# Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2014-28395 ## Record - **Collection:** Federal Register - **Document type:** Proposed Rule - **Published:** December 9, 2014 - **Citation:** 79 FR 73148 ## Text ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 98 [EPA-HQ-OAR-2014-0831; FRL—9918-48-OAR] RIN 2060-AS37 Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems AGENCY: Environmental Protection Agency. ACTION: Proposed rule. SUMMARY: The Environmental Protection Agency (EPA) is proposing revisions and confidentiality determinations for the petroleum and natural gas systems source category of the Greenhouse Gas Reporting Program. In particular, the EPA is proposing to add calculation methods and reporting requirements for greenhouse gas emissions from gathering and boosting facilities, completions and workovers of oil wells with hydraulic fracturing, and blowdowns of natural gas transmission pipelines between compressor stations. The EPA is also proposing well identification reporting requirements to improve the EPA's ability to verify reported data and enhance transparency. This action also proposes confidentiality determinations for new data elements contained in these proposed amendments. DATES: Comments must be received on or before February 9, 2015. Public Hearing. The EPA does not plan to conduct a public hearing unless requested. To request a hearing, please contact the person listed in the following FOR FURTHER INFORMATION CONTACT section by December 16, 2014. If requested, the hearing will be conducted on December 24, 2014, in the Washington, DC area. The EPA will provide further information about the hearing on the Greenhouse Gas Reporting Program Web site, http://www.epa.gov/ghgreporting/index.html if a hearing is requested. ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2014-0831 by any of the following methods: • Federal eRulemaking Portal: http://www.regulations.gov. Follow the online instructions for submitting comments. • Email: A-and-R-Docket @epa.gov. Include Docket ID No. EPA-HQ-OAR-2014-0831 or RIN No. 2060-AS37 in the subject line of the message. • Fax: (202) 566-9744. • Mail: Environmental Protection Agency, EPA Docket Center (EPA/DC), Mailcode 28221T, Attention Docket ID No. EPA-HQ-OAR-2014-0831, 1200 Pennsylvania Avenue NW., Washington, DC 20460. In addition, please mail a copy of your comments on the information collection provisions to the Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), Attn: Desk Officer for EPA, 725 17th Street, NW., Washington, DC 20503. • Hand/Courier Delivery: EPA Docket Center, Room 3334, EPA WJC West Building, 1301 Constitution Avenue NW., Washington, DC 20004. Such deliveries are accepted only during the normal hours of operation of the Docket Center, and special arrangements should be made for deliveries of boxed information. Additional Information on Submitting Comments: To expedite review of your comments by agency staff, you are encouraged to send a separate copy of your comments, in addition to the copy you submit to the official docket, to Carole Cook, U.S. EPA, Office of Atmospheric Programs, Climate Change Division, Mail Code 6207A, 1200 Pennsylvania Avenue NW., Washington, DC 20460, telephone (202) 343-9263, email address: GHGReportingRule@epa.gov. Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-2014-0831, Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule. The EPA's policy is that all comments received will be included in the public docket without change and may be made available online at http://www.regulations.gov, including any personal information provided, unless the comment includes information claimed to be confidential business information (CBI) or other information whose disclosure is restricted by statute. Should you choose to submit information that you claim to be CBI, clearly mark the part or all of the information that you claim to be CBI. For information that you claim to be CBI in a disk or CD-ROM that you mail to the EPA, mark the outside of the disk or CD-ROM as CBI and then identify electronically within the disk or CD-ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. Send or deliver information identified as CBI to only the mail or hand/courier delivery address listed above, attention: Docket ID No. EPA-HQ-OAR-2014-0831. If you have any questions about CBI or the procedures for claiming CBI, please consult the person identified in the FOR FURTHER INFORMATION CONTACT section. Do not submit information that you consider to be CBI or otherwise protected through http://www.regulations.gov or email. The http://www.regulations.gov Web site is an “anonymous access” system, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through http://www.regulations.gov your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, the EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses. Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some information is not publicly available, e.g., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in http://www.regulations.gov or in hard copy at the Air Docket, EPA/DC, WJC West Building, Room 3334, 1301 Constitution Ave., NW., Washington, DC. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the Air Docket is (202) 566-1742. FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division, Office of Atmospheric Programs (MC-6207A), Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 343-9263; fax number: (202) 343-2342; email address: GHGReportingRule@epa.gov. For technical information, please go to the Greenhouse Gas Reporting Program Web site, http://www.epa.gov/ghgreporting/index.html. To submit a question, select Help Center, followed by “Contact Us.” Worldwide Web (WWW ). In addition to being available in the docket, an electronic copy of today's proposal will also be available through the WWW. Following the Administrator's signature, a copy of this action will be posted on the EPA's Greenhouse Gas Reporting Program Web site at http://www.epa.gov/ghgreporting/index.html. SUPPLEMENTARY INFORMATION: Regulated Entities. The Administrator determined that this action is subject to the provisions of Clean Air Act (CAA) section 307(d). See CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to “such other actions as the Administrator may determine”). These are proposed amendments to existing regulations. If finalized, these amended regulations would affect owners or operators of petroleum and natural gas systems that directly emit greenhouse gases (GHGs). Regulated categories and entities include those listed in Table 1 of this preamble: 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 intended to be exhaustive, but rather provides a guide for readers regarding facilities likely to be affected by this action. Other types of facilities than those listed in the table could also be subject to reporting requirements. To determine whether you are affected by this action, you should carefully examine the applicability criteria found in 40 CFR part 98, subpart A and 40 CFR part 98, subpart W. If you have questions regarding the applicability of this action to a particular facility, consult the person listed in the preceding FOR FURTHER INFORMATION CONTACT section. Acronyms and Abbreviations. The following acronyms and abbreviations are used in this document. API American Petroleum Institute BAMM best available monitoring methods Btu British thermal unit CAA Clean Air Act CBI confidential business information CFR Code of Federal Regulations CO 2 carbon dioxide CO 2 e carbon dioxide equivalent EPA Environmental Protection Agency EIA Energy Information Administration FERC Federal Energy Regulatory Commission FR Federal Register GHG greenhouse gas GHGRP Greenhouse Gas Reporting Program GOR gas-to-oil ratio ICR Information Collection Request ISBN International Standard Book Number LDC local distribution company MMscfd million standard cubic feet per day NAICS North American Industry Classification System NESHAP national emission standards for hazardous air pollutants NGO non-government organization NGPA Natural Gas Policy Act NTTAA National Technology Transfer and Advancement Act of 1995 OMB Office of Management and Budget PPDM Professional Petroleum Data Management REC reduced emission completion RFA Regulatory Flexibility Act SBA Small Business Administration SBREFA Small Business Regulatory Enforcement and Fairness Act U.S. United States UMRA Unfunded Mandates Reform Act of 1995 Organization of This Document. The following outline is provided to aid in locating information in this preamble. I. Background A. Organization of This Preamble B. Background on the Proposed Action C. Legal Authority D. How would these amendments apply to 2015 and 2016 reports? II. Revisions and Other Amendments A. Oil Wells With Hydraulic Fracturing B. Onshore Petroleum and Natural Gas Gathering and Boosting Segment C. Natural Gas Transmission Lines Between Compressor Stations D. Well Identification Numbers E. Advanced Innovative Monitoring Methods F. Best Available Monitoring Methods III. Proposed Confidentiality Determinations A. Overview and Background B. Approach to Proposed CBI Determinations C. Proposed Confidentiality Determinations for Data Elements Assigned to the “Unit/Process `Static' Characteristics That Are Not Inputs to Emission Equations” and “Unit/Process Operating Characteristics That Are Not Inputs to Emission Equations” Data Categories D. Other Proposed Case-by-Case Confidentiality Determinations for Subpart W E. Request for Comments on Proposed Confidentiality Determinations IV. Impacts of the Proposed Amendments to Subpart W A. Costs of the Proposed Amendments B. Impacts of the Proposed Amendments on Small Businesses V. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review B. Paperwork Reduction Act C. Regulatory Flexibility Act D. Unfunded Mandates Reform Act E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations I. Background A. Organization of This Preamble The first section of this preamble provides background information regarding the proposed amendments. This section also discusses the EPA's legal authority under the CAA to promulgate and amend 40 CFR part 98 (hereafter referred to as “Part 98”) as well as the legal authority for making confidentiality determinations for the data to be reported. Section II of this preamble contains information on the proposed revisions to 40 CFR part 98, subpart W (hereafter referred to as “subpart W”). Section III of this preamble discusses proposed confidentiality determinations for new data reporting elements. Section IV of this preamble discusses the impacts of the proposed amendments to subpart W. Finally, Section V of this preamble describes the statutory and executive order requirements applicable to this action. B. Background on the Proposed Action The EPA's Greenhouse Gas Reporting Program (GHGRP) requires annual reporting of GHG data and other relevant information from large sources and suppliers in the United States. On October 30, 2009, the EPA published Part 98 for collecting information regarding GHG emissions from a broad range of industry sectors (74 FR 56260). Although reporting requirements for petroleum and natural gas systems were originally proposed to be part of Part 98 (75 FR 16448, April 10, 2009), the final October 2009 rule did not include the petroleum and natural gas systems source category as one of the 29 source categories for which reporting requirements were finalized. The EPA re-proposed subpart W in 2010 (79 FR 18608; April 12, 2010), and a subsequent final rule was published on November 30, 2010, with the requirements for the petroleum and natural gas systems source category at 40 CFR part 98, subpart W (75 FR 74458) (hereafter referred to as “the final subpart W rule”). Following promulgation, the EPA finalized actions revising subpart W (76 FR 22825, April 25, 2011; 76 FR 59533, September 27, 2011; 76 FR 80554, December 23, 2011; 77 FR 51477, August 24, 2012; 78 FR 25392, May 1, 2013; 78 FR 71904, November 29, 2013; 79 FR 63750, October 24, 2014; 79 FR 70352, November 25, 2014). In this current proposal, the EPA is proposing to amend subpart W to require the reporting of GHG emissions from several sources that have not previously been included in subpart W. These sources include oil well completions and workovers with hydraulic fracturing, petroleum and natural gas gathering and boosting systems, and transmission pipeline blowdowns between compressor stations. The proposed reporting requirements for oil well completions and workovers with hydraulic fracturing would be included as part of the existing Onshore Petroleum and Natural Gas Production industry segment. For the other sources, the EPA is proposing two new industry segments: the Onshore Petroleum and Natural Gas Gathering and Boosting segment for petroleum and natural gas gathering and boosting facilities, and Onshore Natural Gas Transmission Pipeline for transmission pipeline blowdowns between compressor stations. The EPA is also proposing to require the reporting of a well identification number for oil and gas wells covered in the Onshore Petroleum and Natural Gas Production segment. The EPA is proposing these changes for several reasons. First, we have been working to enhance the quality of data from petroleum and natural gas systems gathered through Part 98, because it has been an important tool for the EPA and the public to analyze emissions, identify opportunities for improving the data, and understand emissions trends. One of the strengths of the GHGRP's petroleum and natural gas systems data is that it provides a better understanding of sources in the petroleum and natural gas industry for which the public previously had little information. For example, the data that would be collected through these proposed revisions could inform updates to the Inventory of U.S. Greenhouse Gas Emissions and Sinks 1 (hereafter referred to as the “U.S. GHG Inventory”). These proposed revisions reflect the fact that this sector has been growing and changing rapidly since the GHGRP's petroleum and natural gas systems requirements were originally promulgated in 2010. Greenhouse gas reporting from gathering and boosting systems was proposed in 2010 but was not finalized due to the need to conduct additional analysis. Emissions from the sources the EPA is proposing to include are not reported under the GHGRP with the exception of emissions from completions and workovers of oil wells with hydraulic fracturing that are flared and emissions from sources in the Onshore Petroleum and Natural Gas Gathering and Boosting segment that are required to report as combustion sources under subpart C of Part 98. Aside from those exceptions, which only include emissions associated with combustion and do not capture the majority of methane emissions from these sources, a nationally comprehensive data set of the emissions from the sources the EPA is proposing to include does not currently exist in the public domain. The EPA anticipates that these emission sources will be an important part of establishing a comprehensive data set for the petroleum and natural gas industry based on data available in the U.S. GHG Inventory and other sources. For more information, please see “Greenhouse Gas Reporting Rule: Technical Support for 2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule” in Docket ID No. EPA-HQ-OAR-2014-0831. If finalized, this rule would further the EPA's goal of improving the completeness, quality, accuracy, and transparency of data from this sector (79 FR 74484, November 30, 2010), improving the ability of agencies and the public to use these GHG data to analyze emissions and understand emission trends. Adding well identification numbers to the required reporting for oil and gas wells covered by the Onshore Petroleum and Natural Gas Production segment would enable the EPA and other stakeholders to directly match data for reported wells with other local, state, and federal permitting and data reporting information, as it is the common identification number used for wells in the United States (U.S.). 