already subject to subpart W and may require the development and
implementation of new systems of data collection and monitoring.
Therefore, the EPA is finalizing 1 year of automatic transitional BAMM
in place of the proposed 3 months of automatic transitional BAMM. This
additional time for reporters to comply with the revised monitoring
methods in subpart W will allow facilities to install the necessary
monitoring equipment and implement any new systems of data collection
that may be required. Because the amount of time for which automatic
BAMM is available should be sufficient time to comply with the
requirements of subpart W for the new segments and emission sources,
the EPA will not provide additional BAMM beyond the automatic BAMM
provisions in 40 CFR 98.234(g).
    We note that 40 CFR 98.235(e) and(f) provides 6 months of reporting
flexibility for facilities that become subject to subpart W or acquire
new sources after reporting year 2016. Reporters may also refer to the
provisions of 40 CFR 98.235 after reporting year 2016 for guidance on
reporting emissions if certain required data are not collected.

III. Confidentiality Determinations

A. Summary of Final Confidentiality Determinations for New Subpart W
Data Elements

    In the proposed rule, we assigned new data elements to the
appropriate direct emitter data categories created in the 2011 Final
CBI Rule based on the type and characteristics of each data
element.\10\ For data elements the EPA assigned to a direct emitter
category with a categorical determination, the EPA proposed that the
categorical determination for the category be applied to the proposed
new data element. For data elements assigned to the ``Unit/Process
`Static' Characteristics that Are Not Inputs to Emission Equations''
and ``Unit/Process Operating Characteristics that Are Not Inputs to
Emission Equations,'' we proposed confidentiality determinations on a
case-by-case basis taking into

consideration the criteria in 40 CFR 2.208, consistent with the
approach used for data elements previously assigned to these two data
categories. We also proposed individual confidentiality determinations
for six new data elements without making a data category assignment.
Refer to the preamble to the proposed rule (79 FR 76267; December 9,
2014) for additional information regarding the proposed confidentiality
determinations.
---------------------------------------------------------------------------

    \10\ ``Confidentiality Determinations for Data Required Under
the Mandatory Greenhouse Gas Reporting Rule and Amendments to
Special Rules Governing Certain Information Obtained Under the Clean
Air Act'' (76 FR 30782, May 26, 2011).
---------------------------------------------------------------------------

    With consideration of the data provided by commenters, the EPA is
finalizing the confidentiality determinations as proposed.
Specifically, the EPA is finalizing the proposed decision to require
each of the new data elements to be designated as ``not CBI.''
    The EPA proposed to provide reporters with the option to delay
reporting of five data elements for 2 reporting years in situations
where exploratory wells are the only wells in a sub-basin. We received
comment requesting that the EPA provide the same 2-year delay for
additional data elements associated with exploratory wells. The comment
and the EPA's response are included in section III.B of this preamble.
Based on consideration of the comment and consistent with the EPA's
previous decisions related to exploratory wells under part 98 (79 FR
63750, October 24, 2014; 79 FR 70352, November 25, 2014), the EPA is
finalizing provisions to provide reporters with the option to delay
reporting of five data elements as proposed and, based on comments
received, an additional two data elements for 2 reporting years in
situations where exploratory wells are the only wells in a sub-basin.
For a given sub-basin, in situations where wildcat wells and/or
delineation wells are the only wells in a sub-basin that can be used
for the required measurement, the following seven data elements
associated with the delineation or wildcat well may be delayed for 2
reporting years: (1) The cumulative gas flowback time, in hours, for
each sub-basin, from when gas is first detected until sufficient
quantities are present to enable separation (40 CFR 98.236(g)(5)(i));
(2) the cumulative flowback time, in hours, for each sub-basin, after
sufficient quantities of gas are present to enable separation (40 CFR
98.236(g)(5)(i)); (3) the measured flowback rate, in standard cubic
feet per hour, for each sub-basin (40 CFR 98.236(g)(5)(ii)); (4) the
gas to oil ratio for the well (40 CFR 98.236(g)(5)(iii)(A)); (5) the
volume of oil produced during the first 30 days of production after
completions of each newly drilled well or well workover using hydraulic
fracturing (40 CFR 98.236(g)(5)(iii)(B)); (6) the total annual gas-
liquid separator oil volume that is sent to applicable onshore storage
tanks, in barrels (40 CFR 98.236(j)(1)(iii)); and (7) the total annual
oil throughput that is sent to all atmospheric tanks, in barrels (40
CFR 98.236(j)(2)(i)(A).
    Four of the seven data elements for which reporting may be delayed
by 2 years are inputs to emission equations and the EPA provided the
same option in the EPA's previous decisions related to exploratory
wells under part 98 (79 FR 63750, October 24, 2014). Two of the seven
data elements are inputs only when the applicable data are related to a
single well (the two data elements in 40 CFR 98.236(g)(5)(i)), and one
data element is never an input (40 CFR 98.236(j)(2)(i)(A)). Where the
EPA agrees that there are early disclosure concerns related to
exploratory wells, the EPA decided to treat those early disclosure
concerns consistently throughout subpart W by providing the option to
delay reporting by 2 years to all seven data elements listed above.
    At proposal, in cases where the two data elements in 40 CFR
98.236(g)(5)(i)) are not inputs to equations, they were assigned to the
``Unit/Process Operating Characteristics that are Not Inputs to
Emission Equations'' category and were proposed to be ``not CBI.'' The
EPA is finalizing this determination as proposed. Specifically, the
``not CBI'' determination applies to all situations except for when the
data elements are inputs to equations.
    For the situations when the data elements are used as inputs to
equations, the EPA is assigning them to the ``Inputs to Emission
Equations'' data category and is not making confidentiality
determinations for these data. The EPA evaluated and summarized any
potential disclosure concerns with the reporting of the data elements
assigned to the ``Inputs to Emission Equations'' data category in the
memo titled ``Review for Potential Disclosure Concerns for Inputs to
Emission Equations Affected by the 2015 Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems'' available in
Docket ID No. EPA-HQ-OAR-2014-0831. Other than the exception of the
early disclosure concerns for certain data elements related to
exploratory wells discussed earlier in this section, the EPA has
concluded that there are no disclosure concerns with the reporting of
these data elements.
    The data element collected under 40 CFR 98.236(j)(2)(i)(A) was
proposed as ``not CBI'' and was not assigned to a data category. The
EPA is finalizing this determination as proposed as well. For the data
elements reported under 40 CFR 98.236(g)(5)(i)) (in cases where they
are not inputs to equations) and 40 CFR 98.236(j)(2)(i)(A), the ``not
CBI'' determinations will apply once the data are reported to the EPA
following the 2-year delay.

B. Summary of Comments and Responses

    This section summarizes the major comments and responses related to
the proposed categorical assignments and confidentiality
determinations. See ``Response to Public Comments on Greenhouse Gas
Reporting Rule: 2015 Revisions and Confidentiality Determinations for
Petroleum and Natural Gas Systems'' in Docket ID No. EPA-HQ-OAR-2014-
0831 for a complete listing of all comments and responses. See the
memorandum ``Final Data Category Assignments and Confidentiality
Determinations for Data Elements (excluding inputs to emission
equations) in the `Greenhouse Gas Reporting Rule: 2015 Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems;
Final Rule' '' in Docket ID No. EPA-HQ-OAR-2014-0831 for a complete
listing of final data category assignments and confidentiality
determinations, and a discussion of changes since proposal.
    Comment: One commenter requested that the EPA reconsider the
determination that the quantity of produced gas throughput in the
calendar year and the quantity of produced gas consumed by the facility
in the calendar year are ``not CBI.'' The commenter noted that the
quantity of natural gas received and the quantity of processed gas
leaving processing plants was maintained as CBI in the 2014 amendments
(79 FR 70352; November 25, 2014). The commenter also stated that
information on fuel consumed at gathering and boosting facilities is
not typically publically available, and when this information is
combined with the quantity of produced gas throughput, it directly
indicates the fuel efficiency of a station. The commenter noted that
while the EPA is correct that the agreements are long-term for a given
well, revealing information about one facility's fuel efficiency could
cause competitive harm by affecting contracts for other facilities
owned by that company, especially if there are smaller gathering and
boosting facilities in the area that do not have to report this
information to the GHGRP.
    The commenter also requested that the EPA clarify a number of the
reporting elements in 40 CFR

98.236(aa)(10). Specifically, the commenter requested clarification of
the terms ``produced gas,'' ``produced condensate,'' ``produced oil,''
``throughput,'' and ``consumed'' as they are used in proposed 40 CFR
98.236(aa)(10). The commenter also asserted that the data element in 40
CFR 98.236(aa)(10)(ii) (``quantity of produced gas consumed'') would be
redundant with subpart C and should not be finalized. Finally, the
commenter stated that the requirement to report the ``quantity of gas
flared, vented and/or unaccounted for in the calendar year'' in 40 CFR
98.236(10)(aa)(v) would undermine over 5 years of rule development,
public comment, reconsiderations, and petitioner negotiations because
it would require reporting of emissions that are otherwise exempted
(e.g., blowdowns below 50 ft\3\).
    Response: The EPA reviewed these comments and has clarified the
reporting elements in 40 CFR 98.236(aa)(10) for the final rule. The
final reporting requirements include: (1) The quantity of gas received
by the gathering and boosting facility in the calendar year, in
thousand standard cubic feet; (2) the quantity of gas transported to a
natural gas processing facility, a natural gas transmission pipeline, a
natural gas distribution pipeline, or another gathering and boosting
facility in the calendar year, in thousand standard cubic feet; (3) the
quantity of all hydrocarbon liquids received by the gathering and
boosting facility in the calendar year, in barrels; and (4) the
quantity of all hydrocarbon liquids transported to a natural gas
processing facility, a natural gas transmission pipeline, a natural gas
distribution pipeline, or another gathering and boosting facility in
the calendar year, in barrels. The EPA has determined that these
quantities will be easily accessible for all reporters and are more
consistent with the reporting requirements for the Onshore Natural Gas
Processing segment. The EPA is finalizing the CBI determinations for
these quantities as ``not CBI,'' as proposed.
    The final reporting requirements do not include the terms
``produced gas,'' ``produced condensate,'' ``produced oil,''
``throughput,'' or ``consumed,'' so no clarification regarding the use
of those terms is needed. In particular, the final rule does not
include a requirement to report the quantity of produced gas consumed
by the facility. The difference between the quantities received by a
gathering and boosting facility and the quantities exiting the
gathering and boosting facility is expected to include the quantity of
gas consumed by the facility as well as the quantity of gas flared or
vented in one lump sum. Therefore, the reporting requirements do not
directly indicate the fuel efficiency of the stations in a gathering
and boosting facility.
    Comment: One commenter reiterated previously stated concerns over
the disclosure of information for exploratory wells, especially when
they are located in stepout areas where no prior reporting exists for a
given sub-basin. The commenter supported the EPA's proposal to defer
reporting of data elements related to oil well completions and
workovers with hydraulic fracturing for exploratory wells, but
expressed concern that EPA has not provided such a delay in reporting
for all emissions data and data elements that are associated with
exploratory wells. Specifically, the commenter stated that the EPA
failed to provide a necessary 2-year deferral in reporting for the
following data elements, which are as business sensitive and
confidential as the other information for which the EPA proposed to
defer reporting for 2 years:

     40 CFR 98.236(g)(5)(iii)(A)--If you used Equation W-12C
to calculate the average gas production rate for an oil well, the
gas to oil ratio for the well in standard cubic feet of gas per
barrel of oil.
     40 CFR 98.236(g)(5)(iii)(B)--If you used Equation W-12C
to calculate the average gas production rate for an oil well, the
volume of oil produced during the first 30 days of production after
completions of each newly drilled well or well workover using
hydraulic fracturing, in barrels.
     40 CFR 98.236(g)(6)(i)--If you used Equation W-10B to
calculate annual volumetric total gas emissions for completions that
vent gas to the atmosphere, the vented natural gas volume, in
standard cubic feet, for each well in the sub-basin.
     40 CFR 98.236(g)(6)(ii)--If you used Equation W-10B to
calculate annual volumetric total gas emissions for completions that
vent gas to the atmosphere, the flow rate at the beginning of the
period of time when sufficient quantities of gas are present to
enable separation, in standard cubic feet per hour, for each well in
the sub-basin.
     40 CFR 98.236(g)(7)--For each oil well completion or
workover and well type combination, annual gas emissions.
     40 CFR 98.236(g)(8)--For each oil well completion or
workover and well type combination, annual CO2 emissions.
     40 CFR 98.236(g)(9)--For each oil well completion or
workover and well type combination, annual CH4 emissions.
     40 CFR 98.236(g)(10)--For each oil well completion or
workover and well type combination, the total N2O
emissions, if the well emissions were vented to a flare.

