amended definition of ``fuel gas'' in both 40 CFR part 60, subparts J
and Ja states that fuel gas ``does not include vapors that are
collected and combusted in a thermal oxidizer or flare installed to
control emissions from wastewater treatment units other than those
processing sour water, marine tank vessel loading operations, or
asphalt processing units (i.e., asphalt blowing stills).''
    With respect to remediation efforts conducted under RCRA corrective
actions, we are unwilling to grant such an exclusion from the
definition of ``fuel gas'' in 40 CFR part 60, subpart Ja. First, we
anticipate that most vapors from remediation efforts would be low in
sulfur and, if so, the owner or operator could apply for the
alternative monitoring methods provided in the rule. Also, although
some remediation efforts may occur in remote locations, many of the
remediation efforts are conducted in reasonable proximity to existing
process units. Finally, the range of activities included in RCRA
remediation efforts is broad, and we have little information regarding
the number and types of RCRA remediation activities that are being
conducted. The commenter provided no description of such activities,
nor did they provide a reasonable rationale as to why the vapors from
these activities should be exempted.

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

A. What are the emission reduction and cost impacts for the final
amendments?

    The emission reduction and cost impacts presented in this section
for flares are revised estimates for the impacts of the final
requirements of 40 CFR part 60, subpart Ja for flares, as amended by
this action. The table shows the differences in anticipated impacts
between these final amendments to subpart Ja and the final June 2008
NSPS requirements of subpart Ja, which were estimated assuming only 40
flares would trigger applicability to the rule. The impacts are
presented for 400 affected flares that commence construction,
reconstruction or modification that will be required to comply with
this final rule. We anticipate that most of the flares would become
affected due to the modification provisions for flares set forth in the
final June 2008 subpart Ja rule. For this analysis, we assumed that 90
percent of the flares will be modified or reconstructed and 10 percent
of the flares will be newly constructed. Further, we estimate that 30
percent of the 400 affected flares, or 120 flares, either would meet
the definition of ``emergency flare'' in subpart Ja or would be
equipped with a flare gas recovery system such that robust sulfur and
flow monitoring would not be required. Therefore, the values in Table 5
of this preamble include the costs and emissions reductions for 400
flares to comply with the flare management plan and root cause and
corrective action analyses requirements and for 280 flares to comply
with the sulfur and flow monitoring requirements. The cost and
emissions reductions for the affected flares to comply with the short-
term H2S concentration of 162 ppmv in the fuel gas are
included in the baseline rather than the incremental impacts because
this limit is unchanged from the requirements in 40 CFR part 60,
subpart J. For further detail on the methodology of these calculations,
see Documentation of Impact Estimates for Fuel Gas Combustion Device
and Flare Regulatory Options for Amendments to the Petroleum Refinery
NSPS, in Docket ID No. EPA-HQ-OAR-2007-0011.
    We estimate that the final requirements for flares will reduce
emissions of SO2 by 3,200 tons/yr, NOX by 1,100
tons/yr and VOC by 3,400 tons/yr from the baseline. The estimated
annual cost, including annualized capital costs, is a cost savings of
about $79 million (2006 dollars) due to the replacement of some natural
gas purchases with recovered flare gas and the retention of
intermediate and product streams due to a reduction in the number of
malfunctions associated with refinery process units and ancillary
equipment connected to the flare. Note that not all refiners will
realize a cost savings since we only estimate that refineries with high
flare flows will install vapor recovery systems. Although the rule does
not specifically require installation of flare gas recovery systems, we
project that owners and operators of flares receiving high waste gas
flows will conclude, upon installation of monitors, implementation of
their flare management plans, and implementation of root causes
analyses, that installing flare gas recovery would result in fuel
savings by using the recovered flare gas where purchased natural gas is
now being used to fire equipment such as boilers and process heaters.
The flare management plan requires refiners to conduct a thorough
review of the flare system so that flare gas recovery systems are
installed and used where these systems are warranted. As part of the
development of the flare management plan, refinery owners and operators
must provide rationale and supporting evidence regarding the flare
waste gas reduction options considered, the quantity of flare gas that
would be recovered or prevented by the option, the BTU content of the
flare gas and the ability or inability of the reduction option to
offset natural gas purchases. In addition, consistent with Executive
Order 13563 (Improving Regulation and Regulatory Review, issued on
January 18, 2011), for facilities implementing flare gas recovery, we
are finalizing provisions that would allow the owner or operator to
reduce monitoring costs and the number of root cause analyses,
corrective actions, and corresponding recordkeeping and reporting they
would need to perform. We estimate that the final requirements for
flares will reduce emissions of SO2 by 3,200 tons/yr,
NOX by 1,100 tons/yr and VOC by 3,400 tons/yr from the
baseline. The overall cost effectiveness is a cost savings of about
$10,000 per ton of combined pollutants removed. The estimated
nationwide 5-year emissions reductions and cost impacts for the final
standards are summarized in Table 5 of this preamble.

   Table 5--National Emission Reductions and Cost Impacts for Petroleum Refinery Flares Subject to Amended Standards Under 40 CFR part 60, subpart Ja
                                        [Fifth year after the effective date of these final rule amendments] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Natural gas
                                                 Total        Total       offset/       Total        Annual       Annual       Annual          Cost
                                                capital    annual cost    product    annual cost    emission     emission     emission    effectiveness
           Subpart Ja requirements                cost       without      recovery     ($1,000/    reductions   reductions   reductions       ($/ton
                                                ($1,000)      credit       credit        yr)       (tons SO2/   (tons NOX/   (tons VOC/     emissions
                                                           ($1,000/yr)    ($1,000)                    yr)          yr)          yr)          reduced)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Estimates from June 2008 Final Rule.........       40,000  ...........  ...........      (7,000)           80            6          200         (23,000)
Revised Estimates for Amendments............      460,000      100,000    (180,000)     (79,000)        3,200        1,100        3,400         (10,000)
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ All costs in this table are relative to the baseline used for the 2008 final rule.

    We also estimate that the final requirements for flares will result
in emissions reduction co-benefits of CO2 equivalents by
1,900,000 metric tonnes per year, predominantly as a result of our
estimate of the largest flares employing flare gas recovery and to a
lesser extent, as a result of the root cause analyses applicable to all
flares.
    The cost, environmental and economic impacts for the final
amendments to 40 CFR part 60, subpart Ja for process heaters are not
expected to be different than those reported for the final June 2008
standards. We expect owners and operators to install the same
technology to meet these final amendments that we anticipated they
would install to meet the June 2008 final subpart Ja requirements
(i.e., ultra-low NOX burners). We did revise our emission
estimates based on the type of process heater, creating separate
impacts for forced draft process heaters and natural draft process
heaters. Dividing process heaters into separate subcategories, based on
the draft type, required us to develop new distributions of baseline
emissions for each type of process heater. The baseline emission
estimates for natural draft process heaters are slightly lower than
those developed for the existing subpart Ja requirements (per affected
process heater), but the average emission reduction achieved by ultra-
low NOX burners was adjusted to 80 percent (rather than 75
percent used for generic process heaters). For forced draft process
heaters, the baseline (i.e., uncontrolled) emissions rate for forced
draft process heaters was revised slightly upward, based on the
available emissions data. Due to these differences, the mix of controls
needed to meet a 40 ppmv emissions limit was no longer cost effective
for forced draft process heaters, but the emission reductions
associated with process heaters complying with the 60 ppmv standard
were higher than those previously estimated for generic process
heaters. Thus, the creation of new subcategories of process heaters
with different emissions limits for each subcategory did not impact the
control or compliance methods used by the facilities (i.e., BSER in all
cases was based on the performance of advanced combustion monitoring
controls in conjunction with ultra-low NOX burners) and did
not change the estimated compliance costs. As we do not have adequate
data regarding the prevalence of natural draft process heaters versus
forced draft process heaters that will become subject to the rule, we
used the emission reductions estimated for the two different types of
process heaters as a means to bound the range of anticipated
NOX emission reductions to be from 7,100 to 8,600 tons/yr in
the fifth year after the effective date of this final rule (see Revised
NOX Impact Estimates for Process Heaters, in Docket ID No.
EPA-HQ-OAR-2007-0011). We estimated the emission reductions to be 7,500
tons/yr for the June 2008 final standards, which falls well within the
anticipated range of emissions reductions for the standards we are
finalizing here. Given the uncertainty in the emissions estimates, as
well as the uncertainty in the relative number of natural draft process
heaters versus forced draft process heaters, we concluded that the
impacts previously developed for subpart Ja accurately represent the
impacts for process heaters in these final amendments.
    We note that, in the preamble to the June 2008 final standards, we
estimated costs and emissions reductions for 30 fuel gas combustion
devices, but we subsequently determined that those estimates did not
fully account for the number of affected flares (which, at the time,
were considered a subset of fuel gas combustion devices). Therefore, in
the preamble to the December 2008 proposed amendments, we presented
revised emission reduction and cost estimates for affected fuel gas
combustion devices. As previously explained, we are not finalizing the
long-term 60 ppmv H2S fuel gas concentration limit for
flares, as proposed, and we revised our cost estimates accordingly.
Because these final amendments consider flares to be a separate
affected source, the emission reductions and costs for fuel gas
combustion devices are not affected by these final amendments and are
not included in this preamble. Rather, the final emission reduction and
cost estimates for fuel gas combustion devices are very close to the
impacts presented in the June 2008 final rule; the details of the
analysis and the final impacts are presented in Documentation of Impact
Estimates for Fuel Gas Combustion Device and Flare Regulatory Options
for Amendments to the Petroleum Refinery NSPS, in Docket ID No. EPA-HQ-
OAR-2007-0011.
    The final amendments to 40 CFR part 60, subpart J are technical
corrections or clarifications to the existing rule and should have no
negative emissions impacts.

B. What are the economic impacts?

    The total annualized compliance costs are estimated to save about
$79 million (2006 dollars) in the fifth year after the effective date
of these final amendments. Note that not all refiners will realize a
cost savings as only flare systems with high waste gas flows (about 10
percent of all flares) are expected to install vapor recovery systems.
Alternatively, if no refineries install flare gas recovery systems,
total annualized compliance costs are estimated to be $10.7 million
(2006 dollars) in the fifth year after proposal. Regardless of whether
any refineries install flare gas recovery systems, we do not anticipate
any adverse economic impacts associated with this regulatory action, as
no increase in refined petroleum product prices or decrease in refined
petroleum product output is expected.

    For more information, please refer to the Regulatory Impact
Analysis (RIA) that is in the docket for this final rule.

C. What are the benefits?

    Emission controls installed to meet the requirements of this rule
will generate benefits by reducing emissions of criteria pollutants and
their precursors, including SO2, NOX and VOC as
well as CO2. SO2, NOX and VOC are
precursors to PM2.5 (particles smaller than 2.5 microns),
and NOX and VOC are precursors to ozone. For this rule, we
were only able to quantify the health benefits associated with reduced
exposure to PM2.5 from emission reductions of SO2
and NOX and the climate benefits associated with
CO2 emission reductions. We estimate the monetized benefits
of this final regulatory action to be $270 million to $580 million
(2006 dollars, 3-percent discount rate) in the fifth year (2017). The
benefits at a 7-percent discount rate for health benefits and 3-percent
discount rate for climate benefits are $240 million to $530 million
(2006 dollars). For small flares only, we estimate the monetized
benefits are $170 million to $410 million (3-percent discount rate) and
$150 million to $370 million (7-percent discount rate for health
benefits and 3-percent discount rate for climate benefits). For large
flares only, we estimate the monetized benefits are $93 million to $160
million (3-percent discount rate) and $88 million to $150 million (7-
percent discount rate for health benefits and 3-percent discount rate
for climate benefits). Using alternate relationships between
PM2.5 and premature mortality supplied by experts, higher
and lower benefits estimates are plausible, but most of the expert-
based estimates fall between these two estimates.\12\ A summary of the
monetized benefits estimates by pollutant for all flares at discount
rates of 3 percent and 7 percent is in Table 6 of this preamble.
Several benefits categories, including direct exposure to
SO2 and NOX benefits, ozone benefits, ecosystem
benefits and visibility benefits are not included in these monetized
benefits. All estimates are in 2006 dollars for the year 2017.
---------------------------------------------------------------------------

    \12\ Roman, et al., 2008. Expert Judgment Assessment of the
Mortality Impact of Changes in Ambient Fine Particulate Matter in
the U.S., Environ. Sci. Technol., 42, 7, 2268--2274.

