stripper.  We estimate that this alternative would require a capital
cost of approximately $10 million (for 2 storage tanks and excess amine)
for a 50 long LTD SRU system, resulting in an annualized cost of $1
million/year.  If the 24 hours of excess amine was used one time per
year for an entire day, 50 LTD of sulfur would have resulted in 110 tons
of SO2 emissions avoided.  If there are three occurrences per year where
the excess amine solution is used, 330 tons of emissions would be
reduced.  This scenario results in a cost-effectiveness ranging from
$3,000 to 9,000 per ton of SO2 reduced.

Option 2 is to have a redundant Claus unit.  The capital cost of a 50
LTD Claus unit is also approximately $10 million, resulting in an
annualized cost of $1 million/year.  Again, if there are one to three
days of emissions avoided, this option results in a cost-effectiveness
ranging from $3,000 to $9,000 per ton of SO2 reduced.  For sulfur
recovery plants consisting of multiple Claus units, the likelihood of
needing the additional Claus train more than three times per year
increases significantly, making the redundant Claus unit a
cost-effective option.

It is difficult to predict the quantity of emissions avoided as they are
dependent on random malfunction events of variable durations.  While the
cost-effectiveness values of these options are not necessarily
compelling given the uncertainty in the emissions avoided, the options
evaluated are expected to be extreme measures.  It is likely, for
example, that maintaining appropriate spare parts for the system would
provide a cost-effective means of reducing emissions.  This, along with
short-term reductions in high-sulfur fuel gas production could be used
to eliminate the need to flare or otherwise combust these high
sulfur-containing fuel gases.

Based on this analysis, we are proposing that a start-up, shutdown, and
malfunction plan that specifically addresses the minimization of fuel
gas combustion of high sulfur-containing fuel gases during malfunctions
of an amine treatment system or sulfur recovery plant is BDT.  The
start-up, shutdown, and malfunction plan will address specific process
upset and malfunction events associated with the amine treatment system
and sulfur recovery plant and the standard operating procedures to
follow to minimize emissions during these events.  Compliance is
demonstrated by following the procedures in the plan.  As previously
mentioned, we are proposing a work practice standard rather than an
equipment standard to provide flexibility to the refinery owner or
operator regarding the best way to minimize malfunction emissions given
the refinery’s specific configuration and sulfur loads.

	Finally, we evaluated a requirement for performing root-cause analyses
as a means to minimize the frequency of process malfunctions and thereby
reduce malfunction emissions.  Even though process upset gas is exempt
from the SO2 emission limits associated with fuel gas combustion units,
we believe it is good air pollution practice to investigate the causes
of significant atmospheric releases caused by process upsets or
malfunctions to determine if similar upsets or malfunctions can be
reasonably prevented from recurring.  Similarly, we believe it is good
pollution control practice to investigate significant emission
exceedances to determine the cause of the exceedance and to implement
procedures to prevent its recurrence.  The cost-effectiveness of these
investigations is dependent on the frequency and magnitude of the
emission episodes; for very small emission episodes, the manpower
required to perform the investigations do not justify the potential
emission reductions that might be realized from the root-cause analysis.
 We estimate that a root-cause analysis would cost approximately $2,500
to perform.  For emissions of less than 500 pounds per day, the
cost-effectiveness of the root-cause analysis, even assuming it would
completely eliminate a future recurrence, would be approximately $10,000
per ton of SO2 reduced.  Similarly, for emissions of 1,000 pounds per
day, the cost- effectiveness would be on the order of $5,000 per ton of
SO2 reduced.  As the probability of successfully identifying a means to
avoid future emissions from each root-cause analysis performed is
certainly less than 100 percent, we determined that it was not cost
effective to perform root-cause analyses for SO2 emissions exceedances
of 500 pounds per day or less and request comment on alternative
thresholds in the range of 500 to 1,000 lbs per day.

For SO2 releases of greater than 500 pounds per day, the emissions
reductions potential of the root-cause analyses increases and the
cost-effectiveness improves, so we are proposing that performing
root-cause analyses for SO2 releases of greater than 500 pounds per day
would be BDT.  Any emission limit exceedance or any process start-up,
shutdown, upset or malfunction that causes a discharge into the
atmosphere in excess of 500 pounds per day of SO2 would require a root
cause analysis to be performed.  We also considered a similar
requirement for hydrocarbon flaring events with the purpose of reducing
VOC emissions.  However, we expect refinery owners and operators to
investigate large hydrocarbon releases as these releases represent lost
revenues.  Furthermore, as flares are efficient in destroying VOC, the
potential to significantly reduce VOC emissions by performing root-cause
analysis is much less than the potential for reducing SO2 emissions.  We
request comment on the need to include root cause analyses for
hydrocarbon releases.  If root-cause analyses are recommended, please
provide in your comments the recommended release quantities that would
trigger the root-cause analysis and justification for the
recommendation.  If root cause analyses are not recommended, please
provide in your comments the rationale for not requiring root-cause
analysis for any VOC (hydrocarbon) releases.

The proposed rule is intended to provide flexibility for each refinery
owner and operator to develop procedures that are efficient and
effective for their process configuration.  The scope of these
requirements is limited to affected facilities under this rule.  We
request comment on the need to implement this requirement to all new
process units at the refinery, not just fuel gas producing units such as
fluid catalytic cracking units, fluid coking units, fuel gas combustion
devices, and sulfur recovery plants.

On the other hand, based on site-specific conditions and given the
nature of the types of emissions events that are being addressed by the
start-up, shutdown, and malfunction plan, it is impossible to
conclusively determine that one or all of the emission reduction methods
addressed in the start-up, shutdown, and malfunction plan will achieve
any set level of emissions reduction or that those reductions, if any,
will be cost-effective.  Therefore, we are co-proposing no requirement
for a start-up, shutdown, and malfunction plan.  We request comments and
supporting data that indicate the emission reductions that could be
reasonably expected from a flare minimization plan for planned start-up
and shutdown events, the number of planned events that occur per year
(or over a 5 year period), and any other information that can be used to
justify either the inclusion or exclusion of this provision in the final
rule.  We also request comments and supporting data that indicate the
number and duration of malfunctions in the amine stripper and sulfur
recovery plants, the costs associated with alternative sulfur shedding
practices, and other information that can be used to justify either the
inclusion or exclusion of this provision in the final rule.

Finally, we request comment, along with supporting data, that indicate
the frequency of emission events exceeding 500 pounds per day, the
percentage of times the root-cause analysis results in positive steps
that may avoid future recurrence of the event, and other information
that can be used to justify either the inclusion or exclusion of this
provision in the final rule

Delayed Coking Unit Depressurization.  The primary emission releases
from delayed coking units occur as the coking vessels are depressurized
and petroleum coke is removed from the unit.  When the delayed coking
cycle is completed, the coke-filled vessel is steam stripped.  Most of
the gases from this process continue to be sent to the coking unit
distillation column.  At some point in time, the steam gas discharge is
diverted to the blow-down system.  The delayed coking unit typically has
a fuel gas recovery system (compressor) due to the quantity of fuel gas
produced by the unit.  Therefore, it is cost-effective to require the
blow-down system gases to be recovered in the unit’s fuel gas recovery
system, in keeping with the proposed work practice standard that fuel
gas from fuel gas producing units will not be routinely flared.

As the process unit continues to depressurize, there is a point where
the gases can no longer be discharged to the blow-down system or fuel
gas recovery line, at which point the remaining steam and gases are
vented to the atmosphere.  To achieve maximum reduction of uncontrolled
releases, the unit should be depressurized to as low a pressure as
possible before venting to the atmosphere.  Below a pressure of 5 pounds
per square inch gauge (psig) in the delayed coking unit drum, it is not
technically feasible to divert the emissions for recovery.  Above a
vessel pressure of 5 psig, it is technically feasible to divert the
emissions for recovery.  Furthermore, as the unit already has a gas
compressor, the costs associated with recovering these gases is minimal.

We estimate that this practice can reduce VOC emissions by 120 tons per
year and SO2 emissions by at 200 tons per year.  The total annualized
costs are expected to be minimal for new units, but installing the
appropriate piping for a modified or reconstructed unit may result in
annualized costs of up to $100,000 per year.  Even under this extreme
condition, the cost effectiveness of the requirement is about $800 per
ton of VOC reduced and $500 per ton of SO2 reduced.  Therefore, we
conclude that a work practice standard that requires delayed coking unit
shall depressure to 5 psig during reactor vessel depressuring and vent
the exhaust gases to the fuel gas system for recovery is BDT.  Note this
determination is independent of the work practice to eliminate routine
flaring from fuel gas producing units and requires flare gas recovery of
depressurization gases even under the option of no work practice
requirement to minimize flaring.

In addition to the depressurization emissions, we also identified at
least one refinery that has designed an enclosed system for their
coke-cutting operations.  Coke cutting operations were identified as a
significant VOC emission source at refineries during an Alberta Research
Council study, with an estimated VOC emissions rate of 1,300 tons per
year.  We do not have any data regarding the effectiveness of the
coke-cutting enclosure system, whether the enclosure seals are air tight
or if they allow some percentage of the emissions escape.  The enclosure
may simply suppress the emissions until the coke is removed from the
unit, at which time the emissions are released.  Additionally, we do not
have any data on the costs of these systems and whether or not existing
units can be retrofitted if the delayed coking unit is modified or
reconstructed.  Therefore, we cannot conclude that an enclosed coke
cutting system is BDT, but we request comment and additional information
on coke-cutting system controls, their cost, their effectiveness, and
their limitations.

VI.  Modification and Reconstruction Provisions

Existing affected sources that are modified or reconstructed would be
subject to the proposed standards in 40 CFR part 60, subpart Ja.  A
modification is any physical or operational change to an existing
facility which results in an increase in the emission rate to the
atmosphere of any pollutant to which a standard applies (see 40 CFR
60.14).  Changes to an existing 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.

	Rebuilt petroleum refinery process units would become subject to the
proposed standards in 40 CFR part 60, subpart Ja 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).

	With the exception of the standards for fluid catalytic cracking units,
we are proposing that modified or reconstructed sources be subject to
the same proposed standards in 40 CFR part 60, subpart Ja, as new
sources.  The decision to maintain consistent standards for both new and
modified or reconstructed sources was based on an evaluation of the
cost-effectiveness and incremental cost-effectiveness of the proposed
standards on both types of sources and on the feasibility of
retrofitting existing units.  We have included in the docket a table
(Impacts Summary) which summarizes our estimates costs for different
control options for both new and reconstructed or modified process
units.  We request comment on these cost estimates and on specific
issues related to the feasibility of retrofitting existing units, as
well as our assessment that cost-effectiveness numbers are similar
enough such that it is appropriate to have identical standards for both
new and modified or reconstructed sources.

VII.  Request for Comments

	Table 10 summarizes the topics on which we have specifically requested
comment throughout this preamble.  We note, however, that comments on
all aspects of this proposal are welcome.

Table 10.  Summary of Topics on Which Comment is Requested

Topic	Section in this preamble where topic is discussed

Effects of proposed PM, SO2 and NOx standard on modified or
reconstructed fluid catalytic cracking units. Also co-proposed 40 CFR
part 60, Subpart J standards for SO2 and PM and no NOx limits for
modified and reconstructed sources.	III.B. and V.E.1

Exemption for emergency flares.	IV.A

Exemption from monitoring for fuel gas streams related to commercial
liquid products.	IV.A

Exemption from monitoring for fuel gas streams generated by process
units that are intolerant of sulfur.	IV.A

Alternative PM limit for fluid catalytic cracking units based on
condensable PM as well as filterable PM.	V.E.1

Alternative lower (20 ppmv,40 ppmv) NOx limit, averaged over 365 days,
for fluid catalytic cracking units.	V.E.1

Co-propose no new NOx standard for fluid coking units.	V.E.2

Appropriate long-term average H2S concentration limit for fuel gas
combustion units, and requirement to monitor TRS instead of H2S for fuel
gas from coker units.	V.E.4

Various aspects of work practice standards to minimize routine flaring
and enhance SO2 control versus no standards:  alternative means of
eliminating flaring, number of “fuel gas rich” refineries, need for
a startup, shutdown, and malfunction plan (SSMP), including rationale
for or against requiring a root cause analysis for hydrocarbon releases
and sulfur shedding practices, and information about emission control
systems for coke cutting operations.

Also co-propose no requirements for routine flaring and no SSMP.	V.D.5

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

In setting standards, the CAA requires us to consider alternative
emission control approaches, taking into account the estimated costs as
well as impacts on energy, solid waste, and other effects.  We request
comment on whether we have identified the appropriate alternatives and
whether the proposed standards adequately take into consideration the
incremental effects in terms of emission reductions, energy, and other
effects of these alternatives.  We will consider the available
information in developing the final rule.

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

We are presenting estimates of the impacts for the proposed requirements
of subpart Ja that change the performance standards:  the emission
limits for fluid catalytic cracking units, sulfur recovery plants, fluid
coking units, fuel gas combustion devices, and process heaters, as well
as the work practice standards.  The proposed amendments to 40 CFR part
60, subpart J are clarifications to the existing rule, and they have no
emission reduction impacts.  The cost, environmental, and economic
impacts presented in this section are expressed as incremental
differences between the impacts of petroleum refining process units
complying with the proposed subpart Ja and the current NSPS requirements
of subpart J (i.e., baseline).  The impacts are presented for petroleum
refining process units that commence construction, reconstruction, or
modification over the next 5 years.  The analyses and the documents
referenced below can be found in Docket ID No. EPA-HQ-OAR-2007-0011.

