performance. It is not feasible to prescribe or enforce a standard of
performance for these

sources because either the pollution prevention measures eliminates the
emission source, so that there are no emissions to capture and convey,
or the emissions are so transient, and in some cases, occur so
randomly, that the application of a measurement methodology to these
sources is not technically and economically practical.
    Elimination of Routine Flaring. Flares are first and foremost a
safety device used to reduce emissions from emergency pressure relief
of gases from refinery process units. We in no way want to limit the
use of flares for emergency releases. However, many refineries also
routinely use flares as an emission control device under normal
operating conditions.
    Fuel gases produced within the refinery can be roughly divided into
two categories based on the fuel gas stream pressure. Fuel gases
produced in processes operated at higher pressures are easily routed to
the fuel gas system; however, fuel gases that are produced from units
operated near atmospheric pressures are not as easily routed to the
fuel gas system. These ``low pressure'' fuel gases are often routed to
flares because the flare gas system operates at a much lower pressure
than the fuel gas system. Flare gas recovery systems are designed to
compress the low pressure fuel gases, creating a high pressure fuel gas
stream that can readily be added to the fuel gas system.
    In 1998, the South Coast Air Quality Management District developed
a rule requiring refineries to measure the flow rate and hydrocarbon
content of the gases sent to a flare. This South Coast rule, although
it did not set prescriptive emission limits, led to reduced flaring as
refinery operators, armed with the monitoring results, identified cost-
effective flare gas minimization or recovery projects. In 2005, South
Coast amended this rule and established a no routine flaring goal based
on the cost and anticipated emission reductions of flare gas recovery
systems. The Bay Area Air Quality Management District also adopted a
rule requiring flare monitoring in 2003 and adopted a rule to minimize
flaring in 2006.
    We considered adopting the South Coast and Bay Area rules for this
NSPS for new flare systems. However, many refinery flares operate for
50 years, so very few flares or flare systems are expected to become
subject to NSPS requirements, even after several decades. Instead, we
are proposing to add ``fuel gas producing units'' as a new affected
source under subpart Ja and focus the requirement on eliminating
routine flaring of fuel gas at the process units producing the fuel
gas. A refinery owner or operator installing a new process unit that
produces low pressure fuel gas has options for eliminating routine
flaring, including, but not limited to, diverting the fuel gas to a
nearby low-pressure heater or boiler, pressurizing the fuel gas so that
it can be diverted to the fuel gas system, or installing a flare gas
recovery system. The proposed work practice standard is designed to
allow flexibility in compliance approaches without imposing undue
restrictions on the use of flares during malfunctions or other
conditions wherein flaring is the best environmental management
practice considering the safety of the plant personnel and surrounding
people. Additionally, several new fuel gas producing units are expected
to be installed every year, so by regulating the fuel gas producing
units we not only provide flexibility, but we also increase the rate at
which the no routine flaring requirement is implemented within the
industry.
    The impacts for this work practice are highly dependent on the
amount of fuel gas generated by different fuel gas combustion units.
Recovered fuel gas reduces the amount of natural gas a refinery must
purchase to operate their process heaters. For example, fuel gases
