Vol. 79 Tuesday, No. 236 December 9, 2014

Part II

Environmental Protection Agency

40 CFR Part 98 Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule

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ENVIRONMENTAL PROTECTION Mailcode 28221T, Attention Docket ID information identified as CBI to only the AGENCY No. EPA–HQ–OAR–2014–0831, 1200 mail or hand/courier delivery address Pennsylvania Avenue NW., Washington, listed above, attention: Docket ID No. 40 CFR Part 98 DC 20460. In addition, please mail a EPA–HQ–OAR–2014–0831. If you have [EPA–HQ–OAR–2014–0831; FRL—9918–48– copy of your comments on the any questions about CBI or the OAR] information collection provisions to the procedures for claiming CBI, please Office of Information and Regulatory consult the person identified in the FOR RIN 2060–AS37 Affairs, Office of Management and FURTHER INFORMATION CONTACT section. Budget (OMB), Attn: Desk Officer for Greenhouse Gas Reporting Rule: 2015 Do not submit information that you EPA, 725 17th Street, NW., Washington, Revisions and Confidentiality consider to be CBI or otherwise DC 20503. Determinations for Petroleum and protected through http:// • Hand/Courier Delivery: EPA Docket Natural Gas Systems www.regulations.gov or email. The Center, Room 3334, EPA WJC West http://www.regulations.gov Web site is AGENCY: Environmental Protection Building, 1301 Constitution Avenue an ‘‘anonymous access’’ system, which Agency. NW., Washington, DC 20004. Such means the EPA will not know your ACTION: Proposed rule. deliveries are accepted only during the identity or contact information unless normal hours of operation of the Docket you provide it in the body of your SUMMARY: The Environmental Protection Center, and special arrangements should comment. If you send an email Agency (EPA) is proposing revisions be made for deliveries of boxed comment directly to the EPA without and confidentiality determinations for information. going through http:// the petroleum and natural gas systems Additional Information on Submitting www.regulations.gov your email address source category of the Greenhouse Gas Comments: To expedite review of your will be automatically captured and Reporting Program. In particular, the comments by agency staff, you are included as part of the comment that is EPA is proposing to add calculation encouraged to send a separate copy of placed in the public docket and made methods and reporting requirements for your comments, in addition to the copy available on the Internet. If you submit greenhouse gas emissions from you submit to the official docket, to an electronic comment, the EPA gathering and boosting facilities, Carole Cook, U.S. EPA, Office of recommends that you include your completions and workovers of oil wells Atmospheric Programs, Climate Change name and other contact information in with hydraulic fracturing, and Division, Mail Code 6207A, 1200 the body of your comment and with any blowdowns of natural gas transmission Pennsylvania Avenue NW., Washington, disk or CD–ROM you submit. If the EPA pipelines between compressor stations. DC 20460, telephone (202) 343–9263, cannot read your comment due to The EPA is also proposing well email address: GHGReportingRule@ technical difficulties and cannot contact identification reporting requirements to epa.gov. you for clarification, the EPA may not improve the EPA’s ability to verify Instructions: Direct your comments to be able to consider your comment. reported data and enhance Docket ID No. EPA–HQ–OAR–2014– Electronic files should avoid the use of transparency. This action also proposes 0831, Greenhouse Gas Reporting Rule: special characters, any form of confidentiality determinations for new 2015 Revisions and Confidentiality data elements contained in these Determinations for Petroleum and encryption, and be free of any defects or proposed amendments. Natural Gas Systems; Proposed Rule. viruses. Docket: All documents in the docket DATES: The EPA’s policy is that all comments Comments must be received on are listed in the http:// or before February 9, 2015. received will be included in the public www.regulations.gov index. Although Public Hearing. The EPA does not docket without change and may be listed in the index, some information is plan to conduct a public hearing unless made available online at http:// requested. To request a hearing, please www.regulations.gov, including any not publicly available, e.g., CBI or other contact the person listed in the personal information provided, unless information whose disclosure is restricted by statute. Certain other following FOR FURTHER INFORMATION the comment includes information material, such as copyrighted material, CONTACT section by December 16, 2014. claimed to be confidential business If requested, the hearing will be information (CBI) or other information will be publicly available only in hard conducted on December 24, 2014, in the whose disclosure is restricted by statute. copy. Publicly available docket Washington, DC area. The EPA will Should you choose to submit materials are available either provide further information about the information that you claim to be CBI, electronically in http:// hearing on the Greenhouse Gas clearly mark the part or all of the www.regulations.gov or in hard copy at Reporting Program Web site, http:// information that you claim to be CBI. the Air Docket, EPA/DC, WJC West www.epa.gov/ghgreporting/index.html if For information that you claim to be CBI Building, Room 3334, 1301 Constitution a hearing is requested. in a disk or CD–ROM that you mail to Ave., NW., Washington, DC. This Docket Facility is open from 8:30 a.m. ADDRESSES: Submit your comments, the EPA, mark the outside of the disk or to 4:30 p.m., Monday through Friday, identified by Docket ID No. EPA–HQ– CD–ROM as CBI and then identify excluding legal holidays. The telephone OAR–2014–0831 by any of the following electronically within the disk or CD– number for the Public Reading Room is methods: ROM the specific information that is • Federal eRulemaking Portal: http:// claimed as CBI. In addition to one (202) 566–1744, and the telephone www.regulations.gov. Follow the online complete version of the comment that number for the Air Docket is (202) 566– instructions for submitting comments. includes information claimed as CBI, a 1742. • Email: [email protected]. copy of the comment that does not FOR FURTHER INFORMATION CONTACT: Include Docket ID No. EPA–HQ–OAR– contain the information claimed as CBI Carole Cook, Climate Change Division, 2014–0831 or RIN No. 2060–AS37 in the must be submitted for inclusion in the Office of Atmospheric Programs (MC– subject line of the message. public docket. Information marked as 6207A), Environmental Protection • Fax: (202) 566–9744. CBI will not be disclosed except in Agency, 1200 Pennsylvania Ave. NW., • Mail: Environmental Protection accordance with procedures set forth in Washington, DC 20460; telephone Agency, EPA Docket Center (EPA/DC), 40 CFR part 2. Send or deliver number: (202) 343–9263; fax number:

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(202) 343–2342; email address: Following the Administrator’s signature, 307(d) apply to ‘‘such other actions as [email protected]. For a copy of this action will be posted on the Administrator may determine’’). technical information, please go to the the EPA’s Greenhouse Gas Reporting These are proposed amendments to Greenhouse Gas Reporting Program Web Program Web site at http:// existing regulations. If finalized, these site, http://www.epa.gov/ghgreporting/ www.epa.gov/ghgreporting/index.html. amended regulations would affect index.html. To submit a question, select SUPPLEMENTARY INFORMATION: owners or operators of petroleum and Help Center, followed by ‘‘Contact Us.’’ Regulated Entities. The Administrator natural gas systems that directly emit Worldwide Web (WWW). In addition determined that this action is subject to greenhouse gases (GHGs). Regulated to being available in the docket, an the provisions of Clean Air Act (CAA) categories and entities include those electronic copy of today’s proposal will section 307(d). See CAA section listed in Table 1 of this preamble: also be available through the WWW. 307(d)(1)(V) (the provisions of section

TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY

Category NAICS a Examples of affected facilities

Petroleum and Natural Gas Systems ...... 486210 Pipeline transportation of natural gas. 221210 Natural gas distribution. 211111 Crude petroleum and natural gas extraction. 211112 Natural gas liquid extraction. a North American Industry Classification System.

Table 1 of this preamble is not PPDM Professional Petroleum Data B. Impacts of the Proposed Amendments intended to be exhaustive, but rather Management on Small Businesses provides a guide for readers regarding REC reduced emission completion V. Statutory and Executive Order Reviews facilities likely to be affected by this RFA Regulatory Flexibility Act A. Executive Order 12866: Regulatory Planning and Review and Executive action. Other types of facilities than SBA Small Business Administration SBREFA Small Business Regulatory Order 13563: Improving Regulation and those listed in the table could also be Enforcement and Fairness Act Regulatory Review subject to reporting requirements. To U.S. United States B. Paperwork Reduction Act determine whether you are affected by UMRA Unfunded Mandates Reform Act of C. Regulatory Flexibility Act this action, you should carefully 1995 D. Unfunded Mandates Reform Act examine the applicability criteria found E. Executive Order 13132: Federalism in 40 CFR part 98, subpart A and 40 Organization of This Document. The F. Executive Order 13175: Consultation CFR part 98, subpart W. If you have following outline is provided to aid in and Coordination With Indian Tribal questions regarding the applicability of locating information in this preamble. Governments G. Executive Order 13045: Protection of this action to a particular facility, I. Background Children From Environmental Health consult the person listed in the A. Organization of This Preamble Risks and Safety Risks preceding FOR FURTHER INFORMATION B. Background on the Proposed Action H. Executive Order 13211: Actions That CONTACT section. C. Legal Authority Significantly Affect Energy Supply, Acronyms and Abbreviations. The D. How would these amendments apply to Distribution, or Use following acronyms and abbreviations 2015 and 2016 reports? I. National Technology Transfer and are used in this document. II. Revisions and Other Amendments Advancement Act A. Oil Wells With Hydraulic Fracturing J. Executive Order 12898: Federal Actions API American Petroleum Institute B. Onshore Petroleum and Natural Gas To Address Environmental Justice in BAMM best available monitoring methods Gathering and Boosting Segment Minority Populations and Low-Income Btu British thermal unit C. Natural Gas Transmission Lines Populations CAA Clean Air Act Between Compressor Stations CBI confidential business information D. Well Identification Numbers I. Background CFR Code of Federal Regulations E. Advanced Innovative Monitoring A. Organization of This Preamble CO2 carbon dioxide Methods CO e carbon dioxide equivalent 2 F. Best Available Monitoring Methods EPA Environmental Protection Agency The first section of this preamble III. Proposed Confidentiality Determinations EIA Energy Information Administration provides background information A. Overview and Background FERC Federal Energy Regulatory regarding the proposed amendments. Commission B. Approach to Proposed CBI This section also discusses the EPA’s FR Federal Register Determinations legal authority under the CAA to GHG greenhouse gas C. Proposed Confidentiality Determinations for Data Elements promulgate and amend 40 CFR part 98 GHGRP Greenhouse Gas Reporting Program (hereafter referred to as ‘‘Part 98’’) as GOR gas-to-oil ratio Assigned to the ‘‘Unit/Process ‘Static’ ICR Information Collection Request Characteristics That Are Not Inputs to well as the legal authority for making ISBN International Standard Book Number Emission Equations’’ and ‘‘Unit/Process confidentiality determinations for the LDC local distribution company Operating Characteristics That Are Not data to be reported. Section II of this MMscfd million standard cubic feet per day Inputs to Emission Equations’’ Data preamble contains information on the NAICS North American Industry Categories proposed revisions to 40 CFR part 98, Classification System D. Other Proposed Case-by-Case subpart W (hereafter referred to as NESHAP national emission standards for Confidentiality Determinations for ‘‘subpart W’’). Section III of this Subpart W hazardous air pollutants preamble discusses proposed NGO non-government organization E. Request for Comments on Proposed NGPA Natural Gas Policy Act Confidentiality Determinations confidentiality determinations for new NTTAA National Technology Transfer and IV. Impacts of the Proposed Amendments to data reporting elements. Section IV of Advancement Act of 1995 Subpart W this preamble discusses the impacts of OMB Office of Management and Budget A. Costs of the Proposed Amendments the proposed amendments to subpart W.

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Finally, Section V of this preamble reporting of a well identification Gas Reporting Rule: Technical Support describes the statutory and executive number for oil and gas wells covered in for 2015 Revisions and Confidentiality order requirements applicable to this the Onshore Petroleum and Natural Gas Determinations for Petroleum and action. Production segment. Natural Gas Systems; Proposed Rule’’ in The EPA is proposing these changes Docket ID No. EPA–HQ–OAR–2014– B. Background on the Proposed Action for several reasons. First, we have been 0831. If finalized, this rule would The EPA’s Greenhouse Gas Reporting working to enhance the quality of data further the EPA’s goal of improving the Program (GHGRP) requires annual from petroleum and natural gas systems completeness, quality, accuracy, and reporting of GHG data and other gathered through Part 98, because it has transparency of data from this sector (79 relevant information from large sources been an important tool for the EPA and FR 74484, November 30, 2010), and suppliers in the United States. On the public to analyze emissions, identify improving the ability of agencies and October 30, 2009, the EPA published opportunities for improving the data, the public to use these GHG data to Part 98 for collecting information and understand emissions trends. One analyze emissions and understand regarding GHG emissions from a broad of the strengths of the GHGRP’s emission trends. Adding well range of industry sectors (74 FR 56260). petroleum and natural gas systems data identification numbers to the required Although reporting requirements for is that it provides a better understanding reporting for oil and gas wells covered petroleum and natural gas systems were of sources in the petroleum and natural by the Onshore Petroleum and Natural originally proposed to be part of Part 98 gas industry for which the public Gas Production segment would enable (75 FR 16448, April 10, 2009), the final previously had little information. For the EPA and other stakeholders to October 2009 rule did not include the example, the data that would be directly match data for reported wells petroleum and natural gas systems collected through these proposed with other local, state, and federal source category as one of the 29 source revisions could inform updates to the permitting and data reporting categories for which reporting Inventory of U.S. Greenhouse Gas information, as it is the common requirements were finalized. The EPA Emissions and Sinks 1 (hereafter referred identification number used for wells in re-proposed subpart W in 2010 (79 FR to as the ‘‘U.S. GHG Inventory’’). These the United States (U.S.). 18608; April 12, 2010), and a proposed revisions reflect the fact that Second, a key element of the subsequent final rule was published on this sector has been growing and President’s Climate Action Plan is the November 30, 2010, with the changing rapidly since the GHGRP’s Strategy to Reduce Methane Emissions, requirements for the petroleum and petroleum and natural gas systems which the Administration announced natural gas systems source category at requirements were originally on March 28, 2014. 2 The strategy 40 CFR part 98, subpart W (75 FR promulgated in 2010. Greenhouse gas summarizes the sources of methane 74458) (hereafter referred to as ‘‘the reporting from gathering and boosting emissions, commits to new steps to cut final subpart W rule’’). Following systems was proposed in 2010 but was emissions of this potent greenhouse gas, promulgation, the EPA finalized actions not finalized due to the need to conduct and outlines the Administration’s efforts revising subpart W (76 FR 22825, April additional analysis. Emissions from the to improve the measurement of these 25, 2011; 76 FR 59533, September 27, sources the EPA is proposing to include emissions. The strategy builds on 2011; 76 FR 80554, December 23, 2011; are not reported under the GHGRP with progress to date and takes steps to 77 FR 51477, August 24, 2012; 78 FR the exception of emissions from further cut methane emissions from 25392, May 1, 2013; 78 FR 71904, completions and workovers of oil wells several sectors, including the oil and November 29, 2013; 79 FR 63750, with hydraulic fracturing that are flared natural gas sector. In this strategy, the October 24, 2014; 79 FR 70352, and emissions from sources in the EPA was specifically tasked with November 25, 2014). Onshore Petroleum and Natural Gas continuing to review regulatory In this current proposal, the EPA is Gathering and Boosting segment that are requirements to address potential gaps proposing to amend subpart W to required to report as combustion in coverage, improve methods, and help require the reporting of GHG emissions sources under subpart C of Part 98. ensure high quality data reporting. The from several sources that have not Aside from those exceptions, which proposed revisions to subpart W previously been included in subpart W. only include emissions associated with covered in this action would address These sources include oil well combustion and do not capture the data gaps, specify methods for completions and workovers with majority of methane emissions from measuring methane emissions, and hydraulic fracturing, petroleum and these sources, a nationally provide data that could be used to natural gas gathering and boosting comprehensive data set of the emissions further analyze methane emissions in systems, and transmission pipeline from the sources the EPA is proposing this industry. blowdowns between compressor to include does not currently exist in Third, on March 19, 2013, the EPA stations. The proposed reporting the public domain. The EPA anticipates received a petition from a group of non- requirements for oil well completions that these emission sources will be an government organizations (NGOs) and workovers with hydraulic fracturing important part of establishing a asking that the EPA collect data from would be included as part of the comprehensive data set for the emissions sources not currently existing Onshore Petroleum and Natural petroleum and natural gas industry included in subpart W, including well Gas Production industry segment. For based on data available in the U.S. GHG completion emissions from oil wells the other sources, the EPA is proposing Inventory and other sources. For more that co-produce natural gas, facilities two new industry segments: the information, please see ‘‘Greenhouse and pipelines in the gathering and Onshore Petroleum and Natural Gas boosting segment, and transmission Gathering and Boosting segment for 1 U.S. Environmental Protection Agency. pipeline blowdown events, because petroleum and natural gas gathering and Inventory of U.S. Greenhouse Gas Emissions and these sources could be significant boosting facilities, and Onshore Natural Sinks: 1990–2012. April 15, 2014. EPA 430–R–14– Gas Transmission Pipeline for 003. This report tracks total annual U.S. emissions 2 Climate Action Plan—Strategy to Reduce transmission pipeline blowdowns and removals by source, economic sector, and Methane Emissions. The White House, Washington, greenhouse gas going back to 1990. It is updated DC, March 2014. Available at http:// between compressor stations. The EPA annually, and the latest version (cited here) covers www.whitehouse.gov/sites/default/files/strategy_to_ is also proposing to require the emissions through 2012. reduce_methane_emissions_2014–03–28_final.pdf.

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sources of emissions that are not being proposed to be gathered by this rule II. Revisions and Other Amendments reported. The NGOs also asked the EPA because such data would inform and are A. Oil Wells With Hydraulic Fracturing to require the reporting of API well relevant to the EPA’s carrying out a identification numbers (currently wide variety of CAA provisions. See the Subpart W requires the reporting of known as US Well Numbers) to allow preambles to the proposed (74 FR GHG emissions from gas well cross-reference to production data and 16448, April 10, 2009) and final GHG completions and workovers with other important information, to phase reporting rule (74 FR 56260, October 30, hydraulic fracturing in the Onshore out the use of best available monitoring 2009) for further information. Petroleum and Natural Gas Production methods (BAMM), and to consider segment, but it does not require the In addition, the EPA is proposing including ‘‘Advanced Innovative reporting of GHG emissions from oil confidentiality determinations for Monitoring Methods’’ to ‘‘accelerate well completions and workovers with proposed new data elements in subpart development and deployment of real- hydraulic fracturing (unless the W under its authorities provided in time continuous methane emission emissions are routed to a flare, in which sections 114, 301, and 307 of the CAA. monitoring.’’ 3 These proposed case the emissions would be calculated Section 114(c) of the CAA requires that revisions, which address this petition, as part of the flare stacks emission are consistent with the EPA’s intent to the EPA make information obtained source, or the well testing emissions are ‘‘collect complete and accurate facility- under section 114 available to the vented or flared, in which case the level GHG emissions from the public, except where information emissions would be calculated as part of petroleum and natural gas industry’’ (79 qualifies for confidential treatment. The the well testing venting and flaring FR 74484, November 30, 2010) and to Administrator has determined that this emission source). At the time the EPA provide accurate and transparent data to proposed rule is subject to the finalized the subpart W requirements inform future policy decisions. Today’s provisions of section 307(d) of the CAA. (75 FR 74458, November 30, 2010), proposal includes the reporting of D. How would these amendments apply hydraulic fracturing of gas wells was a emissions currently not covered under to 2015 and 2016 reports? well-established and widespread subpart W as well as reporting of well industry practice. However, since that identification numbers which would The EPA is planning to address the time, expansion of the use of horizontal help ensure complete, accurate, and comments we receive on these proposed drilling and hydraulic fracturing has transparent reporting of GHG data under changes and publish the final allowed drilling into new formations, subpart W. The EPA is proposing to amendments before the end of 2015. If leading to increased emissions allow BAMM for a limited time only for finalized according to this schedule, associated with hydraulic fracturing.4 sources affected by these proposed these amendments would become Because hydraulic fracturing allows changes; the use of BAMM for sources effective on January 1, 2016. Facilities access to new geologic formations, some not addressed by the proposed changes would therefore be required to follow of these activities are occurring from in this action was addressed on the revised methods in subpart W, as completions and workovers with November 25, 2014 (79 FR 70352). amended, to calculate, monitor, and hydraulic fracturing of wells considered Finally, the EPA is currently assessing report emissions beginning January 1, to be in oil formations according to the the potential opportunities for applying 2016. The first annual reports of definition of ‘‘sub-basin category, for innovations in measurement technology emissions calculated using the amended onshore natural gas production’’ in 40 to identifying and estimating emissions requirements would be those submitted CFR 98.238. Since subpart W does not from affected sources under subpart W. by March 31, 2017, which would cover currently capture these emissions from While not explicitly adding new, the 2016 emissions reporting. For the oil wells with hydraulic fracturing, the alternative monitoring methods in this 2015 emissions and the corresponding EPA is proposing to close this data gap proposal, the EPA is seeking comment reports due by March 31, 2016, reporters by proposing reporting requirements for on options for allowing use of would continue to calculate, monitor, oil well completions and workovers alternative monitoring methods under and report emissions and other relevant with hydraulic fracturing. the GHGRP to account for advances in data according to the requirements of 40 The EPA is proposing to amend technology. See also, ‘‘Discussion Paper CFR part 98 that are applicable during subpart W: (1) To clarify the on Potential Implementation of the 2015 calendar year. applicability of the current provisions Alternative Monitoring under the For 2016 emissions only, the EPA is for the reporting of GHG emissions from GHGRP’’ in Docket ID No. EPA–HQ– proposing to allow the use of short-term completions and workovers with OAR–2014–0831. transitional BAMM for reporters who hydraulic fracturing for wells in the C. Legal Authority would be subject to new monitoring Onshore Petroleum and Natural Gas requirements associated with these Production segment, regardless of The EPA is proposing these rule proposed revisions. The use of BAMM whether their primary product is oil or amendments under its existing CAA would provide flexibility for the first- natural gas, and (2) to include authority provided in CAA section 114. time monitoring of new emissions provisions for the reporting of GHG As stated in the preamble to the 2009 sources. These reporters would have the emissions from oil well completions final GHG reporting rule (74 FR 56260, option of using BAMM from January 1, and workovers with hydraulic October 30, 2009), CAA section 2016 to March 31, 2016 without seeking fracturing. Consistent with the current 114(a)(1) provides the EPA broad prior EPA approval. Reporters would requirements for gas well completions authority to require the information also have the opportunity to request an 4 extension for the use of BAMM from U.S. EPA Office of Air Quality Planning and 3 Petition for Rulemaking and Interpretive Standards (OAQPS). Oil and Natural Gas Sector Guidance Ensuring Comprehensive Coverage of April 1, 2016 through December 31, Hydraulically Fractured Oil Well Completions and Methane Sources Under Subpart W of the 2016; those owners or operators would Associated Gas During Ongoing Production: Report Greenhouse Gas Reporting Rule—Petroleum And be required to submit a request to the for Oil and Natural Gas Sector, Oil Well Natural Gas Systems; Submitted by Clean Air Task EPA by January 31, 2016. See Section Completions and Associated Gas During Ongoing Force, Environmental Defense Fund, Natural Production Review Panel. April 2014. Available at Resources Defense Council, and Sierra Club; March II.F of this preamble for more http://www.epa.gov/airquality/oilandgas/pdfs/ 19, 2013. information. 20140415completions.pdf.

