facilities MACT standards or 40 CFR 63.1272 for sources subject to the
natural gas transmission and storage facilities MACT standards and to
prevent future malfunctions. For example, the source must prove by a
preponderance of evidence that ``[r]epairs were made as expeditiously
as possible when the applicable emission limitations were being
exceeded * * *'' and that ``[a]ll possible steps were taken to minimize
the impact of the excess emissions on ambient air quality, the
environment and human health * * *.'' In any judicial or administrative
proceeding, the Administrator may challenge the assertion of the
affirmative defense and, if the respondent has not met its burden of
proving all of the requirements in the affirmative defense, appropriate
penalties may be assessed in accordance with section 113 of the CAA
(see also 40 CFR 22.77).
4. Applicability and Compliance
a. Calculating Potential To Emit (PTE)
    We are proposing to amend section 40 CFR 63.760(a)(1)(iii) to
clarify that sources must use a glycol circulation rate consistent with
the definition of PTE in 40 CFR 63.2 in calculating emissions for
purposes of determining PTE. Affected parties have misinterpreted the
current language concerning measured values or annual average to apply
to a broader range of parameters than was intended. Those qualifiers
were meant to apply to gas characteristics that are measured, such as
inlet gas composition, pressure and temperature rather than process
equipment settings. That means that the circulation rate used in PTE
determinations shall be the maximum under its physical and operational
design.
    In addition to the proposed changes described above, we are seeking
comment on several PTE related issues. According to the data available
to the Administrator, when 40 CFR part 63, subpart HH was promulgated,
the level of HAP emissions was predominantly driven by natural gas
throughput (i.e., HAP emissions went up or down in concert with natural
gas throughput). Since promulgation, we have learned that there is not
always a direct correlation between HAP emissions and natural gas
throughput. We have received information suggesting that, in some
cases, HAP emissions can increase despite decreasing natural gas
throughput due to changes in gas composition. We are asking for comment
regarding the likelihood of this occurrence and data demonstrating the
circumstances where it occurs. In light of the potential issue, we are
asking for comment regarding the addition of provisions in the NESHAP
to require area sources to recalculate their PTE to confirm that they
are indeed area sources and whether that calculation should be
performed on an annual or biannual basis to verify that changes in gas
composition have not increased their emissions.
b. Definition of Facility and Applicability Criteria
    Subpart HH of 40 CFR part 63 (section 63.760(a)(2)) currently
defines facilities as those where hydrocarbon liquids are processed,
upgraded or stored prior to the point of custody transfer or where
natural gas is processed, upgraded or stored prior to entering the
Natural Gas Transmission and Storage source category. We are proposing
to remove the references to ``point of custody transfer'' and
``transmission and storage source categories'' from the definition
because the operations performed at a site sufficiently define a
facility and the scope of the subpart is specified already under 40 CFR
63.760. In addition, we are removing the custody transfer reference
from the applicability criteria in 40 CFR 63.760(a)(2). Since
hydrocarbon liquids can pass through several custody transfer points
between the well and the final destination, the custody transfer
criteria is not clear enough. We are, therefore, proposing to replace
the reference to ``point of custody transfer'' with a more specific
description of the point up to which the subpart applies (i.e., the
point where hydrocarbon liquids enter either the organic liquids
distribution or petroleum refineries source categories) and exclude
custody transfer from that criteria. We believe this change eliminates
ambiguity and is consistent with the oil and natural gas production-
specific provisions in the organic liquids distribution MACT.
5. Other Proposed Changes To Clarify These Rules
    The following lists additional changes to the NESHAP we are
proposing. This list includes proposed rule changes that address
editorial corrections and plain language revisions:
     Revise 40 CFR 63.769(b) to clarify that the equipment leak
provisions in 40 CFR part 63, subpart HH do not apply to a source if
that source is required to control equipment leaks under either 40 CFR
part 63, subpart H or 40 CFR part 60, subpart KKK. The current 40 CFR
63.769(b), which states that subpart HH does not apply if a source
meets the

requirements in either of the subparts mentioned above, does not
clearly express our intent that such source must be implementing the
LDAR provisions in the other 40 CFR part 60 or 40 CFR part 63 subparts
to qualify for the exemption.
     Revise 40 CFR 63.760(a)(1) to clarify that an existing
area source that increases its emissions to major source levels has up
to the first substantive compliance date to either reduce its emissions
below major source levels by obtaining a practically enforceable permit
or comply with the applicable major source provisions of 40 CFR part
63, subpart HH. We have revised the second to last sentence in 40 CFR
63.760(a)(1) by removing the parenthetical statement because it simply
reiterates the last sentence of this section and is, therefore,
unnecessary.
     Revise 40 CFR 63.771(d)(1)(ii) and 40 CFR
63.1281(d)(1)(ii) to clarify that the vapor recovery device and ``other
control device'' described in those provisions refer to non-destructive
control devices only.
     Revise the last sentence of 40 CFR 63.764(i) and 40 CFR
63.1274(g) to clarify the requirements following an unsuccessful
attempt to repair a leak.
     Updated the e-mail and physical address for area source
reporting in 40 CFR 63.775(c)(1).

VIII. What are the cost, environmental, energy and economic impacts of
the proposed 40 CFR part 60, subpart OOOO and amendments to subparts HH
and HHH of 40 CFR part 63?

    We are presenting a combined discussion of the estimates of the
impacts for the proposed 40 CFR part 60, subpart OOOO and proposed
amendments to 40 CFR part 63, subpart HH and 40 CFR part 63, subpart
HHH. The cost, environmental and economic impacts presented in this
section are expressed as incremental differences between the impacts of
an oil and natural gas facility complying with the amendments to
subparts HH and HHH and new standards under 40 CFR 60, subpart OOOO and
the baseline, i.e., the standards before these amendments. The impacts
are presented for the year 2015, which will be the year that all
existing oil and natural gas facilities will have to be in compliance,
and also the year that will represent approximately 5 years of
construction of new oil and natural gas facilities subject to the NSPS
emissions limits. The analyses and the documents referenced below can
be found in Docket ID Numbers EPA-HQ-OAR-2007-0877 and EPA-HQ-OAR-2002-
0051.

A. What are the affected sources?

    We expect that by 2015, the year when all existing sources will be
required to come into compliance in the United States, there will be 97
oil and natural gas production facilities and 15 natural gas
transmission and storage facilities with one or more existing glycol
dehydration units. We also estimate that there will be an additional
329 (there are 47 facilities that already have an affected glycol
dehydration unit) existing oil and natural gas production facilities
with existing storage vessels that we expect to be affected by these
final amendments. These facilities operate approximately 134 glycol
dehydration units (115 in production and 19 in transmission and
storage) and 1,970 storage vessels. Approximately 10 oil and natural
gas production and two transmission and storage facilities would have
new glycol dehydration units and 38 production facilities would have
new dehydration units. We expect new production facilities would
operate approximately 12 production glycol dehydration units and 197
storage vessels and new transmission and storage would operate
approximately two glycol dehydration units.
    Based on data provided by the United States Energy Information
Administration, we anticipate that by 2015 there will be approximately
21,800 gas wellhead facilities, 790 reciprocating compressors, 30
centrifugal compressors, 14,000 pneumatic devices and 300 storage
vessels subject to the new NSPS for VOC. Some of these affected
facilities will be built at existing facilities and some at new
greenfield facilities. Based on data limitations, we assume impacts are
equal regardless of location.
    There are about 21 glycol dehydration units with high enough HAP
emissions that we believe cannot meet the emissions limit without using
more than one control technique. In developing the cost impacts, we
assume that they would require multiple controls. The controls for
which we have detailed cost data are condensers and VRU, so we
developed costs for both controls to develop what we consider to be a
reasonable cost estimate for these facilities. This does not imply that
we believe these facilities will specifically use a combination of a
condenser and vapor recovery limit, but we do believe the combination
of these control results is a reasonable estimate of cost.

B. How are the impacts for this proposal evaluated?

    For these proposed Oil and Natural Gas Production and Natural Gas
Transmission and Storage NESHAP amendments and NSPS, the EPA used two
models to evaluate the impacts of the regulation on the industry and
the economy. Typically, in a regulatory analysis, the EPA determines
the regulatory options suitable to meet statutory obligations under the
CAA. Based on the stringency of those options, the EPA then determines
the control technologies and monitoring requirements that sources might
rationally select to comply with the regulation. This analysis is
documented in an engineering analysis. The selected control
technologies and monitoring requirements are then evaluated in a cost
model to determine the total annualized control costs. The annualized
control costs serve as inputs to an Economic Impact Analysis model that
evaluates the impacts of those costs on the industry and society as a
whole.
    The Economic Impact Analysis used the National Energy Modeling
System (NEMS) to estimate the impacts of the proposed NSPS on the
United States energy system. The NEMS is a publically-available model
of the United States energy economy developed and maintained by the
Energy Information Administration of the United States DOE and is used
to produce the Annual Energy Outlook, a reference publication that
provides detailed forecasts of the energy economy from the current year
to 2035. The impacts we estimated included changes in drilling
activity, price and quantity changes in the production and consumption
of crude oil and natural gas and changes in international trade of
crude oil and natural gas. We evaluated whether and to what extent the
increased production costs imposed by the NSPS might alter the mix of
fuels consumed at a national level. Additionally, we combined estimated
emissions co-reductions of methane from the engineering analysis with
NEMS analysis to estimate the net change in CO2e GHG from
energy-related sources.

C. What are the air quality impacts?

    For the oil and natural gas sector NESHAP and NSPS, we estimated
the emission reductions that will occur due to the implementation of
the final emission limits. The EPA estimated emission reductions based
on the control technologies selected by the engineering analysis. These
emission reductions associated with the proposed amendments to 40 CFR
part 63, subpart

HH and 40 CFR part 63, subpart HHH are based on the estimated
population in 2008. Under the proposed limits for glycol dehydration
units and storage vessels, we have estimated that the HAP emissions
reductions will be 1,400 tpy for existing units subject to the proposed
emissions limits.
    For the NSPS, we estimated the emission reductions that will occur
due to the implementation of the final emission limits. The EPA
estimated emission reductions based on the control technologies
selected by the engineering analysis. These emission reductions are
based on the estimated population in 2015. Under the proposed NSPS, we
have estimated that the emissions reductions will be 540,000 tpy VOC
for affected facilities subject to the NSPS.
    The control strategies likely adopted to meet the proposed NESHAP
amendments and the proposed NSPS will result in concurrent control of
HAP, methane and VOC emissions. We estimate that direct reductions in
HAP, methane and VOC for the proposed rules combined total about 38,000
tpy, 3.4 million tpy and 540,000 tpy, respectively.
    Under the final standards, new monitoring requirements are being
added.

D. What are the water quality and solid waste impacts?

    We estimated minimal water quality impacts for the proposed
amendments and proposed NSPS. For the proposed amendments to the
NESHAP, we anticipate that the water impacts associated with the
installation of a condenser system for the glycol dehydration unit
process vent would be minimal. This is because the condensed water
collected with the hydrocarbon condensate can be directed back into the
system for reprocessing with the hydrocarbon condensate or, if
separated, combined with produced water for disposal, usually by
reinjection.
    Similarly, the water impacts associated with installation of a
vapor control system either on a glycol dehydration unit or a storage
vessel would be minimal. This is because the water vapor collected
along with the hydrocarbon vapors in the vapor collection and redirect
system can be directed back into the system for reprocessing with the
hydrocarbon condensate or, if separated, combined with the produced
water for disposal for reinjection.
    There would be no water impacts expected for facilities subject to
the proposed NSPS. Further, we do not anticipate any adverse solid
waste impacts from the implementation of the proposed NESHAP amendments
and the proposed NSPS.

E. What are the secondary impacts?

    Indirect or secondary air quality impacts include impacts that will
result from the increased electricity usage associated with the
operation of control devices, as well as water quality and solid waste
impacts (which were just discussed) that might occur as a result of
these proposed actions. We estimate the proposed amendments to 40 CFR
part 63, subpart HH and 40 CFR part 63, subpart HHH will increase
emissions of criteria pollutants due to the potential use of flares for
the control of storage vessels. We do not estimate an increased energy
demand associated with the installation of condensers, VRU or flares.
The increases in criteria pollutant emissions associated with the use
of flares to control storage vessels subject to existing source
standards are estimated to be 5,500 tpy of CO2, 16 tpy of
carbon monoxide (CO), 3 tpy of NOX, less than 1 tpy of
particulate matter (PM) and 6 tpy total hydrocarbons. For storage
vessels subject to new source standards, increases in secondary air
pollutants are estimated to be less than 900 tpy of CO2, 3
tpy of CO, 1 tpy of NOX, 1 tpy of PM and 1 tpy total
hydrocarbons.
    In addition, we estimate that the secondary impacts associated with
the pneumatic controller requirements to comply with the proposed NSPS
would be about 22 tpy of CO2, 1 tpy of NOX and 3
tpy PM. For gas wellhead affected facilities, we estimate that the use
of flares would result in increases in criteria pollutant emissions of
about 990,000 tons of CO2, 2,800 tpy of CO, 500 tpy of
NOX, 5 tpy of PM and 1,000 tpy total hydrocarbons.

