Frequently Asked Questions Subpart W Petroleum and Natural Gas Production


Frequently Asked Questions

£EPA

Subpart W: Petroleum and Natural Gas Production

United States
Environmental Protection
Agency

Offshore Petroleum and Natural Gas Production

Question: Please clarify whether the final rule amending 40 CFR Part 98 applies to both
onshore and offshore.

Response: On November 8, 2010, EPA signed 40 CFR part 98, subpart W; a rule that finalizes
reporting requirements for the petroleum and natural gas industry. This final rule covers both
offshore and onshore petroleum and natural gas production facilities. Please review section
98.230 for the definition of the source category for each segment of the petroleum and natural
gas industry covered by subpart. Information and resources regarding the applicability and
requirements of subpart W are available

at: http://www.epa.gOv/climatechange/emissions/subpart/w.html

Question: According to § 98.238, offshore means seaward of the terrestrial borders of the
United States, including waters subject to the ebb and flow of the tide, as well as adjacent
bays, lakes or other normally standing waters, and extending to the outer boundaries of the
jurisdiction and control of the United States under the Outer Continental Shelf Lands Act.

*	What is terrestrial border?

*	In south Louisiana most sites are located within the State boundaries in lakes, bays, and
bayous (not in Federal waters). These waters are subject to the ebb and flow of the tide. In
some cases these sites are 150 miles north of the Gulf of Mexico. The sites are over water on
platforms built on pilings. Are these sites considered offshore or onshore sites?

Response: The definition for offshore in § 98.238 includes "lakes or other normally standing
waters", therefore, sites located in lakes, bays, etc are considered offshore.

Question: Is it correct to conclude that emissions from stationary sources of fuel
combustion are to be quantified and reported in accordance with the methodologies
specified in 40 CFR Part 98 Subpart C and not as described in BOEMRE's GOADS instructions?

Response:

EPA confirms that stationary sources of fuel combustion, except flares, must be reported using
methodologies specified in 40 CFR Part 98 Subpart C; flare emissions have to be reported under
subpart W, consistent with BOEMRE (30 CFR 250.302 through 304).

Question: Offshore petroleum and natural gas production facility reported in the GOADS
2008 report, GHG emissions were <25,000 metric tons C02e from equipment leaks, vented
emissions and flare emissions based on GOADS calculation methodology AND stationary

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combustion sources (i.e., sum of all GHG C02e - Subpart W and Subpart C sources). Assume
that actual 2011 GHG emissions were >25,000 metric tons of C02e (Subpart W - GOADS
method and Subpart C sources) for the facility.

a. Does this facility have to report GHG emissions for 2011 reporting year?

Response: If emissions in 2011 are 25,000 tons C02e or more for all sources covered by the
greenhouse gas reporting rule, in this case sources under subparts C and W, then the facility
must report. §98.233(s)(l)(i) also indicates that if the calendar year does not overlap with the
most recent BOEMRE emissions study publication year, the reporter must use the most recent
BOEMRE reported emission data and "adjust emissions based on the operating time for the
facility relative to the operating time in the most recent BOEMRE published study." Therefore,
if reported 2008 emissions, adjusted for any differences in 2011 operating time, are 25,000 tons
C02e or more, then the facility must report for calendar year 2011.

Question: An offshore petroleum and natural gas production facility emits the following
during 2011; note that the facility was NOT operating during 2008 and so no GOADS 2008
data available.

a.	20,000 metric tons C02e from equipment leaks, vented emissions and flare emissions
based on GOADS calculation methodology

b.	10,000 metric tons C02e from stationary combustion sources based on 40 CFR 98 Subpart C
calculation methodology

c.	Would this facility be required to report GHG emissions during 2011?

Response: Yes. The facility is identified as not being in GOADS in 2008, however, the total
emissions from the facility is greater than 25,000 metric tons C02e. §98.233(s)(4) states that
"for either first or subsequent year reporting, offshore facilities either within or outside of
BOEMRE jurisdiction that were not covered in the previous BOEMRE data collection cycle shall
use the most recent BOEMRE data collection and emissions estimation methods published by
BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report emissions (GOADS)
to report emissions". Also, 98.2(a)(2) (as referenced in 98.231(a)) states that "a facility that
contains any source category that is listed in Table A-4 of this subpart that emits 25,000 metric
tons C02e or more per year in combined emissions from stationary fuel combustion units,
miscellaneous uses of carbonate, and all applicable source categories that are listed in Tables A-
3 and Table A-4 of this subpart." Therefore, based on the information provided, this facility is
required to report equipment leaks, vented emissions and flare emissions under subpart W and
stationary combustion emissions under subpart C for calendar year 2011.

Question: For offshore petroleum and natural gas production facilities under
§98.233(s)(l)(i), the GHGRP states that these facilities shall report the same annual emissions
as calculated and reported by BOEMRE and that any calendar year that overlaps with the
most recent study publication year, the most recent BOEMRE reported emissions data should

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be used. We understand this to mean that for the 2011 reporting year, we can use 2011
BOEMRE data, rather that the previously available data from 2008. Please confirm that this is
an acceptable approach.

Response: BOEMRE typically publishes a GOADS study after March 31 of the year following
the data collection. Therefore, for Subpart W reporting year 2011, offshore reporters subject to
BOEMRE must use the latest BOEMRE published emissions data (most likely 2008, as the 2011
GOADS report may not be available until after the March 31, 2012 reporting for subpart W). As
a further clarification, the reporters will report under Subpart W for 2011 using the BOEMRE
methodologies published in 30 CFR 250.302 through 304 with the latest BOEMRE emissions
data. In subsequent years, reporters in state and non-Gulf of Mexico waters will report using
the GOADS methodologies published in 30 CFR 250.302 through 304, which historically have
been published along with the GOADS emissions data.

Question: If an offshore oil & gas production platform/facility is farther out in the ocean
than the limit of state waters (as defined by the Submerged Lands Act), does that facility have
to report 2010 emissions data to EPA for Subpart C?

Response: As provided in guidance during 2010 for offshore platforms, for the purposes of
2010 reporting for subpart C jurisdiction is based on the Submerged Lands Act of 2002 (43
U.S.C. §§1301-1315 (2002) and the Territorial Submerged Lands Act (48 U.S.C. 1705). Generally,
their breadth depends on the state in whose jurisdiction the platform is located. Jurisdictions of
Texas and the Gulf coast of Florida are extended 3 marine leagues seaward from the baseline
from which the breadth of the territorial sea is measured, Louisiana's jurisdiction is extended 3
imperial nautical miles seaward from the baseline from which the breadth of the territorial sea
is measured, other state's seaward limits are extended 3 geographic miles seaward from the
baseline from which the breadth of the territorial sea is measured or to the international
boundaries of the United States in the Great Lakes or any other body of water traversed by
such boundaries. Please consult the State for information specific to the platform, and you may
find helpful information at www.mms.gov/aboutmms/ocsdef.htm.

Please note that amendments were made in December 2010 (75 FR 74487) to extend
applicability of the GHG Reporting Program to facilities "attached to or under the Outer
Continental Shelf." Those same rule amendments amended the definition of United States.
Neither the amendments made to 40 CFR 98.2 (Who must report?) to include the Outer
Continental Shelf, nor the amendments to 40 CFR 98.6 to clarify the definition of United States
or add a definition for Outer Continental Shelf, were intended to have any impact on
applicability under the GHG Reporting Program (GHGRP) for the 2010 reporting year for
subpart C. The rule was made effective December 30, 2010 with the view that data collection
would begin for subpart W January 1, 2011. We recognize that the changes to subpart A could
be perceived to be applicable for the whole of 2010, however, this was not our intent. In fact,
in other final rules published approximately the same time (75 FR 79095 and 75 FR 66436) we
were very clear about how any amendments would apply to the current 2010 reporting year.
In those rulemakings, we concluded that the amendments could be incorporated for the 2010
reporting year, because they, "primarily provide additional clarification regarding the existing

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regulatory requirements, generally do not affect the type of information that must be collected
and do not substantially affect how emissions are calculated". In specific cases where EPA
concluded that the amendments impose additional substantive requirements not reasonably
anticipated by reporters for the 2010 reporting year, we delayed implementation of the
amendments to the 2011 reporting year.

EPA did not provide such a similar rationale for applying any of the amendments in 75 FR 74458
to the 2010 reporting year- the intent was for the amendments to take effect for the 2011
reporting year. Further, given that the amendments could affect applicability for offshore oil
and natural gas facilities required to report under subpart C in 2010, it would not have been
practical to make this change effective for the 2010 reporting year. Based on this, the guidance
provided in earlier communications is still appropriate for the 2010 reporting year.

Question: I need to know if facilities that fall under 40 CFR 98 Subpart W that are subject
to report Stationary Fuel Combustion Sources must do so by March 30, 2011. Please provide
the deadlines for reporting these sources for both Onshore and Offshore production.

Response: Any facility, as defined in 98.6, with annual stationary fuel combustion emissions
greater than or equal to 25,000 metric tons C02e in 2010 must report combustion emissions
under subpart C by September 30, 2011.

For an onshore production facility, if annual combustion emissions were less than 25,000 metric
tons C02e in 2010, but the facility is subject to Subpart W in 2011, then the facility must report
all combustion emissions, equipment leaks, flared emissions, and vented emissions as required
under W for 2011 from onshore on March 31, 2012. For offshore production facility, if annual
combustion emissions were less than 25,000 metric tons C02e in 2010, but the facility is subject
to Subpart W and C combined in 2011, then the facility must report all combustion emissions
under Subpart C and all equipment leaks, flared, and vented emissions as required under W for
2011 from onshore on March 31, 2012.

Question: Subpart W, via GOADS, requires monitoring of "hours operated" for "natural
gas, diesel, and dual-fired turbines". I have two questions:

1)	Since emissions are calculated based on fuel use only, why is it necessary to monitor hours
operated?

2)	For dual-fired turbines, is it necessary to monitor hours operated on each fuel, or just the
total?

Response: You must follow the methods in the rule. In response to industry comments
regarding burden, EPA finalized requirements to use Bureau of Ocean Management, Regulation
and Enforcement (BOEMRE) GOADS reporting methods for all offshore facilities under Subpart
W. As GOADS is under BOEMRE jurisdiction, EPA has no authority regarding GOADS guidelines
or methods.

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Question: I am working with a new off shore facility and my understanding is that they will
start operations in early 2011. When they begin operations they would like to have their
monitoring plan for the GHGRP fully in place. The plan they have right now only covers the
combustion sources and they will need to include a component that addresses the
monitoring requirements to comply with Subpart W.

I was hoping you might have some insight regarding how new facilities that are subject to
GOADS are supposed to report in 2012. They are supposed to use GOADS published data but
for the new sources the data won't be ready in time for them to report in 2012. Should they
be using the GOADS methodologies to calculate the emissions themselves?

Response: New facilities, whether or not under GOADS jurisdiction, have to follow
98.233(s)(4), which states, "For either first or subsequent year reporting, offshore facilities
either within or outside of BOEMRE jurisdiction that were not covered in the previous BOEMRE
data collection cycle shall use the most recent BOEMRE data collection and emissions
estimation methods published by BOEMRE referenced in 30 CFR 250.302 through 304 to
calculate and report emissions (GOADS) to report emissions."

Therefore, if the facility is subject to the rule and is under BOEMRE jurisdiction but is a new
facility that is not included in the most recently published GOADs report, then you must
calculate calendar year 2011 emissions for equipment leaks, vent, and flare emission sources
using the GOADS methodologies in the most recently published GOADS report.

Onshore Petroleum and Natural Gas Production

Question: I currently have a client that has traditional oil and gas wells with various
equipment including tanks, well heads, engines, compressors, dehydrators, separators etc.
These wells are spread out over multiple counties. Do the regulations state how we should
consider this situation in regards to determining whether I meet or exceed the GHG reporting
threshold? Should we count each individual well site as a facility or count all the wells as
basically one facility?

Response: The facility definition for onshore petroleum and natural gas production is
provided in section 98.238 of subpart W. Facility with respect to onshore petroleum and
natural gas production for purposes of this subpart and for subpart A means all petroleum or
natural gas equipment on a well pad or associated with a well pad and C02 EOR operations that
are under common ownership or common control including leased, rented, or contracted
activities by an onshore petroleum and natural gas production owner or operator and that are
located in a single hydrocarbon basin as defined in § 98.238. Where a person or entity owns or
operates more than one well in a basin, then all onshore petroleum and natural gas production
equipment associated with all wells that the person or entity owns or operates in the basin
would be considered one facility. Per this definition, all onshore production sources listed in
98.232(c) in the same basin are considered one facility.

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Question: In the "Leak Detection and leaker emission factor" subsection, I see that this
section is not applicable to production. "You must...conduct leak detection of equipment
leaks from all sources listed in Section 98.232 (d7), (e7), (f5), (g3), (h4), and (il). Therefore, I
wanted to clarify that leak detection is not applicable for wellheads, separators at well site,
storage tanks and other equipment defined by "production equipment".

Response: Onshore production reporters do not need to perform leak detection under
§98.233(q) for equipment leaks. For an onshore petroleum and natural gas production facility,
equipment leaks are calculated with the methodology in §98.233 (r), using population count
and population emissions factors.

Question: With respect to the onshore petroleum and natural gas production segment and
the natural gas distribution segment, reporting of combustion emissions under subpart W is
redundant for those facilities also subject to subpart C. Yet the necessary information seems
different between Subpart W's subsection and Subpart C. The question is which subpart takes
precedence in our monitoring methodology?

Response: For both the onshore production and natural gas distribution industry segments,
all combustion emissions monitoring and reporting requirements are incorporated into Subpart
W. Hence, data reporting for the onshore production and natural gas distribution segments'
combustion emissions starting in 2011(reported 2012) are reported under Subpart W. Please
note that for year 2010 onshore production and natural gas distribution reporters have to
comply with requirements of Subpart C for combustion emissions and, accordingly report
combustion related emissions under subpart C in 2010.

Question: Please provide additional definition for determining the limits of a "basin". The
rule defines a basin as "all wells in a particular county". We have multiple isolated fields in
the same county/parish, and some fields that are in multiple counties/parishes. Do we group
all oil and gas wells in a geologically defined field, as the "basin", for applicability purposes?

Response: The definition of both a basin and a facility, as applicable to onshore petroleum
and natural gas production, is provided in 98.238.

Facility with respect to onshore petroleum and natural gas production for purposes of this
subpart and for subpart A means all petroleum or natural gas equipment on a well pad or
associated with a well pad and C02 EOR operations that are under common ownership or
common control including leased, rented, or contracted activities by an onshore petroleum and
natural gas production owner or operator and that are located in a single hydrocarbon basin as
defined in § 98.238. Where a person or entity owns or operates more than one well in a basin,
then all onshore petroleum and natural gas production equipment associated with all wells that
the person or entity owns or operates in the basin would be considered one facility.

Basin means geologic provinces as defined by the American Association of Petroleum
Geologists (AAPG) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin,
Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10

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(October 1991) (incorporated by reference, see § 98.7) and the Alaska Geological Province
Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on
Statistics of Drilling in Cooperation with the USGS, 1978 (incorporated by reference, see § 98.7).

Therefore, all oil and gas wells in a basin as defined by Subpart W have to be grouped together
for applicability purposes.

Question: I am trying to understand the definition of a "Facility" as it pertains to 40 CFR Part
98 - subpart W. The definition uses the word "Basin". I have copied text from both the rule
and preamble below. Is this saying that all equipment associated with one or more
production facilities, within the same parish (county), and owned by the same company, are
considered one facility? The way it reads to me is that the parish (county) lines are being
used to delineate the basin boundaries. Is this correct?

