single family owning a few production wells) that are unlikely to cross
the 25,000 metric tons CO2e threshold considered for the
rule. An exception to such a scenario is a small (less than 20
employee) enterprise owning large operations but conducting nearly all
of its operations through contractors. This is not an uncommon practice
in the Onshore Petroleum and Natural Gas Production segment. Such
enterprises, however, are a very small group among the almost 16,000
enterprises in the less than 20 employee category, and the EPA proposes
to cover them in the rule.
    The EPA took a conservative approach with the model entity
analysis. Although the appropriate SBA size definition should be
applied at the parent company (enterprise) level, data limitations
allowed us only to compute and compare ratios for a model establishment
within several enterprise size ranges.
    Although this rule will not have a significant economic impact on a
substantial number of small entities, the agency nonetheless tried to
reduce the impact of this rule on small entities. See Section V.C of
this preamble for more detail on the measures taken by the EPA to
ensure that the burdens imposed on small entities would be minimal.

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'' under the
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is
therefore not subject to review under Executive Orders 12866 and 13563
(76 FR 3821, January 21, 2011).

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule have
been submitted for approval to OMB under the Paperwork Reduction Act,
44 U.S.C. 3501 et seq. The Information Collection Request (ICR)
document prepared by the EPA has been assigned EPA ICR number 2300.16.
OMB has previously approved the information collection requirements for
40 CFR part 98 under the provisions of the Paperwork Reduction Act, 44
U.S.C. 3501 et seq., and has assigned OMB control number 2060-0629.
    This action proposes to 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. Impacts
associated with the proposed changes to the monitoring and reporting
requirements are detailed in the memorandum ``Assessment of Impacts of
the 2015 Proposed Revisions to Subpart W'' (see Docket ID No. EPA-HQ-
OAR-2014-0831). Burden is defined at 5 CFR 1320.3(b).
    The estimated projected cost and hour burden associated with
reporting for the proposed amendments to subpart W affecting the three
industry segments are $7.2 million and 73,000 hours, respectively. For
the hour burden, the estimated average burden hours per new response is
113 hours, the proposed frequency of response is once annually, and the
estimated number of likely new respondents that would result from these
proposed amendments is approximately 400.
    The estimated total projected cost and hour burden associated with
all ten subpart W industry segments are 317,400 hours and $29.2 million
per year for a 3-year period, where identical annual costs are
anticipated for all 3 years. The average annual burden to the EPA for
this period is estimated to be 10,400 hours for oversight activities.
The annual reporting and recordkeeping burden for this collection of
information is estimated to average 63.4 hours per response.
    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    To comment on the agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, the EPA has established a public docket
for this rule, which includes this ICR, under Docket ID number EPA-HQ-
OAR-2014-0831. Submit any comments related to the ICR to the EPA and
OMB. See ADDRESSES section at the beginning of this proposed rule for
where to submit comments to the EPA. Send comments to OMB at the Office
of Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street NW., Washington, DC 20503, Attention: Desk Office for
the EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after December 9, 2014, a comment to OMB is best
assured of having its full effect if OMB receives it by January 8,
2015. The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal. We
continue to be interested in the potential impacts of this proposed
action on the burden associated with the proposed amendments and
welcome comments on issues related to such impacts.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's proposed rule on
small entities, small entity is defined as: (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.
    After considering the economic impacts of these proposed rule
amendments on small entities, I certify that this action would not have
a significant economic impact on a substantial number of small
entities. The small entities directly regulated by this proposed rule
include small businesses in the petroleum and gas industry. The EPA has
determined that some small businesses would be

affected because their production processes emit GHGs exceeding the
reporting threshold. This action includes proposed amendments that may
result in a burden increase on subpart W reporters, but the EPA has
determined that it is not a significant increase. See Section IV.B of
this preamble for more details on the analysis of the potential impact
of this proposal on small business entities.
    Although this proposed 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 finalization of the final subpart W 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 GHGRP, which would be available to
answer questions on the provisions in this rulemaking. 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. We continue to be
interested in the potential impacts of the proposed rule amendments on
small entities and welcome comments on issues related to such impacts.

