow is due to an upset or malfunction, provided the 
refinery follows procedures outlined in the flare management plan. The 
flare management plan should address potential causes of fuel gas 
imbalances (i.e., excess fuel gas) and records to be maintained to 
document these periods. As described in 40 CFR 60.103a(a), the flare 
management plan must include a diagram illustrating all connections to 
each affected flare, identification of the flow rate monitoring device 
and a detailed description of the manufacturer's specifications 
regarding quality assurance procedures, procedures to minimize flaring 
during planned start-up and shut down events, and procedures for 
implementing root cause analysis when daily flow to the flare exceeds 
500,000 scfd. The root cause analysis procedures should address the 
evaluation of potential causes of upsets or malfunctions and records to 
be maintained to document the cause of the upset or malfunction. Newly 
constructed and reconstructed flares must comply with the flare 
management plan requirements immediately upon startup. Modified flares 
must comply with the flare management plan requirements no later than 1 
year after the flare becomes an affected facility. Additionally, as 
described above, the owner or operator of a modified flare must conduct 
the first root cause analysis no later than the first discharge that 
occurs after that flare has been an affected flare for 1 year. Excess 
emission events for the flow rate limit of 250,000 scfd and the result 
of root cause analysis must be reported in the semi-annual compliance 
reports.
    Because affected flares are also affected fuel gas combustion 
devices, the root cause analysis for SO2 emissions exceeding 500 lbs/
day also applies to all affected flares. However, compliance with the 
500 lb/day root cause analysis will also require continuous monitoring 
of total reduced sulfur of all gases flared. Although all fuel gas 
combustion devices are required to comply with continuous H2S 
monitoring of fuel gas, flares routinely accept gases from upsets, 
malfunctions and startup and shutdown events, and H2S or sulfur 
monitoring is not specifically required for these gases. In subpart Ja, 
we explicitly require TRS monitoring for flares that become affected 
facilities after June 24, 2008 to ensure that the 500 lb/day SO2 
trigger is accurately measured. The owner or operator of a modified 
flare must install and operate the TRS monitoring instrument no later 
than 1 year after the flare becomes an affected facility. The owner or 
operator of a newly constructed or reconstructed flare must install and 
operate the TRS monitoring instrument no later than start-up of the 
flare.

F. What are the modification and reconstruction provisions?

    Existing affected facilities that commence modification or 
reconstruction after May 14, 2007, are subject to the final standards 
in 40 CFR part 60, subpart Ja. A modification is any physical or 
operational change to an existing affected facility which results in an 
increase in the emission rate to the atmosphere of any pollutant to 
which a standard applies (see 40 CFR 60.14). Changes to an existing 
affected facility that do not result in an increase in the emission 
rate, as well as certain changes that have been exempted under the 
General Provisions (see 40 CFR 60.14(e)), are not considered 
modifications.
    The intermittent operation of a flare makes it difficult to use the 
criteria of 40 CFR 60.14 to determine when a flare is modified; 
therefore, we have specified in the final rule the criteria that define 
a modification to a flare. A flare is considered to be modified if: (1) 
Any piping from a refinery process unit or fuel gas system is newly 
connected to the flare or (2) the flare is physically altered to 
increase flow capacity. See section IV.I of this preamble for further 
explanation on the change in affected source from a fuel gas producing 
unit to the flare.
    Petroleum refinery process units are subject to the final standards 
in 40 CFR part 60, subpart Ja if they meet the criteria under the 
reconstruction provisions, regardless of changes in emission rate. 
Reconstruction means the replacement of components of an existing 
facility such that (1) the fixed capital cost of the new components 
exceeds 50 percent of the fixed capital cost that would be required to 
construct a comparable entirely new facility; and (2) it is 
technologically and economically feasible to meet the applicable 
standards (40 CFR 60.15).

IV. Summary of Significant Comments and Responses

    As previously noted, we received a total of 46 comments during the 
public comment periods associated with the proposed rule and NODA. 
These comments were received from refineries, industry trade 
associations, and consultants; State and local environmental and public 
health agencies; environmental groups; and members of the public. In 
response to these public comments, most of the cost and emission 
reduction impact estimates were recalculated, resulting in several 
changes to the final amendments and new standards. The major comments 
and our responses are

[[Page 35844]]

summarized in the following sections. A summary of the remainder of the 
comments received during the comment period and responses thereto can 
be found in the docket for the final amendments and new standards 
(Docket ID No. EPA-OAR-HQ-2007-0011). The docket also contains further 
details on all the analyses summarized in the responses below.
    In responding to the public comments, we re-evaluated the costs and 
cost-effectiveness of the control options and re-evaluated our BDT 
determinations. In our BDT determinations, we took all relevant factors 
into account consistent with other Agency decisions. It is important to 
note that, due to the different health and welfare effects associated 
with different pollutants, the acceptable cost-effectiveness value of a 
control option is pollutant dependent. These pollutant-specific factors 
were considered along with other factors in our BDT determinations.

A. PM Limits for Fluid Catalytic Cracking Units

    Comment: Several commenters opposed the proposed tightening of the 
FCCU PM standards relative to subpart J and the concurrent change in PM 
monitoring methods. Some commenters supported the co-proposal to keep 
the 1 lb/1,000 lb coke burn PM emission limit based on Method 5B and/or 
5F; other commenters either did not oppose or supported the 0.5 lb/
1,000 lb coke burn emission limit for new ``grassroots'' units, 
provided EPA demonstrates it is cost-effective and that the limit is 
based on EPA Method 5B or 5F (40 CFR part 60, Appendix A-3).
    Commenters stated that EPA should only impose the more stringent 
emission limits on new construction because it is much more difficult 
and costly to meet the proposed emission limits for modified or 
reconstructed equipment. Commenters suggested that if EPA does include 
more stringent limits on modifications, it should exclude certain 
actions (like projects implemented to meet consent decree requirements) 
from the definition of a modification.
    Several commenters suggested that the costs in Table 11 of the 
proposal preamble are significantly underestimated. Commenters 
contended that the single ``model plant'' approach used in EPA's cost 
analysis does not realistically consider important factors such as the 
inherent sulfur content of the feed, partial-burn versus full-burn 
regeneration, FCCU/regenerator size, and sources that are already well-
controlled due to other regulations. Commenters asserted that the 
purchased equipment costs escalated from estimates that are 20 to 30 
years old are underestimated. Several commenters provided estimates of 
costs and emission reductions for several actual projects, which they 
stated indicate that EPA's costs are significantly underestimated and 
that the proposed standards are much less cost-effective than presented 
by EPA.
    A number of commenters asserted that the PM standards should be 
based on EPA Methods 5B or 5F (40 CFR part 60, Appendix A-3), and not 
on EPA Method 5 of Appendix A-3 to part 60. According to these 
commenters, the achievability of the proposed 0.5 lb/1,000 lb coke burn 
PM limit based on EPA Method 5 is questionable because there are 
inadequate data on FCCU using EPA Method 5, and controlling combined 
condensable and filterable PM to the 0.5 lb/1,000 lb coke burn level 
has not been demonstrated to be cost-effective.
    On the other hand, several commenters stated that any PM limit must 
include condensable and filterable PM as condensable PM account for a 
large portion of refinery PM emissions and all condensable PM is PM 
that is less than 2.5 micrometers in diameter (PM2.5), which has more 
adverse health impacts than larger particles; the commenters therefore 
agreed with the use of EPA Method 5 to determine filterable PM and 
requested that EPA consider Method 202 (40 CFR part 51, Appendix M) for 
condensable PM. Commenters also stated that the limits for PM and SO2 
in subpart Ja should apply to all new, reconstructed, and modified 
FCCU. One commenter recommended that a total PM limit (filterable and 
condensable) be set at 1 lb/1,000 coke burn; another stated that the 
total PM limit, including both filterable and condensable PM, should be 
0.5 lb/1,000 lb coke burn, and EPA has not demonstrated that current 
BDT cannot achieve this limit. Finally, one commenter suggested that 
EPA should evaluate the cost of removing each pollutant (PM and SO2) 
separately.
    Response: In response to these comments, we have revised our 
analysis to consider each unique existing FCCU in the United States. By 
doing so, we fully account for plant size, partial-burn versus full-
burn regeneration, existing control configuration, and specific consent 
decree requirements. (Details on the specific revisions to the analysis 
can be found in the docket.) With a revised analysis, we were able to 
more directly assess the impacts of process modifications or 
reconstruction of existing equipment. We also assessed the effects of 
PM and SO2 standards separately in this analysis.
    In our revised analysis, we considered three options for PM: (1) 
Maintain the existing subpart J standard of 1.0 lb/1,000 lb of coke 
burn-off (filterable PM as measured by Method 5B or 5F); (2) 0.5 lb/
1,000 lb of coke burn-off (filterable PM as measured by Method 5B or 5F 
of Appendix A-3 to part 60); and (3) 0.5 lb/1,000 lb of coke burn-off 
(filterable PM as measured by Method 5 of Appendix A-3 to part 60). 
Similar to the analysis for the proposed standards, costs and emission 
reductions for each option were estimated as the increment between 
complying with subpart J and subpart Ja. We note that none of the 
available data suggest that a 0.5 lb/1,000 lb coke burn emission limit 
that includes both filterable and condensable PM as measured using EPA 
Method 202 is achievable in practice for the full range of facilities 
using BDT controls, so we disagree with the comments suggesting this 
level is appropriate to consider as an option for a total PM limit in 
this rulemaking.
    Option 1 includes the same emissions and requirements for PM as the 
current 40 CFR part 60, subpart J, so it will achieve no additional 
emissions reductions. The PM limit in Option 2 is the same numerical 
limit that was proposed in subpart Ja, but the PM emissions are 
determined using Methods 5B and 5F (40 CFR part 60, Appendix A-3). 
These test methods are commonly used for PM tests of FCCU and are the 
methods that were used to generate a majority of the test data we 
reviewed. Option 3 is a limit of 0.5 lb/1,000 lb coke burn using Method 
5 and is the performance level that was proposed for subpart Ja. The 
impacts of these three options for new FCCU are presented in Table 2 to 
this preamble; the impacts for modified and reconstructed FCCU are 
presented in Table 3 to this preamble.

[[Page 35845]]



Table 2.--National Fifth Year Impacts of Options for PM Limits Considered for New Fluid Catalytic Cracking Units
                                    Subject to 40 CFR Part 60, Subpart Ja\a\
----------------------------------------------------------------------------------------------------------------
                                                   Total annual      Emission       Cost effectiveness ($/ton)
             Option                Capital cost   cost  ($1,000/     reduction   -------------------------------
                                     ($1,000)           yr)        (tons PM/yr)       Overall       Incremental
----------------------------------------------------------------------------------------------------------------
2...............................           3,600           1,100             240           5,600           5,600
3...............................           7,100           1,700             300           6,700          11,000
----------------------------------------------------------------------------------------------------------------
\a\ PM cost-effectiveness calculated for PM-fine; 83.3 percent of the PM is PM-fine.


 Table 3.--National Fifth Year Impacts of Options for PM Limits Considered for Reconstructed and Modified Fluid
                        Catalytic Cracking Units Subject to 40 CFR Part 60, Subpart Ja\a\
----------------------------------------------------------------------------------------------------------------
                                                   Total annual      Emission       Cost effectiveness ($/ton)
             Option                Capital cost   cost  ($1,000/     reduction   -------------------------------
                                     ($1,000)           yr)        (tons PM/yr)       Overall       Incremental
----------------------------------------------------------------------------------------------------------------
2...............................          75,000          12,000             690          21,000          21,000
3...............................         100,000          15,000             810          23,000          37,000
----------------------------------------------------------------------------------------------------------------
\a\ PM cost-effectiveness calculated for PM-fine; 83.3 percent of the PM is PM-fine.

    The available data and impacts for the options considered suggest 
that BDT for new FCCU is different than BDT for modified and 
reconstructed FCCU. For new FCCU, the costs for Option 2 are reasonable 
compared to the emission reduction achieved. The incremental cost 
between Option 2 and Option 3 of $11,000 per ton PM-fine would 
generally be considered reasonable, but there are uncertainties in the 
achievability of Option 3. The estimated PM emission reduction achieved 
by Option 3 compared to Option 2 equals the amount of sulfates and 
other condensable PM between 250 [deg]F and 320 [deg]F that would be 
measured by Method 5 but not Method 5B or 5F (40 CFR part 60, Appendix 
A-3). Additionally, available test data indicate that electrostatic 
precipitators (ESP) and wet scrubbers can reduce total filterable PM to 
0.5 lb/1,000 lb of coke burn or less, as measured by Method 5-
equivalent test methods. Although there were few test data points using 
Method 5-equivalent test methods, we concluded at proposal that both 
electrostatic precipitators and wet scrubbers can achieve this level of 
PM emissions. However, the data supporting Option 3 are not extensive, 
and it is unclear at this time whether a limit of 0.5 kg/Mg of coke 
burn as measured by Method 5 (40 CFR part 60, Appendix A-3) could be 
met by all configurations of FCCU. In addition, while the Agency 
supports reducing condensable PM emissions, the amount of condensable 
PM captured by Method 5 is small relative to methods that specifically 
target condensable PM, such as Method 202 (40 CFR part 51, Appendix M). 
We prefer to develop a single performance standard that considers all 
condensable PM rather than implementing phased standards targeting 
different fractions of condensable PM. Such an approach would be costly 
and inefficient. Therefore, we conclude that Option 2, control of PM 
emissions (as measured by Methods 5B and 5F of Appendix A-3 to part 60) 
to 0.5 lb/1,000 lb of coke burn or less, is BDT for newly constructed 
FCCU. This option achieves PM emission reductions of 240 tons per year 
(tons/yr) from a baseline of 910 tons/yr at a cost of $5,600 per ton of 
PM.
    For modified and reconstructed FCCU, Option 1 is the baseline level 
of control established by the existing requirements of subpart J. It 
will achieve no additional cost or emission reduction. The overall 
costs and the incremental costs for Options 2 and 3 are reasonable 
compared to the PM emission reduction; however, as with new FCCU, the 
performance of Option 3 has not been demonstrated, so it is rejected. 
Most of the existing FCCU that could become subject to subpart Ja 
through modification or reconstruction are either already subject to 
subpart J or are covered by the consent decrees. The consent decrees 
are generally based on the existing subpart J. Industry has made 
significant investments in complying with these subpart J requirements 
which may be abandoned if they become subject to subpart Ja. In 
addition, the additional costs could create a disincentive to modernize 
FCCU to make them more energy efficient or to produce more refined 
products. For these reasons, we reject Option 2 for modified or 
reconstructed FCCU and conclude that control of PM emissions (as 
measured by Methods 5B and 5F of Appendix A-3 to part 60) is 1.0 lb/
1,000 lb of coke burn or less is BDT for reconstructed and modified 
FCCU.

B. SO2 Limits for Fluid Catalytic Cracking Units

    Comment: Several commenters supported the co-proposal for modified 
and reconstructed FCCU to meet subpart J and not the 25 ppmv 365-day 
rolling average limit for SO2. Commenters provided data to suggest that 
the retrofits of existing sources are not cost effective, particularly 
if catalyst additives cannot be used. The current subpart J includes 
three compliance options: (1) If using an add-on control device, reduce 
SO2 emissions by at least 90 percent or to less than 50 ppmv; (2) if 
not using an add-on control device, limit sulfur oxides emissions 
(calculated as SO2) to no more than 9.8 kg/Mg of coke burn-off; or (3) 
process in the fluid catalytic cracking unit fresh feed that has a 
total sulfur content no greater than 0.30 percent by weight. Several 
commenters objected to the elimination of the additional compliance 
options in the existing subpart J for subpart Ja because: (1) There are 
no data to show that the SO2 limits proposed in subpart Ja are BDT for 
all FCCU regenerator configurations; (2) the three options are already 
established as BDT and, therefore, the CAA requires that EPA make them 
available; and (3) the substantial cost and other burdens for a 
reconstructed or modified FCCU already complying with one of the 
alternative options in subpart J to change to daily monitoring by 
Method 8 (40 CFR part 60, Appendix A-4) or to install CEMS were not 
addressed in the proposal.
    One commenter supported the proposed SO2 limit under Ja 
for new ``grassroots'' FCCU if the standard is demonstrated to be cost-
effective.

[[Page 35846]]

    Response: As acknowledged in the previous response on PM standards 
for FCCU, we completely revised our impacts analysis to evaluate SO2 
standards for every existing FCCU that may become subject to subpart Ja 
through modification or reconstruction. We did not have access to the 
inherent sulfur content of the feed for each FCCU so SO2 emissions are 
still estimated using average emission factors relevant to the type of 
control device used for FCCU not subject to consent decree 
requirements. Nonetheless, we significantly revised the impact analysis 
to fully account for FCCU-specific throughput, existing controls, and 
consent decree requirements. (Details on the specific revisions to the 
analysis can be found in Docket ID No. EPA-HQ-OAR-2007-0011.) We 
evaluated two options: (1) Current subpart J, including all three 
compliance options; and (2) 50 ppmv SO2 on a 7-day average and 25 ppmv 
on a 365-day average. Data are not available on which to base a more 
stringent control level.
    Option 1 includes the same emissions and requirements as the 
current 40 CFR part 60, subpart J, so it will achieve no additional 
emissions reductions. Based on information provided by vendors and data 
submitted by petroleum refiners, Option 2 can be met with catalyst 
additives or a wet scrubber. Of 38 FCCU currently subject to a 50/25 
ppmv SO2 limit through consent decrees, 26 used wet scrubbers and 12 
used catalyst additives or other (unspecified) techniques. Given the 
number of FCCU currently meeting the 50/25 ppmv SO2 emission limit, we 
conclude that this limit is technically feasible.
    The data in the record suggest that all systems with wet scrubbers 
can meet the 50/25 ppmv SO2 emission limit with no additional cost. 
Further, based on information from the consent decrees, we believe that 
the owner or operator of an existing FCCU that does not already have a 
wet scrubber and is modified or reconstructed such that it becomes 
subject to subpart Ja can use catalyst additives to meet the 50/25 ppmv 
SO2 emission limit. Therefore, the cost of Option 2 is calculated using 
catalyst additives as the method facilities choose for meeting the 
standard. We reject the idea that the 90 percent control efficiency, 
the 9.8 kg/Mg coke burn-off limit, or the 0.3 weight percent sulfur 
content alternatives are equivalent to the 50/25 ppmv SO2 emission 
limit. Based on the original background document for the subpart J 
standards, these alternatives are expected to have outlet SO2 
concentrations of 200 to 400 ppmv. In reality the currently used wet 
scrubbers and catalyst additives achieve much higher SO2 
removal efficiencies and much lower outlet SO2 concentrations. The 
impacts of these options are presented in Table 4 of this preamble.

 Table 4.--National Fifth Year Impacts of Options for SO2 Limits Considered for New, Reconstructed, and Modified Fluid Catalytic Cracking Units Subject
                                                              to 40 CFR Part 60, Subpart Ja
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                        Total annual       Emission        Cost effectiveness ($/ton)
                               Option                                  Capital cost    cost  ($1,000/     reduction    ---------------------------------
                                                                         ($1,000)           yr)         (tons SO2/yr)       Overall        Incremental
--------------------------------------------------------------------------------------------------------------------------------------------------------
2..................................................................               0            3,000            4,400              700              700
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on the data we reviewed to select the options and the 
estimated impacts of those options, we conclude that Option 2, control 
of SO2 emissions to 25 ppmv or less averaged over 365 days 
and 50 ppmv or less averaged over 7 days, is technically feasible and 
cost-effective for new, reconstructed, and modified fluid catalytic 
cracking units. This option has no capital cost and achieves 
SO2 emission reductions of 4,400 tons/yr from a baseline of 
5,900 tons/yr at a cost of $700 per ton of SO2. Therefore, 
we conclude that control of SO2 emissions to 25 ppmv or less 
averaged over 365 days and 50 ppmv or less averaged over 7 days is BDT 
for new, reconstructed, or modified fluid catalytic cracking units.

C. NOX Limit for Fluid Catalytic Cracking Units

    Comment: Several commenters stated that they would support a 
NOX limit of 80 ppmv for new sources only, provided a 
corrected impact analysis considers the different characteristics of 
FCCU and demonstrates that the NOX limit for new sources is 
truly cost-effective. Commenters supported the co-proposal for modified 
and reconstructed FCCU to meet subpart J and not be subject to a 
NOX emission limit. A few commenters provided cost data 
showing the cost of NOX controls is high for modified and 
reconstructed units due to the high cost and space needed for add-on 
controls. The commenters also stated that a large number of existing 
FCCU in the U.S. are covered by consent decrees, so significant 
NOX reductions have already been (or will soon be) achieved, 
and an additional incremental reduction to 20 or 40 ppmv over a 365-day 
average are not widely demonstrated and would not be cost-effective.
    One commenter stated that selective noncatalytic reduction (SNCR), 
selective catalytic reduction (SCR), and catalyst additives have not 
been demonstrated over significant periods of operational life. 
Commenters also cited environmental side-effects, such as the 
generation of ammonia compounds that contribute to condensable PM 
emissions, as a reason not to require these types of controls. 
Commenters also asserted that technologies like flue gas recirculation 
or advanced burner design are typically only cost-effective for new 
units and may be technically infeasible for existing FCCU.
    One commenter suggested that if a limit is necessary for modified 
or reconstructed FCCU, recent catalyst additive trials support an 
emission limit of approximately 150 ppmv on a 7-day rolling average; 
this limit would only be achievable if a 24-hour CO averaging time was 
provided since lowering NOX tends to increase CO emissions 
in FCCU. The commenter noted that this limit is equivalent to the 0.15 
pounds per million British thermal units (lb/MMBtu) standard for 
reconstructed and modified heaters and boilers in NSPS subpart Db.
    Other commenters supported the inclusion of a NOX limit 
for FCCU and opposed the co-proposal of no NOX standard for 
modified and reconstructed FCCU. These commenters also recommended more 
stringent NOX limits for FCCU and stated that 80 ppmv does 
not represent an adequate level of control given the evolution of 
emerging technologies. In addition, a BDT of 80 ppmv on 7-day rolling 
average does not look ``toward what may be fairly projected for the 
regulated future'' as required by Portland Cement I (486 F. 2d 375 at 
384 (D.C. Cir. 1973)) and other court decisions. The commenters 
disagreed with the feasibility and cost analyses for modified and 
reconstructed FCCU and stated that FCCU under a consent decree are 
achieving lower levels than the 80 ppmv proposed by EPA. Given the 
significant hazards to

[[Page 35847]]

human health and the environment posed by NOX emissions, the 
commenters recommended limits of 20 ppmv over a 365-day rolling average 
and 40 ppmv over a 7-day rolling average for all FCCU. The commenters 
noted that these limits have been successfully achieved under consent 
decrees and they are technically feasible on new units at reasonable 
costs without additional controls.
    Response: As shown by the disparate comments received, many 
commenters suggest lower NOX emission limits are achievable, 
while other commenters do not believe the proposed NOX 
emission limits are cost-effective. While we do acknowledge that lower 
NOX emission limits are technically achievable, the 
incremental cost of achieving these lower limits was high when we 
evaluated options for the proposed standards. Therefore, we concluded 
at proposal that 20 or 40 ppmv NOX limits were not BDT. In 
our BDT assessment, we evaluated the various methods to meet 
alternative NOX limits as BDT rather than identifying one 
technology. One of the reasons for this is that each technology has its 
own advantages and limitations. While non-platinum oxidation promoters 
and advanced oxidation controls do not achieve the same reduction in 
NOX emissions as add-on control devices such as SCR, they do 
so without any significant secondary impacts. The added NOX 
reduction of SCR and SNCR must be balanced with these secondary 
impacts. Part of the basis for selecting control methods to achieve an 
80 ppmv NOX emission limit as BDT included both cost and 
secondary impacts. This approach is necessary when conducting our BDT 
analysis, thus ensuring the best overall environmental benefit from the 
subpart Ja standards.
    To ensure that we addressed the commenters' concerns, we re-
evaluated the impacts for FCCU NOX controls. We also 
collected additional data from continuous NOX monitoring 
systems for a variety of FCCU NOX control systems. These 
data suggest that as refiners gain more experience with the 
NOX control systems (including catalyst additive 
improvements), NOX control performance has improved over the 
past year or two. These data suggest that the achievable level for 
combustion controls and catalyst additives is 80 ppmv and the 
achievable level for add-on control systems is 20 ppmv. Therefore, we 
evaluated three outlet NOX emission level options as part of 
the BDT determination: (1) 150 ppmv; (2) 80 ppmv; and (3) 20 ppmv. Each 
NOX concentration is averaged over 7 days. To estimate 
impacts for Option 1, we estimated that some units have current 
NOX emissions below 150 ppmv, and all other units can meet 
this level with combustion controls such as limiting excess 
O2 or using non-platinum catalyst combustion promoters and 
other NOX-reducing catalyst additives in a complete 
combustion catalyst regenerator or a combination of NOX-
reducing combustion promoters and catalyst additives with low-
NOX burners (LNB) in a CO boiler after a partial combustion 
catalyst regenerator. Data collected from FCCU complying with consent 
decrees show that Option 2 can also be met using combustion controls; 
therefore, we estimated impacts for Option 2 using a similar method as 
Option 1. The main difference is that a larger number of FCCU must use 
combustion controls to meet the emission limit (i.e., the FCCU with 
current NOX emissions between 150 and 80 ppmv would not need 
controls under Option 1 but would need controls under Option 2). Option 
3 is the level at which we expect all units to install more costly 
control technology such as LoTOxTM or SCR. The estimated 
fifth-year emission reductions and costs for each option for new FCCU 
are summarized in Table 5 to this preamble; the impacts for modified 
and reconstructed FCCU are summarized in Table 6 to this preamble.

   Table 5.--National Fifth Year Impacts of Options for NOX Limits Considered for New Fluid Catalytic Cracking
                                   Units Subject to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                   Total annual      Emission       Cost effectiveness ($/ton)
             Option                Capital cost   cost  ($1,000/     reduction   -------------------------------
                                     ($1,000)           yr)        (tons NOX/yr)      Overall       Incremental
----------------------------------------------------------------------------------------------------------------
1...............................             860             320             370             880             880
2...............................           1,200             640             860             750             650
3...............................          12,000           3,600           1,400           2,600           5,800
----------------------------------------------------------------------------------------------------------------


 Table 6.--National Fifth Year Impacts of Options for NOX Limits Considered for Modified and Reconstructed Fluid
                         Catalytic Cracking Units Subject to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                   Total annual      Emission       Cost-effectiveness ($/ton)
             Option                Capital cost   cost  ($1,000/     reduction   -------------------------------
                                     ($1,000)           yr)        (tons NOX/yr)      Overall       Incremental
----------------------------------------------------------------------------------------------------------------
1...............................           2,800           1,000             860           1,200           1,200
2...............................           3,700           1,600           1,800             920             660
3...............................          45,000          11,000           3,200           3,600           6,800
----------------------------------------------------------------------------------------------------------------

    Options 1 and 2 provide cost-effective NOX control with 
limited or no secondary impacts. The costs of Option 1 and Option 2 are 
commensurate with the emission reductions for new FCCU as well as 
modified and reconstructed FCCU. Option 3 would impose compliance costs 
that are not warranted for the emissions reductions that would be 
achieved, as shown by the incremental cost-effectiveness values of 
about $6,000 per ton of NOX emission reduction between 
Option 2 and Option 3.
    In evaluating these options, we also considered the secondary 
impacts. In addition to the direct PM impacts of SNCR and SCR, SCR and 
LoTOx\TM\ units require additional electrical consumption. The 
increased energy consumption for Option 3 is 40,000 MW-hr/yr for new, 
modified, and reconstructed units. We also evaluated the secondary PM, 
SO2, and NOX emission impacts of the additional 
electrical consumption for Option 3. Based on the energy impacts, 
Option 3 will generate secondary emissions of PM, SO2, and 
NOX of 6, 150, and 57 tons/yr, respectively.

[[Page 35848]]

    Based on the impacts shown in Table 5 and Table 6, and taking 
secondary impacts into account, we conclude that BDT is Option 2, a 
NOX emission limit of 80 ppmv, for all affected FCCU. For 
new FCCU, this option achieves NOX emission reductions of 
860 tons/yr from a baseline of 1,500 tons/yr at a cost of $750 per ton 
of NOX. For modified and reconstructed FCCU, this option 
achieves NOX emission reductions of 1,800 tons/yr from a 
baseline of 3,600 tons/yr at a cost of $920 per ton of NOX.

