June 2018 Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2017: Updates Under Consideration for Incorporating GHGRP Data In supporting documentation associated with the development of EPA's 2018 Inventory of U.S. Greenhouse Gas Emissions and Sinks (GHGI), EPA stated plans to consider newly reported data from EPA's Greenhouse Gas Reporting Program (GHGRP) for the 2019 GHGI. EPA plans to consider newly reported GHGRP data and other relevant data, described in Section 1 below, for updating current emission estimation methodologies in the 2019 GHGI. The following sections discuss considerations toward updating the emissions and/or activity data specifically for: Gathering and boosting (G&B) segment (stations and pipelines) (Section 2), Hydraulically fractured (HF) oil well completions and workovers (Section 3), Flaring N20 emissions (Section 4), Transmission pipeline blowdowns (Section 5), and Liquefied natural gas (LNG) facilities (Section 6). EPA seeks stakeholder feedback on whether and how to incorporate data from the GHGRP or other data sources into the 2019 or future GHGI methodologies for these emission sources; refer to Section 7 for specific questions. Note, a June 2018 companion memo, Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2017: Updates Under Consideration for Well-Related Activity Data (2018 Well-related Activity Data memo) details further considerations for potentially improving current approaches for well-related emission sources. Section 3.2 below, which discusses updates under consideration for HF oil well completions and workovers, refers to this memo. 1 Available GHGRP Data This section summarizes data sources that EPA has reviewed to develop preliminary approaches and considerations toward updating the GHGI methodologies for the sources covered in this memo. Subpart W of the EPA's GHGRP collects annual activity and emissions data on numerous sources from onshore natural gas and petroleum systems that meet a reporting threshold of 25,000 metric tons of C02 equivalent (mt C02e) emissions. Facilities that meet the subpart W reporting threshold have been reporting since reporting year (RY) 2011; however, HF oil well completions and workover data elements, transmission pipeline blowdowns, and G&B facilities were first required to be reported in RY2016. In addition, subpart W natural gas processing, transmission, underground storage, LNG import/export, and LNG storage facilities report emissions from all flaring under the "flare stacks" emission source as of RY2015. Subpart W activity and emissions data are currently used in the GHGI to calculate CH4 and C02 emissions for many production, processing, and transmission and storage sources. Subpart W specifies facility definitions specific to certain segments. Onshore production and G&B facilities in subpart W are each defined as a unique combination of operator and basin of operation. Therefore, subpart W does not delineate data for G&B stations versus pipelines. However, the data are reported on an emission source level, so each source can be assigned as likely occurring at either G&B stations or pipelines. For the preliminary analyses in this memo organized around separate station and pipeline estimates, most subpart W G&B emission sources were assigned to G&B stations. Blowdown vent stacks from the "pipeline venting" emission source are assigned to gathering pipelines, and all other blowdown venting data were assigned to G&B stations. For equipment leaks, data for pipelines (cast iron, plastic/composite, protected steel, and unprotected steel gathering pipelines) were assigned to G&B pipelines, and all other equipment leak data were assigned to G&B stations. GHGRP subparts W and Y (petroleum refining) include reporting of N20 from flaring. The GHGRP calculation methodologies specify that subpart W reporters must calculate N20 emissions from flares using an EF of 0.0001 kg Page 1 of 27 ------- June 2018 N20 per million BTU, and subpart Y reporters using an EF of 0.0003 kg N20 per million BTU. N20 emissions are also reported to GHGRP for engine exhaust and other combustion sources, combustion emissions from which are generally included within GHGI estimates from fuel combustion, separate from natural gas and petroleum systems. The GHGRP data used in the analyses discussed in this memo are those reported to the EPA as of August 5, 2017. EPA will assess data for RY2017 as they become available. Stakeholders have suggested additional or alternate uses of GHGRP data, such as for certain sources using measurement data only. Stakeholders have also suggested modifications to the reported GHGRP data for use in the GHGI, such as through removal of stakeholder-identified outliers. In the current GHGI, EPA uses the publicly available GHGRP data set without modification for the GHGI, to ensure transparency and reproducibility of GHGI estimates. Prior to public release of the GHGRP data, the EPA has a multi-step data verification process for the data, including automatic checks during data-entry, statistical analyses on completed reports, and staff review of the reported data. Based on the results of the verification process, the EPA follows up with facilities to resolve identified potential issues before public release. 2 Gathering & Boosting Segment Updates Under Consideration In the April 2018 memo Inventory of U.S. GHG Emissions and Sinks 1990-2016: Additional Revisions Considered (2018 Additional Revisions memo),1 EPA stated that incorporating additional subpart W data would be considered for the 2019 GHGI and requested stakeholder feedback on certain items including the incorporation of subpart W G&B data. This section presents the G&B data that are available from subpart W and recent studies, compares these data to the current GHGI basis, and discusses options for updating estimates of national total emissions. G&B stations and pipelines are discussed separately. 2.1 Current GHGI Methodology For the 2016 GHGI, EPA made updates to the G&B segment methodology to incorporate recent study data for G&B stations, while the methodology for G&B pipelines has been unchanged in recent years, as summarized below. EPA's April 2016 memo Inventory of U.S. GHG Emissions and Sinks 1990-2014: Revision to Gathering and Boosting Station Emissions (2016 G&B memo)2 and April 2017 memo Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2015: Revisions to Natural Gas and Petroleum Systems Production Emissions (2017 Production memo)3 document the historical considerations and full methodology used for G&B stations in the current GHGI. In summary, the current GHGI estimates emissions based on station counts in each year paired with station-level EFs for normal events (documented in the 2016 G&B memo) and episodic events (documented in the 2017 Production memo). The total G&B station count in each year of the time series is estimated as the marketed onshore gas production in the given year (obtained from EIA) divided by the year 2012 throughput per station from the Marchese et al. 2015 study cited in the April 2016 memo. The current GHGI pairs this station count AD with a station-level CH4 EF for normal vented and fugitive emissions calculated using data from the Marchese et al. 2015 study. The current GHGI separately estimates episodic event emissions using a station-level CH4 EF from Marchese et al. 2015. The current GHGI estimates C02 emissions from G&B station normal and episodic events using C02 EFs developed by applying a default production segment ratio of C02-to-CH4 gas content, and as such does not fully account for C02 from combustion. The current GHGI estimates gathering pipeline mileage as the total producing gas wells in a given year, multiplied by a factor of pipeline miles per well from the joint Gas Research Institute (GRI)/EPA study published in 1996 (GRI/EPA 1996), plus an assumed 82,600 miles of gathering pipeline owned by transmission companies (per 1 https://www.epa.gov/ghgemissions/natural-gas-and-petroleum-systems-ghg-inventory-additional-information-1990-2016-ghg 2 https://www.epa.gov/sites/production/files/2016-08/documents/final_revision_gb_station_emissions_2016-04-14.pdf 3 https://www.epa.gov/sites/production/files/2017-04/documents/2017_ng-petro_production.pdf Page 2 of 27 ------- June 2018 GRI/EPA 1996). The pipeline leakage and blowdown CH4 EFs are also obtained from the 1996 GRI/EPA study. The current GHGI estimates C02 emissions from gathering pipelines using C02 EFs developed by applying a default production segment ratio of C02-to-CH4 gas content. 2.2 Analysis of Available Data for G&B Stations Table 1 shows subpart W G&B station source-specific emissions and compares the total reported subpart W emissions and 2018 GHGI emissions for G&B stations for year 2016. Appendix A documents the subpart W calculation methodologies for each source. As discussed further in Section 2.4, regional variability is being evaluated for the G&B data; subpart W basin-level G&B station emissions are provided in Appendix B. Table 1. G&B Station Source-Specific Emissions Data from Subpart W and National Totals from 2018 GHGI, Year 2016 Emission Source Total CH4 Emissions (mt) Total CO2 Emissions (mt) AGR n/a 1,521,325 Blowdown Vent Stacks3 43,974 6,373 Centrifugal Compressors 40,781 4,934 Combustion 31,822 n/ab Dehydrators 55,000 657,496 Equipment Leaks0 102,600 11,983 Flare Stacks 10,774 2,667,154 Pneumatic Devices 182,502 12,250 Pneumatic Pumps 29,089 1,783 Reciprocating Compressors 2,654 403 Tanks 297,671 1,046,404 Subpart W Reported Totald 796,868 5,930,105 National Total (2018 GHGI)ฎ 2,149,065 233,502 n/a - Not applicable. a - Includes blowdown emissions reported by G&B facilities for: compressors, emergency shutdowns, facility piping, scrubbers/strainers, pig launchers and receivers, all other equipment with a physical volume greater than or equal to 50 cubic feet, and emissions reported with flow meters, b - Excludes C02 emissions from engine combustion (as these emissions are included in a separate section of the GHGI). c- Includes all emissions reported by G&B facilities under the equipment leaks reporting section, except for emissions attributed to gathering pipelines. d - The G&B facility definition in subpart W does not