D. Unfunded Mandates Reform Act

    The proposed amendments and confidentiality determinations do not
contain a federal mandate that may result in expenditures of $100
million or more for State, local, and tribal governments, in the
aggregate, or the private sector in any one year. This action proposes
to 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. This action also proposes
confidentiality determinations for reported data elements. As discussed
in Section V.B of this preamble, for the first year, the estimated
total projected cost and hour burden associated with reporting for the
proposed amendments to subpart W affecting the three industry segments
are $7.2 million and 73,000 hours, respectively. Thus, this proposed
rule is not subject to the requirements of section 202 and 205 of the
Unfunded Mandates Reform Act of 1995 (UMRA).
    This rule is also not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. As discussed in
Section V.B of this preamble, the total collective impact on regulated
entities is $7.2 million annually. Because this impact on each
individual facility is estimated to be approximately $9,000 annually,
the EPA has determined that the provisions in this action would not
significantly impact small governments. In addition, because none of
the provisions apply specifically to small governments, the EPA has
determined that the provisions in this action would not uniquely impact
small governments. Therefore, this action is not subject to the
requirements of section 203 of the UMRA.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. For a more detailed discussion
about how Part 98 relates to existing state programs, please see
Section II of the preamble to the final Part 98 rule (74 FR 56266,
October 30, 2009).
    This action proposes to 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. This action
also proposes confidentiality determinations for reported data
elements. Few, if any, state or local government facilities would be
affected by the provisions in this proposed rule. This regulation also
does not limit the power of States or localities to collect GHG data
and/or regulate GHG emissions. Thus, Executive Order 13132 does not
apply to this action.
    In the spirit of Executive Order 13132, and consistent with the EPA
policy to promote communications between the EPA and state and local
governments, the EPA specifically solicits comment on this proposed
action from state and local officials.

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

    Subject to the Executive Order 13175 (65 FR 67249, November 9,
2000) the EPA may not issue a regulation that has tribal implications,
that imposes substantial direct compliance costs, and that is not
required by statute, unless the federal government provides the funds
necessary to pay the direct compliance costs incurred by tribal
governments, or the EPA consults with tribal officials early in the
process of developing the proposed regulation and develops a tribal
summary impact statement.
    The EPA has concluded that this action may have tribal
implications. However, it will neither impose substantial direct
compliance costs on tribal governments, nor preempt tribal law. This
action proposes to 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. This action also
proposes confidentiality determinations for reported data elements.
This regulation would apply directly to petroleum and natural gas
facilities that emit greenhouses gases. Although few facilities that
would be subject to the rule are likely to be owned by tribal
governments, it is possible that there may be some facilities owned by
tribal governments.
    The EPA consulted with tribal officials early in the process of
developing subpart W to permit them to have meaningful and timely input
into its development. In particular, the EPA 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). For additional
information about the EPA's interactions with tribal governments, see
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 final subpart W published on November 30, 2010 (75 FR 74458).
    The EPA specifically solicits additional comment on this proposed
action from tribal officials.

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

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

environmental standard intended to mitigate health or safety risks.

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

    This proposed action is not a ``significant energy action'' as
defined in Executive Order 13211 (66 FR 28355, May 22, 2001), because
it is not likely to have a significant adverse effect on the supply,
distribution, or use of energy. Part 98 relates to monitoring,
reporting, and recordkeeping and does not impact energy supply,
distribution, or use. This action proposes to 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. This action also proposes confidentiality
determinations for reported data elements.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs the EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. NTTAA directs the EPA to provide
Congress, through OMB, explanations when the agency decides not to use
available and applicable voluntary consensus standards.
    This proposed rulemaking does not involve any new technical
standards. Therefore, the EPA is not considering the use of any
voluntary consensus standards.

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

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    The EPA has determined that these proposed rule amendments will not
have disproportionately high and adverse human health or environmental
effects on minority or low-income populations because the amendments do
not affect the level of protection provided to human health or the
environment. This is because the proposed amendments address
information collection and reporting and verification procedures.

List of Subjects in 40 CFR Part 98

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

    Dated: November 13, 2014.
Gina McCarthy,
Administrator.

    For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations as amended November 25, 2014 at 79 FR
70351, and effective January 1, 2015, is proposed to be further 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. 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 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.
    (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 paragraph 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
paragraph 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 paragraph 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 paragraph (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.
* * * * *
    (8) Well venting during well workovers with hydraulic fracturing.
* * * * *

    (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
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 the 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 paragraphs (j) introductory text, (j)(1) introductory text,
and (j)(6);
0
n. Revising paragraph (n)(2)(i);
0
o. Revising paragraphs (o) introductory text and (o)(10);
0
p. Revising paragraphs (p) introductory text and (p)(10);
0
q. Revising paragraphs (r) introductory text and (r)(2);
0
r. 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.
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
subpart 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 of this subpart 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 of this section, you must follow the procedures
specified in paragraph (g)(1) of this section. 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. 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] TP09DE14.008

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.
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 gas production rate for the sub-basin and well type combination,
calculated using procedures specified in paragraph (g)(1)(iii) of
this section, expressed in standard cubic feet per hour.
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, expressed in standard cubic feet per hour, 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, 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 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. 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 per hour 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) of this section 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 as specified
in paragraph (g)(1)(iii) of this section to determine the value of
FRMs. You must use Equation W-12B 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 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. 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. 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 Equation 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 paragraphs
(g)(1)(vii)(A) or (g)(1)(vii)(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] TP09DE14.009

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.
* * * * *
    (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 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 hydrocarbon liquids
flowing directly to atmospheric storage tanks without passing through a
wellhead 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
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, you must also calculate emissions that may have occurred due
to dump valves not closing properly using the method specified in
paragraph (j)(4) 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)(5) 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)(6) 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

wellhead gas-liquid separator 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 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:
* * * * *
    (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] TP09DE14.010

