of once a year. If data are lost or an error occurs during emissions
detection and/or measurement or calculation, the operator would be
required to carry out the detection, direct measurement, and/or
calculation a second time to obtain the relevant data point(s) as soon
as the missing data are discovered. If this falls outside of the
reporting year (e.g. between the end of the reporting year and the date
when the emissions must be reported) the operator would be required to
perform the necessary data development and report the results for the
previous year. This prior year's lost data replacement could not be
used as the one-time data collection for the current year. Where
missing data procedures are used for the previous year, at least 30
days would be required to separate emissions estimation and/or
measurements for the previous year and emissions estimation and/or
measurements for the current year of data collection in order to better
represent emissions estimates for different years. Similarly,
engineering estimates would account for relevant source counts and
frequency from the previous reporting period.

G. Selection of Data Reporting Requirements

    EPA proposes that emissions from the petroleum and natural gas
industry be reported on an annual basis. The reporting should be by the
owner or operator of the facility as defined in the supplemental rule.
Emissions from each source type at the facility would be required to be
aggregated for reporting, with a few exceptions for field level
reporting (e.g., well completions and well workovers). For other
equipment, unit-level reporting would not be required. For example, the
owner or operator with multiple reciprocating compressors in an onshore
production basin would be required to report emissions collectively
from all rod packings on all cylinders from all compressors for all
fields in that basin as specified in this proposed rulemaking.
Generally, EPA has proposed that onshore production be reported at the
basin level, as opposed to the unit or field level, to minimize
reporting burden. EPA notes that in a concurrent proposed rulemaking
for facilities that conduct CO2 injection or geologic
sequestration (subpart RR), the term ``facility'' is defined at a more
disaggregated level, specifically as a ``well or group of wells.'' EPA
seeks comment on the use of more disaggregated reporting options for
subpart W.
    Emissions from all sources proposed for monitoring, whether in
operating condition or on standby, would have to be reported. Any
emissions resulting from standby compressor sources would

be separately identified from the aggregate emissions.
    The owner or operator would be required to report the following
information to EPA as a part of the annual emissions reporting:
fugitive, vented and flare combustion emissions monitored at an
aggregate source level (unless specified otherwise), emissions from
standby sources; and activity data for each aggregate source type
level. Owners or operators of natural gas distribution facilities would
report emissions at the individual station level.
    Additional data are proposed to be reported to support
verification: Engineering estimate of total component count; total
number of compressors and average operating hours per year in each mode
of operation for compressors, if applicable; minimum, maximum and
average throughput per year; and specification of the type of any
control device used, including flares. For offshore petroleum and
natural gas production facilities, the number of connected wells, and
whether they are producing oil, gas, or both is proposed to be
reported. For compressors specifically, EPA proposes that the total
number of compressors of each type (reciprocating, centrifugal with dry
seals and centrifugal with wet seals) and average operating hours per
year be reported.
    A full list of data proposed to be reported is included in proposed
40 CFR part 98, subparts A and W.

H. Selection of Records That Must Be Retained

    The owner or operator shall retain relevant information associated
with the monitoring and reporting of emissions to EPA for three years
as follows: Throughput of the facility when the emissions direct
measurement was conducted; date(s) of measurement, detection and
measurement instruments used, if any; and results of the emissions
detection survey, including a video record of the leak survey.
    A full list of records proposed to be retained is included in
proposed 40 CFR part 98, subparts A and W.

III. Economic Impacts of the Proposed Rule

    This section of the preamble examines the costs and economic
impacts of this proposed supplemental rule, including the estimated
costs and benefits of the rule, and the estimated economic impacts of
the rule on affected entities, including estimated impacts on small
entities. Complete details of the economic impacts of the final rule
can be found in the text of the Economic Impact Analysis for the
Mandatory Reporting of Greenhouse Gas Emissions under Subpart W
Supplemental Rule (EPA-HQ-OAR-2009-0923). In brief, all equipment and
labor activities for complying with each emissions estimate in the rule
were analyzed by technical experts with relevant industry experience.
The estimated labor hours and labor categories were applied to each
industry segment, in some cases proportioned to small, medium and large
facilities where such variation exists, to quantify the total labor
hours, multiplied by Government statistics on labor rates, arriving at
the total labor and equipment costs for the estimated numbers of
sources. Administrative costs for reviewing the reporting rules,
training personnel, documenting emissions data and emissions estimates,
approving the submission to the EPA, submitting reports and maintaining
records were included for each reporting company. These total bottom-up
cost estimates were divided by the emissions captured to arrive at the
dollar per metric ton, and divided by the number of reporting entities
to arrive at average costs per entity. The methods proposed by EPA are
a balance between minimizing these costs, maximizing emissions coverage
and maximizing quality of emissions estimates. The cost to affected
parties on a dollar per metric ton has been reduced by greater than 50
percent when compared to the initial petroleum and natural gas
proposal. To achieve this cost reduction, EPA significantly modified
the rule to rely significantly less on direct measurement and more on
engineering estimates, leaker factors and emissions factors. Table W-5
and Table W-6 compare the first year and subsequent year costs,
respectively, to reporters for reporting fugitive and vented emissions
based on the reporting requirements proposed under the initial proposal
as compared to the new supplemental proposed rule.

 Table W-5--Estimated First Year Cost for Reporting Fugitive and Vented Emissions for Petroleum and Natural Gas
                                                Systems, MMTCO2E
----------------------------------------------------------------------------------------------------------------
                                                      Initial proposed rule1         New supplemental proposed
                                                 --------------------------------           rulemaking
                     Segment                                                     -------------------------------
                                                       Cost       Cost per tonne       Cost       Cost per tonne
                                                    ($million)       ($/tonne)      ($million)       ($/tonne)
----------------------------------------------------------------------------------------------------------------
Original six segments...........................           $32.5           $0.38           $26.7           $0.28
Onshore Production..............................              NA              NA            27.7            0.18
Natural Gas Distribution........................              NA              NA             1.6            0.07
                                                 ---------------------------------------------------------------
    Total Segments..............................            32.5            0.38            56.0            0.21
----------------------------------------------------------------------------------------------------------------
\1\ The costs for the initial proposed rule, shown here, reflect the in-house monitoring option. Costs for the
  alternative contractor monitoring option can be found in Docket EPA-HQ-OAR-2008-0508-0138.

 TABLE W-6--Estimated Subsequent Year Cost for Reporting Fugitive and Vented Emissions for Petroleum and Natural
                                              Gas Systems, MMTCO2E
----------------------------------------------------------------------------------------------------------------
                                                       Initial proposed rule         New supplemental proposed
                                                 --------------------------------           rulemaking
                     Segment                                                     -------------------------------
                                                       Cost       Cost per tonne       Cost       Cost per tonne
                                                    ($million)       ($/tonne)      ($million)       ($/tonne)
----------------------------------------------------------------------------------------------------------------
Original six segments...........................           $28.1           $0.33            11.8           $0.13
Onshore Production..............................              NA              NA             8.6            0.06
Natural Gas Distribution........................              NA              NA             1.0            0.04
                                                 ---------------------------------------------------------------

    Total Segments..............................           $28.1           $0.33            21.4            0.08
----------------------------------------------------------------------------------------------------------------
\1\ Subsequent year in the initial proposed rule was defined as Year 2 whereas in the supplemental proposed rule
  it is defined as the average of Years 2, 3, and 4.

A. How were compliance costs estimated?

1. Summary of EPA's Consideration of Comments Received on the Initial
Proposal
    A majority of the comments received on the compliance costs of the
fugitive emissions reporting rule focused on facility level costs for
detection and measurement of emissions. Commenters noted that costs
estimated for certain petroleum and gas industry segments ignored
available data on average leak factors. Some who commented specifically
referred to government programs that gather similar, or in the case of
offshore petroleum and gas production in the Gulf of Mexico Federal
waters, some of the same data as required under Subpart W. Others who
commented noted that Subpart W had higher estimated compliance costs
than other sectors for much smaller GHG emissions.
    EPA recognizes that the costs presented for some petroleum and gas
industry segments in the initial proposal were relatively high for
smaller emissions quantified than other industry sectors. EPA also
recognizes that for many fugitive and vented emissions sources, new
data exist on component emission factors, and long established data may
be justified for smaller, inaccessible to plain view or more burdensome
to identify emission sources. Furthermore, EPA recognizes that other
government programs gather similar or the same data as proposed by this
rule.
    This proposed supplemental rule incorporates a number of different
methodologies to provide improved emissions coverage at a lower cost
burden to affected facilities. The approach used in determining the
appropriate methodology for the supplemental was to minimize the use of
direct measurement of emissions (which results in a higher cost burden
to affected facilities) except for the most significant emissions
sources where other options are not available, and to use engineering
estimates, emissions modeling software, and leak detection and publicly
available emission factors for most vented and fugitive sources. For
smaller fugitive and inaccessible to plain view (i.e. buried or below
grade in vaults) sources, component count and population emissions
factors are proposed. In the case of Offshore platforms, EPA is
recommending that emissions identified under the Minerals Management
Services (MMS) GOADS (Gulfwide Offshore Activities Data System) be used
for reporting, and the GOADS process be extended to platforms in other
Federal regions (i.e., California and Alaska) and all State waters.
These alternative methodologies will provide similar or better coverage
of vented and fugitive methane and carbon dioxide emissions in the
petroleum and gas industry, while significantly reducing industry
burden.
    As described in the next section, EPA collected and evaluated cost
data from multiple sources, and weighed the analysis prepared at
initial proposal against the input received through public comments. In
any analysis of this type, there will be variations in costs among
facilities, and after thoroughly reviewing the available information,
we have concluded that the costs developed for this supplemental
proposed rule in each petroleum and gas industry segment appropriately
reflects a ``representative facility'' in those segments.
2. Summary of Method Used To Estimate Compliance Costs
    EPA estimated costs of complying with the rule for reporting
fugitive and vented GHG emissions in each affected petroleum and gas
industry facility, as well as emissions from stationary combustion
sources at petroleum and gas industry facilities (for threshold and
burden analysis only; stationary combustion is reported under Subpart
C). This supplemental rulemaking proposes methodologies for reporting
fugitive and vented emissions from oil and gas facilities. Once
triggering the proposed rule, all of these facilities would also have
to report emissions from stationary combustion. The costs of compliance
for this proposed rule includes the costs associated with calculating
and reporting fugitive and vented emissions, as well as the costs of
any incremental combustion-related emissions that would be required to
be reported by facilities (i.e., combustion emissions that were not
already required to be reported under the final MRR). The
representative year of the analysis is 2006 and all annual costs were
estimated using the 2006 population of emitting sources. EPA used
available industry and EPA data to characterize conditions at affected
sources. Incremental monitoring, recordkeeping, and reporting
activities were then identified for each type of facility and the
associated costs were estimated.
    The costs of complying with the rule will vary from one petroleum
and gas industry segment and facility to another, depending on the
types of emissions, the number of affected sources at the facility,
existing monitoring, recordkeeping, and reporting activities at the
facility, etc. The costs include labor costs for developing a plan,
setting up records, collecting field data, performing monitoring,
inputting field data into engineering models, recordkeeping, and
reporting activities necessary to comply with the rule. For some
facilities, costs include expenditures related to monitoring,
recording, and reporting both process emissions of GHGs and emissions
from stationary combustion. For other facilities (e.g., LDCs), the only
emissions of GHGs are process emissions. EPA's estimated costs of
compliance are discussed in greater detail below:
    Labor Costs. The costs of complying with and administering this
rule include time of managers, technical, operational and
administrative staff in the private sector. Staff hours are estimated
for activities, including:
     Developing a plan: reporting entity management and
technical staff hours to applicability to the rule, organize
indoctrination of rule requirements, identify staffing assignments,
train staff, schedule activities as required below.