delineate reporting by "station" versus "pipeline." Therefore, these emissions equal the sum of reported subpart W emissions assigned to G&B stations (see footnotes a and c), as documented in Section 1. e - Includes normal vented and fugitive emissions plus episodic event emissions from stations; refer to 2016 G&B memo and 2017 Production memo for additional detail. The current GHGI uses station counts (the 2018 GHGI estimates 5,241 stations for year 2016) coupled with a station-level EF to calculate emissions in each time series year. However, as discussed in Section 1, subpart W reporting is not organized around the station-level; data are reported at the basin-level, so the type and number of emission sources present at a given station cannot be inferred. Therefore, a subpart W station-level EF cannot be calculated for direct comparison to the GHGI. EPA is considering approaches to scale subpart W data to the national level (as reported, it only represents facilities meeting the reporting threshold), to assess how national emission estimates based on subpart W compare to the current GHGI, and to consider how to potentially update the GHGI methodology to incorporate subpart W data. To estimate the degree of national coverage represented by the subpart W G&B emissions, the EPA is considering comparing the quantity of gas received (reported under subpart W by G&B facilities) to the Page 3 of 27 ------- June 2018 total amount of gas produced from wells (estimated from EPA's analysis of Drillinglnfo data4) to assess GHGRP coverage and scale data from GHGRP to the national level. Appendix B provides volumes of gas received and gas produced for each basin in year 2016. Based on the reported quantities of gas received frequently exceeding the amount of gas produced in a basin, it appears that a given volume of gas received might be counted more than once as it moves from one system to another system (operated by the same or different operator) within the same basin (i.e., is "received" multiple times). Acknowledging this, EPA is considering assessing coverage at the basin-level, to account for certain basins where the reported gas received is less than the estimated gas produced. An approach under consideration for scaling subpart W G&B basin-level data to estimate national emissions involves several steps: (1) EPA first compared the reported gas received to Drillinglnfo gas produced in each basin; for basins where the gas produced exceeds the reported gas received, EPA adjusted the gas received to equal the gas produced value, as a reasonable maximum (to minimize impacts of the double-counting described above). (2) EPA identified basins that account for a significant fraction of reported emissions, specifically, those that contributed at least 10 percent of total annual emissions (on a C02 Eq. basis) from G&B sources in a given year. Three basins met this criteria: 430 - Permian Basin, 220 - Gulf Coast Basin, and 360 - Anadarko Basin. (3) For the top-emitting basins, EPA calculated a scaling factor equal to the gas produced divided by the gas received (i.e., the inverse of reporting coverage). For all other basins, EPA summed the gas produced and gas received across basins, then calculated a group scaling factor. (4) For each basin or basin group, EPA applied the scaling factor to reported emissions. Table 2 presents the subpart W G&B station data and calculated scaling factor for each basin or group. The three basins that have the highest G&B emissions each have a scaling factor of 1 for this approach, while the "all other basins group" has a factor higher than 1. The calculated national scaling factor is 1.17, which corresponds to an estimate that subpart W reporting covers approximately 85% of G&B activity in the U.S. Implicit to this approach is an assumption that all gas produced is received at G&B facilities (and basins with less than 100% coverage include G&B facilities, according to the subpart W definition, but have emissions less than the reporting threshold). National emission estimates based on this approach are presented in Section 2.5. The EPA requests comment on this approach and assumption, and other approaches that could be considered to scale subpart W G&B station emissions, in Section 7. Table 2. Basin-Level Approach Data to Scale Subpart W G&B Station Emissions, for Year 2016 Basin Subpart W Reported Station CH4 (mt) Subpart W Reported Station CO2 (mt) Subpart W: Quantity Gas Received (mscf) Adjusted Quantity Gas Received (mscf)a Drillinglnfo: Gas Produced (mscf) Basin Scaling Factor13 430 - Permian Basin 114,330 2,357,782 9,377,991,907 2,546,961,000 2,546,961,000 1.0 220 - Gulf Coast Basin (LA, TX) 180,859 1,427,659 4,671,449,082 3,061,920,423 3,061,920,423 1.0 360 - Anadarko Basin 205,913 179,505 2,378,161,495 1,712,080,076 1,712,080,076 1.0 All Other Basins 295,766 1,965,159 25,273,198,450 18,033,350,200 22,353,867,857 1.24 a - As discussed in step 1 in the paragraph preceding Table 2, for basins where the gas produced exceeds the reported gas received, EPA adjusted the gas received to equal the gas produced value. b - As discussed in step 3 in the paragraph preceding Table 2, equals the gas produced divided by the adjusted gas received. In addition to analyzing scaled subpart W data for comparison to GHGI estimates, EPA reviewed findings from recent research studies which provide station-level EFs that can be directly compared to the current GHGI EF (in contrast to the basin-level subpart W data): Vaughn et al. (2017). Comparing facility-level methane emission rate estimates at natural gas gathering and boosting stations. 4 The activity data methodologies for several upstream emission sources within natural gas and petroleum systems rely on EPA's analyses of the subscription-based digital Dl Desktop raw data feed. This data set is referred to throughout this memo as "Drillinglnfo data." Page 4 of 27 ------- June 2018 Yacovitch et al. (2017). Natural gas facility methane emissions: measurements by tracer flux ratio in two US natural gas producing basins. Zimmerle et al. (2017). Gathering pipeline methane emissions in Fayetteville shale pipelines and scoping guidelines for future pipeline measurement campaigns. The Vaughn, et al. (2017) study calculated two station-level EFs, shown in Table 3. Both EFs are higher than the current GHGI EF, the degree to which depends on whether tank venting (that was observed at two stations) is included in the EF. The Yacovitch et al. (2017) study calculated EFs for two regions, the Fayetteville shale play and Denver-Julesburg (DJ) Basin; Table 3 presents the study results. The emission rate for the DJ Basin is lower than the Fayetteville shale play. Note that the statistical mode of the EFs were presented in the study, rather than average EFs. Yacovitch et al. (2017) also presented confidence intervals around their study data. The confidence intervals encompass the current GHGI EF. The Yacovitch et al. (2017) study also summarized results from prior studies (shown as "Multi-Basin: Tracer Sites" in Table 3), which are included for reference. Table 3. G&B Station CH4 Emission Rates from Recent Studies Compared to the Current GHGI CH4 Emission Rate Parameter (kg/h) Vaughn et al. 2017 Station EF, excluding tank venting 50.4 Station EF, including tank venting 74.5 Yacovitch et al. 2017 Multi-basin: tracer sites mode EF 25 [95% confidence interval] [12 - 3,300] Fayetteville study area mode EF 40 [95% confidence interval] [15 - 730] DJ study area mode EF 11 [95% confidence interval] [4.5-75] 2018 GHGI Station EF 34 EPA seeks stakeholder feedback on whether and how to incorporate data from recent studies into the 2019 or future GHGI methodologies; refer to Section 7 for specific questions. Additionally, Appendix A summarizes the general approach (e.g., measurement methods, representativeness) of each study. 2.3 Analysis of Available Data for G&B Pipelines Table 4 compares the reported subpart W G&B pipeline source-specific emissions and activity (pipeline miles) to the 2018 GHGI emissions and pipeline miles, for year 2016. Appendix A documents the subpart W calculation methodologies for each source. Subpart W basin-level G&B pipeline emissions are provided in Appendix B. Table 4. G&B Pipeline Source-Specific Emissions and Mileage Data from Subpart W and National Totals from 2018 GHGI, for Year 2016 Emission Source Total CH4 Emissions (mt) Total CO2 Emissions (mt) Pipeline Miles Equipment Leaks 137,298 8,166 405,174 Cast iron gathering pipeline 1,246 22 301 Plastic/composite gathering pipeline 27,100 1,268 84,299 Protected steel gathering pipeline 18,171 910 279,128 Unprotected steel gathering pipeline 90,780 5,966 41,986 Page 5 of 27 ------- June 2018 Emission Source Total CH4 Emissions (mt) Total CO2 Emissions (mt) Pipeline Miles Blowdown Vent Stacks3 14,713 801 n/a Subpart W Reported Total 152,011 8,967 405,174 National Total (2018 GHGI) 157,798 18,820 398,554 n/a - Not applicable. a - Includes blowdown emissions reported by G&B facilities for pipeline venting. To identify potential methodological updates that might improve current GHGI estimates through incorporation of subpart W data, the EPA evaluated differences between subpart W reporting and current GHGI assumptions by comparing EFs calculated from the subpart W data to those used in the current GHGI. The EFs shown in Table 5 are calculated as the total reported emissions divided by the total reported miles shown in Table 4. Table 5. G&B Pipeline EFs Calculated from Subpart W and 2018 GHGI Data Source CH4 ef (kg/mile) CO2 EF (kg/mile) Subpart W 375 22 2018 GHGIa 396 47 a - The 2018 GHGI uses specific EFs for each NEMS region, which are adjusted for methane content. This table presents calculated EFs which represent the national average. EPA also considered how to evaluate the subpart W reporting coverage in terms of activity (pipeline miles). As seen in Table 4, the G&B pipeline miles reported to subpart W exceed the estimated national miles from the current GHGI. PHMSA collects data for "regulated gathering lines," but this is a small subset of the total (11,494 miles were reported for 2016s). PHMSA does have a proposed rule, however, that would collect gathering line data, but it is not final