1 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012. April 15, 2014. EPA 430-R-14-003. This report tracks total annual U.S. emissions and removals by source, economic sector, and greenhouse gas going back to 1990. It is updated annually, and the latest version (cited here) covers emissions through 2012. Second, a key element of the President's Climate Action Plan is the Strategy to Reduce Methane Emissions, which the Administration announced on March 28, 2014. 2 The strategy summarizes the sources of methane emissions, commits to new steps to cut emissions of this potent greenhouse gas, and outlines the Administration's efforts to improve the measurement of these emissions. The strategy builds on progress to date and takes steps to further cut methane emissions from several sectors, including the oil and natural gas sector. In this strategy, the EPA was specifically tasked with continuing to review regulatory requirements to address potential gaps in coverage, improve methods, and help ensure high quality data reporting. The proposed revisions to subpart W covered in this action would address data gaps, specify methods for measuring methane emissions, and provide data that could be used to further analyze methane emissions in this industry. 2 Climate Action Plan—Strategy to Reduce Methane Emissions. The White House, Washington, DC, March 2014. Available at http://www.whitehouse.gov/sites/default/files/strategy_to_reduce_methane_emissions_2014-03-28_final.pdf. Third, on March 19, 2013, the EPA received a petition from a group of non-government organizations (NGOs) asking that the EPA collect data from emissions sources not currently included in subpart W, including well completion emissions from oil wells that co-produce natural gas, facilities and pipelines in the gathering and boosting segment, and transmission pipeline blowdown events, because these sources could be significant sources of emissions that are not being reported. The NGOs also asked the EPA to require the reporting of API well identification numbers (currently known as US Well Numbers) to allow cross-reference to production data and other important information, to phase out the use of best available monitoring methods (BAMM), and to consider including “Advanced Innovative Monitoring Methods” to “accelerate development and deployment of real-time continuous methane emission monitoring.” 3 These proposed revisions, which address this petition, are consistent with the EPA's intent to “collect complete and accurate facility-level GHG emissions from the petroleum and natural gas industry” (79 FR 74484, November 30, 2010) and to provide accurate and transparent data to inform future policy decisions. Today's proposal includes the reporting of emissions currently not covered under subpart W as well as reporting of well identification numbers which would help ensure complete, accurate, and transparent reporting of GHG data under subpart W. The EPA is proposing to allow BAMM for a limited time only for sources affected by these proposed changes; the use of BAMM for sources not addressed by the proposed changes in this action was addressed on November 25, 2014 (79 FR 70352). Finally, the EPA is currently assessing the potential opportunities for applying innovations in measurement technology to identifying and estimating emissions from affected sources under subpart W. While not explicitly adding new, alternative monitoring methods in this proposal, the EPA is seeking comment on options for allowing use of alternative monitoring methods under the GHGRP to account for advances in technology. See also, “Discussion Paper on Potential Implementation of Alternative Monitoring under the GHGRP” in Docket ID No. EPA-HQ-OAR-2014-0831. 3 Petition for Rulemaking and Interpretive Guidance Ensuring Comprehensive Coverage of Methane Sources Under Subpart W of the Greenhouse Gas Reporting Rule—Petroleum And Natural Gas Systems; Submitted by Clean Air Task Force, Environmental Defense Fund, Natural Resources Defense Council, and Sierra Club; March 19, 2013. C. Legal Authority The EPA is proposing these rule amendments under its existing CAA authority provided in CAA section 114. As stated in the preamble to the 2009 final GHG reporting rule (74 FR 56260, October 30, 2009), CAA section 114(a)(1) provides the EPA broad authority to require the information proposed to be gathered by this rule because such data would inform and are relevant to the EPA's carrying out a wide variety of CAA provisions. See the preambles to the proposed (74 FR 16448, April 10, 2009) and final GHG reporting rule (74 FR 56260, October 30, 2009) for further information. In addition, the EPA is proposing confidentiality determinations for proposed new data elements in subpart W under its authorities provided in sections 114, 301, and 307 of the CAA. Section 114(c) of the CAA requires that the EPA make information obtained under section 114 available to the public, except where information qualifies for confidential treatment. The Administrator has determined that this proposed rule is subject to the provisions of section 307(d) of the CAA. D. How would these amendments apply to 2015 and 2016 reports? The EPA is planning to address the comments we receive on these proposed changes and publish the final amendments before the end of 2015. If finalized according to this schedule, these amendments would become effective on January 1, 2016. Facilities would therefore be required to follow the revised methods in subpart W, as amended, to calculate, monitor, and report emissions beginning January 1, 2016. The first annual reports of emissions calculated using the amended requirements would be those submitted by March 31, 2017, which would cover the 2016 emissions reporting. For the 2015 emissions and the corresponding reports due by March 31, 2016, reporters would continue to calculate, monitor, and report emissions and other relevant data according to the requirements of 40 CFR part 98 that are applicable during the 2015 calendar year. For 2016 emissions only, the EPA is proposing to allow the use of short-term transitional BAMM for reporters who would be subject to new monitoring requirements associated with these proposed revisions. The use of BAMM would provide flexibility for the first-time monitoring of new emissions sources. These reporters would have the option of using BAMM from January 1, 2016 to March 31, 2016 without seeking prior EPA approval. Reporters would also have the opportunity to request an extension for the use of BAMM from April 1, 2016 through December 31, 2016; those owners or operators would be required to submit a request to the EPA by January 31, 2016. See Section II.F of this preamble for more information. II. Revisions and Other Amendments A. Oil Wells With Hydraulic Fracturing Subpart W requires the reporting of GHG emissions from gas well completions and workovers with hydraulic fracturing in the Onshore Petroleum and Natural Gas Production segment, but it does not require the reporting of GHG emissions from oil well completions and workovers with hydraulic fracturing (unless the emissions are routed to a flare, in which case the emissions would be calculated as part of the flare stacks emission source, or the well testing emissions are vented or flared, in which case the emissions would be calculated as part of the well testing venting and flaring emission source). At the time the EPA finalized the subpart W requirements (75 FR 74458, November 30, 2010), hydraulic fracturing of gas wells was a well-established and widespread industry practice. However, since that time, expansion of the use of horizontal drilling and hydraulic fracturing has allowed drilling into new formations, leading to increased emissions associated with hydraulic fracturing. 4 Because hydraulic fracturing allows access to new geologic formations, some of these activities are occurring from completions and workovers with hydraulic fracturing of wells considered to be in oil formations according to the definition of “sub-basin category, for onshore natural gas production” in 40 CFR 98.238. Since subpart W does not currently capture these emissions from oil wells with hydraulic fracturing, the EPA is proposing to close this data gap by proposing reporting requirements for oil well completions and workovers with hydraulic fracturing. 4 U.S. EPA Office of Air Quality Planning and Standards (OAQPS). Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas During Ongoing Production: Report for Oil and Natural Gas Sector, Oil Well Completions and Associated Gas During Ongoing Production Review Panel. April 2014. Available at http://www.epa.gov/airquality/oilandgas/pdfs/20140415completions.pdf. The EPA is proposing to amend subpart W: (1) To clarify the applicability of the current provisions for the reporting of GHG emissions from completions and workovers with hydraulic fracturing for wells in the Onshore Petroleum and Natural Gas Production segment, regardless of whether their primary product is oil or natural gas, and (2) to include provisions for the reporting of GHG emissions from oil well completions and workovers with hydraulic fracturing. Consistent with the current requirements for gas well completions and workovers with hydraulic fracturing, the proposed provisions include the reporting of activity data on the number of oil wells with hydraulic fracturing and on the use of flaring and reduced emission completions (RECs). The EPA is also proposing to update equations and definitions accordingly under 40 CFR 98.233(g) to reflect applicability to completions and workovers of all wells with hydraulic fracturing. The proposed monitoring methods and reporting requirements would incorporate methods that are already in subpart W for hydraulic fracturing of gas wells. The feasibility of the methods have been demonstrated and refined through several years of reporting and earlier amendments to subpart W. Specifically, the EPA is proposing to require the use of either Equation W-10A or W-10B in the current rule for calculating GHG emissions from oil well completions and workovers with hydraulic fracturing. Equation W-10A is used to calculate emissions from wells using inputs obtained from a representative sample of wells within a sub-basin and the ratio of the gas flowback rate to the production flow rate, and Equation W-10B is used to calculate emissions using inputs obtained from all wells within a sub-basin and the flow rate and flow volume of the gas vented or flared. Emissions would be calculated and reported separately for gas wells and oil wells. Within subpart W, an individual well is labeled an “oil well” or “gas well” depending on the formation type reported for that well. If wells produce from more than one formation type, then the well is classified into only one type based on the formation type with the most contribution to production as determined by the reporter's engineering knowledge. Furthermore, the EPA is proposing to require Calculation Method 1 for calculating inputs to Equations W-12A and W-12B for oil wells. Calculation Method 1 relies on direct measurement of gas flow rate during flowback to develop calculation inputs. The EPA is proposing that subpart W would include the same requirements for the location of the flow meter used to measure the gas flow rate for an oil well as for the flow meter on a gas well. The EPA is seeking comment on whether this is the appropriate location for the oil well flow meter. The EPA is also seeking comment on the burden of requiring direct measurement of gas flow rate during flowback. The EPA is also aware that operators of oil wells with a relatively low gas-to-oil ratio (GOR) may not meter gas during the completion phase or even during the production phase. Instead, the associated natural gas may be vented or flared without measuring the gas flow rate. For these oil wells that do not meter gas production, the EPA is proposing to add a new Equation W-12C to calculate, rather than measure, the value of PR s,p (the average gas production flow rate during the first 30 days of production after the completion or workover), which is used as an input to Equation W-10A. In this proposed Equation W-12C, the value of PR s,p would be calculated by multiplying the GOR of the well by the measured oil production rate during the first 30 days of production after the completion or workover to calculate average gas production flow rate. The EPA is not proposing at this time to allow the use of calculated flowback rate for oil wells based on well parameters, as specified in Calculation Method 2 in 40 CFR 98.233(g). In the current subpart W, Calculation Method 2 uses the