Rule: Where a person or entity owns or operates more than one well in a basin, then all
onshore petroleum and natural gas production equipment associated with all wells that the
person or entity owns or operates in the basin would be considered one facility.

Preamble: Basins are mapped to county boundaries only to give a surface manifestation to
the underground geologic boundaries. EPA decided to use the AAPG geologic definition of
basin because it is referenced to county boundaries and hence likely to be familiar to the
industry, i.e., if the owner or operator knows in which county their well is located, then they
know to which basin they belong.

Response: For the onshore petroleum and natural gas production industry segment, the
facility is comprised of all wells in a single hydrocarbon basin that are under common
ownership or control (see full definition in 98.238). Basin is defined in 98.238 also (see below).
A basin is not a county. What the preamble was explaining is that the AAPG definition of basin
was selected because it uses county boundaries rather than other descriptors (e.g., UTM
coordinates) to define basins. A basin definition that is defined by county boundaries is easier
for a reporter to understand because it uses known geographical demarcations as compared to
ones that use other metrics. A basin can be comprised of multiple counties.

"Basin means geologic provinces as defined by the American Association of Petroleum
Geologists (AAPG) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin,
Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10
(October 1991) (incorporated by reference, see § 98.7) and the Alaska Geological Province
Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on
Statistics of Drilling in Cooperation with the USGS, 1978 (incorporated by reference, see §

98.7)."

This definition of facility for onshore production does not apply to the other 7 source categories
in subpart W.

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Question: Are the blowdown emissions from a compressor, separator, or other field
equipment included in the Onshore petroleum and natural gas production sector?

Response: Blowdown emissions from field equipment in the onshore petroleum and natural
gas production segment are not included for reporting under the onshore petroleum and
natural gas production industry segment; see section 98.231(a) and 98.232(c).

Question: Are the emissions factors listed in Table W-1A for both leaking components and
non-leaking components? How do you calculate emissions from leaking components if
onshore petroleum and natural gas source are not required to monitor components?

Response: Equipment leak emissions in onshore production are to be estimated using
methods provided in 98.233(r)(2). Hence, no leak detection of emissions is required for onshore
production. Table W-1A provides population emission factors, which represent the emissions
on an average from the entire population of components - both leaking and non-leaking;
please see section 6(d) of the Technical Support Document for further details on the concept of
population emission factors.

Question: 98.233(j) - Onshore production storage tanks. The regulation stipulates that
calculation methodologies for onshore production storage tanks depends on whether the
separator has a throughput greater than or equal to 10 barrels per day. Our clients expect
that this would be based on actual annual average since this is an annual report of actual
emissions. Please confirm.

Response: The 10 barrels per day of oil throughput referenced in 98.233(j) is based on
annual average daily throughput.

Question: How should the daily oil throughput be determined for onshore production
storage tanks in 98.233(j) to compare to the threshold of 10 barrels/day? Is it based on design
capacity, maximum daily throughput, or annual average actual daily throughput? Is the
throughput re-evaluated annually? If the throughput decreases below this threshold, are the
equipment excluded from report under Subpart W?

Response: It is EPA's intent that the 10 barrels per day of oil throughput referenced in
98.233(j) be based on annual average daily throughput. On an annual basis, the
owner/operator must evaluate whether individual well pad produced hydrocarbon liquids falls
above or below the equipment threshold and use monitoring methods appropriately. For less
than 10 barrels per day of oil throughput, the reporter must determine if 98.233(j)(5) applies.

Question: For an onshore petroleum and natural gas production site, I am confused on
which calculation to use for centrifugal compressor venting 98.233(o). Should the facility use
98.233(o)(l)-(7), and therefore use equations W-22, W-23, W-24 and W-25? The calculations
are contradictory and redundant.

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But maybe the facility should only calculate emissions for wet seal oil degassing vents (as
suggested in the checklist). Therefore should the facility only use 98.233(o)(7), and therefore
use only equation W-25?

Response: Onshore petroleum and natural gas production facilities should refer to
§98.233(o)(7) to calculate emissions from centrifugal compressor venting.

Question: Does EPA have the hydrocarbon basin map they reference in 98.238 available on
their website some place? Please provide me with the link. I've tried tracking it down with
the American Association of Petroleum Geologists but have not had any luck.

Response: No, the hydrocarbon basin map is not on the EPA website. The AAPG Geologic
Province map can be found at: The American Association of Petroleum Geologists (AAPG)
Bulletin, Volume 75, No. 10 (October 1991) pages 1644-1651.

http://www.aa pg.org/eseries/scriptcontent/BeWeb/orders/Prod uctDetail.cfm?pc=DD0021

Question: For combustion equipment that triggered Subpart C reporting, can this be
incorporated into Subpart W reporting for CY2011, or will there be 2 separate (Subpart C and
Subpart W) reporting schema?

Response: Onshore petroleum and natural gas production facilities and natural gas
distribution facilities must report stationary and portable combustion emissions as specified in
§98.233(z). For all other source categories in Subpart W, emissions from each stationary fuel
combustion unit must be reported under subpart C.

Onshore Natural Gas Processing

Question: Section 98.230(a)(3)(ii) states that "All processing facilities that do not
fractionate with throughput of 25 MMscfd per day or greater." are included in the source
category. Please specify the basis for the 25 MMscf per day throughput - is this based on
annual average daily flow or max design capacity?

Response: The gas processing plant throughput threshold in 98.230(a)(3)(ii) is based on
annual average throughput.

Question: Regarding terms "fractionate" and "fractionation" in 98.230(a)(3): Please define;
does this refer to separation of NGLs from methane, or the separation of NGLs into chemical
species or commercial products?

Response: It is EPA's intention for the purpose of Subpart W to follow general industry
parlance whereby "fractionate" and "fractionation" refers to the separation of NGLs into
individual chemical species or commercial products.

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Question: Section 98.230(a)(3) states that the onshore natural gas processing industry
segment includes (i) all processing facilities that fractionate and (ii) all processing facilities
that do not fractionate with throughput of 25 MMSCF per day or greater. Does this mean
that onshore natural gas processing facilities that do not fractionate and which have a
throughput of less than 25 MMSCF per day are not subject to GHG reporting requirements?

Response: As per the definition provided in 98.230 (a)(3), onshore natural gas processing
includes "all processing facilities that do not fractionate with throughput of 25 MMscf per day
or greater." Therefore natural gas processing facilities that do not fractionate and have a
throughput less than 25 MMscf per day are not subject to the requirements of Subpart W. You
may still be subject to other subparts of the rule (e.g., subpart C, General Stationary
Combustion) therefore you should determine if you are applicable under any other subparts in
98.2(a).

Question: Under onshore natural gas processing where would you report vent emissions?
We have a membrane plant (sweet gas so not acid gas removal) where we remove C02 and
vent should this be reported under flare as unlit?

Response: If a membrane unit is used to remove C02 from natural gas, then emissions must
be calculated and reported as specified in 98.233 (d). Please see EPA-HQ-OAR-2009-0923-1298-
18 in the RTC for further details on the definitions of sweet and sour gas.

Question: In 98.230(a)(3)(ii), is 25 mmscf/day the design capacity for a processing plant or
the actual capacity?

Response: The gas processing plant throughput threshold in 98.230(a)(3)(ii) is based on
annual average throughput.

Question: If there is a natural gas processing plant located at the same location as an
underground storage facility and they share compression, how should we report - as two
separate facilities with estimated compression dedicated to each or as one combined facility.
If we are one combined facility, should we follow the reporting requirements for a gas
processing plant, an underground storage facility or both?

Response: If the natural gas processing plant and the underground storage operations are
part of the same facility, as defined in 98.6 you would report as one facility and submit one
annual GHG report for these operations. EPA has provided guidance on how reporters should
report for co-located industry segments and dual purpose equipment, please see the comment
response number EPA-HQ-OAR-2009-0923-1024-14.

Question: If fuel gas lines are not owned or operated by a gas processing facility, but are on
the gas processing facility property, do the fuel gas lines need to be monitored for equipment
leaks? We assume not because the processing facility has no control over these pipelines
owned by a third party.

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Response: The definition of facility in 98.6 requires equipment to be under "common
ownership or common control." Therefore, based on the information provided, the fuel gas
lines are not subject to the rule because they are not owned and/or operated by the reporting
gas processing facility's owners/operators.

Question: A facility receives a gaseous stream consisting of a high concentration of C02 for
processing. The composition of the inlet gaseous stream is such that the methane
composition is less than 70% by volume, and the gas has a heating value of less than 910 Btu
per standard cubic foot. The definition of Onshore Natural Gas Processing [98.230(a)(3)]
states that this segment "separates and recovers NGLs and/or other non-methane gases and
liquids from a stream of produced natural gas." EPA proposed a new definition of "natural
gas" on August 11,2010 to read, "natural gas is composed of at least 70 percent methane by
volume or has a high heat value between 910 and 1150 Btu per standard cubic foot." Please
confirm that a facility which processes an inlet gas stream with a methane content of less
than 70% by volume, and a heating value of less than 910 Btu per standard cubic foot is
excluded from the Onshore Natural Gas Processing segment.

Response: The definition of "natural gas" in the final rule revision (December 17, 2010)
excludes the composition and heat value specification and simply states: "Natural gas is a
natural occurring mixture of hydrocarbon and non-hydrocarbon gases found in geologic
formations beneath the earth's surface of which the principal constituent is methane. Natural
gas may be field quality or pipeline quality." Based upon the finalized definition of "natural
gas", a facility that processes an inlet gas stream which is field gas could be included in the
Onshore Natural Gas Processing segment if the process otherwise meets the definition of
Onshore Natural Gas Processing.

Question: Some facilities are designed solely to fractionate natural gas liquid
streams. These facilities receive an inlet stream of natural gas liquids (not a gaseous
form of natural gas) which does not contain methane. The facilities are designed to
fractionate the liquids into individual products (ethane, propane, etc.) and do not
produce a methane stream. The definition of Onshore Natural Gas Processing
[98.230(a)(3)] states that this segment "separates and recovers NGLs and/or other
non-methane gases and liquids from a stream of produced natural gas ". The
definition of natural gas [according to 98.6] refers to "gases" - i.e., streams in a
gaseous form ("hydrocarbon and non-hydrocarbon gases [...] field production gas,
process gas, and fuel gas"). Natural gas liquids are defined separately, and are not
mentioned as the stream being processed in the definition of Onshore Natural Gas
Processing. Therefore, please confirm that facilities designed to fractionate natural
gas liquid streams are not included in the definition of Onshore Natural Gas
Processing and are therefore not required to report under Subpart W.

Response: EPA has reviewed your question and is unable to respond at this time. Your
question relates to an issue or issues currently the subject of ongoing litigation. Please monitor
the website for any additional guidance that may be available in the future.
http://www.epa.gOv/climatechange/emissions/subpart/w.html

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Question: As I interpret Subpart W, gas processing facilities that do not process more than
25 mmScf/day are not subject to reporting under Subpart W regardless of whether they are
subject to reporting under Subpart C. Can you please provide more guidance on how this
threshold should be calculated? Is it an average daily throughput based on the entire
reporting year?

Response: The Rule states in §98.230(a)(3)(i) and (ii) that the onshore natural gas processing
industry includes all facilities that fractionate, as well as all facilities that do not fractionate that
have a throughput of 25 MMscf per day or greater. Only those non-fractionating facilities with a
throughput of less than 25 MMscf per day would not be subject to reporting under subpart W
even if the reporting threshold is triggered in Subpart C.

The gas processing plant throughput threshold in 98.230(a)(3)(ii) is based on annual average
throughput.

Question: Is the 25 MMscfd threshold that has been added for gas processing facilities
98.230(a)(3) based on design capacity, maximum daily throughput, or annual average actual
daily throughput? Is the throughput re-evaluated annually? If the throughput decreases
below this threshold, does the facility no longer need to report under Subpart W?

Response: The gas processing plant throughput threshold in 98.230(a)(3)(ii) is based on
annual average throughput. This throughput is re-evaluated annually. Once you are subject to
the rule (e.g., your facility contains a source category listed in Table A-4), your facility must
continue complying with all the requirements of this part, even if the facility does not meet the
applicability requirements in a future year (i.e., 25,000 mtC02e for petroleum and natural gas
systems). The definition of the source category for petroleum and natural gas systems, under
onshore natural gas processing, refers to a processing facility that does not fractionate and has
a throughput of 25MMscf per day or greater. Because a gas processing facility that is over 25
MMscf per day meets the definition of the source category for subpart W, any facility that
becomes subject to the rule in whole or in part because of a natural gas processing facility,
would have to continue reporting until it meets the conditions for cessation of reporting in
98.2(i).

However, please note that if, in year 2, your throughput capacity is less than 25 MMscf per day,
you are not required to calculate and report GHG emissions from gas processing in year 2. You
would still be required to report other covered emissions at your facility. This is because gas
processing would not be an applicable segment for year 2. Nevertheless, your facility would
still be required to report in year 2, even if facility-wide emissions are less than 25,000mtCO2e,
and would continue to report until you meet the criteria in 98.2(i) for ceasing to report.

Question: Which takes precedence for determining the Subpart W applicability of a natural
gas processing facility- the 25,000 MT C02e threshold [under 98.2(a)(2)] or the 25 MMscf per
day throughput [under 98.230(a)(3)]?

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For example, if a processing facility has less than 25,000 MT C02e in combined emissions
from stationary combustion, flaring, vented, and fugitive BUT the throughput of the facility is
30 MMscf per day, is the processing facility still obligated to report under Subpart W?

Response: Both the 25,000 metric ton C02e threshold (from §98.2(a)(2)) and the 25 MMscf
per day throughput capacity (from §98.230(a)(3)(ii)) are considered when determining subpart
W applicability for a natural gas processing facility.

Since the throughput of the facility was identified in the question as 30 MMscf per day
throughput capacity, this exceeds the exclusion identified in the §98.230(a)(3)(ii) for processing
facilities that do not fractionate. Therefore, this facility falls under the onshore natural gas
processing industry segment definition as defined in §98.230(a)(3) and these emissions would
be included in the applicability determination for your facility. (If the throughput were less than
25MMscf this source would not have been considered in the applicability determination for the
facility.) However, based on the information provided, since the processing facility has less than
25,000 metric tons C02e in combined emissions from stationary combustion, flaring, vented,
and fugitive sources, the facility does not need to report under subpart W.

Question: 98.233(n)(2)(ii) indicates that if a gas processing plant does not have a
continuous gas composition analyzer, the composition of the flared stream depends on
whether the gas flared is upstream of the demethanizer, downstream of the demethanizer,
or is a hydrocarbon product. However, at gas processing facilities, flared gas can be a
combination of gases before and after the demethanizer as well as hydrocarbon product. In
addition, for certain facilities it is not possible to distinguish between the streams being
flared. EPA has allowed the use of engineering calculations when flaring hydrocarbon
products; since these products cannot be separated from the other streams being flared,
please confirm that flare gas composition for use in Equations W-19 through W-21 can also be
based on engineering calculations?

Response: EPA agrees that in the event that it is not possible to distinguish the source
streams from the processing facility being flared, whether being located upstream or
downstream of the demethanizer, or being a hydrocarbon product stream, reporters may use
engineering calculations based on process knowledge and best available data.