and data are not available.6 Year 2015 gathering pipeline miles were estimated for the proposed rule by PHMSA (355,509 miles) and industry (399,579 miles), and so while the estimates are based on more recent data than the current GHGI and are of similar magnitude, the estimates are still lower than the reported subpart W miles. If the EPA maintains an approach to estimate G&B pipeline emissions that relies on total national miles, then the subpart W data may currently provide the most complete estimate. However, national miles from PHMSA may be available in the future. The EPA could also consider an approach to scale subpart W G&B pipeline emissions to the national level using the approach discussed in Section 2.2 for G&B stations (i.e., applying the coverage estimate of 85%). Table 6 presents the subpart W G&B pipeline data and calculated scaling factor for each basin. National emission estimates based on this approach are presented in Section 2.5. Table 6. Basin-Level Approach to Scale Subpart W G&B Pipeline Emissions, for Year 2016 Basin Subpart W Reported Pipeline CH4 (mt) Subpart W Reported Pipeline CO2 (mt) Basin Scaling Factor 430 - Permian Basin 47,841 2,049 1.0 220 - Gulf Coast Basin (LA, TX) 7,304 303 1.0 360 - Anadarko Basin 21,148 330 1.0 All Other Basins 75,717 6,285 1.24 5 https://cms.phmsa.dot.gov/data-and-statistics/pipeline/annual-report-mileage-natural-gas-transmission-gathering-systems 6 See docket PHMSA-2011-0023 at regulations.gov. Page 6 of 27 ------- June 2018 2.4 G&B Segment Regional Variability and Time Series Considerations Stakeholders have previously suggested that differences due to regional and temporal variability should be considered when updating GHGI methodologies, particularly for sources where variation is expected. EPA reflects regional variability in the current methodologies for associated gas venting and flaring and miscellaneous production flaring by calculating basin-level emissions and activity factors. The EPA is similarly considering whether and how to represent regional variability in G&B emissions; basin-level data are presented in Appendix B, and a basin-level methodology is under consideration to estimate G&B station and pipeline emissions. The EPA is also considering temporal variability, and ways to reflect emissions changes over the time series. However, limited historical data are available for G&B stations and pipelines. Subpart W data are only available for a single year (2016), and the current GHGI approach and other recent studies only examined data at a single recent point in time. The current GHGI methodology applies the same EFs for all years of the time series, and the activity data vary with changes in gas production or gas wells. For the updates under consideration, the year 2016 subpart W data could be used for all prior years in the time series, and activity could vary with gas production or pipeline miles. Notably, the updates being considered that rely on subpart W data would be able to reflect future trends, as year-specific updates would be applied for 2016 and forward. The EPA requests additional data and information that could inform time series trends. 2.5 G&B Segment Preliminary National Emissions Estimates Table 7 and Table 9 show national CH4 and C02 emissions for 2016 based on the updates under consideration described above for G&B stations and pipelines. Table 8 and Table 10 present the national G&B emissions by source. Table 7. Comparison of National-Level CH4 and C02 Emissions Estimates for G&B Station Emissions, for Year 2016 Basin Subpart W Emissions, as Reported Subpart W Basin-Level Scale Up Approach3 2018 GHGI CH4 (mt) CO2 (mt) CH4 (mt) CO2 (mt) CH4 (mt) CO2 (mt) 430 - Permian Basin 114,330 2,357,782 114,330 2,357,782 NE NE 220 - Gulf Coast Basin (LA, TX) 180,859 1,427,659 180,859 1,427,659 360 - Anadarko Basin 205,913 179,505 205,913 179,505 All Other Basins 295,766 1,965,159 366,627 2,435,981 Total 796,868 5,930,105 867,729 6,400,927 2,149,065 233,502 NE - Not estimated. a - Emissions calculated using the basin-level emissions and scaling factors in Table 2. Table 8. Subpart W Scaled-Up G&B Station Emission Source-Specific Emissions, for Year 2016 Emission Source Subpart W Scaled-Up Emissions3 CH4 (mt) CO2 (mt) AGR 0 1,642,111 Blowdown Vent Stacks3 47,885 6,879 Centrifugal Compressors 44,407 5,326 Combustion 34,652 0 Dehydrators 59,891 709,698 Equipment Leaks0 111,724 12,934 Flare Stacks 11,733 2,878,914 Pneumatic Devices 198,731 13,222 Pneumatic Pumps 31,676 1,924 Reciprocating Compressors 2,890 435 Tanks 324,141 1,129,483 Page 7 of 27 ------- June 2018 Emission Source Subpart W Scaled-Up Emissions3 CH4 (mt) CO2 (mt) Total 867,729 6,400,927 a - To develop national-level scaled up estimates at the emission source-level for this table, ratios of scaled subpart W emissions to reported subpart W emissions (from Table 7) were calculated for CH4 and C02 and applied to the reported total for each emissions source (from Table 1). Table 9. Comparison of National-Level CH4 and C02 Emissions Estimates for G&B Pipeline Emissions, for Year 2016 Basin Subpart W Basin-Level Approach3 Subpart W Pipeline Mileage Approach13 2018 GHGI CH4 (mt) CO2 (mt) CH4 (mt) CO2 (mt) CH4 (mt) CO2 (mt) 430 - Permian Basin 47,841 2,049 NE NE NE NE 220 - Gulf Coast Basin (LA, TX) 7,304 303 360 - Anadarko Basin 21,148 330 All Other Basins 93,858 7,791 Total 170,152 10,473 152,011 8,967 157,798 18,820 NE - Not estimated. a - Emissions calculated using the basin-level emissions and scaling factors in Table 6. b - Emissions calculated using the subpart W pipeline EFs in Table 5 and the reported subpart W pipeline miles in Table 4. Table 10. Subpart W Scaled-Up G&B Pipeline Emission Source-Specific Emissions, for Year 2016 Emission Source Subpart W Scaled-Up Emissions3 CH4 (mt) CO2 (mt) Cast iron gathering pipeline 1,395 26 Plastic/composite gathering pipeline 30,334 1,481 Protected steel gathering pipeline 20,340 1,063 Unprotected steel gathering pipeline 101,614 6,968 Blowdown vent stacks3 16,468 935 Total 170,152 10,473 a - To develop national-level scaled up estimates at the emission source-level for this table, ratios of scaled subpart W emissions to reported subpart W emissions (from Table 9) were calculated for CH4 and C02 and applied to the reported total for each emissions source (from Table 4). Comparing the G&B station subpart W scaled emissions using the basin-level approach that is under consideration to the 2018 GHGI emissions, the subpart W scaled station CH4 emissions are approximately 40% of the 2018 GHGI station CH4 emissions, and the subpart W scaled station C02 emissions are approximately 27 times the 2018 GHGI station C02 emissions. As discussed in Section 2.1, the current GHGI does not fully account for station C02 emissions from flaring, and the subpart W data addresses this issue. However, the EPA seeks stakeholder feedback on whether the G&B emission source estimates reported under subpart W accurately represent U.S. emissions from G&B stations, and if not, whether external data sources might be used to supplement reported data for purposes of GHGI updates and/or perform further assessments. As an example, the subpart W G&B compressor methodology relies on G&B compressor counts paired with an EF that is the same as the EF prescribed for the subpart W onshore production segment, when gathering segment compressors may be largeras a result, the EPA might consider an approach such as applying the GHGI compressor EFs from the natural gas processing segment (currently calculated from subpart W data) to G&B segment reported activity. For G&B pipeline emissions, the subpart W-based approaches that are being considered both have a similar magnitude of emissions compared to the 2018 GHGI emissions. However, the subpart W basin-level approach Page 8 of 27 ------- June 2018 results in some scale-up compared to the reported subpart W emissions (based on the currently available data for RY2016), whereas the pipeline mileage approach assumes 100% reporting coverage of gathering pipeline equipment/activity. 3 HF Oil Well Completions and Workovers Updates Under Consideration In the 2018 GHGI Additional Revisions memo, EPA stated that subpart W data would be considered for the GHGI and requested stakeholder feedback on certain itemsspecifically including updating the GHGI to use GHGRP data on HF oil well completions and workovers and considerations toward developing national-level estimates. This section presents the subpart W data that are available, compares these data to the current GHGI basis, and discusses options for updating estimates of national total emissions for HF oil well completions and workovers. rrent GHGI Methodology In the current GHGI methodology for HF oil well completions, controlled and uncontrolled CH4 EFs were developed using data analyzed for the 2015 NSPS OOOOa proposal. The current GHGI estimates C02 emissions using C02 EFs developed by applying a default production segment ratio of C02-to-CH4 gas content. As such, this approach for does not fully account for C02 emissions from flaring. The 2018 GHGI activity data time series (counts of HF oil well completions, which is also referenced in calculating non-HF oil well completions), was developed from analyzing Drillinglnfo data on well-level dates of completion or first reported production. The existing GHGI methodology also includes assumptions to develop activity factors (AFs) for apportioning total counts into control categories. In 2008, Colorado and Wyoming adopted regulations that require RECs; the current GHGI assumes that 7% of completions are RECs with 95% control efficiency, from 2008 forward. For workovers, the current GHGI methodology estimates emissions from all oil well workovers without distinguishing HF from non-HF, using an EF developed for conventional wells and an assumption that 7.5% of all oil wells are worked over in each year. . ฆฆ . ilile Data EPA analyzed the RY2016 subpart W data for HF oil well completions and workovers to consider updating the existing GHGI methodology, which estimates emissions from HF oil well completions based on historical rulemaking data and does not include a specific emissions estimate for HF oil well workovers (as discussed in Section 3.1). The new subpart W data allow development of separate GHGI emissions estimates for HF completions and workovers, in parallel control categories that exist for HF gas well events (reflecting combinations of reduced emissions completion (REC) use, venting, and flaring).7 Additionally, as summarized in Section 3.1, the current GHGI HF oil well completion C02 EF is calculated by applying an associated gas C02-to-CH4 content ratio, which does not account for C02 conversion during hydrocarbon combustion. This current methodological limitation would be obviated by using subpart W data to directly calculate CH4 and C02 EFs, parallel to the current methodology for HF gas well events. 