measured gas pressure differential across the well choke to estimate gas flow rate. Based on the information available, the EPA concluded that this methodology may not be appropriate for estimating emissions from oil well completions because of the differences in operational conditions between oil and gas production. The EPA is seeking comment on how an engineering estimate of gas flow rate for oil wells might be performed as an alternative to the proposed monitoring methods that would require direct measurement of gas flow rate. Such an engineering estimate would be analogous to the current Calculation Method 2, but with alternatives to the current Equations 11-A and 11-B that would be applicable to oil wells. If an appropriate and technically sound approach can be identified, an engineering estimate methodology analogous to Calculation Method 2 for gas wells would reduce the burden for reporters of oil well completions and workovers with hydraulic fracturing. Additionally, the EPA is seeking comment on whether to establish a minimum GOR threshold such that oil wells with a very low GOR would not be subject to the monitoring and reporting requirements for GHG emissions from completions and workovers with hydraulic fracturing. The EPA is also soliciting data and other supporting information that could be used to establish a level for that threshold in the final rule amendments, if that approach were adopted. Supporting data should include, at a minimum, information sufficient to identify the location of any wells for which data are provided ( e.g., US Well Number), the measured GOR, and whether the GOR for the well was measured during completion or workover. Information that would allow the EPA to estimate the typical emissions from wells with such a low GOR, and to estimate the total emissions from all wells that would be exempt if such a threshold were established, would be particularly helpful to inform potential inclusion of a GOR threshold in the final rule. The EPA particularly solicits specific data, rather than conclusory statements, to support commenters' positions on whether the EPA should include a minimum GOR threshold for monitoring and reporting. The EPA is also seeking comment on whether to establish a minimum well pressure such that oil wells operating below a certain pressure would not be subject to the monitoring and reporting requirements for GHG emissions from completions and workovers with hydraulic fracturing. Similar to the discussion on a potential GOR threshold above, the EPA is also soliciting data and other supporting information that could be used to establish a level for the well pressure threshold in the final rule amendments, if that approach were adopted. Supporting data should include, at a minimum, information sufficient to identify the location of any wells for which data are provided ( e.g., US Well Number), the measured well pressure, and whether the well pressure was measured during completion or workover. Information that would allow the EPA to estimate the typical emissions from wells with low well pressures, and to estimate the total emissions from all wells that would be exempt if such a threshold were established, would be particularly helpful to inform potential inclusion of a well pressure threshold in the final rule. The EPA particularly solicits specific data, rather than conclusory statements, to support commenters' positions on whether the EPA should include a minimum well pressure threshold for monitoring and reporting. B. Onshore Petroleum and Natural Gas Gathering and Boosting Segment The EPA is proposing to add a new industry segment to subpart W, Onshore Petroleum and Natural Gas Gathering and Boosting, that would cover emissions from equipment used by gathering pipeline systems that move petroleum and natural gas from the well to either larger gathering pipeline systems, natural gas processing plants, natural gas transmission pipelines, or natural gas distribution pipelines. A gathering and boosting system is a single network of pipelines, compressors and process equipment, including equipment to perform natural gas compression, dehydration, and acid gas removal, that has one or more well-defined connection points to gas and oil production and a well-defined downstream endpoint, typically a gas processing plant or transmission pipeline. Gathering pipelines are pipelines used to transport gas from the furthermost downstream point in an onshore production facility to certain endpoints, generally either a gas processing facility or point of connection to a transmission pipeline. Compressors located along the gathering and boosting system are used to control or “boost” the pressure of the gas in the pipeline and keep the gas moving downstream. Acid gas removal units and dehydrators may also be located on the gathering and boosting system to treat the collected natural gas. There are two types of gathering and boosting systems, radial and trunk line. The radial type brings all the pipelines to a central header, while the trunk-line type uses several remote headers to collect fluid and is mainly used in large fields. The EPA recognized the need to require reporting from gathering and boosting systems in an earlier GHGRP proposed rule. Gathering lines and boosting stations were included in the original subpart W proposal (75 FR 18608, April 12, 2010) under both the Onshore Petroleum and Natural Gas Production segment and the Onshore Natural Gas Processing segment. The EPA originally proposed to include reporting of emissions from intra-facility gathering lines and all systems engaged in gathering produced gas from multiple wells as part of the Onshore Petroleum and Natural Gas Production segment. The EPA also proposed that field gathering and boosting stations that gather and process natural gas from multiple wellheads and compress and transport natural gas as feed to natural gas processing facilities would be included in the Onshore Natural Gas Processing segment. In response to the April 2010 proposal, the EPA received 32 comment letters addressing numerous aspects of the proposed gathering and boosting reporting requirements. The comments generally focused on the areas of ownership of the gathering and boosting system, and on determining the boundaries of gathering and boosting between the Onshore Petroleum and Natural Gas Production and Onshore Natural Gas Processing segments. The commenters were also concerned with the burden of the proposed reporting requirements for the gathering and boosting systems. These comments were summarized in the preamble to the final subpart W rule (75 FR 74458, November 30, 2010) and can be found in the EPA's Response to Public Comments document for the final rule. 5 5 U.S. Environmental Protection Agency Office of Atmosphere Programs, Climate Change Division. Mandatory Greenhouse Gas Reporting Rule Subpart W—Petroleum and Natural Gas: EPA's Response to Public Comments, November 2010. Docket Item No. EPA-HQ-OAR-2009-0923-3608. In response to public comments, the EPA recognized the need for further analysis of gathering and boosting before developing reporting requirements. As a result, gathering and boosting sources were not included in the final subpart W rule published in November 2010, and the EPA stated that we would continue to evaluate “the most appropriate mechanism for future actions to address the collection of appropriate data on gathering lines and boosting stations” (75 FR 74469, November 30, 2010). After further consideration of the comments and collection of additional data, the EPA is proposing to require reporting of petroleum and natural gas gathering and boosting equipment as part of a new Onshore Petroleum and Natural Gas Gathering and Boosting segment to collect the data needed to quantify the emissions from this segment and to achieve more complete coverage of the petroleum and natural gas systems sector. The EPA is proposing to define the Onshore Petroleum and Natural Gas Gathering and Boosting segment in 40 CFR 98.230 as gathering pipelines and other equipment used to collect petroleum and/or natural gas from onshore production gas or oil wells and used to compress, dehydrate, sweeten, or transport the gas to a natural gas processing facility, a natural gas transmission pipeline, or a natural gas distribution pipeline. Gathering and boosting equipment would include, but would not be limited to, gathering pipelines, separators, compressors, acid gas removal units, dehydrators, pneumatic devices/pumps, storage vessels, engines, boilers, heaters, and flares. The Onshore Petroleum and Natural Gas Gathering and Boosting segment would not include equipment and pipelines that are reported under any other industry segment defined in subpart W. The EPA is proposing to define a gathering and boosting system as a single network of pipelines, compressors and process equipment, including equipment to perform natural gas compression, dehydration, and acid gas removal, that has one or more connection points to gas and oil production and a downstream endpoint, typically a gas processing plant, transmission pipeline, local distribution company (LDC) pipeline, or other gathering and boosting system. The EPA is proposing to define a gathering and boosting system owner or operator as any person that: (1) Holds a contract in which they agree to transport petroleum or natural gas from one or more onshore petroleum and natural gas production wells to a natural gas processing facility, another gathering and boosting system, a natural gas transmission pipeline, or a distribution pipeline; or (2) is responsible for custody of the gas transported. The purpose of including the last phrase of the definition is to address ownership scenarios for vertically integrated companies for which contracts are not needed to transfer gas from production wells to natural gas processing plants. The EPA requests comment on whether this phrase addresses that concern. The EPA is proposing to define a facility with respect to onshore petroleum and natural gas gathering and boosting in 40 CFR 98.238 as all gathering pipelines and other equipment located along those pipelines that are under common ownership or common control by a gathering and boosting system owner or operator and that are located in a single hydrocarbon basin as defined in 40 CFR 98.238. Where a person owns or operates more than one gathering and boosting system in a basin (for example, separate gathering lines that are not connected), then all gathering and boosting systems and equipment that the person owns or operates in the basin would be considered one facility. Any gathering and boosting equipment that is associated with a single gathering and boosting system, including leased, rented, or contracted activities, would be considered to be under common control of the owner or operator of the gathering and boosting system. Emissions from an onshore petroleum and natural gas gathering and boosting facility would only need to be reported if the collection of emission sources emits 25,000 metric tons of carbon dioxide equivalent (CO 2 e) or more per year. The basin-level reporting approach that the EPA is proposing for onshore petroleum and natural gas gathering and boosting facilities is currently being used for reporting in the Onshore Petroleum and Natural Gas Production sector. The proposed basin-level approach for the Onshore Petroleum and Natural Gas Gathering and Boosting segment would achieve a balance of providing geographically specific information, while also reducing burden on reporters by ensuring that owners/operators of gathering and boosting systems would only have to submit one report for all their systems within a basin. For more information on this analysis, please see “Greenhouse Gas Reporting Rule: Technical Support for 2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule” in Docket ID No. EPA-HQ-OAR-2014-0831. The EPA believes that the proposed definitions of the Onshore Petroleum and Natural Gas Gathering and Boosting segment, facility, and owner/operator address or avoid the major issues raised by the commenters in response to the April 2010 proposal. Defining the Onshore Petroleum and Natural Gas Gathering and Boosting segment as a segment separate from the Onshore Petroleum and Natural Gas Production segment and the Onshore Natural Gas Processing segment would avoid many of the boundary issues presented by the earlier proposal. The proposed definition of facility would also clarify how equipment located along the pipeline should be treated as part of the facility. The EPA requests comment on the definitions of the Onshore Petroleum and Natural Gas Gathering and Boosting segment and facility, the gathering and boosting system, the gathering and boosting system owner or operator, the determination of what emission sources are included in a petroleum and natural gas gathering and boosting facility in complex ownership scenarios (for example, multiple owners with operation handled by one of the owners or shared by multiple owners). In complex ownership scenarios, the EPA is proposing that the owners/operators would assign a designated representative responsible for reporting consistent with 40 CFR 98.4, and the EPA requests comment on whether the provisions of 40 CFR 98.4 are appropriate for petroleum and natural gas gathering and boosting facilities with complex ownership scenarios. In addition, the EPA requests comment on whether the proposed definitions clearly define the boundary of the Onshore Petroleum and Natural Gas Gathering and Boosting segment as the pipelines and equipment between the Onshore Petroleum and Natural Gas Production segment and the Onshore Natural Gas Processing segment (or other downstream segment). The EPA also requests comment on potential concerns with overlap of these boundaries and whether specific provisions are needed to address the overlap. For example, the EPA considered whether provisions were needed to address the potential for some non-fractionating processing plants with an annual throughput of around 25 million standard cubic feet per day (MMscfd) to be required to report as part of different industry segments from year to year ( i.e., as part of Onshore Petroleum and Natural Gas Gathering and Boosting if the annual average daily throughput drops below 25 MMscfd one year and then part of the Onshore