F. What are the energy impacts?

    Energy impacts in this section are those energy requirements
associated with the operation of emission control devices. Potential
impacts on the national energy economy from the rule are discussed in
the economic impacts section. There would be little national energy
demand increase from the operation of any of the control options
analyzed under the proposed NESHAP amendments and proposed NSPS.
    The proposed NESHAP amendments and proposed NSPS encourage the use
of emission controls that recover hydrocarbon products, such as methane
and condensate that can be used on-site as fuel or reprocessed within
the production process for sale. We estimated that the proposed
standards will result in a net cost savings due to the recovery of
salable natural gas and condensate. Thus, the final standards have a
positive impact associated with the recovery of non-renewable energy
resources.

G. What are the cost impacts?

    The estimated total capital cost to comply with the proposed
amendments to 40 CFR part 63, subpart HH for major sources in the Oil
and Natural Gas Production source category is approximately $51.5
million. The total capital cost for the proposed amendments to 40 CFR
part 63, subpart HHH for major sources in the Natural Gas Transmission
and Storage source category is estimated to be approximately $370
thousand. All costs are in 2008 dollars.
    The total estimated net annual cost to industry to comply with the
proposed amendments to 40 CFR part 63, subpart HH for major sources in
the Oil and Natural Gas Production source category is approximately $16
million. The total net annual cost for proposed amendments to 40 CFR
part 63, subpart HHH for major sources in the Natural Gas Transmission
and Storage source category is estimated to be approximately $360,000.
These estimated annual costs include: (1) The cost of capital, (2)
operating and maintenance costs, (3) the cost of monitoring,
inspection, recordkeeping and reporting (MIRR) and (4) any associated
product recovery credits. All costs are in 2008 dollars.
    The estimated total capital cost to comply with the proposed NSPS
is approximately $740 million in 2008 dollars. The total estimated net
annual cost to industry to comply with the proposed NSPS is
approximately $740 million in 2008 dollars. This annual cost estimate
includes: (1) The cost of capital, (2) operating and maintenance costs
and (3) the cost of MIRR. This estimated annual cost does not take into
account any producer revenues associated with the recovery of salable
natural gas and hydrocarbon condensates.
    When revenues from additional product recovery are considered, the
proposed NSPS is estimated to result in a net annual engineering cost
savings overall. When including the additional natural gas recovery in
the engineering cost analysis, we assume that producers are paid $4 per
thousand cubic feet (Mcf) for the recovered gas at the wellhead. The
engineering analysis cost analysis assumes the value of recovered
condensate is $70 per barrel. Based on the engineering analysis, about
180,000,000 Mcf (180 billion cubic feet) of natural gas and 730,000
barrels of

condensate are estimated to be recovered by control requirements in
2015. Using the price assumptions, the estimated revenues from natural
gas product recovery are approximately $780 million in 2008 dollars.
This savings is estimated at $45 million in 2008 dollars.
    Using the engineering cost estimates, estimated natural gas product
recovery, and natural gas product price assumptions, the net annual
engineering cost savings is estimated for the proposed NSPS at about
$45 million in 2008 dollars. Totals may not sum due to independent
rounding.
    As the price assumption is very influential on estimated annualized
engineering costs, we performed a simple sensitivity analysis of the
influence of the assumed wellhead price paid to natural gas producers
on the overall engineering annualized costs estimate of the proposed
NSPS. At $4.22/Mcf, the price forecast reported in the 2011 Annual
Energy Outlook in 2008 dollars, the annualized costs are estimated at
about -$90 million, which would approximately double the estimate of
net cost savings of the proposed NSPS. As indicated by this difference,
EPA has chosen a relatively conservative assumption (leading to an
estimate of few savings and higher net costs) for the engineering costs
analysis. The natural gas price at which the proposed NSPS breaks-even
from an estimated engineering costs perspective is around $3.77/Mcf. A
$1/Mcf change in the wellhead natural gas price leads to about a $180
million change in the annualized engineering costs of the proposed
NSPS. Consequently, annualized engineering costs estimates would
increase to about $140 million under a $3/Mcf price or decrease to
about -$230 million under a $5/Mcf price. For further details on this
sensitivity analysis, please refer the regulatory impact analysis (RIA)
for this rulemaking located in the docket.

H. What are the economic impacts?

    The NEMS analysis of energy system impacts for the proposed NSPS
option estimates that domestic natural gas production is likely to
increase slightly (about 20 billion cubic feet or 0.1 percent) and
average natural gas prices to decrease slightly ($0.04 per Mcf in 2008
dollars or 0.9 percent at the wellhead for onshore producers in the
lower 48 states) for 2015, the year of analysis. This increase in
production and decrease in wellhead price is largely a result of the
increased natural gas and condensate recovery as a result of complying
with the NSPS. Domestic crude oil production is not expected to change,
while average crude oil prices are estimated to decrease slightly
($0.02/barrel in 2008 dollars or less than 0.1 percent at the wellhead
for onshore producers in the lower 48 states) in the year of analysis,
2015. The NEMS-based analysis estimates in the year of analysis, 2015,
that net imports of natural gas and crude will not change
significantly.
    Total CO2e emissions from energy-related sources are
expected to increase about 2.0 million metric tons CO2e or
0.04 percent under the proposed NSPS, according to the NEMS analysis.
This increase is attributable largely to natural gas consumption
increases. This estimate does not include CO2e reductions
from the implementation of the controls; these reductions are discussed
in more detail in the benefits section that follows.
    We did not estimate the energy economy impacts of the proposed
NESHAP amendments using NEMS, as the expected costs of the rule are not
likely to have estimable impacts on the national energy economy.

I. What are the benefits?

    The proposed Oil and Natural Gas NSPS and NESHAP amendments are
expected to result in significant reductions in existing emissions and
prevent new emissions from expansions of the industry. These proposed
rules combined are anticipated to reduce 38,000 tons of HAP, 540,000
tons of VOC and 3.4 million tons of methane. These pollutants are
associated with substantial health effects, welfare effects and climate
effects. With the data available, we are not able to provide credible
health benefit estimates for the reduction in exposure to HAP, ozone
and PM (2.5 microns and less) (PM2.5) for these rules, due
to the differences in the locations of oil and natural gas emission
points relative to existing information and the highly localized nature
of air quality responses associated with HAP and VOC reductions.
    This is not to imply that there are no benefits of the rules;
rather, it is a reflection of the difficulties in modeling the direct
and indirect impacts of the reductions in emissions for this industrial
sector with the data currently available. In addition to health
improvements, there will be improvements in visibility effects,
ecosystem effects and climate effects, as well as additional product
recovery.
    Although we do not have sufficient information or modeling
available to provide quantitative estimates for this rulemaking, we
include a qualitative assessment of the health effects associated with
exposure to HAP, ozone and PM2.5 in the RIA for this rule.
These qualitative effects are briefly summarized below, but for more
detailed information, please refer to the RIA, which is available in
the docket. One of the HAP of concern from the oil and natural gas
sector is benzene, which is a known human carcinogen, and formaldehyde,
which is a probable human carcinogen. VOC emissions are precursors to
both PM2.5 and ozone formation. As documented in previous
analyses (U.S. EPA, 2006 \41\ and U.S. EPA, 2010 \42\), exposure to
PM2.5 and ozone is associated with significant public health
effects. PM2.5 is associated with health effects such as
premature mortality for adults and infants, cardiovascular morbidity,
such as heart attacks, hospital admissions and respiratory morbidity
such as asthma attacks, acute and chronic bronchitis, hospital and
emergency room visits, work loss days, restricted activity days and
respiratory symptoms, as well as visibility impairment.\43\ Ozone is
associated with health effects such as respiratory morbidity such as
asthma attacks, hospital and emergency department visits, school loss
days and premature mortality, as well as injury to vegetation and
climate effects.\44\
---------------------------------------------------------------------------

    \41\ U.S. EPA. RIA. National Ambient Air Quality Standards for
Particulate Matter, Chapter 5. Office of Air Quality Planning and
Standards, Research Triangle Park, NC. October 2006. Available on
the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/Chapter%205-Benefits.pdf.
    \42\ U.S. EPA. RIA. National Ambient Air Quality Standards for
Ozone. Office of Air Quality Planning and Standards, Research
Triangle Park, NC. January 2010. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/s1-supplemental_analysis_full.pdf.
    \43\ U.S. EPA. Integrated Science Assessment for Particulate
Matter (Final Report). EPA-600-R-08-139F. National Center for
Environmental Assessment--RTP Division. December 2009. Available at
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.
    \44\ U.S. EPA. Air Quality Criteria for Ozone and Related
Photochemical Oxidants (Final). EPA/600/R-05/004aF-cF. Washington,
DC: U.S. EPA. February 2006. Available on the Internet at
http:[sol][sol]cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923.
---------------------------------------------------------------------------

    In addition to the improvements in air quality and resulting
benefits to human health and non-climate welfare effects previously
discussed, this proposed rule is expected to result in significant
climate co-benefits due to anticipated methane reductions. Methane is a
potent GHG that, once emitted into the atmosphere, absorbs terrestrial
infrared radiation, which contributes to increased global warming and
continuing climate change. Methane reacts in the atmosphere to form
ozone and ozone also impacts global temperatures. According to the

Intergovernmental Panel on Climate Change (IPCC) 4th Assessment Report
(2007), methane is the second leading long-lived climate forcer after
CO2 globally. Total methane emissions from the oil and gas
industry represent about 40 percent of the total methane emissions from
all sources and account for about 5 percent of all CO2e
emissions in the United States, with natural gas systems being the
single largest contributor to United States anthropogenic methane
emissions.\45\ Methane, in addition to other GHG emissions, contributes
to warming of the atmosphere, which, over time, leads to increased air
and ocean temperatures, changes in precipitation patterns, melting and
thawing of global glaciers and ice, increasingly severe weather events,
such as hurricanes of greater intensity and sea level rise, among other
impacts.
---------------------------------------------------------------------------

    \45\ U.S. EPA (2011), 2011 U.S. Greenhouse Gas Inventory Report
Executive Summary available on the internet at
http:[sol][sol]www.epa.gov/climateexchange/emissions/downloads11/US-
GHG-Inventory-2011-Executive Summary.pdf.
---------------------------------------------------------------------------

    This rulemaking proposes emission control technologies and
regulatory alternatives that will significantly decrease methane
emissions from the oil and natural gas sector in the United States. The
regulatory alternatives proposed for the NESHAP and the NSPS are
expected to reduce methane emissions annually by about 3.4 million
short tons or 65 million metric tons CO2e. After considering
the secondary impacts of this proposal previously discussed, such as
increased CO2 emissions from well completion combustion and
decreased CO2e emissions because of fuel-switching by
consumers, the methane reductions become about 62 million metric tons
CO2e. These reductions represent about 26 percent of the
baseline methane emissions for this sector reported in the EPA's U.S.
Greenhouse Gas Inventory Report for 2009 (251.55 million metric tons
CO2e when petroleum refineries and petroleum transportation
are excluded because these sources are not examined in this proposal).
After considering the secondary impacts of this proposal, such as
increased CO2 emissions from well completion combustion and
decreased CO2 emissions because of fuel-switching by
consumers, the CO2e GHG reductions are reduced to about 62
million metric tons CO2e. However, it is important to note
that the emission reductions are based upon predicted activities in
2015; the EPA did not forecast sector-level emissions in 2015 for this
rulemaking. These emission reductions equate to the climate benefits of
taking approximately 11 million typical passenger cars off the road or
eliminating electricity use from about 7 million typical homes each
year.\46\
---------------------------------------------------------------------------

    \46\ U.S. EPA. Greenhouse Gas Equivalency Calculator available
at: http://www.epa.gov/cleanenergy/energy-resources/calculator.html
accessed 07/19/11.
---------------------------------------------------------------------------