generated by fluid catalytic cracking units and coking units are
routinely recovered into the fuel gas system due to the quantity of
fuel gas generated in the process. For these systems, the savings
associated with the recovered fuel gas provides a return on the capital
investment associated with the compressor and ancillary equipment
needed to recover the fuel gas. For other fuel gas producing units,
such as reforming units, it is possible to route the fuel gas directly
to the unit's process heater without additional gas compression. For a
few refineries, a flare gas recovery system may be used.
    We estimated planning and design costs for assessing methods to
recover or otherwise avoid the release of fuel gas from new fuel gas
producing units. As described previously, for many fuel gas producing
units, the cost savings associated with the recovered fuel recovers the
costs of the recovery equipment within the life-span on the equipment
so that the annualized cost of controls is zero or slightly negative
(indicating a cost savings). As a worst-case scenario, we used the
impacts developed by the Bay Area for a system-wide flare gas recovery
system. The total annualized cost of the system was estimated to be
approximately $2 million; no credit was provided for the heating value
of the flare gas recovered. VOC emission reductions were estimated to
be approximately 1,000 tons per year and SO2 emissions were
estimated to be 3,500 tons per year. The cost-effectiveness on the
flare gas recovery system was estimated to be approximately $2,000/ton
of VOC removed and approximately $570/ton of SO2 removed,
assuming total costs are assigned to each pollutant. Therefore, even
when fuel credits are not considered, flare gas recovery is cost-
effective as an emissions control device. When properly sized, these
flare gas recovery systems can eliminate all routine flaring.
Therefore, eliminating routine flaring by use of fuel gas recovery, in-
process fuel use, or system wide flare gas recovery is determined to be
BDT.
    We request comment on alternative means of eliminating routine
flaring. As noted previously, a simple requirement to monitor gas flow
and composition of gases sent to the flares resulted in reduced use of
flares. An exemption from this monitoring requirement for flare systems
that install flare gas recovery could provide refineries an incentive
to install flare gas recovery systems. We request comment on this
alternative and on the need to monitor flares that have flare gas
recovery systems to ensure that the flare gas recovery system is
properly sized and that no routine flaring is occurring.
    Additionally, we understand that there are a limited number of
refineries that produce more fuel gas than they can use in the refinery
process heaters or steam boilers. These ``fuel gas rich'' refineries
contend that flaring is BDT for these refineries. Although we believe
that other options exist, such as building an electric co-generating
unit, the cost-effectiveness of such an endeavor is very site-specific.
We cannot conclude at this time that co-generation or other projects
that use fuel gas are BDT. Therefore, we are co-proposing no
requirement for fuel gas producing units. We request comment on the
actual number and location of ``fuel gas rich'' refineries. We also
request comment and data regarding the technical and economical
feasibility of alternatives for ``fuel gas rich'' refineries to avoid
routine flaring.
    Emission Prevention During Start-up, Shutdown, and Malfunctions.
The current NSPS includes no requirements for a start-up, shutdown, and
malfunction plan. We identified three emission prevention methods that
can be addressed within the context of a start-up, shutdown, and
malfunction plan. These are: Flare minimization during planned start-
ups and shutdowns; flare minimization during malfunctions of the sour
gas amine