Natural Gas Processing segment if the throughput increases to above 25 MMscfd the next year). The EPA considered a provision that would allow a non-fractionating processing facility to stop reporting as part of the Onshore Natural Gas Processing segment and instead report as part of the Onshore Petroleum and Natural Gas Gathering and Boosting segment if the facility throughput is below 25 MMscfd for 5 consecutive years. The EPA is not proposing to include this provision because there is not sufficient information available on gathering and boosting systems for the EPA to assess whether such a provision is necessary, but the EPA is requesting comment on the need for a provision that addresses overlap of segment boundaries and what that provision should include. The EPA is proposing to use current methods in subpart W, when available, for monitoring and calculating emissions from the Onshore Petroleum and Natural Gas Gathering and Boosting segment. Subpart W already contains monitoring and calculation methods for all emission sources that would be included in the Onshore Petroleum and Natural Gas Gathering and Boosting segment, with the exception of gathering pipelines, in either the Onshore Petroleum and Natural Gas Production segment or the Onshore Natural Gas Processing segment. Since similar equipment and sources are included in multiple segments, this approach allows the EPA to rely on methods that have been proven effective for collecting GHG data for at least 3 years. This approach is expected to provide high quality data while reducing the burden on reporters that would be associated with determining how to implement new estimation methods. For natural gas pneumatic devices, pneumatic valves, pneumatic pumps, and atmospheric storage tanks located in the Onshore Petroleum and Natural Gas Gathering and Boosting segment, the EPA is proposing that gathering and boosting reporters use the same methods for calculating emissions as in the Onshore Petroleum and Natural Gas Production segment. Where these emission sources are located within gathering and boosting facilities, these sources are likely to be similar to the ones located in the Onshore Petroleum and Natural Gas Production segment. Specifically, because most processing of the gas and oil extracted from wells will be processed downstream of the gathering and boosting facility, the equipment/activities in the Onshore Petroleum and Natural Gas Production segment will be designed to handle gas and oil of composition similar to the gas and oil in the Onshore Petroleum and Natural Gas Gathering and Boosting segment, so the same methods are applicable and would be no more burdensome. For blowdown vent stacks, the current subpart W requires reporting of emissions for the Onshore Natural Gas Processing segment, but not for the Onshore Petroleum and Natural Gas Production segment. The EPA is proposing that the same methods that are used for the Onshore Natural Gas Processing segment be applied to blowdowns of equipment in the Onshore Petroleum and Natural Gas Gathering and Boosting segment. The same exemptions, including those for volumes less than 50 cubic feet and for desiccant dehydrator reloading, that are applied to the Onshore Natural Gas Processing segment should also be applied to the Onshore Petroleum and Natural Gas Gathering and Boosting segment. The EPA expects that the exemption for volumes less than 50 cubic feet should alleviate any concerns with the burden of calculating emissions from small gathering pipelines. Several emission sources, including compressors, acid gas removal units, dehydrators, flares, and equipment leaks are found in both the Onshore Petroleum and Natural Gas Production segment and the Onshore Natural Gas Processing segment. For acid gas removal units, dehydrators, and flare stacks, the current subpart W specifies the same methods for these sources in both the Onshore Petroleum and Natural Gas Production segment and the Onshore Natural Gas Processing segment. For acid gas removal units and dehydrators, the current rule includes several alternative methods, and the same alternative methods are specified for both segments. Because these emission sources in the Onshore Petroleum and Natural Gas Gathering and Boosting segment are likely to be similar to the ones in the Onshore Petroleum and Natural Gas Production segment or the Onshore Natural Gas Processing segment, the same methods would be applicable. For compressors and equipment leaks, subpart W contains one method in the Onshore Petroleum and Natural Gas Production segment and a different method for the same emission source in the Onshore Natural Gas Processing segment. We are proposing that the gathering and boosting reporters use the same method as in the Onshore Petroleum and Natural Gas Production segment. The method for the Onshore Petroleum and Natural Gas Production segment for compressors and equipment leaks relies on the reporter counting the number of compressors or components ( e.g., population counts) and then applying emission factors per compressor or component for that population. Alternatively, for equipment leaks, the reporter may count the number of pieces of major equipment, assume the default component counts in Table W-1B, and then apply emission factors per component. This proposed population count approach is appropriate for the Onshore Petroleum and Natural Gas Gathering and Boosting segment because, as in the Onshore Petroleum and Natural Gas Production segment, the equipment is often geographically dispersed and may be visited only intermittently. Under the proposed approach, a reporter would need to establish an inventory of the components or equipment subject to the population counts, apply the emission factors, and then update the inventory each year to account for new or retired components or equipment. The EPA also seeks comment on the appropriateness of the methods used in the Onshore Natural Gas Processing segment for compressors and equipment leaks, which are outlined in 40 CFR 98.234(a). For gathering pipelines, the EPA is proposing to use an emission factor approach that is essentially the same as the approach used for equipment leaks in the Onshore Petroleum and Natural Gas Production segment. For gathering lines, reporters would use the population count and emission factor approach in 40 CFR 98.233(r). The emission factors that are being proposed, which would be added to an amended Table W-1A, are whole gas emission factors based on the U.S. GHG Inventory. The population count would be the miles of gathering pipeline, similar to the approach used for calculating emissions from natural gas distribution pipelines in the Natural Gas Distribution segment. The EPA has determined that the proposed monitoring and reporting requirements minimize the potential confusion associated with calculating emissions from the Onshore Petroleum and Natural Gas Gathering and Boosting segment by adopting the same methods used for calculating emissions that are used in the Onshore Petroleum and Natural Gas Production segment and the Onshore Natural Gas Processing segment. The EPA requests comment on whether the proposed monitoring and reporting requirements for the proposed Onshore Petroleum and Natural Gas Gathering and Boosting segment are appropriate for these emission sources, and if not, what methodologies would be more appropriate. Data collected through the proposed reporting requirements for the Onshore Petroleum and Natural Gas Gathering and Boosting segment in subpart W would improve the EPA's estimates and understanding of emissions from sources covered by the new segment and from the petroleum and natural gas sector. The improved data would provide a better understanding of sources in the petroleum and natural gas industry for which the public currently has little information. For example, the data that would be collected through these proposed revisions would inform updates to the U.S. GHG Inventory. The proposed requirements would require the reporting of GHG emissions from an entire gathering and boosting facility instead of the partial approach that currently exists under the GHGRP. Specifically, some gathering and boosting emission sources, such as natural gas compression stations, are only required to report GHG emissions if the facility exceeds the 25,000 metric tons CO 2 e annual emission reporting threshold in subpart A, 40 CFR 98.2(a)(2), based on combustion emissions that are reported under subpart C. Subpart W does currently require reporting from facilities that perform “natural gas processing” in 40 CFR 98.230(a)(3), but this requirement is only for those facilities that perform separation of natural gas liquids or non-methane gases from produced natural gas or the separation of natural gas liquids into one or more component mixtures and exceed 25 MMscfd annual average daily gas throughput. Subpart W also covers sources such as compressors, dehydration, or acid gas removal that are located on a single well-pad or associated with a single well as part of the Onshore Petroleum and Natural Gas Production segment. However, if these sources are associated with multiple well pads and not located on a single well-pad, they are not part of the Onshore Petroleum and Natural Gas Production segment and are currently not subject to reporting under subpart W. The EPA is not proposing to alter the definitions for the Onshore Natural Gas Processing or Onshore Petroleum and Natural Gas Production segments within subpart W, found in 40 CFR 98.230, so if these amendments are finalized as proposed, then the facilities and emission sources that are currently in the Onshore Petroleum and Natural Gas Production segment and the Onshore Natural Gas Processing segment of subpart W would remain in those segments. For facilities that have emissions sources that are covered by the Onshore Petroleum and Natural Gas Production segment and the Onshore Natural Gas Processing segment of subpart W but do not collectively meet the threshold for reporting in those segments, those emission sources or equipment should only be considered in the proposed Onshore Petroleum and Natural Gas Gathering and Boosting segment if they meet the proposed definition of “gathering and boosting system” and the appropriate thresholds. However, the proposed Onshore Petroleum and Natural Gas Gathering and Boosting segment would increase the overall coverage of subpart W by including some facilities that are reporting under subpart C for combustion emissions but only have to report a subset of their emissions currently, or that are not reporting at all under the GHGRP. Under the proposed rule, these facilities would become part of the proposed Onshore Petroleum and Natural Gas Gathering and Boosting segment in subpart W. If a reporter has more than one facility currently reporting under subpart C and they are consolidated as part of a single gathering and boosting facility as defined in this proposal, then the gathering and boosting facility would begin reporting all their relevant facility emissions, including those previously reported under subpart C, as a single consolidated facility under subpart W. The consolidated reporting facility would also include the parts of the system, such as pipelines and smaller compression stations, for which emissions are not currently being reported. The proposed Onshore Petroleum and Natural Gas Gathering and Boosting segment would also include equipment and facilities that are not currently reporting under the GHGRP. For example, the EPA anticipates that the proposed Onshore Petroleum and Natural Gas Gathering and Boosting segment would include many compressor stations in gathering and boosting systems that are not currently reporting because they do not, as a facility defined in 40 CFR 98.6, exceed the 25,000 metric tons CO 2 e per year reporting threshold in subpart A, 40 CFR 98.2(a)(2). However, when aggregated with the gathering pipelines and other compressor stations that are under common ownership and control within a system, the complete system may exceed the reporting threshold and would be required to begin reporting. The EPA considered other reporting options for defining the facility and the level of reporting, but none of them would have achieved the same balance of geographically specific information and reduced industry burden as the proposed option. One option considered was using the definition of “facility” found in 40 CFR 98.6 that states, “Facility means any physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control, that emits or may emit any greenhouse gas. Operators of military installations may classify such installations as more than a single facility based on distinct and independent functional groupings within contiguous military properties.” This would mean that each piece of property (or adjacent properties under common ownership or common control) with gathering and boosting equipment that exceeded the 25,000 metric tons CO 2 e annual threshold would be considered its own “facility”. This option provided limited data on the segment as a whole due to decreased coverage compared to other options, though more granular, site-specific data would likely be achievable for this option. This option would also require separate reports for each compressor station and/or gathering line, which would have resulted in a high reporting burden on owners/operators in this segment. Therefore, the EPA concluded that this option would not achieve the goals of having a thorough data set and transparent, complete information for this sector while minimizing burden to reporters. The EPA also considered an option that would have separated the gathering pipelines and gathering and boosting stations ( e.g., facilities with compressors, dehydration, and acid gas removal) into different segments. The gathering and boosting stations would have reported at the basin level, and the pipelines at the national level ( e.g. all gathering pipelines owned by a person or entity within the United States). However, the EPA is not proposing this option because it would have potentially resulted in higher burden to reporters by requiring reporting of additional facilities under their ownership. The EPA is seeking comment on whether these options should be considered and how they might achieve transparent and complete data for this segment