     Setting up records: technical and field staff hours to
develop data collection sheets and analytical model equations or
linkages to input data into standardized models
     Collecting field data: technical and field staff hours to
collect necessary site-specific data and input that data into the
analytical input tables.
     Monitoring: staff hours to procure, install, operate and
maintain emissions monitoring equipment, instruments and engineering
analysis systems.
     Engineering models: technical staff hours to link and
execute engineering emissions estimation models and analytical
procedures and to organize output data as required for reporting
emissions.
     Record keeping: staff hours required to organize, file and
secure critical data and emissions quantification results as required
for reporting and for documenting determinations of facilities
exceeding and not exceeding reporting thresholds.
     Reporting: management and staff hours to organize data,
perform quality assurance/quality control, inform key management
personnel, and reporting it to EPA through electronic systems.
    Staff activities and associated labor costs will vary from facility
to facility and potentially vary over time where first year start-up
costs are more significant and where site-specific emissions factors
are developed every two or three years. Thus, cost estimates are
developed for start-up and first-time reporting, and subsequent
reporting. Wage rates to monetize staff time are obtained from the
Bureau of Labor Statistics (BLS).
    Equipment Costs. Equipment costs include both the initial purchase
price of monitoring equipment and any facility/process modification
that may be required for installation and/or use of monitoring
equipment. For example, the cost estimation method for large compressor
seal emissions includes both purchase of a flow measurement instrument
and installation of a measurement port in the vent piping where the end
of the vent is inaccessible. Based on expert judgment, the engineering
costs analyses annualized capital equipment costs with appropriate
lifetime and interest rate assumptions. Cost recovery periods and
interest rates vary by industry, but typically, one-time capital costs
are amortized over a 10-year cost recovery period at a rate of seven
percent.

B. What are the costs of the proposed rule?

1. Summary of Costs
    For the cost analysis, EPA gathered existing data from EPA studies
and publications, industry trade associations and publicly available
data sources (e.g., labor rates from the BLS) to characterize the
processes, sources, sectors, facilities, and companies/entities
affected. EPA also considered cost data submitted in public comments on
the proposed rule. Costs were estimated on a per entity basis and then
weighted by the number of entities affected at the 25,000 metric tons
CO2e threshold.
    To develop the costs for the rule, EPA estimated the number of
affected facilities in each source category, the number and types of
process equipment at each facility, the number and types of processes
that emit GHGs, process inputs and outputs (especially for monitoring
procedures that involve a carbon mass balance), and the measurements
that are already being made for reasons not associated with the rule
(to allow only the incremental costs to be estimated). Many of the
affected source categories, especially those that are the largest
emitters of GHGs (e.g., glycol dehydrators, petroleum stock tanks, gas
processing plants) are subject to national emission standards and we
use data generated in the development of these standards to estimate
the number of sources affected by the proposed reporting rule.
    Other components of the cost analysis included estimates of labor
hours to perform specific activities, cost of labor, and cost of
monitoring equipment. Estimates of labor hours were based on previous
analyses of the costs of monitoring, reporting, and recordkeeping for
other rules; information from the industry characterization on the
number of units or process inputs and outputs to be monitored; and
engineering judgment by industry and EPA industry experts and
engineers. Labor costs were taken from the BLS and adjusted to account
for overhead. Monitoring costs were generally based on cost algorithms
or approaches that had been previously developed, reviewed, accepted as
adequate, and used specifically to estimate the costs associated with
various types of measurements and monitoring.
    A detailed engineering analysis was conducted for each petroleum
and gas industry segment of this proposed rule to develop unique unit
costs. This analysis is documented in the Economic Impact Analysis for
the Mandatory Reporting of Greenhouse Gas Emissions under Subpart W
Supplemental Rule (EPA-HQ-OAR-2009-0923). The Greenhouse Gas Emissions
from the Petroleum and Natural Gas Industry: Background TSD (EPA-HQ-
OAR-2009-0923) provides a discussion of the applicable engineering
estimating and measurement technologies and any existing programs and
practices. Incremental combustion-related emissions that would be
required to be reported by facilities (as noted above) were estimated
using Tier 1 factors from Subpart C of the Final MRR. Section 4 of the
Economic Impact Analysis for the proposed rule contains a description
of the engineering cost analysis.
    Table W-7 of this preamble presents: the emissions covered under
this proposed supplemental rule, the first year total costs and the
first year cost per ton for process and combustion emissions, and these
values for the subsequent years. EPA estimates that the total cost for
process emissions in the first year is $56.0 million, and the total
national annualized cost for subsequent years is $21.4 million (2006$).
Of these costs, roughly 49.5 percent fall upon the onshore production
segment in the first year, while 34.5 percent fall upon the gas
transmission segment. Offshore production, which is largely covered by
the MMS GOADS study data, is estimated to incur approximately 0.5
percent of costs every three or four years; other segments incurring
relatively large shares of costs are gas processing (12.5 percent) and
local distribution companies (3 percent). The reporting of incremental
combustion related emission for all segments of the petroleum and
natural gas industry are estimated to cost $3.9 million in both the
first and subsequent years.
    The threshold, in large part, determines the number of entities
required to report GHG emissions and hence the costs of the rule. The
number of entities excluded increases with higher thresholds. Table W-8
of this preamble provides the cost-effectiveness analysis for various
thresholds examined. Two metrics are used to evaluate the cost-
effectiveness of the emissions threshold. The first is the average cost
per metric ton of emissions reported ($/metric ton CO2e).
The second metric for evaluating the threshold option is the
incremental cost of reporting emissions. The incremental cost is
calculated as the additional (incremental) cost per metric ton starting
with the least stringent option and moving successively from one
threshold option to the next. For more information about the first year
capital costs (unamortized), project lifetime and

the amortized (annualized) costs for each petroleum and gas industry
segment please refer to section 4 of the Economic Analysis for the
proposed rule. Not all segments require capital expenditures but those
that do are clearly documented in the Economic Impact Analysis for the
proposed rule.

                                        Table W-7--National Cost Estimates for Petroleum and Natural Gas Systems
                                                                         [2006$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                First year                          Subsequent years
                                                                           -----------------------------------------------------------------------------
         Subpart W--petroleum and natural gas systems             NAICS     $million\1\                              $million
                                                                           -------------   Million       $/ton    -------------   Million       $/ton
                                                                                2006        MtCO2e                     2006        MtCO2e
--------------------------------------------------------------------------------------------------------------------------------------------------------
Fugitive and Vented Emissions................................     211, 486          $56        272.0        $0.21        $21.4        272.0        $0.08
Combustion Emissions.........................................  ...........          3.9         79.1         0.05          3.9         79.1         0.05
                                                              ------------------------------------------------------------------------------------------
    Total Private Sector Emissions...........................  ...........         59.9        351.1         0.17         25.3        351.1         0.07
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                Table W-8--Threshold Cost-Effectiveness Analysis
                                            [Subsequent year, 2006$]
----------------------------------------------------------------------------------------------------------------
                                                                   Percentage of
   Threshold        Facilities      Total costs     Downstream         total          Average       Incremental
  (metric tons     required to       (million        emissions      downstream    reporting cost     cost  ($/
     CO2e)            report          $2006)         reported        emissions        ($/ton)       metric ton)
                                                   (MtCO2e/year)     reported                           \1\
----------------------------------------------------------------------------------------------------------------
        100,000            1,143          $13.66             273              64           $0.05           $0.05
         25,000            3,037           25.30             351              83            0.08            0.13
         10,000            4,884           38.62             380              90            0.10            0.23
          1,000           15,057           97.18             415              98            0.23            0.46
----------------------------------------------------------------------------------------------------------------
\1\ Cost per metric ton relative to the selected option.

C. What are the economic impacts of the proposed rule?

1. Summary of Economic Impacts
    EPA prepared an economic impact analysis to evaluate the impacts of
the rule on affected small to large reporting entities. In evaluating
the various reporting options considered, EPA conducted a cost-
effectiveness analysis, comparing the cost per metric ton of GHG
emissions across reporting options. EPA used this information to
identify the preferred options described in today's proposed rule.
    To estimate the economic impacts of the rule, EPA first conducted a
screening assessment, comparing the estimated total annualized
compliance costs for the petroleum and gas industry, where industry is
defined in terms of North American Industry Classification System
(NAICS) code, with industry average revenues. Overall national costs of
the rule are significant because there are a large number of affected
entities, but per-entity costs are low due to large coverage of
emissions from these entities. Average cost-to-sales ratios for
establishments in the affected NAICS codes for all segments is less
than 1 percent, except in the 1-20 employee range for the onshore
petroleum and natural gas segment.
    These low average cost-to-sales ratios indicate that the proposed
rule is unlikely to result in significant changes in firms' production
decisions or other behavioral changes, and thus unlikely to result in
significant changes in prices or quantities in affected markets. Thus,
EPA followed its Guidelines for Preparing Economic Analyses (EPA, 2002,
p. 124-125) and used the engineering cost estimates to measure the
social cost of the rule, rather than modeling market responses and
using the resulting measures of social cost. Table W-9 of this preamble
summarizes cost-to-sales ratios for affected industries.

                         Table W-9--Estimated Cost-to-Sales Ratios for Affected Entities
                                                    [Year 1]
----------------------------------------------------------------------------------------------------------------
                                                                              Average cost per   Average entity
                  NAICS                            NAICS description          entity  ($1,000/    cost-to-sales
                                                                                entity)          ratio\1\
----------------------------------------------------------------------------------------------------------------
211.....................................  Crude Petroleum and Natural Gas                  $24             0.11%
                                           Extraction.
486210..................................  Pipeline Transportation of Natural                18             0.10%
                                           Gas.
221210..................................  Natural Gas Distribution..........                11             0.05%
----------------------------------------------------------------------------------------------------------------
\1\ This ratio reflects first year costs. Subsequent year costs will be slightly lower because they do not
  include initial start-up activities.

D. What are the impacts of the proposed rule on small businesses?

1. Summary of Impacts on Small Businesses
    As required by the RFA and Small Business Regulatory Enforcement
and Fairness ACT (SBREFA), EPA assessed the potential impacts of the
rule on small entities (small businesses, governments, and non-profit
organizations). (See Section IV.C of this preamble for definitions of
small entities.)
    EPA has determined the selected threshold maximizes the rule
coverage with 83 percent of U.S. GHG emissions from the industry
segments reported by approximately 3,037 reporters, while keeping
reporting burden to a minimum. Furthermore, many industry stakeholders
that EPA met with expressed support for a 25,000 metric ton
CO2e threshold because it sufficiently captures the majority
of GHG emissions in the U.S., while excluding most of the smaller
facilities and sources. We received many comments related to monitoring
and reporting requirements in specific source categories, and made many
changes in response to reduce burden on reporters. For information on
these issues, refer to the discussion of each segment in this preamble.
    EPA conducted a screening assessment comparing compliance costs to
onshore petroleum and natural gas production specific receipts data for
establishments owned by small businesses. This ratio constitutes a
``sales'' test that computes the annualized compliance costs of this
rule as a percentage of sales and determines whether the ratio exceeds
one percent.\9\ The cost-to-sales ratios were constructed at the
establishment level (average reporting program costs per establishment/
average establishment receipts) for several business size ranges. This
allowed EPA to account for receipt differences between establishments
owned by large and small businesses and differences in small business
definitions across affected industries. The results of the screening
assessment are shown in Table W-10 of this preamble.
---------------------------------------------------------------------------

    \9\ EPA's RFA guidance for rule writers suggests the ``sales''
test continues to be the preferred quantitative metric for economic
impact screening analysis.