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and workovers with hydraulic the completion phase or even during the identify the location of any wells for fracturing, the proposed provisions production phase. Instead, the which data are provided (e.g., US Well include the reporting of activity data on associated natural gas may be vented or Number), the measured GOR, and the number of oil wells with hydraulic flared without measuring the gas flow whether the GOR for the well was fracturing and on the use of flaring and rate. For these oil wells that do not measured during completion or reduced emission completions (RECs). meter gas production, the EPA is workover. Information that would allow The EPA is also proposing to update proposing to add a new Equation W– the EPA to estimate the typical equations and definitions accordingly 12C to calculate, rather than measure, emissions from wells with such a low under 40 CFR 98.233(g) to reflect the value of PRs,p (the average gas GOR, and to estimate the total emissions applicability to completions and production flow rate during the first 30 from all wells that would be exempt if workovers of all wells with hydraulic days of production after the completion such a threshold were established, fracturing. or workover), which is used as an input would be particularly helpful to inform The proposed monitoring methods to Equation W–10A. In this proposed potential inclusion of a GOR threshold and reporting requirements would Equation W–12C, the value of PRs,p in the final rule. The EPA particularly incorporate methods that are already in would be calculated by multiplying the solicits specific data, rather than subpart W for hydraulic fracturing of gas GOR of the well by the measured oil conclusory statements, to support wells. The feasibility of the methods production rate during the first 30 days commenters’ positions on whether the have been demonstrated and refined of production after the completion or EPA should include a minimum GOR through several years of reporting and workover to calculate average gas threshold for monitoring and reporting. earlier amendments to subpart W. production flow rate. The EPA is also seeking comment on Specifically, the EPA is proposing to The EPA is not proposing at this time whether to establish a minimum well require the use of either Equation W– to allow the use of calculated flowback pressure such that oil wells operating 10A or W–10B in the current rule for rate for oil wells based on well below a certain pressure would not be calculating GHG emissions from oil well parameters, as specified in Calculation subject to the monitoring and reporting completions and workovers with Method 2 in 40 CFR 98.233(g). In the requirements for GHG emissions from hydraulic fracturing. Equation W–10A is current subpart W, Calculation Method completions and workovers with used to calculate emissions from wells 2 uses the measured gas pressure hydraulic fracturing. Similar to the using inputs obtained from a differential across the well choke to discussion on a potential GOR threshold representative sample of wells within a estimate gas flow rate. Based on the above, the EPA is also soliciting data sub-basin and the ratio of the gas information available, the EPA and other supporting information that flowback rate to the production flow concluded that this methodology may could be used to establish a level for the rate, and Equation W–10B is used to not be appropriate for estimating well pressure threshold in the final rule calculate emissions using inputs emissions from oil well completions amendments, if that approach were obtained from all wells within a sub- because of the differences in operational adopted. Supporting data should basin and the flow rate and flow volume conditions between oil and gas include, at a minimum, information of the gas vented or flared. Emissions production. The EPA is seeking sufficient to identify the location of any would be calculated and reported comment on how an engineering wells for which data are provided (e.g., separately for gas wells and oil wells. estimate of gas flow rate for oil wells US Well Number), the measured well Within subpart W, an individual well is might be performed as an alternative to pressure, and whether the well pressure labeled an ‘‘oil well’’ or ‘‘gas well’’ the proposed monitoring methods that was measured during completion or depending on the formation type would require direct measurement of workover. Information that would allow reported for that well. If wells produce gas flow rate. Such an engineering the EPA to estimate the typical from more than one formation type, estimate would be analogous to the emissions from wells with low well then the well is classified into only one current Calculation Method 2, but with pressures, and to estimate the total type based on the formation type with alternatives to the current Equations 11– emissions from all wells that would be the most contribution to production as A and 11–B that would be applicable to exempt if such a threshold were determined by the reporter’s oil wells. If an appropriate and established, would be particularly engineering knowledge. Furthermore, technically sound approach can be helpful to inform potential inclusion of the EPA is proposing to require identified, an engineering estimate a well pressure threshold in the final Calculation Method 1 for calculating methodology analogous to Calculation rule. The EPA particularly solicits inputs to Equations W–12A and W–12B Method 2 for gas wells would reduce specific data, rather than conclusory for oil wells. Calculation Method 1 the burden for reporters of oil well statements, to support commenters’ relies on direct measurement of gas flow completions and workovers with positions on whether the EPA should rate during flowback to develop hydraulic fracturing. include a minimum well pressure calculation inputs. The EPA is Additionally, the EPA is seeking threshold for monitoring and reporting. proposing that subpart W would include comment on whether to establish a B. Onshore Petroleum and Natural Gas the same requirements for the location minimum GOR threshold such that oil Gathering and Boosting Segment of the flow meter used to measure the wells with a very low GOR would not gas flow rate for an oil well as for the be subject to the monitoring and The EPA is proposing to add a new flow meter on a gas well. The EPA is reporting requirements for GHG industry segment to subpart W, Onshore seeking comment on whether this is the emissions from completions and Petroleum and Natural Gas Gathering appropriate location for the oil well workovers with hydraulic fracturing. and Boosting, that would cover flow meter. The EPA is also seeking The EPA is also soliciting data and other emissions from equipment used by comment on the burden of requiring supporting information that could be gathering pipeline systems that move direct measurement of gas flow rate used to establish a level for that petroleum and natural gas from the well during flowback. threshold in the final rule amendments, to either larger gathering pipeline The EPA is also aware that operators if that approach were adopted. systems, natural gas processing plants, of oil wells with a relatively low gas-to- Supporting data should include, at a natural gas transmission pipelines, or oil ratio (GOR) may not meter gas during minimum, information sufficient to natural gas distribution pipelines. A

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gathering and boosting system is a requirements for the gathering and gas removal, that has one or more single network of pipelines, boosting systems. These comments were connection points to gas and oil compressors and process equipment, summarized in the preamble to the final production and a downstream endpoint, including equipment to perform natural subpart W rule (75 FR 74458, November typically a gas processing plant, gas compression, dehydration, and acid 30, 2010) and can be found in the EPA’s transmission pipeline, local distribution gas removal, that has one or more well- Response to Public Comments company (LDC) pipeline, or other defined connection points to gas and oil document for the final rule.5 gathering and boosting system. The EPA production and a well-defined In response to public comments, the is proposing to define a gathering and downstream endpoint, typically a gas EPA recognized the need for further boosting system owner or operator as processing plant or transmission analysis of gathering and boosting any person that: (1) Holds a contract in pipeline. Gathering pipelines are before developing reporting which they agree to transport petroleum pipelines used to transport gas from the requirements. As a result, gathering and or natural gas from one or more onshore furthermost downstream point in an boosting sources were not included in petroleum and natural gas production onshore production facility to certain the final subpart W rule published in wells to a natural gas processing facility, endpoints, generally either a gas November 2010, and the EPA stated that another gathering and boosting system, processing facility or point of we would continue to evaluate ‘‘the a natural gas transmission pipeline, or a connection to a transmission pipeline. most appropriate mechanism for future distribution pipeline; or (2) is Compressors located along the gathering actions to address the collection of responsible for custody of the gas and boosting system are used to control appropriate data on gathering lines and transported. The purpose of including or ‘‘boost’’ the pressure of the gas in the boosting stations’’ (75 FR 74469, the last phrase of the definition is to pipeline and keep the gas moving November 30, 2010). After further address ownership scenarios for downstream. Acid gas removal units consideration of the comments and vertically integrated companies for and dehydrators may also be located on collection of additional data, the EPA is which contracts are not needed to the gathering and boosting system to proposing to require reporting of transfer gas from production wells to treat the collected natural gas. There are petroleum and natural gas gathering and natural gas processing plants. The EPA two types of gathering and boosting boosting equipment as part of a new requests comment on whether this systems, radial and trunk line. The Onshore Petroleum and Natural Gas phrase addresses that concern. radial type brings all the pipelines to a Gathering and Boosting segment to The EPA is proposing to define a central header, while the trunk-line type collect the data needed to quantify the facility with respect to onshore uses several remote headers to collect emissions from this segment and to petroleum and natural gas gathering and fluid and is mainly used in large fields. achieve more complete coverage of the The EPA recognized the need to petroleum and natural gas systems boosting in 40 CFR 98.238 as all require reporting from gathering and sector. gathering pipelines and other boosting systems in an earlier GHGRP The EPA is proposing to define the equipment located along those pipelines proposed rule. Gathering lines and Onshore Petroleum and Natural Gas that are under common ownership or boosting stations were included in the Gathering and Boosting segment in 40 common control by a gathering and original subpart W proposal (75 FR CFR 98.230 as gathering pipelines and boosting system owner or operator and 18608, April 12, 2010) under both the other equipment used to collect that are located in a single hydrocarbon Onshore Petroleum and Natural Gas petroleum and/or natural gas from basin as defined in 40 CFR 98.238. Production segment and the Onshore onshore production gas or oil wells and Where a person owns or operates more Natural Gas Processing segment. The used to compress, dehydrate, sweeten, than one gathering and boosting system EPA originally proposed to include or transport the gas to a natural gas in a basin (for example, separate reporting of emissions from intra-facility processing facility, a natural gas gathering lines that are not connected), gathering lines and all systems engaged transmission pipeline, or a natural gas then all gathering and boosting systems in gathering produced gas from multiple distribution pipeline. Gathering and and equipment that the person owns or wells as part of the Onshore Petroleum boosting equipment would include, but operates in the basin would be and Natural Gas Production segment. would not be limited to, gathering considered one facility. Any gathering The EPA also proposed that field pipelines, separators, compressors, acid and boosting equipment that is gathering and boosting stations that gas removal units, dehydrators, associated with a single gathering and gather and process natural gas from pneumatic devices/pumps, storage boosting system, including leased, multiple wellheads and compress and vessels, engines, boilers, heaters, and rented, or contracted activities, would transport natural gas as feed to natural flares. The Onshore Petroleum and be considered to be under common gas processing facilities would be Natural Gas Gathering and Boosting control of the owner or operator of the included in the Onshore Natural Gas segment would not include equipment gathering and boosting system. Processing segment. and pipelines that are reported under Emissions from an onshore petroleum In response to the April 2010 any other industry segment defined in and natural gas gathering and boosting proposal, the EPA received 32 comment subpart W. facility would only need to be reported letters addressing numerous aspects of The EPA is proposing to define a if the collection of emission sources the proposed gathering and boosting gathering and boosting system as a emits 25,000 metric tons of carbon reporting requirements. The comments single network of pipelines, dioxide equivalent (CO2e) or more per generally focused on the areas of compressors and process equipment, year. The basin-level reporting approach ownership of the gathering and boosting including equipment to perform natural that the EPA is proposing for onshore system, and on determining the gas compression, dehydration, and acid petroleum and natural gas gathering and boundaries of gathering and boosting boosting facilities is currently being between the Onshore Petroleum and 5 U.S. Environmental Protection Agency Office of used for reporting in the Onshore Natural Gas Production and Onshore Atmosphere Programs, Climate Change Division. Petroleum and Natural Gas Production Mandatory Greenhouse Gas Reporting Rule Subpart Natural Gas Processing segments. The W—Petroleum and Natural Gas: EPA’s Response to sector. The proposed basin-level commenters were also concerned with Public Comments, November 2010. Docket Item No. approach for the Onshore Petroleum the burden of the proposed reporting EPA–HQ–OAR–2009–0923–3608. and Natural Gas Gathering and Boosting

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segment would achieve a balance of provisions are needed to address the Production segment. Where these providing geographically specific overlap. For example, the EPA emission sources are located within information, while also reducing burden considered whether provisions were gathering and boosting facilities, these on reporters by ensuring that owners/ needed to address the potential for some sources are likely to be similar to the operators of gathering and boosting non-fractionating processing plants with ones located in the Onshore Petroleum systems would only have to submit one an annual throughput of around 25 and Natural Gas Production segment. report for all their systems within a million standard cubic feet per day Specifically, because most processing of basin. For more information on this (MMscfd) to be required to report as part the gas and oil extracted from wells will analysis, please see ‘‘Greenhouse Gas of different industry segments from year be processed downstream of the Reporting Rule: Technical Support for to year (i.e., as part of Onshore gathering and boosting facility, the 2015 Revisions and Confidentiality Petroleum and Natural Gas Gathering equipment/activities in the Onshore Determinations for Petroleum and and Boosting if the annual average daily Petroleum and Natural Gas Production Natural Gas Systems; Proposed Rule’’ in throughput drops below 25 MMscfd one segment will be designed to handle gas Docket ID No. EPA–HQ–OAR–2014– year and then part of the Onshore and oil of composition similar to the gas 0831. Natural Gas Processing segment if the and oil in the Onshore Petroleum and The EPA believes that the proposed throughput increases to above 25 Natural Gas Gathering and Boosting definitions of the Onshore Petroleum MMscfd the next year). The EPA segment, so the same methods are and Natural Gas Gathering and Boosting considered a provision that would allow applicable and would be no more segment, facility, and owner/operator a non-fractionating processing facility to burdensome. address or avoid the major issues raised stop reporting as part of the Onshore For blowdown vent stacks, the current by the commenters in response to the Natural Gas Processing segment and subpart W requires reporting of April 2010 proposal. Defining the instead report as part of the Onshore emissions for the Onshore Natural Gas Onshore Petroleum and Natural Gas Petroleum and Natural Gas Gathering Processing segment, but not for the Gathering and Boosting segment as a and Boosting segment if the facility Onshore Petroleum and Natural Gas segment separate from the Onshore throughput is below 25 MMscfd for 5 Production segment. The EPA is Petroleum and Natural Gas Production consecutive years. The EPA is not proposing that the same methods that segment and the Onshore Natural Gas proposing to include this provision are used for the Onshore Natural Gas Processing segment would avoid many because there is not sufficient Processing segment be applied to of the boundary issues presented by the information available on gathering and blowdowns of equipment in the earlier proposal. The proposed boosting systems for the EPA to assess Onshore Petroleum and Natural Gas definition of facility would also clarify whether such a provision is necessary, Gathering and Boosting segment. The how equipment located along the but the EPA is requesting comment on same exemptions, including those for pipeline should be treated as part of the the need for a provision that addresses volumes less than 50 cubic feet and for facility. The EPA requests comment on overlap of segment boundaries and what desiccant dehydrator reloading, that are the definitions of the Onshore that provision should include. applied to the Onshore Natural Gas Petroleum and Natural Gas Gathering The EPA is proposing to use current Processing segment should also be and Boosting segment and facility, the methods in subpart W, when available, applied to the Onshore Petroleum and gathering and boosting system, the for monitoring and calculating Natural Gas Gathering and Boosting gathering and boosting system owner or emissions from the Onshore Petroleum operator, the determination of what and Natural Gas Gathering and Boosting segment. The EPA expects that the emission sources are included in a segment. Subpart W already contains exemption for volumes less than 50 petroleum and natural gas gathering and monitoring and calculation methods for cubic feet should alleviate any concerns boosting facility in complex ownership all emission sources that would be with the burden of calculating scenarios (for example, multiple owners included in the Onshore Petroleum and emissions from small gathering with operation handled by one of the Natural Gas Gathering and Boosting pipelines. owners or shared by multiple owners). segment, with the exception of gathering Several emission sources, including In complex ownership scenarios, the pipelines, in either the Onshore compressors, acid gas removal units, EPA is proposing that the owners/ Petroleum and Natural Gas Production dehydrators, flares, and equipment leaks operators would assign a designated segment or the Onshore Natural Gas are found in both the Onshore representative responsible for reporting Processing segment. Since similar Petroleum and Natural Gas Production consistent with 40 CFR 98.4, and the equipment and sources are included in segment and the Onshore Natural Gas EPA requests comment on whether the multiple segments, this approach allows Processing segment. For acid gas provisions of 40 CFR 98.4 are the EPA to rely on methods that have removal units, dehydrators, and flare appropriate for petroleum and natural been proven effective for collecting GHG stacks, the current subpart W specifies gas gathering and boosting facilities data for at least 3 years. This approach the same methods for these sources in with complex ownership scenarios. In is expected to provide high quality data both the Onshore Petroleum and Natural addition, the EPA requests comment on while reducing the burden on reporters Gas Production segment and the whether the proposed definitions that would be associated with Onshore Natural Gas Processing clearly define the boundary of the determining how to implement new segment. For acid gas removal units and Onshore Petroleum and Natural Gas estimation methods. dehydrators, the current rule includes Gathering and Boosting segment as the For natural gas pneumatic devices, several alternative methods, and the pipelines and equipment between the pneumatic valves, pneumatic pumps, same alternative methods are specified Onshore Petroleum and Natural Gas and atmospheric storage tanks located for both segments. Because these Production segment and the Onshore in the Onshore Petroleum and Natural emission sources in the Onshore Natural Gas Processing segment (or Gas Gathering and Boosting segment, Petroleum and Natural Gas Gathering other downstream segment). the EPA is proposing that gathering and and Boosting segment are likely to be The EPA also requests comment on boosting reporters use the same methods similar to the ones in the Onshore potential concerns with overlap of these for calculating emissions as in the Petroleum and Natural Gas Production boundaries and whether specific Onshore Petroleum and Natural Gas segment or the Onshore Natural Gas

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Processing segment, the same methods requirements minimize the potential currently not subject to reporting under would be applicable. confusion associated with calculating subpart W. For compressors and equipment leaks, emissions from the Onshore Petroleum The EPA is not proposing to alter the subpart W contains one method in the and Natural Gas Gathering and Boosting definitions for the Onshore Natural Gas Onshore Petroleum and Natural Gas segment by adopting the same methods Processing or Onshore Petroleum and Production segment and a different used for calculating emissions that are Natural Gas Production segments within method for the same emission source in used in the Onshore Petroleum and subpart W, found in 40 CFR 98.230, so the Onshore Natural Gas Processing Natural Gas Production segment and the if these amendments are finalized as segment. We are proposing that the Onshore Natural Gas Processing proposed, then the facilities and gathering and boosting reporters use the segment. The EPA requests comment on emission sources that are currently in same method as in the Onshore whether the proposed monitoring and the Onshore Petroleum and Natural Gas Petroleum and Natural Gas Production reporting requirements for the proposed Production segment and the Onshore segment. The method for the Onshore Onshore Petroleum and Natural Gas Natural Gas Processing segment of Petroleum and Natural Gas Production Gathering and Boosting segment are subpart W would remain in those segment for compressors and equipment appropriate for these emission sources, segments. For facilities that have leaks relies on the reporter counting the and if not, what methodologies would emissions sources that are covered by number of compressors or components be more appropriate. the Onshore Petroleum and Natural Gas (e.g., population counts) and then Data collected through the proposed Production segment and the Onshore applying emission factors per reporting requirements for the Onshore Natural Gas Processing segment of compressor or component for that Petroleum and Natural Gas Gathering subpart W but do not collectively meet population. Alternatively, for and Boosting segment in subpart W the threshold for reporting in those equipment leaks, the reporter may count would improve the EPA’s estimates and segments, those emission sources or the number of pieces of major understanding of emissions from equipment should only be considered in equipment, assume the default sources covered by the new segment the proposed Onshore Petroleum and component counts in Table W–1B, and and from the petroleum and natural gas Natural Gas Gathering and Boosting then apply emission factors per sector. The improved data would segment if they meet the proposed component. This proposed population provide a better understanding of definition of ‘‘gathering and boosting count approach is appropriate for the sources in the petroleum and natural gas system’’ and the appropriate thresholds. Onshore Petroleum and Natural Gas industry for which the public currently However, the proposed Onshore Gathering and Boosting segment has little information. For example, the Petroleum and Natural Gas Gathering because, as in the Onshore Petroleum data that would be collected through and Boosting segment would increase and Natural Gas Production segment, these proposed revisions would inform the overall coverage of subpart W by the equipment is often geographically updates to the U.S. GHG Inventory. including some facilities that are dispersed and may be visited only The proposed requirements would reporting under subpart C for intermittently. Under the proposed require the reporting of GHG emissions combustion emissions but only have to approach, a reporter would need to from an entire gathering and boosting report a subset of their emissions establish an inventory of the facility instead of the partial approach currently, or that are not reporting at all components or equipment subject to the that currently exists under the GHGRP. under the GHGRP. Under the proposed population counts, apply the emission Specifically, some gathering and rule, these facilities would become part factors, and then update the inventory boosting emission sources, such as of the proposed Onshore Petroleum and each year to account for new or retired natural gas compression stations, are Natural Gas Gathering and Boosting components or equipment. The EPA only required to report GHG emissions segment in subpart W. If a reporter has also seeks comment on the if the facility exceeds the 25,000 metric more than one facility currently appropriateness of the methods used in tons CO2e annual emission reporting reporting under subpart C and they are the Onshore Natural Gas Processing threshold in subpart A, 40 CFR consolidated as part of a single segment for compressors and equipment 98.2(a)(2), based on combustion gathering and boosting facility as leaks, which are outlined in 40 CFR emissions that are reported under defined in this proposal, then the 98.234(a). subpart C. Subpart W does currently gathering and boosting facility would For gathering pipelines, the EPA is require reporting from facilities that begin reporting all their relevant facility proposing to use an emission factor perform ‘‘natural gas processing’’ in 40 emissions, including those previously approach that is essentially the same as CFR 98.230(a)(3), but this requirement is reported under subpart C, as a single the approach used for equipment leaks only for those facilities that perform consolidated facility under subpart W. in the Onshore Petroleum and Natural separation of natural gas liquids or non- The consolidated reporting facility Gas Production segment. For gathering methane gases from produced natural would also include the parts of the lines, reporters would use the gas or the separation of natural gas system, such as pipelines and smaller population count and emission factor liquids into one or more component compression stations, for which approach in 40 CFR 98.233(r). The mixtures and exceed 25 MMscfd annual emissions are not currently being emission factors that are being average daily gas throughput. Subpart W reported. proposed, which would be added to an also covers sources such as The proposed Onshore Petroleum and amended Table W–1A, are whole gas compressors, dehydration, or acid gas Natural Gas Gathering and Boosting emission factors based on the U.S. GHG removal that are located on a single segment would also include equipment Inventory. The population count would well-pad or associated with a single and facilities that are not currently be the miles of gathering pipeline, well as part of the Onshore Petroleum reporting under the GHGRP. For similar to the approach used for and Natural Gas Production segment. example, the EPA anticipates that the calculating emissions from natural gas However, if these sources are associated proposed Onshore Petroleum and distribution pipelines in the Natural Gas with multiple well pads and not located Natural Gas Gathering and Boosting Distribution segment. on a single well-pad, they are not part segment would include many The EPA has determined that the of the Onshore Petroleum and Natural compressor stations in gathering and proposed monitoring and reporting Gas Production segment and are boosting systems that are not currently

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reporting because they do not, as a option because it would have 717f. For intrastate pipelines, the facility defined in 40 CFR 98.6, exceed potentially resulted in higher burden to onshore natural gas transmission the 25,000 metric tons CO2e per year reporters by requiring reporting of pipeline owner or operator would be the reporting threshold in subpart A, 40 additional facilities under their person identified as the owner or CFR 98.2(a)(2). However, when ownership. The EPA is seeking operator on the transmission pipeline’s aggregated with the gathering pipelines comment on whether these options Statement of Operating Conditions and other compressor stations that are should be considered and how they under section 311 of the Natural Gas under common ownership and control might achieve transparent and complete Policy Act (NGPA). The Certificate of within a system, the complete system data for this segment without imposing Public Convenience and Necessity is a may exceed the reporting threshold and additional burden on reporters certificate issued by the Federal Energy would be required to begin reporting. compared to the proposed option. For Regulatory Commission (FERC) that The EPA considered other reporting more information regarding the options allows the pipeline company to engage options for defining the facility and the considered for defining the facility, see in the transportation and/or sale for level of reporting, but none of them ‘‘Greenhouse Gas Reporting Rule: resale of natural gas in interstate would have achieved the same balance Technical Support for 2015 Revisions commerce or to acquire and operate of geographically specific information and Confidentiality Determinations for facilities needed to accomplish this. The and reduced industry burden as the Petroleum and Natural Gas Systems; certificate is issued by FERC after FERC proposed option. One option considered Proposed Rule.’’ has approved the construction of a was using the definition of ‘‘facility’’ C. Natural Gas Transmission Lines pipeline, and it allows the holder to found in 40 CFR 98.6 that states, Between Compressor Stations build and operate the pipeline. Operators of intrastate pipelines are ‘‘Facility means any physical property, The EPA is proposing to add reporting plant, building, structure, source, or required to prepare a Statement of requirements for emissions from natural Operating Conditions for compliance stationary equipment located on one or gas transmission pipeline blowdowns more contiguous or adjacent properties under section 311 of the NGPA. Section between compressor stations in a new 311 of the NGPA allows an interstate in actual physical contact or separated Onshore Natural Gas Transmission solely by a public roadway or other pipeline company to sell or transport Pipeline segment. For purposes of the gas on behalf of any intrastate pipeline public right-of-way and under common Onshore Natural Gas Transmission ownership or common control, that or local distribution company without Pipeline segment, a blowdown is the prior FERC approval. emits or may emit any greenhouse gas. release of gas from transmission Operators of military installations may pipelines for the purpose of reducing The EPA is proposing that the facility classify such installations as more than system pressure or complete for the new Onshore Natural Gas a single facility based on distinct and depressurization. Transmission pipeline Transmission Pipeline segment would independent functional groupings blowdowns occur when, a segment of be defined as the total U.S. mileage of within contiguous military properties.’’ pipeline is isolated from the rest of the natural gas transmission pipelines This would mean that each piece of line and the natural gas inside is purged owned or operated by an onshore property (or adjacent properties under through a blowdown vent stack. These natural gas transmission pipeline owner common ownership or common control) blowdowns are needed to safely inspect or operator. If an entity owned and with gathering and boosting equipment and maintain the pipelines, but the operated multiple pipelines in the U.S., that exceeded the 25,000 metric tons purging of natural gas produces the facility would be considered the CO2e annual threshold would be methane emissions that are currently aggregate of those pipelines, even if they considered its own ‘‘facility’’. This not included in subpart W. In the U.S. are not interconnected. In defining the option provided limited data on the GHG Inventory, the EPA estimated that facility, the EPA considered other segment as a whole due to decreased there were over 300,000 miles of options, such as the facility being the coverage compared to other options, transmission pipelines in 2012, and the amount of pipeline owned and operated though more granular, site-specific data blowdown emissions associated with by an entity within a state or basin, or would likely be achievable for this those pipelines were estimated to be the facility being each separate pipeline. option. This option would also require 85,000 metric tons of methane a year. In considering these other options, the separate reports for each compressor Although subpart W does require EPA had to take into account that many station and/or gathering line, which reporting of emissions from onshore major pipeline systems are essentially would have resulted in a high reporting natural gas transmission compression linear systems to move gas from one burden on owners/operators in this stations, it currently does not cover part of the U.S. to another, and requiring segment. Therefore, the EPA concluded onshore natural gas transmission reporters to file separate reports for each that this option would not achieve the pipelines in between compressor portion of the system in any one state goals of having a thorough data set and stations. This represents a gap in the or other defined geography would transparent, complete information for coverage of emission sources from the impose higher reporting burden on this sector while minimizing burden to petroleum and natural gas systems those subject to this source category reporters. The EPA also considered an source category covered by subpart W. without providing the EPA with option that would have separated the The EPA is proposing to define the additional, specific information. The gathering pipelines and gathering and onshore natural gas transmission EPA also took into account the fact that boosting stations (e.g., facilities with pipeline owner or operator depending many entities own and operate pipeline compressors, dehydration, and acid gas on whether the transmission pipeline is segments that may not be directly removal) into different segments. The interstate or intrastate. For interstate interconnected, but are connected with gathering and boosting stations would pipelines, the onshore natural gas pipelines owned and operated by other have reported at the basin level, and the transmission pipeline owner or operator entities as part of the national network pipelines at the national level (e.g. all would be the person identified as the of natural gas transmission pipelines. gathering pipelines owned by a person transmission pipeline owner or operator The proposed approach limits the or entity within the United States). on the Certificate of Public Convenience burden on reporters to correlate the However, the EPA is not proposing this and Necessity issued under 15 U.S.C. pipeline ownership transfer points with