In order to determine the incremental costs and emission reductions of
this proposed rule, we first estimated baseline impacts.  For new
sources, baseline costs and emission reductions were estimated for
complying with subpart J; incremental impacts for subpart Ja were
estimated as the costs to comply with subpart J subtracted from the
costs to comply with proposed subpart Ja.  Sources that are modified or
reconstructed over the next 5 years would comply with subpart J in the
absence of proposed subpart Ja.  We assumed that prior to reconstruction
or modification, these sources would either be subject to a consent
decree (equivalent to about 77 percent of the industry by capacity),
complying with subpart J or equivalent limits, or complying with 40 CFR
part 63, subpart UUU (MACT II).  Baseline costs and emission reductions
were estimated as the effort needed to comply with subpart J from one of
those three starting points.  The costs and emission reductions to
comply with proposed subpart Ja were estimated from those starting
points as well.  The estimated costs presented for work practice
standards include only the labor cost to prepare the required plan or
analysis; we did not attempt to quantify costs and emission reductions
for the variety of ways a facility may choose to implement those plans.
We assumed that each facility would evaluate their options and choose
the most cost-effective option for the facility’s unique position.
For further detail on the methodology of these calculations, see Docket
ID No. EPA-HQ-OAR-2007-0011.

When considering and selecting emission limits for the proposed rule, we
evaluated the cost-effectiveness of each option for new sources
separately from reconstructed and modified sources.  However, since our
selections for each process unit and pollutant were consistent for all
units, we are presenting our costs and emission reductions for the
overall rule.  We estimate that the proposed amendments will reduce
combined emissions of PM, SO2, and NOx about 55,800 tons/yr from the
baseline.  The estimated increase in annual cost, including annualized
capital costs, is about $54,100,000.  The overall cost-effectiveness is
about $970 per ton of pollutants removed.  The estimated nationwide
5-year incremental emissions reductions and cost impacts for the
proposed amendments are summarized in Table 11 of this preamble.

Table 11.  National Incremental Emission Reductions and Cost Impacts for
Petroleum Refinery Units Subject to Proposed Standards Under 40 CFR part
60, subpart Ja (Fifth Year After Proposal)

Process Unit	Pollutant	Total Capital Cost ($1,000)	Total Annual

Cost

($1,000/yr)	Annual Emission Reductions (tons/yr)	Cost-Effective-ness
($/ton)

FCCU	PM and SO2	40,000	9,500	9,500	1,000

FCCU	NOx	28,000	7,300	3,500	2,100

Fluid Coker	PM and SO2	14,000	4,800	23,000	210

Fluid Coker	NOx	4,500	970	760	1,300

SRP	SO2	1,100	680	550	1,200

Process Heaters and Fuel Gas Combustion	SO2	0	2,880	1,300	2,200

Process Heaters	NOx	140,000	28,000	17,000	1,600

Work Practices

	250

Total

230,000	54,000	56,000	970

B.  What are the secondary impacts?

Indirect or secondary air quality impacts of this proposed rule would
result from the increased electricity usage associated with the
operation of control devices.  Assuming that plants would purchase
electricity from a power plant, we estimate that the standards as
proposed would increase secondary emissions of criteria pollutants,
including PM, SO2, NOX, and CO from power plants.  For new, modified or
reconstructed sources, this proposed rule would increase secondary PM
emissions by 24 Mg/yr (27 tpy); secondary SO2 emissions by about 970
Mg/yr (1,100 tpy); secondary NOX emissions by about 480 Mg/yr (530 tpy);
and secondary CO emissions by about 16 Mg/yr (17 tpy) for the 5 years
following proposal.

As explained earlier, we expect that affected facilities will control
emissions from fluid catalytic cracking units by installing and
operating ESP or wet gas scrubbers.  We also expect that the emissions
from the affected fluid coker will be controlled with a wet scrubber.
For these process units, we estimated solid waste impacts for both types
of control devices and water impacts for wet gas scrubbers.  In
addition, the controls needed by small sulfur recovery plants will
generate condensate.  We project that this proposed rule will generate
4.5 billion gallons of water per year for the 5 years following
proposal.  We also estimate that this proposed rule will generate 8,600
Mg/yr (7,800 tpy) of solid waste over those 5 years.

Energy impacts consist of the electricity and steam needed to operate
control devices and other equipment that would be required under the
proposed rule.  Our estimate of the increased energy demand includes the
electricity needed to produce the required amounts of steam as well as
direct electricity demand.  We project that this proposed rule would
increase overall energy demand by about 170 gigawatt-hours per year (590
billion British thermal units per year).

C.  What are the economic impacts?

This proposal affects certain new and reconstructed/modified sources
found at petroleum refineries as defined earlier in this preamble.  We
performed an economic impact analysis that estimates changes in prices
and output for gasoline nationally using the annual compliance costs
estimated for this proposal.  The methodology for this analysis
incorporates changes in producer and consumer behavior by considering
passthrough of increased production costs from producers to consumers.
All estimates are for the fifth year after proposal since this is the
year for which the compliance cost impacts are estimated.

The analysis estimates a price increase in gasoline of less than 0.02
percent nationally will take place along with a corresponding reduction
in gasoline output of less than 0.004 percent (or less than 6 million
gallons a year).  The overall total annual social costs, which reflect
changes in consumer and producer behavior in response to the compliance
costs, are $53.0 million (2005 dollars) or almost identical to the
compliance costs.

For more information, please refer to the economic impact analysis
report that is in the public docket for this proposed rule.

D.  What are the benefits?

    D.  What are the benefits?

    We estimate the monetized benefits of this proposed rule to be $957
million (2005$) in the fifth year after proposal.  We base the portion
of the benefits estimate derived from the PM2.5 and SO2 emission
reductions on the approach and methodology laid out in EPA's 2004
benefits analysis supporting the regulation of emissions from the
Industrial Boilers MACT (included in the Regulatory Impact Analysis
(RIA) for the Industrial Boilers and Process Heaters NESHAP, February
2004).  We chose the benefit analysis contained in this RIA as the basis
for estimating the benefits from emission reductions of these two
pollutants since most of the elements in that rule are similar to those
covered here.  These elements, which are the stack height, a number of
the controls applied, and the pollutants affected - PM2.5 and SO2, but
not NOx - are similar to those covered by the Industrial Boiler MACT
standard.

     We base the portion of the benefits estimate derived from the NOx
emission reductions on the approach and methodology laid out in EPA’s
2005 benefits analysis supporting the regulation of emissions from the
Clean Air Interstate Rule (CAIR) (included in the Regulatory Impact
Analysis for the Clean Air Interstate Rule, March 2005).  We chose the
CAIR analysis as the basis for estimating the benefits from emission
reductions of this pollutant since most of the elements in CAIR are
similar to those covered here.  These elements, which are the stack
height, a number of the controls applied, and the pollutant affected –
in this case, NOx only - are similar to those covered by CAIR.  These
three factors lead us to believe that we might reasonably estimate
benefits for this proposed rule using a benefits transfer approach and
values from the Industrial Boilers MACT analysis for estimating the SO2
and PM2.5 benefits of this rule, and the CAIR analysis for the NOx
benefits of the rule. Specifically, these estimates are based on
application of the benefits scaling approach derived from the benefits
analyses completed for these rulemakings.  As mentioned above, the
methodologies are laid out in the Industrial Boilers MACT and CAIR RIA.
A summary of the benefits estimates is in Table 12 below.

Table 12.  Summary of Benefits Estimates For Proposed NSPS

Pollutant	Monetized Benefits per Ton Emission Reduction 	Emission
Reductions (tons)	Total Monetized Benefits*(millions of 2005 dollars)

PM2.5	$88,000	3,221	$283.4

SO2	20,000	31,358	627.2

NOx	2,200	21,266	46.8

	Grand Total: $957.4

* All estimates are for the analysis year (fifth year after proposal).
Emission reductions reflect the combination of proposed options for both
new and reconstructed/modified sources.

	The specific estimates of benefits per ton of pollutant reductions
included in this analysis are largely driven by the concentration
response function for premature mortality, which is based on the
American Cancer Society cohort (ACS) (Pope, C.A. III, et al., “Lung
Cancer, Cardiopulmonary Mortality, and Long-Term Exposure to Fine
Particulate Air Pollution,” JAMA, 2002). Since the publication of
CAIR, the EPA’s Office of Air and Radiation has adopted a different
format for its benefits analysis in which characterization of the
uncertainty in the concentration response function is integrated into
the main benefits analysis.   The PM NAAQS analysis provides an
indication of the sensitivity of our results to the use of alternative
concentration response functions, including those derived from the
recently completed expert elicitation study.  Specifically, compared to
the final PM NAAQS estimate of the mean mortality from the ACS cohort,
the expert-based premature mortality incidence ranged from 50 percent of
the mean ACS estimate to more than five times the size of the ACS mean
estimate.  The Agency is currently updating the estimates used here to
calculate the benefits of the proposed NSPS and intends to consider
using these updated benefits estimates as part of an approach similar to
that used in the PM NAAQS RIA in the benefits analyses for the final
NSPS.

	  With the annualized costs of this rulemaking estimated at $54 million
(2005$) in the fifth year after proposal and with estimated benefits of
$957 million (2005$) for that same year, EPA believes that the benefits
are likely to exceed the costs by a significant margin even when taking
into account the uncertainties in the cost and benefit estimates.  For
more information, please refer to the RIA for this proposed rule that is
available in the docket.

IX.  Statutory and Executive Order Reviews

A.  Executive Order 12866:  Regulatory Planning and Review

	Under section 3(f)(1) of Executive Order 12866   SEQ CHAPTER \h \r 1
(58 FR 51735, October 4, 1993), this action is an "economically
significant regulatory action”  SEQ CHAPTER \h \r 1  because it is
likely to have an annual effect on the economy of $100 million or more.
Accordingly, EPA submitted this action to the Office of Management and
Budget (OMB) for review under Executive Order 12866 and any changes made
in response to OMB recommendations have been documented in the docket
for this action.

	    SEQ CHAPTER \h \r 1 In addition, EPA prepared an analysis of the
potential costs and benefits associated with this action.  This analysis
is contained in the Regulatory Impact Analysis (RIA) for the Proposed
Petroleum Refinery NSPS, EPA-452/R-07-006.  A copy of the analysis is
available in the docket for this action and the analysis is briefly
summarized here.  The monetized benefits of this action are estimated at
$957 million (2005 dollars), and the annualized costs of this action are
estimated at $54 million (2005 dollars).  We also estimated the economic
impacts, small business impacts, and energy impacts associated with this
action.  These analyses are included in the RIA and are summarized
elsewhere in this preamble.

B.  Paperwork Reduction Act

The proposed amendments to the existing standards of performance for
petroleum refineries would add a monitoring exemption for fuel gas
streams combusted in a fuel gas combustion device that are inherently
low in sulfur content.  The exemption would apply to fuel gas streams
that meet specified criteria or that the owner or operator demonstrates
are low sulfur according to the rule requirements.  The owner or
operator would submit a written application for the exemption containing
information needed to document the low sulfur content.  The application
is not a mandatory requirement and the incremental reduction in
monitoring burden that would occur as a result of the exemption would
not be significant compared to the baseline burden estimates for the
existing rule.  Therefore, we have not revised the information
collection request (ICR) for the existing rule.  The OMB has previously
approved the information collection requirements in the existing rule
(40 CFR part 60, subpart J) under the provisions of the Paperwork
Reduction Act, 44 U.S.C. 3501, et seq. and has assigned OMB control
number 2060-0022, EPA ICR number 1054.07.

A copy of the OMB-approved ICR for the Standards of Performance for
Petroleum Refineries may be obtained from Susan Auby, Collection
Strategies Division, Environmental Protection Agency (2822T), 1200
Pennsylvania Ave., NW, Washington, DC 20460, by e-mail at   HYPERLINK
<EMAIL_ADDRESS><EMAIL_ADDRESS>, or by calling (292)
566-1672.

The information collection requirements in the proposed standards of
performance for petroleum refineries (40 CFR part 60, subpart Ja) have
been submitted for approval to OMB under the Paperwork Reduction Act, 44
U.S.C. 3501 et seq.  The ICR document prepared by EPA has been assigned
EPA ICR number 2263.01.