D. PM and SO2 Limits for Fluid Coking Units

    Comment: Several commenters stated that EPA's proposed standards 
for FCU under subpart Ja are inappropriate and not cost-effective. 
Commenters asserted that based on the significant differences between 
FCU and FCCU operations, a separate BDT determination is needed for 
FCCU and FCU. Commenters stated that an FCU has higher particulate 
loading; a heavier feedstock that typically contains a higher 
concentration of sulfur, increasing the SO2 and sulfur 
trioxide (SO3) emissions; and a wider range of feedstocks 
with considerable variability in the nitrogen content.
    The commenters noted that the impacts analysis performed for the 
FCU has shortcomings similar to those in the impacts analysis for FCCU 
(e.g., the analysis did not properly consider the additional costs and 
technical difficulties of meeting the proposed emission limits for 
modified or reconstructed sources, existing units are already 
controlled and thus the emission reductions have already been 
achieved). One commenter provided site-specific engineering cost 
estimates to indicate that the PM controls are much less cost-effective 
than EPA estimates. The commenter requested that EPA consider instances 
when wastewater limitations require regenerative wet scrubbers and 
amend the impact estimates accordingly. One commenter stated that a 
newly installed regenerative wet scrubber system on an existing FCU 
could not meet the proposed Ja PM standards.
    Response: As described in the preamble to the proposed standards, 
the original analysis assumed that one of the larger existing FCU will 
become a modified or reconstructed source in the next 5 years. However, 
the two larger FCU in the U.S. are both subject to consent decrees: one 
has installed controls and the other is in the process of installing 
controls. The remaining two FCU are significantly smaller than the 
original model FCU; therefore, a new analysis was conducted using a 
smaller model FCU indicative of the size of the two remaining FCU that 
are not subject to consent decree requirements. In our new analysis, 
this FCU has approximately one-half the sulfur content as the larger 
FCU for which we have data, based on information received regarding the 
variability in sulfur content across different FCU in the public 
comments.
    In addition to revising our impact analysis, we also collected 
additional source test data from the one FCU operating a newly 
installed wet scrubber system to better characterize the control 
system's performance. At proposal, we had one FCU source test from this 
source, which suggested that the FCU wet scrubber could meet a PM limit 
of 0.5 lb/1,000 coke burn. However, following proposal, we received an 
additional performance test for this same FCU wet scrubber with an 
emission rate between 0.5 and 1.0 lb/1,000 lb coke burn. There was no 
indication of unusual performance during either of these two tests, so 
we conclude that these tests demonstrate the variability of the 
emission source and control system. Based on the available data, 
therefore, we conclude that an appropriate PM performance level to 
consider for a BDT analysis is 1.0 lb/1,000 lb coke burn using EPA 
Method 5B (40 CFR part 60, Appendix A-3) for a FCU with a wet scrubber. 
We also conclude that the PM emission limit initially proposed for FCU 
had not been adequately demonstrated as an emission limit with which 
one must comply at all times.
    Using our revised model FCU and based on the additional source test 
data, we re-evaluated BDT for PM and SO2 emissions from FCU 
based on two options: (1) No new standards, or current subpart J; and 
(2) a PM limit of 1.0 lb/1,000 lb coke burn (as measured using Methods 
5B and 5F of 40 CFR part 60, Appendix A-3), a short-term SO2 
limit of 50 ppmv averaged over 7 days, and a long-term SO2 
limit of 25 ppmv averaged over 365 days. Unlike the FCCU, catalyst 
additives cannot be used in a FCU to reduce SO2, so a wet 
scrubber is the most likely technology (and the one demonstrated 
technology) that would be used to meet the PM and SO2 limits 
of Option 2. Therefore, we estimated costs for an enhanced wet scrubber 
to meet both the PM and SO2 limits. The resulting emission 
reductions and costs for both of the options are shown in Table 7 of 
this preamble.

Table 7.--National Fifth Year Impacts of Options for PM and SO2 Limits Considered for Fluid Coking Units Subject
                                          to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                                                                       Cost
                                   Capital cost    Total annual      Emission        Emission      effectiveness
             Option                  ($1,000)     cost  ($1,000/     reduction       reduction     ($/ton PM and
                                                        yr)        (tons PM/yr)    (tons SO2/yr)       SO2)
----------------------------------------------------------------------------------------------------------------
2...............................          10,000           3,200           1,000           5,900             460
2a..............................         100,000          18,600           1,000           5,900           2,700
----------------------------------------------------------------------------------------------------------------

    One commenter indicated that we should consider the costs of a 
regenerative wet scrubber. This type of system is not needed in most 
applications; however, in the event such a system were needed, we 
estimated the cost of a regenerative wet scrubber to meet Option 2. The 
results of this analysis are also provided in Table 7 as Option 2a. As 
presented in Table 7, even under the most conservative assumptions the 
costs associated with the PM and SO2 emission reductions are 
reasonable.
    Based on the available technology and the costs presented in Table 
7 to this preamble, we conclude that BDT is Option 2, which requires 
technology that reduces PM emissions to 1.0 lb/1,000 of coke burn and 
reduces SO2 emissions to 50 ppmv averaged over 7 days and 25 
ppmv averaged over 365 days. This option achieves PM emission 
reductions of 1,000 tons/yr from a baseline of 1,100 tons/yr and 
SO2 emission reductions of 5,900 tons/yr from a baseline of 
6,100 tons/yr at a cost of $460 per ton of PM and SO2 
combined.

E. NOX Limit for Fluid Coking Units

    Comment: A number of commenters opposed the co-proposal of no 
NOX standard for FCU, and some disagreed with EPA's 80 ppmv 
NOX limit for FCU. These commenters recommended limits

[[Page 35849]]

of 20 ppmv as a 365-day rolling average and 40 ppmv as a 7-day rolling 
average for FCU, as has been successfully achieved under consent 
decrees. The commenters noted that these limits are achievable on new 
units without additional controls.
    One commenter supported the co-proposal that no new NOX 
standard be established for FCU.
    Response: Similar to the revised analysis for PM and SO2 
impacts, we re-evaluated BDT for the FCU NOX controls for a 
smaller modified or reconstructed FCU. We evaluated three options: (1) 
No new standards, which is the current subpart J; (2) outlet 
NOX concentration of 80 ppmv; and (3) outlet NOX 
concentration of 20 ppmv. Similar to the analysis for FCCU 
NOX and depending on the baseline emissions for the FCU, we 
anticipate that Option 2 can be met using combustion controls and 
Option 3 will require add-on control technology. The results of this 
analysis are shown in Table 8 to this preamble.

 Table 8.--National Fifth Year Impacts of Options for NOX Limits Considered for Fluid Coking Units Subject to 40
                                             CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                   Total annual      Emission/      Cost-effectiveness ($/ton)
             Option                Capital cost   cost  ($1,000/     reduction   -------------------------------
                                     ($1,000)           yr)       (tons NOX /yr)      Overall       Incremental
----------------------------------------------------------------------------------------------------------------
2...............................           3,700             850             660           1,300           1,300
3...............................           6,000           1,300             750           1,700           5,000
----------------------------------------------------------------------------------------------------------------

    The costs for Option 1 and Option 2 are commensurate with the 
emission reductions, but the incremental impacts for Option 3 are not 
reasonable, as shown in Table 8. Option 3 achieves an additional 90 
tons per year NOX reduction, but the incremental costs 
between options 2 and 3 of achieving this reduction is $5,000 per ton 
of NOX removed. The cost of achieving this 12 percent 
additional emission reduction nearly triples the total annualized cost 
of operating the controls. As with FCCU, the add-on NOX 
controls for FCU have increased energy requirements and secondary air 
pollution impacts. Based on these projected impacts, we support our 
original determination that BDT is Option 2, or technology needed to 
meet an outlet NOX concentration of 80 ppmv or less. This 
option achieves NOX emission reductions of 660 tons/yr from 
a baseline of 800 tons/yr at a cost of $1,300 per ton of 
NOX.

F. SO2 Limit for Small Sulfur Recovery Plants

    Comment: One commenter stated that no new requirements should be 
added for SRP less than 20 LTD (small SRP) because the controls are not 
cost-effective. The commenter provided data on tail gas treatment 
projects but noted that these costs are for large SRP, and controls for 
small SRP will be less cost-effective. Several commenters noted that if 
EPA does establish standards for small SRP, the monitoring and 
compliance evaluation methods for the 99 percent control standard are 
not clearly specified in the rule and could create difficulties in 
documenting compliance for small Claus plants. Therefore, the small SRP 
should be allowed to comply with the 250 ppmv SO2 emission 
limit provided to large SRP. One commenter suggested that non-Claus 
units should be subject to a 95 percent recovery efficiency standard.
    Response: To ensure that we addressed the commenters' concerns 
regarding cost-effectiveness, we re-evaluated the impacts for small 
SRP. We adjusted our cost estimates upward based on capital costs 
provided by industry representatives. We evaluated three SO2 
control options as part of the BDT determination for small SRP: (1) No 
new standards, or current subpart J; (2) 99 percent sulfur recovery; 
and (3) 99.9 percent sulfur recovery. As noted in the preamble to the 
proposed standards (section V.D), the 99 percent and 99.9 percent 
recovery levels are achievable for SRP of all sizes by various types of 
SRP or tail gas treatments.
    The estimated fifth-year emission reductions and costs for new SRP 
are summarized in Table 9 to this preamble; the impacts for modified 
and reconstructed SRP are summarized in Table 10 to this preamble. 
These values reflect the impacts only for small SRP; there are no 
additional cost impacts for large Claus units because they would 
already have to comply with the existing standards in subpart J.

 Table 9.--National Fifth Year Impacts of Options for SO2 Limits Considered for New Small Sulfur Recovery Plants
                                      Subject to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                   Total annual      Emission       Cost-effectiveness  ($/ton)
             Option                Capital cost   cost  ($1,000/     reduction   -------------------------------
                                     ($1,000)           yr)        (tons SO2/yr)      Overall       Incremental
----------------------------------------------------------------------------------------------------------------
2...............................             130              63              42           1,500           1,500
3...............................             590             230              52           4,500          18,000
----------------------------------------------------------------------------------------------------------------


Table 10.--National Fifth Year Impacts of Options for SO2 Limits Considered for Modified and Reconstructed Small
                          Sulfur Recovery Plants Subject to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                   Total annual      Emission       Cost-effectiveness  ($/ton)
             Option                Capital cost   cost  ($1,000/     reduction   -------------------------------
                                     ($1,000)           yr)        (tons SO2/yr)      Overall       Incremental
----------------------------------------------------------------------------------------------------------------
2...............................           1,600             670             380           1,800           1,800

[[Page 35850]]


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

    The costs for Option 2 are reasonable considering the emission 
reductions achieved, but the incremental impacts shown in Table 9 and 
Table 10 for Option 3 are beyond the costs that the Agency believes are 
reasonable for these small units to achieve an additional 100 tons per 
year of SO2 emission reductions. The additional equipment 
needed to achieve these reductions quadruples the capital costs. These 
smaller units would also generally be found at small refineries. Based 
on these projected impacts and available performance data, we support 
our original determination that BDT is Option 2, or 99 percent sulfur 
recovery. For new SRP, this option achieves SO2 emission 
reductions of 42 tons/yr from a baseline of 150 tons/yr at a cost of 
$1,500 per ton of SO2. For modified and reconstructed SRP, 
this option achieves SO2 emission reductions of 380 tons/yr 
from a baseline of 1,400 tons/yr at a cost of $1,800 per ton of 
SO2.
    We note that we are also revising the format of the standard in 
response to public comments in terms of sulfur outlet concentrations. 
Based on the Option 2 BDT selection of a recovery efficiency of 99 
percent, the emission limit for small SRP is either 2,500 ppmv 
SO2 or 3,000 ppmv reduced sulfur compounds and 100 ppmv of 
H2S, both of which are determined on a dry basis, corrected 
to 0 percent O2.

G. NOX Limit for Process Heaters

    Comment: Several commenters stated that the 80 ppmv NOX 
limit for process heaters is not stringent enough. Commenters stated 
that considering recent settlement negotiations and regulation 
development, NOX emissions reductions well below 80 ppmv can 
be achieved cost effectively. The commenters stated that NOX 
emissions of less than 40 ppmv at 0 percent O2 are 
achievable with combustion modifications such as LNB, ultra low--
NOX burners (ULNB), and flue gas recirculation technologies; 
post-combustion controls such as SCR, SNCR, and LoTOxTM 
achieve NOX reductions an order of magnitude below those 
from combustion modifications. The commenters noted that Bay Area Air 
Quality Management District (BAAQMD) Regulation 9, Rule 10, requires 
process heaters to meet a 0.033 lb/MMBtu NOX limit (roughly 
32 ppmv NOX at 0 percent oxygen). One commenter stated that 
30 ppmv has been demonstrated under consent decrees to be an achievable 
level and ample technology exists. The commenters also noted that 7 to 
10 ppmv NOX limits (at 3 percent oxygen) have been achieved 
in practice. One commenter stated that NSPS subparts J and Ja should 
impose NOX emission limits on all fuel gas combustion 
devices that are at least as stringent as the most stringent consent 
decree. Some consent decrees require next generation ULNB designed to 
achieve NOX emissions rates of 0.012 to 0.020 lb/MMBtu (12 
to 20 ppmv NOX at 0 percent oxygen). Commenters recommending 
more stringent requirements suggested limits ranging from 7 ppmv 
NOX (at 3 percent oxygen) to 30 ppmv for new process heaters 
fueled by refinery fuel gas.
    Other commenters stated that alternative monitoring options should 
be provided to small fuel gas combustion devices due to the high costs 
of CEMS relative to the emissions from the small devices. One commenter 
suggested an exemption from the fuel gas monitoring requirements for 
process heaters less than 50 MMBtu/hr. Another commenter recommended an 
exemption from the fuel gas monitoring requirements for process heaters 
less than 40 MMBtu/hr as used by South Coast Air Quality Management 
District (SCAQMD).
    Response: We revisited the BDT determination based on the public 
comments and revised the methodology used to calculate the cost and 
emission reduction impacts for the proposed standards. We evaluated 
three options as part of the BDT determination. Each option consists of 
a potential NOX emission limit and applicability based on 
process heater size. These differ slightly from the proposal options 
based o n commenter suggestions. Option 1 would limit NOX 
emissions to 80 ppmv or less for all process heaters with a capacity 
greater than 20 MMBtu/hr (the proposed standards). Option 2 would limit 
NOX emissions to 40 ppmv or less for all process heaters 
with a capacity greater than 40 MMBtu/hr. This option is similar to 
many consent decrees that set an emission limit of 0.040 lb/MMBtu 
(roughly 40 ppmv NOX at 0 percent oxygen) for process 
heaters greater than 40 MMBtu/hr. Option 3 would limit NOX 
emissions to 20 ppmv or less for all process heaters with a capacity 
greater than 40 MMBtu/hr. In each option, the NOX 
concentration is based on a 24-hour rolling average.
    The estimated fifth-year emission reductions and costs for each 
option for new process heaters are summarized in Table 11 of this 
preamble; impacts for modified and reconstructed process heaters are 
summarized in Table 12 of this preamble. Similar to the proposal 
analysis, we considered LNB, ULNB, flue gas recirculation, SCR, SNCR, 
and LoTOxTM as feasible technologies. We believe that nearly 
all process heaters at refineries that will become subject to subpart 
Ja can meet Option 1 or Option 2 using combustion controls (LNB or 
ULNB). Most process heaters would need to use more efficient control 
technologies, such as LoTOxTM or SCR, to meet the 
NOX concentration limit in Option 3. Per commenters' request 
to focus on the larger units, Options 2 and 3 do not include process 
heaters between 20 MMBtu/hr and 40 MMBtu/hr. We evaluated the cost-
effectiveness of NOX control options for these units to 
achieve the proposed standard of 80 ppmv. For these process heaters 
with smaller capacities we found the cost-effectiveness ranged from 
$3,500/ton to $4,200/ton of NOX reduced, which was 
determined not to be reasonable for these small heaters, which would 
primarily be located at small refineries.

[[Page 35851]]



 Table 11.--National Fifth Year Impacts of Options for NOX Limits Considered for New Process Heaters Subject to
                                           40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                   Total annual      Emission       Cost-effectiveness  ($/ton)
             Option                Capital cost   cost  ($1,000/     reduction   -------------------------------
                                     ($1,000)           yr)        (tons NOX/yr)      Overall       Incremental
----------------------------------------------------------------------------------------------------------------
1...............................           9,000           7,300           4,800           1,500           1,500
2...............................           9,000           7,500           5,200           1,400             500
3...............................         110,000          30,000           5,900           5,100          37,000
----------------------------------------------------------------------------------------------------------------


   Table 12.--National Fifth Year Impacts of Options for NOX Limits Considered for Modified and Reconstructed
                              Process Heaters Subject to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                   Total annual      Emission       Cost-effectiveness  ($/ton)
             Option                Capital cost   cost  ($1,000/     reduction   -------------------------------
                                     ($1,000)           yr)        (tons NOX/yr)      Overall       Incremental
----------------------------------------------------------------------------------------------------------------
1...............................          12,000           4,000           2,100           1,900           1,900
2...............................          14,000           4,300           2,200           1,900           2,100
3...............................          64,000          15,000           2,500           5,900          39,000
----------------------------------------------------------------------------------------------------------------

    Based on the impacts in Table 11 and Table 12, the costs of Options 
1 and 2 are reasonable compared to the emission reductions. The 
incremental cost between Options 2 and 3 of almost $40,000/ton of 
NOX is not commensurate with the additional 1,000 tons of 
emission reduction achieved for new and modified or reconstructed 
process heaters. Moreover, the capital costs of Option 3 are about $150 
million greater than the capital costs for Option 2, which are only $23 
million. Therefore, we conclude that BDT for process heaters greater 
than 40 MMBtu/hr is technology that achieves an outlet NOX 
concentration of 40 ppmv or less, or Option 2. For new process heaters, 
this option achieves NOX emission reductions of 5,200 tons/
yr from a baseline of 7,500 tons/yr at a cost of $1,400 per ton of 
NOX. For modified and reconstructed process heaters, this 
option achieves NOX emission reductions of 2,200 tons/yr 
from a baseline of 3,200 tons/yr at a cost of $1,900 per ton of 
NOX. Although we agree that lower NOX 
concentrations are achievable, we determined that the incremental cost 
to achieve these lower NOX concentrations was not 
reasonable.

H. Fuel Gas Combustion Devices

    Comment: Several commenters contended that the proposed standards 
for fuel gas combustion devices were not stringent enough; EPA should 
ensure that the best demonstrated emission control technologies are 
installed as the industry is modernized. Given the significant hazards 
to human health and the environment posed by SO2 emissions, 
the commenters suggested that the 365-day average limits should be 40 
ppmv TRS and 5 ppmv SO2. The commenters also recommended 
that EPA tighten the 3-hour concentration limit to 100 ppmv TRS. On the 
other hand, another commenter contended that although amine treatment 
applications for product gases can achieve H2S 
concentrations of 1 to 5 ppmv, a tighter standard is not BDT for 
refinery fuel gas.
    Several commenters objected to the addition of the 60 ppmv 
H2S and 8 ppmv SO2 limits (365-day rolling 
average) in the proposed subpart Ja standards for fuel gas combustion 
devices because they are infeasible and/or not cost-effective. 
According to commenters, EPA erroneously assumed that the additional 
reductions could be achieved with existing equipment. Although this may 
be true in some cases, commenters asserted that some refineries would 
need to add additional amine adsorber/regenerator capacity and some may 
also need to add additional sulfur recovery capacity (e.g., an 
additional Claus train and tail gas treatment unit). One commenter 
requested an exemption be provided for refineries that cannot meet the 
tighter long-term standard by simply increasing their amine circulation 
rates. One commenter stated that there will be little incremental 
environmental benefit from the long-term limit, and it unnecessarily 
penalizes refineries that designed their amine systems to treat to 
levels near the proposed annual standard. The commenters provided cost 
data for examples of projects requiring new amine adsorption units to 
show that the proposed standards are not cost-effective.
    A number of commenters particularly opposed the proposed revision 
to include TRS limits for fuel gas produced from coking units or any 
fuel gas mixed with fuel gas produced from coking units. One commenter 
noted that some State and local agencies have specific TRS standards, 
but these requirements were not based on a BDT assessment. According to 
commenters, EPA has included no technical basis for the achievability 
of the TRS fuel gas standard or explanation of why control of TRS is 
limited to fuel gas generated by coking units. The commenters 
recommended that EPA postpone adoption of a TRS limit until it has 
gathered and evaluated adequate data to conclude that the limit is 
technically feasible and cost effective.
    Commenters stated that EPA did not address the cost-effectiveness 
and non-air quality impacts of the TRS standards and did not define BDT 
for the removal of TRS. One commenter stated that without an 
established de minimis level, an entire fuel gas system could be 
subject to the TRS limits if any amount of coker gas enters the fuel 
gas system. Amine scrubbing systems are selective to H2S and 
are not suitable to other TRS compounds such as mercaptans, according 
to the commenters. Commenters stated that the non-H2S TRS 
compounds are not amenable to amine treating and there is no technology 
readily in-place at refineries for reducing non-H2S TRS 
compounds. Therefore, according to the commenters, removing these other 
TRS compounds would require significant capital outlay for new 
equipment, costs that were not considered in the impacts analysis.

[[Page 35852]]

    One commenter provided an example of a treatment system installed 
to meet a facility-wide fuel gas total sulfur standard of 40 ppmv; the 
commenter estimated the capital cost of the entire system to be $150 
million. The commenter also indicated that low-BTU gas from flexicoking 
units would need to be specially treated at a capital cost of $61 
million to achieve a total sulfur content of less than 150 ppmv, and 
the treatment would increase energy consumption, resulting in increases 
in NOX and CO emissions. Another commenter provided an 
order-of-magnitude engineering estimate of $50 million to treat TRS 
down to 45 ppmv (long-term average). Based on one commenter's 
experience with a new fuel gas treating facility, non-acidic TRS cannot 
be treated down to the proposed levels utilizing Merox-amine treatment. 
A cost-effective solution could be natural gas blending at the affected 
combustion device; however, this option has the negative effect of 
reducing the production of refinery fuel gas and therefore reducing the 
refinery's capacity for making gasoline.
    Several commenters stated that the original BDT determination was 
based on amine scrubbing of H2S and not on SO2; 
the SO2 standard was simply a compliance option that was 
calculated to be equivalent to the H2S concentration limit 
at 0 percent excess air. They also asserted that EPA cannot use the 
SO2 option as a basis for the TRS standard because the 
SO2 option is not BDT. On the other hand, one commenter 
requested that EPA clarify the fuel gas standards in subpart J to 
expressly indicate that the 20 ppmv SO2 limit is a valid 
compliance option (instead of including it only in the monitoring 
section). According to the commenter, focus has been on H2S 
due to the structure of the requirements of subpart J and permits 
rarely require that combustion sources demonstrate compliance with the 
20 ppmv SO2 limit. The commenter stated that refiners 
clearly should be allowed to comply with the broader, more 
comprehensive SO2 limit.
    A few commenters noted that, as H2S is part of TRS, the 
TRS standard is even more stringent than the H2S standard. 
One commenter recommended that no change in the fuel gas standards be 
made or that the standards focus on H2S only with an 
alternative emission limit for SO2. One commenter stated 
that EPA developed the 160 ppmv H2S standard to be more 
stringent than the 20 ppmv SO2 standard specifically because 
H2S did not represent all of the sulfur in the fuel gas. 
Commenters stated that using an F-factor approach (Method 19, 40 CFR 
part 60, Appendix A-7), the TRS limit that is equivalent to the 20 ppmv 
SO2 emission limit is 260 ppmv and the TRS limit that is 
equivalent to the 8 ppmv SO2 emission limit is 104 ppmv.
    Response: We initially concluded that fuel gas generated by the 
coking unit was mixed with other fuel gases that were mostly 
H2S and that increasing the amine circulation rate would 
result in additional H2S removal that could be used to meet 
the proposed standard. However, based on a review of the available 
data, non-H2S sulfur content in coker fuel gas may be 300 to 
500 ppmv. At these levels, specific treatment to reduce these other 
sulfur compounds would be needed. As indicated by one commenter, a 
plant-wide total sulfur limit of 40 ppmv has been achieved in practice 
in at least one refinery using a treatment train consisting of a Merox 
system, sponge oil absorbers, MEA absorbers, and caustic wash towers. 
Therefore, total sulfur fuel gas treatment methods are demonstrated. We 
evaluated the cost of this treatment based on information provided in 
the public comments.
    Based on the public comments and additional data, we revisited the 
BDT determination and assessed three options for increasing 
SO2 control of fuel gas combustion devices: (1) 20 ppmv 
SO2 or 162 ppmv H2S averaged over 3 hours; (2) 
Option 1 plus 8 ppmv SO2 or 60 ppmv H2S averaged 
over 365 days; and (3) a compliance option of 162 ppmv TRS averaged 
over 3 hours and 60 ppmv TRS averaged over 365 days for fuel gas 
combustion devices combusting fuel gas generated by a coking unit and 
Option 2 for combustion devices combusting fuel gas not generated by a 
coking unit. Option 1 includes the same limits that are in subpart J, 
so there are no additional costs or emission reductions beyond those 
expected from the application of subpart J. To address the commenters' 
concerns that not all facilities have available amine capacity to 
ensure compliance with the new long-term limits, we revised our 
proposal analysis to include additional costs for the estimated 10 
percent of the affected facilities that would increase their amine 
capacity to achieve Option 2. We estimated costs for a separate 
treatment train that can treat TRS for Option 3 because, based on the 
public comments received, we have concluded that amine treatment 
systems are not effective for non-H2S components of TRS. The 
estimated fifth-year impacts of each of these options for new fuel gas 
combustion devices are presented in Table 13 of this preamble; the 
impacts for modified and reconstructed fuel gas combustion devices are 
presented in Table 14 of this preamble.

 Table 13.--National Fifth Year Impacts of Options for SO2 Limits Considered for New Fuel Gas Combustion Devices
                                      Subject to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                   Total annual      Emission       Cost-effectiveness  ($/ton)
             Option                Capital cost   cost  ($1,000/     reduction   -------------------------------
                                     ($1,000)           yr)        (tons SO2/yr)      Overall       Incremental
----------------------------------------------------------------------------------------------------------------
2...............................           1,200             720             510           1,400           1,400
3...............................         100,000          13,000             770          17,000          47,000
----------------------------------------------------------------------------------------------------------------


 Table 14.--National Fifth Year Impacts of Options for SO2 Limits Considered for Modified and Reconstructed Fuel
                          Gas Combustion Devices Subject to 40 CFR Part 60, Subpart Ja
----------------------------------------------------------------------------------------------------------------
                                                   Total annual      Emission       Cost-effectiveness  ($/ton)
             Option                Capital cost   cost  ($1,000/     reduction   -------------------------------
                                     ($1,000)           yr)        (tons SO2/yr)      Overall       Incremental
----------------------------------------------------------------------------------------------------------------
2...............................          33,000          11,000           4,700           2,400           2,400
3...............................       1,700,000         200,000           7,600          26,000          63,000
----------------------------------------------------------------------------------------------------------------


[[Page 35853]]

    Overall costs for Options 1 and 2 are reasonable compared to the 
emission reduction achieved for new, modified and reconstructed fuel 
gas combustion devices. We further evaluated the incremental costs and 
reductions between the three options and found that they were 
reasonable for Options 1 and 2, while the incremental cost for Option 3 
is not. While Option 3 provides significant additional SO2 
emission reductions, the additional capital cost of $1.7 billion is 
high and could pose a significant barrier to future refinery upgrades 
and expansions. Based on these impacts and consideration of current 
operating practices, we conclude that BDT is use of technology that 
reduces the emissions from affected fuel gas combustion devices to 20 
ppmv SO2 or 162 ppmv H2S averaged over 3 hours 
and 8 ppmv SO2 or 60 ppmv H2S averaged over 365 
days, or Option 2. For new fuel gas combustion devices, this option 
achieves SO2 emission reductions of 510 tons/yr from a 
baseline of 1,000 tons/yr at a cost of $1,400 per ton of 
SO2. For modified and reconstructed fuel gas combustion 
devices, this option achieves SO2 emission reductions of 
4,700 tons/yr from a baseline of 10,000 tons/yr at a cost of $2,400 per 
ton of SO2.
    We note that although we have determined that Option 3 is not BDT 
and we will not limit the amount of SO2 emissions from 
combustion of sulfur compounds other than H2S in subpart Ja, 
we plan to continue to work with the industry to understand the 
magnitude of these SO2 emissions and to identify 
technologies that can be cost effectively applied to reduce the 
emissions. We have learned through this process that the SO2 
emissions from combustion of TRS in coker gas are generally not 
reflected in emission inventories and we plan to explore this issue in 
greater detail in the future to determine where SO2 
emissions are underestimated and the best way to correct the 
inventories.
    Comment: Several commenters stated that it is impossible for a 
refinery owner or operator to specify, acquire, install, and calibrate 
a continuous monitoring system within 15 days of a change that 
increases the H2S concentration such that an exempt stream 
is no longer exempt. One commenter suggested quarterly stain tube 
sampling for 1 year prior to revoking an exemption from monitoring to 
confirm the change is permanent. The commenter suggested that after 1 
year of confirmation, an additional 12 months be provided to specify, 
acquire, install, and calibrate the continuous monitoring system. One 
commenter suggested 1 year be provided for installing a CEMS, while 
another commenter suggested 180 days be provided (with an allowance for 
an additional extension) for installing a CEMS, rather than the 15 days 
proposed.
    Response: We believe that in most cases, the process change would 
be a deliberate, planned act and that the potential consequences of 
this deliberate change would be evaluated. That is, before the 
equipment is modified, the refinery owner or operator is expected to 
assess the impacts of this change on the exempted fuel gas stream. If 
the change is expected to increase the sulfur content of the fuel gas, 
than the owner or operator can plan to install the required CEMS when 
modifying the process. We recognize that some process changes may have 
unexpected consequences, and a modification that was not expected to 
increase the sulfur content of the fuel gas can result in an increase 
in sulfur content. In this case, it may be impossible to install the 
required CEMS within 15 days. However, quarterly sampling does not 
provide any basis by which the refinery owner or operator can 
demonstrate compliance with the H2S concentration standard. 
Instead, we have added provisions that require an owner or operator to 
install a CEMS as soon as practicable and no later than 180 days after 
a change that makes the stream no longer exempt. Between the process 
change and the time a CEMS is installed, the owner or operator must 
conduct daily stain tube sampling to demonstrate compliance with the 
H2S concentration standard. During this time, a single daily 
sample exceeding 162 ppmv must be reported as an exceedance of the 3-
hour H2S concentration limit and a rolling 365-day average 
concentration must be determined. A daily average H2S 
concentration of 5 ppmv is to be used for the days prior to the process 
change for the previously exempt stream in calculating the rolling 365-
day average concentration.