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specific geographical segments. Instead, stations on natural gas transmission GHGRP data to other databases to more the reporters can track the required pipelines to the Onshore Natural Gas easily match the data reported under the information for their various pipelines, Transmission Compression segment, GHGRP with other data sources and will regardless of location, and submit data which is already a reporting segment improve the accuracy and transparency associated with all of them in one under subpart W, instead of creating a of subpart W. Being able to match the report. new segment. However, the Onshore GHGRP data to other data sources The EPA is proposing that reporters Natural Gas Transmission Compression would provide the EPA with more would use the methods in 40 CFR segment currently uses the same options for analysis of the GHGRP data 98.233(i) to calculate or measure definition of facility as found in 40 CFR to better inform future policy decisions emissions from pipeline blowdown 98.6 and the natural gas transmission related to GHG emissions from the oil events. One method allows a reporter to pipelines that surround a compressor and natural gas production sector. The calculate emissions based on the station might not be compatible with reporting of the well identification volume of the pipeline segment between that definition of ‘‘facility’’ because they numbers would also allow the EPA to isolation valves that is blown down and would likely not be under common assess the completeness and the pressure and temperature of the gas ownership or control with the adjacent representativeness of the data collected within the pipeline. This method uses compressor station(s). Therefore, under the GHGRP as a portion of all information that should be readily keeping the definition of facility found activity in the oil and natural gas available to the reporter (e.g., pipeline in 40 CFR 98.6 for this proposed new production sector. length, diameter, and operating segment would result in a higher Since 1966, almost all U.S. oil and gas pressure) and so should not be overly reporting burden on pipeline owners/ wells have been assigned a unique and burdensome. The second method allows operators with a number of non- permanent API Well Number in the reporter to measure the emissions contiguous pipelines in the U.S. accordance with American Petroleum from the blowdown using a flow meter compared to the proposed option, Institute (API)’s specification in Bulletin on the blowdown vent stack. In both because these owners/operators would D12A.7 The API Well Number was methods, the reporter would calculate have to submit individual reports for established to allow regulators to track both methane and carbon dioxide (CO2) each pipeline they owned or operated. drilling permits, collect royalties, and emissions from the volume of natural The proposed option simplifies optimize field conservation. API gas vented using either default gas reporting for this source by allowing transferred ownership of the well composition or engineering estimates of each owner/operator to submit one numbering specification to the composition as specified in 40 CFR report for all their transmission Professional Petroleum Data 98.233(u)(2)(iii). In addition to the total pipelines. Management (PPDM) Association in annual emissions of methane and CO2, 2010. The PPDM Association issued an natural gas transmission pipeline D. Well Identification Numbers updated specification in May 2013 and reporters would also report the methane The EPA is proposing to amend 40 then renamed the identifier as the US 8 and CO2 emissions and location of each CFR 98.236 to add reporting Well Number in June 2014. The PPDM blowdown event. requirements for well identification Association is working with state The EPA previously considered numbers to improve data quality by regulatory agencies to implement the fugitive emissions that result from leaks enabling identification of wells. If 2013 updates, but adoption is at the in transmission pipelines in the re- finalized, these reporting requirements discretion of the agency. State agencies proposal of subpart W in April 2010 (75 would be reported for the first time in that elect not to use the US Well FR 18616, April 12, 2010), but did not the report covering the year in which Number have assigned unique well include provisions for these emissions the rule is made effective (e.g., if the identification numbers to the gas and oil in either the proposed or final rules. The final rule is effective January 1, 2016, wells in that state for tracking in their April 2010 preamble explained that the then the reports covering 2016 data regulatory databases. US Well Numbers EPA did not propose reporting would be the first to include well and other well identification numbers requirements for fugitive emissions from identification numbers). Reporting of are publically available, but the leaks in natural gas pipeline segments well identification numbers for previous accessibility of the data varies from state between compressor stations due to the years (e.g., 2012) is not being proposed to state. Reporters in the Onshore dispersed nature of the fugitive by the EPA. For the majority of wells, Petroleum and Natural Gas Production emissions, and the fact that, once the well identification number reported segment already track and maintain fugitives are found, the leaks causing will be the US Well Number (formerly records by well identification number the emissions are usually addressed referred to as the API Well Number, or for other regulatory and reporting quickly for safety reasons (75 FR 18616, API Number).6 For any well that does purposes. April 12, 2010). The EPA also notes that not already have a US Well Number, the The EPA is proposing to require the larger fugitive leaks are currently reporter would be required to provide reporting of well identification numbers reported to the U.S. Department of the unique well number assigned by the for the Onshore Petroleum and Natural Transportation’s Pipeline and permitting authority for drilling of oil Gas Production segment in two general Hazardous Materials Safety and gas wells. US Well Numbers are cases. First, the EPA proposes to require Administration as part of 49 CFR 191.3. required for wells in almost all states reporters in the Onshore Petroleum and Under this provision, any pipeline covered in the Onshore Petroleum and incident that results in unintentional Natural Gas Production segment and are 7 American Petroleum Institute. The API Well gas loss of three million cubic feet or generally reported in relevant onshore Number and Standard State And County Numeric Codes Including Offshore Waters. API Bulletin more must be reported. Therefore, the production permitting documentation. D12A, January 1979. Available at http:// EPA is not proposing to include This would allow the EPA to link the wellidentification.org/dl/US_API_Bulliten_ reporting requirements for fugitive 1979.pdf. emissions from transmission pipeline 6 The Professional Petroleum Data Management 8 The Professional Petroleum Data Management Association. The US Well Number Standard: An Association. The US Well Number Standard: An leaks. Identifier for Petroleum Industry Wells in the USA. Identifier for Petroleum Industry Wells in the USA. The EPA also considered adding Version 2013 rev 1, published June 19, 2014. Version 2013 rev 1, published June 19, 2014. blowdowns between compressor Available at http://dl.ppdm.org/dl/1147. Available at http://dl.ppdm.org/dl/1147.

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Natural Gas Production segment to single well pad, and would simply need Additionally, we are seeking report a list of well identification to note and maintain the well comment on the EPA’s memorandum on numbers associated with different identification number(s) for that alternative and innovative measurement emission sources for all wells in a sub- associated piece of equipment. or monitoring technologies (see basin included in the reported ‘‘Discussion Paper on Potential E. Advanced Innovative Monitoring emissions data. Reporting the well Implementation of Alternative Methods identification numbers associated with Monitoring under the GHGRP’’ in different emission sources for each sub- As oil and gas operations seek to Docket ID No. EPA–HQ–OAR–2014– basin would allow the EPA to determine capitalize on advances in measurement 0831). Following review of the data and completeness of reporting by evaluating and monitoring technology in information received in comments, the the coverage of current reporting optimizing process operations and EPA may propose amendments related requirements and identifying potential reducing fugitive emissions from to the use of innovative technologies in cases of under-reporting by comparing process equipment leaks, opportunities reporting to the GHGRP in a future lists of reported well identification will arise for facilities to use innovative rulemaking. numbers to lists of well identification technologies to gather real-time, F. Best Available Monitoring Methods numbers from state agencies. The EPA continuous emissions data from area expects that this would present a low and point sources. For example, optical The EPA is proposing that facilities burden to reporters because reporters remote sensing techniques have existed will be allowed to use BAMM for the should already track and maintain well for many years but recent technological proposed amendments for the 2016 identification numbers. The EPA advances have allowed these devices to reporting year for only the new industry expects that most reporters track and be used in the field (e.g., for fence line segments and emission sources maintain sub-basins for each well monitoring) to provide reliable included in this proposal. These include identification number. If a reporter does measurements of gas concentrations, calculating and reporting emissions not, they can use the state code and including methane, in the ambient air at from oil well completions and county code portions of the US Well the relevant detection limits.910 workovers with hydraulic fracturing, Number to identify the sub-basin. The EPA is assessing the potential from onshore petroleum and natural gas Second, for reporters in the Onshore opportunities for applying remote gathering and boosting systems, and for Petroleum and Natural Gas Production sensing technologies and other transmission pipeline blowdown segment that report emissions using innovations in measurement or emissions. This proposal would allow input data that are calculated from monitoring technology to identifying reporters to use best available methods measurements at individual wells or and calculating emissions from affected to estimate inputs to emission equations equipment associated with individual sources under subpart W. The EPA’s for the newly proposed emission wells (e.g., if Equation W–10A was used objective for this assessment is to sources using their best engineering to calculate emissions from oil well determine if new and innovative judgment for cases where the completions and workovers with technologies could be applied to the monitoring of these inputs would not be hydraulic fracturing, well testing GHGRP to improve the overall accuracy possible beginning on January 1, 2016. emissions), the EPA proposes to require and transparency of reported data in a The EPA is not proposing to allow the the reporter to report the well cost-effective way while still meeting use of BAMM for the proposed reporting identification number for which those the overall objectives of Part 98. While of well identification numbers because measurements were made, or for which the EPA is not proposing to incorporate reporters should already have well the equipment is associated. Reporting these technologies into subpart W in identification numbers readily available the well identification numbers for this action, the EPA is requesting for all wells and associated equipment input data based on measurements at a comment on the feasibility, possible to which this proposed reporting sample of wells would allow the EPA to regulatory approaches, provisions requirement would apply. compare GHGRP data to data from other necessary to incorporate or allow the These reporters have the option of wells in the same basin or sub-basin to use of advanced measurement or using BAMM from January 1, 2016, to evaluate whether the measurements monitoring methods in subpart W, and March 31, 2016, without seeking prior were likely representative of all wells in methods to ensure compliance with EPA approval for certain parameters the basin or sub-basin. The EPA expects those provisions in an efficient manner. that cannot reasonably be measured that this would present a low burden to In particular, the EPA is soliciting data according to the monitoring and QA/QC reporters because reporters should and case studies that could provide requirements of 40 CFR 98.234. already track and maintain well information regarding the benefits, Reporters would also have the identification numbers associated with costs, and potential problem areas, opportunity to request an extension for measurements used for the GHGRP including consistency among reporters the use of BAMM beyond March 31, input data. and the feasibility of verifying 2016; those owners or operators would Where emissions are reported for emissions, associated with using submit a request to the Administrator by equipment that is on or associated with advanced innovative monitoring January 31, 2016. This additional time a single well pad, (e.g., dehydrators, methods for providing emissions for reporters to comply with the acid gas removal units), providing the measurements in the oil and natural gas monitoring methods for new emission well identification number(s) for the sector, including the provision of real- sources in subpart W would allow associated well(s) would also allow the time or continuous measurements. facilities to install the necessary EPA to compare the data that are used monitoring equipment during other as inputs for estimating emissions to the 9 Allen, D.T. et al. Measurements of methane planned (or unplanned) process unit data available from the well(s) to verify emissions at natural gas production sites in the downtime, thus avoiding process those data. The EPA expects that this United States, Proceedings of the National interruptions. would also present a low burden to Academy of Sciences of the United States of The EPA is not proposing to allow the America, 110(44): 17768–17773, 2013. reporters because reporters already have 10 EPA Handbook: Optical Remote Sensing for use of BAMM beyond 2016 and does not to make a determination of whether the Measurement and Monitoring of Emissions Flux, anticipate that BAMM would be needed equipment is on or associated with a http://www.epa.gov/ttnemc01/guidlnd/gd-052.pdf. beyond 2016 for the new segments and

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emissions sources being proposed in confidentiality determination to all data Note that subpart W is a direct emitter this rule. elements assigned to the category. Of source category, thus, no data are these data categories with categorical III. Proposed Confidentiality assigned to any supplier data categories. determinations, the EPA determined Determinations For data elements the EPA has that four direct emitter data categories assigned in this proposed action to a A. Overview and Background are comprised of those data elements direct emitter category with a In this proposed rule, we are that meet the definition of ‘‘emissions data,’’ as defined at 40 CFR 2.301(a), categorical determination, the EPA is proposing confidentiality proposing that the categorical determinations for 171 data elements and that, therefore, are not entitled to confidential treatment under section determination for the category be proposed to be reported by the 114(c) of the CAA.11 The EPA applied to the proposed new data following segments: Onshore Petroleum determined that the other four direct element. For the proposed categorical and Natural Gas Production, Onshore emitter data categories and the eight assignment of the data elements in these Petroleum and Natural Gas Gathering supplier data categories do not meet the eight categories with categorical and Boosting, and Onshore Natural Gas definition of ‘‘emission data.’’ For these determinations, see the memorandum Transmission Pipeline. These data data categories that are determined not ‘‘Data Category Assignments and elements include new reporting to be emission data, the EPA determined Confidentiality Determinations for All requirements for existing sources categorically that data in three direct already reporting under subpart W as Data Elements (excluding inputs to emitter data categories and five supplier well as new reporting requirements that emission equations) in the Proposed data categories are eligible for would be reported by additional ‘2015 Revisions and Confidentiality confidential treatment as CBI, and that Determinations for Petroleum and industry segments or sources under the data in one direct emitter data these proposed amendments. Natural Gas Systems’ ’’ in Docket ID No. category and three supplier data EPA–HQ–OAR–2014–0831. The final confidentiality categories are ineligible for confidential determinations the EPA has previously treatment as CBI. For two direct emitter For data elements assigned to the made for the remainder of the subpart data categories, ‘‘Unit/Process ‘Static’ ‘‘Unit/Process ‘Static’ Characteristics W data elements are unaffected by the Characteristics that Are Not Inputs to that Are Not Inputs to Emission proposed amendments and continue to Emission Equations’’ and ‘‘Unit/Process Equations’’ and ‘‘Unit/Process Operating apply. For information on Operating Characteristics that Are Not Characteristics that Are Not Inputs to confidentiality determinations for the Inputs to Emission Equations,’’ and Emission Equations,’’ we are proposing GHGRP and subpart W data elements, three supplier data categories, ‘‘GHGs confidentiality determinations on a see: 75 FR 39094, July 7, 2010; 76 FR Reported,’’ ‘‘Production/Throughput case-by-case basis taking into 30782, May 26, 2011; 77 FR 48072, Quantities and Composition,’’ and consideration the criteria in 40 CFR August 13, 2012; 79 FR 63750, October ‘‘Unit/Process Operating 2.208, consistent with the approach 24, 2014. These proposed Characteristics,’’ the EPA determined in used for data elements previously confidentiality determinations would be the 2011 Final CBI Rule that the data assigned to these two data categories. finalized after considering public elements assigned to those categories For the proposed categorical assignment comment. The EPA plans to finalize are not emission data, but the EPA did of these data elements, see the these determinations at the same time not make categorical CBI determinations memorandum ‘‘Data Category the proposed rule amendments for them. Rather, the EPA made CBI described in this action are finalized. Assignments and Confidentiality determinations for each individual data Determinations for All Data Elements B. Approach to Proposed CBI element included in those categories on (excluding inputs to emission Determinations a case-by-case basis taking into equations) in the Proposed ‘2015 consideration the criteria in 40 CFR Revisions and Confidentiality With the exception of the specific 2.208. No final confidentiality Determinations for Petroleum and data elements addressed in Section III.D determination was made for the inputs Natural Gas Systems’ ’’ in Docket ID No. of this preamble, we are applying the to emission equation data category (a same approach as previously used for direct emitter data category) in the 2011 EPA–HQ–OAR–2014–0831. For the making confidentiality determinations Final CBI Rule. However, the EPA has results of our case-by-case evaluation of for data elements reported under the since proposed and finalized an these data elements, see Sections III.C GHGRP. In the ‘‘Confidentiality approach for addressing disclosure and III.D of this preamble. Determinations for Data Required Under concerns associated with inputs to In addition to the individual data the Mandatory Greenhouse Gas emissions equations.12 element determinations described above Reporting Rule and Amendments to For this rulemaking, we are proposing and for the reasons stated below, we are Special Rules Governing Certain to assign 165 new data elements to the proposing individual confidentiality Information Obtained Under the Clean appropriate direct emitter data determinations for six new data Air Act’’ (hereafter referred to as ‘‘2011 categories created in the 2011 Final CBI elements without making a data Final CBI Rule’’) (76 FR 30782, May 26, Rule based on the type and category assignment. In the 2011 Final 2011), the EPA grouped Part 98 data characteristics of each data element. CBI rule, although the EPA grouped elements into 22 data categories (11 similar data into categories and made direct emitter data categories and 11 11 Direct emitter data categories that meet the supplier data categories) with each of definition of ‘‘emission data’’ in 40 CFR 2.301(a) are categorical confidentiality the 22 data categories containing data ‘‘Facility and Unit Identifier Information,’’ determinations for a number of data ‘‘Emissions,’’ ‘‘Calculation Methodology and categories, the EPA also recognized that elements that are similar in type or Methodological Tier,’’ and ‘‘Data Elements Reported characteristics. The EPA then made for Periods of Missing Data that are not Inputs to similar data elements may not always categorical confidentiality Emission Equations.’’ have the same confidentiality status, in determinations for eight direct emitter 12 Revisions to Reporting and Recordkeeping which case the EPA made individual Requirements, and Confidentiality Determinations instead of categorical determinations for data categories and eight supplier data Under the Greenhouse Gas Reporting Program; categories and applied the categorical Final Rule. (79 FR 63750, October 24, 2014). the data elements within such data

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categories.13 Similarly, while the six We are also proposing to assign 65 did not identify any disclosure proposed new data elements are similar additional data elements used to concerns, except when the oil wells to in type or certain characteristics to data calculate GHG emissions in subpart W which those inputs to emission elements previously assigned to the for the Onshore Petroleum and Natural equations apply meet the definition of ‘‘Production/Throughput Data Not Used Gas Gathering and Boosting segment, either ‘‘wildcat well’’ or ‘‘delineation as Input’’ and ‘‘Raw Materials Onshore Natural Gas Transmission well.’’ ‘‘Delineation well’’ is defined as Consumed that are Not Inputs to Pipeline segment, and for emissions ‘‘a well drilled in order to determine the Emission Equations’’ data categories, we from oil wells with hydraulic fracturing boundary of a field or producing do not believe that they share the same to the ‘‘Input to Emission Equation’’ reservoir.’’ ‘‘Wildcat well’’ is defined as confidentiality status as the non-subpart data category. We are not proposing a ‘‘a well outside known fields or the first W data elements already assigned to confidentiality determination for this well drilled in an oil or gas field where those two data categories, which the data category. The majority of these data no other oil and gas production exists.’’ EPA has determined categorically to be elements are existing data elements in As noted in a previous rulemaking (79 CBI based on the data elements assigned subpart W that would be applied to the FR 63750, October 24, 2014), the early to those categories at the time of the new Onshore Petroleum and Natural public disclosure of certain data 2011 Final CBI Rule. As discussed in Gas Gathering and Boosting segment elements that are inputs for these two more detail below, our review showed and Onshore Natural Gas Transmission specific well definitions could reveal that these six subpart W production and Pipeline segment. Some of the data data on well productivity that could throughput-related data elements fail to elements are new data elements that are give competitors an advantage by giving qualify for confidential treatment. used as inputs to proposed Equation W– them information on new fields or new Therefore, we do not believe that the 12C. Due to concerns expressed by areas of existing fields without having to categorical determinations for the reporters with the potential release of drill their own wildcat or delineation ‘‘Production/Throughput Data Not Used inputs to emission equations, we wells. This could result in the loss of as Input’’ and ‘‘Raw Materials previously established a process for investment value for certain reporters. Consumed that are Not Inputs to evaluating ‘‘inputs to emission For wildcat and delineation wells, the Emission Equations’’ data categories are equation’’ data elements to identify EPA is proposing to allow reporters to appropriate for these six data elements; potential disclosure concerns and delay reporting of these data elements accordingly, these data elements should actions to address such concerns if for 2 years, as currently allowed for gas not be assigned to these data categories. appropriate.14 The EPA has used this wells with hydraulic fracturing that Not assigning these six data elements to process to evaluate inputs to emission meet the definition of either ‘‘wildcat these two data categories would also equations, including the subpart W data well’’ or ‘‘delineation well’’, because a leave unaffected the existing categorical elements that are already assigned to the 2-year delay of reporting is sufficient to determinations for these data categories, inputs to emission equations data prevent early public disclosure of these 15 which remain valid and applicable to category. We performed a similar data and will provide sufficient time for the data elements assigned to those data evaluation for the 67 subpart W inputs a reporter to thoroughly conduct an categories. For the reasons stated above, to emission equations when they are assessment of the well. The specific we are proposing individual applied to the Onshore Petroleum and proposed data elements impacted are: confidentiality determinations for these Natural Gas Gathering and Boosting (1) The cumulative gas flowback time, six data elements without making segment, Onshore Natural Gas in hours, for each sub-basin, from when categorical assignment. Transmission Pipeline segment, and for gas is first detected until sufficient Our proposed individual calculating emissions from oil wells quantities are present to enable determinations follow the same two step with hydraulic fracturing. separation (§ 98.236(g)(5)(i)); (2) the For the Onshore Natural Gas evaluation process as set forth in the cumulative flowback time, in hours, for Transmission Pipeline segment, the EPA 2011 Final CBI Rule and subsequent each sub-basin, after sufficient did not identify any potential disclosure confidentiality determinations for Part quantities of gas are present to enable concerns with the data elements that are 98 data. Specifically, we first separation (§ 98.236(g)(5)(i)); (3) the inputs to emissions equations. determined whether the data element measured flowback rate, in standard Accordingly, the proposal would meets the definition of emission data in cubic feet per hour, for each sub-basin 40 CFR 2.301(a). Data elements that require reporting of these data elements by March 31, 2017, which is the (§ 98.236(g)(5)(ii)); and (4) the total meet the definition of emission data are annual gas-liquid separator oil volume required to be released under section reporting deadline for the 2016 reporting year. that is sent to applicable onshore storage 114 of the CAA. For data elements tanks, in barrels (§ 98.236(j)(1)(v)). found to not meet the definition of For calculating emissions from oil In addition to the data elements that emission data, we evaluated whether a wells with hydraulic fracturing, the EPA are inputs to emission equations for data element meets the criteria in 40 14 wildcat and delineation wells, the EPA CFR 2.208 for confidential treatment. In See the ‘‘Change to the Reporting Date for Certain Data Elements Required Under the has further determined that one other particular, we focus on: (1) Whether the Mandatory Reporting of Greenhouse Gases Rule’’ proposed data element related to these data are already public; and (2) whether (hereinafter referred to as the ‘‘Final Deferral two specific types of wells may have ‘‘. . . disclosure of the information is Notice’’) (76 FR 53057, August 25, 2011) and the early disclosure concerns due to the likely to cause substantial harm to the accompanying memorandum entitled ‘‘Process for Evaluating and Potentially Amending Part 98 Inputs reasons stated above. Therefore, in order business’s competitive position.’’ For to Emission Equations’’ (Docket ID EPA–HQ–OAR– to treat all early disclosure concerns the results of our case-by-case 2010–0929). related to exploratory wells consistently evaluation of these six proposed subpart 15 See the memoranda titled ‘‘Summary of Data throughout subpart W, the EPA is W data elements, see Section III.D of Collected to Support Determination of Public Availability of Inputs to Emission Equations for proposing to allow reporters to delay this preamble. which Reporting was Deferred to March 31, 2015’’ reporting for this data element for 2 and ‘‘Evaluation of Competitive Harm from 13 In the 2011 Final CBI rule, several data Disclosure of Inputs to Equations Data Elements years as well. The EPA is also proposing categories include both CBI and non-CBI data Deferred to March 31, 2015.’’ (Docket ID EPA–HQ– a confidentiality determination for this elements. See 76 FR 30786. OAR–2010–0929). data element, found in Table 3 of this