                                               Table W-10.--Estimated Cost-to-Sales Ratios for First Year Costs by Industry and Enterprise Size\a\
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Average                                         Owned by enterprises with:
                                                                      SBA Size  Standard   cost per              -------------------------------------------------------------------------------
             Industry                NAICS     NAICS Description     (effective March 11,   entity       All                                 100 to     500 to                750 to    1,000 to
                                                                            2008)          ($1,000/  enterprises       <20       20 to 99     499        749        <500       999       1,499
                                                                                entity)               employees\f\  employees  employees  employees  employees  employees  employees
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Onshore petroleum and natural gas       211  Crude Petroleum and    500 employees........       $24      0.11%          1.83%       0.16%      0.07%      0.03%      0.65%      0.04%      0.03%
 production; offshore petroleum               Natural Gas
 and natural gas production; LNG              Extraction.
 storage; LNG import and export.
Onshore natural gas processing;      486210  Pipeline               7.5 million dollars..        18       0.10           0.14    0.47 \b\   0.28 \b\  .........       0.12  .........  .........
 onshore natural gas transmission;            Transportation of
 underground natural gas storage.             Natural Gas.
Natural gas distribution..........   221210  Natural Gas            7.5 million dollars..        11       0.05           0.22        0.02       0.05       0.09       0.06       0.02      0.02
                                              Distribution.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise
  and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise--the enterprise employment and annual payroll are summed from the
  associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.
Since the SBA's business size definitions (http://www.sba.gov/size) apply to an establishment's ultimate parent company, we assume in this analysis that the enterprise definition above is
  consistent with the concept of ultimate parent company that is typically used for SBREFA screening analyses.
\2\ The Census Bureau has missing data ranges for this employee range. Hence the receipts are an underestimate of the true value. Therefore, the cost-to-sales ratio is a conservative estimate.

    As shown, the cost-to-sales ratios are less than one percent for
establishments owned by small businesses that EPA considers most likely
to be covered by the reporting program, except the ratio for 1-20
employee range for crude petroleum and natural gas extraction, which is
greater than 1 percent but less than 2 percent. The petroleum and
natural gas industry has a large number of enterprises, the majority of
them in the 1-20 employee range. However, a large fraction of
production comes from large corporations and not those with less than
20 employee enterprises. The smaller enterprises in most cases deal
with very small operations (such as a single family owning a few
production wells) that are unlikely to cross even 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 over 19,000 enterprises in the less than 20
employee category and EPA proposes to cover them in the rule.
    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, including seeking
input from a wide range of private- and public-sector

stakeholders. When developing the rule, the Agency took special steps
to ensure that the burdens imposed on small entities were minimal. The
Agency conducted several meetings with industry trade associations to
discuss regulatory options and the corresponding burden on industry,
such as recordkeeping and reporting. The Agency investigated
alternative thresholds and analyzed the marginal costs associated with
requiring smaller entities with lower emissions to report. The Agency
also recommended a hybrid method for reporting, which provides
flexibility to entities and helps minimize reporting costs.

E. What are the benefits of the proposed rule for society?

    EPA examined the potential benefits of the proposed GHG reporting
rule for petroleum and natural gas systems. The benefits of a reporting
system are based on their relevance to policy making, transparency
issues, and market efficiency. Benefits are very difficult to quantify
and monetize. Instead of a quantitative analysis of the benefits, EPA
conducted a systematic literature review of existing studies including
government, consulting, and scholarly reports.
    A mandatory reporting system for petroleum and natural gas systems
will benefit the public by increased transparency of facility emissions
data. Transparent, public data on emissions allows for accountability
of polluters to the public stakeholders who bear the cost of the
pollution. Citizens, community groups, and labor unions have made use
of data from Pollutant Release and Transfer Registers to negotiate
directly with polluters to lower emissions, circumventing greater
government regulation. Publicly available emissions data also will
allow individuals to alter their consumption habits based on the GHG
emissions of producers.
    The greatest benefit of mandatory reporting of petroleum and
natural gas systems GHG emissions to government will be realized in
developing future GHG policies. For example, in the European Union's
Emissions Trading System, a lack of accurate monitoring at the facility
level before establishing CO2 allowance permits resulted in
allocation of permits for emissions levels an average of 15 percent
above actual levels in every country except the United Kingdom.
    As the primary constituent of natural gas, methane is also an
important energy source. As a result, methane emissions reductions can
provide significant economic and environmental benefits. EPA has been
working in collaboration with oil and natural companies in the U.S. as
part of the Natural Gas STAR Program since 1993. Through this
collaborative partnership program, EPA has identified over 120 proven,
cost effective technologies and practices to reduce methane emissions
across operations in all of the major industry sectors--production,
gathering and processing, transmission, and distribution. The proposed
reporting rule will increase knowledge of the location and magnitude of
significant methane emissions sources in the oil and gas industry which
can result in cross-cutting benefits on domestic energy supply,
industrial efficiency and safety, and revenue generation.
    Benefits to industry of GHG emissions monitoring include the value
of having independent, verifiable data to present to the public to
demonstrate appropriate environmental stewardship, and a better
understanding of their emission levels and sources to identify
opportunities to reduce emissions. Such monitoring allows for inclusion
of standardized GHG data into environmental management systems,
providing the necessary information to achieve and disseminate their
environmental achievements.
    Standardization will also be a benefit to industry, once facilities
invest in the institutional knowledge and systems to report emissions,
the cost of monitoring should fall and the accuracy of the accounting
should improve. A standardized reporting program will also allow for
facilities to benchmark themselves against similar facilities to
understand better their relative standing within their industry.
    Section VI of the RIA for the Final MRR summarizes the anticipated
benefits of the finalized rule, which include providing the government
with sound data on which to base future policies and providing industry
and the public independently verified information documenting firms'
environmental performance. While EPA has not quantified the benefits of
the mandatory reporting rule, EPA believes that they are substantial
and outweigh the estimated costs.

IV. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993),
this action is a ``significant regulatory action'' because it raises
novel legal or policy issues arising out of legal mandates, the
President's priorities, or the principles set forth in the EO.
Accordingly, EPA submitted this action to the Office of Management and
Budget (OMB) for review under EO 12866.

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The
Information Collection Request (ICR) document prepared by EPA has been
assigned EPA ICR number 2376.01.
    EPA plans to collect complete and accurate facility-level GHG
emissions from the petroleum and natural gas industry. Accurate and
timely information on GHG emissions is essential for informing future
climate change policy decisions. Through data collected under this
proposed rule, EPA will gain a better understanding of the relative
emissions of different segments of the petroleum and natural gas
industry and the distribution of emissions from individual facilities
within those industries. The facility-specific data will also improve
our understanding of the factors that influence GHG emission rates and
actions that facilities are already taking to reduce emissions.
Additionally, EPA will be able to track the trend of emissions from
facilities within the petroleum and natural gas industry over time,
particularly in response to policies and potential regulations. The
data collected by this proposed rule will improve EPA's ability to
formulate climate change policy options and to assess which segments of
the petroleum and gas industry would be affected, and how these
segments would be affected by the options.
    This information collection is mandatory and will be carried out
under CAA section 114. Information identified and marked as CBI will
not be disclosed except in accordance with procedures set forth in 40
CFR part 2. However, emissions data collected under CAA section 114
cannot generally be claimed as CBI and will be made public.\10\
---------------------------------------------------------------------------

    \10\ Although CBI determinations are usually made on a case-by-
case basis, EPA has issued guidance in an earlier Federal Register
notice on what constitutes emissions data that cannot be considered
CBI (956 FR 7042-7043, February 21, 1991). As discussed in Section
II.R of the Final MRR preamble, EPA is initiating a separate notice
and comment process to make CBI determinations for the data
collected under this rulemaking. EPA intends to issue this notice in
early 2010, and will include in the notice the data proposed for
collection in this rulemaking.
---------------------------------------------------------------------------

    The projected cost and hour burden for non-federal respondents is
$37.8 million and 478,774 hours per year. The

estimated average burden per response is 98.2 hours; the frequency of
response is annual for all respondents that must comply with the
proposed rule's reporting requirements; and the estimated average
number of likely respondents per year is 3,038. The cost burden to
respondents resulting from the collection of information includes the
total capital cost annualized over the equipment's expected useful life
(averaging $5.3 million), a total operation and maintenance component
(averaging $1.6 million per year), and a labor cost component
(averaging $30.9 million per year).\11\ Burden is defined at 5 CFR
1320.3(b).
---------------------------------------------------------------------------

    \11\ Burden is defined at 5 CFR 1320.3(b). These cost numbers
differ from those shown elsewhere in the Economic Analysis because
the ICR costs represent the average cost over the first three years
of the proposed rule, but costs are reported elsewhere in the
Economic Analysis for the first year of the proposed rule and for
subsequent years of the proposed rule. In addition, the ICR focuses
on respondent burden, while the Economic Analysis includes EPA
Agency costs.
---------------------------------------------------------------------------

    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for 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, EPA has established a public docket for
this rule, which includes this ICR, under Docket ID number (EPA-HQ-OAR-
2009-0923). Submit any comments related to the ICR to EPA and OMB. See
ADDRESSES section at the beginning of this notice for where to submit
comments to 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 EPA. Since OMB is
required to make a decision concerning the ICR between 30 and 60 days
after April 12, 2010, a comment to OMB is best assured of having its
full effect if OMB receives it by May 12, 2010. The final rule will
respond to any OMB or public comments on the information collection
requirements contained in this proposal.

C. Regulatory Flexibility Act (RFA)

    The 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 this 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 today's proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. The small
entities directly regulated by this proposed rule include small
businesses in the petroleum and natural gas industry, small
governmental jurisdictions and small non-profits. We have determined
that some small businesses will be affected because their production
processes emit GHGs that must be reported.
    The small entities directly regulated by this proposed rule include
small businesses in the petroleum and gas industry, small governmental
jurisdictions and small non-profits. We have determined that some small
businesses will be affected because their production processes emit
GHGs that must be reported.
    For affected small entities, EPA conducted a screening assessment
comparing compliance costs for affected industry segments to petroleum
and gas-specific data on revenues for small businesses. This ratio
constitutes a ``sales'' test that computes the annualized compliance
costs of this proposed rule as a percentage of sales and determines
whether the ratio exceeds some level (e.g., 1 percent or 3 percent).
The cost-to-sales ratios were constructed at the establishment level
(average compliance cost for the establishment/average establishment
revenues).
    As shown in Table W-10, the average ratio of annualized reporting
program costs to receipts of establishments owned by model small
enterprises was less than 1 percent for industries presumed likely to
have small businesses covered by the reporting program. Although the
costs to receipts for entities with 1-20 employees is over 1 percent,
these facilities would likely not exceed the proposed 25,000
mtCO2e threshold, a threshold supported by many stakeholders
as one that sufficiently captures the majority of GHG emissions while
excluding small facilities. Further, these sales tests examine the
average establishment's total annualized mandatory reporting costs to
the average establishment receipts for enterprises within several
employment categories. The average entity costs used to compute the
sales test are the same across all of these enterprise size categories.
As a result, the sales-test will overstate the cost-to-receipt ratio
for establishments owned by small businesses, because the reporting
costs are likely lower than average entity estimates provided by the
engineering cost analysis.
    The screening analysis thus indicates that the proposed rule will
not have a significant economic impact on a substantial number of small
entities. The screening assessment for small governments for the Final
MRR compared the sum of average costs of compliance for combustion,
local distribution companies, and landfills to average revenues for
small governments. Even for a small government owning all three source
types, the costs constitute less than 1 percent of average revenues for
the smallest category of governments (those with fewer than 10,000
people).
    Although this proposed rule will not have a significant economic
impact on a substantial number of small entities, EPA nonetheless took
several steps to reduce the impact of this proposed rule on small
entities. For example, EPA determined appropriate thresholds that
reduce the number of small businesses reporting. In addition, EPA is
proposing different monitoring methods for different emissions sources,
requiring direct measurement only for selected sources. Also, EPA is
proposing annual instead of more frequent reporting.
    Through comprehensive outreach activities prior to proposal of the
initial rule, EPA held approximately 100 meetings and/or conference
calls with representatives of the primary audience groups, including
numerous trade associations and industries in the petroleum and gas
industry that include small business members. EPA's outreach activities
prior to proposal of the initial rule are documented in the memorandum,
``Summary of EPA Outreach Activities for Developing the Greenhouse Gas
Reporting Rule,'' located in Docket No. EPA-HQ-OAR-2008-0508-053. After
the initial proposal, EPA posted a guide for small businesses on the
EPA GHG reporting rule Web site, along with a general fact sheet for
the rule, information sheets for every source category, and an FAQ
document. EPA also operated a hotline

to answer questions about the proposed rule. We continued to meet with
stakeholders and entered documentation of all meetings into the docket.
    During rule implementation, EPA would maintain an ``open door''
policy for stakeholders to ask questions about the proposed rule or
provide suggestions to EPA about the types of compliance assistance
that would be useful to small businesses. EPA intends to develop a
range of compliance assistance tools and materials and conduct
extensive outreach for the proposed rule.
    We have therefore concluded that today's proposed rule will not
have a significant economic impact on a substantial number of small
entities. We continue to be interested in the potential impacts of the
proposed rule on small entities and welcome comments on issues related
to such impacts.