       Table 6--Summary of the Monetized PM2.5 and CO2 Benefits for Amended Petroleum Refineries Standards
                                         [Millions of 2006 dollars] \a\
----------------------------------------------------------------------------------------------------------------
                                                                    Total monetized          Total monetized
              Pollutant                  Emission reductions      benefits (3-percent      benefits (7-percent
                                           (tons per year)             discount)                discount)
----------------------------------------------------------------------------------------------------------------
                                             With Flare Gas Recovery
----------------------------------------------------------------------------------------------------------------
PM2.5 Benefits\b\:
    SO2..............................  3,200..................  $210 to $510...........  $190 to $460.
    NOX..............................  1,100..................  $7.1 to $18............  $6.4 to $16.
    PM Total.........................  .......................  $220 to $530...........  $190 to $480.
    CO2 Benefits\c\..................  1,900,000\d\...........  $46....................  $46.
                                      --------------------------------------------------------------------------
        Total Monetized Benefits:....  .......................  $260 to $580...........  $240 to $520.
----------------------------------------------------------------------------------------------------------------
                                           Without Flare Gas Recovery
----------------------------------------------------------------------------------------------------------------
PM2.5 Benefits\b\:
    SO2..............................  2,900..................  $190 to $450...........  $170 to $410.
    NOX..............................  56.....................  $0.36 to $0.87.........  $0.32 to $0.78.
    PM Total.........................  .......................  $190 to $460...........  $170 to $410.
    CO2 Benefits\c\..................  110,000\d\.............  $2.6...................  $2.6.
        Total Monetized Benefits.....  .......................  $190 to $460...........  $170 to $410.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for the analysis year (2017) and are rounded to two significant figures so numbers may not
  sum across rows. The total monetized benefits reflect the human health benefits associated with reducing
  exposure to PM2.5 through reductions of PM2.5 precursors, such as NOX and SO2, as well as CO2. It is important
  to note that the monetized benefits do not include reduced health effects from direct exposure to SO2 and NOX,
  ozone exposure, ecosystem effects or visibility impairment.
\b\ PM benefits are shown as a range from Pope, et al. (2002) to Laden, et al. (2006). These models assume that
  all fine particles, regardless of their chemical composition, are equally potent in causing premature
  mortality because the scientific evidence is not yet sufficient to allow differentiation of effects estimates
  by particle type.
\c\ The CO2 emission reductions (shown in metric tonnes) have been reduced to reflect the anticipated emission
  increases associated with the energy disbenefits. CO2-related benefits were calculated using the social cost
  of carbon (SCC), which is discussed further in the RIA. The net present value of reduced CO2 emissions is
  calculated differently than other benefits. This table shows monetized climate benefits using the global
  average SCC estimate at a 3-percent discount rate because the interagency workgroup deemed the SCC at a 3-
  percent discount rate to be the central value. In the RIA, we also provide the monetized CO2 benefits using
  discount rates of 5 percent (average), 2.5 percent (average) and 3 percent (95th percentile).
\d\ Metric tonnes

    These benefits estimates represent the total monetized human health
benefits for populations exposed to less PM2.5 in 2017 from
controls installed to reduce air pollutants in order to meet this rule.
To estimate human health benefits of this rule, the EPA used benefit-
per-ton factors to quantify the changes in PM2.5-related
health impacts and monetized benefits based on changes in
SO2 and NOX emissions. These benefit-per-ton
factors were derived using the general approach and methodology laid
out in Fann, Fulcher, and Hubbell (2009).\13\ This approach uses a
model to convert emissions of PM2.5 precursors into changes
in ambient PM2.5 levels and another model to estimate the
changes in human health associated with that change in air quality,
which are then divided by the emission reductions to

create the benefit-per-ton estimates. However, for this rule, we use
air quality modeling data specific to the petroleum refineries
sector.\14\ The primary difference between the estimates used in this
analysis and the estimates reported in Fann, Fulcher, and Hubbell
(2009) is the air quality modeling data utilized. While the air quality
data used in Fann, Fulcher, and Hubbell (2009) reflects broad
pollutant/source category combinations, such as all non-electric
generating unit stationary point sources, the air quality modeling data
used in this analysis is sector-specific. In addition, the updated air
quality modeling data reflects more recent emissions data (2005 rather
than 2001) and has a higher spatial resolution (12 kilometers (km)
rather than 36 km grid cells). As a result, the benefit-per-ton
estimates presented herein better reflect the geographic areas and
populations likely to be affected by this sector. The benefits
methodology, such as health endpoints assessed, risk estimates applied
and valuation techniques applied did not change. However, these updated
estimates still have similar limitations as all national-average
benefit-per-ton estimates in that they reflect the geographic
distribution of the modeled emissions, which may not exactly match the
emission reductions in this rulemaking, and they may not reflect local
variability in population density, meteorology, exposure, baseline
health incidence rates or other local factors for any specific
location.
---------------------------------------------------------------------------

    \13\ Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. The Influence
of Location, Source, and Emission Type in Estimates of the Human
Health Benefits of Reducing a Ton of Air Pollution. Air Qual Atmos
Health (2009) 2:169-176.
    \14\ U.S. Environmental Protection Agency. 2011. Technical
Support Document: Estimating the Benefit per Ton of Reducing
PM2.5 Precursors from the Petroleum Refineries Sector.
EPA, Research Triangle Park, NC.
---------------------------------------------------------------------------

    We apply these national benefit-per-ton estimates calculated for
this sector separately for SO2 and NOX and
multiply them by the corresponding emission reductions. The sector-
specific modeling does not provide estimates of the PM2.5-
related benefits associated with reducing VOC emissions, but these
unquantified benefits are generally small compared to other
PM2.5 precursors. More information regarding the derivation
of the benefit-per-ton estimates for the petroleum refining sector is
available in the technical support document, which is available in the
docket.
    These models assume that all fine particles, regardless of their
chemical composition, are equally potent in causing premature mortality
because the scientific evidence is not yet sufficient to allow
differentiation of effects estimates by particle type. The main
PM2.5 precursors affected by this rule are SO2
and NOX. Even though we assume that all fine particles have
equivalent health effects, the benefit-per-ton estimates vary between
precursors depending on the location and magnitude of their impact on
PM2.5 levels, which drive population exposure. For example,
SO2 has a lower benefit-per-ton estimate than direct
PM2.5 because it does not form as much PM2.5,
thus, the exposure would be lower, and the monetized health benefits
would be lower.
    It is important to note that the magnitude of the PM2.5
benefits is largely driven by the concentration response function for
premature mortality. Experts have advised the EPA to consider a variety
of assumptions, including estimates based both on empirical
(epidemiological) studies and judgments elicited from scientific
experts, to characterize the uncertainty in the relationship between
PM2.5 concentrations and premature mortality. We cite two
key empirical studies, one based on the American Cancer Society cohort
study \15\ and the extended Six Cities cohort study.\16\ In the RIA for
this final rule, which is available in the docket, we also include
benefits estimates derived from the expert judgments and other
assumptions.
---------------------------------------------------------------------------

    \15\ Pope, et al., 2002. Lung Cancer, Cardiopulmonary Mortality,
and Long-term Exposure to Fine Particulate Air Pollution. Journal of
the American Medical Association 287:1132-1141.
    \16\ Laden, et al., 2006. Reduction in Fine Particulate Air
Pollution and Mortality. American Journal of Respiratory and
Critical Care Medicine 173: 667-672.
---------------------------------------------------------------------------

    The EPA strives to use the best available science to support our
benefits analyses. We recognize that interpretation of the science
regarding air pollution and health is dynamic and evolving. After
reviewing the scientific literature, we have determined that the no-
threshold model is the most appropriate model for assessing the
mortality benefits associated with reducing PM2.5 exposure.
Consistent with this finding, we have conformed the previous threshold
sensitivity analysis to the current state of the PM science by
incorporating a new ``Lowest Measured Level'' (LML) assessment in the
RIA accompanying this rule. While an LML assessment provides some
insight into the level of uncertainty in the estimated PM mortality
benefits, the EPA does not view the LML as a threshold and continues to
quantify PM-related mortality impacts using a full range of modeled air
quality concentrations.
    Most of the estimated PM-related benefits in this rule would accrue
to populations exposed to higher levels of PM2.5. For this
analysis, policy-specific air quality data is not available due to time
or resource limitations, thus, we are unable to estimate the percentage
of premature mortality associated with this specific rule's emission
reductions at each PM2.5 level. As a surrogate measure of
mortality impacts, we provide the percentage of the population exposed
at each PM2.5 level using the source apportionment modeling
used to calculate the benefit-per-ton estimates for this sector. Using
the Pope, et al. (2002) study, 77 percent of the population is exposed
to annual mean PM2.5 levels at or above the LML of 7.5
micrograms per cubic meter ([micro]g/m\3\). Using the Laden, et al.
(2006) study, 25 percent of the population is exposed above the LML of
10 [micro]g/m\3\. It is important to emphasize that we have high
confidence in PM2.5-related effects down to the lowest LML
of the major cohort studies. This fact is important, because, as we
model avoided premature deaths among populations exposed to levels of
PM2.5, we have lower confidence in levels below the LML for
each study.
    Every benefit analysis examining the potential effects of a change
in environmental protection requirements is limited, to some extent, by
data gaps, model capabilities (such as geographic coverage) and
uncertainties in the underlying scientific and economic studies used to
configure the benefit and cost models. Despite these uncertainties, we
believe the benefit analysis for this rule provides a reasonable
indication of the expected health benefits of the rulemaking under a
set of reasonable assumptions. This analysis does not include the type
of detailed uncertainty assessment found in the 2006 PM2.5
NAAQS RIA because we lack the necessary air quality input and
monitoring data to run the benefits model. In addition, we have not
conducted air quality modeling for this rule, and using a benefit-per-
ton approach adds another important source of uncertainty to the
benefits estimates. The 2006 PM2.5 NAAQS benefits analysis
\17\ provides an indication of the sensitivity of our results to
various assumptions.
---------------------------------------------------------------------------

    \17\ U.S. Environmental Protection Agency, 2006. Final
Regulatory Impact Analysis: PM2.5 NAAQS. Prepared by Office of Air
and Radiation. October. Available on the Internet at http://www.epa.gov/ttn/ecas/ria.html.
---------------------------------------------------------------------------

    This rule is expected to reduce CO2 emissions from the
electricity sector. The EPA has assigned a dollar value to reductions
in CO2 emissions using recent estimates of the ``social cost
of carbon'' (SCC). The SCC is an estimate

of the monetized damages associated with an incremental increase in
carbon emissions in a given year or the per metric ton benefit estimate
relating to decreases in CO2 emissions. It is intended to
include (but is not limited to) changes in net agricultural
productivity, human health, property damage from increased flood risk,
and the value of ecosystem services due to climate change.
    The SCC estimates used in this analysis were developed through an
interagency process that included the EPA and other executive branch
entities, and that concluded in February 2010. We first used these SCC
estimates in the benefits analysis for the final joint EPA/DOT
Rulemaking to establish Light-Duty Vehicle Greenhouse Gas Emission
Standards and Corporate Average Fuel Economy Standards; see the rule's
preamble for discussion about application of the SCC (75 FR 25324; May
7, 2010). The SCC Technical Support Document (SCC TSD) provides a
complete discussion of the methods used to develop these SCC
estimates.\18\
---------------------------------------------------------------------------

    \18\ Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support
Document: Social Cost of Carbon for Regulatory Impact Analysis Under
Executive Order 12866, Interagency Working Group on Social Cost of
Carbon, with participation by Council of Economic Advisers, Council
on Environmental Quality, Department of Agriculture, Department of
Commerce, Department of Energy, Department of Transportation,
Environmental Protection Agency, National Economic Council, Office
of Energy and Climate Change, Office of Management and Budget,
Office of Science and Technology Policy, and Department of Treasury
(February 2010). Also available at http://epa.gov/otaq/climate/regulations.htm.
---------------------------------------------------------------------------