    Response: The EPA reviewed the data elements identified by the
commenter as having disclosure concerns for exploratory wells
(delineation wells and wildcat wells). Consistent with the EPA's
previous decisions related to exploratory wells under part 98 (79 FR
63750, October 24, 2014; 79 FR 70352, November 25, 2014), the EPA has
determined that, for gas well completions or workovers with hydraulic
fracturing of wildcat wells and/or delineation wells, early public
disclosure of some of the additional data elements identified by the
commenter could reveal the well productivity of wildcat wells and/or
delineation wells, thereby resulting in the loss of investment value.
    The additional data elements that could reveal well productivity
for wildcat and/or delineation wells are as follows:

     The gas to oil ratio for the well (40 CFR
98.236(g)(5)(iii)(A))
     The volume of oil produced during the first 30 days of
production after completions of each newly drilled well or well
workover using hydraulic fracturing (40 CFR 98.236(g)(5)(iii)(B))

    As the EPA has previously noted (79 FR 70352, November 25, 2014),
in the interim period before these data are reported to the EPA, the
EPA will be able to verify the majority of the emissions using data
elements that will be reported to the EPA. For the seven total data
elements that may be delayed for 2 years, the EPA will verify emissions
using other data reported to the EPA, and will conclude verification
upon receipt of the data. The EPA agrees with the commenter that a 2-
year delay of reporting is sufficient to prevent early public
disclosure of these data and will provide sufficient time for the
reporter to thoroughly conduct an assessment of the well. Given the
results of this evaluation, the EPA determined that, for these data
elements, in those cases where delineation wells or wildcat wells are
the only wells in a sub-basin, reporters should be provided an option
to delay reporting of the given data element for 2 reporting years
starting in 2015. In such cases, if the 2-year delay in reporting is
used, the reporter must indicate for each delayed reporting element
that wildcat wells and/or delineation wells are the only wells in a
sub-basin that can be used for the measurement in the current reporting
year. In addition, when reporters report the delayed data elements
after the 2-year delay, they must also report the well identification
numbers for the applicable wildcat and/or delineation wells in the sub-
basin for which the reporting element was delayed. For example, if a
delineation or wildcat well is completed in 2015 in a sub-basin that

has only delineation or wildcat wells or these are the only wells for
which measurements can be made, then the reporter may: (1) Elect to
report these seven data elements in their 2016 annual report submitted
by March 31, 2017, or (2) elect to delay reporting of these data
elements for up to 2 years. If the reporter elects to delay reporting,
then the well identification numbers for the wildcat and delineation
wells in the sub-basin for which reporting has been delayed and the
data elements delayed from reporting must be reported no later than
March 31, 2019.
    The following inputs meet the definition of emission data in 40 CFR
2.301(a)(2)(i) because they indicate the amount or frequency of gas
emitted by the facility: Volume of natural gas vented (reported under
40 CFR 98.236(g)(6)(i)) and flow rate at the beginning of the period of
time when sufficient quantities of gas are present to enable separation
(reported under 40 CFR 98.236(g)(6)(ii)). Without corresponding
activity data, such as a count of the exploratory wells in a sub-basin
or production or flow rate data for a sub-basin containing only
exploratory wells, there is no potential to disclose business sensitive
information based on these data elements. Therefore, the EPA is not
providing an option to delay reporting of these data elements for 2
reporting years.
    Similarly, the data element annual gas emissions (reported under 40
CFR 98.236(g)(7)) meets the definition of emission data in 40 CFR
2.301(a)(2)(i) and is assigned to the ``Emissions'' data category
because it indicates the amount of gas emitted by the facility. In
addition, the following data elements meet the definition of emission
data in 40 CFR 2.301(a)(2)(i) and are assigned to the ``Emissions''
data category because they are emissions of pollutants emitted by the
source: annual CO2 emissions (reported under 40 CFR
98.236(g)(8)), annual CH4 emissions (reported under 40 CFR
98.236(g)(9)), and annual nitrous oxide (N2O) emissions if
the well emissions were vented to a flare (reported under 40 CFR
98.236(g)(10)). For these data elements that are assigned to the
``Emissions'' data category, the commenter did not claim or provide any
justification for why these data elements do not meet the definition of
emission data. Without corresponding activity data, such as a count of
the exploratory wells in a sub-basin or production or flow rate data
for a sub-basin containing only exploratory wells, there is no
potential to disclose business sensitive information based on these
data elements. Therefore, the EPA is not providing an option to delay
reporting of these data elements for 2 reporting years.

IV. Impacts of the Final Amendments to Subpart W

A. Impacts of the Final Amendments

    The final amendments to subpart W add monitoring and reporting
requirements for reporters in three industry segments: Onshore
Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas
Gathering and Boosting, and Onshore Natural Gas Transmission Pipeline.
The EPA is adding 213 new data elements to the reporting requirements.
The new data elements impose additional burden and costs because, for
each of the new data elements that are required to be reported,
reporters are required to calculate the data element using readily
available data and report the value to the EPA via e-GGRT as part of
the annual report currently required under part 98.
    The EPA calculated the increase in reporting and recordkeeping
burden associated with the new data elements by adjusting labor hours
upwards per reporter for all affected industry segments. For all three
segments, an estimate of 10 hours per year per reporter was allotted
for reporting via e-GGRT and 10 hours per year per reporter was
allotted for recordkeeping.
    Costs to reporters associated with this rulemaking are expressed as
labor costs (i.e., the cost of labor by facility staff to comply with
the amendments), capital costs for equipment and travel, and operation
and maintenance (O&M) costs.
    Reporters in the Onshore Petroleum and Natural Gas Production
segment have to monitor and report emissions and data elements
associated with oil well completions and workovers with hydraulic
fracturing. Reporters in this segment also have to report the well
identification numbers associated with individual oil and gas wells.
The addition of the requirement to report emissions associated with oil
well completions and workovers with hydraulic fracturing is expected to
cause an increase in the amount of emissions that count towards
determining applicability under subpart W. The addition of reporting
requirements for oil wells with hydraulic fracturing is expected to
affect 246 existing reporters and to cause approximately 50 new
reporters to exceed the reporting threshold for the onshore petroleum
and natural gas production facility. These numbers have not changed
from proposal.
    The 50 new reporters will be required to estimate and report
emissions data and related data elements associated with several
different emission sources within this new industry segment, including
acid gas removal units, associated natural gas venting and flaring,
storage tanks, dehydrators, equipment leaks, liquids unloading, and
pneumatic devices.
    Reporters in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment must estimate and report emissions data and related
data elements associated with several different emission sources within
this new industry segment, including acid gas removal units, storage
tanks, blowdown vents, dehydrators, equipment leaks, flare stacks, and
pneumatic devices. Approximately 200 new reporters are expected to be
subject to subpart W due to the amendments for the Onshore Petroleum
and Natural Gas Gathering and Boosting segment in this rulemaking. This
number has not changed from proposal.
    Reporters in the Onshore Natural Gas Transmission Pipeline segment
will need to estimate and report emissions data and related data
elements associated with transmission pipeline blowdown activities.
Approximately 183 new reporters in this segment are expected to be
subject to subpart W. This number increased from 150 to 183 since
proposal due to public comment.
    The EPA received multiple comments regarding the impacts of the
proposed amendments. After evaluating these comments and reviewing
other changes from proposal, the EPA revised the impacts assessment
slightly from proposal. The final amendments to subpart W are not
expected to significantly change the burden calculated at proposal.
    The EPA has determined that the cost associated with this final
action will be $7,190,235 each year and has worked to minimize burden
to reporters where practicable. See the memorandum, ``Assessment of
Impacts of the 2015 Final Revisions to Subpart W'' in Docket ID No.
EPA-HQ-OAR-2014-0831 for additional information.

B. Summary of Comments and Responses

    This section summarizes the major comments and responses related to
the impacts of the proposed amendments to subpart W of part 98. We note
that numerous commenters asserted that the burden was underestimated,
and some provided suggestions for improvement, but most of those
comments did not include the detailed information the EPA needed to
assess the comment

fully, such as a suggestion for a revised burden estimate, support for
the suggestion, and an explanation of why the suggested value is
representative of all sources subject to the same requirements. See
``Response to Public Comments on Greenhouse Gas Reporting Rule: 2015
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems'' in Docket ID No. EPA-HQ-OAR-2014-0831 for a complete
listing of all comments and responses.
    Comment: One commenter asked for an explanation for the estimate of
200 respondents in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment. The commenter noted that the EPA estimated the number
of reporters in the Onshore Natural Gas Processing industry segment as
291 reporters. The commenter stated by the nature of the industry, any
company with a processing plant will most likely also have an
associated gathering system subject to reporting and suggested that the
number of reporters in the Onshore Petroleum and Natural Gas Gathering
and Boosting industry segment should total 291, at minimum, but
potentially more.
    Response: Due to differences in the definitions of the two industry
segments, the EPA disagrees that the number of reporters in the Onshore
Petroleum and Natural Gas Gathering and Boosting segment should match
the number of reporters in the Onshore Natural Gas Processing segment.
The EPA estimate of 200 respondents was based on the regulatory
analysis for Office of Pipeline Safety (OPS) safety regulations. In the
analysis, it was estimated that 50 percent of the 400 natural gas
gathering pipeline operators under regulation are small entities
operating small diameter, low pressure (Type B) gathering lines and
fifty percent are large diameter, high pressure lines (Type A)
potentially subject to the safety regulation (depending upon proximity
to population centers).\11\
---------------------------------------------------------------------------

    \11\ U.S. Department of Transportation. Pipeline and Hazardous
Materials Safety Administration. Draft Regulatory Evaluation,
Regulated Natural Gas Gathering Lines, Regulatory Analysis, Docket
RSPA-1998-4868. Available at www.viadata.com/pipeliner/library_docs/Gatheringanalysis.pdf.
---------------------------------------------------------------------------

    Comment: One commenter noted that the EPA estimated that there are
150 reporters for Onshore Natural Gas Transmission Pipeline facilities
at proposal. However, the commenter stated that the EPA should expect
183 reporters in the segment based on the number of operators that are
required to complete a PHMSA annual report (PHMSA F-7100-2) or are
regulated by FERC under section 311 of the NGPA.
    Response: The EPA agrees with the suggested change. The preamble to
the final amendments, the final Supporting Statement, and the
memorandum ``Assessment of Impacts of the 2015 Final Revisions to
Subpart W'' (see Docket ID No. EPA-HQ-OAR-2014-0831) have been updated
to reflect the change from 150 reporters to 183 reporters in the
Onshore Natural Gas Transmission Pipeline segment.
    Comment: Two commenters objected to the collection of well
identification numbers. One commenter noted that collection would
require significant resources and would be unduly burdensome on
operators. The other commenter stated that the burdens associated with
collecting and reporting this data far outweigh any minimal benefits in
data quality.
    Response: The EPA is finalizing the well identification number
reporting requirements for well-specific data as proposed, but the EPA
is not requiring well identification numbers to be reported in this
rulemaking for equipment other than wells. See section II.D of this
preamble for additional discussion responding to this comment.

V. Statutory and Executive Order Reviews

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

    This action is not a significant regulatory action and was
therefore not submitted to the Office of Management and Budget (OMB)
for review.
    In addition, the EPA prepared an analysis of the potential costs
associated with the final amendments to subpart W. This analysis is
contained in the memorandum ``Assessment of Impacts of the 2015 Final
Revisions to Subpart W.'' A copy of the analysis is available in the
docket for this action (see Docket ID No. EPA-HQ-OAR-2014-0831) and the
analysis is briefly summarized in section IV of this preamble.

B. Paperwork Reduction Act (PRA)

    The information collection activities in this rule have been
submitted for approval to the OMB under the PRA. The Information
Collection Request (ICR) document that the EPA prepared has been
assigned EPA ICR number 2300.16. You can find a copy of the ICR in the
docket for this rule, and it is briefly summarized here. The
information collection requirements are not enforceable until OMB
approves them.
    This action adds monitoring and reporting requirements for
reporters in three industry segments: Onshore Petroleum and Natural Gas
Production, Onshore Petroleum and Natural Gas Gathering and Boosting,
and Onshore Natural Gas Transmission Pipeline. Data collection
complements the Inventory of U.S. Greenhouse Gas Emissions and Sinks
(Inventory) and provides a critical tool for communities to identify
nearby sources of GHGs and provide information to state and local
governments. The data can be used to complement atmospheric GHG studies
and inform updates to emission inventories. Various activity data are
collected that can be used to improve understanding of the occurrence
of emissions from a variety of sources.
    Data collected must be made available to the public unless the data
qualify for CBI treatment under the CAA and EPA regulations. All data
determined by the EPA to be CBI are safeguarded in accordance with
regulations in 40 CFR chapter 1, part 2, subpart B.
    Respondents/Affected Entities: The respondents in this information
collection include owners and operators of petroleum and natural gas
systems facilities that must report their GHG emissions to the EPA to
comply with subpart W of part 98.
    Respondent's Obligation To Respond: The respondent's obligation to
respond is mandatory under the authority provided in CAA section 114.
    Estimated Number of Respondents: Approximately 3,300 respondents
per year.
    Frequency of Response: Annual.
    Total Estimated Burden: 317,100 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
    Total Estimated Cost: $29.2 million (per year), includes $1.1
million annualized capital and 2.8 million operation & maintenance
costs.
    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB
approves this ICR, the Agency will announce that approval in the
Federal Register and publish a technical amendment to 40 CFR part 9 to
display the OMB control number for the approved information collection
activities contained in this final rule.

C. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. The
small entities

subject to the requirements of this action are: (1) A small business as
defined by the Small Business Administration's regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
    The Agency has determined that a few small businesses may
experience an insignificant impact. Details of this analysis are
presented in section IV.B of the preamble to the proposed amendments
(79 FR 76267; December 9, 2014).
    Although this final rule will not have a significant economic
impact on a substantial number of small entities, the EPA nonetheless
has tried to reduce the impact of this rule on small entities. As part
of the process of finalizing the subpart W 2010 final rule, the EPA
took several steps to evaluate the effect of the rule on small
entities. For example, the EPA determined appropriate thresholds that
reduced the number of small businesses reporting. In addition, the EPA
supports a ``help desk'' for the rule, which is available to answer
questions on the provisions in the rule. Finally, the EPA continues to
conduct significant outreach on the GHG reporting rule and maintains an
``open door'' policy for stakeholders to help inform the EPA's
understanding of key issues for the industries.

D. Unfunded Mandates Reform Act (UMRA)

    This action does not contain an unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments. This action imposes
no enforceable duty on any state, local, or tribal governments or the
private sector.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government.

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

    This action has tribal implications. However, it will neither
impose substantial direct compliance costs on federally recognized
tribal governments, nor preempt tribal law. This regulation will apply
directly to petroleum and natural gas facilities that emit GHGs.
Although few facilities that will be subject to the rule are likely to
be owned by tribal governments, the EPA has sought opportunities to
provide information to tribal governments and representatives during
the development of the proposed and final subpart W that was
promulgated on November 30, 2010 (75 FR 74458).
    The EPA consulted with tribal officials under the EPA Policy on
Consultation and Coordination with Indian Tribes early in the process
of developing this regulation to permit them to have meaningful and
timely input into its development. A summary of that consultation is
provided in section IV.F of the preamble to the re-proposal of subpart
W published on April 12, 2010 (75 FR 18608), and section IV.F of the
preamble to the subpart W 2010 final rule published on November 30,
2010 (75 FR 74458).

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

    The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern environmental health or safety risks,
that the EPA has reason to believe may disproportionately affect
children, per the definition of ``covered regulatory action'' in
section 2-202 of the Executive Order. This action is not subject to
Executive Order 13045 because it does not concern an environmental
health risk or safety risks.

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

    This action is not subject to Executive Order 13211, because it is
not a significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act (NTTAA)

    This rulemaking does not involve technical standards.

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

    The EPA believes the human health or environmental risk addressed
by this action will not have potential disproportionately high and
adverse human health or environmental effects on minority, low-income
or indigenous populations because it does not affect the level of
protection provided to human health or the environment. Instead, this
rule addresses information collection and reporting procedures.

K. Congressional Review Act (CRA)

    This action is subject to the CRA, and the EPA will submit a rule
report to each House of the Congress and to the Comptroller General of
the United States. This action is not a ``major rule'' as defined by 5
U.S.C. 804(2).

List of Subjects in 40 CFR Part 98

    Environmental protection, Administrative practice and procedure,
Greenhouse gases, Reporting and recordkeeping requirements.

    Dated: October 1, 2015.
Gina McCarthy,
Administrator.

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

PART 98--MANDATORY GREENHOUSE GAS REPORTING

0
1. The authority citation for part 98 continues to read as follows:

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

Subpart W--Petroleum and Natural Gas Systems

0
2. Section 98.230 is amended by adding paragraphs (a)(9) and (10) to
read as follows:

Sec.  98.230  Definition of the source category.

    (a) * * *
    (9) Onshore petroleum and natural gas gathering and boosting.
Onshore petroleum and natural gas gathering and boosting means
gathering pipelines and other equipment used to collect petroleum and/
or natural gas from onshore production gas or oil wells and used to
compress, dehydrate, sweeten, or transport the petroleum and/or natural
gas to a natural gas processing facility, a natural gas transmission
pipeline or to a natural gas distribution pipeline. Gathering and
boosting equipment includes, but is not limited to gathering pipelines,
separators, compressors, acid gas removal units, dehydrators, pneumatic
devices/pumps, storage vessels, engines, boilers, heaters, and flares.
Gathering and boosting equipment does not include equipment reported
under any other industry segment defined in this section. Gathering
pipelines operating on a vacuum and gathering pipelines with a GOR)
less than 300 standard cubic feet per stock tank barrel (scf/STB) are
not included in this industry segment (oil

here refers to hydrocarbon liquids of all API gravities).
    (10) Onshore natural gas transmission pipeline. Onshore natural gas
transmission pipeline means all natural gas transmission pipelines as
defined in Sec.  98.238.
* * * * *

0
3. Section 98.231 is amended by revising paragraph (a) to read as
follows:

Sec.  98.231  Reporting threshold.

    (a) You must report GHG emissions under this subpart if your
facility contains petroleum and natural gas systems and the facility
meets the requirements of Sec.  98.2(a)(2), except for the industry
segments in paragraphs (a)(1) through (4) of this section.
    (1) Facilities must report emissions from the onshore petroleum and
natural gas production industry segment only if emission sources
specified in Sec.  98.232(c) emit 25,000 metric tons of CO2
equivalent or more per year.
    (2) Facilities must report emissions from the natural gas
distribution industry segment only if emission sources specified in
Sec.  98.232(i) emit 25,000 metric tons of CO2 equivalent or
more per year.
    (3) Facilities must report emissions from the onshore petroleum and
natural gas gathering and boosting industry segment only if emission
sources specified in Sec.  98.232(j) emit 25,000 metric tons of
CO2 equivalent or more per year.
    (4) Facilities must report emissions from the onshore natural gas
transmission pipeline industry segment only if emission sources
specified in Sec.  98.232(m) emit 25,000 metric tons of CO2
equivalent or more per year.
* * * * *

0
4. Section 98.232 is amended by:
0
a. Revising paragraphs (a) and (c)(6) and (8);
0
b. Adding paragraph (j);
0
c. Revising paragraph (k); and
0
d. Adding paragraph (m).
    The revisions and additions read as follows:

Sec.  98.232  GHGs to report.

    (a) You must report CO2, CH4, and
N2O emissions from each industry segment specified in
paragraphs (b) through (j) and (m) of this section, CO2,
CH4, and N2O emissions from each flare as
specified in paragraphs (b) through (j) of this section, and stationary
and portable combustion emissions as applicable as specified in
paragraph (k) of this section.
* * * * *
    (c) * * *
    (6) Well venting during well completions with hydraulic fracturing
that have a GOR of 300 scf/STB or greater (oil here refers to
hydrocarbon liquids produced of all API gravities).
* * * * *
    (8) Well venting during well workovers with hydraulic fracturing
that have a GOR of 300 scf/STB or greater (oil here refers to
hydrocarbon liquids produced of all API gravities).
* * * * *
    (j) For an onshore petroleum and natural gas gathering and boosting
facility, report CO2, CH4, and N2O
emissions from the following source types:
    (1) Natural gas pneumatic device venting.
    (2) Natural gas driven pneumatic pump venting.
    (3) Acid gas removal vents.
    (4) Dehydrator vents.
    (5) Blowdown vent stacks.
    (6) Storage tank vented emissions.
    (7) Flare stack emissions.
    (8) Centrifugal compressor venting.
    (9) Reciprocating compressor venting.
    (10) Equipment leaks from valves, connectors, open ended lines,
pressure relief valves, pumps, flanges, and other equipment leak
sources (such as instruments, loading arms, stuffing boxes, compressor
seals, dump lever arms, and breather caps).
    (11) Gathering pipeline equipment leaks.
    (12) You must use the methods in Sec.  98.233(z) and report under
this subpart the emissions of CO2, CH4, and
N2O from stationary or portable fuel combustion equipment
that cannot move on roadways under its own power and drive train, and
that is located at an onshore petroleum and natural gas gathering and
boosting facility as defined in Sec.  98.238. Stationary or portable
equipment includes the following equipment, which are integral to the
movement of natural gas: Natural gas dehydrators, natural gas
compressors, electrical generators, steam boilers, and process heaters.
    (k) Report under subpart C of this part (General Stationary Fuel
Combustion Sources) the emissions of CO2, CH4,
and N2O from each stationary fuel combustion unit by
following the requirements of subpart C except for facilities under
onshore petroleum and natural gas production, onshore petroleum and
natural gas gathering and boosting, and natural gas distribution.
Onshore petroleum and natural gas production facilities must report
stationary and portable combustion emissions as specified in paragraph
(c) of this section. Natural gas distribution facilities must report
stationary combustion emissions as specified in paragraph (i) of this
section. Onshore petroleum and natural gas gathering and boosting
facilities must report stationary and portable combustion emissions as
specified in paragraph (j) of this section.
* * * * *
    (m) For onshore natural gas transmission pipeline, report pipeline
blowdown CO2 and CH4 emissions from blowdown vent
stacks.

0
5. Section 98.233 is amended by:
0
a. Revising the parameters ``EFt'' and ``GHGi''
of Equation W-1 in paragraph (a);
0
b. Revising paragraph (a)(2);
0
c. Revising the parameter ``EF'' of Equation W-2 in paragraph (c);
0
d. Revising paragraph (d)(8)(iii);
0
e. Revising paragraphs (g) introductory text, (g)(1) introductory text,
(g)(1)(i), and paragraph (g)(1)(ii) heading;
0
f. Revising the parameters ``FRMs,'' ``FRs,p''
and ``PRs,p'' of Equation W-12A in paragraph (g)(1)(iii);
0
g. Revising the parameters ``FRMi,'' and
``PRs,p'' of Equation W-12B in paragraph (g)(1)(iv);
0
h. Revising paragraphs (g)(1)(v) and (vi);
0
i. Adding paragraph (g)(1)(vii);
0
j. Revising paragraph (g)(2) introductory text;
0
k. Adding paragraph (g)(2)(iv);
0
l. Revising paragraph (g)(4) introductory text;
0
m. Revising paragraph (i)(2) introductory text;
0
n. Revising the parameters ``Ta'' and ``Pa'' of
Equation W-14A in paragraph (i)(2)(i);
0
o. Revising paragraphs (j) introductory text, (j)(1) through (3), and
(j)(6);
0
p. Revising paragraph (n)(2)(i);
0
q. Revising paragraphs (o) introductory text and (o)(10);
0
r. Revising paragraphs (p) introductory text and (p)(10);
0
s. Revising paragraphs (r) introductory text, (r)(2) introductory text,
and (r)(2)(i);
0
t. Revising paragraphs (u)(2)(i) and (iii); and
0
x. Revising paragraphs (z) introductory text and (z)(1)(ii).
    The revisions and additions read as follows:

Sec.  98.233  Calculating GHG emissions.

* * * * *
    (a) * * *
* * * * *

EFt = Population emission factors for natural gas
pneumatic device vents (in standard cubic feet per hour per device)
of each type ``t'' listed in Tables W-1A, W-3, and W-4 of this
subpart for onshore petroleum and natural gas production,

onshore natural gas transmission compression, and underground
natural gas storage facilities, respectively. Onshore petroleum and
natural gas gathering and boosting facilities must use the
population emission factors listed in Table W-1A of this subpart.
GHGi = For onshore petroleum and natural gas production
facilities, onshore petroleum and natural gas gathering and boosting
facilities, onshore natural gas transmission compression facilities,
and underground natural gas storage facilities, concentration of
GHGi, CH4 or CO2, in produced
natural gas or processed natural gas for each facility as specified
in paragraphs (u)(2)(i), (iii), and (iv) of this section.

* * * * *
    (2) For the onshore petroleum and natural gas production industry
segment, you have the option in the first two consecutive calendar
years to determine ``Countt'' for Equation W-1 of this
section for each type of natural gas pneumatic device (continuous high
bleed, continuous low bleed, and intermittent bleed) using engineering
estimates based on best available data. For the onshore petroleum and
natural gas gathering and boosting industry segment, you have the
option in the first two consecutive calendar years to determine
``Countt'' for Equation W-1 for each type of natural gas
pneumatic device (continuous high bleed, continuous low bleed, and
intermittent bleed) using engineering estimates based on best available
data.
* * * * *
    (c) * * *
* * * * *

EF = Population emissions factors for natural gas driven pneumatic
pumps (in standard cubic feet per hour per pump) listed in Table W-
1A of this subpart for onshore petroleum and natural gas production
and onshore petroleum and natural gas gathering and boosting
facilities.