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preamble, which would apply once the Equations Affected by the Proposed determinations. Specifically, we focused data element is reported to the EPA ‘2015 Revisions and Confidentiality on whether the data are already publicly following the 2-year delay. The specific Determinations for Petroleum and available from other sources and, if not, proposed data element impacted is: The Natural Gas Systems’ ’’ in Docket ID No. whether disclosure of the data is likely total annual oil throughput that is sent EPA–HQ–OAR–2014–0831. to cause substantial harm to the to all atmospheric tanks, in barrels business’ competitive position. Table 2 C. Proposed Confidentiality (§ 98.236(j)(2)(i)(A)). Other data of this preamble lists the data elements Determinations for Data Elements elements related to delineation or assigned to the ‘‘Unit/Process Operating Assigned to the ‘‘Unit/Process ‘Static’ wildcat wells that are not proposed to Characteristics That Are Not Inputs to Characteristics That Are Not Inputs to be amended in this action have been Emission Equations’’ and ‘‘Unit/Process Emission Equations’’ and ‘‘Unit/Process addressed in a previous rulemaking (79 ‘Static’ Characteristics That Are Not Operating Characteristics That Are Not FR 70352, November 25, 2014). Inputs to Emission Equations’’ data Inputs to Emission Equations’’ Data For calculating emissions from categories, the proposed confidentiality Categories sources in the Onshore Petroleum and determination for each data element, Natural Gas Gathering and Boosting The EPA is proposing that 36 data and our rationale for each determination segment, the EPA did not identify any elements for subpart W that have been as they would apply to the Onshore disclosure concerns. The Onshore assigned to the ‘‘Unit/Process Operating Petroleum and Natural Gas Gathering Petroleum and Natural Gas Gathering Characteristics That Are Not Inputs to and Boosting segment or for oil wells and Boosting segment would be a Emission Equations’’ data category or with hydraulic fracturing in the regionally concentrated segment, with the ‘‘Unit/Process ‘Static’ Characteristics Onshore Petroleum and Natural Gas gathering lines and other services That Are Not Inputs to Emission Production segment. located in fixed geological basins. Equations’’ data category would be For the existing data elements Because of the amount of fixed assets reported for sources in the proposed previously assigned to the ‘‘Unit/ required to operate in this segment (e.g., Onshore Petroleum and Natural Gas Process ‘Static’ Characteristics that Are gathering lines and boosting stations), Gathering and Boosting segment, the Not Inputs to Emission Equations’’ and companies operating in this segment Onshore Natural Gas Transmission ‘‘Unit/Process Operating Characteristics enter into long term agreements with Pipeline segment, or for onshore natural that Are Not Inputs to Emission natural gas producers to gather natural petroleum and natural gas production Equations’’ that would be reported by gas and transport it to natural gas facilities that report emissions from oil the newly proposed Onshore Petroleum processing facilities or, in some cases, wells with hydraulic fracturing. The and Natural Gas Gathering and Boosting transmission pipelines. These data elements were assigned to these segment, the Onshore Natural Gas agreements are for long periods, lasting two categories in earlier EPA actions (77 Transmission Pipeline segment, or for from several years to the life of the lease FR 48072, August 13, 2012; and 79 FR oil wells with hydraulic fracturing, we for the producing wells, and establish 70352, November 25, 2014). We are are proposing confidentiality the prices for gathering services for the proposing confidentiality determinations based on a new case-by- life of the agreement. Once these determinations for these data elements case evaluation of the data elements, agreements are established, information when applied to these new emission taking into consideration the that would be revealed from the ‘‘inputs sources based on the approach set forth characteristics of the new reporters that to emissions equations’’ is not likely to in the 2011 Final CBI Rule for data would be required to report these data affect the competitive position of the elements assigned to these two data elements by the proposed amendments. company operating the gathering and categories. In that rule, the EPA Because these data elements do not boosting system because it will not determined categorically that data meet the definition of emissions data in reveal information about the cost or elements assigned to these two data 40 CFR 2.301(a), the EPA used the profitability of providing that gathering categories do not meet the definition of criteria at 40 CFR 2.208 in making our service, or about the company’s ability emission data in 40 CFR 2.301(a); the proposed confidentiality to enter into new agreements and EPA then made individual, instead of determinations. Specifically, we focused expand operations. As a result, the categorical, confidentiality on whether the data are already publicly ‘‘inputs to equations’’ data elements in determinations for these data elements. available from other sources and, if not, this segment would not be likely to As with all other data elements whether disclosure of the data is likely reveal any proprietary information assigned to these two categories, the to cause substantial harm to the about the facility or cost to do business. EPA concluded that the proposed new business’ competitive position. Table 2 For the list of new subpart W inputs data elements do not meet the definition of this preamble lists the data elements to emission equations and the results of of emissions data in 40 CFR 2.301(a). by data category, the proposed our evaluation, see the memorandum, The EPA then considered the confidentiality determination for each ‘‘Review for Potential Disclosure confidentiality criteria at 40 CFR 2.208 data element, and our rationale for each Concerns for Inputs to Emission in making our proposed confidentiality determination.

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Table 2. Proposed Confidentiality for Data Elements Assigned to the "Unit/Process Operating Characteristics That Are Not Inputs to Emission Equations" and "Unit/Process 'Static' Characteristics That Are Not Inputs to Emission Equations" Data Categories Proposed Confidentiality Determination Citation Data Element and Rationale "Unit/Process Ouerating Characteristics That Are Not Inuuts to Emission Eguations" Data Category

98.236( d)(l )(v) Whether any C02 emissions This proposed data element would be from the acid gas removal unit reported by onshore petroleum and natural are recovered and transferred gas gathering and boosting facilities. This outside the facility. data element indicates that a facility is operating an acid gas removal unit and indicates how the facility handles the C02 emissions it generates. Acid gas removal units are used to remove C02 and hydrogen sulfide from raw natural gas streams and are commonly found at compressor stations in gathering and boosting systems, and at natural gas processing facilities. These units are listed in a facility's construction and operating permits, which are publicly available. Because this information is routinely available through required pennits, we propose these data elements be designated as "not CBI." 98.236( e )(1 )(xvi) Whether any dehydrator These proposed data elements would be emissions are vented to a vapor reported by onshore petroleum and natural recovery device. gas gathering and boosting facilities. These 98.236( e )(1 )(xvii) Whether any dehydrator data elements indicate that a facility is emissions are vented to a flare or equipped with dehydration units, the number regenerator firebox/fire tubes. of dehydrators used, the design of dehydrator used (glycol or desiccant), and how emissions 98.236( e )(1 )(xviii) For each glycol dehydrator with from dehydration units are handled by the an annual average daily natural facility. Dehydration units are used to remove gas throughput greater than or water from natural gas streams and are equal to 0.4 MMscfd, whether commonly found at compressor stations in any dehydrator emissions are gathering and boosting systems, and at natural vented to the atmosphere gas processing facilities. Because they are a without being routed to a flare or source of hazardous air pollutants, these units regenerator firebox/fire tubes. are subject to rigorous emissions control 98.236( e )(2)(iii) For glycol dehydrators with an requirements(~, 40 CFR part 63, subpart annual average daily natural gas HH). Dehydration units and their associated throughput less than 0.4 control devices are listed in a facility's MMscfd, whether any the total construction and operating permits, which are number of dehydrators were publicly available. For this reason, we venting to a vapor recovery propose these data elements be designated as device. "not CBI" for onshore petroleum and natural 98.236( e )(2)(iv) For glycol dehydrators with an gas gathering and boosting facilities. annual average daily natural gas throughput less than 0.4 MMscfd, the number of dehydrators venting to a control device other than a vapor

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Proposed Confidentiality Determination Citation Data Element and Rationale recovery device or a flare or regenerator firebox/fire tubes. 98.236(c)(2)(v) For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 MMscfd, whether any dehydrator emissions were vented to a flare or regenerator firebox/fire tubes. 98.236(e)(2)(v)(A) For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 MMscfd and vented to a flare or regenerator firebox, the total number of dehydrators 98.236(e )(3)(i) For dehydrators that use desiccant, the total number of dehydrators at the facility. 98.236(e)(3)(i) For dehydrators that use desiccant, the total number of dehydrators venting to a vapor recovery device. 98.236( e )(3)(i) For dehydrators that use desiccant, the number of dehydrators venting to a control device other than a vapor recovery device or a flare or regenerator firebox/fire tubes. 98.236(e )(3)(i) For dehydrators that use desiccant and vent to a flare or regenerator firebox, the total number of dehydrators. 98.236(e)(3)(i) For dehydrators that use desiccant and vent to a flare or regenerator firebox, the total number of dehydrators. 98.236(g) Whether the facility had any oil These proposed data elements would be well completions or workovers reported by onshore petroleum and natural with hydraulic fracturing in the gas production facilities and provide calendar year. infotmation on whether the facility conducted 98.236(g)(3) For each oil well completion or any oil well completions or workovers during workovcr and well type the reporting year, and for those facilities that combination, the total number of had well completions and/or workovers, the completions or workovers with number of completions and workovers that hydraulic fracturing. were completed and the cumulative flowback time. Infom1ation on the number of 98.236(g)(5)(i) If you used Equation W-lOA to completions and workovers perfom1ed by an calculate annual volumetric total oil and gas operator in a given year and the gas emissions for multiple wells,

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Proposed Confidentiality Determination Citation Data Element and Rationale the cumulative gas flowback age and production rates for wells can be time, in hours, for each sub- derived from or is available publicly on state basin, from when gas is first oil and gas commission Web sites. detected until sufficient Infonnation on the flowback time would be quantities are present to enable aggregated across multiple oil wells in a sub- separation ("Tr/' in Equation W- basin. Because disclosure of these data lOA). elements would not be likely to cause 98.236(g)(5)(i) If you used Equation W-lOA to substantial competitive harm, we propose calculate annual volumetric total these data elements be designated as "not gas emissions for multiple wells, CBI." the cumulative flowback time, in hours, for each sub-basin, after sufficient quantities of gas are present to enable separation ("Tr.s" in Equation W-1 OA). 98.236(i)(l)(i) If you calculated emissions from This proposed data element would be blowdown vent stacks by reported by onshore petroleum and natural equipment or event type, the gas gathering and boosting facilities and total number ofblowdowns in natural gas transmission pipeline facilities. the calendar year for the Blowdowns occur when equipment is taken equipment or event type (the out of service, either to be placed on standby sum of equation variable "N" or for maintenance purposes, and the natural from Equation W-14A or gas in the equipment is typically released to Equation W-14B of this subpart, the atmosphere. This practice may occur as for all unique physical volumes part of a routine scheduled maintenance or as for the equipment or event type). the result of an un-planned event (~, equipment breakdown). Although blowdown events may be associated with periods of reduced production or throughput, onshore petroleum and natural gas gathering and boosting facilities and natural gas transmission pipeline facilities typically have backup units that can be used to avoid production shutdowns. Hence, the number of blowdown events that occur during a reporting year does not indicate a plant was shut down and would not provide any potentially sensitive infonnation on the impact of such events on a facility's production or throughput. Hence, the disclosure of the number ofblowdowns occurring during a reporting year is not likely to cause substantial competitive harm. For this reason, we propose that this data element be designated "not CBI." 98.236G) If any of the atmospheric tanks These proposed data elements would be are observed to have reported by onshore petroleum and natural malfunctioning dump valves, gas gathering and boosting facilities and indicate that dump valves were provide information on malfunctioning of malfunctioning. dump valves on gas-liquid separators.

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Proposed Confidentiality Determination Citation Data Element and Rationale 98.236(j)(3)(i) If any of the gas-liquid separator Separators are used to separate hydrocarbons liquid dump valves did not close into liquid and gas phases and are typically properly during the reporting connected to atmospheric storage tanks where year, the total number of gas- the hydrocarbon liquids are stored. Dump liquid separators whose liquid valves on separators periodically release dump valves did not close I iquids from the separator. The time period properly during the calendar during which a dump valve is malfunctioning year. provides little insight into maintenance 98.236(j)(3 )(ii) If dump valves on multiple gas- practices or the nature or cost of repairs that liquid separators in a sub-basin are needed. Therefore, release of this did not close properly, the total information would not be likely to cause time the dump valves on gas- substantial competitive harm to reporters. For liquid separators did not close this reason, we are proposing these data properly in the calendar year, in elements be designated as "not CBL" hours (sum of"Tn" in Equation W-16). 98.236(z)(2)(iii) Type of fuel combusted. This data element would be reported by onshore petroleum and natural gas gathering and boosting facilities. This data element would provide information on the types of fuel burned. However, facilities in this segment generally burn fuels that are readily available to them as part of their operations. Information on the types of fuels burned by a facility is typically available in a facility's construction and operating permits. For these reasons, we consider that release of information on the types of fuels burned by onshore petroleum and natural gas gathering and boosting facilities would not be likely to cause substantive competitive harm and propose this data element be designated as "not CBI" for this industry segment. 98.236(aa)(ll)(i) The quantity of natural gas These proposed data elements would be received at all custody transfer reported by natural gas transmission pipeline stations in the calendar year, in companies, which are regionally concentrated thousand standard cubic feet. and have control over particular segments of This value may include meter the pipeline infrastructure. Existing pipeline corrections, but only for the construction and natural gas transmission calendar year covered by the technology and operations development annual report. information is generally well-known and 98.236(aa)(ll )(ii) The quantity of natural gas understood. It is possible that the limited withdrawn from in-system number of firms and the regional storage in the calendar year, in concentration could pose potential data thousand standard cubic feet. sensitivity issues. Firms in the natural gas transmission pipeline segment compete with 98.236(aa)(ll )(iii) The quantity of natural gas others in their region for shipments of natural added to in-system storage in the gas. Even though there may be only one calendar year, in thousand pipeline transmitting natural gas from one standard cubic feet.

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Proposed Confidentiality Determination Citation Data Element and Rationale 98.236(aa)(ll)(iv) The quantity of natural gas location to another, competition exists transferred to third parties such between firms that wish to accept shipments as LDCs or other transmission of natural gas within a given region, for pipelines, in thousand standard potential transmission to different endpoints. cubic feet. Such firms could make use of information 98.236(aa)(ll)(v) The quantity of natural gas about their competitors' throughput quantity consumed by the transmission and/or cost structure to strategically set their pipeline facility for operational prices or other contract tenns. Even though purposes, in thousand standard the market is regulated by FERC, actual cubic feet. contract prices may be set at levels below the FERC-mandated maximum tariff. However, the infonnation proposed to be collected is aggregated to the nationwide level, and small pipeline operations are unlikely to report as they are not expected to exceed the reporting threshold. In addition, these data elements are also reported to the Energy Information Administration (EfA) (~,natural gas withdrawn from storage, natural gas stored, gas received at city gate), and the ETA publishes the data on their Web site on an annual basis. Because disclosure of these proposed new data elements would not be likely to cause substantive competitive harm, we propose these data elements be designated as "not CBI." "Unit/Process 'Static' Characteristics That Are Not Inputs to Emission Eguations" Data Category 98.236(j)( 1)(xi) If using Calculation Method 1 or These data clements would he reported by 2, the number of wells sending onshore petroleum and natural gas gathering oil to gas-liquid separators or and boosting facilities. Separators are used to directly to atmospheric tanks. separate hydrocarbons into liquid and gas 98.236(j)(l )(xii) If using Calculation Method 1 or phases. Separators are typically connected to 2, the number of atmospheric atmospheric storage tanks (hydrocarbon tanks. tanks) where hydrocarbon liquids arc stored. The number of well-head separators sending 98.236(j)(l )(xiv)(A) If using Calculation Method 1 or oil to atmospheric tanks can vary widely 2, if any emissions from the depending on numerous conditions, including atmospheric tanks at your the sizing of the tank and throughput of the facility were controlled with separators, and the number of parties involved vapor recovery systems, the with handling or processing the separated number of atmospheric tanks constituents. Information on the count of that control emissions with atmospheric storage tanks with a throughput vapor recovery systems. above 500 barrels of oil per day is already 98.236(j)(l )(xvi)(A) If using Calculation Method 1 or publicly available in title V permits under the 2, if you controlled emissions EPA's National Emission Standards for from any atmospheric tanks at Hazardous Air Pollutants (NESIIAP) for Oil your facility with one or more and Gas Production ( 40 CFR part 63, subpart flares, the number of HB} Any additional information required atmospheric tanks that controlled under subpart W regarding the number of emissions with flares.

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Proposed Confidentiality Determination Citation Data Element and Rationale 98.236(j)(2)(i)(D) If using Calculation Method 3, wellhead separators is the same type of the number of atmospheric tanks information already made publicly available in the basin. through the NESHAP and thus is a reasonable 98.236(j)(2)(ii)(B) If using Calculation Method 3, expansion of that infonnation. Further, the number of atmospheric tanks information about the number of well-head in the sub-basin that did not separators sending oil to atmospheric tanks control emissions with flares, does not provide insight into the pertormance including those that have vapor (ability to separate hydrocarbon into different recovery. phases) or the overall operational efficiency for the facility that could cause substantial 98.23 6(j)(2 )(iii)(B) If using Calculation Method 3, competitive harm if disclosed. We propose the number of atmospheric tanks that these data elements be designated as "not in the sub-basin that controlled CBI." emissions with flares. 98.236(z)(1 )(ii) For each combustion unit type This data element would be reported by listed in §§ 98.236(z)(l ), the onshore petroleum and natural gas gathering total number of combustion and boosting facilities. This data element units. provides information on the number of internal and external combustion units located at these facilities. However, this information would not be likely to cause substantial competitive harm if released to the public, because internal and external combustion units are typical parts of an onshore petroleum and natural gas gathering and boosting facility and the total number of such units is not considered to be competitively sensitive information by this industry segment. Because disclosure of the number of combustion units would not be likely to cause substantive competitive harm to this segment, we propose this data element be designated as ''not CBI" when reported by onshore petroleum and natural gas gathering and boosting facilities.

98.236(aa)(ll)(vi) The miles of transmission This proposed data element would be pipeline in the facility. reported by natural gas transmission pipeline companies, which are regionally concentrated and have control over particular segments of the pipeline infrastructure. Existing pipeline construction and natural gas transmission technology and operations development information is generally well-known and understood. It is possible that the limited number of firms and the regional concentration could pose potential data sensitivity issues. Firms in the natural gas transmission pipeline segment compete with others in their region for shipments of natural

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D. Other Proposed Case-by-Case first step in the evaluation is important position.’’ See 40 CFR 2.208(e)(1). For Confidentiality Determinations for because emission data are not eligible each of these six data elements, we Subpart W for confidential treatment pursuant to determined whether the information is The proposed revision includes six section 114(c) of the CAA, which already available in the public domain. data elements that are production and/ precludes emissions data from being For those data elements for which no or throughput data from subpart W considered confidential and requires published data could be found, we facilities that would be newly reported that such data be made available to the evaluated whether their publication for the Onshore Petroleum and Natural public. The term ‘‘emission data’’ is would be likely to cause competitive Gas Gathering and Boosting segment. defined in 40 CFR 2.301(a). harm. Although these data elements are We propose to determine that none of For the proposed Onshore Petroleum similar in certain types or these six data elements are emission and Natural Gas Gathering and Boosting characteristics to the data elements in data under 40 CFR 2.301(a)(2)(i), segment, the EPA is proposing that five ‘‘Production/Throughput Data that are because they do not provide any data elements related to the throughput Not Inputs to Emissions Equations’’ or information characterizing actual GHG of each gathering and boosting facility ‘‘Raw Materials Consumed that are Not emissions or descriptive information be reported and one data element Inputs to Emissions Equations’’ data about the location or nature of the related to the amount of produced gas categories, for the reasons provided in emissions source. However, we note consumed by the facility be reported. Section III.B of this preamble, we are that this determination is made strictly These data elements are not publicly not proposing to assign these data in the context of the GHGRP and may available for all facilities operating in elements to a data category. Instead, we not apply to other regulatory programs. the Onshore Petroleum and Natural Gas are proceeding to make individual In the second step, we evaluate Gathering and Boosting segment, confidentiality determinations for these whether the data element is entitled to although they are publicly available for data elements. The proposed results of confidentiality treatment, based on the facilities in the Onshore Petroleum and these individual determinations are criteria for confidential treatment Natural Gas Production segment and the presented in Table 3 of this preamble. specified in 40 CFR 2.208. In particular, Onshore Natural Gas Processing As described in Section III.B of this the EPA focused on the following two segment.16 However, information for preamble, our proposed determinations factors: (1) Whether the data were for these data elements were based on already publicly available; and (2) 16 See the rationale for determining that similar data elements are not CBI for the onshore petroleum a two-step process in which we first whether ‘‘. . . disclosure of the and natural gas production segment and the natural evaluated whether the data element met information is likely to cause significant gas processing segment in the November 25, 2014 the definition of emission data. This harm to the business’ competitive preamble (79 FR 70352).

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some gathering and boosting systems is company operating the gathering and propose that these data, when reported available on the company Web site or in boosting system because it will not by the newly proposed onshore annual reports. In addition, even if the reveal information about the cost or petroleum and natural gas gathering and data are not available, companies profitability of providing that gathering boosting reporters, be designated as not operating in this segment enter into long service, or about the company’s ability CBI because their disclosure would not term agreements with natural gas to enter into new agreements and be likely to cause competitive harm to producers to gather natural gas. Once expand operations. In addition, the reporters in that industry segment. This these agreements are established, information will be aggregated to the proposed determination does not affect information that would be revealed from basin or sub-basin level rather than earlier determinations made for the data elements in Table 3 is not likely being reported for individual gathering reporters of the same data elements in to affect the competitive position of the and boosting systems. Therefore, we other industry segments.

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Table 3. Proposed Individual Confidentiality Determination for New Data Elements Proposed Confidentiality Determination and Citation Data Element Rationale Onshore Petrolewn and Natural Gas Gathering and Boosting 98.236(j)(2)(i)(A) If using Calculation Method We propose that each of these data elements be 3, the total annual designated as "not CBI." The Onshore oil/condensate throughput Petroleum and Natural Gas Gathering and that is sent to all atmospheric Boosting segment is a regionally concentrated tanks in the gathering and segment, with gathering lines and other boosting facility, in barrels. services located in fixed geological basins. 98.236( aa)(l O)(i) The quantity of produced gas Because of the amount of fixed assets required throughput in the calendar to operate in this segment (~, gathering lines year, in thousand standard and boosting stations), companies operating in cubic feet. this segment enter into long term agreements with natural gas producers to gather natural gas 98.236(aa)(1 O)(ii) The quantity of produced gas and transport it to natural gas processing consumed by the facility in facilities or, in some cases, transmission the calendar year, in pipelines. These agreements are for long thousand standard cubic feet. periods, lasting from several years to the life of 98.236(aa)( lO)(iii) The quantity ofproduced the lease for the producing wells, and establish condensate throughput in the the prices for gathering services for the life of calendar year, in barrels. the agreement. Once these agreements are 98.236(aa)(l O)(iv) The quantity of produced oil established, information on the actual throughput in the calendar throughput of the gathering and boosting year, in barrels. system is not likely to affect the competitive 98.236(aa)(l O)(v) The quantity of gas flared, position of the company operating the vented and/or unaccounted gathering and boosting system because it will for in the calendar year, in not reveal information about the cost or thousand standard cubic feet. profitability of providing that gathering service, or about the company's ability to enter into new agreements and expand operations. Data on the length, diameter, and pressure of gathering lines, and on the size (~, horsepower) of gathering compression stations is typically publicly available through construction and operating permits for these sources. These data can be used to determine the capacity of these systems, if it is not already reported elsewhere. Actual throughput of gathering and boosting systems, in terms of annual average daily throughput, is frequently included in the quarterly or annual reports for publicly traded companies and these are readily available on company Web sites. Annual throughput capacity and actual throughput is often also listed on gathering company Web sites. Based on the general availability of the actual throughput information, and the absence of an adverse competitive effect from revealing this information, the EPA is proposing that these data elements be considered "not CBI."