    The EPA recognizes that the methane reductions proposed in this
rule will provide for significant economic climate benefits to society
just described. However, there is no interagency-accepted methodology
to place monetary values on these benefits. A `global warming potential
(GWP) approach' of converting methane to CO2e using the GWP
of methane provides an approximation method for estimating the
monetized value of the methane reductions anticipated from this rule.
This calculation uses the GWP of the non-CO2 gas to estimate
CO2 equivalents and then multiplies these CO2
equivalent emission reductions by the social cost of carbon developed
by the Interagency Social Cost of Carbon Work Group to generate
monetized estimates of the benefits.
    The social cost of carbon is an estimate of the net present value
of the flow of monetized damages from a 1-metric ton increase in
CO2 emissions in a given year (or from the alternative
perspective, the benefit to society of reducing CO2
emissions by 1 ton). For more information about the social cost of
carbon, see the Support Document: Social Cost of Carbon for Regulatory
Impact Analysis Under Executive Order 12866 \47\ and RIA for the Light-
Duty Vehicle GHG rule.\48\ Applying this approach to the methane
reductions estimated for the proposed NESHAP and NSPS of the oil and
gas rule, the 2015 climate co-benefits vary by discount rate and range
from about $370 million to approximately $4.7 billion; the mean social
cost of carbon at the 3-percent discount rate results in an estimate of
about $1.6 billion in 2015.
---------------------------------------------------------------------------

    \47\ Interagency Working Group on Social Cost of Carbon (IWGSC).
2010. Technical Support Document: Social Cost of Carbon for
Regulatory Impact Analysis Under Executive Order 12866. Docket ID
EPA-HQ-OAR-2009-0472-114577. http://www.epa.gov/otaq/climate/regulations/scc-tsd.pdf; Accessed March 30, 2011.
    \48\ U.S. EPA. Final Rulemaking: Light-Duty Vehicle Greenhouse
Gas Emissions Standards and Corporate Average Fuel Economy
Standards. May 2010. Available on the Internet at http://www.epa.gov/otaq/climate/regulations.htm#finalR.
---------------------------------------------------------------------------

    The ratio of domestic to global benefits of emission reductions
varies with key parameter assumptions. For example, with a 2.5 or 3
percent discount rate, the U.S. benefit is about 7-10 percent of the
global benefit, on average, across the scenarios analyzed.
Alternatively, if the fraction of GDP lost due to climate change is
assumed to be similar across countries, the domestic benefit would be
proportional to the U.S. share of global GDP, which is currently about
23 percent. On the basis of this evidence, values from 7 to 23 percent
should be used to adjust the global SCC to calculate domestic effects.
It is recognized that these values are approximate, provisional and
highly speculative. There is no a priori reason why domestic benefits
should be a constant fraction of net global damages over time.\49\
---------------------------------------------------------------------------

    \49\ Interagency Working Group on Social Cost of Carbon (IWGSC).
2010. Technical Support Document: Social Cost of Carbon for
Regulatory Impact Analysis Under Executive Order 12866.
---------------------------------------------------------------------------

    These co-benefits equate to a range of approximately $110 to $1,400
per short ton of methane reduced, depending upon the discount rate
assumed with a per ton estimate of $480 at the 3-percent discount rate.
Methane climate co-benefit estimates for additional regulatory
alternatives are included in the RIA for this proposed rule. These
social cost of methane benefit estimates are not the same as would be
derived from direct computations (using the integrated assessment
models employed to develop the Interagency Social Cost of Carbon
estimates) for a variety of reasons, including the shorter atmospheric
lifetime of methane relative to CO2 (about 12 years compared
to CO2 whose concentrations in the atmosphere decay on
timescales of decades to millennia). The climate impacts also differ
between the pollutants for reasons other than the radiative forcing
profiles and atmospheric lifetimes of these gases.
    Methane is a precursor to ozone and ozone is a short-lived climate
forcer that contributes to global warming. The use of the IPCC Second
Assessment Report GWP to approximate co-benefits may underestimate the
direct radiative forcing benefits of reduced ozone levels and does not
capture any secondary climate co-benefits involved with ozone-ecosystem
interactions. In addition, a recent EPA National Center of
Environmental Economics working paper suggests that this quick `GWP
approach' to benefits estimation will likely understate the climate
benefits of methane reductions in most cases.\50\ This conclusion is
reached using the 100-year GWP for methane of 25 as put forth in the
IPCC Fourth Assessment Report (AR 4), as opposed to the lower

value of 21 used in this analysis. Using the higher GWP estimate of 25
would increase these reported methane climate co-benefit estimates by
about 19 percent. Although the IPCC Assessment Report (AR4) suggested a
GWP of 25 for methane, the EPA has used GWP of 21 to estimate the
methane climate co-benefits for this oil and gas proposal in order to
provide estimates more consistent with global GHG inventories, which
currently use GWP from the IPCC Second Assessment Report.
---------------------------------------------------------------------------

    \50\ Marten and Newbold (2011), Estimating the Social Cost of
Non-CO2 GHG Emissions: Methane and Nitrous Oxide, NCEE Working Paper
Series 11-01. http://yosemite.epa.gov/EE/epa/eed.nsf/WPNumber/2011-01?OpenDocument.
---------------------------------------------------------------------------

    Due to the uncertainties involved with the `GWP approach' estimates
presented and methane climate co-benefits estimates available in the
literature, the EPA chooses not to compare these co-benefit estimates
to the costs of the rule for this proposal. Rather, the EPA presents
the `GWP approach' climate co-benefit estimates as an interim method to
produce these estimates until the Interagency Social Cost of Carbon
Work Group develops values for non-CO2 GHG. The EPA requests
comments from interested parties and the public about this interim
approach specifically and more broadly about appropriate methods to
monetize the climate benefits of methane reductions. In particular, the
EPA seeks public comments to this proposed rulemaking regarding social
cost of methane estimates that may be used to value the co-benefits of
methane emission reductions anticipated for the oil and gas industry
from this rule. Comments specific to whether GWP is an acceptable
method for generating a placeholder value for the social cost of
methane until interagency-modeled estimates become available are
welcome. Public comments may be provided in the official docket for
this proposed rulemaking in accordance with the process outlined
earlier in this notice. These comments will be considered in developing
the final rule for this rulemaking.
    For the proposed NESHAP amendments, a break-even analysis suggests
that HAP emissions would need to be valued at $12,000 per ton for the
benefits to exceed the costs if the health, ecosystem and climate
benefits from the reductions in VOC and methane emissions are assumed
to be zero. Even though emission reductions of VOC and methane are co-
benefits for the proposed NESHAP amendments, they are legitimate
components of the total benefit-cost comparison. If we assume the
health benefits from HAP emission reductions are zero, the VOC
emissions would need to be valued at $1,700 per ton or the methane
emissions would need to be valued at $3,300 per ton for the co-benefits
to exceed the costs. All estimates are in 2008 dollars. For the
proposed NSPS, the revenue from additional product recovery exceeds the
costs, which renders a break-even analysis unnecessary when these
revenues are included in the analysis. Based on the methodology from
Fann, Fulcher, and Hubbell (2009),\51\ ranges of benefit-per-ton
estimates for emissions of VOC indicate that on average in the United
States, VOC emissions are valued from $1,200 to $3,000 per ton as a
PM2.5 precursor, but emission reductions in specific areas
are valued from $280 to $7,000 per ton in 2008 dollars. As a result,
even if VOC emissions from oil and natural gas operations result in
monetized benefits that are substantially below the national average,
there is a reasonable chance that the benefits of the rule would exceed
the costs, especially if we were able to monetize all of the additional
benefits associated with ozone formation, visibility, HAP and methane.
---------------------------------------------------------------------------

    \51\ Fann, N., C.M. Fulcher, B.J. Hubbell. 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.
---------------------------------------------------------------------------

IX. Request for Comments

    We are soliciting comments on all aspects of this proposed action.
All comments received during the comment period will be considered. In
addition to general comments on the proposed actions, we are also
interested in any additional data that may help to reduce the
uncertainties inherent in the risk assessments. We are specifically
interested in receiving corrections to the datasets used for MACT
analyses and risk modeling. Such data should include supporting
documentation in sufficient detail to allow characterization of the
quality and representativeness of the data or information. Please see
the following section for more information on submitting data.

X. Submitting Data Corrections

    The facility-specific data used in the source category risk
analyses, facility-wide analyses and demographic analyses for each
source category subject to this action are available for download on
the RTR Web page at http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. These
data files include detailed information for each HAP emissions release
point at each facility included in the source category and all other
HAP emissions sources at these facilities (facility-wide emissions
sources). However, it is important to note that the source category
risk analysis included only those emissions tagged with the MACT code
associated with the source category subject to the risk analysis.
    If you believe the data are not representative or are inaccurate,
please identify the data in question, provide your reason for concern
and provide any ``improved'' data that you have, if available. When you
submit data, we request that you provide documentation of the basis for
the revised values to support your suggested changes. To submit
comments on the data downloaded from the RTR Web page, complete the
following steps:
    1. Within this downloaded file, enter suggested revisions to the
data fields appropriate for that information. The data fields that may
be revised include the following:

------------------------------------------------------------------------
           Data element                          Definition
------------------------------------------------------------------------
Control Measure...................  Are control measures in place? (yes
                                     or no).
Control Measure Comment...........  Select control measure from list
                                     provided and briefly describe the
                                     control measure.
Delete............................  Indicate here if the facility or
                                     record should be deleted.
Delete Comment....................  Describes the reason for deletion.
Emission Calculation Method Code    Code description of the method used
 for Revised Emissions.              to derive emissions. For example,
                                     CEM, material balance, stack test,
                                     etc.
Emission Process Group............  Enter the general type of emission
                                     process associated with the
                                     specified emission point.
Fugitive Angle....................  Enter release angle (clockwise from
                                     true North); orientation of the y-
                                     dimension relative to true North,
                                     measured positive for clockwise
                                     starting at 0 degrees (maximum 89
                                     degrees).
Fugitive Length...................  Enter dimension of the source in the
                                     east-west (x-) direction, commonly
                                     referred to as length (ft).

Fugitive Width....................  Enter dimension of the source in the
                                     north-south (y-) direction,
                                     commonly referred to as width (ft).
Malfunction Emissions.............  Enter total annual emissions due to
                                     malfunctions (TPY).
Malfunction Emissions Max Hourly..  Enter maximum hourly malfunction
                                     emissions here (lb/hr).
North American Datum..............  Enter datum for latitude/longitude
                                     coordinates (NAD27 or NAD83); if
                                     left blank, NAD83 is assumed.
Process Comment...................  Enter general comments about process
                                     sources of emissions.
REVISED Address...................  Enter revised physical street
                                     address for MACT facility here.
REVISED City......................  Enter revised city name here.
REVISED County Name...............  Enter revised county name here.
REVISED Emission Release Point      Enter revised Emission Release Point
 Type.                               Type here.
REVISED End Date..................  Enter revised End Date here.
REVISED Exit Gas Flow Rate........  Enter revised Exit Gas Flowrate here
                                     (ft\3\/sec).
REVISED Exit Gas Temperature......  Enter revised Exit Gas Temperature
                                     here (OF).
REVISED Exit Gas Velocity.........  Enter revised Exit Gas Velocity here
                                     (ft/sec).
REVISED Facility Category Code....  Enter revised Facility Category Code
                                     here, which indicates whether
                                     facility is a major or area source.
REVISED Facility Name.............  Enter revised Facility Name here.
REVISED Facility Registry           Enter revised Facility Registry
 Identifier.                         Identifier here, which is an ID
                                     assigned by the EPA Facility
                                     Registry System.
REVISED HAP Emissions Performance   Enter revised HAP Emissions
 Level Code.                         Performance Level here.
REVISED Latitude..................  Enter revised Latitude here (decimal
                                     degrees).
REVISED Longitude.................  Enter revised Longitude here
                                     (decimal degrees).
REVISED MACT Code.................  Enter revised MACT Code here.
REVISED Pollutant Code............  Enter revised Pollutant Code here.
REVISED Routine Emissions.........  Enter revised routine emissions
                                     value here (TPY).
REVISED SCC Code..................  Enter revised SCC Code here.
REVISED Stack Diameter............  Enter revised Stack Diameter here
                                     (ft).
REVISED Stack Height..............  Enter revised Stack Height here
                                     (Ft).
REVISED Start Date................  Enter revised Start Date here.
REVISED State.....................  Enter revised state here.
REVISED Tribal Code...............  Enter revised Tribal Code here.
REVISED Zip Code..................  Enter revised Zip Code here.
Shutdown Emissions................  Enter total annual emissions due to
                                     shutdown events (TPY).
Shutdown Emissions Max Hourly.....  Enter maximum hourly shutdown
                                     emissions here (lb/hr).
Stack Comment.....................  Enter general comments about
                                     emission release points.
Startup Emissions.................  Enter total annual emissions due to
                                     startup events (TPY).
Startup Emissions Max Hourly......  Enter maximum hourly startup
                                     emissions here (lb/hr).
Year Closed.......................  Enter date facility stopped
                                     operations.
------------------------------------------------------------------------

    2. Fill in the commenter information fields for each suggested
revision (i.e., commenter name, commenter organization, commenter e-
mail address, commenter phone number and revision comments).
    3. Gather documentation for any suggested emissions revisions
(e.g., performance test reports, material balance calculations, etc.).
    4. Send the entire downloaded file with suggested revisions in
Microsoft[supreg] Access format and all accompanying documentation to
Docket ID Number EPA-HQ-OAR-2010-0505 (through one of the methods
described in the ADDRESSES section of this preamble). To expedite
review of the revisions, it would also be helpful if you submitted a
copy of your revisions to the EPA directly at<EMAIL_ADDRESS>in addition
to submitting them to the docket.
    5. If you are providing comments on a facility with multiple source
categories, you need only submit one file for that facility, which
should contain all suggested changes for all source categories at that
facility. We request that all data revision comments be submitted in
the form of updated Microsoft[supreg] Access files, which are provided
on the http://www.epa.gov/ttn/atw/rrisk/rtrpg.html Web page.