Question: Section 98.230(a)(3) states that the onshore natural gas processing source
category includes equipment that engages in liquid removal, and 98.232(d)(4) states that
dehydrator vents in this source category are covered. But 98.230(a)(3) states that the source
category does not include gathering lines or boosting stations. There is a lack of clarity as to
whether any liquid removal that is located on a gathering line and that meets the thru-put
thresholds is considered part of "processing" and subject to the reporting rules or whether it is
excluded because it is on the gathering line. Specifically, this question relates to the following
scenario: A dehydrator or a "knockout pot" is located on the gathering line after the wellhead
and on the site of a booster station. The dehydrator or "knockout pot" removes liquid from the
gas before it is compressed and then sent to the processing plant. This liquid removal is

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performed as a safety measure because liquid cannot be compressed and is therefore not
considered a process. Does the onshore natural gas processing source category include the
dehydrator or "knockout pot" in the above example?

Response: EPA has reviewed your question and is unable to respond at this time. Your
question relates to an issue or issues currently the subject of ongoing litigation. Please monitor
the website for any additional guidance that may be available in the future.
http://www.epa.gOv/climatechange/emissions/subpart/w.html

Question: Under Subpart W, are we required to calculate potential GHG emissions from all
compressors at a Natural Gas Processing facility? Some of our compressors are only used for
refrigeration and use 100% propane; they do not use or process any GHGs. It seems that
because they are not in service for natural gas processing that they would not be subject to
the reporting requirements.

Response: 98.232 (d) states that "for onshore natural gas processing, reporting C02, CH4,
and N20 emissions from the following sources." If the compressor stream is 100% propane
then the emissions will not include C02, CH4 and N20 emissions and therefore will not have to
be reported under Subpart W. However, if the facility exceeds the 25,000 mtC02e threshold
then the owner or operator must report combustion emissions for this compressor under
Subpart C.

Question: Under Subpart W of Part 98, the definition of Natural Gas Processing provides an
unclear explanation of fractionation, additionally, fractionation is not defined within the rule.
The definition is as follows: Natural gas processing separates and recovers natural gas liquids
(NGLs) and/or other non-methane gases and liquids from a stream of produced natural gas
using equipment performing one or more of the following processes: oil and condensate
removal, water removal, separation of natural gas liquids, sulfur and carbon dioxide removal,
fractionation of NGLs, or other processes, and also the capture of C02separated from natural
gas streams. This segment also includes all residue gas compression equipment owned or
operated by the natural gas processing facility, whether inside or outside the processing
facility fence. This source category does not include reporting of emissions from gathering
lines and boosting stations. This source category includes:

(i) All processing facilities that fractionate.

(ii) All processing facilities that do not fractionate with throughput of 25 MMscf per day or
greater.

The confusion lies as to what is actually meant by fractionation. Under the NSPS Subpart KKK,
fractionation is the separating of natural gas liquids into natural gas products. However,
under the description of processing as provided above, it includes "separation of natural gas
liquids" and "fractionate" as part of what processing plants do.

The main concern is if a plant that do not fractionate NGLs (as defined in Subpart KKK of the

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NSPS) is processes less than 25 MMscf/day but still separates out NGLs from the gas stream if
they still meet the definition of "processing" or if they are then brought into "production"
under the definition of a facility.

Some clarification on this matter would be greatly appreciated.

http://www.epa.gOv/climatechange/emissions/subpart/w.html

Onshore Natural Gas Transmission Compression

Question: Under section 98.233, for transmission storage tanks, the rule states to monitor
the tank emissions for 5 minutes then use a meter to quantify the emissions. Under 98.234#1,
the rule says any emissions detected by the camera is considered a leak. Is there a difference
here? How do we treat intermittent emission from the storage tank? Can we use an
alternative method to quantify the emissions? Or are we limited to the means listed?

Response: The purpose of this detection and measurement is to determine and quantify any
continuous gas emissions from condensate storage tanks. The most common source of vapor
emissions from a transmission compressor station condensate tank would be liquid transfer
from compressor scrubber dump valves. These sources operating properly would be
intermittent transfer of liquids from high pressure vessels to an atmospheric storage tank, with
a short term flashing of dissolved gas, which is assumed to be less than 5 minutes in
duration. Malfunction of scrubber dump valves can result in high pressure vapor leaking
through the valve, into the condensate tank, and out the tank roof vent, which would vent
indefinitely. This continuous release of vapor is detected as a continuous blow of gas from the
condensate tank roof vent using a leak imaging camera or by using an acoustic through-valve
leak detection instrument. Based on the current rule, the tank needs to be monitored to
determine whether the "tank vapors are continuous for 5 minutes"; see section 98.233(k)(2). So
if a leak is detected per requirements of 98.234(a)(1) and is continuous per the requirements of
98.233(k)(2) then the reporter has to measure the emissions per requirements in
98.233(k)(2)(i)-(iii). The reporter has the choice of using an acoustic leak detection device to
detect and measure leaks per requirements in 98.234(a)(5). You cannot use alternative
methods to those outlined in the rule.

Question: What is the definition of a "Booster Station"? One could assume that main
transmission line compressor stations with or without gas treating equipment are booster
stations and wouldn't have to report under Subpart W. Of course most of our mainline
compressor stations crack the 25,000 tonne threshold on compression alone, so we would
report under Subpart C. What is the exact definition of a booster station with regards to the

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Transmission, Processing Sectors versus the Production Sector.

Response: EPA has reviewed your question and is unable to respond at this time. Your
question relates to an issue or issues currently the subject of ongoing litigation. Please
monitor the website for any additional guidance that may be available in the future.
http://www.epa.gOv/climatechange/emissions/subpart/w.html

Question: For transmission tank venting sent to the flare, the reporter is referred to the
emissions source for flare stack emissions, but guidance is only provided for upstream
production and gas processing in this section.

Response: If you have a gas analyzer installed, you must use it. If you do not, then consistent
with 98.233(n)(2)(iii), you must use a representative composition from the source for the
stream determined by engineering calculation based on process knowledge and best available
data.

Question: On the Transmission side, it appears only Condensate tanks at Facilities require
leak checks (not other tanks at facility or not at facility)?

Response: Yes, for the transmission industry segment, only condensate storage tanks (water
or hydrocarbon) require leak checks. For further clarification, please see 98.232(e) and
98.233(k) of the rule.

Question: The definition of the onshore natural gas transmission compression includes "any
stationary combustion of compressors that move natural gas at elevated pressure from
production fields or natural gas processing facilities in transmission pipelines to natural gas
distribution pipelines or into storage." How does EPA currently define transmission pipelines?
Is this definition consistent with how any other federal agencies define transmission? For
example, DOT defines a transmission line as follows: Transmission line means a pipeline,
other than a gathering line, that: (1) Transports gas from a gathering line or storage facility to
a distribution center, storage facility, or large volume customer that is not down-stream from
a distribution center; (2) operates at a hoop stress of 20 percent or more of SMYS; or (3)
transports gas within a storage field.

Response: We are not able to provide further guidance at this time. Your question relates to
an issue or issues currently the subject of ongoing litigation. Please monitor the website for any
additional guidance that may be available in the future.
http://www.epa.gOv/climatechange/emissions/subpart/w.html

Question: I have a question on a natural gas compressor station that operates four 10.58
mmbtu/hr natural gas compressors for natural gas transmission and a 1,475 hp emergency
generator with a 500 hour per year permit limit.

Question:

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Does the facility only need to calculate C02 emissions (C02, methane and N20) for the
natural gas combustion of the compressors to see if they exceed the 25,000 metric tons of
C02 threshold as required by Subpart A. Since they are a Subpart C source do they only need
to calculate the emissions to see if they exceed the reporting threshold or do they need to
test and check for leaks? If they are below the 25,000 metric tons I presume they do not need
to report?

What about the emergency generator emissions?

Response: Pursuant to 40 CFR 98.2, if a facility's calculated total annual emissions are less
than 25,000 metric tons of C02e and the facility does not contain a source category listed in
Table A-3 of 40 CFR part 98, subpart A, then the facility does not have to report under 40 CFR
part 98 as a direct emitter.

For the purpose of determining the applicability of 40 CFR part 98 for the 2010 reporting year,
the facility should calculate the emissions from the gas compressors pursuant to 40 CFR
98.30(a)(2). So long as a the emergency generators meet the definition of "emergency
equipment" as stated in 98.6, emissions from the emergency generators are exempt and should
not be calculated. If the facility is subject to 40 CFR part 98, you should report combustion
emissions pursuant to the applicable requirements of subpart C (General Stationary Fuel
Combustion Sources).

For the purpose of determining the applicability of 40 CFR part 98 for the 2011 reporting year,
the facility should calculate the combustion emissions pursuant to 40 CFR part 98, subpart C
(General Stationary Fuel Combustion Sources) and equipment leak and vent emissions pursuant
to 40 CFR part 98, subpart W (Petroleum and Natural Gas Systems). Transmission compressor
stations follow subpart C for calculating combustion-related emissions and subpart C exempts
emergency equipment. Based on the information provided, if the facility is subject to 40 CFR
part 98, you should report combustion, equipment leak, and vent emissions pursuant to the
applicable requirements of the subparts.

Information and resources regarding the applicability and requirements of the aforementioned
subpart are available at:

http://www.epa.gOv/climatechange/emissions/subpart/w.html

Question: We would like further clarification on the applicability of 40 CFR 98 Subpart W
for C02 pipelines. The pipelines contain approximately 95% C02, which currently does not fit
the definition of residue gas as defined in 98.238 Residue Gas and Residue Gas Compression.
In addition, the definition for Onshore Natural Gas Transmission Compression in 98.230(a)(4)
specifies it "means any stationary combination of compressors that move natural gas at
elevated pressure from production fields or natural gas processing facilities in transmission
pipelines to natural gas distribution pipelines or into storage." This definition includes
"natural gas" but not C02. Will C02 pipelines be subject to the Onshore natural gas
transmission compression segment under 40 CFR 98 Subpart W?

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Response: CO2 pipelines are not required for reporting under Subpart W. See response to
comment EPA-HQ-OAR-2009-0923-1024-19 for further details.

Underground Natural Gas Storage

Question: How do we report emissions from separate facilities that inject or withdraw gas
from the same underground storage reservoir? These facilities may also fall under other
industry segments (e.g. Transmission Compression or under Subpart C for general combustion
sources).

Response: Underground storage and compression and transmission compression are two
separate industry segments. A "facility", as defined in 40 CFR 98.6, must determine if it
contains any of the industry segments listed in subpart W and compare its emissions from all
applicable industry segments against the 25,000 mtC02e threshold defined in 40 CFR 98.2(a)(2)
to determine applicability. For a response to the question related to multipurpose facilities and
dual purpose equipment, please see the response to EPA-HQOAR-2009-0923-1021-14. If
multiple owners or operators use the same underground storage operation, one designated
representative must be appointed for reporting purposes.

Question: Could EPA clarify that the natural gas stored in high pressure steel bottles at
peak-shaving stations should NOT be considered an underground natural gas storage facility
under Subpart W?

Response: High pressure steel bottles that store natural gas at peak-shaving stations without
any subsurface storage per section 98.230(a)(5) would not be considered underground natural
gas storage under Subpart W. However, if the high pressure steel bottles are located at
underground storage per section 98.230(a)(5) then the equipment leak sources listed in
98.232(f)(5) would be subject to reporting.

Question: What is the definition of "facility" for Underground Storage? The "segment"
definition in 98.230(a)(5) leaves us with several related questions.

a. Underground Storage Compression vs. Transmission Compression: Under Sec. 98.236(a) (p.
288), the rule requires us to report annual emissions separately for different industry
segments. The definition of underground natural gas storage (Sec. 98.230(a)(5)) says
"underground natural gas storage means subsurface storage, including depleted gas or oil
reservoirs and salt dome caverns that store natural gas that has been transferred from its
original location for the primary purpose of load balancing; natural gas underground storage
processes and operations (including compression, dehydration and flow measurement, and
excluding transmission pipelines); and all the wellheads connected to the compression units
located at the facility that inject and recover natural gas into and from the underground
reservoirs."

Question: How do we report emissions from separate facilities that inject or withdraw gas
from the same underground storage reservoir? These facilities may also fall under other

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industry segments (e.g. Transmission Compression or under Subpart C for general combustion
sources).

b. Equipment between Compression and the Wellhead: Does the definition of underground
natural gas storage include the equipment between the storage facility (i.e. compression) and
the wellhead e.g. meter runs, separators, and drips?

c. Filters and Separators: Are filters and separators located at the interconnect meter stations
at storage headers considered part of the underground storage facility?

Response: A "facility", as defined in 40 CFR 98.6, must determine if it contains any of the
industry segments listed in subpart W and compare its emissions against the 25,000
mtC02e threshold defined in 40 CFR 98.2(a)(2) to determine applicability. Underground
natural gas storage is as defined in 98.230(a)(5) and includes reporting of GHGs as listed in
98.232(f)(1) through (5). Therefore, the reporter needs to determine all applicable sources
as per this industry segment definition and sources to report. Specifically, filters and
separators are not listed as sources under 98.232(f)(1) through (5) but if filters or
separators are associated with any sources under this section, reporting of those listed
sources is still required.

The sources required to report are listed under the underground storage source category is
listed in 98.232 (f). In this list dehydration units are not included therefore reporting from
this source type is not required.

Question: Underground Storage Owned and Operated by Different Companies: If company
A owns and operates the underground storage facility (i.e. compression) but the associated
storage wellheads are owned by company A and B, in equal percentages, but operated by
Company B, is it possible to submit 2 separate emission reports by each respective operator?

Response: Please refer to the definition of "facility" in 98.6. Based on the information
provided, it would appear that company A would be required to submit one emissions
report for the underground storage and the associated wellheads. Please refer to the
response to comment EPA-HQ-OAR-2009-0923-1024-16 regarding reporting by
designated representatives.

Question: If onshore natural gas transmission has different emission factors for compressor
and non compressor components, why don't natural gas storage facilities have the same?
Some storage facilities can compress up to 3000psi! There is no provision for the different
component categories for compressor or non compressor components!

Response: EPA does not have sufficient data to support the differentiation of compressor
and non-compressor components for underground storage. Should peer-reviewed data become
available, at a time deemed appropriate by EPA, EPA would consider evaluating information on
different emission factors for compressor and non compressor components for the
underground natural gas storage industry segment under subpart W.

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Question: Re: Subpart W - Brine and diesel are used in the salt dome mining process to
create an underground natural gas storage facility for storage or load balancing of natural
gas. During solution mining of the salt dome to create the underground storage facility,
methane may be emitted from the brine water storage tank (on a more or less continuous
basis) or the diesel storage tank (when the tank is vented as pressure builds up). These liquids
are used in the salt dome mining process prior to the introduction of natural gas when the
underground storage facility is completed. Does Subpart W require reporting of these
emissions? Or are emissions from underground natural gas storage facilities to be reported
starting when natural gas is introduced for load balancing and/or storage?

Response: Under 98.230(a)(5) reporting is only required for "...salt dome caverns that store
natural gas..." Methane emissions from building of a storage facility are not included in the
reporting for subpart W. Emissions reporting is required when the storage facility is
operational.

Question: Subpart W Table W-4 has four sections in the final Federal Register publication.
The first and third sections are both labeled "Leaker Emission Factors Storage Station, Gas
Service" and both tables have an entry for "Open-ended Line". It appears from the factor
given that the first section is correct. In the proposed rule the "Storage wellheads" section
has an "Open-ended Line" value which is now missing in the final rule. It appears that the
storage wellhead factors table was split up and mis-labeled in the final rule.

Response: EPA has acknowledged the error and is considering options to address this. The
entry in Table W-4, the second occurrence of the emission factor for Open-Ended Line with a
value of 0.03 scf/hour/component should be included in the Population Emission Factors -
Storage Wellheads, Gas Service section of Table W-4.

