Standards of Performance for Petroleum Refineries, 35838-35881 [E8-13498]

Agencies

• ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 73, Number 122 (Tuesday, June 24, 2008)]
[Rules and Regulations]
[Pages 35838-35881]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E8-13498]



[[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

Federal Register / Vol. 73, No. 122 / Tuesday, June 24, 2008 / Rules 
and Regulations

[[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 https://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
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           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).
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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 re