XI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review

    Under 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 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. The RIA available in the docket
describes in detail the empirical basis for the EPA's assumptions and
characterizes the various sources of uncertainties affecting the
estimates below. Table 8 shows the results of the cost and benefits
analysis for these proposed rules. For more information on the benefit
and cost analysis, as well as details on the regulatory options
considered, please refer to the RIA for this rulemaking, which is
available in the docket.

Table 8--Summary of the Monetized Benefits, Costs and Net Benefits for the Proposed Oil and Natural Gas NSPS and
                                            NEHSAP Amendments in 2015
                                             [Millions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
                                                                                Proposed NSPS and
                                            Proposed NSPS           Proposed NESHAP         NESHAP amendments
                                                                       amendments                combined
----------------------------------------------------------------------------------------------------------------
Total Monetized Benefits \2\........             N/A                      N/A                      N/A.
Total Costs \3\.....................        -$45 million              $16 million             -$29 million.
Net Benefits........................             N/A                      N/A                      N/A.
Non-monetized Benefits 4 5..........  37,000 tons of HAP        1,400 tons of HAP        38,000 tons of HAP.
                                      540,000 tons of VOC       9,200 tons of VOC        540,000 tons of VOC.
                                      3.4 million tons of       4,900 tons of methane    3.4 million tons of
                                       methane                                            methane.
                                     ---------------------------------------------------------------------------
                                                            Health effects of HAP exposure.
                                                      Health effects of PM2.5 and ozone exposure.
                                                                Visibility impairment.
                                                                  Vegetation effects.
                                                                   Climate effects.
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015).
\2\ While we expect that these avoided emissions will result in improvements in air quality and reductions in
  health effects associated with HAP, ozone and PM, as well as climate effects associated with methane, we have
  determined that quantification of those benefits cannot be accomplished for this rule in a defensible way.
  This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties
  in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the
  data currently available.
\3\ The engineering compliance costs are annualized using a 7-percent discount rate. The negative cost for the
  proposed NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate
  recovery that are estimated as a result of the proposed NSPS.
\4\ For the NSPS, reduced exposure to HAP and climate effects are co-benefits. For the NESHAP, reduced VOC
  emissions, PM2.5 and ozone exposure, visibility and vegetation effects and climate effects are co-benefits.
\5\ The specific control technologies for these proposed rules are anticipated to have minor secondary
  disbenefits. The net CO2-equivalent emission reductions are 93,000 metric tons for the NESHAP and 62 million
  metric tons for the NSPS.

B. Paperwork Reduction Act

    The information collection requirements in this proposed action
have been submitted for approval to OMB under the Paperwork Reduction
Act, 44 U.S.C. 3501, et seq. The ICR document prepared by the EPA has
been assigned EPA ICR Numbers 1716.07 (40 CFR part 60, subpart OOOO),
1788.10 (40 CFR part 63, subpart HH), 1789.07 (40 CFR part 63, subpart
HHH) and 1086.10 (40 CFR part 60, subparts KKK and subpart LLL).
    The information to be collected for the proposed NSPS and the
proposed NESHAP amendments are based on notification, recordkeeping and
reporting requirements in the NESHAP General Provisions (40 CFR part
63, subpart A), which are mandatory for all operators subject to
national emission standards. These recordkeeping and reporting
requirements are specifically authorized by section 114 of the CAA (42
U.S.C. 7414). All information submitted to the EPA pursuant to the
recordkeeping and reporting requirements for which a claim of
confidentiality is made is safeguarded according to Agency policies set
forth in 40 CFR part 2, subpart B.
    These proposed rules would require maintenance inspections of the
control devices, but would not require any notifications or reports
beyond those required by the General Provisions. The recordkeeping
requirements require only the specific information needed to determine
compliance.
    For sources subject to the proposed NSPS, burden changes associated
with these amendments result from the respondents' annual reporting and
recordkeeping burden associated with this proposed rule for this
collection (averaged over the first 3 years after the effective date of
the standards). The burden is estimated to be 560,000 labor hours at a
cost of $18 million per year. This includes the burden previously
estimated for sources subject to 40 CFR part 60, subpart KKK (which is
being incorporated into 40 CFR part 60, subpart OOOO). The average
hours and cost per regulated entity subject to the NSPS for oil and
natural gas production and natural gas transmissions and distribution
facilities would be 110 hours per response and $3,693 per response,
based on an average of 1,459 operators responding per year and 16
responses per year.
    The estimated recordkeeping and reporting burden after the
effective date of the proposed amendments is estimated for all affected
major and area sources subject to the Oil and Natural Gas Production
NESHAP to be approximately 63,000 labor hours per year at a cost of
$2.1 million per year. For the Natural Gas Transmission and Storage
NESHAP, the recordkeeping and reporting burden is estimated to be 2,500
labor hours per year at a cost of $86,800 per year. This estimate
includes the cost of reporting, including reading instructions and
information gathering. Recordkeeping cost estimates include reading
instructions, planning activities and conducting compliance monitoring.
The average hours and cost per regulated entity subject to the Oil and
Natural Gas Production NESHAP would be 72 hours per year and $2,500 per
year, based on an average of 846 facilities per year and three
responses per facility. For the Natural Gas Transmission and Storage
NESHAP, the average hours and cost per regulated entity would be 50
hours per year and $1,600 per year, based on an average of 53
facilities per year and three responses per facility. 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 in 40 CFR are listed in 40 CFR part 9.
    To comment on the Agency's need for this information, the accuracy
of the provided burden estimates and any suggested methods for
minimizing respondent burden, the EPA has established a public docket
for this rule, which includes this ICR, under Docket ID Number EPA-HQ-
OAR-2010-0505. Submit any comments related to the ICR to the EPA and
OMB. See the ADDRESSES section at the beginning of this notice for
where to submit comments to the

EPA. Send comments to OMB at the Office of Information and Regulatory
Affairs, Office of Management and Budget, 725 17th Street, NW.,
Washington, DC 20503, Attention: Desk Office for the EPA. Since OMB is
required to make a decision concerning the ICR between 30 and 60 days
after August 23, 2011, a comment to OMB is best assured of having its
full effect if OMB receives it by September 22, 2011. The final rule
will respond to any OMB or public comments on the information
collection requirements contained in this proposal.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act generally requires an agency to
prepare a regulatory flexibility analysis of any rule subject to notice
and comment rulemaking requirements under the Administrative Procedure
Act or any other statute, unless the agency certifies that the rule
will not have a significant economic impact on a substantial number of
small entities (SISNOSE). Small entities include small businesses,
small organizations, and small governmental jurisdictions. For purposes
of assessing the impact of this rule on small entities, a small entity
is defined as: (1) A small business whose parent company has no more
than 500 employees (or revenues of less than $7 million for firms that
transport natural gas via pipeline); (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.
Proposed NSPS
    After considering the economic impact of the proposed NSPS on small
entities, I certify that this action will not have a SISNOSE. The EPA
performed a screening analysis for impacts on a sample of expected
affected small entities by comparing compliance costs to entity
revenues. Based upon the analysis in the RIA, which is in the Docket,
EPA concludes the number of impacted small businesses is unlikely to be
sufficiently large to declare a SISNOSE. Our judgment in this
determination is informed by the fact that many affected firms are
expected to receive revenues from the additional natural gas and
condensate recovery engendered by the implementation of the controls
evaluated in this RIA. As much of the additional natural gas recovery
is estimated to arise from completion-related activities, we expect the
impact on well-related compliance costs to be significantly mitigated.
This conclusion is enhanced because the returns to REC activities occur
without a significant time lag between implementing the control and
obtaining the recovered product, unlike many control options where the
emissions reductions accumulate over long periods of time; the reduced
emission completions and recompletions occur over a short span of time,
during which the additional product recovery is also accomplished.
Proposed NESHAP Amendments
    After considering the economic impact of the proposed NESHAP
amendments on small entities, I certify that this action will not have
a SISNOSE. Based upon the analysis in the RIA, which is in the Docket,
we estimate that 62 of the 118 firms (53 percent) that own potentially
affected facilities are small entities. The EPA performed a screening
analysis for impacts on all expected affected small entities by
comparing compliance costs to entity revenues. Among the small firms,
52 of the 62 (84 percent) are likely to have impacts of less than 1
percent in terms of the ratio of annualized compliance costs to
revenues. Meanwhile, 10 firms (16 percent) are likely to have impacts
greater than 1 percent. Four of these 10 firms are likely to have
impacts greater than 3 percent. While these 10 firms might receive
significant impacts from the proposed NESHAP amendments, they represent
a very small slice of the oil and gas industry in its entirety, less
than 0.2 percent of the estimated 6,427 small firms in NAICS 211.
Although this final rule will not impact a substantial number of small
entities, the EPA, nonetheless, has tried to reduce the impact of this
rule on small entities by setting the final emissions limits at the
MACT floor, the least stringent level allowed by law.
    We continue to be interested in the potential impacts of the
proposed rule on small entities and welcome comments on issues related
to such impacts.

D. Unfunded Mandates Reform Act

    This action contains no Federal mandates under the provisions of
title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C.
1531-1538 for state, local or tribal governments or the private sector.
This proposed 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 to the private sector in any one
year. Thus, this proposed rule is not subject to the requirements of
sections 202 or 205 of UMRA. This proposed 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. This action contains no requirements that apply to
such governments nor does it impose obligations upon them.

E. Executive Order 13132: Federalism

    This proposed rule 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. Thus, Executive Order 13132 does
not apply to this proposed rule. In the spirit of Executive Order 13132
and consistent with the EPA policy to promote communications between
the EPA and state and local governments, the EPA specifically solicits
comment on this proposed rule from state and local officials.

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). It will not have
substantial direct effect on tribal governments, on the relationship
between the Federal government and Indian tribes or on the distribution
of power and responsibilities between the Federal government and Indian
tribes, as specified in Executive Order 13175. Thus, Executive Order
13175 does not apply to this action.
    The EPA specifically solicits additional comment on this proposed
action from tribal officials.

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

    This proposed rule is not subject to Executive Order 13045 (62 FR
19885, April 23, 1997) because the Agency does not believe the
environmental health risks or safety risks addressed by this action
present a disproportionate risk to children. This actions' health and
risk assessments are contained in section VII.C of this preamble.
    The public is invited to submit comments or identify peer-reviewed
studies and data that assess effects of early life exposure to HAP from
oil and natural gas sector activities.