    The interagency group selected four SCC values for use in
regulatory analyses, which we have applied in this analysis: $5.9,
$24.3, $39, and $74.4 per metric ton of CO2 emissions in
2016, in 2007 dollars. The first three values are based on the average
SCC from three integrated assessment models, at discount rates of 5, 3
and 2.5 percent, respectively. Social cost of carbon values at several
discount rates are included because the literature shows that the SCC
is quite sensitive to assumptions about the discount rate, and because
no consensus exists on the appropriate rate to use in an
intergenerational context. The fourth value is the 95th percentile of
the SCC from all three values at a 3-percent discount rate. It is
included to represent higher-than-expected impacts from temperature
change further out in the extremes of the SCC distribution. Low
probability, high impact events are incorporated into all of the SCC
values through explicit consideration of their effects in two of the
three values as well as the use of a probability density function for
equilibrium climate sensitivity. Treating climate sensitivity
probabilistically results in more high temperature outcomes, which in
turn leads to higher projections of damages.
    Applying the global SCC estimates using a 3-percent discount rate,
we estimate the value of the climate related benefits of this rule in
2017 is $49 million (2006$), as shown in Table 6. See the RIA for more
detail on the methodology used to calculate these benefits and
additional estimates of climate benefits using different discount rates
and the 95th percentile of the 3-percent discount rate SCC. Important
limitations and uncertainties of the SCC approach are also described in
the RIA.
    It should be noted that the monetized benefits estimates provided
above do not include benefits from several important benefit
categories, including direct exposure to SO2 and
NOX, ozone exposure, ecosystem effects and visibility
impairment. Although we do not have sufficient information or modeling
available to provide monetized estimates for this rulemaking, we
include a qualitative assessment of these unquantified benefits in the
RIA for this final rule.
    Although this final rule provides refiners with some additional
compliance options and removes some requirements, such as the long-term
H2S limit for flares, these are non-monetized benefits of
the rule.
    For more information on the benefits analysis, please refer to the
RIA for this rulemaking, which is available in the docket.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory 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, the EPA submitted
this action to the Office of Management and Budget (OMB) for review
under Executive Order 12866 and Executive Order 13563 (76 FR 3821,
January 21, 2011), and any changes made in response to OMB
recommendations have been documented in the docket for this action. In
addition, the EPA prepared a RIA of the potential costs and benefits
associated with this action.
    A summary of the monetized benefits, compliance costs and net
benefits for the final rule at discount rates of 3 percent and 7
percent is in Table 7 of this preamble.

  Table 7--Summary of the Monetized Benefits, Compliance Costs and Net
        Benefits for the Final Petroleum Refineries NSPS in 2017
                     [Millions of 2006 dollars] \a\
------------------------------------------------------------------------
                               3-Percent discount    7-Percent discount
                                      rate                  rate
------------------------------------------------------------------------
Total Monetized Benefits \b\  $270 to $580........  $240 to $530.
Total Compliance Costs \c\..  -$79................  -$79.
Net Benefits................  $340 to $660........  $320 to $610.
                             -------------------------------------------
Non-Monetized Benefits......  Health effects from direct exposure to SO2
                                                and NO2.
                             -------------------------------------------
                                Health effects from PM2.5 exposure from
                                                  VOC
                             -------------------------------------------
                                          Ecosystem effects.
                             -------------------------------------------
                                        Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for the implementation year (2017) and are rounded
  to two significant figures.

\b\ The total monetized benefits reflect the human health benefits
  associated with reducing exposure to PM2.5 through reductions of PM2.5
  precursors such as NOX and SO2, as well as CO2 benefits. It is
  important to note that the monetized benefits do not include the
  reduced health effects from direct exposure to SO2 and NOX, ozone
  exposure, ecosystem effects or visibility impairment. Human health
  benefits are shown as a range from Pope, et al. (2002) to Laden, et
  al. (2006). These models assume that all fine particles, regardless of
  their chemical composition, are equally potent in causing premature
  mortality because the scientific evidence is not yet sufficient to
  allow differentiation of effects estimates by particle type. The net
  present value of reduced CO2 emissions is calculated differently than
  other benefits. This table includes monetized climate benefits using
  the global average social cost of carbon (SCC) estimated at a 3-
  percent discount rate because the interagency work group deemed the
  SCC estimate at a 3-percent discount rate to be the central value.
\c\ The engineering compliance costs are annualized using a 7-percent
  discount rate.

    To support the determination of BSER for the June 24, 2008, final
rule, we considered a number of regulatory options and their costs and
benefits. Those results are presented in the RIA for the June 24, 2008,
final rulemaking, which is available in the docket. These final rule
amendments are in response to comments received on the December 22,
2008, proposed rule amendments. Costs and benefits associated with the
amendments in this final rule differ from the June 24, 2008, final rule
and the December 22, 2008, proposed rule amendments primarily as a
result of correcting the number of flares projected to have to comply
with this rule (i.e., 400 affected flares in this rule compared to 40
estimated in the June 24, 2008, final rule and 150 in the December 22,
2008, proposed amendments). In addition, the amendments in this final
rule to address comments received for the other fuel gas combustion
devices do not affect the projected costs and benefits from the
December 22, 2008, proposal, which also did not change from the June
24, 2008, final rule. Therefore, for purposes of developing these final
rule amendments, we did not re-evaluate the suite of regulatory options
for flares and other fuel gas combustion devices considered to support
the June 24, 2008, final rule. However, even with the flare count
adjustment, this final rule is consistent with Executive Order 13563
(Improving Regulation and Regulatory Review) because the monetized
benefits of this final rule exceed the costs. In addition, for
facilities implementing flare gas recovery, we are reducing regulatory
burden by finalizing provisions that would allow the owner or operator
to reduce monitoring costs and the number of root cause analyses,
corrective actions and corresponding recordkeeping and reporting they
would need to perform.
    For more information on the cost-benefits analysis, please refer to
the RIA for this rulemaking, which is available in the docket.

B. Paperwork Reduction Act

    The final amendments to the Standards of Performance for Petroleum
Refineries (40 CFR part 60, subpart J) do not impose any new
information collection burden. The final amendments are clarifications
and technical corrections that do not affect the estimated burden of
the existing rule. Therefore, we have not revised the ICR for the
existing rule. However, OMB has previously approved the information
collection requirements contained 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.
The OMB control numbers for the EPA's regulations are listed in 40 CFR
part 9.
    The OMB has approved the information collection requirements in the
amendments to the Standards of Performance for Petroleum Refineries for
Which Construction, Reconstruction, or Modification Commenced After May
14, 2007 (40 CFR part 60, subpart Ja) under the provisions of the
Paperwork Reduction Act, 44 U.S.C. 3501, et seq., and has assigned OMB
control number 2060-0602.
    The information requirements in these final amendments add new
compliance options, provide more time to comply with the requirements
for flares, clarify the flare management plan requirements and clarify
the flare modification provision. Overall, these changes are expected
to reduce the costs associated with testing, monitoring, recording and
reporting, so they will not result in any increase in burden for the
affected facilities for which the EPA previously estimated the burden.
However, the EPA has revised the number of flares expected to become
subject to the rule over the first 3 years of the ICR. Therefore, the
annual burden was estimated for the additional affected facilities. The
total burden for 40 CFR part 60, subpart Ja can be estimated by summing
the previously approved annual burden for OMB control number 2060-0602
(5,340 labor-hours per year at a cost of $481,249 per year, annualized
capital costs of $2,052,000 per year, and operation and maintenance
costs of $1,117,440 per year) and the annual burden for this ICR, as
described below.
    The annual burden for this information collection averaged over the
first 3 years of this ICR is estimated to total 54,572 labor-hours per
year at a cost of $4,918,110 per year. The annualized capital costs are
estimated at $11,266,000 per year and operation and maintenance costs
are estimated at $8,750,000 per year. We note that the capital costs,
as well as the operation and maintenance costs, are for the continuous
monitors; these costs are also included in the cost impacts presented
in section V.A of this preamble. Therefore, the burden costs associated
with the continuous monitors presented in the ICR are not additional
costs incurred by affected sources subject to final 40 CFR part 60,
subpart Ja. Burden is defined at 5 CFR 1320.3(b).
    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations are listed in 40 CFR part 9. The EPA is amending the
table in 40 CFR part 9 of currently approved ICR control numbers for
various regulations to list regulatory citations for the information
requirements contained in this final rule. This amendment updates the
table to list the information collection requirements being promulgated
here as amendments to the NSPS for petroleum refineries.
    The EPA will continue to present OMB control numbers in a
consolidated table format to be codified in 40 CFR part 9 of the
agency's regulations and in each CFR volume containing the EPA
regulations. The table lists the section numbers with reporting and
recordkeeping requirements and the current OMB control numbers. This
listing of the OMB control numbers and their subsequent codification in
the CFR satisfy the requirements of the Paperwork Reduction Act (44
U.S.C. 3501, et seq.) and OMB's implementing regulations at 5 CFR part
1320.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act 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
would not have a significant economic impact on a substantial number of
small entities. Small entities include small businesses, small
organizations and small governmental jurisdictions.

    For purposes of assessing the impact of this final action on small
entities, small entity is defined as: (1) A small business whose parent
company has no more than 1,500 employees, that is primarily engaged in
refining crude petroleum into refined petroleum as defined by NAICS
code 32411 (as defined by Small Business Administration 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.
    While we estimated the natural gas recovery offsets or credit at a
national level and believe that larger firms are more likely to offset
natural gas purchases, the revenues from natural gas recovery offsets
might mask disproportionate impacts on small refiners. To better
identify disproportionate impacts, we examined the potential impacts on
refiners based on a scenario where no firms adopt flare gas recovery
systems and comply with the NSPS through flare monitoring and flare
management and root cause analysis actions. The incremental compliance
costs imposed on small refineries are not estimated to create
significant impacts on a cost-to-sales ratio basis at the firm level.
Therefore, no adverse economic impacts are expected for any small or
large entity.
    After considering the economic impacts of these final amendments on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. The small
entities directly regulated by these final amendments are small
petroleum refineries. We have determined that 31 small refiners, or 55
percent of total refiners, will experience an impact of between less
than 0.01 percent up to 0.63 percent of revenues.

D. Unfunded Mandates Reform Act

    This rule does not contain a federal mandate that may result in
expenditures of $100 million or more for state, local and tribal
governments, in the aggregate, or the private sector in any one year.
The costs of the final amendments would not increase costs associated
with the final rule. Thus, this rule is not subject to the requirements
of sections 202 or 205 of the UMRA.
    This rule is also not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. The final
amendments contain no requirements that apply to such governments and
impose no obligations upon them.

E. Executive Order 13132: Federalism

    This 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. This action does not modify
existing responsibilities or create new responsibilities among EPA
Regional offices, states or local enforcement agencies. Thus, Executive
Order 13132 does not apply to this action.

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

    This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). The final
amendments impose no requirements on tribal governments. Thus,
Executive Order 13175 does not apply to this action.

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

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

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

    This action is not a ``significant energy action'' as defined in
Executive Order 13211 (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. The final amendments would not increase the level of
energy consumption required for the final rule and may decrease energy
requirements.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs the EPA to use voluntary consensus standards (VCS) in its
regulatory activities, unless to do so would be inconsistent with
applicable law or otherwise impractical. VCS are technical standards
(e.g., materials specifications, test methods, sampling procedures and
business practices) that are developed or adopted by VCS bodies. NTTAA
directs the EPA to provide Congress, through OMB, explanations when the
agency decides not to use available and applicable VCS.
    This rulemaking involves technical standards. The EPA has decided
to use the following VCS for determining the higher heating value of
fuel fed to process heaters: ASTM D240-02 (Reapproved 2007), Standard
Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb
Calorimeter; ASTM D1826-94 (Reapproved 2003), Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter; ASTM D3588-98 (Reapproved 2003), Standard
Practice for Calculating Heat Value, Compressibility Factor, and
Relative Density of Gaseous Fuels; ASTM D4809-06, Standard Test Method
for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter
(Precision Method); ASTM D4891-89 (Reapproved 2006), Standard Test
Method for Heating Value of Gases in Natural Gas Range by
Stoichiometric Combustion; ASTM D1945-03 (Reapproved 2010), Standard
Method for Analysis of Natural Gas by Gas Chromatography; and ASTM
D1946-90 (Reapproved 2006), Standard Method for Analysis of Reformed
Gas by Gas Chromatography.
    The EPA has decided to use the following VCS as acceptable
alternatives to EPA Methods 2, 2A, 2B, 2C or 2D for conducting relative
accuracy evaluations of fuel gas flow monitors: American Society of
Mechanical Engineers (ASME) MFC-3M-2004, Measurement of Fluid Flow in
Pipes Using Orifice, Nozzle, and Venturi; ANSI/ASME MFC-4M-1986
(Reaffirmed 2008), Measurement of Gas Flow by Turbine Meters; ASME MFC-
6M-1998 (Reaffirmed 2005), Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters; ASME/ANSI MFC-7M-1987 (Reaffirmed 2006), Measurement
of Gas Flow by Means of Critical Flow Venturi Nozzles; ASME MFC-11M-
2006, Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters;
ASME MFC-14M-2003, Measurement of Fluid Flow Using Small Bore Precision
Orifice Meters; and ASME MFC-18M-2001, Measurement of Fluid Flow Using
Variable Area Meters.