Question: I have a facility that will be constructed in 2011/2012 timeframe. It will be an
underground natural gas storage facility with associated wellhead storage. In addition to
injecting gas for storage, it will also inject gas for enhanced oil recovery (EOR). This means the
storage station will also meet the definition of onshore natural gas processing and some of
the wellheads will meet the definition of onshore petroleum and natural gas production.
There will be no way to separate the storage activities from the EOR activities as most
equipment is used for both.

For underground storage the wellheads and storage station would be aggregated and
reported as one entity. For onshore production and natural gas processing the onshore
production would be reported as one entity and the onshore processing as another entity. To
make matters more confusing, each industry segment has different sources to include for
reporting. How do we deal with this under Subpart W. Do we call it underground storage and
ignore the sources that would fall under onshore production or processing plant that are not
included as applicable sources for underground storage? If we report under both we will be
double counting multiple sources.

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Response: What constitutes a facility, how to determine the reporting threshold, and
reporting of emissions from collocated and dual purpose equipment is as follows:

1) As a first step the reporter must determine the emissions from all equipment listed in
98.232(c) for onshore petroleum and production. Per section 98.231(a) only sources listed in
98.232(c) need to be considered for threshold determination for onshore petroleum and
natural gas production. 98.238 defines "facility" for the purposes of onshore petroleum and
natural gas systems. Per the requirements of 98.3 each "facility" must submit a GHG report for
all source categories at that "facility".

2) Note that while identifying onshore production emissions sources reporters have to
determine whether the source is "on the well pad or associated with a well pad". The location
of production wells within other facilities is inconsequential to this determination. Sources on a
well pad or associated with a well pad across the entire reporting basin have to be taken into
consideration. If your emissions from onshore petroleum and natural gas production are equal
to or greater than 25,000mtCO2e, then onshore petroleum and natural gas production facilities
report as a separate facility and include all emissions sources listed in 98.232(c).

3) Except for onshore petroleum and natural gas production and natural gas distribution, which
have unique facility definitions, all other segments subject to subpart W are considered in the
threshold determination for a single facility. You would also include emissions from other
source categories at your facility (e.g., stationary combustion).

If there are emissions sources that are dual purpose then the rule requires this piece of
equipment to be reported under the majority use industry segment based on guidance
provided in EPA-HQ-OAR-2009-0923-1024-14.

4) For collocated industry segments, which cannot occur in the case of onshore petroleum and
natural gas production and natural gas distribution due to the requirements in 98.231(a), EPA
has provided guidance on emissions reporting in EPA-HQ-OAR-2009-0923-1024-14.

Based on the information provided, the facility cannot be reported as onshore production and
natural gas processing combined (see point 1 above). For all the other segments, the report
should use guidance in points 2-3 above to determine the segment under which the facility
should be categorized.

Question: Are dehydration units that are used to dehydrate natural gas extracted from
underground storage included within the definition of underground natural gas storage
facility? If so, would those dehydration units be considered part of the same underground
storage facility if they are located on a different site that is not contiguous with the
compression facilities or wellheads?

Response: The sources required to report under the underground storage source category
are listed in 98.232 (f). In this list dehydration units are not included therefore reporting from
this source type is not required.

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Liquified Natural Gas Storage and Import and Export Equipment

Question: For LNG facility equipment that is in Gas Service, is only the equipment listed in
Table W-5 (Vapor Recovery Compressor) required to be reported if it is found to be leaking as
defined in the rule.

Response: Vapor recovery compressors use a population emission factor, hence there is no
leak detection required. Reporters have to count the number of vapor recovery compressors
and use the population emission factor.

LNG facilities will not be surveying the valves, connectors, and other components that are in
Gas Service under 98.233(q). At an LNG facility, a compressor that recovers vapor, but is
designed so that it does not have reportable emissions of methane-containing gas, such as a
flooded screw compressor, or one with seals purged with pressurized nitrogen, will not be
reported, in accordance with the rule and the EPA's response in Response to Public Comments,
EPA-HQ-OAR-2009-0923-1026-7, p. 46.

Question: Do I have to calculate emissions from operational LNG storage tank venting at
LNG storage facilities or LNG import or export terminals? Also, the equipment listed to be
surveyed for leaks does not include pressure relief valves, an emissions source listed for other
facility types in 98.233(q). Am I required to report these emissions?

Response: Section 98.233(q)(6) and (7) states that emissions factors for "...valves, pump
seals, connectors, and other" shall be used from the tables in the rule. A pressure relief valve is
a valve and the relief vent stack would be in the "other" category, so both are included the leak
detection survey and required to be reported.

Question: I am confused as to how offshore LNG would apply. Some offshore terminals are
basically buoys out in the ocean where a ship connects, regasifies the LNG onboard and
injects natural gas under pressure into the pipeline. The ships are hooked up to the buoys for
about a week to 10 days at a time. Once they offload their cargo, they return to their home
ports and are replaced at the buoy by another vessel. These vessels - for purposes of air and
water permits - have been determined by EPA to be stationary sources while they are
connected and offloading, but treated as vessels while under way. How are we to treat GHG
reporting applicability here? There are other types of offshore terminals that have all their
equipment on a fixed or floating processing station. Those ships would be treated like ships
coming to a traditional land based terminal where they offload for half a day and leave.

Response: The LNG import and export terminal source category includes offshore equipment
that receives imported LNG via ocean transport, stores LNG, re-gasifies LNG, and delivers re-
gasified natural gas to a natural gas transmission or distribution system. The floating vessels
described above, not the ships, are considered LNG import terminal facilities. Applicability
would be determined by determining the estimated emissions and comparing against the
threshold in 40 CFR 98.2(a)(2).

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Question: Only LNG Storage vessels located above ground are considered part of "LNG
Storage" under Subpart W. However, "above ground" is not defined. How should LNG
Storage vessels that are partially above-ground and partially below-ground (with the majority
below-ground) be treated under Subpart W? Is an LNG Storage vessel considered "above
ground" if any portion of the vessel is above grade?

Response: LNG storage vessels are considered above ground if any portion of the vessel is
above grade.

Question: At LNG Storage sites, how should pumps that are internal and submerged be
treated? Should they be treated as Pump Seal components even though they are
submerged?

Response: Submerged LNG pumps are not covered in subpart W as there are no emissions
from this source.

Question: Fugitives: Is the correct methodology for a facility subject to 40 CFR 98, with
equipment classified under 40 CFR 98.232(h)(4), to conduct a leak detection survey as stated
in 98.233(q) and use 98.233(r) to estimate emissions from sources that were determined to
be leaking in the leak detection survey? If this is not correct, please specify the correct
methodology.

Response: For equipment in 98.232(h), other than vapor recovery compressors the reporter
should use methods in 98.233(q). For vapor recovery compressors the reporter should use
methods in 98.233(r).

Question: Are LNG Storage sites located adjacent to Subpart D facilities (e.g. Electric
Generating Stations) under "common control" required to report emissions under the
Subpart D "facility", or should the LDC report the emissions under Subpart W? Or should the
combustion emissions be reported under the Subpart D "facility", with the fugitive emissions
reported by the LDC under Subpart W? In short, which facility should report which
emissions? This is not an issue for RY2010 because only Subpart D reporting is required, but
it will be an issue starting in RY2011.

Response: Based on the information provided, the questioner would report as a single facility
under 40 CFR 98. The single facility would be required to report emissions separately for
Subparts C, D and W in the EPA electronic greenhouse gas reporting system (eGGRT). In regard
to specific sources, Subpart W requires the reporting of process and emissions from any source
listed in 98.232(g) sent to a flare from LNG storage facilities, as defined in 40 CFR 98.230, under
Subpart W according to the calculation procedures outlined in 98.233. Additional applicable
emissions are to be reported under subpart D according to the methods described in subpart D.
Finally, stationary combustion emissions are to be reported under subpart C.

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Question: I have a question pertaining to Subpart W. In 98.232(q), the listing of equipment
that must have leak detection conducted includes a reference to 98.232(h)(4), which does not
exist. Please clarify what the correct paragraph in 98.232(h) should reference?

Response: We presume you are referring to 98.233(q). 98.232 (h)(4) does exist and refers to
"equipment leaks from valves, pump seals, connectors, vapor recovery compressors, and other
equipment leaks"; therefore, it is applicable to 98.233 (q).

Question: For an LNG import facility, there does not appear to be a category to report
normal vent emissions from an LNG storage tank. The vent is metered to monitor methane
emissions from boil-off. Please clarify.

Response: Section 98.232 (h) does not include boil-off venting from LNG storage tanks as an
emission source under LNG import and export terminals; therefore, boil-off venting emissions
from LNG storage tanks are not required. However, if the LNG storage tank is blown down to
the atmosphere then reporting is required under 98.233(i).

Natural Gas Distribution

Question: Multiple Leak Surveys - Section 98.233(q)(l) regarding leak detection and leaker
emission factors (bottom of p. 218 of pre-publication notice) provides: "You must select to
conduct either one leak detection survey in a calendar year or multiple complete leak
detection surveys in a calendar year. The number of leak detection surveys selected must be
conducted during the calendar year."

The preamble indicates that you must do one leak detection survey per year, and you may do
multiple leak surveys. The wording in the rule above indicates that you must select either one
or multiple surveys. This sounds as though we are required to indicate in advance how many
leak detection surveys will be conducted in the year which is onerous and doesn't make
sense. We believe you meant that we must conduct at least one leak detection survey in a
calendar year, and if we find a component that has a "leak" (e.g. as understood under
Method 21) then at our option we may fix the leak - e.g. by tightening a fitting - and then
conduct another leak survey to confirm that the component is not leaking.

Response: For natural gas distribution, a facility, which is the collection of all distribution
pipelines, metering stations, and regulating stations that are operated by an LDC, is required to
do at least one facility wide leak detection survey per calendar year and has the option to
conduct additional facility-wide leak detection surveys; if the facility selects this option, the
additional facility-wide survey(s) must be completed during the same calendar year in order to
account for fixing one or more leaks in the annual GHG report. If the facility chooses to fix one
or more leaks and conduct another survey to determine that the component is not leaking, it
must conduct a facility wide leak detection survey in order to account for fixing the leak(s) in
the annual GHG report. As leaks are random in nature and while some leaks are fixed others
are likely to occur. Therefore, a comprehensive survey is the only statistically relevant manner

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by which to establish facility-wide leak emissions rates and account for leaks repaired. Please
see the response to comment EPA-HQ-OAR-2009-0923-1014-9 for further details.

It is very important to note that the requirement to conduct additional facility-wide leak
detection surveys should a company wish to account for fixing a leak does not preclude in any
way a company from repairing a leak. If a company chooses to conduct only one facility-wide
leak detection survey in a calendar year but finds a leak during the survey, the company can
and is encouraged to fix the leak. The leak detected though, as noted above, must be reported
as a leaker for the entire calendar year should the company choose not to conduct a second
survey.

Question: Sunset Non-Leaking City Gates: What happens if an LDC goes out to a custody
transfer city gate station year after year and finds that it has no leaking components? Could
EPA provide a sunset provision so that annual leak surveys would no longer be required?

Response: Equipment/ component leaks are random in nature and minimal leaks in one year
do not guarantee similar leak levels in the future. There are no sunsetting provisions for
individual emissions sources, only facilities. EPA has provided provisions that allow facilities to
stop reporting under certain conditions and with prior notification to EPA. Please see 40 CFR
98.2(i)(l) - (i)(3). EPA addressed sunset provisions in general in the proposal to the 2009
Mandatory Reporting of Greenhouse Gases Rule (74 FR 16478).

Question: Population Counts: It appears that there may be inconsistencies in some factors
used in the equations that Distribution facilities are directed to use on page 220 for
population count emissions (EQ W-31) and the calculated facility emission factor (EQ W-32)
on page 224. "Counts" as used in EQ W-31 is the total number of a type of source or
component type. Does this mean that all components should be counted?

"Count" as used in EQ W-32 is total number of meter runs, which will likely be a much lower
number than the number of a given component type in a meter run. EF as calculated here is
supposed to be a facility emission factor. This should work if there is only one meter run at a
facility (above grade M&R city gate).

EFs for EQ W-31 is defined on page 221 as the EF determined in EQ W-32.

We would appreciate clarification regarding how the population counts will work in the

different formulas.

Response: For natural gas distribution, for below grade meters and regulators; mains; and
services, these sources shall use the appropriate default population emission factors listed in
Table W-7 of subpart W.

The term "Counts" required in Eq. W-31 is a generic term, signifying the total number (activity)
of the type of emission source under consideration, at the facility. For natural gas distribution
non-custody transfer city gate stations, the term "Counts" refers to the total number of meter

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runs, since that is the activity on which the emission factor for this sector is based on (see Table
W-7 of subpart W).

The emission factor as defined in Eq. W-32 is intended for the sources of above grade meters
and regulators at city gate stations not a custody transfer, since these sources use the total
volumetric GHG emissions at standard conditions for all related equipment leak sources. First,
the reporter is required to estimate emissions "for all equipment leaks sources calculated in
paragraph (q)(8) of" section 98.233. Then Es,i as defined in Eq W-32 is the emissions from ALL
sources at above ground custody transfer stations. This when divided by the total number of
meter runs for these custody transfer stations as in Equation W-32 results in an emissions
factor per meter that includes all the sources.

The emission factor for non-custody transfer city gate station comes ONLY from W-32. For all
other emissions source the reporter must use emissions factors in the tables as appropriately
defined for EFs for Equation W-31.

Question: I found what I think is an error in the equations for estimating fugitive emissions
from non-custody transfer gate stations; equations W-31 and W-32.

Equation W-31 is as follows: Es,i = Counts * EFs *GHGi *Ts

EFs is the emission factor in scf/hr and Ts is the number of hours of operation during the
calendar year.

For non custody transfer gate stations EFs is calculated using Equation 32 which is EF = Sum
(Es,i/Count) (Eq. W-32)

Where Es,i is the annual estimated emissions from custody transfer gate station and count is
the number of meter runs.

I think EPA's intent was to assume fugitive emissions from non-custody transfer gate stations
was the same as fugitive emissions from custody transfer gate stations, which isn't a bad
assumption, but equation W-32 produces an emission factor, EFs, that is the average annual
fugitive emissions per meter run at custody transfer gate stations rather than an hourly
emission factor required by Equation W-31. As a result, the estimated emissions from non-
custody transfer gate stations are 8,760 times greater than estimated emissions from custody
transfer gate stations.

Equation W-32 should be EF = Sum (Es,i/(Count*Ts)) so that the calculated emission factor is
an hourly emission factor rather than an annual emission factor.

Response: EPA has acknowledged the error and is considering options to address this issue.

Question: For a distribution company that has underground service lines that are made of
an unknown material, is it appropriate to assume the most conservative worst-case
population emission factor (unprotected steel at 0.19 scf/hr/number of services) for each of
these service lines if available data, excluding a costly excavation of the service line, does not
document the material type for the particular service line?

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Response: Where no information is available on the type of service pipeline material, the
reporter may make the best judgment based on available information and use appropriate
emissions factors. It is not appropriate to assume the worst-case population emission factor.
The reporter should document this determination in the monitoring plan under 40 CFR 98.3(g).

Question: Subpart W provides population factors in Table W-7 for cast iron mains, but not
for cast iron services. If a distribution company owns cast iron services, is it appropriate to
develop a cast-iron specific service lines emission factor by taking the company's average
service line length (in miles) and multiplying this by the emission factor for cast iron
distribution mains?

Response: There is no emission factor for cast iron services in Table W-7, therefore you are
not required to calculate emissions from cast iron services.