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

    Executive Order 13211, (66 FR 28,355, May 22, 2001), provides that
agencies shall prepare and submit to the Administrator of the Office of
Information and Regulatory Affairs, OMB, a Statement of Energy Effects
for certain actions identified as significant energy actions. Section
4(b) of Executive Order 13211 defines ``significant energy actions'' as
``any action by an agency (normally published in the Federal Register)
that promulgates or is expected to lead to the promulgation of a final
rule or regulation, including notices of inquiry, advance notices of
proposed rulemaking, and notices of proposed rulemaking: (1)(i) That is
a significant regulatory action under Executive Order 12866 or any
successor order and (ii) is likely to have a significant adverse effect
on the supply, distribution, or use of energy; or (2) that is
designated by the Administrator of the Office of Information and
Regulatory Affairs as a significant energy action.''
    The proposed rules will result in the addition of control equipment
and monitoring systems for existing and new sources within the oil and
natural gas industry. The proposed NESHAP amendments are unlikely to
have a significant adverse effect on the supply, distribution or use of
energy. As such, the proposed NESHAP amendments are not ``significant
energy actions'' as defined in Executive Order 13211 (66 FR 28355, May
22, 2001).
    The proposed NSPS is also unlikely to have a significant effect on
the supply, distribution or use of energy. As such, the proposed NSPS
is not a ``significant energy action'' as defined in Executive Order
13211 (66 FR 28355, May 22, 2001). The basis for the determination is
as follows.
    As discussed in the impacts section of the Preamble, we use the
NEMS to estimate the impacts of the proposed NSPS on the United States
energy system. The NEMS is a publically available model of the United
States energy economy developed and maintained by the Energy
Information Administration of the United States DOE and is used to
produce the Annual Energy Outlook, a reference publication that
provides detailed forecasts of the United States energy economy.
    Proposed emission controls for the NSPS capture VOC emissions that
otherwise would be vented to the atmosphere. Since methane is co-
emitted with VOC, a large proportion of the averted methane emissions
can be directed into natural gas production streams and sold. One
pollution control requirement of the proposed NSPS also captures
saleable condensates. The revenues from additional natural gas and
condensate recovery are expected to offset the costs of implementing
the proposed NSPS.
    The analysis of energy impacts for the proposed NSPS that includes
the additional product recovery shows that domestic natural gas
production is estimated to increase (20 billion cubic feet or 0.1
percent) and natural gas prices to decrease ($0.04/Mcf or 0.9 percent
at the wellhead for producers in the lower 48 states) in 2015, the year
of analysis. Domestic crude oil production is not estimated to change,
while crude oil prices are estimated to decrease slightly ($0.02/barrel
or less than 0.1 percent at the wellhead for producers in the lower 48
states) in 2015, the year of analysis. All prices are in 2008 dollars.
    Additionally, the NSPS establishes several performance standards
that give regulated entities flexibility in determining how to best
comply with the regulation. In an industry that is geographically and
economically heterogeneous, this flexibility is an important factor in
reducing regulatory burden.
    For more information on the estimated energy effects, please refer
to the economic impact analysis for this proposed rule. The analysis is
available in the RIA, which is in the public docket.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law No. 104-113 (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.
    The proposed rule involves technical standards. Therefore, the
requirements of the NTTAA apply to this action. We are proposing to
revise 40 CFR part 63, subpart HH and 40 CFR part 63, subpart HHH to
allow ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses (Part 10,
Instruments and Apparatus) to be used in lieu of EPA Methods 3B, 6 and
16A. This standard is available from the American Society of Mechanical
Engineers (ASME), Three Park Avenue, New York, NY 10016-5990. Also, we
are proposing to revise subpart HHH to allow ASTM D6420-99 (2004), Test
Method for Determination of Gaseous Organic Compounds by Direct
Interface Gas Chromatography/Mass Spectrometry, to be used in lieu of
EPA Method 18. For a detailed discussion of this VCS, and its
appropriateness as a substitute for Method 18, see the final Oil and
Natural Gas Production NESHAP (Area Sources) (72 FR 36, January 3,
2007).
    As a result, the EPA is proposing ASTM D6420-99 (2004) for use in
40 CFR part 63, subpart HHH. The EPA also proposes to allow Method 18
as an option in addition to ASTM D6420-99 (2004). This would allow the
continued use of gas chromatography configurations other than gas
chromatography/mass spectrometry.
    The EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially-
applicable VCS and to explain why such standards should be used in this
regulation.

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 EJ. Its main provision directs Federal
agencies, to the greatest extent practicable and permitted by law, to
make EJ 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 proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it increases the
level of environmental protection for all affected populations without
having any disproportionately high and adverse human health or
environmental effects on any population, including any minority or low-
income population.
    To examine the potential for any EJ issues that might be associated
with each source category, we evaluated the distributions of HAP-
related cancer and noncancer risks across different social, demographic
and economic groups within the populations living near the facilities
where these source categories

are located. The methods used to conduct demographic analyses for this
rule are described in section VII.C of the preamble for this rule. The
development of demographic analyses to inform the consideration of EJ
issues in EPA rulemakings is an evolving science. The EPA offers the
demographic analyses in this proposed rulemaking as examples of how
such analyses might be developed to inform such consideration, and
invites public comment on the approaches used and the interpretations
made from the results, with the hope that this will support the
refinement and improve utility of such analyses for future rulemakings.
    For the demographic analyses, we focused on the populations within
50 km of any facility estimated to have exposures to HAP which result
in cancer risks of 1-in-1 million or greater, or noncancer HI of 1 or
greater (based on the emissions of the source category or the facility,
respectively). We examined the distributions of those risks across
various demographic groups, comparing the percentages of particular
demographic groups to the total number of people in those demographic
groups nationwide. The results, including other risk metrics, such as
average risks for the exposed populations, are documented in source
category-specific technical reports in the docket for both source
categories covered in this proposal.
    As described in the preamble, our risk assessments demonstrate that
the regulations for the oil and natural gas production and natural gas
transmission and storage source categories, are associated with an
acceptable level of risk and that the proposed additional requirements
will provide an ample margin of safety to protect public health. Our
analyses also show that, for these source categories, there is no
potential for an adverse environmental effect or human health multi-
pathway effects, and that acute and chronic noncancer health impacts
are unlikely. The EPA has determined that, although there may be an
existing disparity in HAP risks from these sources between some
demographic groups, no demographic group is exposed to an unacceptable
level of risk.

List of Subjects

40 CFR Part 60

    Environmental protection, Air pollution control, Reporting and
recordkeeping requirements, Volatile organic compounds.

40 CFR Part 63

    Environmental protection, Air pollution control, Reporting and
recordkeeping requirements, Volatile organic compounds.

    Dated: July 28, 2011.
Lisa P. Jackson,
Administrator.

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

PART 60--[AMENDED]

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

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

    2. Section 60.17 is amended by:
    a. Revising paragraph (a)(7); and
    b. Revising paragraphs (a)(91) and (a)(92) to read as follows:

Sec.  60.17  Incorporations by reference.

* * * * *
    (a) * * *
    (7) ASTM D86-78, 82, 90, 93, 95, 96, Distillation of Petroleum
Products, IBR approved for Sec. Sec.  60.562-2(d), 60.593(d),
60.593a(d), 60.633(h) and 60.5401(h).
* * * * *
    (91) ASTM E169-63, 77, 93, General Techniques of Ultraviolet
Quantitative Analysis, IBR approved for Sec. Sec.  60.485a(d)(1),
60.593(b)(2), 60.593a(b)(2), 60.632(f) and 60.5400(f).
    (92) ASTM E260-73, 91, 96, General Gas Chromatography Procedures,
IBR approved for Sec. Sec.  60.485a(d)(1), 60.593(b)(2), 60.593a(b)(2),
60.632(f), 60.5400(f) and 60.5406(b).
* * * * *

Subpart KKK--Standards of Performance for Equipment Leaks of VOC
From Onshore Natural Gas Processing Plants for Which Construction,
Reconstruction, or Modification Commenced After January 20, 1984,
and on or Before August 23, 2011

    3. The heading for Subpart KKK is revised to read as set out above.
    4. Section 60.630 is amended by revising paragraph (b) to read as
follows:

Sec.  60.630  Applicability and designation of affected facility.

* * * * *
    (b) Any affected facility under paragraph (a) of this section that
commences construction, reconstruction, or modification after January
20, 1984, and on or before August 23, 2011, is subject to the
requirements of this subpart.
* * * * *

Subpart LLL--Standards of Performance for SO2 Emissions From
Onshore Natural Gas Processing for Which Construction,
Reconstruction, or Modification Commenced After January 20, 1984,
and on or Before August 23, 2011

    5. The heading for Subpart LLL is revised to read as set out above.
    6. Section 60.640 is amended by revising paragraph (d) to read as
follows:

Sec.  60.640  Applicability and designation of affected facilities.

* * * * *
    (d) The provisions of this subpart apply to each affected facility
identified in paragraph (a) of this section which commences
construction or modification after January 20, 1984, and on or before
August 23, 2011.
* * * * *
    7. Add subpart OOOO to part 60 to read as follows:
Subpart OOOO--Standards of Performance for Crude Oil and Natural Gas
Production, Transmission, and Distribution
Sec.
60.5360 What is the purpose of this subpart?
60.5365 Am I subject to this subpart?
60.5370 When must I comply with this subpart?
60.5375 What standards apply to gas wellhead affected facilities?
60.5380 What standards apply to centrifugal compressor affected
facilities?
60.5385 What standards apply to reciprocating compressor affected
facilities?
60.5390 What standards apply to pneumatic controller affected
facilities?
60.5395 What standards apply to storage vessel affected facilities?
60.5400 What VOC standards apply to affected facilities at an
onshore natural gas processing plant?
60.5401 What are the exceptions to the VOC standards for affected
facilities at onshore natural gas processing plants?
60.5402 What are the alternative emission limitations for equipment
leaks from onshore natural gas processing plants?
60.5405 What standards apply to sweetening units at onshore natural
gas processing plants?
60.5406 What test methods and procedures must I use for my
sweetening units affected facilities at onshore natural gas
processing plants?
60.5407 What are the requirements for monitoring of emissions and
operations from my sweetening unit affected facilities at onshore
natural gas processing plants?
60.5408 What is an optional procedure for measuring hydrogen sulfide
in acid gas--Tutwiler Procedure?
60.5410 How do I demonstrate initial compliance with the standards
for my

gas wellhead affected facility, my centrifugal compressor affected
facility, my reciprocating compressor affected facility, my
pneumatic controller affected facility, my storage vessel affected
facility, and my affected facilities at onshore natural gas
processing plants?
60.5415 How do I demonstrate continuous compliance with the
standards for my gas wellhead affected facility, my centrifugal
compressor affected facility, my stationary reciprocating compressor
affected facility, my pneumatic controller affected facility, my
storage vessel affected facility, and my affected facilities at
onshore natural gas processing plants?
60.5420 What are my notification, reporting, and recordkeeping
requirements?
60.5421 What are my additional recordkeeping requirements for my
affected facility subject to VOC requirements for onshore natural
gas processing plants?
60.5422 What are my additional reporting requirements for my
affected facility subject to VOC requirements for onshore natural
gas processing plants?
60.5423 What additional recordkeeping and reporting requirements
apply to my sweetening unit affected facilities at onshore natural
gas processing plants?
60.5425 What part of the General Provisions apply to me?
60.5430 What definitions apply to this subpart?
Table 1 to Subpart OOOO of Part 60--Required Minimum Initial
SO2 Emission Reduction Efficiency (Zi)
Table 2 to Subpart OOOO of Part 60--Required Minimum SO2
Emission Reduction Efficiency (Zc)
Table 3 to Subpart OOOO of Part 60--Applicability of General
Provisions to Subpart OOOO

Subpart OOOO--Standards of Performance for Crude Oil and Natural
Gas Production, Transmission, and Distribution

Sec.  60.5360  What is the purpose of this subpart?

    This subpart establishes emission standards and compliance
schedules for the control of volatile organic compounds (VOC) and
sulfur dioxide (SO2) emissions from affected facilities that
commenced construction, modification or reconstruction after August 23,
2011.

Sec.  60.5365  Am I subject to this subpart?

    If you are the owner or operator of one or more of the affected
facilities listed in paragraphs (a) through (g) of this section that
commenced construction, modification, or reconstruction after August
23, 2011 your affected facility is subject to the applicable provisions
of this subpart. For the purposes of this subpart, a well completion
operation following hydraulic fracturing or refracturing that occurs at
a gas wellhead facility that commenced construction, modification, or
reconstruction on or before August 23, 2011 is considered a
modification of the gas wellhead facility, but does not affect other
equipment, process units, storage vessels, or pneumatic devices located
at the well site.
    (a) A gas wellhead affected facility, is a single natural gas well.
    (b) A centrifugal compressor affected facility, which is defined as
a single centrifugal compressor located between the wellhead and the
city gate (as defined in Sec.  60.5430), except that a centrifugal
compressor located at a well site (as defined in Sec.  60.5430) is not
an affected facility under this subpart. For the purposes of this
subpart, your centrifugal compressor is considered to have commenced
construction on the date the compressor is installed at the facility.
    (c) A reciprocating compressor affected facility, which is defined
as a single reciprocating compressor located between the wellhead and
the city gate (as defined in Sec.  60.5430), except that a
reciprocating compressor located at a well site (as defined in Sec.
60.5430) is not an affected facility under this subpart. For the
purposes of this subpart, your reciprocating compressor is considered
to have commenced construction on the date the compressor is installed
at the facility.
    (d) A pneumatic controller affected facility, which is defined as a
single pneumatic controller.
    (e) A storage vessel affected facility, which is defined as a
single storage vessel.
    (f) Compressors and equipment (as defined in Sec.  60.5430) located
at onshore natural gas processing plants.
    (1) Each compressor in VOC service or in wet gas service is an
affected facility.
    (2) The group of all equipment, except compressors, within a
process unit is an affected facility.
    (3) Addition or replacement of equipment, as defined in Sec.
60.5430, for the purpose of process improvement that is accomplished
without a capital expenditure shall not by itself be considered a
modification under this subpart.
    (4) Equipment (as defined in Sec.  60.5430) associated with a
compressor station, dehydration unit, sweetening unit, underground
storage tank, field gas gathering system, or liquefied natural gas unit
is covered by Sec. Sec.  60.5400, 60.5401, 60.5402, 60.5421 and 60.5422
of this subpart if it is located at an onshore natural gas processing
plant. Equipment (as defined in Sec.  60.5430) not located at the
onshore natural gas processing plant site is exempt from the provisions
of Sec. Sec.  60.5400, 60.5401, 60.5402, 60.5421 and 60.5422 of this
subpart.
    (5) Affected facilities located at onshore natural gas processing
plants and described in paragraphs (f)(1) and (f)(2) of this section
are exempt from this subpart if they are subject to and controlled
according to subparts VVa, GGG or GGGa of this part.
    (g) Sweetening units located onshore that process natural gas
produced from either onshore or offshore wells.
    (1) Each sweetening unit that processes natural gas is an affected
facility; and
    (2) Each sweetening unit that processes natural gas followed by a
sulfur recovery unit is an affected facility.
    (3) Facilities that have a design capacity less than 2 long tons
per day (LT/D) of hydrogen sulfide (H2S) in the acid gas
(expressed as sulfur) are required to comply with recordkeeping and
reporting requirements specified in Sec.  60.5423(c) but are not
required to comply with Sec. Sec.  60.5405 through 60.5407 and
paragraphs 60.5410(g) and 60.5415(g) of this subpart.
    (4) Sweetening facilities producing acid gas that is completely
reinjected into oil-or-gas-bearing geologic strata or that is otherwise
not released to the atmosphere are not subject to Sec. Sec.  60.5405
through 60.5407, and Sec. Sec.  60.5410(g), 60.5415(g), and Sec.
60.5423 of this subpart.