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 Calculation
Methods 1 or 2 in paragraphs (j)(1) and (2) of this section (with
separators) 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) of this section 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) of this
section 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) of this section 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) of
this section; and calculate CH4 and CO2 mass
emissions as specified in paragraph (o)(11) of this section.
* * * * *
    (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] TP09DE14.011

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) of this section 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) of this
section 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) of this section 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) of this section; and calculate CH4 and
CO2 mass emissions as specified in paragraph (p)(11) of this
section.
* * * * *
    (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] TP09DE14.012

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 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)(9), and (j)(10) 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 this paragraph (r)
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 and according to paragraph (r)(6)(ii) of this
section.
[GRAPHIC] [TIFF OMITTED] TP09DE14.013

[GRAPHIC] [TIFF OMITTED] TP09DE14.014

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. 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.
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, 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.
    (B) Multiply major equipment counts by the average component counts
listed in Table W-1B 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.
    (ii) Component Count Method 2. Count each component individually
for the facility. 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 paragraph (z)(3) and (4) of this
section, as follows:
    (1) * * *
    (ii) Emissions from fuel combusted in stationary or portable
equipment at onshore natural gas and petroleum production facilities,
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
March 31, 2016, you must use the calculation methodologies and
equations in Sec.  98.233 but you may use the best available monitoring
method for any parameter for which it is not reasonably feasible to
acquire, install, and operate a required piece of monitoring equipment
by January 1, 2016 as specified in paragraphs (g)(2) through (5) of
this section. Starting no later than April 1, 2016, you must
discontinue using best available methods and begin following all
applicable monitoring and QA/QC requirements of this part, except as
provided in paragraph (g)(6) of this section. 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.
    (2) 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.
    (3) Best available monitoring methods 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).
    (4) Best available monitoring methods 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.
    (5) Best available monitoring methods for specified activity data.
You may use best available monitoring methods for activity data as
listed in paragraphs (g)(5)(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).
    (6) Requests for extension of the use of best available monitoring
methods beyond March 31, 2016. You may submit a request to the
Administrator to use one or more best available monitoring methods for
sources listed in paragraphs (g)(2) through (5), of this section beyond
March 31, 2016.