I. Flaring of Refinery Fuel Gas

    Comment: Several commenters supported the proposed work practice 
standards to eliminate routine flaring and develop startup, shutdown, 
and malfunction (SSM) plans; the commenters opposed the co-proposal of 
no standards. One commenter supported the determination that 
elimination of routine flaring is BDT, citing reductions in 
hydrocarbon, NOX, SO2, and carbon dioxide 
(CO2) emissions. One commenter stated that both subparts J 
and Ja should explicitly require that flaring be used only as a last 
resort in unusual circumstances, such as emergencies, and not on a 
routine basis. Commenters asserted that monitoring on an ongoing basis 
is needed to verify that no flaring of nonexempt gases occurs. 
Commenters stated that subpart Ja should also require refiners to 
install a flare gas recovery system, although such requirements should 
not preclude monitoring requirements. One commenter stated that the 
NSPS should require a SSM plan to eliminate venting or flaring during 
such planned start-up, shutdown, and maintenance activities and 
explicitly prohibit venting or flaring during these planned activities; 
proper operation and maintenance practices should completely eliminate 
the need to use flares during these activities. One commenter noted 
that those refineries that have evaluated their startup and shutdown 
procedures to reduce or eliminate direct venting or flaring during 
planned startup and shutdown events have demonstrated the best 
technology; therefore, their actions represent BDT and should be 
adopted in the NSPS. The commenters also supported conducting a root 
cause analysis (RCA) in the event of flaring and other venting releases 
of 500 lb/day SO2.
    A number of commenters generally supported the intent to reduce 
flaring and the idea of SSM plans to address flaring during planned 
startups and shutdowns (one commenter also included combustion of high 
sulfur-containing fuel gases during a malfunction), flare management 
plans, and RCA for flare events in excess of 500 lb/day. However, they 
opposed the work practice standard for elimination of routine flaring 
and the proposed creation of fuel gas producing units for subpart Ja. 
The commenters stated that the definition of ``fuel gas producing 
unit'' is overly broad, making it difficult to determine what 
constitutes a modification or reconstruction, and the proposed work 
practice standard for these units is infeasible, unnecessary, and not 
cost-effective. Facility operators and regulators would have difficulty 
discerning if a flaring event was caused by an affected fuel gas 
producing unit or a unit not subject to the standard. One commenter 
indicated that there is no de minimis level by which units that produce 
insignificant quantities of fuel gas can be excluded from the extensive 
work practice standards.
    Commenters recommended that the affected source be the flare which 
is already subject to the standard as a fuel gas combustion device. The 
commenters suggested that for each affected flare, the facility would 
develop a written Flare Management Plan designed to minimize

[[Page 35854]]

flaring of fuel gas during all periods of operation. This plan, along 
with the RCA, would ensure that all flaring events with potential 
excess emissions will be minimized. One commenter noted that EPA could 
require a flare management plan for any flare tied to a fuel gas system 
that has an affected fuel gas combustion device as a better alternative 
to ``fuel gas producing units.'' One commenter noted that an exemption 
from the notification requirements for modified or reconstructed units 
could be provided as an incentive for early adoption of the flare 
management plan; another commenter suggested that regulatory incentives 
such as exemptions from monitoring and developing flare management 
plans should be provided for facilities that have installed flare gas 
recovery systems. One commenter supported this type of requirement for 
flares currently subject to subpart J, assuming a minimum of 9 months 
is provided for plan development and implementation. On the other hand, 
one commenter noted that the definitions of the affected facility under 
subparts J and Ja are different and recommended that the distinction be 
made stronger so that it is clear that existing process unit facilities 
are ``grandfathered'' and exempt from the flaring minimization 
standards.
    One commenter suggested that the work practices language should be 
clarified to indicate that routing offgas to the flare system would be 
acceptable if the system was equipped with a flare gas recovery system. 
The prohibition should be specific to the flare itself as some flare 
systems are equipped with recovery compressors, the use of which should 
be encouraged rather than discouraged.
    Commenters stressed the need for flares as safety devices; any 
flare minimization program must not interfere with the ability of the 
refinery owner or operator to use flares for safety reasons. The 
commenters stated that ``routine'' flaring cannot be adequately defined 
in practice; therefore, restrictions on ``routine'' flaring will lead 
to unsafe operations in attempts to avoid enforcement actions. The 
commenters requested that EPA include language in the regulation, 
consistent with the preamble discussion, that: ``Nothing in this rule 
should be construed to compromise refinery operations and practices 
with regard to safety.''
    One commenter indicated that the proposed work practice standards 
for ``no routine flaring'' interfere with flare minimization plans 
implemented in response to consent decrees. The proposed work practice 
standard could be interpreted as prohibiting flaring during start-up 
and shutdown, and EPA has not determined this to be BDT. The commenter 
stated that the BAAQMD analysis applies to eliminating flaring during 
normal operation [similar to proposed Sec.  60.103a(b)], not during 
start-up and shutdown as in proposed Sec.  60.103a(a). The commenter 
provided cost estimates for one refinery to install a recovery system 
to eliminate flaring during start-up and shutdowns; the costs ranged 
from $200,000 to $800,000 per ton of VOC reduced and higher for other 
criteria pollutants. Therefore, they contend Sec.  60.103a(a) should 
clearly exclude start-up and shutdown gases.
    A few commenters provided overall project costs for flare gas 
recovery projects indicating the annual costs are higher than those in 
the analysis supporting the proposed work practice. One commenter 
stated that EPA underestimated the cost of flare gas recovery systems 
and, given the uncertainty in emission reductions, contended that flare 
gas recovery systems for the no-flaring option are not cost-effective 
within the NSPS context. The commenter also stated that the regulation 
should include maintenance provisions for flare gas recovery systems 
(that allow flaring) during times of routine and non-routine 
maintenance, as no redundant capacity within the flare system exists.
    A number of commenters provided an alternative to EPA's proposed 
work practice standards. The suggestions included a 500 lb/day 
SO2 standard tied with a flare management plan as an 
alternative compliance option (to the H2S concentration 
limit) for flares. The commenters recommended that this alternative 
compliance option be provided in both subparts J and Ja and noted that 
it could be used as an incentive for the flare management plan to cover 
all flares. One commenter also noted that these requirements should be 
applicable to flares that receive process gas, fuel gas, or process 
upset gas; they should not be applicable to flares used solely as an 
air pollution control device, such as a flare used exclusively to 
control emissions from a gasoline loading rack. Another commenter 
clarified that if the refinery elects to comply with this alternative 
for any flare, all flares at the refinery would need a flare management 
plan. The commenter noted that EPA could choose to set the 500 lb/day 
SO2 limit as a total for all flares for which the 
alternative compliance option is chosen (i.e., if the alternative 
compliance option is selected for two flares at a refinery, the total 
emissions from both flares would be limited to 500 lb/day).
    Response: Although commenters suggested that certain provisions be 
made applicable to facilities subject to subpart J, the following 
provisions are only applicable to facilities subject to subpart Ja as 
CAA section 111 provides that new requirements apply only to new 
sources. We considered these comments and agree that the standards are 
more straightforward when the affected facility is defined as the 
flare. Therefore, we have eliminated ``fuel gas producing units'' as an 
affected facility in this final rule, and we specifically define a 
flare as a subset of fuel gas combustion device, which is an affected 
facility in this final rule. A ``flare'' means ``an open-flame fuel gas 
combustion device used for burning off unwanted gas or flammable gas 
and liquids. The flare includes the foundation, flare tip, structural 
support, burner, igniter, flare controls including air injection or 
steam injection systems, flame arrestors, knockout pots, piping and 
header systems.''
    There are three general work practice standards that were proposed 
for ``fuel gas producing units,'' which may be summarized as follows: 
(1) The ``no routine flaring'' requirement; (2) flare minimization plan 
for start-up, shutdown, and malfunction events; and (3) a root-cause 
analysis for SO2 releases exceeding 500 lb/day (which was 
proposed for all affected fuel gas producing units). The ``no routine 
flaring'' work practice was not intended to prohibit flaring during SSM 
events; the provisions were intended to apply only during normal 
operating conditions. We agree with the commenter that suggested that 
nothing in this rule should be construed to compromise refinery 
operations and practices with regard to safety. Additionally, as 
discussed in the preamble to the proposed rule, we specifically 
rejected a prohibition on flaring for planned start-up and shutdown 
events. We agree with the commenters that noted that numerous 
refineries have demonstrated that flare minimization during planned 
start-up and shutdown activities can greatly reduce flaring during 
these events. We do believe, however, that a complete elimination of 
flaring during these events is very site-specific and although it is 
reported to have been achieved at a limited number of refineries, we do 
not have information to suggest that it has been adequately 
demonstrated for universal application. As ``no routine flaring'' is 
difficult to define in practice, we have re-evaluated BDT using more 
specific options.

[[Page 35855]]

    Option 1 is no additional standards for flares. In Option 2, any 
routine emissions event or any process start-up, shutdown, upset or 
malfunction that causes a discharge into the atmosphere more than 500 
pounds per day of SO2 (in excess of the allowable emission 
limit) from an affected fuel gas combustion device or sulfur recovery 
plant would require a root cause analysis to be performed. This 
approach is similar to what is included in most consent decrees. We are 
also including a requirement for continuous monitoring of TRS for all 
gases flared (including those from upsets, startups, shutdowns, and 
malfunction events), in order to accurately measure SO2 
emissions from affected flares.
    Option 3 includes: (1) The SO2 root cause analysis in 
Option 2; (2) a limit on the fuel gas flow rate to the flare of 250,000 
scfd; and (3) a flare management plan for SSM events. The flow limit of 
250,000 scfd is based on our cost analysis that indicates that for 
typical gas streams in quantities above this limit, the value of 
recovered fuel completely offsets the costs of installing and operating 
recovery systems. Many refineries have implemented flare gas recovery 
to reduce energy needs and save money. The flare management plan must: 
(1) Include a diagram illustrating all connections to each affected 
flare; (2) identify the flow rate monitoring device and a detailed 
description of manufacturer's specifications regarding quality 
assurance procedures; (3) include standard operating procedures for 
planned start-ups and shutdowns of refinery process units that vent to 
the flare (such as staging of process shutdowns) to minimize flaring 
during these events; (4) include procedures for a root cause analysis 
of any process upset or equipment malfunction that causes a discharge 
to the flare in excess of 500,000 scfd; and (5) include an evaluation 
of potential causes of fuel gas imbalances (i.e., excess fuel gas), 
upsets or malfunctions and procedures to minimize their occurrence and 
records to be maintained to document periods of excess fuel gas. Excess 
emission events for the flow rate limit of 250,000 scfd and the result 
of root cause analysis must be reported in the semi-annual compliance 
reports.
    Option 4 is identical to Option 3 except that flaring is limited to 
50,000 scfd. This level is estimated to be a baseline level that 
accounts for the flow requirement needed to maintain safe operations of 
the flare (i.e., flow of sweep gas and compressor cycle gas). For both 
Option 3 and Option 4, the limit on the flow rate does not apply during 
malfunctions and unplanned startups and shutdowns. The flow rate limits 
in Options 3 and 4 were developed to reduce VOC, SO2, and 
NOX emissions; the limits are based on 30-day rolling 
average flow rate values.
    It is anticipated that a flare gas recovery system will be used to 
comply with Options 3 and 4 when a flare is currently used on a 
continuous basis, and the recovered flare gas offsets natural gas 
purchases. The cost-effectiveness of the flare gas recovery system is 
primarily dependent on the quantity of gas that the system can recover. 
Many refineries have already implemented similar work practices through 
consent decrees and local rules (BAAQMD and SCAQMD), and these 
requirements have had a demonstrated reduction in flaring events. Flare 
gas recovery will reduce SO2, NOX, and VOC 
emissions. However, if a refinery produces more fuel gas than the 
refinery needs to power its equipment, there is no place the refinery 
can use the recovered fuel gas and there is no additional natural gas 
purchases to offset. In these cases, flare gas recovery is not 
considered technically feasible because the excess fuel gas will have 
to be flared. Therefore, we have included specific provision within the 
flare management plan to address instances of excess fuel gas. For 
periods when the refinery owner or operator can demonstrate, through 
records of natural gas purchases or other means as described in their 
flare management plan, that the refinery is fuel gas rich, compliance 
with the flow limit is demonstrated by implementing the procedures 
described in the flare management plan.
    Impacts for each of the four options are based on estimates of 
current flaring quantities and include the root cause analysis, flare 
management plan, and flare gas recovery systems when needed. The 
impacts for each option for new flares are presented in Table 15 to 
this preamble; impacts for modified and reconstructed flares are 
presented in Table 16 to this preamble.

      Table 15.--National Fifth Year Impacts of Options for Work Practices Considered for New Flaring Devices Subject to 40 CFR Part 60, Subpart Ja
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           Total annual      Emission        Emission        Emission       Cost-effectiveness ($/ton)
                 Option                    Capital cost   cost  ($1,000/     reduction       reduction       reduction   -------------------------------
                                             ($1,000)           yr)        (tons SO2/yr)   (tons NOX/yr)   (tons VOC/yr)      Overall       Incremental
--------------------------------------------------------------------------------------------------------------------------------------------------------
2.......................................               0              23              15               0               0           1,600           1,600
3.......................................           8,800         (1,300)              16               1              41        (23,000)        (31,000)
4.......................................          15,000           (840)              16               1              52        (12,000)          43,000
--------------------------------------------------------------------------------------------------------------------------------------------------------


  Table 16.--National Fifth Year Impacts of Options for Work Practices Considered for Modified and Reconstructed Flaring Devices Subject to 40 CFR Part
                                                                     60, Subpart Ja
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           Total annual      Emission        Emission        Emission       Cost-effectiveness ($/ton)
                 Option                    Capital cost   cost  ($1,000/     reduction       reduction       reduction   -------------------------------
                                             ($1,000)           yr)        (tons SO2/yr)   (tons NOX/yr)   (tons VOC/yr)      Overall       Incremental
--------------------------------------------------------------------------------------------------------------------------------------------------------
2.......................................               0              92              59               0               0           1,600           1,600
3.......................................          35,000         (5,300)              64               4             165        (23,000)        (31,000)
4.......................................          59,000         (3,300)              66               6             207        (12,000)          43,000
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on these impacts and consideration of technically feasible 
operating practices, we conclude that BDT is Option 3. Option 3 
includes a set of work practice standards that requires root cause 
analysis for a discharge into the atmosphere in excess of 500 pounds 
per day of SO2 (over the allowable emission limit) from a 
fuel gas combustion device or sulfur recovery plant or in excess of 
500,000 scfd flow to a flare. It also includes a flare

[[Page 35856]]

management plan. Finally, fuel gas flow to the flare is limited to 
250,000 scfd. To support implementation of these requirements, 
monitoring and reporting of the flow rate and sulfur content is 
required. For new flaring devices, this option achieves SO2 
emission reductions of 16 tons/yr from a baseline of 32 tons/yr, 
NOX emission reductions of 1 tons/yr from a baseline of 2 
tons/yr, and VOC emission reductions of 41 tons/yr from a baseline of 
67 tons/yr with a net fuel savings of $23,000 per ton of combined 
SO2, NOX, and VOC. For modified and reconstructed 
flaring devices, this option achieves SO2 emission 
reductions of 64 tons/yr from a baseline of 129 tons/yr, NOX 
emission reductions of 4 tons/yr from a baseline of 7 tons/yr, and VOC 
emission reductions of 165 tons/yr from a baseline of 266 tons/yr with 
a net fuel savings of $23,000 per ton of combined SO2, 
NOX, and VOC.
    The flare gas minimization requirements included in the final 
standards are important to reduce criteria pollutant emissions and 
conserve energy. However, we recognize that owners and operators also 
need to be able to make quick changes to existing process units or 
flare systems to avoid unsafe conditions. It could take an owner or 
operator more time to implement the flare requirements, especially flow 
monitoring and any physical changes needed to comply with the limit on 
flow to the flare, than it took to implement the change to the flare 
that caused it to be an affected facility. There is the potential for 
serious safety concerns if the owner or operator must wait until 
compliance has been achieved with all of the flare gas minimization 
requirements prior to venting explosive vapors to the flare or 
modifying the flare system, such as adding a knockout pot for safety 
reasons. Moreover, avoiding unsafe conditions by requiring immediate 
shutdown of all process units connected to the potentially affected 
flare while the owner or operator takes steps to comply with the final 
provisions specific to flare gas minimization results in additional 
emissions, significant costs, and large lost production of refined 
products. By providing 1 year for modified flares to comply with these 
flare gas minimization provisions, refinery owners and operators have 
sufficient time to coordinate the installation of the flow rate and 
sulfur content monitors, to take whatever steps necessary to meet the 
flow limitations, to develop and implement the flare management plan, 
and to make other modifications, if needed, regarding safety and 
maintenance considerations for other process equipment tied to the 
flare.
    Considering the cost and the energy penalty from the reduction in 
refined products (e.g., the need to shut down the refinery until the 
flare gas minimization requirements can be met) and emissions 
associated with the immediate application of these requirements of the 
rule to modified flares, we determined that BDT was to phase in the 
requirements. The owner or operator of a modified flare would have to 
comply with the applicable H2S limit immediately and would have 1 year 
to implement the flare gas minimization requirements. Therefore, the 
final standards specify that for modified flares, the H2S limits for 
fuel gas combustion units apply immediately and the flare gas 
minimization requirements apply no later than 1 year after the flare 
becomes an affected facility. For newly constructed and reconstructed 
flares, the H2S limits and all of the flare gas minimization 
requirements apply immediately upon start-up of the affected flare.
    Comment: Several commenters requested clarification of how one 
would assess a flare ``modification.'' Questions included: (1) How the 
emission basis of a flare should be calculated; (2) if the modification 
determination would be based on flare capacity or increase in discharge 
capability of units connected to the flare; (3) whether the 
modification determination would include all possible flaring events or 
just non-emergency flaring; (4) whether adding a new line to a flare is 
considered to increase the capacity of the flare and cause a 
modification; (5) whether flare tip replacements are considered routine 
maintenance instead of a modification of the flare, even if the new 
flare tip has a different geometry (e.g., a larger diameter to reduce 
noise); and (6) how SSM streams are considered when calculating 
baseline emissions for a modification determination. The commenters 
also suggested that EPA should clarify whether and how the exemption in 
Sec.  60.14(e)(2) applies to a flare, including how the production rate 
for a flare would be defined.
    Response: Section 60.14(a) defines modification as follows: 
``Except as provided in paragraphs (e) and (f) of this section, any 
physical or operational change to an existing facility which results in 
an increase in the emission rate to the atmosphere of any pollutant to 
which a standard applies shall be considered a modification.'' Section 
60.14(e) provides exclusions for maintenance activities, increased 
production rates, increased hours of operation, etc. However, except 
for the maintenance exclusion, the other exemptions are either not 
applicable or ambiguous when applied to a flare. More importantly, 
Sec.  60.14(f) states that ``Applicable provisions set forth under an 
applicable subpart of this part shall supersede any conflicting 
provisions of this section.'' Therefore, to eliminate ambiguity, we 
specifically define what constitutes a flare modification in subpart 
Ja.
    A flare is considered to be modified in one of two ways. First, a 
flare is considered to be modified when any piping from a refinery 
process unit or fuel gas system is newly connected to the flare. This 
new piping could allow additional gas to be sent to the flare, 
consequently increasing emissions from the flare. Second, a flare is 
considered to be modified if that flare is physically altered to 
increase flow capacity.
    While in most cases an affected facility must comply with the final 
standard if it commences construction, reconstruction or modification 
after the proposal date, section 111(a)(2) of the CAA also provides 
that in certain circumstances such a source only need comply with the 
standard if it commences construction after the final date. Given the 
number of changes between proposal and final, we have concluded that 
this is one of the rare cases in which the final, rather than proposal, 
date applies.
    In this case, we are promulgating a newly defined affected 
facility, adding a new provision specifically defining what constitutes 
a modification of a flare, adding several new requirements, and adding 
a definition of a flare. All of these changes significantly alter what 
would be an affected facility and the obligations of the affected 
facility for purposes of reducing flaring. Furthermore, while some of 
the requirements that were proposed for the fuel gas producing unit 
were transferred to the flare as an affected source, the scope of these 
requirements changed significantly when they were applied to a flare 
rather than a fuel gas producing unit. Specifically, under the 
proposal, only the gas stream from the modified fuel gas producing unit 
was barred from routine flaring. Under the final rule, however all of 
the units connected to the flare are now addressed, not just the fuel 
gas producing unit that was new, modified, or reconstructed.
    Accordingly, we are providing in the final standards that only 
those flares commencing construction, reconstruction, or modification 
after June 24, 2008 must meet the requirements in subpart Ja. Flares

[[Page 35857]]

commencing construction, reconstruction, or modification after June 11, 
1973, and on or before June 24, 2008 must meet the requirements in 
subpart J regarding fuel gas combustion devices (i.e., the 
H2S fuel gas limit).

J. Delayed Coking Units

    Comment: Several commenters supported the proposal that requires 
delayed coking units to depressure the coke drums to the fuel gas 
system down to 5 psig. One commenter supported venting the delayed 
coker gas to a flare or to the atmosphere at pressures less than 5 
psig; at pressures greater than 5 psig, the commenter suggested that 
the rule should only prohibit gases from being sent to a flare and 
allow any other disposition. That is, the commenter stated that EPA 
should not restrict the disposition of the coker depressurization gas 
to only the fuel gas system.
    One commenter supported inclusion of a coke drum pressure limit 
above which the coke drum exhaust gases must be sent to a recovery 
system, disagreed that it is technically infeasible to divert emissions 
for recovery at pressures below 5 psig, and urged EPA to require 
venting until the pressure drops below 2 psig. The commenter recently 
issued a permit including the 2 psig level, and although the 
modification has not been completed, the commenter believes the 
requirement is technically feasible.
    A number of commenters objected to the finding that BDT is to 
depressure delayed coking units to the fuel gas system down to 5 psig. 
Commenters provided examples of coking units whose current mode of 
operations (e.g., set points or timed cycles) may divert to a flare or 
to the atmosphere at pressures of approximately 10 to 20 psig and that 
it would not be cost-effective to modify these units to comply with the 
proposed work practice standard. One commenter supported the premise 
that it is cost-effective for delayed coking discharge to be routed to 
fuel gas blowdown, but depressurization down to 5 psig may not be 
feasible with existing equipment; the commenter recommended that the 
work practice simply require a closed blow down system following 
procedures described in the facility's SSM plan. At a minimum, an 
alternative is needed for existing units that would require capital 
expenditure to meet the 5 psig proposal. One commenter stated that 
compressors cannot recover blowdown system gases at pressures below the 
fuel gas recovery compressor suction pressure. The minimum pressure at 
which a suction compressor can operate depends on the design of the 
coking unit and the blowdown management system. Because there is 
uncertainty surrounding the available emission information, the costs 
are not minimal in most cases, and the emissions are difficult to 
measure, the commenter stated that EPA cannot determine that controls 
on coker vents is BDT.
    Response: Based on the public comments, we re-evaluated BDT for 
delayed coking units. We considered three options: (1) Depressurization 
down to 15 psig; (2) depressurization down to 5 psig; and (3) 
depressurization down to 2 psig. We estimated that the baseline is, on 
average, depressurization down to 15 psig and then venting to the 
atmosphere. Therefore, there are no impacts for Option 1. Impacts for 
Options 2 and 3 were estimated based on the baseline conditions, the 
size of typical coke drums, and cost information provided in public 
comments. We also collected emissions test data to support and verify 
the projected emissions and emission reductions. The impacts for each 
option for new delayed coking units are presented in Table 17 to this 
preamble; impacts for modified and reconstructed delayed coking units 
are presented in Table 18 to this preamble.

   Table 17.--National Fifth Year Impacts of Options for Work Practices Considered for New Delayed Coking Units Subject to 40 CFR Part 60, Subpart Ja
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                           Total annual      Emission        Emission       Cost-effectiveness ($/ton)
                         Option                            Capital cost   cost  ($1,000/     reduction       reduction   -------------------------------
                                                             ($1,000)           yr)        (tons SO2/yr)   (tons VOC/yr)      Overall       Incremental
--------------------------------------------------------------------------------------------------------------------------------------------------------
2.......................................................           2,400             230             170               2           1,300           1,300
3.......................................................          24,000           2,300             230               3           9,900          38,000
--------------------------------------------------------------------------------------------------------------------------------------------------------


  Table 18.--National Fifth Year Impacts of Options for Work Practices Considered for Modified and Reconstructed Delayed Coking Units Subject to 40 CFR
                                                                   Part 60, Subpart Ja
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                           Total annual      Emission        Emission       Cost-effectiveness ($/ton)
                         Option                            Capital cost   cost  ($1,000/     reduction       reduction   -------------------------------
                                                             ($1,000)           yr)        (tons SO2/yr)   (tons VOC/yr)      Overall       Incremental
--------------------------------------------------------------------------------------------------------------------------------------------------------
2.......................................................          14,000           1,400             260               4           5,100           5,100
3.......................................................          54,000           5,100             340               5          15,000          47,000
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on these impacts and consideration of technically feasible 
operating practices, we confirmed our conclusion at proposal that BDT 
is depressurization down to 5 psig, or Option 2. For new delayed coking 
units, this option achieves SO2 emission reductions of 170 
tons/yr from a baseline of 520 tons/yr and VOC emission reductions of 2 
tons/yr from a baseline of 7 tons/yr at a cost of $1,300 per ton of 
combined SO2 and VOC. For modified and reconstructed delayed 
coking units, this option achieves SO2 emission reductions 
of 260 tons/yr from a baseline of 780 tons/yr and VOC emission 
reductions of 4 tons/yr from a baseline of 11 tons/yr at a cost of 
$5,100 per ton of combined SO2 and VOC. Although Option 3 
has been established in one refiner's permit, this level of 
depressurization has not been demonstrated in practice. Additionally, 
the difference in the quantity of gas released when the set point is 2 
psig rather than 5 psig is relatively small, 80 tons of SO2 
and 4 tons of VOC, and the resulting incremental cost-effectiveness 
from Option 2 to Option 3 is about $40,000/ton, which is much greater. 
Therefore, Option 3, or depressurization down to 2 psig, is not BDT.