treatment units and sulfur recovery plants; and performing root-cause
analyses of malfunctions that release in excess of 500 lb per day of
SO2. Our rationale for including each of these three
emission prevention methods are described in the following paragraphs.
    Flaring and direct venting of certain gas streams have been
routinely used during planned start-up and shutdown of process units to
quickly bring a process unit online or offline. These flaring and
venting episodes have traditionally been exempt from any emission
limitations. Nonetheless, some refineries have chosen to evaluate their
start-up and shutdown emissions and alter their procedures so as to
reduce or eliminate direct venting or flaring during planned start-up
and shutdown events.
    Typically, alternative start-up and shutdown procedures that reduce
atmospheric emissions or flaring require more time to complete than
conventional procedures. Therefore, there is a cost associated with the
alternative procedures in terms of potential product/productivity loss.
For refineries that have system-wide flare gas recovery systems, it may
be a simple matter of scheduling the start-up or shutdown during a time
when limited other flare gas is being generated so as to not overwhelm
the flare gas recovery system. The cost-effectiveness of the
alternative procedures would depend on the amount of gas flared or
vented using the traditional procedures, the amount of these emissions
that can be avoided using alternative procedures, the amount of product
lost due to the increased start-up/shutdown time period, and the value
of that product. As such, it is difficult to conclude that significant
or complete emission reductions during planned start-up or shutdown
events will be cost-effective under all conditions; therefore, we chose
not to set a specific venting or flaring limit (or prohibition).
    We estimate that the engineering review revision of a unit's start-
up and shutdown plan would require approximately 20 engineering hours
per process unit, at total cost of $1,300 to $1,500 per process unit
(one-time costs). Assuming the unit requires maintenance shut-down only
once every 5 years and the revised procedures only reduce VOC and
SO2 emissions by 1 ton each per event, the cost-
effectiveness of the engineering review is $1,300 to $1,500 per ton of
VOC and the same for SO2.
    Based on this simplistic analysis, we are proposing that
implementing a start-up and shutdown plan focused on reducing emissions
during planned start-up and shutdown events would be BDT.
    We evaluated several different requirements to promote continuous
compliance with the SO2 emission limits associated with fuel
gas combustion devices and sulfur recovery plants even during times of
process upsets or malfunctions associated with the amine system or
sulfur recovery plant. ``Process upset gas'' is ``gas generated by a
petroleum refinery process unit as a result of upset or malfunction.''
Process upset gas is exempt from the SO2 emission limits.
However, when there is a malfunction of the amine treatment system or
the sulfur recovery plant, there has been some uncertainty as to
whether combustion or flaring of the sour gas is considered to be
exempt from the SO2 emission limit. This is because the
amine treatment system or sulfur recovery plant is not ``generating''
the gas stream, it is merely treating it. As such, the amine treatment
system and sulfur recovery plant are essentially control devices, and
refinery owners and operators are required to minimize emissions during
these control system malfunctions, up to and including the shutdown of
the emissions generating units.
    A variety of prescriptive requirements were reviewed, such as
requiring 24-hour storage capacity of lean amine solution and empty
tank storage capacity to receive 24 hours worth of rich amine solution,
requiring inventory of critical spare parts, and requiring redundant
amine scrubbing and sulfur recovery capacity. While these are all
viable options that a plant can employ to minimize malfunction
emissions associated with the amine treatment system or sulfur recovery
plant, the most cost-effective means to minimize these emissions are
highly site-specific, being dependent on the number and location of the
amine units or sulfur recovery trains within the sulfur recovery plant.
    We evaluated two alternatives, which are not mutually exclusive,
for minimizing flaring of H2S-rich fuel gas in the event of
a malfunction in the amine stripper or sulfur recovery plant. Option 1
is to store 24 hours worth of lean amine solution in case of a
malfunction in the amine 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 a delayed coking unit to 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
------------------------------------------------------------------------
                                         Section in this  preamble where
                 Topic                          topic is discussed
------------------------------------------------------------------------
Effects of proposed PM, SO2 and NOX      III.B. and V.E.1.
 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.
Exemption for emergency flares.........  IV.A.
Exemption from monitoring for fuel gas   IV.A.
 streams related to commercial liquid
 products.
Exemption from monitoring for fuel gas   IV.A.
 streams generated by process units
 that are intolerant of sulfur.
Alternative PM limit for fluid           V.E.1.
 catalytic cracking units based on
 condensable PM as well as filterable
 PM.
Alternative lower (20 ppmv, 40 ppmv)     V.E.1.
 NOX limit, averaged over 365 days, for
 fluid catalytic cracking units.
Co-propose no new NOX standard for       V.E.2.
 fluid coking units.
Appropriate long-term average H2S        V.E.4.
 concentration limit for fuel gas
 combustion units, and requirement to
 monitor TRS instead of H2S for fuel
 gas from coker units.
Various aspects of work practice         V.D.5.
 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.
------------------------------------------------------------------------

