[Federal Register: June 24, 2008 (Volume 73, Number 122)]
[Rules and Regulations]
[Page 35837-35881]
[DOCID:fr24jn08-12]

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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

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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<PHONE_NUMBER>, and the telephone number for the
Air Docket is<PHONE_NUMBER>.

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:<PHONE_NUMBER>; e-mail address<EMAIL_ADDRESS>
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

    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

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

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

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

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

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.

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.

    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

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.

    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

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

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.

 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.

    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
----------------------------------------------------------------------------------------------------------------

    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

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.

    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