K. Other Comments

    Comment: One commenter contested the criteria EPA used in its 
Regulatory Flexibility Act/Small Business Regulatory Enforcement 
Fairness Act (RFA/SBREFA) analysis for defining a

[[Page 35858]]

small refiner as one with no more than 1,500 employees or more than 
125,000 barrels per day (BPD) average crude capacity and requested that 
EPA use what the commenter alleged is the commonly recognized 
definition in other EPA programs of no more than 1,500 employees or 
more than 155,000 BPD average crude capacity. The commenter noted that 
EPA did not make any effort in the Regulatory Impact Analysis or in the 
proposal preamble to support its selection or explain why it adopted 
this definition.
    Response: Under the SBA regulations, a small refiner is defined as 
a refinery with no more than 1,500 employees. See Table in 13 CFR 
121.201, NAICS code 324110. Additionally, for government procurement 
purposes only, footnote 4 to that Table further provides that a small 
refinery must meet a certain capacity threshold as follows: ``For 
purposes of Government procurement, the petroleum refiner must be a 
concern that has no more than 1,500 employees nor more than 125,000 
barrels per calendar day total Operable Atmospheric Crude Oil 
Distillation capacity.'' After reviewing our analysis, we realized that 
we inadvertently used the capacity limit to evaluate the impacts on 
small refiners; the definition that should have been used is 1,500 
employees with no capacity limit. We have recalculated the economic 
impact on the small entities using the corrected definition of small 
refiner, and our conclusion that the rule will not have a significant 
economic impact on a substantial number of small entities has not 
changed. See section VI.C of this preamble and the Regulatory Impacts 
Analysis (RIA) in the docket for additional details.
    The commenter is incorrect in asserting that EPA uses any other 
definition for small refiner than the SBA definition when conducting 
its RFA/SBREFA analysis in other rulemakings. EPA consistently uses the 
SBA definition of a small refiner for such purposes. However, in 
promulgating regulations, EPA may define a small refiner differently 
when deciding what standards and requirements apply to these 
facilities. For example, in the fuel standards promulgated by EPA 
(e.g., Control of Air Pollution From New Motor Vehicles: Tier 2 Motor 
Vehicle Emissions Standards and Gasoline Sulfur Control Requirements 
(65 FR 6698)), EPA set different requirements for small refiners than 
for all other refiners, and the 155,000 BPD capacity cutoff cited by 
the commenter is one of the criteria used to define a small refiner in 
those standards. See 40 CFR 80.225. However, the RFA/SBREFA analysis 
conducted in that rulemaking regarding whether those rules had a 
significant economic impact on a substantial number of small entities 
was not conducted based on any capacity cutoff. See 65 FR 6817.
    Comment: One commenter stated that EPA is required under section 
111 of the CAA to promulgate NSPS for each of the pollutants emitted by 
the source category that cause or contribute significantly to air 
pollution which may reasonably be anticipated to endanger public health 
or welfare. The commenter stated that there is scientific consensus 
that greenhouse gases are a leading cause of global warming, and 
anthropogenic emissions of greenhouse gases (GHG) such as 
CO2 and methane (CH4) are increasing and driving 
the warming. Petroleum refineries are a significant source of fossil 
fuel CO2 emissions because they consume large quantities of 
energy, and in fact, U.S. petroleum refineries consume over 3.2 percent 
of the total U.S. energy consumption. Petroleum refineries also emit 
CH4 and are responsible for an additional 0.6 teragrams of 
CO2 equivalence via CH4 emissions. Therefore, the 
commenter believes that EPA must set NSPS for CO2 and 
CH4 because petroleum refineries' emissions of 
CO2 and CH4 cause and contribute significantly to 
air pollution which may reasonably be anticipated to endanger public 
health and welfare.
    Two commenters cited the Supreme Court decision in Massachusetts v. 
EPA, where the Court found that carbon dioxide and other GHG fit into 
the statutory definition of ``air pollutant'' in the CAA. Commenter 
0128 stated that in Massachusetts v. EPA, the Supreme Court rejected 
EPA's overly narrow interpretation that greenhouse gases do not fall 
under the definition. The Court also voided EPA's term ``air 
pollution'' and noted that because greenhouse gases both enter the 
ambient air and warm the atmosphere, they are unquestionably agents of 
air pollution.
    Another commenter contended that while the decision in 
Massachusetts v. EPA states that GHG are ``air pollutants'' as that 
term is used in CAA section 111, section 111 does not require EPA to 
address all air pollutants in NSPS. Therefore, the Supreme Court's 
decision does not mean that EPA necessarily must regulate GHG through 
NSPS. Instead of beginning to address GHG in specific NSPS, the 
commenter stated that EPA should develop a comprehensive plan for 
addressing GHG that ensures that ``any necessary reductions in GHG 
emissions are achieved in a consistent and equitable manner across all 
industry sectors.'' The commenter further stated that since the issue 
of GHG emissions was not raised in the proposal preamble for subparts J 
and Ja, it would be inappropriate for EPA to promulgate GHG standards 
in those subparts without first proposing the new standards.
    Response: While section 111(b)(1)(B) of the CAA permits EPA, under 
appropriate circumstances, to add new standards of performance for 
additional pollutants concurrent with the 8-year review of existing 
standards, for the reasons set forth below, EPA declines to promulgate 
performance standards for GHG, including CO2 and 
CH4, from petroleum refineries as part of this 8-year review 
cycle.
    Section 111(b)(1)(B) imposes two obligations upon EPA for a source 
category listed under section 111(b)(1)(A). First, within 1 year of 
listing a source category, section 111(b)(1)(B) requires the 
Administrator to ``publish proposed regulations, establishing Federal 
standards of performance for new sources'' within such category. After 
providing ``interested persons an opportunity for written comment on 
such proposed regulations,'' EPA must then ``promulgate, within one 
year after such publication, such standards'' as the Administrator 
``deems appropriate.'' The Agency has always interpreted this initial 
requirement as providing the Administrator with significant flexibility 
in determining which pollutants are appropriate for regulation under 
section 111(b)(1)(B). See National Lime Assoc. v. EPA, 627 F.2d 416, 
426 (DC Cir. 1980) (explaining reasons for not promulgating standards 
for NOX, SO2, and CO from lime plants); see also 
National Assoc. of Clean Air Agencies v. EPA, 489 F.3d 1221, 1228-1230 
(DC Cir. 2007) (finding that the ``deems appropriate'' language in CAA 
section 231 provides a ``delegation of authority'' that is ``both 
explicit and extraordinarily broad,'' giving EPA's regulation 
``controlling weight unless it is manifestly contrary to the 
statute'').
    Second, the statute requires that:

    ``The Administrator shall, at least every 8 years, review and, 
if appropriate, revise such standards following the procedure 
required by this subsection for promulgation of such standards. 
Notwithstanding the requirements of the previous sentence, the 
Administrator need not review any such standard if the Administrator 
determines that such review is not appropriate in light of readily 
available information on the efficacy of such standard.''

    Nothing in the 8-year review provision mandates that EPA include a 
new standard of performance for an air pollutant not already covered by 
the

[[Page 35859]]

standard of performance under review. Instead, the 8-year review 
provision can be reasonably understood as requiring ``review'' of only 
``such standards'' \1\ as were previously promulgated. As there would 
be no standard to review for an air pollutant not already subject to 
the standard, there would be no requirement for promulgating a new 
standard of performance since the ``review'' requirement in section 
111(b)(1)(B) cannot be transformed into a ``promulgation'' 
requirement.\2\ Moreover, as noted above, even if the 8-year review 
provision were a ``promulgation'' requirement, such a requirement still 
would not mandate that EPA set performance standards for all air 
pollutants emitted from the source category. In the 1990 CAA 
Amendments, Congress amended the definition of ``standard of 
performance'' to be ``a standard for emissions of air pollutants,'' 
specifically deleting the word ``any'' from the phrase ``any air 
pollutant'' that was contained in the 1977 definition. This amendment 
restored the definition to the 1970 version. This deliberate change 
demonstrates that Congress was aware that the 1970 definition did not 
require EPA to cover all air pollutants emitted from a source category. 
Additionally, by reinstating the 1970 definition through the 1990 CAA 
amendments, Congress was also indicating its understanding that EPA is 
not required to regulate all air pollutants emitted from a source under 
section 111.
---------------------------------------------------------------------------

    \1\ Commenters assert that ``the term `such standards' 
incorporates the inclusive `any' air pollutant language in the 
definition of a `standard of performance' '' and therefore 
contemplates new standards of performance during the 8-year review. 
See Comments, pg. 3. However, the word ``any'' does not appear in 
the definition of ``standard of performance'' in the manner quoted 
by commenters. See CAA section 111(a)(1).
    \2\ Commenters assert that EPA must develop performance 
standards during the 8-year review ``for any air pollutant'' emitted 
by a source ``provided that EPA finds those emissions cause or 
contribute to air pollution'' that may endanger public health or 
welfare. See Comments, pg. 2. To the extent any such finding were 
required, EPA notes that no such finding has been made regarding GHG 
emitted from refineries. Indeed, 111(b)(1)(A), which contains the 
only endangerment finding requirement in section 111, gives the 
Administrator significant discretion on the timing of endangerment 
findings after the initial set of source category listings (``from 
time to time thereafter shall revise''). Nothing in the statute ties 
the endangerment and 8-year review requirements. Hence, commenters' 
own arguments lack merit and EPA is under no obligation for 
promulgating GHG performance standards for refineries.
---------------------------------------------------------------------------

    EPA has promulgated new performance standards for pollutants not 
previously covered concurrent with some previous 8-year review 
rulemakings. See 52 FR 24672, 24710 (July 1, 1987) (considering 
PM10 controls in future rulemakings); 71 FR 9866 (February 
27, 2006) (new PM standards for boilers). Additionally, as commenters 
correctly point out, EPA is promulgating a new standard of performance 
for NOX emissions from certain affected facilities at 
refineries in this rulemaking. However, contrary to commenters' 
assertions,\3\ these actions were discretionary; EPA may, but is not 
required to, promulgate new standards of performance concurrent with 
its 8-year review. While it may often be appropriate for EPA to 
exercise its discretion by promulgating new standards of performance 
concurrent with an 8-year review, because it is in the process of 
gathering information and reviewing controls for an industry, for the 
reasons set forth above, EPA reasonably interprets section 111(b)(1)(B) 
to not mandate such a result.
---------------------------------------------------------------------------

    \3\ Commenters again predicate their assertions on a 
prerequisite endangerment finding. See Comments, pg. 4. As explained 
in footnote 2, EPA has made no such finding and therefore under 
petitioners' interpretation is under no obligation to promulgate GHG 
performance standards for this source category.
---------------------------------------------------------------------------

    In this instance, it is reasonable for EPA not to promulgate 
performance standards for GHG emissions as part of this 8-year review 
cycle. We believe that the nature of GHG emissions renders them readily 
distinguishable from other air pollutants for which we have previously 
promulgated new performance standards concurrent with an 8-year review 
of the existing standards. Indeed, GHG emissions present issues that we 
have never had to address in the context of even an initial NSPS 
rulemaking for a source category. These differences warrant proceeding 
initially through a more deliberate process, i.e., the announced 
advanced notice of proposed rulemaking (ANPR), than in this source 
category-specific rulemaking. While commenters correctly note that we 
have previously exercised our discretion to promulgate new performance 
standards concurrent with an 8-year review, and indeed are doing so 
here with respect to NOX, the exercise of that discretion 
had limited impact as those air pollutants were either already 
regulated elsewhere under the Act or were emitted by a sufficiently 
limited subset of source categories. Here, promulgating new performance 
standards for these air pollutants in this one source category could 
potentially mandate regulation for numerous other source categories 
under several other parts of the Act. Similarly, our initial decision 
to regulate non-National Ambient Air Quality Standards (NAAQS) air 
pollutants in an NSPS has generally raised issues limited to the source 
category before us. For example, with the exception of landfill related 
air pollutants,\4\ our decisions to regulate non-NAAQS air pollutants 
were reached at a time prior to the enactment of the statutory 
Prevention of Significant Deterioration (PSD) program and accordingly 
did not implicate the many complexities that we are struggling with 
today and which we intend to address in the ANPR discussed below. See 
45 FR 52,676, 52,708-10 (Aug. 7, 1980).
---------------------------------------------------------------------------

    \4\ Because of the unique nature of landfill related air 
pollutants the Agency determined it was appropriate to define the 
air pollutants at issue as emissions from landfills and thus limited 
the potential implications for other programs. See 56 FR 24468, 
24470 (May 30, 1991). In other words, only landfills emit these 
particular air pollutants; thus, it was appropriate that only this 
source category was subject to the PSD program for this air 
pollutant.
---------------------------------------------------------------------------

    In contrast to those circumstances, the regulation of GHG emissions 
raises numerous issues that are not well suited to initial resolution 
in a rulemaking directed at an individual source category. To that end, 
as Administrator Johnson announced on March 27, 2008, in letters to 
Senator Barbara Boxer and Representative John Dingell, it is his intent 
to issue an ANPR in the very near future that explores and seeks public 
comment on the many complex interconnections between the relevant 
sections of the Clean Air Act, including section 111, and lays the 
foundation for a comprehensive path forward with respect to regulation 
of all GHG.
    We have previously noted that at this stage it is most appropriate 
to address these complexities in an ANPR addressing a variety of 
interconnected statutory provisions. In his April 10, 2008, testimony 
before the Subcommittee on Energy and Air Quality, Committee on Energy 
and Commerce, U.S. House of Representatives, Robert J. Meyers, 
Principal Deputy Assistant Administrator of the Office of Air and 
Radiation, further elaborated on the reasons for and anticipated 
content of an ANPR and discussed some of these complexities. For 
example, he noted the potential complexities resulting from 
implementation of the PSD preconstruction review permitting program:

    For PSD purposes, major stationary sources are those with the 
potential to emit 100 tons per year of a regulated air pollutant in 
the case of certain statutorily-listed source categories, and 250 
tons per year in the case of all other source categories. New large 
schools, nursing homes, and hospitals could be considered a ``major 
source'' under this section of the Clean Air Act. For modifications, 
only those that increase

[[Page 35860]]

emissions above a tonnage threshold established by EPA for each 
regulated pollutant through rulemaking triggers PSD. Until EPA 
establishes this so-called ``significance'' level, however, any 
increase in a regulated pollutant at a major stationary source 
undergoing a modification would trigger PSD permitting.
    As noted previously, PSD sources are required to install best 
available control technology (BACT). BACT must be at least as 
stringent as any applicable NSPS, and is to reflect the maximum 
degree of emissions reduction achievable for such a facility, taking 
into account energy, environment and economic impacts and other 
costs.
    Controlling GHG emissions under any section of the Clean Air Act 
could significantly increase the number of stationary sources 
subject to PSD permitting.
    Because CO2 is typically emitted in larger quantities than 
criteria and other traditional air pollutants from combustion 
sources, facilities not previously subject to Clean Air Act 
permitting--such as large commercial and residential buildings 
heated by natural gas boilers--could qualify as major stationary 
sources for PSD purposes. In addition, some small industrial sources 
not now covered by PSD could be expected to become subject to PSD 
due to their GHG emissions.
    Currently, our best estimate of the potential impact of 
including GHG in the PSD program is that the number of PSD permits 
issued annually nationwide could rise by an order of magnitude above 
the current 200-300 a year. Such estimates are subject to 
significant uncertainty. At present, we do not have comprehensive 
information on GHG emissions from the many categories of stationary 
sources of such emissions; instead we have relied on available 
information and general engineering estimates.
    Such a broadening of the PSD program could pose significant 
implementation issues for covered facilities (particularly newly 
covered facilities) and permitting agencies. EPA is examining the 
scope of these potential difficulties and whether, for GHG, the 
program could be limited to larger sources, at least temporarily, in 
view of the very substantial increase in administrative burden that 
might otherwise occur. However, at present it is unclear as to 
whether EPA has the legal discretion to exempt sources above the 
statutory thresholds. In addition, EPA is exploring concepts for 
streamlining implementation of the PSD program for smaller sources, 
such as guidance on general permits or source definitions for BACT 
determinations and model permits for use by permitting agencies. EPA 
will address permitting issues in greater detail in the planned 
ANPR.

    Given the complexity of PSD issues arising from regulation of GHG 
emissions, among other complex issues of regulating a pollutant--
particularly a pollutant global in nature--for the first time under the 
CAA, it is reasonable for the Agency to proceed first by evaluating 
these issues, and other potential complexities, in the previously 
announced ANPR rather than by taking action to promulgate performance 
standards for GHG emissions in this rulemaking.
    In addition to the reasons set forth above, it is appropriate for 
EPA to decline to promulgate performance standards for GHG emissions 
concurrent with this 8-year review as section 111(b)(1)(B) does not 
require that the Agency revise the standards when essential information 
becomes available too late in the review period. The 8-year review 
provision itself conditions the need to review a standard on ``readily 
available information on the efficacy of such standard.'' CAA section 
111(b)(1)(B). The legislative history of the 1970 CAA predecessor for 
the review provision also states that the review obligation depends on 
the availability of ``new technology processes or operating methods.'' 
1970 Sen. Comm. Rep. at 17. Additionally, the Massachusetts decision, 
which held that GHG are air pollutants, was handed down merely four 
weeks before the court-ordered deadline to propose the standards for 
this 8-year review period. As explained above, section 111(b)(1)(B) 
contemplates a two-year period for NSPS promulgation, and, as noted 
below, the consent decree under which EPA was acting contemplated a 
two-and-a-half year period for this 8-year review; hence, EPA did not 
have sufficient time within this rulemaking for proposing and 
promulgating performance standards for GHG emissions from refineries. 
The following discussion provides more information regarding the 
timeline of events for this particular rulemaking's review period.
    EPA entered into a consent decree with the Sierra Club and Our 
Children's Earth Foundation on October 31, 2005, that required EPA to 
conduct its review of 40 CFR part 60, subpart J and propose revisions 
by April 30, 2007, and to promulgate a final rule by April 30, 2008. 
EPA began its review of subpart J and drafted a proposal package. 
Shortly before EPA sent the proposed rule package to OMB for its 
review, the U.S. Supreme Court, on April 2, 2007, issued its decision 
in Massachusetts v. EPA, holding that GHG are air pollutants under the 
CAA, and remanding the case for the Agency to take action consistent 
with the Court's opinion. Less than one month later, EPA was obligated 
under the terms of its consent decree to propose revisions to subpart J 
by April 30, 2007; this proposed rule did not include performance 
standards for GHG emissions. On August 27, 2007, EPA received comments 
from Earthjustice asserting that EPA, as part of its 8-year review 
under section 111(b)(1)(B), must promulgate GHG emissions limits for 
petroleum refineries. On September 14, 2007, the Massachusetts case was 
officially remanded to the Agency by the DC Circuit Court of Appeals. 
Under the terms of the consent decree, EPA was obligated to finalize 
its subpart J revisions by April 30, 2008. Considering this timeline of 
events, and the complexities of the issues involved, EPA would not have 
had sufficient time during this particular 8-year review of subpart J 
to propose and promulgate GHG performance standards for refineries even 
if the Agency had deemed such action appropriate. As explained above, 
the Agency will use the information it gathers through the ANPR for 
determining what may be appropriate for future rulemakings.

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

A. What are the impacts for petroleum refinery process units?

    We are presenting estimates of the impacts for the final 
requirements of subpart Ja that change the performance standards for 
the following: (1) The emission limits for fluid catalytic cracking 
units, sulfur recovery plants, fluid coking units, fuel gas combustion 
devices, and process heaters; and (2) the work practice standards for 
flares and delayed coking units. The final amendments to 40 CFR part 
60, subpart J are clarifications to the existing rule and they have no 
emission reduction impacts. The cost, environmental, and economic 
impacts presented in this section are expressed as incremental 
differences between the impacts of petroleum refinery process units 
complying with the final subpart Ja and the current NSPS requirements 
of subpart J (i.e., baseline). The impacts are presented for petroleum 
refinery process units that commence construction, reconstruction, or 
modification over the next 5 years. The analyses and the documents 
referenced below can be found in Docket ID No. EPA-HQ-OAR-2007-0011.
    In order to determine the incremental costs and emission reductions 
of this final rule, we first estimated baseline impacts. For new 
sources, baseline costs and emission reductions were estimated for 
complying with subpart J; incremental impacts for subpart Ja were 
estimated as the costs to comply with subpart J subtracted from the 
costs to comply with final subpart Ja. Sources that are modified or 
reconstructed over the next 5 years must comply with subpart J in the 
absence of final subpart Ja. Prior to reconstruction or modification, 
these sources will either be subject to a consent decree

[[Page 35861]]

(equivalent to about 77 percent of the industry by capacity), complying 
with subpart J or equivalent limits, and/or complying with 40 CFR part 
63, subpart UUU (MACT II). Baseline costs and emission reductions were 
estimated as the effort needed to comply with subpart J from one of 
those three starting points. The costs and emission reductions to 
comply with final subpart Ja were estimated from those starting points 
as well. For further detail on the methodology of these calculations, 
see Docket ID No. EPA-HQ-OAR-2007-0011.
    When considering and selecting emission limits for the final rule, 
we evaluated the cost-effectiveness of each option for new sources 
separately from reconstructed and modified sources. In most cases, our 
selections for each process unit and pollutant were consistent for 
modified and reconstructed units and new units. In this section, we are 
presenting our costs and emission reductions for the overall rule. We 
estimate that the final amendments will reduce emissions of PM by 1,300 
tons/yr, SO2 by 17,000 tons/yr, NOX by 11,000 tons/yr, and VOC by 200 
tons/yr from the baseline. The estimated increase in annual cost, 
including annualized capital costs, is about $31 million (2006 
dollars). The overall cost-effectiveness is about $1,070 per ton of 
combined pollutants removed. The estimated nationwide 5-year 
incremental emissions reductions and cost impacts for the final 
standards are summarized in Table 19 of this preamble.

   Table 19.--National Incremental Emission Reductions and Cost Impacts for Petroleum Refinery Units Subject to Final Standards Under 40 CFR Part 60,
                                                         Subpart Ja (Fifth Year After Proposal)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                              Annual          Annual          Annual          Annual
                                           Total capital   Total annual      emission        emission        emission        emission          Cost
              Process unit                cost  ($1,000)  cost  ($1,000/    reductions      reductions      reductions      reductions     effectiveness
                                                                yr)        (tons PM/yr)    (tons SO2/yr)   (tons NOX/yr)   (tons VOC/yr)      ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
FCCU....................................           8,500           6,400             240           4,300           2,600  ..............             890
FCU.....................................          14,000           4,000           1,000           5,900             660  ..............             530
SRP.....................................           1,700             730  ..............             420  ..............  ..............           1,700
Fuel gas combustion devices.............          34,000          12,000  ..............           5,200  ..............  ..............           2,300
Process heaters.........................          23,000          12,000  ..............  ..............           7,500  ..............           1,600
Flaring.................................          40,000          -7,000  ..............              80               6             200         -23,000
Delayed coking units....................          17,000           1,600  ..............             440  ..............              25           3,400
Sulfur pits.............................           8,300           1,000  ..............             300  ..............  ..............           3,400
                                         ---------------------------------------------------------------------------------------------------------------
    Total...............................         150,000          31,100           1,300          17,000          11,000           1,400           1,070
--------------------------------------------------------------------------------------------------------------------------------------------------------

B. What are the secondary impacts?

    Indirect or secondary air quality impacts of this final rule will 
result from the increased electricity usage associated with the 
operation of control devices. If plants purchase electricity from a 
power plant, we estimate that the final standards will increase 
secondary emissions of criteria pollutants, including PM, SO2, NOX, and 
CO from power plants. For new, modified or reconstructed sources, this 
final rule will increase secondary PM emissions by 56 Megagrams per 
year (Mg/yr) (62 tons/yr); secondary SO2 emissions by about 1,400 Mg/yr 
(1,500 tons/yr); and secondary NOX emissions by about 530 Mg/yr (580 
tons/yr) for the 5 years following proposal.
    As explained earlier, we expect that affected facilities will 
control emissions from fluid catalytic cracking units by installing and 
operating ESP or wet gas scrubbers. We also expect that the emissions 
from the affected FCU will be controlled with a wet scrubber. For these 
process units, we estimated solid waste impacts for both types of 
control devices and water impacts for wet gas scrubbers. In addition, 
the controls needed by small sulfur recovery plants will generate 
condensate. We project that this final rule will generate 1.6 billion 
gallons of water per year for the 5 years following proposal. We also 
estimate that this final rule will generate 2,200 Mg/yr (2,400 tons/yr) 
of solid waste over those 5 years.
    Energy impacts as defined in this preamble section consist of the 
electricity and steam needed to operate control devices and other 
equipment that would be required under the final rule. Our estimate of 
the increased energy demand includes the electricity needed to produce 
the required amounts of steam as well as direct electricity demand. We 
project that this final rule will increase overall energy demand by 
about 410 gigawatt-hours per year (1,400 billion British thermal units 
per year). An analysis of energy impacts that accounts for reactions in 
affected markets to the costs of this final rule can be found in the 
section on Executive Order 13211 found later in this preamble.

C. What are the economic impacts?

    Our economic impact analysis estimated the impacts on product price 
and output that the final NSPS would have on five petroleum products-- 
motor gasoline, jet fuel, distillate fuel oil, residual fuel oil, and 
liquefied petroleum gases. This analysis estimates in the fifth year 
after proposal that the price of these petroleum products will increase 
less than 0.01 percent nationally along with a corresponding reduction 
in output of less than 0.01 percent. The overall total annual social 
costs, which reflect changes in consumer and producer behavior in 
response to the compliance costs, are $27 million ($2006) in the fifth 
year after proposal or almost identical to the compliance costs 
incurred by affected producers of these petroleum products.
    For more information, please refer to the regulatory impact 
analysis (RIA) that is in the docket for this final rule.

D. What are the benefits?

    We estimate the monetized benefits of this final rule to be $220 
million to $1.9 billion (2006$) in the fifth year after proposal. We 
base the benefits estimate derived from the PM2.5 and PM2.5 precursor 
emission reductions on the approach and methodology laid out in the 
Technical Support Document that accompanied the recently completed 
Regulatory Impact Analysis (RIA) for the revision to the National 
Ambient Air Quality Standard for Ground-level Ozone (NAAQS), March 
2008. We generated estimates that represent the total monetized human 
health benefits (the sum of premature mortality and premature 
morbidity) of reducing one ton of PM2.5 and PM2.5 precursor

[[Page 35862]]

emissions. A summary of the range of benefits estimates at discount 
rates of 3% and 7% is in Table 20 of this preamble.

                                     Table 20.--Summary of the Range of Benefits Estimates for Final Refineries NSPS
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                     Total monetized benefits   Total monetized benefits
                                Monetized benefits per ton    Monetized benefits per     Emission       (millions of 2006          (millions of 2006
           Pollutant             emission  reduction  (3%    ton emission  reduction    reductions    dollars,  3% discount)     dollars,  7% discount)
                                         discount)                (7% discount)           (tons)               \1\                        \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Direct PM2.5..................  $68,000 to $570,000.......  $63,000 to $520,000......        1,054  $72 to $600..............  $66 to $540.
PM2.5 Precursor:
    SO2.......................  $8,000 to $68,000.........  $7,400 to $62,000........       16,714  $130 to $1,100...........  $120 to $1,000.
    NOX.......................  $1,300 to $11,000.........  $1,200 to $9,600.........       10,786  $14 to $110..............  $13 to $100.
    VOC.......................  $210 to $1,700............  $190 to $1,500...........          230  $0.05 to $.38............  $0.04 to $.35.
                                                                                       Grand total  $220 to $1,900...........  $200 to $1,700.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the analysis year (fifth year after proposal, 2012), and are rounded to two significant figures so numbers may not sum across
  columns. Emission reductions reflect the combination of selected options for both new and reconstructed/modified sources. The PM2.5 fraction of total
  PM emissions is estimated at 83.3%, and only the reduction in the PM2.5 fraction is monetized in this analysis. All fine particles are assumed to have
  equivalent health effects, but the benefit per ton estimates vary because each ton of precursor reduced has a different propensity to become PM2.5.
  The monetized benefits incorporate the conversion from precursor emissions to ambient fine particles.