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)
----------------------------------------------------------------------------------------------------------------
                                                                                Annual
                                                   Total capital   Total annual      emission          Cost-
         Process unit               Pollutant     cost  ($1,000)  cost  ($1,000/    reductions     effectiveness
                                                                        yr)          (tons/yr)        ($/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    SO2.............               0           2,880           1,300           2,200
 Combustion.
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?

    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.\1\
---------------------------------------------------------------------------

    \1\ We use the SO2 benefits/ton estimate derived from
the Industrial Boilers MACT benefit analysis based on the factors
listed above. We also note that the SO2 benefits/ton
estimate derived from the CAIR benefits analysis is $18,000 in 2010
and $22,000 in 2015, both of which are quite close to the estimate
we use in this analysis. We use the NOX benefits/ton
estimate from the CAIR Boilers MACT benefits analysis (no
NOX reductions take place as a result of the Industrial
Boilers MACT).

                           Table 12.--Summary of Benefits Estimates For Proposed NSPS
----------------------------------------------------------------------------------------------------------------
                                                                                Total
                                                                     Monetized       Emission        monetized
                            Pollutant                              benefits per     reductions       benefits*
                                                                   ton emission       (tons)       (millions of
                                                                     reduction                     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 (58 FR 51735,
October 4, 1993), this action is an ``economically significant
regulatory action'' because it is likely to have an annual effect on
the

economy of $100 million or more. Accordingly, EPA submitted this action
to the Office of Management and Budget (OMB) for review under Executive
Order 12866 and any changes made in response to OMB recommendations
have been documented in the docket for this action.
    In addition, EPA prepared an analysis of the potential costs and
benefits associated with this action. This analysis is contained in the
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
<EMAIL_ADDRESS>or by calling<PHONE_NUMBER>.

    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 May 14, 2007, a comment to OMB is best
assured of having its full effect if OMB receives it by June 13, 2007.
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: April 30, 2007.
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:

Sec.  60.17  Incorporations by reference.

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

Subpart J--[Amended]

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

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

    (a) The provisions of this subpart are applicable to the following
affected facilities in petroleum refineries: fluid catalytic cracking
unit catalyst regenerators, fuel gas combustion devices, and all Claus
sulfur recovery plants except Claus plants with a design capacity 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 May 14, 2007, or any Claus sulfur recovery plant
under paragraph (a) of this section which commences construction,
reconstruction, or modification after October 4, 1976, and on or before
May 14, 2007, is subject to the requirements of this subpart except as
provided under paragraphs (c) and (d) of this section.
    (c) Any fluid catalytic cracking unit catalyst regenerator under
paragraph (b) of this section which commences construction,
reconstruction, or modification on or before January 17, 1984, is
exempted from Sec.  60.104(b).
    (d) Any fluid catalytic cracking unit in which a contact material
reacts with petroleum derivatives to improve feedstock quality and in
which the contact material is regenerated by burning off coke and/or
other deposits and that commences construction, reconstruction, or
modification on or before January 17, 1984, is exempt from this subpart
* * * * *
    4. Section 60.101 is amended by revising paragraphs (d), (i), (j),
and (k) to read as follows:

Sec.  60.101  Definitions.

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

Sec.  60.102  Standard for particulate matter.

* * * * *
    (b) Where the gases discharged by the fluid catalytic cracking unit
catalyst regenerator pass through an incinerator or waste heat boiler
in which auxiliary or supplemental liquid or solid fossil fuel is
burned, particulate matter in excess of that permitted by paragraph
(a)(1) of this section may be emitted to the atmosphere, except that
the incremental rate of particulate matter emissions shall not exceed
43 grams per Gigajoule (g/GJ) (0.10 lb/million British thermal units
(Btu)) of heat input attributable to such liquid or solid fossil fuel.
    6. Section 60.104 is amended by revising paragraphs (b)(1) and
(b)(2) to read as follows:

Sec.  60.104  Standards for sulfur oxides.

* * * * *
    (b) * * *
    (1) With an add-on control device, reduce SO2 emissions
to the atmosphere by 90 percent or maintain SO2

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

Sec.  60.105  Monitoring of emissions and operations.