    The EPA has also decided to use the following VCS as acceptable
alternatives to EPA Methods 2, 2A, 2B, 2C or 2D for conducting relative
accuracy evaluations of fuel oil flow monitors: ANSI/ASME MFC-5M-1985
(Reaffirmed 2006), Measurement of Liquid Flow in Closed Conduits Using
Transit-Time Ultrasonic Flowmeters; ASME/ANSI MFC-9M-1988 (Reaffirmed
2006), Measurement of Liquid Flow in Closed Conduits by Weighing
Method; ASME MFC-16-2007, Measurement of Liquid Flow in Closed Conduits
with Electromagnetic Flowmeters; ASME MFC-22-2007, Measurement of
Liquid by Turbine Flowmeters; and ISO 8316: Measurement of Liquid Flow
in Closed Conduits--Method by Collection of the Liquid in a Volumetric
Tank (1987-10-01)--First Edition.
    The EPA has decided to use the following VCS as acceptable
alternatives to EPA Method 15A and 16A for conducting relative accuracy
evaluations of monitors for reduced sulfur compounds, total sulfur
compounds, and H2S: ANSI/ASME PTC 19.10-1981, Flue and
Exhaust Gas Analyses. The EPA has decided to use the following VCS as
acceptable alternatives to EPA Method 16A for analysis of total sulfur
samples: ASTM D4468-85 (Reapproved 2006), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry; and ASTM D5504-08, Standard Test Method for Determination
of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas
Chromatography and Chemiluminescence.
    The EPA has decided to use the following VCS as acceptable
alternatives to EPA Method 18 for relative accuracy evaluations of gas
composition analyzers for gas-fired process heaters: ASTM D1945-03
(Reapproved 2010), Standard Method for Analysis of Natural Gas by Gas
Chromatography; ASTM D1946-90 (Reapproved 2006), Standard Method for
Analysis of Reformed Gas by Gas Chromatography; ASTM UOP539-97,
Refinery Gas Analysis by Gas Chromatography; and ASTM D6420-99
(Reapproved 2004), Standard Test Method for Determination of Gaseous
Organic Compounds by Direct Interface Gas Chromatography-Mass
Spectrometry. However, ASTM D6420-99 is a suitable alternative to EPA
Method 18 only where:
    (1) The target compound(s) are those listed in Section 1.1 of ASTM
D6420-99, and
    (2) The target concentration is between 150 parts per billion by
volume and 100 ppmv.
    For target compound(s) not listed in Section 1.1 of ASTM D6420-99,
but potentially detected by mass spectrometry, the regulation specifies
that the additional system continuing calibration check after each run,
as detailed in Section 10.5.3 of the ASTM method, must be followed,
met, documented and submitted with the data report even if there is no
moisture condenser used or the compound is not considered water
soluble. For target compound(s) not listed in Section 1.1 of ASTM
D6420-99 and not amenable to detection by mass spectrometry, ASTM
D6420-99 does not apply.
    These above-listed VCS are incorporated by reference (see 40 CFR
60.17).
    The EPA has also decided to use American Gas Association Report No.
3: Orifice Metering for Natural Gas and Other Related Hydrocarbon
Fluids, Part 1: General Equations and Uncertainty Guidelines (1990),
American Gas Association Report No. 3: Orifice Metering for Natural Gas
and Other Related Hydrocarbon Fluids, Part 2: Specification and
Installation Requirements (2000), American Gas Association Report No.
11: Measurement of Natural Gas by Coriolis Meter (2003), American Gas
Association Transmission Measurement Committee Report No. 7,
Measurement of Natural Gas by Turbine Meters (Revised February 2006)
and API's Manual of Petroleum Measurement Standards, Chapter 22--
Testing Protocol, Section 2--Differential Pressure Flow Measurement
Devices, First Edition, August 2005, for conducting relative accuracy
evaluations of fuel gas flow monitors; Gas Processors Association (GPA)
Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures
by Gas Chromatography (2000), for relative accuracy evaluations of gas
composition analyzers for gas-fired process heaters; and GPA 2172-09,
Calculation of Gross Heating Value, Relative Density, Compressibility
and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for
Custody Transfer, for determining the higher heating value of fuel fed
to process heaters. These methods are also incorporated by reference
(see 40 CFR 60.17).
    While the agency has identified five VCS as being potentially
applicable to this rule, we have decided not to use these VCS in this
rulemaking. The use of these VCS would be impractical because they do
not meet the objectives of the standards cited in this rule. See the
docket for this rule for the reasons for these determinations.
    Under 40 CFR 60.13(i) of the NSPS General Provisions, a source may
apply to the EPA for permission to use alternative test methods or
alternative monitoring requirements in place of any required testing
methods, performance specifications or procedures in the final rule and
amendments.

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

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies and activities on minority populations and low-income
populations in the United States.
    The EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment. The final amendments are either clarifications or
compliance alternatives which will neither increase or decrease
environmental protection.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801, et seq., as added by
the Small Business Regulatory Enforcement Fairness Act of 1996,
generally provides that before a rule may take effect the agency
promulgating the rule must submit a rule report, which includes a copy
of the rule, to each House of Congress and to the Comptroller General
of the United States. The EPA will submit a report containing these
final rules and other required information to the United States Senate,
the United States House of Representatives and the Comptroller General
of the United States prior to publication of the final rules in the
Federal Register. A major rule cannot take effect until 60 days after
it is published in the Federal Register. This action is a ``major
rule'' as defined by 5 U.S.C. 804(2). This final rule will be effective
on November 13, 2012.

List of Subjects

40 CFR Part 9

    Environmental protection, Reporting and recordkeeping requirements.

40 CFR Part 60

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

    Dated: June 1, 2012.
Lisa P. Jackson,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is amended as follows:

PART 9--[AMENDED]

0
1. The authority citation for part 9 continues to read as follows:

    Authority: 7 U.S.C. 135, et seq., 136-136y; 15 U.S.C. 2001,
2003, 2005, 2006, 2601-2671; 21 U.S.C. 331j, 346a, 348; 31 U.S.C.
9701; 33 U.S.C. 1251, et seq., 1311, 1313d, 1314, 1318, 1321, 1326,
1330, 1342, 1344, 1345(d) and (e), 1361; E.O. 11735, 38 FR 21243, 3
CFR, 1971-1975 Comp. p. 973; 42 U.S.C. 241, 242b, 243, 246, 300f,
300g, 300g-1, 300g-2, 300g-3, 300g-4, 300g-5, 300g-6, 300j-1, 300j-
2, 300j-3, 300j-4, 300j-9, 1857, et seq., 6901-6992k, 7401-7671q,
7542, 9601-9657, 11023, 11048.

0
2. The table in Section 9.1 is amended by adding an entry in numerical
order for 60.103a-60.108a under the heading ``Standards of Performance
for New Stationary Sources'' to read as follows:

Sec.  9.1  OMB Approvals under the Paperwork Reduction Act.

* * * * *

------------------------------------------------------------------------
                                                            OMB control
                     40 CFR citation                            No.
------------------------------------------------------------------------

                                * * * * *
------------------------------------------------------------------------
         Standards of Performance for New Stationary Sources \1\
------------------------------------------------------------------------

                                * * * * *
------------------------------------------------------------------------
60.103a-60.108a.........................................       2060-0602

                                * * * * *
------------------------------------------------------------------------
\1\ The ICRs referenced in this section of the table encompass the
  applicable general provisions contained in 40 CFR part 60, subpart A,
  which are not independent information collection requirements.

* * * * *

PART 60--[AMENDED]

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

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

Subpart A--[AMENDED]

0
4. Section 60.17 is amended by:
0
a. Revising paragraphs (a)(84), (a)(95), (a)(96), (a)(97), and (a)(98);
0
b. Adding paragraphs (a)(100) through (a)(108);
0
c. Adding paragraph (c)(2);
0
d. Revising paragraph (h)(4) and adding paragraphs (h)(5) through
(h)(15);
0
e. Adding paragraphs (m)(2) and (m)(3); and
0
f. Adding paragraphs (p) and (q) to read as follows:

Sec.  60.17  Incorporations by reference.

* * * * *
    (a) * * *
    (84) ASTM D6420-99 (Reapproved 2004), Standard Test Method for
Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography-Mass Spectrometry, (Approved October 1, 2004), IBR
approved for Sec.  60.107a(d) of subpart Ja and table 2 of subpart JJJJ
of this part.
* * * * *
    (95) ASTM D3588-98 (Reapproved 2003), Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels, (Approved May 10, 2003), IBR approved for Sec. Sec.
60.107a(d) and 60.5413(d).
    (96) ASTM D4891-89 (Reapproved 2006), Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion, (Approved June 1, 2006), IBR approved for Sec. Sec.
60.107a(d) and 60.5413(d).
    (97) ASTM D1945-03 (Reapproved 2010), Standard Method for Analysis
of Natural Gas by Gas Chromatography, (Approved January 1, 2010), IBR
approved for Sec. Sec.  60.107a(d) and 60.5413(d).
    (98) ASTM D5504-08, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence, (Approved June 15, 2008), IBR approved for
Sec. Sec.  60.107a(e) and 60.5413(d).
* * * * *
    (100) ASTM D4468-85 (Reapproved 2006), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry (Approved June 1, 2006), IBR approved for Sec.  60.107a(e).
    (101) ASTM D240-02 (Reapproved 2007), Standard Test Method for Heat
of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter,
(Approved May 1, 2007), IBR approved for Sec.  60.107a(d).
    (102) ASTM D1826-94 (Reapproved 2003), Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter, (Approved May 10, 2003), IBR approved for Sec.
60.107a(d).
    (103) ASTM D1946-90 (Reapproved 2006), Standard Method for Analysis
of Reformed Gas by Gas Chromatography, (Approved June 1, 2006), IBR
approved for Sec.  60.107a(d).
    (104) ASTM D4809-06, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method),
(Approved December 1, 2006), IBR approved for Sec.  60.107a(d).
    (105) ASTM UOP539-97, Refinery Gas Analysis by Gas Chromatography,
(Copyright 1997), IBR approved for Sec.  60.107a(d).
    (106) ASTM D3699-08, Standard Specification for Kerosine, including
Appendix X1, (Approved September 1, 2008), IBR approved for Sec. Sec.
60.41b of subpart Db and 60.41c of subpart Dc of this part.
    (107) ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1
through X3, (Approved July 15, 2011), IBR approved for Sec. Sec.
60.41b of subpart Db and 60.41c of subpart Dc of this part.
    (108) ASTM D7467-10, Standard Specification for Diesel Fuel Oil,
Biodiesel Blend (B6 to B20), including Appendices X1 through X3,
(Approved August 1, 2010), IBR approved for Sec. Sec.  60.41b of
subpart Db and 60.41c of subpart Dc of this part.
* * * * *
    (c) * * *
    (2) American Petroleum Institute (API) Manual of Petroleum
Measurement Standards, Chapter 22-Testing Protocol, Section 2-
Differential Pressure Flow Measurement Devices, First Edition, August
2005, IBR approved for Sec.  60.107a(d) of subpart Ja of this part.
* * * * *
    (h) * * *
    (4) ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus], (Issued August 31, 1981), IBR approved
for Sec.  60.56c(b), Sec.  60.63(f), Sec.  60.106(e), Sec.  60.104a(d),
(h), (i), and (j), Sec.  60.105a(d), (f), and (g), Sec.  60.106a(a),
Sec.  60.107a(a), (c), and (e), tables 1 and 3 of subpart EEEE, tables
2 and 4 of subpart FFFF, table 2 of subpart JJJJ, Sec. Sec.
60.4415(a), 60.2145(s), 60.2145(t),