    (i) Timing of request. The extension request must be submitted to
EPA no later than January 31, 2016.
    (ii) Content of request. Requests must contain the following
information:
    (A) A list of specific source types and parameters for which you
are seeking use of best available monitoring methods.
    (B) For each specific source type for which you are requesting use
of best available monitoring methods, a description of the reasons that
the needed equipment could not be obtained and installed before April
1, 2016.
    (C) A description of the specific actions you will take to obtain
and install the equipment as soon as reasonably feasible and the
expected date by which the equipment will be installed and operating.
    (iii) Approval criteria. To obtain approval to use best available
monitoring methods after March 31, 2016, you must submit a request
demonstrating to the Administrator's satisfaction that it is not
reasonably feasible to acquire, install, and operate a required piece
of monitoring equipment by April 1, 2016. The use of best available
methods under this paragraph (g) will not be approved beyond December
31, 2016.
* * * * *
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 (b)(1)(ii)(A) and (B) and (c) introductory text;
0
d. Redesignating paragraphs (c)(2) through (4) as paragraphs (c)(3)
through (5), respectively;
0
e. Adding new paragraph (c)(2);
0
f. Revising paragraphs (d)(1) introductory text and (d)(1)(i);
0
g. Redesignating paragraphs (d)(1)(ii) through (vi) as paragraphs
(d)(1)(iii) through (vii), respectively;
0
h. Adding new paragraph (d)(1)(ii);
0
i. Revising newly redesignated paragraph (d)(1)(vii);
0
j. Revising paragraphs (e)(1) introductory text and (e)(1)(i);
0
k. Redesignating paragraphs (e)(1)(ii) through (xviii) as paragraphs
(e)(1)(iii) through (xix), respectively;
0
l. Adding new paragraph (e)(1)(ii);
0
m. Revising newly redesignated paragraphs (e)(1)(xvii) introductory
text, (e)(1)(xviii) introductory text, and (e)(1)(xix);
0
n. Revising paragraph (e)(2) introductory text;
0
o. Redesignating paragraphs (e)(2)(ii) through (v) as paragraphs
(e)(2)(iii) through (vi), respectively;
0
q. Adding new paragraph (e)(2)(ii);
0
p. Revising newly redesignated paragraphs (e)(2)(iii), (e)(1)(iv),
(e)(2)(v) introductory text, and (e)(2)(vi) introductory text;
0
q. Revising paragraphs (e)(3)(i) introductory text, (f)(1)(ii),
(f)(1)(xi)(A), (f)(1)(xii)(A), (f)(2)(i), (g) introductory text,
(g)(1), (g)(2), (g)(5)(i), and (g)(5)(ii);
0
r. Adding paragraph (g)(5)(iii);
0
s. Revising paragraph (g)(6);
0
t. Revising paragraphs (h)(1)(i), (h)(1)(iv), (h)(2)(i), (h)(2)(iv),
(h)(3)(i), (h)(4)(i) and (i) introductory text;
0
u. Adding paragraph (i)(3);
0
v. Revising paragraphs (j) introductory text and (j)(1) introductory
text;
0
w. Redesignating paragraphs (j)(1)(ii) through (xiv) as paragraphs
(j)(1)(iv) through (xvi), respectively;
0
x. Adding new paragraphs (j)(1)(ii) and (j)(1)(iii);
0
y. Revising newly redesignated paragraphs (j)(1)(v), (j)(1)(ix),
(j)(1)(x), (j)(1)(xiv) introductory text, (j)(1)(xv) introductory text,
and (j)(1)(xvi) introductory text;
0
z. Revising paragraphs (j)(2)(i) introductory text, (j)(2)(i)(A)
through (j)(2)(i)(C), (j)(2)(ii)(B), (j)(2)(iii)(B), and (l)(1)
introductory text;
0
aa. Redesignating paragraphs (l)(1)(ii) through (vi) as paragraphs
(l)(1)(iii) through (vii), respectively;
0
bb. Adding new paragraph (l)(1)(ii);
0
cc. Revising newly designated paragraph (l)(1)(v);
0
dd. Revising paragraph (l)(2) introductory text;
0
ee. Redesignating paragraphs (l)(2)(ii) through (vii) as paragraphs
(l)(2)(iii) through (viii), respectively;
0
ff. Adding new paragraph (l)(2)(ii);
0
gg. Revising newly designated paragraph (l)(2)(v);
0
hh. Revising paragraph (l)(3) introductory text;
0
ii. Redesignating paragraphs (l)(3)(ii) through (v) as paragraphs
(l)(3)(iii) through (vi), respectively;
0
jj. Adding new paragraph (l)(3)(ii);
0
kk. Revising newly designated paragraph (l)(3)(iv);
0
ll. Revising paragraph (l)(4) introductory text;
0
mm. Redesignating paragraphs (l)(4)(ii) through (vi) as paragraphs
(l)(4)(iii) through (vii), respectively;
0
nn. Adding new paragraph (l)(4)(ii);
0
oo. Revising newly designated paragraph (l)(4)(iv);
0
pp. Revising paragraphs (m)(1), (m)(5), (m)(6), (m)(7)(i), (m)(8)(i),
(n) introductory text and (n)(1);
0
qq. Adding paragraph (n)(13);
0
rr. Revising paragraphs (o) introductory text and (o)(5) introductory
text;
0
ss. Redesignating paragraphs (o)(5)(ii) and (iii) as paragraphs
(o)(5)(iii) and (iv), respectively;
0
tt. Adding new paragraph (o)(5)(ii);
0
uu. Revising paragraphs (p) introductory text and (p)(5) introductory
text;
0
vv. Redesignating paragraphs (p)(5)(ii) and (iii) as paragraphs
(p)(5)(iii) and (iv), respectively;
0
ww. Adding new paragraph (p)(5)(ii);
0
xx. Revising paragraphs (r)(1) introductory text, (r)(1)(i), (r)(3)
introductory text, (r)(3)(ii), (w)(2), and (x) introductory text;
0
yy. Redesignating paragraphs (x)(2) through (4) as paragraphs (x)(3)
through (5), respectively;
0
zz. Adding new paragraph (x)(2);
0
aaa. Revising paragraphs (z) introductory text and (z)(1) introductory
text;
0
bbb. Adding new paragraph (z)(1)(iii);
0
ccc. Revising paragraph (z)(2) introductory text;
0
ddd. Redesignating paragraphs (z)(2)(ii) through (vi) as paragraphs
(z)(2)(iii) through (vii), respectively;
0
eee. Adding new paragraph (z)(2)(ii);
0
fff. Revising paragraphs (aa) introductory text and (aa)(1)(ii)(D)
through (H);
0
ggg. Adding paragraphs (aa)(10) and (11); and
0