Sec.  60.5370  When must I comply with this subpart?

    (a) You must be in compliance with the standards of this subpart no
later than the date of publication of the final rule in the Federal
Register or upon startup, whichever is later.
    (b) The provisions for exemption from compliance during periods of
startup, shutdown, and malfunctions provided for in 40 CFR 60.8(c) do
not apply to this subpart.
    (c) You are exempt from the obligation to obtain a permit under 40
CFR part 70 or 40 CFR part 71, provided you are not otherwise required
by law to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a).
Notwithstanding the previous sentence, you must continue to comply with
the provisions of this subpart.

Sec.  60.5375  What standards apply to gas wellhead affected
facilities?

    If you are the owner or operator of a gas wellhead affected
facility, you must comply with paragraphs (a) through (g) of this
section.

    (a) Except as provided in paragraph (f) of this section, for each
well completion operation with hydraulic fracturing, as defined in
Sec.  60.5430, you must control emissions by the operational procedures
found in paragraphs (a)(1) through (a)(3) of this section.
    (1) You must minimize the emissions associated with venting of
hydrocarbon fluids and gas over the duration of flowback by routing the
recovered liquids into storage vessels and routing the recovered gas
into a gas gathering line or collection system.
    (2) You must employ sand traps, surge vessels, separators, and
tanks during flowback and cleanout operations to safely maximize
resource recovery and minimize releases to the environment. All salable
quality gas must be routed to the gas gathering line as soon as
practicable.
    (3) You must capture and direct flowback emissions that cannot be
directed to the gathering line to a completion combustion device,
except in conditions that may result in a fire hazard or explosion.
Completion combustion devices must be equipped with a reliable
continuous ignition source over the duration of flowback.
    (b) You must maintain a log for each well completion operation at
each gas wellhead affected facility. The log must be completed on a
daily basis and must contain the records specified in Sec.
60.5420(c)(1)(iii).
    (c) You must demonstrate initial compliance with the standards that
apply to gas wellhead affected facilities as required by Sec.  60.5410.
    (d) You must demonstrate continuous compliance with the standards
that apply to gas wellhead affected facilities as required by Sec.
60.5415.
    (e) You must perform the required notification, recordkeeping, and
reporting as required by Sec.  60.5420.
    (f) For wells meeting the criteria for wildcat or delineation
wells, each well completion operation with hydraulic fracturing at a
gas wellhead affected facility must reduce emissions by using a
completion combustion device meeting the requirements of paragraph
(a)(3) of this section. You must also maintain records specified in
Sec.  60.5420(c)(1)(iii) for wildcat or delineation wells.

Sec.  60.5380  What standards apply to centrifugal compressor affected
facilities?

    You must comply with the standards in paragraphs (a) through (d) of
this section, as applicable for each centrifugal compressor affected
facility.
    (a) You must equip each rotating compressor shaft with a dry seal
system upon initial startup.
    (b) You must demonstrate initial compliance with the standards that
apply to centrifugal compressor affected facilities as required by
Sec.  60.5410.
    (c) You must demonstrate continuous compliance with the standards
that apply to centrifugal compressor affected facilities as required by
Sec.  60.5415.
    (d) You must perform the required notification, recordkeeping, and
reporting as required by Sec.  60.5420.

Sec.  60.5385  What standards apply to reciprocating compressor
affected facilities?

    You must comply with the standards in paragraphs (a) through (d) of
this section for each reciprocating compressor affected facility.
    (a) You must replace the reciprocating compressor rod packing
before the compressor has operated for 26,000 hours. The number of
hours of operation must be continuously monitored beginning upon
initial startup of your reciprocating compressor affected facility, or
the date of publication of the final rule in the Federal Register, or
the date of the previous reciprocating compressor rod packing
replacement, whichever is later.
    (b) You must demonstrate initial compliance with standards that
apply to reciprocating compressor affected facilities as required by
Sec.  60.5410.
    (c) You must demonstrate continuous compliance with standards that
apply to reciprocating compressor affected facilities as required by
Sec.  60.5415.
    (d) You must perform the required notification, recordkeeping, and
reporting as required by Sec.  60.5420.

Sec.  60.5390  What standards apply to pneumatic controller affected
facilities?

    For each pneumatic controller affected facility you must comply
with the VOC standards, based on natural gas as a surrogate for VOC, in
either paragraph (b) or (c) of this section, as applicable. Pneumatic
controllers meeting the conditions in paragraph (a) are exempt from
this requirement.
    (a) The requirements of paragraph (b) or (c) of this section are
not required if you demonstrate, to the Administrator's satisfaction,
that the use of a high bleed device is predicated. The demonstration
may include, but is not limited to, response time, safety and
actuation.
    (b) Each pneumatic controller affected facility located at a
natural gas processing plant (as defined in Sec.  60.5430) must have
zero emissions of natural gas.
    (c) Each pneumatic controller affected facility not located at a
natural gas processing plant (as defined in Sec.  60.5430) must have
natural gas emissions no greater than 6 standard cubic feet per hour.
    (d) You must demonstrate initial compliance with standards that
apply to pneumatic controller affected facilities as required by Sec.
60.5410.
    (e) You must demonstrate continuous compliance with standards that
apply to pneumatic controller affected facilities as required by Sec.
60.5415.
    (f) You must perform the required notification, recordkeeping, and
reporting as required by Sec.  60.5420, except that you are not
required to submit the notifications specified in Sec.  60.5420(a).

Sec.  60.5395  What standards apply to storage vessel affected
facilities?

    You must comply with the standards in paragraphs (a) through (e) of
this section for each storage vessel affected facility.
    (a) You must comply with the standards for storage vessels
specified in Sec.  63.766(b) and (c) of this chapter, except as
specified in paragraph (b) of this section. Storage vessels that meet
either one or both of the throughput conditions specified in paragraphs
(a)(1) or (a)(2) of this section are not subject to the standards of
this section.
    (1) The annual average condensate throughput is less than 1 barrel
per day per storage vessel.
    (2) The annual average crude oil throughput is less than 20 barrels
per day per storage vessel.
    (b) This standard does not apply to storage vessels already subject
to and controlled in accordance with the requirements for storage
vessels in Sec.  63.766(b)(1) or (2) of this chapter.
    (c) You must demonstrate initial compliance with standards that
apply to storage vessel affected facilities as required by Sec.
60.5410.
    (d) You must demonstrate continuous compliance with standards that
apply to storage vessel affected facilities as required by Sec.
60.5415.
    (e) You must perform the required notification, recordkeeping, and
reporting as required by Sec.  60.5420.

Sec.  60.5400  What VOC standards apply to affected facilities at an
onshore natural gas processing plant?

    This section applies to each compressor in VOC service or in wet
gas service and the group of all equipment (as defined in Sec.
60.5430), except compressors, within a process unit.
    (a) You must comply with the requirements of Sec.  60.482-1a(a),
(b), and (d), Sec.  60.482-2a, and Sec.  60.482-4a through 60.482-11a,
except as provided in Sec.  60.5401.

    (b) You may elect to comply with the requirements of Sec. Sec.
60.483-1a and 60.483-2a, as an alternative.
    (c) You may apply to the Administrator for permission to use an
alternative means of emission limitation that achieves a reduction in
emissions of VOC at least equivalent to that achieved by the controls
required in this subpart according to the requirements of Sec.  60.5402
of this subpart.
    (d) You must comply with the provisions of Sec.  60.485a of this
part except as provided in paragraph (f) of this section.
    (e) You must comply with the provisions of Sec. Sec.  60.486a and
60.487a of this part except as provided in Sec. Sec.  60.5401, 60.5421,
and 60.5422 of this part.
    (f) You must use the following provision instead of Sec.
60.485a(d)(1): Each piece of equipment is presumed to be in VOC service
or in wet gas service unless an owner or operator demonstrates that the
piece of equipment is not in VOC service or in wet gas service. For a
piece of equipment to be considered not in VOC service, it must be
determined that the VOC content can be reasonably expected never to
exceed 10.0 percent by weight. For a piece of equipment to be
considered in wet gas service, it must be determined that it contains
or contacts the field gas before the extraction step in the process.
For purposes of determining the percent VOC content of the process
fluid that is contained in or contacts a piece of equipment, procedures
that conform to the methods described in ASTM E169-63, 77, or 93, E168-
67, 77, or 92, or E260-73, 91, or 96 (incorporated by reference as
specified in Sec.  60.17) must be used.

Sec.  60.5401  What are the exceptions to the VOC standards for
affected facilities at onshore natural gas processing plants?

    (a) You may comply with the following exceptions to the provisions
of subpart VVa of this part.
    (b)(1) Each pressure relief device in gas/vapor service may be
monitored quarterly and within 5 days after each pressure release to
detect leaks by the methods specified in Sec.  60.485a(b) except as
provided in Sec.  60.5400(c) and in paragraph (b)(4) of this section,
and Sec.  60.482-4a(a) through (c) of subpart VVa.
    (2) If an instrument reading of 5000 ppm or greater is measured, a
leak is detected.
    (3)(i) When a leak is detected, it must be repaired as soon as
practicable, but no later than 15 calendar days after it is detected,
except as provided in Sec.  60.482-9a.
    (ii) A first attempt at repair must be made no later than 5
calendar days after each leak is detected.
    (4)(i) Any pressure relief device that is located in a
nonfractionating plant that is monitored only by non-plant personnel
may be monitored after a pressure release the next time the monitoring
personnel are on-site, instead of within 5 days as specified in
paragraph (b)(1) of this section and Sec.  60.482-4a(b)(1) of subpart
VVa.
    (ii) No pressure relief device described in paragraph (b)(4)(i) of
this section must be allowed to operate for more than 30 days after a
pressure release without monitoring.
    (c) Sampling connection systems are exempt from the requirements of
Sec.  60.482-5a.
    (d) Pumps in light liquid service, valves in gas/vapor and light
liquid service, and pressure relief devices in gas/vapor service that
are located at a nonfractionating plant with a design capacity to
process 283,200 standard cubic meters per day (scmd) (10 million
standard cubic feet per day) or more of field gas are exempt from the
routine monitoring requirements of Sec. Sec.  60.482-2a(a)(1) and
60.482-7a(a), and paragraph (b)(1) of this section.
    (e) Pumps in light liquid service, valves in gas/vapor and light
liquid service, and pressure relief devices in gas/vapor service within
a process unit that is located in the Alaskan North Slope are exempt
from the routine monitoring requirements of Sec. Sec.  60.482-2a(a)(1),
60.482-7a(a), and paragraph (b)(1) of this section.
    (f) Flares used to comply with this subpart must comply with the
requirements of Sec.  60.18.
    (g) An owner or operator may use the following provisions instead
of Sec.  60.485a(e):
    (1) Equipment is in heavy liquid service if the weight percent
evaporated is 10 percent or less at 150 [deg]C (302 [deg]F) as
determined by ASTM Method D86-78, 82, 90, 95, or 96 (incorporated by
reference as specified in Sec.  60.17).
    (2) Equipment is in light liquid service if the weight percent
evaporated is greater than 10 percent at 150 [deg]C (302 [deg]F) as
determined by ASTM Method D86-78, 82, 90, 95, or 96 (incorporated by
reference as specified in Sec.  60.17).