* * * * *
    (d) * * *
    (8) * * *
    (iii) If a continuous gas analyzer is not available or installed,
you may use the outlet pipeline quality specification for
CO2 in natural gas.
* * * * *
    (g) Well venting during completions and workovers with hydraulic
fracturing. Calculate annual volumetric natural gas emissions from gas
well and oil well venting during completions and workovers involving
hydraulic fracturing using Equation W-10A or Equation W-10B of this
section. Equation W-10A applies to well venting when the gas flowback
rate is measured from a specified number of example completions or
workovers and Equation W-10B applies when the gas flowback vent or
flare volume is measured for each completion or workover. Completion
and workover activities are separated into two periods, an initial
period when flowback is routed to open pits or tanks and a subsequent
period when gas content is sufficient to route the flowback to a
separator or when the gas content is sufficient to allow measurement by
the devices specified in paragraph (g)(1) of this section, regardless
of whether a separator is actually utilized. If you elect to use
Equation W-10A, you must follow the procedures specified in paragraph
(g)(1). If you elect to use Equation W-10B, you must use a recording
flow meter installed on the vent line, downstream of a separator and
ahead of a flare or vent, to measure the gas flowback. For either
equation, emissions must be calculated separately for completions and
workovers, for each sub-basin, and for each well type combination
identified in paragraph (g)(2) of this section. You must calculate
CH4 and CO2 volumetric and mass emissions as
specified in paragraph (g)(3) of this section. If emissions from well
venting during completions and workovers with hydraulic fracturing are
routed to a flare, you must calculate CH4, CO2,
and N2O annual emissions as specified in paragraph (g)(4) of
this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.007

Where:

Es,n = Annual volumetric natural gas emissions in
standard cubic feet from gas venting during well completions or
workovers following hydraulic fracturing for each sub-basin and well
type combination.
W = Total number of wells completed or worked over using hydraulic
fracturing in a sub-basin and well type combination.
Tp,s = Cumulative amount of time of flowback, after
sufficient quantities of gas are present to enable separation, where
gas vented or flared for the completion or workover, in hours, for
each well, p, in a sub-basin and well type combination during the
reporting year. This may include non-contiguous periods of venting
or flaring.
Tp,i = Cumulative amount of time of flowback to open
tanks/pits, from when gas is first detected until sufficient
quantities of gas are present to enable separation, for the
completion or workover, in hours, for each well, p, in a sub-basin
and well type combination during the reporting year. This may
include non-contiguous periods of routing to open tanks/pits but
does not include periods when the oil well ceases to produce fluids
to the surface.
FRMs = Ratio of average gas flowback, during the period
when sufficient quantities of gas are present to enable separation,
of well completions and workovers from hydraulic fracturing to 30-
day production rate for the sub-basin and well type combination,
calculated using procedures specified in paragraph (g)(1)(iii) of
this section.
FRMi = Ratio of initial gas flowback rate during well
completions and workovers from hydraulic fracturing to 30-day gas
production rate for the sub-basin and well type combination,
calculated using procedures specified in paragraph (g)(1)(iv) of
this section, for the period of flow to open tanks/pits.
PRs,p = Average gas production flow rate during the first
30 days of production after completions of newly drilled wells or
well workovers using hydraulic fracturing in standard cubic feet per
hour of each well p, that was measured in the sub-basin and well
type combination. If applicable, PRs,p may be calculated
for oil wells using procedures specified in paragraph (g)(1)(vii) of
this section.
EnFs,p = Volume of N2 injected gas in cubic
feet at standard conditions that was injected into the reservoir
during an energized fracture job or during flowback for each well,
p, as determined by using an appropriate meter according to methods
described in Sec.  98.234(b), or by using receipts of gas purchases
that are used for the energized fracture job or injection during
flowback. Convert to standard conditions using paragraph (t) of this
section. If the fracture process did

not inject gas into the reservoir or if the injected gas is
CO2 then EnFs,p is 0.
FVs,p = Flow volume of vented or flared gas for each
well, p, in standard cubic feet measured using a recording flow
meter (digital or analog) on the vent line to measure gas flowback
during the separation period of the completion or workover according
to methods set forth in Sec.  98.234(b).
FRp,i = Flow rate vented or flared of each well, p, in
standard cubic feet per hour measured using a recording flow meter
(digital or analog) on the vent line to measure the flowback, at the
beginning of the period of time when sufficient quantities of gas
are present to enable separation, of the completion or workover
according to methods set forth in Sec.  98.234(b).

    (1) If you elect to use Equation W-10A of this section on gas
wells, you must use Calculation Method 1 as specified in paragraph
(g)(1)(i) of this section, or Calculation Method 2 as specified in
paragraph (g)(1)(ii) of this section, to determine the value of
FRMs and FRMi. If you elect to use Equation W-10A
of this section on oil wells, you must use Calculation Method 1 as
specified in paragraph (g)(1)(i) to determine the value of
FRMs and FRMi. These values must be based on the
flow rate for flowback gases, once sufficient gas is present to enable
separation. The number of measurements or calculations required to
estimate FRMs and FRMi must be determined
individually for completions and workovers per sub-basin and well type
combination as follows: Complete measurements or calculations for at
least one completion or workover for less than or equal to 25
completions or workovers for each well type combination within a sub-
basin; complete measurements or calculations for at least two
completions or workovers for 26 to 50 completions or workovers for each
sub-basin and well type combination; complete measurements or
calculations for at least three completions or workovers for 51 to 100
completions or workovers for each sub-basin and well type combination;
complete measurements or calculations for at least four completions or
workovers for 101 to 250 completions or workovers for each sub-basin
and well type combination; and complete measurements or calculations
for at least five completions or workovers for greater than 250
completions or workovers for each sub-basin and well type combination.
    (i) Calculation Method 1. You must use Equation W-12A of this
section as specified in paragraph (g)(1)(iii) of this section to
determine the value of FRMs. You must use Equation W-12B of
this section as specified in paragraph (g)(1)(iv) of this section to
determine the value of FRMi. The procedures specified in
paragraphs (g)(1)(v) and (vi) of this section also apply. When making
gas flowback measurements for use in Equations W-12A and W-12B of this
section, you must use a recording flow meter (digital or analog)
installed on the vent line, downstream of a separator and ahead of a
flare or vent, to measure the gas flowback rates in units of standard
cubic feet per hour according to methods set forth in Sec.  98.234(b).
    (ii) Calculation Method 2 (for gas wells). * * *
    (iii) * * *
* * * * *

FRMs = Ratio of average gas flowback rate, during the
period of time when sufficient quantities of gas are present to
enable separation, of well completions and workovers from hydraulic
fracturing to 30-day gas production rate for each sub-basin and well
type combination.
FRs,p = Measured average gas flowback rate from
Calculation Method 1 described in paragraph (g)(1)(i) of this
section or calculated average flowback rate from Calculation Method
2 described in paragraph (g)(1)(ii) of this section, during the
separation period in standard cubic feet per hour for well(s) p for
each sub-basin and well type combination. Convert measured and
calculated FRa values from actual conditions upstream of
the restriction orifice (FRa) to standard conditions
(FRs,p) for each well p using Equation W-33 in paragraph
(t) of this section. You may not use flow volume as used in Equation
W-10B of this section converted to a flow rate for this parameter.
PRs,p = Average gas production flow rate during the first
30 days of production after completions of newly drilled wells or
well workovers using hydraulic fracturing, in standard cubic feet
per hour for each well, p, that was measured in the sub-basin and
well type combination. For oil wells for which production is not
measured continuously during the first 30 days of production, the
average flow rate may be based on individual well production tests
conducted within the first 30 days of production. Alternatively, if
applicable, PRs,p may be calculated for oil wells using
procedures specified in paragraph (g)(1)(vii) of this section.

* * * * *
    (iv) * * *
* * * * *

FRMi = Ratio of initial gas flowback rate during well
completions and workovers from hydraulic fracturing to 30-day gas
production rate for the sub-basin and well type combination, for the
period of flow to open tanks/pits.
* * * * *
PRs,p = Average gas production flow rate during the first
30-days of production after completions of newly drilled wells or
well workovers using hydraulic fracturing, in standard cubic feet
per hour of each well, p, that was measured in the sub-basin and
well type combination. For oil wells for which production is not
measured continuously during the first 30 days of production, the
average flow rate may be based on individual well production tests
conducted within the first 30 days of production. Alternatively, if
applicable, PRs,p may be calculated for oil wells using
procedures specified in paragraph (g)(1)(vii) of this section.

* * * * *
    (v) For Equation W-10A of this section, the ratio of gas flowback
rate during well completions and workovers from hydraulic fracturing to
30-day gas production rate are applied to all well completions and well
workovers, respectively, in the sub-basin and well type combination for
the total number of hours of flowback and for the first 30 day average
gas production rate for each of these wells.
    (vi) For Equations W-12A and W-12B of this section, calculate new
flowback rates for well completions and well workovers in each sub-
basin and well type combination once every two years starting in the
first calendar year of data collection.
    (vii) For oil wells where the gas production rate is not metered
and you elect to use Equation W-10A of this section, calculate the
average gas production rate (PRs,p) using Equation W-12C of
this section. If GOR cannot be determined from your available data,
then you must use one of the procedures specified in paragraph
(g)(1)(vii)(A) or (B) of this section to determine GOR. If GOR from
each well is not available, use the GOR from a cluster of wells in the
same sub-basin category.
[GRAPHIC] [TIFF OMITTED] TR22OC15.008

Where:

PRs,p = Average gas production flow rate during the first
30 days of production after completions of newly drilled wells or
well workovers using hydraulic fracturing in standard cubic feet per
hour of well p, in the sub-basin and well type combination.
GORp = Average gas to oil ratio during the first 30 days
of production after completions of newly drilled wells or workovers
using hydraulic fracturing in standard cubic feet of gas per barrel
of oil for each well p, that was measured in the sub-basin and well
type combination; oil here refers to hydrocarbon liquids produced of
all API gravities.
Vp = Volume of oil produced during the first 30 days of
production after completions of newly drilled wells or well
workovers using hydraulic fracturing in barrels of each well p, that
was measured in the sub-basin and well type combination.
720 = Conversion from 30 days of production to hourly production
rate.

    (A) You may use an appropriate standard method published by a
consensus-based standards organization if such a method exists.
    (B) You may use an industry standard practice as described in Sec.
98.234(b).
    (2) For paragraphs (g) introductory text and (g)(1) of this
section, measurements and calculations are completed separately for
workovers and completions per sub-basin and well type combination. A
well type combination is a unique combination of the parameters listed
in paragraphs (g)(2)(i) through (iv) of this section.
* * * * *
    (iv) Oil well or gas well.
* * * * *
    (4) Calculate annual emissions from well venting during well
completions and workovers from hydraulic fracturing where all or a
portion of the gas is flared as specified in paragraphs (g)(4)(i) and
(ii) of this section.
* * * * *
    (i) * * *
    (2) Method for determining emissions from blowdown vent stacks
according to equipment or event type. If you elect to determine
emissions according to each equipment or event type, using unique
physical volumes as calculated in paragraph (i)(1) of this section, you
must calculate emissions as specified in paragraph (i)(2)(i) of this
section and either paragraph (i)(2)(ii) or, if applicable, paragraph
(i)(2)(iii) of this section for each equipment or event type. For
industry segments other than onshore natural gas transmission pipeline,
equipment or event types must be grouped into the following seven
categories: Facility piping (i.e., piping within the facility boundary
other than physical volumes associated with distribution pipelines),
pipeline venting (i.e., physical volumes associated with distribution
pipelines vented within the facility boundary), compressors, scrubbers/
strainers, pig launchers and receivers, emergency shutdowns (this
category includes emergency shutdown blowdown emissions regardless of
equipment type), and all other equipment with a physical volume greater
than or equal to 50 cubic feet. If a blowdown event resulted in
emissions from multiple equipment types and the emissions cannot be
apportioned to the different equipment types, then categorize the
blowdown event as the equipment type that represented the largest
portion of the emissions for the blowdown event. For the onshore
natural gas transmission pipeline segment, pipeline segments or event
types must be grouped into the following eight categories: Pipeline
integrity work (e.g., the preparation work of modifying facilities,
ongoing assessments, maintenance or mitigation), traditional operations
or pipeline maintenance, equipment replacement or repair (e.g.,
valves), pipe abandonment, new construction or modification of
pipelines including commissioning and change of service, operational
precaution during activities (e.g. excavation near pipelines),
emergency shutdowns including pipeline incidents as defined in 49 CFR
191.3, and all other pipeline segments with a physical volume greater
than or equal to 50 cubic feet. If a blowdown event resulted in
emissions from multiple categories and the emissions cannot be
apportioned to the different categories, then categorize the blowdown
event in the category that represented the largest portion of the
emissions for the blowdown event.
    (i) * * *
* * * * *

Ta = Temperature at actual conditions in the unique
physical volume ([deg]F). For emergency blowdowns at onshore
petroleum and natural gas gathering and boosting facilities,
engineering estimates based on best available information may be
used to determine the temperature.
* * * * *
Pa = Absolute pressure at actual conditions in the unique
physical volume (psia). For emergency blowdowns at onshore petroleum
and natural gas gathering and boosting facilities, engineering
estimates based on best available information may be used to
determine the pressure.