D. Unfunded Mandates Reform Act (UMRA)

    The UMRA seeks to protect State, local, and Tribal governments from
the imposition of unfunded Federal mandates. In addition, the Act seeks
to strengthen the partnership between the Federal government and State,
local, and Tribal governments and ensure that the Federal government
covers the costs incurred during compliance with Federal mandates.
    Title II of the UMRA of 1995, Public Law 104-4, establishes
requirements for Federal agencies to assess the effects of their
regulatory actions on State, local, and tribal governments and the
private segment. Under section 202 of UMRA, EPA generally must prepare
a written statement, including a cost-benefit analysis, for proposed
and final rules with Federal mandates that may result in expenditures
to State, local, and Tribal governments, in the aggregate, or to the
private segment, of $100 million or more in any one year.
    Before promulgating an EPA rule for which a written statement is
needed, section 205 of UMRA generally requires EPA to identify and
consider a reasonable number of regulatory alternatives and adopt the
least costly, most cost-effective or least burdensome alternative that
achieves the objectives of the rule. The provisions of section 205 do
not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted.
    Before EPA establishes any regulatory requirements that may
significantly or uniquely affect small governments, including Tribal
governments, it must have developed under section 203 of UMRA a small
government agency plan. The plan must provide for notifying potentially
affected small governments, enabling officials of affected small
governments to have meaningful and timely input in the development of
EPA regulatory proposals with significant Federal intergovernmental
mandates, and informing, educating, and advising small governments on
compliance with the regulatory requirements.
    EPA has determined that the Subpart W rule does not contain a
Federal mandate that may result in expenditures of $100 million or more
for State, local, and Tribal governments, in the aggregate, or the
private segment in any one year. Expenditures associated with
compliance, defined as the incremental costs beyond the existing
regulations will not surpass $100 million in the aggregate in any year.
Thus, today's rule is not subject to the requirements of sections 202
and 205 of 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. This regulation
applies to facilities that directly emit greenhouse gases. It does not
apply to governmental entities unless the government entity owns a
facility in the petroleum and gas industry that directly emits
greenhouse gases above threshold levels. In addition, this proposed
rule does not impose any implementation responsibilities on State,
local, or Tribal governments and it is not expected to increase the
cost of existing regulatory programs managed by those governments.
Thus, the impact on governments affected by the proposed rule is
expected to be minimal.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. This regulation applies directly to
petroleum and natural gas facilities that emit greenhouse gases. Few,
if any, state or local government facilities would be affected. 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 EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on this proposed action
from State and local officials.

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

    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 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, EPA has sought opportunities
to provide information to tribal governments and representatives during
rule development. EPA consulted with tribal officials early in the
process of developing this regulation to permit them to have meaningful
and timely input into its development. EPA sought opportunities to
provide information to Tribal governments and representatives during
development of the mandatory GHG reporting rule that was proposed in
April 2009 and finalized in September 2009. Today's action is a
supplemental proposal to that rule. In consultation with EPA's American
Indian Environment Office, EPA's outreach plan included tribes. EPA
conducted several conference calls with Tribal organizations during the
proposal phase. For example, EPA staff provided information to tribes
through conference calls with multiple Indian working groups and
organizations at EPA that interact with tribes and through individual
calls with two Tribal board members of TCR. In addition, EPA prepared a
short article on the GHG reporting rule that appeared on the front page
of a Tribal newsletter--Tribal Air News--that was distributed to EPA/
OAQPS's network of Tribal organizations. EPA gave a presentation on
various climate efforts, including the mandatory reporting rule, at the
National Tribal Conference on Environmental Management on June 24-26,
2008. In addition, EPA had copies of a short information sheet
distributed at a meeting of the National Tribal Caucus. See the
``Summary of EPA Outreach Activities for Developing the GHG reporting
rule,'' in Docket No. EPA-HQ-OAR-2008-0508-055 for a complete list of
Tribal contacts. EPA

participated in a conference call with Tribal air coordinators in April
2009 and prepared a guidance sheet for Tribal governments on the
proposed rule. It was posted on the MRR Web site and published in the
Tribal Air Newsletter.
    EPA specifically solicits additional comment on this proposed rule
from Tribal officials.

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

    EPA interprets EO 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 EO has the
potential to influence the regulation. This action is not subject to EO
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 rule is not a ``significant energy action'' as
defined in EO 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. Further, we have concluded that this
proposed rule is not likely to have any adverse energy effects. This
proposed rule relates to monitoring, reporting and recordkeeping at
petroleum and gas facilities that emit over 25,000 mtCO2e
and does not impact energy supply, distribution or use. Therefore, we
conclude that this proposed rule is not likely to have any adverse
effects on energy supply, distribution, or use.

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 (15 U.S.C. 272 note) directs
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 EPA to provide Congress,
through OMB, explanations when the Agency decides not to use available
and applicable voluntary consensus standards.
    This rulemaking involves technical standards. EPA provides the
flexibility to use any one of the voluntary consensus standards from at
least seven different voluntary consensus standards bodies, including
the following: ASTM, ASME, ISO, Gas Processors Association, and
American Gas Association. These voluntary consensus standards will help
facilities monitor, report, and keep records of greenhouse gas
emissions. No new test methods were developed for this proposed rule.
Instead, from existing rules for source categories and voluntary
greenhouse gas programs, EPA identified existing means of monitoring,
reporting, and keeping records of greenhouse gas emissions. The
existing methods (voluntary consensus standards) include a broad range
of measurement techniques, including many for combustion sources such
as methods to analyze fuel and measure its heating value; methods to
measure gas or liquid flow; and methods to gauge and measure petroleum
and petroleum products.
    By incorporating voluntary consensus standards into this proposed
rule, EPA is both meeting the requirements of the NTTAA and presenting
multiple options and flexibility for measuring greenhouse gas
emissions.

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

    Executive Order (EO) 12898 (59 FR 7629 (Feb. 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.
    EPA has determined that this proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment because it is a rule addressing information collection and
reporting procedures.

List of Subjects in 40 CFR Part 98

    Environmental protection, Administrative practice and procedure,
Greenhouse gases, Incorporation by reference, Suppliers, Reporting and
recordkeeping requirements.

    Dated: March 22, 2010.
Lisa P. Jackson,
Administrator.

    For the reasons stated in the preamble, the Environmental
Protection Agency proposes to amend 40 CFR part 98 as follows:

PART 98--MANDATORY GREENHOUSE GAS REPORTING

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

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

Subpart A--[Amended]

    2. Section 98.2 is amended by revising paragraph (a) introductory
text to read as follows:

Sec.  98.2  Who must report?

    (a) The GHG reporting requirements and related monitoring,
recordkeeping, and reporting requirements of this part apply to the
owners and operators of any facility that is located in the United
States or under or attached to the Outer Continental Shelf (as defined
in 43 U.S.C. 1331) and that meets the requirements of either paragraph
(a)(1), (a)(2), or (a)(3) of this section; and any supplier that meets
the requirements of paragraph (a)(4) of this section:
* * * * *
    3. Section 98.6 is amended by adding the following definitions in
alphabetical order and revising the definition of ``United States'' to
read as follows:

Sec.  98.6  Definitions.

    Absorbent circulation pump means a pump commonly powered by natural
gas pressure that circulates the absorbent liquid between the absorbent
regenerator and natural gas contactor.
* * * * *
    Acid Gas means hydrogen sulfide (H2S) and carbon dioxide
(CO2) contaminants that are separated from sour natural gas
by an acid gas removal.
    Acid Gas Removal unit (AGR) means a process unit that separates
hydrogen sulfide and/or carbon dioxide from sour natural gas using
liquid or solid absorbents or membrane separators.
    Acid gas removal vent stack emissions mean the acid gas separated
from the acid gas absorbing medium (e.g., an amine solution) and
released with methane and other light hydrocarbons to the atmosphere or
a flare.
* * * * *
    Air injected flare means a flare in which air is blown into the
base of a flare stack to induce complete combustion of low Btu natural
gas (i.e.,