    The specific estimates of benefits per ton of pollutant reductions 
included in this analysis are largely driven by the concentration 
response function for premature mortality, which is based on the PM 
Expert Elicitation study (Industrial Economics, Inc., September 2006. 
Expanded Expert Judgment Assessment of the Concentration-Response 
Relationship Between PM2.5 Exposure and Mortality. Prepared 
for the U.S. EPA, Office of Air Quality Planning and Standards). The 
preamble for the proposal indicated that EPA would update the benefits 
estimates to incorporate the results of the expert elicitation for the 
final rule, and we have done so. The range of benefits estimates 
presented above represents the range from the lowest expert estimate to 
the highest expert estimate to characterize the uncertainty in the 
concentration response function. To generate the benefit-per-ton 
estimates, we used a model to convert emissions of direct 
PM2.5 and PM2.5 precursors into changes in 
PM2.5 air quality and another model to estimate the changes 
in human health based on that change in air quality. Finally, the 
monetized health benefits were divided by the emission reductions to 
create the benefit-per-ton estimates. Even though all fine particles 
are assumed to have equivalent health effects, the benefit-per-ton 
estimates vary because each ton of precursor reduced has a different 
propensity to become PM2.5. For example, NOX has 
a lower benefit-per-ton estimate than direct PM2.5 because 
it does not form as much PM2.5, thus the exposure would be 
lower, and the monetized health benefits would be lower.
    This analysis does not include the type of detailed uncertainty 
assessment found in the PM NAAQS RIA because we lack the necessary air 
quality input and monitoring data to run the benefits model. However, 
the 2006 PM NAAQS analysis provides an indication of the sensitivity of 
our results to the use of alternative concentration response functions, 
including those derived from the PM expert elicitation study.
    The annualized costs of this rulemaking are estimated at $31 
million (2006 dollars) in the fifth year after proposal, and the 
benefits are estimated at $220 million to $1.9 billion (2006 dollars) 
for that same year. Thus, net benefits of this rulemaking are estimated 
at $190 million to $1.8 billion (2006 dollars). EPA believes that the 
benefits are likely to exceed the costs by a significant margin even 
when taking into account the uncertainties in the cost and benefit 
estimates. It should be noted that the range of benefits estimates 
provided above does not include ozone-related benefits from the 
reductions in VOC and NOX emissions expected to occur as a 
result of this final rule, nor does this range include benefits from 
the portion of total PM emissions reduction that is not 
PM2.5. We do not have sufficient information or modeling 
available to provide such estimates for this rulemaking. For more 
information, please refer to the RIA for this final rule that is 
available in the docket.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under section 3(f)(1) of Executive Order 12866 (58 FR 51735, 
October 4, 1993), this action is an ``economically significant 
regulatory action'' because it is likely to have an annual effect on 
the economy of $100 million or more. Accordingly, EPA submitted this 
action to the Office of Management and Budget (OMB) for review under 
Executive Order 12866 and any changes made in response to OMB 
recommendations have been documented in the docket for this action.
    In addition, EPA prepared an analysis of the potential costs and 
benefits associated with this action. This analysis is contained in the 
RIA for the Final Petroleum Refinery NSPS. A copy of the analysis is 
available in the docket for this action and the analysis is briefly 
summarized here. The monetized benefits of this action are estimated as 
a range from $220 million to $1.9 billion (2006 dollars), and the 
annualized costs of this action are $31.1 million (2006 dollars). We 
also estimated the economic impacts, small business impacts, and energy 
impacts associated with this action. These analyses are included in the 
RIA and are summarized elsewhere in this preamble.

B. Paperwork Reduction Act

    The final amendments to the standards of performance for petroleum 
refineries (40 CFR part 60, subpart J) do not impose any new 
information collection burden. The final amendments add a monitoring 
exemption for fuel gas streams combusted in a fuel gas combustion 
device that are inherently low in sulfur content. The exemption applies 
to fuel gas streams that meet specified criteria or that the owner or 
operator demonstrates are low sulfur according to the rule 
requirements. The owner or operator is required to submit a written 
application for the exemption containing information needed to document 
the low sulfur content. The application is not a mandatory requirement 
and the incremental reduction in monitoring burden that

[[Page 35863]]

will occur as a result of the exemption is not significant compared to 
the baseline burden estimates for the existing rule. Therefore, we have 
not revised the information collection request (ICR) for the existing 
rule. However, OMB has previously approved the information collection 
requirements in the existing rule (40 CFR part 60, subpart J) under the 
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501, et seq., and 
has assigned OMB control number 2060-0022, EPA ICR number 1054.09. The 
OMB control numbers for EPA's regulations are listed in 40 CFR part 9.
    The information collection requirements in the final standards of 
performance for petroleum refineries (40 CFR part 60, subpart Ja) have 
been submitted for approval to OMB under the Paperwork Reduction Act, 
44 U.S.C. 3501, et seq. The information collection requirements are not 
enforceable until OMB approves them.
    The information collection requirements in this final rule are 
needed by the Agency to determine compliance with the standards. These 
requirements are based on recordkeeping and reporting requirements in 
the NSPS General Provisions in 40 CFR part 60, subpart A, and on 
specific requirements in subpart J or subpart Ja which are mandatory 
for all operators subject to new source performance standards. These 
recordkeeping and reporting requirements are specifically authorized by 
section 114 of the CAA (42 U.S.C. 7414). All information submitted to 
EPA pursuant to the recordkeeping and reporting requirements for which 
a claim of confidentiality is made is safeguarded according to EPA 
policies set forth in 40 CFR part 2, subpart B.
    The final standards of performance for petroleum refineries include 
work practice requirements for delayed coking reactor vessel 
depressuring and written plans to minimize emissions from flares. 
Plants also are required to analyze the cause of any exceedance that 
releases more than 500 pounds per day of SO2 from an 
affected fuel gas combustion device. The final standards also include 
testing, monitoring, recordkeeping, and reporting provisions. 
Monitoring requirements include control device operating parameters, 
bag leak detection systems, or CEMS, depending on the type of process, 
pollutant, and control device. Exemptions are also included for small 
emitters.
    The annual burden for this information collection averaged over the 
first 3 years of this ICR is estimated to total 5,340 labor-hours per 
year at a cost of $481,249 per year. The annualized capital costs are 
estimated at $2,052,000 per year and operation and maintenance costs 
are estimated at $1,117,440 per year. We note that the capital costs as 
well as the operation and maintenance costs are for the continuous 
monitors; these costs are also included in the cost impacts presented 
in section V.A of this preamble. Therefore, the burden costs associated 
with the continuous monitors presented in the ICR are not additional 
costs incurred by affected sources subject to final subpart Ja. Burden 
is defined at 5 CFR 1320.3(b).
    An agency may not conduct or sponsor, and a person is not required 
to respond to a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations are listed in 40 CFR part 9. When this ICR is approved by 
OMB, the Agency will publish a technical amendment to 40 CFR part 9 in 
the Federal Register to display the OMB control number for the approved 
information collection requirements contained in this final rule.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impact of this final action on small 
entities, small entity is defined as: (1) A small business whose parent 
company has no more than 1,500 employees, depending on the size 
definition for the affected NAICS code (as defined by Small Business 
Administration (SBA) size standards); (2) a small governmental 
jurisdiction that is a government of a city, county, town, school 
district, or special district with a population of less than 50,000; 
and (3) a small organization that is any not-for-profit enterprise 
which is independently owned and operated and is not dominant in its 
field.
    After considering the economic impact of this final rule on small 
entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. The small 
entities directly regulated by the current standards of performance for 
petroleum refineries are small refineries. After reviewing the small 
business analysis for the proposed NSPS, we realized that we 
inadvertently used the capacity limit of 125,000 barrels/day production 
as part of the small business size standard to evaluate the impacts on 
small refiners; the definition that should have been used is 1,500 
employees for an ultimate parent entity with no capacity limit in the 
United States. The effect of this change in the small business size 
standard for this analysis is one additional small refiner. This change 
in the small business size standard does not lead to any effect on the 
certification that there is no significant economic impact on a 
substantial number of small entities resulting from today's action. We 
have determined that, of the 58 entities that are in the affected 
industry, 25 of these (or 43 percent) are classified as small according 
to the SBA small business size standard listed previously. Of these 25 
affected entities, three are expected to be affected by today's action. 
None of these three small entities is expected to incur an annualized 
compliance cost of more than 1.0 percent to comply with this final 
action. For more information, please refer to the economic impact 
analysis that is in the public docket for this rulemaking.
    Although this final action will not have a significant economic 
impact on a substantial number of small entities, EPA nonetheless has 
tried to reduce the impact of this final action on small entities by 
incorporating specific standards for small sulfur recovery plants and 
streamlining procedures for exempting inherently low-sulfur fuel gases 
from continuous monitoring.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act (UMRA) of 1995, Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of the UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures by State, local, and tribal governments, in 
the aggregate, or to the private sector, of $100 million or more in any 
one year. Before promulgating an EPA rule for which a written statement 
is needed, section 205 of the UMRA generally requires EPA to identify 
and consider a reasonable number of regulatory alternatives and adopt 
the least costly, most cost-effective, or least burdensome alternative 
that achieves the objectives of the rule. The provisions of section

[[Page 35864]]

205 do not apply when they are inconsistent with applicable law. 
Moreover, section 205 allows EPA to adopt an alternative other than the 
least costly, most cost-effective, or least burdensome alternative if 
the Administrator publishes with the final rule an explanation why that 
alternative was not adopted. Before EPA establishes any regulatory 
requirements that may significantly or uniquely affect small 
governments, including tribal governments, it must have developed under 
section 203 of the UMRA a small government agency plan. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments to have meaningful and timely 
input in the development of EPA regulatory proposals with significant 
Federal intergovernmental mandates, and informing, educating, and 
advising small governments on compliance with the regulatory 
requirements.
    EPA has determined that this final action does not contain a 
Federal mandate that may result in expenditures of $100 million or more 
for State, local, and tribal governments, in the aggregate, or the 
private sector in any one year. As discussed earlier in this preamble, 
the estimated expenditures for the private sector in the fifth year 
after proposal are an annualized cost of $31.1 million (2006 dollars). 
Thus, this final action is not subject to the requirements of section 
202 and 205 of the UMRA. In addition, EPA has determined that this 
final action contains no regulatory requirements that might 
significantly or uniquely affect small governments. This final action 
contains no requirements that apply to such governments, imposes no 
obligations upon them, and would not result in expenditures by them of 
$100 million or more in any one year or any disproportionate impacts on 
them. Therefore, this final action is not subject to the requirements 
of section 203 of the UMRA.

E. Executive Order 13132: Federalism

    Executive Order 13132 (64 FR 43255, August 10, 1999), requires EPA 
to develop an accountable process to ensure ``meaningful and timely 
input by State and local officials in the development of regulatory 
policies that have federalism implications.'' ``Policies that have 
federalism implications'' is defined in the Executive Order to include 
regulations that have ``substantial direct effects on the States, on 
the relationship between the national government and the States, or on 
the distribution of power and responsibilities among the various levels 
of government.''
    This final action does not have federalism implications. It will 
not have substantial direct effects on the States, on the relationship 
between the national government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in Executive Order 13132. None of the affected facilities 
are owned or operated by State governments. Thus, Executive Order 13132 
does not apply to this final action.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Executive Order 13175 (65 FR 67249, November 9, 2000) requires EPA 
to develop an accountable process to ensure ``meaningful and timely 
input by tribal officials in the development of regulatory policies 
that have tribal implications.'' This final action does not have tribal 
implications, as specified in Executive Order 13175. It will not have 
substantial direct effects on tribal governments, on the relationship 
between the Federal government and Indian tribes, or on the 
distribution of power and responsibilities between the Federal 
government and Indian tribes, as specified in Executive Order 13175. 
The final rules impose requirements on owners and operators of 
specified industrial facilities and not tribal governments. Thus, 
Executive Order 13175 does not apply to this final action.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997) 
as applying to those regulatory actions that concern health or safety 
risks, such that the analysis required under section 5-501 of the 
Executive Order has the potential to influence the regulation. This 
action is not subject to Executive Order 13045 because it is based 
solely on technology performance.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This rule is not a ``significant energy action'' as defined in 
Executive Order 13211, ``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR 
28355, May 22, 2001) because it is not likely to have a significant 
adverse effect on the supply, distribution, or use of energy. We 
prepared an analysis of the impacts on energy markets as part of our 
RIA for this final action. This analysis accounts for the increase in 
electricity generation occurring due to additional control requirements 
associated with this final action. Our analysis shows that there is a 
reduction in gasoline output of less than 0.75 million gallons per 
year, or less than 50 barrels of gasoline production per day in the 
fifth year after proposal of this final action. In addition, our 
analysis shows that there is no increase in gasoline prices in the 
fifth year after proposal of this final action. With no increase in 
domestic gasoline prices, no significant increase in our dependence on 
foreign energy supplies should take place. Finally, this final action 
will have no adverse effect on crude oil supply, coal production, 
electricity production, and energy distribution. Further, we conclude 
that this final action is not likely to have any adverse energy 
effects. For more information on this analysis, please refer to the RIA 
available in the docket for this rulemaking.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (``NTTAA''), Public Law No. 104-113 (15 U.S.C. 272 note) 
directs EPA to use voluntary consensus standards (VCS) in its 
regulatory activities unless to do so would be inconsistent with 
applicable law or otherwise impractical. Voluntary consensus standards 
are technical standards (e.g., materials specifications, test methods, 
sampling procedures, and business practices) that are developed or 
adopted by VCS bodies. NTTAA directs EPA to provide Congress, through 
OMB, explanations when the Agency decides not to use available and 
applicable VCS.
    This rulemaking involves technical standards. EPA has decided to 
use the VCS ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas 
Analyses,'' for its manual methods of measuring the content of the 
exhaust gas. These parts of ANSI/ASME PTC 19.10-1981 are acceptable 
alternatives to EPA Methods 3B, 6, 6A, 7, 7C, and 15A. This standard is 
available from the American Society of Mechanical Engineers (ASME), 
Three Park Avenue, New York, NY 10016-5990.
    The EPA has also decided to use EPA methods 1, 2, 3, 3A, 3B, 5, 5B, 
5F, 5I, 6, 6A, 6C, 7, 7A, 7C, 7D, 7E, 10, 10A, 10B, 11, 15, 15A, 16, 
and 17 (40 CFR part 60, Appendices A-1 through A6); Performance 
Specifications 1, 2, 3, 4, 4A, 5, 7, and 11 (40 CFR part 60, Appendix 
B); quality assurance procedures in 40 CFR part 60, Appendix F; and the 
Gas Processors Association Standard 2377-86, ``Test for Hydrogen

[[Page 35865]]

Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain 
Tubes,'' 1986 Revision. While the Agency has identified 22 VCS as being 
potentially applicable to this rule, we have decided not to use these 
VCS in this rulemaking. The use of these VCS would have been 
impractical because they do not meet the objectives of the standards 
cited in this rule. See the docket for this rule for the reasons for 
these determinations.
    Under 40 CFR 60.13(i) of the NSPS General Provisions, a source may 
apply to EPA for permission to use alternative test methods or 
alternative monitoring requirements in place of any required testing 
methods, performance specifications, or procedures in the final rule 
and amendments.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes 
Federal executive policy on environmental justice. Its main provision 
directs Federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States. EPA has determined that these final 
amendments to 40 CFR part 60, subpart J will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because they do not 
affect the level of protection provided to human health or the 
environment. The final amendments are clarifications which do not relax 
the control measures on sources regulated by the rule and, therefore, 
will not cause emissions increases from these sources.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801, et seq., as added by 
the Small Business Regulatory Enforcement Fairness Act of 1996, 
generally provides that before a rule may take effect the agency 
promulgating the rule must submit a rule report, which includes a copy 
of the rule, to each House of Congress and to the Comptroller General 
of the United States. The EPA will submit a report containing these 
final rules and other required information to the U.S. Senate, the U.S. 
House of Representatives, and the Comptroller General of the United 
States prior to publication of the final rules in the Federal Register. 
A major rule cannot take effect until 60 days after it is published in 
the Federal Register. This action is not a ``major rule'' as defined by 
5 U.S.C. 804(2). This final rule will be effective on June 24, 2008.

List of Subjects in 40 CFR Part 60

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Incorporations by reference, Intergovernmental 
relations, Reporting and recordkeeping requirements.

    Dated: April 30, 2008.
Stephen L. Johnson,
Administrator.

0
For the reasons stated in the preamble, title 40, chapter I of the Code 
of Federal Regulations is amended as follows:

PART 60--[AMENDED]

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

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

Subpart A--[Amended]

0
2. Section 60.17 is amended by:
0
a. Revising paragraph (h)(4),
0
b. Revising the last sentence of paragraph (m) introductory text, and
0
c. Revising paragraph (m)(1) to read as follows:


Sec.  60.17  Incorporations by reference.

* * * * *
    (h) * * *
    (4) ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part 
10, Instruments and Apparatus], IBR approved for Sec.  60.106(e)(2) of 
subpart J, Sec. Sec.  60.104a(d)(3), (d)(5), (d)(6), (h)(3), (h)(4), 
(h)(5), (i)(3), (i)(4), (i)(5), (j)(3), and (j)(4), 60.105a(d)(4), 
(f)(2), (f)(4), (g)(2), and (g)(4), 60.106a(a)(1)(iii), (a)(2)(iii), 
(a)(2)(v), (a)(2)(viii), (a)(3)(ii), and (a)(3)(v), and 
60.107a(a)(1)(ii), (a)(1)(iv), (a)(2)(ii), (c)(2), (c)(4), and (d)(2) 
of subpart Ja, Tables 1 and 3 of subpart EEEE, Tables 2 and 4 of 
subpart FFFF, Table 2 of subpart JJJJ, and Sec. Sec.  60.4415(a)(2) and 
60.4415(a)(3) of subpart KKKK of this part.
* * * * *
    (m) * * * You may inspect a copy at EPA's Air and Radiation Docket 
and Information Center, Room 3334, 1301 Constitution Ave., NW., 
Washington, DC 20460.
    (1) Gas Processors Association Standard 2377-86, Test for Hydrogen 
Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes, 
1986 Revision, IBR approved for Sec. Sec.  60.105(b)(1)(iv), 
60.107a(b)(1)(iv), 60.334(h)(1), 60.4360, and 60.4415(a)(1)(ii).
* * * * *

Subpart J--[Amended]

0
3. Section 60.100 is amended by revising the first sentence in 
paragraph (a) and revising paragraphs (b) through (d) to read as 
follows:


Sec.  60.100  Applicability, designation of affected facility, and 
reconstruction.

    (a) The provisions of this subpart are applicable to the following 
affected facilities in petroleum refineries: fluid catalytic cracking 
unit catalyst regenerators, fuel gas combustion devices, and all Claus 
sulfur recovery plants except Claus plants with a design capacity for 
sulfur feed of 20 long tons per day (LTD) or less. * * *
    (b) Any fluid catalytic cracking unit catalyst regenerator or fuel 
gas combustion device under paragraph (a) of this section other than a 
flare as defined in Sec.  60.101a which commences construction, 
reconstruction, or modification after June 11, 1973, and on or before 
May 14, 2007, or any fuel gas combustion device under paragraph (a) of 
this section that meets the definition of a flare as defined in Sec.  
60.101a which commences construction, reconstruction, or modification 
after June 11, 1973, and on or before June 24, 2008, or any Claus 
sulfur recovery plant under paragraph (a) of this section which 
commences construction, reconstruction, or modification after October 
4, 1976, and on or before May 14, 2007, is subject to the requirements 
of this subpart except as provided under paragraphs (c) and (d) of this 
section.
    (c) Any fluid catalytic cracking unit catalyst regenerator under 
paragraph (b) of this section which commences construction, 
reconstruction, or modification on or before January 17, 1984, is 
exempted from Sec.  60.104(b).
    (d) Any fluid catalytic cracking unit in which a contact material 
reacts with petroleum derivatives to improve feedstock quality and in 
which the contact material is regenerated by burning off coke and/or 
other deposits and that commences construction, reconstruction, or 
modification on or before January 17, 1984, is exempt from this 
subpart.
* * * * *

0
4. 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

[[Page 35866]]

which is combusted. Fuel gas also includes natural gas when the natural 
gas is combined and combusted in any proportion with a gas generated at 
a refinery. Fuel gas does not include gases generated by catalytic 
cracking unit catalyst regenerators and fluid coking burners. Fuel gas 
does not include vapors that are collected and combusted to comply with 
the wastewater provisions in Sec.  60.692, 40 CFR 61.343 through 
61.348, or 40 CFR 63.647, or the marine tank vessel loading provisions 
in 40 CFR 63.562 or 40 CFR 63.651.
* * * * *

0
5. Section 60.102 is amended by revising paragraph (b) to read as 
follows:


Sec.  60.102  Standard for particulate matter.

* * * * *
    (b) Where the gases discharged by the fluid catalytic cracking unit 
catalyst regenerator pass through an incinerator or waste heat boiler 
in which auxiliary or supplemental liquid or solid fossil fuel is 
burned, particulate matter in excess of that permitted by paragraph 
(a)(1) of this section may be emitted to the atmosphere, except that 
the incremental rate of particulate matter emissions shall not exceed 
43 grams per Gigajoule (g/GJ) (0.10 lb/million British thermal units 
(Btu)) of heat input attributable to such liquid or solid fossil fuel.

0
6. Section 60.104 is amended by revising paragraphs (b)(1) and (b)(2) 
to read as follows:


Sec.  60.104  Standards for sulfur oxides.

* * * * *
    (b) * * *
    (1) With an add-on control device, reduce SO2 emissions 
to the atmosphere by 90 percent or maintain SO2 emissions to 
the atmosphere less than or equal to 50 ppm by volume (ppmv), whichever 
is less stringent; or
    (2) Without the use of an add-on control device to reduce 
SO2 emissions, maintain sulfur oxides emissions calculated 
as SO2 to the atmosphere less than or equal to 9.8 kg/Mg (20 
lb/ton) coke burn-off; or
* * * * *

0
7. Section 60.105 is amended by:
0
a. Revising the first sentence of paragraph (a)(3) introductory text;
0
b. Revising paragraph (a)(3)(iv);
0
c. Revising paragraph (a)(4) introductory text;
0
d. Adding paragraph (a)(4)(iv);
0
e. Revising paragraph (a)(8) introductory text;
0
f. Revising paragraph (a)(8)(i); and
0
g. Adding paragraph (b) to read as follows:


Sec.  60.105  Monitoring of emissions and operations.

    (a) * * *
    (3) For fuel gas combustion devices subject to Sec.  60.104(a)(1), 
either an instrument for continuously monitoring and recording the 
concentration by volume (dry basis, zero percent excess air) of 
SO2 emissions into the atmosphere or monitoring as provided 
in paragraph (a)(4) of this section). * * *
* * * * *
    (iv) Fuel gas combustion devices having a common source of fuel gas 
may be monitored at only one location (i.e., after one of the 
combustion devices), if monitoring at this location accurately 
represents the SO2 emissions into the atmosphere from each 
of the combustion devices.
    (4) Instead of the SO2 monitor in paragraph (a)(3) of 
this section for fuel gas combustion devices subject to Sec.  
60.104(a)(1), an instrument for continuously monitoring and recording 
the concentration (dry basis) of H2S in fuel gases before 
being burned in any fuel gas combustion device.
* * * * *
    (iv) The owner or operator of a fuel gas combustion device is not 
required to comply with paragraph (a)(3) or (4) of this section for 
fuel gas streams that are exempt under Sec.  60.104(a)(1) and fuel gas 
streams combusted in a fuel gas combustion device that are inherently 
low in sulfur content. Fuel gas streams meeting one of the requirements 
in paragraphs (a)(4)(iv)(A) through (D) of this section will be 
considered inherently low in sulfur content. If the composition of a 
fuel gas stream changes such that it is no longer exempt under Sec.  
60.104(a)(1) or it no longer meets one of the requirements in 
paragraphs (a)(4)(iv)(A) through (D) of this section, the owner or 
operator must begin continuous monitoring under paragraph (a)(3) or (4) 
of this section within 15 days of the change.
    (A) Pilot gas for heaters and flares.
    (B) Fuel gas streams that meet a commercial-grade product 
specification for sulfur content of 30 ppmv or less. In the case of a 
liquefied petroleum gas (LPG) product specification in the pressurized 
liquid state, the gas phase sulfur content should be evaluated assuming 
complete vaporization of the LPG and sulfur containing-compounds at the 
product specification concentration.
    (C) Fuel gas streams produced in process units that are intolerant 
to sulfur contamination, such as fuel gas streams produced in the 
hydrogen plant, the catalytic reforming unit, the isomerization unit, 
and HF alkylation process units.
    (D) Other fuel gas streams that an owner or operator demonstrates 
are low-sulfur according to the procedures in paragraph (b) of this 
section.
* * * * *
    (8) An instrument for continuously monitoring and recording 
concentrations of SO2 in the gases at both the inlet and 
outlet of the SO2 control device from any fluid catalytic 
cracking unit catalyst regenerator for which the owner or operator 
seeks to comply specifically with the 90 percent reduction option under 
Sec.  60.104(b)(1).
    (i) The span value of the inlet monitor shall be set at 125 percent 
of the maximum estimated hourly potential SO2 emission 
concentration entering the control device, and the span value of the 
outlet monitor shall be set at 50 percent of the maximum estimated 
hourly potential SO2 emission concentration entering the 
control device.
* * * * *
    (b) An owner or operator may demonstrate that a fuel gas stream 
combusted in a fuel gas combustion device subject to Sec.  60.104(a)(1) 
that is not specifically exempted in Sec.  60.105(a)(4)(iv) is 
inherently low in sulfur. A fuel gas stream that is determined to be 
low-sulfur is exempt from the monitoring requirements in paragraphs 
(a)(3) and (4) of this section until there are changes in operating 
conditions or stream composition.
    (1) The owner or operator shall submit to the Administrator a 
written application for an exemption from monitoring. The application 
must contain the following information:
    (i) A description of the fuel gas stream/system to be considered, 
including submission of a portion of the appropriate piping diagrams 
indicating the boundaries of the fuel gas stream/system, and the 
affected fuel gas combustion device(s) to be considered;
    (ii) A statement that there are no crossover or entry points for 
sour gas (high H2S content) to be introduced into the fuel 
gas stream/system (this should be shown in the piping diagrams);
    (iii) An explanation of the conditions that ensure low amounts of 
sulfur in the fuel gas stream (i.e., control equipment or product 
specifications) at all times;
    (iv) The supporting test results from sampling the requested fuel 
gas stream/system demonstrating that the sulfur content is less than 5 
ppmv. Sampling data must include, at minimum, 2 weeks of daily 
monitoring (14 grab samples) for frequently operated fuel gas streams/
systems; for infrequently operated fuel gas streams/systems,

[[Page 35867]]

seven grab samples must be collected unless other additional 
information would support reduced sampling. The owner or operator shall 
use detector tubes (``length-of-stain tube'' type measurement) 
following the ``Gas Processors Association Standard 2377-86, Test for 
Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using Length of 
Stain Tubes,'' 1986 Revision (incorporated by reference--see Sec.  
60.17), with ranges 0-10/0-100 ppm (N = 10/1) to test the applicant 
fuel gas stream for H2S; and
    (v) A description of how the 2 weeks (or seven samples for 
infrequently operated fuel gas streams/systems) of monitoring results 
compares to the typical range of H2S concentration (fuel 
quality) expected for the fuel gas stream/system going to the affected 
fuel gas combustion device (e.g., the 2 weeks of daily detector tube 
results for a frequently operated loading rack included the entire 
range of products loaded out, and, therefore, should be representative 
of typical operating conditions affecting H2S content in the 
fuel gas stream going to the loading rack flare).
    (2) The effective date of the exemption is the date of submission 
of the information required in paragraph (b)(1) of this section).
    (3) No further action is required unless refinery operating 
conditions change in such a way that affects the exempt fuel gas 
stream/system (e.g., the stream composition changes). If such a change 
occurs, the owner or operator will follow the procedures in paragraph 
(b)(3)(i), (b)(3)(ii), or (b)(3)(iii) of this section.
    (i) If the operation change results in a sulfur content that is 
still within the range of concentrations included in the original 
application, the owner or operator shall conduct an H2S test 
on a grab sample and record the results as proof that the concentration 
is still within the range.
    (ii) If the operation change results in a sulfur content that is 
outside the range of concentrations included in the original 
application, the owner or operator may submit new information following 
the procedures of paragraph (b)(1) of this section within 60 days (or 
within 30 days after the seventh grab sample is tested for infrequently 
operated process units).
    (iii) If the operation change results in a sulfur content that is 
outside the range of concentrations included in the original 
application and the owner or operator chooses not to submit new 
information to support an exemption, the owner or operator must begin 
H2S monitoring using daily stain sampling to demonstrate 
compliance. The owner or operator must begin monitoring according to 
the requirements in paragraphs (a)(1) or (a)(2) of this section as soon 
as practicable but in no case later than 180 days after the operation 
change. During daily stain tube sampling, a daily sample exceeding 162 
ppmv is an exceedance of the 3-hour H2S concentration limit. 
The owner or operator must determine a rolling 365-day average using 
the stain sampling results; an average H2S concentration of 
5 ppmv must be used for days prior to the operation change.
* * * * *

0
8. Section 60.106 is amended by revising paragraph (b)(3) introductory 
text and revising the first sentence of paragraph (e)(2) to read as 
follows:


Sec.  60.106  Test methods and procedures.