60.2710(s), 60.2710(t), 60.2710(w), 60.2730(q), 60.4900(b), 60.5220(b),
tables 1 and 2 to subpart LLLL, tables 2 and 3 to subpart MMMM,
Sec. Sec.  60.5406(c) and 60.5413(b).
    (5) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi, IBR approved for Sec.  60.107a(d) of
subpart Ja of this part.
    (6) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008), Measurement of Gas
Flow by Turbine Meters, IBR approved for Sec.  60.107a(d) of subpart Ja
of this part.
    (7) ANSI/ASME-MFC-5M-1985 (Reaffirmed 2006), Measurement of Liquid
Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, IBR
approved for Sec.  60.107a(d) of subpart Ja of this part.
    (8) ASME MFC-6M-1998 (Reaffirmed 2005), Measurement of Fluid Flow
in Pipes Using Vortex Flowmeters, IBR approved for Sec.  60.107a(d) of
subpart Ja of this part.
    (9) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006), Measurement of Gas
Flow by Means of Critical Flow Venturi Nozzles, IBR approved for Sec.
60.107a(d) of subpart Ja of this part.
    (10) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006), Measurement of Liquid
Flow in Closed Conduits by Weighing Method, IBR approved for Sec.
60.107a(d) of subpart Ja of this part.
    (11) ASME MFC-11M-2006, Measurement of Fluid Flow by Means of
Coriolis Mass Flowmeters, IBR approved for Sec.  60.107a(d) of subpart
Ja of this part.
    (12) ASME MFC-14M-2003, Measurement of Fluid Flow Using Small Bore
Precision Orifice Meters, IBR approved for Sec.  60.107a(d) of subpart
Ja of this part.
    (13) ASME MFC-16-2007, Measurement of Liquid Flow in Closed
Conduits with Electromagnetic Flowmeters, IBR approved for Sec.
60.107a(d) of subpart Ja of this part.
    (14) ASME MFC-18M-2001, Measurement of Fluid Flow Using Variable
Area Meters, IBR approved for Sec.  60.107a(d) of subpart Ja of this
part.
    (15) ASME MFC-22-2007, Measurement of Liquid by Turbine Flowmeters,
IBR approved for Sec.  60.107a(d) of subpart Ja of this part.
* * * * *
    (m) * * *
    (2) Gas Processors Association Standard 2172-09, Calculation of
Gross Heating Value, Relative Density, Compressibility and Theoretical
Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody
Transfer (2009), IBR approved for Sec.  60.107a(d) of subpart Ja of
this part.
    (3) Gas Processors Association Standard 2261-00, Analysis for
Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (2000),
IBR approved for Sec.  60.107a(d) of subpart Ja of this part.
* * * * *
    (p) The following American Gas Association material is available
for purchase from the following address: ILI Infodisk, 610 Winters
Avenue, Paramus, New Jersey 07652:
    (1) American Gas Association Report No. 3: Orifice Metering for
Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General
Equations and Uncertainty Guidelines (1990), IBR approved for Sec.
60.107a(d) of subpart Ja of this part.
    (2) American Gas Association Report No. 3: Orifice Metering for
Natural Gas and Other Related Hydrocarbon Fluids, Part 2: Specification
and Installation Requirements (2000), IBR approved for Sec.  60.107a(d)
of subpart Ja of this part.
    (3) American Gas Association Report No. 11: Measurement of Natural
Gas by Coriolis Meter (2003), IBR approved for Sec.  60.107a(d) of
subpart Ja of this part.
    (4) American Gas Association Transmission Measurement Committee
Report No. 7: Measurement of Gas by Turbine Meters (Revised February
2006), IBR approved for Sec.  60.107a(d) of subpart Ja of this part.
    (q) The following material is available for purchase from the
International Standards Organization (ISO), 1, ch. de la Voie-Creuse,
Case postale 56, CH-1211 Geneva 20, Switzerland, +41 22 749 01 11,
http://www.iso.org/iso/home.htm.
    (1) ISO 8316: Measurement of Liquid Flow in Closed Conduits--Method
by Collection of the Liquid in a Volumetric Tank (1987-10-01)--First
Edition, IBR approved for Sec.  60.107a(d) of subpart Ja of this part.
    (2) [Reserved]

Subpart J--[AMENDED]

0
5. Section 60.100 is amended by:
0
a. Revising paragraph (b);
0
b. Redesignating paragraph (e) as (f); and
0
c. Adding a new paragraph (e) to read as follows:

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

* * * * *
    (b) Any fluid catalytic cracking unit catalyst regenerator or fuel
gas combustion device under paragraph (a) of this section other than a
flare which commences construction, reconstruction or modification
after June 11, 1973, and on or before May 14, 2007, or any fuel gas
combustion device under paragraph (a) of this section that is also a
flare which commences construction, reconstruction or modification
after June 11, 1973, and on or before June 24, 2008, or any Claus
sulfur recovery plant under paragraph (a) of this section which
commences construction, reconstruction or modification after October 4,
1976, and on or before May 14, 2007, is subject to the requirements of
this subpart except as provided under paragraphs (c) through (e) of
this section.
* * * * *
    (e) Owners or operators may choose to comply with the applicable
provisions of subpart Ja of this part to satisfy the requirements of
this subpart for an affected facility.
* * * * *

0
6. Section 60.101 is amended by revising paragraph (d) to read as
follows:

Sec.  60.101  Definitions.

* * * * *
    (d) Fuel gas means any gas which is generated at a petroleum
refinery and 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.
Fuel gas does not include vapors that are collected and combusted in a
thermal oxidizer or flare installed to control emissions from
wastewater treatment units or marine tank vessel loading operations.
* * * * *

0
7. Section 60.106 is amended by revising paragraph (c)(1) to read as
follows:

Sec.  60.106  Test methods and procedures.

* * * * *
    (c) * * *
    (1) The allowable emission rate (Es) of PM shall be
computed for each run using the following equation:

Es = F + A (H/Rc)

Where:

Es = Emission rate of PM allowed, kg/Mg (lb/ton) of coke
burn-off in catalyst regenerator.
F = Emission standard, 1.0 kg/Mg (2.0 lb/ton) of coke burn-off in
catalyst regenerator.
A = Allowable incremental rate of PM emissions, 43 g/GJ (0.10 lb/
million Btu).
H = Heat input rate from solid or liquid fossil fuel, GJ/hr (million
Btu/hr).
Rc = Coke burn-off rate, Mg coke/hr (ton coke/hr).
* * * * *

Subpart Ja--[AMENDED]

0
7. In Sec.  60.100a, lift the stay on paragraph (c) published December
22, 2008 (73 FR 78552).

0
8. Section 60.100a is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraph (b);
0
c. Revising paragraph (c) introductory text and paragraph (c)(1); and
0
d. Revising paragraph (d).
    The revisions read as follows:

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

    (a) The provisions of this subpart apply to the following affected
facilities in petroleum refineries: fluid catalytic cracking units
(FCCU), fluid coking units (FCU), delayed coking units, fuel gas
combustion devices (including process heaters), flares and sulfur
recovery plants. The sulfur recovery plant need not be physically
located within the boundaries of a petroleum refinery to be an affected
facility, provided it processes gases produced within a petroleum
refinery.
    (b) Except for flares and delayed coking units, the provisions of
this subpart apply only to affected facilities under paragraph (a) of
this section which commence construction, modification or
reconstruction after May 14, 2007. For flares, the provisions of this
subpart apply only to flares which commence construction, modification
or reconstruction after June 24, 2008. For the purposes of this
subpart, a modification to a flare commences when a project that
includes any of the activities in paragraphs (c)(1) or (2) of this
section is commenced. For delayed coking units, the provisions of this
subpart apply to delayed coking units that commence construction,
reconstruction or modification on the earliest of the following dates:
    (1) May 14, 2007, for such activities that involve a ``delayed
coking unit'' defined as follows: one or more refinery process units in
which high molecular weight petroleum derivatives are thermally cracked
and petroleum coke is produced in a series of closed, batch system
reactors;
    (2) December 22, 2008, for such activities that involve a ``delayed
coking unit'' defined as follows: a refinery process unit in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is produced in a series of closed, batch system
reactors. A delayed coking unit consists of the coke drums and
associated fractionator;
    (3) September 12, 2012, for such activities that involve a
``delayed coking unit'' as defined in Sec.  60.101a.
    (c) For all affected facilities other than flares, the provisions
in Sec.  60.14 regarding modification apply. As provided in Sec.
60.14(f), the special provisions set forth under this subpart shall
supersede the provisions in Sec.  60.14 with respect to flares. For the
purposes of this subpart, a modification to a flare occurs as provided
in paragraphs (c)(1) or (2) of this section.
    (1) Any new piping from a refinery process unit, including
ancillary equipment, or a fuel gas system is physically connected to
the flare (e.g., for direct emergency relief or some form of continuous
or intermittent venting). However, the connections described in
paragraphs (c)(1)(i) through (vii) of this section are not considered
modifications of a flare.
    (i) Connections made to install monitoring systems to the flare.
    (ii) Connections made to install a flare gas recovery system or
connections made to upgrade or enhance components of a flare gas
recovery system (e.g., addition of compressors or recycle lines).
    (iii) Connections made to replace or upgrade existing pressure
relief or safety valves, provided the new pressure relief or safety
valve has a set point opening pressure no lower and an internal
diameter no greater than the existing equipment being replaced or
upgraded.
    (iv) Connections made for flare gas sulfur removal.
    (v) Connections made to install back-up (redundant) equipment
associated with the flare (such as a back-up compressor) that does not
increase the capacity of the flare.
    (vi) Replacing piping or moving an existing connection from a
refinery process unit to a new location in the same flare, provided the
new pipe diameter is less than or equal to the diameter of the pipe/
connection being replaced/moved.
    (vii) Connections that interconnect two or more flares.
* * * * *
    (d) For purposes of this subpart, under Sec.  60.15, the ``fixed
capital cost of the new components'' includes the fixed capital cost of
all depreciable components which are or will be replaced pursuant to
all continuous programs of component replacement which are commenced
within any 2-year period following the relevant applicability date
specified in paragraph (b) of this section.

0
9. In Sec.  60.101a, lift the stay on the definition of ``flare''
published December 22, 2008 (73 FR 78552).

0
10. Section 60.101a is amended by:
0
a. Revising the introductory text;
0
b. Adding, in alphabetical order, definitions of ``Air preheat,''
``Ancillary equipment,'' ``Cascaded flare system,'' ``Co-fired process
heater,'' ``Corrective action,'' ``Corrective action analysis,''
``Emergency flare,'' ``Flare gas header system,'' ``Flare gas recovery
system,'' ``Forced draft process heater,'' ``Natural draft process
heater,'' ``Non-emergency flare,'' ``Primary flare,'' ``Purge gas,''
``Root cause analysis,'' ``Secondary flare,'' and ``Sweep gas''; and
0
c. Revising the definitions of ``Delayed coking unit,'' ``Flare,''
``Flexicoking unit,'' ``Fluid coking unit,'' ``Fuel gas,'' ``Fuel gas
combustion device,'' ``Petroleum refinery,'' ``Process upset gas'' and
``Sulfur recovery plant''
    The revisions and additions read as follows:

Sec.  60.101a  Definitions.