without imposing additional burden on reporters compared to the proposed option. For more information regarding the options considered for defining the facility, see “Greenhouse Gas Reporting Rule: Technical Support for 2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule.” C. Natural Gas Transmission Lines Between Compressor Stations The EPA is proposing to add reporting requirements for emissions from natural gas transmission pipeline blowdowns between compressor stations in a new Onshore Natural Gas Transmission Pipeline segment. For purposes of the Onshore Natural Gas Transmission Pipeline segment, a blowdown is the release of gas from transmission pipelines for the purpose of reducing system pressure or complete depressurization. Transmission pipeline blowdowns occur when, a segment of pipeline is isolated from the rest of the line and the natural gas inside is purged through a blowdown vent stack. These blowdowns are needed to safely inspect and maintain the pipelines, but the purging of natural gas produces methane emissions that are currently not included in subpart W. In the U.S. GHG Inventory, the EPA estimated that there were over 300,000 miles of transmission pipelines in 2012, and the blowdown emissions associated with those pipelines were estimated to be 85,000 metric tons of methane a year. Although subpart W does require reporting of emissions from onshore natural gas transmission compression stations, it currently does not cover onshore natural gas transmission pipelines in between compressor stations. This represents a gap in the coverage of emission sources from the petroleum and natural gas systems source category covered by subpart W. The EPA is proposing to define the onshore natural gas transmission pipeline owner or operator depending on whether the transmission pipeline is interstate or intrastate. For interstate pipelines, the onshore natural gas transmission pipeline owner or operator would be the person identified as the transmission pipeline owner or operator on the Certificate of Public Convenience and Necessity issued under 15 U.S.C. 717f. For intrastate pipelines, the onshore natural gas transmission pipeline owner or operator would be the person identified as the owner or operator on the transmission pipeline's Statement of Operating Conditions under section 311 of the Natural Gas Policy Act (NGPA). The Certificate of Public Convenience and Necessity is a certificate issued by the Federal Energy Regulatory Commission (FERC) that allows the pipeline company to engage in the transportation and/or sale for resale of natural gas in interstate commerce or to acquire and operate facilities needed to accomplish this. The certificate is issued by FERC after FERC has approved the construction of a pipeline, and it allows the holder to build and operate the pipeline. Operators of intrastate pipelines are required to prepare a Statement of Operating Conditions for compliance under section 311 of the NGPA. Section 311 of the NGPA allows an interstate pipeline company to sell or transport gas on behalf of any intrastate pipeline or local distribution company without prior FERC approval. The EPA is proposing that the facility for the new Onshore Natural Gas Transmission Pipeline segment would be defined as the total U.S. mileage of natural gas transmission pipelines owned or operated by an onshore natural gas transmission pipeline owner or operator. If an entity owned and operated multiple pipelines in the U.S., the facility would be considered the aggregate of those pipelines, even if they are not interconnected. In defining the facility, the EPA considered other options, such as the facility being the amount of pipeline owned and operated by an entity within a state or basin, or the facility being each separate pipeline. In considering these other options, the EPA had to take into account that many major pipeline systems are essentially linear systems to move gas from one part of the U.S. to another, and requiring reporters to file separate reports for each portion of the system in any one state or other defined geography would impose higher reporting burden on those subject to this source category without providing the EPA with additional, specific information. The EPA also took into account the fact that many entities own and operate pipeline segments that may not be directly interconnected, but are connected with pipelines owned and operated by other entities as part of the national network of natural gas transmission pipelines. The proposed approach limits the burden on reporters to correlate the pipeline ownership transfer points with specific geographical segments. Instead, the reporters can track the required information for their various pipelines, regardless of location, and submit data associated with all of them in one report. The EPA is proposing that reporters would use the methods in 40 CFR 98.233(i) to calculate or measure emissions from pipeline blowdown events. One method allows a reporter to calculate emissions based on the volume of the pipeline segment between isolation valves that is blown down and the pressure and temperature of the gas within the pipeline. This method uses information that should be readily available to the reporter ( e.g., pipeline length, diameter, and operating pressure) and so should not be overly burdensome. The second method allows the reporter to measure the emissions from the blowdown using a flow meter on the blowdown vent stack. In both methods, the reporter would calculate both methane and carbon dioxide (CO 2 ) emissions from the volume of natural gas vented using either default gas composition or engineering estimates of composition as specified in 40 CFR 98.233(u)(2)(iii). In addition to the total annual emissions of methane and CO 2 , natural gas transmission pipeline reporters would also report the methane and CO 2 emissions and location of each blowdown event. The EPA previously considered fugitive emissions that result from leaks in transmission pipelines in the re-proposal of subpart W in April 2010 (75 FR 18616, April 12, 2010), but did not include provisions for these emissions in either the proposed or final rules. The April 2010 preamble explained that the EPA did not propose reporting requirements for fugitive emissions from leaks in natural gas pipeline segments between compressor stations due to the dispersed nature of the fugitive emissions, and the fact that, once fugitives are found, the leaks causing the emissions are usually addressed quickly for safety reasons (75 FR 18616, April 12, 2010). The EPA also notes that larger fugitive leaks are currently reported to the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration as part of 49 CFR 191.3. Under this provision, any pipeline incident that results in unintentional gas loss of three million cubic feet or more must be reported. Therefore, the EPA is not proposing to include reporting requirements for fugitive emissions from transmission pipeline leaks. The EPA also considered adding blowdowns between compressor stations on natural gas transmission pipelines to the Onshore Natural Gas Transmission Compression segment, which is already a reporting segment under subpart W, instead of creating a new segment. However, the Onshore Natural Gas Transmission Compression segment currently uses the same definition of facility as found in 40 CFR 98.6 and the natural gas transmission pipelines that surround a compressor station might not be compatible with that definition of “facility” because they would likely not be under common ownership or control with the adjacent compressor station(s). Therefore, keeping the definition of facility found in 40 CFR 98.6 for this proposed new segment would result in a higher reporting burden on pipeline owners/operators with a number of non-contiguous pipelines in the U.S. compared to the proposed option, because these owners/operators would have to submit individual reports for each pipeline they owned or operated. The proposed option simplifies reporting for this source by allowing each owner/operator to submit one report for all their transmission pipelines. D. Well Identification Numbers The EPA is proposing to amend 40 CFR 98.236 to add reporting requirements for well identification numbers to improve data quality by enabling identification of wells. If finalized, these reporting requirements would be reported for the first time in the report covering the year in which the rule is made effective ( e.g., if the final rule is effective January 1, 2016, then the reports covering 2016 data would be the first to include well identification numbers). Reporting of well identification numbers for previous years ( e.g., 2012) is not being proposed by the EPA. For the majority of wells, the well identification number reported will be the US Well Number (formerly referred to as the API Well Number, or API Number). 6 For any well that does not already have a US Well Number, the reporter would be required to provide the unique well number assigned by the permitting authority for drilling of oil and gas wells. US Well Numbers are required for wells in almost all states covered in the Onshore Petroleum and Natural Gas Production segment and are generally reported in relevant onshore production permitting documentation. This would allow the EPA to link the GHGRP data to other databases to more easily match the data reported under the GHGRP with other data sources and will improve the accuracy and transparency of subpart W. Being able to match the GHGRP data to other data sources would provide the EPA with more options for analysis of the GHGRP data to better inform future policy decisions related to GHG emissions from the oil and natural gas production sector. The reporting of the well identification numbers would also allow the EPA to assess the completeness and representativeness of the data collected under the GHGRP as a portion of all activity in the oil and natural gas production sector. 6 The Professional Petroleum Data Management Association. The US Well Number Standard: An Identifier for Petroleum Industry Wells in the USA. Version 2013 rev 1, published June 19, 2014. Available at http://dl.ppdm.org/dl/1147. Since 1966, almost all U.S. oil and gas wells have been assigned a unique and permanent API Well Number in accordance with American Petroleum Institute (API)'s specification in Bulletin D12A. 7 The API Well Number was established to allow regulators to track drilling permits, collect royalties, and optimize field conservation. API transferred ownership of the well numbering specification to the Professional Petroleum Data Management (PPDM) Association in 2010. The PPDM Association issued an updated specification in May 2013 and then renamed the identifier as the US Well Number in June 2014. 8 The PPDM Association is working with state regulatory agencies to implement the 2013 updates, but adoption is at the discretion of the agency. State agencies that elect not to use the US Well Number have assigned unique well identification numbers to the gas and oil wells in that state for tracking in their regulatory databases. US Well Numbers and other well identification numbers are publically available, but the accessibility of the data varies from state to state. Reporters in the Onshore Petroleum and Natural Gas Production segment already track and maintain records by well identification number for other regulatory and reporting purposes. 7 American Petroleum Institute. The API Well Number and Standard State And County Numeric Codes Including Offshore Waters. API Bulletin D12A, January 1979. Available at http://wellidentification.org/dl/US_API_Bulliten_1979.pdf. 8 The Professional Petroleum Data Management Association. The US Well Number Standard: An Identifier for Petroleum Industry Wells in the USA. Version 2013 rev 1, published June 19, 2014. Available at http://dl.ppdm.org/dl/1147. The EPA is proposing to require the reporting of well identification numbers for the Onshore Petroleum and Natural Gas Production segment in two general cases. First, the EPA proposes to require reporters in the Onshore Petroleum and Natural Gas Production segment to report a list of well identification numbers associated with different emission sources for all wells in a sub-basin included in the reported emissions data. Reporting the well identification numbers associated with different emission sources for each sub-basin would allow the EPA to determine completeness of reporting by evaluating the coverage of current reporting requirements and identifying potential cases of under-reporting by comparing lists of reported well identification numbers to lists of well identification numbers from state agencies. The EPA expects that this would present a low burden to reporters because reporters should already track and maintain well identification numbers. The EPA expects that most reporters track and maintain sub-basins for each well identification number. If a reporter does not, they can use the state code and county code portions of the US Well Number to identify the sub-basin. Second, for reporters in the Onshore Petroleum and Natural Gas Production segment that report emissions using input data that are calculated from measurements at individual wells or equipment associated with individual wells ( e.g., if Equation W-10A was used to calculate emissions from oil well completions and workovers with hydraulic fracturing, well testing emissions), the EPA proposes to require the reporter to report the well identification number for which those measurements were made, or for which the equipment is associated. Reporting the well identification numbers for input data based on measurements at a sample of wells would allow the EPA to compare GHGRP data to data from other wells in the same basin or sub-basin to evaluate whether the measurements were likely representative of all wells in the basin or sub-basin. The EPA expects that this would present a low burden to reporters because reporters should already track and maintain well identification numbers associated with measurements used for the GHGRP input data. Where emissions are reported for equipment that is on or associated with a single well pad, ( e.g., dehydrators, acid gas removal units), providing the well identification number(s) for the associated well(s) would also allow the EPA to compare the data that are used as inputs for estimating emissions to the data available from the well(s) to verify those data. The EPA expects that this would also present a low burden to reporters because reporters already have to make a determination of whether the equipment is on or associated with a single well pad, and would simply need to note and maintain the well identification number(s) for that associated piece of equipment. E. Advanced Innovative Monitoring Methods As oil and gas operations seek to capitalize on advances in measurement and monitoring technology in optimizing process operations and reducing fugitive emissions from process equipment leaks, opportunities will arise for facilities to use innovative technologies to gather real-time, continuous emissions data from area and point sources. For example, optical remote sensing techniques have existed for many years but recent technological advances have allowed these devices to be used in the field ( e.g., for fence line monitoring) to provide reliable measurements of gas concentrations, including methane, in the ambient air at the relevant detection limits. 