Question: If an LDC has an external combustion device (e.g. M&R Station Heater) that is < 5
MMBtu/hr located adjacent to a Subpart D facility under "common control", is reporting of
the combustion emissions from the device required? If such a source were located at a stand
alone site, it clearly would be exempt from Subpart W reporting. However, if it is located at a
site adjacent to a Subpart D Electric Generating Station under "common control", it appears
that the small combustion source's emissions may need to be reported. This is not an issue
for RY2010 because only Subpart D reporting is required, but it will be an issue starting in
RY2011.

Response: In the case of an external combustion device of less than 5 mmBtu located in an
LDC facility adjacent to a subpart D facility the equipment would be subject to Subpart W
requirements and therefore exempted. The reporter must follow all applicable activity data
collection requirements under Subpart W.

Question: I have read the definition of a facility under Subpart W and need further clarity.
We are a municipally owned local distribution company, and are subject to Subpart W of the
rule. PGW has distribution systems, meter stations, pipelines and 2 natural gas plants that
store LNG. Do we report each natural gas plant as 1 facility and the distribution systems along
with the meter stations and pipelines as another?

Response: The general definition of a "facility" provided in §98.6 indicates "any physical
property, plant, building, structure, source, or stationary equipment located on one or more
contiguous or adjacent properties in actual physical contact or separated solely by a public
roadway or other public right-of-way and under common ownership or common control, that
emits or may emit any greenhouse gas." This definition applies to the two natural gas plants
that store LNG; see section 98.230(a)(6). Whether these two natural gas plants are two
separate facilities depends upon whether or not they are located on one or more contiguous or
adjacent properties in actual physical contact or separated solely by a public roadway or other
public right-of-way.

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The definition of "facility" for the natural gas distribution industry segment is provided in
§98.238: "the collection of all distribution pipelines, metering stations, and regulating stations
that are operated by a Local Distribution Company (LDC) that is regulated as a separate
operating company by a public utility commission or that are operated as an independent
municipally-owned distribution system." As indicated, this definition applies to the distribution
systems, meter stations, and pipelines. The LDC is a separate facility without overlap with other
industry segments mentioned in 98.230; see section 98.231(a).

Question: Customer Meters and Regulators - In an upcoming technical corrections rule,
could you revise section 98.232(i)(l)-(3) to clarify that customer regulators are also excluded
from the reporting requirements? This could be done by inserting "and regulators" so that
the rule states that "Customer meters and regulators are excluded." See page 165 of
prepublication notice. Could you confirm that this was your intent?

Response: We did not intend to include reporting requirements for residential and
commercial customer meters and associated regulator(s). Note, we did not intend to exclude
all regulators from mandatory reporting but only those included with residential and
commercial customer meters not covered in Subpart W.

Question: This Subpart covers stationary combustion emissions sources for LDCs. For
combustion of pipeline natural gas it refers you back to Subpart C for HHV, emissions factors,
and calculation methodology. In Subpart C there are exemptions for emergency equipment.
Does this exemption apply to the sources which are potentially covered by Subpart W? In
other words, if an LDC operates an emergency generator, is that covered by Subpart W or is it
exempt from reporting by the guidelines for stationary combustion equipment as outlined in
Subpart C?

Response: Combustion emissions from emergency equipment under natural gas distribution is
exempt from reporting under Subpart W. LDCs report stationary and portable combustion
equipment under Subpart W per methodologies in §98.233(z), which refers to the
methodologies in Subpart C. Emergency equipment is defined in Subpart A as "any auxiliary
fossil fuel-powered equipment, such as a fire pump, that is used only in emergency situations".
Subpart C clearly states that "This source category [stationary fuel combustion sources] does
not include emergency generators and emergency equipment."

Question: If an LDC detects and voluntarily fixes a leak, Subpart W requires the LDC to
complete a leak survey on all Above-Ground Custody Transfer M&R Stations to get credit for
the fixed leak. This requirement imposes an unnecessary burden on companies who
voluntarily limit emissions. Does EPA intend to limit the burden on LDCs that voluntary fix
leaks (e.g. allow LDCs to take credit for leaks fixed within 30-days of the leak survey, without
retesting all Above- Ground Custody Transfer M&R Stations, which would provide LDCs with
an incentive to fix leaks in a timely manner)?

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Response: Please see rulemaking docket EPA-HQ-OAR-2009-0923 under "Understanding the
Substance of the DOT Regulations and Comparing Them to the Subpart W Requirements". In
addition, please see response to comment EPA-HQ-OAR-2009-0923-1026-8.

Question: Custody Transfer M&R Stations tend to handle a significantly higher volume of
natural gas at higher pressures than Non-Custody Transfer M&R Stations. Using an emission
factor without accounting for the volume and pressure differences at the M&R stations
results in significant over reporting. Does EPA intend to allow for any correction factors for
Non-Custody M&R Stations?

Response: The rule does not allow for the use of correction factors for non-custody M&R
stations.

Question: Please explain whether detecting leaks through soap bubble testing is acceptable
for natural gas distribution systems and compressor stations?

Response: Reporters may use soap bubble testing methods as specified in Method 21 (please
see 98.234(a)(2)).

Question: Subpart W requests a log regarding venting. Does this include maintenance work
(i.e., tie-ins, new mains, etc.), or is it assumed that this value is included with the emission
factors?

Response: EPA is assuming that the question is related to the use of population emission
factors to calculate the emissions from distribution mains and service lines. The emission factor
in Table W-7 for distribution mains and distribution services does not include maintenance
work on pipes. Emissions from maintenance work on pipe are not required to be reported;
please see the response to comment EPA-HQ-OAR-2009-0923-1156-6. Therefore, a log of
venting as a result of maintenance work is not required.

Question: For a 2011 report with the "Natural Gas Distribution" option selected; what
definition does the term "stations" account for in the excel calculation spreadsheet?

Response: For the "Natural Gas Distribution" calculation utility, the term "stations" is defined
by the explanation given in the source used for the methane emission factor (column F of the
"Guidance & Sources" tab). Please see the following reference for more information:

GRI and EPA. Methane Emissions from the Natural Gas Industry. Volume 10: Metering and
Pressure Regulating Stations in Natural Gas Transmission and Distribution. June 1996. pgs IV,
13-17 (Table 5-1), and 19-22. epa.gov/gasstar/tools/related.html

Question: What is the meaning of Substitute Data as it relates to Local Distribution
Companies?

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Response: The term "Substitute Data" is used in subpart W to refer to any data that is used to
replace missing data. 98.235 states, "Data developed and/or collected in a subsequent
calendar year to substitute for missing data cannot be used for that subsequent year's
emissions estimation."

Question: Under 98.233(r), tubing systems that are equal or less than one half inch diameter
are exempt from the requirements of paragraph (r) of Subpart W. For certain distribution
companies, the %-inch iron pipe size (IPS) pipe is a common standardized size used for gas
service lines. Actual measurement shows these service lines to have an inside diameter of
0.66 inches. Is Subpart W referring to the standardized pipe naming convention when
exempting one half inch diameter pipe? Or should tubing systems that are "%-inch" IPS be
subject to paragraph (r) due to actual measured ID?

Response: The term more commonly used today is nominal pipe size (NPS) not iron pipe size
(IPS). The actual internal diameter (ID) depends not only on the outside diameter (OD) of the
pipe but also the schedule (wall thickness) of the pipe which varies with the pressure rating of
the pipe. Therefore the references to pipe size in the rule are to NPS not actual ID.

Other: Acid Gas Removal Units

Question: 98.236(c)(3) requires the "total throughput off the acid gas removal unit" to be
reported. Please confirm that the throughput is the volume of gas exiting the AGR unit (outlet
gas), not the volume of gas vented to atmosphere.

Response: Yes, the term "throughput" refers to the volume of gas flowing out of the AGR
unit.

Question: This question relates to Subpart W, Acid Gas Removal Vents, using Calculation
Methodology 3. Are we allowed to assume that volume fraction of C02 content in natural gas
out of the AGR unit (Vo) is zero? This will result in a conservative estimate of AGR vent
emissions.

Response: No. §98.233(d)(8) does not instruct reporters to assume volume fraction of zero
for V0. Reporter must use the methodologies prescribed in §98.233(d)(8) to determine the C02
composition of the natural gas exiting the AGR unit (V0).

Question: Do acid gas removal units which are used to sweeten a liquid stream meet the
definition of acid gas removal units (which states that units are used to sweeten a natural gas
- i.e., gaseous - stream)?

Response: The definition of acid gas removal unit in 98.238 states, "process unit that
separates hydrogen sulfide and/or carbon dioxide from sour natural gas using liquid or solid
absorbents or membrane separators." Reporters do not have to report data for acid gas
removal units which are used to only sweeten a liquid stream.

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Question: This question relates to Subpart W, Acid Gas Removal Vents. Section
98.233(d)(ll) states "Determine if emissions from the AGR unit are recovered and
transferred outside the facility. Adjust the emission estimated in paragraphs (d)(1) through
(d)(10) of this section downward by the magnitude of emission recovered and transferred
outside the facility." If all of the emissions from an AGR unit are recovered and transferred
outside of the facility, does the facility still need to calculate emissions pursuant to Section
98.233(d)(ll) and then "reduce" the emission to zero?

Also, if all of the emissions from an AGR units are recovered and injected underground (via an
Acid Gas Injection Well), does the facility need to report zero emissions for the source under
Subpart W? Or can the facility just report under Subparts PP and UU?

Response: EPA requires the reporters to calculate the emissions from AGR units and then
adjust it downwards by the amount transferred outside of the facility. Therefore, if 100% of the
C02 vented from an AGR unit is transferred outside of the facility, the C02 emissions from the
AGR unit must be calculated prior to determining the amount being transferred outside the
facility. Note that 98.236(c)(3) requires reporting of both the AGR emissions and emissions
captured for offsite transfer separately, even if the numbers are the same.

As regards acid gas injection wells and subparts PP and UU, please see response to EPA-HQ-
OAR-2009-0923-0582-31.

Question: 98.233(d)(ll) - Acid gas removal vents. When calculating emissions from acid gas
removal vents, the regulation reads, "determine if emissions from the AGR unit are recovered
and transferred outside the facility. Adjust the emission estimated...downward by the
magnitude of emission recovered and transferred outside the facility." Many operators
perform on-site injection of acid gas - Our clients request that the EPA clarify that those
performing on-site acid gas injection can also estimate their emissions downward.

Response: Reporters performing on-site injection of acid gas may not adjust emissions
downward. 98.233(d)(ll) clearly states that you may only adjust emissions estimates
downwards for emissions recovered and transferred OUTSIDE the facility. Please see response
to comment EPA-HQ-OAR-2009-0923-0582-31.

Question: Do acid gas removal units which are used to sweeten a liquid stream meet the
definition of acid gas removal units (which states that units are used to sweeten a natural gas
- i.e., gaseous - stream)?

Response: The definition of acid gas removal unit in 98.238 states, "process unit that
separates hydrogen sulfide and/or carbon dioxide from sour natural gas using liquid or solid
absorbents or membrane separators." Reporters do not have to report data for acid gas
removal units which are used to only sweeten a liquid stream.

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Question: For AGR vents, Option 3, the MRR says a meter must be installed, but then says
in the next sentence that engineering calculations may be used if a meter is not installed -
this is unclear on whether or not a meter is required

Response: The rule requires the use of a meter if one is in place. If a meter is not in place, the
reporter has the choice of installing a meter or alternatively using engineering estimation;
please see section 98.233(d)(5).

Question: How are acid gas injection processes handled under Subpart W? Is this part of
the traditional sources included for onshore production?

Response: If the acid gas being injected is from a Subpart W reporting acid gas recovery unit
then the reporter has to comply with section 98.236(c)(3)(iv) for data reporting.

Question: I need some clarification. If there is an amine treatment system used to remove
H2S from produced gas that is located at a boosting station is this subject to subpart W.

The current subpart W source category also does not include reporting of emissions from
gathering lines and boosting stations. However, gathering lines and boosting stations are not
well defined and it is not clear if this would include amine treatment located at a boosting
station.

Question: 98.233(d)(ll) - Acid gas removal vents. When calculating emissions from acid
gas removal vents, the regulation reads, "determine if emissions from the AGR unit are
recovered and transferred outside the facility. Adjust the emission estimated...downward by
the magnitude of emission recovered and transferred outside the facility." Many operators
perform on-site injection of acid gas - we request that the EPA clarify that those performing
on-site acid gas injection can also estimate their emissions downward.

Response: Reporters performing on-site injection of acid gas may not adjust emissions
downward. 98.233(d)(ll) clearly states thatyou may only adjust emissions estimates
downwards for emissions recovered and transferred OUTSIDE the facility. Please see
response to comment EPA-HQ-OAR-2009-0923-0582-31

Question: Do incinerators and/or thermal oxidizers need to be reported under Subpart W?
The rule does not currently address either, only flares. In many cases, acid gas from an AGR
unit is routed to an incinerator to burn. Though AGR units are required to report emissions
under the rule, it would be inaccurate to report the AGR unit emissions without taking into
account a downstream incinerator. If an incinerator is required to report under the rule, what
calculation methods should be used, as there are not currently any calculation methods

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published?

Response: An incinerator and/or thermal oxidizer is considered a combustion unit. If an
incinerator and/or thermal oxidizer is located within a production or distribution facility, you
must follow 98.233(z) and report the resulting emissions under Subpart W. If an incinerator
and/or thermal oxidizer is located within all other oil and gas segments, you must follow
98.33(a) and report under Subpart C.

Question: In which units are we required to calculate and report emissions for Equation W-
3? Can we use a flow meter to calculate annual emission C02?

Response: If the reporter uses the methodology set forth in 98.233 (d)(2), then a vent meter
must be used to determine the annual volume of vent gas. The emissions calculated in Equation
W-3 are in units of cubic feet per year. However, paragraph 98.233 (d)(10) references 98.233 (v)
of this section, which converts the results from Equation W-3 into metric tons C02e. You must
report emissions in metric tons of C02, by gas, as required to meet the reporting requirements
in 98.3(c)(4)(iii).

Question: Section 98.233(d)(ll) states "Determine if emissions from the AGR unit are
recovered and transferred outside the facility. Adjust the emission estimated in paragraphs
(d)(1) through (d)(10) of this section downward by the magnitude of emission recovered and
transferred outside the facility." If all of the emissions from an AGR unit are recovered and
transferred outside of the facility, does the facility still need to calculate emissions pursuant
to Section 98.233(d)(ll) and then "reduce" the emission to zero?

Also, if all of the emissions from an AGR units are recovered and injected underground (via an
Acid Gas Injection Well), does the facility need to report zero emissions for the source under
Subpart W? Or can the facility just report under Subparts PP and UU?

Response: EPA requires reporters to calculate emissions from AGR units and then adjust it
downwards by the amount transferred outside of the facility. Therefore, if 100% of the C02
vented from an AGR unit is transferred outside of the facility, the C02 emissions from the AGR
unit must be calculated prior to determining the amount being transferred outside the facility.
Note that 98.236(c)(3) requires reporting of both the AGR emissions and emissions captured for
offsite transfer separately, even if the numbers are the same.

As regards acid gas injection wells and subparts PP and UU, please see response to EPA-HQ-
OAR-2009-0923-0582-31.

Other: Blowdown Vent Stacks

Question: Clarify whether 98.233(i) Blowdown vent stacks is applicable to pipeline
blowdowns (if occurring at a Subpart W "facility" such as a well pad). The term 'equipment'
makes this unclear whether it only applies to compressors and tanks and their associated
piping, or if it actually applies to pipeline blowdowns as well.

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Response: The blowdown vent stacks source is not listed under 98.232(c) and therefore does
not have to be monitored for onshore petroleum and natural gas production.