The proposed standards of performance for petroleum refineries include
work practice requirements for delayed coking reactor vessel
depressuring and written plans to minimize emissions during startups,
shutdowns, and malfunctions.  Plants also would be required to analyze
the cause of any exceedance that releases more than 500 pounds per day
of SO2 above an allowable limit.  EPA is co-proposing work practice
standards that would include the requirement for delayed coking reactor
vessel depressuring but exclude the requirements for written plans and
root-cause analyses for SO2 emissions discharges exceeding allowable
limits by at least 500 pounds per day.  The proposed standards also
include testing, monitoring, recordkeeping, and reporting provisions.
Monitoring requirements may include control device operating parameters,
bag leak detection systems, or CEMS, depending on the type of process,
pollutant, and control device.  Exemptions are also proposed for small
emitters.  These requirements are based on recordkeeping and reporting
requirements in the NSPS General Provisions in 40 CFR part 60, subpart
A, and on specific requirements in subpart J or subpart Ja which are
mandatory for all operators subject to new source performance standards.
 These recordkeeping and reporting requirements are specifically
authorized by section 114 of the CAA (42 U.S.C. 7414).  All information
submitted to EPA pursuant to the recordkeeping and reporting
requirements for which a claim of confidentiality is made is safeguarded
according to EPA policies set forth in 40 CFR part 2, subpart B.

The annual burden for this information collection averaged over the
first 3 years of this ICR is estimated to total 6,084 labor-hours per
year at a cost of $526,241 per year.  The annualized capital costs are
estimated at $2,736,000 per year and operation and maintenance costs are
estimated at $1,627,200 per year.  We note that the capital costs as
well as the operation and maintenance costs are for the continuous
monitors; these costs are also included in the cost impacts presented in
section VIII.A of this preamble.  Therefore, the burden costs associated
with the continuous monitors presented in the ICR are not additional
costs incurred by affected sources subject to proposed subpart Ja.

Burden means the total time, effort, or financial resources expended by
persons to generate, maintain, retain, or disclose or provide
information to or for a Federal agency.  This includes the time needed
to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to comply
with any previously applicable instructions and requirements; train
personnel to be able to respond to a collection of information; search
data sources; complete and review the collection of information; and
transmit or otherwise disclose the information.

An agency may not conduct or sponsor, and a person is not required to
respond to a collection of information unless it displays a currently
valid OMB control number.  The OMB control numbers for EPA’s
regulations are listed in 40 CFR part 9.

To comment on the Agency’s need for this information, the accuracy of
the provided burden estimates, and any suggested methods for minimizing
respondent burden, including the use of automated collection techniques,
EPA has established a public docket for this rule, which includes this
ICR, under Docket ID number EPA-HQ-OAR-2007-0011.  Submit any comments
related to the ICR for this proposed rule to EPA and OMB.  See
‘Addresses’ section at the beginning of this document for where to
submit comments to EPA.  Send comments to OMB at the Office of
Information and Regulatory Affairs, Office of Management and Budget, 725
17th Street, NW, Washington, DC 20503, Attention: Desk Office for EPA.
Since OMB is required to make a decision concerning the ICR between 30
and 60 days after [INSERT DATE OF PUBLICATION OF THIS PROPOSED RULE IN
THE FEDERAL REGISTER], a comment to OMB is best assured of having its
full effect if OMB receives it by [INSERT DATE 30 DAYS AFTER PUBLICATION
OF THIS PROPOSED RULE IN THE FEDERAL REGISTER].  The final rule will
respond to any OMB or public comments on the information collection
requirements contained in this proposal.

C.  Regulatory Flexibility Act

	The Regulatory Flexibility Act (RFA) generally requires an agency to
prepare a regulatory flexibility analysis of any rule subject to notice
and comment rulemaking requirements under the Administrative Procedure
Act or any other statute unless the agency certifies that the rule will
not have a significant economic impact on a substantial number of small
entities.  Small entities include small businesses, small organizations,
and small governmental jurisdictions.

	For purposes of assessing the impact of today’s proposed action on
small entities, small entity is defined as:  (1) a small business whose
parent company has no more than 1,500 employees and no more than 125,000
barrels per day total operable atmospheric crude oil distillation
capacity, depending on the size definition for the affected NAICS code
(as defined by Small Business Administration (SBA) size standards); (2)
a small governmental jurisdiction that is a government of a city,
county, town, school district, or special district with a population of
less than 50,000; and (3) a small organization that is any
not-for-profit enterprise which is independently owned and operated and
is not dominant in its field.

After considering the economic impact of today’s proposed action on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities.  Of the 58
entities that we expect could be affected by today’s proposed action,
24 of these (or 41 percent) are classified as small according to the SBA
small business size standard listed previously.  Of these 24 affected
entities, one small entity is expected to incur an annualized compliance
cost of more than 1.0 percent to comply with today’s proposed action.
In addition, the impact on gasoline prices nationwide is expected to be
less than 0.02 percent of the baseline gasoline price, and this
represents less than a 1 cent increase in the price per gallon of
gasoline. Also, the output of gasoline in the U.S. is expected to fall
by less than 0.004 percent, or less than 6 million gallons per year in
the U.S.  For more information, please refer to the economic impact
analysis that is in the public docket for this rulemaking.

Although this proposed action would not have a significant economic
impact on a substantial number of small entities, EPA nonetheless has
tried to reduce the impact of this proposed action on small entities by
incorporating specific standards for small sulfur recovery plants and
streamlining procedures for exempting inherently low-sulfur fuel gases
from continuous monitoring.  We continue to be interested in the
potential impacts of this proposed action on small entities and welcome
comments on issues related to such impacts.

D.  Unfunded Mandates Reform Act

Title II of the Unfunded Mandates Reform Act (UMRA) of 1995, Public Law
104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector.  Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with “Federal mandates” that
may result in expenditures by State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
1 year.  Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective, or least burdensome alternative
that achieves the objectives of the rule.  The provisions of section 205
do not apply when they are inconsistent with applicable law.  Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective, or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted.  Before EPA establishes any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, it must have developed under
section 203 of the UMRA a small government agency plan.  The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of EPA regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.

EPA has determined that this proposed action does not contain a Federal
mandate that may result in expenditures of $100 million or more for
State, local, and tribal governments, in the aggregate, or the private
sector in any 1 year.  As discussed earlier in this preamble, the
estimated expenditures for the private sector in the fifth year after
proposal are $54 million.  Thus, this proposed action is not subject to
the requirements of section 202 and 205 of the UMRA.  In addition, EPA
has determined that this proposed action contains no regulatory
requirements that might significantly or uniquely affect small
governments.  This proposed action contains no requirements that apply
to such governments, imposes no obligations upon them, and would not
result in expenditures by them of $100 million or more in any 1 year or
any disproportionate impacts on them.  Therefore, this proposed action
is not subject to the requirements of section 203 of the UMRA.

E.  Executive Order 13132:  Federalism

Executive Order 13132 (64 FR 43255, August 10, 1999), requires EPA to
develop an accountable process to ensure “meaningful and timely input
by State and local officials in the development of regulatory policies
that have federalism implications.”  “Policies that have federalism
implications” is defined in the Executive Order to include regulations
that have “substantial direct effects on the States, on the
relationship between the national government and the States, or on the
distribution of power and responsibilities among the various levels of
government.”

This proposed action does not have federalism implications.  It will not
have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government, as
specified in Executive Order 13132.  None of the affected facilities are
owned or operated by State governments.  Thus, Executive Order 13132
does not apply to this proposed action.

In the spirit of Executive Order 13132, and consistent with EPA policy
to promote communications between EPA and State and local governments,
EPA specifically solicits comment on this proposed action from State and
local officials.

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

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

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

Executive Order 13045 “Protection of Children from Environmental
Health Risks and Safety Risks” (62 FR 19885, April 23, 1997) applies
to any rule that:  (1) is determined to be “economically
significant” as defined under Executive Order 12866, and (2) concerns
an environmental health or safety risk that EPA has reason to believe
may have a disproportionate effect on children.  If the regulatory
action meets both criteria, the Agency must evaluate the environmental
health or safety effects of the planned rule on children, and explain
why the planned regulation is preferable to other potentially effective
and reasonably feasible alternatives considered by the Agency.

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

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

This rule is not a “significant energy action” as defined in
Executive Order 13211, “Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use” (66 FR
28355, May 22, 2001) because it is not likely to have a significant
adverse effect on the supply, distribution, or use of energy.  We
prepared an analysis of the impacts on energy markets as part of our
economic impact analysis for today’s proposed action.  Our analysis
shows that there is a reduction in gasoline output of less than 6
million gallons per year, or less than 400 barrels of gasoline
production per day, in the fifth year after proposal of this proposed
action.  In addition, our analysis shows that there is an increase in
gasoline prices of less than 0.02 percent in the fifth year after
proposal of this proposed action.  Given this degree of increase in
domestic gasoline prices, no significant increase in our dependence on
foreign energy supplies should take place.  Finally, today’s proposed
action will have no adverse effect on crude oil supply, coal production,
electricity production, and energy distribution.  Based on the findings
from the analysis of impacts on energy markets, we conclude that
today’s proposed action is not a “significant energy action” as
defined in Executive Order 13211.  For more information on this
analysis, please refer to the economic impact analysis for this
rulemaking.  This analysis is found in the public docket.

I.  National Technology Transfer and Advancement Act

	Section 12(d) of the National Technology Transfer and Advancement Act
(NTTAA) of 1995 (Public Law No. 104-113, Section 12(d), 15 U.S.C. 272
note) directs EPA to use voluntary consensus standards (VCS) in its
regulatory activities, unless to do so would be inconsistent with
applicable law or otherwise impractical.  The VCS are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by VCS
bodies.  The NTTAA directs EPA to provide Congress, through OMB,
explanations when the Agency does not use available and applicable VCS.

	Today’s proposed rule (subpart Ja) involves technical standards.  The
EPA cites the following standards: EPA Methods 1, 2, 3, 3A, 3B, 5, 6,
6A, 6B, 6C, 7, 7A, 7C, 7D, 7E, 10, 10A, 11, 15, 15A, and 16 of 40 CFR
part 60, appendix A; Performance Specifications 2, 3, 4, 5, 7, and 11 in
40 CFR part 60, appendix B; and Appendix F to 40 CFR Part 60.  This
rule also cites ASME PTC 19.10-1981, “Flue and Exhaust Gas
Analyses,” for its manual methods of measuring the content of the
exhaust gas.  This part of ASME PTC 19.10-1981 is an acceptable
alternative to EPA Methods 3B, 6, 6A, 6B, 7, 7C, and 15A.

	Consistent with the NTTAA, EPA conducted searches to identify VCS in
addition to these methods.  No applicable VCS were identified for EPA
Methods 7D and 11; EPA Performance Specifications 3, 4, 5, and 7; and
Appendix F to 40 CFR part 60.  The search and review results are in the
docket for this rule.

	The search for emissions measurement procedures identified 22 other
VCS.  The EPA determined that these 22 standards identified for
measuring emissions of the targeted pollutants or surrogates subject to
emission standards in this rule were impractical alternatives to EPA
test methods for the purposes of this rule.  Therefore, EPA does not
intend to adopt these standards for this purpose.  The reasons for the
determinations for the 22 standards are discussed in the memorandum
submitted to the docket to this rule.

	Both the proposed amendments for subpart J and the proposed rule
(subpart Ja) cite the Gas Processor’s Association Method 2377-86,
“Test for Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using
Length of Stain Tubes” (incorporated by reference—see 40 CFR 60.17)
as an acceptable method for determining the H2S content of low sulfur
streams.  The amendments to subpart J do not include any other technical
standards.

	Consistent with the NTTAA, EPA conducted searches to identify VCS in
addition to Gas Processor’s Association Method 2377-86.  No applicable
voluntary consensus standards were identified for Gas Processor’s
Association Method 2377-86.  The search and review results are in the
docket for this rule.

Under 40 CFR 60.13(i) of the NSPS General Provisions, a source may apply
to EPA for permission to use alternative test methods or alternative
monitoring requirements in place of any required testing methods,
performance specifications, or procedures in the proposed rule and
amendments.

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

Executive Order 12898 (59 FR 7629 (Feb. 16, 1994)) establishes Federal
executive policy on environmental justice.  Its main provision directs
Federal agencies, to the greatest extent practicable and permitted by
law, to make environmental justice part of their mission by identifying
and addressing, as appropriate, disproportionately high and adverse
human health or environmental effects of their programs, policies, and

activities on minority populations and low-income populations in the
United States.  EPA has determined that the proposed amendments would
not have disproportionately high and adverse human health or
environmental effects on minority or low-income populations because they
do not affect the level of protection provided to human health or the
environment.  The proposed

amendments are clarifications which do not relax the control measures on
sources regulated by the rule and therefore will not

cause emissions increases from these sources.  EPA has determined that
the proposed standards would not have disproportionately high and
adverse human health or environmental effects on minority or low-income
populations because they would increase the level of environmental
protection for all affected populations without having any
disproportionately high and adverse human health or environmental
effects on any population, including any

minority or low-income population.  These proposed standards would
reduce emissions of criteria pollutants from all new, reconstructed, or
modified sources at petroleum refineries, decreasing the amount of such
emissions to which all affected populations are exposed.

List of Subjects in 40 CFR Part 60

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

Dated:

Stephen L. Johnson,

Administrator.For the reasons stated in the preamble, title 40, chapter
I of the Code of Federal Regulations is proposed to be amended as
follows:

PART 60--[AMENDED]

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

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

Subpart A--[AMENDED]

	2.  Section 60.17 is amended by:

	a.  Revising paragraph (h)(4),

	b.  Revising the last sentence of paragraph (m) introductory text, and

	c.  Revising paragraph (m)(1) to read as follows:

§60.17  Incorporations by reference.