9 10 9 Allen, D.T. et al. Measurements of methane emissions at natural gas production sites in the United States, Proceedings of the National Academy of Sciences of the United States of America, 110(44): 17768-17773, 2013. 10 EPA Handbook: Optical Remote Sensing for Measurement and Monitoring of Emissions Flux, http://www.epa.gov/ttnemc01/guidlnd/gd-052.pdf. The EPA is assessing the potential opportunities for applying remote sensing technologies and other innovations in measurement or monitoring technology to identifying and calculating emissions from affected sources under subpart W. The EPA's objective for this assessment is to determine if new and innovative technologies could be applied to the GHGRP to improve the overall accuracy and transparency of reported data in a cost-effective way while still meeting the overall objectives of Part 98. While the EPA is not proposing to incorporate these technologies into subpart W in this action, the EPA is requesting comment on the feasibility, possible regulatory approaches, provisions necessary to incorporate or allow the use of advanced measurement or monitoring methods in subpart W, and methods to ensure compliance with those provisions in an efficient manner. In particular, the EPA is soliciting data and case studies that could provide information regarding the benefits, costs, and potential problem areas, including consistency among reporters and the feasibility of verifying emissions, associated with using advanced innovative monitoring methods for providing emissions measurements in the oil and natural gas sector, including the provision of real-time or continuous measurements. Additionally, we are seeking comment on the EPA's memorandum on alternative and innovative measurement or monitoring technologies (see “Discussion Paper on Potential Implementation of Alternative Monitoring under the GHGRP” in Docket ID No. EPA-HQ-OAR-2014-0831). Following review of the data and information received in comments, the EPA may propose amendments related to the use of innovative technologies in reporting to the GHGRP in a future rulemaking. F. Best Available Monitoring Methods The EPA is proposing that facilities will be allowed to use BAMM for the proposed amendments for the 2016 reporting year for only the new industry segments and emission sources included in this proposal. These include calculating and reporting emissions from oil well completions and workovers with hydraulic fracturing, from onshore petroleum and natural gas gathering and boosting systems, and for transmission pipeline blowdown emissions. This proposal would allow reporters to use best available methods to estimate inputs to emission equations for the newly proposed emission sources using their best engineering judgment for cases where the monitoring of these inputs would not be possible beginning on January 1, 2016. The EPA is not proposing to allow the use of BAMM for the proposed reporting of well identification numbers because reporters should already have well identification numbers readily available for all wells and associated equipment to which this proposed reporting requirement would apply. These reporters have the option of using BAMM from January 1, 2016, to March 31, 2016, without seeking prior EPA approval for certain parameters that cannot reasonably be measured according to the monitoring and QA/QC requirements of 40 CFR 98.234. Reporters would also have the opportunity to request an extension for the use of BAMM beyond March 31, 2016; those owners or operators would submit a request to the Administrator by January 31, 2016. This additional time for reporters to comply with the monitoring methods for new emission sources in subpart W would allow facilities to install the necessary monitoring equipment during other planned (or unplanned) process unit downtime, thus avoiding process interruptions. The EPA is not proposing to allow the use of BAMM beyond 2016 and does not anticipate that BAMM would be needed beyond 2016 for the new segments and emissions sources being proposed in this rule. III. Proposed Confidentiality Determinations A. Overview and Background In this proposed rule, we are proposing confidentiality determinations for 171 data elements proposed to be reported by the following segments: Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Onshore Natural Gas Transmission Pipeline. These data elements include new reporting requirements for existing sources already reporting under subpart W as well as new reporting requirements that would be reported by additional industry segments or sources under these proposed amendments. The final confidentiality determinations the EPA has previously made for the remainder of the subpart W data elements are unaffected by the proposed amendments and continue to apply. For information on confidentiality determinations for the GHGRP and subpart W data elements, see: 75 FR 39094, July 7, 2010; 76 FR 30782, May 26, 2011; 77 FR 48072, August 13, 2012; 79 FR 63750, October 24, 2014. These proposed confidentiality determinations would be finalized after considering public comment. The EPA plans to finalize these determinations at the same time the proposed rule amendments described in this action are finalized. B. Approach to Proposed CBI Determinations With the exception of the specific data elements addressed in Section III.D of this preamble, we are applying the same approach as previously used for making confidentiality determinations for data elements reported under the GHGRP. In the “Confidentiality Determinations for Data Required Under the Mandatory Greenhouse Gas Reporting Rule and Amendments to Special Rules Governing Certain Information Obtained Under the Clean Air Act” (hereafter referred to as “2011 Final CBI Rule”) (76 FR 30782, May 26, 2011), the EPA grouped Part 98 data elements into 22 data categories (11 direct emitter data categories and 11 supplier data categories) with each of the 22 data categories containing data elements that are similar in type or characteristics. The EPA then made categorical confidentiality determinations for eight direct emitter data categories and eight supplier data categories and applied the categorical confidentiality determination to all data elements assigned to the category. Of these data categories with categorical determinations, the EPA determined that four direct emitter data categories are comprised of those data elements that meet the definition of “emissions data,” as defined at 40 CFR 2.301(a), and that, therefore, are not entitled to confidential treatment under section 114(c) of the CAA. 11 The EPA determined that the other four direct emitter data categories and the eight supplier data categories do not meet the definition of “emission data.” For these data categories that are determined not to be emission data, the EPA determined categorically that data in three direct emitter data categories and five supplier data categories are eligible for confidential treatment as CBI, and that the data in one direct emitter data category and three supplier data categories are ineligible for confidential treatment as CBI. For two direct emitter data categories, “Unit/Process `Static' Characteristics that Are Not Inputs to Emission Equations” and “Unit/Process Operating Characteristics that Are Not Inputs to Emission Equations,” and three supplier data categories, “GHGs Reported,” “Production/Throughput Quantities and Composition,” and “Unit/Process Operating Characteristics,” the EPA determined in the 2011 Final CBI Rule that the data elements assigned to those categories are not emission data, but the EPA did not make categorical CBI determinations for them. Rather, the EPA made CBI determinations for each individual data element included in those categories on a case-by-case basis taking into consideration the criteria in 40 CFR 2.208. No final confidentiality determination was made for the inputs to emission equation data category (a direct emitter data category) in the 2011 Final CBI Rule. However, the EPA has since proposed and finalized an approach for addressing disclosure concerns associated with inputs to emissions equations. 12 11 Direct emitter data categories that meet the definition of “emission data” in 40 CFR 2.301(a) are “Facility and Unit Identifier Information,” “Emissions,” “Calculation Methodology and Methodological Tier,” and “Data Elements Reported for Periods of Missing Data that are not Inputs to Emission Equations.” 12 Revisions to Reporting and Recordkeeping Requirements, and Confidentiality Determinations Under the Greenhouse Gas Reporting Program; Final Rule. (79 FR 63750, October 24, 2014). For this rulemaking, we are proposing to assign 165 new data elements to the appropriate direct emitter data categories created in the 2011 Final CBI Rule based on the type and characteristics of each data element. Note that subpart W is a direct emitter source category, thus, no data are assigned to any supplier data categories. For data elements the EPA has assigned in this proposed action to a direct emitter category with a categorical determination, the EPA is proposing that the categorical determination for the category be applied to the proposed new data element. For the proposed categorical assignment of the data elements in these eight categories with categorical determinations, see the memorandum “Data Category Assignments and Confidentiality Determinations for All Data Elements (excluding inputs to emission equations) in the Proposed `2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems' ” in Docket ID No. EPA-HQ-OAR-2014-0831. For data elements assigned to the “Unit/Process `Static' Characteristics that Are Not Inputs to Emission Equations” and “Unit/Process Operating Characteristics that Are Not Inputs to Emission Equations,” we are proposing confidentiality determinations on a case-by-case basis taking into consideration the criteria in 40 CFR 2.208, consistent with the approach used for data elements previously assigned to these two data categories. For the proposed categorical assignment of these data elements, see the memorandum “Data Category Assignments and Confidentiality Determinations for All Data Elements (excluding inputs to emission equations) in the Proposed `2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems' ” in Docket ID No. EPA-HQ-OAR-2014-0831. For the results of our case-by-case evaluation of these data elements, see Sections III.C and III.D of this preamble. In addition to the individual data element determinations described above and for the reasons stated below, we are proposing individual confidentiality determinations for six new data elements without making a data category assignment. In the 2011 Final CBI rule, although the EPA grouped similar data into categories and made categorical confidentiality determinations for a number of data categories, the EPA also recognized that similar data elements may not always have the same confidentiality status, in which case the EPA made individual instead of categorical determinations for the data elements within such data categories. 13 Similarly, while the six proposed new data elements are similar in type or certain characteristics to data elements previously assigned to the “Production/Throughput Data Not Used as Input” and “Raw Materials Consumed that are Not Inputs to Emission Equations” data categories, we do not believe that they share the same confidentiality status as the non-subpart W data elements already assigned to those two data categories, which the EPA has determined categorically to be CBI based on the data elements assigned to those categories at the time of the 2011 Final CBI Rule. As discussed in more detail below, our review showed that these six subpart W production and throughput-related data elements fail to qualify for confidential treatment. Therefore, we do not believe that the categorical determinations for the “Production/Throughput Data Not Used as Input” and “Raw Materials Consumed that are Not Inputs to Emission Equations” data categories are appropriate for these six data elements; accordingly, these data elements should not be assigned to these data categories. Not assigning these six data elements to these two data categories would also leave unaffected the existing categorical determinations for these data categories, which remain valid and applicable to the data elements assigned to those data categories. For the reasons stated above, we are proposing individual confidentiality determinations for these six data elements without making categorical assignment. 