7 The GHGI methodology for HF gas well completions and workovers incorporates GHGRP data. For HF gas well completions and workovers, EFs are developed from reporting year-specific GHGRP subpart W data (2011 through 2016), with year 2011 EFs applied for earlier time series years. The EFs are developed for four control categories: non-REC/vented; non-REC/flared; REC/vented; and REC/flared. The total counts of HF completions are developed from Drillinglnfo data for years prior to 2011, and GHGRP data are used for year 2011 forward (as the directly reported counts are higher than Drillinglnfo-based estimates). The counts are apportioned into control categories based on year-specific GHGRP data for 2011-2016; for years 1990-2000, it is assumed all events are non-REC, and 10% of events flare; interpolation is used to develop AFs in intermediate years. For HF gas well workovers, it is assumed that 1% of the count of existing HF gas wells in a given year (estimated from analyzing Drillinglnfo data) are worked over. Page 9 of 27 ------- June 2018 This section documents development of EFs and activity data for HF oil well completions and workovers according to the general methodology used in the current GHGI for HF gas well completions and workovers. The 2018 Well- related Activity Data companion memo details considerations for potentially improving the approach to estimating national total activity data for all completions and workovers (e.g., Drillinglnfo query methodology, workover rate assumptions). Table 11 below shows EFs calculated using RY2016 subpart W data for HF oil well completions and workovers for each event type/control category, compared to current GHGI EFs. Table 12 shows AFs for each event type/control category. Table 11. Emission Factors Calculated from Subpart W Compared to Current GHGI, for Year 2016 Event Type Control Category CH4 EF (mt/event) CO2 EF (mt/event) 2018 GHGI Subpart W 2018 GHGI Subpart W Non-REC Vent 6.76 36.0 0.38 0.8 Flare 1.1 248.8 REC Vent 0.34 1.3 0.02 0.1 Flare 2.6 287.1 Table 12. Activity Factors Calculated from Subpart W Compared to Current GHGI, for Year 2016 Event Type Control Category HF Completions HF Workovers Subpart W 2018 GHGIa Subpart W # of Events % of total # of Events % of total # of Events % of total Non-REC Vent 111 3% 11,567 93% 35 11% Flare 542 13% 16 5% REC Vent 1,345 33% 871 7% 186 56% Flare 2,061 51% 93 28% Total 4,059 100% 12,438 100% 330 100% a - For years 2008 forward, the current GHGI assumes 7% of HF oil well completions are controlled via REC due to state- specific regulations. The current GHGI does not include specific estimates for HF oil well workovers. To develop national total activity data for HF oil well completions, EPA analyzed counts derived from the Drillinglnfo data set compared to reported counts. For HF gas well completions, counts reported under GHGRP exceed Drillinglnfo-based estimates, so are assumed to represent national coverage and used directly as national total activity in the GHGI. For HF oil well completions, this is not the case; Drillinglnfo-based counts exceed reported counts. Therefore, to develop the preliminary national emissions estimates presented in Section 3.4, Drillinglnfo-based activity data are used in conjunction with the EFs and AFs in Table 11 and Table 12, respectively. Workover data are not contained within EPA's Drill ingl nfo analysis data set, so an assumption of 1% annual workover rate is applied for HF gas wells in the current GHGI. In each year of the time series, 1% of existing HF wells (estimated from the Drill inglnfo data set) are assumed to undergo workovers. For HF gas wells, this approach results in national total activity data that exceed HF workover counts reported under subpart W. For the preliminary national emissions estimates presented in Section 3.4, EPA applies the same assumption to HF oil wells to calculate national total workover activity. Similar to HF gas wells, this approach results in national total activity data that exceed HF oil well workover counts reported under subpart W. As stated above, the 2018 Well-related Activity Data companion memo details considerations for potentially improving the approach to estimating national total activity data for all completions and workovers in the GHGI, which might include refining the Drillinglnfo query methodology and/or further incorporating subpart W data. For example, the 2018 Well-related Activity data memo estimates that within the RY2015-2016 subpart W data for Page 10 of 27 ------- June 2018 gas wells, an overall workover rate is 5-6% in recent years (compared to the current GHGI assumption of 4.35% for non-HF gas wells and 1% for HF gas wells). 3.3 Regional Variability and Time Series Considerations For HF oil well completions and workovers, this memo presents preliminary emissions estimates (see Section 3.4) according to the existing GHGI methodology to develop estimates for HF gas well events; EFs and AFs are calculated at the national level. EPA seeks stakeholder feedback on whether a region-specific approach should be considered for these sources. To develop the time series AFs for HF oil well completions and workovers based generally on the existing methodology for gas well events, and incorporating current control assumptions for HF oil well events, the following assumptions could be applied: For years 1990-2007, all completions and workovers are non-REC, and 10% of events flare. For the first year in which subpart W data are available, 2016, control fractions across the four categories are developed directly from reported subpart W data. For intermediate years, 2008-2015, control fractions are developed through linear interpolation. This produces AFs across the time series that are generally consistent with the existing GHGI assumption that oil well RECs are introduced beginning in year 2008, during which 7% of completions and workovers are REC, and 10% of both REC and non-REC events flare. EPA seeks feedback on the assumptions above used to develop these control category AFs. To apply EFs across the time series, EPA would apply year-specific EFs for GHGRP years, and EFs from the earliest GHGRP year to all prior years, consistent with the approach for HF gas well events. For the 2019 GHGI, this approach means that EFs calculated from RY2016 data would be applied for years 1990-2016, and RY2017 data would be used to develop EFs for year 2017. 3.4 Preliminary National Emissions Estimates Table 13 below shows national total activity data and CH4 emissions for select time series years based on the updates under consideration described above. Table 13. Preliminary National Activity and Emissions Estimates for HF Oil Well Completions and Workovers, Select Years Data Element 1990 2000 2005 2010 2015 2016 HF oil well completions (#) 3,075 2,246 4,594 8,188 12,438 12,438 Non-REC/Vent (%) 90% 90% 90% 61% 12% 3% Non-REC/Flare (%) 10% 10% 10% 11% 13% 13% REC/Vent(%) 0% 0% 0% 11% 29% 33% REC/Flare (%) 0% 0% 0% 17% 45% 51% HF oil well workovers (#) 846 848 947 1,235 1,916 1,884 Non-REC/Vent (%) 90% 90% 90% 64% 19% 11% Non-REC/Flare (%) 10% 10% 10% 8% 5% 5% REC/Vent(%) 0% 0% 0% 19% 50% 56% REC/Flare (%) 0% 0% 0% 9% 25% 28% Total CH4 emissions (kt) 128 101 180 222 95 46 2018 GHGI CH4 emissions (kt)a 21 15 31 52 79 79 Total CO2 emissions (kt) 100 79 142 688 2,179 2,402 2018 GHGI CO2 emissions (kt)a 1 1 2 3 4 4 a - Does not include estimate for workovers. The 2018 GHGI does not specifically estimate emissions from HF oil well workovers; the estimate for all (non-HF and HF) oil well workovers is negligible compared to the magnitude of other estimates shown in this table (<0.1 kt across the time series). Page 11 of 27 ------- June 2018 4 Flaring N2O Emissions Updates Under Consideration The current GHGI does not estimate N20 emissions for natural gas and petroleum systems. However, with recent updates that use GHGRP data to estimate CH4 and C02 flaring emissions, the EPA is considering updates to incorporate N20 emissions for the same flaring sources. The EPA would apply the existing source-specific methodology for using GHGRP CH4 data to develop N20 EFs. For purposes of presenting preliminary national total flaring N20 emission estimates, EPA calculated a ratio of the GHGRP reported N20 emissions to C02 emissions and then multiplied the N20-to-C02 ratio by the 2018 GHGI C02 emissions, for each emission source. Table 14 presents reported GHGRP N20 and C02 flaring emissions, the calculated N20-to-C02 ratio, 2018 GHGI C02 emissions, and the resulting scaled N20 emissions, for RY2016. This table focuses on sources that currently use a GHGRP-based methodology in the GHGI, but also includes reference GHGRP data for sources in this memo where updates are being considered. Table 14. Preliminary National N20 Emissions Estimates for Flaring Sources in Natural Gas and Petroleum Systems, Year 2016 GHGRP Flaring Estimated Emission Source GHGRP N20 C02 Ratio of 2018 GHGI National (as reported)3 (as reported) N20:C02 CO2 Total N2O (mt) (mt) (xl00,000) (mt) (mt) Natural Gas & Petroleum Production Tank Flaring 9.3 4,966,089 - 8,510,234 16.7 NG: Large Condensate Tanks w/Flares 1.0 1,063,935 0.1 1,172,292 1.0 NG: Small Condensate Tanks w/Flares + 31,800 0.1 35,039 + Petro: Large Oil Tanks w/Flares 8.2 3,859,139 0.2 7,281,742 15.6 Petro: Small Oil Tanks w/Flares + 11,215 0.1 21,161 + Associated Gas 21.6 7,312,187 - 9,102,967 26.9 Petro: Associated Gas Flaring 21.6 7,312,187 0.3 9,102,967 26.9 NG: Flared Gas Well Completions and Workovers 2.1 135,343 - 186,054 2.3 HF Completions - Non-REC with Flaring + 8,872 0.2 8,710 + HF Completions - REC with Flaring 2.1 110,800 1.9 110,998 2.1 Non-HF Completions - flared + 1,876 0.2 16,407 + HF Workovers - Non-REC with Flaring + 279 0.4 10,669 + HF Workovers - REC with Flaring + 1,582 0.2 33,436 0.1 Non-HF Workovers - flared 0 11,933 0 5,836 0 Petro: Flared Oil Well HF Completions and Workovers 18.2 757,150 - 4,382 + HF Completions - Non-REC with Flaring 0.3 136,782 0.2 4,365b + HF Completions - REC with Flaring 17.9 618,126 2.9 16b + HF Workovers - Non-REC with Flaring + 2,024 0.1 NEb + HF Workovers - REC with Flaring 0 218 0 NEb 0 Miscellaneous Production Flaring 7.7 2,633,587 - 3,583,254 10.4 NG 3.3 991,718 0.3 1,128,617 3.8 Petro 4.4 1,641,869 0.3 2,454,637 6.6 Well Testing + 13,800 - 34,803 0.1 NG 0 220 0 323 0 Petro + 13,580 0.2 34,481 0.1 Gathering and Boosting 25.9 5,930,105 - 225,373 1.0 Gathering and Boosting Stations 25.9 5,930,105ฐ 0.4 225,373bc 1.0 Page 12 of 27 ------- June 2018 GHGRP Flaring Estimated Emission Source GHGRP N20 C02 Ratio of 2018 GHGI National (as reported)3 (as reported) N20:C02 CO2 Total N2O (mt) (mt) (xl00,000) (mt) (mt) Offshore Production 10.9 457,617 - - - Offshore Flaring 10.9 457,617 2.4 368,840d 10.9d Natural Gas Processing Flare Stacks 10.4 3,621,791 0.3 5,404,328 15.5 Transmission and Storage Transmission Station Flare Stacks + 25,116 0.05 88,409 + Storage Station Flare Stacks + 2,343 0.2 15,307 + LNG Storage Station Flare Stacks + 2,506 _e NE +e LNG Import/Export Station Flare Stacks 0.2 97,940 _e NE 0.2e Petroleum Refining Flare Stacks 36.0 3,604,229 1.0 3,604,229 36.0 NE - Not estimated + Does not exceed 0.05 mt a - For gas well and oil well completions and workovers, access to flaring N20 data via EPA's Envirofacts portal is not working correctly and is being fixed. b - Current GHGI does not rely on subpart W data for this source, and 2018 GHGI estimated C02 emissions shown in this table do not fully account for combustion. Using C02 emissions estimates developed under the draft subpart W-based approaches discussed in this memo, national N20 emissions would be approximately 53 mt for flared oil well HF completions and workovers and 28 mt for G&B station flaring, c - C02 includes vented and fugitive sources, in addition to flared sources. d - Current GHGI does not rely on subpart W data for this source. As the GHGRP reported C02 emissions exceed the current GHGI estimate, the as-reported GHGRP N20 emissions are shown. e - Current GHGI does not estimate flaring C02 from these sources. Therefore, as-reported GHGRP N20 emissions are shown as surrogate for national estimates. Section 6 discusses updates under consideration for this segment to use GHGRP data, but EPA has not yet developed updated draft estimates of national C02 emissions. 5 Transmission Pipeline Blowdowns Updates Under Consideration As discussed in Section 1, transmission pipeline blowdowns were newly required to be reported in RY2016. EPA analyzed the RY2016 subpart W data for this source as an initial step for considering potential updates to the existing GHGI methodology. 5.1 Current GHGI Methodology The current GHGI shows emissions from transmission pipeline blowdowns as "pipeline venting for routine maintenance and upsets." Emissions are calculated using a CH4 EF from GRI/EPA 1996 and annual transmission pipeline miles from the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA). C02 emissions are calculated from the CH4 emission factor and a default downstream gas profile of 93.4% CH4 and 1.0% C02. 5.2 Analysis of Available Data EPA calculated a transmission pipeline blowdown EF from the subpart W data by summing the reported emissions and dividing by the reported transmission pipeline miles. Table 15 shows the calculated subpart W EF compared to the current GHGI EF. Note, the subpart W RY2016 data reflect approximately 50% of the total transmission pipeline mileage estimated in the current GHGI for year 2016 (147,000 of 300,000 miles). Table 15. Emission Factors (mt/pipeline mile) Calculated from Subpart W Compared to Current GHGI, for Year 2016 Data Source CH4 CO2 2018 GHGI 0.6 0.01 Subpart W 1.2 0.02 Page 13 of 27 ------- June 2018 6 Liquefied Natural Gas (LNG) Facility Updates Under Consideration GHGI emissions estimates for LNG facilities have not been updated in recent years. Below, EPA summarizes the current methodology and available subpart W data that might be used to improve the current GHGI estimates. 6.1 Current GHGI Methodology The current GHGI estimates emissions from LNG storage stations and LNG import terminals in the transmission and storage segment of natural gas systems. Each LNG facility type estimate includes estimates for station fugitives, reciprocating and centrifugal compressor fugitives, compressor exhaust, and station venting (i.e., blowdowns). The GHGI uses the same source-specific EFs for both LNG storage stations and LNG import terminals. The EFs are based on the 1996 GRI/EPA study, which developed EFs using underground natural gas storage and transmission compressor station data. Specific emissions data for LNG storage stations and LNG import terminals were not available in the GRI/EPA study. The GHGI considers both complete storage stations and satellite facilities (that do not perform liquefaction) to calculate activity data for LNG storage stations. The GHGI assumes that satellite facilities have approximately one- third of the equipment found at complete storage stations, and thus only includes one-third of the satellite facility count in the emissions calculations. Complete storage station and satellite facility counts are available for 1993 and 2003.8 Storage station counts for years before 2003 are calculated by applying linear interpolation between the 1993 and 2003 values. Storage station counts for years after 2003 are set equal to the 2003 counts. The count of reciprocating and centrifugal compressors are estimated by applying a certain ratio of compressors per plant. Compressor exhaust activity data are estimated by applying a certain ratio of hp-hr per facility throughput. The GHGI determines LNG import terminal counts using data available from FERC.9 The terminal counts include onshore and offshore facilities. FERC provides both import and export terminal data, but only import terminals are considered for the GHGI, since export terminals have only recently been constructed in the U.S. The GHGI also reduces the count of reported import terminals from FERC by 30%, assuming that import terminals have approximately two-thirds of the equipment found at complete facilities (as they do not perform liquefaction). Compressor counts and exhaust activity data are determined in the same manner as for LNG storage, applying ratios. 6.2 Analysis of Available Data Subpart W of the EPA's Greenhouse Gas Reporting Program (GHGRP) collects data from LNG storage and LNG import and export facilities that meet a reporting threshold of 25,000 metric tons of C02 equivalent (MT C02e) emissions. Subpart W collects emissions and activity data for centrifugal and reciprocating compressors, and equipment leaks for LNG storage and LNG import and export facilities. Subpart W also collects blowdown emissions for LNG import and export facilities. Facilities began reporting flare emissions under a unique flare stacks source starting in RY2015; in prior RYs, compressor flaring emissions were reported with the centrifugal and reciprocating compressor emissions data. The subpart W emission calculation methodologies for each emission source are: Reciprocating compressor vented/fugitive emissions are calculated using direct leak measurement for the following major component sources: rod packing emissions (in operating mode), blowdown valve emissions (in operating mode and standby, pressurized mode), and isolation valve emissions (in not 8 Energy Information Administration, Department of Energy. "US LNG Markets and Uses." 2004. Available at http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2004/lng/lng2004.pdf. 9 FERC. "North American LNG Import/Export Terminals - Existing." Available at http://www.ferc.gov/industries/gas/indus- act/lng/lng-existing.pdf. Page 14 of 27 ------- June 2018 operating, depressurized mode). Facilities use the measured leak rate data in conjunction with relevant hours of operation in each compressor mode to determine annual emissions. Centrifugal compressor vented/fugitive emissions are calculated using direct leak measurement for the following major component sources: wet seal oil degassing emissions (in operating mode), blowdown valve emissions (in operating mode), and isolation valve emissions (in not operating, depressurized mode). Facilities use the measured leak rate data in conjunction with relevant hours of operation in each compressor mode to determine annual emissions. Equipment leak emissions are calculated using leak surveys or population counts, depending on the component type. o Leak surveys: Applicable to valves, connectors, pump seals, and other components. Facilities use leaking component counts, the time each component is leaking (hours), and component-specific "leaker" EFs to calculate emissions. Facilities conduct leak surveys to determine the number of leaking components. The component-specific leaker EFs provided in subpart W were developed using light liquid data for (synthetic organic chemical manufacturing industry (SOCMI) facilities from the Protocol for Equipment Leaks.10 o Population counts: For vapor recovery compressors, facilities use the total number of compressors and their operating hours in a year, coupled with the population EF, to calculate emissions. Flare emissions are calculated in subpart W using a continuous flow measurement device or engineering calculations, the gas composition, and the flare combustion efficiency. A default flare combustion efficiency of 98% may be applied, if manufacturer data are not available. A coverage analysis comparing RY2015 GHGRP data to U.S. Department of Energy (DOE) data shows that 86% of the LNG import facilities, 100% of the LNG export facilities, and 10% of LNG storage capacity are GHGRP reporters. Comparisons of the current GHGI and reported subpart W CH4 and C02 