high non-combustible component content).
* * * * *
    Blowdown vent stack emissions mean natural gas released due to
maintenance and/or blowdown operations including but not limited to
compressor blowdown and emergency shut-down (ESD) system testing.
* * * * *
    Calibrated bag means a flexible, non-elastic, anti-static bag of a
calibrated volume that can be affixed to a emitting source such that
the emissions inflate the bag to its calibrated volume.
* * * * *
    Centrifugal compressor means any equipment that increases the
pressure of a process natural gas by centrifugal action, employing
rotating movement of the driven shaft.
    Centrifugal compressor dry seals mean a series of rings around the
compressor shaft where it exits the compressor case that operates
mechanically under the opposing forces to prevent natural gas from
escaping to the atmosphere.
    Centrifugal compressor dry seals emissions mean natural gas
released from a dry seal vent pipe and/or the seal face around the
rotating shaft where it exits one or both ends of the compressor case.
    Centrifugal compressor wet seal degassing venting emissions means
emissions that occur when the high-pressure oil barriers for
centrifugal compressors are depressurized to release absorbed natural
gas. High-pressure oil is used as a barrier against escaping gas in
centrifugal compressor shafts. Very little gas escapes through the oil
barrier, but under high pressure, considerably more gas is absorbed by
the oil. The seal oil is purged of the absorbed gas (using heaters,
flash tanks, and degassing techniques) and recirculated. The separated
gas is commonly vented to the atmosphere.
* * * * *
    Coal Bed Methane (CBM) means natural gas which is extracted from
underground coal deposits or ``beds.''
* * * * *
    Component, for the purposes of subpart W only, means but is not
limited to each metal to metal joint or seal of non-welded connection
separated by a compression gasket, screwed thread (with or without
thread sealing compound), metal to metal compression, or fluid barrier
through which natural gas or liquid can escape to the atmosphere.
    Compressor means any machine for raising the pressure of a natural
gas by drawing in low pressure natural gas and discharging
significantly higher pressure natural gas.
* * * * *
    Condensate means hydrocarbon and other liquid separated from
natural gas that condenses due to changes in the temperature, pressure,
or both, and remains liquid at storage conditions, includes both water
and hydrocarbon liquids.
* * * * *
    Conventional wells mean gas wells in producing fields that do not
employ hydraulic fracturing to produce commercially viable quantities
of natural gas.
* * * * *
    Dehydrator means a device in which a liquid absorbent (including
but not limited to desiccant, ethylene glycol, diethylene glycol, or
triethylene glycol) directly contacts a natural gas stream to absorb
water vapor.
    Dehydrator vent stack emissions means natural gas released from a
natural gas dehydrator system absorbent (typically glycol) reboiler or
regenerator, including stripping natural gas and motive natural gas
used in absorbent circulation pumps.
* * * * *
    De-methanizer means the natural gas processing unit that separates
methane rich residue gas from the heavier hydrocarbons (e.g., ethane,
propane, butane, pentane-plus) in feed natural gas stream).
* * * * *
    Desiccant means a material used in solid-bed dehydrators to remove
water from raw natural gas by adsorption. Desiccants include activated
alumina, palletized calcium chloride, lithium chloride and granular
silica gel material. Wet natural gas is passed through a bed of the
granular or pelletized solid adsorbent in these dehydrators. As the wet
gas contacts the surface of the particles of desiccant material, water
is adsorbed on the surface of these desiccant particles. Passing
through the entire desiccant bed, almost all of the water is adsorbed
onto the desiccant material, leaving the dry gas to exit the contactor.
* * * * *
    E&P Tank means the most current version of an exploration and
production field tank emissions equilibrium program that estimates
flashing, working and standing losses of hydrocarbons, including
methane, from produced crude oil and gas condensate. Equal or
successors to E&P Tank Version 2.0 for Windows Software. Copyright (C)
1996-1999 by The American Petroleum Institute and The Gas Research
Institute.
* * * * *
    Engineering estimation, for purposes of subpart W, means an
estimate of emissions based on engineering principles applied to
measured and/or approximated physical parameters such as dimensions of
containment, actual pressures, actual temperatures, and compositions.
    Enhanced Oil Recovery (EOR) means the use of certain methods such
as water flooding or gas injection into existing wells to increase the
recovery of crude oil from a reservoir. In the context of this rule,
EOR applies to injection of critical phase carbon dioxide into a crude
oil reservoir to enhance the recovery of oil.
* * * * *
    Field means standardized field names and codes of all oil and gas
fields identified in the United States as defined by the Energy
Information Administration Oil and Gas Field Code Master List.
* * * * *
    Flare combustion means unburned hydrocarbons including
CH4, CO2, N2O emissions resulting from
the incomplete combustion of gas in flares.
    Flare combustion efficiency means the fraction of natural gas, on a
volume or mole basis, that is combusted at the flare burner tip.
* * * * *
    Fugitive emissions means those emissions which are unintentional
and could not reasonably pass through a stack, chimney, vent, or other
functionally-equivalent opening.
    Fugitive emissions detection means the process of identifying
emissions from equipment, components, and other point sources.
    Gas conditions mean the actual temperature, volume, and pressure of
a gas sample.
* * * * *
    Gas gathering/booster stations mean centralized stations where
produced natural gas from individual wells is co-mingled, compressed
for transport to processing plants, transmission and distribution
systems, and other gathering/booster stations which co-mingle gas from
multiple production gathering/booster stations. Such stations may
include gas dehydration, gravity separation of liquids (both
hydrocarbon and water), pipeline pig launchers and receivers, and gas
powered pneumatic devices.
* * * * *
    Gas to oil ratio (GOR) means the ratio of the volume of gas at
standard

temperature and pressure that is produced from a volume of oil when
depressurized to standard temperature and pressure.
* * * * *
    High-Bleed Pneumatic Devices are automated flow control devices
powered by pressurized natural gas and used for maintaining a process
condition such as liquid level, pressure, delta-pressure and
temperature. Part of the gas power stream which is regulated by the
process condition flows to a valve actuator controller where it vents
(bleeds) to the atmosphere at a rate in excess of six standard cubic
feet per hour.
* * * * *
    Liquefied natural gas (LNG) means natural gas (primarily methane)
that has been liquefied by reducing its temperature to -260 degrees
Fahrenheit at atmospheric pressure.
    LNG boiloff gas means natural gas in the gaseous phase that vents
from LNG storage tanks due to ambient heat leakage through the tank
insulation and heat energy dissipated in the LNG by internal pumps.
    Low-Bleed Pneumatic Devices mean automated flow control devices
powered by pressurized natural gas and used for maintaining a process
condition such as liquid level, pressure, delta-pressure and
temperature. Part of the gas power stream which is regulated by the
process condition flows to a valve actuator controller where it vents
(bleeds) to the atmosphere at a rate equal to or less than six standard
cubic feet per hour.
* * * * *
    Natural gas driven pneumatic pump means a pump that uses
pressurized natural gas to move a piston or diaphragm, which pumps
liquids on the opposite side of the piston or diaphragm.
* * * * *
    Offshore means seaward of the terrestrial borders of the United
States, including waters subject to the ebb and flow of the tide, as
well as adjacent bays, lakes or other normally standing waters, and
extending to the outer boundaries of the jurisdiction and control of
the United States under the Outer Continental Shelf Lands Act.
* * * * *
    Onshore petroleum and natural gas production owner or operator
means the entity who is the permitee to operate petroleum and natural
gas wells on the state drilling permit or a state operating permit
where no drilling permit is issued by the state, which operates an
onshore petroleum and/or natural gas production facility (as described
in Sec.  98.230(b)(2). Where more than one entity are permitees on the
state drilling permit, or operating permit where no drilling permit is
issued by the state, the permitted entities for the joint facility must
designate one entity to report all emissions from the joint facility.
* * * * *
    Operating pressure means the containment pressure that
characterizes the normal state of gas or liquid inside a particular
process, pipeline, vessel or tank.
* * * * *
    Outer Continental Shelf means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in 43
U.S.C. Sec.  1301, and of which the subsoil and seabed appertain to the
United States and are subject to its jurisdiction and control.
* * * * *
    Pump means a device used to raise pressure, drive, or increase flow
of liquid streams in closed or open conduits.
    Pump seals means any seal on a pump drive shaft used to keep
methane and/or carbon dioxide containing light liquids from escaping
the inside of a pump case to the atmosphere.
    Pump seal emissions means hydrocarbon gas released from the seal
face between the pump internal chamber and the atmosphere.
* * * * *
    Reciprocating compressor means a piece of equipment that increases
the pressure of a process natural gas by positive displacement,
employing linear movement of a shaft driving a piston in a cylinder.
    Reciprocating compressor rod packing means a series of flexible
rings in machined metal cups that fit around the reciprocating
compressor piston rod to create a seal limiting the amount of
compressed natural gas that escapes to the atmosphere.
    Re-condenser means heat exchangers that cool compressed boil-off
gas to a temperature that will condense natural gas to a liquid.
* * * * *
    Reservoir means a porous and permeable underground natural
formation containing significant quantities of hydrocarbon liquids and/
or gases. A reservoir is characterized by a single natural pressure
system.
* * * * *
    Sales oil means produced crude oil or condensate measured at the
production lease automatic custody transfer (LACT) meter or custody
transfer meter tank gauge.
* * * * *
    Sour natural gas means natural gas that contains significant
concentrations of hydrogen sulfide and/or carbon dioxide that exceed
the concentrations specified for commercially saleable natural gas
delivered from transmission and distribution pipelines.
* * * * *
    Sweet Gas is natural gas with low concentrations of hydrogen
sulfide (H2S) and/or carbon dioxide (CO2) that
does not require (or has already had) acid gas treatment to meet
pipeline corrosion-prevention specifications for transmission and
distribution.
* * * * *
    Transmission pipeline means high pressure cross country pipeline
transporting sellable quality natural gas from production or natural
gas processing to natural gas distribution pressure let-down, metering,
regulating stations where the natural gas is typically odorized before
delivery to customers.
* * * * *
    Turbine meter means a flow meter in which a gas or liquid flow rate
through the calibrated tube spins a turbine from which the spin rate is
detected and calibrated to measure the fluid flow rate.
* * * * *
    Unconventional wells means gas well in producing fields that employ
hydraulic fracturing to enhance gas production volumes.
* * * * *
    United States means the 50 States, the District of Columbia, the
Commonwealth of Puerto Rico, American Samoa, the Virgin Islands, Guam,
and any other Commonwealth, territory or possession of the United
States, as well as the territorial sea as defined by Presidential
Proclamation No. 5928.
* * * * *
    Vapor recovery system means any equipment located at the source of
potential gas emissions to the atmosphere or to a flare, that is
composed of piping, connections, and, if necessary, flow-inducing
devices, and that is used for routing the gas back into the process as
a product and/or fuel.
    Vaporization unit means a process unit that performs controlled
heat input to vaporize LNG to supply transmission and distribution
pipelines or consumers with natural gas.
* * * * *
    Vented emissions means intentional or designed releases of
CH4 or CO2 containing natural gas or hydrocarbon
gas (not including stationary combustion flue gas), including but not
limited to process designed flow to the

atmosphere through seals or vent pipes, equipment blowdown for
maintenance, and direct venting of gas used to power equipment (such as
pneumatic devices).
* * * * *
    Well completions means a process that allows for the flow of
petroleum or natural gas from newly drilled wells to expel drilling and
reservoir fluids and test the reservoir flow characteristics. This
process includes high-rate back-flow of injected water and sand used to
fracture and prop-open fractures in low permeability gas reservoirs.
    Well workover means the performance of one or more of a variety of
remedial operations on producing oil and gas wells to try to increase
production. This process also includes high-rate back-flow of injected
water and sand used to re-fracture and prop-open new fractures in
existing low permeability gas reservoirs.
    Wellhead means the piping, casing, tubing and connected valves
protruding above the Earth's surface for an oil and/or natural gas
well. The wellhead ends where the flow line connects to a wellhead
valve.
    Wet natural gas means natural gas in which water vapor exceeds the
concentration specified for commercially saleable natural gas delivered
from transmission and distribution pipelines. This input stream to a
natural gas dehydrator is referred to as ``wet gas''.
    4. Section 98.7 is amended by adding paragraphs (k), (l), and (m)
to read as follows:

Sec.  98.7  What standardized methods are incorporated by reference
into this part?

* * * * *
    (k) The following material is available for purchase from the Gas
Technology Institute, 1700 South Mount Prospect Road, Des Plaines,
Illinois 60018, http://www.gastechnology.org.
    (1) GRI-GLYCalc Version 4.0, IBR approved for Sec.  98.233(e).
    (2) [Reserved]
    (l) The following material is available for purchase from IHS
Standards Store, Jane's Information Group, Inc., 110 North Royal
Street, Suite 200, Alexandria, Virginia 22314, http://www.ihs.com.
    (1) E&P Tank Version 2.0, IBR approved for Sec.  98.233(j) and
Sec.  98.236(c).
    (2) [Reserved]
    (m) The following material is available for purchase from the
American Association of Petroleum Geologists, 1444 South Boulder
Avenue, Tulsa, Oklahoma 74119, www.aapg.org.
    (1) AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Volume 75,
Number 10 (October 1991), pages 1644-1651, IBR approved for Sec.
98.230(b).
    (2) [Reserved]
    5. Add subpart W to read as follows:

Subpart W--Petroleum and Natural Gas Systems
Sec.
98.230 Definition of the source category.
98.231 Reporting threshold.
98.232 GHGs to report.
98.233 Calculating GHG emissions.
98.234 Monitoring and QA/QC requirements.
98.235 Procedures for estimating missing data.
98.236 Data reporting requirements.
98.237 Records that must be retained.
98.238 Definitions.

Subpart W--Petroleum and Natural Gas Systems

Sec.  98.230  Definition of the source category.