hhh. 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) of this section, 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.
    (b) * * *
    (1) * * *
    (ii) * * *
    (A) The number of devices of each type reported in paragraph
(b)(1)(i) of this section that are counted. A list of the well ID
numbers associated with the devices that are counted (for the onshore
petroleum and natural gas production industry segment only).
    (B) The number of devices of each type reported in paragraph
(b)(1)(i) of this section that are estimated (not counted). A list of
the well ID numbers associated with the devices that are estimated (not
counted) (for the onshore petroleum and natural gas production industry
segment only).
* * * * *
    (c) Natural gas driven pneumatic pumps. You must indicate whether
the facility has any natural gas driven pneumatic pumps. If the
facility contains any natural gas driven pneumatic pumps, then you must
report the information specified in paragraphs (c)(1) through (5) of
this section.
* * * * *
    (2) A list of the well ID numbers associated with the natural gas
driven pneumatic pumps (for the onshore petroleum and natural gas
production industry segment only).
* * * * *
    (d) * * *
    (1) You must report the information specified in paragraphs
(d)(1)(i) through (vii) of this section for each acid gas removal unit.
    (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.
    (ii) A list of the well ID number(s) associated with the acid gas
removal units (for the onshore petroleum and natural gas production
industry segment only).
* * * * *
    (vii) Sub-basin ID that best represents the wells and/or equipment
supplying gas to the unit (for the onshore petroleum and natural gas
production and the onshore petroleum and natural gas gathering and
boosting industry segments only).
* * * * *
    (e) * * *
    (1) For each glycol dehydrator that has an annual average daily
natural gas throughput greater than or equal to 0.4 million standard
cubic feet per day (as specified in Sec.  98.233(e)(1)), you must
report the information specified in paragraphs (e)(1)(i) through (xix)
of this section for the dehydrator.
    (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.
    (ii) A list of well ID number(s) associated with the dehydrators
(for the onshore petroleum and natural gas production industry segment
only).
* * * * *
    (xvii) Whether any dehydrator emissions are vented to a flare or
regenerator firebox/fire tubes. If any emissions are vented to a flare
or regenerator firebox/fire tubes, report the information specified in
paragraphs (e)(1)(xvii)(A) through (C) of this section for these
emissions from the dehydrator.
    (xviii) Whether any dehydrator emissions are vented to the
atmosphere without being routed to a flare or regenerator firebox/fire
tubes. If any emissions are not routed to a flare or regenerator
firebox/fire tubes, then you must report the information specified in
paragraphs (e)(1)(xviii)(A) and (B) of this section for those emissions
from the dehydrator.
    (xix) Sub-basin ID that best represents the wells and/or equipment
supplying gas to the dehydrator (for the onshore petroleum and natural
gas production and the onshore petroleum and natural gas gathering and
boosting industry segments only).
    (2) For glycol dehydrators with an annual average daily natural gas
throughput less than 0.4 million standard cubic feet per day (as
specified in Sec.  98.233(e)(2)), you must report the information
specified in paragraphs (e)(2)(i) through (vi) of this section for the
entire facility.
* * * * *
    (ii) A list of the well ID numbers associated with the dehydrators
at the facility (for the onshore petroleum and natural gas production
industry segment only).
    (iii) Whether any dehydrator emissions were vented to a vapor
recovery device. If any dehydrator emissions were vented to a vapor
recovery device, then you must report the total number of dehydrators
at the facility that vented to a vapor recovery device. For the onshore
petroleum and natural gas production industry segment only, also report
a list of the associated well ID numbers.
    (iv) Whether any dehydrator emissions were vented to a control
device other than a vapor recovery device or a flare or regenerator
firebox/fire tubes. If any dehydrator emissions were vented to a
control device(s) other than a vapor recovery device or a flare or
regenerator firebox/fire tubes, then you must specify the type of
control device(s) and the total number of dehydrators at the facility
that were vented to each type of control device. For the onshore
petroleum and natural gas production industry segment only, also report
a list of the associated well ID numbers for each type of control
device.
    (v) Whether any dehydrator emissions were vented to a flare or
regenerator firebox/fire tubes. If any dehydrator emissions were vented
to a flare or regenerator firebox/fire tubes, then you must report the
information specified in paragraphs (e)(2)(v)(A) through (D) of this
section.
* * * * *
    (vi) For dehydrators reported in paragraph (e)(2)(i) of this
section that were not vented to a flare or regenerator firebox/fire
tubes, report the information specified in paragraphs (e)(2)(vi)(A) and
(B) of this section.
* * * * *
    (3) * * *
    (i) The same information specified in paragraphs (e)(2)(i) through
(v) of this section for glycol dehydrators, and report the information
under this paragraph for dehydrators that use desiccant.
* * * * *
    (f) * * *
    (1) * * *
    (ii) Well tubing diameter and pressure group ID and a list of the
well ID