* * * * *
    (b) * * *
    (3) The coke burn-off rate (Rc) shall be computed for 
each run using the following equation:

 Rc = K1Qr (%CO2 + %CO) + 
K2Qa-K3Qr (%CO/2 + 
%CO2 + %O2) + K3Qoxy 
(%Ooxy)

Where:

Rc = Coke burn-off rate, kilograms per hour (kg/hr) (lb/
hr).
Qr = Volumetric flow rate of exhaust gas from fluid 
catalytic cracking unit regenerator before entering the emission 
control system, dscm/min (dscf/min).
Qa = Volumetric flow rate of air to fluid catalytic 
cracking unit regenerator, as determined from the fluid catalytic 
cracking unit control room instrumentation, dscm/min (dscf/min).
Qoxy = Volumetric flow rate of O2 enriched air 
to fluid catalytic cracking unit regenerator, as determined from the 
fluid catalytic cracking unit control room instrumentation, dscm/min 
(dscf/min).
%CO2 = Carbon dioxide concentration in fluid catalytic 
cracking unit regenerator exhaust, percent by volume (dry basis).
%CO = CO concentration in FCCU regenerator exhaust, percent by 
volume (dry basis).
%O2 = O2 concentration in fluid catalytic 
cracking unit regenerator exhaust, percent by volume (dry basis).
%Ooxy = O2 concentration in O2 
enriched air stream inlet to the fluid catalytic cracking unit 
regenerator, percent by volume (dry basis).
K1 = Material balance and conversion factor, 0.2982 (kg-
min)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)].
K2 = Material balance and conversion factor, 2.088 (kg-
min)/(hr-dscm) [0.1303 (lb-min)/(hr-dscf)].
K3 = Material balance and conversion factor, 0.0994 (kg-
min)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].
* * * * *
    (e) * * *
    (2) Where emissions are monitored by Sec.  60.105(a)(3), compliance 
with Sec.  60.104(a)(1) shall be determined using Method 6 or 6C and 
Method 3 or 3A. The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust 
Gas Analyses,'' (incorporated by reference--see Sec.  60.17) is an 
acceptable alternative to EPA Method 6. * * *
* * * * *
0
9. Section 60.107 is amended by:
0
a. Revising the first sentence of paragraph (c)(1)(i);
0
b. Redesignating paragraphs (e) and (f) as (f) and (g); and
0
c. Adding paragraph (e) to read as follows:


Sec.  60.107  Reporting and recordkeeping requirements.

* * * * *
    (c) * * *
    (1) * * *
    (i) The average percent reduction and average concentration of 
sulfur dioxide on a dry, O2-free basis in the gases 
discharged to the atmosphere from any fluid cracking unit catalyst 
regenerator for which the owner or operator seeks to comply with Sec.  
60.104(b)(1) is below 90 percent and above 50 ppmv, as measured by the 
continuous monitoring system prescribed under Sec.  60.105(a)(8), or 
above 50 ppmv, as measured by the outlet continuous monitoring system 
prescribed under Sec.  60.105(a)(9). * * *
* * * * *
    (e) For each fuel gas stream combusted in a fuel gas combustion 
device subject to Sec.  60.104(a)(1), if an owner or operator 
determines that one of the exemptions listed in Sec.  60.105(a)(4)(iv) 
applies to that fuel gas stream, the owner or operator shall maintain 
records of the specific exemption chosen for each fuel gas stream. If 
the owner or operator applies for the exemption described in Sec.  
60.105(a)(4)(iv)(D), the owner or operator must keep a copy of the 
application as well as the letter from the Administrator granting 
approval of the application.
* * * * *

0
10. Section 60.108 is amended by revising the last sentence of 
paragraph (e) to read as follows:


Sec.  60.108  Performance test and compliance provisions.

* * * * *
    (e) * * * The owner or operator shall furnish the Administrator 
with a written notification of the change in the semiannual report 
required by Sec.  60.107(f).

0
11. Part 60 is amended by adding subpart Ja to read as follows:

[[Page 35868]]

Subpart Ja--Standards of Performance for Petroleum Refineries for Which 
Construction, Reconstruction, or Modification Commenced After May 14, 
2007
Sec.
60.100a Applicability, designation of affected facility, and 
reconstruction.
60.101a Definitions.
60.102a Emissions limitations.
60.103a Work practice standards.
60.104a Performance tests.
60.105a Monitoring of emissions and operations for fluid catalytic 
cracking units (FCCU) and fluid coking units (FCU).
60.106a Monitoring of emissions and operations for sulfur recovery 
plants.
60.107a Monitoring of emissions and operations for process heaters 
and other fuel gas combustion devices.
60.108a Recordkeeping and reporting requirements.
60.109a Delegation of authority.

Subpart Ja--Standards of Performance for Petroleum Refineries for 
Which Construction, Reconstruction, or Modification Commenced After 
May 14, 2007


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 flares and process heaters, and sulfur 
recovery plants. The sulfur recovery plant need not be physically 
located within the boundaries of a petroleum refinery to be an affected 
facility, provided it processes gases produced within a petroleum 
refinery.
    (b) Except for flares, the provisions of this subpart apply only to 
affected facilities under paragraph (a) of this section which commence 
construction, modification, or reconstruction after May 14, 2007. For 
flares, the provisions of this subpart apply only to flares which 
commence construction, modification, or reconstruction, after June 24, 
2008.
    (c) For the purposes of this subpart, under Sec.  60.14, a 
modification to a flare occurs if:
    (1) Any new piping from a refinery process unit or fuel gas system 
is physically connected to the flare (e.g., for direct emergency relief 
or some form of continuous or intermittent venting); or
    (2) A flare is physically altered to increase the flow capacity of 
the flare.
    (d) For purposes of this subpart, under 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 May 14, 2007. For purposes of this 
paragraph, ``commenced'' means that an owner or operator has undertaken 
a continuous program of component replacement or that an owner or 
operator has entered into a contractual obligation to undertake and 
complete, within a reasonable time, a continuous program of component 
replacement.


Sec.  60.101a  Definitions.

    Terms used in this subpart are defined in the Clean Air Act, in 
Sec.  60.2, and in this section.
    Coke burn-off means the coke removed from the surface of the FCCU 
catalyst by combustion in the catalyst regenerator. The rate of coke 
burn-off is calculated by the formula specified in Sec.  60.104a.
    Contact material means any substance formulated to remove metals, 
sulfur, nitrogen, or any other contaminant from petroleum derivatives.
    Delayed coking unit means one or more refinery process units in 
which high molecular weight petroleum derivatives are thermally cracked 
and petroleum coke is produced in a series of closed, batch system 
reactors.
    Flare means an open-flame fuel gas combustion device used for 
burning off unwanted gas or flammable gas and liquids. The flare 
includes the foundation, flare tip, structural support, burner, 
igniter, flare controls including air injection or steam injection 
systems, flame arrestors, knockout pots, piping and header systems.
    Flexicoking unit means one or more refinery process units in which 
high molecular weight petroleum derivatives are thermally cracked and 
petroleum coke is continuously produced and then gasified to produce a 
synthetic fuel gas.
    Fluid catalytic cracking unit means a refinery process unit in 
which petroleum derivatives are continuously charged and hydrocarbon 
molecules in the presence of a catalyst suspended in a fluidized bed 
are fractured into smaller molecules, or react with a contact material 
suspended in a fluidized bed to improve feedstock quality for 
additional processing and the catalyst or contact material is 
continuously regenerated by burning off coke and other deposits. The 
unit includes the riser, reactor, regenerator, air blowers, spent 
catalyst or contact material stripper, catalyst or contact material 
recovery equipment, and regenerator equipment for controlling air 
pollutant emissions and for heat recovery. When fluid catalyst cracking 
unit regenerator exhaust from two separate fluid catalytic cracking 
units share a common exhaust treatment (e.g., CO boiler or wet 
scrubber), the fluid catalytic cracking unit is a single affected 
facility.
    Fluid coking unit means one or more refinery process units in which 
high molecular weight petroleum derivatives are thermally cracked and 
petroleum coke is continuously produced in a fluidized bed system. The 
fluid coking unit includes equipment for controlling air pollutant 
emissions and for heat recovery on the fluid coking burner exhaust 
vent.
    Fuel gas means any gas which is generated at a petroleum refinery 
and which is combusted. Fuel gas includes natural gas when the natural 
gas is combined and combusted in any proportion with a gas generated at 
a refinery. Fuel gas does not include gases generated by catalytic 
cracking unit catalyst regenerators and fluid coking burners, but does 
include gases from flexicoking unit gasifiers. Fuel gas does not 
include vapors that are collected and combusted to comply with the 
wastewater provisions in Sec.  60.692, 40 CFR 61.343 through 61.348, 40 
CFR 63.647, or the marine tank vessel loading provisions in 40 CFR 
63.562 or 40 CFR 63.651.
    Fuel gas combustion device means any equipment, such as process 
heaters, boilers, and flares, used to combust fuel gas, except 
facilities in which gases are combusted to produce sulfur or sulfuric 
acid.
    Fuel gas system means a system of compressors, piping, knock-out 
pots, mix drums, and units used to remove sulfur contaminants from the 
fuel gas (e.g., amine scrubbers) that collects refinery fuel gas from 
one or more sources for treatment as necessary prior to combusting in 
process heaters or boilers. A fuel gas system may have an overpressure 
vent to a flare but the primary purpose for a fuel gas system is to 
provide fuel to the refinery.
    Oxidation control system means an emission control system which 
reduces emissions from sulfur recovery plants by converting these 
emissions to sulfur dioxide (SO2) and recycling the 
SO2 to the reactor furnace or the first-stage catalytic 
reactor of the Claus sulfur recovery plant or converting the 
SO2 to a sulfur product.
    Petroleum means the crude oil removed from the earth and the oils 
derived from tar sands, shale, and coal.
    Petroleum refinery means any facility engaged in producing 
gasoline, kerosene, distillate fuel oils, residual fuel oils, 
lubricants, asphalt (bitumen)

[[Page 35869]]

or other products through distillation of petroleum or through 
redistillation, cracking, or reforming of unfinished petroleum 
derivatives.
    Process heater means an enclosed combustion device used to transfer 
heat indirectly to process stream materials (liquids, gases, or solids) 
or to a heat transfer material for use in a process unit instead of 
steam.
    Process upset gas means any gas generated by a petroleum refinery 
process unit as a result of upset or malfunction.
    Reduced sulfur compounds means hydrogen sulfide (H2S), 
carbonyl sulfide, and carbon disulfide.
    Reduction control system means an emission control system which 
reduces emissions from sulfur recovery plants by converting these 
emissions to H2S and either recycling the H2S to 
the reactor furnace or the first-stage catalytic reactor of the Claus 
sulfur recovery plant or converting the H2S to a sulfur 
product.
    Refinery process unit means any segment of the petroleum refinery 
in which a specific processing operation is conducted.
    Sulfur pit means the storage vessel in which sulfur that is 
condensed after each Claus catalytic reactor is initially accumulated 
and stored. A sulfur pit does not include secondary sulfur storage 
vessels downstream of the initial Claus reactor sulfur pits.
    Sulfur recovery plant means all process units which recover sulfur 
from HS2 and/or SO2 at a petroleum refinery. The 
sulfur recovery plant also includes sulfur pits used to store the 
recovered sulfur product, but it does not include secondary sulfur 
storage vessels downstream of the sulfur pits. For example, a Claus 
sulfur recovery plant includes: Reactor furnace and waste heat boiler, 
catalytic reactors, sulfur pits, and, if present, oxidation or 
reduction control systems, or incinerator, thermal oxidizer, or similar 
combustion device. Multiple sulfur recovery units are a single affected 
facility only when the units share the same source of sour gas. Sulfur 
recovery plants that receive source gas from completely segregated sour 
gas treatment systems are separate affected facilities.


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 (h) 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.
    (b) An owner or operator subject to the provisions of this subpart 
shall not discharge or cause the discharge into the atmosphere from any 
FCCU or FCU:
    (1) Particulate matter (PM) in excess of the limits in paragraphs 
(b)(1)(i), (ii), or (iii) of this section.
    (i) 1.0 kilogram per Megagram (kg/Mg)(1 pound (lb) per 1,000 lb) 
coke burn-off or, if a PM continuous emission monitoring system (CEMS) 
is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 
0 percent excess air for each modified or reconstructed FCCU.
    (ii) 0.5 gram per kilogram (g/kg) coke burn-off (0.5 lb PM/1,000 lb 
coke burn-off) or, if a PM CEMS is used, 0.020 gr/dscf corrected to 0 
percent excess air for each newly constructed FCCU.
    (iii) 1.0 kg/Mg (1 lb/1,000 lb) coke burn-off; or if a PM CEMS is 
used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 
percent excess air for each affected FCU.
    (2) Nitrogen oxides (NOX) in excess of 80 parts per 
million by volume (ppmv), dry basis corrected to 0 percent excess air, 
on a 7-day rolling average basis.
    (3) Sulfur dioxide (SO2) in excess of 50 ppmv dry basis 
corrected to 0 percent excess air, on a 7-day rolling average basis and 
25 ppmv, dry basis corrected to 0 percent excess air, on a 365-day 
rolling average basis.
    (4) Carbon monoxide (CO) in excess of 500 ppmv, dry basis corrected 
to 0 percent excess air, on an hourly average basis.
    (c) The owner or operator of a FCCU or FCU that uses a continuous 
parameter monitoring system (CPMS) according to Sec.  60.105a(b)(1) 
shall comply with the applicable control device parameter operating 
limit in paragraph (c)(1) or (2) of this section.
    (1) If the FCCU or FCU is controlled using an electrostatic 
precipitator:
    (i) The 3-hour rolling average total power and secondary current to 
the entire system must not fall below the level established during the 
most recent performance test; and
    (ii) The daily average exhaust coke burn-off rate must not exceed 
the level established during the most recent performance test.
    (2) If the FCCU or FCU is controlled using a wet scrubber:
    (i) The 3-hour rolling average pressure drop must not fall below 
the level established during the most recent performance test; and
    (ii) The 3-hour rolling average liquid-to-gas ratio must not fall 
below the level established during the most recent performance test.
    (d) If an FCCU or FCU uses a continuous opacity monitoring system 
(COMS) according to the alternative monitoring option in Sec.  
60.105a(e), the 3-hour rolling average opacity of emissions from the 
FCCU or FCU as measured by the COMS must not exceed the site-specific 
opacity limit established during the most recent performance test.
    (e) The owner or operator of a FCCU or FCU that is exempted from 
the requirement for a CO continuous emissions monitoring system under 
Sec.  60.105a(h)(3) shall comply with the parameter operating limits in 
paragraph (e)(1) or (2) of this section.
    (1) For a FCCU or FCU with no post-combustion control device:
    (i) The hourly average temperature of the exhaust gases exiting the 
FCCU or FCU must not fall below the level established during the most 
recent performance test.
    (ii) The hourly average oxygen (O2) concentration of the 
exhaust gases exiting the FCCU or FCU must not fall below the level 
established during the most recent performance test.
    (2) For a FCCU or FCU with a post-combustion control device:
    (i) The hourly average temperature of the exhaust gas vent stream 
exiting the control device must not fall below the level established 
during the most recent performance test.
    (ii) The hourly average O2 concentration of the exhaust 
gas vent stream exiting the control device must not fall below the 
level established during the most recent performance test.
    (f) Except as provided in paragraph (f)(3), each owner or operator 
of an affected sulfur recovery plant shall comply with the applicable 
emission limits in paragraphs (f)(1) or (2) of this section.
    (1) For a sulfur recovery plant with a capacity greater than 20 
long tons per day (LTD):
    (i) For a sulfur recovery plant with an oxidation control system or 
a reduction control system followed by incineration, the owner or 
operator shall not discharge or cause the discharge of any gases into 
the atmosphere in excess of 250 ppm by volume (dry basis) of sulfur 
dioxide (SO2) at zero percent excess air. If the sulfur 
recovery plant consists of multiple process trains or release points 
the owner or operator shall comply with the 250 ppmv limit for each 
process train or release point or comply with a flow rate weighted 
average of 250 ppmv for all release points from the sulfur recovery 
plant; or

[[Page 35870]]

    (ii) For sulfur recovery plant with a reduction control system not 
followed by incineration, the owner or operator shall not discharge or 
cause the discharge of any gases into the atmosphere in excess of 300 
ppm by volume of reduced sulfur compounds and 10 ppm by volume of 
hydrogen sulfide (HS2), each calculated as ppm 
SO2 by volume (dry basis) at zero percent excess air; or
    (iii) For systems using oxygen enrichment, the owner or operator 
shall calculate the applicable emission limit using Equation 1 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR24JN08.000

Where:

ELS = Emission rate of SO2 for large sulfur 
recovery plant, ppmv;
k1 = Constant factor for emission limit conversion: 
k1 = 1 for converting to SO2 limit and 
k1 = 1.2 for converting to the reduced sulfur compounds 
limit; and
%O2 = O2 concentration to the SRP, percent by 
volume (dry basis).

    (2) For a sulfur recovery plant with a capacity of 20 LTD or less:
    (i) For a sulfur recovery plant with an oxidation control system or 
a reduction control system followed by incineration, the owner or 
operator shall not discharge or cause the discharge of any gases into 
the atmosphere in excess of 2,500 ppm by volume (dry basis) of 
SO2 at zero percent excess air. If the sulfur recovery plant 
consists of multiple process trains or release points the owner or 
operator shall comply with the 2,500 ppmv limit for each process train 
or release point or comply with a flow rate weighted average of 2,500 
ppmv for all release points from the sulfur recovery plant; or
    (ii) For sulfur recovery plant with a reduction control system not 
followed by incineration, the owner or operator shall not discharge or 
cause the discharge of any gases into the atmosphere in excess of 3,000 
ppm by volume of reduced sulfur compounds and 100 ppm by volume of 
hydrogen sulfide (H2S), each calculated as ppm SO2 by volume 
(dry basis) at zero percent excess air; or
    (iii) For systems using oxygen enrichment, the owner or operator 
shall calculate the applicable emission limit using Equation 2 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR24JN08.001

Where:

ESS = Emission rate of SO2 for small sulfur 
recovery plant, ppmv.

    (3) Periods of maintenance of the sulfur pit, during which the 
emission limits in paragraphs (f)(1) and (2) shall not apply, shall not 
exceed 240 hours per year. The owner or operator must document the time 
periods during which the sulfur pit vents were not controlled and 
measures taken to minimize emissions during these periods. Examples of 
these measures include not adding fresh sulfur or shutting off vent 
fans.
    (g) Each owner or operator of an affected fuel gas combustion 
device shall comply with the emission limits in paragraphs (g)(1) 
through (3) of this section.
    (1) For each fuel gas combustion device, the owner or operator 
shall comply with either the emission limit in paragraph (g)(1)(i) of 
this section or the fuel gas concentration limit in paragraph 
(g)(1)(ii) of this section.
    (i) The owner or operator shall not discharge or cause the 
discharge of any gases into the atmosphere that contain SO2 
in excess of 20 ppmv (dry basis, corrected to 0 percent excess air) 
determined hourly on a 3-hour rolling average basis and SO2 
in excess of 8 ppmv (dry basis, corrected to 0 percent excess air), 
determined daily on a 365 successive day rolling average basis; or
    (ii) The owner or operator shall not burn in any fuel gas 
combustion device any fuel gas that contains H2S in excess 
of 162 ppmv determined hourly on a 3-hour rolling average basis and 
H2S in excess of 60 ppmv determined daily on a 365 
successive calendar day rolling average basis.
    (2) For each process heater with a rated capacity of greater than 
40 million British thermal units per hour (MMBtu/hr), the owner or 
operator shall not discharge to the atmosphere any emissions of 
NOX in excess of 40 ppmv (dry basis, corrected to 0 percent 
excess air) on a 24-hour rolling average basis.
    (3) Except as provided in paragraphs (h) and (i) of this section, 
the owner or operator of an affected flare shall not allow flow to each 
affected flare during normal operations of more than 7,080 standard 
cubic meters per day (m3/day) (250,000 standard cubic feet 
per day (scfd)) on a 30-day rolling average. The owner or operator of a 
newly constructed or reconstructed flare shall comply with the emission 
limit in this paragraph by no later than the date that flare becomes an 
affected flare subject to this subpart. The owner or operator of a 
modified flare shall comply with the emission limit in this paragraph 
by no later than 1 year after that flare becomes an affected flare 
subject to this subpart.
    (h) The combustion in a flare of process upset gases or fuel gas 
that is released to the flare as a result of relief valve leakage or 
other emergency malfunctions is exempt from paragraph (g) of this 
section.
    (i) In periods of fuel gas imbalance that are described in the 
flare management plan required in section 60.103a(a), compliance with 
the emission limit in paragraph (g)(3) of this section is demonstrated 
by following the procedures and maintaining records described in the 
flare management plan to document the periods of excess fuel gas.


Sec.  60.103a  Work practice standards.

    (a) Each owner or operator that operates a flare that is subject to 
this subpart shall develop and implement a written flare management 
plan. The owner or operator of a newly constructed or reconstructed 
flare must develop and implement the flare management plan by no later 
than the date that flare becomes an affected flare subject to this 
subpart. The owner or operator of a modified flare must develop and 
implement the flare management plan by no later than 1 year after the 
flare becomes an affected flare subject to this subpart. The plan must 
include:
    (1) A diagram illustrating all connections to the flare;
    (2) Methods for monitoring flow rate to the flare, including a 
detailed

[[Page 35871]]

description of the manufacturer's specifications, including but not 
limited to, make, model, type, range, precision, accuracy, calibration, 
maintenance, and quality assurance procedures for flare gas monitoring 
devices;
    (3) Procedures to minimize discharges to the flare gas system 
during the planned start-up and shutdown of the refinery process units 
that are connected to the affected flare;
    (4) Procedures to conduct a root cause analysis of any process 
upset or malfunction that causes a discharge to the flare in excess of 
14,160 m\3\/day (500,000 scfd);
    (5) Procedures to reduce flaring in cases of fuel gas imbalance 
(i.e., excess fuel gas for the refinery's energy needs); and
    (6) Explanation of procedures to follow during times that the flare 
must exceed the limit in Sec.  60.102a(g)(3) (e.g., keep records of 
natural gas purchases to support assertion that the refinery is 
producing more fuel gas than needed to operate the processes).
    (b) Each owner or operator that operates a fuel gas combustion 
device or sulfur recovery plant subject to this subpart shall conduct a 
root cause analysis of any emission limit exceedance or process start-
up, shutdown, upset, or malfunction that causes a discharge to the 
atmosphere in excess of 227 kilograms per day (kg/day) (500 lb per day 
(lb/day)) of SO2. For any root cause analysis performed, the owner or 
operator shall record the identification of the affected facility, the 
date and duration of the discharge, the results of the root cause 
analysis, and the action taken as a result of the root cause analysis. 
The first root cause analysis for a modified flare must be conducted no 
later than the first discharge that occurs after the flare has been an 
affected flare subject to this subpart for 1 year.
    (c) Each owner or operator of a delayed coking unit shall 
depressure to 5 lb per square inch gauge (psig) during reactor vessel 
depressuring and vent the exhaust gases to the fuel gas system for 
combustion in a fuel gas combustion device.


Sec.  60.104a  Performance tests.

    (a) The owner or operator shall conduct a performance test for each 
FCCU, FCU, sulfur recovery plant, and fuel gas combustion device to 
demonstrate initial compliance with each applicable emissions limit in 
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.
    (b) The owner or operator of a FCCU or FCU that elects to monitor 
control device operating parameters according to the requirements in 
Sec.  60.105a(b), to use bag leak detectors according to the 
requirements in Sec.  60.105a(c), or to use COMS according to the 
requirements in Sec.  60.105a(e) shall conduct a PM performance test at 
least once every 12 months and furnish the Administrator a written 
report of the results of each test.
    (c) In conducting the performance tests required by this subpart 
(or as requested by the Administrator), the owner or operator shall use 
the test methods in 40 CFR part 60, Appendices A-1 through A-8 or other 
methods as specified in this section, except as provided in Sec.  
60.8(b).
    (d) The owner or operator shall determine compliance with the PM, 
NOX, SO2, and CO emissions limits in Sec.  60.102a(b) for FCCU and FCU 
using the following methods and procedures:
    (1) Method 1 of Appendix A-1 to part 60 for sample and velocity 
traverses.
    (2) Method 2 of Appendix A-1 to part 60 for velocity and volumetric 
flow rate.
    (3) Method 3, 3A, or 3B of Appendix A-2 to part 60 for gas 
analysis. The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas 
Analyses,'' (incorporated by reference--see Sec.  60.17) is an 
acceptable alternative to EPA Method 3B of Appendix A-2 to part 60.
    (4) Method 5, 5B, or 5F of Appendix A-3 to part 60 for determining 
PM emissions and associated moisture content from a FCCU or FCU without 
a wet scrubber subject to the emissions limit in Sec.  63.102a(b)(1). 
Use Method 5 or 5B of Appendix A-3 to part 60 for determining PM 
emissions and associated moisture content from a FCCU or FCU with a wet 
scrubber subject to the emissions limit in Sec.  63.102a(b)(1).
    (i) The PM performance test consists of 3 valid test runs; the 
duration of each test run must be no less than 60 minutes.
    (ii) The emissions rate of PM (EPM) is computed for each 
run using Equation 3 of this section:
[GRAPHIC] [TIFF OMITTED] TR24JN08.002

Where:

E = Emission rate of PM, g/kg, lbs per 1,000 lbs (lb/1,000 lbs) of 
coke burn-off;
cs = Concentration of total PM, grams per dry standard cubic meter 
(g/dscm), gr/dscf;
Qsd = Volumetric flow rate of effluent gas, dry standard cubic 
meters per hour, dry standard cubic feet per hour;
Rc = Coke burn-off rate, kilograms per hour (kg/hr), lbs per hour 
(lbs/hr) coke; and
K = Conversion factor, 1.0 grams per gram (7,000 grains per lb).

    (iii) The coke burn-off rate (Rc) is computed for each run using 
Equation 4 of this section:
[GRAPHIC] [TIFF OMITTED] TR24JN08.003

Where:

Rc = Coke burn-off rate, kg/hr (lb/hr);
Qr = Volumetric flow rate of exhaust gas from FCCU regenerator or 
fluid coking burner before any emissions control or energy recovery 
system that burns auxiliary fuel, dry standard cubic meters per 
minute (dscm/min), dry standard cubic feet per minute (dscf/min);
Qa = Volumetric flow rate of air to FCCU regenerator or fluid coking 
burner, as determined from the unit's control room instrumentation, 
dscm/min (dscf/min);
Qoxy = Volumetric flow rate of O2 enriched air to FCCU 
regenerator or fluid coking unit, as determined from the unit's 
control room instrumentation, dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in FCCU regenerator or fluid 
coking burner exhaust, percent by volume (dry basis);
%CO = CO concentration in FCCU regenerator or fluid coking burner 
exhaust, percent by volume (dry basis);
%O2 = O2 concentration in FCCU regenerator or fluid 
coking burner exhaust, percent by volume (dry basis);
%Ooxy = O2 concentration in O2 enriched air stream inlet to the FCCU 
regenerator or fluid coking burner, percent by volume (dry basis);
K1 = Material balance and conversion factor, 0.2982 (kg-min)/(hr-
dsc-%) [0.0186 (lb-min)/(hr-dscf-%)];
K2 = Material balance and conversion factor, 2.088 (kg-min)/(hr-
dscm) [0.1303 (lb-min)/(hr-dscf)]; and

[[Page 35872]]

K3 = Material balance and conversion factor, 0.0994 (kg-min)/(hr-
dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].

    (iv) During the performance test, the volumetric flow rate of 
exhaust gas from catalyst regenerator (Qr) before any emission control 
or energy recovery system that burns auxiliary fuel is measured using 
Method 2 of Appendix A-1 to part 60.
    (v) For subsequent calculations of coke burn-off rates or exhaust 
gas flow rates, the volumetric flow rate of Qr is calculated using 
average exhaust gas concentrations as measured by the monitors in Sec.  
60.105a(b)(2), if applicable, using Equation 5 of this section:

[GRAPHIC] [TIFF OMITTED] TR24JN08.004

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(g)(3), assume %CO to be zero;
%O2 = O2 concentration in FCCU regenerator or fluid coking burner 
exhaust, percent by volume (dry basis); and
%Ooxy = O2 concentration in O2 enriched air stream inlet 
to the FCCU regenerator or fluid coking burner, percent by volume 
(dry basis).