Question: The calculation methodology for blowdown vent stacks indicates that natural gas
volumetric emissions at standard conditions (calculated using Eq. W-14) are to be converted
to GHG mass emissions using the methodology in 98.233(v). Unless the blowdown stream
was a pure CH4 or C02 stream, natural gas volumetric emissions cannot be converted directly
to GHG mass emissions. Before volumetric natural gas emissions can be converted to GHG
mass emissions, the volumetric natural gas emissions must first be converted to GHG
volumetric emissions. Please confirm that emissions for blowdown vent stacks should be
calculated using the following approach: volumetric natural gas emissions at standard
conditions [98.233(i), Eq. W-14], convert to GHG volumetric emissions (CH4 and C02) at
standard conditions [98.233(u), Eq. W-35], convert to GHG mass emissions at standard
conditions [98.233(v), Eq. W-36].

Response: EPA acknowledges the error and is considering ways to address this.

Question: For blowdown vent stacks the preamble indicates that blowdowns from
containers less than 50 cubic feet total physical volume are exempt from reporting. However,
requirements under 98.233(i) refer to "50 standard cubic feet", which could imply a gas
volume rather than a physical container volume. In comments to the proposed Subpart W,
GPA had suggested a threshold of 50 cubic feet of physical container volume and we assume
that is the intent here. Please clarify.

Response: It is EPA's intent that the physical volume between isolation valves be considered
against the 50 standard cubic feet threshold for blowdown vent stacks. Reference EPA-HQ-
OAR-2009-0923-1018-27.

Question: The commenter requests the use of average blowdown volumes for sectors
where this emission source is required (processing, transmission, and LNG imports/exports).

Response: Where section 98.232 requires reporting of emissions from blowdowns, reporters
have to follow methods provided in section 98.233(i) of the rule.

Question: On Page 3 of the April 2011 FAQ list for Subpart W, the FAQ doc states,
"Blowdown emissions from field equipment in the onshore petroleum and natural gas
production segment are not included for reporting under the onshore petroleum and natural
gas production industry segment; see section 98.231(a) and 98.232(c)." and on Page 10 of the
it states that blowdown vent stacks are not covered per 98.232(c).

I agree that blowdown vent stacks are NOT covered.

But, if the blowdown gas from a facility or compressor at an onshore petroleum and natural
gas production facility is routed to a flare, then based on 98.232(c) and 98.233(n) these

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emissions to the flare would have to be reported.

Do you agree?

Some operators may interpret the FAQ as meaning all such blowdown gas does NOT have to
be reported.

Response: If blowdown vent stack gas at an onshore production facility is routed to a flare,
then these emissions will be reported as flare emissions and the calculation methodology in
98.233 (n) must be used. If you have a continuous flow measurement device on the volume to
the flare, you must use the measured volume. If not, you can estimate flow using engineering
calculations based on best available data or company records. For example, you may use the
methods in 98.233(i) to estimate the volume of blowdown being sent to a flare.

Other: Compressors

Question: With regards to the (Component Count Methodology 1), are tubing systems that
are one half inch in diameter included in the totals shown on Tables W-1B and W-1C. If a
component count exists for a facility, and the component totals are significantly higher than
using the average component counts listed in Tables W-1B and W-1C, which count should be
used?

Response: Tubing systems equal to less than one half inch diameter are exempt from the
requirements of section 98.233(r). If a component count exists for a facility, then that actual
count may be used as required in section 98.233(r)(2)(ii).

Question: In regard to emissions calculations for reciprocating compressor venting,
specifically for production, using Equation W-29, why and how would I use Section 98.233 (u)
to estimate volumetric GHGi emissions from volumetric natural gas emissions as outlined in
the above section using Equation W-35? It appears as though Equation W-29 already
calculates volumetric GHGi emissions and one should proceed to calculation of mass
emissions with Equation W-36 from Section 98.233 (v).

Response: Regarding calculating emissions from reciprocating compressor venting, it is EPA's
intent that 40 CFR 98.233(p) should only reference paragraph 98.233(v) for determining mass
emissions. EPA is currently considering options to address this.

Question: I was seeking clarification on Subpart W, Section 98.233, Subsection (o),
regarding calculation of emissions for Centrifugal compressor venting. From the regulation I
am unclear as to the procedures for using Equations W-22 and W-23, specifically, are both
calculations used independent of each other? If so, under what circumstances is one
employed over the other?

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Response: The text in paragraphs 98.233(o)(4) and 98.233(o)(5) are not alternate methods.
Per 98.234(o) compressors must be measured in all three modes over a 3 year period and
therefore section 98.233(o)(4) is the calculation method for compressor modes measured
during a specific reporting year and section 98.233(o)(5) is the calculation method for
compressor modes not measured during the specific reporting year.

Question: 98.233(p)(10) for reciprocating compressors refers to applying the calculation
methods found in paragraph (u) yet all equations in paragraph (p) calculate component
volumes rather than total volumes. The similar section 98.233(o) for centrifugal compressors
does not reference paragraph (u). It appears that the reference to paragraph (u) is in error in
section (p)(10), please verify.

Response: Paragraph (u) is incorrectly referenced in §98.233(p)(10). We are considering
options to address this.

Question: 1. If reciprocating compressor venting emissions are controlled by a device other
than a VRU (e.g., routed to a flare), do they still need to be measured/estimated under
Subpart W? 98.233(p)(8) only mentions adjusting emissions downward when a VRU is used
to control emissions. If a flare is used to control emissions, there would be no "venting
emissions", and therefore these controlled emissions would not be reportable under
98.233(p).

2. If reciprocating compressor venting emissions are controlled by a device other than a VRU
(e.g., routed to a flare), are they required to be measured/estimated under Subpart W, are
the compressor emissions estimated using the flare stack methodology identified in
98.233(n)?

Response: Section 98.233(p) does not provide any exclusion for reciprocating compressor
venting emissions. Thank you for alerting EPA to the missing adjustment for emissions recovery
in reciprocating compressor methodology; we are considering options to address this.

Question: At any given facility, emissions from multiple vents on a compressor (e.g., rod
packing vents and blowdown vents) may be routed through the same vent line such that the
emissions cannot be measured for each vent individually. In this situation, how should
vented emissions be determined for compliance with 98.233?

Response: According to 98.233(o) you must monitor emissions from each isolation valve
leakage, blowdown valve leakage, and wet seal degassing vent for each compressor
individually. Please note that your question relates to an issue or issues currently the subject of
ongoing litigation. Please monitor the website for any additional guidance that may be available
in the future. http://www.epa.gOv/climatechange/emissions/subpart/w.html

Question: Need clarification on what entity the "reporter" is in terms of developing the
compressor emission factors for measurements conducted in the "as found" mode and
applied to other compressors. This applies to processing, storage, transmission, and LNG

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operations. Is the "reporter" the facility, or all facilities operated by the same company?

Response: For purposes of developing the compressor emission factors for measurements
conducted in the "as found" mode, EPA intended the "reporter" to be all facilities operated by
the same company. In other words, the company could develop an emission factor, and apply it
to all facilities operated by the same company. EPA has reviewed your question and cannot
provide further guidance at this time. Your question relates to an issue or issues currently the
subject of ongoing litigation. Please monitor the website for any additional guidance that may
be available in the future. http://www.epa.gOv/climatechange/emissions/subpart/w.html

Question: In Subpart W, does a rotary screw compressor meet the definition of a
centrifugal compressor in the rule. These units do operate using a rotating shaft; however,
they are designed for high capacity and lower pressures than most common centrifugal
compressors, rotary screw compressors operate on the principle of positive displacement
(similar to reciprocating compressor) while centrifugal compressors depend on the transfer of
energy from a rotating impeller to the gas being compressed.

Response: In the context of sections 98.233 (o) and (p), EPA confirms that screw
compressors and rotary vane compressors are not covered under 40 CFR 98, Subpart W.

Question: Under Subpart W, reporters are required to directly measure emissions from
centrifugal and reciprocating compressors. If the seals, rod packing, isolation valves, and
blowdown valves all vent to a flare, are reporters still required to measure those emissions or
can the flare gas composition and volume be used to estimate emissions?

Response: Regardless of whether all emissions from centrifugal compressors and
reciprocating compressors are sent to flare, emissions must be measured and reported using
the methodologies specified in 98.233 (o)(l) through (o)(8) and 98.233 (p)(l) through (p)(7).
The reporter cannot measure the flare gas composition and volume to determine the emissions
from a particular centrifugal or reciprocating compressor.

Question: Do we have to calculate and report emissions from dry seals?

Response: 40 CFR 98.233(o) includes requirements to calculate emissions from both wet
seals and dry seals.

Question: Reciprocating Compressors: In the calculation of these emissions for these
sources using equations W-27 and W-28 we calculate an emission factor, but we are unclear
on where to use this emission factor in the calculation of the final emissions. Please clarify.

Response: 98.233(p)(6) states, "estimate annual emissions using the flow measurement",
which means Equation W-26 measures the emissions from compressor in the mode that it was
found in the calendar year. 98.233(p)(7)(i) states that develop an emissions factor for "all the
reporter's compressors not measured in the calendar year", which means that Equation W-28
develops an emission factor from measurements that were possible in specific modes.

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Reporters must then use Equation W-27 to determine emissions from a compressor in the
modes that it was not measured in during the current calendar year using a modal emission
factor calculated in Equation W-28. The emission factors, parameter EFm, is on a modal basis
and is calculated using metered emissions from the current year and the previous two calendar
years in Equation W-28.

Question: Centrifugal Compressors: In the calculation of these emissions for these sources
using equations W-23 and W-24 we calculate an emission factor, but we are unclear on where
to use this emission factor in the calculation of the final emissions. Please clarify.

Response: 98.233(o)(4) states, "estimate annual emissions using the flow measurement",
which means Equation W-22 measures the emissions from compressor in the mode that it was
found in the calendar year. 98.233(o)(6) states that develop an emissions factor for "all the
reporter's compressors not measured in the calendar year", which means that Equation W-24
develops an emission factor from measurements that were possible in specific modes.

Reporters must then use Equation W-23 to determine emissions from a compressor in the
modes that it was not measured in during the current calendar year. Equation W-24 determines
the emission factors, parameter EFm, used in equation W-23. It should be noted that EFm is on
a modal basis and is calculated using metered emissions from the current year and the previous
two calendar years.

Question: Non-operating pressurized mode for centrifugal compressors: The regulation
recognizes only two modes for centrifugal compressors: operating and non-operating
depressurized. While the non-operating pressurized mode is not typical, it does occur for
certain centrifugal compressors with dry seals. Should direct measurements be taken if a
centrifugal compressor is found in non-operating pressurized mode during the leak survey?
Are emissions from this mode subject to reporting?

Response: As the rule is currently stated per 98.233(o)(l) centrifugal compressors do not
have to be monitored in the standby pressurized mode.

Question: If a site has EOR compressors that handle critical phase C02 for EOR, are they
included?

Response: If the compressor is a reciprocating or centrifugal compressor and is located in the
onshore production facility as defined in 98.230 and 98.238 then the compressor has to be
monitored per requirements in 98.233(o) or (p), as appropriate.

Question: If a site has EOR compressors that handle to sub-critical phase C02 for EOR, are
they excluded?

Response: If the compressor is a reciprocating or centrifugal compressor and is located in the
onshore production facility as defined in 98.230 and 98.238 then the compressor has to be
monitored per requirements in 98.233(o) or (p), as appropriate.

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Question: 98.233(o) - Centrifugal Compressor Venting. It is not clear whether vapors
leaving sour seal oil traps must be measured. It is assumed they would have to be measured
using a temporary or permanent flow meter under 98.233(o)(2), but the paragraph refers
only to installation of a permanent flow meter on the wet seal oil degassing tank. I believe
the sour seal oil traps on compressors can vent through a closed system directly to flare.

Ports for hot wire anemometers to quantify the seal oil trap vapor flow rate can require a
facility shut-down in order to install; unless use of an acoustic device were allowable for
closed systems.

Another issue of concern is the wording on the use of blind flanges. The paragraph is clear
that if a compressor has blind flanges in place during the entire 3 year period, that
measurements are not required. The interpretation is not clear however for a compressor
that is taken off-line during a year, where the routine procedure is to install blind flanges
before it is taken down, (i.e., the blind flanges would not be in place for the entire 3 year
period.) There would not be an opportunity to measure a compressor in the standby
depressurized mode if blind flanges are routinely installed prior compressor shut-down.

Please verify that no venting measurements are required for a depressurized compressor
found with blind flanges in place during the annual survey if the compressor is never placed in
depressurized, not operating mode without blind flanges.

Response: This question has been responded to in the following two parts:

Sour Seal Oil Traps

Assuming that you mean by the term "sour seal oil traps" the seal oil-gas disengagement
vessels that receive the inboard seal oil contaminated with entrained and dissolved compressed
gas, then the rule treats these as seal oil degassing, and a vent either to the atmosphere or a
flare or a vapor recovery device must be measured and reported: vent emissions as measured,
flared emissions in accordance with 98.233(n) and vapor recovery operating factor deducting
from the otherwise vented or flared emissions.

Depressurized compressor with Blind Flanges

No measurements are required by 98.233(o) or (p) on a compressor that is not in service for
any time during the three consecutive year period. Therefore, if a compressor has blind flanges
installed on the suction and discharge unit isolation valves for the entire three consecutive year
period, then no measurements are needed. When a compressor is shut down for standby
depressurized or maintenance modes, the rule requires measurement of blowdown vent
emissions or alternatively measurement of unit isolation valve leakage using an acoustic
through-valve leak detection instrument BEFORE blind flanges are installed on the unit isolation
valves to assure no leakage of gas through the compressor. Unit isolation valve leakage cannot
be measured with blind flanges in place, and the rule recognizes that there is normally a short
period between compressor shutdown, isolation valve closure, and blowdown before the blind
flanges are swung into place. Therefore, it is incumbent on the operator to plan and execute
the through-valve leakage measurement on unit isolation valves during this short interval.

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Other: Dehydrators

Question: 98.233(e) - Dehydrator vents. The regulation requires producers and processors
to identify which dehydrators have a throughput less than 0.4 MMscf/day. Our clients expect
that this would be based on actual annual average since this is an annual report of actual
emissions.

Response: The daily throughput of 0.4 MMscf per day for dehydrators referenced in
98.233(e) is based on annual average daily throughput.

Question: How should the daily throughput be determined for dehydrators in 98.233(e) to
compare to the threshold of 0.4 MMscf/day? Is it based on design capacity, maximum daily
throughput, or annual average actual daily throughput? Is the throughput re-evaluated
annually? If the throughput decreases below this threshold, are the equipment excluded from
report under Subpart W?

Response: It is EPA's intent that reporters determine the daily throughput of 0.4 MMscf per
day for dehydrators referenced in 98.233(e) based on annual average daily throughput. On an
annual basis, the owner/operator must evaluate whether individual equipment falls above or
below the equipment threshold and use monitoring methods appropriately. For less than of
0.4 MMscf per day throughput, the reporter must use 98.233(e)(2).

Question: Similarly, do dehydrators which are used to dry a liquid stream meet the
definition of dehydrator (which states that units are used to dry a natural gas - i.e., gaseous -
stream)? If a dehydrator which dries a liquid stream is considered a "dehydrator" (see
question above), how does the 0.4 MMSCFD threshold apply to that dehydrator?

Response: No, per 98.6, a "dehydrator is a device in which "a liquid absorbent (including
desiccant, ethylene glycol, diethylene glycol, or triethylene glycol) directly contacts a
natural gas stream to absorb water vapor."

Question: The emission methods for dehydrator vents <0.4 MMscfd in the preamble (use
flow rate of wet NG and EF) contradict the requirements in the rule (use dehydrator count
and EF).