* * * * *
    (j) Onshore production and onshore petroleum and natural gas
gathering and boosting storage tanks. Calculate CH4,
CO2, and N2O (when flared) emissions from
atmospheric pressure fixed roof storage tanks receiving hydrocarbon
produced liquids from onshore petroleum and natural gas production
facilities and onshore petroleum and natural gas gathering and boosting
facilities (including stationary liquid storage not owned or operated
by the reporter), as specified in this paragraph (j). For gas-liquid
separators or onshore petroleum and natural gas gathering and boosting
non-separator equipment (e.g., stabilizers, slug catchers) with annual
average daily throughput of oil greater than or equal to 10 barrels per
day, calculate annual CH4 and CO2 using
Calculation Method 1 or 2 as specified in paragraphs (j)(1) and (2) of
this section. For wells flowing directly to atmospheric storage tanks
without passing through a separator with throughput greater than or
equal to 10 barrels per day, calculate annual CH4 and
CO2 emissions using Calculation Method 2 as specified in
paragraph (j)(2) of this section. For hydrocarbon liquids flowing to
gas-liquid separators or non-separator equipment or directly to
atmospheric storage tanks with throughput less than 10 barrels per day,
use Calculation Method 3 as specified in paragraph (j)(3) of this
section. If you use Calculation Method 1 or Calculation Method 2 for
separators, you must also calculate emissions that may have occurred
due to dump valves not closing properly using the method specified in
paragraph (j)(6) of this section. If emissions from atmospheric
pressure fixed roof storage tanks are routed to a vapor recovery
system, you must adjust the emissions downward according to paragraph
(j)(4) of this section. If emissions from atmospheric pressure fixed
roof storage tanks are routed to a flare, you must calculate
CH4, CO2, and N2O annual emissions as
specified in paragraph (j)(5) of this section.
    (1) Calculation Method 1. Calculate annual CH4 and
CO2 emissions from onshore production storage tanks and
onshore petroleum and natural gas gathering and boosting storage tanks
using operating conditions in the last gas-liquid separator or non-
separator equipment before liquid transfer to storage tanks. Calculate
flashing emissions with a software program, such as AspenTech
HYSYS[supreg] or API 4697 E&P Tank, that uses the Peng-Robinson
equation of state, models flashing emissions, and speciates
CH4 and CO2 emissions that will result when the
oil from the separator or non-separator equipment enters an atmospheric
pressure storage tank. The following parameters must be determined for
typical operating

conditions over the year by engineering estimate and process knowledge
based on best available data, and must be used at a minimum to
characterize emissions from liquid transferred to tanks:
    (i) Separator or non-separator equipment temperature.
    (ii) Separator or non-separator equipment pressure.
    (iii) Sales oil or stabilized oil API gravity.
    (iv) Sales oil or stabilized oil production rate.
    (v) Ambient air temperature.
    (vi) Ambient air pressure.
    (vii) Separator or non-separator equipment oil composition and Reid
vapor pressure. If this data is not available, determine these
parameters by using one of the methods described in paragraphs
(j)(1)(vii)(A) through (C) of this section.
    (A) If separator or non-separator equipment oil composition and
Reid vapor pressure default data are provided with the software
program, select the default values that most closely match your
separator or non-separator equipment pressure first, and API gravity
secondarily.
    (B) If separator or non-separator equipment oil composition and
Reid vapor pressure data are available through your previous analysis,
select the latest available analysis that is representative of produced
crude oil or condensate from the sub-basin category for onshore
petroleum and natural gas production or from the county for onshore
petroleum and natural gas gathering and boosting.
    (C) Analyze a representative sample of separator or non-separator
equipment oil in each sub-basin category for onshore petroleum and
natural gas production or each county for onshore petroleum and natural
gas gathering and boosting for oil composition and Reid vapor pressure
using an appropriate standard method published by a consensus-based
standards organization.
    (2) Calculation Method 2. Calculate annual CH4 and
CO2 emissions using the methods in paragraph (j)(2)(i) of
this section for gas-liquid separators with annual average daily
throughput of oil greater than or equal to 10 barrels per day.
Calculate annual CH4 and CO2 emissions using the
methods in paragraph (j)(2)(ii) of this section for wells with annual
average daily oil production greater than or equal to 10 barrels per
day that flow directly to atmospheric storage tanks in onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting (if applicable). Calculate annual
CH4 and CO2 emissions using the methods in
paragraph (j)(2)(iii) of this section for non-separator equipment with
annual average daily hydrocarbon liquids throughput greater than or
equal to 10 barrels per day that flow directly to atmospheric storage
tanks in onshore petroleum and natural gas gathering and boosting.
    (i) Flow to storage tank after passing through a separator. Assume
that all of the CH4 and CO2 in solution at
separator temperature and pressure is emitted from oil sent to storage
tanks. You may use an appropriate standard method published by a
consensus-based standards organization if such a method exists or you
may use an industry standard practice as described in Sec.  98.234(b)
to sample and analyze separator oil composition at separator pressure
and temperature.
    (ii) Flow to storage tank direct from wells. Calculate
CH4 and CO2 emissions using either of the methods
in paragraph (j)(2)(ii)(A) or (B) of this section.
    (A) If well production oil and gas compositions are available
through a previous analysis, select the latest available analysis that
is representative of produced oil and gas from the sub-basin category
and assume all of the CH4 and CO2 in both oil and
gas are emitted from the tank.
    (B) If well production oil and gas compositions are not available,
use default oil and gas compositions in software programs, such as API
4697 E&P Tank, that most closely match the well production gas/oil
ratio and API gravity and assume all of the CH4 and
CO2 in both oil and gas are emitted from the tank.
    (iii) Flow to storage tank direct from non-separator equipment.
Calculate CH4 and CO2 emissions using either of
the methods in paragraph (j)(2)(iii)(A) or (B) of this section.
    (A) If other non-separator equipment liquid and gas compositions
are available through a previous analysis, select the latest available
analysis that is representative of liquid and gas from non-separator
equipment in the same county and assume all of the CH4 and
CO2 in both hydrocarbon liquids and gas are emitted from the
tank.
    (B) If non-separator equipment liquid and gas compositions are not
available, use default liquid and gas compositions in software
programs, such as API 4697 E&P Tank, that most closely match the non-
separator equipment gas/liquid ratio and API gravity and assume all of
the CH4 and CO2 in both hydrocarbon liquids and
gas are emitted from the tank.
    (3) Calculation Method 3. Calculate CH4 and
CO2 emissions using Equation W-15 of this section:
[GRAPHIC] [TIFF OMITTED] TR22OC15.009

Where:

Es,i = Annual total volumetric GHG emissions (either
CO2 or CH4) at standard conditions in cubic
feet.
EFi = Population emission factor for separators, wells,
or non-separator equipment in thousand standard cubic feet per
separator, well, or non-separator equipment per year, for crude oil
use 4.2 for CH4 and 2.8 for CO2 at
60[emsp14][deg]F and 14.7 psia, and for gas condensate use 17.6 for
CH4 and 2.8 for CO2 at 60 [deg]F and 14.7
psia.
Count = Total number of separators, wells, or non-separator
equipment with annual average daily throughput less than 10 barrels
per day. Count only separators, wells, or non-separator equipment
that feed oil directly to the storage tank.
1,000 = Conversion from thousand standard cubic feet to standard
cubic feet.

* * * * *
    (6) If you use Calculation Method 1 or Calculation Method 2 in
paragraph (j)(1) or (2) of this section, calculate emissions from
occurrences of gas-liquid separator liquid dump valves not closing
during the calendar year by using Equation W-16 of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.010

Where:

Es,i,o = Annual volumetric GHG emissions at standard
conditions from each storage tank in cubic feet that resulted from
the dump valve on the gas-liquid separator not closing properly.
En = Storage tank emissions as determined in paragraphs
(j)(1), (j)(2) and, if applicable, (j)(4) of this section in
standard cubic feet per year.
Tn = Total time a dump valve is not closing properly in
the calendar year in hours. Estimate Tn based on
maintenance, operations, or routine separator inspections that
indicate the period of time when the valve was malfunctioning in
open or partially open position.
CFn = Correction factor for tank emissions for time
period Tn is 2.87 for crude oil production. Correction
factor for tank emissions for time period Tn is 4.37 for
gas condensate production.
8,760 = Conversion to hourly emissions.

* * * * *
    (n) * * *
    (2) * * *
    (i) For onshore natural gas production and onshore petroleum and
natural gas gathering and boosting, determine the GHG mole fraction
using paragraph (u)(2)(i) of this section.
* * * * *
    (o) Centrifugal compressor venting. If you are required to report
emissions from centrifugal compressor venting as specified in Sec.
98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct
volumetric emission measurements specified in paragraph (o)(1) of this
section using methods specified in paragraphs (o)(2) through (5) of
this section; perform calculations specified in paragraphs (o)(6)
through (9) of this section; and calculate CH4 and
CO2 mass emissions as specified in paragraph (o)(11) of this
section. If emissions from a compressor source are routed to a flare,
paragraphs (o)(1) through (11) do not apply and instead you must
calculate CH4, CO2, and N2O emissions
as specified in paragraph (o)(12) of this section. If emissions from a
compressor source are captured for fuel use or are routed to a thermal
oxidizer, paragraphs (o)(1) through (12) do not apply and instead you
must calculate and report emissions as specified in subpart C of this
part. If emissions from a compressor source are routed to vapor
recovery, paragraphs (o)(1) through (12) do not apply. If you are
required to report emissions from centrifugal compressor venting at an
onshore petroleum and natural gas production facility as specified in
Sec.  98.232(c)(19) or an onshore petroleum and natural gas gathering
and boosting facility as specified in Sec.  98.232(j)(8), you must
calculate volumetric emissions as specified in paragraph (o)(10); and
calculate CH4 and CO2 mass emissions as specified
in paragraph (o)(11).
* * * * *
    (10) Method for calculating volumetric GHG emissions from wet seal
oil degassing vents at an onshore petroleum and natural gas production
facility or an onshore petroleum and natural gas gathering and boosting
facility. You must calculate emissions from centrifugal compressor wet
seal oil degassing vents at an onshore petroleum and natural gas
production facility or an onshore petroleum and natural gas gathering
and boosting facility using Equation W-25 of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.011

Where:

Es,i = Annual volumetric GHGi (either
CH4 or CO2) emissions from centrifugal
compressor wet seals, at standard conditions, in cubic feet.
Count = Total number of centrifugal compressors that have wet seal
oil degassing vents.
EFi,s = Emission factor for GHGi. Use 1.2 x
10\7\ standard cubic feet per year per compressor for CH4
and 5.30 x 10\5\ standard cubic feet per year per compressor for
CO2 at 60 [deg]F and 14.7 psia.

* * * * *
    (p) Reciprocating compressor venting. If you are required to report
emissions from reciprocating compressor venting as specified in Sec.
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct
volumetric emission measurements specified in paragraph (p)(1) of this
section using methods specified in paragraphs (p)(2) through (5) of
this section; perform calculations specified in paragraphs (p)(6)
through (9) of this section; and calculate CH4 and
CO2 mass emissions as specified in paragraph (p)(11) of this
section. If emissions from a compressor source are routed to a flare,
paragraphs (p)(1) through (11) do not apply and instead you must
calculate CH4, CO2, and N2O emissions
as specified in paragraph (p)(12) of this section. If emissions from a
compressor source are captured for fuel use or are routed to a thermal
oxidizer, paragraphs (p)(1) through (12) do not apply and instead you
must calculate and report emissions as specified in subpart C of this
part. If emissions from a compressor source are routed to vapor
recovery, paragraphs (p)(1) through (12) do not apply. If you are
required to report emissions from reciprocating compressor venting at
an onshore petroleum and natural gas production facility as specified
in Sec.  98.232(c)(11) or an onshore petroleum and natural gas
gathering and boosting facility as specified in Sec.  98.232(j)(5), you
must calculate volumetric emissions as specified in paragraph (p)(10);
and calculate CH4 and CO2 mass emissions as
specified in paragraph (p)(11).
* * * * *
    (10) Method for calculating volumetric GHG emissions from
reciprocating compressor venting at an onshore petroleum and natural
gas production facility or an onshore petroleum and natural gas
gathering and boosting facility. You must calculate emissions from
reciprocating compressor venting at an onshore petroleum and natural
gas production facility or an onshore petroleum and natural gas
gathering and boosting facility using Equation W-29D of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.012

Where:

Es,i = Annual volumetric GHGi (either
CH4 or CO2) emissions from reciprocating
compressors, at standard conditions, in cubic feet.
Count = Total number of reciprocating compressors.
EFi,s = Emission factor for GHGi. Use 9.48 x
10\3\ standard cubic feet per year per compressor for CH4
and 5.27 x 10\2\ standard cubic feet per year per compressor for
CO2 at 60 [deg]F and 14.7 psia.