    (a) * * *
    (3) For fuel gas combustion devices subject to Sec.  60.104(a)(1),
either an instrument for continuously monitoring and recording the
concentration by volume (dry basis, 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 Sec.
60.104(a)(1), an instrument for continuously monitoring and recording
the concentration (dry basis) of H2S in fuel gases before
being burned in any fuel gas combustion device.
* * * * *
    (iv) The owner or operator of a fuel gas combustion device is not
required to comply with paragraph (a)(3) or (4) of this section for
streams that are exempt under Sec.  60.104(a)(1) and fuel gas streams
combusted in a fuel gas combustion device that are inherently low in
sulfur content. Fuel gas streams meeting one of the requirements in
paragraphs (a)(4)(iv)(A) through (D) of this section will be considered
inherently low in sulfur content. If the composition of a fuel gas
stream changes such that it is no longer exempt under Sec.
60.104(a)(1) or it no longer meets one of the requirements in
paragraphs (a)(4)(iv)(A) through (D) of this section, the owner or
operator must begin continuous monitoring under paragraph (a)(3) or (4)
of this section within 15 days of the change.
    (A) Pilot gas for heaters and flares.
    (B) 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
Sec.  60.104(b)(1).
    (i) The span value of the inlet monitor shall be set at 125 percent
of the maximum estimated hourly potential SO2 emission
concentration entering the control device, and the span value of the
outlet monitor shall be set at 50 percent of the maximum estimated
hourly potential SO2 emission concentration entering the
control device.
* * * * *
    (b) An owner or operator may demonstrate that a gas stream
combusted in a fuel gas combustion device subject to Sec.  60.104(a)(1)
that is not specifically exempted in Sec.  60.105(a)(4)(iv) is
inherently low in sulfur. A 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 Sec.  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:

Sec.  60.106  Test methods and procedures.

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

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

Where:

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

Sec.  60.107  Reporting and recordkeeping requirements.

* * * * *
    (c) * * *
    (1) * * *
    (i) The average percent reduction and average concentration of
sulfur dioxide on a dry, O2-free basis in the gases
discharged to the atmosphere from any fluid cracking unit catalyst
regenerator for which the owner or operator seeks to comply with Sec.
60.104(b)(1) is below 90 percent and above 50 ppmv, as measured by the
continuous monitoring system prescribed under Sec.  60.105(a)(8), or
above 50 ppmv, as measured by the outlet continuous monitoring system
prescribed under Sec.  60.105(a)(9). * * *
* * * * *
    (e) For each stream combusted in a fuel gas combustion device
subject to Sec.  60.104(a)(1), if an owner or operator determines that
one of the exemptions listed in Sec.  60.105(a)(4)(iv) applies to that
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 Sec.  60.105(a)(4)(iv)(D), the owner or
operator must keep a copy of the application as well as the letter from
the Administrator granting approval of the application.
* * * * *
    10. Section 60.108 is amended by revising the last sentence of
paragraph (e) to read as follows:

Sec.  60.108  Performance test and compliance provisions.

* * * * *
    (e) * * * The owner or operator shall furnish the Administrator
with a written notification of the change in the semiannual report
required by Sec.  60.107(f).
    11. Section 60.109 is amended by redesignating paragraph (b)(2) as
(b)(3) and adding paragraph (b)(2) to read as follows:

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

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

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

    (a) The provisions of this subpart apply to the following affected
facilities in petroleum refineries: Fluid catalytic cracking units
(FCCU), fluid coking units, 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 May 14, 2007.
    (c) For purposes of this subpart, under Sec.  60.15, the ``fixed
capital cost of the new components'' includes the fixed capital cost of
all depreciable components which are or will be replaced pursuant to
all continuous

programs of component replacement which are commenced within any 2-year
period following May 14, 2007. For purposes of this paragraph,
``commenced'' means that an owner or operator has undertaken a
continuous program of component replacement or that an owner or
operator has entered into a contractual obligation to undertake and
complete, within a reasonable time, a continuous program of component
replacement.

Sec.  60.101a  Definitions.

    Terms used in this subpart are defined in the Clean Air Act, in
Sec.  60.2, and in this section.
    Coke burn-off means the coke removed from the surface of the FCCU
catalyst by combustion in the catalyst regenerator. The rate of coke
burn-off is calculated by the formula specified in Sec.  60.104a.
    Contact material means any substance formulated to remove metals,
sulfur, nitrogen, or any other contaminant from petroleum derivatives.
    Delayed coking unit means one or more 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 Sec.  60.692, 40 CFR 61.343 through 61.348, 40
CFR 63.647, or the marine tank vessel loading provisions in 40 CFR
63.562 or 40 CFR 63.651.
    Fuel gas 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.