*  *  *  *  *

	(h)  *  *  *

	(4)  ANSI/ASME PTC 19.10–1981, Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus], IBR approved for Tables 1 and 3 of
subpart EEEE, Tables 2 and 4 of subpart FFFF, §60.106(e)(2) of subpart
J, §§60.104a(d)(3), (d)(6), (g)(3), (g)(4), (g)(6), (i)(3), (i)(4),
(j)(3), (j)(4), (j)(4)(iii), and 60.105a(d)(4), (e)(4), (f)(2), and
(f)(4), and 60.106a(a)(1)(ii), (a)(1)(iv), (a)(2)(ii), (a)(2)(iv),
(a)(3)(ii), (a)(3)(iv), and (a)(4)(iii), and 60.107a(a)(1)(ii),
(a)(1)(iv), (a)(2)(ii), (c)(2), and (c)(4) of subpart Ja, and
§§60.4415(a)(2) and 60.4415(a)(3) of subpart KKKK of this part.

*  *  *  *  *

	(m)  *  *  *  You may inspect a copy at EPA’s Air and Radiation
Docket and Information Center, Room 3334, 1301 Constitution Ave., NW,
Washington, DC 20460.

	(1)  Gas Processors Association Method 2377-86, Test for Hydrogen
Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes,
IBR approved for §§60.105(b)(1)(iv), 60.107a(b)(1)(iv), 60.334(h)(1),
60.4360, and 60.4415(a)(1)(ii).

*  *  *  *  *

Subpart J--[AMENDED]

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

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

	(a)  The provisions of this subpart are applicable to the following
affected facilities in petroleum refineries:  fluid catalytic cracking
unit catalyst regenerators, fuel gas combustion devices, and all Claus
sulfur recovery plants except Claus plants with a design capacity of 20
long tons per day (LTD) or less. *  *  *

	(b)  Any fluid catalytic cracking unit catalyst regenerator or fuel gas
combustion device under paragraph (a) of this section which commences
construction, reconstruction, or modification after June 11, 1973, and
on or before [INSERT DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE
FEDERAL REGISTER], or any Claus sulfur recovery plant under paragraph
(a) of this section which commences construction, reconstruction, or
modification after October 4, 1976, and on or before [INSERT DATE OF
PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER], is subject
to the requirements of this subpart except as provided under paragraphs
(c) and (d) of this section.

	(c)  Any fluid catalytic cracking unit catalyst regenerator under
paragraph (b) of this section which commences construction,
reconstruction, or modification on or before January 17, 1984, is
exempted from §60.104(b).

(d)  Any fluid catalytic cracking unit in which a contact material
reacts with petroleum derivatives to improve feedstock quality and in
which the contact material is regenerated by burning off coke and/or
other deposits and that commences construction, reconstruction, or
modification on or before January 17, 1984, is exempt from this subpart

*  *  *  *  *

	4.  Section 60.101 is amended by revising paragraphs (d), (i), (j), and
(k) to read as follows:

§60.101  Definitions.

*  *  *  *  *

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

*  *  *  *  *

	(i)  Claus sulfur recovery plant means a series of process units which
recover sulfur from hydrogen sulfide (H2S) by a vapor-phase catalytic
reaction of sulfur dioxide and H2S.  The Claus sulfur recovery plant
includes the reactor furnace and waste heat boiler, catalytic reactors,
sulfur pits, and, if present, oxidation or reduction control systems.
One Claus sulfur recovery plant may consist of multiple trains.

	(j)  Oxidation control system means an emission control system which
reduces emissions from sulfur recovery plants by converting these
emissions to sulfur dioxide and recycling the sulfur dioxide to the
reactor furnace or the first-stage catalytic reactor of the Claus sulfur
recovery plant.

	(k)  Reduction control system means an emission control system which
reduces emissions from sulfur recovery plants by converting these
emissions to H2S and recycling the H2S to the reactor furnace or the
first-stage catalytic reactor of the Claus sulfur recovery plant.

*  *  *  *  *

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

§60.102  Standard for particulate matter.

*  *  *  *  *

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

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

§60.104   Standards for sulfur oxides.

*  *  *  *  *

	(b)  *  *  *

(1)  With an add-on control device, reduce SO2 emissions to the
atmosphere by 90 percent or maintain SO2 emissions to the atmosphere
less than or equal to 50 ppm by volume (ppmv), whichever is less
stringent; or

(2)  Without the use of an add-on control device to reduce SO2
emissions, maintain sulfur oxides emissions calculated as SO2 to the
atmosphere less than or equal to 9.8 kg/Mg (20 lb/ton) coke burn-off; or

*  *  *  *  *

	7.  Section 60.105 is amended by:

	a.  Revising the first sentence of paragraph (a)(3) introductory text;

	b.  Revising paragraph (a)(3)(iv);

	c.  Revising paragraph (a)(4) introductory text;

	d.  Adding paragraph (a)(4)(iv);

	e.  Revising paragraph (a)(8) introductory text;

	f.  Revising paragraph (a)(8)(i); and

	g.  Adding paragraph (b) to read as follows:

§60.105  Monitoring of emissions and operations.

	(a)  *  *  *

(3)  For fuel gas combustion devices subject to §60.104(a)(1), either
an instrument for continuously monitoring and recording the
concentration by volume (dry basis, 0 percent excess air) of SO2
emissions into the atmosphere or monitoring as provided in paragraph
(a)(4) of this section). * * *

*  *  *  *  *

(iv)  Fuel gas combustion devices having a common source of fuel gas may
be monitored at only one location (i.e., after one of the combustion
devices), if monitoring at this location accurately represents the SO2
emissions into the atmosphere from each of the combustion devices.

	(4)  Instead of the SO2 monitor in paragraph (a)(3) of this section for
fuel gas combustion devices subject to §60.104(a)(1), an instrument for
continuously monitoring and recording the concentration (dry basis) of
H2S in fuel gases before being burned in any fuel gas combustion device.

*  *  *  *  *

	(iv)  The owner or operator of a fuel gas combustion device is not
required to comply with paragraph (a)(3) or (4) of this section for
streams that are exempt under §60.104(a)(1) and fuel gas streams
combusted in a fuel gas combustion device that are inherently low in
sulfur content.  Fuel gas streams meeting one of the requirements in
paragraphs (a)(4)(iv)(A) through (D) of this section will be considered
inherently low in sulfur content.  If the composition of a fuel gas
stream changes such that it is no longer exempt under §60.104(a)(1) or
it no longer meets one of the requirements in paragraphs (a)(4)(iv)(A)
through (D) of this section, the owner or operator must begin continuous
monitoring under paragraph (a)(3) or (4) of this section within 15 days
of the change.

	(A)  Pilot gas for heaters and flares.

	(B)  Gas streams that meet commercial-grade product specifications and
have a sulfur content of 30 ppmv or less.

	(C)  Fuel gas streams produced in process units that are intolerant to
sulfur contamination, such as fuel gas streams produced in the hydrogen
plant, the catalytic reforming unit, and the isomerization unit.

	(D)  Other streams that an owner or operator demonstrates are
low-sulfur according to the procedures in paragraph (b) of this section.

*  *  *  *  *

(8)  An instrument for continuously monitoring and recording
concentrations of SO2 in the gases at both the inlet and outlet of the
SO2 control device from any fluid catalytic cracking unit catalyst
regenerator for which the owner or operator seeks to comply specifically
with the 90 percent reduction option under §60.104(b)(1).

(i)  The span value of the inlet monitor shall be set at 125 percent of
the maximum estimated hourly potential SO2 emission concentration
entering the control device, and the span value of the outlet monitor
shall be set at 50 percent of the maximum estimated hourly potential SO2
emission concentration entering the control device.

*  *  *  *  *

	(b)  An owner or operator may demonstrate that a gas stream combusted
in a fuel gas combustion device subject to §60.104(a)(1) that is not
specifically exempted in §60.105(a)(4)(iv) is inherently low in sulfur.
 A gas stream that is determined to be low-sulfur is exempt from the
monitoring requirements in paragraphs (a)(3) and (4) of this section
until there are changes in operating conditions or stream composition.

	(1)  The owner or operator shall submit to the Administrator a written
application for an exemption from monitoring.  The application must
contain the following information:

	(i)  A description of the gas stream/system to be considered, including
submission of a portion of the appropriate piping diagrams indicating
the boundaries of the gas stream/system, and the affected fuel gas
combustion device(s) to be considered;

	(ii)  A statement that there are no crossover or entry points for sour
gas (high H2S content) to be introduced into the gas stream/system (this
should be shown in the piping diagrams);

	(iii)  An explanation of the conditions that ensure low amounts of
sulfur in the gas stream (i.e., control equipment or product
specifications) at all times;

	(iv)  The supporting test results from sampling the requested gas
stream/system demonstrating that the sulfur content is less than 5 ppmv.
 Minimum sampling data must consist of 2 weeks of daily monitoring (14
grab samples) for frequently operated gas streams/systems; for
infrequently operated gas streams/systems, seven grab samples must be
collected unless other additional information would support reduced
sampling.  The owner or operator shall use detector tubes
(“length-of-stain tube” type measurement) following the Gas
Processor Association’s Test for Hydrogen Sulfide and Carbon Dioxide
in Natural Gas Using Length of Stain Tubes, 1986 revision with ranges
0-10/0-100 ppm (N =10/1) to test the applicant stream (incorporated by
reference-see §60.17).

	(v)  A description of how the 2 weeks (or seven samples for
infrequently operated gas streams/systems) of monitoring results
compares to the typical range of H2S concentration (fuel quality)
expected for the gas stream/system going to the affected fuel gas
combustion device (e.g., the 2 weeks of daily detector tube results for
a frequently operated loading rack included the entire range of products
loaded out, and, therefore, should be representative of typical
operating conditions affecting H2S content in the gas stream going to
the loading rack flare).

	(2)  Once EPA receives a complete application, the Administrator will
determine whether an exemption is granted.  The owner or operator shall
continue to comply with the monitoring requirements in paragraph (a)(3)
or (paragraph (a)(4) of this section until an exemption is granted.

	(3)  Once an exemption from continuous monitoring is granted, no
further action is required unless refinery operating conditions change
in such a way that affects the exempt gas stream/system (e.g., the
stream composition changes).  If such a change occurs, the owner or
operator will follow the procedures in paragraph (b)(2)(i), (b)(2)(ii),
or (b)(2)(iii) of this section.

	(i)  If the operation change results in a sulfur content that is still
within the range of concentrations included in the original application,
the owner or operator shall conduct an H2S test on a grab sample and
record the results as proof that the concentration is still within the
range.

	(ii)  If the operation change results in a sulfur content that is
outside the range of concentrations included in the original
application, the owner or operator may submit a new application
following the procedures of paragraph (b)(1) of this section within 60
days (or within 30 days after the seventh grab sample is tested for
infrequently operated process units).

	(iii)  If the operation change results in a sulfur content that is
outside the range of concentrations included in the original application
and the owner or operator chooses not to submit a new application, the
owner or operator must begin continuous monitoring as specified in
paragraphs (a)(3) or (a)(4) of this section within 60 days of the
operation change.

*  *  *  *  *

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

§60.106   Test methods and procedures.

*  *  *  *  *

	(b)  *  *  *

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

 − K3Qr(%CO/2 + %CO2 + %O2) + K3Qoxy (%Ooxy)

Where:

Rc 	= Coke burn-off rate, kilograms per hour (kg/hr) (lb/hr).

Qr	= Volumetric flow rate of exhaust gas from fluid

       catalytic cracking unit regenerator before

       entering the emission control system, dscm/min

	  (dscf/min).

Qa 	= Volumetric flow rate of air to fluid catalytic

       cracking unit regenerator, as determined from the

       fluid catalytic cracking unit control room

	  instrumentation, dscm/min (dscf/min).

Qoxy   = Volumetric flow rate of O2 enriched air to fluid

       Catalytic cracking unit regenerator, as determined

       from the fluid catalytic cracking unit control room

       instrumentation, dscm/min (dscf/min).

%CO2 = Carbon dioxide concentration in fluid catalytic

       cracking unit regenerator exhaust, percent by volume (dry basis).

%CO  = CO concentration in FCCU

       regenerator exhaust, percent by volume (dry basis).

%O2  = O2 concentration in fluid catalytic cracking unit

       regenerator exhaust, percent by volume (dry basis).

%Ooxy = O2 concentration in O2 enriched air stream inlet to

       the fluid catalytic cracking unit regenerator,

       percent by volume (dry basis).

K1 	= Material balance and conversion factor, 0.2982 (kg-

       min)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)].

K2 	= Material balance and conversion factor, 2.088 (kg-

       min)/(hr-dscm-%) [0.1303 (lb-min)/(hr-dscf-%)].

K3 	= Material balance and conversion factor, 0.0994 (kg-

       min)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].

*  *  *  *  *

	(e)  *  *  *

(2)  Where emissions are monitored by §60.105(a)(3), compliance with
§60.104(a)(1) shall be determined using Method 6 or 6C and Method 3 or
3A.  The method ASME PTC 19.10-1981, “Flue and Exhaust Gas
Analyses,” (incorporated by reference-see §60.17) is an acceptable
alternative to EPA Method 6.  *  *  *

*  *  *  *  *

	9.  Section 60.107 is amended by:

	a.  Revising the first sentence of paragraph (c)(1)(i);

	b.  Redesignating paragraphs (e) and (f) as (f) and (g); and

	c.  Adding paragraph (e) to read as follows:

§60.107  Reporting and recordkeeping requirements.