* * * * *

    (r) Equipment leaks by population count. This paragraph (r) applies
to emissions sources listed in Sec.  98.232 (c)(21), (f)(5), (g)(3),
(h)(4), (i)(2), (i)(3), (i)(4), (i)(5), (i)(6), (j)(10), and (j)(11) on
streams with gas content greater than 10 percent CH4 plus
CO2 by weight. Emissions sources in streams with gas content
less than or equal to 10 percent CH4 plus CO2 by
weight are exempt from the requirements of this paragraph (r) and do
not need to be reported. Tubing systems equal to or less than one half
inch diameter are exempt from the requirements of paragraph (r) of this
section and do not need to be reported. You must calculate emissions
from all emission sources listed in this paragraph using Equation W-32A
of this section, except for natural gas distribution facility emission
sources listed in Sec.  98.232(i)(3). Natural gas distribution facility
emission sources listed in Sec.  98.232(i)(3) must calculate emissions
using Equation W-32B of this section and according to paragraph
(r)(6)(ii) of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.013

Where:

Es,e,i = Annual volumetric emissions of GHGi
from the emission source type in standard cubic feet. The emission
source type may be a component (e.g. connector, open-ended line,
etc.), below grade metering-regulating station, below grade
transmission-distribution transfer station, distribution main,
distribution service, or gathering pipeline.
Es,MR,i = Annual volumetric emissions of GHGi
from all meter/regulator runs at above grade metering regulating
stations that are not above grade transmission-distribution transfer
stations or, when used to calculate emissions according to paragraph
(q)(9) of this section, the annual volumetric emissions of
GHGi from all meter/regulator runs at above grade
transmission-distribution transfer stations, in standard cubic feet.
Counte = Total number of the emission source type at the
facility. For onshore petroleum and natural gas production
facilities and onshore petroleum and natural gas gathering and
boosting facilities, average component counts are provided by major
equipment piece in Tables W-1B and Table W-1C of this subpart. Use
average component counts as appropriate for operations in Eastern
and Western U.S., according to Table W-1D of this subpart. Onshore
petroleum and natural gas gathering and boosting facilities must
also count the miles of gathering pipelines by material type
(protected steel, unprotected steel, plastic, or cast iron).
Underground natural gas storage facilities must count each component
listed in Table W-4 of this subpart. LNG storage facilities must
count the number of vapor recovery compressors. LNG import and
export facilities must count the number of vapor recovery
compressors. Natural gas distribution facilities must count: (1) The
number of distribution services by material type; (2) miles of
distribution mains by material type; and (3) number of below grade
metering-regulating stations, by pressure type; as listed in Table
W-7 of this subpart.
CountMR = Total number of meter/regulator runs at above
grade metering-regulating stations that are not above grade
transmission-distribution transfer stations or, when used to
calculate emissions according to paragraph (q)(9) of this section,
the total number of meter/regulator runs at above grade
transmission-distribution transfer stations.
EFs,e = Population emission factor for the specific
emission source type, as listed in Tables W-1A and W-4 through W-7
of this subpart. Use appropriate population emission factor for
operations in Eastern and Western U.S., according to Table W-1D of
this subpart.
EFs,MR,i = Meter/regulator run population emission factor
for GHGi based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic
feet of GHGi per operational hour of all meter/regulator
runs, as determined in Equation W-31 of this section.
GHGi = For onshore petroleum and natural gas production
facilities and onshore petroleum and natural gas gathering and
boosting facilities, concentration of GHGi,
CH4, or CO2, in produced natural gas as
defined in paragraph (u)(2) of this section; for onshore natural gas
transmission compression and underground natural gas storage,
GHGi equals 0.975 for CH4 and 1.1 x
10-2 for CO2; for LNG storage and LNG import
and export equipment, GHGi equals 1 for CH4
and 0 for CO2; and for natural gas distribution,
GHGi equals 1 for CH4 and 1.1 x
10-2 CO2.
Te = Average estimated time that each emission source
type associated with the equipment leak emission was operational in
the calendar year, in hours, using engineering estimate based on
best available data.
Tw,avg = Average estimated time that each meter/regulator
run was operational in the calendar year, in hours per meter/
regulator run, using engineering estimate based on best available
data.

* * * * *
    (2) Onshore petroleum and natural gas production facilities and
onshore petroleum and natural gas gathering and boosting facilities
must use the appropriate default whole gas population emission factors
listed in Table W-1A of this subpart. Major equipment and components
associated with gas wells and onshore petroleum and natural gas
gathering and boosting systems are considered gas service components in
reference to Table W-1A of this subpart and major natural gas equipment
in reference to Table W-1B of this subpart. Major equipment and
components associated with crude oil wells are considered crude service
components in reference to Table W-1A of this subpart and major crude
oil equipment in reference to Table W-1C of this subpart. Where
facilities conduct EOR operations the emissions factor listed in Table
W-1A of this subpart shall be used to estimate all streams of gases,
including recycle CO2 stream. The component count can be
determined using either of the calculation methods described in this
paragraph (r)(2), except for miles of gathering pipelines by material
type, which must be determined using Component Count Method 2 in
paragraph (r)(2)(ii) of this section. The same calculation method must
be used for the entire calendar year.
    (i) Component Count Method 1. For all onshore petroleum and natural
gas production operations and onshore petroleum and natural gas
gathering and boosting operations in the facility perform the following
activities:
    (A) Count all major equipment listed in Table W-1B and Table W-1C
of this subpart. For meters/piping, use one meters/piping per well-pad
for onshore petroleum and natural gas production operations and the
number of meters in the facility for onshore petroleum and natural gas
gathering and boosting operations.
    (B) Multiply major equipment counts by the average component counts
listed in Table W-1B of this subpart for onshore natural gas production
and onshore petroleum and natural gas gathering and boosting; and Table
W-1C of this subpart for onshore oil production. Use the appropriate
factor

in Table W-1A of this subpart for operations in Eastern and Western
U.S. according to the mapping in Table W-1D of this subpart.
* * * * *
    (u) * * *
    (2) * * *
    (i) GHG mole fraction in produced natural gas for onshore petroleum
and natural gas production facilities and onshore petroleum and natural
gas gathering and boosting facilities. If you have a continuous gas
composition analyzer for produced natural gas, you must use an annual
average of these values for determining the mole fraction. If you do
not have a continuous gas composition analyzer, then you must use an
annual average gas composition based on your most recent available
analysis of the sub-basin category or facility, as applicable to the
emission source.
* * * * *
    (iii) GHG mole fraction in transmission pipeline natural gas that
passes through the facility for the onshore natural gas transmission
compression industry segment and the onshore natural gas transmission
pipeline industry segment. You may use either a default 95 percent
methane and 1 percent carbon dioxide fraction for GHG mole fraction in
natural gas or site specific engineering estimates based on best
available data.
* * * * *
    (z) Onshore petroleum and natural gas production, onshore petroleum
and natural gas gathering and boosting, and natural gas distribution
combustion emissions. Calculate CO2, CH4, and
N2O combustion-related emissions from stationary or portable
equipment, except as specified in paragraphs (z)(3) and (4) of this
section, as follows:
    (1) * * *
    (ii) Emissions from fuel combusted in stationary or portable
equipment at onshore petroleum and natural gas production facilities,
at onshore petroleum and natural gas gathering and boosting facilities,
and at natural gas distribution facilities will be reported according
to the requirements specified in Sec.  98.236(z) and not according to
the reporting requirements specified in subpart C of this part.
* * * * *

0
6. Section 98.234 is amended by adding paragraph (g) to read as
follows:

Sec.  98.234  Monitoring and QA/QC requirements.

* * * * *
    (g) Special reporting provisions for best available monitoring
methods in reporting year 2016--(1) Best available monitoring methods.
From January 1, 2016, to December 31, 2016, you must use the
calculation methodologies and equations in Sec.  98.233 but you may use
the best available monitoring method as described in paragraph (g)(2)
of this section for any parameter specified in paragraphs (g)(3)
through (6) of this section for which it is not reasonably feasible to
acquire, install, and operate a required piece of monitoring equipment
by January 1, 2016. Starting no later than January 1, 2017, you must
discontinue using best available methods and begin following all
applicable monitoring and QA/QC requirements of this part. For onshore
petroleum and natural gas production, this paragraph (g)(1) only
applies if emissions from well completions and workovers of oil wells
with hydraulic fracturing cause your facility to exceed the reporting
threshold in Sec.  98.231(a)(1).
    (2) Best available monitoring methods means any of the following
methods:
    (i) Monitoring methods currently used by the facility that do not
meet the specifications of this subpart.
    (ii) Supplier data.
    (iii) Engineering calculations.
    (iv) Other company records.
    (3) Best available monitoring methods for well-related measurement
data for oil wells with hydraulic fracturing. You may use best
available monitoring methods for any well-related measurement data that
cannot reasonably be measured according to the monitoring and QA/QC
requirements of this subpart for venting during well completions and
workovers of oil wells with hydraulic fracturing.
    (4) Best available monitoring methods for measurement data for
onshore petroleum and natural gas gathering and boosting facilities.
You may use best available monitoring methods for any leak detection
and/or measurement data that cannot reasonably be measured according to
the monitoring and QA/QC requirements of this subpart for acid gas
removal vents as specified in Sec.  98.233(d).
    (5) Best available monitoring methods for measurement data for
natural gas transmission pipelines. You may use best available
monitoring methods for any measurement data for natural gas
transmission pipelines that cannot reasonably be obtained according to
the monitoring and QA/QC requirements of this subpart for blowdown vent
stacks.
    (6) Best available monitoring methods for specified activity data.
You may use best available monitoring methods for activity data as
listed in paragraphs (g)(6)(i) through (iii) of this section that
cannot reasonably be obtained according to the monitoring and QA/QC
requirements of this subpart for well completions and workovers of oil
wells with hydraulic fracturing, onshore petroleum and natural gas
gathering and boosting facilities, or natural gas transmission
pipelines.
    (i) Cumulative hours of venting, days, or times of operation in
Sec.  98.233(e), (g), (o), (p), and (r).
    (ii) Number of blowdowns, completions, workovers, or other events
in Sec.  98.233(g) and (i).
    (iii) Cumulative volume produced, volume input or output, or volume
of fuel used in paragraphs Sec.  98.233(d), (e), (j), (n), and (z).
* * * * *

0
7. Section 98.236 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Adding paragraphs (a)(9) and (10);
0
c. Revising paragraphs (d)(1)(i) and (vi);
0
d. Revising paragraphs (e)(1)(i) and (xviii);
0
e. Revising paragraphs (f)(1)(ii), (f)(1)(xi)(A), (f)(1)(xii)(A), and
(f)(2)(i);
0
f. Revising paragraphs (g) introductory text, (g)(1), (g)(2), (g)(5),
and (g)(6);
0
g. Revising paragraphs (h)(1)(i) and (iv), (h)(2)(i) and (iv),
(h)(3)(i), and (h)(4)(i);
0
h. Revising paragraphs (i) introductory text and (i)(1) introductory
text;
0
i. Adding paragraph (i)(3);
0
j. Revising paragraphs (j) introductory text and (j)(1) introductory
text;
0
k. Revising paragraphs (j)(1)(i), (iii), (iv) (v), (vii), and (viii);
0
l. Revising paragraphs (j)(2)(i) introductory text, (j)(2)(i)(A)
through (C), (j)(2)(ii), (j)(2)(iii) introductory text, (j)(2)(iii)(A)
and (B), and (j)(3) introductory text;
0
m. Revising paragraph (l)(1) introductory text;
0
n. Redesignating paragraphs (l)(1)(ii) through (vi) as paragraphs
(l)(1)(iii) through (vii), respectively;
0
o. Adding paragraph (l)(1)(ii);
0
p. Revising newly designated paragraph (l)(1)(v);
0
q. Revising paragraph (l)(2) introductory text;
0
r. Redesignating paragraphs (l)(2)(ii) through (vii) as paragraphs
(l)(2)(iii) through (viii), respectively;
0
s. Adding paragraph (l)(2)(ii);
0
t. Revising newly designated paragraph (l)(2)(v);
0
u. Revising paragraph (l)(3) introductory text;
0
v. Redesignating paragraphs (l)(3)(ii) through (v) as paragraphs
(l)(3)(iii) through (vi), respectively;
0
w. Adding paragraph (l)(3)(ii);
0
x. Revising newly designated paragraph (l)(3)(iv);

0
y. Revising paragraph (l)(4) introductory text;
0
a. Redesignating paragraphs (l)(4)(ii) through (vi) as paragraphs
(l)(4)(iii) through (vii), respectively;
0
aa. Adding paragraph (l)(4)(ii);
0
bb. Revising newly designated paragraph (l)(4)(iv);
0
cc. Revising paragraphs (m)(1), (m)(5), (m)(6), (m)(7)(i), (m)(8)(i);
0
dd. Revising paragraph (n)(1);
0
ee. Revising paragraphs (o) introductory text and (o)(5) introductory
text;
0
ff. Revising paragraphs (p) introductory text and (p)(5) introductory
text;
0
gg. Revising paragraphs (r)(1) introductory text, (r)(1)(i), (r)(3)
introductory text, and (r)(3)(ii) introductory text;
0
hh. Revising paragraph (z) introductory text;
0
ii. Revising paragraphs (aa) introductory text and (aa)(1)(ii)(D)
through (H);
0
jj. Adding paragraphs (aa)(10) and (11); and
0
kk. Revising paragraph (cc).
    The revisions and additions read as follows:

Sec.  98.236  Data reporting requirements.