    (5) Method 6, 6A, or 6C of Appendix A-4 to part 60 for moisture 
content and for the concentration of SO2; the duration of each test run 
must be no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, 
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see 
Sec.  60.17) is an acceptable alternative to EPA Method 6 or 6A of 
Appendix A-4 to part 60.
    (6) Method 7, 7A, 7C, 7D, or 7E of Appendix A-4 to part 60 for 
moisture content and for the concentration of NOX calculated as 
nitrogen dioxide (NO2); the duration of each test run must be no less 
than 4 hours. The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust 
Gas Analyses,'' (incorporated by reference--see Sec.  60.17) is an 
acceptable alternative to EPA Method 7 or 7C of Appendix A-4 to part 
60.
    (7) Method 10, 10A, or 10B of Appendix A-4 to part 60 for moisture 
content and for the concentration of CO. The sampling time for each run 
must be 60 minutes.
    (8) The owner or operator shall adjust PM, NOX, SO2, and CO 
pollutant concentrations to 0 percent excess air or 0 percent O2 using 
Equation 6 of this section:

[GRAPHIC] [TIFF OMITTED] TR24JN08.005

Where:

Cadj = pollutant concentration adjusted to 0 percent excess air or 
O2, parts per million (ppm) or g/dscm;
Cmeas = pollutant concentration measured on a dry basis, ppm or g/
dscm;
20.9c = 20.9 percent O2-0.0 percent O2 (defined O2 correction 
basis), percent;
20.9 = O2 concentration in air, percent; and
%O2 = O2 concentration measured on a dry basis, percent.

    (e) The owner or operator of a FCCU or FCU that is controlled by an 
electrostatic precipitator or wet scrubber and that is subject to 
control device operating parameter limits in Sec.  60.102a(c) shall 
establish the limits based on the performance test results according to 
the following procedures:
    (1) Reduce the parameter monitoring data to hourly averages for 
each test run;
    (2) Determine the hourly average operating limit for each required 
parameter as the average of the three test runs.
    (f) The owner or operator of an FCCU or FCU that uses cyclones to 
comply with the PM limit in Sec.  60.102a(b)(1) and elects to comply 
with the COMS alternative monitoring option in Sec.  60.105a(d) shall 
establish a site-specific opacity operating limit according to the 
procedures in paragraphs (f)(1) through (3) of this section.
    (1) Collect COMS data every 10 seconds during the entire period of 
the PM performance test and reduce the data to 6-minute averages.
    (2) Determine and record the hourly average opacity from all the 6-
minute averages.
    (3) Compute the site-specific limit using Equation 7 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR24JN08.006

Where:

Opacity limit = Maximum permissible hourly average opacity, percent, 
or 10 percent, whichever is greater;
Opacityst = Hourly average opacity measured during the source test 
runs, percent; and
PMEmRst = PM emission rate measured during the source test, lb/1,000 
lbs coke burn.

    (g) The owner or operator of a FCCU or FCU that is exempt from the 
requirement to install and operate a CO CEMS pursuant to Sec.  
60.105a(h)(3) and that is subject to control device operating parameter 
limits in Sec.  60.102a(c) shall establish the limits based on the 
performance test results

[[Page 35873]]

using the procedures in paragraphs (g)(1) and (2) of this section.
    (1) Reduce the temperature and O2 concentrations from the parameter 
monitoring systems to hourly averages for each test run.
    (2) Determine the operating limit for temperature and O2 
concentrations as the average of the average temperature and O2 
concentration for the three test runs.
    (h) The owner or operator shall determine compliance with the SO2 
and H2S emissions limits for sulfur recovery plants in Sec. Sec.  
60.102a(f)(1)(i), 60.102a(f)(1)(iii), 60.102a(f)(1)(iii), 
60.102a(f)(2)(i), and 60.102a(f)(2)(iii) and the reduced sulfur 
compounds and H2S emissions limits for sulfur recovery plants in Sec.  
60.102a(f)(1)(ii) and Sec.  60.102a(f)(2)(ii) using the following 
methods and procedures:
    (1) Method 1 of Appendix A-1 to part 60 for sample and velocity 
traverses.
    (2) Method 2 of Appendix A-1 to part 60 for velocity and volumetric 
flow rate.
    (3) Method 3, 3A, or 3B of Appendix A-2 to part 60 for gas 
analysis. The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas 
Analyses,'' (incorporated by reference--see Sec.  60.17) is an 
acceptable alternative to EPA Method 3B of Appendix A-2 to part 60.
    (4) Method 6, 6A, or 6C of Appendix A-4 to part 60 to determine the 
SO2 concentration. The method ANSI/ASME PTC 19.10-1981, ``Flue and 
Exhaust Gas Analyses,'' (incorporated by reference--see Sec.  60.17) is 
an acceptable alternative to EPA Method 6 or 6A of Appendix A-4 to part 
60.
    (5) Method 15 or 15A of Appendix A-5 to part 60 or Method 16 of 
Appendix A-6 to part 60 to determine the reduced sulfur compounds and 
H2S concentrations. The method ANSI/ASME PTC 19.10-1981, ``Flue and 
Exhaust Gas Analyses,'' (incorporated by reference--see Sec.  60.17) is 
an acceptable alternative to EPA Method 15A of Appendix A-5 to part 60.
    (i) Each run consists of 16 samples taken over a minimum of 3 
hours.
    (ii) The owner or operator shall calculate the average H2S 
concentration after correcting for moisture and O2 as the arithmetic 
average of the H2S concentration for each sample during the run (ppmv, 
dry basis, corrected to 0 percent excess air).
    (iii) The owner or operator shall calculate the SO2 equivalent for 
each run after correcting for moisture and O2 as the arithmetic average 
of the SO2 equivalent of reduced sulfur compounds for each sample 
during the run (ppmv, dry basis, corrected to 0 percent excess air).
    (iv) The owner or operator shall use Equation 6 of this section to 
adjust pollutant concentrations to 0 percent O2 or 0 percent excess 
air.
    (i) The owner or operator shall determine compliance with the SO2 
and NOX emissions limits in Sec.  60.102a(g) for a fuel gas combustion 
device according to the following test methods and procedures:
    (1) Method 1 of Appendix A-1 to part 60 for sample and velocity 
traverses;
    (2) Method 2 of Appendix A-1 to part 60 for velocity and volumetric 
flow rate;
    (3) Method 3, 3A, or 3B of Appendix A-2 to part 60 for gas 
analysis. The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas 
Analyses,'' (incorporated by reference--see Sec.  60.17) is an 
acceptable alternative to EPA Method 3B of Appendix A-2 to part 60;
    (4) Method 6, 6A, or 6C of Appendix A-4 to part 60 to determine the 
SO2 concentration. The method ANSI/ASME PTC 19.10-1981, 
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see 
Sec.  60.17) is an acceptable alternative to EPA Method 6 or 6A of 
Appendix A-4 to part 60.
    (i) The performance test consists of 3 valid test runs; the 
duration of each test run must be no less than 1 hour.
    (ii) If a single fuel gas combustion device having a common source 
of fuel gas is monitored as allowed under Sec.  60.107a(a)(1)(v), only 
one performance test is required. That is, performance tests are not 
required when a new affected fuel gas combustion device is added to a 
common source of fuel gas that previously demonstrated compliance.
    (5) Method 7, 7A, 7C, 7D, or 7E of Appendix A-4 to part 60 for 
moisture content and for the concentration of NOX calculated as NO2; 
the duration of each test run must be no less than 4 hours. The method 
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' 
(incorporated by reference--see Sec.  60.17) is an acceptable 
alternative to EPA Method 7 or 7C of Appendix A-4 to part 60.
    (j) The owner or operator shall determine compliance with the H2S 
emissions limit in Sec.  60.102a(g) for a fuel gas combustion device 
according to the following test methods and procedures:
    (1) Method 1 of Appendix A-1 to part 60 for sample and velocity 
traverses;
    (2) Method 2 of Appendix A-1 to part 60 for velocity and volumetric 
flow rate;
    (3) Method 3, 3A, or 3B of Appendix A-2 to part 60 for gas 
analysis. The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas 
Analyses,'' (incorporated by reference--see Sec.  60.17) is an 
acceptable alternative to EPA Method 3B of Appendix A-2 to part 60;
    (4) Method 11, 15, or 15A of Appendix A-5 to part 60 or Method 16 
of Appendix A-6 to part 60 for determining the H2S 
concentration for affected plants using an H2S monitor as 
specified in Sec.  60.107a(a)(2). The method ANSI/ASME PTC 19.10-1981, 
``Flue and Exhaust Gas Analyses,'' (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 for each 
individual fuel gas stream used in the fuel gas combustion device.
    (i) For Method 11 of Appendix A-5 to part 60, the sampling time and 
sample volume must be at least 10 minutes and 0.010 dscm (0.35 dscf). 
Two samples of equal sampling times must be taken at about 1-hour 
intervals. The arithmetic average of these two samples constitutes a 
run. For most fuel gases, sampling times exceeding 20 minutes may 
result in depletion of the collection solution, although fuel gases 
containing low concentrations of H2S may necessitate sampling for 
longer periods of time.
    (ii) For Method 15 of Appendix A-5 to part 60, at least three 
injects over a 1-hour period constitutes a run.
    (iii) For Method 15A of Appendix A-5 to part 60, a 1-hour sample 
constitutes a run. The method ANSI/ASME PTC 19.10-1981, ``Flue and 
Exhaust Gas Analyses,'' (incorporated by reference--see Sec.  60.17) is 
an acceptable alternative to EPA Method 15A of Appendix A-5 to part 60.
    (iv) If monitoring is conducted at a single point in a common 
source of fuel gas as allowed under 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 is added to a 
common source of fuel gas that previously demonstrated compliance.


Sec.  60.105a  Monitoring of emissions and operations for fluid 
catalytic cracking units (FCCU) and fluid coking units (FCU).

    (a) FCCU and FCU subject to PM emissions limit. Each owner or 
operator subject to the provisions of this subpart shall monitor each 
FCCU and FCU subject to the PM emissions limit in Sec.  60.102a(b)(1) 
according to the requirements in paragraph (b), (c), (d), or (e) of 
this section.
    (b) Control device operating parameters. Each owner or operator of 
a FCCU or FCU subject to the PM per coke burn-off emissions limit in 
Sec.  60.102a(b)(1) shall comply with the requirements in paragraphs 
(b)(1) through (3) of this section.

[[Page 35874]]

    (1) The owner or operator shall install, operate, and maintain 
continuous parameter monitor systems (CPMS) to measure and record 
operating parameters for each control device according to the 
requirements in paragraph (b)(1)(i) through (iii) of this section.
    (i) For units controlled using an electrostatic precipitator, the 
owner or operator shall use CPMS to measure and record the hourly 
average total power input and secondary voltage to the entire system.
    (ii) For units controlled using a wet scrubber, the owner or 
operator shall use CPMS to measure and record the hourly average 
pressure drop, liquid feed rate, and exhaust gas flow rate. As an 
alternative to a CPMS, the owner or operator must comply with the 
requirements in either paragraph (b)(1)(ii)(A) or (B) of this section.
    (A) As an alterative to pressure drop, the owner or operator of a 
jet ejector type wet scrubber or other type of wet scrubber equipped 
with atomizing spray nozzles must conduct a daily check of the air or 
water pressure to the spray nozzles and record the results of each 
check.
    (B) As an alternative to exhaust gas flow rate, the owner or 
operator shall comply with the approved alternative for monitoring 
exhaust gas flow rate in 40 CFR 63.1573(a) of the National Emission 
Standards for Hazardous Air Pollutants for Petroleum Refineries: 
Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur 
Recovery Units.
    (iii) The owner or operator shall install, operate, and maintain 
each CPMS according to the manufacturer's specifications and 
requirements.
    (iv) The owner or operator shall determine and record the average 
coke burn-off rate and hours of operation for each FCCU or FCU using 
the procedures in Sec.  60.104a(d)(4)(iii).
    (v) If you use a control device other than an electrostatic 
precipitator, wet scrubber, fabric filter, or cyclone, you may request 
approval to monitor parameters other than those required in paragraph 
(b)(1) of this section by submitting an alternative monitoring plan to 
the Administrator. The request must include the information in 
paragraphs (b)(1)(v)(A) through (E) of this section.
    (A) A description of each affected facility and the parameter(s) to 
be monitored to determine whether the affected facility will 
continuously comply with the emission limitations and an explanation of 
the criteria used to select the parameter(s).
    (B) A description of the methods and procedures that will be used 
to demonstrate that the parameter(s) can be used to determine whether 
the affected facility will continuously comply with the emission 
limitations and the schedule for this demonstration. The owner or 
operator must certify that an operating limit will be established for 
the monitored parameter(s) that represents the conditions in existence 
when the control device is being properly operated and maintained to 
meet the emission limitation.
    (C) The frequency and content of the recordkeeping, recording, and 
reporting, if monitoring and recording are not continuous. The owner or 
operator also must include the rationale for the proposed monitoring, 
recording, and reporting requirements.
    (D) Supporting calculations.
    (E) Averaging time for the alternative operating parameter.
    (2) For use in determining the coke burn-off rate for an FCCU or 
FCU, the owner or operator shall install, operate, calibrate, and 
maintain an instrument for continuously monitoring the concentrations 
of CO2, O2 (dry basis), and if needed, CO in the 
exhaust gases prior to any control or energy recovery system that burns 
auxiliary fuels.
    (i) The owner or operator shall install, operate, and maintain each 
monitor according to Performance Specification 3 of Appendix B to part 
60.
    (ii) The owner or operator shall conduct performance evaluations of 
each CO2, O2, and CO monitor according to the 
requirements in Sec.  60.13(c) and Performance Specification 3 of 
Appendix B to part 60. The owner or operator shall use Method 3 of 
Appendix A-3 to part 60 for conducting the relative accuracy 
evaluations.
    (iii) The owner or operator shall comply with the quality assurance 
requirements of procedure 1 of Appendix F to part 60, including 
quarterly accuracy determinations for CO2 and CO monitors, 
annual accuracy determinations for O2 monitors, and daily 
calibration drift tests.
    (c) Bag leak detection systems. Each owner or operator shall 
install, operate, and maintain a bag leak detection system for each 
baghouse or similar fabric filter control device that is used to comply 
with the PM per coke burn-off emissions limit in Sec.  60.102a(b)(1) 
for an FCCU or FCU according to paragraph (c)(1) of this section; 
prepare and operate by a site-specific monitoring plan according to 
paragraph (c)(2) of this section; take action according to paragraph 
(c)(3) of this section; and record information according to paragraph 
(c)(4) of this section.
    (1) Each bag leak detection system must meet the specifications and 
requirements in paragraphs (c)(1)(i) through (viii) of this section.
    (i) The bag leak detection system must be certified by the 
manufacturer to be capable of detecting PM emissions at concentrations 
of 0.00044 grains per actual cubic foot or less.
    (ii) The bag leak detection system sensor must provide output of 
relative PM loadings. The owner or operator shall continuously record 
the output from the bag leak detection system using electronic or other 
means (e.g., using a strip chart recorder or a data logger).
    (iii) The bag leak detection system must be equipped with an alarm 
system that will sound when the system detects an increase in relative 
particulate loading over the alarm set point established according to 
paragraph (c)(1)(iv) of this section, and the alarm must be located 
such that it can be heard by the appropriate plant personnel.
    (iv) In the initial adjustment of the bag leak detection system, 
the owner or operator must establish, at a minimum, the baseline output 
by adjusting the sensitivity (range) and the averaging period of the 
device, the alarm set points, and the alarm delay time.
    (v) Following initial adjustment, the owner or operator shall not 
adjust the averaging period, alarm set point, or alarm delay time 
without approval from the Administrator or delegated authority except 
as provided in paragraph (c)(1)(vi) of this section.
    (vi) Once per quarter, the owner or operator may adjust the 
sensitivity of the bag leak detection system to account for seasonal 
effects, including temperature and humidity, according to the 
procedures identified in the site-specific monitoring plan required by 
paragraph (c)(2) of this section.
    (vii) The owner or operator shall install the bag leak detection 
sensor downstream of the baghouse and upstream of any wet scrubber.
    (viii) Where multiple detectors are required, the system's 
instrumentation and alarm may be shared among detectors.
    (2) The owner or operator shall develop and submit to the 
Administrator for approval a site-specific monitoring plan for each 
baghouse and bag leak detection system. The owner or operator shall 
operate and maintain each baghouse and bag leak detection system 
according to the site-specific monitoring plan at all times. Each 
monitoring plan must describe the items in paragraphs (c)(2)(i) through 
(vii) of this section.

[[Page 35875]]

    (i) Installation of the bag leak detection system;
    (ii) Initial and periodic adjustment of the bag leak detection 
system, including how the alarm set-point will be established;
    (iii) Operation of the bag leak detection system, including quality 
assurance procedures;
    (iv) How the bag leak detection system will be maintained, 
including a routine maintenance schedule and spare parts inventory 
list;
    (v) How the bag leak detection system output will be recorded and 
stored;
    (vi) Procedures as specified in paragraph (c)(3) of this section. 
In approving the site-specific monitoring plan, the Administrator or 
delegated authority may allow owners and operators more than 3 hours to 
alleviate a specific condition that causes an alarm if the owner or 
operator identifies in the monitoring plan this specific condition as 
one that could lead to an alarm, adequately explains why it is not 
feasible to alleviate this condition within 3 hours of the time the 
alarm occurs, and demonstrates that the requested time will ensure 
alleviation of this condition as expeditiously as practicable; and
    (vii) How the baghouse system will be operated and maintained, 
including monitoring of pressure drop across baghouse cells and 
frequency of visual inspections of the baghouse interior and baghouse 
components such as fans and dust removal and bag cleaning mechanisms.
    (3) For each bag leak detection system, the owner or operator shall 
initiate procedures to determine the cause of every alarm within 1 hour 
of the alarm. Except as provided in paragraph (c)(2)(vi) of this 
section, the owner or operator shall alleviate the cause of the alarm 
within 3 hours of the alarm by taking whatever action(s) are necessary. 
Actions may include, but are not limited to the following:
    (i) Inspecting the baghouse for air leaks, torn or broken bags or 
filter media, or any other condition that may cause an increase in 
particulate emissions;
    (ii) Sealing off defective bags or filter media;
    (iii) Replacing defective bags or filter media or otherwise 
repairing the control device;
    (iv) Sealing off a defective baghouse compartment;
    (v) Cleaning the bag leak detection system probe or otherwise 
repairing the bag leak detection system; or
    (vi) Shutting down the process producing the particulate emissions.
    (4) The owner or operator shall maintain records of the information 
specified in paragraphs (c)(4)(i) through (iii) of this section for 
each bag leak detection system.
    (i) Records of the bag leak detection system output;
    (ii) Records of bag leak detection system adjustments, including 
the date and time of the adjustment, the initial bag leak detection 
system settings, and the final bag leak detection system settings; and
    (iii) The date and time of all bag leak detection system alarms, 
the time that procedures to determine the cause of the alarm were 
initiated, the cause of the alarm, an explanation of the actions taken, 
the date and time the cause of the alarm was alleviated, and whether 
the alarm was alleviated within 3 hours of the alarm.
    (d) Continuous emissions monitoring systems (CEMS). An owner or 
operator subject to the PM concentration emission limit (in gr/dscf) in 
Sec.  60.102a(b)(1) for an FCCU or FCU shall install, operate, 
calibrate, and maintain an instrument for continuously monitoring and 
recording the concentration (0 percent excess air) of PM in the exhaust 
gases prior to release to the atmosphere. The monitor must include an 
O2 monitor for correcting the data for excess air.
    (1) The owner or operator shall install, operate, and maintain each 
PM monitor according to Performance Specification 11 of appendix B to 
part 60. The span value of this PM monitor is 0.08 gr/dscf PM.
    (2) The owner or operator shall conduct performance evaluations of 
each PM monitor according to the requirements in Sec.  60.13(c) and 
Performance Specification 11 of appendix B to part 60. The owner or 
operator shall use EPA Methods 5 or 5I of Appendix A-3 to part 60 or 
Method 17 of Appendix A-6 to part 60 for conducting the relative 
accuracy evaluations.
    (3) The owner or operator shall install, operate, and maintain each 
O2 monitor according to Performance Specification 3 of 
appendix B to part 60. The span value of this O2 monitor 
must be selected between 10 and 25 percent, inclusive.
    (4) The owner or operator shall conduct performance evaluations of 
each O2 monitor according to the requirements in Sec.  
60.13(c) and Performance Specification 3 of Appendix B to part 60. 
Method 3, 3A, or 3B of Appendix A-2 to part 60 shall be used for 
conducting the relative accuracy evaluations. The method ANSI/ASME PTC 
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by 
reference--see Sec.  60.17) is an acceptable alternative to EPA Method 
3B of Appendix A-2 to part 60.
    (5) The owner or operator shall comply with the quality assurance 
requirements of Procedure 2 of Appendix B to part 60 for each PM CEMS 
and Procedure 1 of Appendix F to part 60 for each O2 
monitor, including quarterly accuracy determinations for each PM 
monitor, annual accuracy determinations for each O2 monitor, 
and daily calibration drift tests.
    (e) Alternative monitoring option for FCCU and FCU--COMS. Each 
owner or operator of an FCCU or FCU that uses cyclones to comply with 
the PM emission limit in Sec.  60.102a(b)(1) shall monitor the opacity 
of emissions according to the requirements in paragraphs (e)(1) through 
(3) of this section.
    (1) The owner or operator shall install, operate, and maintain an 
instrument for continuously monitoring and recording the opacity of 
emissions from the FCCU or the FCU exhaust vent.
    (2) The owner or operator shall install, operate, and maintain each 
COMS according to Performance Specification 1 of Appendix B to part 60. 
The instrument shall be spanned at 20 to 60 percent opacity.
    (3) The owner or operator shall conduct performance evaluations of 
each COMS according to Sec.  60.13(c) and Performance Specification 1 
of Appendix B to part 60.
    (f) FCCU and FCU subject to NOX limit. Each owner or operator 
subject to the NOX emissions limit in Sec.  60.102a(b)(2) 
for an FCCU or FCU shall install, operate, calibrate, and maintain an 
instrument for continuously monitoring and recording the concentration 
by volume (dry basis, 0 percent excess air) of NOX emissions 
into the atmosphere. The monitor must include an O2 monitor 
for correcting the data for excess air.
    (1) The owner or operator shall install, operate, and maintain each 
NOX monitor according to Performance Specification 2 of 
Appendix B to part 60. The span value of this NOX monitor is 
200 ppmv NOX.
    (2) The owner or operator shall conduct performance evaluations of 
each NOX monitor according to the requirements in Sec.  
60.13(c) and Performance Specification 2 of Appendix B to part 60. The 
owner or operator shall use Methods 7, 7A, 7C, 7D, or 7E of Appendix A-
4 to part 60 for conducting the relative accuracy evaluations. The 
method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas

[[Page 35876]]

Analyses,'' (incorporated by reference--see Sec.  60.17) is an 
acceptable alternative to EPA Method 7 or 7C of Appendix A-4 to part 
60.
    (3) The owner or operator shall install, operate, and maintain each 
O2 monitor according to Performance Specification 3 of 
Appendix B to part 60. The span value of this O2 monitor 
must be selected between 10 and 25 percent, inclusive.
    (4) The owner or operator shall conduct performance evaluations of 
each O2 monitor according to the requirements in Sec.  
60.13(c) and Performance Specification 3 of Appendix B to part 60. 
Method 3, 3A, or 3B of Appendix A-2 to part 60 shall be used for 
conducting the relative accuracy evaluations. The method ANSI/ASME PTC 
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by 
reference--see Sec.  60.17) is an acceptable alternative to EPA Method 
3B of Appendix A-2 to part 60.
    (5) The owner or operator shall comply with the quality assurance 
requirements of Procedure 1 of Appendix F to part 60 for each 
NOX and O2 monitor, including quarterly accuracy 
determinations for NOX monitors, annual accuracy 
determinations for O2 monitors, and daily calibration drift 
tests.
    (g) FCCU and FCU subject to SO2 limit. The owner or operator 
subject to the SO2 emissions limit in Sec.  60.102a(b)(3) 
for an FCCU or an FCU shall install, operate, calibrate, and maintain 
an instrument for continuously monitoring and recording the 
concentration by volume (dry basis, corrected to 0 percent excess air) 
of SO2 emissions into the atmosphere. The monitor shall 
include an O2 monitor for correcting the data for excess 
air.
    (1) The owner or operator shall install, operate, and maintain each 
SO2 monitor according to Performance Specification 2 of 
Appendix B to part 60. The span value of this SO2 monitor is 
200 ppmv SO2.
    (2) The owner or operator shall conduct performance evaluations of 
each SO2 monitor according to the requirements in Sec.  
60.13(c) and Performance Specification 2 of Appendix B to part 60. The 
owner or operator shall use Methods 6, 6A, or 6C of Appendix A-4 to 
part 60 for conducting the relative accuracy evaluations. The method 
ANSI / ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' 
(incorporated by reference--see Sec.  60.17) is an acceptable 
alternative to EPA Method 6 or 6A of Appendix A-4 to part 60.
    (3) The owner or operator shall install, operate, and maintain each 
O2 monitor according to Performance Specification 3 of 
Appendix B to part 60. The span value of this O2 monitor 
must be selected between 10 and 25 percent, inclusive.
    (4) The owner or operator shall conduct performance evaluations of 
each O2 monitor according to the requirements in Sec.  
60.13(c) and Performance Specification 3 of Appendix B to part 60. 
Method 3, 3A, or 3B of Appendix A-2 to part 60 shall be used for 
conducting the relative accuracy evaluations. The method ANSI/ASME PTC 
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by 
reference--see Sec.  60.17) is an acceptable alternative to EPA Method 
3B of Appendix A-2 to part 60.
    (5) The owner or operator shall comply with the quality assurance 
requirements in Procedure 1 of Appendix F to part 60 for each 
SO2 and O2 monitor, including quarterly accuracy 
determinations for SO2 monitors, annual accuracy 
determinations for O2 monitors, and daily calibration drift 
tests.
    (h) FCCU and fluid coking units subject to CO emissions limit. 
Except as specified in paragraph (h)(3) of this section, the owner or 
operator shall install, operate, calibrate, and maintain an instrument 
for continuously monitoring and recording the concentration by volume 
(dry basis) of CO emissions into the atmosphere from each FCCU and FCU 
subject to the CO emissions limit in Sec.  60.102a(b)(4).
    (1) The owner or operator shall install, operate, and maintain each 
CO monitor according to Performance Specification 4 or 4A of Appendix B 
to part 60. The span value for this instrument is 1,000 ppm CO.
    (2) The owner or operator shall conduct performance evaluations of 
each CO monitor according to the requirements in Sec.  60.13(c) and 
Performance Specification 4 or 4A of Appendix B to part 60. The owner 
or operator shall use Methods 10, 10A, or 10B of Appendix A-4 to part 
60 for conducting the relative accuracy evaluations.
    (3) A CO CEMS need not be installed if the owner or operator 
demonstrates that all hourly average CO emissions are and will remain 
less than 50 ppmv (dry basis) corrected to 0 percent excess air. The 
Administrator may revoke this exemption from monitoring upon a 
determination that CO emissions on an hourly average basis have 
exceeded 50 ppmv (dry basis) corrected to 0 percent excess air, in 
which case a CO CEMS shall be installed within 180 days.
    (i) The demonstration shall consist of continuously monitoring CO 
emissions for 30 days using an instrument that meets the requirements 
of Performance Specification 4 or 4A of Appendix B to part 60. The span 
value shall be 100 ppm CO instead of 1,000 ppm, and the relative 
accuracy limit shall be 10 percent of the average CO emissions or 5 ppm 
CO, whichever is greater. For instruments that are identical to Method 
10 of Appendix A-4 to part 60 and employ the sample conditioning system 
of Method 10A of Appendix A-4 to part 60, the alternative relative 
accuracy test procedure in section 10.1 of Performance Specification 2 
of Appendix B to part 60 may be used in place of the relative accuracy 
test.
    (ii) The owner or operator must submit the following information to 
the Administrator:
    (A) The measurement data specified in paragraph (h)(3)(i) of this 
section along with all other operating data known to affect CO 
emissions; and
    (B) Descriptions of the CPMS for exhaust gas temperature and 
O2 monitor required in paragraph (h)(4) of this section and 
operating limits for those parameters to ensure combustion conditions 
remain similar to those that exist during the demonstration period.
    (iii) The effective date of the exemption from installation and 
operation of a CO CEMS is the date of submission of the information and 
data required in paragraph (h)(3)(ii) of this section.
    (4) The owner or operator of a FCCU or FCU that is exempted from 
the requirement to install and operate a CO CEMS in paragraph (h)(3) of 
this section shall install, operate, calibrate, and maintain CPMS to 
measure and record the operating parameters in paragraph (h)(4)(i) or 
(ii) of this section. The owner or operator shall install, operate, and 
maintain each CPMS according to the manufacturer's specifications.
    (i) For a FCCU or FCU with no post-combustion control device, the 
temperature and O2 concentration of the exhaust gas stream 
exiting the unit.
    (ii) For a FCCU or FCU with a post-combustion control device, the 
temperature and O2 concentration of the exhaust gas stream 
exiting the control device.
    (i) Excess emissions. For the purpose of reports required by Sec.  
60.7(c), periods of excess emissions for a FCCU or FCU subject to the 
emissions limitations in Sec.  60.102a(b) are defined as specified in 
paragraphs (i)(1) through (6) of this section. Note: Determine all 
averages, except for opacity, as the arithmetic average of the 
applicable 1-hour averages, e.g., determine the rolling 3-hour average 
as the arithmetic average of three contiguous 1-hour averages.