*  *  *  *  *

	(c)  *  *  *

	(1)  *  *  *

(i)  The average percent reduction and average concentration of sulfur
dioxide on a dry, O2-free basis in the gases discharged to the
atmosphere from any fluid cracking unit catalyst regenerator for which
the owner or operator seeks to comply with §60.104(b)(1) is below 90
percent and above 50 ppmv, as measured by the continuous monitoring
system prescribed under §60.105(a)(8), or above 50 ppmv, as measured by
the outlet continuous monitoring system prescribed under §60.105(a)(9).
*  *  *

*  *  *  *  *

(e)  For each stream combusted in a fuel gas combustion device subject
to §60.104(a)(1), if an owner or operator determines that one of the
exemptions listed in §60.105(a)(4)(iv) applies to that stream, the
owner or operator shall maintain records of the specific exemption
chosen for each stream.  If the owner or operator applies for the
exemption described in §60.105(a)(4)(iv)(D), the owner or operator must
keep a copy of the application as well as the letter from the
Administrator granting approval of the application.

*  *  *  *  *

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

§60.108  Performance test and compliance provisions.

*  *  *  *  *

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

	11.  Section 60.109 is amended by redesignating paragraph (b)(2) as
(b)(3) and adding paragraph (b)(2) to read as follows:

§60.109  Delegation of authority.

*  *  *  *  *

	(b)  *  *  *

	(1)  *  *  *

	(2)  Section 60.105(b), and

*  *  *  *  *

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

Subpart Ja--Standards of Performance for Petroleum Refineries for which
Construction, Reconstruction, or Modification Commenced After [INSERT
DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER]

Sec.

60.100a  Applicability, designation of affected facility,

         and reconstruction.

60.101a  Definitions.

60.102a  Emissions limitations.

60.103a  Work practice standards.

60.104a  Performance tests.

60.105a  Monitoring of emissions and operations for fluid

         catalytic cracking units (FCCU) and fluid coking

    	    units.

60.106a  Monitoring of emissions and operations for sulfur

         recovery plants.

60.107a  Monitoring of emissions and operations for process

         heaters and other fuel gas combustion devices.

60.108a  Recordkeeping and reporting requirements.

60.109a  Delegation of authority.

Subpart Ja--Standards of Performance for Petroleum Refineries for which
Construction, Reconstruction, or Modification Commenced After [INSERT
DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER]

§60.100a  Applicability, designation of affected facility, and
reconstruction.

	(a)  The provisions of this subpart apply to the following affected
facilities in petroleum refineries:  fluid catalytic cracking units
(FCCU), fluid coking units, delayed coking units, process heaters, other
fuel gas combustion devices, fuel gas producing units, and sulfur
recovery plants.  The sulfur recovery plant need not be physically
located within the boundaries of a petroleum refinery to be an affected
facility, provided it processes gases produced within a petroleum
refinery.

	(b)  The provisions of this subpart apply only to affected facilities
under paragraph (a) of this section which commence construction,
modification, or reconstruction after [INSERT DATE OF PUBLICATION OF
THIS PROPOSED RULE IN THE FEDERAL REGISTER].

	(c)  For purposes of this subpart, under §60.15, the “fixed capital
cost of the new components” includes the fixed capital cost of all
depreciable components which are or will be replaced pursuant to all
continuous programs of component replacement which are commenced within
any 2-year period following [INSERT DATE OF PUBLICATION OF THIS PROPOSED
RULE IN THE FEDERAL REGISTER].  For purposes of this paragraph,
“commenced” means that an owner or operator has undertaken a
continuous program of component replacement or that an owner or operator
has entered into a contractual obligation to undertake and complete,
within a reasonable time, a continuous program of component replacement.

§60.101a  Definitions.

	Terms used in this subpart are defined in the Clean Air Act, in §60.2,
and in this section.

	Coke burn-off means the coke removed from the surface of the FCCU
catalyst by combustion in the catalyst regenerator.  The rate of coke
burn-off is calculated by the formula specified in §60.104a.

	Contact material means any substance formulated to remove metals,
sulfur, nitrogen, or any other contaminant from petroleum derivatives.

	Delayed coking unit means one or more coking units in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is produced in a series of closed, batch system reactors.

	Flexicoking unit means one or more coking units in which high molecular
weight petroleum derivatives are thermally cracked and petroleum coke is
produced then gasified to produce a synthetic fuel gas.

	Fluid catalytic cracking unit means one or more units in which
petroleum derivatives are continuously charged and hydrocarbon molecules
in the presence of a catalyst suspended in a fluidized bed are fractured
into smaller molecules, or react with a contact material suspended in a
fluidized bed to improve feedstock quality for additional processing and
the catalyst or contact material is continuously regenerated by burning
off coke and other deposits.  The unit includes the riser, reactor,
regenerator, air blowers, spent catalyst or contact material

stripper, catalyst or contact material recovery equipment, and
regenerator equipment for controlling air pollutant emissions and for
heat recovery.

	Fluid coking unit means one or more coking units in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is continuously produced in a fluidized bed system and in
which the fluid coking burner exhaust gas is continuously released to
the atmosphere.  The fluid coking unit includes equipment for
controlling air pollutant emissions and for heat recovery on the fluid
coking burner exhaust vent.  Flexicoking units that use gasifiers to
generate a synthetic fuel gas for use in other processes and that do not
exhaust to the atmosphere are not considered fluid coking units under
this subpart.

	Fresh feed means any petroleum derivative feedstock stream charged
directly into the riser or reactor of a FCCU except for petroleum
derivatives recycled within the FCCU, fractionator, or gas recovery
unit.

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

	Fuel gas producing unit means any refinery process unit that produces
fuel gas as a routine part of normal operations.  A fuel gas producing
unit includes, but is not limited to, the atmospheric distillation unit,
the FCCU, the catalytic hydrocracking unit, all types of coking units,
and the catalytic reforming unit.

	Other fuel gas combustion device means any equipment, such as boilers
and flares, used to combust fuel gas, except process heaters and
facilities in which gases are combusted to produce sulfur or sulfuric
acid.

	Oxidation control system means an emission control system which reduces
emissions from sulfur recovery plants by converting these emissions to
sulfur dioxide (SO2) and recycling the SO2 to the reactor furnace or the
first-stage catalytic reactor of the Claus sulfur recovery plant.

	Petroleum means the crude oil removed from the earth and the oils
derived from tar sands, shale, and coal.

	Petroleum refinery means any facility engaged in producing gasoline,
kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt
(bitumen) or other products through distillation of petroleum or through
redistillation, cracking, or reforming of unfinished petroleum
derivatives.

	Process gas means any gas generated by a petroleum refinery process
unit, except fuel gas and process upset gas as defined in this section.

	Process heater means an enclosed combustion device used to transfer
heat indirectly to process stream materials (liquids, gases, or solids)
or to a heat transfer material for use in a process unit instead of
steam.

	Process upset gas means any gas generated by a petroleum refinery
process unit as a result of upset or malfunction.

	Reduced sulfur compounds means hydrogen sulfide (H2S), carbonyl
sulfide, and carbon disulfide.

	Reduction control system means an emission control system which reduces
emissions from sulfur recovery plants by converting these emissions to
H2S and recycling the H2S to the reactor furnace or the first-stage
catalytic reactor of the Claus sulfur recovery plant.

	Refinery process unit means any segment of the petroleum refinery in
which a specific processing operation is conducted.

	Sulfur recovery plant means all process units which recover sulfur from
H2S and/or SO2 at a petroleum refinery.  The sulfur recovery plant also
includes vessels, tanks, or pits used to store the recovered sulfur
product.  For example, a Claus sulfur recovery plant includes:  reactor
furnace and waste heat boiler, catalytic reactors, sulfur pits, and, if
present, oxidation or reduction control systems, or incinerator, thermal
oxidizer, or similar combustion device.

§60.102a  Emissions limitations.

	(a)  Each owner or operator that is subject to the requirements of this
subpart shall comply with the emissions limitations in paragraphs (b)
through (h) of this section on and after the date on which the initial
performance test, required by §60.8, is completed, but not later than
60 days after achieving the maximum production rate at which the
affected facility will be operated, or 180 days after initial startup,
whichever comes first.

Option 1 for paragraph (b):

	(b)  An owner or operator subject to the provisions of this subpart
shall not discharge or cause the discharge into the atmosphere from any
FCCU or fluid coking unit:

	(1)  Particulate matter (PM) in excess of 0.5 gram per kilogram (g/kg)
coke burn-off (0.5 pound (lb) PM/1,000 lbs coke burn-off) or 0.020
grains per dry standard cubic feet (gr/dscf) corrected to 0 percent
excess air; and

	(2)  NOx in excess of 80 parts per million by volume (ppmv), dry basis
corrected to 0 percent excess air, on a 7-day rolling average basis; and

	(3)  SO2 in excess of 50 ppmv dry basis corrected to 0 percent excess
air, on a 7-day rolling average basis and 25 ppmv, dry basis corrected
to 0 percent excess air, on a 365-day rolling average basis; and

	(4)  Carbon monoxide (CO) in excess of 500 ppmv, dry basis corrected to
0 percent excess air, on an hourly average basis.

Option 2 for paragraph (b)

	(b)  Except as provided in paragraph (b)(2) of this section, an owner
or operator subject to the provisions of this subpart shall not
discharge or cause the discharge into the atmosphere from any FCCU or
fluid coking unit:

	(1)  Particulate Matter (PM) in excess of 0.5 gram per kilogram (g/kg)
coke burn-off (0.5 lb PM/1,000 lbs coke burn-off) or 0.020 grains per
dry standard cubic feet (gr/dscf) corrected to 0 percent excess air; and

	(2)  NOx in excess of 80 parts per million by volume (ppmv), dry basis
corrected to 0 percent excess air, on a 7-day rolling average basis.
This emissions limit does not apply to a fluid coking unit subject to
this subpart;

	(3)  SO2 in excess of 50 ppmv dry basis corrected to 0 percent excess
air, on a 7-day rolling average basis and 25 ppmv, dry basis corrected
to 0 percent excess air, on a 365-day rolling average basis; and

	(4)  Carbon monoxide (CO) in excess of 500 ppmv, dry basis corrected to
0 percent excess air, on an hourly average basis.

	(c)  The owner or operator of a FCCU or fluid coking unit that uses
continuous parameter monitoring systems (CPMS) according to
§60.105a(b)(1) shall comply with the applicable control device
parameter operating limit in paragraph (c)(1) or (c)(2) of this section.

	(1)  If the FCCU or fluid coking unit is controlled using an
electrostatic precipitator:

	(i)   The hourly average total power and secondary current to the
control device must not fall below the level established during the most
recent performance test; and

	(ii)  The exhaust coke burn-off rate must not exceed the level
established during the most recent performance test.

	(2)  If the FCCU or fluid coking unit is controlled using a wet
scrubber:

	(i)  The hourly average pressure drop must not fall below the level
established during the most recent performance test; and

	(ii)  The hourly average liquid-to-gas ratio must not fall below the
level established during the most recent performance test.

	(d)  The owner or operator of a FCCU or fluid coking unit that is
exempted from the requirement for a CO continuous emissions monitoring
system (CEMS) under §60.105a(g)(3) shall comply with the parameter
operating limits in paragraph (d)(1) or (d)(2) of this section.

	(1)  For a FCCU or fluid coking unit with no post-combustion control
device:

	(i)  The hourly average temperature of the exhaust gases exiting the
FCCU or fluid coking unit must not fall below the level established
during the most recent performance test.

	(ii)  The hourly average oxygen (O2) concentration of the exhaust gases
exiting the FCCU or fluid coking unit must not fall below the level
established during the most recent performance test.

	(2)  For a FCCU or fluid coking unit with a post-combustion control
device:

	(i)  The hourly average temperature of the exhaust gas vent stream
exiting the control device must not fall below the level established
during the most recent performance test.

	(ii)  The hourly average O2 concentration of the exhaust gas vent
stream exiting the control device must not fall below the level
established during the most recent performance test.

	(e)  Each owner or operator that is subject to the provisions of this
subpart shall comply with the following emissions limits for each sulfur
recovery plant:

	(1)  For a sulfur recovery plant with a capacity greater than 20 long
tons per day (LTD), the owner or operator shall not discharge or cause
the discharge of any gases into the atmosphere containing a combined SO2
and reduced sulfur compounds concentration in excess of 250 ppmv as SO2
(dry basis) at 0 percent excess air determined hourly on a 12-hour
rolling average basis.  If the sulfur recovery plant consists of
multiple process trains or release points the owner or operator shall
comply with the 250 ppmv limit for each process train or release point
or comply with a flow rate weighted average of 250 ppmv for all release
points from the sulfur recovery plant.