13 In the 2011 Final CBI rule, several data categories include both CBI and non-CBI data elements. See 76 FR 30786. Our proposed individual determinations follow the same two step evaluation process as set forth in the 2011 Final CBI Rule and subsequent confidentiality determinations for Part 98 data. Specifically, we first determined whether the data element meets the definition of emission data in 40 CFR 2.301(a). Data elements that meet the definition of emission data are required to be released under section 114 of the CAA. For data elements found to not meet the definition of emission data, we evaluated whether a data element meets the criteria in 40 CFR 2.208 for confidential treatment. In particular, we focus on: (1) Whether the data are already public; and (2) whether “. . . disclosure of the information is likely to cause substantial harm to the business's competitive position.” For the results of our case-by-case evaluation of these six proposed subpart W data elements, see Section III.D of this preamble. We are also proposing to assign 65 additional data elements used to calculate GHG emissions in subpart W for the Onshore Petroleum and Natural Gas Gathering and Boosting segment, Onshore Natural Gas Transmission Pipeline segment, and for emissions from oil wells with hydraulic fracturing to the “Input to Emission Equation” data category. We are not proposing a confidentiality determination for this data category. The majority of these data elements are existing data elements in subpart W that would be applied to the new Onshore Petroleum and Natural Gas Gathering and Boosting segment and Onshore Natural Gas Transmission Pipeline segment. Some of the data elements are new data elements that are used as inputs to proposed Equation W-12C. Due to concerns expressed by reporters with the potential release of inputs to emission equations, we previously established a process for evaluating “inputs to emission equation” data elements to identify potential disclosure concerns and actions to address such concerns if appropriate. 14 The EPA has used this process to evaluate inputs to emission equations, including the subpart W data elements that are already assigned to the inputs to emission equations data category. 15 We performed a similar evaluation for the 67 subpart W inputs to emission equations when they are applied to the Onshore Petroleum and Natural Gas Gathering and Boosting segment, Onshore Natural Gas Transmission Pipeline segment, and for calculating emissions from oil wells with hydraulic fracturing. 14 See the “Change to the Reporting Date for Certain Data Elements Required Under the Mandatory Reporting of Greenhouse Gases Rule” (hereinafter referred to as the “Final Deferral Notice”) (76 FR 53057, August 25, 2011) and the accompanying memorandum entitled “Process for Evaluating and Potentially Amending Part 98 Inputs to Emission Equations” (Docket ID EPA-HQ-OAR-2010-0929). 15 See the memoranda titled “Summary of Data Collected to Support Determination of Public Availability of Inputs to Emission Equations for which Reporting was Deferred to March 31, 2015” and “Evaluation of Competitive Harm from Disclosure of Inputs to Equations Data Elements Deferred to March 31, 2015.” (Docket ID EPA-HQ-OAR-2010-0929). For the Onshore Natural Gas Transmission Pipeline segment, the EPA did not identify any potential disclosure concerns with the data elements that are inputs to emissions equations. Accordingly, the proposal would require reporting of these data elements by March 31, 2017, which is the reporting deadline for the 2016 reporting year. For calculating emissions from oil wells with hydraulic fracturing, the EPA did not identify any disclosure concerns, except when the oil wells to which those inputs to emission equations apply meet the definition of either “wildcat well” or “delineation well.” “Delineation well” is defined as “a well drilled in order to determine the boundary of a field or producing reservoir.” “Wildcat well” is defined as “a well outside known fields or the first well drilled in an oil or gas field where no other oil and gas production exists.” As noted in a previous rulemaking (79 FR 63750, October 24, 2014), the early public disclosure of certain data elements that are inputs for these two specific well definitions could reveal data on well productivity that could give competitors an advantage by giving them information on new fields or new areas of existing fields without having to drill their own wildcat or delineation wells. This could result in the loss of investment value for certain reporters. For wildcat and delineation wells, the EPA is proposing to allow reporters to delay reporting of these data elements for 2 years, as currently allowed for gas wells with hydraulic fracturing that meet the definition of either “wildcat well” or “delineation well”, because a 2-year delay of reporting is sufficient to prevent early public disclosure of these data and will provide sufficient time for a reporter to thoroughly conduct an assessment of the well. The specific proposed data elements impacted are: (1) The cumulative gas flowback time, in hours, for each sub-basin, from when gas is first detected until sufficient quantities are present to enable separation (§ 98.236(g)(5)(i)); (2) the cumulative flowback time, in hours, for each sub-basin, after sufficient quantities of gas are present to enable separation (§ 98.236(g)(5)(i)); (3) the measured flowback rate, in standard cubic feet per hour, for each sub-basin (§ 98.236(g)(5)(ii)); and (4) the total annual gas-liquid separator oil volume that is sent to applicable onshore storage tanks, in barrels (§ 98.236(j)(1)(v)). In addition to the data elements that are inputs to emission equations for wildcat and delineation wells, the EPA has further determined that one other proposed data element related to these two specific types of wells may have early disclosure concerns due to the reasons stated above. Therefore, in order to treat all early disclosure concerns related to exploratory wells consistently throughout subpart W, the EPA is proposing to allow reporters to delay reporting for this data element for 2 years as well. The EPA is also proposing a confidentiality determination for this data element, found in Table 3 of this preamble, which would apply once the data element is reported to the EPA following the 2-year delay. The specific proposed data element impacted is: The total annual oil throughput that is sent to all atmospheric tanks, in barrels (§ 98.236(j)(2)(i)(A)). Other data elements related to delineation or wildcat wells that are not proposed to be amended in this action have been addressed in a previous rulemaking (79 FR 70352, November 25, 2014). For calculating emissions from sources in the Onshore Petroleum and Natural Gas Gathering and Boosting segment, the EPA did not identify any disclosure concerns. The Onshore Petroleum and Natural Gas Gathering and Boosting segment would be a regionally concentrated segment, with gathering lines and other services located in fixed geological basins. Because of the amount of fixed assets required to operate in this segment ( e.g., gathering lines and boosting stations), companies operating in this segment enter into long term agreements with natural gas producers to gather natural gas and transport it to natural gas processing facilities or, in some cases, transmission pipelines. These agreements are for long periods, lasting from several years to the life of the lease for the producing wells, and establish the prices for gathering services for the life of the agreement. Once these agreements are established, information that would be revealed from the “inputs to emissions equations” is not likely to affect the competitive position of the company operating the gathering and boosting system because it will not reveal information about the cost or profitability of providing that gathering service, or about the company's ability to enter into new agreements and expand operations. As a result, the “inputs to equations” data elements in this segment would not be likely to reveal any proprietary information about the facility or cost to do business. For the list of new subpart W inputs to emission equations and the results of our evaluation, see the memorandum, “Review for Potential Disclosure Concerns for Inputs to Emission Equations Affected by the Proposed `2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems' ” in Docket ID No. EPA-HQ-OAR-2014-0831. C. Proposed Confidentiality Determinations for Data Elements Assigned to the “Unit/Process `Static' Characteristics That Are Not Inputs to Emission Equations” and “Unit/Process Operating Characteristics That Are Not Inputs to Emission Equations” Data Categories The EPA is proposing that 36 data elements for subpart W that have been assigned to the “Unit/Process Operating Characteristics That Are Not Inputs to Emission Equations” data category or the “Unit/Process `Static' Characteristics That Are Not Inputs to Emission Equations” data category would be reported for sources in the proposed Onshore Petroleum and Natural Gas Gathering and Boosting segment, the Onshore Natural Gas Transmission Pipeline segment, or for onshore natural petroleum and natural gas production facilities that report emissions from oil wells with hydraulic fracturing. The data elements were assigned to these two categories in earlier EPA actions (77 FR 48072, August 13, 2012; and 79 FR 70352, November 25, 2014). We are proposing confidentiality determinations for these data elements when applied to these new emission sources based on the approach set forth in the 2011 Final CBI Rule for data elements assigned to these two data categories. In that rule, the EPA determined categorically that data elements assigned to these two data categories do not meet the definition of emission data in 40 CFR 2.301(a); the EPA then made individual, instead of categorical, confidentiality determinations for these data elements. As with all other data elements assigned to these two categories, the EPA concluded that the proposed new data elements do not meet the definition of emissions data in 40 CFR 2.301(a). The EPA then considered the confidentiality criteria at 40 CFR 2.208 in making our proposed confidentiality determinations. Specifically, we focused on whether the data are already publicly available from other sources and, if not, whether disclosure of the data is likely to cause substantial harm to the business' competitive position. Table 2 of this preamble lists the 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, the proposed confidentiality determination for each data element, and our rationale for each determination as they would apply to the Onshore Petroleum and Natural Gas Gathering and Boosting segment or for oil wells with hydraulic fracturing in the Onshore Petroleum and Natural Gas Production segment. For the existing data elements previously assigned to the “Unit/Process `Static' Characteristics that Are Not Inputs to Emission Equations” and “Unit/Process Operating Characteristics that Are Not Inputs to Emission Equations” that would be reported by the newly proposed Onshore Petroleum and Natural Gas Gathering and Boosting segment, the Onshore Natural Gas Transmission Pipeline segment, or for oil wells with hydraulic fracturing, we are proposing confidentiality determinations based on a new case-by-case evaluation of the data elements, taking into consideration the characteristics of the new reporters that would be required to report these data elements by the proposed amendments. Because these data elements do not meet the definition of emissions data in 40 CFR 2.301(a), the EPA used the criteria at 40 CFR 2.208 in making our proposed confidentiality determinations. Specifically, we focused on whether the data are already publicly available from other sources and, if not, whether disclosure of the data is likely to cause substantial harm to the business' competitive position. Table 2 of this preamble lists the data elements by data category, the proposed confidentiality determination for each data element, and our rationale for each determination. EP09DE14.000 EP09DE14.001 EP09DE14.002 EP09DE14.003 EP09DE14.004 EP09DE14.005 EP09DE14.006 D. Other Proposed Case-by-Case Confidentiality Determinations for Subpart W The proposed revision includes six data elements that are production and/or throughput data from subpart W facilities that would be newly reported for the Onshore Petroleum and Natural Gas Gathering and Boosting segment. Although these data elements are similar in certain types or characteristics to the data elements in “Production/Throughput Data that are Not Inputs to Emissions Equations” or “Raw Materials Consumed that are Not Inputs to Emissions Equations” data categories, for the reasons provided in Section III.B of this preamble, we are not proposing to assign these data elements to a data category. Instead, we are proceeding to make individual confidentiality determinations for these data elements. The proposed results of these individual determinations are presented in Table 3 of this preamble. As described in Section III.B of this preamble, our proposed determinations for these data elements were based on a two-step process in which we first evaluated whether the data element met the definition of emission data. This first step in the evaluation is important because emission data are not eligible for confidential treatment pursuant to section 114(c) of the CAA, which precludes emissions data from being considered confidential and requires that such data be made available to the public. The term “emission data” is defined in 40 CFR 2.301(a). We propose to determine that none of these six data elements are emission data under 40 CFR 2.301(a)(2)(i), because they do not provide any information characterizing actual GHG emissions or descriptive information about the location or nature of the emissions source. However, we note that this determination is made strictly in the context of the GHGRP and may not apply to other regulatory programs. In the second step, we evaluate whether the data element is entitled to confidentiality treatment, based on the criteria for confidential treatment specified in 40 CFR 2.208. In particular, the EPA focused on the following two factors: (1) Whether the data were already publicly available; and (2) whether “. . . disclosure of the information is likely to cause significant harm to the business' competitive position.” See 40 CFR 2.208(e)(1). For each of these six data elements, we determined whether the information is already available in the public domain. For those data elements for which no published data could be found, we evaluated whether their publication would be likely to cause competitive harm. For the proposed Onshore Petroleum and Natural Gas Gathering and Boosting segment, the EPA is proposing that five data elements related to the throughput of each gathering and boosting facility be reported and one data element related to the amount of produced gas consumed by the facility be reported. These data elements are not publicly available for all facilities operating in the Onshore Petroleum and Natural Gas Gathering and Boosting segment, although they are publicly available for facilities in the Onshore Petroleum and Natural Gas Production segment and the Onshore Natural Gas Processing segment. 