[[Page 35877]]

    (1) If a CPMS is used according to Sec.  60.105a(b)(1), all 3-hour 
periods during which the average PM control device operating 
characteristics, as measured by the continuous monitoring systems under 
Sec.  60.105a(b)(1), fall below the levels established during the 
performance test.
    (2) If a PM CEMS is used according to Sec.  60.105a(d), all 7-day 
periods during which the average PM emission rate, as measured by the 
continuous PM monitoring system under Sec.  60.105a(d) exceeds 0.040 
gr/dscf corrected to 0 percent excess air for a modified or 
reconstructed FCCU, 0.020 gr/dscf corrected to 0 percent excess air for 
a newly constructed FCCU, or 0.040 gr/dscf for an affected fluid coking 
unit.
    (3) If a COMS is used according to Sec.  60.105a(e), all 3-hour 
periods during which the average opacity, as measured by the COMS under 
Sec.  60.105a(e), exceeds the site-specific limit established during 
the most recent performance test.
    (4) All rolling 7-day periods during which the average 
concentration of NOX as measured by the NOX CEMS 
under Sec.  60.105a(f) exceeds 80 ppmv for an affected FCCU or FCU.
    (5) Except as provided in paragraph (i)(7) of this section, all 
rolling 7-day periods during which the average concentration of 
SO2 as measured by the SO2 CEMS under 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.
    (6) All 1-hour periods during which the average CO concentration as 
measured by the CO continuous monitoring system under Sec. 1A60.105a(h) 
exceeds 500 ppmv or, if applicable, all 1-hour periods during which the 
average temperature and O2 concentration as measured by the 
continuous monitoring systems under Sec.  60.105a(h)(4) fall below the 
operating limits established during the performance test.


Sec.  60.106a  Monitoring of emissions and operations for sulfur 
recovery plants.

    (a) The owner or operator of a sulfur recovery plant that is 
subject to the emissions limits in Sec.  60.102a(f)(1) or Sec.  
60.102a(f)(2) shall:
    (1) For sulfur recovery plants subject to the SO2 
emission limit in Sec.  60.102a(f)(1)(i) or Sec.  60.102a(f)(2)(i), the 
owner or operator shall install, operate, calibrate, and maintain an 
instrument for continuously monitoring and recording the concentration 
(dry basis, zero percent excess air) of any SO2 emissions 
into the atmosphere. The monitor shall include an oxygen monitor for 
correcting the data for excess air.
    (i) The span values for this monitor are two times the applicable 
SO2 emission limit and between 10 and 25 percent 
O2, inclusive.
    (ii) The owner or operator shall install, operate, and maintain 
each SO2 CEMS according to Performance Specification 2 of 
Appendix B to part 60.
    (iii) The owner or operator shall conduct performance evaluations 
of each SO2 monitor according to the requirements in Sec.  
60.13(c) and Performance Specification 2 of Appendix B to part 60. The 
owner or operator shall use Methods 6 or 6C of Appendix A-4 to part 60 
and Method 3 or 3A of Appendix A-2 of part 60 for conducting the 
relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, 
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see 
Sec.  60.17) is an acceptable alternative to EPA Method 6.
    (2) For sulfur recovery plants that are subject to the reduced 
sulfur compound and H2S emission limit in Sec.  
60.102a(f)(1)(ii) or Sec.  60.102a(f)(2)(ii), the owner or operator 
shall install, operate, calibrate, and maintain an instrument for 
continuously monitoring and recording the concentration of reduced 
sulfur, H2S, and O2 emissions into the 
atmosphere. The reduced sulfur emissions shall be calculated as 
SO2 (dry basis, zero percent excess air).
    (i) The span values for this monitor are two times the applicable 
reduced sulfur emission limit, two times the H2S emission 
limit, and between 10 and 25 percent O2, inclusive.
    (ii) The owner or operator shall install, operate, and maintain 
each reduced sulfur CEMS according to Performance Specification 5 of 
Appendix B to part 60.
    (iii) The owner or operator shall conduct performance evaluations 
of each reduced sulfur monitor according to the requirements in Sec.  
60.13(c) and Performance Specification 5 of Appendix B to part 60. The 
owner or operator shall use Methods 15 or 15A of Appendix A-5 to part 
60 for conducting the relative accuracy evaluations. The method ANSI/
ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated 
by reference--see Sec.  60.17) is an acceptable alternative to EPA 
Method 15A of Appendix A-5 to part 60.
    (iv) The owner or operator shall install, operate, and maintain 
each H2S CEMS according to Performance Specification 7 of 
Appendix B to part 60.
    (v) The owner or operator shall conduct performance evaluations of 
each reduced sulfur monitor according to the requirements in Sec.  
60.13(c) and Performance Specification 5 of Appendix B to part 60. The 
owner or operator shall use Methods 11, 15, or 15A of Appendix A-5 to 
part 60 or Method 16 of Appendix A-6 to part 60 for conducting the 
relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, 
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see 
Sec.  60.17) is an acceptable alternative to EPA Method 15A of Appendix 
A-5 to part 60.
    (vi) The owner or operator shall install, operate, and maintain 
each O2 monitor according to Performance Specification 3 of 
Appendix B to part 60.
    (vii) The span value for the O2 monitor must be selected 
between 10 and 25 percent, inclusive.
    (viii) The owner or operator shall conduct performance evaluations 
for the O2 monitor according to the requirements of Sec.  
60.13(c) and Performance Specification 3 of Appendix B to part 60. The 
owner or operator shall use Methods 3, 3A, or 3B of Appendix A-2 to 
part 60 for conducting the relative accuracy evaluations. The method 
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' 
(incorporated by reference--see Sec.  60.17) is an acceptable 
alternative to EPA Method 3B of Appendix A-2 to part 60.
    (ix) The owner or operator shall comply with the applicable quality 
assurance procedures of Appendix F to part 60 for each monitor, 
including annual accuracy determinations for each O2 
monitor, and daily calibration drift determinations.
    (3) In place of the reduced sulfur monitor required in paragraph 
(a)(2) of this section, the owner or operator shall install, calibrate, 
operate, and maintain an instrument using an air or O2 
dilution and oxidation system to convert any reduced sulfur to 
SO2 for continuously monitoring and recording the 
concentration (dry basis, 0 percent excess air) of the total resultant 
SO2. The monitor must include an O2 monitor for 
correcting the data for excess O2.
    (i) The span value for this monitor is two times the applicable 
SO2 emission limit.
    (ii) The owner or operator shall conduct performance evaluations of 
each SO2 monitor according to the requirements in Sec.  
60.13(c) and Performance Specification 5 of Appendix B to part 60. The 
owner or operator shall use Methods 15 or 15A of

[[Page 35878]]

Appendix A-5 to part 60 for conducting the relative accuracy 
evaluations. The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust 
Gas Analyses,'' (incorporated by reference--see Sec.  60.17) is an 
acceptable alternative to EPA Method 15A of Appendix A-5 to part 60.
    (iii) The owner or operator shall install, operate, and maintain 
each O2 monitor according to Performance Specification 3 of 
Appendix B to part 60.
    (iv) The span value for the O2 monitor must be selected 
between 10 and 25 percent, inclusive.
    (v) The owner or operator shall conduct performance evaluations for 
the O2 monitor according to the requirements of Sec.  
60.13(c) and Performance Specification 3 of Appendix B to part 60. The 
owner or operator shall use Methods 3, 3A, or 3B of Appendix A-2 to 
part 60 for conducting the relative accuracy evaluations. The method 
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' 
(incorporated by reference--see Sec.  60.17) is an acceptable 
alternative to EPA Method 3B of Appendix A-2 to part 60.
    (vi) The owner or operator shall comply with the applicable quality 
assurance procedures of Appendix F to part 60 for each monitor, 
including quarterly accuracy determinations for each SO2 
monitor, annual accuracy determinations for each O2 monitor, 
and daily calibration drift determinations.
    (b) Excess emissions. For the purpose of reports required by Sec.  
60.7(c), periods of excess emissions for sulfur recovery plants subject 
to the emissions limitations in Sec.  60.102a(f) are defined as 
specified in paragraphs (b)(1) through (3) of this section. Note: 
Determine all averages as the arithmetic average of the applicable 1-
hour averages, e.g., determine the rolling 12-hour average as the 
arithmetic average of 12 contiguous 1-hour averages.
    (1) All 12-hour periods during which the average concentration of 
SO2 as measured by the SO2 continuous monitoring 
system required under paragraph (a)(1) of this section exceeds the 
applicable emission limit (dry basis, zero percent excess air); or
    (2) All 12-hour periods during which the average concentration of 
reduced sulfur (as SO2) as measured by the reduced sulfur 
continuous monitoring system required under paragraph (a)(2) of this 
section exceeds the applicable emission limit; or
    (3) All 12-hour periods during which the average concentration of 
H2S as measured by the H2S continuous monitoring 
system required under paragraph (a)(2) of this section exceeds the 
applicable emission limit (dry basis, 0 percent excess air).


Sec.  60.107a  Monitoring of emissions and operations for fuel gas 
combustion devices.

    (a) Fuel gas combustion devices subject to SO2 or H2S limit. The 
owner or operator of a fuel gas combustion device that is subject to 
the requirements in Sec.  60.102a(g) shall comply with the requirements 
in paragraph (a)(1) of this section for SO2 emissions or 
paragraph (a)(2) of this section for H2S emissions.
    (1) The owner or operator of a fuel gas combustion device subject 
to the SO2 emissions limits in 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.
    (i) The owner or operator shall install, operate, and maintain each 
SO2 monitor according to Performance Specification 2 of 
Appendix B to part 60. The span value for the SO2 monitor is 
50 ppm SO2.
    (ii) The owner or operator shall conduct performance evaluations 
for the SO2 monitor according to the requirements of Sec.  
60.13(c) and Performance Specification 2 of Appendix B to part 60. The 
owner or operator shall use Methods 6, 6A, or 6C of Appendix A-4 to 
part 60 for conducting the relative accuracy evaluations. The method 
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' 
(incorporated by reference--see Sec.  60.17) is an acceptable 
alternative to EPA Method 6 or 6A of Appendix A-4 to part 60. Samples 
taken by Method 6 of Appendix A-4 to part 60 shall be taken at a flow 
rate of approximately 2 liters/min for at least 30 minutes. The 
relative accuracy limit shall be 20 percent or 4 ppm, whichever is 
greater, and the calibration drift limit shall be 5 percent of the 
established span value.
    (iii) The owner or operator shall install, operate, and maintain 
each O2 monitor according to Performance Specification 3 of 
Appendix B to part 60. The span value for the O2 monitor 
must be selected between 10 and 25 percent, inclusive.
    (iv) The owner or operator shall conduct performance evaluations 
for the O2 monitor according to the requirements of Sec.  
60.13(c) and Performance Specification 3 of Appendix B to part 60. The 
owner or operator shall use Methods 3, 3A, or 3B of Appendix A-2 to 
part 60 for conducting the relative accuracy evaluations. The method 
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' 
(incorporated by reference--see Sec.  60.17) is an acceptable 
alternative to EPA Method 3B of Appendix A-2 to part 60.
    (v) The owner or operator shall comply with the applicable quality 
assurance procedures in Appendix F to part 60, including quarterly 
accuracy determinations for SO2 monitors, annual accuracy 
determinations for O2 monitors, and daily calibration drift 
tests.
    (vi) Fuel gas combustion devices having a common source of fuel gas 
may be monitored at only one location (i.e., after one of the 
combustion devices), if monitoring at this location accurately 
represents the SO2 emissions into the atmosphere from each 
of the combustion devices.
    (2) The owner or operator of a fuel gas combustion device subject 
to the H2S concentration limits in Sec.  60.102a(g)(1)(ii) 
shall install, operate, calibrate, and maintain an instrument for 
continuously monitoring and recording the concentration by volume (dry 
basis) of H2S in the fuel gases before being burned in any 
fuel gas combustion device.
    (i) The owner or operator shall install, operate, and maintain each 
H2S monitor according to Performance Specification 7 of 
Appendix B to part 60. The span value for this instrument is 320 ppmv 
H2S.
    (ii) The owner or operator shall conduct performance evaluations 
for each H2S monitor according to the requirements of Sec.  
60.13(c) and Performance Specification 7 of Appendix B to part 60. The 
owner or operator shall use Method 11, 15, or 15A of Appendix A-5 to 
part 60 or Method 16 of Appendix A-6 to part 60 for conducting the 
relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, 
``Flue and Exhaust Gas Analyses,'' (incorporated by reference--see 
Sec.  60.17) is an acceptable alternative to EPA Method 15A of Appendix 
A-5 to part 60.
    (iii) The owner or operator shall comply with the applicable 
quality assurance procedures in Appendix F to part 60 for each 
H2S monitor.
    (iv) Fuel gas combustion devices having a common source of fuel gas 
may be monitored at only one location, if monitoring at this location 
accurately represents the concentration of H2S in the fuel 
gas being burned.
    (3) The owner or operator of a fuel gas combustion device is not 
required to comply with paragraph (a)(1) or (2) of this section for 
fuel gas streams that are

[[Page 35879]]

exempt under Sec.  60.102a(h) and fuel gas streams combusted in a 
process heater or other fuel gas combustion device that are inherently 
low in sulfur content. Fuel gas streams meeting one of the requirements 
in paragraphs (a)(3)(i) through (iv) of this section will be considered 
inherently low in sulfur content.
    (i) Pilot gas for heaters and flares.
    (ii) Fuel gas streams that meet a commercial-grade product 
specification for sulfur content of 30 ppmv or less. In the case of a 
liquefied petroleum gas (LPG) product specification in the pressurized 
liquid state, the gas phase sulfur content should be evaluated assuming 
complete vaporization of the LPG and sulfur containing-compounds at the 
product specification concentration.
    (iii) Fuel gas streams produced in process units that are 
intolerant to sulfur contamination, such as fuel gas streams produced 
in the hydrogen plant, catalytic reforming unit, isomerization unit, 
and HF alkylation process units.
    (iv) Other fuel gas streams that an owner or operator demonstrates 
are low-sulfur according to the procedures in paragraph (b) of this 
section.
    (4) If the composition of an exempt fuel gas stream changes, the 
owner or operator must follow the procedures in paragraph (b)(3) of 
this section.
    (b) Exemption from H2S monitoring requirements for low-sulfur fuel 
gas streams. The owner or operator of a fuel gas combustion device may 
apply for an exemption from the H2S monitoring requirements 
in paragraph (a)(2) of this section for a fuel gas stream that is 
inherently low in sulfur content. A fuel gas stream that is 
demonstrated to be low-sulfur is exempt from the monitoring 
requirements of paragraphs (a)(1) and (2) of this section until there 
are changes in operating conditions or stream composition.
    (1) The owner or operator shall submit to the Administrator a 
written application for an exemption from monitoring. The application 
must contain the following information:
    (i) A description of the fuel gas stream/system to be considered, 
including submission of a portion of the appropriate piping diagrams 
indicating the boundaries of the fuel gas stream/system, and the 
affected fuel gas combustion device(s) to be considered;
    (ii) A statement that there are no crossover or entry points for 
sour gas (high H2S content) to be introduced into the fuel 
gas stream/system (this should be shown in the piping diagrams);
    (iii) An explanation of the conditions that ensure low amounts of 
sulfur in the fuel gas stream (i.e., control equipment or product 
specifications) at all times;
    (iv) The supporting test results from sampling the requested fuel 
gas stream/system demonstrating that the sulfur content is less than 5 
ppm H2S. Sampling data must include, at minimum, 2 weeks of 
daily monitoring (14 grab samples) for frequently operated fuel gas 
streams/systems; for infrequently operated fuel gas streams/systems, 
seven grab samples must be collected unless other additional 
information would support reduced sampling. The owner or operator shall 
use detector tubes (``length-of-stain tube'' type measurement) 
following the ``Gas Processors Association Standard 2377-86, Test for 
Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using Length of 
Stain Tubes,'' 1986 Revision (incorporated by reference--see Sec.  
60.17), with ranges 0-10/0-100 ppm (N = 10/1) to test the applicant 
fuel gas stream for H2S; and
    (v) A description of how the 2 weeks (or seven samples for 
infrequently operated fuel gas streams/systems) of monitoring results 
compares to the typical range of H2S concentration (fuel 
quality) expected for the fuel gas stream/system going to the affected 
fuel gas combustion device (e.g., the 2 weeks of daily detector tube 
results for a frequently operated loading rack included the entire 
range of products loaded out, and, therefore, should be representative 
of typical operating conditions affecting H2S content in the 
fuel gas stream going to the loading rack flare).
    (2) The effective date of the exemption is the date of submission 
of the information required in paragraph (b)(1) of this section.
    (3) No further action is required unless refinery operating 
conditions change in such a way that affects the exempt fuel gas 
stream/system (e.g., the stream composition changes). If such a change 
occurs, the owner or operator shall follow the procedures in paragraph 
(b)(3)(i), (b)(3)(ii), or (b)(3)(iii) of this section.
    (i) If the operation change results in a sulfur content that is 
still within the range of concentrations included in the original 
application, the owner or operator shall conduct an H2S test 
on a grab sample and record the results as proof that the concentration 
is still within the range.
    (ii) If the operation change results in a sulfur content that is 
outside the range of concentrations included in the original 
application, the owner or operator may submit new information following 
the procedures of paragraph (b)(1) of this section within 60 days (or 
within 30 days after the seventh grab sample is tested for infrequently 
operated process units).
    (iii) If the operation change results in a sulfur content that is 
outside the range of concentrations included in the original 
application, and the owner or operator chooses not to submit new 
information to support an exemption, the owner or operator must begin 
H2S monitoring using daily stain sampling to demonstrate 
compliance. The owner or operator must begin monitoring according to 
the requirements in paragraphs (a)(1) or (a)(2) of this section as soon 
as practicable but in no case later than 180 days after the operation 
change. During daily stain tube sampling, a daily sample exceeding 162 
ppmv is an exceedance of the 3-hour H2S concentration limit. 
The owner or operator must determine a rolling 365-day average using 
the stain sampling results; an average H2S concentration of 
5 ppmv must be used for days prior to the operation change.
    (c) Process heaters subject to NOX limit. The owner or operator of 
a process heater subject to the NOX emission limit in Sec.  
60.102a(g)(2) shall install, operate, calibrate, and maintain an 
instrument for continuously monitoring and recording the concentration 
(dry basis, 0 percent excess air) of NOX emissions into the 
atmosphere. The monitor must include an O2 monitor for 
correcting the data for excess air.
    (1) The owner or operator shall install, operate, and maintain each 
NOX monitor according to Performance Specification 2 of 
Appendix B to part 60. The span value of this NOX monitor is 
200 ppmv NOX.
    (2) The owner or operator shall conduct performance evaluations of 
each NOX monitor according to the requirements in Sec.  
60.13(c) and Performance Specification 2 of Appendix B to part 60. The 
owner or operator shall use Methods 7, 7A, 7C, 7D, or 7E of Appendix A-
4 to part 60 for conducting the relative accuracy evaluations. The 
method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' 
(incorporated by reference--see Sec.  60.17) is an acceptable 
alternative to EPA Method 7 or 7C of Appendix A-4 to part 60.
    (3) The owner or operator shall install, operate, and maintain each 
O2 monitor according to Performance Specification 3 of 
Appendix B to part 60. The span value of this O2 monitor 
must be selected between 10 and 25 percent, inclusive.
    (4) The owner or operator shall conduct performance evaluations of 
each O2 monitor according to the requirements in Sec.  
60.13(c) and

[[Page 35880]]

Performance Specification 3 of Appendix B to part 60. Method 3, 3A, or 
3B of Appendix A-2 to part 60 shall be used for conducting the relative 
accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, ``Flue and 
Exhaust Gas Analyses,'' (incorporated by reference--see Sec.  60.17) is 
an acceptable alternative to EPA Method 3B of Appendix A-2 to part 60.
    (5) The owner or operator shall comply with the quality assurance 
requirements in Procedure 1 of Appendix F to part 60 for each 
NOX and O2 monitor, including quarterly accuracy 
determinations for NOX monitors, annual accuracy 
determinations for O2 monitors, and daily calibration drift 
tests.
    (6) The owner or operator of a process heater that has a rated 
heating capacity of less than 100 MMBtu and is equipped with low-
NOX burners (LNB) or ultra low-NOX burners (ULNB) 
is not subject to the monitoring requirements in paragraphs (c)(1) 
through (5) of this section. The owner or operator of such a process 
heater must conduct biennial performance tests to demonstrate 
compliance.
    (d) Sulfur monitoring for affected flares. The owner or operator of 
an affected flare subject to Sec.  60.103a(b) shall install, operate, 
calibrate, and maintain an instrument for continuously monitoring and 
recording the concentration of reduced sulfur in flare gas. The owner 
or operator of a modified flare shall install this instrument by no 
later than 1 year after the flare becomes an affected flare subject to 
this subpart.
    (1) The owner or operator shall install, operate, and maintain each 
reduced sulfur CEMS according to Performance Specification 5 of 
Appendix B to part 60.
    (2) The owner or operator shall conduct performance evaluations of 
each reduced sulfur monitor according to the requirements in Sec.  
60.13(c) and Performance Specification 5 of Appendix B to part 60. The 
owner or operator shall use Methods 15 or 15A of Appendix A-5 to part 
60 for conducting the relative accuracy evaluations. The method ANSI/
ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated 
by reference--see Sec.  60.17) is an acceptable alternative to EPA 
Method 15A of Appendix A-5 to part 60.
    (3) The owner or operator shall comply with the applicable quality 
assurance procedures in Appendix F to part 60 for each reduced sulfur 
monitor.
    (e) Flow monitoring for flares. The owner or operator of an 
affected flare subject to Sec.  60.102a(g)(3) shall install, operate, 
calibrate, and maintain CPMS to measure and record the exhaust gas flow 
rate. The owner or operator of a modified flare shall install this 
instrument by no later than 1 year after the flare becomes an affected 
flare subject to this subpart.
    (1) The CPMS must be able to correct for the temperature and 
pressure of the system and output flow in standard conditions as 
defined in Sec.  60.2.
    (2) The owner or operator shall install, operate, and maintain each 
CPMS according to the manufacturer's specifications and requirements.
    (f) Excess emissions. For the purpose of reports required by Sec.  
60.7(c), periods of excess emissions for fuel gas combustion devices 
subject to the emissions limitations in Sec.  60.102a(g) are defined as 
specified in paragraphs (f)(1) through (4) of this section. Note: 
Determine all averages as the arithmetic average of the applicable 1-
hour averages, e.g., determine the rolling 3-hour average as the 
arithmetic average of three contiguous 1-hour averages.
    (1) All rolling 3-hour periods during which the average 
concentration of SO2 as measured by the SO2 
continuous monitoring system required under paragraph (a)(1) of this 
section exceeds 20 ppmv, and all rolling 365-day periods during which 
the average concentration as measured by the SO2 continuous 
monitoring system required under paragraph (a)(1) of this section 
exceeds 8 ppmv; or
    (2) All rolling 3-hour periods during which the average 
concentration of H2S as measured by the H2S 
continuous monitoring system required under paragraph (a)(2) of this 
section exceeds 162 ppmv, all days in which the concentration of 
H2S as measured by daily stain tube sampling required under 
paragraph (b)(3)(iii) of this section exceeds 162 ppmv, and all rolling 
365-day periods during which the average concentration as measured by 
the H2S continuous monitoring system under paragraph (a)(2) 
of this section exceeds 60 ppmv.
    (3) All rolling 24-hour periods during which the average 
concentration of NOX as measured by the NOX 
continuous monitoring system required under paragraph (c) of this 
section exceeds 40 ppmv.
    (4) All rolling 30-day periods during which the average flow rate 
to an affected flare as measured by the monitoring system required 
under paragraph (e) of this section exceeds 250,000 scfd.


Sec.  60.108a  Recordkeeping and reporting requirements.

    (a) Each owner or operator subject to the emissions limitations in 
Sec.  60.102a shall comply with the notification, recordkeeping, and 
reporting requirements in Sec.  60.7 and other requirements as 
specified in this section.
    (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 seeks to comply. Notification shall be submitted with 
the notification of initial startup required by Sec.  60.7(a)(3).
    (c) The owner or operator shall maintain the following records:
    (1) A copy of the flare management plan and each root cause 
analysis of a discharge;
    (2) Records of information to document conformance with bag leak 
detection system operation and maintenance requirements in Sec.  
60.105a(c).
    (3) Records of bag leak detection system alarms and actions 
according to Sec.  60.105a(c).
    (4) For each FCCU and fluid coking unit subject to the monitoring 
requirements in Sec.  60.105a(b)(1), records of the average coke burn-
off rate and hours of operation.
    (5) For each fuel gas stream to which one of the exemptions listed 
in Sec.  60.107a(a)(3) applies, records of the specific exemption 
determined to apply for each fuel stream. If the owner or operator 
applies for the exemption described in Sec.  60.107a(a)(3)(iv), the 
owner or operator must keep a copy of the application as well as the 
letter from the Administrator granting approval of the application.
    (6) The owner or operator shall record and maintain records of 
discharges greater than 500 lb/day SO2 from any affected 
fuel gas combustion device or sulfur recovery plant and discharges to 
an affected flare in excess of 500,000 scfd. These records shall 
include:
    (i) A description of the discharge.
    (ii) For discharges greater than 500 lb/day SO2, the 
date and time the discharge was first identified and the duration of 
the discharge.
    (iii) The measured or calculated cumulative quantity of gas 
discharged over the discharge duration. If the discharge duration 
exceeds 24 hours, record the discharge quantity for each 24-hour 
period. Engineering calculations are allowed for fuel gas combustion 
devices other than flares.
    (iv) For discharges greater than 500 lb/day SO2, the 
measured or estimated

[[Page 35881]]

concentration of H2S, TRS and SO2 of the stream 
discharged. Process knowledge can be used to make these estimates for 
fuel gas combustion devices other than flares.
    (v) For discharges greater than 500 lb/day SO2, the 
cumulative quantity of H2S and SO2 released into 
the atmosphere. For releases controlled by flares, assume 99 percent 
conversion of reduced sulfur to SO2. For other fuel gas 
combustion devices, assume 99 percent conversion of H2S to 
SO2.
    (vi) Results of any root-cause analysis conducted as required in 
Sec.  60.103a(a)(4) and Sec.  60.103a(b).
    (d) Each owner or operator subject to this subpart shall submit an 
excess emissions report for all periods of excess emissions according 
to the requirements of Sec.  60.7(c) except that the report shall 
contain the information specified in paragraphs (d)(1) through (7) of 
this section.
    (1) The date that the exceedance occurred;
    (2) An explanation of the exceedance;
    (3) Whether the exceedance was concurrent with a startup, shutdown, 
or malfunction of an affected facility or control system; and
    (4) A description of the action taken, if any.
    (5) A root-cause summary report that provides the information 
described in paragraph (e)(6) of this section for all discharges for 
which a root-cause analysis was required by Sec.  60.103a(a)(4) and 
Sec.  60.103a(b).
    (6) For any periods for which monitoring data are not available, 
any changes made in operation of the emission control system during the 
period of data unavailability which could affect the ability of the 
system to meet the applicable emission limit. Operations of the control 
system and affected facility during periods of data unavailability are 
to be compared with operation of the control system and affected 
facility before and following the period of data unavailability.
    (7) A written statement, signed by a responsible official, 
certifying the accuracy and completeness of the information contained 
in the report.


Sec.  60.109a  Delegation of authority.

    (a) This subpart can be implemented and enforced by the U.S. EPA or 
a delegated authority such as a State, local, or tribal agency. You 
should contact your U.S. EPA Regional Office to find out if this 
subpart is delegated to a State, local, or tribal agency within your 
State.
    (b) In delegating implementation and enforcement authority of this 
subpart to a State, local, or tribal agency, the approval authorities 
contained in paragraphs (b)(1) through (3) of this section are retained 
by the Administrator of the U.S. EPA and are not transferred to the 
State, local, or tribal agency.
    (1) Approval of a major change to test methods under Sec.  60.8(b). 
A ``major change to test method'' is defined in 40 CFR 63.90.
    (2) Approval of a major change to monitoring under Sec.  60.13(i). 
A ``major change to monitoring'' is defined in 40 CFR 63.90.
    (3) Approval of a major change to recordkeeping/reporting under 
Sec.  60.7(b) through (f). A ``major change to recordkeeping/
reporting'' is defined in 40 CFR 63.90.

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

BILLING CODE 6560-50-P