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E. Request for Comments on Proposed will be a reporter’s only opportunity to assertions regarding potential harm. Confidentiality Determinations substantiate a confidentiality claim for Please be as specific as possible in your For the CBI component of this the data elements identified in this comments and include all information rulemaking, we are specifically rulemaking. Upon finalizing the necessary for the EPA to evaluate your soliciting comment on the following confidentiality determinations of the comments. issues. First, we specifically seek data elements identified in this rule, the EPA will release or withhold these data IV. Impacts of the Proposed comment on the proposed data category Amendments to Subpart W assignments, and application of the in accordance with 40 CFR 2.301, which established categorical confidentiality contains special provisions governing A. Costs of the Proposed Amendments determinations to new data elements the treatment of Part 98 data for which As discussed in Section II of this assigned to categories with such confidentiality determinations have preamble, the EPA is proposing been made through rulemaking. determinations. If a commenter believes amendments to subpart W that would When submitting comments regarding that the EPA has improperly assigned add monitoring and reporting the confidentiality determinations we certain new data elements to any of the are proposing in this action, please requirements for reporters in three data categories established in the 2011 identify each individual data element industry segments: Onshore Petroleum Final CBI Rule, please provide specific you do or do not consider to be CBI or and Natural Gas Production, Onshore comments identifying which of these emission data in your comments. Please Petroleum and Natural Gas Gathering data elements may be mis-assigned explain specifically how the public and Boosting, and Onshore Natural Gas along with a detailed explanation of release of that particular data element Transmission Pipeline. why you believe them to be incorrectly would or would not cause a competitive Reporters in the Onshore Petroleum assigned and in which data category you disadvantage to a facility. Discuss how and Natural Gas Production segment believe they belong. In addition, if you this data element may be different from would have to monitor and report believe that a data element should be or similar to data that are already emissions and data elements associated assigned to one of the two direct emitter publicly available. Please submit with oil well completions and data categories that do not have a information identifying any publicly workovers with hydraulic fracturing. categorical confidentiality available sources of information Reporters in this segment would also determination, please also provide containing the specific data elements in have to report the well identification specific comment along with detailed question. Data that are already available numbers associated with individual oil rationale and supporting information on through other sources would likely be and gas wells, and when reporting whether such data element does or does found not to qualify for CBI protection. emissions for certain pieces of not qualify as CBI. In your comments, please identify the equipment, such as acid gas removal We also seek comment on the manner and location in which each units, dehydrators, tanks, and flares, proposed individual confidentiality specific data element you identify is that are associated with individual oil determinations for the following data publicly available, including a citation. and gas wells. The addition of the elements: 26 data elements assigned to If the data are physically published, requirement to report emissions the ‘‘Unit/Process Operating such as in a book, industry trade associated with oil well completions Characteristics That Are Not Inputs to publication, or federal agency and workovers with hydraulic fracturing Emission Equations’’ data category; 10 publication, provide the title, volume is expected to cause an increase in the data elements assigned to the ‘‘Unit/ number (if applicable), author(s), amount of emissions that would count Process ‘Static’ Characteristics That Are publisher, publication date, and towards determining applicability with Not Inputs to Emission Equations’’ International Standard Book Number subpart W. The proposed addition of category; and six data elements for (ISBN) or other identifier. For data reporting requirements for oil wells which no data category assignment was published on a Web site, provide the with hydraulic fracturing is expected to proposed. address of the Web site and the date you affect 246 existing reporters and to By proposing confidentiality last visited the Web site and identify the cause approximately 50 new reporters to determinations prior to data reporting Web site publisher and content author. exceed the reporting threshold for the through this proposal and rulemaking If your concern is that competitors onshore petroleum and natural gas process, we provide reporters an could use a particular data element to production facility. opportunity to submit comments, in discern sensitive information, Reporters in the Onshore Petroleum particular comments identifying data specifically describe the pathway by and Natural Gas Gathering and Boosting they consider sensitive and their which this could occur and explain how segment would need to estimate and rationales and supporting the discerned information would report emissions data and related data documentation; this opportunity is the negatively affect your competitive elements associated with several same opportunity that is afforded to position. Describe any unique process or different emission sources within this submitters of information in case-by- aspect of your facility that would be newly proposed industry segment. case confidentiality determinations revealed if the particular data element Approximately 200 new reporters are made in response to individual claims you consider sensitive were made expected to be subject to subpart W due for confidential treatment not made publicly available. If the data element to the proposed amendments for the through rulemaking. It provides an you identify would cause harm only Onshore Petroleum and Natural Gas opportunity to rebut the agency’s when used in combination with other Gathering and Boosting segment in this proposed determinations prior to publicly available data, then describe rulemaking. finalization. We will evaluate the the other data, identify the public Reporters in the Onshore Natural Gas comments on our proposed source(s) of these data, and explain how Transmission Pipeline segment would determinations, including claims of the combination of data could be used need to estimate and report emissions confidentiality and information to cause competitive harm. Describe the data and related data elements substantiating such claims, before measures currently taken to keep the associated with transmission pipeline finalizing the confidentiality data confidential. Avoid conclusory and blowdown activities. Approximately determinations. Please note that this unsubstantiated statements, or general 150 new reporters are expected to be

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subject to subpart W due to the Fairness Act (SBREFA), the EPA as a percentage of sales and determines proposed amendments in this assessed the potential impacts of these whether the ratio exceeds 1 percent.17 rulemaking. amendments on small entities (small The cost-to-sales ratios were constructed The proposed amendments to subpart businesses, governments, and non-profit at the establishment level (average W are not expected to significantly organizations). (See Section V.C of this reporting program costs per increase burden. See the memorandum, preamble for definitions of small establishment/average establishment ‘‘Assessment of Impacts of the 2015 entities.) receipts) for several business size Proposed Revisions to Subpart W’’ in ranges. This allowed the EPA to account Docket ID No. EPA–HQ–OAR–2014– The EPA conducted a screening for receipt differences between 0831 for additional information. assessment comparing compliance costs to onshore petroleum and natural gas establishments owned by large and B. Impacts of the Proposed production specific receipts data for small businesses and differences in Amendments on Small Businesses establishments owned by small small business definitions across As required by the Regulatory businesses. This ratio constitutes a affected industries. The results of the Flexibility Act (RFA) and Small ‘‘sales’’ test that computes the screening assessment are shown in Business Regulatory Enforcement and annualized compliance costs of this rule Table 4 of this preamble.

TABLE 4—ESTIMATED COST-TO-SALES RATIOS FOR FIRST YEAR COSTS BY INDUSTRY AND ENTERPRISE SIZE A

Owned by enterprises with: Average All en- 100 to 500 to <20 20 to 499 <500 999 1,000 SBA size standard cost per ter- em- 99 em- em- to Industry segment NAICS NAICS description (effective January entity prises ploy- em- ploy- em- 2,499 22, 2014) ($1,000/ (per- ploy- ploy- ploy- ees b ees ees em- entity) cent) (per- (per- ees (per- ees ploy- cent) (per- (per- cent) cent) cent) cent) ees

Onshore Petroleum 211 Oil and Gas Extrac- 500 employees...... $29.36 0.07 0.43 0.03 0.01 0.09 0.00 0.00 and Natural Gas tion. Production. 213111 Drilling Oil and Gas 500 employees...... 29.36 0.28 1.00 0.32 0.06 0.19 0.02 0.01 Wells. 213112 Support Activities for $35.5 million...... 29.36 0.45 1.24 0.39 0.08 0.33 0.02 NA Oil and Gas Oper- ations. 221 Utilities...... 500 employees...... 29.36 0.08 0.84 0.14 0.06 0.19 0.04 NA 486 Pipeline Transpor- $25.5 million...... 29.36 0.29 0.44 0.18 0.26 0.26 0.33 NA tation. Onshore Natural 211 Oil and Gas Extrac- 500 employees...... 3.19 0.01 0.05 0.00 0.00 0.01 0.00 0.00 Gas Transmission tion. Pipeline. 213111 Drilling Oil and Gas 500 employees...... 3.19 0.03 0.11 0.03 0.01 0.02 0.00 0.00 Wells. 213112 Support Activities for $35.5 million...... 3.19 0.05 0.13 0.04 0.01 0.04 0.00 NA Oil and Gas Oper- ations. 221 Utilities...... 500 employees...... 3.19 0.01 0.09 0.01 0.01 0.02 0.00 NA 486 Pipeline Transpor- $25.5 million...... 3.19 0.03 0.05 0.02 0.03 0.03 0.04 NA tation. Onshore Petroleum 211 Oil and Gas Extrac- 500 employees...... 24.70 0.06 0.36 0.03 0.01 0.08 0.00 0.00 and Natural Gas tion. Gathering and Boosting. 213111 Drilling Oil and Gas 500 employees...... 24.70 0.23 0.84 0.27 0.05 0.16 0.02 0.01 Wells. 213112 Support Activities for $35.5 million...... 24.70 0.38 1.04 0.32 0.07 0.27 0.02 NA Oil and Gas Oper- ations. 221 Utilities...... 500 employees...... 24.70 0.07 0.70 0.12 0.05 0.16 0.04 NA 486 Pipeline Transpor- $25.5 million...... 24.70 0.24 0.37 0.15 0.22 0.22 0.28 NA tation. a 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 Small Business Administration (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 typi- cally used for SBREFA screening analyses. b 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.

17 The EPA’s RFA guidance for rule writers preferred quantitative metric for economic impact suggests the ‘‘sales’’ test continues to be the screening analysis.

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As shown, the cost-to-sales ratios are Orders 12866 and 13563 (76 FR 3821, suggested methods for minimizing less than 1 percent for all January 21, 2011). respondent burden, the EPA has establishments, except the ratio for the established a public docket for this rule, B. Paperwork Reduction Act 1–20 employee range for facilities in the which includes this ICR, under Docket Onshore Petroleum and Natural Gas The information collection ID number EPA–HQ–OAR–2014–0831. Production segment with NAICS code requirements in this proposed rule have Submit any comments related to the ICR 213111, which is 1 percent, and the been submitted for approval to OMB to the EPA and OMB. See ADDRESSES ratios for the 1–20 employee range for under the Paperwork Reduction Act, 44 section at the beginning of this proposed facilities in the Onshore Petroleum and U.S.C. 3501 et seq. The Information rule for where to submit comments to Natural Gas Production and Onshore Collection Request (ICR) document the EPA. Send comments to OMB at the Petroleum and Natural Gas Gathering prepared by the EPA has been assigned Office of Information and Regulatory and Boosting segments with NAICS EPA ICR number 2300.16. OMB has Affairs, Office of Management and code 213112, which are greater than 1 previously approved the information Budget, 725 17th Street NW., percent but less than 2 percent. The collection requirements for 40 CFR part Washington, DC 20503, Attention: Desk petroleum and natural gas industry has 98 under the provisions of the Office for the EPA. Since OMB is a large number of enterprises, the Paperwork Reduction Act, 44 U.S.C. required to make a decision concerning majority of them in the 1–20 employee 3501 et seq., and has assigned OMB the ICR between 30 and 60 days after range. However, a large fraction of control number 2060–0629. December 9, 2014, a comment to OMB production comes from large This action proposes to add is best assured of having its full effect corporations and not those with less monitoring and reporting requirements if OMB receives it by January 8, 2015. than 20 employee enterprises. The for reporters in three industry segments: The final rule will respond to any OMB Onshore Petroleum and Natural Gas smaller enterprises in most cases deal or public comments on the information Production, Onshore Petroleum and with very small operations (such as a collection requirements contained in Natural Gas Gathering and Boosting, single family owning a few production this proposal. We continue to be and Onshore Natural Gas Transmission wells) that are unlikely to cross the interested in the potential impacts of Pipeline. Impacts associated with the 25,000 metric tons CO e threshold this proposed action on the burden 2 proposed changes to the monitoring and considered for the rule. An exception to associated with the proposed reporting requirements are detailed in such a scenario is a small (less than 20 amendments and welcome comments the memorandum ‘‘Assessment of employee) enterprise owning large on issues related to such impacts. Impacts of the 2015 Proposed Revisions operations but conducting nearly all of to Subpart W’’ (see Docket ID No. EPA– C. Regulatory Flexibility Act its operations through contractors. This HQ–OAR–2014–0831). Burden is The Regulatory Flexibility Act (RFA) is not an uncommon practice in the defined at 5 CFR 1320.3(b). generally requires an agency to prepare Onshore Petroleum and Natural Gas The estimated projected cost and hour a regulatory flexibility analysis of any Production segment. Such enterprises, burden associated with reporting for the rule subject to notice and comment however, are a very small group among proposed amendments to subpart W rulemaking requirements under the the almost 16,000 enterprises in the less affecting the three industry segments are Administrative Procedure Act or any than 20 employee category, and the EPA $7.2 million and 73,000 hours, other statute unless the agency certifies proposes to cover them in the rule. respectively. For the hour burden, the that the rule will not have a significant The EPA took a conservative estimated average burden hours per new economic impact on a substantial approach with the model entity response is 113 hours, the proposed number of small entities. Small entities analysis. Although the appropriate SBA frequency of response is once annually, include small businesses, small size definition should be applied at the and the estimated number of likely new organizations, and small governmental parent company (enterprise) level, data respondents that would result from jurisdictions. limitations allowed us only to compute these proposed amendments is For purposes of assessing the impacts and compare ratios for a model approximately 400. of today’s proposed rule on small establishment within several enterprise The estimated total projected cost and entities, small entity is defined as: (1) A size ranges. hour burden associated with all ten small business as defined by the Small Although this rule will not have a subpart W industry segments are Business Administration’s regulations at significant economic impact on a 317,400 hours and $29.2 million per 13 CFR 121.201; (2) a small substantial number of small entities, the year for a 3-year period, where identical governmental jurisdiction that is a agency nonetheless tried to reduce the annual costs are anticipated for all 3 government of a city, county, town, impact of this rule on small entities. See years. The average annual burden to the school district or special district with a Section V.C of this preamble for more EPA for this period is estimated to be population of less than 50,000; and (3) detail on the measures taken by the EPA 10,400 hours for oversight activities. a small organization that is any not-for- to ensure that the burdens imposed on The annual reporting and recordkeeping profit enterprise which is independently small entities would be minimal. burden for this collection of information owned and operated and is not V. Statutory and Executive Order is estimated to average 63.4 hours per dominant in its field. Reviews response. After considering the economic An agency may not conduct or impacts of these proposed rule A. Executive Order 12866: Regulatory sponsor, and a person is not required to amendments on small entities, I certify Planning and Review and Executive respond to, a collection of information that this action would not have a Order 13563: Improving Regulation and unless it displays a currently valid OMB significant economic impact on a Regulatory Review control number. The OMB control substantial number of small entities. This action is not a ‘‘significant numbers for the EPA’s regulations in 40 The small entities directly regulated by regulatory action’’ under the terms of CFR are listed in 40 CFR part 9. this proposed rule include small Executive Order 12866 (58 FR 51735, To comment on the agency’s need for businesses in the petroleum and gas October 4, 1993) and is therefore not this information, the accuracy of the industry. The EPA has determined that subject to review under Executive provided burden estimates, and any some small businesses would be

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affected because their production requirements that might significantly or that is not required by statute, unless processes emit GHGs exceeding the uniquely affect small governments. As the federal government provides the reporting threshold. This action discussed in Section V.B of this funds necessary to pay the direct includes proposed amendments that preamble, the total collective impact on compliance costs incurred by tribal may result in a burden increase on regulated entities is $7.2 million governments, or the EPA consults with subpart W reporters, but the EPA has annually. Because this impact on each tribal officials early in the process of determined that it is not a significant individual facility is estimated to be developing the proposed regulation and increase. See Section IV.B of this approximately $9,000 annually, the EPA develops a tribal summary impact preamble for more details on the has determined that the provisions in statement. analysis of the potential impact of this this action would not significantly The EPA has concluded that this proposal on small business entities. impact small governments. In addition, action may have tribal implications. Although this proposed rule will not because none of the provisions apply However, it will neither impose have a significant economic impact on specifically to small governments, the substantial direct compliance costs on a substantial number of small entities, EPA has determined that the provisions tribal governments, nor preempt tribal the EPA nonetheless has tried to reduce in this action would not uniquely law. This action proposes to add the impact of this rule on small entities. impact small governments. Therefore, monitoring and reporting requirements As part of the process of finalization of this action is not subject to the for reporters in three industry segments: the final subpart W rule, the EPA took requirements of section 203 of the Onshore Petroleum and Natural Gas several steps to evaluate the effect of the UMRA. Production, Onshore Petroleum and rule on small entities. For example, the E. Executive Order 13132: Federalism Natural Gas Gathering and Boosting, EPA determined appropriate thresholds and Onshore Natural Gas Transmission This action does not have federalism that reduced the number of small Pipeline. This action also proposes implications. It will not have substantial businesses reporting. In addition, the confidentiality determinations for direct effects on the states, on the EPA supports a ‘‘help desk’’ for the reported data elements. This regulation relationship between the national GHGRP, which would be available to would apply directly to petroleum and government and the states, or on the answer questions on the provisions in natural gas facilities that emit distribution of power and this rulemaking. Finally, the EPA greenhouses gases. Although few responsibilities among the various continues to conduct significant facilities that would be subject to the levels of government, as specified in outreach on the GHG reporting rule and rule are likely to be owned by tribal Executive Order 13132. For a more maintains an ‘‘open door’’ policy for governments, it is possible that there detailed discussion about how Part 98 stakeholders to help inform the EPA’s may be some facilities owned by tribal relates to existing state programs, please understanding of key issues for the governments. industries. We continue to be interested see Section II of the preamble to the The EPA consulted with tribal in the potential impacts of the proposed final Part 98 rule (74 FR 56266, October rule amendments on small entities and 30, 2009). officials early in the process of welcome comments on issues related to This action proposes to add developing subpart W to permit them to such impacts. monitoring and reporting requirements have meaningful and timely input into for reporters in three industry segments: its development. In particular, the EPA D. Unfunded Mandates Reform Act Onshore Petroleum and Natural Gas sought opportunities to provide The proposed amendments and Production, Onshore Petroleum and information to tribal governments and confidentiality determinations do not Natural Gas Gathering and Boosting, representatives during the development contain a federal mandate that may and Onshore Natural Gas Transmission of the proposed and final subpart W that result in expenditures of $100 million or Pipeline. This action also proposes was promulgated on November 30, 2010 more for State, local, and tribal confidentiality determinations for (75 FR 74458). For additional governments, in the aggregate, or the reported data elements. Few, if any, information about the EPA’s private sector in any one year. This state or local government facilities interactions with tribal governments, action proposes to add monitoring and would be affected by the provisions in see Section IV.F of the preamble to the reporting requirements for reporters in this proposed rule. This regulation also re-proposal of subpart W published on three industry segments: Onshore does not limit the power of States or April 12, 2010 (75 FR 18608), and Petroleum and Natural Gas Production, localities to collect GHG data and/or Section IV.F of the preamble to the final Onshore Petroleum and Natural Gas regulate GHG emissions. Thus, subpart W published on November 30, Gathering and Boosting, and Onshore Executive Order 13132 does not apply 2010 (75 FR 74458). Natural Gas Transmission Pipeline. This to this action. The EPA specifically solicits action also proposes confidentiality In the spirit of Executive Order 13132, additional comment on this proposed determinations for reported data and consistent with the EPA policy to action from tribal officials. elements. As discussed in Section V.B promote communications between the G. Executive Order 13045: Protection of of this preamble, for the first year, the EPA and state and local governments, Children From Environmental Health estimated total projected cost and hour the EPA specifically solicits comment Risks and Safety Risks burden associated with reporting for the on this proposed action from state and proposed amendments to subpart W local officials. The EPA interprets Executive Order affecting the three industry segments are 13045 (62 FR 19885, April 23, 1997) as $7.2 million and 73,000 hours, F. Executive Order 13175: Consultation applying only to those regulatory respectively. Thus, this proposed rule is and Coordination With Indian Tribal actions that concern health or safety not subject to the requirements of Governments risks, such that the analysis required section 202 and 205 of the Unfunded Subject to the Executive Order 13175 under section 5–501 of the Executive Mandates Reform Act of 1995 (UMRA). (65 FR 67249, November 9, 2000) the Order has the potential to influence the This rule is also not subject to the EPA may not issue a regulation that has regulation. This proposed action is not requirements of section 203 of UMRA tribal implications, that imposes subject to Executive Order 13045 because it contains no regulatory substantial direct compliance costs, and because it does not establish an

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environmental standard intended to populations and low-income gas transmission pipelines as defined in mitigate health or safety risks. populations in the United States. § 98.238. H. Executive Order 13211: Actions That The EPA has determined that these * * * * * Significantly Affect Energy Supply, proposed rule amendments will not ■ 3. Section 98.231 is amended by Distribution, or Use have disproportionately high and revising paragraph (a) to read as follows: adverse human health or environmental This proposed action is not a effects on minority or low-income § 98.231 Reporting threshold. ‘‘significant energy action’’ as defined in populations because the amendments (a) You must report GHG emissions Executive Order 13211 (66 FR 28355, do not affect the level of protection under this subpart if your facility May 22, 2001), because it is not likely provided to human health or the contains petroleum and natural gas to have a significant adverse effect on environment. This is because the systems and the facility meets the the supply, distribution, or use of proposed amendments address requirements of § 98.2(a)(2), except for energy. Part 98 relates to monitoring, information collection and reporting the industry segments in paragraphs reporting, and recordkeeping and does and verification procedures. (a)(1) through (4) of this section. not impact energy supply, distribution, (1) Facilities must report emissions or use. This action proposes to add List of Subjects in 40 CFR Part 98 from the onshore petroleum and natural monitoring and reporting requirements Environmental protection, gas production industry segment only if for reporters in three industry segments: Administrative practice and procedure, emission sources specified in paragraph Onshore Petroleum and Natural Gas Greenhouse gases, Reporting and § 98.232(c) emit 25,000 metric tons of Production, Onshore Petroleum and recordkeeping requirements. CO2 equivalent or more per year. Natural Gas Gathering and Boosting, Dated: November 13, 2014. (2) Facilities must report emissions and Onshore Natural Gas Transmission from the natural gas distribution Gina McCarthy, Pipeline. This action also proposes industry segment only if emission confidentiality determinations for Administrator. sources specified in paragraph reported data elements. For the reasons stated in the § 98.232(i) emit 25,000 metric tons of I. National Technology Transfer and preamble, title 40, chapter I, of the Code CO2 equivalent or more per year. Advancement Act of Federal Regulations as amended (3) Facilities must report emissions November 25, 2014 at 79 FR 70351, and from the onshore petroleum and natural Section 12(d) of the National effective January 1, 2015, is proposed to gas gathering and boosting industry Technology Transfer and Advancement be further amended as follows: segment only if emission sources Act of 1995 (NTTAA), Public Law 104– specified in paragraph § 98.232(j) emit 113, 12(d) (15 U.S.C. 272 note) directs PART 98—MANDATORY 25,000 metric tons of CO2 equivalent or the EPA to use voluntary consensus GREENHOUSE GAS REPORTING more per year. standards in its regulatory activities (4) Facilities must report emissions unless to do so would be inconsistent ■ 1. The authority citation for part 98 from the onshore natural gas with applicable law or otherwise continues to read as follows: transmission pipeline industry segment impractical. Voluntary consensus Authority: 42 U.S.C. 7401, et seq. only if emission sources specified in standards are technical standards (e.g., § 98.232(m) emit 25,000 metric tons of materials specifications, test methods, Subpart W—Petroleum and Natural CO2 equivalent or more per year. sampling procedures, and business Gas Systems * * * * * practices) that are developed or adopted ■ 4. Section 98.232 is amended by: by voluntary consensus standards ■ 2. Section 98.230 is amended by ■ a. Revising paragraphs (a) and (c)(6) bodies. NTTAA directs the EPA to adding paragraphs (a)(9) and (10) to read and (8); provide Congress, through OMB, as follows: ■ b. Adding paragraph (j); explanations when the agency decides §§ 98.230 Definition of the source ■ c. Revising paragraph (k); and not to use available and applicable category. ■ d. Adding paragraph (m). voluntary consensus standards. The revisions and additions read as This proposed rulemaking does not (a) * * * follows: involve any new technical standards. (9) Onshore petroleum and natural Therefore, the EPA is not considering gas gathering and boosting. Onshore § 98.232 GHGs to report. petroleum and natural gas gathering and the use of any voluntary consensus (a) You must report CO , CH , and boosting means gathering pipelines and 2 4 standards. N O emissions from each industry other equipment used to collect 2 segment specified in paragraphs (b) J. Executive Order 12898: Federal petroleum and/or natural gas from through (j) and (m) of this section, CO , Actions To Address Environmental onshore production gas or oil wells and 2 CH , and N O emissions from each flare Justice in Minority Populations and used to compress, dehydrate, sweeten, 4 2 as specified in paragraph (b) through (j) Low-Income Populations or transport the gas to a natural gas of this section, and stationary and Executive Order 12898 (59 FR 7629, processing facility, a natural gas portable combustion emissions as February 16, 1994) establishes federal transmission pipeline or to a natural gas applicable as specified in paragraph (k) executive policy on environmental distribution pipeline. Gathering and of this section. justice. Its main provision directs boosting equipment includes, but is not federal agencies, to the greatest extent limited to gathering pipelines, * * * * * practicable and permitted by law, to separators, compressors, acid gas (c) * * * make environmental justice part of their removal units, dehydrators, pneumatic (6) Well venting during well mission by identifying and addressing, devices/pumps, storage vessels, engines, completions with hydraulic fracturing. as appropriate, disproportionately high boilers, heaters, and flares. * * * * * and adverse human health or (10) Onshore natural gas transmission (8) Well venting during well environmental effects of their programs, pipeline. Onshore natural gas workovers with hydraulic fracturing. policies, and activities on minority transmission pipeline means all natural * * * * *