Sec.  60.5402  What are the alternative emission limitations for
equipment leaks from onshore natural gas processing plants?

    (a) If, in the Administrator's judgment, an alternative means of
emission limitation will achieve a reduction in VOC emissions at least
equivalent to the reduction in VOC emissions achieved under any design,
equipment, work practice or operational standard, the Administrator
will publish, in the Federal Register, a notice permitting the use of
that alternative means for the purpose of compliance with that
standard. The notice may condition permission on requirements related
to the operation and maintenance of the alternative means.
    (b) Any notice under paragraph (a) of this section must be
published only after notice and an opportunity for a public hearing.
    (c) The Administrator will consider applications under this section
from either owners or operators of affected facilities, or
manufacturers of control equipment.
    (d) The Administrator will treat applications under this section
according to the following criteria, except in cases where the
Administrator concludes that other criteria are appropriate:
    (1) The applicant must collect, verify and submit test data,
covering a period of at least 12 months, necessary to support the
finding in paragraph (a) of this section.
    (2) If the applicant is an owner or operator of an affected
facility, the applicant must commit in writing to operate and maintain
the alternative means so as to achieve a reduction in VOC emissions at
least equivalent to the reduction in VOC emissions achieved under the
design, equipment, work practice or operational standard.

Sec.  60.5405  What standards apply to sweetening units at onshore
natural gas processing plants?

    (a) During the initial performance test required by Sec.  60.8(b),
you must achieve at a minimum, an SO2 emission reduction
efficiency (Zi) to be determined from Table 1 of this
subpart based on the sulfur feed rate (X) and the sulfur content of the
acid gas (Y) of the affected facility.
    (b) After demonstrating compliance with the provisions of paragraph
(a) of this section, you must achieve at a minimum, an SO2
emission reduction efficiency (Zc) to be determined from
Table 2 of this subpart based on the sulfur feed rate (X) and the
sulfur content of the acid gas (Y) of the affected facility.

60.5406  What test methods and procedures must I use for my sweetening
units affected facilities at onshore natural gas processing plants?

    (a) In conducting the performance tests required in Sec.  60.8, you
must use

the test methods in Appendix A of this part or other methods and
procedures as specified in this section, except as provided in
paragraph Sec.  60.8(b).
    (b) During a performance test required by Sec.  60.8, you must
determine the minimum required reduction efficiencies (Z) of
SO2 emissions as required in Sec.  60.5405(a) and (b) as
follows:
    (1) The average sulfur feed rate (X) must be computed as follows:

X - KQa[gamma]

Where:

X = average sulfur feed rate, Mg/D (LT/D).
Qa = average volumetric flow rate of acid gas from
sweetening unit, dscm/day (dscf/day).
Y = average H2S concentration in acid gas feed from
sweetening unit, percent by volume, expressed as a decimal.
K = (32 kg S/kg-mole) / ((24.04 dscm/kg-mole) (1000 kg S/Mg))
    = 1.331 x 10-3 Mg/dscm, for metric units
    = (32 lb S/lb-mole) / ((385.36 dscf/lb-mole) (2240 lb S/long
ton))
= 3.707 x 10-5 long ton/dscf, for English units.

    (2) You must use the continuous readings from the process flowmeter
to determine the average volumetric flow rate (Qa) in dscm/
day (dscf/day) of the acid gas from the sweetening unit for each run.
    (3) You must use the Tutwiler procedure in Sec.  60.5408 or a
chromatographic procedure following ASTM E-260 (incorporated by
reference--see Sec.  60.17) to determine the H2S
concentration in the acid gas feed from the sweetening unit (Y). At
least one sample per hour (at equally spaced intervals) must be taken
during each 4-hour run. The arithmetic mean of all samples must be the
average H2S concentration (Y) on a dry basis for the run. By
multiplying the result from the Tutwiler procedure by 1.62 x
10-3, the units gr/100 scf are converted to volume percent.
    (4) Using the information from paragraphs (b)(1) and (b)(3) of this
section, Tables 1 and 2 of this subpart must be used to determine the
required initial (Zi) and continuous (Zc)
reduction efficiencies of SO2 emissions.
    (c) You must determine compliance with the SO2 standards
in Sec.  60.5405(a) or (b) as follows:
    (1) You must compute the emission reduction efficiency (R) achieved
by the sulfur recovery technology for each run using the following
equation:
[GRAPHIC] [TIFF OMITTED] TP23AU11.005

    (2) You must use the level indicators or manual soundings to
measure the liquid sulfur accumulation rate in the product storage
tanks. You must use readings taken at the beginning and end of each
run, the tank geometry, sulfur density at the storage temperature, and
sample duration to determine the sulfur production rate (S) in kg/hr
(lb/hr) for each run.
    (3) You must compute the emission rate of sulfur for each run as
follows:
[GRAPHIC] [TIFF OMITTED] TP23AU11.006

Where:

E = emission rate of sulfur per run, kg/hr.
Ce = concentration of sulfur equivalent (SO2 +
reduced sulfur), g/dscm (lb/dscf).
Qsd = volumetric flow rate of effluent gas, dscm/hr
(dscf/hr).
K1 = conversion factor, 1000 g/kg (7000 gr/lb).

    (4) The concentration (Ce) of sulfur equivalent must be
the sum of the SO2 and TRS concentrations, after being
converted to sulfur equivalents. For each run and each of the test
methods specified in this paragraph (c) of this section, you must use a
sampling time of at least 4 hours. You must use Method 1 of Appendix A
to part 60 of this chapter to select the sampling site. The sampling
point in the duct must be at the centroid of the cross-section if the
area is less than 5 m\2\ (54 ft\2\) or at a point no closer to the
walls than 1 m (39 in) if the cross-sectional area is 5 m\2\ or more,
and the centroid is more than 1 m (39 in.) from the wall.
    (i) You must use Method 6 of Appendix A to part 60 of this chapter
to determine the SO2 concentration. You must take eight
samples of 20 minutes each at 30-minute intervals. The arithmetic
average must be the concentration for the run. The concentration must
be multiplied by 0.5 x 10-3 to convert the results to sulfur
equivalent.
    (ii) You must use Method 15 of appendix A to part 60 of this
chapter to determine the TRS concentration from reduction-type devices
or where the oxygen content of the effluent gas is less than 1.0
percent by volume. The sampling rate must be at least 3 liters/min (0.1
ft\3\/min) to insure minimum residence time in the sample line. You
must take sixteen samples at 15-minute intervals. The arithmetic
average of all the samples must be the concentration for the run. The
concentration in ppm reduced sulfur as sulfur must be multiplied by
1.333 x 10-3 to convert the results to sulfur equivalent.
    (iii) You must use Method 16A or Method 15 of appendix A to part 60
of this chapter to determine the reduced sulfur concentration from
oxidation-type devices or where the oxygen content of the effluent gas
is greater than 1.0 percent by volume. You must take eight samples of
20 minutes each at 30-minute intervals. The arithmetic average must be
the concentration for the run. The concentration in ppm reduced sulfur
as sulfur must be multiplied by 1.333 x 10-3 to convert the
results to sulfur equivalent.
    (iv) You must use Method 2 of appendix A to part 60 of this chapter
to determine the volumetric flow rate of the effluent gas. A velocity
traverse must be conducted at the beginning and end of each run. The
arithmetic average of the two measurements must be used to calculate
the volumetric flow rate (Qsd) for the run. For the
determination of the effluent gas molecular weight, a single integrated
sample over the 4-hour period may be taken and analyzed or grab samples
at 1-hour intervals may be taken, analyzed, and averaged. For the
moisture content, you must take two samples of at least 0.10 dscm (3.5
dscf) and 10 minutes at the beginning of the 4-hour run and near the
end of the time period. The arithmetic average of the two runs must be
the moisture content for the run.

Sec.  60.5407  What are the requirements for monitoring of emissions
and operations from my sweetening unit affected facilities at onshore
natural gas processing plants?

    (a) If your sweetening unit affected facility is located at an
onshore natural gas processing plant and is subject to the provisions
of Sec.  60.5405(a) or (b) you must install, calibrate, maintain, and
operate monitoring devices or perform measurements to determine the
following operations information on a daily basis:
    (1) The accumulation of sulfur product over each 24-hour period.
The monitoring method may incorporate the use of an instrument to
measure and record the liquid sulfur production rate, or may be a
procedure for measuring and recording the sulfur liquid levels in the
storage tanks with a level indicator or by manual soundings, with
subsequent calculation of the sulfur production rate based on the tank
geometry, stored sulfur density, and elapsed time between readings. The
method must be designed to be accurate within  2 percent of
the 24-hour sulfur accumulation.
    (2) The H2S concentration in the acid gas from the sweetening unit
for each 24-hour period. At least one sample per 24-hour period must be
collected and analyzed using the equation specified in Sec.
60.5406(b)(1). The Administrator may require you to demonstrate that
the H2S concentration obtained from one or more samples over
a 24-hour period is

within  20 percent of the average of 12 samples collected
at equally spaced intervals during the 24-hour period. In instances
where the H2S concentration of a single sample is not within
 20 percent of the average of the 12 equally spaced
samples, the Administrator may require a more frequent sampling
schedule.
    (3) The average acid gas flow rate from the sweetening unit. You
must install and operate a monitoring device to continuously measure
the flow rate of acid gas. The monitoring device reading must be
recorded at least once per hour during each 24-hour period. The average
acid gas flow rate must be computed from the individual readings.
    (4) The sulfur feed rate (X). For each 24-hour period, you must
compute X using the equation specified in Sec.  60.5406(b)(3).
    (5) The required sulfur dioxide emission reduction efficiency for
the 24-hour period. You must use the sulfur feed rate and the
H2S concentration in the acid gas for the 24-hour period, as
applicable, to determine the required reduction efficiency in
accordance with the provisions of Sec.  60.5405(b).
    (b) Where compliance is achieved through the use of an oxidation
control system or a reduction control system followed by a continually
operated incineration device, you must install, calibrate, maintain,
and operate monitoring devices and continuous emission monitors as
follows:
    (1) A continuous monitoring system to measure the total sulfur
emission rate (E) of SO2 in the gases discharged to the atmosphere. The
SO2 emission rate must be expressed in terms of equivalent
sulfur mass flow rates (kg/hr (lb/hr)). The span of this monitoring
system must be set so that the equivalent emission limit of Sec.
60.5405(b) will be between 30 percent and 70 percent of the measurement
range of the instrument system.
    (2) Except as provided in paragraph (b)(3) of this section: A
monitoring device to measure the temperature of the gas leaving the
combustion zone of the incinerator, if compliance with Sec.  60.5405(a)
is achieved through the use of an oxidation control system or a
reduction control system followed by a continually operated
incineration device. The monitoring device must be certified by the
manufacturer to be accurate to within  1 percent of the
temperature being measured.
    (3) When performance tests are conducted under the provision of
Sec.  60.8 to demonstrate compliance with the standards under Sec.
60.5405, the temperature of the gas leaving the incinerator combustion
zone must be determined using the monitoring device. If the volumetric
ratio of sulfur dioxide to sulfur dioxide plus total reduced sulfur
(expressed as SO2) in the gas leaving the incinerator is
equal to or less than 0.98, then temperature monitoring may be used to
demonstrate that sulfur dioxide emission monitoring is sufficient to
determine total sulfur emissions. At all times during the operation of
the facility, you must maintain the average temperature of the gas
leaving the combustion zone of the incinerator at or above the
appropriate level determined during the most recent performance test to
ensure the sulfur compound oxidation criteria are met. Operation at
lower average temperatures may be considered by the Administrator to be
unacceptable operation and maintenance of the affected facility. You
may request that the minimum incinerator temperature be reestablished
by conducting new performance tests under Sec.  60.8.
    (4) Upon promulgation of a performance specification of continuous
monitoring systems for total reduced sulfur compounds at sulfur
recovery plants, you may, as an alternative to paragraph (b)(2) of this
section, install, calibrate, maintain, and operate a continuous
emission monitoring system for total reduced sulfur compounds as
required in paragraph (d) of this section in addition to a sulfur
dioxide emission monitoring system. The sum of the equivalent sulfur
mass emission rates from the two monitoring systems must be used to
compute the total sulfur emission rate (E).
    (c) Where compliance is achieved through the use of a reduction
control system not followed by a continually operated incineration
device, you must install, calibrate, maintain, and operate a continuous
monitoring system to measure the emission rate of reduced sulfur
compounds as SO2 equivalent in the gases discharged to the
atmosphere. The SO2 equivalent compound emission rate must
be expressed in terms of equivalent sulfur mass flow rates (kg/hr (lb/
hr)). The span of this monitoring system must be set so that the
equivalent emission limit of Sec.  60.5405(b) will be between 30 and 70
percent of the measurement range of the system. This requirement
becomes effective upon promulgation of a performance specification for
continuous monitoring systems for total reduced sulfur compounds at
sulfur recovery plants.
    (d) For those sources required to comply with paragraph (b) or (c)
of this section, you must calculate the average sulfur emission
reduction efficiency achieved (R) for each 24-hour clock internal. The
24-hour interval may begin and end at any selected clock time, but must
be consistent. You must compute the 24-hour average reduction
efficiency (R) based on the 24-hour average sulfur production rate (S)
and sulfur emission rate (E), using the equation in Sec.
60.5406(c)(1).
    (1) You must use data obtained from the sulfur production rate
monitoring device specified in paragraph (a) of this section to
determine S.
    (2) You must use data obtained from the sulfur emission rate
monitoring systems specified in paragraphs (b) or (c) of this section
to calculate a 24-hour average for the sulfur emission rate (E). The
monitoring system must provide at least one data point in each
successive 15-minute interval. You must use at least two data points to
calculate each 1-hour average. You must use a minimum of 18 1-hour
averages to compute each 24-hour average.
    (e) In lieu of complying with paragraphs (b) or (c) of this
section, those sources with a design capacity of less than 152 Mg/D
(150 LT/D) of H2S expressed as sulfur may calculate the
sulfur emission reduction efficiency achieved for each 24-hour period
by:
[GRAPHIC] [TIFF OMITTED] TP23AU11.000