    (a) This source category consists of the following:
    (1) Offshore petroleum and natural gas production. Offshore
petroleum and natural gas production is any platform structure, affixed
temporarily or permanently to offshore submerged lands, that houses
equipment to extract hydrocarbons from the ocean or lake floor and that
transfers such hydrocarbons to storage, transport vessels, or onshore.
In addition, offshore production includes secondary platform structures
and storage tanks associated with the platform structure.
    (2) Onshore petroleum and natural gas production. Onshore petroleum
and natural gas production equipment means all structures associated
with wells (including but not limited to compressors, generators, or
storage facilities), piping (including but not limited to flowlines or
intra-facility gathering lines), and portable non-self-propelled
equipment (including but not limited to well drilling and completion
equipment, workover equipment, gravity separation equipment, auxiliary
non-transportation-related equipment, and leased, rented or contracted
equipment) used in the production, extraction, recovery, lifting,
stabilization, separation or treating of petroleum and/or natural gas
(including condensate). This also includes associated storage or
measurement and all systems engaged in gathering produced gas from
multiple wells, all EOR operations using CO2, and all
petroleum and natural gas production located on islands, artificial
islands or structures connected by a causeway to land, an island, or
artificial island.
    (3) Onshore natural gas processing plants. Natural gas processing
plants are designed to separate and recover natural gas liquids (NGLs)
or other non-methane gases and liquids from a stream of produced
natural gas to meet onshore natural gas transmission pipeline quality
specifications through equipment performing one or more of the
following processes: oil and condensate removal, water removal,
separation of natural gas liquids, sulfur and carbon dioxide removal,
fractionation of NGLs, or other processes, and also the capture of
CO2 separated from natural gas streams for delivery outside
the facility. In addition, field gathering and/or boosting stations
that gather and process natural gas from multiple wellheads, and
compress and transport natural gas (including but not limited to
flowlines or intra-facility gathering lines or compressors) as feed to
the natural gas processing plants are considered a part of the
processing plant. Gathering and boosting stations that send the natural
gas to an onshore natural gas transmission compression facility, or
natural gas distribution facility, or to an end user are considered
stand alone natural gas processing facilities. All residue gas
compression equipment operated by a processing plant, whether inside or
outside the processing plant fence, are considered part of natural gas
processing plant.
    (4) Onshore natural gas transmission compression. Onshore natural
gas transmission compression means any fixed combination of compressors
that move natural gas at elevated pressure from production fields or
natural gas processing facilities, in transmission pipelines, to
natural gas distribution pipelines, or into storage. In addition,
transmission compressor station includes equipment for liquids
separation, natural gas dehydration, and tanks for the storage of water
and hydrocarbon liquids.
    (5) Underground natural gas storage. Underground natural gas
storage means subsurface storage, including but not limited to,
depleted gas or oil reservoirs and salt dome caverns utilized for
storing natural gas that has been transferred from its original
location for the primary purpose of load balancing (the process of
equalizing the receipt and delivery of natural gas); natural gas
underground storage processes and operations (including, but not
limited to, compression, dehydration and flow measurement); and all the
wellheads connected to the compression units located at the facility.
    (6) Liquefied natural gas (LNG) storage. LNG storage means onshore
LNG storage vessels located above ground, equipment for liquefying
natural gas, compressors to capture and re-liquefy boil-off-gas, re-
condensers,

and vaporization units for re-gasification of the liquefied natural
gas.
    (7) LNG import and export equipment. LNG import equipment means all
onshore or offshore equipment that receives imported LNG via ocean
transport, stores LNG, re-gasifies LNG, and delivers re-gasified
natural gas to a natural gas transmission or distribution system. LNG
export equipment means all onshore or offshore equipment that receives
natural gas, liquefies natural gas, stores LNG, and transfers the LNG
via ocean transportation to any location, including locations in the
United States.
    (8) Natural Gas Distribution. Natural gas distribution means
distribution pipelines (not interstate pipelines or intrastate
pipelines) and metering and regulating stations, that physically
deliver natural gas to end users.
    (b) [Reserved]

Sec.  98.231  Reporting threshold.

    (a) You must report GHG emissions from petroleum and natural gas
systems if your facility as defined in Sec.  98.230 meets the
requirements of Sec.  98.2(a)(2).
    (b) For applying the threshold defined in Sec.  98.2(a)(2), you
must include combustion emissions from portable equipment that cannot
move on roadways under its own power and drive train and that is
stationed at a wellhead for more than 30 days in a reporting year,
including drilling rigs, dehydrators, compressors, electrical
generators, steam boilers, and heaters.

Sec.  98.232  GHGs to report.

    (a) You must report CO2 and CH4 emissions
from each industry segment specified in paragraph (b) through (i) of
this section.
    (b) For offshore petroleum and natural gas production, report
emissions from all ``stationary fugitive'' and ``stationary vented''
sources as identified in the Minerals Management Service (MMS) Gulfwide
Offshore Activity Data System (GOADS) study (2005 Gulfwide Emission
Inventory Study MMS 2007-067).
    (c) For onshore petroleum and natural gas production, report
emissions from the following source types:
    (1) Natural gas pneumatic high bleed device venting.
    (2) Natural gas pneumatic low bleed device venting.
    (3) Natural gas driven pneumatic pump venting.
    (4) Well venting for liquids unloading.
    (5) Gas well venting during conventional well completions.
    (6) Gas well venting during unconventional well completions.
    (7) Gas well venting during conventional well workovers.
    (8) Gas well venting during unconventional well workovers.
    (9) Gathering pipeline fugitives.
    (10) Storage tanks.
    (11) Reciprocating compressor rod packing venting.
    (12) Well testing venting and flaring.
    (13) Associated gas venting and flaring.
    (14) Dehydrator vent stacks.
    (15) Coal bed methane produced water emissions.
    (16) EOR injection pump blowdown.
    (17) Acid gas removal vent stack.
    (18) Hydrocarbon liquids dissolved CO2.
    (19) Centrifugal compressor wet seal degassing venting.
    (20) Produced water dissolved CO2.
    (21) Fugitive emissions from valves, connectors, open ended lines,
pressure relief valves, compressor starter gas vents, pumps, flanges,
and other fugitive sources (such as instruments, loading arms, pressure
relief valves, stuffing boxes, compressor seals, dump lever arms, and
breather caps for crude services).
    (d) For onshore natural gas processing, report emissions from the
following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor wet seal degassing venting.
    (3) Storage tanks.
    (4) Blowdown vent stacks.
    (5) Dehydrator vent stacks.
    (6) Acid gas removal vent stack.
    (7) Flare stacks.
    (8) Gathering pipeline fugitives.
    (9) Fugitive emissions from: valves, connectors, open ended lines,
pressure relief valves, meters, and centrifugal compressor dry seals.
    (e) For onshore natural gas transmission compression, report
emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor wet seal degassing venting.
    (3) Transmission storage tanks.
    (4) Blowdown vent stacks.
    (5) Natural gas pneumatic high bleed device venting.
    (6) Natural gas pneumatic low bleed device venting.
    (7) Fugitive emissions from connectors, block valves, control
valves, compressor blowdown valves, pressure relief valves, orifice
meters, other meters, regulators, and open ended lines.
    (f) For underground natural gas storage, report emissions from the
following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor wet seal degassing venting.
    (3) Natural gas pneumatic high bleed device venting.
    (4) Natural gas pneumatic low bleed device venting.
    (5) Fugitive emissions from connectors, block valves, control
valves, compressor blowdown valves, pressure relief valves, orifice
meters, other meters, regulators, and open ended lines.
    (g) For LNG storage, report emissions from the following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor wet seal degassing venting.
    (3) Fugitive emissions from valves; pump seals; connectors; vapor
recovery compressors, and other fugitive sources.
    (h) LNG import and export equipment, report emissions from the
following sources:
    (1) Reciprocating compressor rod packing venting.
    (2) Centrifugal compressor wet seal degassing venting.
    (3) Blowdown vent stacks.
    (4) Fugitive emissions from valves, pump seals, connectors, vapor
recovery compressors, and other fugitive sources.
    (i) For natural gas distribution, report emissions from the
following sources:
    (1) Above ground meter regulators and gate station fugitive
emissions from connectors, block valves, control valves, pressure
relief valves, orifice meters, other meters, regulators, and open ended
lines.
    (2) Below ground meter regulators and vault fugitives.
    (3) Pipeline main fugitives.
    (4) Service line fugitives.
    (j) You must report the CO2, CH4, and
N2O emissions from each flare.
    (k) You must 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.
    (l) You must report under subpart PP of this part (Suppliers of
Carbon Dioxide), CO2 emissions captured and transferred off
site by following the requirements of subpart PP.

Sec.  98.233  Calculating GHG emissions.

    (a) Natural gas pneumatic high bleed device venting. Calculate
emissions from a natural gas pneumatic high bleed flow control device
venting as follows:
    (1) Calculate vented emissions using manufacturer data.
    (i) Obtain from the manufacturer specific pneumatic device model
natural gas bleed rate during normal operation.

    (ii) Calculate the natural gas emissions for each continuous bleed
device using Equation W-1 of this section.

[GRAPHIC] [TIFF OMITTED] TP12AP10.082

Where:
Es,n = Annual natural gas emissions at standard
conditions, in cubic feet.
Bs = Natural gas driven pneumatic device bleed rate
volume at standard conditions in cubic feet per minute, as provided
by the manufacturer.
T = Amount of time in minutes that the pneumatic device has been
operational through the reporting period.

    (iii) Both CH4 and CO2 volumetric and mass
emissions shall be calculated from volumetric natural gas emissions
using calculations in paragraphs (u) and (v) of this section.
    (2) If manufacturer data for a specific device is not available,
then use data for a similar device model, size and operational
characteristics to estimate emissions.
    (b) Natural gas pneumatic low bleed device venting. Calculate
emissions from natural gas pneumatic low continuous bleed device
venting using Equation W-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.000

Where:

Masss,i = Annual total mass GHG emissions in metric tons
per year at standard conditions from all natural gas pneumatic low
bleed device venting, for GHG i.
Count = Total number of natural gas pneumatic low bleed devices.
EF = Population emission factors for natural gas pneumatic low bleed
device venting listed in Tables W-1, W-3, and W-4 of this subpart
for onshore petroleum and natural gas production, onshore natural
gas transmission, and underground natural gas storage facilities,
respectively.
GHG i = For onshore petroleum and natural gas production facilities,
concentration of GHG i, CH4 or CO2, in
produced natural gas; for facilities listed in Sec.  98.230(a)(3)
through (a)(8), GHGi equals 1.
Convi = Conversion from standard cubic feet to metric tons
CO2e; 0.000404 for CH4, and 0.00005189 for
CO2.
24 * 365 = Conversion to yearly emissions estimate.

    (c) Natural gas driven pneumatic pump venting. Calculate emissions
from natural gas driven pneumatic pump venting as follows:
    (1) Calculate emissions using manufacturer data.
    (i) Obtain from the manufacturer specific pump model natural gas
emission (or manufacturer ``gas consumption'') per unit volume of
liquid circulation rate at pump speeds and operating pressures.
    (ii) Maintain a log of the amount of liquid pumped annually from
individual pumps.
    (iii) Calculate the natural gas emissions for each pump using
Equation W-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.001

Where:

    Es,n = Annual natural gas emissions at standard
conditions in cubic feet per year.
    Fs = Natural gas driven pneumatic pump gas emission
in ``emission per volume of liquid pumped at operating pressure'' in
scf/gallon at standard conditions, as provided by the manufacturer.
    V = Volume of liquid pumped annually in gallons/year.

    (iv) Both CH4 and CO2 volumetric and mass
emissions shall be calculated from volumetric natural gas emissions
using calculations in paragraphs (u) and (v) of this section.
    (2) If manufacturer data for a specific pump in Equation W-3 is not
available, then use data for a similar pump model, size and operational
characteristics to estimate emissions.
    (d) Acid gas removal (AGR) vent stacks. For AGR (including but not
limited to processes such as amine, membrane, molecular sieve or other
absorbents and adsorbents), calculate emissions for CO2 only
(not CH4) using Equation W-4 of this section.

[GRAPHIC] [TIFF OMITTED] TP12AP10.002

Where:

Ea,CO2 = Annual volumetric CO2 emissions at
ambient condition, in cubic feet per year.
V1 = Metered total annual volume of natural gas flow into
AGR unit in cubic feet per year at ambient condition.
%Vol1 = Volume weighted CO2 content of natural
gas into the AGR unit.
V2 = Metered total annual volume of natural gas flow out
of the AGR unit in cubic feet per year at ambient condition.
%Vol2 = Volume weighted CO2 content of natural
gas out of the AGR unit.