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(j) For an onshore petroleum and ■ 5. Section 98.233 is amended by: (2) For the onshore petroleum and natural gas gathering and boosting ■ a. Revising the parameters ‘‘EFt’’ and natural gas production industry facility, report CO2, CH4, and N2O ‘‘GHGi’’ of Equation W–1 in paragraph segment, you have the option in the first emissions from the following source (a); two consecutive calendar years to ■ types: b. Revising paragraph (a)(2); determine ‘‘Countt’’ for Equation W–1 of (1) Natural gas pneumatic device ■ c. Revising the parameter ‘‘EF’’ of this subpart for each type of natural gas venting. Equation W–2 in paragraph (c); pneumatic device (continuous high ■ d. Revising paragraph (d)(8)(iii); (2) Natural gas driven pneumatic ■ bleed, continuous low bleed, and pump venting. e. Revising paragraphs (g) intermittent bleed) using engineering (3) Acid gas removal vents. introductory text, (g)(1) introductory estimates based on best available data. (4) Dehydrator vents. text, (g)(1)(i) and the paragraph (g)(1)(ii) For the onshore petroleum and natural heading; (5) Blowdown vent stacks. gas gathering and boosting industry ■ f. Revising the parameters ‘‘FRM ,’’ (6) Storage tank vented emissions. s segment, you have the option in the first ‘‘FRs,p’’ and ‘‘PRs,p’’ of Equation W–12A (7) Flare stack emissions. in paragraph (g)(1)(iii); two consecutive calendar years to (8) Centrifugal compressor venting. determine ‘‘Countt’’ for Equation W–1 of ■ g. Revising the parameters ‘‘FRMi,’’ (9) Reciprocating compressor venting. this subpart for each type of natural gas and ‘‘PRs,p’’ of Equation W–12B in (10) Equipment leaks from valves, paragraph (g)(1)(iv); pneumatic device (continuous high connectors, open ended lines, pressure ■ h. Revising paragraphs (g)(1)(v) and bleed, continuous low bleed, and relief valves, pumps, flanges, and other (vi); intermittent bleed) using engineering equipment leak sources (such as ■ i. Adding paragraph (g)(1)(vii); estimates based on best available data. instruments, loading arms, stuffing ■ j. Revising paragraph (g)(2) * * * * * boxes, compressor seals, dump lever introductory text; (c) * * * arms, and breather caps). ■ k. Adding paragraph (g)(2)(iv); * * * * * (11) Gathering pipeline equipment ■ l. Revising paragraph (g)(4) leaks. introductory text; EF = Population emissions factors for natural ■ m. Revising paragraphs (j) gas driven pneumatic pumps (in (12) You must use the methods in standard cubic feet per hour per pump) § 98.233(z) and report under this introductory text, (j)(1) introductory listed in Table W–1A of this subpart for subpart the emissions of CO2, CH4, and text, and (j)(6); onshore petroleum and natural gas ■ N2O from stationary or portable fuel n. Revising paragraph (n)(2)(i); production and onshore petroleum and ■ combustion equipment that cannot o. Revising paragraphs (o) natural gas gathering and boosting move on roadways under its own power introductory text and (o)(10); facilities. ■ p. Revising paragraphs (p) and drive train, and that is located at an * * * * * onshore petroleum and natural gas introductory text and (p)(10); ■ q. Revising paragraphs (r) (d) * * * gathering and boosting facility as introductory text and (r)(2); (8) * * * defined in § 98.238. Stationary or ■ r. Revising paragraphs (u)(2)(i) and (iii) If a continuous gas analyzer is not portable equipment includes the (iii); and available or installed, you may use the following equipment, which are integral ■ x. Revising paragraphs (z) outlet pipeline quality specification for to the movement of natural gas: natural introductory text and (z)(1)(ii). CO2 in natural gas. gas dehydrators, natural gas The revisions and additions read as * * * * * compressors, electrical generators, follows: (g) Well venting during completions steam boilers, and process heaters. and workovers with hydraulic (k) Report under subpart C of this part § 98.233 Calculating GHG emissions. fracturing. Calculate annual volumetric (General Stationary Fuel Combustion * * * * * natural gas emissions from gas well and Sources) the emissions of CO2, CH4, and (a) * * * oil well venting during completions and N2O from each stationary fuel * * * * * workovers involving hydraulic combustion unit by following the EFt = Population emission factors for natural fracturing using Equation W–10A or requirements of subpart C except for gas pneumatic device vents (in standard Equation W–10B of this section. facilities under onshore petroleum and cubic feet per hour per device) of each Equation W–10A applies to well venting natural gas production, onshore type ‘‘t’’ listed in Tables W–1A, W–3, when the gas flowback rate is measured petroleum and natural gas gathering and and W–4 of this subpart for onshore from a specified number of example boosting, and natural gas distribution. petroleum and natural gas production, completions or workovers and Equation Onshore petroleum and natural gas onshore natural gas transmission compression, and underground natural W–10B applies when the gas flowback production facilities must report gas storage facilities, respectively. vent or flare volume is measured for stationary and portable combustion Onshore petroleum and natural gas each completion or workover. emissions as specified in paragraph (c) gathering and boosting facilities must Completion and workover activities are of this section. Natural gas distribution use the population emission factors separated into two periods, an initial facilities must report stationary listed in Table W–1A. period when flowback is routed to open combustion emissions as specified in GHGi = For onshore petroleum and natural pits or tanks and a subsequent period gas production facilities, onshore paragraph (i) of this section. Onshore when gas content is sufficient to route petroleum and natural gas gathering and petroleum and natural gas gathering and boosting facilities, onshore natural gas the flowback to a separator or when the boosting facilities must report stationary transmission compression facilities, and gas content is sufficient to allow and portable combustion emissions as underground natural gas storage measurement by the devices specified in specified in paragraph (j) of this section. facilities, concentration of GHGi, CH4 or paragraph (g)(1) of this section, * * * * * CO2, in produced natural gas or regardless of whether a separator is (m) For onshore natural gas processed natural gas for each facility as actually utilized. If you elect to use specified in paragraphs (u)(2)(i), (iii), and transmission pipeline, report CO2 and (iv) of this section. Equation W–10A of this section, you CH4 emissions from blowdown vent must follow the procedures specified in stacks. * * * * * paragraph (g)(1) of this section. If you

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elect to use Equation W–10B, you must and workovers, for each sub-basin, and section. If emissions from well venting use a recording flow meter installed on for each well type combination during completions and workovers with the vent line, downstream of a separator identified in paragraph (g)(2) of this hydraulic fracturing are routed to a and ahead of a flare or vent, to measure section. You must calculate CH4 and flare, you must calculate CH4, CO2, and the gas flowback. Emissions must be CO2 volumetric and mass emissions as N2O annual emissions as specified in calculated separately for completions specified in paragraph (g)(3) of this paragraph (g)(4) of this section.

Where: procedures specified in paragraph follows: Complete measurements or Es,n = Annual volumetric natural gas (g)(1)(vii) of this section. calculations for at least one completion emissions in standard cubic feet from gas EnFs,p = Volume of N2 injected gas in cubic or workover for less than or equal to 25 venting during well completions or feet at standard conditions that was completions or workovers for each well workovers following hydraulic fracturing injected into the reservoir during an energized fracture job for each well, p, as type combination within a sub-basin; for each sub-basin and well type complete measurements or calculations combination. determined by using an appropriate W = Total number of wells completed or meter according to methods described in for at least two completions or worked over using hydraulic fracturing § 98.234(b), or by using receipts of gas workovers for 26 to 50 completions or in a sub-basin and well type purchases that are used for the energized workovers for each sub-basin and well combination. fracture job. Convert to standard type combination; complete conditions using paragraph (t) of this Tp,s = Cumulative amount of time of measurements or calculations for at section. If the fracture process did not flowback, after sufficient quantities of least three completions or workovers for gas are present to enable separation, inject gas into the reservoir or if the injected gas is CO2 then EnFs,p is 0. 51 to 100 completions or workovers for where gas vented or flared for the each sub-basin and well type completion or workover, in hours, for FVs,p = Flow volume of vented or flared gas each well, p, in a sub-basin and well for each well, p, in standard cubic feet combination; complete measurements or type combination during the reporting per hour measured using a recording calculations for at least four year. This may include non-contiguous flow meter (digital or analog) on the vent completions or workovers for 101 to 250 periods of venting or flaring. line to measure gas flowback during the completions or workovers for each sub- T = Cumulative amount of time of flowback separation period of the completion or p,i workover according to methods set forth basin and well type combination; and to open tanks/pits, from when gas is first in § 98.234(b). complete measurements or calculations detected until sufficient quantities of gas FR = Flow rate vented or flared of each for at least five completions or are present to enable separation, for the p,i well, p, in standard cubic feet per hour workovers for greater than 250 completion or workover, in hours, for measured using a recording flow meter each well, p, in a sub-basin and well completions or workovers for each sub- (digital or analog) on the vent line to type combination during the reporting basin and well type combination. measure the flowback, at the beginning year. This may include non-contiguous (i) Calculation Method 1. You must of the period of time when sufficient periods of routing to open tanks/pits. quantities of gas are present to enable use Equation W–12A as specified in FRMs = Ratio of average gas flowback, during separation, of the completion or paragraph (g)(1)(iii) of this section to the period when sufficient quantities of workover according to methods set forth determine the value of FRMs. You must gas are present to enable separation, of in § 98.234(b). use Equation W–12B as specified in well completions and workovers from paragraph (g)(1)(iv) of this section to hydraulic fracturing to 30-day gas (1) If you elect to use Equation W– production rate for the sub-basin and 10A of this section on gas wells, you determine the value of FRMi. The well type combination, calculated using must use Calculation Method 1 as procedures specified in paragraphs procedures specified in paragraph specified in paragraph (g)(1)(i) of this (g)(1)(v) and (vi) of this section also (g)(1)(iii) of this section, expressed in section, or Calculation Method 2 as apply. When making gas flowback standard cubic feet per hour. specified in paragraph (g)(1)(ii) of this measurements for use in Equations W– FRMi = Ratio of initial gas flowback rate 12A and W–12B of this section, you section, to determine the value of FRMs during well completions and workovers must use a recording flow meter (digital from hydraulic fracturing to 30-day gas and FRMi. If you elect to use Equation W–10A of this section on oil wells, you or analog) installed on the vent line, production rate for the sub-basin and downstream of a separator and ahead of well type combination, calculated using must use Calculation Method 1 as procedures specified in paragraph specified in paragraph (g)(1)(i) of this a flare or vent, to measure the gas flowback rates in units of standard cubic (g)(1)(iv) of this section, expressed in section to determine the value of FRMs feet per hour according to methods set standard cubic feet per hour, for the and FRMi. These values must be based period of flow to open tanks/pits. on the flow rate for flowback gases, once forth in § 98.234(b). PRs,p = Average gas production flow rate sufficient gas is present to enable (ii) Calculation Method 2 (for gas during the first 30 days of production separation. The number of wells). *** after completions of newly drilled wells (iii) * * * or well workovers using hydraulic measurements or calculations required fracturing in standard cubic feet per hour to estimate FRMs and FRMi must be * * * * * of each well p, in the sub-basin and well determined individually for FRMs = Ratio of average gas flowback rate, type combination. If applicable, PRs,p completions and workovers per sub- during the period of time when sufficient may be calculated for oil wells using basin and well type combination as quantities of gas are present to enable

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separation, of well completions and specified in paragraph (g)(1)(vii) of this production rate are applied to all well workovers from hydraulic fracturing to section. completions and well workovers, 30-day gas production rate for each sub- respectively, in the sub-basin and well basin and well type combination. * * * * * (iv) * * * type combination for the total number of FRs,p = Measured average gas flowback rate hours of flowback and for the first 30 from Calculation Method 1 described in * * * * * paragraph (g)(1)(i) of this section or day average gas production rate for each FRMi = Ratio of initial gas flowback rate of these wells. calculated average flowback rate from during well completions and workovers Calculation Method 2 described in from hydraulic fracturing to 30-day gas (vi) For Equation W–12A and W–12B paragraph (g)(1)(ii) of this section, during production rate for the sub-basin and of this section, calculate new flowback the separation period in standard cubic well type combination, for the period of rates for well completions and well feet per hour for well(s) p for each sub- flow to open tanks/pits. workovers in each sub-basin and well basin and well type combination. * * * * * type combination once every two years Convert measured and calculated FRa starting in the first calendar year of data values from actual conditions upstream PRs,p = Average gas production flow rate during the first 30-days of production of the restriction orifice (FR ) to standard collection. a after completions of newly drilled wells conditions (FR ) for each well p using (vii) For oil wells where the gas s,p or well workovers using hydraulic Equation W–33 in paragraph (t) of this production rate is not metered and you fracturing, in standard cubic feet per section. You may not use flow volume as elect to use Equation W–10A of this hour of each well, p, that was measured used in Equation W–10B converted to a in the sub-basin and well type section, calculate the average gas flow rate for this parameter. combination. If applicable, PRs,p may be production rate (PRs,p) using Equation PRs,p = Average gas production flow rate calculated for oil wells using procedures W–12C of this section. If GOR cannot be during the first 30 days of production specified in paragraph (g)(1)(vii) of this determined from your available data, after completions of newly drilled wells section. then you must use one of the procedures or well workovers using hydraulic fracturing, in standard cubic feet per * * * * * specified in paragraphs (g)(1)(vii)(A) or hour for each well, p, that was measured (v) For Equation W–10A of this (g)(1)(vii)(B) of this section to determine in the sub-basin and well type section, the ratio of gas flowback rate GOR. If GOR from each well is not combination. If applicable, PRs,p may be during well completions and workovers available, use the GOR from a cluster of calculated for oil wells using procedures from hydraulic fracturing to 30-day gas wells in the same sub-basin category.

Where: is a unique combination of the tanks without passing through a PRs,p = Average gas production flow rate parameters listed in paragraphs (g)(2)(i) wellhead separator with throughput during the first 30 days of production through (iv) of this section. greater than or equal to 10 barrels per after completions of newly drilled wells * * * * * day, calculate annual CH4 and CO2 or well workovers using hydraulic (iv) Oil well or gas well. emissions using Calculation Method 2 fracturing in standard cubic feet per hour as specified in paragraph (j)(2) of this of well p, in the sub-basin and well type * * * * * section. For hydrocarbon liquids combination. (4) Calculate annual emissions from flowing to gas-liquid separators or GORp = Average gas to oil ratio during the well venting during well completions directly to atmospheric storage tanks first 30 days of production after and workovers from hydraulic with throughput less than 10 barrels per completions of newly drilled wells or fracturing where all or a portion of the workovers using hydraulic fracturing in day, use Calculation Method 3 as gas is flared as specified in paragraphs standard cubic feet of gas per barrel of specified in paragraph (j)(3) of this (g)(4)(i) and (ii) of this section. oil for each well p, that was measured in section. If you use Calculation Method the sub-basin and well type combination; * * * * * 1 or Calculation Method 2, you must oil here refers to hydrocarbon liquids (j) Onshore production and onshore also calculate emissions that may have produced of all API gravities. petroleum and natural gas gathering occurred due to dump valves not Vp = Volume of oil produced during the first and boosting storage tanks. Calculate 30 days of production after completions closing properly using the method of newly drilled wells or well workovers CH4, CO2, and N2O (when flared) specified in paragraph (j)(4) of this using hydraulic fracturing in barrels of emissions from atmospheric pressure section. If emissions from atmospheric each well p, that was measured in the fixed roof storage tanks receiving pressure fixed roof storage tanks are sub-basin and well type combination. hydrocarbon produced liquids from routed to a vapor recovery system, you 720 = Conversion from 30 days of production onshore petroleum and natural gas must adjust the emissions downward to hourly production rate. production facilities and onshore according to paragraph (j)(5) of this (A) You may use an appropriate petroleum and natural gas gathering and section. If emissions from atmospheric standard method published by a boosting facilities (including stationary pressure fixed roof storage tanks are consensus-based standards organization liquid storage not owned or operated by routed to a flare, you must calculate if such a method exists. the reporter), as specified in this CH4, CO2, and N2O annual emissions as (B) You may use an industry standard paragraph (j). For gas-liquid separators specified in paragraph (j)(6) of this practice as described in § 98.234(b). with annual average daily throughput of section. (2) For paragraphs (g) introductory oil greater than or equal to 10 barrels per (1) Calculation Method 1. Calculate text and (g)(1) of this section, day, calculate annual CH4 and CO2 annual CH4 and CO2 emissions from measurements and calculations are using Calculation Method 1 or 2 as onshore production storage tanks and completed separately for workovers and specified in paragraphs (j)(1) and (2) of onshore petroleum and natural gas completions per sub-basin and well type this section. For hydrocarbon liquids gathering and boosting storage tanks combination. A well type combination flowing directly to atmospheric storage using operating conditions in the last

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wellhead gas-liquid separator before pressure storage tank. The following (6) If you use Calculation Method 1 or liquid transfer to storage tanks. parameters must be determined for Calculation Method 2 in paragraph (j)(1) Calculate flashing emissions with a typical operating conditions over the or (2) of this section, calculate emissions software program, such as AspenTech year by engineering estimate and from occurrences of gas-liquid separator ® HYSYS or API 4697 E&P Tank, that process knowledge based on best liquid dump valves not closing during uses the Peng-Robinson equation of available data, and must be used at a the calendar year by using Equation W– state, models flashing emissions, and minimum to characterize emissions 16 of this section. speciates CH4 and CO2 emissions that from liquid transferred to tanks: will result when the oil from the separator enters an atmospheric * * * * *

Where: GHG mole fraction using paragraph compressor source are routed to vapor Es,i,o = Annual volumetric GHG emissions at (u)(2)(i) of this section. recovery, paragraphs (o)(1) through (12) standard conditions from each storage * * * * * of this section do not apply. If you are tank in cubic feet that resulted from the (o) Centrifugal compressor venting. If required to report emissions from dump valve on the gas-liquid separator you are required to report emissions centrifugal compressor venting at an not closing properly. from centrifugal compressor venting as onshore petroleum and natural gas En = Storage tank emissions as determined in specified in § 98.232(d)(2), (e)(2), (f)(2), production facility as specified in Calculation Methods 1 or 2 in paragraphs (g)(2), and (h)(2), you must conduct (j)(1) and (2) of this section (with § 98.232(c)(19) or an onshore petroleum separators) in standard cubic feet per volumetric emission measurements and natural gas gathering and boosting year. specified in paragraph (o)(1) of this facility as specified in § 98.232(j)(8), you Tn = Total time a dump valve is not closing section using methods specified in must calculate volumetric emissions as properly in the calendar year in hours. paragraphs (o)(2) through (5) of this specified in paragraph (o)(10) of this Estimate Tn based on maintenance, section; perform calculations specified section; and calculate CH4 and CO2 operations, or routine separator in paragraphs (o)(6) through (9) of this mass emissions as specified in inspections that indicate the period of section; and calculate CH4 and CO2 paragraph (o)(11) of this section. time when the valve was malfunctioning mass emissions as specified in * * * * * in open or partially open position. paragraph (o)(11) of this section. If CFn = Correction factor for tank emissions for emissions from a compressor source are (10) Method for calculating time period Tn is 2.87 for crude oil routed to a flare, paragraphs (o)(1) volumetric GHG emissions from wet seal production. Correction factor for tank through (11) of this section do not apply oil degassing vents at an onshore emissions for time period Tn is 4.37 for and instead you must calculate CH4, petroleum and natural gas production gas condensate production. facility or an onshore petroleum and 8,760 = Conversion to hourly emissions. CO2, and N2O emissions as specified in paragraph (o)(12) of this section. If natural gas gathering and boosting * * * * * emissions from a compressor source are facility. You must calculate emissions (n) * * * captured for fuel use or are routed to a from centrifugal compressor wet seal oil thermal oxidizer, paragraphs (o)(1) degassing vents at an onshore petroleum (2) * * * through (12) of this section do not apply and natural gas production facility or an (i) For onshore natural gas production and instead you must calculate and onshore petroleum and natural gas and onshore petroleum and natural gas report emissions as specified in subpart gathering and boosting facility using gathering and boosting, determine the C of this part. If emissions from a Equation W–25 of this section.

Where: as specified in § 98.232(d)(1), (e)(1), paragraph (p)(12) of this section. If Es,i = Annual volumetric GHGi (either CH4 or (f)(1), (g)(1), and (h)(1), you must emissions from a compressor source are CO2) emissions from centrifugal conduct volumetric emission captured for fuel use or are routed to a compressor wet seals, at standard measurements specified in paragraph thermal oxidizer, paragraphs (p)(1) conditions, in cubic feet. Count = Total number of centrifugal (p)(1) of this section using methods through (12) of this section do not apply compressors that have wet seal oil specified in paragraphs (p)(2) through and instead you must calculate and degassing vents. (5) of this section; perform calculations report emissions as specified in subpart × EFi,s = Emission factor for GHGi. Use 1.2 specified in paragraphs (p)(6) through C of this part. If emissions from a 107 standard cubic feet per year per (9) of this section; and calculate CH4 compressor source are routed to vapor × 5 compressor for CH4 and 5.30 10 and CO mass emissions as specified in recovery, paragraphs (p)(1) through (12) standard cubic feet per year per 2 paragraph (p)(11) of this section. If of this section do not apply. If you are compressor for CO2 at 60 °F and 14.7 psia. emissions from a compressor source are required to report emissions from * * * * * routed to a flare, paragraphs (p)(1) reciprocating compressor venting at an (p) Reciprocating compressor venting. through (11) of this section do not apply onshore petroleum and natural gas If you are required to report emissions and instead you must calculate CH4, production facility as specified in from reciprocating compressor venting CO2, and N2O emissions as specified in § 98.232(c)(11) or an onshore petroleum

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and natural gas gathering and boosting (10) Method for calculating compressor venting at an onshore facility as specified in § 98.232(j)(5), you volumetric GHG emissions from petroleum and natural gas production must calculate volumetric emissions as reciprocating compressor venting at an facility or an onshore petroleum and specified in paragraph (p)(10) of this onshore petroleum and natural gas natural gas gathering and boosting section; and calculate CH4 and CO2 production facility or an onshore facility using Equation W–29D of this mass emissions as specified in petroleum and natural gas gathering section. paragraph (p)(11) of this section. and boosting facility. You must * * * * * calculate emissions from reciprocating

Where: (r) Equipment leaks by population half inch diameter are exempt from the Es,i = Annual volumetric GHGi (either CH4 or count. This paragraph applies to requirements of this paragraph (r) and CO2) emissions from reciprocating emissions sources listed in do not need to be reported. You must compressors, at standard conditions, in § 98.232(c)(21), (f)(5), (g)(3), (h)(4), (i)(2), calculate emissions from all emission cubic feet. (i)(3), (i)(4), (i)(5), (i)(6), (j)(9), and (j)(10) sources listed in this paragraph using Count = Total number of reciprocating on streams with gas content greater than Equation W–32A of this section, except compressors. 10 percent CH4 plus CO2 by weight. for natural gas distribution facility EFi,s = Emission factor for GHGi. Use 9.48 × 103 standard cubic feet per year per Emissions sources in streams with gas emission sources listed in § 98.232(i)(3). 2 compressor for CH4 and 5.27 × 10 content less than or equal to 10 percent Natural gas distribution facility standard cubic feet per year per CH4 plus CO2 by weight are exempt emission sources listed in § 98.232(i)(3) ° compressor for CO2 at 60 F and 14.7 from the requirements of this paragraph must calculate emissions using Equation psia. (r) and do not need to be reported. W–32B and according to paragraph * * * * * Tubing systems equal to or less than one (r)(6)(ii) of this section.