	(2)  For a sulfur recovery plant with a capacity of 20 LTD or less, the
owner or operator shall not discharge or cause the discharge of any
gases into the atmosphere containing combined SO2 and reduced sulfur
compounds mass emissions in excess of 1 percent by weight of sulfur
recovered, measured as the mass ratio of sulfur emitted (from all
release points combined) to sulfur recovered determined hourly on a
12-hour rolling average basis.

	(3)  For all sulfur recovery plants, regardless of size, the owner or
operator shall not discharge or cause the discharge of any gases into
the atmosphere containing H2S in excess of 10 ppmv (dry basis) at 0
percent excess air determined hourly on a 12-hour rolling average basis.

	(f)  The owner or operator of a sulfur recovery plant subject to the
H2S emissions limit in paragraph (e)(3) of this section and that uses
CPMS pursuant to §60.106a(a)(4) shall comply with the following
operating limits:

	(1)  The hourly average temperature of the exhaust gases exiting the
sulfur recovery plant must not fall below the level established during
the most recent performance test.

	(2)  The hourly average O2 concentration of the exhaust gases exiting
the sulfur recovery plant must not fall below the level established
during the most recent performance test.

	(g)  Each owner or operator subject to the provisions of this subpart
shall comply with the emission limitations in paragraphs (g)(1) through
(3) for each process heater and other fuel gas combustion device, except
as provided in paragraph (h) and (i) of this section.

	(1)  SO2 in excess of 20 ppmv (dry basis, corrected to 0 percent excess
air) on a 3-hour rolling average basis; and

(2)  SO2 in excess of 8 ppmv (dry basis, corrected to 0 percent excess
air), determined daily on a 365 successive day rolling average basis;
and

	(3)  For process heaters with a rated capacity of greater than 20
million British thermal units per hour, NOx in excess of 80 ppmv (dry
basis, corrected to 0 percent excess air) on a 24-hour rolling average
basis.

(h)  For process heaters that combust only fuel gas and for other fuel
gas combustion devices, the following emission limitations may be used
instead of the SO2 emission limits in paragraph (g)(1) and (2) of this
section:

	(1)  For process heaters and other fuel gas combustion devices that do
not combust fuel gas generated from a coking unit:

	(i)  H2S in excess of 160 ppmv determined hourly on a 3-hour rolling
average basis; and

	(ii)  H2S in excess of 60 ppmv determined daily on a 365 successive
calendar day rolling average basis.

	(2)  For process heaters and other fuel gas combustion devices that
combust fuel gas generated from a coking unit or fuel gas that is mixed
with fuel gas generated from a coking unit:

 	(i)  Total reduced sulfur (TRS) in excess of 160 ppmv determined
hourly on a 3-hour rolling average basis; and

	(ii)  TRS in excess of 60 ppmv determined daily on a 365 successive
calendar day rolling average basis.

	(i)  The combustion in a flare of process upset gases or fuel gas that
is released to the flare as a result of relief valve leakage or other
emergency malfunctions is exempt from paragraphs (g) and (h) of this
section.

Option 1 for §60.103a:

§60.103a  Work practice standards.

	(a)  Each owner or operator subject to the provisions of this subpart
shall not routinely release fuel gas to a flare from any fuel gas
producing unit.  The combustion in a flare of process upset gases or
fuel that that is released to the flare as a result of relief valve
leakage or other emergency malfunctions is exempt from this paragraph.

	(b)  The owner or operator shall develop a written startup, shutdown,
and malfunction plan that describes, in detail, procedures for operating
and maintaining each affected facility during periods of startup,
shutdown, and malfunction; and a program of corrective action for
malfunctioning process, air pollution control, and monitoring equipment
used to comply with the requirements of this subpart.  The owner or
operator may use the affected source's standard operating procedures
(SOP) manual, or an Occupational Safety and Health Administration (OSHA)
or other plan, provided the alternative plans meet all the requirements
of this section and are made available for inspection or submitted when
requested by the Administrator.

	(1)  The written plan must cover fluid catalytic cracking units, fluid
coking units, sulfur recovery plants (including tail gas treatment
system), amine treatment system, and fuel process heaters and other gas
combustion devices.  The written plan must include procedures to
minimize discharges either directly to the atmosphere or to the flare
gas system during the planned startup or shutdown of these units,
procedures to minimize emissions during malfunctions of the amine
treatment system or sulfur recovery plant, and procedures for conducting
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 refinery process
unit subject to the provisions of this subpart in excess of 500 lb per
day (lb/d) of SO2.

	(2)  When actions taken by the owner or operator during a startup or
shutdown (and the startup or shutdown causes the source to exceed any
applicable emission limitation in the relevant emission standards), or
malfunction (including actions taken to correct a malfunction) are
consistent with the procedures specified in the startup, shutdown, and
malfunction plan, the owner or operator must keep records for that event
which demonstrate that the procedures specified in the plan were
followed.  These records may take the form of a “checklist,” or
other effective form of recordkeeping that confirms conformance with the
startup, shutdown, and malfunction plan and describes the actions taken
for that event.  The owner or operator must identify the exceedance in
the semiannual excess emissions report and certify that the actions
taken during the startup, shutdown, or malfunction were consistent with
the procedures in the startup, shutdown, and malfunction plan.

	(3)  If an action taken by the owner or operator during a startup,
shutdown, or malfunction (including an action taken to correct a
malfunction) is not consistent with the procedures specified in the
startup, shutdown, and malfunction plan, and the source exceeds any
applicable emission limitation, then the owner or operator must record
the actions taken for that event and identify the exceedance in the
semiannual excess emissions report.

	(4)  The owner or operator must maintain at the affected facility a
current startup, shutdown, and malfunction plan and must make the plan
available to the Administrator upon request. 	(5)  The Administrator may
require the owner or operator to make changes to the startup, shutdown,
and malfunction plan if the Administrator finds:

	(i)  The plan does not address a startup, shutdown, or malfunction
event that has occurred;

	(ii)  The plan fails to provide for the minimization of emissions
during operation of the source (including associated air pollution
control and monitoring equipment) during a startup, shutdown, or
malfunction event;

	(iii)  The plan does not provide adequate procedures for correcting
malfunctioning process and/or air pollution control and monitoring
equipment as quickly as practicable; or

	(6) The owner or operator may periodically revise the startup,
shutdown, and malfunction plan as necessary to satisfy the requirements
of this subpart or to reflect changes in equipment or procedures at the
affected facility. However, each such revision to a startup, shutdown,
and malfunction plan must be reported in the semiannual report.

	(c)  Each owner or operator of a delayed coking unit shall depressure
to 5 lb per square inch gauge (psig) during reactor vessel depressuring
and vent the exhaust gases to the fuel gas system for recovery.

Option 2 for §60.103a

§60.103a  Work practice standards.

	Each owner or operator of a delayed coking unit shall depressure to 5
lb per square inch gauge (psig) during reactor vessel depressuring and
vent the exhaust gases to the fuel gas system for recovery.

§60.104a  Performance tests.

	(a)  The owner or operator shall conduct a performance test for a FCCU,
fluid coking unit, sulfur recovery plant, process heater and other fuel
gas combustion device to demonstrate initial compliance with each
applicable emissions limit in §60.102a according to the requirements of
§60.8.  The notification requirements of §60.8(d) apply to the initial
performance test and to subsequent performance tests required by
paragraph (b) of this section (or as required by the Administrator), but
does not apply to performance tests conducted for the purpose of
obtaining supplemental data because of continuous monitoring system
breakdowns, repairs, calibration checks, and zero and span adjustments
as provided in §60.105a(l).

	(b)  The owner or operator of a FCCU or fluid coking unit that elects
to monitor control device operating parameters according to the
requirements in §60.105a(b) shall conduct a PM performance test at
least once every 24 months and furnish the Administrator a written
report of the results of each test.

	(c)  In conducting the performance tests required by this subpart (or
as requested by the Administrator), the owner or operator shall use the
test methods in 40 CFR part 60, appendix A or other methods as specified
in this section, except as provided in §60.8(b).

	(d)  The owner or operator shall determine compliance with the PM, NOx,
SO2, and CO emissions limits in §60.102a(b) for FCCU and fluid coking
units using the following methods and procedures:

	(1)  Method 1 for sample and velocity traverses.

	(2)  Method 2 for velocity and volumetric flow rate.

	(3)  Method 3, 3A, or 3B for gas analysis.  The method ASME PTC
19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by
reference-see §60.17) is an acceptable alternative to EPA Method 3B.

	(4)  Method 5 for determining PM emissions and associated moisture
content from affected facilities.

	(i)  The PM performance test consists of 3 valid test runs; the
duration of each test run must be no less than 60 minutes.

	(ii)  The emissions rate of PM (EPM) is computed for each run using
Equation 1 of this section:

 			 (Eq. 1)

Where:

E 	=	Emission rate of PM (EPM), g/kg,

          lbs per 1,000 lbs (lb/1,000 lbs) of coke burn-	off;

cs 	=	Concentration of total PM, grams per dry standard

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

Qsd   =	Volumetric flow rate of effluent gas, dry standard   	cubic
meters per hour, dry standard cubic feet per 	hour;

Rc 	=	Coke burn-off rate, kilograms per hour (kg/hr), lbs 	per hour
(lbs/hr) coke; and

K 	=	Conversion factor, 1.0 grams per gram (7,000 	grains per lb).

	(iii)  The coke burn-off rate (Rc) is computed for each run using
Equation 2 of this section:

(Eq. 2)

Where:

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

Qr 	= Volumetric flow rate of exhaust gas from FCCU

       regenerator or fluid coking burner before any

       emissions control or energy recovery system that

       burns auxiliary fuel, dry standard cubic meters per

       minute (dscm/min), dry standard cubic feet per

       minute (dscf/min);

Qa 	= Volumetric flow rate of air to FCCU regenerator or

       fluid coking burner, as determined from the unit’s

       control room instrumentation, dscm/min (dscf/min);

Qoxy  =	Volumetric flow rate of O2 enriched air to FCCU regenerator or
fluid coking unit, as determined from the unit’s control room
instrumentation, dscm/min (dscf/min);

%CO2 =	Carbon dioxide concentration in FCCU regenerator or fluid coking
burner exhaust, percent by volume (dry basis);

%CO  =	CO concentration in FCCU regenerator or fluid coking burner
exhaust, percent by volume (dry basis);

%O2  =	O2 concentration in FCCU regenerator or fluid coking burner
exhaust, percent by volume (dry basis);

%Ooxy =	O2 concentration in O2 enriched air stream inlet to the FCCU
regenerator or fluid coking burner, percent by volume (dry basis);

K1   = Material balance and conversion factor, 0.2982 (kg-

       min)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)];

K2    = Material balance and conversion factor, 2.088 (kg-

       min)/(hr-dscm-%) [0.1303 (lb-min)/(hr-dscf-%)]; and

K3   = Material balance and conversion factor, 0.0994 (kg-

       min)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].

	(iv)  During the performance test, the volumetric flow rate of exhaust
gas from catalyst regenerator (Qr) before any emission control or energy
recovery system that burns auxiliary fuel is measured using Method 2.

	(v)  For subsequent calculations of coke burn-off rates or exhaust gas
flow rates, the volumetric flow rate of Qr is calculated using average
exhaust gas concentrations as measured by the monitors in
§60.105a(b)(2), if applicable, using Equation 3 of this section:

 		(Eq. 3)

Where:

Qr 	= Volumetric flow rate of exhaust gas from FCCU

       regenerator or fluid coking burner before any

       emission control or energy recovery system that

       burns auxiliary fuel, dscm/min (dscf/min);

Qa 	= Volumetric flow rate of air to FCCU regenerator or

       fluid coking burner, as determined from the unit’s

       control room instrumentation, dscm/min (dscf/min);

Qoxy  = Volumetric flow rate of O2 enriched air to FCCU

       regenerator or fluid coking unit, as determined from

       the unit’s control room instrumentation, dscm/min

       (dscf/min);

%CO2 =	Carbon dioxide concentration in FCCU regenerator or fluid coking
burner exhaust, percent by volume (dry basis);

%CO  =	CO concentration FCCU regenerator or fluid coking burner exhaust,
percent by volume (dry basis).  When no auxiliary fuel is burned and a
continuous CO monitor is not required in accordance with
§60.105a(g)(3), assume %CO to be zero;

%O2  =	O2 concentration in FCCU regenerator or fluid coking burner
exhaust, percent by volume (dry basis); and

%Ooxy =	O2 concentration in O2 enriched air stream inlet to the FCCU
regenerator or fluid coking burner, percent by volume (dry basis).

	(5)  Method 7, 7A, 7C, 7D, or 7E for moisture content and for the
concentration of NOx calculated as nitrogen dioxide (NO2); the duration
of each test run must be no less than 4 hours.

	(6)  Method 6, 6A, or 6C for moisture content and for the concentration
of SO2; the duration of each test run must be no less than 4 hours.  The
method ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,”
(incorporated by reference-see §60.17) is an acceptable alternative to
EPA Method 6 or 6A.

	(7)  Method 10, 10a, or 10B for moisture content and for the
concentration of CO.  The sampling time for each run must be 60 minutes.