    (1) If a continuous gas analyzer is installed, then the continuous
gas analyzer results must be used. If continuous gas analyzer is not
available, quarterly gas samples must be taken to determine
%Vol1 and %Vol2 according to methods set forth in
Sec.  98.234(b).
    (2) Calculate CO2 volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
    (3) Mass CO2 emissions shall be calculated from
volumetric CO2 emissions using calculations in paragraphs
(u) and (v) of this section.
    (e) Dehydrator vent stacks. For dehydrator vent stacks without
vapor recovery or thermal control devices, calculate annual mass
CH4 and CO2 emissions at standard temperature and
pressure (STP) conditions using the simulation software package GRI-
GLYCalc Version 4.0 (incorporated by reference, see Sec.  98.7).
    (1) A minimum of the following parameters must be used for
characterizing emissions from dehydrators:
    (i) Feed natural gas flow rate.
    (ii) Feed natural gas water content.
    (iii) Outlet natural gas water content.
    (iv) Absorbent circulation pump type (natural gas pneumatic/air
pneumatic/electric).
    (v) Absorbent circulation rate.
    (vi) Absorbent type: Including, but not limited to, triethylene
glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG).
    (vii) Use of stripping natural gas.
    (viii) Use of flash tank separator (and disposition of recovered
gas).
    (ix) Hours operated.
    (x) Wet natural gas temperature, pressure, and composition.
    (2) Calculate annual emissions from dehydrator vent stacks to
flares or regenerator fire-box/fire tubes as follows:
    (i) Use the dehydrator vent stack volume and gas composition as
determined in paragraph (e)(1) of this section.

    (ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine dehydrator vent stack emissions from
the flare or regenerator combustion gas vent.
    (3) Dehydrators that use desiccant shall calculate emissions from
the amount of gas vented from the vessel every time it is depressurized
for the desiccant refilling process using Equation W-5 of this section.

[GRAPHIC] [TIFF OMITTED] TP12AP10.003

Where:

Es,n = Annual natural gas emissions at standard
conditions.
H = Height of the dehydrator vessel (ft).
D = Inside diameter of the vessel (ft).
P1 = Atmospheric pressure (psia).
P2 = Pressure of the gas (psia).
P = pi (3.14).
%G = Percent of packed vessel volume that is gas.
T = Time between refilling (days).

    (i) Both CH4 and CO2 volumetric and mass
emissions shall be calculated from volumetric natural gas emissions
using calculations in paragraphs (u) and (v) of this section.
    (f) Well venting for liquids unloadings.
    (1) The emissions for well venting for liquids unloading shall be
determined using either of the calculation methodologies described in
paragraph (f)(1) of this section. The same calculation methodology must
be used for the entire volume for the reporting year.
    (i) Calculation Methodology 1. For each unique well tubing diameter
and producing horizon/formation combination in each gas producing field
where gas wells are vented to the atmosphere to expel liquids
accumulated in the tubing, a recording flow meter shall be installed on
the vent line used to vent gas from the well (e.g., on the vent line
off the wellhead separator or atmospheric storage tank) according to
methods set forth in Sec.  98.234(b). Calculate emissions from well
venting for liquids unloading using Equation W-6 of this section.

[GRAPHIC] [TIFF OMITTED] TP12AP10.004

Where:

Ea,n = Annual natural gas emissions at ambient conditions
in cubic feet.
T = Cumulative amount of time in hours of well venting during the
year.
FR = Flow Rate in cubic feet per hour, under ambient conditions as
required in paragraph (f)(1)(i)(A), (f)(1)(i)(B) and (f)(1)(i)(C) of
this section.

    Calculate natural gas volumetric emissions at standard conditions
using calculations in paragraph (t) of this section. Both
CH4 and CO2 volumetric and mass emissions shall
be calculated from volumetric natural gas emissions using calculations
in paragraphs (u) and (v) of this section.
    (A) The average flow rate per minute of venting is calculated for
each unique tubing diameter and producing horizon/formation combination
in each producing field.
    (B) This factor is applied to all wells in the field that have the
same tubing diameter and producing horizon/formation combination,
multiplied by the number of minutes of venting from all wells of the
same tubing diameter and producing horizon/formation combination in
that field.
    (C) A new emission factor is calculated every other year for each
reporting field and horizon.
    (ii) Calculation Methodology 2. Calculate emissions from each well
venting for liquids unloading using Equation W-7 of this section.

[GRAPHIC] [TIFF OMITTED] TP12AP10.005

Where:

Es,n = Annual natural gas emissions at standard
conditions, in cubic feet/year.
0.37 x 10-3 = {pi(3.14)/4{time} /{(14.7*144) psia
converted to pounds per square feet{time}
CD = Casing diameter (inches).
WD = Well depth (feet).
SP = Shut-in pressure (psig).
V = Number of vents per year.
SFR = Sales flow rate of gas well in cubic feet per hour.
HR = Hours that the well was left open to the atmosphere during
unloading.

    (A) Both CH4 and CO2 volumetric and mass
emissions shall be calculated from volumetric natural gas emissions
using calculations in paragraphs (u) and (v) of this section.
    (B) [Reserved]
    (g) Gas well venting during unconventional well completions and
workovers. Calculate emissions from gas unconventional well venting
during well completions and workovers from hydraulic fracturing using
Equation W-8 of this section. Calculate natural gas volumetric
emissions at standard conditions using calculations in paragraph (t) of
this section. Both CH4 and CO2 volumetric and
mass emissions shall be calculated from volumetric natural gas
emissions using calculations in paragraphs (u) and (v) of this section.

[GRAPHIC] [TIFF OMITTED] TP12AP10.006

Where:
Ea,n = Annual natural gas vented emissions at ambient
conditions in cubic feet.
T = Cumulative amount of time in hours of well venting during the
year.
FR = Flow Rate in cubic feet per hour, under ambient conditions, as
required in paragraph (g)(1) of this section.

    (1) The flow rate for gas well venting during well completions and
workovers from hydraulic fracturing shall be determined using either of
the calculation methodologies described in this paragraph (g)(1). The
same calculation methodology must be used for the entire volume for the
reporting year.
    (i) Calculation methodology 1. For one well completion in each gas
producing field and for one well workover in each gas producing field,
a recording flow meter shall be installed on the vent line during each
well unloading event according to methods set forth in Sec.  98.234(b).
    (A) The average flow rate in cubic feet per minute of venting is
calculated for one well completion in each field and for one well
workover in each field.
    (B) The respective flow rates are applied to all well completions
in the field and to all well workovers in the field, multiplied by the
number of minutes of venting of all well completions and workovers,
respectively, in that field.

    (C) New flow rates for completions and workovers are calculated
every other year for each reporting field and horizon.
    (ii) Calculation Methodology 2. For one well completion in each gas
producing field and for one well workover in each gas producing field,
record the pressures measured before and after the well choke according
to methods set forth in Sec.  98.234(b).
    (A) The average flow rate in cubic feet per minute of venting
across the choke is calculated for one well completion in each field
and for one well workover in each field.
    (B) The respective flow rates are applied to all well completions
in the field and to all well workovers in the field, multiplied by the
number of minutes of venting of all well completions and workovers in
that field.
    (C) New flow rates for completions and workovers are calculated
every other year for each reporting field and horizon.
    (iii) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
    (iv) Both CH4 and CO2 volumetric and mass
emissions shall be calculated from volumetric natural gas emissions
using calculations in paragraphs (u) and (v) of this section.
    (2) Calculate annual emissions from gas well venting during well
completions and workovers to flares as follows:
    (i) Use the gas well venting volume during well completions and
workovers as determined in paragraph (g)(1) of this section.
    (ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine gas well venting during well
completions and workovers emissions from the flare.
    (h) Gas well venting during conventional well completions and
workovers. Calculate emissions from each gas well venting during
conventional well completions and workovers using Equation W-9 of this
section:
[GRAPHIC] [TIFF OMITTED] TP12AP10.007

    Where:

Ea,n = Annual emissions in cubic feet at ambient
conditions from gas well venting during conventional well
completions or workovers.
V = Daily gas production rate in cubic feet per minute.
T = Cumulative amount of time of well venting in minutes during the
year.

    (i) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
    (ii) Both CH4 and CO2 volumetric and mass
emissions shall be calculated from volumetric natural gas emissions
using calculations in paragraphs (u) and (v) of this section.
    (iii) Blowdown vent stacks. Calculate blowdown vent stack emissions
as follows:
    (1) Calculate the total volume (including, but not limited to,
pipelines, compressor case or cylinders, manifolds, suction and
discharge bottles and vessels) between isolation valves.
    (2) Retain logs of the number of blowdowns for each equipment type.
    (3) Calculate the total annual venting emissions using Equation W-
10 of this section:
[GRAPHIC] [TIFF OMITTED] TP12AP10.008

Where:

Ea,n = Annual natural gas venting emissions at ambient
conditions from blowdowns in cubic feet.
N = Number of blowdowns for the equipment in reporting year.
Vv = Total volume of blowdown equipment chambers
(including, but not limited to, pipelines, compressors and vessels)
between isolation valves in cubic feet.

    (4) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
    (5) Calculate both CH4 and CO2 volumetric and
mass emissions from volumetric natural gas emissions using calculations
in paragraphs (u) and (v) of this section.
    (j) Onshore production and processing storage tanks. For emissions
from atmospheric pressure storage tanks receiving produced liquids from
onshore petroleum and natural gas production facilities (including
stationary liquid storage not owned or operated by the reporter) and
onshore natural gas processing facilities, calculate annual
CH4 and CO2 emissions using the latest software
package for E&P Tank (incorporated by reference, see Sec.  98.7).
    (1) A minimum of the following parameters must be used to
characterize emissions from liquid transfer to atmospheric pressure
storage tanks.
    (i) Separator oil composition.
    (ii) Separator temperature.
    (iii) Separator pressure.
    (iv) Sales oil API gravity.
    (v) Sales oil production rate.
    (vi) Sales oil Reid vapor pressure.
    (vii) Ambient air temperature.
    (viii) Ambient air pressure.
    (2) Determine if the storage tank has vapor recovery or thermal
control devices.
    (i) Adjust the emissions estimated using E&P Tank (incorporated by
reference, see Sec.  98.7) downward by the magnitude of emissions
captured using a vapor recovery system for beneficial use.
    (ii) [Reserved]
    (3) Calculate emissions from liquids sent to atmospheric storage
tanks vented to flares as follows:
    (i) Use the storage tank emissions volume and gas composition as
determined in this section.
    (ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine storage tank emissions from the flare.
    (4) If liquids are sent to atmospheric storage tanks where the tank
emissions are not represented by the equilibrium conditions of the
liquid in a gas-liquid separator and calculated by E&P Tank
(incorporate by reference, see Sec.  98.7), then emissions shall be
calculated as follows:
    (i) Use the storage tank emissions as determined in this section.
    (ii) Multiply the emissions by 3.87 for sales oil less than 45 API
gravity.
    (iii) Multiply the emissions by 5.37 for sales oil equal to or
greater than 45 API gravity.
    (k) Transmission storage tanks. For storage tanks without vapor
recovery or thermal control devices in onshore natural gas transmission
compression facilities calculate annual emissions as follows:
    (1) Monitor tank vapor vent stack for emissions using an optical
gas imaging instrument according to methods set forth in Sec.
98.234(a)(1) for a duration of 5 minutes.
    (2) If the tank vapors are continuous then use a meter to measure
tank vapors.
    (i) Use a meter, such as, but not limited to a turbine meter, to
estimate tank vapor volumes according to methods set forth in Sec.
98.234(b).
    (ii) Use the appropriate gas composition in paragraph (u)(2)(iii)
of this section.
    (3) Calculate emissions from storage tanks to flares as follows:
    (i) Use the storage tank emissions volume and gas composition as
determined in paragraph (j)(1) of this section.
    (ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine storage tank emissions from the flare.
    (l) Well testing venting and flaring. Calculate well testing
venting and flaring emissions as follows:
    (1) Determine the gas to oil ratio (GOR) of the hydrocarbon
production from each well tested.