    Terms used in this subpart are defined in the Clean Air Act (CAA),
in Sec.  60.2 and in this section.
    Air preheat means a device used to heat the air supplied to a
process heater generally by use of a heat exchanger to recover the
sensible heat of exhaust gas from the process heater.
    Ancillary equipment means equipment used in conjunction with or
that serve a refinery process unit. Ancillary equipment includes, but
is not limited to, storage tanks, product loading operations,
wastewater treatment systems, steam- or electricity-producing units
(including coke gasification units), pressure relief valves, pumps,
sampling vents and continuous analyzer vents.
    Cascaded flare system means a series of flares connected to one
flare gas header system arranged with increasing pressure set points so
that discharges will be initially directed to the first flare in the
series (i.e., the primary flare). If the discharge pressure exceeds a
set point at which the flow to the primary flare would exceed the
primary flare's capacity, flow will be diverted to the second flare in
the series. Similarly, flow would be diverted to a third (or fourth)
flare if the pressure in the flare gas header system exceeds a
threshold where the flow to the first two (or three) flares would
exceed their capacities.
    Co-fired process heater means a process heater that employs burners
that are designed to be supplied by both gaseous and liquid fuels on a
routine basis. Process heaters that have gas burners with emergency oil
back-up burners are not considered co-fired process heaters.
* * * * *
    Corrective action means the design, operation and maintenance
changes that one takes consistent with good

engineering practice to reduce or eliminate the likelihood of the
recurrence of the primary cause and any other contributing cause(s) of
an event identified by a root cause analysis as having resulted in a
discharge of gases to an affected flare in excess of specified
thresholds.
    Corrective action analysis means a description of all reasonable
interim and long-term measures, if any, that are available, and an
explanation of why the selected corrective action(s) is/are the best
alternative(s), including, but not limited to, considerations of cost
effectiveness, technical feasibility, safety and secondary impacts.
    Delayed coking unit means a refinery process unit in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is produced in a series of closed, batch system
reactors. A delayed coking unit includes, but is not limited to, all of
the coke drums associated with a single fractionator; the fractionator,
including the bottoms receiver and the overhead condenser; the coke
drum cutting water and quench system, including the jet pump and coker
quench water tank; process piping and associated equipment such as
pumps, valves and connectors; and the coke drum blowdown recovery
compressor system.
    Emergency flare means a flare that combusts gas exclusively
released as a result of malfunctions (and not startup, shutdown,
routine operations or any other cause) on four or fewer occasions in a
rolling 365-day period. For purposes of this rule, a flare cannot be
categorized as an emergency flare unless it maintains a water seal.
    Flare means a combustion device that uses an uncontrolled volume of
air to burn gases. The flare includes the foundation, flare tip,
structural support, burner, igniter, flare controls, including air
injection or steam injection systems, flame arrestors and the flare gas
header system. In the case of an interconnected flare gas header
system, the flare includes each individual flare serviced by the
interconnected flare gas header system and the interconnected flare gas
header system.
    Flare gas header system means all piping and knockout pots,
including those in a subheader system, used to collect and transport
gas to a flare either from a process unit or a pressure relief valve
from the fuel gas system, regardless of whether or not a flare gas
recovery system draws gas from the flare gas header system. The flare
gas header system includes piping inside the battery limit of a process
unit if the purpose of the piping is to transport gas to a flare or
knockout pot that is part of the flare.
    Flare gas recovery system means a system of one or more
compressors, piping and the associated water seal, rupture disk or
similar device used to divert gas from the flare and direct the gas to
the fuel gas system or to a fuel gas combustion device.
    Flexicoking unit means a refinery process unit in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is continuously produced and then gasified to produce a
synthetic fuel gas.
* * * * *
    Fluid coking unit means a refinery process unit in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is continuously produced in a fluidized bed system. The
fluid coking unit includes the coking reactor, the coking burner, and
equipment for controlling air pollutant emissions and for heat recovery
on the fluid coking burner exhaust vent.
    Forced draft process heater means a process heater in which the
combustion air is supplied under positive pressure produced by a fan at
any location in the inlet air line prior to the point where the
combustion air enters the process heater or air preheat. For the
purposes of this subpart, a process heater that uses fans at both the
inlet air side and the exhaust air side (i.e., balanced draft system)
is considered to be a forced draft process heater.
    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, coke calciners (used to make
premium grade coke) and fluid coking burners, but does include gases
from flexicoking unit gasifiers and other gasifiers. Fuel gas does not
include vapors that are collected and combusted in a thermal oxidizer
or flare installed to control emissions from wastewater treatment units
other than those processing sour water, marine tank vessel loading
operations or asphalt processing units (i.e., asphalt blowing stills).
    Fuel gas combustion device means any equipment, such as process
heaters and boilers, used to combust fuel gas. For the purposes of this
subpart, fuel gas combustion device does not include flares or
facilities in which gases are combusted to produce sulfur or sulfuric
acid.
* * * * *
    Natural draft process heater means any process heater in which the
combustion air is supplied under ambient or negative pressure without
the use of an inlet air (forced draft) fan. For the purposes of this
subpart, a natural draft process heater is any process heater that is
not a forced draft process heater, including induced draft systems.
    Non-emergency flare means any flare that is not an emergency flare
as defined in this subpart.
* * * * *
    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. A facility that produces only oil
shale or tar sands-derived crude oil for further processing at a
petroleum refinery using only solvent extraction and/or distillation to
recover diluent is not a petroleum refinery.
    Primary flare means the first flare in a cascaded flare system.
* * * * *
    Process upset gas means any gas generated by a petroleum refinery
process unit or by ancillary equipment as a result of startup,
shutdown, upset or malfunction.
    Purge gas means gas introduced between a flare's water seal and a
flare's tip to prevent oxygen infiltration (backflow) into the flare
tip. For flares with no water seals, the function of purge gas is
performed by sweep gas (i.e., flares without water seals do not use
purge gas).
* * * * *
    Root cause analysis means an assessment conducted through a process
of investigation to determine the primary cause, and any other
contributing cause(s), of a discharge of gases in excess of specified
thresholds.
    Secondary flare means a flare in a cascaded flare system that
provides additional flare capacity and pressure relief to a flare gas
system when the flare gas flow exceeds the capacity of the primary
flare. For purposes of this subpart, a secondary flare is characterized
by infrequent use and must maintain a water seal.
* * * * *
    Sulfur recovery plant means all process units which recover sulfur
from H2S and/or SO2 from a common source of sour
gas produced at a petroleum

refinery. The sulfur recovery plant also includes sulfur pits used to
store the recovered sulfur product, but it does not include secondary
sulfur storage vessels or loading facilities downstream of the sulfur
pits. For example, a Claus sulfur recovery plant includes: Reactor
furnace and waste heat boiler, catalytic reactors, sulfur pits and, if
present, oxidation or reduction control systems or incinerator, thermal
oxidizer or similar combustion device. Multiple sulfur recovery units
are a single affected facility only when the units share the same
source of sour gas. Sulfur recovery plants that receive source gas from
completely segregated sour gas treatment systems are separate affected
facilities.
    Sweep gas means the gas introduced in a flare gas header system to
maintain a constant flow of gas to prevent oxygen buildup in the flare
header. For flares with no water seals, sweep gas also performs the
function of preventing oxygen infiltration (backflow) into the flare
tip.

0
11. In Sec.  60.102a, lift the stay on paragraph (g) published December
22, 2008 (73 FR 78552).

0
12. Section 60.102a is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraph (f)(1)(ii);
0
c. Revising paragraph (g);
0
d. Removing and reserving paragraph (h); and
0
e. Revising paragraph (i).
    The revisions read as follows:

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 (i) 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.
* * * * *
    (f) * * *
    (1) * * *
    (ii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere in excess of
300 ppmv of reduced sulfur compounds and 10 ppmv of H2S,
each calculated as ppmv SO2 (dry basis) at 0-percent excess
air; or
* * * * *
    (g) Each owner or operator of an affected fuel gas combustion
device shall comply with the emissions limits in paragraphs (g)(1) and
(2) of this section.
    (1) Except as provided in (g)(1)(iii) of this section, for each
fuel gas combustion device, the owner or operator shall comply with
either the emission limit in paragraph (g)(1)(i) of this section or the
fuel gas concentration limit in paragraph (g)(1)(ii) of this section.
    (i) The owner or operator shall not discharge or cause the
discharge of any gases into the atmosphere that contain SO2
in excess of 20 ppmv (dry basis, corrected to 0-percent excess air)
determined hourly on a 3-hour rolling average basis and SO2
in excess of 8 ppmv (dry basis, corrected to 0-percent excess air),
determined daily on a 365 successive calendar day rolling average
basis; or
    (ii) The owner or operator shall not burn in any fuel gas
combustion device any fuel gas that contains H2S in excess
of 162 ppmv determined hourly on a 3-hour rolling average basis and
H2S in excess of 60 ppmv determined daily on a 365
successive calendar day rolling average basis.
    (iii) The combustion in a portable generator of fuel gas released
as a result of tank degassing and/or cleaning is exempt from the
emissions limits in paragraphs (g)(1)(i) and (ii) of this section.
    (2) For each process heater with a rated capacity of greater than
40 million British thermal units per hour (MMBtu/hr) on a higher
heating value basis, the owner or operator shall not discharge to the
atmosphere any emissions of NOX in excess of the applicable
limits in paragraphs (g)(2)(i) through (iv) of this section.
    (i) For each natural draft process heater, comply with the limit in
either paragraph (g)(2)(i)(A) or (B) of this section. The owner or
operator may comply with either limit at any time, provided that the
appropriate parameters for each alternative are monitored as specified
in Sec.  60.107a; if fuel gas composition is not monitored as specified
in Sec.  60.107a(d), the owner or operator must comply with the
concentration limits in paragraph (g)(2)(i)(A) of this section.
    (A) 40 ppmv (dry basis, corrected to 0-percent excess air)
determined daily on a 30-day rolling average basis; or
    (B) 0.040 pounds per million British thermal units (lb/MMBtu)
higher heating value basis determined daily on a 30-day rolling average
basis.
    (ii) For each forced draft process heater, comply with the limit in
either paragraph (g)(2)(ii)(A) or (B) of this section. The owner or
operator may comply with either limit at any time, provided that the
appropriate parameters for each alternative are monitored as specified
in Sec.  60.107a; if fuel gas composition is not monitored as specified
in Sec.  60.107a(d), the owner or operator must comply with the
concentration limits in paragraph (g)(2)(ii)(A) of this section.
    (A) 60 ppmv (dry basis, corrected to 0-percent excess air)
determined daily on a 30-day rolling average basis; or
    (B) 0.060 lb/MMBtu higher heating value basis determined daily on a
30-day rolling average basis.
    (iii) For each co-fired natural draft process heater, comply with
the limit in either paragraph (g)(2)(iii)(A) or (B) of this section.
The owner or operator must choose one of the emissions limits with
which to comply at all times:
    (A) 150 ppmv (dry basis, corrected to 0-percent excess air)
determined daily on a 30 successive operating day rolling average
basis; or
    (B) The daily average emissions limit calculated using Equation 3
of this section:
[GRAPHIC] [TIFF OMITTED] TR12SE12.001

Where:

ERNOx = Daily allowable average emission rate of
NOX, lb/MMBtu (higher heating value basis);
Qgas = Daily average volumetric flow rate of fuel gas,
standard cubic feet per day (scf/day);
Qoil = Daily average volumetric flow rate of fuel oil,
scf/day;
HHVgas = Daily average higher heating value of gas fired
to the process heater, MMBtu/scf; and
HHVoil = Daily average higher heating value of fuel oil
fired to the process heater, MMBtu/scf.

    (iv) For each co-fired forced draft process heater, comply with the
limit in either paragraph (g)(2)(iv)(A) or (B) of this section. The
owner or operator must choose one of the emissions limits with which to
comply at all times:
    (A) 150 ppmv (dry basis, corrected to 0-percent excess air)
determined daily on a 30 successive operating day rolling average
basis; or
    (B) The daily average emissions limit calculated using Equation 4
of this section:
[GRAPHIC] [TIFF OMITTED] TR12SE12.002

Where:

ERNOx = Daily allowable average emission rate of
NOX, lb/MMBtu (higher heating value basis);
Qgas = Daily average volumetric flow rate of fuel gas,
scf/day;
Qoil = Daily average volumetric flow rate of fuel oil,
scf/day;
HHVgas = Daily average higher heating value of gas fired
to the process heater, MMBtu/scf; and
HHVoil = Daily average higher heating value of fuel oil
fired to the process heater, MMBtu/scf.