Where: this subpart. LNG storage facilities must petroleum and natural gas gathering and

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

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components in reference to Table W–1A available analysis of the sub-basin (i) Monitoring methods currently used of this subpart and major natural gas category or facility, as applicable to the by the facility that do not meet the equipment in reference to Table W–1B emission source. specifications of this subpart. of this subpart. Major equipment and * * * * * (ii) Supplier data. components associated with crude oil (iii) GHG mole fraction in (iii) Engineering calculations. wells are considered crude service transmission pipeline natural gas that (iv) Other company records. components in reference to Table W–1A passes through the facility for the (2) Best available monitoring methods of this subpart and major crude oil onshore natural gas transmission for well-related measurement data for equipment in reference to Table W–1C compression industry segment and the oil wells with hydraulic fracturing. You of this subpart. Where facilities conduct onshore natural gas transmission may use best available monitoring EOR operations the emissions factor pipeline industry segment. You may use methods for any well-related listed in Table W–1A of this subpart either a default 95 percent methane and measurement data that cannot shall be used to estimate all streams of 1 percent carbon dioxide fraction for reasonably be measured according to the GHG mole fraction in natural gas or site gases, including recycle CO2 stream. monitoring and QA/QC requirements of specific engineering estimates based on The component count can be this subpart for venting during well best available data. determined using either of the completions and workovers of oil wells calculation methods described in this * * * * * with hydraulic fracturing. paragraph (r)(2), except for miles of (z) Onshore petroleum and natural (3) Best available monitoring methods gathering pipelines, which must be gas production, onshore petroleum and for onshore petroleum and natural gas determined using Component Count natural gas gathering and boosting, and gathering and boosting facilities. You Method 2 in paragraph (r)(2)(ii) of this natural gas distribution combustion may use best available monitoring section. The same calculation method emissions. Calculate CO , CH , and N O 2 4 2 methods for any leak detection and/or must be used for the entire calendar combustion-related emissions from measurement data that cannot year. stationary or portable equipment, except reasonably be measured according to the (i) Component Count Method 1. For as specified in paragraph (z)(3) and (4) monitoring and QA/QC requirements of all onshore petroleum and natural gas of this section, as follows: this subpart for acid gas removal vents production operations and onshore (1) * * * as specified in § 98.233(d). petroleum and natural gas gathering and (ii) Emissions from fuel combusted in boosting operations in the facility stationary or portable equipment at (4) Best available monitoring methods perform the following activities: onshore natural gas and petroleum for natural gas transmission pipelines. (A) Count all major equipment listed production facilities, onshore petroleum You may use best available monitoring in Table W–1B and Table W–1C of this and natural gas gathering and boosting methods for any measurement data for subpart. For meters/piping, use one facilities, and at natural gas distribution natural gas transmission pipelines that meters/piping per well-pad. facilities will be reported according to cannot reasonably be obtained (B) Multiply major equipment counts the requirements specified in § 98.236(z) according to the monitoring and QA/QC by the average component counts listed and not according to the reporting requirements of this subpart for in Table W–1B for onshore natural gas requirements specified in subpart C of blowdown vent stacks. production and onshore petroleum and this part. (5) Best available monitoring methods natural gas gathering and boosting; and * * * * * for specified activity data. You may use Table W–1C of this subpart for onshore ■ 6. Section 98.234 is amended by best available monitoring methods for oil production. Use the appropriate adding paragraph (g) to read as follows: activity data as listed in paragraphs factor in Table W–1A of this subpart for (g)(5)(i) through (iii) of this section that § 98.234 Monitoring and QA/QC cannot reasonably be obtained operations in Eastern and Western U.S. requirements. according to the mapping in Table according to the monitoring and QA/QC * * * * * W–1D of this subpart. requirements of this subpart for well (g) Special reporting provisions for completions and workovers of oil wells (ii) Component Count Method 2. best available monitoring methods in Count each component individually for with hydraulic fracturing, onshore reporting year 2016. petroleum and natural gas gathering and the facility. Use the appropriate factor in (1) Best available monitoring boosting facilities, or natural gas Table W–1A of this subpart for methods. From January 1, 2016 to transmission pipelines. operations in Eastern and Western U.S. March 31, 2016, you must use the according to the mapping in Table calculation methodologies and (i) Cumulative hours of venting, days, W–1D of this subpart. equations in § 98.233 but you may use or times of operation in § 98.233(e), (g), * * * * * the best available monitoring method for (o), (p), and (r). (u) * * * any parameter for which it is not (ii) Number of blowdowns, (2) * * * reasonably feasible to acquire, install, completions, workovers, or other events (i) GHG mole fraction in produced and operate a required piece of in § 98.233(g) and (i). natural gas for onshore petroleum and monitoring equipment by January 1, (iii) Cumulative volume produced, natural gas production facilities and 2016 as specified in paragraphs (g)(2) volume input or output, or volume of onshore petroleum and natural gas through (5) of this section. Starting no fuel used in paragraphs § 98.233(d), (e), gathering and boosting facilities. If you later than April 1, 2016, you must (j), (n), and (z). have a continuous gas composition discontinue using best available (6) Requests for extension of the use analyzer for produced natural gas, you methods and begin following all of best available monitoring methods must use an annual average of these applicable monitoring and QA/QC beyond March 31, 2016. You may values for determining the mole requirements of this part, except as submit a request to the Administrator to fraction. If you do not have a continuous provided in paragraph (g)(6) of this use one or more best available gas composition analyzer, then you section. Best available monitoring monitoring methods for sources listed in must use an annual average gas methods means any of the following paragraphs (g)(2) through (5), of this composition based on your most recent methods: section beyond March 31, 2016.

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(i) Timing of request. The extension ■ q. Adding new paragraph (e)(2)(ii); ■ tt. Adding new paragraph (o)(5)(ii); request must be submitted to EPA no ■ p. Revising newly redesignated ■ uu. Revising paragraphs (p) later than January 31, 2016. paragraphs (e)(2)(iii), (e)(1)(iv), (e)(2)(v) introductory text and (p)(5) introductory (ii) Content of request. Requests must introductory text, and (e)(2)(vi) text; contain the following information: introductory text; ■ vv. Redesignating paragraphs (p)(5)(ii) (A) A list of specific source types and ■ q. Revising paragraphs (e)(3)(i) and (iii) as paragraphs (p)(5)(iii) and parameters for which you are seeking introductory text, (f)(1)(ii), (f)(1)(xi)(A), (iv), respectively; use of best available monitoring (f)(1)(xii)(A), (f)(2)(i), (g) introductory ■ ww. Adding new paragraph (p)(5)(ii); methods. text, (g)(1), (g)(2), (g)(5)(i), and (g)(5)(ii); ■ xx. Revising paragraphs (r)(1) (B) For each specific source type for ■ r. Adding paragraph (g)(5)(iii); introductory text, (r)(1)(i), (r)(3) ■ which you are requesting use of best s. Revising paragraph (g)(6); introductory text, (r)(3)(ii), (w)(2), and ■ t. Revising paragraphs (h)(1)(i), available monitoring methods, a (x) introductory text; (h)(1)(iv), (h)(2)(i), (h)(2)(iv), (h)(3)(i), description of the reasons that the ■ yy. Redesignating paragraphs (x)(2) (h)(4)(i) and (i) introductory text; through (4) as paragraphs (x)(3) through needed equipment could not be ■ u. Adding paragraph (i)(3); (5), respectively; obtained and installed before April 1, ■ v. Revising paragraphs (j) introductory 2016. ■ zz. Adding new paragraph (x)(2); text and (j)(1) introductory text; ■ (C) A description of the specific ■ aaa. Revising paragraphs (z) w. Redesignating paragraphs (j)(1)(ii) introductory text and (z)(1) introductory actions you will take to obtain and through (xiv) as paragraphs (j)(1)(iv) install the equipment as soon as text; through (xvi), respectively; ■ bbb. Adding new paragraph (z)(1)(iii); reasonably feasible and the expected ■ x. Adding new paragraphs (j)(1)(ii) ■ ccc. Revising paragraph (z)(2) date by which the equipment will be and (j)(1)(iii); installed and operating. ■ y. Revising newly redesignated introductory text; ■ ddd. Redesignating paragraphs (iii) Approval criteria. To obtain paragraphs (j)(1)(v), (j)(1)(ix), (j)(1)(x), (z)(2)(ii) through (vi) as paragraphs approval to use best available (j)(1)(xiv) introductory text, (j)(1)(xv) (z)(2)(iii) through (vii), respectively; monitoring methods after March 31, introductory text, and (j)(1)(xvi) ■ eee. Adding new paragraph (z)(2)(ii); 2016, you must submit a request introductory text; ■ fff. Revising paragraphs (aa) demonstrating to the Administrator’s ■ z. Revising paragraphs (j)(2)(i) introductory text and (aa)(1)(ii)(D) satisfaction that it is not reasonably introductory text, (j)(2)(i)(A) through through (H); feasible to acquire, install, and operate (j)(2)(i)(C), (j)(2)(ii)(B), (j)(2)(iii)(B), and ■ ggg. Adding paragraphs (aa)(10) and a required piece of monitoring (l)(1) introductory text; ■ aa. Redesignating paragraphs (l)(1)(ii) (11); and equipment by April 1, 2016. The use of ■ hhh. Revising paragraph (cc). best available methods under this through (vi) as paragraphs (l)(1)(iii) through (vii), respectively; The revisions and additions read as paragraph (g) will not be approved follows: beyond December 31, 2016. ■ bb. Adding new paragraph (l)(1)(ii); ■ cc. Revising newly designated * * * * * § 98.236 Data reporting requirements. ■ paragraph (l)(1)(v); 7. Section 98.236 is amended by: ■ dd. Revising paragraph (l)(2) * * * * * ■ a. Revising paragraph (a) introductory introductory text; (a) The annual report must include text; ■ ee. Redesignating paragraphs (l)(2)(ii) the information specified in paragraphs ■ b. Adding paragraphs (a)(9) and (10); through (vii) as paragraphs (l)(2)(iii) (a)(1) through (10) of this section for ■ c. Revising paragraphs (b)(1)(ii)(A) through (viii), respectively; each applicable industry segment. The and (B) and (c) introductory text; ■ ff. Adding new paragraph (l)(2)(ii); annual report must also include annual ■ d. Redesignating paragraphs (c)(2) ■ gg. Revising newly designated emissions totals, in metric tons of each through (4) as paragraphs (c)(3) through paragraph (l)(2)(v); GHG, for each applicable industry (5), respectively; ■ hh. Revising paragraph (l)(3) segment listed in paragraphs (a)(1) ■ e. Adding new paragraph (c)(2); introductory text; through (10) of this section, and each ■ f. Revising paragraphs (d)(1) ■ ii. Redesignating paragraphs (l)(3)(ii) applicable emission source listed in introductory text and (d)(1)(i); through (v) as paragraphs (l)(3)(iii) paragraphs (b) through (z) of this ■ g. Redesignating paragraphs (d)(1)(ii) through (vi), respectively; section. ■ through (vi) as paragraphs (d)(1)(iii) jj. Adding new paragraph (l)(3)(ii); * * * * * ■ through (vii), respectively; kk. Revising newly designated (9) Onshore petroleum and natural ■ h. Adding new paragraph (d)(1)(ii); paragraph (l)(3)(iv); gas gathering and boosting. For the ■ ll. Revising paragraph (l)(4) ■ i. Revising newly redesignated equipment/activities specified in introductory text; paragraph (d)(1)(vii); ■ paragraphs (a)(9)(i) through (xi) of this ■ j. Revising paragraphs (e)(1) mm. Redesignating paragraphs (l)(4)(ii) through (vi) as paragraphs section, report the information specified introductory text and (e)(1)(i); in the applicable paragraphs of this ■ k. Redesignating paragraphs (e)(1)(ii) (l)(4)(iii) through (vii), respectively; ■ nn. Adding new paragraph (l)(4)(ii); section. through (xviii) as paragraphs (e)(1)(iii) ■ oo. Revising newly designated (i) Natural gas pneumatic devices. through (xix), respectively; paragraph (l)(4)(iv); Report the information specified in ■ l. Adding new paragraph (e)(1)(ii); ■ pp. Revising paragraphs (m)(1), (m)(5), paragraph (b) of this section. ■ m. Revising newly redesignated (m)(6), (m)(7)(i), (m)(8)(i), (n) (ii) Natural gas driven pneumatic paragraphs (e)(1)(xvii) introductory text, introductory text and (n)(1); pumps. Report the information specified (e)(1)(xviii) introductory text, and ■ qq. Adding paragraph (n)(13); in paragraph (c) of this section. (e)(1)(xix); ■ rr. Revising paragraphs (o) (iii) Acid gas removal units. Report ■ n. Revising paragraph (e)(2) introductory text and (o)(5) introductory the information specified in paragraph introductory text; text; (d) of this section. ■ o. Redesignating paragraphs (e)(2)(ii) ■ ss. Redesignating paragraphs (o)(5)(ii) (iv) Dehydrators. Report the through (v) as paragraphs (e)(2)(iii) and (iii) as paragraphs (o)(5)(iii) and information specified in paragraph (e) of through (vi), respectively; (iv), respectively; this section.

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(v) Blowdown vent stacks. Report the and natural gas gathering and boosting throughput less than 0.4 million information specified in paragraph (i) of industry segments, a different name or standard cubic feet per day (as specified this section. ID may be used for a single acid gas in § 98.233(e)(2)), you must report the (vi) Storage tanks. Report the removal unit for each location it information specified in paragraphs information specified in paragraph (j) of operates at in a given year. (e)(2)(i) through (vi) of this section for this section. (ii) A list of the well ID number(s) the entire facility. (vii) Flare stacks. Report the associated with the acid gas removal * * * * * information specified in paragraph (n) units (for the onshore petroleum and (ii) A list of the well ID numbers of this section. natural gas production industry segment associated with the dehydrators at the (viii) Centrifugal compressors. Report only). facility (for the onshore petroleum and the information specified in paragraph * * * * * natural gas production industry segment (o) of this section. (vii) Sub-basin ID that best represents only). (ix) Reciprocating compressors. the wells and/or equipment supplying (iii) Whether any dehydrator Report the information specified in gas to the unit (for the onshore emissions were vented to a vapor paragraph (p) of this section. petroleum and natural gas production recovery device. If any dehydrator (x) Equipment leaks by population and the onshore petroleum and natural emissions were vented to a vapor count. Report the information specified gas gathering and boosting industry recovery device, then you must report in paragraph (r) of this section. segments only). the total number of dehydrators at the (xi) Combustion equipment. Report * * * * * facility that vented to a vapor recovery the information specified in paragraph (e) * * * device. For the onshore petroleum and (z) of this section. (1) For each glycol dehydrator that natural gas production industry segment (10) Onshore natural gas transmission has an annual average daily natural gas only, also report a list of the associated pipeline. For blowdown vent stacks, throughput greater than or equal to 0.4 well ID numbers. report the information specified in million standard cubic feet per day (as (iv) Whether any dehydrator paragraph (i) of this section. specified in § 98.233(e)(1)), you must emissions were vented to a control (b) * * * report the information specified in device other than a vapor recovery (1) * * * paragraphs (e)(1)(i) through (xix) of this device or a flare or regenerator firebox/ (ii) * * * section for the dehydrator. fire tubes. If any dehydrator emissions (A) The number of devices of each (i) A unique name or ID number for were vented to a control device(s) other type reported in paragraph (b)(1)(i) of the dehydrator. For the onshore than a vapor recovery device or a flare this section that are counted. A list of petroleum and natural gas production or regenerator firebox/fire tubes, then the well ID numbers associated with the and the onshore petroleum and natural you must specify the type of control devices that are counted (for the gas gathering and boosting industry device(s) and the total number of onshore petroleum and natural gas segments, a different name or ID may be dehydrators at the facility that were production industry segment only). used for a single dehydrator for each vented to each type of control device. (B) The number of devices of each location it operates at in a given year. For the onshore petroleum and natural type reported in paragraph (b)(1)(i) of (ii) A list of well ID number(s) gas production industry segment only, this section that are estimated (not associated with the dehydrators (for the also report a list of the associated well counted). A list of the well ID numbers onshore petroleum and natural gas ID numbers for each type of control associated with the devices that are production industry segment only). device. estimated (not counted) (for the onshore * * * * * (v) Whether any dehydrator emissions petroleum and natural gas production were vented to a flare or regenerator industry segment only). (xvii) Whether any dehydrator emissions are vented to a flare or firebox/fire tubes. If any dehydrator * * * * * regenerator firebox/fire tubes. If any emissions were vented to a flare or (c) Natural gas driven pneumatic emissions are vented to a flare or regenerator firebox/fire tubes, then you pumps. You must indicate whether the regenerator firebox/fire tubes, report the must report the information specified in facility has any natural gas driven information specified in paragraphs paragraphs (e)(2)(v)(A) through (D) of pneumatic pumps. If the facility (e)(1)(xvii)(A) through (C) of this section this section. contains any natural gas driven for these emissions from the dehydrator. * * * * * pneumatic pumps, then you must report (xviii) Whether any dehydrator (vi) For dehydrators reported in the information specified in paragraphs emissions are vented to the atmosphere paragraph (e)(2)(i) of this section that (c)(1) through (5) of this section. without being routed to a flare or were not vented to a flare or regenerator * * * * * regenerator firebox/fire tubes. If any firebox/fire tubes, report the information (2) A list of the well ID numbers emissions are not routed to a flare or specified in paragraphs (e)(2)(vi)(A) and associated with the natural gas driven regenerator firebox/fire tubes, then you (B) of this section. pneumatic pumps (for the onshore must report the information specified in * * * * * petroleum and natural gas production paragraphs (e)(1)(xviii)(A) and (B) of (3) * * * industry segment only). this section for those emissions from the (i) The same information specified in * * * * * dehydrator. paragraphs (e)(2)(i) through (v) of this (d) * * * (xix) Sub-basin ID that best represents section for glycol dehydrators, and (1) You must report the information the wells and/or equipment supplying report the information under this specified in paragraphs (d)(1)(i) through gas to the dehydrator (for the onshore paragraph for dehydrators that use (vii) of this section for each acid gas petroleum and natural gas production desiccant. removal unit. and the onshore petroleum and natural * * * * * (i) A unique name or ID number for gas gathering and boosting industry (f) * * * the acid gas removal unit. For the segments only). (1) * * * onshore petroleum and natural gas (2) For glycol dehydrators with an (ii) Well tubing diameter and pressure production and the onshore petroleum annual average daily natural gas group ID and a list of the well ID

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numbers associated with each sub-basin the measurement. If you elect to delay basin without hydraulic fracturing and well tubing diameter and pressure group reporting of this data element, you must with flaring. ID. report by the date specified in * * * * * * * * * * § 98.236(cc) the measured flowback rate (iv) Average daily gas production rate (xi) * * * during well completion or workover and for all completions without hydraulic (A) Well ID number of tested well. the well ID number(s) for the well(s) fracturing in the sub-basin with flaring, * * * * * included in the measurement. in standard cubic feet per hour (the (xii) * * * (iii) If you used Equation W–12C to average of all ‘‘Vp’’ from Equation W– (A) Well ID number. calculate the average gas production rate 13B). You may delay reporting of this * * * * * for an oil well, then you must report the data element if you indicate in the (2) * * * information specified in paragraphs annual report that wildcat wells and/or (i) Sub-basin ID and a list of the well (g)(5)(iii)(A) and (B) of this section. delineation wells are the only wells that ID numbers associated with each sub- (A) Gas to oil ratio for the well in can be used for the measurement. If you basin. standard cubic feet of gas per barrel of elect to delay reporting of this data * * * * * oil (‘‘GORp’’ in Equation W–12C). element, you must report by the date (g) Completions and workovers with (B) Volume of oil produced during the specified in § 98.236(cc) the measured hydraulic fracturing. You must indicate first 30 days of production after average daily gas production rate for all whether your facility had any well completions of each newly drilled well wells during completions and the well completions or workovers with or well workover using hydraulic ID number(s) for the well(s) included in hydraulic fracturing during the calendar fracturing, in barrels (‘‘Vp’’ in Equation the measurement. year. If your facility had well W–12C). * * * * * completions or workovers with (6) If you used Equation W–10B to (3) * * * hydraulic fracturing during the calendar calculate annual volumetric total gas (i) Sub-basin ID and a list of the well year, then you must report information emissions for completions that vent gas ID numbers associated with each sub- specified in paragraphs (g)(1) through to the atmosphere, then you must report basin without hydraulic fracturing and (10) of this section, for each sub-basin the information specified in paragraphs without flaring. (g)(6)(i) through (iii) of this section. and well type combination. Report * * * * * (i) Vented natural gas volume, in information separately for completions (4) * * * standard cubic feet, for each well in the and workovers. (i) Sub-basin ID and a list of well ID (1) Sub-basin ID and a list of the well sub-basin (‘‘FV ’’ in Equation W–10B). s,p numbers associated with each sub-basin ID numbers associated with each sub- (ii) Flow rate, in standard cubic feet without hydraulic fracturing and with basin that had completions or per hour, at the beginning of the period flaring. workovers with hydraulic fracturing of time when sufficient quantities of gas * * * * * during the calendar year. are present to enable separation (‘‘FRp,i’’ (2) Well type combination (horizontal in Equation W–10B). (i) Blowdown vent stacks. You must or vertical, gas well or oil well). (iii) The well ID number for which indicate whether your facility has * * * * * vented natural gas volume was blowdown vent stacks. If your facility (5) * * * measured. has blowdown vent stacks, then you must report whether emissions were (i) Cumulative gas flowback time, in * * * * * hours, from when gas is first detected calculated by equipment or event type (h) * * * or by using flow meters or a until sufficient quantities are present to (1) * * * enable separation, and the cumulative combination of both. If you calculated (i) Sub-basin ID and a list of the well emissions by equipment or event type flowback time, in hours, after sufficient ID numbers associated with each sub- quantities of gas are present to enable for any blowdown vent stacks, then you basin without hydraulic fracturing and must report the information specified in separation (sum of ‘‘Tp,i’’ and sum of without flaring. paragraph (i)(1) of this section ‘‘Tp,s’’ values used in Equation W–10A). You may delay the reporting of this data * * * * * considering, in aggregate, all blowdown element if you indicate in the annual (iv) Average daily gas production rate vent stacks for which emissions were report that wildcat wells and/or for all completions without hydraulic calculated by equipment or event type. delineation wells are the only wells fracturing in the sub-basin without If you calculated emissions using flow included in this number. If you elect to flaring, in standard cubic feet per hour meters for any blowdown vent stacks, delay reporting of this data element, you (average of all ‘‘Vp’’ used in Equation then you must report the information must report by the date specified in W–13B). You may delay reporting of specified in paragraph (i)(2) of this § 98.236(cc) the total number of hours of this data element if you indicate in the section considering, in aggregate, all flowback from all wells during annual report that wildcat wells and/or blowdown vent stacks for which completions or workovers and the well delineation wells are the only wells that emissions were calculated using flow ID number(s) for the well(s) included in can be used for the measurement. If you meters. For the onshore natural gas the number. elect to delay reporting of this data transmission pipeline segment, you (ii) For the measured well(s), the element, you must report by the date must also report the information in flowback rate, in standard cubic feet per specified in § 98.236(cc) the measured paragraph (i)(3) of this section. hour, for each sub-basin (average of average daily gas production rate for all * * * * * ‘‘FRs,p’’ values in Equation W–12A), and wells during completions and the well (3) Onshore natural gas transmission the well ID numbers of the wells for ID number(s) for the well(s) included in pipeline segment. Report the which it is measured. You may delay the measurement. information in paragraphs (i)(3)(i) to the reporting of this data element if you * * * * * (i)(3)(iii) for each separate transmission indicate in the annual report that (2) * * * pipeline blowdown event. wildcat wells and/or delineation wells (i) Sub-basin ID and a list of the well (i) Annual CO2 emissions in metric are the only wells that can be used for ID numbers associated with each sub- tons CO2.