* * * * *
    (a) The annual report must include the information specified in
paragraphs (a)(1) through (10) of this section for each applicable
industry segment. The annual report must also include annual emissions
totals, in metric tons of each GHG, for each applicable industry
segment listed in paragraphs (a)(1) through (10), and each applicable
emission source listed in paragraphs (b) through (z) of this section.
* * * * *
    (9) Onshore petroleum and natural gas gathering and boosting. For
the equipment/activities specified in paragraphs (a)(9)(i) through (xi)
of this section, report the information specified in the applicable
paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified
in paragraph (b) of this section.
    (ii) Natural gas driven pneumatic pumps. Report the information
specified in paragraph (c) of this section.
    (iii) Acid gas removal units. Report the information specified in
paragraph (d) of this section.
    (iv) Dehydrators. Report the information specified in paragraph (e)
of this section.
    (v) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
    (vi) Storage tanks. Report the information specified in paragraph
(j) of this section.
    (vii) Flare stacks. Report the information specified in paragraph
(n) of this section.
    (viii) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
    (ix) Reciprocating compressors. Report the information specified in
paragraph (p) of this section.
    (x) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
    (xi) Combustion equipment. Report the information specified in
paragraph (z) of this section.
    (10) Onshore natural gas transmission pipeline. For blowdown vent
stacks, report the information specified in paragraph (i) of this
section.
* * * * *
    (d) * * *
    (1) * * *
    (i) A unique name or ID number for the acid gas removal unit. For
the onshore petroleum and natural gas production and the onshore
petroleum and natural gas gathering and boosting industry segments, a
different name or ID may be used for a single acid gas removal unit for
each location it operates at in a given year.
* * * * *
    (vi) Sub-basin ID that best represents the wells supplying gas to
the unit (for the onshore petroleum and natural gas production industry
segment only) or name of the county that best represents the equipment
supplying gas to the unit (for the onshore petroleum and natural gas
gathering and boosting industry segment only).
* * * * *
    (e) * * *
    (1) * * *
    (i) A unique name or ID number for the dehydrator. For the onshore
petroleum and natural gas production and the onshore petroleum and
natural gas gathering and boosting industry segments, a different name
or ID may be used for a single dehydrator for each location it operates
at in a given year.
* * * * *
    (xviii) Sub-basin ID that best represents the wells supplying gas
to the dehydrator (for the onshore petroleum and natural gas production
industry segment only) or name of the county that best represents the
equipment supplying gas to the dehydrator (for the onshore petroleum
and natural gas gathering and boosting industry segment only).
* * * * *
    (f) * * *
    (1) * * *
    (ii) Well tubing diameter and pressure group ID and a list of the
well ID numbers associated with each sub-basin and well tubing diameter
and pressure group ID.
* * * * *
    (xi) * * *
    (A) Well ID number of tested well.
* * * * *
    (xii) * * *
    (A) Well ID number.
* * * * *
    (2) * * *
    (i) Sub-basin ID and a list of the well ID numbers associated with
each sub-basin.
* * * * *
    (g) Completions and workovers with hydraulic fracturing. You must
indicate whether your facility had any well completions or workovers
with hydraulic fracturing during the calendar year. If your facility
had well completions or workovers with hydraulic fracturing during the
calendar year, then you must report information specified in paragraphs
(g)(1) through (10) of this section, for each sub-basin and well type
combination. Report information separately for completions and
workovers.
    (1) Sub-basin ID and a list of the well ID numbers associated with
each sub-basin that had completions or workovers with hydraulic
fracturing during the calendar year.
    (2) Well type combination (horizontal or vertical, gas well or oil
well).
* * * * *
    (5) If you used Equation W-10A of Sec.  98.233 to calculate annual
volumetric total gas emissions, then you must report the information
specified in paragraphs (g)(5)(i) through (iii) of this section.
    (i) Cumulative gas flowback time, in hours, from when gas is first
detected until sufficient quantities are present to enable separation,
and the cumulative flowback time, in hours, after sufficient quantities
of gas are present to enable separation (sum of ``Tp,i'' and
sum of ``Tp,s'' values used in Equation W-10A of Sec.
98.233). You may delay the reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells are the only wells included in this number. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec.  98.236(cc) the total number of hours of flowback from all
wells during completions or workovers and the well ID number(s) for the
well(s) included in the number.
    (ii) For the measured well(s), the flowback rate, in standard cubic
feet per

hour (average of ``FRs,p'' values used in Equation W-12A of
Sec.  98.233), and the well ID numbers of the wells for which it is
measured. You may delay the reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that can be used for the measurement. If you
elect to delay reporting of this data element, you must report by the
date specified in Sec.  98.236(cc) the measured flowback rate during
well completion or workover and the well ID number(s) for the well(s)
included in the measurement.
    (iii) If you used Equation W-12C of Sec.  98.233 to calculate the
average gas production rate for an oil well, then you must report the
information specified in paragraphs (g)(5)(iii)(A) and (B) of this
section.
    (A) Gas to oil ratio for the well in standard cubic feet of gas per
barrel of oil (``GORp'' in Equation W-12C of Sec.  98.233).
You may delay the reporting of this data element if you indicate in the
annual report that wildcat wells and/or delineation wells are the only
wells that can be used for the measurement. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec.  98.236(cc) the gas to oil ratio for the well and the well ID
number for the well.
    (B) Volume of oil produced during the first 30 days of production
after completions of each newly drilled well or well workover using
hydraulic fracturing, in barrels (``Vp'' in Equation W-12C
of Sec.  98.233). You may delay the reporting of this data element if
you indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that can be used for the measurement. If you
elect to delay reporting of this data element, you must report by the
date specified in Sec.  98.236(cc) the volume of oil produced during
the first 30 days of production after well completion or workover and
the well ID number for the well.
    (6) If you used Equation W-10B of Sec.  98.233 to calculate annual
volumetric total gas emissions, then you must report the information
specified in paragraphs (g)(6)(i) through (iii) of this section.
    (i) Vented natural gas volume, in standard cubic feet, for each
well in the sub-basin (``FVs,p'' in Equation W-10B of Sec.
98.233).
    (ii) Flow rate at the beginning of the period of time when
sufficient quantities of gas are present to enable separation, in
standard cubic feet per hour, for each well in the sub-basin
(``FRp,i'' in Equation W-10B of Sec.  98.233).
    (iii) The well ID number for which vented natural gas volume was
measured.
* * * * *
    (h) * * *
    (1) * * *
    (i) Sub-basin ID and a list of the well ID numbers associated with
each sub-basin for gas well completions without hydraulic fracturing
and without flaring.
* * * * *
    (iv) Average daily gas production rate for all completions without
hydraulic fracturing in the sub-basin without flaring, in standard
cubic feet per hour (average of all ``Vp'' used in Equation
W-13B of Sec.  98.233). You may delay reporting of this data element if
you indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that can be used for the measurement. If you
elect to delay reporting of this data element, you must report by the
date specified in Sec.  98.236(cc) the measured average daily gas
production rate for all wells during completions and the well ID
number(s) for the well(s) included in the measurement.
* * * * *
    (2) * * *
    (i) Sub-basin ID and a list of the well ID numbers associated with
each sub-basin for gas well completions without hydraulic fracturing
and with flaring.
* * * * *
    (iv) Average daily gas production rate for all completions without
hydraulic fracturing in the sub-basin with flaring, in standard cubic
feet per hour (the average of all ``Vp'' from Equation W-13B
of Sec.  98.233). You may delay reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that can be used for the measurement. If you
elect to delay reporting of this data element, you must report by the
date specified in Sec.  98.236(cc) the measured average daily gas
production rate for all wells during completions and the well ID
number(s) for the well(s) included in the measurement.
* * * * *
    (3) * * *
    (i) Sub-basin ID and a list of the well ID numbers associated with
each sub-basin for gas well workovers without hydraulic fracturing and
without flaring.
* * * * *
    (4) * * *
    (i) Sub-basin ID and a list of well ID numbers associated with each
sub-basin for gas well workovers without hydraulic fracturing and with
flaring.
* * * * *
    (i) Blowdown vent stacks. You must indicate whether your facility
has blowdown vent stacks. If your facility has blowdown vent stacks,
then you must report whether emissions were calculated by equipment or
event type or by using flow meters or a combination of both. If you
calculated emissions by equipment or event type for any blowdown vent
stacks, then you must report the information specified in paragraph
(i)(1) of this section considering, in aggregate, all blowdown vent
stacks for which emissions were calculated by equipment or event type.
If you calculated emissions using flow meters for any blowdown vent
stacks, then you must report the information specified in paragraph
(i)(2) of this section considering, in aggregate, all blowdown vent
stacks for which emissions were calculated using flow meters. For the
onshore natural gas transmission pipeline segment, you must also report
the information in paragraph (i)(3) of this section.
    (1) Report by equipment or event type. If you calculated emissions
from blowdown vent stacks by the seven categories listed in Sec.
98.233(i)(2) for industry segments other than the onshore natural gas
transmission pipeline segment, then you must report the equipment or
event types and the information specified in paragraphs (i)(1)(i)
through (iii) of this section for each equipment or event type. If a
blowdown event resulted in emissions from multiple equipment types, and
the emissions cannot be apportioned to the different equipment types,
then you may report the information in paragraphs (i)(1)(i) through
(iii) of this section for the equipment type that represented the
largest portion of the emissions for the blowdown event. If you
calculated emissions from blowdown vent stacks by the eight categories
listed in Sec.  98.233(i)(2) for the onshore natural gas transmission
pipeline segment, then you must report the pipeline segments or event
types and the information specified in paragraphs (i)(1)(i) through
(iii) of this section for each ``equipment or event type'' (i.e.,
category). If a blowdown event resulted in emissions from multiple
categories, and the emissions cannot be apportioned to the different
categories, then you may report the information in paragraphs (i)(1)(i)
through (iii) of this section for the ``equipment or event type''
(i.e., category) that represented the largest portion of the emissions
for the blowdown event.
* * * * *

    (3) Onshore natural gas transmission pipeline segment. Report the
information in paragraphs (i)(3)(i) through (iii) of this section for
each state.
    (i) Annual CO2 emissions in metric tons CO2.
    (ii) Annual CH4 emissions in metric tons CH4.
    (iii) Annual number of blowdown events.
    (j) Onshore production and onshore petroleum and natural gas
gathering and boosting storage tanks. You must indicate whether your
facility sends produced oil to atmospheric tanks. If your facility
sends produced oil to atmospheric tanks, then you must indicate which
Calculation Method(s) you used to calculate GHG emissions, and you must
report the information specified in paragraphs (j)(1) and (2) of this
section as applicable. If you used Calculation Method 1 or Calculation
Method 2 of Sec.  98.233(j), and any atmospheric tanks were observed to
have malfunctioning dump valves during the calendar year, then you must
indicate that dump valves were malfunctioning and you must report the
information specified in paragraph (j)(3) of this section.
    (1) If you used Calculation Method 1 or Calculation Method 2 of
Sec.  98.233(j) to calculate GHG emissions, then you must report the
information specified in paragraphs (j)(1)(i) through (xvi) of this
section for each sub-basin (for onshore production) or county (for
onshore petroleum and natural gas gathering and boosting) and by
calculation method. Onshore petroleum and natural gas gathering and
boosting facilities do not report the information specified in
paragraphs (j)(1)(ix) and (xi) of this section.
    (i) Sub-basin ID (for onshore production) or county name (for
onshore petroleum and natural gas gathering and boosting).
* * * * *
    (iii) The total annual oil volume from gas-liquid separators and
direct from wells or non-separator equipment that is sent to applicable
onshore production and onshore petroleum and natural gas gathering and
boosting storage tanks, in barrels. You may delay reporting of this
data element for onshore production if you indicate in the annual
report that wildcat wells and delineation wells are the only wells in
the sub-basin with oil production greater than or equal to 10 barrels
per day and flowing to gas-liquid separators or direct to storage
tanks. If you elect to delay reporting of this data element, you must
report by the date specified in Sec.  98.236(cc) the total volume of
oil from all wells and the well ID number(s) for the well(s) included
in this volume.
    (iv) The average gas-liquid separator or non-separator equipment
temperature, in degrees Fahrenheit.
    (v) The average gas-liquid separator or non-separator equipment
pressure, in pounds per square inch gauge.
* * * * *
    (vii) The minimum and maximum concentration (mole fraction) of
CO2 in flash gas from onshore production and onshore natural
gas gathering and boosting storage tanks.
    (viii) The minimum and maximum concentration (mole fraction) of
CH4 in flash gas from onshore production and onshore natural
gas gathering and boosting storage tanks.
* * * * *
    (2) * * *
    (i) Report the information specified in paragraphs (j)(2)(i)(A)
through (F) of this section, at the basin level, for atmospheric tanks
where emissions were calculated using Calculation Method 3 of Sec.
98.233(j). Onshore gathering and boosting facilities do not report the
information specified in paragraphs (j)(2)(i)(E) and (F) of this
section.
    (A) The total annual oil/condensate throughput that is sent to all
atmospheric tanks in the basin, in barrels. You may delay reporting of
this data element for onshore production if you indicate in the annual
report that wildcat wells and delineation wells are the only wells in
the sub-basin with oil/condensate production less than 10 barrels per
day and that send oil/condensate to atmospheric tanks. If you elect to
delay reporting of this data element, you must report by the date
specified in Sec.  98.236(cc) the total annual oil/condensate
throughput from all wells and the well ID number(s) for the well(s)
included in this volume.
    (B) An estimate of the fraction of oil/condensate throughput
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric
tanks in the basin that controlled emissions with flares.
    (C) An estimate of the fraction of oil/condensate throughput
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric
tanks in the basin that controlled emissions with vapor recovery
systems.
* * * * *
    (ii) Report the information specified in paragraphs (j)(2)(ii)(A)
through (D) of this section for each sub-basin (for onshore production)
or county (for onshore petroleum and natural gas gathering and
boosting) with atmospheric tanks whose emissions were calculated using
Calculation Method 3 of Sec.  98.233(j) and that did not control
emissions with flares.
    (A) Sub-basin ID (for onshore production) or county name (for
onshore petroleum and natural gas gathering and boosting).
    (B) The number of atmospheric tanks in the sub-basin (for onshore
production) or county (for onshore petroleum and natural gas gathering
and boosting) that did not control emissions with flares.
    (C) Annual CO2 emissions, in metric tons CO2,
from atmospheric tanks in the sub-basin (for onshore production) or
county (for onshore petroleum and natural gas gathering and boosting)
that did not control emissions with flares, calculated using Equation
W-15 of Sec.  98.233(j) and adjusted for vapor recovery, if applicable.
    (D) Annual CH4 emissions, in metric tons CH4,
from atmospheric tanks in the sub-basin (for onshore production) or
county (for onshore petroleum and natural gas gathering and boosting)
that did not control emissions with flares, calculated using Equation
W-15 of Sec.  98.233(j) and adjusted for vapor recovery, if applicable.
    (iii) Report the information specified in paragraphs (j)(2)(iii)(A)
through (E) of this section for each sub-basin (for onshore production)
or county (for onshore petroleum and natural gas gathering and
boosting) with atmospheric tanks whose emissions were calculated using
Calculation Method 3 of Sec.  98.233(j) and that controlled emissions
with flares.
    (A) Sub-basin ID (for onshore production) or county name (for
onshore petroleum and natural gas gathering and boosting).
    (B) The number of atmospheric tanks in the sub-basin (for onshore
production) or county (for onshore petroleum and natural gas gathering
and boosting) that controlled emissions with flares.
* * * * *
    (3) If you used Calculation Method 1 or Calculation Method 2 of
Sec.  98.233(j), and any gas-liquid separator liquid dump values did
not close properly during the calendar year, then you must report the
information specified in paragraphs (j)(3)(i) through (iv) of this
section for each sub-basin (for onshore production) or county (for
onshore petroleum and natural gas gathering and boosting).
* * * * *
    (l) * * *
    (1) If you used Equation W-17A of Sec.  98.233 to calculate annual
volumetric natural gas emissions at actual