emissions, including average emissions per station, are presented in Table 16 and Table 17. Subpart W C02 emissions are higher starting in 2015 due to the new flare stacks reporting requirements, as discussed in Section 1. Table 16. LNG Storage and LNG Import/Export Terminal CH4 Emissions Comparison Source 2011 2012 2013 2014 2015 2016 LNG Storage 2018 GHGI CH4 Emissions (mt) 73,124 73,124 73,124 73,124 73,124 73,124 # Stations3 70 70 70 70 70 70 CH4 EF (mt/station) 1,041 1,041 1,041 1,041 1,041 1,041 Subpart W (as reported) CH4 Emissions (mt) 67 10 31 17 70 152 # Stations 4 4 3 4 5 5 CH4 EF (mt/station) 17 2 10 4 14 30 LNG Import/Export Terminals 2018 GHGI (Import Terminals) CH4 Emissions (mt) 15,681 12,377 10,902 10,190 10,801 10,741 #Terminals 8 8 8 8 8 8 CH4 EF (mt/terminal) 2,036 1,607 1,416 1,323 1,403 1,395 10 EPA. Protocol for Equipment Leak Emission Estimates. Emission Standards Division. U.S. EPA. SOCMI, Table 2-7. November 1995. Page 15 of 27 ------- June 2018 Source 2011 2012 2013 2014 2015 2016 Subpart W - Import Terminals (as reported)13 Cm Emissions (mt) 2,481 2,151 1,249 6,939 650 18,470 #Terminals 7 7 7 6 6 4 Cm EF (mt/terminal) 354 307 178 1,156 108 4,618 Subpart W - Export Terminals (as reported)c Cm Emissions (mt) 1,826 1,990 1,572 1,067 801 2.0 #Terminals 1 1 1 1 1 1 Cm EF (mt/terminal) 1,826 1,990 1,572 1,067 801 2.0 a - 2003 estimate is carried forward for all years. This number reflects all complete storage stations (57) and one-third of the count of satellite stations (39). b - Includes an unknown amount of emissions from export terminals, because two subpart W facilities have both import and export operations, and emissions from both operations are reported together, c - Emissions from the one facility that has only LNG export operations. Table 17. LNG Storage and LNG Import/Export Terminal C02 Emissions Comparison Source 2011 2012 2013 2014 2015 2016 LNG Storage 2018 GHGI CO2 Emissions (mt) 2,409 2,409 2,409 2,409 2,409 2,409 # Stations3 70 70 70 70 70 70 CO2 EF (mt/station) 34 34 34 34 34 34 Subpart W (as reported) CO2 Emissions (mt) 0.5 8 84 74 260 2,507 # Stations 4 4 3 4 5 5 CO2 EF (mt/station) 0.1 2 28 19 52 501 LNG Import/Export Terminals 2018 GHGI (Import Terminals) CO2 Emissions (mt) 300 300 300 300 300 300 #Terminals 8 8 8 8 8 8 CO2 EF (mt/terminal) 39 39 39 39 39 39 Subpart W - Import Terminals (as reported)13 CO2 Emissions (mt) 36 6 5 8 77,432 98,753 #Terminals 7 7 7 6 6 4 CO2 EF (mt/terminal) 5 1 1 1 12,905 24,688 Subpart W - Export Terminals (as reported)c CO2 Emissions (mt) 58 45 31 23 0 58 #Terminals 1 1 1 1 1 1 CO2 EF (mt/terminal) 58 45 31 23 0 58 a - 2003 estimate is carried forward for all years. This number reflects all complete storage stations (57) and one-third of the count of satellite stations (39). b - Includes an unknown amount of emissions from export terminals, because two subpart W facilities have both import and export operations, and emissions from both operations are reported together, c - Emissions from the one facility that has only LNG export operations. The EPA reviewed the subpart W activity data and calculated activity factors for reciprocating and centrifugal compressors. A comparison of the 2018 GHGI and subpart W activity data for years 2015 and 2016 are presented in Table 18. Note, the subpart W compressor data below includes counts for all compressors, even if the compressor did not operate (e.g., was in standby pressurized mode all year). Page 16 of 27 ------- June 2018 Table 18. LNG Storage and LNG Import/Export Terminal Activity Data Comparison Source 2015 2016 2018 GHGI Subpart W (as reported) 2018 GHGI Subpart W (as reported) LNG Storage # Stations 70 5 70 5 # Recip. Compr. 270 10 270 6 # Recip. Compr. per Station 3.8 2.0 3.8 1.2 Recip. Compr., MMhphr per Compr. 2.1 1.3 2.1 1.1 # Centr. Compr. 64 2 64 1 # Centr. Compr. per Station 0.9 0.4 0.9 0.2 Centr. Compr., MMhphr per Compr. 1.8 12.2 1.8 14.8 LNG Import/Export Terminals #Terminals 8 7 8 5 # Recip. Compr. 37 17 37 16 # Recip. Compr. per Terminal 4.9 2.4 4.9 3.2 Recip. Compr., MMhphr per Compr. 11.6 7.8 11.6 8.2 # Centr. Compr. 7 10 7 9 # Centr. Compr. per Terminal 0.9 1.4 0.9 1.8 Centr. Compr., MMhphr per Compr. 14.1 10.4 14.1 1.2 The EPA might calculate EFs based on the subpart W data for each of the emission sources described above. Linear interpolation could then be applied from the 1992 EFs (based on GRI/EPA) to a recent year EF (such as RY2015 calculated EFs) to calculate EFs over the time series. The current GHGI EFs are not based on data specific to LNG facilities (they are based on data from transmission and storage stations), and therefore, the EPA might also apply subpart W EFs to all years of the GHGI. Subpart W does not collect blowdown data from LNG storage facilities; the EPA could apply the current GHGI EF or use the subpart W LNG import/export blowdown data for this source. The EPA might also develop facility-level EFs using subpart W data due to the minimal emissions from LNG facilities and to allow for straightforward implementation of subpart W data. Compressor exhaust data in the GHGI were evaluated as part of the gas processing segment update in the 2017 GHGI. The EPA retained the existing GHGI EF, but updated the AD to use an activity factor developed from subpart W data. The EPA is considering implementing a similar approach involving developing an updated activity factor on a station level-basis (i.e., MMhp-hr/station) using subpart W data and maintaining the current GHGI EF. Sources of activity data for scaling LNG storage emissions include the national LNG storage database maintained by PHMSA11, and for scaling LNG import/export emissions include the national LNG import/export activity database maintained by EIA.12 EPA plans to investigate these two sources of activity data for use in calculating LNG facility emissions over the 1990-2017 time period. The GHGI does not currently include LNG export terminals while subpart W does require reporting from LNG export terminals. EPA may update the GHGI methodology to include LNG export terminals. FERC identifies three LNG export terminals;13 one that only exports LNG and two that import and export LNG. In addition, several LNG 11 http://www.phmsa.dot.gov/pipeline/library/data-stats/distribution-transmission-and-gathering-lng-and-liquid-annual-data 12 http://energy.gov/fe/downloads/lng-annual-report-2015 13 FERC. "North American LNG Import/Export Terminals - Existing." Available at http://www.ferc.gov/industries/gas/indus-act/lng/lng- existing.pdf. Page 17 of 27 ------- June 2018 export terminals are under construction, are approved for construction, or are proposed to be constructed.1415 LNG export terminals may not have been a significant emissions contributor over most of the GHGI time series, but LNG export emissions may be expected to increase as additional terminals go into operation. 7 Requests for Stakeholder Feedback EPA seeks stakeholder feedback on the approaches under consideration discussed in this memo and the particular questions below. General 1. What other new or upcoming studies might provide useful data to consider for the GHGI, to use as a quality check against GHGRP-based estimates, and/or to supplement GHGRP data? For example, EPA is aware of several DOE-funded field studies being conducted by researchers including GSI Environmental, Inc., Utah State University, Colorado State University, and Houston Advanced Research Center; focused on topics such as component-specific measurements to develop gathering compressor emission factors16; developing nationally representative emission factors for equipment at G&B stations17; and methane emissions rate quantification for natural gas storage wells and fields18. 2. EPA seeks feedback or suggestions on the general approach for incorporating GHGRP data into recently updated GHGI estimates, which has been: Apply existing historical EFs and AFs (e.g., control category splits) for early time series years Apply GHGRP-based EFs and AFs for GHGRP years Develop intermediate EFs and AFs through linear interpolation Apply a basin-level approach for sources with large regional variability and where national-level emissions estimates are impacted by a basin-level versus national level approach (e.g., associated gas venting and flaring, miscellaneous production flaring) Gathering & Boosting Segment (Section 2) 3. What data source(s) and methodology are most appropriate to develop national G&B station and pipeline emissions (both steady-state and episodic) in light of newly available data (GHGRP subpart W and studies)? EPA seeks feedback on whether additional data sources or methods should be considered for specific equipment types for gathering stations (e.g. compressors). 4. For subpart W, which reported G&B activity data elements should be evaluated to assess the fraction of national activity represented in the reporting data (for considerations toward developing appropriate emissions factors that can be combined with available national-level activity data to develop national emission estimates for the GHGI)? a. Does the fraction of national activity represented in subpart W vary by equipment type due to the G&B facility definition (e.g., is it possible that close to 100% of G&B pipeline mileage is represented, but equipment such as G&B compressors or G&B tanks have different coverage)? b. EPA seeks feedback on data sources that provide national-level totals for purposes of considering G&B scaling approaches (e.g., while total gathering pipeline mileage is reported to GHGRP, PHMSA only reports gathering miles for "regulated gathering lines," which is a small subset of the total). 