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(ii) Annual CH4 emissions in metric all wells and the well ID number(s) for (C) An estimate of the fraction of oil/ tons CH4. the well(s) included in this volume. condensate throughput reported in (iii) The location of the blowdown, in * * * * * paragraph (j)(2)(i)(A) of this section sent latitude and longitude in decimal degree (ix) The minimum and maximum to atmospheric tanks in the basin that format provided as a comma-delimited concentration (mole fraction) of CO2 in controlled emissions with vapor ‘‘latitude, longitude’’ coordinate pair flash gas from onshore production and recovery systems. reported in decimal degrees to at least onshore natural gas gathering and * * * * * four digits to the right of the decimal boosting storage tanks. (ii) * * * point. (x) The minimum and maximum (B) The number of atmospheric tanks in the sub-basin that did not control (j) Onshore production and onshore concentration (mole fraction) of CH4 in emissions with flares, including those petroleum and natural gas gathering flash gas from onshore production and that have vapor recovery, and for the and boosting storage tanks. You must onshore petroleum and natural gas onshore petroleum and natural gas indicate whether your facility sends gathering and boosting storage tanks. production industry segment only, a list produced oil to atmospheric tanks. If * * * * * of the well ID numbers of the associated your facility sends produced oil to (xiv) If any emissions from the wells. atmospheric tanks, then you must atmospheric tanks at your facility were indicate which Calculation Method(s) controlled with vapor recovery systems, * * * * * you used to calculate GHG emissions, then you must report the information (iii) * * * and you must report the information specified in paragraphs (j)(1)(xiv)(A) (B) The number of atmospheric tanks specified in paragraphs (j)(1) and (2) of through (E) of this section. in the sub-basin that controlled this section as applicable. If you used * * * * * emissions with flares, and for the onshore petroleum and natural gas Calculation Method 1 or Calculation (xv) If any atmospheric tanks at your production industry segment only, a list Method 2, and any atmospheric tanks facility vented gas directly to the of the well ID numbers of the associated were observed to have malfunctioning atmosphere without using a vapor wells. dump valves during the calendar year, recovery system or without flaring, then then you must indicate that dump you must report the information * * * * * valves were malfunctioning and you specified in paragraphs (j)(1)(xv)(A) (l) * * * must report the information specified in through (C) of this section. (1) If you used Equation W–17A to calculate annual volumetric natural gas paragraph (j)(3) of this section. * * * * * emissions at actual conditions from oil (1) If you used Calculation Method 1 (xvi) If you controlled emissions from wells and the emissions are not vented or Calculation Method 2 to calculate any atmospheric tanks at your facility to a flare, then you must report the GHG emissions, then you must report with one or more flares, then you must information specified in paragraphs the information specified in paragraphs report the information specified in (l)(1)(i) through (vii) of this section. (j)(1)(i) through (xv) of this section for paragraphs (j)(1)(xvi)(A) through (D) of each sub-basin and by calculation this section. * * * * * method. Onshore petroleum and natural (ii) Well ID numbers for the wells * * * * * tested in the calendar year. gas gathering and boosting facilities do (2) * * * not report the information specified in (i) Report the information specified in * * * * * (v) Average flow rate for well(s) paragraph (j)(1)(xiii) of this section. paragraphs (j)(2)(i)(A) through (F) of this tested, in barrels of oil per day. You may * * * * * section, at the basin level, for delay reporting of this data element if atmospheric tanks where emissions (ii) A list of the well ID number(s) you indicate in the annual report that were calculated using Calculation associated with the tanks that controlled wildcat wells and/or delineation wells Method 3. Onshore gathering and emissions with flares (for the onshore are the only wells that are tested. If you boosting facilities do not report the petroleum and natural gas production elect to delay reporting of this data information specified in paragraphs industry segment only). element, you must report by the date (j)(2)(i)(E) and (F) of this section. (iii) A list of the well ID number(s) specified in § 98.236(cc) the measured (A) The total annual oil/condensate associated with the tanks that did not average flow rate for well(s) tested and throughput that is sent to all control emissions with flares (for the the well ID number(s) for the well(s) atmospheric tanks in the basin, in onshore petroleum and natural gas included in the measurement. barrels. You may delay reporting of this production industry segment only). data element if you indicate in the * * * * * * * * * * annual report that wildcat wells and/or (2) If you used Equation W–17A to (v) The total annual oil volume from delineation wells are the only wells in calculate annual volumetric natural gas gas-liquid separators and direct from the sub-basin with oil production less emissions at actual conditions from oil wells that is sent to applicable onshore than 10 barrels per day and that send oil wells and the emissions are vented to a production and onshore petroleum and to atmospheric tanks. If you elect to flare, then you must report the natural gas gathering and boosting delay reporting of this data element, you information specified in paragraphs storage tanks, in barrels. You may delay must report by the date specified in (l)(2)(i) through (viii) of this section. reporting of this data element if you § 98.236(cc) the total annual oil * * * * * indicate in the annual report that throughput from all wells and the well (ii) Well ID numbers for the wells wildcat wells and/or delineation wells ID number(s) for the well(s) included in tested in the calendar year. are the only wells in the sub-basin the measurement. * * * * * flowing to gas-liquid separators or direct (B) An estimate of the fraction of oil/ (v) Average flow rate for well(s) to storage tanks. If you elect to delay condensate throughput reported in tested, in barrels of oil per day. You may reporting of this data element, you must paragraph (j)(2)(i)(A) of this section sent delay reporting of this data element if report by the date specified in to atmospheric tanks in the basin that you indicate in the annual report that § 98.236(cc) the total volume of oil from controlled emissions with flares. wildcat wells and/or delineation wells

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are the only wells that are tested. If you vented or flared (the sum of ‘‘Vp,q’’ used paragraphs (o)(1) and (2) of this section elect to delay reporting of this data in Equation W–18 of this subpart). You for all centrifugal compressors at your element, you must report by the date may delay reporting of this data element facility. For each compressor source or specified in § 98.236(cc) the measured if you indicate in the annual report that manifolded group of compressor sources average flow rate for well(s) tested and wildcat wells and/or delineation wells that you conduct as found leak the well ID number(s) for the well(s) are the only wells from which measurements as specified in included in the measurement. associated gas was vented or flared. If § 98.233(o)(2) or (4), you must report the * * * * * you elect to delay reporting of this data information specified in paragraph (3) If you used Equation W–17B to element, you must report by the date (o)(3) of this section. For each calculate annual volumetric natural gas specified in § 98.236(cc) the volume of compressor source or manifolded group emissions at actual conditions from gas oil produced for well(s) with associated of compressor sources that you conduct wells and the emissions were not vented gas venting and flaring and the well ID continuous monitoring as specified in to a flare, then you must report the number(s) for the well(s) included in the § 98.233(o)(3) or (5), you must report the information specified in paragraphs measurement. information specified in paragraph (l)(3)(i) through (vi) of this section. (6) Total volume of associated gas sent (o)(4) of this section. Centrifugal * * * * * to sales, in standard cubic feet, in the compressors in onshore petroleum and (ii) Well ID numbers for the wells calendar year during time periods in natural gas production and onshore tested in the calendar year. which associated gas was vented or petroleum and natural gas gathering and flared (the sum of ‘‘SG’’ values used in boosting are not required to report * * * * * Equation W–18 of § 98.233(m)). You (iv) Average annual production rate information in paragraphs (o)(1) through may delay reporting of this data element for well(s) tested, in actual cubic feet (4) of this section and instead must if you indicate in the annual report that per day. You may delay reporting of this report the information specified in wildcat wells and/or delineation wells data element if you indicate in the paragraph (o)(5) of this section. from which associated gas was vented annual report that wildcat wells and/or * * * * * or flared. If you elect to delay reporting delineation wells are the only wells that of this data element, you must report by (5) Onshore petroleum and natural are tested. If you elect to delay reporting the date specified in § 98.236(cc) the gas production and onshore petroleum of this data element, you must report by measured total volume of associated gas and natural gas gathering and boosting. the date specified in § 98.236(cc) the sent to sales for well(s) with associated Centrifugal compressors with wet seal measured average annual production gas venting and flaring and the well ID degassing vents in onshore petroleum rate for well(s) tested and the well ID number(s) for the well(s) included in the and natural gas production and onshore number(s) for the well(s) included in the measurement. petroleum and natural gas gathering and measurement. (7) * * * boosting must report the information * * * * * (i) Total number of wells for which specified in paragraphs (o)(5)(i) through (4) If you used Equation W–17B to associated gas was vented directly to the (iv) of this section. calculate annual volumetric natural gas atmosphere without flaring and a list of * * * * * emissions at actual conditions from gas their well ID numbers. (ii) A list of the well ID numbers for wells and the emissions were vented to * * * * * the wells at which these compressors a flare, then you must report the (8) * * * information specified in paragraphs (i) Total number of wells for which are located (for the onshore petroleum (l)(4)(i) through (vii) of this section. associated gas was flared and a list of and natural gas production industry * * * * * their well ID numbers. segment only). (ii) Well ID numbers for the wells * * * * * * * * * * tested in the calendar year. (n) Flare stacks. You must indicate if (p) Reciprocating compressors. You * * * * * your facility contains any flare stacks. must indicate whether your facility has (iv) Average annual production rate You must report the information reciprocating compressors. You must for well(s) tested, in actual cubic feet specified in paragraphs (n)(1) through report the information specified in per day. You may delay reporting of this (13) of this section for each flare stack paragraphs (p)(1) and (2) of this section data element if you indicate in the at your facility, and for each industry for all reciprocating compressors at your annual report that wildcat wells and/or segment applicable to your facility. facility. For each compressor source or delineation wells are the only wells that (1) Unique name or ID for the flare manifolded group of compressor sources are tested. If you elect to delay reporting stack. For the onshore petroleum and that you conduct as found leak of this data element, you must report by natural gas production and onshore measurements as specified in the date specified in § 98.236(cc) the petroleum and natural gas gathering and § 98.233(p)(2) or (4), you must report the measured average annual production boosting industry segments, a different information specified in paragraph rate for well(s) tested and the well ID name or ID may be used for a single (p)(3) of this section. For each number(s) for the well(s) included in the flare stack for each location where it compressor source or manifolded group measurement. operates at in a given calendar year. of compressor sources that you conduct * * * * * * * * * * continuous monitoring as specified in (m) * * * (13) For the onshore petroleum and § 98.233(p)(3) or (5), you must report the (1) Sub-basin ID and a list of well ID natural gas production industry information specified in paragraph numbers for wells in each sub-basin for segment, a list of the well ID numbers (p)(4) of this section. Reciprocating which associated gas was vented or associated with flare stacks in each sub- compressors in onshore petroleum and flared. basin. natural gas production and onshore * * * * * (o) Centrifugal compressors. You must petroleum and natural gas gathering and (5) Volume of oil produced, in barrels, indicate whether your facility has boosting are not required to report in the calendar year during the time centrifugal compressors. You must information in paragraphs (p)(1) through periods in which associated gas was report the information specified in (4) of this section and instead must

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report the information specified in (w) * * * than 5 million Btu per hour; internal paragraph (p)(5) of this section. (2) EOR injection pump system fuel combustion units that are not * * * * * identifier and a list of the well ID compressor-drivers, with a rated heat (5) Onshore petroleum and natural number(s) associated with each EOR capacity greater than 1 million Btu per gas production and onshore petroleum injection pump. hour (or the equivalent of 130 and natural gas gathering and boosting. * * * * * horsepower); or, internal fuel Reciprocating compressors in onshore (x) EOR hydrocarbon liquids. You combustion units of any heat capacity petroleum and natural gas production must indicate whether hydrocarbon that are compressor-drivers. If your and onshore petroleum and natural gas liquids were produced through EOR facility contains: External fuel gathering and boosting must report the operations. If hydrocarbon liquids were combustion units with a rated heat information specified in paragraphs produced through EOR operations, you capacity greater than 5 mmBtu/hr; (p)(5)(i) through (iv) of this section. must report the information specified in internal fuel combustion units that are * * * * * paragraphs (x)(1) through (5) of this not compressor-drivers, with a rated (ii) A list of the well ID numbers for section for each sub-basin category with heat capacity greater than 1 million Btu the wells at which these compressors EOR operations. per hour (or the equivalent of 130 are located (for the onshore petroleum * * * * * horsepower); or internal fuel and natural gas production industry (2) A list of the well ID numbers combustion units of any heat capacity segment only). associated with the EOR operations in that are compressor-drivers, then you each sub-basin. must report the information specified in * * * * * paragraphs (z)(2)(i) through (vii) for (r) * * * * * * * * (z) Combustion equipment at onshore each combustion unit type and fuel type (1) You must indicate whether your combination. facility contains any of the emission petroleum and natural gas production source types required to use Equation facilities, onshore petroleum and * * * * * (ii) A list of the well ID numbers W–32A of this subpart. You must report natural gas gathering and boosting associated with the combustion units the information specified in paragraphs facilities, and natural gas distribution (for the onshore petroleum and natural (r)(1)(i) through (v) of this section facilities. If your facility is required by gas production industry segment only). separately for each emission source type § 98.232(c)(22), (i)(7), or (j)(12) to report required to use Equation W–32A of this emissions from combustion equipment, * * * * * subpart that is located at your facility. then you must indicate whether your (aa) Each facility must report the Onshore petroleum and natural gas facility has any combustion units information specified in paragraphs production facilities and onshore subject to reporting according to (aa)(1) through (11) of this section, for petroleum and natural gas gathering and paragraphs (a)(1)(xvii), (a)(8)(i), or each applicable industry segment, by boosting facilities must report the (a)(9)(xi) of this section. If your facility using best available data. If a quantity information specified in paragraphs contains any combustion units subject required to be reported is zero, you must (r)(1)(i) through (v) of this section to reporting according to paragraphs report zero as the value. separately by component type, service (a)(1)(xvii), (a)(8)(i), or (a)(9)(xi) of this (1) * * * type, and geographic location (i.e., section, then you must report the (ii) * * * Eastern U.S. or Western U.S.). information specified in paragraphs (D) The number of producing wells (i) Emission source type. Onshore (z)(1) and (2) of this section, as and a list of the well ID numbers at the petroleum and natural gas production applicable. end of the calendar year (exclude only facilities and onshore petroleum and (1) Indicate whether the combustion those wells permanently taken out of natural gas gathering and boosting units include: External fuel combustion production, i.e., plugged and facilities must report the component units with a rated heat capacity less abandoned). type, service type, and geographic than or equal to 5 million Btu per hour; (E) The number of producing wells location. For the onshore petroleum and or, internal fuel combustion units that and a list of the well ID numbers natural gas production facilities only, are not compressor-drivers, with a rated acquired during the calendar year. (F) The number of producing wells also report a list of well ID numbers for heat capacity less than or equal to 1 and a list of the well ID numbers the associated wells. mmBtu/hr (or the equivalent of 130 horsepower). If the facility contains divested during the calendar year. * * * * * external fuel combustion units with a (G) The number of wells and a list of (3) Onshore petroleum and natural gas rated heat capacity less than or equal to the well ID numbers completed during production facilities and onshore 5 million Btu per hour or internal fuel the calendar year. petroleum and natural gas gathering and combustion units that are not (H) The number of wells permanently boosting facilities must also report the compressor-drivers, with a rated heat taken out of production (i.e., plugged information specified in paragraphs capacity less than or equal to 1 million and abandoned) and a list of the well ID (r)(3)(i) and (ii) of this section. Btu per hour (or the equivalent of 130 numbers during the calendar year. * * * * * horsepower), then you must report the * * * * * (ii) Onshore petroleum and natural information specified in paragraphs (10) For onshore petroleum and gas production facilities and onshore (z)(1)(i) through (iii) of this section for natural gas gathering and boosting petroleum and natural gas gathering and each unit type. facilities, report the quantities specified boosting facilities must report the * * * * * in paragraphs (aa)(10)(i) through (v) of information specified in paragraphs (iii) A list of the well ID numbers this section. (r)(3)(ii)(A) and (B) of this section, for associated with the combustion units (i) The quantity of produced gas each major equipment type, production (for the onshore petroleum and natural throughput in the calendar year, in type (i.e., natural gas or crude oil), and gas production industry segment only). thousand standard cubic feet. geographic location combination in (2) Indicate whether the combustion (ii) The quantity of produced gas Tables W–1B and W–1C of this subpart. units include: External fuel combustion consumed by the facility in the calendar * * * * * units with a rated heat capacity greater year, in thousand standard cubic feet.

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(iii) The quantity of produced corresponding subpart A requirements,’’ Gathering and boosting system means condensate throughput in the calendar ‘‘Facility with respect to the onshore a single network of pipelines, year, in barrels. natural gas transmission pipeline compressors and process equipment, (iv) The quantity of produced oil segment,’’ ‘‘Gathering and boosting including equipment to perform natural throughput in the calendar year, in system,’’ ‘‘Gathering and boosting gas compression, dehydration, and acid barrels. system owner or operator,’’ ‘‘Onshore gas removal, that has one or more (v) The quantity of gas flared, vented natural gas transmission pipeline owner connection points to gas and oil and/or unaccounted for in the calendar or operator,’’ and ‘‘Well identification production and a downstream endpoint, year, in thousand standard cubic feet. (ID) number’’ in alphabetical order to typically a gas processing plant, (11) For onshore natural gas read as follows: transmission pipeline, LDC pipeline, or transmission pipeline facilities, report other gathering and boosting system. § 98.238 Definitions. the quantities specified in paragraphs Gathering and boosting system owner (aa)(11)(i) through (vi) of this section. * * * * * or operator means any person that holds (i) The quantity of natural gas Facility with respect to petroleum and a contract in which they agree to received at all custody transfer stations natural gas gathering and boosting for transport petroleum or natural gas from in the calendar year, in thousand purposes of reporting under this subpart one or more onshore petroleum and standard cubic feet. This value may and for the corresponding subpart A natural gas production wells to a natural include meter corrections, but only for requirements means all gathering gas processing facility, another the calendar year covered by the annual pipelines and other equipment located gathering and boosting system, a natural report. along those pipelines that are under gas transmission pipeline, or a (ii) The quantity of natural gas common ownership or common control distribution pipeline, or any person withdrawn from in-system storage in the by a gathering and boosting system responsible for custody of the gas calendar year, in thousand standard owner or operator and that are located transported. in a single hydrocarbon basin as defined cubic feet. * * * * * (iii) The quantity of natural gas added in this section. Where a person owns or Onshore natural gas transmission to in-system storage in the calendar operates more than one gathering and pipeline owner or operator means, for year, in thousand standard cubic feet. boosting system in a basin (for example, (iv) The quantity of natural gas separate gathering lines that are not interstate pipelines, the person transferred to third parties such as LDCs connected), then all gathering and identified as the transmission pipeline or other transmission pipelines, in boosting equipment that the person owner or operator on the Certificate of thousand standard cubic feet. owns or operates in the basin would be Public Convenience and Necessity (v) The quantity of natural gas considered one facility. Any gathering issued under 15 U.S.C. 717f, or, for consumed by the transmission pipeline and boosting equipment that is intrastate pipelines, the person facility for operational purposes, in associated with a single gathering and identified as the owner or operator on thousand standard cubic feet. boosting system, including leased, the transmission pipeline’s Statement of (vi) The miles of transmission rented, or contracted activities, is Operating Conditions under section 311 pipeline in the facility. considered to be under common control of the Natural Gas Policy Act. * * * * * of the owner or operator of the gathering * * * * * (cc) If you elect to delay reporting the and boosting system that contains the Well identification (ID) number means information in paragraph (g)(5)(i), pipeline. The facility does not include the unique and permanent identification (g)(5)(ii), (h)(1)(iv), (h)(2)(iv), (j)(1)(v), equipment and pipelines that are part of number assigned to a petroleum or (j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), (l)(3)(iii), any other industry segment defined in natural gas well. If the well has been (l)(4)(iii), (m)(5), or (m)(6) of this this subpart. assigned a US Well Number, the well ID section, you must report the information Facility with respect to the onshore number required in this subpart is the required in that paragraph no later than natural gas transmission pipeline US Well Number. If a US Well Number the date 2 years following the date segment means the total U.S. mileage of has not been assigned to the well, the specified in § 98.3(b) introductory text. natural gas transmission pipelines, as well ID number is the identifier ■ 8. Section 98.238 is amended by defined in this section, owned and established by the well’s permitting adding definitions of ‘‘Facility with operated by an onshore natural gas authority. respect to petroleum and natural gas transmission pipeline owner or operator * * * * * gathering and boosting for purposes of as defined in this section. ■ 9. Revise Table W–1A of Subpart W of reporting under this subpart and for the * * * * * part 98 to read as follows:

TABLE W–1A OF SUBPART W OF PART 98—DEFAULT WHOLE GAS EMISSION FACTORS FOR ONSHORE PETROLEUM AND NATURAL GAS PRODUCTION FACILITIES AND ONSHORE PETROLEUM AND NATURAL GAS GATHERING AND BOOSTING FACILITIES

Emission factor Onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting (scf/hour/component)

Eastern U.S.

Population Emission Factors—All Components, Gas Service 1

Valve ...... 0.027 Connector ...... 0.003 Open-ended Line ...... 0 .061 Pressure Relief Valve ...... 0 .040 Low Continuous Bleed Pneumatic Device Vents 2 ...... 1.39

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TABLE W–1A OF SUBPART W OF PART 98—DEFAULT WHOLE GAS EMISSION FACTORS FOR ONSHORE PETROLEUM AND NATURAL GAS PRODUCTION FACILITIES AND ONSHORE PETROLEUM AND NATURAL GAS GATHERING AND BOOSTING FACILITIES—Continued

Emission factor Onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting (scf/hour/component)

High Continuous Bleed Pneumatic Device Vents 2 ...... 37 .3 Intermittent Bleed Pneumatic Device Vents 2 ...... 13 .5 Pneumatic Pumps 3 ...... 13 .3

Population Emission Factors—All Components, Light Crude Service 4

Valve ...... 0.05 Flange ...... 0 .003 Connector ...... 0.007 Open-ended Line ...... 0 .05 Pump ...... 0 .01 Other 5 ...... 0.30

Population Emission Factors—All Components, Heavy Crude Service 6

Valve ...... 0.0005 Flange ...... 0 .0009 Connector (other) ...... 0.0003 Open-ended Line ...... 0 .006 Other 5 ...... 0.003

Population Emission Factors—Gathering Pipelines

Gathering Pipeline 7 ...... 2.81

Western U.S.

Population Emission Factors—All Components, Gas Service 1

Valve ...... 0.121 Connector ...... 0.017 Open-ended Line ...... 0 .031 Pressure Relief Valve ...... 0 .193 Low Continuous Bleed Pneumatic Device Vents 2 ...... 1.39 High Continuous Bleed Pneumatic Device Vents 2 ...... 37 .3 Intermittent Bleed Pneumatic Device Vents 2 ...... 13 .5 Pneumatic Pumps 3 ...... 13 .3

Population Emission Factors—All Components, Light Crude Service 4

Valve ...... 0.05 Flange ...... 0 .003 Connector (other) ...... 0.007 Open-ended Line ...... 0 .05 Pump ...... 0 .01 Other 5 ...... 0.30

Population Emission Factors—All Components, Heavy Crude Service 6

Valve ...... 0.0005 Flange ...... 0 .0009 Connector (other) ...... 0.0003 Open-ended Line ...... 0 .006 Other 5 ...... 0.003

Population Emission Factors—Gathering Pipelines

Gathering Pipeline 7 ...... 2.81 1 For multi-phase flow that includes gas, use the gas service emissions factors. 2 Emission Factor is in units of ‘‘scf/hour/device.’’ 3 Emission Factor is in units of ‘‘scf/hour/pump.’’ 4 Hydrocarbon liquids greater than or equal to 20°API are considered ‘‘light crude.’’ 5 ‘‘Others’’ category includes instruments, loading arms, pressure relief valves, stuffing boxes, compressor seals, dump lever arms, and vents. 6 Hydrocarbon liquids less than 20°API are considered ‘‘heavy crude.’’ 7 Emission factor is in units of ‘‘scf/hour/mile of pipeline.’’

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■ 10. Amend Table W–1B of Subpart W TABLE W–1B TO SUBPART W OF PART * * * * * of part 98 by revising the table heading 98—DEFAULT AVERAGE COMPO- [FR Doc. 2014–28395 Filed 12–8–14; 8:45 am] to read as follows: NENT COUNTS FOR MAJOR ON- BILLING CODE 6560–50–P SHORE NATURAL GAS PRODUCTION EQUIPMENT AND ONSHORE PETRO- LEUM AND NATURAL GAS GATH- ERING AND BOOSTING EQUIPMENT

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