conditions from oil wells and the emissions are not vented to a flare,
then you must report the information specified in paragraphs (l)(1)(i)
through (vii) of this section.
* * * * *
    (ii) Well ID numbers for the wells tested in the calendar year.
* * * * *
    (v) Average flow rate for well(s) tested, in barrels of oil per
day. You may delay reporting of this data element if you indicate in
the annual report that wildcat wells and/or delineation wells are the
only wells that are tested. If you elect to delay reporting of this
data element, you must report by the date specified in Sec.  98.236(cc)
the measured average flow rate for well(s) tested and the well ID
number(s) for the well(s) included in the measurement.
* * * * *
    (2) If you used Equation W-17A of Sec.  98.233 to calculate annual
volumetric natural gas emissions at actual conditions from oil wells
and the emissions are vented to a flare, then you must report the
information specified in paragraphs (l)(2)(i) through (viii) of this
section.
* * * * *
    (ii) Well ID numbers for the wells tested in the calendar year.
* * * * *
    (v) Average flow rate for well(s) tested, in barrels of oil per
day. You may delay reporting of this data element if you indicate in
the annual report that wildcat wells and/or delineation wells are the
only wells that are tested. If you elect to delay reporting of this
data element, you must report by the date specified in Sec.  98.236(cc)
the measured average flow rate for well(s) tested and the well ID
number(s) for the well(s) included in the measurement.
* * * * *
    (3) If you used Equation W-17B of Sec.  98.233 to calculate annual
volumetric natural gas emissions at actual conditions from gas wells
and the emissions were not vented to a flare, then you must report the
information specified in paragraphs (l)(3)(i) through (vi) of this
section.
* * * * *
    (ii) Well ID numbers for the wells tested in the calendar year.
* * * * *
    (iv) Average annual production rate for well(s) tested, in actual
cubic feet per day. You may delay reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that are tested. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec.  98.236(cc) the measured average annual production rate for
well(s) tested and the well ID number(s) for the well(s) included in
the measurement.
* * * * *
    (4) If you used Equation W-17B of Sec.  98.233 to calculate annual
volumetric natural gas emissions at actual conditions from gas wells
and the emissions were vented to a flare, then you must report the
information specified in paragraphs (l)(4)(i) through (vii) of this
section.
* * * * *
    (ii) Well ID numbers for the wells tested in the calendar year.
* * * * *
    (iv) Average annual production rate for well(s) tested, in actual
cubic feet per day. You may delay reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that are tested. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec.  98.236(cc) the measured average annual production rate for
well(s) tested and the well ID number(s) for the well(s) included in
the measurement.
* * * * *
    (m) * * *
    (1) Sub-basin ID and a list of well ID numbers for wells for which
associated gas was vented or flared.
* * * * *
    (5) Volume of oil produced, in barrels, in the calendar year during
the time periods in which associated gas was vented or flared (the sum
of ``Vp,q'' used in Equation W-18 of Sec.  98.233). You may
delay reporting of this data element if you indicate in the annual
report that wildcat wells and/or delineation wells are the only wells
from which associated gas was vented or flared. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec.  98.236(cc) the volume of oil produced for well(s) with
associated gas venting and flaring and the well ID number(s) for the
well(s) included in the measurement.
    (6) Total volume of associated gas sent to sales, in standard cubic
feet, in the calendar year during time periods in which associated gas
was vented or flared (the sum of ``SG'' values used in Equation W-18 of
Sec.  98.233(m)). You may delay reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells from which associated gas was vented or flared. If you elect to
delay reporting of this data element, you must report by the date
specified in Sec.  98.236(cc) the measured total volume of associated
gas sent to sales for well(s) with associated gas venting and flaring
and the well ID number(s) for the well(s) included in the measurement.
    (7) * * *
    (i) Total number of wells for which associated gas was vented
directly to the atmosphere without flaring and a list of their well ID
numbers.
* * * * *
    (8) * * *
    (i) Total number of wells for which associated gas was flared and a
list of their well ID numbers.
* * * * *
    (n) * * *
    (1) Unique name or ID for the flare stack. For the onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting industry segments, a different name or ID
may be used for a single flare stack for each location where it
operates at in a given calendar year.
* * * * *
    (o) Centrifugal compressors. You must indicate whether your
facility has centrifugal compressors. You must report the information
specified in paragraphs (o)(1) and (2) of this section for all
centrifugal compressors at your facility. For each compressor source or
manifolded group of compressor sources that you conduct as found leak
measurements as specified in Sec.  98.233(o)(2) or (4), you must report
the information specified in paragraph (o)(3) of this section. For each
compressor source or manifolded group of compressor sources that you
conduct continuous monitoring as specified in Sec.  98.233(o)(3) or
(5), you must report the information specified in paragraph (o)(4) of
this section. Centrifugal compressors in onshore petroleum and natural
gas production and onshore petroleum and natural gas gathering and
boosting are not required to report information in paragraphs (o)(1)
through (4) of this section and instead must report the information
specified in paragraph (o)(5) of this section.
* * * * *
    (5) Onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting. Centrifugal
compressors with wet seal degassing vents in onshore petroleum and
natural gas production and onshore petroleum and natural gas gathering
and boosting must report the information specified in paragraphs
(o)(5)(i) through (iii) of this section.
* * * * *
    (p) Reciprocating compressors. You must indicate whether your
facility has reciprocating compressors. You must report the information
specified in

paragraphs (p)(1) and (2) of this section for all reciprocating
compressors at your facility. For each compressor source or manifolded
group of compressor sources that you conduct as found leak measurements
as specified in Sec.  98.233(p)(2) or (4), you must report the
information specified in paragraph (p)(3) of this section. For each
compressor source or manifolded group of compressor sources that you
conduct continuous monitoring as specified in Sec.  98.233(p)(3) or
(5), you must report the information specified in paragraph (p)(4) of
this section. Reciprocating compressors in onshore petroleum and
natural gas production and onshore petroleum and natural gas gathering
and boosting are not required to report information in paragraphs
(p)(1) through (4) of this section and instead must report the
information specified in paragraph (p)(5) of this section.
* * * * *
    (5) Onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting. Reciprocating
compressors in onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting must report the
information specified in paragraphs (p)(5)(i) through (iii) of this
section.
* * * * *
    (r) * * *
    (1) You must indicate whether your facility contains any of the
emission source types required to use Equation W-32A of Sec.  98.233.
You must report the information specified in paragraphs (r)(1)(i)
through (v) of this section separately for each emission source type
required to use Equation W-32A that is located at your facility.
Onshore petroleum and natural gas production facilities and onshore
petroleum and natural gas gathering and boosting facilities must report
the information specified in paragraphs (r)(1)(i) through (v)
separately by component type, service type, and geographic location
(i.e., Eastern U.S. or Western U.S.).
    (i) Emission source type. Onshore petroleum and natural gas
production facilities and onshore petroleum and natural gas gathering
and boosting facilities must report the component type, service type
and geographic location.
* * * * *
    (3) Onshore petroleum and natural gas production facilities and
onshore petroleum and natural gas gathering and boosting facilities
must also report the information specified in paragraphs (r)(3)(i) and
(ii) of this section.
* * * * *
    (ii) Onshore petroleum and natural gas production facilities and
onshore petroleum and natural gas gathering and boosting facilities
must report the information specified in paragraphs (r)(3)(ii)(A) and
(B) of this section, for each major equipment type, production type
(i.e., natural gas or crude oil), and geographic location combination
in Tables W-1B and W-1C of this subpart.
* * * * *
    (z) Combustion equipment at onshore petroleum and natural gas
production facilities, onshore petroleum and natural gas gathering and
boosting facilities, and natural gas distribution facilities. If your
facility is required by Sec.  98.232(c)(22), (i)(7), or (j)(12) to
report emissions from combustion equipment, then you must indicate
whether your facility has any combustion units subject to reporting
according to paragraph (a)(1)(xvii), (a)(8)(i), or (a)(9)(xi) of this
section. If your facility contains any combustion units subject to
reporting according to paragraph (a)(1)(xvii), (a)(8)(i), or (a)(9)(xi)
of this section, then you must report the information specified in
paragraphs (z)(1) and (2) of this section, as applicable.
* * * * *
    (aa) Each facility must report the information specified in
paragraphs (aa)(1) through (11) of this section, for each applicable
industry segment, by using best available data. If a quantity required
to be reported is zero, you must report zero as the value.
    (1) * * *
    (ii) * * *
    (D) The number of producing wells at the end of the calendar year
and a list of the well ID numbers (exclude only those wells permanently
taken out of production, i.e., plugged and abandoned).
    (E) The number of producing wells acquired during the calendar year
and a list of the well ID numbers.
    (F) The number of producing wells divested during the calendar year
and a list of the well ID numbers.
    (G) The number of wells completed during the calendar year and a
list of the well ID numbers.
    (H) The number of wells permanently taken out of production (i.e.,
plugged and abandoned) during the calendar year and a list of the well
ID numbers.
* * * * *
    (10) For onshore petroleum and natural gas gathering and boosting
facilities, report the quantities specified in paragraphs (aa)(10)(i)
through (iv) of this section.
    (i) The quantity of gas received by the gathering and boosting
facility in the calendar year, in thousand standard cubic feet.
    (ii) The quantity of gas transported to a natural gas processing
facility, a natural gas transmission pipeline, a natural gas
distribution pipeline, or another gathering and boosting facility in
the calendar year, in thousand standard cubic feet.
    (iii) The quantity of all hydrocarbon liquids received by the
gathering and boosting facility in the calendar year, in barrels.
    (iv) The quantity of all hydrocarbon liquids transported to a
natural gas processing facility, a natural gas transmission pipeline, a
natural gas distribution pipeline, or another gathering and boosting
facility in the calendar year, in barrels.
    (11) For onshore natural gas transmission pipeline facilities,
report the quantities specified in paragraphs (aa)(11)(i) through (vi)
of this section.
    (i) The quantity of natural gas received at all custody transfer
stations in the calendar year, in thousand standard cubic feet. This
value may include meter corrections, but only for the calendar year
covered by the annual report.
    (ii) The quantity of natural gas withdrawn from in-system storage
in the calendar year, in thousand standard cubic feet.
    (iii) The quantity of natural gas added to in-system storage in the
calendar year, in thousand standard cubic feet.
    (iv) The quantity of natural gas transferred to third parties such
as LDCs or other transmission pipelines, in thousand standard cubic
feet.
    (v) The quantity of natural gas consumed by the transmission