numbers associated with each sub-basin 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) * * *
    (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). 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, for each sub-basin (average of ``FRs,p''
values in Equation W-12A), 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 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).
    (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).
    (6) If you used Equation W-10B to calculate annual volumetric total
gas emissions for completions that vent gas to the atmosphere, 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).
    (ii) Flow rate, in standard cubic feet per hour, at the beginning
of the period of time when sufficient quantities of gas are present to
enable separation (``FRp,i'' in Equation W-10B).
    (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 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). 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 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). 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 without hydraulic fracturing and without flaring.
* * * * *
    (4) * * *
    (i) Sub-basin ID and a list of well ID numbers associated with each
sub-basin 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.
* * * * *
    (3) Onshore natural gas transmission pipeline segment. Report the
information in paragraphs (i)(3)(i) to (i)(3)(iii) for each separate
transmission pipeline blowdown event.
    (i) Annual CO2 emissions in metric tons CO2.

    (ii) Annual CH4 emissions in metric tons CH4.
    (iii) The location of the blowdown, in latitude and longitude in
decimal degree format provided as a comma-delimited ``latitude,
longitude'' coordinate pair reported in decimal degrees to at least
four digits to the right of the decimal point.
    (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, 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 to
calculate GHG emissions, then you must report the information specified
in paragraphs (j)(1)(i) through (xv) of this section for each sub-basin
and by calculation method. Onshore petroleum and natural gas gathering
and boosting facilities do not report the information specified in
paragraph (j)(1)(xiii) of this section.
* * * * *
    (ii) A list of the well ID number(s) associated with the tanks that
controlled emissions with flares (for the onshore petroleum and natural
gas production industry segment only).
    (iii) A list of the well ID number(s) associated with the tanks
that did not control emissions with flares (for the onshore petroleum
and natural gas production industry segment only).
* * * * *
    (v) The total annual oil volume from gas-liquid separators and
direct from wells 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 if you
indicate in the annual report that wildcat wells and/or delineation
wells are the only wells in the sub-basin 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.
* * * * *
    (ix) The minimum and maximum concentration (mole fraction) of
CO2 in flash gas from onshore production and onshore natural
gas gathering and boosting storage tanks.
    (x) The minimum and maximum concentration (mole fraction) of
CH4 in flash gas from onshore production and onshore
petroleum and natural gas gathering and boosting storage tanks.
* * * * *
    (xiv) If any emissions from the atmospheric tanks at your facility
were controlled with vapor recovery systems, then you must report the
information specified in paragraphs (j)(1)(xiv)(A) through (E) of this
section.
* * * * *
    (xv) If any atmospheric tanks at your facility vented gas directly
to the atmosphere without using a vapor recovery system or without
flaring, then you must report the information specified in paragraphs
(j)(1)(xv)(A) through (C) of this section.
* * * * *
    (xvi) If you controlled emissions from any atmospheric tanks at
your facility with one or more flares, then you must report the
information specified in paragraphs (j)(1)(xvi)(A) through (D) of this
section.
* * * * *
    (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. 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 if you indicate in the annual report that wildcat
wells and/or delineation wells are the only wells in the sub-basin with
oil production less than 10 barrels per day and that send oil 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 throughput from all wells and the well ID number(s)
for the well(s) included in the measurement.
    (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) * * *
    (B) The number of atmospheric tanks in the sub-basin that did not
control emissions with flares, including those that have vapor
recovery, and for the onshore petroleum and natural gas production
industry segment only, a list of the well ID numbers of the associated
wells.
* * * * *
    (iii) * * *
    (B) The number of atmospheric tanks in the sub-basin that
controlled emissions with flares, and for the onshore petroleum and
natural gas production industry segment only, a list of the well ID
numbers of the associated wells.
* * * * *
    (l) * * *
    (1) If you used Equation W-17A 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 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 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 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 in each
sub-basin 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 this subpart). 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) Flare stacks. You must indicate if your facility contains any
flare stacks. You must report the information specified in paragraphs
(n)(1) through (13) of this section for each flare stack at your
facility, and for each industry segment applicable to your facility.
    (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.
* * * * *
    (13) For the onshore petroleum and natural gas production industry
segment, a list of the well ID numbers associated with flare stacks in
each sub-basin.
    (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 (iv) of this section.
* * * * *
    (ii) A list of the well ID numbers for the wells at which these
compressors are located (for the onshore petroleum and natural gas
production industry segment only).
* * * * *
    (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 (iv) of this
section.
* * * * *
    (ii) A list of the well ID numbers for the wells at which these
compressors are located (for the onshore petroleum and natural gas
production industry segment only).
* * * * *
    (r) * * *
    (1) You must indicate whether your facility contains any of the
emission source types required to use Equation W-32A of this subpart.
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 of this subpart 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) of this section 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. For the onshore petroleum and natural gas
production facilities only, also report a list of well ID numbers for
the associated wells.
* * * * *
    (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.
* * * * *
    (w) * * *
    (2) EOR injection pump system identifier and a list of the well ID
number(s) associated with each EOR injection pump.
* * * * *
    (x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon
liquids were produced through EOR operations. If hydrocarbon liquids
were produced through EOR operations, you must report the information
specified in paragraphs (x)(1) through (5) of this section for each
sub-basin category with EOR operations.
* * * * *
    (2) A list of the well ID numbers associated with the EOR
operations in each sub-basin.
* * * * *
    (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 paragraphs (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 paragraphs (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.
    (1) Indicate whether the combustion units include: External fuel
combustion units with a rated heat capacity less than or equal to 5
million Btu per hour; or, internal fuel combustion units that are not
compressor-drivers, with a rated heat capacity less than or equal to 1
mmBtu/hr (or the equivalent of 130 horsepower). If the facility
contains external fuel combustion units with a rated heat capacity less
than or equal to 5 million Btu per hour or internal fuel combustion
units that are not compressor-drivers, with a rated heat capacity less
than or equal to 1 million Btu per hour (or the equivalent of 130
horsepower), then you must report the information specified in
paragraphs (z)(1)(i) through (iii) of this section for each unit type.
* * * * *
    (iii) A list of the well ID numbers associated with the combustion
units (for the onshore petroleum and natural gas production industry
segment only).
    (2) Indicate whether the combustion units include: External fuel
combustion units with a rated heat capacity greater than 5 million Btu
per hour; internal fuel combustion units that are not compressor-
drivers, with a rated heat capacity greater than 1 million Btu per hour
(or the equivalent of 130 horsepower); or, internal fuel combustion
units of any heat capacity that are compressor-drivers. If your
facility contains: External fuel combustion units with a rated heat
capacity greater than 5 mmBtu/hr; internal fuel combustion units that
are not compressor-drivers, with a rated heat capacity greater than 1
million Btu per hour (or the equivalent of 130 horsepower); or internal
fuel combustion units of any heat capacity that are compressor-drivers,
then you must report the information specified in paragraphs (z)(2)(i)
through (vii) for each combustion unit type and fuel type combination.
* * * * *
    (ii) A list of the well ID numbers associated with the combustion
units (for the onshore petroleum and natural gas production industry
segment only).
* * * * *
    (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 and a list of the well ID numbers
at the end of the calendar year (exclude only those wells permanently
taken out of production, i.e., plugged and abandoned).
    (E) The number of producing wells and a list of the well ID numbers
acquired during the calendar year.
    (F) The number of producing wells and a list of the well ID numbers
divested during the calendar year.
    (G) The number of wells and a list of the well ID numbers completed
during the calendar year.
    (H) The number of wells permanently taken out of production (i.e.,
plugged and abandoned) and a list of the well ID numbers during the
calendar year.
* * * * *
    (10) For onshore petroleum and natural gas gathering and boosting
facilities, report the quantities specified in paragraphs (aa)(10)(i)
through (v) of this section.
    (i) The quantity of produced gas throughput in the calendar year,
in thousand standard cubic feet.
    (ii) The quantity of produced gas consumed by the facility in the
calendar year, in thousand standard cubic feet.