    (h) [Reserved]
    (i) For a process heater that meets any of the criteria of
paragraphs (i)(1)(i) through (iv) of this section, an owner or operator
may request approval from the Administrator for a NOX
emissions limit which shall apply specifically to that affected
facility. The request shall include information as described in
paragraph (i)(2) of this section. The request shall be submitted and
followed as described in paragraph (i)(3) of this section.
    (1) A process heater that meets one of the criteria in paragraphs
(i)(1)(i) through (iv) of this section may apply for a site-specific
NOX emissions limit:
    (i) A modified or reconstructed process heater that lacks
sufficient space to accommodate installation and proper operation of
combustion modification-based technology (e.g., ultra-low
NOX burners); or
    (ii) A modified or reconstructed process heater that has downwardly
firing induced draft burners; or
    (iii) A co-fired process heater; or
    (iv) A process heater operating at reduced firing conditions for an
extended period of time (i.e., operating in turndown mode). The site-
specific NOX emissions limit will only apply for those
operating conditions.
    (2) The request shall include sufficient and appropriate data, as
determined by the Administrator, to allow the Administrator to confirm
that the process heater is unable to comply with the applicable
NOX emissions limit in paragraph (g)(2) of this section. At
a minimum, the request shall contain the information described in
paragraphs (i)(2)(i) through (iv) of this section.
    (i) The design and dimensions of the process heater, evaluation of
available combustion modification-based technology, description of fuel
gas and, if applicable, fuel oil characteristics, information regarding
the combustion conditions (temperature, oxygen content, firing rates)
and other information needed to demonstrate that the process heater
meets one of the four classes of process heaters listed in paragraph
(i)(1) of this section.
    (ii) An explanation of how the data in paragraph (i)(2)(i)
demonstrate that ultra-low NOX burners, flue gas
recirculation, control of excess air or other combustion modification-
based technology (including combinations of these combustion
modification-based technologies) cannot be used to meet the applicable
emissions limit in paragraph (g)(2) of this section.
    (iii) Results of a performance test conducted under representative
conditions using the applicable methods specified in Sec.  60.104a(i)
to demonstrate the performance of the technology the owner or operator
will use to minimize NOX emissions.
    (iv) The means by which the owner or operator will document
continuous compliance with the site-specific emissions limit.
    (3) The request shall be submitted and followed as described in
paragraphs (i)(3)(i) through (iii) of this section.
    (i) The owner or operator of a process heater that meets one of the
criteria in paragraphs (i)(1)(i) through (iv) of this section may
request approval from the Administrator within 180 days after initial
startup of the process heater for a NOX emissions limit
which shall apply specifically to that affected facility.
    (ii) The request must be submitted to the Administrator for
approval. The owner or operator must comply with the request as
submitted until it is approved.
    (iii) The request shall also be submitted to the following address:
U.S. Environmental Protection Agency, Office of Air Quality Planning
and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom
(E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive,
Research Triangle Park, NC 27711. Electronic copies in lieu of hard
copies may also be submitted to<EMAIL_ADDRESS>    (4) The approval process for a request for a facility-specific
NOX emissions limit is described in paragraphs (i)(4)(i)
through (iii) of this section.
    (i) Approval by the Administrator of a facility-specific
NOX emissions limit request will be based on the
completeness, accuracy and reasonableness of the request. Factors that
the EPA will consider in reviewing the request for approval include,
but are not limited to, the following:
    (A) A demonstration that the process heater meets one of the four
classes of process heaters outlined in paragraphs (i)(1) of this
section;
    (B) A description of the low-NOX burner designs and
other combustion modifications considered for reducing NOX
emissions;
    (C) The combustion modification option selected; and
    (D) The operating conditions (firing rate, heater box temperature
and excess oxygen concentration) at which the NOX emission
level was established.
    (ii) If the request is approved by the Administrator, a facility-
specific NOX emissions limit will be established at the
NOX emission level demonstrated in the approved request.
    (iii) If the Administrator finds any deficiencies in the request,
the request must be revised to address the deficiencies and be re-
submitted for approval.

0
13. Section 60.103a is revised to read as follows:

Sec.  60.103a  Design, equipment, work practice or operational
standards.

    (a) Except as provided in paragraph (g) of this section, each owner
or operator that operates a flare that is subject to this subpart shall
develop and implement a written flare management plan no later than the
date specified in paragraph (b) of this section. The flare management
plan must include the information described in paragraphs (a)(1)
through (7) of this section.

    (1) A listing of all refinery process units, ancillary equipment,
and fuel gas systems connected to the flare for each affected flare.
    (2) An assessment of whether discharges to affected flares from
these process units, ancillary equipment and fuel gas systems can be
minimized. The flare minimization assessment must (at a minimum)
consider the items in paragraphs (a)(2)(i) through (iv) of this
section. The assessment must provide clear rationale in terms of costs
(capital and annual operating), natural gas offset credits (if
applicable), technical feasibility, secondary environmental impacts and
safety considerations for the selected minimization alternative(s) or a
statement, with justifications, that flow reduction could not be
achieved. Based upon the assessment, each owner or operator of an
affected flare shall identify the minimization alternatives that it has
implemented by the due date of the flare management plan and shall
include a schedule for the prompt implementation of any selected
measures that cannot reasonably be completed as of that date.
    (i) Elimination of process gas discharge to the flare through
process operating changes or gas recovery at the source.
    (ii) Reduction of the volume of process gas to the flare through
process operating changes.
    (iii) Installation of a flare gas recovery system or, for
facilities that are fuel gas rich, a flare gas recovery system and a
co-generation unit or combined heat and power unit.
    (iv) Minimization of sweep gas flow rates and, for flares with
water seals, purge gas flow rates.
    (3) A description of each affected flare containing the information
in paragraphs (a)(3)(i) through (vii) of this section.
    (i) A general description of the flare, including the information
in paragraphs (a)(3)(i)(A) through (G) of this section.
    (A) Whether it is a ground flare or elevated (including height).
    (B) The type of assist system (e.g., air, steam, pressure, non-
assisted).
    (C) Whether it is simple or complex flare tip (e.g., staged,
sequential).
    (D) Whether the flare is part of a cascaded flare system (and if
so, whether the flare is primary or secondary).
    (E) Whether the flare serves as a backup to another flare.
    (F) Whether the flare is an emergency flare or a non-emergency
flare.
    (G) Whether the flare is equipped with a flare gas recovery system.
    (ii) Description and simple process flow diagram showing the
interconnection of the following components of the flare: flare tip
(date installed, manufacturer, nominal and effective tip diameter, tip
drawing); knockout or surge drum(s) or pot(s) (including dimensions and
design capacities); flare header(s) and subheader(s); assist system;
and ignition system.
    (iii) Flare design parameters, including the maximum vent gas flow
rate; minimum sweep gas flow rate; minimum purge gas flow rate (if
any); maximum supplemental gas flow rate; maximum pilot gas flow rate;
and, if the flare is steam-assisted, minimum total steam rate.
    (iv) Description and simple process flow diagram showing all gas
lines (including flare, purge (if applicable), sweep, supplemental and
pilot gas) that are associated with the flare. For purge, sweep,
supplemental and pilot gas, identify the type of gas used. Designate
which lines are exempt from sulfur, H2S or flow monitoring
and why (e.g., natural gas, inherently low sulfur, pilot gas).
Designate which lines are monitored and identify on the process flow
diagram the location and type of each monitor.
    (v) For each flow rate, H2S, sulfur content, pressure or
water seal monitor identified in paragraph (a)(3)(iv) of this section,
provide a detailed description of the manufacturer's specifications,
including, but not limited to, make, model, type, range, precision,
accuracy, calibration, maintenance and quality assurance procedures.
    (vi) For emergency flares, secondary flares and flares equipped
with a flare gas recovery system designed, sized and operated to
capture all flows except those resulting from startup, shutdown or
malfunction:
    (A) Description of the water seal, including the operating range
for the liquid level.
    (B) Designation of the monitoring option elected (flow and sulfur
monitoring or pressure and water seal liquid level monitoring).
    (vii) For flares equipped with a flare gas recovery system:
    (A) A description of the flare gas recovery system, including
number of compressors and capacity of each compressor.
    (B) A description of the monitoring parameters used to quantify the
amount of flare gas recovered.
    (C) For systems with staged compressors, the maximum time period
required to begin gas recovery with the secondary compressor(s), the
monitoring parameters and procedures used to minimize the duration of
releases during compressor staging and a justification for why the
maximum time period cannot be further reduced.
    (4) An evaluation of the baseline flow to the flare. The baseline
flow to the flare must be determined after implementing the
minimization assessment in paragraph (a)(2) of this section. Baseline
flows do not include pilot gas flow or purge gas flow (i.e., gas
introduced after the flare's water seal) provided these gas flows
remain reasonably constant (i.e., separate flow monitors for these
streams are not required). Separate baseline flow rates may be
established for different operating conditions provided that the
management plan includes:
    (i) A primary baseline flow rate that will be used as the default
baseline for all conditions except those specifically delineated in the
plan;
    (ii) A description of each special condition for which an alternate
baseline is established, including the rationale for each alternate
baseline, the daily flow for each alternate baseline and the expected
duration of the special conditions for each alternate baseline; and
    (iii) Procedures to minimize discharges to the affected flare
during each special condition described in paragraph (a)(4)(ii) of this
section, unless procedures are already developed for these cases under
paragraph (a)(5) through (7) of this section, as applicable.
    (5) Procedures to minimize or eliminate discharges to the flare
during the planned startup and shutdown of the refinery process units
and ancillary equipment that are connected to the affected flare,
together with a schedule for the prompt implementation of any
procedures that cannot reasonably be implemented as of the date of the
submission of the flare management plan.
    (6) Procedures to reduce flaring in cases of fuel gas imbalance
(i.e., excess fuel gas for the refinery's energy needs), together with
a schedule for the prompt implementation of any procedures that cannot
reasonably be implemented as of the date of the submission of the flare
management plan.
    (7) For flares equipped with flare gas recovery systems, procedures
to minimize the frequency and duration of outages of the flare gas
recovery system and procedures to minimize the volume of gas flared
during such outages, together with a schedule for the prompt
implementation of any procedures that cannot reasonably be implemented
as of the date of the submission of the flare management plan.
    (b) Except as provided in paragraph (g) of this section, each owner
or