Sec.  60.102a  Emissions limitations.

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

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 Sec.
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 Sec.  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 Sec.  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 Sec.  60.103a:

Sec.  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 Sec.  60.103a:

Sec.  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.

Sec.  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 Sec.  60.102a according to the
requirements of Sec.  60.8. The notification requirements of Sec.
60.8(d) apply to the initial performance test and to subsequent
performance tests required by paragraph (b) of this section (or as
required by the Administrator), but does not apply to performance tests
conducted for the purpose of obtaining supplemental data because of
continuous monitoring system breakdowns, repairs, calibration checks,
and zero and span adjustments as provided in Sec.  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 Sec.  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 Sec.  60.8(b).
    (d) The owner or operator shall determine compliance with the PM,
NOX, SO2, and CO emissions limits in Sec.
60.102a(b) for FCCU and 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 Sec.  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:
[GRAPHIC] [TIFF OMITTED] TP14MY07.000

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:

[GRAPHIC] [TIFF OMITTED] TP14MY07.001

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
Sec.  60.105a(b)(2), if applicable, using Equation 3 of this section:

[GRAPHIC] [TIFF OMITTED] TP14MY07.002

Where:

Qr = Volumetric flow rate of exhaust gas from FCCU
regenerator or fluid coking burner before any emission control or
energy recovery system that burns auxiliary fuel, dscm/min (dscf/
min);
Qa = Volumetric flow rate of air to FCCU regenerator or
fluid coking burner, as determined from the unit's control room
instrumentation, dscm/min (dscf/min);
Qoxy = Volumetric flow rate of O2 enriched air
to FCCU regenerator or fluid coking unit, as determined from the
unit's control room instrumentation, dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in FCCU regenerator
or fluid coking burner exhaust, percent by volume (dry basis);
%CO = CO concentration FCCU regenerator or fluid coking burner
exhaust, percent by volume (dry basis). When no auxiliary fuel is
burned and a continuous CO monitor is not required in accordance
with Sec.  60.105a(g)(3), assume %CO to be zero;
%O2 = O2 concentration in FCCU regenerator or
fluid coking burner exhaust, percent by volume (dry basis); and
%Ooxy = O2 concentration in O2
enriched air stream inlet to the FCCU regenerator or fluid coking
burner, percent by volume (dry basis).

    (5) Method 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 Sec.  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:

[GRAPHIC] [TIFF OMITTED] TP14MY07.003

Where:

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

    (e) The owner or operator of a FCCU or fluid coking unit that is
controlled by an electrostatic precipitator or wet scrubber and that is
subject to control device operating parameter limits Sec.  60.102a(c)
shall establish the limits based on the performance test results
according to the following procedures:
    (1) Reduce the parameter monitoring data to hourly averages for
each test run;
    (2) Determine the 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 Sec.  60.105a(g)(3) and that is subject to control device operating
parameter limits in Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  60.102a(e)(1) using Equation 5 of this
section:

[GRAPHIC] [TIFF OMITTED] TP14MY07.004

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 Sec.  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
Sec.  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 Sec.  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:

[GRAPHIC] [TIFF OMITTED] TP14MY07.005

Where:

FS,emit = Mass fraction of sulfur emitted, weight
percent;
K4 = Conversion factor, 0.5 [lbs S/lb SO2] x
60 [min/hr] x 1.66E-7 [lbs/dscf per ppmv]/2,240 [lbs/long ton] =
2.22E-9 (lbs S[middot]min[middot]long ton[middot]lbs/dscf)/(lbs
SO2[middot]hr[middot]lb[middot]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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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.

Sec.  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 Sec.  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 Sec.
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 Sec.  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 Sec.  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 Sec.  60.102a(b)(1) according to paragraph (c)(1) of