Response: Reporters with dehydrators with throughputs less than 0.4 MMscfd must
count such dehydrators and apply an emissions factor as provided in EquationW-5 to
estimate emissions. Rule text supersedes preamble text where inconsistencies occur.

Question: For onshore petroleum and natural gas facility dehydrator vents at glycol
dehydrators with throughputs less than 0.4 million standard cubic feet per day, can GRI-
GLYCalc be used instead of Method 2 in §98.233(e)(2)?

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Response: Emissions from glycol dehydrators with a throughput less than 0.4 million
standard cubic feet per day must be reported using the requirements of 98.233 (e)(2),
Calculation Methodology 2.

Question: Under §98.233(e)(1), emissions must be calculated from dehydrator vents with
throughput greater than or equal to 0.4 million standard cubic feet per day. Is this throughput
specific to vent throughput or dehydrator throughput?

Response: The 0.4 million standard cubic feet per day refers to the dehydrator throughput.

Question: Subpart W 98.233(e)(l)(xi)(A) (related to dehydrator wet natural gas sampling)
reads, "Use the wet natural gas composition as defined in paragraph (u)(2)(i) of this section."

Is it correct that this is meant to only reference (u)(2)(i) which is only applicable to Onshore
Petroleum and natural Gas Production Facilities?

Or, is it supposed to reference all of (u)(2), which would include other source categories as
well?

Response: EPA intended the reference to be (u)(2)(i) and (u)(2)(ii) for onshore production
and onshore processing respectively. EPA is considering options to address this.

Question: This question relates to Subpart W calculation methodology for dehydrator
vents.

For dehydrators >=0.4 mmscfd, Calculation Methodology 1 98.233(e)(1) specifies that
software that "speciates CH4 and C02 emissions" shall be used.

For dehydrators <0.4 mmscfd, Calculation Methodology 2 98.233(e)(2) required equation W-5
which calculates speciated emissions only.

However, 98.233(e)(6) says "Both CH4 and C02 volumetric and mass emissions shall be
calculated from volumetric natural gas emissions using calculations in paragraphs (u) and (v)
of this section." Is 98.233(e)(6) supposed to be referring to dehydrators that use desiccant
only? If so, the rule should be modified to clarify that this is the intent. Otherwise, the rule
does not provide a method for estimating volumetric natural gas emissions, particularly for
dehydrators with <0.4 mmscfd throughput.

Response: EPA intended §98.233(e)(6) to apply to those calculations in §98.233(e) that
yielded volumetric natural gas emissions. Since the method in §98.233(e)(1) and Equation W-5
speciate emissions, the calculations in paragraphs §98.233(u) and §98.233(v) are not necessary.
Equation W-6, however, does yield volumetric natural gas emissions, therefore, the calculations
in paragraphs §98.233(u) and §98.233(v) are necessary to speciate emissions. EPA is
considering options to address this.

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Question: Is a software application necessary to calculate dehydrator vent emissions and
storage tank emissions if flash gas is being sent to a flare? Can a reporter use engineering
calculations and direct measurement to estimate volume to flare?

Response: §98.233(e)(4)(A) states that for dehydrator vents to flares or regenerator fire-
box/fire tubes "use the dehydrator vent volume and gas composition as determined in
paragraphs (e)(1) and (e)(2) of this section." Therefore, consistent with (e)(1) and (e)(2), if the
glycol dehydrator has a throughout greater than 0.4 million standard cubic feet then the CH4
and C02 emissions must be determined using a software program prior to determining
emissions from gas sent to flares. 98.233 (j)(7)(i) states that for flash gas sent to flare, "use
your separator flash gas volume and gas composition as determined in this section." Therefore,
if Calculation Methodology 1 is used, the CH4 and C02 emissions must be determined using a
software program to determine emissions sent to flares.

The calculation methodology of flare stacks in paragraph (n) is used to determine emissions
from dehydrator vents sent to flares and flash gas sent to flares. In 98.233 (n)(l), the rule
language states:

"If you have a continuous flow measurement device on the flare, you must use the measured
flow volume to calculate the flare gas emissions. If all of the flare gas is not measured by the
existing flow measurement device, then the flow not measured can be estimated using
engineering calculations based on best available data or company records. If you do not have a
continuous flow measurement device on the flare, you can install a flow measuring device on
the flare or use engineering calculations based on process knowledge, company records, and
best available data."

Therefore, a reporter can use direct measurement or engineering calculation to determine the
volume to flare if the required conditions in 98.233(n)(l) are met.

Question: This question relates to Subpart W, glycol dehydrator flash tanks.

The rule requests:

98.233(e)(l)(viii) Use of flash tank separator (and disposition of recovered gas).
98.236(c)(4)(i)(D) Whether a flash tank separator is used in glycol dehydrator.

In a GlyCalc model, the only parameters required for the flash tank are the operating
temperature and pressure. So what does EPA mean by "disposition of recovered gas", and
why does EPA think this is a required parameter for the software model?

Response: 98.233(e)(1) states that "a minimum of the following parameters determined by
engineering estimate based on best available data must be used to characterize emissions from
dehydrators". Therefore, the items listed in 98.233(e)(l)(i)-(xi) are not all necessarily inputs.
With item (viii) the reporter has to account for the flash tank separator used. As the question
indicates, the input of operating temperature and pressure in GlyCalc model would account for

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the presence of a flash tank. The "disposition of recovered gas" means any recovery of flash gas
and is covered in 98.233(e)(3) and (4)(B).

Other: Flaring

Question: For Equation W-21 - Flare Emissions: Do you use "5" for Ri (# of carbon atoms)
for hydrocarbons with more than 5 carbons?

Response: For hydrocarbon constituents with 5 or more carbon atoms, Rj is 5 as defined in
equation W-21.

Question: We noticed in Subpart W of the MRR on page 74498 (n) Flare Stack Emissions that
the calculation methods do not offer use of a CEMS as a valid method of quantifying
emissions for flare stacks. The Dehydration vent stack source category and the AGR unit vent
stack source category both allow use of a CEMS to quantify emissions. Was it possibly an
oversight to not allow use of a CEMS as a quantification method on flares? Most facilities are
more likely to have a CEMS on the flare than the Dehy/AGR units, and given the extremely
large variance in possible products going to the flare, the CEMS would likely be much more
accurate than any calculation.

Response: You must follow the calculation and monitoring requirements in the rule. You are
correct that 98.233(n) does not currently allow the use of CEMS as a method for quantifying
emissions for flare stacks.

Question: Please confirm that flare stack emissions are included in determining applicability
for Subpart W. That is, are flare emissions included in the 98.2(a)(3)(iii) combined emissions
from all stationary fuel combustion sources when determining applicability for Subpart W per
Section 98.231(a)?

Response: To determine facility applicability, you must determine if you meet the
requirements of paragraphs 98.2(a)(1), (a)(2) or (a)(3). Based on the information provided we
assume you meet the definition of the source category for subpart W and are only subject to
reporting for subparts C and W.

Based on the assumptions above, for the 2010 reporting year, you are only required to report
emissions from stationary combustion. When determining applicability under 98.2(a)(3)(iii) you
do not need to include emissions from flares because flares are not included specifically under
subpart C.

For the 2011 reporting year, you must include flare stack emissions in the applicability
determination, as flares are included under subpart W.

Question: Subpart W 98.233(m), covering Associated Gas Venting and Flaring, assumes
continuous gas venting or flaring throughout the year, which is typically the case for
"stranded" gas from oil wells where gathering infrastructure is not available to route gas to
sales. Equation W-18 uses total annual oil production with the appropriate GOR to capture

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total gas emissions for the reporting year. In a situation where associated gas is only flared
when an equipment disruption occurs, like a compressor going down for a short period of
time, it is our interpretation that this quantity of flared gas does not fall within 98.232(m)
since it is not continuous throughout the year, and therefore Equation W-18 would grossly
overestimate emissions from the flaring event. Instead, our interpretation is that this flaring
event should be reported under 98.232(n) [EPA note: should be 98.233(n)) that covers Flare
Stack Emissions to allow for a more accurate reflection of the emissions from the flaring
event.

Response: The interpretation on equipment disruption is correct; it has to be reported under
98.233(n) and not 98.233(m). Section 98.233(m) only covers natural gas that is not recovered
from the production operation.

Question: Why does EPA specify that reporters should subtract out volumes sent to flares
to account for the portions of gas routed from dehys, completions and workovers. The flare
emissions include all of the sources. This additional accounting is overly burdensome.

Response: EPA requires tracking of flare emissions from individual sources of emissions to
inform policy. See the response to EPA-HQ-OAR-2009-0923-1018-37 for further discussion on
this subject.

Question: 98.233(n)(2)(ii) indicates that if a gas processing plant does not have a
continuous gas composition analyzer, the composition of the flared stream depends on
whether the gas flared is upstream of the demethanizer or downstream of the demethanizer.
However, at gas processing facilities, flared gas can be a combination of gases before and
after the demethanizer. In this situation, how is flare gas composition to be determined for
use in Equations W-19 through W-21?

Response: As per section 98.233(n)(l) the reporter shall estimate the proportion of flare gas
upstream and downstream of the demethanizer and use the composition as determined in
98.233(n)(2) to determine flare gas emissions.

Question: How is the composition for flare gas calculations determined if using a
continuous analyzer (e.g., annual average)? Based on the Preamble, EPA is allowing reporters
to use existing sampling data (e.g., composition analysis of gas sold) if reporters do not have a
continuous gas composition analyzer already installed. This wording is more clear than
98.233(n)(2).

Response: If using a continuous analyzer the reporter should use best representation of gas
sent to flare. EPA's intent on gas composition of gas to flare is as provided in section
98.233(n)(2).

Question: Under §98.232(e), emissions from flares are not a required source for calculation
and reporting. Under section §98.233(o)(9), however, emissions from flares associated with
centrifugal compressors must be reported. There are multiple cases throughout Subpart W

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where these confusions exist (i.e. section §98.233(k)(4), which is specific to the transmission
compression industry segment). Please clarify which section of the rule is the correct guiding
action.

Response: Under §98.232(e), the flare stack emission source is not required for reporting by
natural gas compression facilities. However, this does not exclude the other emission sources
listed in §98.232(e) if they are routed to a flare. The flare source type in 98.233(n) covers only
emissions that are not reported in any of the other source types in 98.233; see 98.233(n)(9). For
example, if transmission storage tank emissions are going to a flare then the rule requires the
adjustment of transmission storage tank emissions sent to flare per section 98.233(k)(4). The
transmission storage tank flare emissions, however, have to be reported as transmission
storage tank emissions under 98.236(c)(9).

Question: Is flare combustion reported separately?

Response: All applicable industry segments must report emissions from flares. Emissions
from sources listed under 98.233 that are routed to a flare must be reported under that
particular emissions source, not under the flare source type to avoid double counting of
emissions. Please see section 98.233(n)(9).

All hydrocarbon streams that are sent to a flare that result in CH4, C02, and N20 emissions
must be reported under subpart W. Please see section 98.233(n)(2)(iii), which states "When the
stream going to the flare is a hydrocarbon product stream, such as ethane, propane, butane,
pentane-plus and mixed light hydrocarbons, then use a representative composition from the
source for the stream determined by engineering calculation based on process knowledge and
best available data."

Section 98.233(n) provides several methods to determine the composition of gas going to the
flare. The reporter may either analyze the gas mixture before or after mixing as long as it is
representative of the flare gas. This determination should be documented in the monitoring
plan in 98.3(g).

Question: Does a simple open pipe with no flare tip count as a flare under 98.233 (n) in
Subpart W?

Response: The flare definition in 98.6 does not indicate any exclusion, therefore, a simple
open pipe with no flare tip is covered as a flare.

Question: I wanted to confirm that for flares at onshore natural gas production facilities,
C02, CH4 and N20 should be reported; while at onshore natural gas processing facilities, only
C02 and CH4 should be reported. Is this correct?

Response: You are required to report C02, CH4 and N20 emissions for all flare stacks.
98.232(j) clearly states that all applicable industry segments must report the C02, CH4 and N20
emissions from each flare. Flare stacks are included to be reported under natural gas

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processing facilities (98.232(d)(6)). The calculation methodology for flare stack emissions
includes the method for quantifying N20 emissions from these stacks (See section
98.233(n)(8)).

Question: Under Subpart W, under both the onshore production and gas processing source
categories, are we required to report emissions from ALL flares at the gas processing facility
or on/associated with a well pad? In particular, are emergency flares to be counted?

Response: Yes, emergency flares are covered under the general category of flares, for
reporting purposes EPA needs accurate data on flare emissions to better understand this
emission source, including startup, shutdown and malfunction events, as flare use can vary
significantly from day-to-day and year-to-year. EPA sought to reduce the burden associated
with the flare monitoring and reporting requirements. In the final rule, EPA allows the use of
engineering calculations based on process knowledge, company records, and best available
data for estimating flow volumes; and for gas composition the use of appropriate gas
compositions.

Question: In section 98.233(n) concerning calculation of emissions from flaring, paragraph
(n)(8) provides a means of calculating N20, however, nothing is said about converting this
emission rate to C02e. Should the N20 emissions be multiplied by the GWP for N20 similar to
the procedure in paragraph (n)(6) for C02 and CH4 then added to the total for C02 and CH4
C02e amounts as suggested in paragraph (n)(7)?

Response: Thank you for alerting EPA to the non availability of a method to convert the
emission results from Eq. W-40 to metric tons C02 equivalent; we are considering options to
address this. You may use a multiplier of 310 to convert the metric tons of N20 into C02e.

Question: We noticed in Subpart W of the MRR on page 74498 (n) Flare Stack Emissions
that the calculation methods do not offer use of a CEMS as a valid method of quantifying
emissions for flare stacks. The dehydration vent stack source category and the AGR unit vent
stack source category both allow use of a CEMS to quantify emissions. Was it possibly an
oversight to not allow use of a CEMS as a quantification method on flares? Most facilities are
more likely to have a CEMS on the flare than the dehy/AGR units, and given the extremely
large variance in possible products going to the flare, the CEMS would likely be much more
accurate than any calculation.

Response: You must follow the calculation and monitoring requirements in the rule. You
are correct that 98.233(n) does not allow the use of CEMS as a method for quantifying
emissions for flare stacks. We may consider this issue further in future amendments to the
rule.

Other: Pneumatic Devices

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Question: Equation W-l, legend entry for GHGi includes reference to facilities listed in
98.230(a)(3) through (a)(8). However, reporting for this source (pneumatic device venting) is
required only for onshore production (which is specifically mentioned earlier in this
legend item), and NG transmission compression and underground NG storage, which are
98.230(a)(4) and (a)(5) respectively. I recommend changing this reference in the legend to
reference only (a)(4) and (a)(5), to avoid confusion.

Response: For the source of pneumatic device venting, section §98.233(a)(1) and (a)(2)
outlines the segments to be considered for emissions reporting from this source, in the
definition of the term 'count'. Further, the definition of the term 'EF' highlights the sectors that
are relevant for this source. The reference of sections §98.233(a)(3) through §98.233(a)(8) is a
generic reference to the term 'GHGi.'

Leak Detection and Equipment Leaks

Question: What types of equipment meet the requirements of Method 21? We understand
that "Gas Rangers" qualify. What other brands of hand held gas wand devices qualify? Could
you provide a list? Or could we rely on the vendor to certify compliance of the device?
Method 21 provides specs in Section 6 - e.g., instrument scale readable to 2.5% of leak
definition (or 250 ppm in this rule which is 2.5% of 10,000 ppm). Could EPA allow an option
that does not require such fine resolution (e.g., if you can detect 10,000 ppm - the threshold
for having a defined "leak" - it should not matter whether the device scale is readable to 250
ppm). Method 21 performance specifications may inadvertently exclude some devices that
can accurately measure the leak threshold of 10,000 ppm. Does the rule provide an avenue to
use those devices?