operator required to develop and implement a written flare management
plan as described in paragraph (a) of this section must submit the plan
to the Administrator as described in paragraphs (b)(1) through (3) of
this section.
    (1) The owner or operator of a newly constructed or reconstructed
flare must develop and implement the flare management plan by no later
than the date that the flare becomes an affected facility subject to
this subpart, except for the selected minimization alternatives in
paragraph (a)(2) and/or the procedures in paragraphs (a)(5) though
(a)(7) of this section that cannot reasonably be implemented by that
date, which the owner or operator must implement in accordance with the
schedule in the flare management plan. The owner or operator of a
modified flare must develop and implement the flare management plan by
no later than November 11, 2015 or upon startup of the modified flare,
whichever is later.
    (2) The owner or operator must comply with the plan as submitted by
the date specified in paragraph (b)(1) of this section. The plan should
be updated periodically to account for changes in the operation of the
flare, such as new connections to the flare or the installation of a
flare gas recovery system, but the plan need be re-submitted to the
Administrator only if the owner or operator adds an alternative
baseline flow rate, revises an existing baseline as described in
paragraph (a)(4) of this section, installs a flare gas recovery system
or is required to change flare designations and monitoring methods as
described in Sec.  60.107a(g). The owner or operator must comply with
the updated plan as submitted.
    (3) All versions of the plan submitted to the Administrator shall
also be submitted to the following address: U.S. Environmental
Protection Agency, Office of Air Quality Planning and Standards, Sector
Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention:
Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park,
NC 27711. Electronic copies in lieu of hard copies may also be
submitted to<EMAIL_ADDRESS>    (c) Except as provided in paragraphs (f) and (g) of this section,
each owner or operator that operates a fuel gas combustion device,
flare or sulfur recovery plant subject to this subpart shall conduct a
root cause analysis and a corrective action analysis for each of the
conditions specified in paragraphs (c)(1) through (3) of this section.
    (1) For a flare:
    (i) Any time the SO2 emissions exceed 227 kilograms (kg)
(500 lb) in any 24-hour period; or
    (ii) Any discharge to the flare in excess of 14,160 standard cubic
meters (m\3\) (500,000 standard cubic feet (scf)) above the baseline,
determined in paragraph (a)(4) of this section, in any 24-hour period;
or
    (iii) If the monitoring alternative in Sec.  60.107a(g) is elected,
any period when the flare gas line pressure exceeds the water seal
liquid depth, except for periods attributable to compressor staging
that do not exceed the staging time specified in paragraph
(a)(3)(vii)(C) of this section.
    (2) For a fuel gas combustion device, each exceedance of an
applicable short-term emissions limit in Sec.  60.102a(g)(1) if the
SO2 discharge to the atmosphere is 227 kg (500 lb) greater
than the amount that would have been emitted if the emissions limits
had been met during one or more consecutive periods of excess emissions
or any 24-hour period, whichever is shorter.
    (3) For a sulfur recovery plant, each time the SO2
emissions are more than 227 kg (500 lb) greater than the amount that
would have been emitted if the SO2 or reduced sulfur
concentration was equal to the applicable emissions limit in Sec.
60.102a(f)(1) or (2) during one or more consecutive periods of excess
emissions or any 24-hour period, whichever is shorter.
    (d) Except as provided in paragraphs (f) and (g) of this section, a
root cause analysis and corrective action analysis must be completed as
soon as possible, but no later than 45 days after a discharge meeting
one of the conditions specified in paragraphs (c)(1) through (3) of
this section. Special circumstances affecting the number of root cause
analyses and/or corrective action analyses are provided in paragraphs
(d)(1) through (5) of this section.
    (1) If a single continuous discharge meets any of the conditions
specified in paragraphs (c)(1) through (3) of this section for 2 or
more consecutive 24-hour periods, a single root cause analysis and
corrective action analysis may be conducted.
    (2) If a single discharge from a flare triggers a root cause
analysis based on more than one of the conditions specified in
paragraphs (c)(1)(i) through (iii) of this section, a single root cause
analysis and corrective action analysis may be conducted.
    (3) If the discharge from a flare is the result of a planned
startup or shutdown of a refinery process unit or ancillary equipment
connected to the affected flare and the procedures in paragraph (a)(5)
of this section were followed, a root cause analysis and corrective
action analysis is not required; however, the discharge must be
recorded as described in Sec.  60.108a(c)(6) and reported as described
in Sec.  60.108a(d)(5).
    (4) If both the primary and secondary flare in a cascaded flare
system meet any of the conditions specified in paragraphs (c)(1)(i)
through (iii) of this section in the same 24-hour period, a single root
cause analysis and corrective action analysis may be conducted.
    (5) Except as provided in paragraph (d)(4) of this section, if
discharges occur that meet any of the conditions specified in
paragraphs (c)(1) through (3) of this section for more than one
affected facility in the same 24-hour period, initial root cause
analyses shall be conducted for each affected facility. If the initial
root cause analyses indicate that the discharges have the same root
cause(s), the initial root cause analyses can be recorded as a single
root cause analysis and a single corrective action analysis may be
conducted.
    (e) Except as provided in paragraphs (f) and (g) of this section,
each owner or operator of a fuel gas combustion device, flare or sulfur
recovery plant subject to this subpart shall implement the corrective
action(s) identified in the corrective action analysis conducted
pursuant to paragraph (d) of this section in accordance with the
applicable requirements in paragraphs (e)(1) through (3) of this
section.
    (1) All corrective action(s) must be implemented within 45 days of
the discharge for which the root cause and corrective action analyses
were required or as soon thereafter as practicable. If an owner or
operator concludes that corrective action should not be conducted, the
owner or operator shall record and explain the basis for that
conclusion no later than 45 days following the discharge as specified
in Sec.  60.108a(c)(6)(ix).
    (2) For corrective actions that cannot be fully implemented within
45 days following the discharge for which the root cause and corrective
action analyses were required, the owner or operator shall develop an
implementation schedule to complete the corrective action(s) as soon as
practicable.
    (3) No later than 45 days following the discharge for which a root
cause and corrective action analyses were required, the owner or
operator shall record the corrective action(s) completed to date, and,
for action(s) not already completed, a schedule for implementation,
including proposed commencement and completion dates as specified in
Sec.  60.108a(c)(6)(x).

    (f) Modified flares shall comply with the requirements of
paragraphs (c) through (e) of this section by November 11, 2015 or at
startup of the modified flare, whichever is later. Modified flares that
were not affected facilities subject to subpart J of this part prior to
becoming affected facilities under Sec.  60.100a shall comply with the
requirements of paragraph (h) of this section and the requirements of
Sec.  60.107a(a)(2) by November 11, 2015 or at startup of the modified
flare, whichever is later. Modified flares that were affected
facilities subject to subpart J of this part prior to becoming affected
facilities under Sec.  60.100a shall comply with the requirements of
paragraph (h) of this section and the requirements of Sec.
60.107a(a)(2) by November 13, 2012 or at startup of the modified flare,
whichever is later, except that modified flares that have accepted
applicability of subpart J under a federal consent decree shall comply
with the subpart J requirements as specified in the consent decree, but
shall comply with the requirements of paragraph (h) of this section and
the requirements of Sec.  60.107a(a)(2) by no later than November 11,
2015.
    (g) An affected flare subject to this subpart located in the Bay
Area Air Quality Management District (BAAQMD) may elect to comply with
both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 as
an alternative to complying with the requirements of paragraphs (a)
through (e) of this section. An affected flare subject to this subpart
located in the South Coast Air Quality Management District (SCAQMD) may
elect to comply with SCAQMD Rule 1118 as an alternative to complying
with the requirements of paragraphs (a) through (e) of this section.
The owner or operator of an affected flare must notify the
Administrator that the flare is in compliance with BAAQMD Regulation
12, Rule 11 and BAAQMD Regulation 12, Rule 12 or SCAQMD Rule 1118. The
owner or operator of an affected flare shall also submit the existing
flare management plan to the following address: U.S. Environmental
Protection Agency, Office of Air Quality Planning and Standards, Sector
Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention:
Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park,
NC 27711. Electronic copies in lieu of hard copies may also be
submitted to<EMAIL_ADDRESS>    (h) Each owner or operator shall not burn in any affected flare any
fuel gas that contains H2S in excess of 162 ppmv determined
hourly on a 3-hour rolling average basis. 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 this limit.
    (i) Each owner or operator of a delayed coking unit shall
depressure each coke drum to 5 lb per square inch gauge (psig) or less
prior to discharging the coke drum steam exhaust to the atmosphere.
Until the coke drum pressure reaches 5 psig, the coke drum steam
exhaust must be managed in an enclosed blowdown system and the
uncondensed vapor must either be recovered (e.g., sent to the delayed
coking unit fractionators) or vented to the fuel gas system, a fuel gas
combustion device or a flare.
    (j) Alternative means of emission limitation. (1) Each owner or
operator subject to the provisions of this section may apply to the
Administrator for a determination of equivalence for any means of
emission limitation that achieves a reduction in emissions of a
specified pollutant at least equivalent to the reduction in emissions
of that pollutant achieved by the controls required in this section.
    (2) Determination of equivalence to the design, equipment, work
practice or operational requirements of this section will be evaluated
by the following guidelines:
    (i) Each owner or operator applying for a determination of
equivalence shall be responsible for collecting and verifying test data
to demonstrate the equivalence of the alternative means of emission
limitation.
    (ii) For each affected facility for which a determination of
equivalence is requested, the emission reduction achieved by the
design, equipment, work practice or operational requirements shall be
demonstrated.
    (iii) For each affected facility for which a determination of
equivalence is requested, the emission reduction achieved by the
alternative means of emission limitation shall be demonstrated.
    (iv) Each owner or operator applying for a determination of
equivalence to a work practice standard shall commit in writing to work
practice(s) that provide for emission reductions equal to or greater
than the emission reductions achieved by the required work practice.
    (v) The Administrator will compare the demonstrated emission
reduction for the alternative means of emission limitation to the
demonstrated emission reduction for the design, equipment, work
practice or operational requirements and, if applicable, will consider
the commitment in paragraph (j)(2)(iv) of this section.
    (vi) The Administrator may condition the approval of the
alternative means of emission limitation on requirements that may be
necessary to ensure operation and maintenance to achieve the same
emissions reduction as the design, equipment, work practice or
operational requirements.
    (3) An owner or operator may offer a unique approach to demonstrate
the equivalence of any equivalent means of emission limitation.
    (4) Approval of the application for equivalence to the design,
equipment, work practice or operational requirements of this section
will be evaluated by the following guidelines:
    (i) After a request for determination of equivalence is received,
the Administrator will publish a notice in the Federal Register and
provide the opportunity for public hearing if the Administrator judges
that the request may be approved.
    (ii) After notice and opportunity for public hearing, the
Administrator will determine the equivalence of a means of emission
limitation and will publish the determination in the Federal Register.
    (iii) Any equivalent means of emission limitations approved under
this section shall constitute a required work practice, equipment,
design or operational standard within the meaning of section 111(h)(1)
of the CAA.
    (5) Manufacturers of equipment used to control emissions may apply
to the Administrator for determination of equivalence for any
alternative means of emission limitation that achieves a reduction in
emissions achieved by the equipment, design and operational
requirements of this section. The Administrator will make an
equivalence determination according to the provisions of paragraphs
(j)(2) through (4) of this section.

0
14. Section 60.104a is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraphs (d)(4)(ii), (d)(4)(iii), (d)(4)(v) and (d)(8);
0
c. Revising paragraph (f)(3);
0
d. Revising paragraph (h)(5)(iv);
0
e. Revising paragraph (i) introductory text;
0
f. Adding paragraphs (i)(6) through (i)(8);
0
g. Revising paragraph (j) introductory text and paragraph (j)(4)
introductory text; and
0
h. Revising paragraph (j)(4)(iv) to read as follows:

Sec.  60.104a  Performance tests.

    (a) The owner or operator shall conduct a performance test for each
FCCU, FCU, sulfur recovery plant, flare and fuel gas combustion device
to

demonstrate initial compliance with each applicable emissions limit in
Sec.  60.102a according to the requirements of Sec.  60.8. The
notification requirements of Sec.  60.8(d) apply to the initial
performance test and to subsequent performance tests required by
paragraph (b) of this section (or as required by the Administrator),
but does not apply to performance tests conducted for the purpose of
obtaining supplemental data because of continuous monitoring system
breakdowns, repairs, calibration checks and zero and span adjustments.
* * * * *
    (d) * * *
    (4) * * *
    (ii) The emissions rate of PM (EPM) is computed for each
run using Equation 5 of this section:
[GRAPHIC] [TIFF OMITTED] TR12SE12.003

Where:

E = Emission rate of PM, g/kg (lb/1,000 lb) 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) [lb
per hour (lb/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 6 of this section:
[GRAPHIC] [TIFF OMITTED] TR12SE12.004

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 (CO2) 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-%)].
* * * * *
    (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
required in Sec.  60.105a(b)(2), if applicable, using Equation 7 of
this section:
[GRAPHIC] [TIFF OMITTED] TR12SE12.005

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(h)(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).
* * * * *
    (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 8 of this section:

[GRAPHIC] [TIFF OMITTED] TR12SE12.006

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.
* * * * *
    (f) * * *
    (3) Compute the site-specific limit using Equation 9 of this
section:
[GRAPHIC] [TIFF OMITTED] TR12SE12.007

Where:

Opacity limit = Maximum permissible 3-hour average opacity, percent,
or 10 percent, whichever is greater;
Opacityst = Hourly average opacity measured during the
source test, percent; and
PMEmRst = PM emission rate measured during the source
test, lb/1,000 lb coke burn.
* * * * *
    (h) * * *
    (5) * * *
    (iv) The owner or operator shall use Equation 8 of this section to
adjust pollutant concentrations to 0-percent O2 or 0-
percent excess air.
    (i) The owner or operator shall determine compliance with the
SO2 and NOX emissions limits in Sec.  60.102a(g)
for a fuel gas combustion device according to the following test
methods and procedures:
* * * * *
    (6) For process heaters with a rated heat capacity between 40 and