	(8)  The owner or operator shall adjust PM, NOx, SO2, and CO pollutant
concentrations to 0 percent excess air or 0 percent O2 using Equation 4
of this section:

  			(Eq. 4)

Where:

Cadj	= pollutant concentration adjusted to 0 percent

       excess air or O2, parts per million (ppm) or g/dscm;

Cmeas  = pollutant concentration measured on a dry basis, ppm

       or g/dscm;

−0.0 percent O2 (defined O2 correction basis), percent;

20.9 =	O2 concentration in air, percent; and

%O2   = 	O2 concentration measured on a dry basis, percent.

	(e)  The owner or operator of a FCCU or fluid coking unit that is
controlled by an electrostatic precipitator or wet scrubber and that is
subject to control device operating parameter limits §60.102a(c) shall
establish the limits based on the performance test results according to
the following procedures:

	(1)	Reduce the parameter monitoring data to hourly averages for each
test run;

	(2)	Determine the operating limit for each required parameter as the
lowest hourly average voltage and secondary current and the highest coke
burn-off rate (if you use an electrostatic precipitator) or the lowest
average pressure drop and liquid-to-gas ratio (if you use a wet
scrubber) measured during a test run that achieves the applicable PM
emission limit.

	(f)  The owner or operator of a FCCU or fluid coking unit that is
exempt from the requirement to install and operate a CO CEMS pursuant to
§60.105a(g)(3) and that is subject to control device operating
parameter limits in §60.102a(d) shall establish the limits based on the
performance test results using the following procedures:

	(1)  Reduce the temperature and O2 concentrations from the parameter
monitoring systems to hourly averages for each test run.

	(2)  Determine the operating limit for temperature and O2
concentrations as the lowest hourly average temperature and O2
concentration measured during a test run achieving the emission
limitation.

	(g)  The owner or operator shall determine compliance with the SO2 and
H2S emissions limits for sulfur recovery plants in §60.102a(e) using
the following methods and procedures:

	(1)  Method 1 for sample and velocity traverses.

	(2)  Method 2 for velocity and volumetric flow rate.

	(3)  Method 3, 3A, or 3B for gas analysis.  The method ASME PTC
19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by
reference-see §60.17) is an acceptable alternative to EPA Method 3B.

	(4)  Method 6, 6A, or 6C to determine the SO2 concentration.  The
method ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,”
(incorporated by reference-see §60.17) is an acceptable alternative to
EPA Method 6 or 6A.

	(5)  Method 15 or 15A to determine the reduced sulfur compounds and H2S
concentrations.

	(i)  Each run consists of 16 samples taken over a minimum of 3 hours.

	(ii)  The owner or operator shall calculate the average H2S
concentration after correcting for moisture and O2 as the arithmetic
average of the H2S concentration for each sample during the run (ppmv,
dry basis, corrected to 0 percent excess air).

	(iii)  The owner or operator shall calculate the SO2 equivalent for
each run after correcting for moisture and O2 as the arithmetic average
of the SO2 equivalent of reduced sulfur compounds for each sample during
the run (ppmv, dry basis, corrected to 0 percent excess air).

	 (iv)  The owner or operator shall use Equation 4 of this section to
adjust pollutant concentrations to 0 percent O2 or 0 percent excess air.

	(6)  The owner or operator shall calculate the combined SO2 and reduced
sulfur compound concentrations for a sulfur recovery plant with a
capacity greater than 20 LTD that is subject to the emissions limit in
§60.102a(e)(1) using Equation 5 of this section:

  	(Eq. 5)

Where:

Ccombined 	= Cmbined SO2 and reduced sulfur compounds
concentration, ppmv, dry basis, at 0 percent 	    	 		  excess air;

CSO2,M6 	= SO2 concentration in the exhaust stream measured 	 	 	  using
Method 6, 6A, or 6C as required in 	 	 	   		  paragraph (c)(4) of this
section, ppmv, dry 	  	 		  basis at 0 percent excess air;  The method
ASME PTC 			  19.10-1981, “Flue and Exhaust Gas Analyses,”
(incorporated by reference-see §60.17) is an 				  acceptable
alternative to EPA Method 6 or 6A.

CSO2_eq,M15    = SO2 equivalent concentration of reduced sulfur
compounds in the exhaust stream measured using 			 	  Method 15 or 15A
as required in paragraph (c)(5) 		 	  of this section, ppmv, dry basis
at 0 percent 			 	  excess air.  The method ASME PTC 19.10-1981, “Flue
			  and Exhaust Gas Analyses,” (incorporated by 				  reference-see
§60.17) is an acceptable alternative 			  to EPA Method 15A.

	(7)  The owner or operator shall calculate the mass sulfur emission
percentage for a sulfur recovery plant with a capacity of 10 LTD or less
that is subject to the emissions limit in §60.102a(e)(2) using the
following procedures:

	(i)  Calculate the combined SO2 and reduced sulfur compound
concentration using Equation 5 of this section.

	(ii)  Calculate the mass sulfur emissions percentage using Equation 6
of this section:

 	(Eq. 6)

Where:

FS,emit 	=	Mass fraction of sulfur emitted, weight percent;

K4 	   = Conversion factor, 0.5 [lbs S/lb SO2] × 60 					[min/hr] ×
1.66E-7 [lbs/dscf per ppmv]/2,240 				[lbs/long ton] = 2.22E-9 (lbs
S·min·long   					ton·lbs/dscf)/(lbs SO2·hr·lb·ppmv);

Ccombined  = Combined SO2 and reduced sulfur compounds
concentration, ppmv, dry basis at 0 percent 					excess air;

Qsd 	   = Volumetric flow rate of effluent gas dscf/min; and

Msulfur   = Mass rate of sulfur recovery, long tons/hr.

	(h)  The owner or operator of a sulfur recovery plant that is subject
to the operating limits in §60.102a(f) shall establish the limits based
on the results of the performance test according to the following
procedures:

	(1)	 Reduce the temperature and O2 concentrations from the CPMS to
hourly averages for each test run;

	(2)	 Determine the operating limit for temperature and O2
concentrations as the lowest hourly average temperature and O2
concentration measured during a test run achieving the H2S emissions
limit.

	(i)  The owner or operator shall determine compliance with the SO2 and
NOx emissions limits in §60.102a(g) for a process heater or other fuel
gas combustion device according to the following test methods and
procedures:

	(1)  Method 1 for sample and velocity traverses;

	(2)  Method 2 for velocity and volumetric flow rate;

	(3)  Method 3, 3A, or 3B for gas analysis.  The method ASME PTC
19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by
reference-see §60.17) is an acceptable alternative to EPA Method 3B.;

	(4)  Method 6, 6A, or 6C to determine the SO2 concentration.  The
method ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,”
(incorporated by reference-see §60.17) is an acceptable alternative to
EPA Method 6 or 6A.

	(i)  The performance test consists of 3 valid test runs; the duration
of each test run must be no less than 1 hour.

	(ii)  If a single fuel gas combustion device having a common source of
fuel gas is monitored as allowed under §60.107a(a)(2)(v), only one
performance test is required.  That is, performance tests are not
required when a new affected fuel gas combustion device is added to a
common source of fuel gas that previously demonstrated compliance.

	(5)  Method 7, 7A, 7C, 7D, or 7E for moisture content and for the
concentration of NOx calculated as NO2; the duration of each test run
must be no less than 4 hours.

	(j)  The owner or operator shall determine compliance with the H2S or
TRS emissions limit in §60.102a(h) for a process heater or other fuel
gas combustion device according to the following test methods and
procedures:

	(1)  Method 1 for sample and velocity traverses;

	(2)  Method 2 for velocity and volumetric flow rate;

	(3)  Method 3, 3A, or 3B for gas analysis.  The method ASME PTC
19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by
reference-see §60.17) is an acceptable alternative to EPA Method 3B.;

	(4)  Method 11, 15, 15A, or 16 for determining the H2S concentration
for affected plants using an H2S monitor as specified in §60.107a(a)(1)
or Method 16 for determining the TRS concentration.  The method ASME PTC
19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by
reference-see §60.17) is an acceptable alternative to EPA Method 15A.

	(i)  For Method 11, the sampling time and sample volume must be at
least 10 minutes and 0.010 dscm (0.35 dscf).  Two samples of equal
sampling times must be taken at about 1-hour intervals.  The arithmetic
average of these two samples constitute a run.  For most fuel gases,
sampling times exceeding 20 minutes may result in depletion of the
collection solution, although fuel gases containing low concentrations
of H2S may necessitate sampling for longer periods of time.

	(ii)  For Method 15 or 16, at least three injects over a 1-hour period
constitutes a run.

	(iii)  For Method 15A, a 1-hour sample constitutes a run.  The method
ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated
by reference-see §60.17) is an acceptable alternative to EPA Method
15A.

	(iv)  If monitoring is conducted at a single point in a common source
of fuel gas as allowed under §60.107a(a)(1)(iv), only one performance
test is required.  That is, performance tests are not required when a
new affected fuel gas combustion device is added to a common source of
fuel gas that previously demonstrated compliance.

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

	(a)  FCCU and fluid coking units subject to PM emissions limit.  Each
owner or operator subject to the provisions of this subpart shall
monitor each FCCU and fluid coking unit subject to the PM emissions
limit in §60.102a(b)(1) according to the requirements in paragraph (b),
(c), or (d) of this section.

	(b)  Control device operating parameters.  Each owner or operator of a
FCCU or fluid coking unit subject to the PM emissions limit in
§60.102a(b)(1) shall comply with the requirements in paragraphs (b)(1)
through (3) of this section.

	(1)  The owner or operator shall install, operate, and maintain
continuous parameter monitor systems (CPMS) to measure and record
operating parameters for each control device according to the
requirements in paragraph (b)(1)(i) through (iii) of this section.

    	(i)  For units controlled using an electrostatic precipitator, the
owner or operator shall use CPMS to measure and record the hourly
average total power input and secondary voltage to the control device.

	(ii)  For units controlled using a wet scrubber, the owner or operator
shall use CPMS to measure and record the hourly average pressure drop,
liquid feed rate, and exhaust gas flow rate.

	(iii)  The owner or operator shall install, operate, and maintain each
CPMS according to the manufacturer’s specifications and requirements.

	(2)  The owner or operator shall install, operate, calibrate, and
maintain an instrument for continuously monitoring the concentrations of
CO2, O2 (dry basis), and if needed, CO in the exhaust gases prior to any
control or energy recovery system that burns auxiliary fuels.

	(i)  The owner or operator shall install, operate, and maintain each
monitor according to Performance Specification 3 (40 CFR part 60,
appendix B).

	(ii)  The owner or operator shall conduct performance evaluations of
each CO2, O2, and CO monitor according to the requirements in §60.13(c)
and Performance Specification 3.  The owner or operator shall use Method
3 for conducting the relative accuracy evaluations.

	(iii)  The owner or operator shall comply with the quality assurance
requirements of procedure 1 in 40 CFR part 60, appendix F, including
quarterly accuracy determinations for CO2 and CO monitors, annual
accuracy determinations for O2 monitors, and daily calibration drift
tests.

	(3)  The owner or operator shall determine and record the average coke
burn-off rate and hours of operation for each FCCU or fluid coking unit
using the procedures in §60.104a(d)(4)(vii).

	(c)  Bag leak detection systems.  Each owner or operator of a FCCU or
fluid coking unit shall install, operate, and maintain a bag leak
detection system for each baghouse that is used to comply with the PM
emissions limit in §60.102a(b)(1) according to paragraph (c)(1) of this
section; prepare and operate by a site-specific monitoring plan
according to paragraph (c)(2) of this section; take corrective action
according to paragraph (c)(3) of this section; and record information
according to paragraph (c)(4) of this section.

	(1)  Each bag leak detection system must meet the specifications and
requirements in paragraphs (c)(1)(i) through (viii) of this section.

	(i)  The bag leak detection system must be certified by the
manufacturer to be capable of detecting PM emissions at concentrations
of 0.00044 grains per actual cubic foot or less.

	(ii)  The bag leak detection system sensor must provide output of
relative PM loadings.  The owner or operator shall continuously record
the output from the bag leak detection system using electronic or other
means (e.g., using a strip chart recorder or a data logger).

	(iii)  The bag leak detection system must be equipped with an alarm
system that will sound when the system detects an increase in relative
particulate loading over the alarm set point established according to
paragraph (c)(1)(iv) of this section, and the alarm must be located such
that it can be heard by the appropriate plant personnel.

	(iv)  In the initial adjustment of the bag leak detection system, the
owner or operator must establish, at a minimum, the baseline output by
adjusting the sensitivity (range) and the averaging period of the
device, the alarm set points, and the alarm delay time.

	(v)  Following initial adjustment, the owner or operator shall not
adjust the averaging period, alarm set point, or alarm delay time
without approval from the Administrator or delegated authority except as
provided in paragraph (c)(1)(vi) of this section.

	(vi)  Once per quarter, the owner or operator may adjust the
sensitivity of the bag leak detection system to account for seasonal
effects, including temperature and humidity, according to the procedures
identified in the site-specific monitoring plan required by paragraph
(c)(2) of this section.

	(vii)  The owner or operator shall install the bag leak detection
sensor downstream of the baghouse and upstream of any wet scrubber.

	(viii)  Where multiple detectors are required, the system’s
instrumentation and alarm may be shared among detectors.