16 However, information for some gathering and boosting systems is available on the company Web site or in annual reports. In addition, even if the data are not available, companies operating in this segment enter into long term agreements with natural gas producers to gather natural gas. Once these agreements are established, information that would be revealed from the data elements in Table 3 is not likely to affect the competitive position of the company operating the gathering and boosting system because it will not reveal information about the cost or profitability of providing that gathering service, or about the company's ability to enter into new agreements and expand operations. In addition, the information will be aggregated to the basin or sub-basin level rather than being reported for individual gathering and boosting systems. Therefore, we propose that these data, when reported by the newly proposed onshore petroleum and natural gas gathering and boosting reporters, be designated as not CBI because their disclosure would not be likely to cause competitive harm to reporters in that industry segment. This proposed determination does not affect earlier determinations made for reporters of the same data elements in other industry segments. 16 See the rationale for determining that similar data elements are not CBI for the onshore petroleum and natural gas production segment and the natural gas processing segment in the November 25, 2014 preamble (79 FR 70352). EP09DE14.007 E. Request for Comments on Proposed Confidentiality Determinations For the CBI component of this rulemaking, we are specifically soliciting comment on the following issues. First, we specifically seek comment on the proposed data category assignments, and application of the established categorical confidentiality determinations to new data elements assigned to categories with such determinations. If a commenter believes that the EPA has improperly assigned certain new data elements to any of the data categories established in the 2011 Final CBI Rule, please provide specific comments identifying which of these data elements may be mis-assigned along with a detailed explanation of why you believe them to be incorrectly assigned and in which data category you believe they belong. In addition, if you believe that a data element should be assigned to one of the two direct emitter data categories that do not have a categorical confidentiality determination, please also provide specific comment along with detailed rationale and supporting information on whether such data element does or does not qualify as CBI. We also seek comment on the proposed individual confidentiality determinations for the following data elements: 26 data elements assigned to the “Unit/Process Operating Characteristics That Are Not Inputs to Emission Equations” data category; 10 data elements assigned to the “Unit/Process `Static' Characteristics That Are Not Inputs to Emission Equations” category; and six data elements for which no data category assignment was proposed. By proposing confidentiality determinations prior to data reporting through this proposal and rulemaking process, we provide reporters an opportunity to submit comments, in particular comments identifying data they consider sensitive and their rationales and supporting documentation; this opportunity is the same opportunity that is afforded to submitters of information in case-by-case confidentiality determinations made in response to individual claims for confidential treatment not made through rulemaking. It provides an opportunity to rebut the agency's proposed determinations prior to finalization. We will evaluate the comments on our proposed determinations, including claims of confidentiality and information substantiating such claims, before finalizing the confidentiality determinations. Please note that this will be a reporter's only opportunity to substantiate a confidentiality claim for the data elements identified in this rulemaking. Upon finalizing the confidentiality determinations of the data elements identified in this rule, the EPA will release or withhold these data in accordance with 40 CFR 2.301, which contains special provisions governing the treatment of Part 98 data for which confidentiality determinations have been made through rulemaking. When submitting comments regarding the confidentiality determinations we are proposing in this action, please identify each individual data element you do or do not consider to be CBI or emission data in your comments. Please explain specifically how the public release of that particular data element would or would not cause a competitive disadvantage to a facility. Discuss how this data element may be different from or similar to data that are already publicly available. Please submit information identifying any publicly available sources of information containing the specific data elements in question. Data that are already available through other sources would likely be found not to qualify for CBI protection. In your comments, please identify the manner and location in which each specific data element you identify is publicly available, including a citation. If the data are physically published, such as in a book, industry trade publication, or federal agency publication, provide the title, volume number (if applicable), author(s), publisher, publication date, and International Standard Book Number (ISBN) or other identifier. For data published on a Web site, provide the address of the Web site and the date you last visited the Web site and identify the Web site publisher and content author. If your concern is that competitors could use a particular data element to discern sensitive information, specifically describe the pathway by which this could occur and explain how the discerned information would negatively affect your competitive position. Describe any unique process or aspect of your facility that would be revealed if the particular data element you consider sensitive were made publicly available. If the data element you identify would cause harm only when used in combination with other publicly available data, then describe the other data, identify the public source(s) of these data, and explain how the combination of data could be used to cause competitive harm. Describe the measures currently taken to keep the data confidential. Avoid conclusory and unsubstantiated statements, or general assertions regarding potential harm. Please be as specific as possible in your comments and include all information necessary for the EPA to evaluate your comments. IV. Impacts of the Proposed Amendments to Subpart W A. Costs of the Proposed Amendments As discussed in Section II of this preamble, the EPA is proposing amendments to subpart W that would add monitoring and reporting requirements for reporters in three industry segments: Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Onshore Natural Gas Transmission Pipeline. Reporters in the Onshore Petroleum and Natural Gas Production segment would have to monitor and report emissions and data elements associated with oil well completions and workovers with hydraulic fracturing. Reporters in this segment would also have to report the well identification numbers associated with individual oil and gas wells, and when reporting emissions for certain pieces of equipment, such as acid gas removal units, dehydrators, tanks, and flares, that are associated with individual oil and gas wells. The addition of the requirement to report emissions associated with oil well completions and workovers with hydraulic fracturing is expected to cause an increase in the amount of emissions that would count towards determining applicability with subpart W. The proposed addition of reporting requirements for oil wells with hydraulic fracturing is expected to affect 246 existing reporters and to cause approximately 50 new reporters to exceed the reporting threshold for the onshore petroleum and natural gas production facility. Reporters in the Onshore Petroleum and Natural Gas Gathering and Boosting segment would need to estimate and report emissions data and related data elements associated with several different emission sources within this newly proposed industry segment. Approximately 200 new reporters are expected to be subject to subpart W due to the proposed amendments for the Onshore Petroleum and Natural Gas Gathering and Boosting segment in this rulemaking. Reporters in the Onshore Natural Gas Transmission Pipeline segment would need to estimate and report emissions data and related data elements associated with transmission pipeline blowdown activities. Approximately 150 new reporters are expected to be subject to subpart W due to the proposed amendments in this rulemaking. The proposed amendments to subpart W are not expected to significantly increase burden. See the memorandum, “Assessment of Impacts of the 2015 Proposed Revisions to Subpart W” in Docket ID No. EPA-HQ-OAR-2014-0831 for additional information. B. Impacts of the Proposed Amendments on Small Businesses As required by the Regulatory Flexibility Act (RFA) and Small Business Regulatory Enforcement and Fairness Act (SBREFA), the EPA assessed the potential impacts of these amendments on small entities (small businesses, governments, and non-profit organizations). (See Section V.C of this preamble for definitions of small entities.) The EPA conducted a screening assessment comparing compliance costs to onshore petroleum and natural gas production specific receipts data for establishments owned by small businesses. This ratio constitutes a “sales” test that computes the annualized compliance costs of this rule as a percentage of sales and determines whether the ratio exceeds 1 percent. 17 The cost-to-sales ratios were constructed at the establishment level (average reporting program costs per establishment/average establishment receipts) for several business size ranges. This allowed the EPA to account for receipt differences between establishments owned by large and small businesses and differences in small business definitions across affected industries. The results of the screening assessment are shown in Table 4 of this preamble. 17 The EPA's RFA guidance for rule writers suggests the “sales” test continues to be the preferred quantitative metric for economic impact screening analysis. Table 4—Estimated Cost-To-Sales Ratios for First Year Costs by Industry and Enterprise Size a Industry segment NAICS NAICS description SBA size standard (effective January 22, 2014) Average cost per entity ($1,000/entity) All enterprises (percent) Owned by enterprises with: <20 employees b (percent) 20 to 99 employees (percent) 100 to 499 employees (percent) <500 employees (percent) 500 to 999 employees (percent) 1,000 to 2,499 employees Onshore Petroleum and Natural Gas Production 211 Oil and Gas Extraction 500 employees $29.36 0.07 0.43 0.03 0.01 0.09 0.00 0.00 213111 Drilling Oil and Gas Wells 500 employees 29.36 0.28 1.00 0.32 0.06 0.19 0.02 0.01 213112 Support Activities for Oil and Gas Operations $35.5 million 29.36 0.45 1.24 0.39 0.08 0.33 0.02 NA 221 Utilities 500 employees 29.36 0.08 0.84 0.14 0.06 0.19 0.04 NA 486 Pipeline Transportation $25.5 million 29.36 0.29 0.44 0.18 0.26 0.26 0.33 NA Onshore Natural Gas Transmission Pipeline 211 Oil and Gas Extraction 500 employees 3.19 0.01 0.05 0.00 0.00 0.01 0.00 0.00 213111 Drilling Oil and Gas Wells 500 employees 3.19 0.03 0.11 0.03 0.01 0.02 0.00 0.00 213112 Support Activities for Oil and Gas Operations $35.5 million 3.19 0.05 0.13 0.04 0.01 0.04 0.00 NA 221 Utilities 500 employees 3.19 0.01 0.09 0.01 0.01 0.02 0.00 NA 486 Pipeline Transportation $25.5 million 3.19 0.03 0.05 0.02 0.03 0.03 0.04 NA Onshore Petroleum and Natural Gas Gathering and Boosting 211 Oil and Gas Extraction 500 employees 24.70 0.06 0.36 0.03 0.01 0.08 0.00 0.00 213111 Drilling Oil and Gas Wells 500 employees 24.70 0.23 0.84 0.27 0.05 0.16 0.02 0.01 213112 Support Activities for Oil and Gas Operations $35.5 million 24.70 0.38 1.04 0.32 0.07 0.27 0.02 NA 221 Utilities 500 employees 24.70 0.07 0.70 0.12 0.05 0.16 0.04 NA 486 Pipeline Transportation $25.5 million 24.70 0.24 0.37 0.15 0.22 0.22 0.28 NA 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 typically 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. As shown, the cost-to-sales ratios are less than 1 percent for all establishments, except the ratio for the 1-20 employee range for facilities in the Onshore Petroleum and Natural Gas Production segment with NAICS code 213111, which is 1 percent, and the ratios for the 1-20 employee range for facilities in the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting segments with NAICS code 213112, which are greater than 1 percent but less than 2 percent. The petroleum and natural gas industry has a large number of enterprises, the majority of them in the 1-20 employee range. However, a large fraction of production comes from large corporations and not those with less than 20 employee enterprises. The smaller enterprises in most cases deal with very small operations (such as a single family owning a few production wells) that are unlikely to cross the 25,000 metric tons CO 2 e threshold considered for the rule. An exception to such a scenario is a small (less than 20 employee) enterprise owning large operations but conducting nearly all of its operations through contractors. This is not an uncommon practice in the Onshore Petroleum and Natural Gas Production segment. Such enterprises, however, are a very small group among the almost 16,000 enterprises in the less than 20 employee category, and the EPA proposes to cover them in the rule. The EPA took a conservative approach with the model entity analysis. Although the appropriate SBA size definition should be applied at the parent company (enterprise) level, data limitations allowed [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2014-28395. Public record. Not legal advice.