    (i) If GOR is not available then use an appropriate standard method
published by a consensus-based standards organization to determine GOR.
    (ii) [Reserved]
    (2) Estimate venting emissions using Equation W-11 of this section.
    [GRAPHIC] [TIFF OMITTED] TP12AP10.009

Where:

Ea,n = Annual volumetric natural gas emissions from well
testing in cubic feet under ambient conditions.
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil
here refers to hydrocarbon liquids produced of all API gravities.
FR = Flow rate in barrels of oil per day for the well being tested.
D = Number of days during the year, the well is tested.

    (3) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
    (4) Calculate both CH4 and CO2 volumetric and
mass emissions from volumetric natural gas emissions using calculations
in paragraphs (u) and (v) of this section.
    (5) Calculate emissions from well testing to flares as follows:
    (i) Use the well testing emissions volume and gas composition as
determined in paragraphs (l)(1) through (3) of this section.
    (ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine well testing emissions from the flare.
    (m) Associated gas venting and flaring. Calculate associated gas
venting and flaring emissions as follows:
    (1) Determine the GOR ratio of the hydrocarbon production from each
well whose associated natural gas is vented or flared.
    (i) If GOR is not available then use an appropriate standard method
published by a consensus-based standards organization to determine GOR.
    (i) [Reserved]
    (2) Estimate venting emissions using the Equation W-12 of this
section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.010

Where:

Ea,n = Annual volumetric natural gas emissions from
associated gas venting under ambient conditions, in cubic feet.
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil
here refers to hydrocarbon liquids produced of all API gravities.
V = Total volume of oil produced in barrels in the reporting year.

    (3) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
    (4) Calculate both CH4 and CO2 volumetric and
mass emissions from volumetric natural gas emissions using calculations
in paragraphs (u) and (v) of this section.
    (5) Calculate emissions from associated natural gas to flares as
follows:
    (i) Use the associated natural gas volume and gas composition as
determined in paragraphs (m)(1) through (3) of this section.
    (ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine associated gas emissions from the
flare.
    (n) Flare stacks. Calculate emissions from a flare stack as
follows:
    (1) If you have a continuous flow measurement device on the flare,
you must use the measured flow volumes to calculate the flare gas
emissions. If you do not have a continuous flow measurement device on
the flare, you can install a flow measuring device on the flare or use
engineering calculations, company records, or similar estimates of
volumetric flare gas flow.
    (2) If you have a continuous gas composition analyzer on gas to the
flare, you must use these compositions in calculating emissions. If you
do not have a continuous gas composition analyzer on gas to the flare,
you must use the appropriate gas compositions for each stream of
hydrocarbons going to the flare as follows:
    (i) When the stream going to the flare is natural gas, use the GHG
mole percent in feed natural gas for all streams upstream of the de-
methanizer and GHG mole percent in facility specific residue gas to
transmission pipeline systems for all emissions sources downstream of
the de-methanizer overhead for onshore natural gas processing
facilities.
    (ii) When the stream going to the flare is a hydrocarbon product
stream, such as ethane or butane, then use a representative composition
from the source for the stream.
    (3) Determine flare combustion efficiency from manufacturer. If not
available, assume that flare combustion efficiency is 98 percent.
    (4) Calculate GHG volumetric emissions at actual conditions using
Equations W-13, W-14, and W-15 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.011

[GRAPHIC] [TIFF OMITTED] TP12AP10.012

[GRAPHIC] [TIFF OMITTED] TP12AP10.013

Where:

Ea,i (un-combusted) = Contribution of annual uncombusted
GHG i emissions from flare stack in cubic feet, under ambient
conditions.
Ea,CO2 (combusted) = Contribution of annual emissions
from combustion from flare stack in cubic feet, under ambient
conditions.
Ea,I (total) = Total annual emissions from flare stack in
cubic feet, under ambient conditions.
Va = Volume of natural gas sent to flare in cubic feet,
during the year.
[eta] = Percent of natural gas combusted by flare (default is 98
percent).
Xi = Concentration of GHG i in gas to the flare.
Yj = Concentration of natural gas hydrocarbon
constituents j (such as methane, ethane, propane, butane, and
pentanes plus).
Rj = Number of carbon atoms in the natural gas
hydrocarbon constituent j; 1 for methane, 2 for ethane, 3 for
propane, 4 for butane, and 5 for pentanes plus).

    (5) Calculate GHG volumetric emissions at standard conditions using
calculations in paragraph (t) of this section.
    (6) Calculate both CH4 and CO2 mass emissions
from volumetric CH4 and CO2 emissions using
calculation in paragraph (v) of this section.

    (7) Calculate N2O emissions using the emission factors
for Gas Flares listed in Table W-8 of this subpart.
    (8) This emissions source excludes any emissions calculated under
other emissions sources in Sec.  98.233.
    (o) Centrifugal compressor wet seal degassing vents. Calculate
emissions from centrifugal compressor wet seal degassing vents as
follows:
    (1) For each centrifugal compressor determine the volume of vapors
from wet seal oil degassing tank sent to an atmospheric vent or flare
using a temporary or permanent flow measurement meter such as, but not
limited to, a vane anemometer according to methods set forth in Sec.
98.234(b).
    (2) Estimate annual emissions using meter flow measurement using
Equation W-16 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.014

Where:

Ea,i = Annual GHG i (either CH4 or
CO2) volumetric emissions at ambient conditions.
MT = Meter reading of gas emissions per unit time.
T = Total time the compressor associated with the wet seal(s) is
operational in the reporting year.
Mi = Mole percent of GHG i in the degassing vent gas; use
the appropriate gas compositions in paragraph (u)(2) of this
section.
B = Percentage of centrifugal compressor wet seal degassing vent gas
sent to vapor recovery or fuel gas or other beneficial use as
determined by keeping logs of the number of operating hours for the
vapor recovery system and the amount of vent gas that is directed to
the fuel gas system.

    (3) Calculate CH4 and CO2 volumetric
emissions at standard conditions using paragraph (t) of this section.
    (4) Calculate both CH4 and CO2 mass emissions
from volumetric emissions using calculations in paragraph (v) of this
section.
    (5) Calculate emissions from degassing vent vapors to flares as
follows:
    (i) Use the degassing vent vapor volume and gas composition as
determined in paragraphs (o)(1) through (3) of this section.
    (ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine degassing vent vapor emissions from
the flare.
    (p) Reciprocating compressor rod packing venting. Calculate annual
CH4 and CO2 emissions from each reciprocating
compressor rod packing venting as follows:
    (1) Estimate annual emissions using a meter flow measurement using
Equation W-17 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.015

Where:

Ea,i = Annual GHG i (either CH4 or
CO2) volumetric emissions at ambient conditions.
MT = Meter volumetric reading of gas emissions per unit time, under
ambient conditions.
T = Total time the compressor associated with the venting is
operational in the reporting year.
Mi = Mole percent of GHG i in the vent gas; use the
appropriate gas compositions in paragraph (u)(2) of this section.

    (2) If the rod packing case is connected to an open ended vent line
then use one of the following two methods to calculate emissions.
    (i) Measure emissions from all vents (including emissions
manifolded to common vents) including rod packing, unit isolation
valves, and blowdown valves using bagging according to methods set
forth in Sec.  98.234(c).
    (ii) Use a temporary meter such as, but not limited to, a vane
anemometer or a permanent meter such as, but not limited to, an orifice
meter to measure emissions from all vents (including emissions
manifolded to a common vent) including rod packing vents, unit
isolation valves, and blowdown valves according to methods set forth in
Sec.  98.234(b).
    (3) If the rod packing case is not equipped with a vent line use
the following method to estimate emissions:
    (i) You must use the methods described in Sec.  98.234(a) to
conduct annual leak detection of fugitive emissions from the packing
case into an open distance piece, or from the compressor crank case
breather cap or vent with a closed distance piece.
    (ii) Measure emissions using a high flow sampler, or calibrated
bag, or appropriate meter according to methods set forth in Sec.
98.234(d).
    (4) Conduct one measurement for each compressor in each of the
operational modes that occurs during a reporting period:
    (i) Operating.
    (ii) Standby pressurized.
    (iii) Not operating, depressurized.
    (5) Calculate CH4 and CO2 volumetric
emissions at standard conditions using calculations in paragraph (t) of
this section.
    (6) Estimate CH4 and CO2 volumetric and mass
emissions from volumetric natural gas emissions using the calculations
in paragraphs (u) and (v) of this section.
    (q) Leak detection and leaker emission factors. You must use the
methods described in Sec.  98.234(a) to conduct an annual leak
detection of fugitive emissions from all sources listed in Sec.
98.232(d)(9), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). This
paragraph (q) applies to emissions sources in streams with gas content
greater than 10 percent CH4 plus CO2 by weight.
Emissions sources in streams with gas content less than 10 percent
CH4 plus CO2 by weight do not need to be
reported. If fugitive emissions are detected for sources listed in this
paragraph, calculate emissions using Equation W-18 of this section for
each source with fugitive emissions.
[GRAPHIC] [TIFF OMITTED] TP12AP10.016

Where:

Es,i = Annual total volumetric GHG emissions at standard
conditions from each fugitive source.
Count = Total number of this type of emission source found to be
leaking.
EF = Leaker emission factor for specific sources listed in Table W-2
through Table W-7 of this subpart.
GHGi = For onshore natural gas processing facilities,
concentration of GHGi, CH4 or CO2, in the
total hydrocarbon of the feed natural gas; for other facilities
listed in Sec.  98.230(a)(3) through (a)(8), GHGi equals
1.
T = Total time the specific source associated with the fugitive
emission was operational in the reporting year, in hours.

    (1) Calculate GHG mass emissions in carbon dioxide equivalent at
standard conditions using calculations in paragraph (v) of this
section.
    (2) Onshore natural gas processing facilities shall use the
appropriate default leaker emission factors listed in Table W-2 of this
subpart for fugitive emissions detected from valves; connectors; open
ended lines; pressure relief valves; meters; and centrifugal compressor
dry seals.
    (3) Onshore natural gas transmission compression facilities shall
use the appropriate default leaker emission factors listed in Table W-3
of this subpart for fugitive emissions detected from connectors; block
valves; control valves; compressor blowdown valves; pressure relief
valves; orifice meters; other meters; regulators; and open ended lines.
    (4) Underground natural gas storage facilities for storage stations
shall use the appropriate default leaker emission factors listed in
Table W-4 of this subpart for fugitive emissions detected from
connectors; block valves; control valves; compressor blowdown valves;
pressure relief valves; orifice meters; other meters; regulators; and
open ended lines.
    (5) LNG storage facilities shall use the appropriate default leaker
emission factors listed in Table W-5 of this subpart for fugitive
emissions detected from valves; pump seals; connectors; and other.
    (6) LNG import and export facilities shall use the appropriate
default leaker emission factors listed in Table W-6 of this subpart for
fugitive emissions detected from valves; pump seals; connectors; and
other.
    (7) Natural gas distribution facilities for above ground meter
regulator and gate stations shall use the appropriate default leaker
emission factors listed in Table W-7 of this subpart for fugitive
emissions detected from connectors; block valves; control valves;
pressure relief valves; orifice meters; other meters; regulators; and
open ended lines.
    (r) Population count and emission factors. This paragraph applies
to emissions sources listed in Sec.  98.232(c)(2), (c)(9), (c)(15),
(c)(21), (d)(8), (e)(6), (f)(4), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3)