Response: Method 21 describes industry practices reviewed and established by EPA as a
standard for the measurement of volatile organic compound leaks. The methodology has been
mutually accepted by EPA and industry and used in practice for many years, and EPA references
it in the interest of reducing burden on the user and assuring consistency of measurements. As
such, EPA also relies on the quality assurance standards built into Section 6.3 of the existing
methodology, which specify that the "scale of the instrument meter shall be readable to ±2.5
percent of the specified leak definition concentration;" in the case of Subpart W this translates
to 2.5% of 10,000 ppm, or 250 ppm. Rather than recommending one particular type of brand
of equipment, defining the methodology and instrumentation accuracy allows the user to select
from a range of equipment options to best suit their individual situation.

Subpart W allows for facilities to use alternatives to the Method 21 approach and such
provisions are outlined in the rule. For example, facilities are also given the option of using
other methods such as an optical gas imaging device in the Alternative Work Practice to
Method 21, or acoustic leak detection methods to monitor sources. For additional information,
please see the response to comment EPA-HQ-OAR-2009-0923-1039-18.

Question: Documentation for Leak Surveys of Components: What documentation is
required for leak surveys? Must all connectors, block valves, control valves, pressure relief

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valves, office meters, regulators, and open ended lines be documented regardless if they are
leaking or not. Currently, we check all connectors, valves, etc. but only document the actual
leaks. If documentation will be needed on all components surveyed, then that would place an
additional burden of recordkeeping and additional manpower will be needed to meet the
requirements.

Response: For emissions source types indicted in 98.232(i)(l), the rule requires facilities to
report the "total count of leaks found in each complete survey listed by date of survey and each
type of leak source". Therefore, only leakers are to be reported, not the entire population of
equipment/ components. Please refer to section 98.236(b) (15)(i). There are no recordkeeping
requirements for emissions sources determined not to be leaking.

Question: Option for Direct Measurement & Facility-Specific Emission Factors: Can a
facility choose between (a) the provided emission factors or (b) conducting a statistical
analysis and calculating a site-specific emission factor and applying it "across the board" to
that facility and to other facilities with like equipment?

Response: EPA requires that the reporters use emissions factors provided in the rule, except
where a facility-specific emission factor is specifically required (e.g., above grade M&R at city
gate stations). EPA does not allow for statistical analysis based emissions on a reporter by
reporter basis as this cannot be verified easily and can result in non-standard reporting across
the reporting facilities.

Question: Can you tell me if the Hi Flow Sampler qualifies as a meter? It quantifies like any
type of flow meter.

Response: Section 98.234 (a) states that any of the methods including flow meters, calibrated
bags, or high volume samplers may be used for quantifying equipment leaks and through-valve
leakage. While EPA does not endorse a specific equipment manufacturer, high volume
samplers (including the Hi Flow Sampler) can be used as a method for leak quantification as
well as long as it conforms to requirements in 98.234(d).

Question: Under Subpart W, Section 98.233 (q) addressing leak detection and leaker
emission factors: Provided the streams with gas content greater than 10 percent methane
plus carbon dioxide by weight are monitored, can monitoring data from a state permit
required fugitive emissions monitoring program already in place, which has a lower leak
detection rate of 500 ppm, be used to estimate fugitive greenhouse gas emissions?

Response: You must follow the methods outlined in the rule. The reporter has to determine
whether the concentration limits required by the state permit fall within or outside the 10
percent by weight methane plus carbon dioxide limit imposed by Subpart W. Concentration of
GHGs in a leak cannot be always correlated with the weight percent of the GHGs in the stream
that is leaking. This is because concentrations of GHGs in the leak are dependent on external
factors that cause dispersion of the emissions. Hence EPA cannot provide concrete guidance on
using State specified limits that are not directly comparable to Subpart W requirements.

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Question: In the "Leak Detection and leaker emission factor" subsection, I see that this
section is not applicable to production. "You must...conduct leak detection of equipment
leaks from all sources listed in Section98.232 (d7), (e7), (f5), (g3), (h4), and (il). Therefore, I
wanted to clarify that leak detection is not applicable for wellheads, separators at well site,
storage tanks and other equipment defined by "production equipment".

Response: Onshore production reporters do not need to perform leak detection under
§98.233(q) for equipment leaks. For an onshore petroleum and natural gas production facility,
equipment leaks are calculated with the methodology in §98.233 (r), using population count
and population emissions factors.

Question: Method 21 leak is a reading equal to or greater than 10,000 ppm. Does this
include methane?

Response: For subpart W the Method 21 leak definition concentration is 10,000 ppm
methane.

Question: Can leak repair logs be used to determine leak duration?

Response: Leaks found during a single leak survey performed during the calendar year, must
be assumed to be leaking since the beginning of the calendar year. If multiple complete leak
detection surveys are conducted, reporters must assume that the component found to be
leaking has been leaking since the previous survey whereby no leak was found or the beginning
of the calendar year, whichever is more recent. See section 98.233(q) for further details.

Question: Subsection 98.234(a)(4) states: "An optical gas imaging instrument must be used
for all source types that are inaccessible and cannot be monitored without elevating the
monitoring personnel more than 2 meters above a support surface." This seems
straightforward, but we have encountered other entities who insist that other monitoring
methods, such as other Method 21 compliant instruments, may be used in conjunction with
manlifts to perform this monitoring. Are there circumstances, or component classes, for
which use of other instruments and elevation of personnel is acceptable?

Response: The final Subpart W rule does not allow for Method 21 compliant instruments to
be used for inaccessible sources. Thank you for alerting EPA on this issue; we are considering
options to address this.

Question: Calculation section 98.233(r) regarding "Population Count and Emission Factors"
states that "This paragraph applies to emissions sources listed in §98.232 (c)(21), (f)(5), (g)(3),
(h)(4), (i)(2), (i)(3), (i)(4), and (i)(5), on streams with gas content greater than 10 percent CH4
plus C02 by weight." This does not contain any references to the source categories of
"Onshore Natural Gas Processing" or "Onshore Natural Gas Transmission Compression".

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However, reporting section 98.236(c)(15)(ii)(A) states "For source categories §98.230(a)(3),
(a)(4), (a)(5), (a)(6), and (a)(7), total count for each type of leak source in Tables W-2, W-3, W-
4, W-5, and W-6 of this subpart for which there is a population emission factor, listed by
major heading and component type." Source category 98.230(a)(3) is Onshore Natural Gas
Processing and 98.230(a)(4) is Onshore Natural Gas Transmission Compression.

Please clarify which source categories are required to report for equipment leaks calculated
using population count and factors (98.233(r))?

Response: All source categories in §98.230(a)(3), (a)(4), (a)(5), (a)(6), and (a)(7) are required
to report the total count and type of leak source for which there is a population emission factor
listed in Tables W-2, W-3, W-4, W-5, and W-6. Since there are no population emission factors
listed in Table W-2 (for the processing segment), there is nothing to report under
§98.236(c)(15)(ii)(A) for the processing segment. Pneumatic devices are reported under
98.236(c)(1).

Applicability Tool ?

Question: Screening Tools - Especially for LNG Peak Shaving Facilities and Underground
Storage: When and how will EPA develop its Screening Tools to help companies determine
whether certain facilities do not need to report?

Response: The screening tools are available on the website and are created to assist in the
determination of which facilities are required to report under subpart W. Please see
.

Question: Any way we can get unlocked Subpart W screening spreadsheets (see attached)
from the applicability tool?

Response: No. EPA's intention in posting Subpart W calculation utilities is to provide facilities
with a simple tool for estimating emissions when determining applicability. Additionally, the
tools include a guidance and source tab to document how emission estimates were calculated.
The utilities are only a guide to help facilities determine their Subpart W applicability. If you
suspect a facility may exceed the annual 25,000 metric ton C02e threshold, you should refer to
the calculation methodologies in 98.233 to determine emissions.

Question: The applicability tool for Onshore Petroleum and Natural Gas has an operating
factor for associated gas venting from produced hydrocarbons. How does this operating
factor correlate with the barrels of crude oil produced?

Response: EPA has provided guidance on the operating factor in the Notes section, where it
states, "This is defined as the fraction of time the process unit is operating in a calendar year.
For example, a 90% operating factor would be entered as 0.9 because the unit is in operation
for 90% of the year."

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Question: For a 2011 report with the "Liquefied Natural Gas Storage" option selected; how
does the "calculation utility" excel spreadsheet account for "Population Count & Emission
Factors" when providing the user with a final C02e number?

Response: For the "Liquefied Natural Gas Storage" calculation utility, the spreadsheet
multiplies Population Counts, Emission Factors, and conversion factors to output methane
emissions in tonnes C02e for each source.

Final C02e emissions = (Population Count) x (Emission Factors) x (Volume conversion)

Question: Where can I find the screening tool for onshore petroleum and natural gas
production?

Response: The screening tool for onshore petroleum and natural gas production is now
available through EPA's applicability tool at

http://www.epa.gov/climatechange/emissions/GHG-calculator/index.html.

Question: I am trying to determine Subpart W applicability for a facility that falls under
source category onshore natural gas transmission compression. The calculation utility for
onshore natural gas transmission compression makes note of the fact that GHG emissions
from transmission storage tanks are not included in the calculation utility spreadsheet. The
Subpart W preamble and rule, and EPA guidance document for this source category list
transmission storage tanks as requiring direct measurement of emissions. Does EPA offer
guidance on how to estimate a worst case scenario for GHG emissions from transmission
storage tanks for purpose of determining applicability? Is there a default or assumed value
for emissions from transmission storage tanks and that is why it was left out of the
calculation utility?

Response: EPA does not have sufficient data to characterize an average emissions factor for
scrubber dump valve leakage through transmission storage tanks. Therefore, the calculation
tool does not have this source built in. Hence, it is left to the facility to consider whether this is
a significant source, including use of an acoustic detection device that has algorithms to
quantify through-valve leakage from scrubber dump valves to determine applicability.

Question: There are differences in the applicability tool calculation spreadsheets for the
estimation of vented emission from reciprocating compressor rod-packing venting. In the
Transmission Compression Tool the units are "number of compressor cylinders" while in the
Underground NG Storage Tool the units are "number of compressors". What is the difference
and which do you think should be used?

Response: EPA has developed the calculation spreadsheets using best available data to help
industry determine applicability. Based on the data available, EPA has developed factors on a
per cylinder level and compressor level for transmission and underground storage segments,
respectively. The transmission compression tool may be used for the transmission segment and

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the underground storage tool for underground storage segment. Please note that the
applicability tool is intended to assist reporting facilities/owners in understanding key
provisions of the rule. They are not intended to be a substitute for the rule.

Monitoring Plan

Question: Subparts C and W: If a facility that operates stationary combustion equipment
becomes subject the GHGRP due to Subpart W related emissions, does a GHG monitoring
plan have to be put in place by January 1 or April 1, 2011 for the basic procedures that will be
used to collect data necessary for Subpart C combustion emissions?

Response: For Subpart W, monitoring plans as outlined in 40 CFR 98.237 were to be
completed by April 1, 2011. This monitoring plan must include an explanation of the processes
and methods used to collect the necessary data for all GHG calculations, including those in both
subpart C and subpart W.

Best Available Monitoring Methods (BAMM)

Question: The June 20th proposed amendments to 40 CFR 98.234(f) Best Available
Monitoring Methods (BAMM) will grant automatic BAMM until December 31, 2011. As
currently published, operators are required to submit BAMM extension requests by July 31st
for BAMM extension until December 31st 2011. Does EPA expect to have a final rule
published prior to the July 31st deadline operators currently face for BAMM extension
requests?

Response: You are correct that on April 25, 2011, EPA finalized a rule extending the deadline
for submission of a request to use BAMM until July 31, 2011 (76 FR 22825). On June 27, 2011, a
proposed rule was published in the Federal Register that would allow automatic use of BAMM
for the entire 2011 reporting year for emissions sources covered under subpart W (Petroleum
and Natural Gas Systems) without seeking approval from EPA (76 FR 37300). The public
comment period for the proposed rule will be open through July 27, 2011. Given the timing
necessary to consider public comment and finalize the rule, EPA will not be able to promulgate
the final rule by July 31, 2011. Please note that 40 CFR 98.234(f)(1) indicates that "If the
reporter anticipates the potential need for best available monitoring for sources for which they
need to petition EPA and the situation is unresolved at the time of the deadline, reporters
should submit written notice of this potential situation to EPA by the specified deadline for
requests to be considered." EPA agrees that as of July 31, 2011, the circumstances surrounding
the applicability of the deadline will be "unresolved" and that submitting a notification of intent
would satisfy the rule requirements.

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General

Question: Is there a PowerPoint presentation available on the reporting rule signed by
Administrator Jackson on November 8, 2010 for the petroleum and natural gas facilities? We
would like to share the presentation with our state technical advisory committee.

Response: A PowerPoint briefing on Subpart W, Petroleum and Natural Gas Systems, as well
as other supporting materials are available on the Subpart W page of the Greenhouse Gas
Reporting Program website at http://www.epa.gOv/climatechange/emissions/subpart/w.html.

Question: Subpart W states that external combustion sources with rated heat
capacity equal to or less than 5 MMbtu/hr do not need to report combustion emissions. Do
the emissions from these sources need to be included in the 25,000 metric ton threshold
determination?

Response: The emissions from external combustion equipment equal to or below the
threshold do not have to be included in the determination of reporting threshold for the
facility. Please see response to comment EPA-HQ-OAR-2009-0923-1060-27.

Question: My question concerns the calculation of standard temperature and pressure. The
rule stipulates what standard temperature and pressure are, but how, for an annual average,
is actual temperature and pressure defined. Is it conditions at the time data were collected?
Is it the average temperature and pressure for a given location based on annual averages? Is
it something else? Flow sensors are going to read actual CFM not SCFM.

Response: Actual temperature and pressure as defined for 98.233 is the "average
atmospheric conditions or typical operating conditions." Therefore, the average temperature
and pressure at a given location based on annual averages can be used for actual temperature
and actual pressure.

Question: Should self-propelled workover equipment and truck loading/unloading be
included for reporting GHG emissions under Subpart W?

Response: If the power take-off for operating the truck mounted workover rig is the truck
wheel drive engine (i.e. a transmission option to transfer the truck wheel drive shaft to
powering the rig generator or wench or other rig equipment) then yes, this workover rig
arrangement is "self propelled." and not required to be reported. However, if the truck has a
separate engine not connected to the drive wheels that powers the workover rig equipment,
then it is "non-self propelled" and must be included in your report.

Question: How do I define a facility under subpart W? Are all industry segments included in
one annual GHG report?

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Response: An onshore production facility is defined in 40 CFR 98.238 and will report only
those emissions from the emissions sources listed in 40 CFR 98.232. The onshore production
facility has a single designated representative and does not include other industry segments or
other source categories in its annual GHG report. Similarly, if a facility meets the definition for
natural gas distribution that facility reports only what's listed in 98.232(i). All other industry
segments under subpart W use the definition of facility in subpart A and report emissions in a
single annual GHG report. Each facility must have one and only one designated representative.
But, the same DR could represent multiple facilities. Other than onshore production and
natural gas distribution, it is possible for a single facility to report under multiple industry
segments. Please see requirements in 98.231(a) and response to comment EPA-HQ-OAR-2009-
0923-1024-14 in the EPA's final Response to Public Comments Document for subpart W.

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