5. EPA seeks feedback on how to consider regional and temporal variability specifically for G&B. 14 FERC. "North American LNG Import/Export Terminals-Approved." Available at https://www.ferc.gov/industries/gas/indus-act/lng/lng- approved.pdf 15 FERC. "North American LNG Export Terminals - Proposed." Available at https://www.ferc.gov/industries/gas/indus-act/lng/lng-proposed- export.pdf 16 https://www.netl.doe.gov/research/oil-and-gas/project-summaries/natural-gas-midstream-projects/fe0029084-gsi 17 https://www.netl.doe.gov/research/oil-and-gas/project-summaries/natural-gas-midstream-projects/fe0029068-csu 18 https://www.netl.doe.gov/research/oil-and-gas/project-summaries/natural-gas-midstream-projects/fe0029085-gsi Page 18 of 27 ------- June 2018 6. EPA seeks feedback on how to consider the subpart W definition of the G&B segment which includes equipment that serves more than one well pad (e.g., tank batteries) that might generally be considered production equipment. EPA notes that the current GHGI approach for developing activity estimates for the production segment relies on data from production segment facilities that report under subpart W, so incorporating data from the subpart W G&B segment facilities should theoretically avoid double-counting. 7. EPA seeks feedback on the level of detail for presenting emissions from gathering and boosting in the GHGI. For example, emissions could be presented by equipment type (similar to how other production segment equipment emissions are presented) or could be presented at the station-level (as in the current GHGI) or at the basin level (as presented in Section 2.5). HF Oil Well Completions and Workovers (Section 3) Note, EPA's 2018 Well-related Activity Data companion memo details further considerations for potentially updating activity data for sources including HF oil well completions and workovers and includes additional stakeholder questions. 8. EPA seeks feedback on the national representativeness of subpart W-based HF oil well completion and workover emissions factors (emissions per event) and activity factors (i.e., allocation of total event counts across four control categories). 9. EPA seeks feedback on how to consider regional and temporal variability for HF oil well completions and workovers. 10. EPA seeks stakeholder feedback on the methodology and assumptions for allocating events into the four control categories across the time series (i.e., control category AFs, as detailed in Section 3.2). Specifically, for years 1990-2007, it is assumed all events are non-REC, and 10% of events flare; in contrast, the GHGI methodology for HF gas well event AFs assumes that RECs are introduced earlier, in year 2000. 11. Historical analyses for HF gas well events data (RY2011-2015) included all HF well event data reported, and therefore might have included reported data from HF oil well events if any reporters reported data from these activities in those years. Should EPA revisit these historical EFs (e.g., discard from the EF data set any events seemingly conducted at oil wells? develop factors specific to oil well events prior to RY2016?)? N2Q Emissions (Section 4) 12. EPA seeks feedback on updating the GHGI to include N20 from flaring, based on GHGRP data. 13. EPA seeks feedback on other available data sources for N20 emissions. Transmission Pipeline Blowdowns (Section 5) 14. EPA seeks feedback on the use of subpart W data to update the current GHGI methodology for this source. 15. Are the EFs calculated from RY2016 subpart W data (shown in Table 15) nationally representative,? 16. EPA seeks feedback on time series calculations; e.g., on whether GHGI EFs be retained for early time series years or if subpart W EFs should be applied for all years. LNG Facilities (Section 6) 17. EPA seeks feedback on time series calculations; e.g., on whether GHGI EFs (which are based on data from transmission and storage stations) should be retained for early time series years or if subpart W EFs should be applied for all years. 18. EPA seeks feedback on how LNG storage blowdown emissions should be incorporated into the GHGI; e.g., maintain the current GHGI EFs or use data from subpart W LNG import/export terminals. 19. EPA seeks feedback on an approach that maintains the current GHGI EF for compressor exhaust, but using subpart W compressor hp-hr data. Page 19 of 27 ------- June 2018 Page 20 of 27 ------- June 2018 Appendix A - Measurement Methodologies from Data Sources Considered for Updates Emission Source Measurement and/or Calculation Type | # Sources Location & Representativeness | EF Calculation Method GHGRP Subpart W Oil Well HF Completions and Workovers Emissions calculated for each event, based on (1) measured actual flowback gas volumes from the well or (2) calculated flowback gas volume based on well parameters (e.g., pressure differentials, temps). If flared, then flare control efficiency is applied. Emissions data (for 2016) are available for 4,059 completions and 330 workover events at HF oil wells Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. For this memo, the EPA used reported data to calculate, event/control category specific (e.g., REC, flare), average EFs G&B Acid gas removal (AGR) vents Emissions calculated from the available methods: (1) CEMS for C02 with volumetric flow rate monitors, (2) Vent meter for C02 and annual volume of vent gas, (3) measured inlet (or outlet) gas flow rate and inlet and outlet volumetric fraction of C02, or (4) simulation software. Emissions data (for 2016) are available from only 49 facilities. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. For this memo, the EPA evaluated the reported data at the basin-level to scale to the national-level. G&B Centrifugal Compressors Emissions calculated using the count of centrifugal compressors that have wet seal oil degassing vents multiplied by default EF (annual volumetric flow per unit). Emissions data (for 2016) are available from 25 facilities. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. For this memo, the EPA evaluated the reported data at the basin-level to scale to the national-level. G&B Combustion Emission calculations depend on the type of fuel burned: If burning pipeline quality natural gas or the identified fuels and blends (i.e., coal, coke, natural gas, petroleum products, certain other solids and gaseous fuels, solids/gaseous/liquid biomass fuels) then use default EFs. If burning field gas, process vent gas, or a gas blend then determine volume of fuel combusted from company records and use a continuous gas composition analyzer to measure mole fraction of gas. These sources are exempt: (1) external fuel combustion sources with rated heat capacity < 5 MMBtu/hr, (2) internal combustion sources, not compressor- drivers, with a rated heat capacity < 1 MMBtu/hr (equal to 130 HP). Emissions data (for 2016) are available from 289 facilities. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. For this memo, the EPA evaluated the reported data at the basin-level to scale to the national-level. Page 21 of 27 ------- June 2018 Emission Source Measurement and/or Calculation Type # Sources Location & Representativeness EF Calculation Method G&B Dehydrators Emissions calculations depend on the daily throughput: If daily throughput is > 0.4 million scf then use simulation software. If daily throughput is < 0.4 million scf then use EFs and a dehydrator count For dessicant dehys, use the amount of gas vented from the dessicant vessel when it is depressurized When a flare or a regenerator fire- box/fire tube is used adjust the emissions to reflect the control efficiency. Emissions data (for 2016) are available from 242 facilities. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. For this memo, the EPA evaluated the reported data at the basin-level to scale to the national-level. G&B Equipment Leaks Emissions calculated using: (1) default EFs, by source type; (2) source type counts (rule provides default counts e.g., valves per wellhead) including miles of gathering pipelines by material type; (3) estimated time the source was operational; and (4) concentration of C02 and CH4. Emissions data (for 2016) are available from 297 facilities. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. For this memo, the EPA evaluated the reported data at the basin-level to scale to the national-level. G&B Pneumatic Devices Emissions calculated using: (1) counts of continuous high bleed, continuous low bleed, and intermittent bleed devices, (2) default EFs for each device type, (3) annual operating hours, and (4) GHG concentrations in vented gas. Emissions data (for 2016) are available from 263 facilities. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. For this memo, the EPA evaluated the reported data at the basin-level to scale to the national-level. G&B Pneumatic Pumps Emissions calculated using: (1) counts of pneumatic pumps, (2) default EF, (3) annual operating hours, and (4) GHG concentrations in vented gas. Emissions data (for 2016) are available from 194 facilities. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. For this memo, the EPA evaluated the reported data at the basin-level to scale to the national-level. G&B Reciprocating Compressors Emissions calculated using the count of reciprocating compressors multiplied by default EF (annual volumetric flow per unit). Emissions data (for 2016) are available from 291 facilities. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. For this memo, the EPA evaluated the reported data at the basin-level to scale to the national-level. G&B Tanks Emissions calculations depend on the daily throughput: If oil throughput is >10 bbl/d and the gas and liquid passes through non- separator equipment (e.g., stabilizers, slug catchers) before flowing to the tank, calculate C02 and CH4 emissions Emissions data (for 2016) are available from 215 facilities. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. For this memo, the EPA evaluated the reported data at the basin-level to scale to the national-level. Page 22 of 27 ------- June 2018 Emission Source Measurement and/or Calculation Type # Sources Location & Representativeness EF Calculation Method using simulation software or by assuming all C02 and CH4 is emitted. If oil throughput is >10 bbl/d and the gas and liquid flows directly to a tank without passing through a separator, assume all C02 and CH4 is emitted. If oil throughput is <10 bbl/d then calculate C02 and CH4 emissions from (1) counts of separators, wells, or non- separator equipment that feed oil directly to the storage tank and multiply by EF (annual volumetric flow per unit). Subtract emissions if a VRU is used and if a flare is used then use the flare calculation methodology. G&B, LNG Storage, & LNG Import/Export - Flare Stacks Emissions calculated using: (1) gas volume sent to the flare, (2) combustion efficiency (from manufacturer or assume 98%), fraction of feed gas sent to an un-lit flare, and (3) gas composition for C02, CH4, and hydrocarbon constituents. G&B: Emissions data (for 2016) are available from 140 facilities. LNG Storage: Emissions data (for 2016) are available from 1 station and a total of 1 flare stack. LNG Import/Export: Emissions data (for 2016) are available from 2 stations and a total of 6 flare stacks. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. G&B: For this memo, the EPA evaluated the reported data at the basin-level to scale to the national- level. G&B & LNG Import/Export - Blowdown Vent Stacks Emissions calculated from the available methods: (1) use blowdown volumes, the number of blowdowns, and the ideal gas law modified with a compressibility factor, or (2) used a flowmeter to directly measure emissions for each equipment type or all equipment associated with a blowdown event. G&B: Emissions data (for 2016) are available from 236 facilities. LNG Import/Export: Emissions data (for 2016) are available from 5 stations and a total of 5 blowdown vent stacks. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. G&B: For this memo, the EPA evaluated the reported data at the basin-level to scale to the national- level. LNG Storage & LNG Import/Export - Equipment Leaks Emissions calculated using: Population counts and EF approach, estimate time emission source was operational, and Leak surveys (>1 per year) to identify leaking components, estimate time assumed to be leaking, and use component type EFs in the rule. LNG Storage: Emissions data (for 2016) are available from 5 stations and a total of 5 leak surveys and population counts. LNG Import/Export: Emissions data (for 2016) are available from 5 stations and a total of 5 leak surveys and population counts. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. EFs not currently calculated. Page 23 of 27 ------- June 2018 Emission Source Measurement and/or Calculation Type # Sources Location & Representativeness EF Calculation Method LNG Storage & LNG Import/Export - Centrifugal Compressors Direct measurement of emissions from: Wet seals, blowdown vents, and isolation valves; or Manifolded groups of compressor sources. LNG Storage: Emissions data (for 2016) are available from 1 station and a total of 1 centrifugal compressor. LNG Import/Export: Emissions data (for 2016) are available from 2 stations and a total of 9 centrifugal compressors. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. EFs not currently calculated. LNG Storage & LNG Import/Export- Reciprocating Compressors Direct measurement of emissions from: Blowdown valves, rod packing, and isolation valves; or Manifolded groups of compressor sources. LNG Storage: Emissions data (for 2016) are available from 2 stations and a total of 6 reciprocating compressors. LNG Import/Export: Emissions data (for 2016) are available from 4 stations and a total of 16 reciprocating compressors. Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. EFs not currently calculated. Transmission Blowdown Vent Stack Emissions calculated using: Blowdown volumes, number of blowdowns, and the ideal gas low modified for compressibility; or Flow meter to measure emissions for all equipment associated with a blowdown event. Blowdown volumes <50 scf are exempt. Emissions data (for 2016) are available from 9,093 blowdowns (which occurred over 147,187 miles). Facilities in the U.S. that exceed 25,000 mt C02e reporting threshold. EFs calculated as a straight average of all available data. Vaughn et al. 2017 G&B facilities Dual-tracer measurements, aircraft measurements, and on-site component- level measurements (direct measurements and simulated direct measurements) coupled with engineering estimates using Monte Carlo model. 36 gathering stations Measurements conducted September-October 2015 Eastern portion of the Fayetteville shale play (Arkansas) Dual-tracer measurements, including and excluding significant tank venting Yacovitch et al. 2017 Production, gathering, processing, and transmission facilities Dual tracer flux ratio method DJ study area: 12 gathering stations, 5 wellpads, and 4 processing plants measured. FV study area: 31 gathering stations, 18 wellpads, and 4 transmission stations measured. Two natural gas production regions: Denver-Julesberg (DJ) basin and Fayetteville shale play (FV) in Arkansas Nov 2014 for DJ basin Sep-Oct 2015 for FV play Dual-tracer measurements to calculate facility-level emission rates and throughput-weighted emissions Page 24 of 27 ------- June 2018 Emission Source Measurement and/or Calculation Type # Sources Location & Representativeness EF Calculation Method Zimmerle et al. 2017 Gathering pipelines Detect and localize pipeline leaks using vehicle-based measurement and handheld equipment Measure leaks: INDACO high flow (using above-ground enclosure for pipelines based on Lamb 2015 study methods) Pigging facilities: 56 locations screened, 50% with measurable emissions Block valves: 39 locations screened, 15% with measurable emissions Pipeline leaks: 96 km screened, 1 leak detected Measurements conducted September-October 2015 Fayetteville shale play (Arkansas) Measured leaks from underground pipelines and above-ground auxiliary equipment Monte Carlo approach used to estimate total study area methane emissions Page 25 of 27 ------- June 2018 Appendix B - Subpart W Reported Basin-Level G&B Data, for Year 2016 (descending by quantity gas received) Subpart W: Basin Subpart W: Station - C02 (mt) Subpart W: Station - CH4 (mt) Subpart W: Pipeline - C02 (mt) Subpart W: Pipeline - CH4 (mt) Subpart W: % of Total Reported Emissions (C02e basis) Subpart W: Pipeline Miles Subpart W: Quantity Gas Received (mscf) Drillinglnfo: Gas Produced (mscf) 430 - Permian Basin 2,357,782 114,330 2,049 47,841 22% 88,779 9,377,991,907 2,546,961,000 160A - Appalachian Basin (Eastern Overthrust Area) 237,240 43,632 64 9,330 5% 21,491 9,085,887,678 6,963,307,185 220 - Gulf Coast Basin (LA, TX) 1,427,659 180,859 303 7,304 21% 77,306 4,671,449,082 3,061,920,423 890 - Arctic Coastal Plains Province 282,030 8,988 440 1,013 2% 466 2,631,488,269 0 360 - Anadarko Basin 179,505 205,913 330 21,148 20% 79,855 2,378,161,495 1,712,080,076 230 - Arkla Basin 78,662 15,870 77 675 2% 5,473 1,572,948,899 1,383,010,956 345 - Arkoma Basin 91,957 42,829 166 3,169 4% 9,485 1,446,997,239 1,152,833,455 535 - Green River Basin 38,600 12,137 102 2,767 1% 7,367 1,217,043,594 1,320,824,691 580 - San Juan Basin 33,580 27,635 313 2,270 3% 12,654 1,117,052,404 950,371,313 415 - Strawn Basin 92,667 7,816 13 212 1% 3,057 1,112,322,086 790,688,219 260 - East Texas Basin 27,507 26,385 213 2,933 3% 14,157 1,088,736,072 1,231,438,252 595 - Piceance Basin 22,749 5,520 1,140 2,293 1% 3,483 921,296,725 572,215,719 160 - Appalachian Basin 29,102 7,777 169 18,288 2% 11,710 678,462,313 327,688,787 395 - Williston Basin 556,431 12,340 189 3,046 3% 14,102 649,086,818 649,228,154 420 - Fort Worth Syncline 29,816 7,451 83 779 1% 8,657 601,323,784 596,143,279 540 - Denver Basin 82,700 12,371 40 1,065 1% 9,069 600,318,419 654,717,466 210 - Mid-Gulf Coast Basin 13,705 634 16 31 0% 50 586,701,993 266,348,942 350 - South Oklahoma Folded Belt 11,420 9,867 116 3,990 1% 6,194 385,990,762 196,332,085 575 - Uinta Basin 24,127 10,889 165 6,085 2% 4,502 334,179,136 330,771,548 507 - Central Western Overthrust 87 916 0 52 0% 744 324,760,269 144,840,092 355 - Chautauqua Platform 9,010 6,726 32 2,318 1% 8,344 227,037,752 167,058,005 745 - San Joaquin Basin 137,854 5,223 2,243 4,423 1% 2,282 192,211,752 146,297,127 515 - Powder River Basin 21,014 4,843 449 5,811 1% 6,404 177,702,150 276,528,876 305 - Michigan Basin 4,883 10,543 83 245 1% 1,185 70,799,977 114,012,350 820 - AK Cook Inlet Basin 2,323 666 0 14 0% 172 67,195,723 69,286,251 455 - Las Vegas-Raton Basin 91,527 2,543 16 885 1% 1,286 59,160,425 102,155,261 425 - Bend Arch 196 1,495 18 1,195 0% 4,335 39,409,305 35,370,315 375 - Sedgwick Basin 117 1,131 5 743 0% 1,498 38,192,792 56,061,331 730 - Sacramento Basin 36 3,929 8 1,291 0% 540 16,453,024 67,915,824 740 - Coastal Basins 181 121 64 118 0% 59 6,974,637 1,919,724 450 - Las Animas Arch 30 243 0 24 0% 360 6,089,722 8,200,509 530 - Wind River Basin 6 142 0 3 0% 45 5,731,782 166,238,346 760 - Los Angeles Basin 19,331 607 15 71 0% 58 5,360,745 58,536,331 755 - Ventura Basin 25,813 419 43 490 0% 266 3,178,610 6,139,904 Page 26 of 27 ------- June 2018 Subpart W: % of Subpart W: Subpart W: Subpart W: Subpart W: Total Reported Subpart W: Subpart W: Station - C02 Station - Pipeline - Pipeline - CH4 Emissions (C02e Pipeline Quantity Gas Drillinglnfo: Gas Subpart W: Basin (mt) CH4 (mt) C02 (mt) (mt) basis) Miles Received (mscf) Produced (mscf) 365 - Cherokee Basin 457 4,054 2 88 0% 232 3,103,595 23,594,565 845 - Bristol Bay Basin 0 0 0 0 0% 0 0 2,777,440,868 585 - Paradox Basin 0 0 0 0 0% 0 0 500,632,196 445 - Sierra Grande Uplift 0 0 0 0 0% 0 0 97,122,899 200 - Black Warrior Basin 0 0 0 0 0% 0 0 55,702,726 400 - Ouachita Folded Belt 0 0 0 0 0% 0 0 46,874,613 520 - Big Horn Basin 0 0 0 0 0% 0 0 13,359,240 750 - Santa Maria Basin 0 0 0 0 0% 0 0 8,202,838 500 - Sweetgrass Arch 0 0 0 0 0% 0 0 7,773,963 435 - Palo Duro Basin 1 24 0 2 0% 47 0 5,317,449 510 - Central Montana Uplift 0 0 0 0 0% 0 0 4,048,704 385 - Central Kansas Uplift 0 0 0 0 0% 0 0 2,872,248 250 - Upper Mississippi Embayment 0 0 0 0 0% 0 0 1,053,875 630 - Overthrust&Wasatch Uplift 0 0 0 0 0% 0 0 803,882 300 - Cincinnati Arch 0 0 0 0 0% 0 0 762,456 710 - Western Columbia Basin 0 0 0 0 0% 0 0 581,536 545 - North Park Basin 0 0 0 0 0% 0 0 387,513 720 - Eel River Basin 0 0 0 0 0% 0 0 356,368 405 - Kerr Basin 0 0 0 0 0% 0 0 160,190 315 - Illinois Basin 0 0 0 0 0% 0 0 99,929 370 - Nemaha Anticline 0 0 0 0 0% 0 0 70,568 335 - Forest City Basin 0 0 0 0 0% 0 0 57,665 590 - Black Mesa Basin 0 0 0 0 0% 0 0 51,567 140 - Florida Platform 0 0 0 0 0% 0 0 33,177 725 - Northern Coast Range Prov 0 0 0 0 0% 0 0 22,803 625 - Great Basin Province 0 0 0 0 0% 0 0 2,858 640 - Mojave Basin 0 0 0 0 0% 0 0 589 650 - Sierra Nevada Province 0 0 0 0 0% 0 0 273 Total 5,930,105 796,868 2,049 47,841 100% 405,714 41,700,800,934 29,674,829,356 Page 27 of 27 ------- |