Where:

R = The sulfur dioxide removal efficiency achieved during the 24-
hour period, percent.
K2 = Conversion factor, 0.02400 Mg/D per kg/hr (0.01071
LT/D per lb/hr).
S = The sulfur production rate during the 24-hour period, kg/hr (lb/
hr).
X = The sulfur feed rate in the acid gas, Mg/D (LT/D).

    (f) The monitoring devices required in paragraphs (b)(1), (b)(3)
and (c) of this section must be calibrated at least annually according
to the manufacturer's specifications, as required by Sec.  60.13(b).
    (g) The continuous emission monitoring systems required in
paragraphs (b)(1), (b)(3), and (c) of this section must be subject to
the emission monitoring requirements of Sec.  60.13 of the General
Provisions. For conducting the continuous emission monitoring system
performance evaluation required by Sec.  60.13(c), Performance
Specification 2 of appendix B to part 60 of this chapter must apply,
and Method 6 must be used for systems required by paragraph (b) of this
section.

Sec.  60.5408  What is an optional procedure for measuring hydrogen
sulfide in acid gas--Tutwiler Procedure? \1\
---------------------------------------------------------------------------

    \1\ Gas Engineers Handbook, Fuel Gas Engineering practices, The
Industrial Press, 93 Worth Street, New York, NY, 1966, First
Edition, Second Printing, page 6/25 (Docket A-80-20-A, Entry II-I-
67).
---------------------------------------------------------------------------

    (a) When an instantaneous sample is desired and H2S
concentration is ten grains per 1000 cubic foot or more, a 100 ml
Tutwiler burette is used. For concentrations less than ten grains, a
500 ml Tutwiler burette and more dilute solutions are used. In
principle, this method consists of titrating hydrogen sulfide in a gas
sample directly with a standard solution of iodine.
    (b) Apparatus. (See Figure 1 of this subpart) A 100 or 500 ml
capacity Tutwiler burette, with two-way glass stopcock at bottom and
three-way stopcock at top which connect either with inlet tubulature or
glass-stoppered cylinder, 10 ml capacity, graduated in 0.1 ml
subdivision; rubber tubing connecting burette with leveling bottle.
    (c) Reagents. (1) Iodine stock solution, 0.1N. Weight 12.7 g
iodine, and 20 to 25 g cp potassium iodide for each liter of solution.
Dissolve KI in as little water as necessary; dissolve iodine in
concentrated KI solution, make up to proper volume, and store in glass-
stoppered brown glass bottle.
    (2) Standard iodine solution, 1 ml = 0.001771 g I. Transfer 33.7 ml
of above 0.1N stock solution into a 250 ml volumetric flask; add water
to mark and mix well. Then, for 100 ml sample of gas, 1 ml of standard
iodine solution is equivalent to 100 grains H2S per cubic
feet of gas.
    (3) Starch solution. Rub into a thin paste about one teaspoonful of
wheat starch with a little water; pour into about a pint of boiling
water; stir; let cool and decant off clear solution. Make fresh
solution every few days.
    (d) Procedure. Fill leveling bulb with starch solution. Raise (L),
open cock (G), open (F) to (A), and close (F) when solutions starts to
run out of gas inlet. Close (G). Purge gas sampling line and connect
with (A). Lower (L) and open (F) and (G). When liquid level is several
ml past the 100 ml mark, close (G) and (F), and disconnect sampling
tube. Open (G) and bring starch solution to 100 ml mark by raising (L);
then close (G). Open (F) momentarily, to bring gas in burette to
atmospheric pressure, and close (F). Open (G), bring liquid level down
to 10 ml mark by lowering (L). Close (G), clamp rubber tubing near (E)
and disconnect it from burette. Rinse graduated cylinder with a
standard iodine solution (0.00171 g I per ml); fill cylinder and record
reading. Introduce successive small amounts of iodine thru (F); shake
well after each addition; continue until a faint permanent blue color
is obtained. Record reading; subtract from previous reading, and call
difference D.
    (e) With every fresh stock of starch solution perform a blank test
as follows: Introduce fresh starch solution into burette up to 100 ml
mark. Close (F) and (G). Lower (L) and open (G). When liquid level
reaches the 10 ml mark, close (G). With air in burette, titrate as
during a test and up to same end point. Call ml of iodine used C. Then,

Grains H2S per 100 cubic foot of gas = 100 (D-C)
    (f) Greater sensitivity can be attained if a 500 ml capacity
Tutwiler burette is used with a more dilute (0.001N) iodine solution.
Concentrations less than 1.0 grains per 100 cubic foot can be
determined in this way. Usually, the starch-iodine end point is much
less distinct, and a blank determination of end point, with
H2S-free gas or air, is required.
BILLING CODE 6560-50-P

[GRAPHIC] [TIFF OMITTED] TP23AU11.001

BILLING CODE 6560-50-C

Sec.  60.5410  How do I demonstrate initial compliance with the
standards for my gas wellhead affected facility, my centrifugal
compressor affected facility, my reciprocating compressor affected
facility, my pneumatic controller affected facility, my storage vessel
affected facility, and my affected facilities at onshore natural gas
processing plants?

    You must determine initial compliance with the standards for each
affected facility using the requirements in paragraphs (a) through (g)
of this section. The initial compliance period begins on the date of
publication of the final rule in the Federal Register or upon initial
startup, whichever is later, and ends on the date the first annual
report is due as specified in Sec.  60.5420(b).
    (a) You have achieved initial compliance with standards for each
well completion operation conducted at your gas wellhead affected
facility if you have complied with paragraphs (a)(1) and (a)(2) of this
section.
    (1) You have notified the Administrator within 30 days of the
commencement of the well completion operation, the date of the
commencement of the well completion operation, the latitude and
longitude coordinates of the well in decimal degrees to an accuracy and
precision of five (5) decimals of a degree using the North American
Datum (NAD) of 1983.
    (2) You have maintained a log of records as specified in Sec.
60.5375(b) or (f) for each well completion operation conducted during
the initial compliance period.

    (3) You have submitted the initial annual report for your wellhead
affected facility as required in Sec.  60.5420(b).
    (b) You have achieved initial compliance with standards for your
centrifugal compressor affected facility if the centrifugal compressor
is fitted with a dry seal system upon initial startup as required by
Sec.  60.5380.
    (c) You have achieved initial compliance with standards for each
reciprocating compressor affected facility if you have complied with
paragraphs (c)(1) and (c)(2) of this section.
    (1) During the initial compliance period, you have continuously
monitored the number of hours of operation.
    (2) You have included the cumulative number of hours of operation
for your reciprocating compressor affected facility during the initial
compliance period in your initial annual report required in Sec.
60.5420(b).
    (d) You have achieved initial compliance with emission standards
for your pneumatic controller affected facility if you comply with the
requirements specified in paragraphs (d)(1) through (d)(4) of this
section.
    (1) You have demonstrated, to the Administrator's satisfaction, the
use of a high bleed device is predicated as specified in Sec.
60.5490(a).
    (2) You own or operate a pneumatic controller affected facility
located at a natural gas processing plant and your pneumatic controller
is driven other than by use of natural gas and therefore emits zero
natural gas.
    (3) You own or operate a pneumatic controller affected facility not
located at a natural gas processing plant and the manufacturer's design
specifications guarantee the controller emits less than or equal to 6.0
standard cubic feet of gas per hour.
    (4) You have included the information in paragraphs (d)(1) through
(d)(3) of this section in the initial annual report submitted for your
pneumatic controller affected facilities according to the requirements
of Sec.  60.5420(b).
    (e) You have demonstrated initial compliance with emission
standards for your storage vessel affected facility if you are
complying with paragraphs (e)(1) through (e)(7) of this section.
    (1) You have equipped the storage vessel with a closed vent system
that meets the requirements of Sec.  63.771(c) of this chapter
connected to a control device that meets the conditions specified in
Sec.  63.771(d).
    (2) You have conducted an initial performance test as required in
Sec.  63.772(e) of this chapter within 180 days after initial startup
or the date of publication of the final rule in the Federal Register
and have conducted the compliance demonstration in Sec.  63.772(f).
    (3) You have conducted the initial inspections required in Sec.
63.773(c) of this chapter.
    (4) You have installed and operated continuous parameter monitoring
systems in accordance with Sec.  63.773(d) of this chapter.
    (5) If you are exempt from the standards of Sec.  60.5395 according
to Sec.  60.5395(a)(1) or (a)(2), you have determined the condensate or
crude oil throughput, as applicable, according to paragraphs (e)(5)(i)
or (e)(5)(ii) of this section and demonstrated to the Administrator's
satisfaction that your annual average condensate throughput is less
than 1 barrel per day per tank and your annual average crude oil
throughput is less than 20 barrels per day per tank.
    (i) You have installed and operated a flow meter to measure
condensate or crude oil throughput in accordance with the
manufacturer's procedures or specifications.
    (ii) You have used any other method approved by the Administrator
to determine annual average condensate or crude oil throughput.
    (6) You have submitted the information in paragraphs (e)(1) through
(e)(5) of this section in the initial annual report for your storage
vessel affected facility as required in Sec.  60.5420(b).
    (f) For affected facilities at onshore natural gas processing
plants, initial compliance with the VOC requirements is demonstrated if
you are in compliance with the requirements of Sec.  60.5400.
    (g) For sweetening unit affected facilities at onshore natural gas
processing plants, initial compliance is demonstrated according to
paragraphs (g)(1) through (g)(3) of this section.
    (1) To determine compliance with the standards for SO2
specified in Sec.  60.5405(a), during the initial performance test as
required by Sec.  60.8, the minimum required sulfur dioxide emission
reduction efficiency (Zi) is compared to the emission
reduction efficiency (R) achieved by the sulfur recovery technology as
specified in paragraphs (g)(1)(i) and (g)(1)(ii) of this section.
    (i) If R >= Zi, your affected facility is in compliance.
    (ii) If R < Zi, your affected facility is not in
compliance.
    (2) The emission reduction efficiency (R) achieved by the sulfur
reduction technology must be determined using the procedures in Sec.
60.5406(c)(1).
    (3) You have submitted the results of paragraphs (g)(1) and (g)(2)
of this section in the initial annual report submitted for your
sweetening unit affected facilities at onshore natural gas processing
plants.

Sec.  60.5415  How do I demonstrate continuous compliance with the
standards for my gas wellhead affected facility, my centrifugal
compressor affected facility, my stationary reciprocating compressor
affected facility, my pneumatic controller affected facility, my
storage vessel affected facility, and my affected facilities at onshore
natural gas processing plants?

    (a) For each gas wellhead affected facility, you must demonstrate
continuous compliance by maintaining the records for each completion
operation (as defined in Sec.  60.5430) specified in Sec.  60.5420.
    (b) For each centrifugal compressor affected facility, continuous
compliance is demonstrated if the rotating compressor shaft is equipped
with a dry seal.
    (c) For each reciprocating compressor affected facility, you have
demonstrated continuous compliance according to paragraphs (c)(1) and
(2) of this section
    (1) You have continuously monitored the number of hours of
operation for each reciprocating compressor affected facility since
initial startup, or the date of publication of the final rule in the