	(2)  The owner or operator shall develop and submit to the
Administrator for approval a site-specific monitoring plan for each
baghouse and bag leak detection system.  The owner or operator shall
operate and maintain each baghouse and bag leak detection system
according to the site-specific monitoring plan at all times.  Each
monitoring plan must describe the items in paragraphs (c)(2)(i) through
(vii) of this section.

	(i)  Installation of the bag leak detection system;

	(ii)  Initial and periodic adjustment of the bag leak detection system,
including how the alarm set-point will be established;

	(iii)  Operation of the bag leak detection system, including quality
assurance procedures;

	(iv)  How the bag leak detection system will be maintained, including a
routine maintenance schedule and spare parts inventory list;

	(v)  How the bag leak detection system output will be recorded and
stored;

	(vi)  Corrective action procedures as specified in paragraph (c)(3) of
this section.  In approving the site-specific monitoring plan, the
Administrator or delegated authority may allow owners and operators more
than 3 hours to alleviate a specific condition that causes an alarm if
the owner or operator identifies in the monitoring plan this specific
condition as one that could lead to an alarm, adequately explains why it
is not feasible to alleviate this condition within 3 hours of the time
the alarm occurs, and demonstrates that the requested time will ensure
alleviation of this condition as expeditiously as practicable; and

	(vii)  How the baghouse system will be operated and maintained,
including monitoring of pressure drop across baghouse cells and
frequency of visual inspections of the baghouse interior and baghouse
components such as fans and dust removal and bag cleaning mechanisms.

	(3)  For each bag leak detection system, the owner or operator shall
initiate procedures to determine the cause of every alarm within 1 hour
of the alarm.  Except as provided in paragraph (c)(2)(vi) of this
section, the owner or operator shall alleviate the cause of the alarm
within 3 hours of the alarm by taking whatever corrective action(s) are
necessary.  Corrective actions may include, but are not limited to the
following:

	(i)  Inspecting the baghouse for air leaks, torn or broken bags or
filter media, or any other condition that may cause an increase in
particulate emissions;

	(ii)  Sealing off defective bags or filter media;

	(iii)  Replacing defective bags or filter media or otherwise repairing
the control device;

	(iv)  Sealing off a defective baghouse compartment;

	(v)  Cleaning the bag leak detection system probe or otherwise
repairing the bag leak detection system; or

	(vi)  Shutting down the process producing the particulate emissions.

	(4)  The owner or operator shall maintain records of the information
specified in paragraphs (c)(4)(i) through (iii) of this section for each
bag leak detection system.

	(i)  Records of the bag leak detection system output;

	(ii)  Records of bag leak detection system adjustments, including the
date and time of the adjustment, the initial bag leak detection system
settings, and the final bag leak detection system settings; and

	(iii)  The date and time of all bag leak detection system alarms, the
time that procedures to determine the cause of the alarm were initiated,
the cause of the alarm, an explanation of the actions taken, the date
and time the cause of the alarm was alleviated, and whether the alarm
was alleviated within 3 hours of the alarm.

	(d)  Continuous emissions monitoring systems (CEMS).  The owner or
operator of a FCCU or fluid coking unit subject to the PM emissions
limit (gr/dscf) in §60.102a(b)(1) shall install, operate, calibrate,
and maintain an instrument for continuously monitoring and recording the
concentration (0 percent excess air) of PM in the exhaust gases prior to
release to the atmosphere.  The monitor must include an O2 monitor for
correcting the data for excess air.

	(1)  The owner or operator shall install, operate, and maintain each PM
monitor according to Performance Specification 11 of 40 CFR part 60,
appendix B.  The span value of this PM monitor is 0.08 gr/dscf PM.

	(2)  The owner or operator shall conduct performance evaluations of
each PM monitor according to the requirements in §60.13(c) and
Performance Specification 11.  The owner or operator shall use Method 5
for conducting the relative accuracy evaluations.

	(3)  The owner or operator shall install, operate, and maintain each O2
monitor according to Performance Specification 3 of 40 CFR part 60,
appendix B.  The span value of this O2 monitor is 25 percent.

	(4)  The owner or operator shall conduct performance evaluations of
each O2 monitor according to the requirements in §60.13(c) and
Performance Specification 3.  Method 3, 3A, or 3B shall be used for
conducting the relative accuracy evaluations.  The method ASME PTC
19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by
reference-see §60.17) is an acceptable alternative to EPA Method 3B.

	(5)  The owner or operator shall comply with the quality assurance
requirements of procedure 2 in 40 CFR part 60, appendix F for each PM
CEMS and procedure 1 in 40 CFR part 60, appendix F for each O2 monitor,
including quarterly accuracy determinations for each PM monitor, annual
accuracy determinations for each O2 monitor, and daily calibration drift
tests.

	(e)  FCCU and fluid coking units subject to NOx limit.

Each owner or operator of a FCCU or fluid coking unit subject to the NOx
emissions limit in §60.102a(b)(2) shall install, operate, calibrate,
and maintain an instrument for continuously monitoring and recording the
concentration by volume (dry basis, 0 percent excess air) of NOx
emissions into the atmosphere.  The monitor must include an O2 monitor
for correcting the data for excess air.

	(1)  The owner or operator shall install, operate, and maintain each
NOx monitor according to Performance Specification 2 (40 CFR part 60,
appendix B).  The span value of this NOx monitor is 200 ppmv NOx.

	(2)  The owner or operator shall conduct performance evaluations of
each NOx monitor according to the requirements in §60.13(c) and
Performance Specification 2.  The owner or operator shall use Methods 7,
7A, 7C, 7D, or 7E (40 CFR part 60, appendix A) for conducting the
relative accuracy evaluations.

	(3)  The owner or operator shall install, operate, and maintain each O2
monitor according to Performance Specification 3 of 40 CFR part 60,
appendix B.  The span value of this O2 monitor is 25 percent.

	(4)  The owner or operator shall conduct performance evaluations of
each O2 monitor according to the requirements in §60.13(c) and
Performance Specification 3.  Method 3, 3A, or 3B shall be used for
conducting the relative accuracy evaluations.  The method ASME PTC
19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by
reference-see §60.17) is an acceptable alternative to EPA Method 3B.

	(5)  The owner or operator shall comply with the quality assurance
requirements of procedure 1 in 40 CFR part 60, appendix F for each SO2
and O2 monitor, including quarterly accuracy determinations for SO2
monitors, annual accuracy determinations for O2 monitors, and daily
calibration drift tests.

	(f)  FCCU and fluid coking units subject to SO2 limit.  The owner or
operator a FCCU and fluid coking unit subject to the SO2 emissions limit
in §60.102a(b)(3) shall install, operate, calibrate, and maintain an
instrument for continuously monitoring and recording the concentration
by volume (dry basis, corrected to 0 percent excess air) of SO2
emissions into the atmosphere.  The monitor shall include an O2 monitor
for correcting the data for excess air.

	(1)  The owner or operator shall install, operate, and maintain each
SO2 monitor according to Performance Specification 2 (40 CFR part 60,
appendix B).  The span value of this SO2 monitor is 200 ppmv SO2.

	(2)  The owner or operator shall conduct performance evaluations of
each SO2 monitor according to the requirements in §60.13(c) and
Performance Specification 2.  The owner or operator shall use Methods 6,
6A, or 6C (40 CFR part 60, appendix A) for conducting the relative
accuracy evaluations.  The method ASME PTC 19.10-1981, “Flue and
Exhaust Gas Analyses,” (incorporated by reference-see §60.17) is an
acceptable alternative to EPA Method 6 or 6A.

	(3)  The owner or operator shall install, operate, and maintain each O2
monitor according to Performance Specification 3 of 40 CFR part 60,
appendix B.  The span value of this O2 monitor is 10 percent.

	(4)  The owner or operator shall conduct performance evaluations of
each O2 monitor according to the requirements in §60.13(c) and
Performance Specification 3.  Method 3, 3A, or 3B shall be used for
conducting the relative accuracy evaluations.  The method ASME PTC
19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by
reference-see §60.17) is an acceptable alternative to EPA Method 3B.

	(5)  The owner or operator shall comply with the quality assurance
requirements of procedure 1 in 40 CFR part 60, appendix F for each SO2
and O2 monitor, including quarterly accuracy determinations for SO2
monitors, annual accuracy determinations for O2 monitors, and daily
calibration drift tests.

	(g)  FCCU and fluid coking units subject to CO emissions limit.  Except
as specified in paragraph (g)(3) of this section, the owner or operator
shall install, operate, calibrate, and maintain an instrument for
continuously monitoring and recording the concentration by volume (dry
basis) of CO emissions into the atmosphere from each FCCU and fluid
coking unit subject to the CO emissions limit in §60.102a(b)(4).

	(1)  The owner or operator shall install, operate, and maintain each CO
monitor according to Performance Specification 4 (40 CFR part 60,
appendix B).  The span value for this instrument is 1,000 ppm CO.

	(2)  The owner or operator shall conduct performance evaluations of
each CO monitor according to the requirements in §60.13(c) and
Performance Specification 4 (40 CFR part 60, appendix A).  The owner or
operator shall use Methods 10, 10A, or 10B for conducting the relative
accuracy evaluations using the procedures specified in §60.106a(b).

	(3)  A CO CEMS need not be installed if the owner or operator
demonstrates that the average CO emissions are less than 50 ppm (dry
basis) and also submits a written request for exemption to the
Administrator and receives such an exemption.

  	(i)  The demonstration shall consist of continuously monitoring CO
emissions for 30 days using an instrument that meets the requirements of
Performance Specification 4 (40 CFR part 60, appendix B).  The span
value shall be 100 ppm CO instead of 1,000 ppm, and the relative
accuracy limit shall be 10 percent of the average CO emissions or 5 ppm
CO, whichever is greater.  For instruments that are identical to Method
10 and employ the sample conditioning system of Method 10A, the
alternative relative accuracy test procedure in section 10.1 of
Performance Specification 2 may be used in place of the relative
accuracy test.

	(ii)  The written request for exemption must include descriptions of
the CPMS for exhaust gas temperature and O2 monitor required in
paragraph (g)(4) of this section and operating limits for those
parameters to ensure combustion conditions remain similar to those that
exist during the demonstration period.

	(4)  The owner or operator of a FCCU or fluid coking unit that is
exempted from the requirement to install and operate a CO CEMS in
paragraph (g)(3) of this section shall install, operate, calibrate, and
maintain CPMS to measure and record the operating parameters in
paragraph (g)(4)(i) or (ii) of this section.  The owner or operator
shall install, operate, and maintain each CPMS according to the
manufacturer’s specifications.

	(i)  For a FCCU or fluid coking unit with no post-combustion control
device, the temperature and O2 concentration of the exhaust gas stream
exiting the unit.

	(ii)  For a FCCU or fluid coking unit with a post-combustion control
device, the temperature and

O2 concentration of the exhaust gas stream exiting the control device.

	(h)  Excess emissions.  For the purpose of reports required by
§60.7(c), periods of excess emissions for a FCCU or fluid coking unit
subject to the emissions limitations in §60.102a(b) are defined as
specified in paragraphs (h)(1) through (4) of this section.  Note:
Determine all averages as the arithmetic average of the applicable
1-hour averages, e.g., determine the rolling 3-hour average as the
arithmetic average of three contiguous 1-hour averages.

	(1)  All 24-hour periods during which the average PM control device
operating characteristics, as measured by the continuous monitoring
systems under §60.105a(b)(1), fall below the levels established during
the performance test.  Alternatively, if a PM CEMS is used according to
§60.105a(d), all 7-day periods during which the average PM emission
rate, as measured by the continuous PM monitoring system under
§60.105a(a)(2) exceeds 0.020 gr/dscf.

	(2)  All rolling 7-day periods during which the average concentration
of NOx as measured by the NOx CEMS under §60.105a(e) exceeds 80 ppmv.

	(3)  All rolling 7-day periods during which the average concentration
of SO2 as measured by the SO2 CEMS under §60.105a(f) exceeds 50 ppmv,
and all rolling 365-day periods during which the average concentration
of SO2 as measured by the SO2 CEMS exceeds 25 ppmv.

	(4)  All 1-hour periods during which the average CO concentration as
measured by the CO continuous monitoring system under §60.105a(g)
exceeds 500 ppmv or, if applicable, all 1-hour periods during which the
average temperature and O2 concentration as measured by the continuous
monitoring systems under §60.105a(g)(4) fall below the operating limits
established during the performance test.

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

	(a)  Sulfur recovery plants.  The owner or operator of a sulfur
recovery plant shall comply with the applicable requirements in
paragraphs (a)(1) through (5) of this section.

	(1)  The owner or operator of a sulfur recovery plant with a capacity
greater than 20 LTD that is subject to an SO2 emissions limit in
§60.102a(e)(1) shall install, operate, calibrate, and maintain an
instrument using an air or O2 dilution and oxidation system to convert
any reduced sulfur to SO2 for continuously monitoring and recording the
concentration (dry basis, 0 percent excess air) of the total resultant
SO2.  The monitor must include an O2 monitor for correcting the data for
excess O2.

	(i)  The owner or operator shall install, operate, and maintain each
SO2 CEMS according to Performance Specification 2 (40 CFR part 60,
appendix B).  The span value for this monitor is 500 ppm SO2.