    (iii) The quantity of produced condensate throughput in the
calendar year, in barrels.
    (iv) The quantity of produced oil throughput in the calendar year,
in barrels.
    (v) The quantity of gas flared, vented and/or unaccounted for in
the calendar year, in thousand standard cubic feet.
    (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
pipeline facility for operational purposes, in thousand standard cubic
feet.
    (vi) The miles of transmission pipeline in the facility.
* * * * *
    (cc) If you elect to delay reporting the information in paragraph
(g)(5)(i), (g)(5)(ii), (h)(1)(iv), (h)(2)(iv), (j)(1)(v), (j)(2)(i)(A),
(l)(1)(iv), (l)(2)(iv), (l)(3)(iii), (l)(4)(iii), (m)(5), or (m)(6) of
this section, you must report the information required in that
paragraph no later than the date 2 years following the date specified
in Sec.  98.3(b) introductory text.
0
8. Section 98.238 is amended by adding definitions of ``Facility with
respect to petroleum and natural gas gathering and boosting for
purposes of reporting under this subpart and for the corresponding
subpart A requirements,'' ``Facility with respect to the onshore
natural gas transmission pipeline segment,'' ``Gathering and boosting
system,'' ``Gathering and boosting system owner or operator,''
``Onshore natural gas transmission pipeline owner or operator,'' and
``Well identification (ID) number'' in alphabetical order to read as
follows:

Sec.  98.238  Definitions.

* * * * *
    Facility with respect to petroleum and natural gas gathering and
boosting for purposes of reporting under this subpart and for the
corresponding subpart A requirements means all gathering pipelines and
other equipment located along those pipelines that are under common
ownership or common control by a gathering and boosting system owner or
operator and that are located in a single hydrocarbon basin as defined
in this section. Where a person owns or operates more than one
gathering and boosting system in a basin (for example, separate
gathering lines that are not connected), then all gathering and
boosting equipment that the person owns or operates in the basin would
be considered one facility. Any gathering and boosting equipment that
is associated with a single gathering and boosting system, including
leased, rented, or contracted activities, is considered to be under
common control of the owner or operator of the gathering and boosting
system that contains the pipeline. The facility does not include
equipment and pipelines that are part of any other industry segment
defined in this subpart.
    Facility with respect to the onshore natural gas transmission
pipeline segment means the total U.S. mileage of natural gas
transmission pipelines, as defined in this section, owned and operated
by an onshore natural gas transmission pipeline owner or operator as
defined in this section.
* * * * *
    Gathering and boosting system means a single network of pipelines,
compressors and process equipment, including equipment to perform
natural gas compression, dehydration, and acid gas removal, that has
one or more connection points to gas and oil production and a
downstream endpoint, typically a gas processing plant, transmission
pipeline, LDC pipeline, or other gathering and boosting system.
    Gathering and boosting system owner or operator means any person
that holds a contract in which they agree to transport petroleum or
natural gas from one or more onshore petroleum and natural gas
production wells to a natural gas processing facility, another
gathering and boosting system, a natural gas transmission pipeline, or
a distribution pipeline, or any person responsible for custody of the
gas transported.
* * * * *
    Onshore natural gas transmission pipeline owner or operator means,
for interstate pipelines, the person identified as the transmission
pipeline owner or operator on the Certificate of Public Convenience and
Necessity issued under 15 U.S.C. 717f, or, for intrastate pipelines,
the person identified as the owner or operator on the transmission
pipeline's Statement of Operating Conditions under section 311 of the
Natural Gas Policy Act.
* * * * *
    Well identification (ID) number means the unique and permanent
identification number assigned to a petroleum or natural gas well. If
the well has been assigned a US Well Number, the well ID number
required in this subpart is the US Well Number. If a US Well Number has
not been assigned to the well, the well ID number is the identifier
established by the well's permitting authority.
* * * * *
0
9. Revise Table W-1A of Subpart W of part 98 to read as follows:

 Table W-1A of Subpart W of Part 98--Default Whole Gas Emission Factors
 for Onshore Petroleum and Natural Gas Production Facilities and Onshore
       Petroleum and Natural Gas Gathering and Boosting Facilities
------------------------------------------------------------------------
Onshore petroleum and natural gas production and
 onshore petroleum and natural gas gathering and   Emission factor (scf/
                    boosting                          hour/component)
------------------------------------------------------------------------
                              Eastern U.S.
------------------------------------------------------------------------
       Population Emission Factors_All Components, Gas Service \1\
------------------------------------------------------------------------
Valve...........................................                  0.027
Connector.......................................                  0.003
Open-ended Line.................................                  0.061
Pressure Relief Valve...........................                  0.040
Low Continuous Bleed Pneumatic Device Vents \2\.                  1.39

High Continuous Bleed Pneumatic Device Vents \2\                 37.3
Intermittent Bleed Pneumatic Device Vents \2\...                 13.5
Pneumatic Pumps \3\.............................                 13.3
------------------------------------------------------------------------
   Population Emission Factors_All Components, Light Crude Service \4\
------------------------------------------------------------------------
Valve...........................................                  0.05
Flange..........................................                  0.003
Connector.......................................                  0.007
Open-ended Line.................................                  0.05
Pump............................................                  0.01
Other \5\.......................................                  0.30
------------------------------------------------------------------------
   Population Emission Factors_All Components, Heavy Crude Service \6\
------------------------------------------------------------------------
Valve...........................................                  0.0005
Flange..........................................                  0.0009
Connector (other)...............................                  0.0003
Open-ended Line.................................                  0.006
Other \5\.......................................                  0.003
------------------------------------------------------------------------
             Population Emission Factors_Gathering Pipelines
------------------------------------------------------------------------
Gathering Pipeline \7\..........................                  2.81
------------------------------------------------------------------------
                              Western U.S.
------------------------------------------------------------------------
       Population Emission Factors_All Components, Gas Service \1\
------------------------------------------------------------------------
Valve...........................................                  0.121
Connector.......................................                  0.017
Open-ended Line.................................                  0.031
Pressure Relief Valve...........................                  0.193
Low Continuous Bleed Pneumatic Device Vents \2\.                  1.39
High Continuous Bleed Pneumatic Device Vents \2\                 37.3
Intermittent Bleed Pneumatic Device Vents \2\...                 13.5
Pneumatic Pumps \3\.............................                 13.3
------------------------------------------------------------------------
   Population Emission Factors_All Components, Light Crude Service \4\
------------------------------------------------------------------------
Valve...........................................                  0.05
Flange..........................................                  0.003
Connector (other)...............................                  0.007
Open-ended Line.................................                  0.05
Pump............................................                  0.01
Other \5\.......................................                  0.30
------------------------------------------------------------------------
   Population Emission Factors_All Components, Heavy Crude Service \6\
------------------------------------------------------------------------
Valve...........................................                  0.0005
Flange..........................................                  0.0009
Connector (other)...............................                  0.0003
Open-ended Line.................................                  0.006
Other \5\.......................................                  0.003
------------------------------------------------------------------------
             Population Emission Factors_Gathering Pipelines
------------------------------------------------------------------------
Gathering Pipeline \7\..........................                  2.81
------------------------------------------------------------------------
\1\ For multi-phase flow that includes gas, use the gas service
  emissions factors.
\2\ Emission Factor is in units of ``scf/hour/device.''
\3\ Emission Factor is in units of ``scf/hour/pump.''
\4\ Hydrocarbon liquids greater than or equal to 20[deg]API are
  considered ``light crude.''
\5\ ``Others'' category includes instruments, loading arms, pressure
  relief valves, stuffing boxes, compressor seals, dump lever arms, and
  vents.
\6\ Hydrocarbon liquids less than 20[deg]API are considered ``heavy
  crude.''
\7\ Emission factor is in units of ``scf/hour/mile of pipeline.''

0
10. Amend Table W-1B of Subpart W of part 98 by revising the table
heading to read as follows:

Table W-1B to Subpart W of Part 98--Default Average Component Counts for
Major Onshore Natural Gas Production Equipment and Onshore Petroleum and
              Natural Gas Gathering and Boosting Equipment

* * * * *
[FR Doc. 2014-28395 Filed 12-8-14; 8:45 am]
BILLING CODE 6560-50-P